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.
<TABLE>
<CAPTION>
Annual Increase/(Decrease)
Updated
Requested Request Granted Status
(Millions of dollars)
<S> <C> <C> <C> <C>
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)
</TABLE>
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.
<TABLE>
<CAPTION>
Cumulative Mw Resource Needs By Type vs. Base of 1993
1996 2000 2004 2008
<S> <C> <C> <C> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
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)
<S> <C> <C> <C> <C> <C>
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)
</TABLE>
*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.
<PAGE>
Electric Operating Statistics
The following table summarizes the revenues, sales and customers from
NSP's electric transmission and distribution business:
<TABLE>
1994 1993 1992 1991 1990
<S> <C> <C> <C> <C> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
<S> <C> <C> <C> <C> <C>
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.
</TABLE>
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.
<TABLE>
<CAPTION>
EXECUTIVE OFFICERS *
Present Positions and Business Experience
Name Age During the Past Five Years
<S> <C> <C>
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
</TABLE>
Item 2 - Properties
The Company's major electric generating facilities consist of the
following:
<TABLE>
<CAPTION>
1994 1994
Capability Output
Station and Unit Fuel Installed (Mw) (Millions of Kwh)
<S> <C> <C> <C> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
1994 1993
High Low Dividends High Low Dividends
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>
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.
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
<S> <C> <C> <C> <C> <C>
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.
</TABLE>
Item 6 - Selected Financial Data
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990 1984
(Dollars in millions except per share data)
<S> <C> <C> <C> <C> <C> <C>
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.
</TABLE>
Item 7 - Management's Discussion and Analysis of Financial Condition and
Results of Operations
Northern States Power Company, a Minnesota corporation (the Company), has 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.
<TABLE>
<CAPTION>
1994 vs 1993 1993 vs 1992
<S> <C> <C>
(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
</TABLE>
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.
<TABLE>
<CAPTION>
1994 vs 1993 1993 vs 1992
<S> <C> <C>
(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
</TABLE>
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
<TABLE>
<CAPTION>
Consolidated Statements of Income Year Ended Dec. 31
(Thousands of dollars, except per share data) 1994 1993 1992
<S> <C> <C> <C>
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
</TABLE>
<TABLE>
<CAPTION>
Consolidated Statements of Cash Flows Year Ended Dec. 31
(Thousands of dollars) 1994 1993 1992
<S> <C> <C> <C>
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
</TABLE>
<TABLE>
<CAPTION>
Consolidated Balance Sheets Dec. 31
(Thousands of dollars) 1994 1993
<S> <C> <C>
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
</TABLE>
<TABLE>
<CAPTION>
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
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>
<TABLE>
<CAPTION>
Consolidated Statements of Capitalization
Dec. 31
(Thousands of dollars) 1994 1993
<S> <C> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
Purchased or
Name Geographic Area Economic Interest Placed in Service
<S> <C> <C> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
Stock Awards (Thousands of shares) 1994 1993 1992
<S> <C> <C> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
(Thousands of dollars) 1994 1993
<S> <C> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
(Thousands of dollars) 1994 1993 1992
<S> <C> <C> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
(Millions of dollars) 1994 1993
<S> <C> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
(Millions of dollars) 1994 1993
<S> <C> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
(Thousands of dollars) 1994 1993 1992
<S> <C> <C> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
(Thousands of dollars) 1994 1993
<S> <C> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
Amortization
(Thousands of dollars) Period 1994 1993
<S> <C> <C> <C>
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.
</TABLE>
13. Financial Instruments
The estimated Dec. 31 fair values of NSP's recorded financial instruments are
as follows:
<TABLE>
<CAPTION>
1994 1993
Carrying Fair Carrying Fair
(Thousands of dollars) Amount Value Amount Value
<S> <C> <C> <C> <C>
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
</TABLE>
For cash, cash equivalents and short-term investments, the carrying
amount approximates fair value because of the short maturity of those
instruments. The fair values of the Company's long-term investments 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.
<TABLE>
<CAPTION>
Net Effective
Notional Amount Term of Interest Cost
Series (millions of dollars) Swap Agreement at Dec. 31, 1994
<S> <C> <C> <C>
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:
</TABLE>
<TABLE>
<CAPTION>
(Thousands of dollars) 1994 1993 1992
<S> <C> <C> <C>
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)
</TABLE>
*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:
<TABLE>
<CAPTION>
(Millions of dollars) 1994 1993 1992
<S> <C> <C> <C>
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
</TABLE>
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
<TABLE>
<CAPTION>
Year Ended Dec. 31
(Thousands of dollars) 1994 1993 1992
<S> <C> <C> <C>
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
</TABLE>
19. Summarized Quarterly Financial Data (Unaudited)
<TABLE>
<CAPTION>
Quarter Ended
(Thousands of dollars) March 31, 1994 June 30, 1994 Sept. 30, 1994 Dec. 31, 1994
<S> <C> <C> <C> <C>
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
</TABLE>
* 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
<TABLE>
<CAPTION>
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)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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
</TABLE>
(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 $0 for all other
named executives.
OPTIONS AND STOCK APPRECIATION RIGHTS (SARs)
The following table indicates for each of the named executives (i) the
extent to which the Company used stock options and SARs for executive
compensation purposes in 1994 and (ii) the potential value of such options
and SARs as determined pursuant to the SEC rules.
OPTIONS AND SARS GRANTED IN 1994
<TABLE>
<CAPTION>
POTENTIAL REALIZABLE VALUE
AT ASSUMED ANNUAL RATES
OF STOCK PRICE APPRECIATION
INDIVIDUAL GRANTS FOR OPTION TERM
(a) (b) (c) (d) (e) (f) (g)
% OF TOTAL
OPTIONS AND
OPTIONS/ SARS EXERCISE
SARS GRANTED TO OR BASE
GRANTED(1) EMPLOYEES PRICE EXPIRATION
NAME (#) IN 1994 ($/SH) DATE 5%($)(3) 10%($)(3)
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>
(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 ($42.187) and the outstanding
shares (66,893,377) of common stock of the Company on that date.
(3) The hypothetical potential appreciation shown in columns (f) and (g) for
the named executives is required by the SEC rules. The amounts in these
columns do not represent either the historical or anticipated future
performance of the Company's common stock level of appreciation.
The following table indicates for each of the named executives the number
and value of exercisable and unexercisable options and SARs as of December 31,
1994.
AGGREGATED OPTION AND SAR EXERCISES IN 1994
AND FY-END OPTION/SAR VALUE
<TABLE>
<CAPTION>
(a) (b) (c) (d) (e)
NUMBER OF UNEXERCISED VALUE OF UNEXERCISED IN-THE-MONEY
SHARES OPTIONS AND SARS AT 12/31/94 OPTIONS AND SARS AT
ACQUIRED ON REALIZED (#) -- EXERCISABLE (EX)/ 12/31/94 ($) -- EXERCISABLE (EX)/
NAME EXERCISE(#) VALUE($) UNEXERCISABLE (UNEX) UNEXERCISABLE (UNEX)*
<S> <C> <C> <C> <C>
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)
</TABLE>
* 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:
<TABLE>
<CAPTION>
ESTIMATED ANNUAL BENEFITS FOR YEARS OF SERVICE INDICATED
AVERAGE
COMPENSATION YEARS OF SERVICE
(4 YEARS) 5 10 15 20 25 30
<S> <C> <C> <C> <C> <C> <C>
$ 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
</TABLE>
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
Exhibit 4.60
12-15-94
NORTHERN STATES POWER COMPANY
EMPLOYEE STOCK OWNERSHIP PLAN
Amended and Restated
Effective as of December 31, 1988
NORTHERN STATES POWER COMPANY
EMPLOYEE STOCK OWNERSHIP PLAN
Amended and Restated
Effective as of December 31, 1988
TABLE OF CONTENTS
Page
ARTICLE I. NATURE OF THE PLAN . . . . . . . . . . . . 1
Section 1.1 Purpose. . . . . . . . . . . . . . . . . . 1
Section 1.2 History. . . . . . . . . . . . . . . . . . 1
Section 1.3 General Information. . . . . . . . . . . . 1
Section 1.4 Benefits Determined Under Provisions in
effect at Termination of Employment . . . 1
ARTICLE II. DEFINITIONS. . . . . . . . . . . . . . . . 2
Section 2.1 Definitions. . . . . . . . . . . . . . . . 2
ARTICLE III. ELIGIBILITY FOR PARTICIPATION . . . . . . . . . 7
Section 3.1 Eligibility. . . . . . . . . . . . . . . . 7
Section 3.2 Re-employment. . . . . . . . . . . . . . . 8
Section 3.3 Excluded Employees.. . . . . . . . . . . . 9
ARTICLE IV. CONTRIBUTIONS . . . . . . . . . . . . . . . . . 10
Section 4.1 Discretionary Contributions. . . . . . . . 10
Section 4.2 Employee Contributions.. . . . . . . . . . 10
ARTICLE V. ACCOUNTS AND ALLOCATIONS . . . . . . . . . 11
Section 5.1 Separate Accounts. . . . . . . . . . . . . 11
Section 5.2 Allocation of Contributions. . . . . . . . 11
Section 5.3 Limitation on Allocations. . . . . . . . . 12
Section 5.4 Trust Income . . . . . . . . . . . . . . . 13
Section 5.5 Statement of Account . . . . . . . . . . . 14
Section 5.6 Immediate Vesting. . . . . . . . . . . . . 14
Section 5.7 Voting of Shares and Exercise of
Other Rights 14
Section 5.8 Tender or Exchange Offers Regarding
Company Stock 14
ARTICLE VI. DISTRIBUTION. . . . . . . . . . . . . . . . . . 16
Section 6.1 Termination of Employment. . . . . . . . . 16
Section 6.2 Effect of Re-Employment After
Distribution Has Been Made or Commenced . 17
Section 6.3 Withdrawals of Common Stock. . . . . . . . 17
Section 6.4 Diversification Options. . . . . . . . . . 19
Section 6.5 Rollovers and Transfers to Other
Qualified Plans 20
ARTICLE VII. BENEFICIARIES . . . . . . . . . . . . . . . . . 22
Section 7.1 Surviving Spouse as Required Beneficiary . 22
Section 7.2 Other Beneficiaries. . . . . . . . . . . . 22
Section 7.3 Presumptions . . . . . . . . . . . . . . . 22
Section 7.4 Waiver of Interest . . . . . . . . . . . . 23
ARTICLE VIII. ADMINISTRATIVE PROVISIONS . . . . . . . . . . . 24
Section 8.1 Company as "Named Fiduciary" May
Delegate Powers and Authorities. . . . . . 24
Section 8.2 Facility of Payment. . . . . . . . . . . . 24
Section 8.3 Spendthrift Trust and Qualified
Domestic Relations Order 24
Section 8.4 Source of Payment. . . . . . . . . . . . . 25
Section 8.5 Company to Pay Administration Expenses . . 25
Section 8.6 Record Address . . . . . . . . . . . . . . 25
Section 8.7 Required Information to be Furnished . . . 25
Section 8.8 Company Rules. . . . . . . . . . . . . . . 25
Section 8.9 Claims Procedure . . . . . . . . . . . . . 26
ARTICLE IX. AMENDMENT AND TERMINATION . . . . . . . . . . . 27
Section 9.1 Amendment. . . . . . . . . . . . . . . . . 27
Section 9.2 Discontinuance of Contributions and
Termination of the Plan 27
Section 9.3 Limitations. . . . . . . . . . . . . . . . 27
Section 9.4 Merger, Etc., with Another Plan. . . . . . 27
Section 9.5 Election to Participate by New Employer. . 27
ARTICLE X. TRUSTEE. . . . . . . . . . . . . . . . . . 28
Section 10.1 Trust Agreement. . . . . . . . . . . . . . 28
Section 10.2 Trust Investments. . . . . . . . . . . . . 28
Section 10.3 Exclusive Benefit of Participants. . . . . 28
Section 10.4 Borrowed Funds . . . . . . . . . . . . . . 28
Section 10.5 Dividends Applied to Loan Repayment. . . . 29
Section 10.6 Release from Suspense Account and
Allocation of Shares 29
Section 10.7 Non-Tradable Company Stock . . . . . . . . 30
ARTICLE XI. MISCELLANEOUS PROVISIONS. . . . . . . . . . . . 32
Section 11.1 No Contract of Employment. . . . . . . . . 32
Section 11.2 No Guarantees on Value . . . . . . . . . . 32
Section 11.3 Fiduciary Responsible Only For Own Acts. . 32
Section 11.4 Company Indemnification. . . . . . . . . . 32
Section 11.5 Laws of Minnesota. . . . . . . . . . . . . 32
Section 11.6 Securities Regulations . . . . . . . . . . 32
Section 11.7 Contributions Conditioned on Tax
Deductions 32
Section 11.8 Top Heavy Contingency. . . . . . . . . . . 33
Section 11.9 Tax Credit Rules . . . . . . . . . . . . . 33
NORTHERN STATES POWER COMPANY
EMPLOYEE STOCK OWNERSHIP PLAN
(Amended and Restated, Effective as of December 31, 1988)
ARTICLE I. NATURE OF THE PLAN
Section 1.1 Purpose. The purpose of this Plan is to provide Employees
who become Participants in the Plan with an opportunity to acquire ownership
of Company Stock, thereby promoting Employee interest in the business
endeavors of the Company and its subsidiaries and enhancing the Employees'
welfare.
Section 1.2 History. The Plan was originally adopted, effective
January 1, 1975, to take advantage of an investment tax credit available to
employers with respect to certain employee stock ownership plan contributions.
The investment tax credit expired December 31, 1982, and the Plan was amended
to take advantage of a payroll based tax credit available from January 1, 1983
through December 31, 1986. After 1986, the Plan remained in effect, both to
hold shares acquired previously, and to acquire additional shares of Company
Stock in leveraged and non-leveraged transactions.
Section 1.3 General Information. The Plan is intended to qualify as
a "tax credit employee stock ownership plan" under Code Section 409, as an
"employee stock ownership plan" as defined by Code Section 4975(e), and as a
qualified stock bonus plan under Code Section 401(a). The Plan consists of
the Plan and the Trust Agreement. It is administered by the Company for the
exclusive benefit of Participants and their Beneficiaries, pursuant to the
Plan and the Trust Agreement. A copy of the Trust Agreement is available for
review by Participants and their Beneficiaries in the Company's Benefits
Department. The administrative costs of the Plan, other than taxes, if any,
on assets held by the Trustee, will be borne by the Company, except to the
extent indirectly reimbursed by a reduction in a Discretionary Contribution
under Section 4.1. The Plan is designed to invest primarily in qualifying
employer securities meeting the requirements of Code Sections 4975(e)(8) and
409(l).
Section 1.4 Benefits Determined Under Provisions in effect at
Termination of Employment. Except as may be specifically provided herein to
the contrary, with respect to a Participant whose Termination of Employment
has occurred, benefits under the Plan attributable to service prior to his or
her Termination of Employment shall be determined and paid in accordance with
the provisions of the Plan as in effect on the date the Termination of
Employment occurred. Except where an earlier or later effective date is
specified, this amended and restated Plan is effective as of December 31,
1988.
ARTICLE II. DEFINITIONS
Section 2.1 Definitions. Unless the context clearly implies
otherwise, as used in this Plan the following terms shall have the meanings
set forth below:
"Account" refers to the records maintained by the Company to record the
proportional amount of the Trust Fund credited to an individual under the
Plan.
"Basic Account" refers to the entire Account of a Participant exclusive
of the Company Stock or other interest credited to the Participant's Savings
Account.
"Beneficiary" means the designated person, persons, trust, or estate to
whom all or a portion of the decedent's Account is to be distributed in the
event of death as provided in Article VII, except that, in the event of
homicide, the provisions of Section 524.2-803 of Minnesota Statutes shall be
applied.
"Board of Directors" means the Board of Directors of the Company.
"Code" refers to the Internal Revenue Code of 1986, as amended.
"Committee" shall mean the committee provided for in Section 8.1.
"Common Control" - a trade or business entity (whether a corporation,
partnership, sole proprietorship or otherwise) is under "Common Control" with
another trade or business entity (i) if both entities are corporations which
are members of a controlled group of corporations as defined in Code Section
414(b) , (ii) if both entities are trades or businesses (whether or not
incorporated) under common control as defined in Code Section 414(c), (iii)
if both entities are members of an affiliated service group as defined in Code
Section 414(m), or (iv) if both entities are required to be aggregated
pursuant to regulations under Code Section 404(o). Service for all entities
under Common Control shall be treated as service for a single employer to the
extent required by the Code. In applying the preceding sentence for purposes
of Section 5.3, the provisions of Code Section 414(b) and (c) are deemed to
be modified as provided in Code Section 415(h).
"Company" means Northern States Power Company, a Minnesota corporation.
"Company Stock" means common stock of the Company.
"Converted Pay" is a dollar amount which the Employee elected to have the
Employer make as a contribution on behalf of the Employee to a trust under a
plan adopted by the Company in accordance with Code Section 401(k) or which
the Employee directed the Employer to apply to the acquisition of benefits
under a written plan established by the Company under Code Section 125.
"Covered Compensation" means the total compensation received from the
Employer during a Plan Year as stated in the payroll records of the Employer,
including overtime, bonus or incentive pay, and Converted Pay, subject to the
following:
(a) Covered Compensation does not include expense allowances, per
diem payments and other special payments not classified as regular
compensation.
(b) Covered Compensation does not include Employer contributions
to this Plan or another employee benefit plan, nor does it include any
benefits from an employee benefit plan.
(c) Covered Compensation does not include any compensation in
excess of the maximum annual amount specified in Code Section 401(a)(17),
subject to any applicable cost of living adjustments.
(d) In applying the annual limits under Code Section 401(a)(17),
the spouse of a Highly Compensated Employee who is more than a 5% owner or who
is among the 10 highest paid Highly Compensated Employees and any lineal
descendants of such a Highly Compensated Employee who have not attained age
18 before the end of the Plan Year shall not be treated as a separate
participant, and any Covered Compensation of said family member shall be
treated as Covered Compensation of the Highly Compensated Employee.
(e) The term "Covered Compensation" includes compensation received
from an Employer in the entire Plan Year in which participation commences.
"Disability" means a total and permanent disability of a Participant.
A Participant will be deemed to be totally and permanently disabled when, on
the basis of medical evidence satisfactory to the Company, such Participant
is found to be unable to engage in any substantial gainful activity by reason
of any medically determinable physical or mental impairment which can be
expected to result in death or to be of long-continued and indefinite
duration.
"Discretionary Contribution" refers to an Employer contribution under
Section 4.1.
"Effective Date" means the date on which the Plan became effective, that
is, January 1, 1975.
"Employee" refers to an employee of an Employer as defined herein.
"Employer" means the Company, Northern States Power Company, a Wisconsin
corporation, and any other corporation under Common Control with the Company
which, with the consent of the Company, is participating pursuant to Section
9.5.
"ERISA" refers to the Employee Retirement Income Security Act of 1974.
"Highly Compensated Employee" for any Plan Year means an individual
described in Code Section 414(q), including Employees meeting the following
requirements:
(a) The Employee at any time during the current or prior Plan Year
was a 5 percent owner as defined in Code Section 414(q)(3).
(b) The Employee received Testing Wages in excess of $75,000
(adjusted for cost of living increases as provided by regulation) for the
prior Plan Year.
(c) The Employee both received Testing Wages in excess of $50,000
(adjusted for cost of living increases as provided by regulation) for the
prior Plan Year and was in the top paid 20 percent of Employees, determined
in accordance with Code Section 414(q)(8).
(d) The Employee was an officer receiving Testing Wages in excess
of $45,000 (adjusted for cost of living increases as provided by regulation)
for the prior Plan Year. However, no more than the greater of 50 persons or
10 percent of Employees shall be treated as officers for purposes of this
subsection.
(e) The employee would meet the requirements of subsections (b),
(c), or (d) in the current Plan Year (but not in the prior Plan Year) and is
among the 100 Employees paid the greatest Testing Wages.
"Hour of Service" means an hour for which an Employee is directly or
indirectly paid, or entitled to payment, by the Employer prior to termination
of service, including overtime and paid "time-off" such as paid vacation days,
holidays, or days on jury duty. An "Hour of Service" includes each hour for
which back pay, irrespective of mitigation of damage, has been awarded or
agreed to by the Employer; such hours shall be credited to the Employee for
the computation period or periods to which the award or agreement pertains
rather than the computation period in which the award, agreement, or payment
was made. Credit for payments made for or during periods of time in which no
duties are performed shall be determined in accordance with Department of
Labor Regulation Sections 2530.200b-2(b) and (c).
"Investment Date" is the 20th day of each month if shares of Company
Stock are traded on the New York Stock Exchange on that day; if not, the
Investment Date shall be the first succeeding day during which shares of such
stock are traded on such Exchange. For purposes of section 4.2(B) only,
"10th" shall be substituted for "20th" in the preceding sentence.
"Investment Price" shall be a price equal to the average of the reported
high and low prices for the Company Stock as of the Investment Date preceding
the applicable transaction as reported in the Wall Street Journal for the New
York Stock Exchange-Composite Transactions. (In the event Company Stock should
not be readily tradeable on an established security market, then the
Investment Price shall be determined by an independent appraiser meeting
requirements similar to those contained under regulations issued under Code
Section 170(a)(1).)
"Leased Employee" is any person who is not otherwise an Employee and who,
pursuant to an agreement between the recipient Employer and any other person
or organization, has performed services for an Employer, or for an Employer
and related persons (determined in accordance with Code Section 414(n)(6)),
who completes 1000 Hours of Service either in the initial computation year
referred to in Section 3.1(B)(2) or any Plan Year thereafter, and such
services are of a type historically performed by employees in the business
field of the Employer; provided, that a person shall not be treated as a
Leased Employee for any Plan Year if, during such Plan Year: (i) such person
is covered by a money purchase pension plan described in Code Section
414(n)(5)(B), and (ii) not more than 20% of the Employees who are not Highly
Compensated Employees are Leased Employees. Once a person is classified as
a Leased Employee, such person shall remain a Leased Employee for every Plan
Year for which the person completes at least 1000 Hours of Service.
"Matching Employee Contributions" refer to contributions made by a
Participant prior to 1987 under Plan provisions which at that time resulted
in a matching contribution from the Employer.
"Participant" refers to an Employee who has become eligible to
participate under Article III and any former Employee who is still entitled
to benefits under the Plan.
"Plan Entry Date" refers to December 31 or June 30 of each Plan Year.
"Plan Year" means the twelve month period beginning each December 31 and
ending the following December 30.
"Retirement or Retirees" refers to normal (age 65), late (after age 65),
or early (after age 55 but before age 65), retirement under the Company's
defined benefit pension plan, or termination of service after attainment of
age 65 for Participants entitled to no benefits from said pension plan.
"Savings Account" refers to the subaccount which separately accounts for
a Participant's contributions made pursuant to Section 4.2.
"Suspense Account" refers to an unallocated account maintained by the
Trustee under Section 10.4 in regard to Company Stock acquired with the
proceeds of a loan.
"Termination of Employment" means any termination of the employment
relationship pursuant to the Employer's practices and procedures. Termination
of Employment generally does not occur until termination of any leave of
absence granted to an Employee who leaves the service of an Employer, except
that a "leave of absence for third party service" will be deemed a
"termination of employment." A "leave of absence for third party service" is
an unpaid leave of absence of indefinite duration, but expected to exceed one
year, granted the Employee either by the Employer or by operation of law for
the purpose of allowing the Employee to perform services for a third party
(such as full-time government, military or union service). No distribution
shall be made to an Employee during a "leave of absence for third party
service" unless the Employee delivers to the Company a written request for
such distribution.
"Testing Wages" for a Plan Year means the Employee's wages for the Plan
Year as defined for purposes of federal income tax withholding, subject to the
following:
(a) The Committee may, on a uniform and nondiscriminatory basis,
modify the definition of Testing Wages in any way that satisfies the
definition of "compensation" under Code Section 414(s).
(b) Except for purposes of Section 5.3, the Committee shall
determine whether Testing Wages for a Plan Year shall include Converted Pay.
For purposes of Section 5.3, Testing Wages shall not include Converted Pay.
(c) Testing Wages does not include any compensation in excess of
the maximum annual limit applicable under Code Section 401(a)(17), subject to
any applicable cost of living adjustments.
(d) In applying the annual limits under Code Section 401(a)(17),
the spouse of a Highly Compensated Employee who is more than a 5% owner or who
is among the 10 highest paid Highly Compensated Employees and any of the
lineal descendants of such a Highly Compensated Employee who have not attained
age 18 before the end of the Plan Year shall not be treated as a separate
participant, and any Testing Wages of said family member shall be treated as
Testing Wages of the Highly Compensated Employee.
"Trust" is the trust created by the Trust Agreement entered between the
Company and the Trustee.
"Trust Agreement" is the agreement, as provided in Article X, entered
into by the Company and the Trustee, or any successor Trustee, establishing
the Trust and specifying the duties of the Trustee.
"Trustee" means the Trustee (which can be more than one individual or
corporation) under the Plan and related Trust Agreement.
"Trust Fund" shall mean the Trust Fund provided for in Article X.
"Year of Service" means any Plan Year, calendar year or other applicable
12-month computation period during which an Employee completes at least 1,000
Hours of Service.
ARTICLE III. ELIGIBILITY FOR PARTICIPATION
Section 3.1 Eligibility.
(A) An Employee in the employ of an Employer shall become a Participant
on the first Plan Entry Date which occurs after the earlier of the following:
(1) the date the Employee completes one continuous Year of Service;
or
(2) the date the Employee completes two Years of Service without
a Break in Service,
unless such Employee is no longer in the employ of an Employer on the date
such Employee would otherwise become a Participant.
(B) For the purpose of Subsection (A), the following rules and
definitions apply:
(1) No period of employment with an Employer prior to January 1,
1972, shall be considered to determine eligibility.
(2) The computation period for determining a Year of Service for
eligibility shall be a consecutive 12-month period measured from the date of
the first Hour of Service commencing on or after January 1, 1972.
(3) "One continuous Year of Service" means that the Employee
completes a Year of Service in a consecutive 12-month computation period
measured from the date of the first Hour of Service commencing on or after
January 1, 1974, and remains in the employ of an Employer throughout such
entire computation period.
(4) A "Break in Service" means a failure by an Employee who is not
a Participant under the Plan to complete more than 500 Hours of Service for
the Employer in the computation period, or in any immediately succeeding
12-month period, being used to account for such Employee's Hours of Service.
If an Employee incurs a Break in Service, all service for the Employer prior
to the Break in Service shall be disregarded. After a Break in Service by an
Employee, the computation period for determining a Year of Service for
eligibility shall be a consecutive 12 month period commencing with the first
date such Employee completes an Hour of Service following the computation
period in which the Break in Service occurred.
(5) A "Break in Service" shall not occur as to a computation period
during which the Employee completes less than 500 Hours of Service if such
failure to complete 500 Hours of Service was due to a maternity or paternity
leave (assuming the greater of the Employee's usual Hours of Service or eight
Hours a day during the portion of the computation period for which the
Employee is absent from service by reason of a maternity or paternity leave).
However, a "Break in Service" shall occur in any succeeding computation period
for failure to complete 500 Hours of Service even if the maternity or
paternity leave extends into such succeeding computation period. "Maternity
or paternity leave" means a period of absence by an Employee from the
Employer's service by reason of (1) the Employee's pregnancy; (2) the birth
of a child of the Employee; (3) the adoption of a child by the Employee; or
(4) the caring for such a child for a period beginning immediately following
birth or placement for adoption. The Company may require the Employee to
furnish timely and adequate information that an absence, or the total period
of absence, was for one of the foregoing reasons before crediting all or a
portion of an absence as a maternity or paternity leave.
(C) Notwithstanding (A) above, an Employee of an Employer which became
an Employer pursuant to an election under Section 9.5, shall become a
Participant as of the effective date of such an Employer's election to
participate in the Plan if:
(1) Such an Employee was a participant in a defined contribution
plan of such an Employer which plan was merged into this Plan effective as of
the date such Employer's participation in this Plan commenced; or
(2) Such an Employee would have been eligible under (A) above,
prior to such effective date if such Employer had become a participating
employer as of the first day of the third Plan Year preceding the Plan Year
in which such Employer actually commenced participation in this Plan.
In all other situations, such an Employee shall become a Participant upon
meeting the requirements of (A) above, disregarding any service for the
Employer more than three Plan Years prior to the Plan Year in which the
Employer's participation in this Plan commenced.
(D) Once an Employee becomes a Participant, all Hours of Service for all
purposes shall be accounted for on a Plan Year basis only.
(E) In addition to the service credited pursuant to subsection (C)
above, certain Employees shall receive additional service credit as follows:
(1) Employees who were employed by Viking Gas Transmission Co. at
the time it was acquired by the Company from Tenneco Inc. shall be credited
with additional service equal to their pre-acquisition service for Tenneco
Inc. and its subsidiaries.
(2) Employees who were employees of Centran Corporation immediately
prior to the acquisition of certain of its assets by a subsidiary of the
Company on October 1, 1993 shall be credited with additional service equal to
their service prior to that date for Centran Corporation.
Section 3.2 Re-employment. If a Participant ceases to participate due
to a termination of employment and is re-employed by an Employer such former
Participant shall immediately reenter the Plan as a Participant.
Section 3.3 Excluded Employees. Notwithstanding any other provisions
hereof, the following Employees are excluded from coverage under the Plan:
(A) An Employee who is a member of a union which has a collective
bargaining agreement through or with an employers' association, which
agreement is followed by the Employer and the Employee is eligible for
coverage under a retirement plan established by negotiations between such
union and association, or if there is other evidence that retirement benefits
were the subject of good faith bargaining between such employer association
and such union.
(B) Any Leased Employee as defined in Section 2.1.
(C) Prior to January 1, 1994, certain Employees participating in work
study arrangements.
ARTICLE IV. CONTRIBUTIONS
Section 4.1 Discretionary Contributions. For each Plan Year the
Company shall determine whether a Discretionary Contribution to the Plan shall
be made and the amount of any such contribution. Said contribution will be
made by the Participating Employers in proportions determined by the Company.
Such contribution will normally be made on or before the 31st day following
the end of the Plan Year; but the Company may, in its discretion, delay such
contribution until the due date (including extension) for filing the federal
income tax return for the taxable year of the Company with respect to which
the contribution is made. The contribution may be made in the form of cash
or Company Stock, or any combination thereof. All cash contributions shall
be applied by the Trustee within 30 days of receipt in one or more of the
following ways, as determined by the Company: (1) to purchase Company Stock
in market transactions, (2) to purchase Company Stock directly from the
Company at the Investment Price, or (3) to redeem fractional shares of
terminating Participants at the Investment Price.
Section 4.2 Employee Contributions.
(A) Except as hereafter provided, a Participant who is an Employee may
elect to make Employee contributions to the Plan to be held in such
Participant's Savings Account, which will be reflected by the sub-accounts
established by Sections 5.1(D) and 5.1(E), as applicable. However,
Participants who are Highly Compensated Employees or who the Company
determines are exempt employees for purposes of the federal wage and hour laws
are not eligible to make Employee contributions pursuant to this Section. If
the Company determines that it has accepted a contribution from such a
Participant, the Company Stock acquired with such a contribution, including
stock acquired by the reinvestment of dividends relating thereto, shall be
distributed to the Participant as soon as practical after the determination
is made by the Company. Contributions may be made by payroll deductions or
cash contributions. Such contributions may be made up to an amount equal to
ten percent of the aggregate Covered Compensation received by the Participant
for all years during which the Participant participated in this Plan, less the
amount of previous voluntary contributions to this Plan under this Section 4.2
or to the NSP Retirement Savings Plan or any other plan qualified under Code
Section 401(a) maintained by the Employer.
(B) All Employee contributions shall be applied monthly by the Trustee
in one or more of the following ways, as determined by the Company: (1) to
purchase Company Stock in market transactions, (2) to purchase such stock
directly from the Company at the Investment Price, or (3) to redeem fractional
shares of terminating Participants at the Investment Price.
(C) Participants may elect to make Employee contributions by signing a
form provided by the Company for such purpose. The Employer may require, on
a nondiscriminatory basis, that no payroll deduction will be made, changed or
terminated for any payroll period which commences less than 15 days after
delivery by a Participant of such election, change or termination to the
Employer's Payroll Department. No payroll deduction shall be in an amount
less than $5.00 per month and no cash contribution shall be less than $10.00.
The Employer may require that the payroll deduction be in a specific dollar
amount, and, if permitted as a percent of eligible compensation, the
authorization may be rounded to the next highest dollar amount divisible by
twelve. The Employer may require that payroll deductions for the Savings
Account be collected in the same payroll period each month and may specify a
specific payroll period for such payroll deductions.
ARTICLE V. ACCOUNTS AND ALLOCATIONS
Section 5.1 Separate Accounts. The Company shall create a separate
Account for each Participant. The Company shall also maintain separate
subaccounts reflecting:
(A) Company Stock acquired with Discretionary Contributions;
(B) Company Stock acquired with Matching Employee Contributions;
(C) Company Stock acquired directly (or indirectly through repayment of
a loan to the Plan) due to reinvestment of dividends or other income which
does not relate to the shares of stock allocated to the subaccount established
pursuant to Sections 5.1(D) and 5.1(E).
(D) Company Stock acquired with Employee contributions (other than
Matching Employee Contributions) made prior to January 1, 1987, as well as
with the dividends on stock allocated to such subaccount; and
(E) Company Stock acquired with other Employee contributions made after
December 31, 1986, as well as with the dividends on stock allocated to such
subaccount.
Additional subaccounts may be established in the Company's discretion.
Section 5.2 Allocation of Contributions.
(A) Allocation Using Covered Compensation. Except to the extent
otherwise provided in Section 10.6, the Discretionary Contributions for a
given Plan Year shall be allocated to the Accounts of Participants who meet
the eligibility requirements of subsection (B) in the ratio which the Covered
Compensation of each Participant for such Plan Year bears to the Covered
Compensation of all such Participants, provided that if any portion of the
contribution is allocated before the end of a Plan Year, such allocation may
be based on either Covered Compensation paid to the date of the allocation or
Covered Compensation projected for the Plan Year. The shares of Company Stock
acquired with a Discretionary Contribution shall be allocated within 90 days
after the end of the Plan Year for which the contribution is made or, if
later, within 60 days after the date on which the contribution is made.
(B) Participants Entitled to Receive Allocations.
(1) Except for those Participants who commence participation during
the Plan Year, or who terminate their employment with the Employer during the
Plan Year by reason of death or retirement or under circumstances that entitle
them to receive benefits under the NSP Severance Plan for non-bargaining
employees, no portion of the Discretionary Contribution for a Plan Year shall
be allocated to the Account of a Participant unless such Participant had at
least 1,000 Hours of Service during such Plan Year. However, if a Participant
is an active Employee at the time of allocation and the Company used dividends
on the shares allocated to the Employee's Account throughout the Plan Year for
the purposes of loan repayment under Section 10.5, such Participant shall
share in the allocation of a Discretionary Contribution for the Plan Year even
if the Participant did not complete 1,000 Hours of Service in the Plan Year.
(2) No allocation of Discretionary Contributions shall be made to
an Account for a Participant commencing participation on a date other than the
first day of the Plan Year unless such Participant had, during the part of the
Plan Year remaining after becoming a Participant, at least that fraction of
1,000 Hours of Service which is equal to the fraction of the Plan Year in
which the Participant participated.
(3) No allocation of Discretionary Contributions shall be made to
an Account of a former Participant who has received a distribution of his or
her total account balance before the allocation of the contribution is made,
except in the case of an early distribution for which the Participant incurred
a payment as provided in Section 6.1(A).
Section 5.3 Limitation on Allocations. Notwithstanding any provisions
of the Plan to the contrary, allocations to Participants under the Plan shall
not exceed the maximum amount permitted under Code section 415. For purposes
of the preceding sentence, the following rules shall apply unless otherwise
provided in Code section 415:
(A) The Annual Additions with respect to a Participant for any Plan Year
shall not exceed the lesser of:
(1) $30,000, or, if greater, 25% of the defined benefit dollar
limitation set forth in Code section 415(b)(1)(A) as in effect for the Plan
Year.
(2) 25% of the Testing Wages of such Participant for such Plan
Year.
(B) If for any Plan Year the limitation described in subsection (A)
would otherwise be exceeded with respect to any Participant, correction shall
be made as follows:
(1) The Participant's Employee contributions for said Plan Year
will be refunded to him.
(2) Any remaining excess amount will be transferred to a suspense
account, from which it will be allocated as Employer contributions for all
Participants in the next Plan Year. The suspense account will not participate
in allocation of the Trust Fund's earnings or losses.
(C) If a Participant is also a participant in one or more other defined
contribution plans maintained by an Employer, and if the amount of Employer
contributions otherwise allocated to the Participant for a Plan Year must be
reduced to comply with the limitations under Code section 415, such
allocations under this Plan and each of such other plans shall be reduced pro
rata to the extent necessary to comply with said limitations, but reductions
shall occur first from employee after-tax contributions, next from employee
before-tax contributions, and finally from all other allocations.
(D) If the Participant is also a participant in one or more defined
benefit plans maintained by an Employer, the sum of the Participant's defined
benefit plan fraction and defined contribution plan fraction, determined
according to Code section 415(e), for any Plan Year may not exceed 1.0, and
benefits under said defined benefit pension plan(s) shall be reduced as
necessary to reduce the sum of the fractions to 1.0.
(E) For purposes of this section, "Annual Additions" means the sum of
the following amounts allocated to a Participant for a Plan Year under this
Plan and all other defined contribution plans maintained by his Employer in
which he participates:
(1) Principal payments on exempt loans to the extent such payments
are attributable to shares of Company Stock allocated to the Participant.
(2) Discretionary Contributions under Section 4.1.
(3) Employee Contributions under Section 4.2.
(4) Amounts considered to be "Annual Additions" under the terms of
the other defined contribution plans.
Contributions used to pay interest on an Exempt Loan shall be an annual
Addition for any Plan Year that the requirements of subsection (F) are not
met. An Annual Addition with respect to a Participant's Account shall be
deemed credited thereto with respect to a Plan Year if it is allocated to
the Participant's Account under the terms of the Plan as of any date within
such Plan Year.
(F) The requirements of this subsection (F) are met with respect to a
particular Plan Year if no more than one third of the Employer contributions
for that year are allocated to the group consisting of Highly Compensated
Employees.
Section 5.4 Trust Income. Except as provided under Section 10.5,
income earned by the Trust will be promptly invested in additional shares of
Company Stock. However, any income earned on cash held pending investment in
Company Stock will be held in an unallocated account until the next quarterly
dividend payment when it shall be commingled, invested and allocated with the
dividend income for the applicable Accounts then existing. Trust income shall
be applied by the Trustee in one or more of the following ways, as determined
by the Company (1) to purchase Company Stock in market transactions,
(2) to purchase such stock directly from the Company at the Investment Price,
or (3) to redeem fractional shares of terminating Participants at the
Investment Price. When the total funds available for investment in shares of
Company Stock at a particular time have been fully applied by the Trustee, the
acquired shares shall be allocated to Participant Accounts so as to reflect
the shares held in a Participant's Account at the time of allocation in
relation to the total shares held in all Accounts, subject to a pro rata
adjustment for any application by the Trustee of income as authorized herein,
including reducing dividends credited to an Account to the extent applied
under Section 10.5. The stated price of the shares so allocated shall reflect
the weighted average price at which all such shares were acquired. For the
purpose of this Section, the terms "Participant's Accounts" or "Participant's
Account" refer to any account maintained by the Company including temporarily
unallocated accounts and accounts reflecting the amount credited to a former
Participant or to an alternate payee.
Section 5.5 Statement of Account. As soon as practicable after the
end of each Plan Year, the Company shall present to each Participant a
statement showing the amount of Company Stock credited to the Participant's
Account at the beginning of such Plan Year, any change during the Year, the
accrued balance at the end of the Year, and such other information as the
Company may determine. However, neither the maintenance of the accounts, the
allocation of credits to the accounts, nor the statement of accounts shall
operate to vest in any Participant any right or interest in or to any assets
of the Trust except as the Plan and Trust specifically provide.
Section 5.6 Immediate Vesting. All amounts allocated to a
Participant's Accounts shall be fully vested at all times. Notwithstanding
the Participant's nonforfeitable right hereunder, no stock in the Account of
a Participant shall be distributed to a Participant or Beneficiary prior to
a time authorized under Article VI.
Section 5.7 Voting of Shares and Exercise of Other Rights. A
Participant is entitled to direct the exercise of voting rights or other
rights with respect to the number of shares of Company Stock allocated to said
Participant's Account. The Company shall provide to each Participant
materials pertaining to the exercise of such rights containing all the
information distributed to shareholders as part of its distribution of such
information to shareholders. A Participant shall have the opportunity to
exercise any such rights within the same time period as shareholders of the
Company. The Trustee shall vote the shares allocated to a Participant's
Account in accordance with the directions given by that Participant.
Unallocated shares and allocated shares for which no Participant direction is
given will be voted in proportion to the votes cast pursuant to the preceding
sentence.
Section 5.8 Tender or Exchange Offers Regarding Company Stock. As
soon as practicable after the commencement of a tender or exchange offer (an
"Offer") for shares of Company Stock, the Company shall use its best efforts
to cause each Participant (whose Account has allocated to it any shares
of Company Stock) to be advised in writing of the terms of the Offer, and to
be provided with forms by which the Participant may instruct the Trustee, or
revoke such instruction, to tender or exchange shares of Company Stock, to the
extent permitted under the terms of such Offer. The Trustee shall follow the
directions of each Participant. In advising Participants of the terms of the
Offer, the Company may include statements from the Board of Directors setting
forth its position with respect to the Offer. The giving of instructions by
a Participant to the Trustee to tender or exchange shares and the tender or
exchange thereof shall not be deemed a withdrawal or suspension from the Plan
or a forfeiture of any portion of such Participant's interest in the Plan
solely by reason of the giving of such instructions and the Trustee's
compliance therewith. Instructions by Participants pursuant to this Section
shall apply both to allocated shares and to unallocated shares held in the
Suspense Account. The number of shares as to which a Participant may provide
instructions shall be determined as follows:
(A) The Trustee shall determine the aggregate number of shares held by
the Plan, including both allocated and unallocated shares.
(B) The Company shall determine the number of shares allocated to each
Participant's Accounts as a percentage of the aggregate number allocated to
Accounts of all Participants.
(C) The Participant may provide instructions with respect to a number
of shares of Company Stock determined by applying the percentage in (B) to the
aggregate number of shares in (A). If the Participant directs tender or
exchange of the shares for which he may provide instructions, the Trustee
shall follow that instruction. The Trustee shall not tender or exchange the
shares for which a Participant may provide instructions if the Participant (i)
directs against their tender or exchange or (ii) gives no direction.
The determination of the number of shares as to which a Participant may
provide instructions shall be as of the close of business on the day preceding
the date on which the Offer is commenced or such earlier date as shall be
designated by the Company as the Company, in its sole discretion, deems
appropriate for reasons of administrative convenience. Any securities
received by the Trustee as a result of a tender or exchange of shares of
Company Stock shall be held, and any cash so received shall be invested in
short-term investments pending any reinvestment by the Trustee, as it may deem
appropriate, consistent with the purposes of the Plan. The rights extended
to Participants by this Section shall also apply to the Beneficiaries of
deceased Participants.
If a tender or exchange offer is limited so that all of the shares that
the Trustee has been directed to tender or exchange cannot be sold or
exchanged, the shares that each Participant directed be tendered or exchanged
shall be deemed to have been sold or exchanged in the same ratio that the
number of shares actually sold or exchanged bears to the total number of
shares that the Trustee was directed to tender or exchange. Shares sold or
exchanged at the direction of a Participant shall be deemed to come first out
of the shares allocated to the Participant's Accounts and only after all of
those shares have been sold or exchanged, out of the Unallocated Reserve.
For purposes of this Section, each Participant or Beneficiary who is
entitled to give such instructions shall be deemed a "named fiduciary" (within
the meaning of ERISA) with respect to such instructions.
ARTICLE VI. DISTRIBUTION
Section 6.1 Termination of Employment. Upon a Participant's
Termination of Employment, the entire amount credited to his or her Account
shall be distributed as follows:
(A) Distribution Upon Retirement or Disability. Upon Retirement or
Disability, a Participant's Account will be distributed at a time directed by
the Participant, but not before all allocations to the Participant's account
have been completed, subject to the following:
(1) However, if requested in writing by the Participant at least
60 days before the desired distribution, the Company will distribute the
current balance credited to the Participant's Account at any time after
Retirement or Disability that cash funds are available for distributing the
fractional share as provided in Section 6.1(D). In the event of such an
additional early distribution, the Company may require the Participant to
submit a payment in an amount determined by the Company, but not exceeding
$100, which payment will be used to offset Plan administration costs incurred
by the Company or the Trustee.
(2) Unless the Participant elects otherwise, distributions must
occur no later than the 60th day after the close of the Plan Year in which he
reaches age 65 or in which his Termination of Employment occurs, whichever is
later; provided, however, that if the amount of the payment to be made cannot
be determined by the later of said dates, payment may be made no later than
60 days after the earliest date on which the amount of such payment can be
ascertained.
(B) Distribution Upon Termination of Employment for Reasons other than
Retirement, Death or Disability. If a Participant's Termination of Employment
occurs for a reason other than the Participant's Retirement, Disability or
death, the Participant's Account will be distributed at a time directed by the
Participant, but not before all allocations to the Participant's Account have
been completed, subject to the following:
(1) Distributions must occur as soon as administratively feasible
after the date the Participant attains age 65.
(2) However, if the value of the Participant's Account is $3,500
or less, the distribution must occur promptly after allocations are completed,
and may not be deferred.
(C) Distribution Upon Death. If a Participant's Termination of
Employment is due to his death, his account will be distributed to his
Beneficiary in a single sum promptly after all allocations to the Account have
been completed. However, if the Beneficiary is the Participant's spouse, the
spouse may elect to defer the distribution, but not beyond whichever of the
following dates is applicable:
(1) If the Participant died after attaining age 55 or after
qualifying for disability retirement benefits under the Company-sponsored
defined benefit pension plan in which the Participant participates, April 1
following the calendar year in which the Participant would have attained age
70 1/2 if he or she had not died.
(2) If paragraph (1) does not apply to the Participant, the date
the Participant would have attained age 65 if he or she had not died (or as
soon as administratively feasible thereafter).
(D) Single Sum Distributions; Distributions In Kind. All distributions
under this Section will be made in a single sum consisting of whole shares of
Company Stock with cash in lieu of any fractional shares. Such cash may be
derived from other cash held by the Plan, in which case the fractional share
will be valued at the Investment Price. If cash is not available within the
Plan, shares may be sold and the proceeds used to make cash distributions in
lieu of fractional shares.
(E) Required Distributions At Age 70-1/2. Any amounts remaining in a
Participant's Account at the close of the calendar year in which he attains
age 70-1/2 shall be distributed to him not later than April 1 of the following
calendar year. Any amounts allocated to him thereafter shall be distributed
to him not later than April 1 following the close of the calendar year in
which the allocation occurs. Such distributions shall occur regardless of
whether the Participant has had a Termination of Employment.
(F) Code Section 401(a)(9) Requirements. Notwithstanding any provision
of the Plan to the contrary, distributions hereunder shall be made in
accordance with the minimum distribution requirements of Code section
401(a)(9), including the incidental death benefit requirements of Code section
401(a)(9)(G), and the regulations thereunder. Any provisions of the Plan that
are inconsistent with Code section 401(a)(9) and the regulations thereunder
shall be deemed to be inoperative.
Section 6.2 Effect of Re-Employment After Distribution Has Been Made
or Commenced. In the event that a former Participant is re-employed by an
Employer before full distribution is accomplished or commenced, distribution
of the Account shall be suspended and the undistributed remainder in such
Account shall continue to be held until employment is again terminated, it
being the intent hereof that no distribution shall be made while a Participant
is maintaining an employment relationship with an Employer. Notwithstanding
the foregoing and the provisions of Section 3.2, if a retired Employee is
re-employed on a part-time basis whereby the Employee is scheduled to work
less than 1,000 hours per calendar year, distribution of such Employee's
Account will not be suspended and such Employee shall not be eligible to
participate in the Plan based on such part-time re-employment.
Section 6.3 Withdrawals of Common Stock.
(A) A Participant may withdraw full shares of Company Stock allocated
to the subaccount maintained pursuant to Section 5.1(D) at any time to the
extent such shares were purchased with the Employee's own contributions.
Shares purchased with dividends or other income are not subject to
withdrawal under this subsection, but may be withdrawn as provided in
subsection (D).
(B) After the Participant has withdrawn all shares available for
withdrawal under subsection (A), the Participant may withdraw full shares of
Company Stock allocated to the subaccount maintained pursuant to Section
5.1(B).
(C) After the Participant has withdrawn all shares available for
withdrawal under subsections (A) and (B), the Participant may withdraw full
shares of Company Stock allocated to the subaccount maintained pursuant to
Section 5.1(E), but only to the extent such shares were purchased with the
Employee's own contributions. (Shares purchased with dividends or other
income may not be withdrawn.)
(D) Subject to the restrictions described in this subsection, a
Participant who has withdrawn or requested withdrawal of all amounts available
pursuant to subsections (A), (B), and (C) may withdraw full shares of Company
Stock credited to the subaccount established for the Participant under Section
5.1(D) which were acquired as a result of the reinvestment of dividends or
other income on the shares of stock allocated to such subaccount. Any such
withdrawal must be on account of an immediate and heavy financial need of the
Participant and must be necessary to satisfy such financial need. A
withdrawal shall be deemed to constitute an "immediate and heavy financial
need" if the Company determines that such withdrawal is on account of:
(1) Expenses for medical care described in Code Section 213(d)
incurred by the Participant, the Participant's spouse or dependent (as defined
in Code Section 152), or expenses necessary for such persons to obtain such
medical care;
(2) Purchase (excluding mortgage payments) of a principal residence
for the Participant;
(3) Payment of tuition and related educational fees (not room and
board) for the next 12 months of post-secondary education for the Participant
or the Participant's spouse, children or dependents (as defined in Code
Section 152);
(4) The need to prevent the eviction of the Participant from the
Participant's principal residence or foreclosure on the mortgage on that
residence; or
(5) Such other events as may be permitted pursuant to regulations
promulgated by the Internal Revenue Service.
A withdrawal will not be treated as necessary to satisfy an immediate and
heavy financial need of a Participant to the extent the amount of such
withdrawal exceeds the amount the Company determines is required to meed the
financial need or to the extent the Company determines that such need may be
satisfied from other resources that are reasonably available to the
Participant. In making this determination, the Company may rely upon a
Participant's written representation that the financial need cannot reasonably
be relieved:
(A) through reimbursement or compensation by insurance or
otherwise;
(B) by liquidation of the Participant's assets, to the extent
such liquidation would not itself cause an immediate and heavy financial need;
(C) by cessation of the Participant's Pre-Tax or Voluntary
Contributions; or
(D) by other distributions or nontaxable (at the time of the
loan) loans from plans maintained by the Employer or by any other employer,
or by borrowing from commercial sources on reasonable commercial terms.
Absent such a representation, a withdrawal will be permitted only if the
Participant shows to the satisfaction of the Company that the Participant does
not have the financial ability to meet the financial hardship with other
reasonable means. Such a showing shall not require a Participant to: (i)
first withdraw his or her interest in another retirement plan or individual
retirement account to the extent there is a tax consequence or penalty, (ii)
sell or encumber the Participant's principal residence or the furnishings
thereof, (iii) sell or encumber other assets if doing so would increase the
amount of the financial need. A hardship withdrawal request shall be
submitted in writing signed by the Participant or his legal representative,
shall describe fully the circumstances which are deemed to justify the payment
and the amounts necessary to alleviate the hardship, and shall be accompanied
by such other documentation as may be requested by the Company. Any
determination made by the Company with regard to a withdrawal pursuant to this
section shall be final and binding upon the Participant.
(E) The Company may require that any withdrawal pursuant to this Section
6.3 shall be made by executing a request in writing on a form provided by the
Company for such purpose.
Section 6.4 Diversification Options.
(A) Distribution Election for Post-1986 Shares. A limited distribution
to Qualified Participants is available under this Section 6.4 during the
Qualified Election Period, subject to the following provisions of this
section.
(B) Definitions. For the purpose of this Section 6.4, the following
definitions apply:
(1) "Annual Election Period" refers to December 31 through March
30 of each Plan Year.
(2) "Qualified Election Period" means the six-Plan Year period
beginning the later of (a) the Plan Year after the Plan Year in which the
Participant attains age 55; or (b) the Plan Year after the Plan Year in which
the Participant first becomes a Qualified Participant.
(3) "Qualified Participant" means a Participant who has attained
age 55 and who has completed at least ten years of participation in the Plan.
(C) Annual Withdrawal Election. Each Qualified Participant shall be
permitted to withdraw whole shares of Company Stock allocated to the
Participant's Basic Account due to Employer contributions after 1986, plus any
income allocated to the Basic Account after 1986, including amounts
contributed for a Plan Year and allocated to the Basic Account within 90 days
after the end of the Plan Year. The withdrawal under this Section 6.4 for a
Qualified Participant cannot exceed 25 percent of the post-1986 Company Stock
in the Participant's Basic Account. In the case of the election year in which
the Qualified Participant can make his last election, "50%" shall be
substituted for "25%" in the preceding sentence. The maximum percentage that
may be distributed for any one Plan Year shall be reduced by any amounts
previously distributed pursuant to this section.
(D) Election Requirements. The Participant's election to withdraw, or
any revocation of such an election, must be delivered in writing to the
Company on a form provided by the Company within the applicable Annual
Election Period during the Participant's Qualified Election Period. No
revocation is effective unless delivered before the end of the Annual Election
Period in which an election to withdraw was made. The Company will not make
an initial distribution under this Section unless the shares in the
Participant's Basic Account as of the Investment Date preceding the applicable
Annual Election Period exceed a value of $500. In addition, the first
distribution under this Section pursuant to an election which requests less
than 25 percent of the post-1986 Basic Account must be of a value of at least
$500. The value shall be determined at the Investment Price on the Investment
Date last preceding the beginning of the applicable Annual Election Period.
Within 90 days after the end of each Annual Election Period the Company shall
distribute shares of Company Stock, rounded to the nearest whole share, to
each Qualified Participant requesting a withdrawal meeting the requirements
of this Section 6.4 provided that the Company will not make such a
distribution to a Participant who is no longer an Employee, but if it
accidentally does so, the Company shall not be required to seek a return of
the distribution, but the Company will allow the former Employee to return the
distribution within 60 days after the distribution is received by the former
Employee.
(E) Sequence of Distribution. Any shares withdrawn from a Participant's
Basic Account pursuant to this Section 6.4 shall, to the extent possible, be
drawn from the subaccount in which shares acquired with Trust income are
recorded. No shares will be withdrawn from a subaccount reflecting shares
purchased with Employer contributions unless the whole shares allocated to the
income subaccount are not sufficient to complete the distribution.
Section 6.5 Rollovers and Transfers to Other Qualified Plans.
Notwithstanding any provision of the Plan to the contrary that would otherwise
limit a distributee's election under this Section, a distributee may elect,
at the time and in the manner prescribed by the Company, to have any portion
of an eligible rollover distribution equal to or greater than $200 paid
directly to another eligible retirement plan specified by the distributee in
a direct rollover. The following definitions shall be used in administering
the provisions of this Section.
(A) Eligible rollover distribution: An eligible rollover distribution
is any distribution of all or any portion of the balance to the credit of the
distributee, except that an eligible rollover distribution does not include:
any distribution that is one of a series of substantially equal periodic
payments (not less frequently than annually) made for the life (or life
expectancy) of the distributee or the joint lives (or joint life expectancies)
of the distributee and the distributee's designated Beneficiary, or for a
specified period of ten years or more; any distribution to the extent such
distribution is required under Code section 401(a)(9); and the portion of any
distribution that is not includable in gross income (determined without
regard to the exclusion for net unrealized appreciation with respect to
employer securities).
(B) Eligible retirement plan: An eligible retirement plan is an
individual retirement account described in Code section 408(a), an individual
retirement annuity described in Code section 408(b), an annuity plan described
in Code section 403(a), or a qualified trust described in Code section 401(a),
that accepts the distributee's eligible rollover distribution. However, in
the case of an eligible rollover distribution to the surviving spouse, an
eligible retirement plan is limited to an individual retirement account or
individual retirement annuity.
(C) Distributee: A distributee includes an employee or former employee.
In addition, the employee's or former employee's surviving spouse or former
spouse who is the alternate payee under a qualified domestic relations order,
as defined in Code section 414(p), are distributees with regard to the
interest of the spouse or former spouse.
(D) Direct rollover: A direct rollover is a payment by the Trustee to
the eligible retirement plan specified by the distributee.
(E) Effective date: This section applies to distributions on or after
January 1, 1993.
ARTICLE VII. BENEFICIARIES
Section 7.1 Surviving Spouse as Required Beneficiary. If a
Participant is married at the time of death, any undistributed amount credited
or to be credited to the Participant's Account shall be distributed to such
surviving spouse unless the Participant has designated another Beneficiary
under Section 7.2 with the contemporaneous or later written consent to such
designation by the surviving spouse acknowledging the effect of such consent
before a notary public. In the absence of such consent, the designation shall
be void upon the death of the Participant. Unless the filed consent
specifically permits further changes in a designated Beneficiary, a
Participant who has designated a Beneficiary with the consent of the spouse
may not subsequently change that Beneficiary without the further consent of
the spouse.
Section 7.2 Other Beneficiaries. Subject to the requirements of
Section 7.1, a Participant may designate a Beneficiary (the Beneficiary may
be more than one person or entity) to whom the balance of the Participant's
Account is to be distributed in the event of the Participant's death prior to
the full receipt thereof. Such a designation may, without notice to the
Beneficiary, be changed or revoked by the Participant at any time. The
designation of any Beneficiary and any change or revocation thereof shall be
made in writing and in a form prescribed by the Company, and delivered to the
Company prior to the death of the Participant. If no Beneficiary is
designated or a designation is revoked in whole or in part, or if a
designated Beneficiary shall not survive to receive all payments due
hereunder, all or such part of the Participant's Account as has not been
distributed, shall be payable to the first class of the following classes
of automatic Beneficiaries then surviving and (except in the case of surviving
issue) in equal shares if there are then more than one in each class:
(1) Participant's surviving spouse;
(2) Participant's surviving issue per stirpes;
(3) Participant's surviving parents;
(4) Participant's surviving brothers and sisters;
(5) Executor or administrator of Participant's estate.
For the purpose of the foregoing, "per stirpes" means in equal shares among
living children and the issue of deceased children, the latter taking by right
of representation, and issue means all persons who are descended from the
person referred to, either by legitimate birth to or legal adoption by such
person, or any of such person's legitimately born or legally adopted
descendants. The foregoing provision shall not preclude the designation of
a Beneficiary's estate or other conditional Beneficiaries in the event the
first designated Beneficiary does not survive to receive full payment.
Notwithstanding the foregoing, when the Beneficiary is the surviving spouse,
the contingent Beneficiaries of the Participant will not be applicable
as to any balance in the Account upon death of the surviving spouse if the
surviving spouse prior to death delivers to the Company a specific written
designation of Beneficiary in a form prescribed by the Company.
Section 7.3 Presumptions. If a Beneficiary, including a surviving
spouse, and the Participant die under circumstances where it is not known who
died first, it will be presumed for the purpose of this Article VII, that the
Participant survived the Beneficiary. If the Administrator is unable to
locate an automatic or designated Beneficiary (other than a surviving spouse)
within six months after death, or within 60 days prior to the contemplated
initial distribution of the decedent's Account, whichever date shall last
occur, the Beneficiary as of that date shall be deemed to have waived the
Beneficiary's right to receive a distribution from the Plan. The distribution
which would otherwise have been made to such Beneficiary shall then be made
from the Plan to the contingent Beneficiary(ies) then surviving as though the
missing Beneficiary did not survive the decedent. A surviving spouse who
cannot be located within two years of the decedent's death shall be presumed
to have not survived the decedent, and distribution of the decedent's
Account shall be made to the contingent Beneficiary(ies) surviving at the time
of distribution.
Section 7.4 Waiver of Interest. If a Beneficiary, including a
surviving spouse, waives all right to receive distribution from the Plan in
writing delivered to the Administrator, the distribution shall be made to the
contingent Beneficiary(ies) surviving at the time of distribution. In
addition, if the Beneficiary's social security number or other information
required for distribution is not delivered to the Administrator within the
time designated (not less than 30 days) in a written notice sent by the
Administrator to the last known address of the Beneficiary, the Beneficiary
shall be deemed to have waived the Beneficiary's right to receive distribution
from the Plan.
ARTICLE VIII. ADMINISTRATIVE PROVISIONS
Section 8.1 Company as "Named Fiduciary" May Delegate Powers and
Authorities. For the purposes of ERISA, the Company shall be the "Named
Fiduciary" and "Administrator" of the Plan. Except as expressly otherwise
provided herein, the Company shall control and manage the operation and
administration of the Plan and make all decisions and determinations incident
thereto. In carrying out its Plan responsibilities, the Company shall have
discretionary authority to construe the terms of the Plan. The Company may
delegate its powers and authorities under the Plan and may designate any
person or persons to exercise such powers and authorities in its behalf. In
the delegation of such powers and authorities, the Company may authorize or
limit the authority of the recipient of the delegated powers and authorities
to redelegate such powers and authorities to another person or persons. The
Company shall appoint a Committee with authority to deny or grant a request
for withdrawal of common stock pursuant to Section 6.3. Such Committee may be
contacted through the officer in charge of the Human Resources Department of
the Company.
Section 8.2 Facility of Payment. In case of incompetency of a
Participant (including an Alternate Payee) or Beneficiary entitled to receive
any distributions under the Plan, and if the Company shall be advised of the
existence of such condition, the Company shall direct distribution to any one
of the following:
(1) To the duly appointed guardian or other legal representative
of such Participant or Beneficiary;
(2) To any person designated as a Beneficiary by the Participant
if such Beneficiary resides in the same household as the Participant;
(3) To a person or institution entrusted with the care and
maintenance of the incompetent Participant or Beneficiary, provided such
distributed interest will be used for the best interest and assist in the care
of such Participant or Beneficiary, and provided further, that no prior claim
for said payment has been made by a legal representative of such Participant
or Beneficiary.
Any distribution made in accordance with the foregoing provisions of this
Section shall constitute a complete discharge of any liability or obligation
on the part of the Company or the Trustee under the Plan and Trust.
Section 8.3 Spendthrift Trust and Qualified Domestic Relations Order.
(A) Benefits Unassignable. Except as hereafter provided in this Section
8.3, no Participant or Beneficiary, shall have any transferable interest in
any Account nor shall any Participant or Beneficiary have any power to
anticipate, alienate, dispose of, pledge or encumber the same while in the
possession or control of the Trustee, nor shall the Trustee or the Company
recognize any assignment thereof, either in whole or in part, nor shall any
account herein be subject to attachment, garnishment, execution following
judgment, or other legal process while in possession or control of the
Trustee. The power to designate Beneficiaries to receive the Account of a
Participant in the event of the Participant's death shall not permit,
or be construed as to permit such power or right to be exercised so as thereby
to anticipate, pledge, mortgage, or encumber his or her Account, and the right
of a Participant to obtain or seek a withdrawal under Section 6.3 shall not
permit, or be construed to permit, such a right to be exercised by a receiver,
trustee or other person or entity lawfully representing the Participant except
as provided by Section 8.2 for the purpose of making distributions to an
incompetent former Participant, alternate payee or Beneficiary.
(B) Payment Pursuant to a QDRO. Subsection 8.3(A) above shall not apply
to any amounts payable with respect to a Participant pursuant to any
"qualified domestic relations order" as such term is defined in Code Section
414(p). The Company shall establish reasonable written procedures to
determine the qualified status of domestic relations orders and to administer
distributions pursuant to such qualified orders. The Company may defer
distributions from an account subject to a domestic relations order
pending determination that the order is qualified. For purposes of any such
order approved by the Company prior to the adoption of this amended and
restated Plan document, the provisions of Section 8.3 of the Plan as in effect
immediately prior to such adoption shall be deemed to remain in effect.
Section 8.4 Source of Payment. Benefits under this Plan shall be
payable only out of the Trust Fund. No persons shall have any rights under
the Plan with respect to the Trust Fund, or against the Trustee or the
Company, except as specifically provided for herein.
Section 8.5 Company to Pay Administration Expenses. The Company shall
pay all expenses (not including any tax obligation of the Trust) incurred in
the administration of the Plan, including the compensation and expenses of the
Trustee, if any. If a corporate trustee shall be acting hereunder, the
corporate trustee shall be entitled to receive compensation for its services
as Trustee hereunder as agreed from time to time between the Trustee and the
Company. Any individual trustee who is an Employee of the Company or other
Employer shall receive no compensation for services. Other individual
trustees shall likewise serve without compensation except by specific
agreement with the Company. However, in any event the Trustee (whether
corporate or individual) shall be entitled to receive reimbursement for
reasonable expenses, fees, costs, and other charges incurred on account of
performing duties under the Plan and Trust. Such reimbursement may be paid
directly by the Company to the Trustee, but if not so paid, the same shall be
payable from and out of the Trust Fund.
Section 8.6 Record Address. Each individual or entity with an actual
or potential interest in an existing Account shall file and maintain a current
record address with the Payroll Department of the Employer. Such record
address will be furnished by the Employer to the appropriate personnel of the
Company. Mailings by the Company to such record address fulfills any
obligation on the part of the Company to provide required information to
Participants, including former Employees and Beneficiaries, in regard to the
Plan. If no record address is filed, it will be presumed that the address
used by the Company in forwarding statements of a Participant's Account
balance is the record address.
Section 8.7 Required Information to be Furnished. Participants and
Beneficiaries who may become entitled to any payment hereunder shall furnish
to the Company such information as the Company considers necessary or
desirable for purposes of administering the Plan, and the provisions of the
Plan with respect to any payment hereunder are conditioned upon the prompt
receipt by the Company of such true, full, and complete information as the
Company may reasonably request.
Section 8.8 Company Rules. Rules consistent with the provisions of
the Plan may be adopted by the Company for the purpose of administering the
Plan.
Section 8.9 Claims Procedure.
(A) If a Participant or other person with a claim to benefits under the
Plan makes a written request for a Plan benefit, the Company shall treat it
as a claim for benefit. All claims for benefits under the Plan should be sent
to the officer in charge of the Human Resources Department of the Company.
If the Company determines that any individual who has claimed a right to
receive benefits under the Plan is not entitled to receive all or any part of
the benefits claimed, it will inform the claimant in writing of its
determination and the reasons therefore in terms calculated to be understood
by the claimant. The notice shall make specific reference to the pertinent
Plan provisions on which the denial is based, and describe any additional
material or information, if any, necessary for the claimant to perfect the
clam and the reason any such additional material or information is necessary.
Such notice shall, in addition, inform the claimant what procedure the
claimant should follow to take advantage of the review procedures set forth
below in the event the claimant desires to contest the denial of the claim.
(B) The claimant may within 90 days thereafter submit, in writing to the
officer in charge of the Company's Human Resources Department, a notice that
the claimant contests the Company's denial of claim and desires a further
review. The Company shall within 60 days thereafter review the claim and
authorize the claimant to appear personally and review pertinent documents and
submit issues and comments relating to the claim to the persons responsible
for making the determination on behalf of the Company. The Company will
render its final decision with the specific reasons therefor in writing and
will transmit it to the claimant within 60 days of the written request for
review, unless the claimant and the Company have agreed to an extension of
time.
(C) No person claiming a benefit under the Plan may initiate a civil
action regarding the claim until all steps under the claims procedure
(including appeals) have been completed.
ARTICLE IX. AMENDMENT AND TERMINATION
Section 9.1 Amendment. The Company reserves the right to amend the
Plan at any time. Any Plan amendment must be executed by two principal
officers of the Company and attested by its Secretary or an Assistant
Secretary. No amendment shall reduce or divest the Account of any Participant
without the Participant's consent unless the same shall be adopted in order
to comply with the applicable provisions of ERISA, the provisions of the Code,
and regulations and rulings thereunder, affecting the tax qualified status of
the Plan and the deductibility of Employer contributions thereto, or to comply
with the provisions of any salary or wage stabilization law, regulations,
orders, or directives that may now or hereafter be applicable.
Section 9.2 Discontinuance of Contributions and Termination of the
Plan. The Company reserves the right, by action of its Board of Directors,
to discontinue its contributions to this Plan and to terminate the Plan in its
entirety.
Section 9.3 Limitations. No power of amendment or of full or partial
termination may be exercised so as to discriminate in favor of Highly
Compensated Employees or to permit any part of the assets of the Plan to be
used for or diverted to purposes other than for the exclusive benefit of
Participants or their Beneficiaries prior to the satisfaction of all
liabilities with respect to such Participants and their Beneficiaries under
this Plan.
Section 9.4 Merger, Etc., with Another Plan. In case of merger or
consolidation of this Plan with, or transfer of the assets and liabilities of
this Plan to, any other plan, each Participant shall be entitled to a benefit
immediately after the merger, consolidation, or transfer which is not less
than the benefit such Participant would have been entitled to receive
immediately before the merger, consolidation, or transfer if this Plan had
then terminated.
Section 9.5 Election to Participate by New Employer. A subsidiary
corporation acquired or organized after the Effective Date which otherwise
falls within the definition of Employer in Article I and which elects to
participate in the Plan shall become an Employer hereunder as of the effective
date of its election. Such a subsidiary corporation may elect to participate,
either by action of its board of directors or by written action of two or more
of its officers. Any such election shall be contingent upon the approval of
the Board of Directors or the written approval of any two principal officers
of the Company. The Employees of such subsidiary corporation shall, upon the
effective date of such election, become
Employees hereunder and shall become Participants as provided in Section
3.1(C). The election to participate in this Plan and any related merger with
this Plan of a pre-existing plan of such subsidiary corporation may be
contingent upon such subsidiary corporation or the Company, as Plan
Administrator, receiving a determination from the Internal Revenue Service
that the Plan and related Trust Agreement continue thereafter as a qualified
plan and exempt trust under Section 401 and Section 501 of the Code.
ARTICLE X. TRUSTEE
Section 10.1 Trust Agreement. The Company shall enter into a Trust
Agreement with a Trustee to be selected by the Company who shall serve at the
pleasure of the Company. The Trust Agreement shall provide, among other
things, for a Trust Fund to which all contributions shall be paid,
and the Trustee shall have such rights, powers, and duties as are set forth
in the Trust Agreement. All assets of the Trust Fund shall be held, invested,
and reinvested in accordance with the provisions of the Trust Agreement and
the Plan.
Section 10.2 Trust Investments. The Trustee shall be responsible
solely for the investment and safekeeping of the assets of the Trust Fund and
shall have no responsibility for the operation or administration of the Plan,
except as expressly provided herein. If the Trustee is a bank or trust
company supervised by the United States or a State, assets of the Trust Fund
may be invested in deposits which bear a reasonable rate of interest with such
bank or trust company to the extent they are not required by the Plan to be
invested in Company Stock. The Trustee shall have the authority to pay moneys
to or upon the order of the Company for the use of the Plan upon requisition
drawn upon the Trustee.
Section 10.3 Exclusive Benefit of Participants. The Company
contributions shall be held by the Trustee for the benefit of the Participants
and their Beneficiaries, and no part of such contributions and no part of the
respective Participant's Accounts shall be recoverable by the Company, or used
for, or diverted to purposes other than for the exclusive benefit of the
Participants and their Beneficiaries in accordance with the provisions of the
Plan.
Section 10.4 Borrowed Funds. The Trustee, the Company, or both, may
enter into loan agreements where the proceeds of the loan shall be applied by
the Trustee, no later than the thirtieth day after receipt of the proceeds,
to purchase Company Stock or to repay a prior loan which was applied to
the acquisition of Company Stock. Purchases direct from the Company shall be
made at a price not in excess of the average of the high and low prices of
Company Stock on the date of purchase (or if the date of purchase is not a
trading date, the price on the last preceding trading date) as reported in the
Wall Street Journal. Any such loan and related contracts must be primarily
for the benefit of Participants and their Beneficiaries, and shall be subject
to the following terms and conditions:
(1) The interest rate respecting such loan shall not exceed a
reasonable rate of interest.
(2) The shares of Company Stock acquired with the proceeds of a
loan, which proceeds may include interest earned on cash proceeds of the loan
pending investment in shares, shall be held in a Suspense Account and not
allocated to Accounts until released from the Suspense Account in accordance
with Section 10.6.
(3) The only assets of the Trust Fund which may be given as
collateral for the loan are the shares of Company Stock acquired with the loan
proceeds (or shares acquired with a prior loan repaid with the proceeds of
current loan) and held in the Suspense Account. No person entitled to payment
under such loan shall have any right to assets of the Trust Fund other than
the above referred to stock in the Suspense Account and dividends or other
income thereon, and any contributions made by the Company with direction for
the Trustee to apply toward repayment of the loan. In the event of default
on such loan, the value of Trust Fund assets transferred in satisfaction of
the loan must not exceed the amount of default.
Section 10.5 Dividends Applied to Loan Repayment. When a loan balance
is outstanding, dividends paid on Company Stock that was acquired with the
proceeds of the loan (other than dividends on shares that have been allocated
to inactive Participants) shall be applied to the repayment of the Loan.
Dividends on shares of such stock which are held in the Suspense Account shall
be applied to any scheduled loan payment before dividends on shares which have
been allocated to Participant's Accounts. To the extent dividends on shares
of Company Stock that were acquired with the proceeds of a loan are
insufficient to discharge in full any scheduled loan payment, then dividends
on shares of Company Stock that were not acquired with the proceeds of the
loan (other than dividends on shares that have been allocated to inactive
Participants) shall be applied to such payment as follows:
(A) Dividends paid on shares of Company Stock that were acquired by the
Plan before August 5, 1989, shall be applied to the loan payment; and
(B) Dividends paid on such shares of Company Stock that were acquired
by the Plan after August 4, 1989, shall be applied to the loan payment to the
extent directed by the Company.
Dividends applied to the repayment of a loan shall first be applied to any
scheduled payment of interest and then to any scheduled payment of principal
(to the extent the Trustee shall elect to prepay a loan, such prepayment shall
be treated as a scheduled payment for the purposes of this Section). To the
extent dividends on shares that would otherwise be applied toward the
repayment of the loan are in excess of a scheduled loan payment, the Trustee
shall invest such excess dividends in interest bearing accounts or in
similar short-term investments for credit to the Suspense Account, unless
directed by the Company to acquire additional shares of Company Stock for
credit to the Suspense Account. Any short-term investments shall then be
applied to subsequent loan payments, provided that if such investments have
not been applied prior to the ninetieth day following the end of the Plan Year
in which such dividends were paid, the Trustee shall apply the balance of such
investments to the purchase of Company Stock. Such stock will then be
allocated to Accounts of Participants as follows: (i) shares acquired due to
dividends paid on stock that was allocated to a Participant's Account shall
be allocated to that Participant's Account as a dividend; and (ii) shares
acquired due to dividends paid on stock held in the Suspense Account shall be
allocated as a Company contribution under Section 5.2. (The preceding
sentence is applicable to Plan Years beginning on or after December 31, 1994;
allocations for prior years will be handled as provided in the Plan as
previously in effect.) The Trustee shall not apply income from investments
or Company contributions toward repayment of a loan until all dividends
available for such purpose have been so applied.
Section 10.6 Release from Suspense Account and Allocation of Shares.
All shares of Company Stock held in the Suspense Account shall be released
from the Suspense Account, and allocated to Accounts of Participants, as
follows:
(A) Release of Shares from Suspense Account. For each Plan Year during
the duration of the loan the minimum number of shares of Company Stock
acquired with the proceeds of such loan and released from the Suspense Account
shall equal the number of shares acquired with the loan held at the beginning
of the Plan Year (or when the loan originated if later) multiplied by a
fraction. The numerator of the fraction is the amount of principal paid to
the lender during the Plan Year, and the denominator of the fraction is the
sum of the numerator plus the principal to be paid for all future years. The
number of future years under the loan must be definitely ascertainable and
must be determined without taking into account any possible extensions or
renewal periods. However, the number of shares released will not be less than
the number needed to make the allocations in (B). In applying the provisions
of this Section 10.6(A), the following special rules shall apply:
(1) The loan must provide for annual payments of principal and
interest at a cumulative rate that is not less rapid at any time than level
annual payments of such amounts for ten years;
(2) Interest included in any payment shall be disregarded only to
the extent that it does not exceed the interest that would be payable under
standard loan amortization tables; and
(3) If the loan is renewed, extended, or refinanced, the sum of the
expired duration of the loan and the renewal, extension or new loan period
shall not exceed ten years.
(B) Shares Allocated to Replace Dividends. If dividends from a
Participant's Account are used to make loan payments, said Account will
receive an allocation of a number of shares of Company Stock equal to the
shares which would have been acquired if the dividends had been used to
purchase Company Stock for whichever of the following prices is less:
(1) The weighted average price at purchase of the shares of Company
Stock acquired with the loan proceeds.
(2) The current market price of shares of Company Stock at the time
the dividends were paid.
Allocations at the price described in (B)(1) shall be made as soon as
administratively feasible after the dividends are applied to make a loan
payment. Any additional allocation required at the price described
in (B)(2) shall be made annually. If the shares released under (A) are
insufficient to make the foregoing allocation, the balance will be derived
from Company contributions.
(C) Allocation of Remaining Shares. Any remaining shares of Company
Stock released from the Suspense Account after all allocations under (B) have
been completed will be allocated as Company contributions as provided in
Section 5.2.
(D) Transition Rules. The foregoing allocation rules apply to Plan
Years beginning on and after December 31, 1994. Allocations for prior years
will be handled as provided in the Plan as previously in effect.
Section 10.7 Non-Tradable Company Stock. If at the time of
distribution, shares of Company Stock distributed from the Trust Fund are not
"readily tradeable on an established market" within the meaning of Code
section 409(h) and the regulations thereunder, such shares shall be subject
to a put option under which all or any part of the distributed shares may be
sold to the Company. The put option shall be subject to the following
conditions:
(1) The put option shall be exercisable only by the distributee
(whether the Participant or a Beneficiary), any person to whom the Company
Stock has passed by gift from the distributee and any person (including an
estate or the distributee from an estate) to whom the Company Stock passed
upon the death of the distributee (hereinafter referred to as the "holder").
(2) The put option must be exercised during the 60 day period
beginning on the date the Company Stock is first distributed by the Plan, or
during a 60 day period designated by the Company during the Plan Year
following the Plan Year in which the distribution occurred.
(3) To exercise the put option, the holder shall notify the Company
in writing that the put option is being exercised.
(4) Within 30 days after receipt of such notice, the Company shall
tender to the holder a cash payment equal to the fair market value of the
Company Stock, said value to be determined as of the Plan valuation date
coincident with or immediately preceding exercise of the put option.
(5) The Plan is not bound to purchase Company Stock pursuant to the
put option, but the Trustee may cause the Plan to assume the Company's rights
and obligations to acquire Company Stock under the put option.
(6) The put option extended under this section shall continue in
force notwithstanding that a loan is repaid or that this Plan ceases to be an
employee stock ownership plan.
(7) Except as provided in this section, no Company Stock acquired
with the proceeds of a loan may be subject to a put, call or other option, or
any buy-sell or similar arrangement, while held by or distributed from the
Plan.
ARTICLE XI. MISCELLANEOUS PROVISIONS
Section 11.1 No Contract of Employment. Nothing contained in this Plan
shall be construed as a contract of employment between an Employer and any
Employee or as a right of any Employee to be continued in the employment of
an Employer or as a limitation on the right of an Employer to discharge
any Employee with or without cause.
Section 11.2 No Guarantees on Value. Neither the Company nor the
Trustee guarantees the Trust Fund in any manner against loss or depreciation.
Section 11.3 Fiduciary Responsible Only For Own Acts. The Company, the
Board of Directors, the Committee, or any other committee assigned by the
Company to perform all or some of the administration of the Plan, the Trustee,
and any person who is deemed to be a fiduciary under the Plan, will not be
liable for a breach of fiduciary responsibility of another fiduciary under the
Plan except to the extent (1) it shall have participated knowingly in, or
knowingly undertaken to conceal, an act or omission of such fiduciary, knowing
such act or omission was a breach of such fiduciary's responsibilities; (2)
it shall have, through a breach of its fiduciary responsibilities, enabled
such fiduciary to commit a breach of its fiduciary responsibilities; or (3)
it shall have knowledge of a breach of fiduciary responsibilities by such
fiduciary, unless it has made a reasonable effort to remedy the breach.
Section 11.4 Company Indemnification. Employees of the Company
designated by the Company to perform acts under the Plan shall be indemnified
by the Company or from proceeds under insurance policies purchased by the
Company against any and all liabilities arising by reason of any act,
or failure to act, made in good faith pursuant to the provisions of the Plan,
including expenses reasonably incurred in defense of any claim relating
thereto.
Section 11.5 Laws of Minnesota. The Plan shall be governed by, and
construed in accordance with the laws of the State of Minnesota, except to the
extent such laws are preempted by ERISA.
Section 11.6 Securities Regulations. The Company reserves the right
to withhold authorization of any distribution of an Account or to restrict the
transfer of any shares of Company Stock distributed from an Account to the
extent necessary to satisfy the requirements of any Federal or State law or
regulation applicable to securities of the Company. In compliance with the
Securities Act of 1933, no contributions from Participants will be accepted
unless a Securities and Exchange Commission Registration Statement, if a
Registration Statement is required, is effective for the issuance of
securities to be issued for such contributions.
Section 11.7 Contributions Conditioned on Tax Deductions. All Company
contributions to the Plan are expressly conditioned upon their being
deductible under Section 404 of the Code. In addition, the Company's
contributions under Section 4.1, is an amount up to the deductions claimed on
the Company's United States corporate income tax return pursuant to Code
section 404(k), are conditioned upon receiving the deduction. To the extent
that a deduction claimed for any Company contribution, or any deduction
pursuant to Code section 404(k) is subsequently disallowed, the Company may
withdraw its contribution conditioned on the disallowed deduction within one
year after the date of disallowance.
Section 11.8 Top Heavy Contingency. The provisions of Appendix A
relating to a top heavy contingency shall apply if the Plan should ever become
a Top Heavy Plan as defined in such Appendix for any Plan Year.
Section 11.9 Tax Credit Rules. The Plan will comply with any
provisions of the Code or regulations thereunder with respect to tax credit
shares contributed in the past in order to qualify for an investment or
payroll tax credit.
APPENDIX A
TOP HEAVY CONTINGENCY
Notwithstanding any of the foregoing provisions of the Plan, if, after
applying the special definitions set forth in Section 1 of this Appendix, this
Plan is determined under Section 2 of this Appendix to be a Top Heavy Plan for
a Plan Year, then the special rules set forth in Section 3 of this Appendix
shall apply. For so long as this Plan is not determined to be a Top Heavy
Plan, the special rules in Section 3 of this Appendix shall be inapplicable
to this Plan.
Section 1. Special Definitions. Terms defined in the Plan shall have
the same meanings when used in this Appendix. In addition, when used in this
Appendix, the following terms shall have the following meanings:
1.1 Aggregated Employers -- the Employer and each other corporation,
partnership or proprietorship which is a "predecessor" to the Employer, or is
under "common control" with the Employer, or is a member of an affiliated
service group that includes the Employer, as those terms are defined in
section 414(b), (c) or (m) of the Code.
1.2 Aggregation Group -- a grouping of this plan and each other
qualified pension, profit sharing or stock bonus plan, regardless of whether
the plan has terminated (including any qualified defined benefit plan which,
during the five-year period ending on the Determination Date, has or has had
any accrued benefits) of the Aggregated Employers:
(a) in which a Key Employee is a Participant; and
(b) which is required to be taken into account for this Plan to satisfy
the qualification requirement that this Plan cover a nondiscriminatory group
of employees (i.e., either the so-called "70% test," the "70%/80% test" or the
nondiscriminatory classification test"); and
(c) which is not included in paragraph (a) or (b) above, but which the
Employer elects to include in the Aggregation Group and which, when included,
would not cause the Aggregation Group to fail to satisfy the qualification
requirement that the Aggregation Group of plans cover a nondiscriminatory
group of employees (i.e., either the so-called "70% test", the "70/80% test"
or the "nondiscriminatory classification test").
1.3 Determination Date -- for the first (1st) plan year of a plan, the
last day of such first (1st) plan year, and for each subsequent plan year, the
last day of the immediately preceding plan year.
1.4 Five Percent Owner -- for each Aggregated Employer that is a
corporation, any person who owns (or is considered to own within the meaning
of the Shareholder Attribution Rules) more than five percent (5%) of the
outstanding stock of the corporation or stock possessing more than five
percent (5%) of the total combined voting power of the corporation, any person
who owns more than five percent (5%) of the capital interest or the profits
interest in such Aggregated Employer. For the purposes of determining
ownership percentages, each corporation, partnership and proprietorship
otherwise required to be aggregated shall be viewed as a separate entity.
1.5 Key Employee -- each Participant (whether or not then an employee)
who at any time during a plan year (or any of the four preceding plan years)
is:
(a) an officer of any corporate Aggregated Employer having annual
Testing Wages for any such plan year in excess of 150% of the amount in effect
under Code section 415(c)(1)(A) for any such plan year, or
(b) one of the 10 employees (not necessarily Participants) owning (or
considered to own within the meaning of the Shareholder Attribution Rules) the
largest interests in any of the Aggregated Employers (which are owned by
employees) and who has annual Testing Wages in excess of the limitation in
effect under section Code 415(c)(1)(A) for any such plan year, or
(c) a Five Percent Owner, or
(d) a One Percent Owner having an annual Testing Wages of more than
$150,000;
provided, however, that no more than 50 employees shall be treated
as officers. For the purposes of determining ownership percentages, each
corporation, partnership and proprietorship otherwise required to be
aggregated shall be viewed as a separate entity. For purposes of paragraph
(b) above, if two employees have the same interest in any of the Aggregated
Employers, the employee having the greatest annual total compensation from
that Aggregated Employer shall be treated as having a larger interest. The
term "Key Employee" shall include the beneficiaries of a deceased Key
Employee.
1.6 One Percent Owner -- for each Aggregated Employer that is a
corporation, any person who owns (or is considered to own within the meaning
of the Shareholder Attribution Rules) more than one percent (1%) of the
outstanding stock of the corporation or stock possessing more than one percent
(1%) of the total combined voting power of the corporation, and, for each
Aggregated Employer that is not a corporation, any person who owns more than
one percent (1%) of the capital or the profits interest in such Aggregated
Employer. For the purposes of determining ownership percentages, each
corporation, partnership and proprietorship otherwise required to be
aggregated shall be viewed as a separate entity. For the purposes of
determining Testing Wages, however, all compensation received from all
Aggregated Employees shall be taken into account.
1.7 Shareholder Attribution Rules -- the rules of section 318 of the
Code, except that subparagraph (C) of section 318(a)(2) of the Code shall be
applied by substituting "5 percent" for "50 percent" or, if the Employer is
not a corporation, the rules determining ownership in such Employer which
shall be set forth in regulations prescribed by the Secretary of the Treasury.
1.8 Top Heavy Aggregation Group -- any Aggregation Group for which, as
of the Determination Date, the sum of:
(i) the present value of the cumulative accrued benefits for Key
Employees under all defined benefit plans included in such Aggregation Group;
and
(ii) the aggregate of the accounts of Key Employees under all
defined contribution plans included in such Aggregation Group,
exceed sixty percent (60%) of a similar sum determined for all employees.
In applying the foregoing, the following rules shall be observed:
(a) For the purpose of determining the present value of the cumulative
accrued benefit for any employees under a defined benefit plan, or the amount
of the account of any employee under a defined contribution plan, such present
value or amount shall be increased by the aggregate distributions made with
respect to such employee under the plan during the five (5) year period ending
on the Determination Date.
(b) Any rollover contribution (or similar transfer) initiated by the
employee and made after December 31, 1983, to a plan shall not be taken into
account with respect to the transferee plan for the purpose of determining
whether such transferee plan is a Top Heavy Plan (or whether any Aggregation
Group which includes such plan is a Top Heavy Aggregation Group).
(c) If any individual is not a Key Employee with respect to a plan for
any plan year, but such individual was a Key Employee with respect to a plan
for any prior plan year, the cumulative accrued benefit of such employee and
the account of such employee shall not be taken into account.
(d) The determination of whether a plan is a Top Heavy Plan shall be
made once for each plan year of the plan as of the Determination Date for that
plan year.
(e) In determining the present value of the cumulative accrued benefits
of employees under a defined benefit plan, the determination shall be made as
of the actuarial valuation date last occurring during the twelve (12) months
preceding the Determination Date and shall be determined on the assumption
that the employees terminated employment on the valuation date. In
determining this present value, the mortality and interest assumptions
shall be those which would be used by the Pension Benefit Guaranty Corporation
in valuing the defined benefit plan if it terminated on such valuation date.
The accrued benefit to be valued shall be the benefit expressed as a single
life annuity.
(f) In determining the accounts of employees under a defined
contribution plan, the account values determined as of the most recent asset
valuation occurring within the twelve (12) month period ending on the
Determination Date shall be used. In addition, amounts required to be
contributed under either the minimum funding standards or the plan's
contribution formula shall be included in determining the account. In the
first year of the plan, contributions made or to be made as of the
Determination Date shall be included even if such contributions are not
required.
1.9 Top Heavy Plan -- a qualified plan under which (as of the
Determination Date):
(i) If the plan is a defined benefit plan, the present value of the
cumulative accrued benefits for Key Employees exceed sixty percent (60%) of
the present value of the cumulative accrued benefits for all employees; and
(ii) If the plan is a defined contribution plan, the aggregate of
the accounts of Key Employees exceeds sixty percent (60%) of the aggregate of
all of the accounts of all employees.
In applying the foregoing, the following rules shall be observed:
(a) Each plan of an Employer required to be included in an Aggregation
Group shall be a Top Heavy Plan if such Aggregation Group is a Top Heavy
Aggregation Group.
(b) For the purpose of determining the present value of the cumulative
accrued benefit for any employee under a defined benefit plan, or the amount
of the account of any employee under a defined benefit plan, or the amount of
the account of any employee under a defined contribution plan, such present
value or amount shall be increased by the aggregate distributions made with
respect to such employee under the plan during the five (5) year period ending
on the Determination Date.
(c) The rules in subsections (b) through (f) of Section 1.8 are
applicable.
(d) For the purpose of determining if the Plan, or any other plan
included in a required aggregation group of which this Plan is a part, is top
heavy, the accrued benefit of an Employee other than a Key Employee shall be
determined under: (i) the method, if any, that uniformly applies for accrual
purposes under all plans maintained by the Aggregated Employers, or (ii) if
there is no such method, as if such benefit accrued not more rapidly than the
slowest accrual rate permitted under the fractional accrual rate of Code
section 411(b)(1)(C).
Section 2. Determination of Top Heaviness. Once each Plan Year, as
of the Determination Date for that Plan Year, the administrator of this Plan
shall determine if this Plan is a Top Heavy Plan.
Section 3. Contingent Provisions.
3.1 When Applicable. If this Plan is determined to be a Top Heavy Plan
for any Plan Year, the following provisions shall apply for that Plan Year
(and, to the extent hereinafter specified, for subsequent Plan Years),
notwithstanding any provisions to the contrary in the Plan.
3.2 Defined Contribution Plan Minimum Benefit Requirement.
3.2.1 General Rule. If this Plan is a defined contribution plan,
then for any Plan Year that this Plan is determined to be a Top Heavy Plan,
the Employer shall make a contribution for allocation to the account of each
employee who is a Participant for that Plan Year and who is not a Key Employee
in an amount (when combined with other Employer contributions and forfeited
accounts allocated to his account) which is at least equal to three percent
(3%) of such Participant's Testing Wages. This contribution shall be made for
each Participant who has not separated from service with the Employer at the
end of the Plan Year including, for this purpose, each Participant who, under
other Plan provisions, would have received no contribution, or would have
received a lesser contribution, for the Plan Year because he or she:
(a) completed fewer than one thousand (1,000) Hours of Service (or the
equivalent) during the Plan Year, or
(b) failed to make mandatory contributions to the Plan, or
(c) earned compensation which was less than the stated amount required
to receive a full contribution under the Plan, but only if such Participant
must be counted as a Participant in order for this Plan to satisfy the
qualification requirement that the Plan cover a nondiscriminatory group of
employees (i.e., the so-called "70% test," the "70/80% test" or the
"nondiscriminatory classification test").
3.2.2 Special Rule. Subject to the following rules, the percentage
referred to in Section 3.2.1 of this Appendix shall not exceed the percentage
at which contributions are made (or required to be made) under this Plan for
the Plan Year for that Key Employee for whom that percentage is the highest
for the Plan Year.
(a) The percentage referred to above shall be determined by dividing the
Employer contributions for such Key Employee for such Plan Year by his Testing
Wages.
(b) For the purposes of this Section 3.2, all defined contribution plans
required to be included in an Aggregation Group shall be treated as one plan.
(c) The exception contained in this Section 3.2.2 shall not apply to (be
available to) this Plan if this Plan is required to be included in an
Aggregation Group if including this Plan in an Aggregation Group enables a
defined benefit plan to satisfy the qualification requirement that the defined
benefit plan cover a nondiscriminatory group of employees (i.e., either the
so-called "70% test", the "70/80% test" or the nondiscriminatory
classification test").
3.2.3 Salary Reduction. Salary reduction contributions made by key
employees under Code section 401(k) are taken into account, but salary
reduction contributions by non-key employees are disregarded.
3.3 Priorities Among Plans. In applying the minimum benefit provisions
of this Appendix in any Plan Year that this Plan is determined to be a Top
Heavy Plan, the following rules shall apply:
(a) If an employee participates only in this Plan, the employee shall
receive the minimum benefit applicable to this Plan.
(b) If an employee participates in both a defined benefit plan and a
defined contribution plan and only one (1) of such plans is a Top Heavy Plan
for the Plan Year, the employee shall receive the minimum benefit applicable
to the plan which is a Top Heavy Plan.
(c) If an employee participates in both a defined contribution plan and
a defined benefit plan and both are Top Heavy Plans, then the employee, for
that Plan Year, shall receive the defined benefit plan minimum benefit unless
for that Plan Year the employee has received employer contributions and
forfeitures allocated to his account in the defined contribution plan in an
amount which is at least equal to five percent (5%) of his total compensation.
3.4 Annual Contribution Limits. If a Participant is also a participant
in a defined benefit plan maintained by the employer, with respect to any Plan
Year for which the Plan is a Top Heavy Plan, Section 5.3 of the Plan shall be
applied by substituting "1.0" for "1.25" in paragraphs (2)(B) and (3)(B) of
Code section 415(e), and by substituting "$41,500" for "$51,875" in Code
section 415(e)(6)(B)(i). The foregoing provisions of this section shall be
suspended with respect to any individual so long as there are no employer
contributions or forfeitures allocated to such individual, and no defined
benefit plan accruals for such individual, either under this Plan or under any
other plan that is in a required aggregation group of plans, within the
meaning of Code section 416(g)(2)(A)(i), that includes this Plan.
3.5 Exception For Collective Bargaining Unit. Section 3.2 shall not
apply with respect to any employee included in a unit of employees covered by
an agreement which the Secretary of Labor finds to be a collective bargaining
agreement between employee representatives and one or more employers if
there is evidence that retirement benefits were the subject of good faith
bargaining between such employee representative and such employer or
employers.
Exhibit 10.01
MID-CONTINENT AREA POWER POOL AGREEMENT
PREAMBLE
THIS AGREEMENT, made and entered into as of the 31st day of MARCH, 1972,
by and between the signatories hereto, herein referred to individually as a
"Party" or collectively as "Parties" and with the Parties further herein
referred to as "Participants" and "Associate Participants" as defined in
Article IV, as amended thereafter including additional signatories since 1972.
WITNESSETH
0.01 WHEREAS the Parties are engaged in the electric utility business;
and
0.02 WHEREAS the systems of the Parties are interconnected by
transmission facilities and are operated in synchronism pursuant to a number
of power pooling interconnection agreements; and
0.03 WHEREAS an extensive network of high voltage transmission
facilities has been developed by the interconnection of such transmission
facilities between the systems of the Parties; and
0.04 WHEREAS the Parties desire to continue to participate in a
regional power pool coextensive with such interconnected transmission
facilities to further enhance the reliability and other benefits of
interconnected operations and to provide further opportunities to coordinate
the installation and operation of generation and transmission facilities on
the respective systems of the Parties; and
0.05 WHEREAS all the present Parties that were signatory to the Mid-
Continent Area Reliability Coordination Agreement (MARCA) are also
Participants of the Mid-Continent Area Power Pool; and
0.06 WHEREAS the Parties that are members of MARCA have dissolved that
Agreement and have included the necessary functions from MARCA in the Mid-
Continent Area Power Pool Agreement;
NOW, THEREFORE, the Parties agree to enter into this Agreement for the
operation of the Mid-Continent Area Power Pool, hereinafter call "MAPP," in
accordance herewith.
ARTICLE I
OBJECTIVES
1.01 The objective of this Agreement is to provide reliable and
economical electric service to the customers of each of the Parties consistent
with reasonable utilization of natural resources and effect on the
environment. In order to accomplish such purposes, the Parties shall endeavor
to coordinate the installation and operation of generation and transmission
facilities. However, each Party has the right and obligation, regardless of
size or type of organization, to own or otherwise provide the facilities
required to provide its electric service requirements. Each and all of the
provisions of this Agreement are considered reasonably necessary in order to
furnish a basis for the Parties reaching an agreement to accomplish these
objectives.
ARTICLE II
TERM OF AGREEMENT
2.01 This Agreement shall become effective on the first of the month
next following sixty (60) days after acceptance for filing of this Agreement
by the Federal Energy Regulatory Commission and shall not become effective if
such acceptance is not received within 180 days of the execution of this
Agreement.
2.02 This Agreement and amendments thereto shall be of no force or
effect for a Participant which is a borrower from the Rural Electrification
Administration and which requires Rural Electrification Administration
approval thereof unless such approval is obtained within 180 days of the date
of execution thereof by such borrower.
2.03 Any Participant may terminate its participation in this Agreement
by four years written notice to the other Parties hereto. Any Associate
Participant may terminate its participation in this Agreement by ninety (90)
days written notice to the other Parties hereto.
2.04 In the event a Participant fails to perform its obligations
pursuant to this Agreement, the Management Committee shall give written notice
to such Participant specifying such failure to perform and establishing such
reasonable period as such Participant shall have to fulfill its obligations
pursuant to this Agreement. In accordance with such notice, the Management
Committee shall review the performance of such Participant and if the failure
to perform its obligation is continuing, the Management Committee may
thereupon terminate such Participant's participation. This provision shall
not limit the right of any other Participant to enforce the rights and
obligations established pursuant to this Agreement.
2.05 If any of the transmission facilities of a terminating Participant
are required for the continuing stability and reliability of the
interconnected systems of the remaining Participants, such terminating
Participant as to the affected facilities shall continue to be subject to the
requirements relating to stability and reliability which are in effect at the
time of termination. This obligation shall continue only for as long as the
affected facilities continue to be interconnected, directly or indirectly,
with the system of any continuing Participant, but for no longer a period than
the remaining Participants may reasonably and with due diligence require to
permit the establishment of alternative arrangements for stability and
reliability, but for no longer than four years from the date of notice issued
pursuant to Paragraph 2.03 or from the date of termination by the Management
Committee pursuant to Paragraph 2.04.
2.06 Any Participant terminated as provided in Paragraph 2.04 shall
continue to fulfill its obligations pursuant to any power transaction under
the Service Schedules until the completion of such power transaction.
2.07 Any terminated or terminating Participant will continue, or enter
into, an agreement contemplated by Article XV on such terms and conditions and
for such annual payment as shall be established between the Management
Committee and the Contractor. The annual payment shall be such share of the
total payment for services provided by the Contractor reasonably related to
the continuing obligation of the terminated or terminating Participant and
shall include for a period not exceeding ten (10) years any unsatisfied
portion of any payment measured by investment in facilities or equipment
committed by such Contractor to provide services from the Coordination Center
when such commitment was made and the measure of payment established between
the Management Committee and the Contractor prior to notice of default or
termination.
ARTICLE III
DEFINITIONS
For the purposes of this Agreement and of the Service Schedules which
are a part hereof, the following definitions shall apply:
3.01 Firm Energy shall mean energy intended to be supplied at all
times.
3.02 System Demand of a Party shall mean that number of kilowatts which
is equal to the kilowatt-hours required in any clock hour, attributable to
energy required by such Party during such hour for supply of Firm Energy to
the Party's consumers, including system losses, and also including any
transmission losses occurring on other systems supplied by such party for
transmission of such Firm Energy, but excluding generating station uses,
excluding transmission losses supplied by another system, and excluding
Interruptible Load Replacement Energy as provided for in Service Schedule "L."
3.03 Annual System Demand of a Party shall mean the highest System
Demand of such Party occurring during the 12-month period ending with the
current month.
3.04 Certified Interruptible Demand shall mean the quantity of
kilowatts which is equal to the kilowatt-hours in any clock hour that can be
removed from a Party's system under control of the Party. Such quantities
shall be certified by the Party to the Engineering Committee for each month
according to requirements the Engineering Committee may establish.
3.05 Net Generating Capability of a Participant for any month shall
mean that amount of kilowatts, less station use, that all the generating
facilities of such Participant could normally supply simultaneously to its
system and the interconnected systems of the Participants at the time of such
Participant's maximum System Demand for such month under such conditions as
may be established by the Engineering Committee. The capability of the
generating units of a Participant which are temporarily out of service for
maintenance or repair shall be included in the Net Generating Capability of
such Participant.
3.06 Accredited Capability of a Participant for any month shall mean
(a) the Net Generating Capability of such Participant, plus (b) the value in
kilowatts assigned to such Participant's purchases under Service Schedules
"A," "B," "H," "I," "J," and "K," hereof, and to commitments for power from
electric suppliers under separate contracts now existing or hereafter created,
and minus (c) the value in kilowatts assigned to any commitment of such
Participant to deliver power to another Participant under Service Schedules
"A," "B," "H," "I," "J," and "K," hereof, or to any electric supplier or
suppliers pursuant to any valid order or under separate contract or contracts
now existing or hereafter created. The Accredited Capability of such
Participant will be determined and assigned by the Engineering Committee in
accordance with the provisions of Paragraph 16.03 hereof.
3.07 Available Accredited Capability of a Participant shall mean its
Accredited Capability adjusted for generating capacity out of service for
maintenance or repair.
3.08 Reserve Capacity of a Participant for any month shall mean the
excess in kilowatts of each Participant's Accredited Capability above such
Participant's maximum System Demand for such month.
3.09 Reserve Capacity Obligation of a Participant shall be the capacity
which that Participant is obligated to reserve and use for the purpose of
maintaining continuity of service.
3.10 Spinning Reserve shall mean the amount of unloaded generating
capability of a Participant connected to and synchronized with the
interconnected system of the Participants and ready to take load. Spinning
Reserve allocation to any generator shall not exceed the amount of generation
increase that can be realized in ten (10) minutes.
3.11 Non-Spinning Reserve shall mean all unloaded generating capability
not meeting the Spinning Reserve criteria (Paragraph 3.10) that can be made
fully effective in ten (10) minutes.
3.12 Operating Reserve shall mean the sum of Spinning and Non-Spinning
Reserve.
3.13 Operating Reserve Obligation shall mean that amount of Spinning
Reserve and Non-Spinning Reserve which a Participant is obligated under the
terms of this Agreement to provide for the purpose of maintaining continuity
of service.
3.14 Total Operating Reserve Obligation shall be that amount of
Spinning Reserve and Non-Spinning Reserve of the Participants collectively
required to maintain continuity of service.
3.15 An Emergency Outage shall mean any unanticipated, unscheduled
outage of generating or transmission facilities; however, such outage
classification shall not exceed a period of six hours.
3.16 A Scheduled Outage shall mean any outage of generating or
transmission facilities which is scheduled in advance for maintenance and
shall include the remainder of an Emergency Outage which is rescheduled as a
Scheduled Outage. Such rescheduling shall be required within six hours of the
initiation of the Emergency Outage.
3.17 Participation Power shall mean power and associated energy which
is sold or purchased by Participants as provided for in Service Schedule "A."
3.18 Seasonal Participation Power shall mean power and associated
energy which is sold or purchased by Participants as provided for in Service
Schedule "B."
3.19 System Participation Power shall mean power and associated energy
which is sold or purchased by Participants as provided for in Service Schedule
"K."
3.20 Peaking Power shall mean power and associated energy which is sold
or purchased by Participants as provided for in Service Schedule "H."
3.21 Short Term Power shall mean power and associated energy which is
sold or purchased by the Participants and intended to be available at all
times during the period covered by the commitment as provided for in Service
Schedule "I."
3.22 Emergency Energy shall mean energy which is supplied under Service
Schedule "C" of this Agreement by any Participant to any other Participant
during and as required by an Emergency Outage on such other Participant's
system which is not supplied under another provision of this Agreement.
3.23 Scheduled Outage Energy shall mean energy which is supplied under
Service Schedule "C" of this Agreement by any Participant to any other
Participant as a result of a Scheduled Outage which is not supplied under
another provision of this Agreement.
3.24 Economy Energy shall mean energy which one Participant may deliver
under Service Schedule "E" to another Participant for the purpose of replacing
more expensive energy.
3.25 Interruptible Load Replacement Energy shall mean energy which is
supplied under Service Schedule "L" of this Agreement by any Participant to
another Participant for the purpose of serving interruptible load.
3.26 Operational Control Energy shall mean energy which is sold or
purchased by the Participants to improve electric system control and
reliability as provided for in Service Schedule "G."
3.27 General Purpose Energy shall mean energy which is supplied under
Service Schedule "M" by any Participant to any other Participant to enhance
economic system operation.
3.28 Average Production Cost per kilowatt-hour of a generating unit for
a month shall be:
a. The total cost of all fuel consumed by the unit in such
month divided by the net kilowatt-hours produced by the
unit in such month, plus
b. An amount, established by the Operating Committee after
annual review, which shall represent the average monthly
production cost, other than fuel, of the unit, plus
c. An amount, established by the Operating Committee, which
shall represent the cost per kilowatt-hour of incremental
losses on the supplying Participant's system and on any
other system or systems of electric suppliers not
Participants hereto incurred in delivering power and energy
hereunder.
3.29 Incremental Cost of a supplying Participant to supply energy to
another Participant shall be:
a. The cost of the fuel, operating labor and maintenance
required to generate the energy necessary to supply (1) the
scheduled delivery to the receiving Participant's system,
plus (2) the incremental losses incurred on the supplying
Participant's system, plus (3) the energy supplied to any
intervening system or systems as compensation for losses.
b. The cost of starting and operating any generating units
which must be started as a result of supplying such energy.
c. The supplying Participant's cost of purchased energy if the
purchase is made as a result of supplying such energy. The
incremental cost per kilowatt-hour for any particular
transaction shall be the total of such costs divided by the
kilowatt-hours scheduled for delivery to the receiving
Participant either directly by the supplying Participant or
through an intervening system or systems.
3.30 Decremental Cost of a receiving Participant for avoiding the
operation of generating facilities through the purchase of energy from another
Participant shall be:
a. The cost of the fuel, operating labor and maintenance which
such Participant avoided using by means of such purchase.
b. The cost of starting and operating of a generating unit or
units which such Participant avoided by means of such
purchase.
The decremental cost per kilowatt-hour shall be the total of such costs
divided by the number of kilowatt-hours scheduled for delivery to the
receiving Participant either directly by the supplying Participant or through
an intervening system or systems.
3.31 Latest Base Load Unit shall mean a single turbine generator unit
declared by the Participant to be either its most recent wholly owned or
leased and controlled capacity addition, or its most recent wholly owned or
leased and controlled share of a jointly owned unit.
3.32 Transmission Service is the transfer of electricity by a
Participant over its transmission system for another Participant, pursuant to
Service Schedule "F."
3.33 Contractor shall be MAPPCOR, a Minnesota non-profit corporation,
or other such entity as may be selected by the Management Committee pursuant
to Paragraph 15.01 of this Agreement.
3.34 Coordination Transactions are transactions between electric
utility systems for the purpose of achieving short-term cost savings,
providing assistance in emergency situations, or coordinating operating
procedures and maintenance schedules.
3.35 Control Area shall mean a system capable of regulating its
generation in order to maintain its interchange schedule with other systems
and contribute its frequency bias obligation to the interconnected system.
A system shall qualify as a Control Area by meeting the criteria for control
areas established by the North American Electric Reliability Council and by
being recognized by the North American Electric Reliability Council as a
control area.
ARTICLE IV
PARTICIPANTS AND ASSOCIATE PARTICIPANTS
4.01 Any entity engaged in the electric utility business:
a. Which owns or leases and controls the operation of one or
more generating units, and which regularly operates such
unit or units to meet all or part of its system load; and
b. Whose system is normally operated directly interconnected
with one or more Participants at a voltage level and
interconnection capacity so as to enable it to meet its
obligations under this Agreement or enters into contractual
arrangements to have its system so interconnected; and
c. Which operates or participates in the operation of a
twenty-four hour dispatch center with a terminal on the
MAPP communication network connecting the Participants or
enters into contractual arrangements for such service; and
d. Which maintains during each month Accredited Capability in
an amount equal to or greater than its maximum System
Demand for such month plus Participant's Reserve Capacity
Obligation as defined and determined pursuant to the terms
of this Agreement;
may become a Party to this Agreement as a Participant.
4.02 Electric utilities which meet the qualifications for Participant
membership as set forth in Paragraph 4.01 but elect not to become a
Participant and electric utilities which do not meet the qualifications for
Participant membership as set forth in Paragraph 4.01 may execute this
Agreement as Associate Participants and participate herein as set forth for
Associate Participant.
ARTICLE V
PARTICIPATION IN NORTH-AMERICAN ELECTRIC
RELIABILITY COUNCIL (NERC)
5.01 The North-American Electric Reliability Council which was
incorporated on October 15, 1975, has nine member regions, one of which is
MARCA. Each region is responsible to appoint two members to the NERC Board
of Trustees and other representatives to Engineering and Operating Committees
and working groups as established by the Board of Trustees. Since MARCA has
been terminated and MAPP has assumed the reliability functions of MARCA, MAPP
shall assume the previous MARCA membership in NERC and will participate in
NERC activities as required to adequately represent the MAPP membership.
Representatives to the NERC Board of Trustees and other NERC committees shall
be appointed by the MAPP Management Committee. Expenses of those
representatives while representing MAPP at NERC functions shall be reimbursed
from funds provided by the MAPP Coordination Center and allocation procedure.
ARTICLE VI
RELATION TO OTHER AGREEMENTS AND OBLIGATIONS
6.01 Each Party represents that there are no conditions in such Party's
existing agreements, including financing agreements, which will preclude such
Party from performance of all obligations hereunder; and further, each Party
agrees not to enter into an agreement which will preclude performance
hereunder. The failure by any Party to get approval under any financing
agreement for entering into a contract, or amending or terminating any
existing agreement, shall not excuse performance hereunder.
6.02 The execution of this Agreement shall not impair, amend, or change
any previous contracts or agreements and such contracts and agreements shall
continue, including all rates, terms and conditions until the expiration of
such contracts and agreements.
ARTICLE VII
COMMITTEE ORGANIZATION
7.01 The committee organization under this Agreement shall include a
Management Committee, Executive Committee, Engineering Committee, Operating
Committee, Design Review Committee, Environmental Committee, Area Relations
Committee and such other committees as may be established by the Management
Committee from time to time.
7.02 The expenses of each committee member shall be borne by the
represented Party.
7.03 Committee expenses, other than those described in Paragraphs 5.01
and 7.02 shall be shared in a manner agreed to by the affected Parties.
7.04 Minutes of all committee meetings shall be recorded and copies
thereof distributed in accordance with procedures established by the
Management Committee.
ARTICLE VIII
MANAGEMENT COMMITTEE
8.01 The Management Committee shall consist of one representative
selected by each Participant. Each Participant shall designate the person who
shall act as its representative by written notice to the MAPP Secretary
provided under Paragraph 8.04. By similar notice, a Participant may change
its representative on the Management Committee and also designate an alternate
representative to act in the absence of the designated representative. Each
Associate Participant may designate, by written notice to the MAPP Secretary,
a representative as a non-voting member of the Management Committee.
8.02 The Management Committee shall administer this Agreement to
accomplish the objectives of MAPP.
8.03 The Management Committee shall hold an annual meeting during the
last month of the fiscal year at such time and place as the Chairman shall
designate and shall hold meetings at other times at the call of the Chairman
or upon call of three or more Committee members. At least ten (10) days
written notice shall be given to each member of the Management Committee of
any meeting of such Committee. The notice shall state the time and place of
the meeting and shall include an agenda of the items to be considered. Except
by unanimous consent of those present, no action shall be taken on any item
other than those included on the agenda.
8.04 The Management Committee, at its annual meeting, shall elect three
officers who shall serve until the next annual meeting. They shall be a
Chairman and a Vice Chairman elected from the representatives of the
Participants on the Committee, also, a secretary, herein called "MAPP
Secretary," who need not be a member of the Committee. The Chairman shall not
serve for more than two consecutive terms.
8.05 The duties of the Management Committee include but are not
limited to the following:
a. Supervise the development of plans and procedures that will
result in attainment of the objectives of this Agreement.
b. Specify the duties and authority, other than set forth
herein, of the Engineering Committee, the Operating
Committee, the Design Review Committee, the Environmental
Committee, the Area Relations Committee and other
committees which may be established by the Management
Committee.
c. Make such administrative arrangements as may be required
pertaining to matters which are pertinent to this Agreement
but which are not specifically covered herein including the
establishment of a fiscal year.
d. Review and rule on appeals from Executive Committee
decisions filed pursuant to the provisions of Paragraph
9.04.
e. Review and rule on appeals from Engineering and Operating
Committees as provided for in Paragraphs 10.08 and 11.06
respectively.
f. Provide representation to the NERC Board of Trustees and
participate in its functions.
g. Review and approve an annual operating budget for the MAPP
Coordination Center and Committee activities.
h. Establish the Reserve Capacity Obligation of each
Participant.
i. Establish total Operating Reserve Obligation and formula
for the Operating Reserve Obligation of each Participant.
j. Review and approve recommendations of the Design Review
Committee.
8.06 Each Participant on the Management Committee shall be entitled to
the number of votes determined by the following formula:
a. One vote for each 25 megawatts, or fraction thereof, of
Annual System Demand up to 300 megawatts.
b. One vote for each 50 megawatts, or fraction thereof, of
Annual System Demand from 301 to 600 megawatts.
c. One vote for each 100 megawatts, or fraction thereof, of
Annual System Demand over 600 megawatts.
A Participant's Annual System Demand shall be counted only once
in determining voting allocation.
8.07 A majority affirmative vote of the total authorized votes is
required to authorize any action, determination, or recommendation of the
Management Committee. Any such action, determination, or recommendation of
the Management Committee shall be binding on the Parties thirty (30) days
after the vote thereon unless any Participant or Participants who vote against
such action, determination, or recommendation invoke the arbitration provision
set forth in Article XXX.
ARTICLE IX
EXECUTIVE COMMITTEE
9.01 The Executive Committee shall consist of not less than nine voting
members including the Chairman and Vice Chairman of the Management Committee,
a representative from the Western Area Power Administration, a representative
of the MAPP Participant utility allocated the largest portion of the MAPP
Annual Budget and a representative from each of any other MAPP Participant
utilities allocated 20% or more of the MAPP Annual Budget, plus additional
voting members elected by and from the Management Committee representatives.
The other number of voting members of the Executive Committee shall be elected
by and determined by the Management Committee. The Executive Committee shall
be representative of the membership; factors to be considered are size and
type of corporate organization and geographic area covered. Any state or
province in which at least ten percent (10%) of the pool load is located shall
be represented by not less than one Participant representative on the
Executive Committee. The Chairman and Vice Chairman of the Management
Committee shall also be the Chairman and Vice Chairman of the Executive
Committee. The MAPP Secretary and a representative of the Contractor under
Article XV shall be non-voting members of the Executive Committee.
9.02 Between meetings of the Management Committee, the Executive
Committee shall have the duties of the Management Committee except those under
Article XV and Paragraph 8.05 b, d, e, f, g, h, i and j, subject to appeal
pursuant to the provisions of Paragraph 9.04.
9.03 The Executive Committee shall hold an annual meeting within six
months after the annual meeting of the Management Committee at such time and
place as the Chairman shall designate and shall hold other meetings in
accordance with a schedule adopted by the Executive Committee or at the call
of the Chairman or upon call of two or more members of the Executive
Committee. At least ten (10) days written notice shall be given to each
member of the Executive Committee of any meeting of such Committee.
9.04 An affirmative vote of two-thirds of the voting representatives
on the Executive Committee is required to authorize any action, determination
or recommendation of the Executive Committee. Any action, determination or
recommendation adopted by the Executive Committee may be appealed to the
Management Committee by one or more of the Participants; provided that, the
sum of the Annual System Demands of such appealing Participant or Participants
for the immediately preceding fiscal year is at least equal to one percent
(1%) of the sum of the Annual System Demand of all Participants for such
fiscal year. Such appeal shall be made by filing a notice of appeal with the
MAPP Secretary within thirty (30) days after mailing of the written notice
under Paragraph 9.05. The filing of a notice of appeal as aforesaid shall
suspend such action, determination or recommendation pending action thereon
by the Management Committee.
9.05 The MAPP Secretary shall send written notice to each member of the
Management Committee of any action taken by the Executive Committee prior to
the end of the fifth business day following the meeting of the Executive
Committee at which such action was taken.
ARTICLE X
ENGINEERING COMMITTEE
10.01The Engineering Committee shall consist of one representative of
each Participant designated by such Participant's representative on the
Management Committee by written notice to the MAPP Secretary. By similar
notice, a Participant may change its Engineering Committee representative and
also designate an alternate Engineering Committee representative to act in the
absence of the designated representative. Each Associate Participant may
designate, by written notice to the MAPP Secretary, a representative as a non-
voting member of the Engineering Committee.
10.02The Engineering Committee, under the direction of the Management
Committee, shall administer the planning and design reliability functions for
the bulk power supply pursuant to this Agreement.
10.03The Engineering Committee shall hold an annual meeting in the
first quarter of each year and shall hold other meetings at other times upon
call of the Chairman or upon request of three or more Participant members.
At least ten (10) days written notice shall be given to each member of the
Engineering Committee of any meeting of such Committee. The notice shall
state the time and place of the meeting and shall include an agenda of items
to be considered. Except by unanimous consent of those present, no action
shall be taken on any item other than those included on the agenda.
10.04The Engineering Committee, at its annual meeting, shall elect two
officers who shall serve until the next annual meeting. They shall be a
Chairman and Vice Chairman elected from the representatives of the
Participants on the Committee. The Chairman shall not serve for more than two
consecutive terms. A person from the staff of the MAPP Coordination Center
shall serve as its Secretary and shall be a non-voting member.
10.05The duties of the Engineering Committee shall include, but shall
not be limited to the following:
a. Establish and revise as necessary, design reliability
standards for the bulk power supply of MAPP, and coordinate
such standards with regional power coordinating groups.
b. Conduct periodic overall system reliability studies as
required.
c. Recommend revisions to the Reserve Capacity Obligation of
the Participants as periodically required, to the
Management Committee.
d. Establish annually a plan for the ensuing ten (10) years or
longer period covering:
i. The size and type of the generating units to be
installed, and the voltage and capacity of each
transmission facility 115 Kv and above, where such
facilities would have a significant effect upon MAPP
area reliability,
ii. The location of such facilities,
iii. The time when such facilities are to be placed in
operation,
iv. The entity or entities installing such facilities,
and
v. The contracted purchases and sales by Participants.
e. Review on a continuing basis, the load and capability
forecasts which take into account conservation and load
management plans of the Parties as reported by the MAPP
Coordination Center and take the necessary action therewith
in accordance with Article XVI.
f. Coordinate the MAPP bulk power production and transmission
system development with adjoining systems, pools and
regional power coordinating groups.
g. Establish and revise rules relating to the effect of
abnormal conditions on System Demand and Reserve Capacity
Obligation.
h. Establish and revise rules for the determination of
Accredited Capability of the Participants.
i. Cause studies to be made as necessary for administration of
its duties hereunder.
j. Establish procedures for the use of Service Schedules,
including the use of Service Schedule "F" for capacity
transactions.
k. Review and recommend changes to the Service Schedules to
the Management Committee.
l. Recommend to the Management Committee, representation to
the NERC Engineering Committee and participate in its
functions.
m. Prepare and publish schedules of the Transmission Service
schedule charges, in accordance with Service Schedule "F".
10.06The Engineering Committee may establish subcommittees and assign
duties consistent with this Agreement and policies of the Management
Committee.
10.07The Engineering Committee shall recommend to the Management
Committee, planning functions which should be assigned to the MAPP
Coordination Center to improve reliability and economy. Such recommendations
shall be provided to the General Manager, MAPP Coordination Center to
facilitate preparation of budget recommendations.
10.08Any action of the Engineering Committee shall be taken only if
seventy percent (70%) or more of the total authorized votes, as provided in
the formula in Paragraph 8.06, are present at a meeting. Any action approved
by at least ninety percent (90%) of the total authorized votes present shall
become effective immediately. If less than a ninety percent (90%) vote, any
action receiving an affirmative vote of at least two-thirds of the total
authorized votes present shall become effective after thirty (30) days unless
it is appealed to the Management Committee. Within five business days of any
action receiving less than ninety percent (90%) vote by the Engineering
Committee, the Committee Secretary shall give written notice thereof to the
members of the Engineering Committee. Notice of any appeal therefrom shall
be filed with the MAPP Secretary within ten (10) days of mailing of said
notice of action. The submittal to the Management Committee shall include
such alternative proposals as any Participant may request.
ARTICLE XI
OPERATING COMMITTEE
11.01The Operating Committee shall consist of one representative of
each Participant designated by such Participant's representative on the
Management Committee by written notice to the MAPP Secretary. By similar
notice, a Participant may change its Operating Committee representative and
also designate an alternate representative to act in the absence of the
designated representative. Each Associate Participant may designate, by
written notice to the MAPP Secretary, a representative as a non-voting member
of the Operating Committee.
11.02The Operating Committee, under the direction of the Management
Committee, shall be responsible for establishing such practices, rules and
procedures as may be required to coordinate the operations and pool energy
accounting of the bulk power generation and transmission facilities of the
Parties pursuant to this Agreement.
11.03The Operating Committee shall hold an annual meeting in the first
quarter of each year and shall hold other meetings at others times upon call
of the Chairman or upon request of three or more Participant members. At
least ten (10) days written notice shall be given to each member of the
Operating Committee of any meeting of such Committee. The notice shall state
the time and place of the meeting and shall include an agenda of the items
to be considered. Except by unanimous consent of those present, no action
shall be taken on any item other than those included on the agenda.
11.04The Operating Committee, at its annual meeting, shall elect two
officers who shall serve until the next annual meeting. They shall be a
Chairman and Vice Chairman elected from the representatives of the
Participants on the Committee. The Chairman shall not serve for more than two
consecutive terms. A person from the staff of the MAPP Coordination Center
shall serve as its Secretary and shall be a non-voting member.
11.05The duties of the Operating Committee shall include, but shall not
be limited to the following:
a. Coordinate the operation of the bulk power generation and
transmission facilities of the Parties so as to effect
optimum reliability and economy of service.
b. Establish methods, standards, and procedures for the
determination of costs associated with transactions
hereunder.
c. Periodically review the Total Operating Reserve Obligation
and the formula for establishing the Operating Reserve
Obligation of a Participant and make recommendations to the
Management Committee for revisions as required.
d. Collect and analyze operating data pertinent to the
interconnected operation of the systems of the Participants
and arrange for conducting such transmission network
studies as may be necessary in the performance of its
duties hereunder.
e. Review and approve the coordinated maintenance schedules of
the Participants as provided by the MAPP Coordination
Center to assure at all times satisfying the Total
Operating Reserve Obligation.
f. Establish procedures for the use of the Service Schedules,
including the use of Service Schedule "F" for energy
transactions.
g. Review and recommend changes to the Service Schedules to
the Management Committee.
h. Determine and periodically review the procedures to be
followed by the Participants in restoring the Total
Operating Reserve Obligation in the event of a large
generator failure or other comparable contingency.
i. Coordinate the periods and methods of reporting scheduled
and actual power and energy flows.
j. Establish methods and procedures for accounting and billing
of bulk power and energy interchanges and Transmission
Services hereunder.
k. Establish operating reliability standards, criteria and
rules relating to protective equipment, switching, voltage
control, system control performance, load shedding,
emergency and restoration procedures and the operation and
maintenance of generation and transmission facilities of
the Participants necessary to assure the reliable operation
of the MAPP systems.
l. Establish procedures and practices for coordinating the
power pool operation activities of MAPP with adjoining
systems, pools and other regional power coordination
agencies.
m. Recommend to the Management Committee representation to the
NERC Operating Committee and participate in its functions.
n. Recommend to the Management Committee the power pool
operating functions which should be conducted at the MAPP
Coordination Center to improve reliability and economy.
Such recommendations shall be provided to the General
Manager, MAPP Coordination Center to facilitate preparation
of budget recommendations.
11.06Any action of the Operating Committee shall be taken only if
seventy percent (70%) or more of the total authorized votes, as provided in
the formula in Paragraph 8.06, are present at a meeting. Any action approved
by at least ninety percent (90%) of the total authorized votes present shall
become effective immediately. If less than a ninety percent (90%) vote, any
action receiving an affirmative vote of at least two-thirds of the total
authorized votes present shall become effective after thirty (30) days unless
it is appealed to the Management Committee. Within five business days of any
action receiving less than ninety percent (90%) vote by the Operating
Committee, the Committee Secretary shall give written notice thereof to the
members of the Operating Committee. Notice of any appeal therefrom shall be
filed with the MAPP Secretary within ten (10) days of mailing of said notice
of action. The submittal to the Management Committee shall include such
alternative proposals as any Participant may request.
ARTICLE XII
DESIGN REVIEW COMMITTEE
12.01The Design Review Committee shall consist of members representing
various Participants appointed by the Management Committee, one of whom shall
be appointed Chairman by the Management Committee. Members appointed should
have experience in system operation and analysis and be representative of the
geographic area covered. A person from the staff of the MAPP Coordination
Center shall serve as its Secretary and shall be a non-voting member.
12.02The Committee shall meet on call of its Chairman as required to
carry out its duties. Committee recommendations to the Management Committee
as well as other committee action taken, shall be adopted by two-thirds vote
of its members. Minority recommendations may be submitted.
12.03The Design Review Committee, with assistance of the staff of the
MAPP Coordination Center and in conjunction with each Participant, shall
review and evaluate such Participant's planning for generation and
transmission facilities for conformance to reliability design standards
established by the Engineering Committee and report their findings to the
Management Committee. Any operating restrictions necessary to make a
Participant's planned facilities operate within MAPP reliability design
standards will be subject to approval of the Design Review Committee.
12.04To enable the Design Review Committee to carry out its tasks, the
Participants shall furnish such studies and data as it shall reasonably
request, including but not limited to, technical studies of system
performance, data on current and projected loads, system equipment
capabilities, capability margins, spinning reserves, relay settings
controlling major facilities, communication facilities, recording facilities
and operating procedures.
ARTICLE XIIA
OPERATING REVIEW COMMITTEE
12A.01 An Operating Review committee is created which, with assistance
of the staff of the Contractor and in conjunction with each Participant, shall
review and evaluate each Participant's operating studies, guides and practices
for compliance with operating reliability standards, criteria, rules, methods,
and procedures established by the Operating Committee and report its findings
to the Management Committee. Any operating restrictions necessary to make a
Participant's facilities operate within MAPP systems operating standards
established by the Operating Committee will be subject to approval by the
Operating Review Committee.
12A.02 The Operating Review Committee shall be composed of nine
members; a Chair and Vice Chair appointed by the Management committee and
seven members appointed by the Chair with the approval of the Management
Committee. All members shall serve for an indefinite term at the pleasure of
the Management Committee. The members of the Operating Review Committee shall
have electric system operating knowledge and experience and shall be
representative of the geographic area served by MAPP. A staff member of the
Contractor shall serve as Secretary of the Operating Review Committee and
shall be a non-voting member thereof.
12A.03 The Operating Review Committee shall meet at the call of the
Chair as required to carry out its duties, or in case of the disability of the
Chair, at the call of the Vice Chair. Recommendations of the Operating Review
Committee to the Management Committee and other actions taken shall be by the
affirmative vote of 2/3rds of all of the members. Minority recommendations
may be submitted to the Management Committee.
12A.04 In cases where the Operating Review Committee determines from
available information that a Participant has failed to comply with established
operating standards, it shall notify the noncompliant Participant in writing.
If the noncompliant Participant does not, within three months after receipt
of the notice, propose a plan acceptable to the Operating Review Committee to
correct the failure, or fails to comply with the correction plan, the
Operating Review Committee shall report such failure to the Management
Committee.
ARTICLE XIII
ENVIRONMENTAL COMMITTEE
13.01The Environmental Committee shall be appointed by the Management
Committee. In selection of such representatives, consideration shall be given
to geographic representation.
13.02The Environmental Committee shall hold an annual meeting in the
first quarter of each year and shall hold other meetings at other times upon
call of the Chairman or upon request of three or more Participant members.
At least ten (10) days written notice shall be given to each member of the
Environmental Committee of any meeting of such Committee. The notice shall
state the time and place of the meeting and shall include an agenda of the
items to be considered.
13.03The Environmental Committee, at its annual meeting, shall elect
two officers who shall serve until the next annual meeting. They shall be a
Chairman and Vice Chairman elected from the representatives of the
Participants on the Committee. The Chairman shall not serve for more than two
consecutive terms. A person from the staff of the MAPP Coordination Center
shall serve as its Secretary and shall be a non-voting member.
13.04Under the direction of the Management Committee, the Environmental
Committee shall keep abreast of national and regional matters relating to air
quality, water quality, land use and other environmental factors. The
Committee shall also carry out other functions and activities as assigned or
approved by the Management Committee. Findings and recommendations shall be
reported to the Management Committee.
13.05The Environmental Liaison Group shall consist of one
representative of each Participant designated by such Participant's
representative on the Management Committee by written notice to the MAPP
Secretary. The Liaison representative shall serve as the liaison between the
Environmental Committee and each Participant for supplying information and
receiving reports. The Environmental Liaison Group shall meet with the
Environmental Committee as directed by the Environmental Committee.
13.06The Environmental Committee may establish subcommittees and task
forces and assign duties as necessary to carry out its assigned functions.
ARTICLE XIV
AREA RELATIONS COMMITTEE
14.01The Area Relations Committee shall consist of one representative
from each Participant designated by such Participant's representative on the
Management Committee by written notice to the MAPP Secretary. By similar
notice, a Participant may change its representative or designate an alternate
to act in place of its representative.
14.02The Area Relations Committee shall hold an annual meeting in the
first quarter of each year and shall hold other meetings at other times upon
call of the Chairman or upon request of three or more Participant members.
At least ten (10) days written notice shall be given to each member of the
Area Relations Committee of any meeting of such Committee. The notice shall
state the time and place of the meeting and shall include an agenda of the
items to be considered. Except by unanimous consent of those present, no
action shall be taken on any item other than those included on the agenda.
14.03The Area Relations Committee, at its annual meeting, shall elect
two officers who shall serve until the next annual meeting. They shall be a
Chairman and Vice Chairman elected from the representatives of the
Participants on the Committee. The Chairman shall not serve for more than two
consecutive terms. A person from the staff of the MAPP Coordination Center
shall serve as its Secretary and shall be a non-voting member.
14.04Under the direction of the Management Committee, the Area
Relations Committee shall be responsible for advising the Parties on preparing
progress reports, public presentations and educational materials relating to
activities of the Parties pursuant to this Agreement and shall carry out other
functions and activities as assigned or approved by the Management Committee.
14.05The Committee shall meet as required on call of the Committee
Chairman or the Management Committee.
ARTICLE XV
MAPP COORDINATION CENTER
15.01The Management Committee shall select a Contractor which will
agree to provide various information and other services, as determined by the
Management Committee, to each of the Participants in order to enhance the
attainment of the goals of this Agreement.
15.02Consistent with policy and guidelines provided by the Management
Committee, the Contractor shall be an independent contractor with each of the
Participants and will be responsible for the establishment and operation of
a MAPP Coordination Center hereinafter called "Center." The Contractor shall
provide facilities, manpower, and administration necessary for such operation.
15.03Each Participant shall enter into an agreement with the Contractor
providing for services as provided in Paragraph 15.01 under the terms and
conditions and such annual payment as may be established from time to time
between the Management Committee and the Contractor.
15.04Each Party shall retain the sole responsibility for the operation
of its system and the utilization of the information which may be provided
from the Center.
15.05Subject to a determination by the Management Committee that such
action can be taken without prejudicing the Contractor's fulfillment of its
obligations to the Participants for services from the Coordination Center, the
Contractor may contract with electrical power suppliers which are not parties
to this Agreement for services from the Contractor or with parties for other
services under conditions approved by the Management Committee.
15.06In consideration of the services provided by the Contractor
inuring to the Associate Participants, the Associate Participants shall make
payment directly to the Contractor for their share of the costs of providing
such services which shall be as follows or as subsequently established by the
Management Committee:
$200 for each fiscal year where the Annual System
Demand for the previous fiscal year is 5,000
kilowatts or less plus $60 for each 5,000 kilowatts
or fraction thereof by which such Annual System
Demand exceeds 5,000 kilowatts, with a maximum of
$10,000.
15.07The Contractor shall be responsible to maintain a staff adequate
to support the services required by the MAPP Committees. Such services shall
include but not be limited to gathering of historical data, maintaining a data
base for planning and operating studies, maintaining official records of the
MAPP Committees, administering certain contracts with other Parties or
entities for studies, publishing reports and filing such reports as required
with regulatory bodies, continuously monitoring the operation of the Pool and
the MAPP communications system, providing assistance in determining potential
operating problems, conducting studies as required, coordinating the
operations of the MAPP Region with adjoining coordinated regions and others
as appropriate, and carrying out projects of the MAPP Committees as directed.
ARTICLE XVI
MAINTENANCE OF ADEQUATE CAPABILITY
16.01Each Participant expects and is expected to maintain utility
responsibility for its own load and, as a part of such responsibility, shall
maintain during each month Accredited Capability in an amount equal to or
greater than its maximum System Demand for such month plus such Participant's
Reserve Capacity Obligation, as set forth in Paragraph 16.02.
16.02The Reserve Capacity Obligation of a Participant, for any month,
shall be equal to fifteen percent (ten percent for a predominantly hydro
system) of the Annual System Demand of such Participant or as established by
the Management Committee.
16.03The Engineering Committee shall determine the Accredited
Capability for each Participant on the following basis:
a. In respect to Net Generating Capability, the Accredited
Capability shall be determined in accordance with Paragraph
3.07.
b. In respect to purchases and sales under Service Schedules
"A," "B," and "K," the Accredited Capability shall include
the amount for which the Participant has contracted
provided that such transactions are in accordance with
rules and regulations established by the Engineering
Committee.
c. In respect to purchases and sales under Service Schedules
"H," "I," and "J," the Accredited Capability shall include
the amount for which the Participant has contracted plus
the associated reserve capacity established from the
percentage determined by the Management Committee subject
to the provisions of Paragraph 2.02 of Service Schedule "I"
provided that such transactions are in accordance with
rules and regulations established by the Engineering
Committee.
d. In respect to commitments for power from or to any electric
power supplier, which are not under the Service Schedules
of this Agreement but are under separate contracts now
existing or hereafter created, such commitments shall be
reflected in a Participant's Accredited Capability provided
that such transactions are in accordance with rules and
regulations established by the Engineering Committee. Each
Participant shall submit, if requested, copies of its
contracts for such commitments to the Engineering Committee
for the purpose of such determination.
Determinations of Accredited Capability shall be reviewed by the Engineering
Committee at least semi-annually and at any other time upon the written
request of any Participant and any appropriate changes resulting from such
review shall be made. In order to secure consistency and continuity in
determining Accredited Capability, the Engineering Committee shall establish
rules and regulations as necessary These rules and regulations shall reflect
the following understanding:
i. Approval of transactions which are associated with a
coordinated system development, which may include non-
Participants, will be on the basis of reliability
considerations.
ii. Transactions for capability deficiencies which are residual
to subparagraph (i) normally will be made with Pool
Participants and Pool surpluses normally will be dedicated
to such transactions.
iii. Transactions will not be compelled with a Participant for
power and energy from generating capacity constructed by a
Participant in excess of capacity recommended by the
Engineering Committee.
16.04The Engineering Committee shall continually review the load and
capability forecasts for the Participants. If the forecast of a Participant
indicates that, during any month of the ensuing period, the length of period
being determined by the Engineering Committee, such Participant will not meet
its Reserve Capacity Obligation, such Participant shall make arrangements to
obtain additional Accredited Capability as approved by the Engineering
Committee so that during such month it will have sufficient capacity to meet
its Reserve Capacity Obligation. In the event that during any month a
Participant did not meet its maximum System Demand plus its Reserve Capacity
Obligation, such Participant shall be required to obtain additional
Accredited Capability from the other Participants. The amount of Accredited
Capability required by the deficient Participant and the source or sources
will be determined by the Engineering Committee. If Accredited Capability is
not available from Participants, the Engineering Committee may recommend:
a. Purchase from non-Participants.
b. Other means of sharing Reserve Capacity to effect
equalization of reserves.
16.05Nothing contained in this Agreement shall be interpreted to
require a Party to install facilities or to restrict a Party's election of
whether to install facilities or purchase power to maintain its Accredited
Capability.
ARTICLE XVII
INSTALLATION OF ADDITIONAL FACILITIES
17.01It is the intent hereof to provide for an equitable staggering of
future investments in generating capacity and other facilities in order to
obtain maximum economy and benefits from interconnected system operation. It
is understood that the generating units installed by the Participants
hereafter should be the most economical size and type practicable, taking into
consideration the size of the installing Participants' systems, the loads of
the Participants, the anticipated growth of such loads, the transmission
facilities required to transmit the output thereof to such loads or to supply
such loads when the unit is not in service and the ability of the systems of
the Participants and their interconnections with other interconnected systems
to withstand the instantaneous loss of such units without causing unstable
operation. It is also anticipated, that, in general, the amount and type of
additional generating capacity to be installed by any Participant shall take
into consideration the load and the load growth of such Participant and that
the installation of specific generating units shall be rotated among the
Participants so as to accomplish this overall intent. Whenever the
recommendation of the Engineering Committee is that a Participant construct
and install any additional generating or transmission facilities, such
Participant shall not be deemed committed to such construction or installation
unless it has elected to accept such recommendation by proper corporate action
reported by its representative on the Management Committee.
17.02It is understood by the Parties that nothing in the Agreement is
intended to preclude a Participant from constructing or utilizing generation
and transmission facilities other than those recommended by the Engineering
Committee; however, such facilities shall be subject to the established
reliability standards.
ARTICLE XVIII
MAINTENANCE OF ADEQUATE OPERATING RESERVE
18.01Each Participant shall provide Spinning Reserve and Non-Spinning
Reserve in the proportions recommended by the Operating Committee and
established by the Management Committee, equal to or greater than the
Operating Reserve Obligation of the Participant, as provided in Paragraph
18.02. As soon as practicable after the occurrence of an incident which
utilizes Operating Reserve, each Participant shall restore its Operating
Reserve Obligation by following procedures determined by the Operating
Committee.
18.02The Total Operating Reserve Obligation at any time shall initially
be an amount equal to 150 percent of the capability of the largest generating
unit in operation on the interconnected systems of the Participants and shall
be subject to revision by the Management Committee. The Operating Reserve
Obligation of a Participant shall be that percentage of the Total Operating
Reserve Obligation determined by the Operating Committee in accordance with
formula based on the capability of the largest generating unit of each
Participant and the Annual System Demand of such Participant. Initially one-
third weight shall be given to unit size and two-thirds weight to Annual
System Demand, such weighting shall be subject to revision by the Management
Committee.
18.03The Operating Committee will establish procedures for determining
the Operating Reserve that is available on the systems of the Participants at
all times. Whenever a Participant is unable to meet its Operating Reserve
Obligation, such Participant shall immediately advise all other Participants
and make arrangements to restore its Operating Reserve Obligation.
ARTICLE XIX
SERVICES TO BE RENDERED
19.01The various specific services to be rendered in furtherance of the
purposes of this Agreement are covered by Service Schedules of the Agreement
which are listed as follows:
"A" Participation Power Interchange Service
"B" Seasonal Participation Power Interchange Service
"C" Emergency and Scheduled Outage Interchange Service
"D" Operating Reserve Interchange Service
"E" Economy Energy Interchange Service
"F" Transmission Services and Losses
"G" Operational Control Energy Interchange Service
"H" Peaking Power Interchange Service
"I" Short Term Power Interchange Service
"J" Firm Power
"K" System Participation Power
"L" Interruptible Load Replacement Energy Service
"M" General Purpose Energy Service
19.02The Service Schedules are intended to facilitate coordinated daily
operation and the staggering of generation additions in accordance with
Paragraph 10.05 (d) and Article XVII and shall not be used to provide power
supply from a generation source for a greater period than that consistent with
Article XVII.
19.03The providing of Transmission Service under Service Schedule "F"
is based on each Participant providing an equitable portion of the
transmission facilities required to accomplish the coordinated daily operation
and coordinated planning contemplated hereunder.
a. Participants meeting the following criteria will be assumed
to be providing an equitable share of transmission:
i. Whose system is normally operated directly
interconnected with two or more Participants systems.
ii. Which owns or controls transmission facilities
operated at 115 Kv or higher forming an integral part
of the regional transmission network.
b. All other Participants may meet the qualifications set
forth in (a) through contractual arrangements with a
Participant which does meet the qualifications and to which
it is interconnected. Participants shall negotiate such
arrangements in good faith and in doing so shall be
expected to permit a Participant to qualify under this
subsection by making investment in facilities or by making
payments. The investment facilities or payments shall be
calculated to compensate the Participant for the use of its
facilities for transactions under the Service Schedules.
If two Participants are unable to negotiate a mutually
satisfactory contracting arrangement within a period of six
months after written notice has been received from the
Participant expressing a desire to enter into such a
contractual arrangement and the Participant receiving such
notice is a public utility within the meaning of section
201 (e) of the Federal Power Act, the Participant receiving
such notice shall, at the written request of the other
Participant, made at any time following the expiration of
six month period, file within sixty (60) days thereafter a
contractual arrangement with the Federal Energy Regulatory
Commission in accordance with the provision of section 205
of the Federal Power Act and the Regulations thereunder.
ARTICLE XX
SERVICE OBLIGATIONS
20.01It is recognized that the systems of the Participants are now or
may be interconnected with other systems and that other agreements for
interconnection, mutual assistance, pooling, power supply and transmission
service may exist or may be entered into between Participants or between a
Participant and another system. It is understood that the Participants intend
to assist each other to the maximum extent of their capabilities, but it is
recognized that such agreements may limit the capacities available to
Participants under the terms hereof.
20.02Any Participant, upon request by any other Participant, shall
supply to such other Participant Emergency Energy up to the full amount of its
Available Accredited Capability provided that such request conforms with the
provisions of Service Schedule "C."
20.03Any Participant, upon request by any other Participant, shall
supply to such other Participant Scheduled Outage Energy up to the full amount
of its Accredited Capability not required to maintain its Operating Reserve
Obligation; provided that the delivery thereof shall conform with the
provisions of Service Schedule "C" and provided further that, if the
requesting Participant is not using its Total Available Accredited Capability,
the Participant requested to supply scheduled Outage Energy shall not be
obligated to supply such energy when in the sole judgment of such Participant,
the supply of such energy would cause a hardship.
20.04Any Participant may procure through its interconnection with other
electric suppliers, Emergency Energy or Scheduled Outage Energy in addition
to that which can be supplied by the Participants which may be available under
agreements covering such interconnections from a source or sources which will
result in the lowest cost to the receiving Participant and shall arrange for
the delivery of such Emergency Energy or Scheduled Outage Energy to such
receiving Participant; provided that the delivery thereof can be made, in the
sole judgment of the Participant procuring such service, without endangering
its facilities or interfering with its obligations to its customers, other
Participants, or other electric suppliers.
20.05Any Participant whose transmission facilities are required to
provide Transmission Service for Emergency Energy supplied to a receiving
Participant shall transmit such energy up to such amounts as will not, in the
sole judgment of the Participant providing the Transmission Service, endanger
its facilities or interfere with its obligations to its customers, other
Participants, or other electric suppliers.
20.06Any Participant, upon request by any other Participant, shall
supply to such other Participant, Operating Reserve up to the full amount of
its Available Accredited Capability not required to maintain its Operating
Reserve Obligation; provided that the delivery thereof shall conform with the
provisions of Service Schedule "D" and provided further, however, that there
shall be no obligation of a Participant to supply Operating Reserve if the
requesting Participant is not making full use of its Available Accredited
Capability.
20.07Any Participant, when called upon to do so by any other
Participant, may supply Economy Energy to such other Participant provided such
call conforms with the provisions of Service Schedule "E."
20.08Any Participant, when called upon to do so by any other
Participant, may supply Interruptible Load Replacement Energy to such other
Participant, provided such call conforms with the provisions of Service
Schedule "L."
20.09Any Participant, when called upon to do so by any other
Participant, may supply General Purpose Energy to such other Participant,
provided such call conforms with the provisions of Service Schedule "M."
20.10Each Participant agrees that it will provide Transmission Service
in accordance with the provisions of Section 19.03 and Service Schedule "F."
The Participants shall endeavor to make maximum use of facilities for Pool
transactions consistent with MAPP reliability standards. Nothing herein shall
be construed as obligating any of the Participants to provide Transmission
Service other than for Participants in accordance with Section 19.03 and
Service Schedule "F".
20.11The service obligations set forth in this Article are each subject
to the limitations that the Participant on which the request is made as
therein stated shall not be obligated to use Available Accredited Capability
if it is at the time being used to supply the requirements of its customers
including obligations now existing or hereafter created to other Participants
or to other electric suppliers. A Participant shall not be obligated to
deliver power and energy over its transmission facilities if, in the sole
judgment of said Participant, such delivery will:
a. Endanger its facilities, or
b. Interfere with its obligations, now existing or hereafter
created, to its customers or to other electric suppliers.
20.12The Participant purchasing power and energy under Service
Schedules "A," "B," "H," "I," "J," "K," and "L" shall be responsible for
initiating scheduled deliveries thereunder and the scheduled rate of delivery
shall not exceed the amount being purchased under the Schedule. In the
scheduling of deliveries, due consideration shall be given to the rate of
change of delivery and the continuity of delivery so as not to cause undue
hardship on the system of the supplying Participant.
ARTICLE XXI
SERVICE CONDITIONS
21.01The systems of the Participants shall be operated interconnected
continuously under normal system conditions and the Participants shall
cooperate in keeping the frequency of the interconnected systems of the
Parties at 60 Hz as closely as is practicable, in keeping the interchange of
power and energy between the systems of the Participants as closely as is
practicable to the scheduled amounts and in maintaining mutually satisfactory
voltage levels. Each Participant shall be responsible for the reactive volt-
ampere requirements of its system. Reactive volt-amperes may be interchanged
between systems from time to time, subject to agreement between the
Participants involved, when benefit to one system may be gained thereby
without causing hardship to another system.
21.02The systems of the Participants shall normally be so maintained
and operated as to minimize, in accordance with good practice, the likelihood
of a disturbance originating in the system of one Participant causing
impairment to the service of the system of any other Participant or of any
other system with which the systems of the Participants are interconnected.
21.03It is recognized that unintentional interchange of power and
energy between interconnected systems will occur because of the impossibility
of continuously controlling generation to exactly equal the load. It also
is recognized that, due to the manner in which the systems of the Participants
are interconnected with each other and with other systems, a portion of the
power and energy scheduled for delivery between any two of such interconnected
systems may not flow directly from the supplier thereof to the receiver
thereof over the intended route through the transmission systems of the
Participants, but may result in inadvertent flows through other systems.
Therefore, because of these conditions:
a. All intentional power and energy deliveries between the
system of one Participant and the system of another
Participant shall be scheduled in advance.
b. It shall be the responsibility of each Participant to
maintain the net power and energy flowing into and out of
its system during each hour so that deliveries are, as near
as practicable, equal to the net scheduled amount. The
difference between the net scheduled deliveries and the
actual net deliveries shall be balanced out in kind in
accordance with principles and practices established by the
Operating Committee.
c. A Participant shall be entitled to compensation for losses
caused by the flow of power and energy scheduled from or to
another Participant. Such compensation shall be in the
form of an equivalent amount of energy in accordance with
methods determined by the Operating Committee.
d. It is not the intent to grant any Participant any right
generally to use the system of any other Participant as an
intermediary in power and energy transactions, nor shall
consent by a Participant to any power and energy flows
through its system in a particular case create any rights
for a Participant to continue such flows; and, where such
flows are objectionable to a Participant experiencing such
flows, the Participants shall cooperate to prevent such
flows from occurring normally and to minimize flows of this
character.
ARTICLE XXII
METERING
22.01All metering equipment required for recording the deliveries of
power and energy between the systems of each Participant and the systems of
the other Participants with which it is interconnected shall be maintained by
the Parties owning such metering equipment in accordance with good practice
and accepted industry standards.
22.02Should any such metering equipment at any time fail to register
or should the registration thereof be so erratic as to be meaningless, the
power and energy delivered shall be determined from the best information
available.
ARTICLE XXIII
RECORDS
23.01In addition to meter records, the Participants shall keep such log
sheets and other records (determined by the Operating Committee) as may be
needed to afford a clear history of the various movements of power and energy
between the systems of the Participants involved both in transactions
hereunder and in transactions between Participants hereto under other
agreements between such Participants and to effect such differentiation as may
be needed in connection with settlements in respect to such transactions. The
originals of all such meter records and other records shall be open to
inspection by representatives of the Participants concerned and by the
Operating Committee.
23.02Each Party shall furnish to the Operating Committee appropriate
data from meter registrations and from other sources on such time basis as are
determined by the Operating Committee when such data is needed for
settlements, special tests, operating records or for other purposes consistent
with the objectives hereof. As promptly as practicable after the end of each
month, each Participant shall render to the other Participants concerned,
statements setting forth appropriate data from meter registrations and other
sources in such detail and with such segregation as may be needed for
operating records and for settlements hereunder.
ARTICLE XXIV
BILLINGS AND PAYMENTS
24.01For billing purposes, the amount of energy delivered pursuant to
this Agreement by a supplying Participant to a receiving Participant, during
any period, shall be the amount scheduled for delivery.
24.02Billing for any transaction involving generation or transmission
capacity pursuant to this Agreement, including any Transmission Service
charges pertaining to such transaction, shall be based upon the amount of such
capacity committed in advance for delivery.
24.03All bills for services supplied pursuant to this Agreement shall
be rendered monthly by the supplying Participant to the purchasing Participant
after the end of the period to which such bills are applicable. Unless
otherwise agreed upon by the Operating Committee, such period shall be from
12:01 AM on the first day of the month to 12:01 AM of the first day of the
succeeding month. Bills shall be due and payable within fifteen days from the
date such bills are rendered and payment shall be made when due and without
deduction. Bills shall be deemed rendered on the postmark date if deposited
in first class mail with postage prepaid and shall be deemed rendered upon
receipt if another means of delivery is used. If the due date of any bill
falls on Saturday, Sunday or holiday observed by either Party, the bill shall
be due and payable on the next following working day of both Parties. Interest
shall accrue and be compounded daily on any unpaid amount, from the date due
until the date upon which payment is made, using the lowest daily prime rates
published in the money rates section of the Wall Street Journal for the
applicable time period. Such daily interest shall be computed on the basis
of actual days and a 365 day calendar year.
24.04Billing for Transmission Service shall be rendered monthly in a
manner to be determined by the Operating Committee.
24.05In the event a Participant desires to dispute all or any part of
the charges submitted by some other Participant, it shall nevertheless pay the
full amount of the charges when due and give notification in writing within
sixty (60) days from the date of the statement stating the grounds on which
the charges are disputed and the amount in dispute. The complaining
Participant will not be entitled to any adjustment on account of any disputed
charges which are not brought to the attention of the Participant rendering
such charges within the time and in the manner herein specified. If
settlement of the dispute results in a refund to the payer, interest shall
accrue and be compounded daily on the amount to be refunded from the date of
payment until the date upon which refund is made, using the lowest daily prime
rates published in the money rates section of the Wall Street Journal for the
applicable time period. Such daily interest shall be computed on the basis
of a 365 day year.
24.06All billings under this Agreement shall be determined and stated
and all payments shall be made in the currency of the United States of
America. For all billings, the rate to be used to convert from the currency
of the United States to that of Canada or from the currency of Canada to that
of the United States shall be the monthly average noon spot exchange rate for
the monthly billing period covered by such billing provided by the Royal Bank
of Canada, Winnipeg, Manitoba.
ARTICLE XXV
TAXES
25.01Any tax imposed upon the seller and levied upon or measured by
power or energy supplied by one Participant to another Participant shall be
added to the bill rendered by the Participant supplying the power or energy.
ARTICLE XXVI
UNCONTROLLABLE FORCES
26.01A Participant shall not be considered to be in default in respect
of any obligation hereunder if prevented from fulfilling such obligation by
reason of uncontrollable forces. The term "uncontrollable forces" shall be
deemed for the purposes hereof to mean storm, flood, lightning, earthquake,
fire, explosion, failure of facilities not due to lack of proper care or
maintenance, civil disturbance, labor disturbance, sabotage, war, national
emergency, restraint by court or public authority, or other causes beyond the
control of the Participant affected which such Participant could not
reasonably have been expected to avoid by exercise of due diligence and
foresight and by provision of reserves in accordance with the requirements of
this Agreement. Any Participant unable to fulfill any obligation by reason
of uncontrollable forces will exercise due diligence to remove such disability
with reasonable dispatch, but such obligation shall not require the settlement
of a labor dispute except in the sole discretion of the Participant
experiencing such labor dispute.
ARTICLE XXVII
WAIVERS
27.01Any waiver at any time by any Party of its rights with respect to
a default under this Agreement, or with respect to any other matter arising
in connection with this Agreement, shall not be deemed a waiver with respect
to any subsequent default or other matter arising in connection herewith. Any
delay short of the statutory period of limitation in asserting or enforcing
any right shall not be deemed a waiver of such right, except as provided in
Paragraph 24.05 of this Agreement.
ARTICLE XXVIII
NOTICES
28.01Any formal notice, demand or request required or authorized by
this Agreement shall be deemed properly given if mailed, postage prepaid, to
the Management Committee representative of the Party concerned, at the address
of such Party shown on the signature pages hereof.
28.02Any notice or request of a routine character in connection with
delivery of power and energy or in connection with operation of facilities,
shall be given in such manner as the Operating Committee from time to time
shall arrange.
ARTICLE XXIX
SUCCESSORS AND ASSIGNS
29.01No Party shall assign this Agreement without the consent, in
writing, of the other Parties, except in connection with the sale or merger
of a substantial portion of its properties including its high voltage
transmission facilities.
29.02The several provisions of this Agreement are not intended to and
shall not create rights of any character whatsoever in favor of any persons,
corporations, or associations other than the Parties to this Agreement and the
obligations herein assumed are solely for the use and benefits of the Parties
to this Agreement.
ARTICLE XXX
ARBITRATION
30.01Any controversy or claim arising out of or relating to this
Agreement or the breach thereof, or appeal from action of the Management
Committee under Paragraph 8.07 of this Agreement, shall be settled by
arbitration. Such arbitration shall be conducted before a board of three
arbitrators selected by the American Arbitration Association and the
arbitration shall be conducted in accordance with the commercial arbitration
rules of the American Arbitration Association then in effect, subject to the
further qualification that the arbitrators named under said rules shall be
competent by virtue of education and experience in the particular matter
subject to arbitration.
30.02The Party or Parties desiring arbitration shall demand such
arbitration by giving written notice to the other Party or Parties involved.
Such notice shall conform to the procedures of the American Arbitration
Association and shall include a statement of the facts or circumstances
causing the controversy and the resolution, determination or relief sought by
the Party or Parties desiring arbitration.
30.03 Before the matter is presented to the board of arbitrators a
conference shall be held to attempt to resolve the controversy or if that is
not possible, to stipulate as many facts as possible and to clarify and narrow
the issues to be submitted to arbitration.
30.04 The board of arbitrators shall have no authority, power or
jurisdiction to alter, amend, change, modify, add to or subtract from any of
the provisions of this Agreement nor to consider any issues arising other than
from the language in and authority derived from this Agreement.
30.05 The decision or award of the arbitrators shall be final and
binding upon the Parties and the Parties shall do such acts as the arbitration
decision or award may require of them. Judgment upon any award rendered by
the arbitrators may be entered in any court having jurisdiction and execution
issued thereon. This provision shall survive the termination of this
Agreement.
30.06 The Party or Parties demanding arbitration shall pay the costs
incurred in connection with the arbitration.
ARTICLE XXXI
CHOICE OF LAW
31.01In order to promote the uniformity of the interpretation of this
Agreement, it is agreed that the laws of the State of Minnesota shall control
the obligations and procedures established by this Agreement and the
performance and enforcement thereof.
ARTICLE XXXII
REGULATION
32.01This Agreement is subject to the regulation of any regulatory body
having jurisdiction thereof.
ARTICLE XXXIII
AMENDMENTS
33.01Any Participant may propose an amendment to this Agreement by
filing such proposed amendment with the Chairman of the Management Committee
who shall immediately forward copies thereof to the Participants. Each
Participant shall forward its vote to the Chairman and said vote must be
received by the Chairman within sixty (60) days after the date of filing.
33.02In voting on any amendment, each Participant shall have the same
number of votes as its representative would have under Paragraph 8.06. If
seventy-five percent (75%) or more of the total authorized votes favor the
amendment, such amendment will become effective 120 days after filing with the
Chairman of the Management Committee but no amendment shall affect
transactions agreed upon in writing prior to the effective date of such
amendment. Abstentions shall be counted as negative votes.
33.03 Notwithstanding Section 33.02 above, amendments that are subject
to the jurisdiction of the Federal Energy Regulatory Commission (FERC) will
become effective only upon acceptance without change or condition by the FERC,
or if accepted with change or condition by the FERC, upon confirmation and
approval of such change or condition by an affirmative vote of seventy-five
percent (75%) or more of the total authorized votes of the Management
Committee, and unless otherwise provided, will become effective the first day
of the MAPP Season following acceptance by the FERC, and if necessary,
confirmation by the Management Committee.
ARTICLE XXXIV
INTRA-CORPORATE RELATIONSHIPS
34.01Northern States Power Company, a Minnesota corporation,
hereinafter called "NSP," as a Participant herein shall include its
subsidiary, Northern States Power Company, a Wisconsin corporation. All
interchanges of power and energy between said companies and other Participants
shall be considered as transactions between such Participants and NSP.
34.02Minnesota Power & Light Company, a Minnesota corporation,
hereinafter called "MP," as a Participant herein shall include its subsidiary
Superior Water, Light and Power Company, a Wisconsin corporation. All
interchanges of power and energy between said companies and other Participants
shall be considered as transactions between such Participants and MP.
ARTICLE XXXV
PARTICIPATION BY THE WESTERN AREA POWER ADMINISTRATION
35.01The Parties understand that participation in this Agreement by THE
UNITED STATES OF AMERICA, hereinafter called the United States, is limited to
application of this Agreement to a specific electric system operated by the
Western Area Power Administration.
a. Application of this Agreement to the United States is
limited to a defined part of the electric system operated
by, and of the electric power facilities and resources
available to, the EASTERN DIVISION, PICK-SLOAN MISSOURI
BASIN PROGRAM, or its successor administrative entities.
b. Transactions between said Eastern Division of the Pick-
Sloan Missouri Basin Program and other power systems of the
United States shall be considered to be internal, one-
entity transactions for the purposes of this Agreement.
35.02The participation by the United States in this Agreement is
subject in all respects to acts of Congress and to regulations of the
Secretary of Energy established thereunder and rate schedules promulgated by
the Secretary of Energy or delegatee. This reservation includes, but is not
limited to:
a. The operation and administration of provisions of law
giving preference to certain classes of customers in the
sale of Federal power.
b. The final authority of Congress in all matters relating to
the installation, construction or operation of facilities.
c. The statutory authority of the Secretary of Energy to set
rates for the sale of power by the United States.
d. The statutory limitations upon the authority of the
Secretary of Energy to submit disputes arising under this
contract to arbitration.
35.03Contingent Upon Appropriations: Notwithstanding Article VI, where
the operations of this Agreement extend beyond the current fiscal year,
participation by the United States is contingent upon Congress making the
necessary appropriation for expenditures by the United States after such
current year shall have expired. In case such appropriation as may be
necessary to carry out obligations of the United States under this Agreement
is not made, the Parties release the United States from all liability due to
the failure of Congress to make such appropriation.
35.04Officials Not To Benefit: No member of or Delegate to Congress or
Resident Commissioner shall be admitted to any share or part of this Agreement
or to any benefit that may arise herefrom, but this restriction shall not be
construed to extend to this Agreement if made with corporations or companies
for their general benefit.
35.05Covenant Against Contingent Fees: The Parties warrant that no
person or selling agency has been employed or retained to solicit or secure
participation by the United States in this Agreement upon an agreement or
understanding for a commission, percentage, brokerage or contingent fee,
excepting bona fide employees or bona fide established commercial or selling
agencies maintained by the Parties for the purpose of securing business. For
breach or violation of this warranty, the United States shall have the right
to annul its participation in this Agreement without liability or, in its
discretion, to deduct from the contract price or consideration due from the
United States the full amount of such commission, percentage, brokerage, or
contingent fee.
35.06Utility Responsibility: Any reference in this Agreement to
"utility responsibility" of a Participant shall apply to the United States
only to the extent, and in the sense, that the United States has
responsibility for satisfying its obligations for power service as established
by other contracts.
35.07Membership in Other Groups: It is understood by the Parties that
the United States is at present a participant in the Western Systems
Coordinating Council (for a small part of its western facilities and
operations) and the Missouri Basin Systems Groups (for certain planning
coordination and joint transmission activities) and the United States may in
the future participate in other similar coordination arrangements.
Participation of the United States is dependent on its understanding that
nothing in this Agreement would preclude such other participation or
commitment of resources thereto, but rather that it remains the responsibility
of each Participant to insure that its obligations are not in conflict.
35.08Rate Schedules: Rate Schedules for rates and conditions of service
by the United States shall be governed by rate schedules promulgated by the
Secretary of Energy or delegatee:
a. The Service Schedules, except for Service Schedule "F"
Transmission Services and Losses, shall not apply to the
transactions of the United States. Service Schedule "F"
will apply to transactions to which the United States is a
party and to transactions by other Participants which
utilize the transmission system of the United States.
b. The United States will initiate discussion with the other
Participants as to the future applicability of the Service
Schedules to transactions made by the United States.
35.09Area Relations Committee: It is understood by the Parties that
Federal agencies are prohibited by law from participating in or contributing
to any activities influencing legislation or involving lobbying.
Participation of the United States in this Agreement and especially as to
participation in the Area Relations Committee, shall be limited to activities
that are clearly legal for an agency of the United States.
35.10Provisions Relative to Employment: The following provisions
governing employment under government contracts are set forth in Article P of
the "General Power Contract Provisions" made a part of all current power
contracts entered into by the Western Area Power Administration. It is
understood by the Parties that these provisions shall be applicable hereunder
to transactions between the United States and other Participants. For the
purpose of this Paragraph 35.10, the term "contract" shall mean this Agreement
and the term "Contractor" shall mean a Participant having transactions with
the United States.
a. During the performance of this contract, the Contractor
agrees as follows:
i. The Contractor will not discriminate against any
employee or applicant for employment because of race,
color, religion, sex or national origin. The
Contractor will take affirmative action to ensure
that applicants are employed and that employees are
treated during employment, without regard to their
race, color, religion, sex, or national origin. Such
action shall include, but not be limited to, the
following: employment, upgrading, demotion or
transfer, recruitment or recruitment advertising,
layoff or termination, rates of pay or other forms
of compensation, and selection for training,
including apprenticeship. The Contractor agrees to
post in conspicuous places, available to employees
and applicants for employment, notices to be provided
by the Contracting Officers setting forth the
provisions of this Equal Opportunity clause.
ii. The Contractor will, in all solicitations or
advertisements for employees placed by or on behalf
of the Contractor, state that all qualified
applicants will receive consideration for employment
without regard to race, color, religion, sex, or
national origin.
iii. The Contractor will send to each labor union or
representative of workers with which he has a
collective bargaining agreement or other contract or
understanding, a notice, to be provided by the agency
Contracting Officer, advising the labor union or
workers' representative of the Contractor's
commitments under this Equal Opportunity clause and
shall post copies of the notice in conspicuous places
available to employees and applicants for employment.
iv. The Contractor will comply with all provisions of
Executive Order No. 11246 of September 24, 1965, and
the rules, regulations and relevant orders of the
Secretary of Labor.
v. The Contractor will furnish all information and
reports required by Executive Order No. 11246 of
September 24, 1965, and by the rules, regulations and
orders of the Secretary of Labor or pursuant thereto
and will permit access to his books, records and
accounts by the contracting agency and the Secretary
of Labor for purposes of investigation to ascertain
compliance with such rules, regulations and orders.
vi. In the event of the Contractor's noncompliance with
the Equal Opportunity clause of this contract or with
any of the said rules, regulation or orders, this
contract may be canceled, terminated or suspended, in
whole or in part, and the Contractor may be declared
ineligible for further Government contracts in
accordance with procedures authorized in Executive
Order No. 11246 of September 24, 1965, and such
other sanctions may be imposed and remedies invoked
as provided in Executive Order No. 11246 of September
24, 1965, or by rule, regulation or order of the
Secretary of Labor, or as otherwise provided by law.
vii. The Contractor will include the provisions of
paragraphs (i) through (vii) in every subcontract or
purchase order unless exempted by rules, regulations
or orders of the Secretary of Labor issued pursuant
to Section 204 of Executive Order No. 11246 of
September 24, 1965, so that such provisions will be
binding upon each subcontractor or vendor. The
Contractor will take such action with respect to any
subcontract or purchase as the contracting agency may
direct as a means of enforcing such provisions,
including sanctions or noncompliance; provided
however, that in the event the Contractor becomes
involved in, or is threatened with, litigation with
a subcontractor or vendor as a result of such
direction by the contracting agency, the Contractor
may request the United States to enter into such
litigation to protect the interests of the United
States.
b. In the performance of any part of the work contemplated by
this contract, the Contractor shall not employ any person
undergoing sentence of imprisonment at hard labor.
ARTICLE XXXVI
PARTICIPATION BY THE MANITOBA HYDRO
36.01The generating and transmission systems of the Manitoba Hydro and
the City of Winnipeg Hydro Electric System are interconnected and operated as
a single system. Manitoba Hydro provides any additional generating capacity
required to meet the combined needs of Manitoba Hydro and the City of
Winnipeg. For the purposes of this Agreement, System Demand and Accredited
Capability for Manitoba Hydro shall be determined for the combined systems of
Manitoba Hydro and the City of Winnipeg Hydro Electric System.
36.02The participation by Manitoba Hydro in this Agreement is subject
in all respects to legislation of the Governments of Canada and Manitoba.
This includes but is not limited to: a. The final authority of the Government
of Canada in all matters relating to the export of electric power. b. The
final authority of the Government of Manitoba in all matters relating to the
installation or construction of facilities.
36.03It is understood by the Parties that Manitoba Hydro has entered
into interconnection agreements with electric utilities in other Provinces of
Canada. Under the terms of these agreements, Manitoba Hydro may not make
commitments to supply surplus electric power and energy or any other related
services to a utility based outside of Canada without first giving utilities
based in Canada the prior right to purchase such surplus electric power,
energy and other services on the same terms and conditions and at an
equivalent price.
36.04The reliability characteristics of Manitoba Hydro's generating
facilities, which are predominantly hydroelectric, shall be considered when
establishing Manitoba Hydro's Reserve Capacity Obligation.
36.05It is an acknowledged condition to the participation by Manitoba
Hydro in this Agreement that:
a. Nothing in this Agreement shall alter or diminish the
rights of other Canadian electric utilities to purchase
surplus electric power, energy, and services from Manitoba
Hydro.
b. Nothing in this Agreement shall preclude participation by
Manitoba Hydro in any Canadian electric power pool or the
commitment of resources thereto.
c. Manitoba Hydro's participation in the Area Relations
Committee shall be limited to activities which are clearly
nonpolitical inasmuch as Manitoba Hydro does not have the
right to participate in or contribute to any activity which
is intended to influence legislation.
d. Any provision governing employment or production of goods
and services enacted by the Congress of the United States
of America or enacted by any other legislative body in the
United States of America shall not be applicable to any
power or other service provided by Manitoba Hydro to the
United States of America or to any other party in the
United States of America.
e. The authority of the Federal Energy Regulatory Commission
on matters pertaining to power transactions between
Manitoba Hydro and the other Parties shall not be
applicable to the transmission or use of such power within
Canada.
f. The provisions of Article XXX shall not apply to any
controversy, claim or dispute arising out of or relating to
this Agreement or the breach thereof which involves
Manitoba Hydro and any such controversy, claim or dispute
shall be referred to the Chief Executive Officer of each of
the disputing parties to resolve.
g. Notwithstanding Article XXXI, the laws of the Province of
Manitoba, Canada, shall apply to any transactions
undertaken or services rendered in Canada and the
performance and enforcement thereof.
Execution. Separate copies of this Agreement are executed by the
Parties with the understanding that, when each of the Parties has executed a
copy, its separately executed copy will be joined together with all other
similarly executed copies and one conformed master copy of said agreement
shall be prepared, which shall bind all of the Parties to the same extent and
purpose as if all of said Parties had joined in the execution of said master
copy.
<PAGE>
IN WITNESS WHEREOF, each of the Parties has caused this Agreement to be
executed by its duly authorized officer as of the day and year of the
membership shown below.
SIGNATORY PARTICIPANTS
(Date of Membership)
BASIN ELECTRIC POWER COOPERATIVE ARTHUR JONES
(August 14, 1975) President
CENTRAL IOWA POWER COOPERATIVE JOSEPH C. ARMBRECHT
(March 31, 1972) President
COOPERATIVE POWER ASSOCIATION ORVILLE J. LIPKE
(March 31, 1972) President
CORN BELT POWER COOPERATIVE WARREN C. SNELL
(March 31, 1972) President
DAIRYLAND POWER COOPERATIVE JOHN P. MADGETT
(March 31, 1972) General Manager
HEARTLAND CONSUMERS POWERDISTRICT WENDELL J. GARWOOD
(February 13, 1979) General Manager
HUTCHINSON UTILITIES COMMISSION THOMAS B. LYKE
(February 25, 1991) Vice President
INTERSTATE POWER COMPANY GLENN J. LYSHOJ
(March 31, 1972) Vice President
IOWA ELECTRIC LIGHT AND POWER COMPANY DUANE ARNOLD
(March 31, 1972) Chairman of the Board and President
IOWA-ILLINOIS GAS AND ELECTRIC COMPANY C. J. MATH
(March 31, 1972) Vice President
IOWA POWER AND LIGHT COMPANY D. H. SWANSON
(March 31, 1972) President
IOWA PUBLIC SERVICE COMPANY F. W. GRIFFITH
(March 31, 1972) Chairman and President
IOWA SOUTHERN UTILITIES COMPANY R. F. BREWER
(March 31, 1972) President
LINCOLN ELECTRIC SYSTEM WALTER A. CANNEY
(December 1, 1977) Administrator
MINNESOTA POWER J. F. ROWE
(March 31, 1972) Executive Vice President
MINNKOTA POWER COOPERATIVE, INC. TED M. LEE
(March 31, 1972) President
MISSOURI BASIN MUNICIPAL POWER AGENCY RUSSELL DAU
(March 12, 1980) General Manager
MONTANA-DAKOTAS UTILITIES CO. DAVID M. HESKETT
(March 31, 1972) President
MUSCATINE POWER & WATER JAMES P. FULLER
(March 19, 1976) General Manager
NEBRASKA PUBLIC POWER DISTRICT DON E. SCHAUFELBERGER
(March 31, 1972) Deputy General Manager
NORTHERN STATES POWER COMPANY EDWARD C. SPETHMANN
(March 31, 1972) Vice President - Public Affairs
NORTHWEST IOWA POWER COOPERATIVE CARL PAULSON
(November 26, 1979) Exec. Vice President and General Manager
NORTHWESTERN PUBLIC SERVICE COMPANY A. D. SCHMIDT
(March 31, 1972) President
OMAHA PUBLIC POWER DISTRICT A. L. MONROE
(March 31, 1972) General Manager
OTTER TAIL POWER COMPANY DONALD F. VRASPIR
(December 27, 1979) Vice President
SOUTHERN MINNESOTA MUNICIPAL POWER AGENCY PIERRE HEROUX
(November 1, 1982) Executive Director
UNITED POWER ASSOCIATION
(May 1, 1972)
THE UNITED STATES OF AMERICA H. E. ALDRICH
(March 31, 1972) Regional Director, Region 6
U.S. Bureau of Reclamation
SIGNATORY ASSOCIATE PARTICIPANTS
AMES MUNICIPAL ELECTRIC SYSTEM MERLIN C. HOVE
(January 5, 1983) Director
CEDAR FALLS, IOWA LEONARD J. KEEFE
(March 31, 1972) Cedar Falls Utilities Board of Trustees
CUMBERLAND MUNICIPAL UTILITY CHARLES CHRISTENSEN
(December 30, 1982) Manager
DELANO, MINNESOTA LAURENCE RIEDER
(March 31, 1972) Mayor
FREMONT, NEBRASKA MILTON LAUNER
(January 9, 1980) Assistant General Manager
GLENCOE, MINNESOTA DONALD A. NELSON
(March 31, 1972) Secretary
Light & Power Commission
GRAND ISLAND, NEBRASKA R. J. OLSON
(September 6, 1977) Director of Utility Operation
HARLAN MUNICIPAL UTILITIES F. JAMES KALAL
(July 14, 1983) General Manager
MADELIA, MINNESOTA C. W. SEIBERT
(March 31, 1972) Commissioner
Public Utilities Commission
MUNICIPAL ENERGY AGENCY OF NEBRASKA H. STEVE WACKER
(June 26, 1979) General Manager
NORTH IOWA MUNICIPAL ELECTRIC COOPERATIVE
ASSOCIATION RONALD L. DEIBER
(March 9, 1982) President
NORTHWESTERN WISCONSIN ELECTRIC CO. FRED E. DAHLBERG
(March 31, 1972) President
OWATONNA, MINNESOTA TY SINCOCK
(November 1, 1972) President
Municipal Public Utilities
ROCHESTER, MINNESOTA R. JOHN MINER
(January 2, 1980) Director
SASKATCHEWAN POWER CORPORATION K. D. WELLMAN
(February 10, 1981) Corporate Legal Counsel
WISCONSIN PUBLIC POWER, INC. DAVID PENN
(November 2, 1990) General Manager
MID-CONTINENT AREA POWER POOL
Service Schedule A
Participation Power Interchange Service
Section 1.Service to be Provided
1.01 This Schedule provides for the sale of Participation Power by a
Participant to any other Participant from a specific generating unit or units.
Participation Power shall mean power and energy which is sold from a specific
generating unit or units on the basis that it is continuously available except
when such unit or units are temporarily out of service for maintenance during
which time the delivery of energy from other sources shall be at the seller's
option.
Section 2.Conditions of Service
2.01 This Schedule shall be available for the sale of Participation
Power for a period of six months or more.
2.02 Participation Power shall be supplied through transmission
facilities which have adequate capacity for transmitting such power and
energy, and Transmission Service shall be arranged in accordance with the
procedures established under Service Schedule "F."
2.03 FERC-regulated Participants who enter into transactions to sell
power under this schedule shall file the applicable agreement with the FERC
as a rate schedule.
Section 3.Schedule of Rates
3.01 The rate and term for Participation Power under this Service
Schedule "A" shall be negotiated by the Participants arranging the
transaction.
3.02 In the event that service cannot be supplied on the effective date
of an Agreement to sell Participation Power under this Service Schedule "A"
due to a delayed in-service date of the associated generating facilities, the
demand charge to be paid by the purchasing Participant shall not be effective
until the date such facilities are included as Accredited Capability.
3.03 The Transmission Service charge and losses provisions of Service
Schedule "F" shall also apply.
Service Schedule B
Seasonal Participation Power Interchange Service
Section 1.Service to be Provided
1.01 This Schedule provides for the sale of Seasonal Participation
Power by any Participant to any other Participant from a specific generating
unit. Seasonal Participation Power shall mean power and energy which is sold
from a base load unit on the basis that it is continuously available except
when such unit is temporarily out of service for maintenance during which time
the delivery of energy from other sources shall be at the seller's option.
Section 2.Conditions of Service
2.01 This Schedule shall be available for the sale of Seasonal
Participation Power for six consecutive months beginning on May 1 or November
1 unless other dates are agreed to by the Engineering Committee.
2.02 Seasonal Participation Power shall be supplied through
transmission facilities which have adequate capacity for transmitting such
power and energy, and Transmission Service shall be arranged in accordance
with the procedures established under Service Schedule "F."
Section 3.Schedule of Rates
3.01 The receiving Participant shall pay to the supplying Participant
for Seasonal Participation Power furnished during any month under this
Schedule an amount determined from the following schedule of rates:
Demand Charge:
For each megawatt or fraction thereof committed by the supplier, a
charge per month not more than P, where
P = A/12
where A = the value for the applicable year based on ten (10) years of
data representing the composite levelized annual fixed charges per
megawatt for the units of the Participants which supplied, or are most
likely to supply capacity and energy under this Schedule.
For each FERC regulated Participant, the levelized annual fixed carrying
charge would be the sum of the return requirement, depreciation, income
tax, property tax and administrative and general costs. The return
requirement shall be calculated in accordance with standard FERC methods
using debt costs, preferred stock cost and a percentage rate of return
on equity, weighted in accordance with the Participant's capital ratios
at the end of the preceding calendar year. The percentage rate of
return on equity shall be the FERC benchmark rate of return on equity
percentage, which shall be filed annually with the FERC. The income tax
requirement which shall include deferred taxes, shall be calculated in
accordance with standard FERC methods using federal and state tax rates
in effect for the current year. The administrative and general costs
in column b on line 167 of page 323 of the FERC Form 1 shall be
appropriately allocated to the electric production plant and converted
to a percentage of the electric production plant investment. Appendix
1 describes the calculation of the demand charge for this Service
Schedule.
Participants not regulated by the FERC will file a comparable,
reasonable levelized annual carrying charge with the MAPP Coordination
Center for use in this calculation.
Energy Charge:
a. For all energy supplied from the assigned generating unit,
a charge per kilowatt-hour of 110 percent of Average Production
Cost for the month of the assigned generating unit, for both the
energy delivered to the receiving Participant and the energy
supplied by the supplying Participant to any intervening
Participant or Participants as compensation for losses.
b. For all energy supplied when the assigned generating unit
is temporarily out of service for maintenance, a charge per
kilowatt-hour of 110 percent of Incremental Cost of supplying
such energy, for both the energy delivered to the receiving
Participant and the energy supplied by the supplying Participant
to any intervening Participant or Participants as compensation
for losses.
c. The percentage adder components contained in the third-
party purchase and resale provisions of this rate schedule are
hereby limited to recover no more than:
i. The FERC Order 84 adder for each FERC-regulated
Participant. The FERC Order 84 adder for each FERC-
regulated Participant is shown on Appendix 6 to this
Agreement. FERC-regulated Participants shall provide the
FERC and the MAPP Coordination Center with a revised
Appendix 6 whenever a change to their Order 84 adder is
filed with the FERC.
ii. A value on file at the MAPP Center for Participants
not regulated by the FERC.
3.02 In the event that service cannot be supplied on the effective date
of an agreement to sell Seasonal Participation Power under this Service
Schedule "B" due to a delayed in-service date of the associated generating
facilities, the demand charge to be paid by the purchasing Participant shall
not be effective until the date such facilities are included as Accredited
Capability.
3.03 The Transmission Service charge and losses provisions of Service
Schedule "F" shall also apply.
Service Schedule C
Emergency and Scheduled Outage Energy Interchange Service
Section 1.Service to be Provided
1.01 This Schedule provides for the supply of energy by any Participant
to any other Participant during Emergency Outages or Scheduled Outages for
maintenance of generating or transmission facilities or both.
Section 2.Scheduling of Deliveries
2.01 Deliveries of Emergency Energy shall be scheduled as soon as
possible after the occurrence of an Emergency Outage in accordance with
principles and practices established by the Operating Committee. Transmission
Service for Emergency Energy shall be available in accordance with the
procedures established under Service Schedule "F."
2.02 Scheduled Outage Energy may be scheduled from a Participant not
directly interconnected providing such energy is available at a lower
delivered cost than from a directly interconnected Participant. Transmission
Service for Scheduled Outage Energy shall be available in accordance with the
procedures established under Service Schedule "F."
Section 3.Schedule of Rates
3.01 The receiving Participant shall pay to the supplying Participant
for Emergency Energy furnished during any month under this Schedule the
greater of 3.0 cents per kilowatt-hour or 110 percent of the supplying
Participant's Incremental Cost of supplying such energy.
3.02 The receiving Participant shall compensate the supplying
Participant for Scheduled Outage Energy furnished during any month under this
Schedule in accordance with one of the following subparagraphs:
a. The receiving Participant shall pay to the supplying
Participant for such Scheduled Outage Energy an amount of
whichever is the greater:
i. 110 percent of the Incremental Cost of producing such
energy, or
ii. 110 percent of the average cost of the receiving
Participant had it produced such energy with the generating
unit which is out of service, which average cost shall
include but not be limited to fuel cost and operation and
maintenance cost;
provided that, if the receiving Participant is not using its Total
Available Accredited Capability, the supplying Participant may require
the receiving Participant to make an additional payment for any
financial loss that accrues to the supplying Participant due to this
transaction replacing a sale to another party. For uniformity of
application, such additional payment should be calculated assuming that
the decremental cost of the other sale would have been an amount equal
to the cost of energy from oil-fired generation determined in accordance
with principles and practices established by the Operating Committee as
follows:
The cost of oil-fired generation will be calculated using the least-
squares method based on a maximum of seven years' data. For FERC
regulated Participants, the data used will be the sum of fuel, operation
and maintenance costs divided by net KWH (where net generation is
sufficient to demonstrate true operating costs) which is line 35 on page
402 and columns e, h, i and o on pages 410 and 411 of the FERC Form 1.
Participants not regulated by the FERC will provide comparable data when
cost data is requested for filing at the MAPP Coordination Center.
b. The Participant supplying Scheduled Outage Energy may, at
its option, require the receiving Participant to return such
energy at such times and under such conditions that the supplying
Participant will not experience a loss due to the transaction, or
under conditions mutually agreeable to both Participants.
3.03 The Transmission Service charge and losses provisions of Service
Schedule "F" shall also apply to Scheduled Outage Energy transactions. The
Transmission Service charge and losses provisions of Service Schedule "F"
shall not apply to Emergency Energy transactions.
Service Schedule D
Operating Reserve Interchange Service
Section 1.Service to be Provided
1.01 A Participant may arrange for some other Participant to supply
part or all of its Operating Reserve requirement.
Section 2.Scheduling of Rates (See Note No. 1)
2.01 Except as otherwise agreed to by the Participants concerned, a
Participant supplying a portion or all of some other Participant's Operating
Reserve during any month shall be paid by the purchasing Participant an amount
of whichever is greater of the following:
a. 110 percent of the incremental cost of supplying such
service, or
b. The incremental cost of supplying such service plus one-
half of the overall savings of such transaction, where overall
savings shall be equal to the difference between the incremental
cost of the selling Participant and the decremental cost of the
purchasing Participant.
2.02 In the event there are repetitive transactions between certain
Participants involving similar incremental and decremental costs, flat rates
or an exchange arrangements may be established for such transactions by the
representatives of the Participants concerned.
Note No. 1
Incremental and Decremental Cost for the purpose of this schedule only,
shall be determined as follows:
Incremental cost of the supplying Participant shall be based on
the costs incurred in starting and/or operating any generating
unit or units which must be started as a result of supplying such
service.
Decremental cost of the purchasing Participant shall be based on
the cost avoided by not starting and/or operating any generator
unit or units as a result of receiving such service.
Service Schedule E
Economy Energy Interchange Service
Section 1.Service to be Provided
1.01 This Schedule provides for the supply of Economy Energy by any
Participant to any other Participant when it is economical and practical to
do so under the conditions set forth hereinafter and in Paragraph 20.07 of the
Agreement.
Section 2.Conditions of Service
2.01 It is the intent hereof that, insofar as is practicable, Economy
Energy from available sources having the lowest Incremental Costs shall be
used to displace generation having the highest Decremental Costs and so on
until such transactions are no longer economical; provided that such
transactions are not scheduled in amounts which will overload any transmission
facility or endanger the operation of the interconnected systems.
2.02 Transmission Service shall be available in accordance with the
procedures established under Service Schedule "F."
Section 3.Scheduling of Deliveries
3.01 Prior to beginning deliveries, the Participants involved will
agree on an hour-by-hour schedule of energy to be delivered.
Section 4.Schedule of Rates
4.01 The overall savings of an Economy Energy transaction shall be
equal to the difference between the Incremental Cost of the supplying
Participant and the Decremental Cost of the receiving Participant. If the
transmission system of a non-Participant is involved in an Economy Energy
transaction, any transmission fees and losses to be paid for the use of such
system shall be deducted from the overall savings in determining the net
savings of the transactions.
4.02 The receiving Participant shall pay the supplying Participant for
the Economy Energy supplied during each month, an amount equal to the
Incremental Cost of the energy so supplied, plus one-half of the net savings
of such transactions which remain after deducting the amount paid by the
receiving Participant to any parties providing transmission service in
accordance with Paragraph 4.01 herein and with Service Schedule "F."
4.03 The Transmission Service charge and losses provisions of Service
Schedule "F" shall also apply.
<PAGE>
Service Schedule F
Transmission Services and Losses
Section 1.Service to be Provided
1.01 This Schedule provides for Transmission Service in connection with
Coordination Transactions scheduled between Participants, or scheduled between
a Participant and another utility, in a non-Participant Control Area, with
which the Participant has a direct interconnection or has rights to deliver
or receive power and energy at such an interconnection.
1.02 This Service Schedule shall not be used for and will not be
applied to provide Transmission Service to deliver power and energy from
generation owned or leased by a Participant or from which a Participant
purchases power and energy pursuant to life-of-unit contracts, to serve load
which that Participant has an obligation under law or contract to supply
(including preference customers in the case of the United States). This
Service Schedule shall also not be used for and will not be applied to provide
for Transmission Service to deliver power and energy to an ultimate consumer.
1.03 Service Schedule "F" shall be applicable to transactions, to which
a Participant is a party, of four years (eight full seasons) or less from the
date notice of the transaction is given to the MAPP Center in accordance with
the procedures established by the applicable committee. Transmission Service
under Service Schedule "F" may be used for portions of longer term
transactions, but only to the extent any such portion occurs within four years
(eight full seasons) of the date notice of the transaction is given to the
MAPP Center. The eight full seasons are the eight consecutive seasons
immediately following notification of the MAPP Center of the transaction,
assuming notification is provided before the first season. To the extent the
transaction occurs during the first season, the eight seasons shall consist
of that season and the following seven seasons.
Section 2.Conditions of Service
2.01 Transmission Service for transactions under Service Schedules "A",
"B", "H", "I", "J", and "K", and any other capacity transactions, shall be
arranged in accordance with procedures established by the Engineering
Committee. Transmission Service for transactions under Service Schedules "C",
"E", "G", "L", and "M", and any other energy-only transactions, shall be
available in accordance with procedures established by the Operating
Committee. There shall be no Transmission Service charge applicable to
Emergency Energy transactions under Service Schedule "C".
2.02. Nothing contained in this Service Schedule "F" or in the
procedures established by the appropriate committee pursuant to Section 2.01
shall be interpreted to require a Party to install or upgrade transmission
facilities or to redispatch its generation in order to enable Transmission
Service to be arranged or made available for prospective transactions.
2.03 Available transmission capacity for MAPP Service Schedule "F"
shall be determined on an integrated system basis considering the combined
transfer capability of all Participants' transmission systems. If requests
for transmission capacity exceed the available transmission capacity, the
available transmission capacity will be allocated under procedures established
by the Engineering and Operating Committees.
Section 3.Compensation
3.01 Each Participant who provides Transmission Service utilizing
transmission facilities of 115kV and higher, except for Service Schedule C
Emergency Energy transactions, shall be entitled to compensation in accordance
with the Transmission Service charge formulae and methodology set forth in
Appendix 7. Participants whose 69kV transmission facilities meet the criteria
set forth in Appendix 7 for inclusion in such formulae and methodology of the
investments in and flows through such facilities shall also be entitled to
compensation in accordance with Appendix 7.
3.02 The buyer shall pay for Transmission Service, unless the buyer is
a non-Participant, in which case the selling Participant pays.
3.03 Whenever a Participant schedules the delivery of power and energy
pursuant to this Agreement, the amount of power and energy to be furnished to
the other Participants as compensation for losses shall be determined in
accordance with formulae established by the Operating Committee.
<PAGE>
Service Schedule G
Operational Control Energy Interchange Service
Section 1.Service to be Provided
1.01 This Schedule provides for the supply of Operational Control
Energy by any Participant to any other Participant to improve electric system
control and reliability.
1.02 This Schedule also provides for the supply of energy by any
Participant to any other Participant for resale to another electric supplier,
not signatory hereto, to enable such other supplier to meet emergency
conditions on its own system.
Section 2.Conditions of Service
2.01 Operational Control Energy shall not be used in lieu of energy
available under any other Service Schedule and shall not be considered in the
determination of a Participant's Accredited Capability.
2.02 Transmission Service shall be available in accordance with the
procedures established under Service Schedule "F."
Section 3.Schedule of Rates
3.01 For all energy supplied under Paragraph 1.01 herein, the receiving
Participant shall pay to the supplying Participant for Operational Control
Energy, furnished during any month under this Schedule, 110 percent of the
Incremental Cost of the supplying Participant when the transaction is
initiated by the receiving Participant for its benefit or ninety percent (90%)
of the Decremental Cost of the receiving Participant when the transaction is
initiated by the supplying Participant for its benefit.
The percentage adder components contained in the third-party purchase
and resale provisions of this rate schedule are hereby limited to
recover no more than:
i. The FERC Order 84 adder for each FERC-regulated
Participant. The FERC Order 84 adder for each FERC-regulated
Participant is shown on Appendix 6 to this Agreement. FERC-
regulated Participants shall provide the FERC and the MAPP
Coordination Center with a revised Appendix 6 whenever a change
to their Order 84 adder is filed with the FERC.
ii. A value on file at the MAPP Center for Participants not
regulated by the FERC.
3.02 For all energy supplied during any month under Paragraph 1.02, the
receiving Participant shall pay to the supplying Participant the rate in
effect under Service Schedule "C," Paragraph 3.01.
3.03 The Transmission Service charge and losses provisions of Service
Schedule "F" shall also apply.
Service Schedule H
Peaking Power Interchange Service
Section 1.Service to be Provided
1.01 This Schedule provides for the sale of Peaking Power by any
Participant to any other Participant. Peaking Power shall mean power and
associated energy intended to be available at all times during the period
covered by a commitment and which is sold with anticipated low load factor
use. Such power shall include required reserve capacity.
Section 2.Conditions of Service
2.01 This Schedule shall be available for the sale of Peaking Power for
a period of six consecutive months beginning on May 1 or November 1 unless
other dates are agreed to by the Engineering Committee.
2.02 Peaking Power shall be supplied through transmission facilities
which have adequate capacity for transmitting such power and energy, and
Transmission Service shall be arranged in accordance with the procedures
established under Service Schedule "F."
2.03 The supplying Participant shall guarantee that Peaking Power
purchased hereunder shall be available to the receiving Participant on at
least a twenty percent (20%) monthly capacity factor. The supplying
Participant of such Peaking Power may limit delivery of energy, above the
guaranteed amount. The capacity factor set forth herein shall be subject to
change by the Engineering Committee from time to time.
Section 3. Schedule of Rates
3.01 The receiving Participant shall pay to the supplying Participant
for Peaking Power furnished during any month under this Schedule an amount
determined from the following schedule of rates:
Demand Charge:
For each megawatt or fraction thereof committed by the supplying
Participant, a charge per month not more than the greater of:
i. Q, where
Q = B/12
where B = a value based on all Participant's current levelized annual
fixed charges per megawatt for their total peaking generating capacity,
or
ii. $2,000
For each FERC regulated Participant, the levelized annual fixed carrying
charge would be the sum of the return requirement, depreciation, income
tax, property tax and administrative and general costs. The return
requirement shall be calculated in accordance with standard FERC methods
using debt costs, preferred stock cost and a percentage rate of return
on equity, weighted in accordance with the Participant's capital ratios
at the end of the preceding calendar year. The percentage rate of
return on equity shall be the FERC benchmark rate of return on equity
percentage which shall be filed annually with the FERC. The income tax
requirement, which shall include deferred taxes, shall be calculated in
accordance with standard FERC methods using federal and state tax rates
in effect for the current year. The administrative and general costs
in column b on line 167 of page 323 of the FERC Form 1 shall be
appropriately allocated to the electric production plant and converted
to a percentage of the electric production plant investment. Appendix
2 describes the calculation of the demand charge for this Service
Schedule.
Participants not regulated by the FERC will file a comparable,
reasonable levelized annual carrying charge with the MAPP Coordination
Center for use in this calculation.
Energy Charge:
For all energy supplied hereunder, a charge per kilowatt-hour of 110
percent of the Incremental Cost of producing or purchasing such energy,
whichever is less, for both the energy delivered to the purchasing
Participant and the energy supplied by the supplying Participant to any
intervening Participant or Participants as compensation for losses.
The percentage adder components contained in the third-party purchase
and resale provisions of this rate schedule are hereby limited to
recover no more than:
i. The FERC Order 84 adder for each FERC-regulated
Participant. The FERC Order 84 adder for each FERC-regulated
Participant is shown on Appendix 6 to this Agreement. FERC-
regulated Participants shall provide the FERC and the MAPP
Coordination Center with a revised Appendix 6 whenever a change
to their Order 84 adder is filed with the FERC.
ii. A value on file at the MAPP Coordination Center for
Participants not regulated by the FERC.
In the event it is desired by the Participants involved, an exchange
arrangement may be established by the representatives of the Parties
concerned. The supplying Participant of Peaking Power may, at its
option, require the return of any energy delivered above the guaranteed
monthly capacity factor at such times and under such conditions as
agreed to by representatives of the Participants concerned.
3.02 The Transmission Service charge and losses provisions of Service
Schedule "F" shall also apply.
<PAGE>
Service Schedule I
Short Term Power Interchange Service
Section 1.Service to be Provided
1.01 This Schedule provides for the sale of Short Term Power by any
Participant to any other Participant. Short Term Power shall mean power and
associated energy intended to be available at all times during the period
covered by a commitment. Such power shall include required reserve capacity.
Section 2.Conditions of Service
2.01 This Schedule shall be available for the sale of Short Term Power
for periods of seven or more consecutive days each.
2.02 Short Term Power shall be included in the Accredited Capability
of a Participant only under special conditions, such as:
a. In an instance where a significant new industrial customer
load is imposed upon a Participant's system at a time different
from the purchase period for which other schedules are
applicable.
b. In an instance where a generator or transmission line
addition does not meet the scheduled in-service date.
c. In an instance where it is being purchased for resale to an
electric supplier who is not a Participant.
d. In an instance where a Participant's October system demand
is forecast to exceed the maximum system demand of the previous
five months.
2.03 Short Term Power shall be supplied through transmission facilities
which have adequate capacity for transmitting such power and energy, and
Transmission Service shall be arranged in accordance with the procedures
established under Service Schedule "F."
Section 3.Schedule of Rates
3.01 The receiving Participant shall pay to the supplying Participant
for Short Term Power furnished during any month under this Schedule an amount
determined from the following schedule of rates:
Demand Charge:
For each megawatt or fraction thereof committed by the supplying
Participant, a charge per day not more than the greater of:
i. R, where
R = B/365
where B = a value based on all Participants' current levelized
annual fixed charges per megawatt for their total peaking
generating capacity, or
ii. $66
For each FERC regulated Participant, the levelized annual fixed carrying
charge would be the sum of the return requirement, depreciation, income
tax, property tax and administrative and general costs. The return
requirement shall be calculated in accordance with standard FERC methods
using debt costs, preferred stock cost and a percentage rate of return
on equity, weighted in accordance with the Participant's capital ratios
at the end of the preceding calendar year. The percentage rate of
return on equity shall be the FERC benchmark rate of return on equity
percentage, which shall be filed annually with the FERC. The income tax
requirement, which shall include deferred taxes, shall be calculated in
accordance with standard FERC methods using federal and state tax rates
in effect for the current year. The administrative and general costs
in column b on line 167 of page 323 of the FERC Form 1 shall be
appropriately allocated to the electric production plant and converted
to a percentage of the electric production plant investment. Appendix
3 describes the calculation of the demand charge for this Service
Schedule.
Participants not regulated by the FERC will file a comparable,
reasonable levelized annual carrying charge with the MAPP Coordination
Center for use in this calculation.
Energy Charge:
For all energy supplied hereunder, a charge per kilowatt-hour of 110
percent of the Incremental Cost of supplying such energy, for both the
energy delivered to the receiving Participant and the energy supplied
by the supplying Participant to any intervening Participant or
Participants as compensation for losses. The percentage adder components
contained in the third-party purchase and resale provisions of this rate
schedule are hereby limited to recover no more than:
i. The FERC Order 84 adder for each FERC-regulated
Participant. The FERC Order 84 adder for each FERC-regulated
Participant is shown on Appendix 6 to this Agreement. FERC-
regulated Participants shall provide the FERC and the MAPP
Coordination Center with a revised Appendix 6 whenever a change
to their Order 84 adder is filed with the FERC.
ii. A value on file at the MAPP Center for Participants not
regulated by the FERC.
3.02 The Transmission Service charge and losses provisions of Service
Schedule "F" shall also apply.
3.03 For any Short Term Capacity which the supplying Participant
procures from electric suppliers not signatory hereto for delivery to the
receiving Participant, the receiving Participant shall pay to the supplying
Participant the cost of procuring such capacity and 110 percent of the cost
of procuring such energy, but not less than the rates specified herein, in
addition to compensation as set forth in Service Schedule "F."
Service Schedule J
Firm Power Interchange Service
Section 1.Service to be Provided
1.01 This Schedule provides for the sale of Firm Power by any
Participant to any other Participant. Firm Power shall mean power and
associated energy intended to be available at all times during the period
covered by a commitment. Such power shall include required reserve capacity.
Section 2.Conditions of Service
2.01 Firm Power shall be supplied through transmission facilities which
have adequate capacity for transmitting such power and energy, and
Transmission Service shall be arranged in accordance with the procedures
established under Service Schedule "F."
2.02 This Schedule shall be available for the sale of Firm Power for
a period of six months or longer.
2.03 FERC-regulated Participants who enter into transactions to sell
power under this schedule shall file the applicable agreement with the FERC
as a rate schedule.
Section 3.Schedule of Rates
3.01 The rate and term for Firm Power shall be negotiated by the
Participants to each transaction.
3.02 The Transmission Service charge and losses provisions of Service
Schedule "F" shall also apply.
Service Schedule K
System Participation Power Interchange Service
Section 1.Service to be Provided
1.01 This Schedule provides for the sale of System Participation Power
by any Participant to any other Participant for a specified period for the
purpose of obtaining a supply of power which can be depended upon with the
same degree of assurance as that expected from the Purchaser's own generating
capacity, but which does not include reserve capacity.
Section 2.Conditions of Service
2.01 This Schedule shall be available for the sale of System
Participation Power for periods of seven or more consecutive days.
2.02 System Participation Power is intended to be available at all
times during the period covered by the commitment; provided, however, that in
the event conditions arise during the period covered by the commitment which
in the sole judgment of the supplying Participant would otherwise require
curtailment of firm power sales or service to its own customers, the supplying
Participant has the right to notify and require the receiving Participant to
reduce its take of such energy to any amount specified and for any portion of
the term of the commitment and the receiving Participant shall promptly comply
with the decision of the supplying Participant.
2.03 System Participation Power shall be included in the Accredited
Capability of a Participant only under the following conditions:
a. In an instance where it is being purchased for resale to an
electric supplier who is not a Participant.
b. In an instance where a Participant purchases power under
this schedule for a period of six consecutive months beginning
May 1 or November 1 or such other dates as are agreed to by the
Management Committee.
2.04 System Participation Power shall be supplied through transmission
facilities which have adequate capacity for transmitting such power and
energy, and Transmission Service shall be arranged in accordance with the
procedures established under Service Schedule "F".
Section 3.Schedule of Rates
3.01 The receiving Participant shall pay to the supplying Participant
for System Participation Power furnished during any period under this Schedule
an amount determined from the following schedule of rates:
Demand Charge:
For each megawatt or fraction thereof committed by the supplying
Participant, a charge per week of not more than S, where
S = C/52
where C = a value based on all Participants' current levelized annual
fixed charges per megawatt for their total thermal generating capacity
excluding cogeneration, provided however, that should delivery of System
Participation Power be curtailed by the supplying Participant, the
demand charge shall be reduced by one-sixth per megawatt of curtailment
for each day during which there is a curtailment, but such reduction
shall not exceed the demand charge for the reservation period.
For each FERC regulated Participant, the levelized annual fixed carrying
charge would be the sum of the return requirement, depreciation, income
tax, property tax and administrative and general costs. The return
requirement shall be calculated in accordance with standard FERC methods
using debt costs, preferred stock cost and a percentage rate of return
on equity, weighted in accordance with the Participant's capital ratios
at the end of the preceding calendar year. The percentage rate of
return on equity shall be the FERC benchmark rate of return on equity
percentage, which shall be filed annually with the FERC. The income tax
requirement which shall include deferred taxes, shall be calculated in
accordance with standard FERC methods using federal and state tax rates
in effect for the current year. The administrative and general costs
in column b on line 167 of page 323 of the FERC Form 1 shall be
appropriately allocated to the electric production plan and converted
to a percentage of the electric production plant investment. Appendix
4 describes the calculation of the demand charge for this Service
Schedule.
Participants not regulated by the FERC will file a comparable,
reasonable levelized annual carrying charge with the MAPP Coordination
Center for use in this calculation.
Energy Charge:
For all energy supplied hereunder, a charge per kilowatt-hour of 110
percent of the Incremental Cost of supplying such energy, for both the
energy delivered to the receiving Participant and the energy supplied
by the supplying Participant to any intervening Participant or
Participants as compensation for losses.
The percentage adder components contained in the third-party purchase
and resale provisions of this rate schedule are hereby limited to
recover no more than:
i. The FERC Order 84 adder for each FERC-regulated
Participant. The FERC Order 84 adder for each FERC-regulated
Participant is shown on Appendix 6 to this Agreement. FERC-
regulated Participants shall provide the FERC and the MAPP
Coordination Center with a revised Appendix 6 whenever a change
to their Order 84 adder is filed with the FERC.
ii. A value on file at the MAPP Coordination Center for
Participants not regulated by the FERC.
3.02 The Transmission Service charge and losses provisions of Service
Schedule "F" shall also apply.
3.03 For any System Participation Capacity which the supplying
Participant procures from electric suppliers not signatory hereto for delivery
to the receiving Participant, the receiving Participant shall pay to the
supplying Participant the cost of procuring such capacity at cost and such
associated energy cost at 110 percent of the cost of procuring such energy,
in addition to wheeling and loss compensation as set forth in Service Schedule
"F."
<PAGE>
Service Schedule L
Interruptible Load Replacement Energy Service
Section 1.Services to be Provided
1.01 This Schedule provides for the supply of Interruptible Load
Replacement Energy by any Participant to any other Participant when it is
economical and practical to do so under the conditions set forth hereinafter
and in Paragraph 20.08 of this Agreement.
Section 2. Conditions of Service
2.01 It is the intent that Interruptible Load Replacement Energy may
be used by Participants to serve interruptible load when that load would
otherwise be interrupted.
a. In order to be eligible for Interruptible Load Replacement
Energy Service, the purchasing Participant must report in advance
monthly quantities of Certified Interruptible Demand.
b. The rate of delivery of energy supplied under this schedule
in any hour shall not exceed the purchasing Participant's
Certified Interruptible Demand.
c. Deliveries of energy may be received under this schedule
only when a Participant's maximum System Demand would otherwise
be greater than the Participant's forecast System Demand for the
current season and shall not exceed that required to reduce the
System Demand to the forecast System Demand.
d. Interruptible Load Replacement Energy Service shall not be
scheduled in amounts which will overload any transmission
facilities or endanger the operation of the interconnected
systems of the Participants.
e. Interruptible Load Replacement Energy Service transactions
between Participants which are directly interconnected shall
normally take precedence over transactions between Participants
not directly interconnected unless cost differential exceeds the
Operating Committee guidelines.
2.02 Transmission Service shall be available in accordance with the
procedures established under Service Schedule "F."
Section 3.Scheduling Deliveries
3.01 Prior to the scheduling of deliveries, the Participants concerned,
including the wheeling Participant or Participants, if any, will agree on
hour-by-hour amounts of energy to be delivered.
Section 4.Schedule of Rates
4.01 The overall savings of an Interruptible Load Replacement Energy
Service transaction shall be equal to the difference between the Incremental
Cost of the supplying Participant and the Displaced Cost of the receiving
Participant where Displaced Cost shall be determined as in Section 4.04
following. If the transmission facilities of a system not a party hereto is
involved in an Interruptible Load Replacement Energy transaction, any
transmission fees and losses to be paid for the use of such facilities, shall
be deducted from the overall savings of the transactions in determining the
net savings of the transactions.
4.02 The receiving Participant shall pay the supplying Participant for
the energy supplied during each month an amount equal to the Incremental Cost
of the energy so supplied, plus one-half of the overall savings of such
transactions. However, the amount paid by the receiving Participant shall not
be less than 110 percent of the supplying Participant's Incremental Cost.
4.03 When the receiving Participant's Displaced Cost equals or is lower
than the supplying Participants Incremental Cost, transactions may occur with
the price being the minimum specified in Paragraph 4.02.
4.04 The Displaced Cost per kilowatt-hour to be used under this
schedule shall be determined as the total revenues received in the prior 12
months from retail customers whose load is associated with the Interruptible
Load Replacement Energy to be purchased, divided by the kilowatt-hours of
energy supplied those customers over the same period. Participants that
supply wholesale loads which are associated with Interruptible Load
Replacement Energy to be purchased under this schedule shall utilize the
revenues received by the retail supplier(s) for the energy supplied these
customers in the computation of the Displaced Cost.
<PAGE>
Service Schedule M
General Purpose Energy Service
Section 1.Service to be Provided
1.01 This Schedule provides for the supply of General Purpose Energy
by any Participant to any other Participant to enhance economic system
operation.
Section 2.Conditions of Service
2.01 It is the intent hereof that, insofar as is practicable, General
Purpose Energy shall be used to improve the overall economy of the systems
involved in the transactions; provided that such transactions are not
scheduled in amounts which will overload any transmission facility or endanger
the operation of the interconnected systems.
2.02 Transmission Service shall be available in accordance with the
procedures established under Service Schedule "F."
Section 3.Scheduling of Deliveries
3.01 Prior to beginning deliveries, the Participants involved will
agree on the terms of the transaction and on an hour-by-hour schedule of
energy to be delivered.
Section 4.Schedule of Rates
4.01 The receiving Participant shall pay the supplying Participant for
the General Purpose Energy supplied a charge of up to 110 percent of the
anticipated Incremental Cost of supplying such energy, plus an additional
charge per megawatt-hour of up to S/96, where
S is the weekly demand charge for System Participation Power Interchange
Service as specified in Service Schedule K, Section 3 and,
96 is the number of on-peak hours for a given week.
This additional charge shall not exceed S/6 multiplied by the highest number
of megawatt-hours delivered in any one hour during that day, where
6 is the number of days in a week containing on-peak hours.
The total charge for each transaction shall not be less than 100 percent of
the Incremental Cost of supplying the energy for the transaction.
4.02 The Transmission Service charge and losses provisions of Service
Schedule "F" shall also apply.
Exhibit 10.12
FINAL
NSP SEVERANCE PLAN
(As Amended and Restated Effective November 1, 1989)
TABLE OF CONTENTS
Section Page
1 Purpose 1
2 Effective Date 1
3 Definitions 1
4 Eligibility for Benefits 2
5 Amount of Benefits 3
6 General Release 5
7 Notice Requirement 5
8 Non-Alienation of Benefits 5
9 Fund 6
10 Employment Rights 6
11 Administration 6
12 Claim Procedure 6
13 Headings 8
14 Amendment and Termination 8
15 Applicable 8
NSP SEVERANCE PLAN
Section 1. Purpose. The purpose of the Plan is to provide severance benefits
to Employees whose employment with Northern States Power Company, a Minnesota
corporation, ("NSP") and its subsidiaries is terminated in accordance with the
terms and conditions of the Plan.
Section 2. Effective Date. The Plan was established by NSP effective as of
June 1, 1987 and was formerly known as the "NSP Transitional Employee Plan."
The Plan, as stated herein, is amended, restated and renamed the "NSP
Severance Plan," effective November 1, 1989.
Section 3. Definitions. As used herein: "Annual Salary" means the Employee's
regular annual base salary immediately prior to his or her Termination,
including compensation converted to other benefits under a flexible pay
arrangement maintained by the Company or deferred pursuant to a written
agreement with the Company. The term shall exclude overtime pay, allowance,
premium pay, compensation paid or payable under any Company's long-term or
short-term incentive plan or any payment found by NSP to be similar thereto.
"Company" means Northern States Power Company, a Minnesota corporation
("NSP") and any subsidiary of NSP which makes the Plan available to its
Employees.
"Employee" means any full-time, regular-benefit, non-bargaining employee of
the Company. The term shall exclude an individuals employed as independent
contractors, temporary employees, other benefit employees, non-benefit
employees, leased employees, even if it is subsequently determined that such
classification is incorrect.
"Month of Salary" means the Annual Salary of an Employee divided by twelve
(12).
"Plan" means this NSP Severance Plan, as set forth herein and as amended
from time to time.
"Termination" means an Employee's termination of employment from NSP
and its subsidiaries.
"Two Years' Pay" means twice the Employee's "annual compensation" during
the calendar year immediately preceding his or her Termination. Such annual
compensation will include compensation reported on Form W-2; any compensation
converted to other benefits under a flexible pay arrangement maintained by the
Company or deferred pursuant to a written agreement with the Company; and any
other benefit of monetary value, whether in cash or otherwise, which was paid
as consideration for services for the Employee's service during such year.
"Week of Salary" means the Annual Salary of an Employee divided by fifty-
two (52).
"Year of Service" means a year of "pensionable service" under the Northern
States Power Company Pension Plan.
Section 4. Eligibility for Benefits. An Employee shall be eligible for
severance benefits, as described in Section 5, if:
(a) the Employee's Termination resulted from (i) the elimination of
a job position; (ii) a reorganization, realignment or elimination of certain
job functions or activities; (iii) a reduction in workforce; or (iv) the
Employee's inability, for reasons beyond his or her control, to perform the
duties of his or her job; and
(b) such Termination was not caused by (i) death or disability; (ii)
voluntary resignation by the Employee, provided, that a Termination shall not
be deemed to be a voluntary resignation if an Employee requests Termination
under circumstances described in Subsection 4(a) and the Company, in its sole
discretion, approves such request; (iii) termination of employment for cause,
including but not limited to unsatisfactory performance or behavior; or (iv)
the sale of operations to an employer who offers continued employment to the
Employee; and<PAGE>
(c) the Employee (i) is not a temporary employee or classified as an
"other benefit" or "non-benefit employee" or similar classification; (ii) is
not covered by a collective bargaining agreement; (iii) has not been
re-employed by an Employer; and (iv) is not the recipient of any individual
agreement or understanding that provides for severance benefits upon such
Termination.
Section 5. Amount of Benefits. The severance benefits of an Employee who
meets the eligibility requirements of Section 4 shall be subject to a maximum
benefit of Two Years' Pay and shall be as follows:
(a) Cash Payments:
(i) Basic Benefits. An amount equal to two (2)
Months of Salary of the Employees.
(ii) Enhanced Benefits. An amount equal to the greater of
(A) two (2) Weeks of Salary of the Employee for each
whole Year of Service and a proportionate share thereof
for any partial Year of Service; or (B) one (1) Week of
Salary of the Employee for each full $2,000.00 of Annual
Salary and a proportionate share thereof of any partial
amount thereof; provided, however, that an Employee
shall receive the Enhanced Benefits described under this
Subsection 5(a)(ii) only if he or she signs a General
Release as described in Section 6.
The period that an Employee is eligible to receive severance benefits under
Subsections 5(a)(i) and (ii) above shall hereafter be referred to as the
"Severance Period."
(iii) Incentive Pay. An amount, if any, equal to the
incentive award an Employee would have received for the
Severance Period under the Executive Annual Incentive
Compensation Plan, the Management Annual Compensation
Plan, or the Power of Performance Incentive Plan, as
applicable, if his or her employment with the Company
had continued during the Severance Period and such award
was based on the applicable plan year-end results and
an individual performance level of 1.0.
(iv) Form of Payment. Basic and Enhanced Benefits, if any,
shall be paid monthly on successive months commencing
the month following Termination. Incentive Pay, if any,
shall be paid when incentive awards are paid under the
applicable incentive plan. Notwithstanding any other
provision of the Plan to the contrary, in no event shall
cash payments under Subsection 5(a) be paid more than
24 months after an Employee's Termination.
(b) Group Insurance. Coverage under the NSP's Medical Plan (or
Health Maintenance Organizations), the NSP Group Dental Program and the NSP
Group Life Insurance Plan during the Severance Period upon the payment of
any required premiums.<PAGE>
(c) Outplacement. Outplacement services, as selected by the Company,
shall be provided to an Employee.
Section 6. General Release. Notwithstanding any other provision of this Plan
to the contrary, to receive the Enhanced Benefits described in Subsection
5(a)(ii), an Employee must sign a General Release, in such form as determined
by NSP, which releases NSP and its subsidiaries from any and all claims except
as such claims relate directly to the payment of any benefit due under this
Plan or benefits payable under any other plan or agreement of the Company
unrelated to severance benefits.
Section 7. Notice Requirement. Receipt by an Employee of the Basic Benefits
described in Subsection 5(a)(i) shall, with respect to such Employee,
constitute full satisfaction of all termination pay requirements of any kind
under any federal or state law, including without limitation, advance
notification of layoffs or similar notice requirements.
Section 8. Non-Alienation of Benefits. No rights under the Plan shall be
assignable, either voluntarily, or involuntarily by way of encumbrance,
pledge, attachment, levy or change of any nature, except as may be required
by federal or state law. If an Employee receiving cash severance benefits
dies before all payments are paid, the remaining of such benefits shall be
paid to the Employee's estate.
Section 9. Fund. This Plan is unfunded and no fund is being set aside or
allocated specifically for the purpose of the Plan. Benefits shall be paid by
the Company out of operating funds against which the former Employee shall
have no greater claim than any other general creditor of NSP and its
subsidiaries.
Section 10. Employment Rights. The Plan shall not interfere with the right
of the Company to discharge any employee at any time, nor shall the Plan be
construed so as to create as to any employee a contract, promise, or guarantee
of employment for any particular position or assignment, or at any particular
level of compensation or benefits.
Section 11. Administration. The Plan shall be administered by NSP which
shall have sole and absolute discretion in: (a) determining all questions
relating to Plan eligibility and benefits; (b) adopting rules and procedures
to administer the Plan; and (c) interpreting Plan provisions. The
interpretation by NSP of the terms and provisions of the Plan and the
administration thereof, and all action taken by NSP, shall be final, binding
and conclusive on all employees and other persons claiming under or through
any of them, unless it is found by a court of competent jurisdiction
to have been arbitrary and capricious.
Section 12. Claim Procedure. If an Employee or former Employee makes a
written request alleging a right to receive benefits under this Plan or
alleging a right to receive an adjustment in benefits being paid under the
Plan, NSP shall treat it as a claim for benefit. All claims for benefit under
the Plan shall be sent to the Human Resources Department of NSP and must be
received within 30 days after termination of employment. If NSP determines
that any individual who has claimed a right to receive benefits, or different
benefits, under the Plan is not entitled to receive all or any part of the
benefits claimed, it will inform the claimant in writing of its determination
and the reasons therefor in terms calculated to be understood by the claimant.
The notice will be sent within 90 days of the claim unless NSP determines
additional time, not exceeding 90 days, is needed. The notice shall make
specific reference to the pertinent Plan provisions on which the denial is
based, and describe any additional material or information, if any, necessary
for the claimant to perfect the claim and the reason any such additional
material or information is necessary. Such notice shall, in addition, inform
the claimant what procedure the claimant should follow to take advantage of
the review procedures set forth below in the event the claimant desires to
contest the denial of the claim. The claimant may within 90 days thereafter
submit in writing to NSP a notice that the claimant contests the denial of his
or her claim by NSP and desires a further review. NSP shall within 60 days
thereafter review the claim and authorize the claimant to appear personally
and review pertinent documents and submit issues and comments relating to the
claim to the persons responsible for making the determination on behalf of
NSP. NSP will render its final decision with specific reasons therefore in
writing and will transmit it to the claimant within 60 days of the written
request for review, unless NSP determines additional time, not exceeding 60
days, is needed.
Section 13. Headings. Headings are given to the Sections of the Plan solely
as a convenience to facilitate reference. Such headings nor numbering or
paragraphing shall be deemed in any way material or relevant to the
construction of the Plan or any provision thereof.
Section 14. Amendment and Termination. NSP reserves the right to amend or
terminate this Plan at any time by a written instrument executed by any Vice
President and by the Secretary or any Assistant Secretary of NSP. Any
amendment or termination of the Plan shall be solely prospective in impact and
shall not adversely affect any severance benefit in pay status.
Section 15. Applicable. The provisions of this Plan shall be governed and
enforced in accordance with the laws of Minnesota except to the extent
superseded by applicable federal law.
IN WITNESS WHEREOF, Northern States Power Company, a Minnesota
corporation, has caused this Plan to be made and signed and its corporate seal
to be hereunto affixed by its duly authorized officers, effective as of
November 1, 1989.
NORTHERN STATES POWER COMPANY
By (John A. Noer)
John A. Noer
Vice President, Human Resources Counsel
ATTEST:
(Arland D. Brusven)
Arland D. Brusven
Secretary and Financial
NSP SEVERANCE PLAN
Amendment of Supplement A
Pursuant to Section 14 of the NSP Severance Plan ("Plan"), the undersigned
officers of Northern States Power Company, a Minnesota corporation, hereby
amend the Plan effective January 1, 1993 by deleting Supplement A as in effect
immediately prior to that date and by adopting the following Supplement A:
SUPPLEMENT A
Notwithstanding anything in Section 4 of the Plan to the contrary, an
Employee whose Termination occurs on or after January 1, 1993 as a result
of a reorganization of all or a portion of the department in which the
employee works will not fail to be eligible for severance benefits solely
because the Employee is offered a "noncomparable job" after commencement of
the reorganization and on or before the date of the Employee's Termination.
For purposes of this Supplement A a "noncomparable job" is a job that either:
a. has a starting Annual Salary that is less than 90 percent of the
Employee's Annual Salary at the time of Termination, or
b. relocates the Employee's primary work site to a place that is more
than 50 miles from the Employee's previous primary work site.
The definitions contained in the Plan shall apply to this Supplement A.
Except as expressly provided herein, the terms of the Plan in effect
immediately prior to adoption of this Supplement A shall remain unchanged.
IN WITNESS WHEREOF, Northern States Power Company, a Minnesota
corporation, has caused this amendment to be signed by its duly authorized
officers this 17th day of June, 1993.
NORTHERN STATES POWER COMPANY
By: (Cynthia L. Lesher)
Its: Vice President-Human Resources
By: (Hollies M. Winston)
Its: Vice President, Corporate Secretary
& Financial Counsel
NSP SEVERANCE PLAN
Amendment of Definition of Annual Salary
Pursuant to Section 14 of the NSP Severance Plan ("Plan"), the undersigned
officers of Northern States Power Company, a Minnesota corporation, hereby
amend the definition of Annual Salary in Section 3 of the Plan, effective
January 1, 1994, to read as follows:
"Annual Salary" means the Employee's regular annual base salary immediately
prior to his or her Termination or, in the case of an Employee who is a
participant in NSP's Staffing Transition Program at the time of Termination,
the Employee's regular annual base salary immediately prior to such
participation. "Annual Salary" shall include compensation converted to other
benefits under a flexible pay arrangement maintained by the Company or
deferred pursuant to a written agreement with the Company. The term shall
exclude overtime pay, allowances, premium pay, compensation paid or payable
under any Company long-term or short-term incentive plan or any payment found
by NSP to be similar thereto.
IN WITNESS WHEREOF, Northern States Power Company, a Minnesota corporation,
has caused this amendment to be signed by its duly authorized officers this
day of February, 1994.
NORTHERN STATES POWER COMPANY
By: (Cynthia L. Lesher)
Its: Vice President of Human Resources
By: (Chandra G. Houston)
Its: Assistant Corporate Secretary
NSP SEVERANCE PLAN
Amendment to Eliminate Post-Termination Incentive Compensation
Pursuant to Section 14 of the NSP Severance Plan ("Plan"), the undersigned
officers of Northern States Power Company, a Minnesota corporation, hereby
amend the Plan, effective May 1, 1994, by deleting paragraphs (iii) and (iv)
of subsection (a) of Section 5 of the Plan, and by inserting in lieu thereof,
the following:
(iii) Form of Payment. Basic and Enhanced Benefits, if any, shall be paid
monthly on successive months commencing the month following Termination;
provided, however, that if earlier commencement is administratively feasible
and NSP in its sole discretion consents, such benefits may commence no earlier
than the end of the month in which Termination occurred. Notwithstanding any
other provision of the Plan to the contrary, in no event shall cash payments
under Subsection 5(a) be paid more than 24 months after an Employee's
Termination.
IN WITNESS WHEREOF, Northern States Power Company, a Minnesota corporation,
has caused this amendment to be signed by its duly authorized officers this
28th day of April, 1994.
NORTHERN STATES POWER COMPANY
By: (Cynthia L. Lesher)
Its: Vice President - Human Resources
By: (Sutton A. Plombon)
Its: Assistant Secretary
<TABLE>
<CAPTION>
Exhibit 12.01
NORTHERN STATES POWER COMPANY AND SUBSIDIARY COMPANIES
STATEMENT OF COMPUTATION OF
RATIO OF EARNINGS TO FIXED CHARGES
1994 1993 1992 1991 1990
(Thousands of dollars)
<S> <C> <C> <C> <C> <C>
Earnings
Income from continuing
operations before accounting
change $243,475 $211,740 $160,928 $207,012 $192,971
Add
Taxes based on income (1)
Federal income taxes 114,484 99,952 71,549 75,905 120,686
State income taxes 34,805 28,076 19,148 22,209 34,442
Deferred income taxes-net (2,262) 12,256 5,185 26,506 (31,794)
Investment tax credit
adjustment - net (13,979) (9,544) (9,708) (9,189) (10,048)
Foreign income taxes 219
Fixed charges 115,083 113,562 109,888 110,146 111,826
Deduct
Undistributed equity in earnings of
unconsolidated investees 27,427 1,142 1,006 0 1,876
Earnings $464,398 $454,900 $355,984 $432,589 $416,207
Fixed charges
Interest charges per
statement of income $115,083 $113,562 $109,888 $110,146 $111,826
Ratio of earnings to fixed
charges 4.0 4.0 3.2 3.9 3.7
(1) Includes income taxes included in Other Income and Deductions - Net.
</TABLE>
Exhibit 21.01
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES
Subsidiaries of Registrant
Name State of Incorporation Purpose
Northern States Power
Company (Wisconsin) Wisconsin Electric and gas utility
First Midwest Auto
Park, Inc. Minnesota Owns and manages a parking ramp
United Power and Land
Company Minnesota Real estate holding company
Cormorant Corporation Montana Former owner of interest in
coal and lignite properties
NRG Energy, Inc. Delaware Owns and manages non-
regulated energy subsidiaries
of the Company
Cenergy, Inc. Minnesota Natural gas marketing and energy
services
Viking Gas Transmission Company Delaware Natural gas transmission
Eloigne Company Minnesota Owns and operates affordable
housing units
Exhibit 23.01
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement
No. 2-74630 on Form S-16 and Registration Statement Nos. 33-43812 and 33-54534
on Form S-3 (relating to the Northern States Power Company Dividend
Reinvestment and Stock Purchase Plan), Registration Statement No. 2-61264 on
Form S-8 (relating to the Northern States Power Company Employee Stock
Ownership Plan), Registration Statement No. 33-38700 on Form S-8 (relating to
the Northern States Power Company Executive Long-Term Incentive Award Stock
Plan), and in Registration Statement No. 33-51593 on Form S-3 (relating to the
Northern States Power Company $600,000,000 Principal Amount of First Mortgage
Bonds) of our report dated February 8, 1995, which expresses an unqualified
opinion and includes an explanatory paragraph relating to the change in method
of accounting for postretirement health care costs in 1993 appearing in this
Annual Report on Form 10-K of Northern States Power Company for the year ended
December 31, 1994.
DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
March 27, 1995
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
Statements of Income, Balance Sheets, Statements of Capitalization, Statements
of Changes in Common Stockholders' Equity and Statements of Cash Flows and is
qualified in its entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,273,652
<OTHER-PROPERTY-AND-INVEST> 519,757
<TOTAL-CURRENT-ASSETS> 665,227
<TOTAL-DEFERRED-CHARGES> 357,576
<OTHER-ASSETS> 137,359
<TOTAL-ASSETS> 5,953,571
<COMMON> 167,305
<CAPITAL-SURPLUS-PAID-IN> 545,875
<RETAINED-EARNINGS> 1,183,191
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,896,967<F1>
0
240,469
<LONG-TERM-DEBT-NET> 1,463,354
<SHORT-TERM-NOTES> 3,660
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 234,779
<LONG-TERM-DEBT-CURRENT-PORT> 157,706
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,957,232<F1>
<TOT-CAPITALIZATION-AND-LIAB> 5,953,571
<GROSS-OPERATING-REVENUE> 2,486,547
<INCOME-TAX-EXPENSE> 133,266<F2>
<OTHER-OPERATING-EXPENSES> 2,049,001
<TOTAL-OPERATING-EXPENSES> 2,178,229
<OPERATING-INCOME-LOSS> 308,318
<OTHER-INCOME-NET> 46,410<F2>
<INCOME-BEFORE-INTEREST-EXPEN> 350,690
<TOTAL-INTEREST-EXPENSE> 107,215
<NET-INCOME> 243,475
12,364
<EARNINGS-AVAILABLE-FOR-COMM> 231,111
<COMMON-STOCK-DIVIDENDS> 175,292
<TOTAL-INTEREST-ON-BONDS> 97,143
<CASH-FLOW-OPERATIONS> 500,556
<EPS-PRIMARY> 3.46
<EPS-DILUTED> 0
<FN>
<F1>
NOTE 1 - $596 thousand of Common Stockholders' Equity is classified as Other
Items-Capitalization and Liabilities. This represents the net of
leveraged common stock held by the Employee Stock Ownership Plan
and the currency translation adjustments.
<F2>
NOTE 2 - $4.038 million of non-operating income taxes are classified as
Income Tax Expense. The financial statement presentation includes
them as a component of Other Income and Deductions-Net.
</FN>
</TABLE>
