<PAGE>
===============================================================================
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
For the Fiscal Year Ended December 31, 1994
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission File No. 1-3548
MINNESOTA POWER & LIGHT COMPANY
(Exact name of registrant as specified in its charter)
Minnesota 41-0418150
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
30 West Superior Street
Duluth, Minnesota 55802
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (218) 722-2641
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Stock
Title of Each Class Exchange on Which Registered
------------------- ----------------------------
Common Stock, without par value New York Stock Exchange
5% Cumulative Preferred Stock,
par value $100 per share American Stock Exchange
Serial Preferred Stock, $7.36 Series,
cumulative, without par value American Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock, without par value
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 / /
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. /X/
The aggregate market value of voting stock held by nonaffiliates on March
1, 1995, was $839,981,386.
As of March 1, 1995, there were 31,251,068 shares of Minnesota Power &
Light Company Common Stock, without par value, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Minnesota Power 1994 Annual Report are incorporated by
reference in Part II, Items 7 and 8, and portions of the Proxy Statement for
the 1995 Annual Meeting of Shareholders are incorporated by reference in
Part III.
===============================================================================
<PAGE>
INDEX
Page
PART I
Item 1. Business 1
Electric Utility Operations 1
Electric Sales 2
Firm Large Power Customer Contracts 2
Purchased Power 4
Capacity Sales 5
Fuel 5
Regulatory Issues 6
Electric Rates 6
Federal Energy Regulatory Commission 7
Minnesota Public Utilities Commission 8
Public Service Commission of Wisconsin 9
Capital Expenditure Program 9
Competition 10
Retail 10
Wholesale 10
Franchises 11
Environmental Matters 11
Air 11
Water 12
Solid Waste 12
Mining Control and Reclamation 13
Water Utility Operations 13
Regulatory Issues 14
Florida Public Service Commission 14
North Carolina Utilities Commission and
South Carolina Public Service Commission 15
Capital Expenditure Program 16
Franchises 16
Environmental Matters 16
Investments and Corporate Services 18
Capital Expenditure Program 20
Environmental Matters 20
Executive Officers of the Registrant 21
Item 2. Properties 23
Item 3. Legal Proceedings 24
Item 4. Submission of Matters to a Vote of Security Holders 24
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters 25
Item 6. Selected Financial Data 25
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations 26
Item 8. Financial Statements and Supplementary Data 26
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 26
PART III
Item 10. Directors and Executive Officers of the Registrant 26
Item 11. Executive Compensation 26
Item 12. Security Ownership of Certain Beneficial Owners and Management 26
Item 13. Certain Relationships and Related Transactions 26
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 27
SIGNATURES 33
<PAGE>
DEFINITIONS
The following abbreviations or acronyms are used in the text.
Abbreviations
or Acronyms Term
---------------------- -----------------------------------------------------
ADESA ADESA Corporation
BNI Coal BNI Coal, Ltd.
Boise Boise Cascade Corp.
Boswell Boswell Energy Center
Btu British thermal units
Capital Re Capital Re Corporation
CIP Conservation Improvement Programs
Company Minnesota Power & Light Company and its Subsidiaries
Duluth City of Duluth, Minnesota
Energy Policy Act National Energy Policy Act of 1992
EPA Environmental Protection Agency
FERC Federal Energy Regulatory Commission
FPSC Florida Public Service Commission
Heater Heater Utilities, Inc.
Hibbard M. L. Hibbard Station
Hibbing Taconite Hibbing Taconite Co.
Inland Inland Steel Mining Co.
Laskin Laskin Energy Center
Lehigh Lehigh Acquisition Corporation
LSPI Lake Superior Paper Industries
Manitoba Hydro Manitoba Hydro Electric Board
MBtu Million British thermal units
Minnesota Paper Minnesota Paper, Incorporated
Minnesota Power Minnesota Power & Light Company and its Subsidiaries
Minnkota Minnkota Power Cooperative, Inc.
MPCA Minnesota Pollution Control Agency
MPUC Minnesota Public Utilities Commission
MW Megawatt(s)
MWh Megawatt-hour
National National Steel Pellet Co.
NCUC North Carolina Utilities Commission
Note __ Note __ to the consolidated financial statements in
the Minnesota Power 1994 Annual Report
PSCW Public Service Commission of Wisconsin
Rainy River Rainy River Energy Corporation
Reach All Reach All Partnership
SCPSC South Carolina Public Service Commission
Square Butte Square Butte Electric Cooperative
SRFI Superior Recycled Fiber Industries Joint Venture
SSU Southern States Utilities, Inc.
SWL&P Superior Water, Light and Power Company
Synertec Synertec, Incorporated
Topeka Topeka Group Incorporated
UtilEquip UtilEquip, Incorporated
WPPI Wisconsin Public Power, Inc. SYSTEM
<PAGE>
PART I
Item 1. Business.
Minnesota Power is an operating public utility incorporated under the
laws of the State of Minnesota in 1906. Its principal executive office is at
30 West Superior Street, Duluth, Minnesota, 55802; and its telephone number
is (218) 722-2641. Minnesota Power has operations in three business areas:
(1) electric utility operations, which include electric, gas and coal mining
operations; (2) water utility operations, which include water, wastewater and
sanitation operations; and (3) investments and corporate services, which
include investments in securities, equity ownership in a financial guaranty
reinsurance company, real estate, paper and pulp production and manufacturing
of truck-mounted lifting equipment. As of December 31, 1994, the Company and
its subsidiaries had approximately 2,500 employees.
<TABLE>
<CAPTION>
Summary of Consolidated Earnings Per Share
------------------------------------------
1994 1993 1992
----- ----- -----
<S> <C> <C> <C>
Total Earnings Per Share $2.06 $2.20 $2.47
Business Area Percentage
Electric Utility Operations 62% 64% 56%
Water Utility Operations 23 4 (2)
Investments and Corporate Services 15 32 46
--- --- ---
100% 100% 100%
</TABLE>
Since 1983 Minnesota Power has been diversifying to reduce its reliance
on electricity sales to Minnesota's taconite industry and to gain additional
earnings growth potential. Acquisitions have been a primary means of
diversification, and this is expected to continue as the Company reinvests
funds from its securities investment portfolio in additional businesses.
For a detailed discussion of results of operations and trends, see
Management's Discussion and Analysis of Financial Condition and Results of
Operations in the Minnesota Power 1994 Annual Report. For business segment
information, see Note 1.
The information contained or incorporated by reference in this annual
report on Form 10-K reflects a categorization of the Company's business which
is different from the categorization used in the annual report on Form 10-K
for 1993. Financial data from prior years has been reclassified in this
annual report on Form 10-K to present comparable data in all periods.
Electric Utility Operations
Minnesota Power's electric utility operations generate, distribute and
sell electricity in a 26,000 square mile electric service territory located
in northern Minnesota. On December 31, 1994, the Company was supplying retail
electric service to 119,100 customers in 135 cities, towns and communities,
and outlying rural areas. The largest city served is Duluth with a population
of 85,000 based on the 1990 census. Wholesale electric service for resale is
supplied to 13 municipal distribution systems, a private utility and to
SWL&P. Transmission service (wheeling) is provided to 7 customers.
Minnesota Power has three wholly owned subsidiary companies within its
electric utility operations - SWL&P, BNI Coal and Rainy River. SWL&P provides
electric, water and natural gas service in Superior, Wisconsin, and adjacent
areas. As of December 31, 1994, SWL&P was supplying electric service to
13,700 customers, water service to 9,800 customers and gas service to 10,400
customers. BNI Coal owns and operates a lignite mine in North Dakota. Two
electric
-1-
<PAGE>
generating cooperatives, Minnkota and Square Butte, presently
consume virtually all of BNI Coal's production of lignite coal under coal
supply agreements extending to 2027. Minnkota has an option to extend its
coal supply agreement to 2042. (See - Fuel.) Rainy River is exploring
possibilities for participation in cogeneration projects.
Electric Sales
The Company expects that kilowatt-hour sales will remain relatively
stable over the next five years. (See Regulatory Issues - Minnesota Public
Utilities Commission.)
<TABLE>
<CAPTION>
Summary of Electric Revenue and Income
--------------------------------------
1994 1993 1992
---- ---- ----
In thousands
<S> <C> <C> <C>
Total Electric Revenue and Income $453,182 $457,719 $449,803
Type of Sales and Income Percentage
Retail Sales
Industrial
Taconite and Iron Mining <F1> 35% 34% 37%
Paper and Other Wood Products 14 14 14
Other Industrial 6 8 8
--- --- ---
Total Industrial 55 56 59
Residential 12 11 11
Commercial 12 11 11
Other Retail 3 4 3
Sales for Resale <F2> 8 7 6
Other Sales and Income 10 11 10
--- --- ---
100% 100% 100%
<FN>
--------------------------
<F1> The Company's largest customers, Minntac and Hibbing Taconite,
represented 13 percent and 10 percent, respectively, of total electric
revenue and income in 1994, 1993 and 1992.
<F2> The Company sold 171 MW of firm energy to sales for resale customers in
1994. (See Regulatory Issues - Federal Energy Regulatory Commission.)
</FN>
</TABLE>
In the last five years, more than 70 percent of all iron ore consumed by
iron and steel plants in the United States has originated from within the
Company's Minnesota electric service territory. Taconite, an iron-bearing
rock of relatively low iron content which is abundantly available in
Minnesota, is an important domestic source of raw material for the steel
industry. Taconite processing plants use large quantities of electric power
to grind the ore-bearing rock and agglomerate and pelletize the iron
particles into taconite pellets. The taconite industry in Minnesota has had
relatively stable production levels over the past five years. Annual
production from the Minnesota taconite companies was 43 million tons in 1994,
41 million tons in 1993, 40 million tons in 1992, 41 million tons in 1991,
and 44 million tons in 1990. The Company estimates that 1995 taconite
production will be about 48 million tons.
Firm Large Power Customer Contracts
The Company has power contracts which require the Company to have a
certain amount of capacity available at all times (Firm Power) with five
large taconite and five paper producing customers, each requiring 10 MW or
more (Firm Large Power Customers). Contracts with these ten Firm Large Power
Customers require payment of minimum monthly demand charges that cover most
of the fixed costs associated with having capacity available to serve them,
including a return on common equity. Such contracts minimize the impact on
earnings that otherwise would result from significant reductions in kilowatt-
hour sales to such customers. These contracts, which are subject to MPUC
approval, have a minimum contract term of ten years initially, with a four-
year
-2-
<PAGE>
cancellation notice required for termination of the contract at or
beyond the end of the tenth year. The rates and corresponding revenue
associated with capacity and energy provided under these contracts are
subject to change through the same regulatory process governing all retail
electric rates. As of March 17, 1995, the minimum annual revenue the Company
would collect under contracts with these Firm Large Power Customers, assuming
no electric energy use by these customers, is estimated to be $113.6, $95.7,
$92.8, $80.2 and $61.1 million during the years 1995, 1996, 1997, 1998 and
1999, respectively. The Company believes actual revenue received from these
Firm Large Power Customers will be substantially in excess of the minimum
contract amounts.
<TABLE>
Contract Status for Minnesota Power Firm Large Power Customers
as of March 17, 1995
<CAPTION>
Firm
Contracted Earliest
Plant and Location Operating Agent Ownership MW <F1> Termination Date
------------------ --------------- --------- ---------- ----------------
<S> <C> <C> <C> <C>
Eveleth Mines Oglebay Norton 41.7% Rouge Steel Co. 67.0 <F2> October 31, 1999
Eveleth, MN Co. 17.8% Oglebay Norton Co.
28.5% Armco Steel
12.0% Steel Co. of Canada
Hibbing Taconite Cliffs Mining 50% Bethlehem Hibbing 162.2 <F3> December 31, 2000
Co. Company Corporation
Hibbing, MN 10% Cliffs Mining Company
6.67% Ontario Hibbing
Company
33.33% Hibbing Development
Company
Inland Steel Inland Steel 100% Inland Steel Co. 45.0 <F4> October 31, 1997
Mining Co. Mining Co.
Virginia, MN
Minntac (USX) U.S. Steel Co. 100% USX Corp. 201.0 <F5> April 30, 1999
Mt. Iron, MN
National Steel National Steel 100% National Steel Corp. 85.0 <F6> October 31, 2004
Pellet Co. Corp.
Keewatin, MN
Blandin Paper Co. Blandin Paper Co. 100% Fletcher Challenge 50.6 <F7> December 31, 2003
Grand Rapids, MN Canada Ltd.
Boise Cascade Boise Cascade Corp. 100% Boise Cascade Corp. 32.0 December 31, 1998
Corp.
International
Falls, MN
Lake Superior Lake Superior 50% Minnesota Paper 48.0 <F8> December 31, 2005
Paper Industries Paper 50% Pentair Duluth Corp.
Duluth, MN Industries
Potlatch Corp. Potlatch Corp. 100% Potlatch Corp. 14.7 April 30, 1997
Cloquet, MN
Potlatch Corp. Potlatch Corp. 100% Potlatch Corp. 10.0 November 30, 1999
Brainerd, MN
<FN>
-----------------------------
The following terms are used in the contract descriptions footnoted below.
Firm demand is a take-or-pay obligation which is the sum of contract demand
plus incremental demand.
Incremental production service is billed on an energy only basis for energy
used above a customer's specific demand threshold. This service does not
include a take-or-pay obligation.
Interruptible service is electrical service for a customer that may be
interrupted by the Company under certain conditions. In return for this
service, customers receive a reduced demand charge, but are obligated to the
Company for future service requirements. In June 1993 the MPUC approved 100
MW of interruptible service. In October 1994 the MPUC approved an additional
100 MW of interruptible service to become effective May 1, 1995.
<F1> Firm contracted MW represents take-or-pay obligation for March 1995.
<F2> Eveleth Mines has firm demand through October 1999. Service requirements
through October 1995 are between 58 and 67 MW, from November 1995
through October 1998 are at 51 MW, and from November 1998 through
October 1999 are at 37.8 MW. This contract also provides $2.15 million
of CIP funding commitments and allows Eveleth to use incremental
production service as well as interruptible service. Beginning May 1,
1995, 10 MW of Eveleth's firm demand will be interruptible service.
-3-
<PAGE>
<F3> Hibbing Taconite has contract demand of 120.6 MW through December 2000
and incremental demand of approximately 40 MW through December 1997.
Hibbing Taconite's firm demand includes 53 MW of interruptible service.
This contract also includes a CIP funding commitment of $2.1 million and
incremental production service for loads above 162.7 MW. Beginning May
1, 1995, Hibbing Taconite's firm demand will include another 28 MW of
interruptible service.
<F4> Inland has contract demand of 34 MW and incremental demand of between 9
and 11 MW through October 1997. Inland's firm demand includes 18 MW of
interruptible service.
<F5> Minntac (USX) has contract demand of 150.4 MW through December 1995,
incremental demand of between 50.6 and 52.6 MW through April 1995, and
contract demand of 95 MW from January 1996 through April 1999. This
contract also includes a CIP funding commitment of $1.85 million and
provides for incremental production service for loads in excess of 203
MW. Beginning May 1, 1995, 21 MW of Minntac's firm demand will be
interruptible service.
<F6> National has firm demand of 85 MW (63 MW of contract demand and 22 MW of
incremental demand) through October 2004. An amendment incorporating
incremental production service over 85 MW and updating the interruptible
service provision is subject to MPUC approval. Beginning May 1, 1995, 39
MW of National's firm demand will be interruptible service.
<F7> Blandin Paper has contract demand of 37.5 MW and incremental demand of
13.1 MW through December 2003.
<F8> LSPI has contract demand of 38 MW, incremental demand of 10 MW, and
incremental production service above 52 MW through December 2005. LSPI's
firm demand includes 29 MW of interruptible service and beginning May 1,
1995, will include another 2 MW of interruptible service.
</FN>
</TABLE>
Purchased Power
Minnesota Power has contracts to purchase capacity from various
entities.
<TABLE>
Contract Status of Minnesota Power Purchased Power Contracts
<CAPTION>
Entity Contract MW Contract Period
------ ----------- ---------------
<S> <C> <C>
Participation Power Purchases <F1>
-----------------------------
Square Butte <F2> 323 May 6, 1977, through December 31, 2007
LTV Steel Mining Company 75 November 1, 1991, through April 30, 1995
City of Aitkin 2 May 1, 1993, through April 30, 1998
City of Two Harbors 2 May 1, 1993, through April 30, 1998
Silver Bay Power Company 10 May 1, 1995, through October 31, 1995
<FN>
----------------------------
<F1> Participation power purchase contracts require the Company to pay the
demand charges for MW under contract and an energy charge for each MWh
purchased. The selling entity is obligated to provide energy as
scheduled by the Company from the generating unit specified in the
contract as energy is available from that unit.
<F2> The Company has a contract which extends through 2007 to purchase 71
percent of the output of a generating plant owned by Square Butte which
is capable of generating up to 455 MW. Reductions to about 49 percent of
the output are provided for in the contract and, at the option of Square
Butte, could begin after a five-year advance notice to the Company. The
cost of the power and energy purchased is a proportionate share of
Square Butte's fixed obligations and operating costs based on the
percentage of the total output purchased by the Company. The annual
fixed lease obligations of the Company to Square Butte are $19.4 million
from 1995 through 1999. The variable obligation consists of operating
costs which are not incurred unless production takes place. The Company
is responsible for paying all costs and expenses of Square Butte
(including leasing, operating and any debt service costs) if not paid by
Square Butte when due. These obligations and responsibilities of the
Company are absolute and unconditional, whether or not any power is
actually delivered to the Company. (See Note 10.)
</TABLE>
-4-
<PAGE>
Capacity Sales
Minnesota Power has contracts to sell capacity to nonaffiliated utility
companies.
<TABLE>
Contract Status of Minnesota Power Capacity Sales Contracts
<CAPTION>
Utility Contract MW Contract Period
------- ----------- ---------------
<S> <C> <C>
Participation Power Sales <F1>
-------------------------
Interstate Power Company 55 May 1 through October 31 of each year from
1994 through 2000
20 November 1, 1997, through April 30, 1998
35 November 1, 1998, through April 30, 1999
50 November 1, 1999, through April 30, 2000
Firm Power Sales <F2>
----------------
Wisconsin Power & Light Company 30 November 1, 1993, through December 31, 1997
75 January 1, 1998, through December 31, 2007
Northern States Power Company 150 May 1 through October 31 of each year from
1994 through 1996
Cooperative Power Association 25 April 1, 1995, through September 30, 1995
10 April 1, 1997, through September 30, 1997
Minnkota Power Cooperative 10 May 1 through October 31 of each year for 1995
and 1996
<FN>
-----------------------
<F1> Participation power sales contracts require the purchasing utility to
pay the demand charges for MW under contract and an energy charge for
each MWh purchased. The Company is obligated to provide energy as
scheduled by the purchasing utility from the generating unit specified
in the contract as energy is available from that unit.
<F2> Firm power sales contracts require the purchasing utility to pay the
demand charges for MW under contract and an energy charge for each MWh
purchased. The Company is obligated to provide energy as scheduled by
the purchasing utility.
</FN>
</TABLE>
Fuel
The Company has experienced no difficulty in obtaining an adequate fuel
supply. The Company purchases low-sulfur, sub-bituminous coal from the Powder
River Basin coal field located in Montana and Wyoming to meet substantially
all of its coal supply requirements. Coal consumption for electric generation
at the Company's Minnesota coal-fired generating stations in 1994 was about
3.4 million tons. As of December 31, 1994, the Company had a coal inventory
of about 410,000 tons. During 1994, the Company obtained its coal through
both long- and short-term agreements. A long-term agreement (January 1993
through May 1997) with Big Sky Coal Company enables the Company to purchase
up to 2.5 million tons of coal on an annualized basis from the Big Sky Mine.
The Company also obtained coal under one-year agreements from Kennecott
Energy Company's Spring Creek Mine, Western Energy Company's Rosebud Mine,
and additional coal from Big Sky Coal Company's Big Sky Mine. In August 1994
the Company entered into a separate agreement (November 1994 through May
1997) with Big Sky Coal Company to purchase an additional 600,000 tons of
coal on an annualized basis from the Big Sky Mine. The Company will obtain
coal in 1995 under similar one-year agreements with Kennecott Energy Company
and Western Energy Company and will continue to obtain coal under its long-
term agreements with Big Sky Coal Company. This mix of coal supply options
allows the Company to reduce market risk and to take advantage of favorable
spot market prices.
-5-
<PAGE>
The Company is exploring future coal supply options and believes that
adequate supplies of low-sulfur, sub-bituminous coal will continue to be
available.
Burlington Northern Railroad transports the coal by unit train from
Montana or Wyoming to the Company's generating stations. The Company and
Burlington Northern Railroad have two long-term coal freight-rate contracts
that have been in effect since January 1, 1993. These contracts substantially
lowered the delivered price of coal to Minnesota Power. The contracts provide
for coal deliveries through 2002 to Laskin and through 2003 to Boswell. The
Company also has a contract with the Duluth Missabe & Iron Range Railway
which is the final destination short-hauler to Laskin. This contract, which
has been in effect since October 15, 1992, also substantially lowered the
delivered price of coal and provides for deliveries through 2002. The
delivered price of coal is subject to periodic adjustments in freight rates.
<TABLE>
Summary of Coal Delivered to Minnesota Power
--------------------------------------------
<CAPTION>
Average Delivery Price
----------------------
Year Ended December 31 Per Ton Per MBtu
---------------------- ------- --------
<S> <C> <C>
1994 $19.27 $1.08
1993 $19.31 $1.07
1992 $21.30 $1.18
</TABLE>
The generating unit operated by Square Butte, which is capable of
generating up to 455 MW, burns North Dakota lignite that is being supplied by
BNI Coal, a wholly owned subsidiary of the Company, pursuant to the terms of
a contract expiring in 2027. Square Butte's cost of lignite burned in 1994
was approximately 56 cents per million Btu. The lignite acreage that has been
dedicated to Square Butte by BNI Coal is located on lands essentially all of
which are under private control and presently leased by BNI Coal. This
lignite supply is sufficient to provide the fuel for the anticipated useful
life of the generating unit. Under the various agreements with Square Butte,
the Company is unconditionally obligated to pay all costs not paid by Square
Butte when due. These costs include the price of lignite purchased under a
cost-plus contract from BNI Coal. (See Item 2. Properties and Note 10.) BNI
Coal has experienced no difficulty in supplying all of Square Butte's lignite
requirements.
Regulatory Issues
The Company and its subsidiaries are exempt from regulation under the
Public Utility Holding Company Act of 1935, except as to Section 9(a)(2)
which relates to acquisition of securities of public utility companies.
The Company and its subsidiaries are subject to the jurisdiction of
various regulatory authorities. The MPUC has regulatory authority over
Minnesota Power's retail rates, issuance of securities and other matters. The
FERC has jurisdiction over the licensing of hydroelectric projects, the
establishment of rates and charges for the sale of electricity for resale,
and certain accounting and record keeping practices. The PSCW has regulatory
authority over the retail sales of electricity, water and gas by SWL&P. The
MPUC, FERC and PSCW had regulatory authority over 55 percent, 6 percent, and
5 percent, respectively, of the Company's 1994 total operating revenue and
income.
Electric Rates
The Company has historically designed its electric service rates based
on cost of service studies under which allocations are made to the various
classes of customers. Nearly all retail
-6-
<PAGE>
sales include billing adjustment clauses which adjust electric service rates
for changes in the cost of fuel and purchased energy, and recovery of current
and deferred CIP expenditures.
The Company's current policy for all contracts with Firm Large Power
Customers is to require a minimum initial contract term of ten years with the
term perpetuated thereafter (continuous term) subject to a minimum
cancellation notice of four years. The Company's Firm Power rate schedules
are designed to recover the fixed costs of providing Firm Power to Firm Large
Power Customers, including a return on common equity, regardless of the
amount of power or energy actually used. A Firm Large Power Customer's
monthly demand charge obligation in any particular month is determined based
upon the greater of its actual demand for electricity or the firm demand
amount. Contract and rate schedule provisions provide for adjustment if the
customer's firm demand amount is set significantly below the customer's
actual electric requirements. The rates and corresponding revenue associated
with capacity and energy provided under these contracts are subject to change
through the regulatory process governing all retail electric rates. Contracts
with eight of the ten Firm Large Power Customers provide for deferral without
interest or diminishment of one-half of demand charge obligations incurred
during the first three months of a strike or illegal walkout at a customer's
facilities, with repayment required over the 12-month period following
resolution of the work stoppage.
The Company also has contracts with large industrial customers who
require less than 10 MW of capacity (Large Light and Power Customers). The
terms of these contracts vary depending upon the customers' demand for power
and the cost of extending the Company's facilities to provide electric
service. Generally, the contracts for less than 3 MW have one-year terms and
the contracts ranging from 3 to 10 MW have initial five-year terms. The
Company's rate schedule for Large Light and Power Customers is designed to
minimize fluctuations in revenue and to recover a significant portion of the
fixed costs of providing service to such customers.
The Company requires that all large industrial and commercial customers
under contract specify the date when power is first required, and thereafter
the customer is billed for at least the minimum power for which it
contracted. These conditions are part of all contracts covering power to be
supplied to new large industrial and commercial customers and to current
contract customers as their contracts expire or are amended. All contracts
provide that new rates which have been approved by appropriate regulatory
authorities will be substituted immediately for obsolete rates, without
regard to any unexpired term of the existing contract. All rate schedules are
subject to approval by appropriate regulatory authorities.
Federal Energy Regulatory Commission
Twelve Minnesota municipalities have contracts with the Company through
at least 2007 and three additional municipalities have contracts through
1999. Thirteen of these contracts have caps of about 2 percent per year
(including fuel costs) on rate increases. The other two municipal customers
signed amendments under which the Company will provide exclusive brokering
service for the municipalities' purchases of economy energy and will supply
emergency, scheduled outage and firm energy as required through 1999. In
1994, 11 municipal customers purchased 76 MW of Firm Power.
In September 1988 the FERC approved a contract between Minnesota Power
and SWL&P which provides for SWL&P to purchase its power from the Company
through at least 1999 and incorporates the same cap on future rate increases
as discussed above. The Company also has a contract, approved by the FERC, to
supply electricity to Dahlberg Light and Power Company (Dahlberg) through
December 2004. SWL&P purchased 87 MW and Dahlberg purchased 8 MW of Firm
Power in 1994.
-7-
<PAGE>
The Company's hydroelectric facilities which are located in Minnesota
are licensed by the FERC. The FERC issued an annual operating license for the
St. Louis River hydroelectric project (88.2 MW generation capability) in
January 1994, which is effective until a final 30-year license is issued. As
a part of the relicensing process, the FERC issued an environmental impact
statement for the St. Louis River project in February 1995. A new license is
expected in late 1995. The Company filed a draft relicensing application for
the Pillager hydroelectric project (1.6 MW) in January 1995 and will file a
final application in May 1995. (See Environmental Matters - Water.)
Minnesota Public Utilities Commission
In January 1994 the Company filed with the MPUC a request for a final
annual rate increase for all retail electric customers aggregating $34
million, or 11.8 percent, with a 12.5 percent return on equity. In August
1994 the Company reduced its requested annual increase of $34 million to $27
million for 1994 and $23 million for 1995 because of reductions in the
projected cost of service and the addition of long-term contract commitments
by a taconite customer. On February 17, 1994, the MPUC voted to approve the
Company's requested annual interim rate increase of $20 million, or 7
percent. This interim rate increase was implemented on March 1, 1994, subject
to refund with interest, and will continue until final rates are effective.
In November 1994 the MPUC issued an order granting the Company an
increase in annual electric operating revenue of $19 million, or 6.4 percent,
with an 11.6 percent return on equity. Rates for large industrial customers
will increase less than 4 percent, while the rate for small businesses will
increase 6.5 percent. The rate increase for residential customers will be
phased in over three years: 13.5 percent beginning in 1995, an additional
3.75 percent beginning January 1996 and another 3.75 percent beginning
January 1997. The increase for large industrial users will be more than
offset by savings in coal purchase and transportation costs. These savings
are passed on to all customers and are the result of contracts negotiated
with suppliers in recent years.
In December 1994 intervenors, including the Company, filed with the MPUC
for reconsideration of its November 1994 order. In a March 15, 1995 order,
the MPUC denied all material aspects of the requests for reconsideration and
upheld the increase granted in November 1994. This order is subject to appeal
for a 30 day period ending April 14, 1995. However, no appeals have been
filed to date. Final rates are expected to be implemented in the second
quarter of 1995.
In 1994 the Company collected $17.2 million of interim revenue, subject
to refund with interest. As of December 31, 1994, the Company had reserved
$6.1 million of the interim rate revenue for anticipated refunds.
In 1991 the Minnesota State Legislature passed legislation that mandates
Minnesota electric utilities to spend a minimum of 1.5 percent of gross
annual electric revenue by 1995, on CIP. In 1994, 1993 and 1992, the Company
spent $8, $4.1 and $1.8 million, respectively, on CIP and expects to spend a
total of $8.5 million during 1995. The MPUC allows such conservation
expenditures to be accumulated in a deferred account for recovery through
future rates.
In January 1994 the Company began recovering ongoing 1994 CIP
expenditures and $8.2 million of deferred CIP expenditures incurred prior to
December 31, 1993, through an annual billing adjustment mechanism approved by
the MPUC. Through the adjustment the Company is allowed to recover current
and deferred CIP expenditures and a lost margin associated with power saved
as a result of these programs. The adjustment is revised annually to reflect
CIP expenditures that differ from the base level included in the rate
schedules. The Company collected $7.8 million of CIP related revenue in 1994.
-8-
<PAGE>
In 1993 the MPUC approved 100 MW of interruptible service for Firm Large
Power Customers. As a condition to taking advantage of the interruptible
service, the customers agreed that, to the extent they have electric service
requirements (other than requirements served by the customer's ownership
share of electric generating facilities at the customer's site) in the period
1997 through 2008, such customers will purchase from the Company not less
than the initially certified interruptible load allocation. Also, if the
interruptible customer is permitted in the future to obtain electric service
from another supplier, the Company shall have the right of first refusal to
provide an additional amount of electric service equal to the customer's
allocated interruptible load during the eleven-year period, 1997 through
2008. New contract amendments negotiated and approved in 1993 for Hibbing
Taconite, Inland, and LSPI extended the contract demand terms to at least
October 31, 1997. Of the initial 100 MW available for the interruptible
service, Hibbing Taconite was allocated 53 MW, Inland 18 MW and LSPI 29 MW.
In 1994 the MPUC approved an additional 100 MW of interruptible service
to become effective May 1, 1995. Conditions for service are similar to those
with respect to the initial 100 MW offered, however, the period extends from
1999 through 2010. Of the second 100 MW of interruptible service, Eveleth
Mines was allocated 10 MW, Hibbing Taconite 28 MW, Minntac 21 MW, National 39
MW, and LSPI 2 MW.
Minnesota law enables the Company to offer retail customers special
rates to meet competition from unregulated energy suppliers or cogenerators.
The Company implemented a generation deferral rate in November 1990 for
Boise. In March 1994 the MPUC approved an amendment to Boise's contract which
includes extension of the generation deferral rate until December 1998. While
this rate is lower than the normal retail rate, it provides for recovery of
approximately $20 million over the next five years of the Company's fixed
costs which would not have been recovered had Boise installed its own
generating facilities. In addition, special rates were implemented to attract
a new commercial customer that has a 1 MW load. (See Competition.)
In 1994 the Company asked the MPUC to approve two additional rates for
retail customers. First, an economic development rate, if approved, would
give discounts to customers who invest in new capital improvements or
equipment and increase electrical load on the Company's system. Second, an
incremental sales rider has been approved which allows more flexibility for
some customers to operate above their specified demand levels in certain
months and pay only energy charges for the incremental load. (See
Competition.)
Public Service Commission of Wisconsin
During 1993 and 1994 SWL&P received approval from the PSCW to expand its
gas service territory to serve eight additional rural communities adjacent to
its existing service territory. The expansion projects were completed in 1994
at a total cost of $2.4 million.
Capital Expenditure Program
Capital expenditures for the electric utility operations totaled $45
million during 1994, of which $2 million was for coal operations. Internally
generated funds were used to fund these capital expenditures.
The Company's electric generating stations have the capacity to meet
customer needs through the 1990s without major capacity additions or
environmental modifications. Electric utility operations capital expenditures
are expected to be $37 million in 1995, of which $7 million is related to
coal operations. A total of approximately $158 million of electric utility
operations capital expenditures is expected during the period 1996 through
1999, of which $10 million is related to coal operations. The Company's
estimates of such capital expenditures and the sources of financing are
subject to continuing review and adjustment.
-9-
<PAGE>
Competition
The enactment of the Energy Policy Act resulted in an increase in the
competitive forces that affect two of the three key elements of the electric
utility industry, namely generation and transmission. The third element,
distribution, remains unaffected. This legislation has resulted in a more
competitive market for electricity in both the retail and wholesale markets.
Minnesota Power is well-positioned to meet both retail and wholesale
competitive forces. The Company's rates are very competitive even with the
retail rate increase approved by the MPUC in November 1994. Many of the
Company's wholesale and Firm Large Power Customers have extended the terms of
their electric service agreements with the Company. As such agreements are
extended, the Company's competitive position is enhanced. In addition to
providing electricity to its customers, the Company offers its customers a
wide variety of value-added services, including conservation improvement
services, to meet their energy needs. The Company has also obtained MPUC
approval to offer interruptible rates to Firm Large Power Customers and may
offer competitive rates within its service territory to serve customers that
could otherwise obtain their energy needs from an unregulated energy supplier
or by generating their own electricity with MPUC approval.
Retail
Large industrial and commercial customers that have the ability to own
and operate their own generation facilities may compete directly with the
Company to supply their own electric needs. If these facilities are
Qualifying Facilities (QFs), the customers that own them may require that the
Company purchase the output from them at the Company's "avoided cost"
pursuant to the Public Utility Regulatory Policies Act. Additionally, these
customers, as well as the balance of the Company's customers, may elect to
substitute other sources of energy, such as natural gas, oil or wood, for
various end uses rather than continuing to use electric energy.
Municipalities may elect to serve customers of the Company lying within
municipal boundaries, but must fully compensate the Company for its loss of
property and revenue associated with this load. Finally, the prospect that
large industrial customers might seek state authorization of retail wheeling
in the future would have the effect of substantially increasing competition
in the retail segment of the market for electricity.
Wholesale
The Energy Policy Act increased competition in the wholesale market by
eliminating existing legal barriers with respect to entry into the generation
market and with respect to the provision of transmission services. First, the
Energy Policy Act created a new class of power producers, known as Exempt
Wholesale Generators (EWGs). EWGs are exempt from regulation under the Public
Utility Holding Company Act of 1935 and EWG sales are generally subject to
less regulation than sales by traditional utilities. The fact that EWGs may
include independent power producers as well as affiliates of electric
utilities marks a further diminution of the role of electric utilities as the
exclusive generators of electric energy. Second, the Energy Policy Act
authorized the FERC to order utilities which own or operate transmission
facilities to provide wholesale transmission services to or from other
utilities or entities generating electric energy for sale or resale, provided
that the rates charged for transmission services are recovered from the
entity seeking the transmission service and not from the transmitting
utility's existing wholesale, retail or transmission customers. The Energy
Policy Act expressly prohibits the FERC from ordering a utility to provide
retail wheeling services to any of its customers.
-10-
<PAGE>
Franchises
Minnesota Power holds franchises to construct and maintain an electric
distribution and transmission system in 93 cities and towns located within
its service territory. SWL&P holds franchises in 11 cities and towns within
its service territory. The remaining cities and towns served will not grant a
franchise or do not require a franchise to operate within their boundaries.
Environmental Matters
The Company's electric utility operations are subject to regulation by
various federal, state and local authorities in the areas of air quality,
water quality, solid wastes, and other environmental matters. The Company
considers its electric utility operations to be in substantial compliance
with those environmental regulations currently applicable to its operations
and believes all necessary permits to conduct such operations have been
obtained. Except as noted below, the Company does not currently anticipate
that its potential capital expenditures for environmental control purposes
will be material. However, because environmental laws and regulations are
constantly evolving, the character, scope and ultimate costs of environmental
compliance cannot be estimated.
Air
The Federal Clean Air Act Amendments of 1990 (Clean Air Act) require
that specified fossil-fueled generating plants meet new sulfur dioxide and
nitrogen oxide emission standards beginning January 1, 1995 (Phase I) and
that virtually all generating plants meet more strict emission standards
beginning January 1, 2000 (Phase II). None of Minnesota Power's generating
facilities are covered by the Phase I requirements of the Clean Air Act.
The Clean Air Act creates emission allowances for sulfur dioxide based
on formulas relating to the permitted 1985 emissions rate and a baseline of
average fossil fuel consumed in the years 1985, 1986 and 1987. Each allowance
is an authorization to emit one ton of sulfur dioxide, and each utility must
have sufficient allowances to cover its annual emissions. Minnesota Power's
generating facilities in Minnesota burn mainly low-sulfur western coal and
Square Butte, located in North Dakota, burns lignite coal. All of these
facilities are equipped with pollution control equipment such as scrubbers,
baghouses or electrostatic precipitators. Phase II sulfur dioxide emission
requirements are currently being met by Boswell Unit 4. Some moderate
reductions in emissions may be necessary from Boswell Units 1, 2, and 3,
Laskin Units 1 and 2, and Square Butte to meet the Phase II sulfur dioxide
emission requirements. The Company believes it is in a good position to
comply with the sulfur dioxide standards without extensive modifications. Any
required reductions at the Minnesota generating facilities are expected to be
achieved through the use of lower sulfur coal. Square Butte anticipates
meeting any required reductions through increased use of existing scrubbers.
The Clean Air Act requires the EPA to set the nitrogen oxide limitations
by January 1, 1997, for Phase II generating units. To meet anticipated Phase
II nitrogen oxide limitations, the Company expects to install low-nitrogen
oxide burner technology by the year 2000. Square Butte will be able to
determine the costs of complying with the nitrogen oxide limitations when
regulations applicable to this plant are promulgated by the EPA. Based on
preliminary estimates, the costs of complying with the nitrogen oxide
limitations for Boswell, Laskin and Hibbard are not expected to exceed $10
million.
-11-
<PAGE>
Installation of continuous emission monitoring equipment by January 1,
1995, is also required by the Clean Air Act for Phase II units. Boswell,
Laskin and Hibbard installed $2.8 million of continuous emission monitoring
(CEM) equipment, and Square Butte installed over $400,000 of CEM equipment in
1994.
In August 1993 the Company indicated its intent to work with the U.S.
Department of Energy to identify appropriate activities that the Company has
taken and additional measures that the Company may undertake on a voluntary
basis that will result in limitations, reductions or sequestrations of
greenhouse gas emissions by the year 2000. Section 1605 of the Energy Policy
Act mandates timely and acceptable definitions of greenhouse gas accounting
guidelines and greenhouse gas crediting guidelines. The Company has agreed to
participate in this voluntary program provided that such participation is
consistent with the Company's integrated resource planning process, does not
have a material adverse effect on the Company's competitive position with
respect to rates and costs, and continues to be acceptable to the Company's
regulators.
Water
The Federal Water Pollution Control Act of 1972 (FWPCA), as amended by
the Clean Water Act of 1977 and the Water Quality Act of 1987, established
the National Pollutant Discharge Elimination System (NPDES) permit program.
The FWPCA requires that NPDES permits be obtained from the EPA (or, when
delegated, from individual state pollution control agencies) for any
wastewater discharged into navigable waters.
The MPCA reissued the Laskin NPDES permit on December 22, 1993. This
permit will remain in effect until October 31, 1998. The permit contained a
schedule of compliance which required a 57 percent reduction in the size of
the ash disposal ponds by November 1, 1994. This work was completed in August
1994 at a total cost of $1.1 million. Additional work is currently planned to
begin in the second quarter of 1995 at an estimated cost of $150,000. No
further actions are anticipated during the remainder of the permit term.
Federal Energy Regulatory Commission (FERC) operating licenses for
several of the Company's hydroelectric facilities have been received or are
currently undergoing relicensing by the FERC. Thirty (30) year licenses for
Little Falls, Sylvan and Prairie River Hydroelectric Projects were issued by
FERC in 1993 effective on January 1, 1994. The St. Louis River Project is
currently operating under an annual license until the FERC has completed its
environmental review of the project. Since the final environmental impact
statement for the project was released by FERC dated February 1995, the
Company expects that the final license will be issued sometime in late 1995.
A final application to relicense the Pillager Project will be filed with the
FERC by May 11, 1995. The FERC will perform an engineering, environmental and
economic analysis of that application over a two year period prior to the
current Pillager FERC license expiration on May 11, 1997. A new license is
expected to be issued for this project by the FERC before the current
expiration date. The Company believes, that although environmental
considerations may require additional studies or higher minimum flow releases
for fish habitat, recreation and water quality enhancement, that the
economics of each project will not be compromised.
Solid Waste
The Resource Conservation and Recovery Act of 1976 regulates the
management and disposal of solid wastes. As a result of this legislation, the
EPA has promulgated various hazardous waste rules. The Company is required to
notify the EPA of hazardous waste activity and routinely submits the
necessary annual reports to the EPA.
-12-
<PAGE>
In 1990 the Company was notified by the EPA and the MPCA that it had
been named as a potentially responsible party under the Comprehensive
Environmental Response, Compensation and Liability Act pertaining to the
cleanup of pollution at a northern Minnesota oil refinery site (Arrowhead
Site). In 1994 a settlement proposal was reached regarding cleanup at the
Arrowhead Site. State and federal officials have agreed cleanup should begin
in 1995. The total costs to remediate the Arrowhead Site are currently
estimated at $37 million. Funding under the proposal is shared by several
governmental entities and about 130 companies. The formal request for
approval of the settlement has been filed with the appropriate agencies.
Under the terms of the settlement, Minnesota Power's share of remediation
costs is approximately $314,000, which has been paid. In addition, the
Company has spent about $600,000 to date on legal and other costs since the
suit was initiated.
Mining Control and Reclamation
BNI Coal's mining operations are governed by the Federal Surface Mining
Control and Reclamation Act of 1977. This Act, together with the rules and
regulations adopted thereunder by the Department of the Interior, Office of
Surface Mining Reclamation and Enforcement (OSM), governs the approval or
disapproval of all mining permits on federally owned land and also governs
the actions of the OSM in approving or disapproving state regulatory programs
regulating mining activities. The North Dakota Reclamation of Strip Mined
Lands Act and rules and regulations enacted thereunder in 1969, as
subsequently amended by the North Dakota Mining and Reclamation Act and rules
and regulations enacted thereunder in 1977, govern the reclamation of surface
mined lands and are generally as stringent or more stringent than the federal
rules and regulations. Compliance is monitored by the North Dakota Public
Service Commission. The federal and state laws and regulations require a wide
range of procedures including water management, topsoil and subsoil
segregation, stockpiling and revegetation, and the posting of performance
bonds to assure compliance. In general, these laws and regulations require
the reclaiming of mined lands to a level of usefulness equal to or greater
than that available before active mining.
Water Utility Operations
Topeka, a wholly owned subsidiary of the Company, owns 100 percent of
the companies described below which sell water and provide wastewater
treatment services. These water utilities have been upgrading existing
operations, building new facilities, acquiring new systems and seeking rate
increases.
. SSU owns and operates water and wastewater treatment facilities in
many communities in Florida. SSU is the largest private water
supplier in Florida. At December 31, 1994, SSU served 104,000 water
customers and 44,100 wastewater treatment customers. SSU also
provides sanitation services to one franchise area serving 11,800
customers.
. Heater owns and operates 4 companies which provide water and
wastewater treatment services in North Carolina and South Carolina.
At December 31, 1994, these companies served 24,800 water customers
and 2,600 wastewater treatment customers.
In October 1994 SSU and Sarasota County signed a purchase agreement
regarding the threatened condemnation of the Venice Gardens water and
wastewater facilities owned by SSU and located in Sarasota County, Florida.
The sale for $37.6 million was completed in December 1994 adding $11.8
million or 42 cents per share to 1994 earnings.
-13-
<PAGE>
In September 1994 SSU signed a purchase agreement to acquire the assets
of Orange Osceola Utilities, Inc. located near Kissimmee, Florida, for
approximately $13 million. The purchase is subject to various regulatory
approvals prior to closing which the Company believes will be received in due
course. In October 1994 SSU filed with the FPSC for approval of the purchase.
The 17,450 water and wastewater connections which will be gained as a result
of the purchase will approximate the number of connections SSU sold in the
Venice Gardens transaction.
In October 1994 Seabrook Island, South Carolina, residents voted to
allow the town to purchase or acquire through eminent domain powers the
town's current water and wastewater treatment facilities owned by Heater of
Seabrook, a wholly owned subsidiary of Heater. Heater of Seabrook currently
serves 3,300 customers. In January 1995 the town of Seabrook Island initiated
an eminent domain action to take the assets of Heater of Seabrook from
Heater. The price will be determined through court proceedings.
Regulatory Issues
The FPSC and certain county commissions in Florida have regulatory
authority over water and wastewater treatment services sold by SSU. The NCUC
and the SCPSC have regulatory authority over water and wastewater treatment
services sold by Heater and its subsidiaries. The Florida commissions had
regulatory authority over 9 percent of the Company's 1994 total operating
revenue and income, and the North Carolina and South Carolina commissions had
regulatory authority over 1 percent.
Florida Public Service Commission
The following is a summary of SSU's rate filings with the FPSC and three
county commissions during 1993 and 1994.
. Under provisions of a Florida state statute, water and wastewater
utilities may file with the FPSC an annual index and pass-through
filing designed to recover inflation costs associated with
operation and maintenance expenses. The intent of the statute is to
provide inflationary relief to utilities thus delaying or avoiding
the costs associated with full rate case filings. In May 1994 SSU
made an index and pass-through filing for its FPSC regulated
systems. The annual increase requested was $711,000 or a rate
increase of approximately 1.6 percent. In June 1994 SSU withdrew
the portion of the request relating to Hernando County at the
request of the FPSC. The FPSC approved $550,000 of the filing on an
annual basis and the rates became effective in July 1994.
. In September 1994 SSU filed a pass-through filing with the
Hillsborough Board of County Commissioners for a $500,000 increase
in wastewater rates for the Seaboard facilities. The increase was
effective in October 1994 and recovers costs SSU pays to the City
of Tampa for wastewater treatment.
. In December 1994 SSU filed a pass-through filing with the FPSC for
a $714,000 increase in water and wastewater rates for the Deep
Creek facilities. The increase became effective in February 1995
and is expected to recover costs SSU pays to Charlotte County for
bulk water and wastewater treatment.
. The FPSC ordered statewide uniform rates for 90 water and 37
wastewater service areas in SSU's 1992 consolidated rate filing. In
September 1993 the FPSC initiated a separate investigation into the
appropriate rate structure for SSU. The investigation was initiated
for the purpose of determining if, as a matter of policy, uniform
statewide rates are appropriate for SSU. In June 1994 the FPSC
issued
-14-
<PAGE>
an order declining to issue a declaratory statement which
would have acknowledged FPSC jurisdiction over SSU service areas in
Hillsborough and Polk Counties. Instead the FPSC opened an
investigation to determine if SSU is a single system pursuant to
Florida statutes. If SSU is classified as a single system, all SSU
facilities operated in Florida will be subject to FPSC
jurisdiction. Hearings were held in January 1995, with a final
decision expected in June 1995.
. In April 1994 the Hernando County Board of County Commissioners
issued an order rescinding FPSC jurisdiction in Hernando County. In
June 1994 the FPSC issued an order acknowledging that Hernando
County has jurisdiction over privately-owned water and wastewater
facilities located in the County as of April 5, 1994. In April 1994
SSU filed a court action before the Florida Circuit Court for
Hernando County to stay the change in jurisdiction. This action
remains pending. In April 1994 SSU also requested the FPSC to
retain interim jurisdiction over SSU's facilities in Hernando
County until jurisdictional determinations are made by the courts.
In June 1994 the FPSC issued an order denying SSU's request. SSU
has appealed this order to Florida's First District Court of
Appeals. SSU believes that a jurisdictional change should not be
made at this time because of the FPSC investigation to determine if
SSU's facilities in all counties within Florida constitute a single
system subject to the sole jurisdiction of the FPSC.
. In September 1994 the Charlotte County Board of County
Commissioners declared that as of September 27, 1994, all water and
wastewater utilities in Charlotte County were subject to the
jurisdiction of the FPSC. The FPSC acknowledged the County action
in a November 1994 order and is expected to issue in 1995 a
Certificate of Authority to SSU for facilities located in Charlotte
County.
SSU plans to file a general rate increase application with the FPSC in
1995. New facilities added since 1992 (SSU's last general rate increase) are
not yet included in rate base for earnings purposes. Additionally, mandated
regulatory compliance cost increases during the same period, particularly for
environmental protection, have increased operating expenses and should also
be recovered in rates. The filing is expected to include water conservation
incentives and request approval of a consistent policy on charges for service
availability.
North Carolina Utilities Commission and South Carolina Public Service
Commission
The following is a summary of Heater's pending rate filings with the
NCUC and the SCPSC.
. In July 1992 Heater filed with the SCPSC for a $233,000 rate
increase for operations near Columbia, South Carolina. In January
1993 the SCPSC denied the rate increase request. In March 1993
Heater filed with the Circuit Court of South Carolina an appeal of
the SCPSC's denial of the request. In September 1993 the requested
rates were implemented, under surety bond, pending the decision on
the appeal. As a condition to the SCPSC's grant to Heater of a
$110,000 annual increase in May 1994, Heater was required to cease
charging the increased rates under surety bond. The final decision
on the appeal is expected in 1995 and will determine the amount of
the refund with interest, if any.
. In January 1994 Heater of Seabrook, a wholly owned subsidiary of
Heater, filed with the SCPSC for a $263,000 annual rate increase
for operations near Charleston, South Carolina. In July 1994 the
SCPSC denied the request for an
-15-
<PAGE>
annual rate increase. The SCPSC treated $64,000 in availability
fees as revenue. Previously, the SCPSC treated these fees as a
reduction to rate base. This treatment resulted in an 8.6 percent
operating margin which the SCPSC found to be adequate. Heater of
Seabrook filed a motion for reconsideration in July 1994
maintaining that the resulting 3.98 percent return on equity is
inadequate. In August 1994 the SCPSC denied reconsideration. In
September 1994 Heater of Seabrook filed an appeal in the Circuit
Court of South Carolina and subsequently provided notice to the
customers and implemented the requested rates under surety bond in
January 1995, pending the final decision on the appeal.
. In July 1994 Upstate Heater Utilities (Upstate), a wholly owned
subsidiary of Heater, filed for a $71,000 annual rate increase with
the SCPSC. In December 1994 the SCPSC denied the request for an
annual rate increase primarily due to customer opposition. In
January 1995 Upstate filed for reconsideration and the SCPSC denied
the request. In February 1995 Upstate filed an appeal in the
Circuit Court of South Carolina.
. In February 1995 Heater filed for a $314,000 annual rate increase
with the NCUC. A hearing is scheduled for July 18, 1995.
. In March 1995 Brookwood Water Corporation, a wholly owned
subsidiary of Heater, filed with the NCUC for a $120,000 annual
rate increase.
Capital Expenditure Program
Capital expenditures for the water and wastewater utility operations
totaled $28 million during 1994. Expenditures were funded with the proceeds
from long-term bonds issued by SSU and internally generated funds. Water
utility capital expenditures are expected to be $26 million in 1995 for
upgrades, water reuse projects and new water facilities, and to total
approximately $99 million during the period 1996 through 1999.
Franchises
SSU provides water and wastewater treatment services in 22 counties
regulated by the FPSC and holds franchises in three counties which to date
have retained authority to regulate such operations. SSU is contesting in a
Florida circuit court and a Florida appellate court the authority of one of
these three counties, Hernando County, to regulate SSU's operations. (See
Regulatory Issues - Florida Public Service Commission.)
All of the water and wastewater services of Heater are under the
jurisdiction of regulatory commissions. These commissions grant franchises
for Heater's service territory when the rates are authorized.
In March 1995 East LA Services Corporation, a wholly owned subsidiary of
Topeka, was notified by Lee County, Florida that it would not be awarded any
sanitation service area franchises requested as part of a proposal procedure.
As a result, East LA Services Corporation expects to discontinue operations
on or about September 30, 1995, the existing franchise agreement's expiration
date. Discontinuation of this business will not be material.
Environmental Matters
The Company's water utility operations are subject to regulation by
various federal, state and local authorities in the areas of water quality,
solid wastes, and other environmental matters. The Company considers its
water utility operations to generally be in compliance with those
-16-
<PAGE>
environmental regulations currently applicable to its operations and have the
permits necessary to conduct such operations. Except as noted below, the
Company does not currently anticipate that its potential capital expenditures
for environmental control purposes will be material. However, because
environmental laws and regulations are constantly evolving, the character,
scope and ultimate costs of environmental compliance cannot be estimated.
In July 1992 the EPA issued a Request for Information to SSU regarding
operations of SSU's wastewater facilities in the Seaboard service area in
Hillsborough County, Florida. The request was made to obtain more details
concerning exceedances of the NPDES permit for effluent quality. Requested
information was compiled and sent to the EPA in September 1992. In 1993 SSU
complied with an additional Request for Information issued by the EPA. In
1993, the EPA issued an Administrative Order regarding the violations. The
Order required SSU to select a method to consistently meet all NPDES permit
requirements or cease all discharges to the surface waters of the United
States. In March 1994 SSU connected the Seaboard facilities with the City of
Tampa's facilities and ceased discharges from the facilities to surface
waters. SSU has received no further communication from the EPA regarding this
matter and is unable to determine what further action, if any, may be
required.
In October 1992 the EPA issued an Information Request to SSU regarding
operations of SSU's facilities in the University Shores service area in
Orange County, Florida. The request was made to obtain more details
concerning exceedances of the NPDES permit for effluent quality. The
requested information was compiled and sent to the EPA in late 1992 and
supplemented in February 1993. In February 1993 the EPA issued a Notice to
Show Cause letter to request SSU representatives to meet in Atlanta, Georgia,
to discuss the exceedances. SSU met with the EPA in March 1993 and received
an additional Information Request from the EPA in April 1993. The requested
information was supplied to the EPA in June 1993. At that time, SSU was
attempting to determine a feasible method to eliminate surface water
discharges allowed by the NPDES permit. After months of design and
environmental permitting problems, SSU signed an agreement with Orange County
Utilities (OCU) to construct an interconnect between the two collection
systems so that a portion of the sewage flow at University Shores could be
sent to OCU. The construction of the interconnect was completed in September
1994 thereby allowing SSU to eliminate effluent discharges by the University
Shores facilities to surface waters. Additional information on the project
was requested by EPA in November 1994 and SSU supplied the requested
information to the EPA in December 1994.
In September 1993 the EPA issued an Administrative Order to SSU
regarding operations of SSU's facilities in the Woodmere service area in
Duval County, Florida (Woodmere facilities). The Order requires monthly
toxicity testing of the effluent for at least one year because of toxicity
test failures during 1992 and 1993. In September 1994, because of additional
1993 and 1994 toxicity test failures at the Woodmere facilities, the EPA
required implementation of a Toxicity Reduction Evaluation (TRE) plan to
determine the cause of the toxicity. The TRE plan is expected to take
approximately 15 months to complete.
In August 1994 the EPA issued an Administrative Order to SSU regarding
operations of SSU's facilities in the Beacon Hills service area in Duval
County. The Order requires monthly toxicity testing of the effluent because
of toxicity test failures during 1993 and 1994.
SSU and the Florida Department of Environmental Protection (FDEP)
completed negotiations in 1994 on five consent orders involving water and
wastewater facilities within SSU's system resulting in penalties and
reimbursement totaling approximately $27,000. Three additional consent orders
with proposed penalties of approximately $25,000 are being negotiated with
the FDEP.
-17-
<PAGE>
In 1994 SSU invested approximately $11.2 million of a $23.6 million
annual capital expenditure budget (or approximately 47.5 percent) in
facilities necessary to comply with environmental requirements. In 1995 SSU
expects that approximately $9.4 million of the $20.8 million annual capital
expenditure budget (or approximately 45 percent) will be necessary to comply
with environmental requirements.
Investments and Corporate Services
Non-regulated investments supplement Minnesota Power's earnings and, in
some cases, perform an economic development function in Minnesota Power's
electric utility service area. These investments include a portfolio of
securities investments managed by Minnesota Power which are intended to
provide funds for reinvestment and business acquisitions. Considered a part
of the portfolio, the Company owns a 22.1 percent equity investment in a
financial guaranty reinsurance company. Additionally, the Company owns an 80
percent interest in a real estate company in Florida, a 50 percent interest
in a Duluth paper making mill, an 88 percent interest in a Duluth plant which
produces recycled pulp and an 82.5 percent interest in a Duluth manufacturer
of specialized truck-mounted lifting equipment.
. As of December 31, 1994, the Company had approximately $202 million
in a portfolio of securities investments. The majority of the
securities investments are investment grade stocks of other utility
companies and are considered by the Company to be conservative
investments. Additionally, the Company sells common stock
securities short and enters into short sales of treasury futures
contracts as part of an overall investment portfolio hedge
strategy. Selling common stock securities short and entering into
treasury futures contracts create off-balance-sheet market risk to
the Company. At December 31, 1994, the Company had approximately
$61.5 million of short stock sales outstanding and $31.7 million of
treasury futures contracts. (See Note 4.)
. At December 31, 1994, Minnesota Power had a $72.1 million equity
investment which represented a 21.4 percent ownership interest in
Capital Re, a Delaware holding company engaged in financial and
mortgage guaranty reinsurance through its wholly owned
subsidiaries, Capital Reinsurance Company and Capital Mortgage
Reinsurance Company. Capital Reinsurance Company is a reinsurer of
financial guarantees of municipal and non-municipal debt
obligations. Capital Mortgage Reinsurance Company is a reinsurer of
residential mortgage guaranty insurance. In 1994 the Company
purchased an additional 417,100 shares of Capital Re common stock
for $8.8 million. (See Note 5.) In March 1995 the Company purchased
another 100,000 shares of Capital Re common stock for $2.2 million
increasing the Company's ownership interest to 22.1 percent.
. The Company, through Topeka, acquired a two-thirds ownership
interest in Lehigh, a real estate company which owns various real
estate properties and operations in Florida, for $6 million in July
1991. In June 1993 the Company issued 140,648 shares of common
stock, with a market value at the time of issuance of approximately
$4.9 million, in exchange for an additional 13.4 percent ownership
in Lehigh bringing the Company's total ownership interest in Lehigh
to 80 percent. Real estate properties and operations are being sold
over the next several years. The acquisition was accounted for
under the purchase method and has been consolidated with the
Company since July 1991.
. Minnesota Paper, a wholly owned subsidiary of the Company, is a 50
percent participant in LSPI, a joint venture with Pentair Duluth
Corp., a subsidiary of
-18-
<PAGE>
St. Paul based Pentair, Inc. LSPI operates a paper mill in Duluth
which produces supercalendered paper. (See Note 5.)
. UtilEquip, a wholly owned subsidiary of the Company, has an 82.5
percent ownership interest in Reach All. Located in Duluth, Reach
All manufactures specialized truck-mounted lifting equipment used
by utilities and governmental entities.
. Synertec, a wholly owned subsidiary of the Company, is pursuing
opportunities in ventures relating to energy efficiency, resource
conservation such as recycling and solid waste management, and
pollution prevention.
. SRFI, a joint venture owned 88 percent by subsidiaries of the
Company and 12 percent by a subsidiary of Pentair, Inc., built a
$78 million plant in Duluth that produces pulp from recycled office
scrap paper. Commercial operations began at SRFI in November 1993.
The plant has the capacity to produce 90,000 tons of recycled pulp
annually and has commitments from paper producers to purchase up to
82 percent of its output under multi-year contracts.
In January 1995 the Company and ADESA jointly announced that they had
entered into a letter of intent outlining terms of a merger under which ADESA
will become an 80 percent-owned subsidiary of Minnesota Power in return for
payment of $167 million. ADESA, headquartered in Indianapolis, owns and
operates auto redistribution facilities and performs related services through
which used cars and other vehicles are sold by automobile manufacturers,
franchised automobile dealers, fleet/lease companies, and licensed used car
dealers. Pursuant to the proposed merger, all shareholders of ADESA, other
than certain officers with respect to a portion of their shares, will receive
$17.00 in cash for each share of their ADESA common stock. In February 1995 a
merger agreement was signed along with employment agreements with ADESA's
four top managers, and put and call agreements. The put and call agreements
provide ADESA management the right to sell to Minnesota Power, and Minnesota
Power the right to purchase, ADESA management's 20 percent retained ownership
interest in ADESA, in increments during the years 1997, 1998 and 1999, at a
price based on ADESA's financial performance. The transaction is scheduled to
be completed during the second quarter of 1995 subject to, among other
things, approval of the transaction by ADESA's shareholders and satisfaction
of other customary conditions. It is anticipated that a portion of the
Company's securities portfolio will be used to fund the ADESA purchase.
In September 1994 Pentair, Inc., the Company's joint-venture partner in
LSPI, announced its desire to exit the paper business, which would likely
include selling LSPI. The Company would participate in a sale under the right
conditions. If LSPI is sold, it may be logical to also consider a
simultaneous sale of SRFI, whose paper recycling/pulp production plant is
adjacent to and operated by LSPI.
In March 1995 based on the results of a project which analyzed the
economic feasibility of realizing future tax benefits available to the
Company, the board of directors of Lehigh directed Lehigh Corporation, a
subsidiary of Lehigh, to dispose of its assets in a manner that would
maximize utilization of the tax benefits. As a result of the project findings
and the board's directive, Lehigh will reduce a $26.2 million valuation
allowance against its deferred tax assets to $7.8 million and recognize $18.4
million in income. The Company's portion will be $14.7 million or 52 cents
per share in income in the first quarter of 1995.
The Company anticipates exiting the specialized truck-mounted lifting
equipment business in 1995 and is reviewing its alternatives to accomplish
this objective. In anticipation of
-19-
<PAGE>
that action, a loss, estimated to range from $3 to $5 million, after tax,
will be reflected in the Company's first quarter 1995 earnings.
Capital Expenditure Program
Capital expenditures for investments and corporate services businesses
totaled approximately $8 million during 1994. These expenditures included
approximately $3 million for construction of the pulp production plant and
approximately $5 million for affordable housing. Capital expenditures for the
investments and corporate services businesses are expected to be $1.5 million
in 1995 and total approximately $8.7 million during the period 1996 through
1999.
Environmental Matters
Certain of the Company's investments and corporate services businesses
are subject to regulation by various federal, state and local authorities in
the areas of air quality, water quality, solid wastes, and other
environmental matters. The Company considers these businesses to be in
substantial compliance with those environmental regulations currently
applicable to its operations and believes all necessary permits to conduct
such operations have been obtained. The Company does not currently anticipate
that its potential capital expenditures for environmental control purposes
will be material. However, because environmental laws and regulations are
constantly evolving, the character, scope and ultimate costs of environmental
compliance cannot be estimated.
-20-
<PAGE>
<TABLE>
Executive Officers of the Registrant
<CAPTION>
Initial
Executive Officers Effective Date
------------------ --------------
<S> <C>
Arend J. Sandbulte, Age 61
Chairman, President and Chief Executive Officer May 9, 1989
Robert D. Edwards, Age 50
Executive Vice President and Chief Operating Officer March 1, 1993
Group Vice President-Corporate Services and
Chief Financial Officer January 1, 1991
Group Vice President-Finance and Chief Financial Officer May 10, 1988
Jack R. McDonald, Age 57
Executive Vice President-Finance and Corporate Development March 1, 1993
Group Vice President-Corporate Development January 1, 1991
Group Vice President-Power Systems February 1, 1990
Group Vice President-Topeka Group May 10, 1988
Donnie R. Crandell, Age 51
Senior Vice President-Corporate Development December 1, 1994
Retired February 28, 1994
Vice President-Corporate Development March 1, 1993
David G. Gartzke, Age 51
Senior Vice President-Finance and Chief Financial Officer December 1, 1994
Vice President-Finance and Chief Financial Officer March 1, 1993
Vice President-Finance and Treasurer January 1, 1991
Vice President and Treasurer May 9, 1989
Warren L. Candy, Age 45
Vice President-Boswell Energy Center May 10, 1994
Roger P. Engle, Age 46
Vice President-Customer Operations June 1, 1993
General Manager-Central Division June 1, 1992
Corporate Controller January 1, 1991
Controller May 8, 1984
Philip R. Halverson, Age 46
General Counsel and Corporate Secretary March 1, 1993
General Counsel and Assistant Secretary January 23, 1991
Allen D. Harmon, Age 43
Resigned from office March 17, 1995
Group Vice President-Electric Utility Operations January 1, 1991
Group Vice President-Customer Service May 10, 1988
Eugene G. McGillis, Age 60
Vice President June 1, 1992
Vice President-Customer Operations April 17, 1989
Gerald B. Ostroski, Age 54
Vice President January 1, 1991
Vice President-Information and Environmental Services May 10, 1988
Bert T. Phillips, Age 54
Resigned from office due to health reasons December 31, 1994
Group Vice President-Water Resource Operations January 1, 1991
Group Vice President-Topeka Group February 1, 1990
Group Vice President-Power Systems May 10, 1988
Charles M. Reichert, Age 57
Vice President July 21, 1993
Kevin G. Robb, Age 48
Vice President-Generation June 1, 1993
</TABLE>
-21-
<PAGE>
<TABLE>
<CAPTION>
Initial
Executive Officers Effective Date
------------------ --------------
<S> <C>
Mark A. Schober, Age 39
Corporate Controller March 1, 1993
Stephen D. Sherner, Age 44
Vice President-Power Marketing and Delivery March 1, 1993
Vice President-Strategic Resource Management May 10, 1988
Geraldine R. VanTassel, Age 53
Vice President-Corporate Resource Planning March 1, 1993
Corporate Controller June 1, 1992
James K. Vizanko, Age 41
Corporate Treasurer March 1, 1993
</TABLE>
All of the executive officers above, except Mr. Crandell, Mr. Reichert
and Mr. McGillis, had been employed by the Company for more than five years
in executive or management positions. Mr. Crandell was director of business
development, vice president of Topeka and vice president of business
development for Topeka prior to March 1, 1993. Mr. Reichert is also president
of BNI Coal, a position which he held before being elected to the above
position. Mr. McGillis is also president and chief operating officer of
SWL&P, a position which he held before being elected to the above position.
Prior to election to the positions shown above, the following executive
officers held other positions with the Company after January 1, 1990:
Mr. Candy was director of Boswell, assistant plant manager and leader of the
organizational development team; Mr. Halverson was director of legal services
and assistant general counsel, and assistant secretary; Mr. Robb was director
of independent power projects and director of engineering administration; Mr.
Schober was director of internal audit; Ms. VanTassel was director of
internal audit and leader of the organizational development team; and Mr.
Vizanko was director of investments and analysis, and manager of financial
planning and analysis. There are no family relationships between any
executive officers of the Company. All officers and directors are elected or
appointed annually.
The present term of office of the above executive officers extends to
the first meeting of the Company's Board of Directors after the next annual
meeting of shareholders. Both meetings are scheduled for May 9, 1995.
-22-
<PAGE>
Item 2. Properties.
The Company had a net peak load during 1994 of 1,338 MW on December 19,
1994. At the time of the peak the Company's capacity margin based on
installed capacity and scheduled firm purchases and sales was approximately
16 percent. Information with respect to existing power supply sources is
shown below.
<TABLE>
<CAPTION>
Unit Year Net Winter Net Electric
Power Supply No. Installed Capability Requirements
------------ ---- --------- ---------- ------------
(MW) (MWh) (%)
<S> <C> <C> <C> <C> <C>
Steam
Coal-Fired
Boswell Energy Center
near Grand Rapids, MN 1 1958 69
2 1960 69
3 1973 350
4 1980 428
-----
916 5,363,634 50.4%
-----
Laskin Energy Center
Hoyt Lakes, MN 1 1953 55
2 1953 55 193,772 1.8
----- ---------- -----
110
-----
Total Steam 1,026 5,557,406 52.2
----- ---------- -----
Hydro
Group consisting of ten stations in MN Various 121 693,752 6.5
----- ---------- -----
Purchased Power
Square Butte burns lignite in Center, ND 322 2,300,795 21.6
All other - net - 2,095,211 19.7
----- ---------- -----
Total Purchased Power 322 4,396,006 41.3
----- ---------- -----
For the Year Ended December 31, 1994 1,469 10,647,164 100.0%
===== ========== =====
</TABLE>
The Company has electric transmission and distribution lines of 500
kilovolts (kV) (7.8 miles), 230 kV (606.4 miles), 161 kV (42.8 miles), 138 kV
(5.8 miles), 115 kV (1,239.6 miles) and less than 115 kV (6,001.3 miles). The
Company owns and operates 180 substations with a total capacity of 8,545.7
megavoltamperes. Some of the transmission and distribution lines interconnect
with other utilities.
The Company owns and has a substantial investment in offices and service
buildings, area headquarters, an energy control center, repair shops, motor
vehicles, construction equipment and tools, office furniture and equipment,
and leases offices and storerooms in various localities within the Company's
service territory. It also owns miscellaneous parcels of real estate not
presently used in utility operations.
Substantially all of the electric utility plant of the Company is
subject to the lien of its Mortgage and Deed of Trust which secures first
mortgage bonds issued by the Company. The Company's properties are held by it
in fee and are free from other encumbrances, subject to minor exceptions,
none of which are of such a nature as to substantially impair the usefulness
to the Company of such properties. Other property, including certain offices
and equipment, is utilized under leases. In general, some of the electric
lines are located on land not owned in fee, but are covered by necessary
consents of various governmental authorities or by appropriate rights
obtained from owners of private property. These consents and rights are
deemed adequate for the purposes for which the properties are being used. In
September 1990 the Company sold a portion of Boswell Unit 4 to WPPI. WPPI has
the right to use the Company's transmission line facilities to transport its
share of generation.
-23-
<PAGE>
Substantially all of the utility plant of SWL&P is subject to the lien
of its Mortgage and Deed of Trust which secures first mortgage bonds issued
by SWL&P. Substantially all of SSU's properties used in the operation of its
respective water utility businesses are encumbered by mortgages.
Approximately one-half of BNI Coal's equipment is leased under a leveraged
lease agreement which expires in 2002. The remaining property and equipment
are owned by BNI Coal.
The Mid-Continent Area Power Pool (MAPP) consists of nine investor-owned
utilities including the Company, eight rural electric generation and
transmission cooperatives, three public power districts, four municipal
electric systems, four municipal organizations, and the Western Area Power
Administration - Billings, Montana. MAPP operates pursuant to an agreement,
dated March 31, 1972, as amended, among its members. This agreement provides
for the members to coordinate the installation and operation of generating
plants and transmission line facilities.
Manitoba Hydro has export licenses from the National Energy Board in
Calgary until November 1, 2005, to export up to 16.7 billion kilowatt-hours a
year of energy and short-term firm hydroelectric power to other Canadian
utilities and four utility companies in the United States, including the
Company. Manitoba Hydro presently exports approximately 12 billion kilowatt-
hours a year. When it is available and economical, the Company purchases
energy and power from Manitoba Hydro that can be delivered through Minnesota
Power's transmission lines.
Item 3. Legal Proceedings.
Material legal and regulatory proceedings are included in the discussion
of the Company's business in Item 1 and are incorporated by reference herein.
Item 4. Submission of Matters to a Vote of Security Holders.
No matters were submitted to a vote of security holders during the
fourth quarter of 1994.
-24-
<PAGE>
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters.
The Company has paid dividends without interruption on its common stock
since 1948. A quarterly dividend of $.51 per share on the common stock was
paid on March 1, 1995, to the holders of record on February 15, 1995. The
Company's common stock is listed on The New York Stock Exchange. Dividends
paid per share and the high and low prices for the Company's common stock for
the periods indicated as reported by The Wall Street Journal, Midwest
Edition, were as follows:
<TABLE>
<CAPTION>
Dividends
Price Range Paid Per Share
----------- --------------
Quarter High Low Quarterly Annual
------- ---- --- --------- ------
<S> <C> <C> <C> <C>
1994 - First $33 $28 $.505
Second 30 1/8 25 .505
Third 28 1/8 25 .505
Fourth 26 5/8 24 3/4 .505 $2.02
1993 - First $36 1/2 $32 5/8 $.495
Second 36 3/8 34 .495
Third 36 1/2 35 1/4 .495
Fourth 35 1/2 30 .495 $1.98
</TABLE>
The Company's Articles of Incorporation, Mortgage and Deed of Trust and
preferred stock purchase agreements contain provisions which under certain
circumstances would restrict the payment of common stock dividends. As of
December 31, 1994, no retained earnings were restricted as a result of these
provisions. At March 1, 1995, there were 26,882 common stock shareholders of
record.
Item 6. Selected Financial Data.
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
-------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Operating Revenue and $ 637,782 $ 589,607 $ 576,197 $ 588,015 $ 556,318
Income (000)
Income Before Extraordinary 61,333 62,621 68,457 75,481 74,570
Item (000)
Extraordinary Gain (000) - - 4,831 - -
Net Income (000) 61,333 62,621 73,288 75,481 74,570
Earnings per Share
Before Extraordinary Item 2.06 2.20 2.31 2.46 2.37
Extraordinary Item - - 0.16 - -
Total 2.06<F1> 2.20 2.47<F2> 2.46<F3> 2.37<F4>
Dividends per Share 2.02 1.98 1.94 1.90 1.86
Total Assets (000) 1,807,798 1,760,526 1,625,504 1,586,519 1,572,389
Long-Term Debt (000) 601,317 611,144 541,960 533,989 520,278
Redeemable Preferred
Stock (000) 20,000 20,000 21,000 24,000 28,000
<FN>
-------------------------------
<F1> Includes $0.42 per share from the sale of water utility plant. (See Note
12.)
<F2> Includes $0.16 per share from the early extinguishment of debt.
<F3> Includes $0.20 per share from a favorable court decision.
<F4> Includes $0.31 per share from the Boswell Unit 4 transactions. (See Note
11.)
</FN>
</TABLE>
-25-
<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
The management's discussion and analysis of financial condition and
results of operations appearing on pages 6 through 23 of the Minnesota Power
1994 Annual Report are incorporated by reference in this Form 10-K Annual
Report.
On March 16, 1995, Duff & Phelps lowered its ratings on the Company's
first mortgage bonds from A to A-.
Item 8. Financial Statements and Supplementary Data.
The financial statements appearing on pages 25 through 39, together with
the report thereon of Price Waterhouse LLP dated January 24, 1995, on page
24, of the Minnesota Power 1994 Annual Report are incorporated by reference
in this Form 10-K Annual Report.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
PART III
Item 10. Directors and Executive Officers of the Registrant.
The information required for this Item is incorporated by reference
herein from the "Election of Directors" section in the Company's Proxy
Statement for the 1995 Annual Meeting of Shareholders, except for information
with respect to executive officers which is set forth in Part I hereof.
Item 11. Executive Compensation.
The information required for this Item is incorporated by reference
herein from the "Compensation of Executive Officers" section in the Company's
Proxy Statement for the 1995 Annual Meeting of Shareholders.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The information required for this Item is incorporated by reference
herein from the "Security Ownership of Certain Beneficial Owners and
Management" section in the Company's Proxy Statement for the 1995 Annual
Meeting of Shareholders.
Item 13. Certain Relationships and Related Transactions.
The information required for this Item is incorporated by reference
herein from the "Certain Relationships and Related Transactions" section in
the Company's Proxy Statement for the 1995 Annual Meeting of Shareholders.
-26-
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
(a) Certain Documents Filed as Part of Form 10-K.
(1) Financial Statements
Pages in
Annual Report*
--------------
Minnesota Power
Report of Independent Accountants 24
Consolidated Balance Sheet at December 31, 1994
and 1993 25
For the three years ended December 31, 1994
Consolidated Statement of Income 26
Consolidated Statement of Retained Earnings 26
Consolidated Statement of Cash Flows 27
Notes to Consolidated Financial Statements 28-39
--------------------------
* Incorporated by reference herein from the Minnesota Power 1994 Annual
Report.
(2) Financial Statement Schedules
Page
----
Report of Independent Accountants on Financial
Statement Schedule 31
Minnesota Power and Subsidiaries Schedule:
II - Valuation and Qualifying Accounts 32
and Reserves
All other schedules have been omitted either because the information is
not required to be reported by the Company or because the information is
included in the consolidated financial statements or the notes thereto.
-26-
<PAGE>
(3) Exhibits including those incorporated by reference
Exhibit
Number
---------
*2 - Agreement and Plan of Merger by and among Minnesota Power &
Light Company, AC Acquisition Sub, Inc., ADESA Corporation and
Certain ADESA Management Shareholders dated February 23, 1995
(filed as Exhibit 2 to Form 8-K dated March 3, 1995, File No.
1-3548).
*3(a)1 - Articles of Incorporation, restated as of July 27, 1988
(filed as Exhibit 3(a), File No. 33-24936).
*3(a)2 - Certificate Fixing Terms of Serial Preferred Stock A,
$7.125 Series (filed as Exhibit 3(a)2, File No. 33-50143).
*3(a)3 - Certificate Fixing Term of Serial Preferred Stock A,
$6.70 Series (filed as Exhibit 3(a)3, File No. 33-50143).
*3(b) - Bylaws as amended January 23, 1991 (filed as Exhibit
3(b), File No. 33-45549).
*4(a)1 - Mortgage and Deed of Trust, dated as of September 1,
1945, between the Company and Irving Trust Company (now The
Bank of New York) and Richard H. West (W. T. Cunningham,
successor), Trustees (filed as Exhibit 7(c), File No. 2-5865).
*4(a)2 - Supplemental Indentures to Mortgage and Deed of Trust:
Number Dated as of Reference File Exhibit
------ ----------- -------------- -------
First March 1, 1949 2-7826 7(b)
Second July 1, 1951 2-9036 7(c)
Third March 1, 1957 2-13075 2(c)
Fourth January 1, 1968 2-27794 2(c)
Fifth April 1, 1971 2-39537 2(c)
Sixth August 1, 1975 2-54116 2(c)
Seventh September 1, 1976 2-57014 2(c)
Eighth September 1, 1977 2-59690 2(c)
Ninth April 1, 1978 2-60866 2(c)
Tenth August 1, 1978 2-62852 2(d)2
Eleventh December 1, 1982 2-56649 4(a)3
Twelfth April 1, 1987 33-30224 4(a)3
Thirteenth March 1, 1992 33-47438 4(b)
Fourteenth June 1, 1992 33-55240 4(b)
Fifteenth July 1, 1992 33-55240 4(c)
Sixteenth July 1, 1992 33-55240 4(d)
Seventeenth February 1, 1993 33-50143 4(b)
Eighteenth July 1, 1993 33-50143 4(c)
-28-
<PAGE>
Exhibit
Number
*4(b) - Mortgage and Deed of Trust, dated as of March 1, 1943,
between Superior Water, Light and Power Company and Chemical
Bank & Trust Company (Chemical Bank, successor) and Howard B.
Smith (Steven F. Lasher, successor), as Trustees (filed as
Exhibit 7(c), File No. 2-8668), as supplemented and modified
by First Supplemental Indenture thereto dated as of March 1,
1951 (filed as Exhibit 2(d)(1), File No. 2-59690), Second
Supplemental Indenture thereto dated as of March 1, 1962
(filed as Exhibit 2(d)1, File No. 2-27794), Third Supplemental
Indenture thereto dated July 1, 1976 (filed as Exhibit 2(e)1,
File No. 2-57478) and Fourth Supplemental Indenture thereto
dated as of March 1, 1985 (filed as Exhibit 4(b), File No.
2-78641), Fifth Supplemental Indenture thereto dated as of
December 1, 1992 (filed as Exhibit 4(b)1 to Form 10-K for the
year ended December 31, 1992, File No. 1-3548).
*4(c) - Indenture, dated as of March 1, 1993, between Southern
States Utilities, Inc. and Nationsbank of Georgia, National
Association, as Trustee (filed as Exhibit 4(d) to Form 10-K
for the year ended December 31, 1992, File No. 1-3548).
+*10(a) - Incentive Compensation Plan, as amended and restated,
effective January 1, 1994 (filed as Exhibit 10(a) to Form 10-K
for the year ended December 31, 1993, File No. 1-3548).
+*10(b) - Supplemental Executive Retirement Plan, as amended and
restated, effective January 1, 1990 (filed as Exhibit 10(b) to
Form 10-K for the year ended December 31, 1992, File No.
1-3548).
+*10(c) - Executive Investment Plan-I, as amended and restated,
effective November 1, 1988 (filed as Exhibit 10(c) to Form
10-K for the year ended December 31, 1988, File No. 1-3548).
+*10(d) - Executive Investment Plan-II, as amended and restated,
effective November 1, 1988 (filed as Exhibit 10(d) to Form
10-K for the year ended December 31, 1988, File No. 1-3548).
+10(e) - Executive Long-Term Incentive Plan, as amended and
restated, effective January 1, 1994.
+10(f) - Directors' Long-Term Incentive Plan, as amended and
restated, effective January 1, 1994.
+*10(g) - Deferred Compensation Trust Agreement, as amended and
restated, effective January 1, 1989 (filed as Exhibit 10(f) to
Form 10-K for the year ended December 31, 1988, File No.
1-3548).
+10(h) - Minnesota Power Electric Utility Operations Annual
Incentive Plan, effective January 1, 1995.
+10(i) - Minnesota Power Corporate Annual Incentive Plan,
effective January 1, 1995.
12 - Computation of Ratios of Earnings to Fixed Charges and
Supplemental Ratios of Earnings to Fixed Charges.
-29-
<PAGE>
Exhibit
Number
13 - Minnesota Power 1994 Annual Report.
*21 - Subsidiaries of the Registrant (reference is made to the
Company's Form U-3A-2 for the year ended December 31, 1994,
File No. 69-78).
23(a) - Consent of Independent Accountants.
23(b) - Consent of General Counsel.
*27 - Financial Data Schedule (filed as Exhibit 27 to Form 8-K dated
February 27, 1995, File No. 1-3548).
------------------------
* Incorporated herein by reference as indicated.
+ Management contract or compensatory plan or arrangement required to be
filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
(b) Reports on Form 8-K
Report on Form 8-K dated and filed on January 5, 1995, with respect to
Item 5. Other Events.
Report on Form 8-K dated and filed on February 23, 1995, with respect to
Item 5. Other Events.
Report on Form 8-K dated and filed on February 27, 1995, with respect to
Item 7. Financial Statements and Exhibits.
Report on Form 8-K dated and filed on March 3, 1995, with respect to
Item 5. Other Events and Item 7. Financial Statements and Exhibits.
-30-
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
ON FINANCIAL STATEMENT SCHEDULE
To the Board of Directors
of Minnesota Power
Our audits of the consolidated financial statements referred to in our
report dated January 24, 1995, appearing on page 24 of the 1994 Annual Report
to Shareholders of Minnesota Power (which report and consolidated financial
statements are incorporated by reference in this Annual Report on Form 10-K)
also included an audit of the Financial Statement Schedule listed in Item
14(a) of this Form 10-K. In our opinion, the Financial Statement Schedule
presents fairly, in all material respects, the information set forth therein
when read in conjunction with the related consolidated financial statements.
PRICE WATERHOUSE LLP
Minneapolis, Minnesota
January 24, 1995
-31-
<PAGE>
SCHEDULE II
<TABLE>
MINNESOTA POWER AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended December 31, 1994, 1993 and 1992
In thousands
<CAPTION>
Additions
------------------------
Balance at Charged to Deductions Balance
Beginning Charged Other from at End of
of Year to Income Accounts<F1> Reserves<F2> Period
---------- ---------- ------------ ------------ ---------
<S> <C> <C> <C> <C> <C>
Reserve deducted from related assets
Provision for uncollectible accounts
1994 Trade accounts receivable $ 1,565 $ 722 $116 $ 1,362 $1,041
Other accounts receivable 1,135 1,845 - 207 2,773
1993 Trade accounts receivable 1,538 492 151 616 1,565
Other accounts receivable 1,490 494 - 849 1,135
1992 Trade accounts receivable 1,787 326 150 725 1,538
Other accounts receivable 620 1,091 4 225 1,490
Deferred asset valuation
allowance <F3>
1994 Deferred tax assets 31,475 - - 4,597 26,878
1993 Deferred tax assets - - 31,475 - 31,475
<FN>
<F1> Provision for uncollectible accounts include bad debts recovered,
transfers from customers' deposits, etc.
<F2> Provision for uncollectible accounts include bad debts written off.
<F3> The Company adopted Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes" on a prospective basis in January 1993.
</FN>
</TABLE>
- 32 -
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
MINNESOTA POWER & LIGHT COMPANY
(Registrant)
Dated: March 24, 1995 By A. J. SANDBULTE
-----------------------------------
A. J. Sandbulte
Chairman, President and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
A. J. SANDBULTE Chairman, President, March 24, 1995
----------------------------- Chief Executive Officer
A. J. Sandbulte and Director
D. G. GARTZKE Senior Vice President- March 24, 1995
----------------------------- Finance and
D. G. Gartzke Chief Financial Officer
MARK A. SCHOBER Corporate Controller March 24, 1995
-----------------------------
Mark A. Schober
- 33 -
<PAGE>
Signature Title Date
--------- ----- ----
M. K. CRAGUN Director March 24, 1995
-----------------------------
M. K. Cragun
D. E. EVANS Director March 24, 1995
-----------------------------
D. E. Evans
SR. KATHLEEN HOFER Director March 24, 1995
-----------------------------
Sr. Kathleen Hofer
PETER J. JOHNSON Director March 24, 1995
-----------------------------
Peter J. Johnson
MARY E. JUNCK Director March 24, 1995
-----------------------------
Mary E. Junck
R. S. MARS, JR. Director March 24, 1995
-----------------------------
R. S. Mars, Jr.
PAULA F. McQUEEN Director March 24, 1995
-----------------------------
Paula F. McQueen
ROBERT S. NICKOLOFF Director March 24, 1995
-----------------------------
Robert S. Nickoloff
JACK I. RAJALA Director March 24, 1995
-----------------------------
Jack I. Rajala
C. A. RUSSELL Director March 24, 1995
-----------------------------
C. A. Russell
DONALD C. WEGMILLER Director March 24, 1995
-----------------------------
Donald C. Wegmiller
- 34 -
<PAGE>
MINNESOTA POWER
EXECUTIVE LONG-TERM
INCENTIVE PLAN
(Amended and Restated Effective as of January 1, 1994)
<PAGE>
MINNESOTA POWER
EXECUTIVE LONG-TERM INCENTIVE PLAN
(Amended and Restated Effective as of January 1, 1994)
I. EFFECTIVE DATE
This amended and restated Minnesota Power & Light Company (Company)
Executive Long-Term Incentive Plan (Plan) for a select group of management or
highly compensated executive employees is made effective as of January 1, 1994.
Effective January 1, 1994, participation in the Plan was extended to the
responsibility level of Salary Grade V. This Plan supersedes and replaces the
Minnesota Power Long-Term Incentive Plan dated January 1, 1992.
II. PURPOSES OF THE PLAN
The purposes of the Plan are:
1. To reward focusing on long-term planning and results.
2. To link compensation with enhancement of shareholder value.
III. CONCEPT
At the beginning of each new Performance Period, eligible key executives
will be granted a maximum Performance Award Opportunity expressed as a number
of shares of the Company's common stock, not to exceed the designated maximum
for that position. The extent to which the Award Opportunity is earned (e.g.,
the number of shares earned) depends on the Company's performance in terms of
stock price appreciation plus dividends in relation to the comparator groups
during the Performance Period. The Performance Period will be four calendar
years and the actual value of the shares earned will depend upon the price of
the Company's common stock at the end of the fourth calendar year.
1
<PAGE>
Illustrated below, Performance Period 1 began January 1, 1991, and will
end December 31, 1994. A new Performance Period will begin every year as shown.
1991 1992 1993 1994 1995 1996 1997
Performance
Period 1 ------ ------ ------ ------
Performance
Period 2 ------ ------ ------ ------
Performance
Period 3 ------ ------ ------ ------
Performance
Period 4, etc. ------ ------ ------ ------
IV. ELIGIBILITY
Participation is restricted to certain key executives. Participants are
divided into five groups (Participant Categories) to reflect varying
responsibility levels as follows:
<TABLE>
<CAPTION>
Participant Salary
Category Grade
----------- ----------------
<S> <C>
I XI
II IX
III VIII
IV VI-VII
V V
</TABLE>
V. AWARD OPPORTUNITY
A maximum Performance Award Opportunity has been established for each
Participant Category. The Performance Award Opportunity is stated as a maximum
number of shares of common stock of the Company. If a Participant's
Responsibility Level changes during the Performance Period, or if a participant
first becomes eligible during a Performance Period, the Award Opportunity will
be
2
<PAGE>
prorated or adjusted as determined by the Executive Compensation Committee.
For Performance Periods 1, 2 and 3 illustrated in Section III, Performance
Award Opportunities will be based on the following schedule:
<TABLE>
<CAPTION>
Award Opportunity
Participant Maximum Number of
Category Common Shares<F1>
----------- -----------------
<S> <C>
I 6,000
II 5,000
III 4,000
IV 2,000
V 0 (Not Eligible)
<FN>
<F1>Based on shares outstanding as of January 1, 1991; to be adjusted in
the event of ensuing stock splits.
</FN>
</TABLE>
For Performance Period 4 and later, Performance Award Opportunities will
be based on the following schedule:
<TABLE>
<CAPTION>
Award Opportunity
Participant Maximum Number of
Category Common Shares<F1>
----------- -----------------
<S> <C>
I 6,000
II 5,000
III 4,000
IV 2,000
V 1,500
<FN>
<F1>Based on shares outstanding as of January 1, 1994; to be adjusted in
the event of ensuing stock splits.
</FN>
</TABLE>
VI. PERFORMANCE MEASURE
The Company's long-term performance will be measured by its Total
Shareholder Return (TSR) Ranking over each four-year Performance Period. TSR
is defined as:
TSR = Stock Price Appreciation + Reinvested Dividends
-----------------------------------------------
Initial Stock Price
3
<PAGE>
The TSR is determined by means of combining the change in stock price over
the entire Performance Period with dividends which are assumed to be reinvested
on each ex-dividend date. Key assumptions to be followed in calculation of TSR
are:
1) Stock prices used with respect to a performance Period are the
closing prices on the New York Stock Exchange on the last day
before the beginning of the Performance Period and the last day of
the Performance Period.
2) Dividends are assumed to be reinvested on the ex-
dividend date at the closing stock prices on that
date.
3) Calculation of TSR for the S&P 500 group is based
on the companies included in the S&P 500 as of the
end of Performance Period.
The current performance measure will be reviewed at the beginning of each
new Performance Period to determine that it remains applicable and effective.
A new performance measure may be adopted at any time by amending this Plan.
VII. COMPARATOR GROUPS
The TSR performance measure discussed above will be used to rank the
Company's performance relative to two comparator groups on a 60/40 weighted
basis. The first comparator group (weighted 60% in the award computation) will
consist of the 10 regional utility companies that are used in the Minnesota
Power and Affiliated Companies Incentive Compensation Plan. At the end of each
Performance Period, all companies, including the Company, will be ranked from 1
to 11, according to TSR.
The second comparator group (weighted at 40% in the award computation)
will include a broader group of companies comprising the S&P 500. Comparison
against this group will be based on the TSR percentile ranking of the Company
among the S&P 500, at the end of each Performance Period.
4
<PAGE>
VIII. AWARD DETERMINATION
After calculation of the Company's TSR ranking within the utility industry
comparator group and the S&P 500, the schedule below will prescribe the percent
of the Participant's Performance Award Opportunity actually earned. The
Performance Award Opportunity shall be as specified in Section V above.
<TABLE>
<CAPTION>
Industry
TSR Percent of Award Opportunity Earned
Ranking
<S> <C> <C> <C> <C> <C> <C>
1-2 60 68 76 84 92 100
3 48 56 64 72 80 88
4 36 44 52 60 68 76
5 24 32 40 48 56 64
6 12 20 28 36 44 52
7-11 0 8 16 24 32 40
0-40 50 60 70 80 90
</TABLE>
TSR Percentile Ranking in S&P 500
Straight line interpolation will be used for TSR Percentile Ranking
results between those discrete values specified in the table (no interpolation
is necessary regarding the Industry TSR Ranking).
Final awards will be reviewed and approved by the Executive Compensation
Committee. Each Participant's award amount will be the product obtained by
multiplying the Participant's Performance Award Opportunity shares as
determined at the beginning of the Performance Period by the appropriate
weighted percentages.
IX. EXAMPLE CALCULATION OF AWARDS
Assume a Participant's Performance Award Opportunity is 4,000 shares at
the beginning of the Performance Period. Assume further, that at the end of
the four-year Performance Period, the Company ranks fifth in its Industry TSR
Ranking and is at the 75th percentile among the S&P 500 comparator group. The
award would be computed as follows:
Opportunity Industry S&P 500 Final
Shares Ranking Ranking Shares Awarded
4,000 x (24% + 28%) = 2,080.
5
<PAGE>
X. PAYMENT OPTIONS
As soon as practicable following the end of the last year of the
Performance Period and upon approval of the Executive Compensation Committee,
awards will be paid totally in stock or in a combination of stock and cash (up
to a maximum of fifty percent cash) at the election of the Participant. At the
time awards are determined and approved, a Participant may elect on a form
provided by the Company to receive payment of up to fifty percent of the
approved award in cash.
XI. TERMINATION OF EMPLOYMENT
Awards to the CEO and COO will continue to run after their retirement
without any proration or reduction for the fact that retirement occurs before a
performance period has ended.
In the event of death, disability or retirement of any Participant prior
to the end of a four-year Performance Period, the provisions in the paragraphs
below will apply unless the Executive Compensation Committee makes an exception
and elects in its discretion to continue the award.
If termination of employment due to death, disability, or retirement
occurs (except as noted above for the CEO and COO in the event of retirement)
prior to the end of a Performance Period, the Participant's performance award
will be paid as soon as practicable after the end of the year of such
termination. The final award determination will be calculated as provided in
Section VIII above, after the end of such year (as if it were the end of the
four-year Performance Period). The award will then be multiplied by a prorated
adjustment factor, the numerator of which is the number of months the
Participant was employed by the Company during the Performance Period rounded
up to whole months and the denominator of which is 48. The result thus
obtained will be the actual final award to be provided by the Company to a
Participant or his/her beneficiary or estate if no beneficiary is named.
Notwithstanding any provisions in this Plan to the contrary, any payment to any
beneficiary may be withheld until it is determined if any generation-skipping
tax is due. Any amounts necessary to pay such tax may be subtracted from any
benefits otherwise due.
6
<PAGE>
Termination of employment for reasons other than death, disability, or
retirement before the end of a Performance Period will result in forfeiture of
the associated award opportunity unless an exception is made by the Executive
Compensation Committee.
XII. ADMINISTRATION
The administration of the Plan will be under the overall responsibility of
the Executive Compensation Committee of the Board of Directors. The Chief
Executive Officer will be responsible for administering the Plan (computing
awards, measuring performance of the comparator group, etc.). Any revisions to
the Plan will require review by the Executive Compensation Committee and
approval of the Board of Directors. The Chief Executive Officer will involve
other individuals and departments as required for the full and complete
administration of the Plan, in accordance with its terms.
XIII. NON-TRANSFERABILITY
In no event shall the Company make any payment under the Plan to any
assignee or creditor of a Participant or of a Participant's beneficiary. Prior
to the time of payment hereunder, a Participant or beneficiary shall have no
rights by way of anticipation or otherwise to assign or otherwise dispose of
any interest under the Plan nor shall such rights be assigned or transferred by
operation of law.
XIV. CLAIMS PROCEDURE
A) Filing a Claim
--------------
Any Participant or beneficiary, or his/her authorized representative, may
make a claim for benefits due under the Plan by making a written request
therefor to the Executive Compensation Committee, setting forth with
specificity the facts and events which give rise to the claim.
7
<PAGE>
b) Denial of Claim
---------------
The Executive Compensation Committee shall notify in writing any
Participant or beneficiary whose claim for benefits hereunder is denied. Said
notice shall be furnished within ninety days after the Executive Compensation
Committee receives the claim, unless special circumstances require an extension
of time for processing the claim. If such an extension of time for processing
is required, written notice of the extension shall be furnished to the
Participant or beneficiary prior to the termination of the initial ninety-day
period. In no event shall such extension exceed a period of ninety days from
the end of such initial period. The notice of extension shall indicate the
special circumstances requiring an extension of time and the date by which the
Executive Compensation Committee expects to render the final decision. The
notice of claim denial shall set forth the specific reasons for the denial,
including specific reference to pertinent Plan provisions. If appropriate,
said notice shall set forth any additional information the Participant or
beneficiary needs to supply in order to perfect his/her claim. The notice
shall also inform the Participant or beneficiary of the review procedure
available pursuant to this Section, and of his/her right to inspect pertinent
documents.
c) Review Of Claim Denial
----------------------
A Participant or beneficiary who desires further consideration of his/her
position, or a duly authorized representative, shall, within sixty days of
receipt of the notice above referred to, make written request to the Executive
Compensation Committee for review of such denial. Such request shall include a
statement of the Participant's or beneficiary's position. The Executive
Compensation Committee shall make a full and fair review of the decision
denying the claim, and shall deliver to the Participant or beneficiary a
written statement setting forth its decision and the specific reasons therefor,
including specific reference to pertinent Plan provisions, within sixty days
after receiving the request for review (unless special circumstances require an
extension of time for processing, in which case written notice of the extension
shall be furnished to the Participant or beneficiary prior to the commencement
of the extension and a decision shall be rendered as soon as possible, but not
later than 120 days after receiving the request for review).
8
<PAGE>
XV. EXPENSES
The cost of payments from the Plan and the expense of administering the
Plan shall be borne by the Company.
XVI. TAX WITHHOLDING
The Company shall have the right to deduct from all payments to be made
under the Plan, any federal, state or local taxes or other charges required by
law to be withheld with respect to such payments.
XVII. AMENDMENT AND TERMINATION
The Company expects the Plan to continue, but since future conditions
affecting the Company cannot be anticipated or foreseen, the Company must and
does hereby reserve the right to amend, modify, terminate or partially
terminate the Plan at any time and in any manner whatsoever by recommendation
of the Executive Compensation Committee and by action of the Board of
Directors. No amendment or termination may divest a Participant of amounts
accrued or credited to the Participant at the time of such amendment.
XVIII. APPLICABLE LAW
The Plan shall be governed and construed in accordance with the laws of
the State of Minnesota. The invalidity of any portion of the Plan shall not
invalidate the remainder hereof and said remainder shall continue in full
force. The captions and other titles herein are designed for convenience only
and are not to be resorted to for the purpose of interpreting any provision of
the Plan.
XIX. NO EMPLOYMENT RIGHTS
The Plan and elections hereto shall not be deemed or construed to be a
written contract of employment between any Participant and the Company, nor
shall any provision of the Plan (i) restrict the right of the Company to
discharge any Participant or (ii) in any way whatsoever grant to any
Participant the right to receive any
9
<PAGE>
guaranteed salary, bonus, incentive compensation award or any other payments of
any nature whatsoever.
XX. BINDING AGREEMENT
The provisions of the plan shall be binding upon the Participant, his or
her heirs, personal representatives and beneficiaries, and subject to the
rights granted to amend or terminate the Plan, the provisions of the Plan shall
also be binding upon the Company, its successors and assigns.
XXI. CONTRACTUAL OBLIGATIONS
It is intended that the Company is under a contractual obligation to make
payments to Participants or their beneficiaries from the general funds and
assets of the Company in accordance with the terms and conditions of the Plan.
A Participant or his/her beneficiary shall have no rights to such payments,
other than as a general, unsecured creditor of the Company.
MINNESOTA POWER
By Arend J. Sandbulte
-----------------------------------
Its Chief Executive Officer
Attest:
By Philip R. Halverson
-----------------------------------
Its Secretary
10
<PAGE>
MINNESOTA POWER
DIRECTORS' LONG TERM
INCENTIVE PLAN
(Amended and Restated Effective as of January 1, 1994)
<PAGE>
MINNESOTA POWER
DIRECTORS' LONG-TERM INCENTIVE PLAN
(Amended and restated effective January 1, 1994)
I. EFFECTIVE DATE
The Minnesota Power Directors' Long-Term Incentive Plan (Plan) for members
of the Board of Directors of Minnesota Power & Light Company (Company) is made
effective as of January 1, 1994. This Plan supersedes and replaces the
Minnesota Power Directors' Long Term Incentive Plan dated January 1, 1992.
II. PURPOSES OF THE PLAN
The purposes of the Plan are:
1. To reward focusing on long-term planning and results.
2. To link compensation with enhancement of shareholder value.
III. CONCEPT
At the beginning of each new Performance Period, Directors will be granted
a maximum Performance Award Opportunity of up to 600 shares of the Company's
common stock. The extent to which the Award Opportunity is earned (e.g., the
number of shares earned) depends on the Company's performance in terms of stock
price appreciation plus dividends in relation to the comparator groups during
the Performance Period. The Performance Period will be four calendar years
and the actual value of the shares earned will depend upon the price of the
Company's common stock at the end of the fourth calendar year.
1
<PAGE>
Performance Periods will begin every other year as illustrated below.
1992 1993 1994 1995 1996 1997 1998 1999
Performance
Period 1 ------ ------ ------ ------
Performance
Period 2 ------ ------ ------ ------
Performance
Period 3 ------ ------ ------ ------
Performance
Period 4, etc. ------ ------
IV. PERFORMANCE MEASURE
The Company's long-term performance will be measured by its Total
Shareholder Return (TSR) Ranking over each four-year Performance Period. TSR
is defined as:
TSR = Stock Price Appreciation + Reinvested Dividends
-----------------------------------------------
Initial Stock Price
The TSR is determined by means of combining the change in stock price over
the entire Performance Period with dividends which are assumed to be reinvested
on each ex-dividend date. Key assumptions to be followed in calculation of TSR
are:
1) Stock prices used with respect to a performance Period are the
closing prices on the New York Stock Exchange on the last day before
the beginning of the Performance Period and the last day of the
Performance Period.
2) Dividends are assumed to be reinvested on the ex-dividend date at
the closing stock prices on that date.
3) Calculation of TSR for the S&P 500 group is based on the companies
included in the S&P 500 as of the end of Performance Period.
The current performance measure will be reviewed at the beginning of each
new Performance Period to determine that it
2
<PAGE>
remains applicable and effective. A new performance measure may be adopted at
any time by amending this Plan.
V. COMPARATOR GROUPS
The TSR performance measure discussed above will be used to rank the
Company's performance relative to two comparator groups on a 60/40 weighted
basis. The first comparator group (weighted 60% in the award computation) will
consist of the 10 regional utility companies that are used in the Minnesota
Power and Affiliated Companies Incentive Compensation Plan. At the end of each
Performance Period, all companies, including the Company, will be ranked from 1
to 11, according to TSR.
The second comparator group (weighted at 40% in the award computation)
will include a broader group of companies comprising the S&P 500. Comparison
against this group will be based on the TSR percentile ranking of the Company
among the S&P 500, at the end of each Performance Period.
VI. AWARD DETERMINATION
After calculation of the Company's TSR ranking within the utility industry
comparator group and the S&P 500, the schedule below will prescribe the percent
of the Director's Performance Award Opportunity actually earned. The
Performance Award Opportunity shall be as specified in Section III above.
<TABLE>
<CAPTION>
Industry
TSR Percent of Award Opportunity Earned
Ranking
<S> <C> <C> <C> <C> <C> <C>
1-2 60 68 76 84 92 100
3 48 56 64 72 80 88
4 36 44 52 60 68 76
5 24 32 40 48 56 64
6 12 20 28 36 44 52
7-11 0 8 16 24 32 40
0-40 50 60 70 80 90
</TABLE>
TSR Percentile Ranking in S&P 500
3
<PAGE>
Straight line interpolation will be used for TSR Percentile Ranking
results between those discrete values specified in the table (no interpolation
is necessary regarding the Industry TSR Ranking).
Final awards will be reviewed and approved by the Executive Compensation
Committee. Each Director's award amount will be the product obtained by
multiplying the Director's Performance Award Opportunity shares as determined
at the beginning of the Performance Period by the appropriate weighted
percentages.
VII. EXAMPLE CALCULATION OF AWARDS
The Director's Performance Award Opportunity is 600 shares at the
beginning of the Performance Period. Assume that at the end of the four-year
Performance Period, the Company ranks fifth in its Industry TSR Ranking and is
at the 75th percentile among the S&P 500 comparator group. The award would be
computed as follows:
Opportunity Industry S&P 500 Final
Shares Ranking Ranking SharesAwarded
----------- -------- ------- -------------
600 x (24% + 28%) = 312
VIII. PAYMENT OPTIONS
As soon as practicable following the end of the last year of the
Performance Period and upon approval of the Executive Compensation Committee,
awards will be paid totally in stock or in a combination of stock and cash (up
to a maximum of fifty percent cash) at the election of the Director. At the
time awards are determined and approved, a Director may elect on a form
provided by the Company to receive payment of up to fifty percent of the
approved award in cash.
IX. PRORATION OF AWARDS FOR INCOMPLETE PERFORMANCE PERIODS
Awards will be prorated for any Performance Period that a Director did not
serve during the full four year period, due to joining the board or retiring
from the board during a performance period(s). The Director's performance
award will be calculated as provided in Section VI above, after the end of
the last year of service (as if it
4
<PAGE>
were a full four-year Performance Period). The award will then be multiplied
by a prorated adjustment factor, the numerator of which is the number of months
the Director served as a Director during the Performance Period rounded up to
whole months and the denominator of which is 48. The result thus obtained will
be the actual award to be provided by the Company to a Director or his/her
beneficiary or estate if no beneficiary is named. Notwithstanding any
provisions in this Plan to the contrary, any payment to any beneficiary may be
withheld until it is determined if any generation-skipping tax is due. Any
amounts necessary to pay such tax may be subtracted from any benefits otherwise
due.
X. ADMINISTRATION
The administration of the Plan will be under the overall responsibility of
the Executive Compensation Committee of the Board of Directors. The Chief
Executive Officer will be responsible for administering the Plan (computing
awards, measuring performance of the comparator group, etc.). Any revisions to
the Plan will require review by the Executive Compensation Committee and
approval of the Board of Directors. The Chief Executive Officer will involve
other individuals and departments as required for the full and complete
administration of the Plan, in accordance with its terms.
XI. NON-TRANSFERABILITY
In no event shall the Company make any payment under the Plan to any
assignee or creditor of a Director or of a Director's beneficiary. Prior to
the time of payment hereunder, a Director or beneficiary shall have no rights
by way of anticipation or otherwise to assign or otherwise dispose of any
interest under the Plan nor shall such rights be assigned or transferred by
operation of law.
XII. CLAIMS PROCEDURE
A) Filing a Claim
--------------
Any Director or beneficiary, or his/her authorized representative, may
make a claim for benefits due under the Plan by making a written request
therefor to the Executive Compensation
5
<PAGE>
Committee, setting forth with specificity the facts and events which give rise
to the claim.
b) Denial of Claim
---------------
The Executive Compensation Committee shall notify in writing any Director
or beneficiary whose claim for benefits hereunder is denied. Said notice shall
be furnished within ninety days after the Executive Compensation Committee
receives the claim, unless special circumstances require an extension of time
for processing the claim. If such an extension of time for processing is
required, written notice of the extension shall be furnished to the Director or
beneficiary prior to the termination of the initial ninety-day period. In no
event shall such extension exceed a period of ninety days from the end of such
initial period. The notice of extension shall indicate the special
circumstances requiring an extension of time and the date by which the
Executive Compensation Committee expects to render the final decision. The
notice of claim denial shall set forth the specific reasons for the denial,
including specific reference to pertinent Plan provisions. If appropriate,
said notice shall set forth any additional information the Director or
beneficiary needs to supply in order to perfect his/her claim. The notice
shall also inform the Director or beneficiary of the review procedure available
pursuant to this Section, and of his/her right to inspect pertinent documents.
c) Review Of Claim Denial
----------------------
A Director or beneficiary who desires further consideration of his/her
position, or a duly authorized representative, shall, within sixty days of
receipt of the notice above referred to, make written request to the Executive
Compensation Committee for review of such denial. Such request shall include a
statement of the Director's or beneficiary's position. The Executive
Compensation Committee shall make a full and fair review of the decision
denying the claim, and shall deliver to the Director or beneficiary a written
statement setting forth its decision and the specific reasons therefor,
including specific reference to pertinent Plan provisions, within sixty days
after receiving the request for review (unless special circumstances require an
extension of time for processing, in which case written notice of the extension
shall be furnished to the Director or beneficiary prior to the commencement of
the extension and a decision shall be rendered as soon as possible, but not
later than 120 days after receiving the request for review).
6
<PAGE>
XIII. EXPENSES
The cost of payments from the Plan and the expense of administering the
Plan shall be borne by the Company.
XIV. TAX WITHHOLDING
The Company shall have the right to deduct from all payments to be made
under the Plan, any federal, state or local taxes or other charges required by
law to be withheld with respect to such payments.
XV. AMENDMENT AND TERMINATION
This Plan maybe amended, modified, terminated or partially terminated at
any time by action of the Board of Directors. No amendment or termination may
divest a Director of amounts accrued or credited to the Director at the time of
such amendment.
XVI. APPLICABLE LAW
The Plan shall be governed and construed in accordance with the laws of
the State of Minnesota. The invalidity of any portion of the Plan shall not
invalidate the remainder hereof and said remainder shall continue in full
force. The captions and other titles herein are designed for convenience only
and are not to be resorted to for the purpose of interpreting any provision of
the Plan.
XVII. NO EMPLOYMENT RIGHTS
The Plan and elections hereto shall not be deemed or construed to be a
promise of or right to continued service on the Board of Directors.
XVIII. BINDING AGREEMENT
The provisions of the plan shall be binding upon the Director, his or her
heirs, personal representatives and beneficiaries, and
7
<PAGE>
subject to the rights granted to amend or terminate the Plan, the provisions of
the Plan shall also be binding upon the Company, its successors and assigns.
XIX. CONTRACTUAL OBLIGATIONS
It is intended that the Company is under a contractual obligation to make
payments to Directors or their beneficiaries from the general funds and assets
of the Company in accordance with the terms and conditions of the Plan. A
Director or his/her beneficiary shall have no rights to such payments, other
than as a general, unsecured creditor of the Company.
MINNESOTA POWER
By Arend J. Sandbulte
-----------------------------------
Its Chief Executive Officer
Attest:
By Philip R. Halverson
-----------------------------------
Its Secretary
8
<PAGE>
MINNESOTA POWER ELECTRIC UTILITY
OPERATIONS
ANNUAL INCENTIVE PLAN
EFFECTIVE JANUARY 1, 1995
<PAGE>
TABLE OF CONTENTS
Page
Electric Utility Operations (EUO) Annual 1
Incentive Plan
Appendix A - EUO Plan Illustration A-1
Appendix B - Definition of Plan Measurements B-1
Appendix C - Payment/Deferral Options and C-1
Administration
1
<PAGE>
I. INTRODUCTION
This amended and restated Minnesota Power & Light Company (Company)
Annual Incentive Plan (Plan) for a select group of Electric Utility
Operations (EUO) management employees is made effective as of
January 1, 1995. This Plan supersedes and replaces the Minnesota
Power and Affiliated Company Amended and Restated Incentive
Compensation Plan dated January 1, 1994.
II. PLAN PURPOSES
. Provide a meaningful and competitive incentive opportunity geared to
the achievement of specified internal and external corporate,
business unit, and strategic goals.
. Vary performance criteria/goals and incentive award amounts to
reflect differences in business unit and individual participant
challenges and accomplishments.
III. CONCEPT
An annual incentive plan for key management employees where the
award opportunity is set at the beginning of each year. Actual
payments are based on the achievement of corporate (both internal
and external), business unit, and strategic goals.
IV. PARTICIPATION
Participation will be limited to those Key individuals whose actions
can have a substantial impact on Minnesota Power's success. This
group will consist of the officer group, directors, and management
employees in salary grades I and above.
V. INCENTIVE OPPORTUNITIES
A threshold, target, and maximum award opportunity will be
established for each salary range grouping. The "target" award will
be earned for achievement of above average performance (60th
percentile) as compared to the specified peer groups and for
achievement of budgeted performance of the electric utility group.
"Threshold" and "maximum" performance award levels then will be
developed in relation to the target performance award levels.
2
<PAGE>
The following table states the base award opportunity, as a percent
of base salary, for each management group and is exclusive of the
strategic award opportunity available for participants in salary
grades VIII and above. Actual participant awards can vary from 0 to
120 percent of the base award opportunity depending upon actual
corporate and business unit performance.
<TABLE>
<CAPTION>
---------------------------------------------------------------
Salary Grade Base Award Opportunities<F1>
---------------------------------------------------------------
<S> <C>
VIII-IX 40%
VI-VII 30%
IV-V 25%
I-III 15%
<FN>
-------------------------------------------
<F1> As a percent of base salary.
</FN>
---------------------------------------------------------------
</TABLE>
The Chief Executive Officer will suggest, and the Compensation
Committee will determine, the treatment of "extraordinary" gains or
losses and their impact on earnings per share (EPS) and operating
income in the Plan. Where possible, this determination will be made
prior to establishing the annual targets for EPS and operating
income.
VI. PERFORMANCE APPORTIONMENT
Performance will be assessed at two levels - corporate and business
unit. Corporate performance will be divided into internal and
external measures. The Chief Executive Officer will recommend, and
the Compensation Committee will approve, the weighting of incentive
opportunity. This apportionment will be determined by salary grade
and will be the same for each participant within that salary grade.
A participant's total incentive award will be equal to the sum of
the amounts earned from each portion of the incentive opportunity.
The weighting is illustrated below.
3
<PAGE>
<TABLE>
<CAPTION>
---------------------------------------------------------
Corporate
Performance
Salary ----------------------- Business Unit
Grade Internal External Performance
---------------------------------------------------------
<S> <C> <C> <C>
VIII-IX 25.0% 25.0% 50.0%
I-VII 12.5% 12.5% 75.0%
---------------------------------------------------------
</TABLE>
VII. INTERNAL CORPORATE PERFORMANCE
Internal corporate performance will be measured based on earnings
per share (EPS). At the beginning of each plan year, a "target" EPS
goal will be established for the Company. "Threshold" and "maximum"
performance levels, for incentive award determination purposes, will
be set up in relation to this performance target.
EPS for the plan year must equal or exceed the "threshold" level of
performance before any incentive award is earned from this
performance measure. The "maximum" performance level, when
achieved, will produce the maximum incentive award opportunity
achievable from the EPS portion, as illustrated below.
<TABLE>
<CAPTION>
---------------------------------------------------------
Percent of Corporate Internal
Performance EPS Performance Award Earned
---------------------------------------------------------
<S> <C> <C>
Maximum $ 120%
-----
Target $ 60%
-----
Threshold $ 25%
-----
Below Threshold 0%
---------------------------------------------------------
</TABLE>
Straight line interpolation will be used for determining results
between those specified in the table.
VIII. EXTERNAL CORPORATE PERFORMANCE
External corporate performance will be based upon Minnesota Power's
total shareholder return (TSR), as measured against both a
diversified electric utility peer group consisting of the ten
companies identified in Appendix B (60% weighting) and the S&P 500
(40%
4
<PAGE>
weighting). TSR is defined in Appendix B. Minnesota Power's TSR
performance will be determined relative to the two peer groups based
on a ranking illustrated in the following table.
<TABLE>
Peer Group
Percentile Ranking
<CAPTION>
TSR to
S&P 500
(40% Percent of External Corporate
Weighting) Performance Award Earned
<S> <C> <C> <C> <C>
> or = 90th percentile 48% 63% 84% 120%
60th percentile 24% 39% 60% 96%
40th percentile 10% 25% 46% 82%
< 40th percentile 0% 15% 36% 72%
<4 > or = 4 > or = 6 > or = 9
companies companies companies companies
</TABLE>
TSR to Diversified
Utility Peer Group
(60% weighting)
Straight-line interpolation will be used for determining results
between those specified in the table. No payouts will be made if
TSR performance is below the 40th percentile in the S&P 500 and TSR
performance is less than that of 4 companies in the utility peer
group.
IX. BUSINESS UNIT PERFORMANCE
Business unit goals will be based equally upon internal operating
income and annual percentage change in cost/kwh measured against the
electric utility peer group identified in Appendix B. At the
beginning of each plan year, a target operating income goal will be
established. Threshold and maximum performance levels also will be
determined. A matrix will then be established to define award
opportunities based on various levels of achievement as illustrated
in the following table.
5
<PAGE>
<TABLE>
Annual %
Change in
Cost/kwh Percent of Business Unit
(50% Performance Award Earned
weighting)
<S> <C> <C> <C> <C>
> or = 9
companies 60% 73% 90% 120%
> or = 6
companies 30% 43% 60% 90%
> or = 4
companies 13% 25% 43% 73%
< 4
companies 0% 13% 30% 60%
$(Threshold) $(Target) $(Maximum)
------------ --------- ----------
</TABLE>
Operating Income
(50% weighting)
Straight-line interpolation will be used for determining results
between those specified in the table. No payouts will be made if
performance is below threshold and performance is less than that of
4 companies in the utility peer group.
X. STRATEGIC AWARD
The purpose of including a strategic award opportunity is to
recognize individual performance and to reward those contributions
that may not be adequately reflected by financial measures. The
strategic award will be available to participants in salary grade
VIII and above only and will consist of an additional opportunity of
up to 10 percent of base salary at the end of the Plan year in
which the award is earned.
At the beginning of the plan year, the specific strategic goals will
be set forth by the Chief Executive Officer. Following year end,
the Chief Executive Officer, with the approval of the Compensation
Committee, shall determine the extent to which the strategic goals
have been accomplished.
XI. FINAL AWARD DETERMINATION
See Appendix A for an illustrative award calculation.
6
<PAGE>
XII. FORM AND TIMING OF PAYMENT
Cash awards will be paid as soon as practical following approval of
award amounts by the Compensation Committee. No portion of the
award shall be paid in employer stock.
XIII. AWARD DEFERRAL
Each participant may elect to defer receipt of all or a portion of
his or her earned award. The election must be made prior to the
beginning of the year in which the award is earned. The terms
related to such deferrals will correspond to those provisions
specified in Appendix C.
XIV. TERMINATION OF EMPLOYMENT DUE TO RETIREMENT, DEATH, OR DISABILITY
If a participant's employment is terminated due to retirement,
death, or active employment is terminated due to disability during a
plan year, the award earned shall be prorated based on the number of
months of participation within the plan year and be based upon
performance determined at year end.
XV. TERMINATION FOR ANY OTHER REASON
Termination of employment for reasons other than retirement, death,
or disability before the end of a plan year will result in
forfeiture of any associated award opportunity. However, the Chief
Executive Officer, with the approval of the Compensation Committee,
may waive such forfeiture provision.
XVI. TAX TREATMENT
Award payments are taxable to the participant in the year of
receipt.
XVII. WITHHOLDING TAXES
The Company will have the right to deduct any Federal, state, or
local taxes required by law to be withheld.
XVIII. BENEFICIARY DESIGNATION
A participant may name a beneficiary or beneficiaries to whom any
benefit under this Plan is to be paid in the event of death.
7
<PAGE>
XIX. EFFECT ON EMPLOYEE BENEFIT PLANS
Payments from this Plan shall not be included in calculating the
amount of employee benefits to be paid under the terms of any of the
Company's qualified employee benefit plans. Payments will be
included for calculating benefits under the Supplemental Executive
Retirement Plan (SERP).
XX. PARTICIPANT RIGHTS
Participation in this Plan shall not interfere with the Company's
right to terminate any participant's employment at any time. Rights
or interests of any participants in this Plan are nontransferable.
XXI. PLAN ADMINISTRATION
The Executive Compensation Committee of the Board of Directors will
have responsibility for administration of the Plan in accordance
with the provisions of the Plan, as specified in this Plan document
and these administrative plan specifications.
XXII. PLAN AMENDMENTS
The Compensation Committee may, in its sole discretion, modify,
amend, suspend, or terminate, in whole or in part, any or all of the
provisions of the Plan. However, no modification, amendment,
suspension, or termination may adversely affect a payment or
distribution accrued or credited to a participant.
XXIII. BINDING AGREEMENT
The provisions of the Plan shall be binding upon the Participant,
his or her heirs, personal representatives and beneficiaries, and
subject to the rights granted to amend or terminate the Plan, the
provisions of the Plan shall also be binding upon the Company, its
successors and assigns.
XXIV. CONTRACTUAL OBLIGATIONS
It is intended that the Company is under a contractual obligation to
make payments to Participants or their beneficiaries from the
general funds and assets of the Company in accordance with the terms
and conditions of the Plan. A Participant or his/her beneficiary
shall have no
8
<PAGE>
rights to such payments, other than as a general, unsecured creditor
of the Company.
This Minnesota Power Electric Utility Operations Annual Incentive
Plan has been approved, and is effective, as of January 1, 1995.
MINNESOTA POWER
By Arend J. Sandbulte
-----------------------------------
Its Chief Executive Officer
Attest:
By Philip R. Halverson
-----------------------------------
Its Secretary
9
<PAGE>
Appendix A - EUO Plan Illustration
The following illustrates application of the Plan.
Assumptions
. Participant (salary grade VI-VII) Vice President
. Salary for 1995 $100,000
. Base award opportunity 30%
. Internal corporate performance (12.5%) Maximum - 120%
(EPS at $2.60)
. External corporate performance (12.5%) Target - 60%
(both peer groups
at 60th percentile)
. Overall business unit performance (75%) Threshold - 25%
(threshold level
for both goals)
<TABLE>
Calculation of Award
<CAPTION>
Base Base Performance Performance Award
Salary Award Apportionment Achievement
<S> <C> <C> <C> <C> <C>
Internal $100,000 x 30% x 12.5% x 120% = $4,500
corporate
portion
External $100,000 x 30% x 12.5% x 60% = $2,250
corporate
portion
EUO
portion $100,000 x 30% x 75% x 25% = $5,625
$12,375
=======
</TABLE>
A-1
<PAGE>
Appendix B - Definition of Plan Measurements
The diversified electric utility peer group used to compare TSR (60% weighting)
in the external corporate performance measure and to compare annual percentage
change in cost/kwh in the business unit performance measure is:
IES Industries, Inc.
Interstate Power Company
Iowa-Illinois Gas & Electric
Madison Gas & Electric Company
Midwest Resources
Northern States Power Company
Otter Tail Power Company
Wisconsin Energy Corporation
Wisconsin Public Service Corporation
WPL Holdings, Inc.
Performance Measures Definition
. TSR is defined as:
TSR = Stock price appreciation + reinvested dividends
-----------------------------------------------
Initial stock price
The TSR is determined by means of combining the change in stock price over the
plan year with dividends which are assumed to be reinvested on each dividend
date.
- Stock prices for the beginning and end of the one-year period are the
closing prices on the New York Stock Exchange on the last business day of
the period (last business day prior to the start of the period for the
beginning prices).
- Dividends are assumed to be reinvested on the ex-dividend date at the
closing stock prices on that date.
- Calculation of TSR for the S&P 500 group is based on the companies
included in the S&P 500 Index as of the end of the period.
. Annual percentage change in cost/kwh is defined as:
The dollar amount of O&M expense (adjusted as discussed below)
incurred by the Company for each kwh sold
This performance measure reflects the change in operating and maintenance
expenses incurred by the Company expressed in cents per kwh. O&M expenses
exclude fuel, P&I power, taxes, and
B-1
<PAGE>
Appendix B - Definition of Plan Measurements
depreciation, but include an amount equal to the O&M component (the current
MAPP rate) of net purchased and interchanged power.
Cost/kwh = O&M expenses, as defined above
+ (___ mills x net purchased
and interchanged power in)
---------------------------
Total kwh sales
Performance based on this measure is calculated on an annual percentage
rate of change. The lowest percentage change rate, when compared to other
companies in the group, indicates the best performance.
In computing these performance measures, the most recent data published by each
utility in the comparator group applicable to the plan year will be used for
purposes of determining results. If the most recent data are different data
from data used previously (due to restatement, etc), the latest data will be
used for the current plan year in determining such year's awards, but no
retroactive adjustments will be made relative to awards made previously.
B-2
<PAGE>
Appendix C - Payment/Deferral Options
Except as hereinafter specifically provided, participants will be given
the following options to receive their award:
a) current payment of all or a portion of the award
b) payment deferred to a date specified by the participant (at which
time such award shall be paid in full), with the latest deferral date to be the
earlier of (i) six months after the participant's seventieth birthday or (ii)
such date selected by the participant up to five years after the date of the
participant's retirement; or
c) payment deferred to the earlier to occur of the following events:
(i) The retirement of the participant or, if elected up to five
years after retirement, but in no event later than age 70 1/2 (in which
case the participant may also elect to receive the award in equal monthly
installments commencing on the first day of the month following the date
of the participant's retirement or anniversary thereof if so elected, and
continuing thereafter for a period of fifteen (15), ten (10) or five (5)
years, as is elected by the participant).
(ii) the death of the participant,
(iii) the termination of the participant's employment.
The foregoing Elections must be made in writing to the Executive
Compensation Committee prior to the end of the calendar year preceding the year
in which the award is earned. Such election shall be irrevocable.
Participants who elect to receive their awards currently will be paid the
amount of their awards plus interest from January 1 following the Plan year to
the payment date, at the rate of 8 percent per annum.
Participants who elect to defer their awards will have the following three
options available under which their awards can be deferred (with the
irrevocable election of an option being made contemporaneously with the
election to defer):
a) Deferral in accordance with the participant's commitment under
the Company's Executive Investment Plan I or Executive Investment Plan II.
Amounts will be credited to the participant's account under such Plan(s)
effective January 1 following the Plan year.
C-1
<PAGE>
b) Deferral with interest paid on all amounts deferred effective
January 1 following the Plan year at a fixed rate of 8 percent per annum.
c) Deferral with interest paid on all amounts deferred effective
January 1 following the Plan year to the award payment date at the rate of
8 percent per annum and thereafter for the deferral period on all amounts
at a rate equivalent to the overall percentage return achieved as if the
deferred amounts had been invested in any of the following Mutual Funds,
which shall serve as a performance reference only:
(i) Nicholas Fund, Inc.
(ii) Fidelity Magellan Fund (Amounts deferred into this Fund
are subject to a 3% upfront sales charge)
(iii) Investment Advisors Incorporated (IAI) Emerging Growth
Fund
(iv) Investment Advisors Incorporated (IAI) International
Developed Market Fund
(v) Fidelity Balanced Fund
(vi) Vanguard Index Trust 500 Portfolio
(vii) Templeton International Emerging Market
Participants who choose deferral under either b) or c) above are permitted
annually to continue the accrual of interest on deferred awards using the
interest rate alternative chosen one year earlier, or to switch to an alternate
method of computing interest on all deferred awards during the succeeding year.
This does not in any way affect the period of the deferral chosen by the
participant.
If payments to a participant are to be made in installments, then the
unpaid amounts due to the participant shall continue to be credited based on
the participant's annual elections.
Notwithstanding anything to the contrary herein, if a participant dies
while employed by the Company, or if a participant who has terminated
employment dies before receiving all payments which such participant is
entitled to receive pursuant to an election hereunder, the amount then standing
to the credit of such participant under this Plan shall be paid in a single sum
within the first 30 days of the calendar year following the date of the
participant's death to the participant's beneficiary.
C-2
<PAGE>
In the event of a participant's financial hardship or unforeseen financial
emergency, the Executive Compensation Committee, in its sole and absolute
discretion may alter the timing or manner of payment of any benefits or
deferred amounts to be paid pursuant to the Plan, (provided, however, any such
alteration shall only occur with respect to these amounts reasonably required
to alleviate the participant's financial hardship or unforeseen emergency).
Financial hardship shall be deemed to have occurred in the event of the
participant's impending bankruptcy, a participant's or defendant's long and
serious illness or other events of similar magnitude. An unforeseeable
financial emergency shall mean an unexpected need for cash arising from
illness, casualty loss, sudden financial reversal or other such unforeseeable
occurrence. Normal expenditures for the vocational or college education of a
dependent, the purchase of a house or any similar expense, shall not be
considered a financial hardship or an unforeseeable financial emergency. The
Benefit Plans Committee's decision in passing upon the financial hardship or
unforeseeable financial emergency of the participant, and the manner in which,
if at all, the payment of any amounts pursuant to the Plan shall be altered or
modified, shall be final, conclusive and not subject to appeal. The
participant, the participant's spouse, if any, and the participant's
beneficiary waive all claims against the Benefit Plans Committee for
determinations made by the Benefit Plans Committee under this Section, and the
participant shall have no claim or right to make up any amount distributed or
transferred as a result of a determination of financial hardship or
unforeseeable financial emergency by the Benefit Plans Committee pursuant to
this Section. Any participant for whom the Benefit Plans Committee grants
relief under this Section may not re-enter the Plan, or make any deferral of
compensation under the Plan, until the Plan Year following the second
anniversary of the date on which such relief is granted to such participant.
If a participant's employment with the Company terminates for any reason
other than retirement, death or disability, the balance then standing to the
credit of such participant under this Plan, as of the end of the month
immediately preceding or coincident with the date of termination of employment,
shall be paid to the participant in a single sum upon the date of separation
from service, or within 30 days thereafter. If a participant entitled to a
benefit under this paragraph dies prior to receiving payment, then such payment
shall be made to the participant's beneficiary.
In years where deferred compensation elections are made available under
Executive Investment Plans I & II, each participant shall be entitled to
transfer unpaid awards under this plan as a Rollover Amount to the Minnesota
Power and Affiliated Companies Executive Investment Plan I or the Minnesota
Power and Affiliated Companies Executive Investment Plan II, all subject to the
specific terms and restrictions in said Plans. Provided, however, the transfer
of an unpaid award as a Rollover Amount shall not result in a deferral or
acceleration of the date
C-3
<PAGE>
or dates on which such Rollover Amount would have been received had no transfer
occurred.
"Retire" and "retirement" as used in this Plan shall mean a termination of
employment after attaining "Early Retirement Age" as defined in the
Supplemental Retirement Plan.
The administration of the Annual Incentive Plan will be under the overall
responsibility of the Executive Compensation Committee of the Board of
Directors. The Chief Executive Officer will be responsible for administering
the Plan on a routine basis (computing awards, measuring performance of the
comparator group, etc). Any revisions to the Plan will require review by the
Executive Compensation Committee and approval of the Board of Directors. The
Chief Executive Officer will involve those other individuals and departments as
required in the full and complete administration of the Plan, in accordance
with its terms.
In administering the Plan, the Executive Compensation Committee will apply
uniform rules to all participants similarly situated. If any claim for
benefits under the Plan is wholly or partially denied, the claimant shall be
given notice in writing, within a reasonable period of time after receipt of
the claim by the Plan, by registered or certified mail, of such denial, written
in a manner calculated to be understood by the claimant, setting forth the
specific reasons for such denial, specific reference to pertinent Plan
provisions on which the denial is based, a description of any additional
material or information necessary for the claimant to perfect the claim and an
explanation of why such material or information is necessary, and an
explanation of the Plan's claim review procedure. The claimant also shall be
advised that the claimant's duly authorized representative may request a
review, by the Executive Compensation Committee, of the decision denying the
claim by filing with the Executive Compensation Committee, within 65 days after
such notice has been received by the claimant, a written request for such
review, and that the claimant's duly authorized representative may review
pertinent documents, and submit issues and comments in writing within the same
65-day period. If such request is so filed, such review shall be made by the
Executive Compensation Committee within 60 days after receipt of such request;
and the claimant shall be given written notice of the decision resulting from
such review, and shall include specific reasons for the decision, written in a
manner calculated to be understood by the claimant, and specific references to
the pertinent Plan provisions on which the decision is based.
The Executive Compensation Committee may make payment to any participant
or any beneficiary of a participant, of any benefits or deferred amounts to be
paid under the Plan, in advance of the date when otherwise due, if, based on a
change in federal tax law or regulation, published rulings or similar
announcements by the Internal Revenue Service, decision by a court of competent
jurisdiction involving the Plan,
C-4
<PAGE>
or a closing agreement made under Section 7121 of the Internal Revenue Code of
1986 that involves the Plan, it determines that a participant or beneficiary
will recognize income for federal income tax purposes with respect to amounts
that are otherwise not then payable under the Plan. The Executive Compensation
Committee may also make such payments to any participant, or beneficiary of a
participant, in advance of the date when otherwise due, if it shall be
determined that the Plan is subject to the requirements of Parts 2 and 3 of
Subtitle B of Title I of the Employee Retirement Income Security Act of 1974,
because such Plan is not maintained primarily for the purpose of providing
deferred compensation for a select group of management or highly compensated
employees.
All payments to be made by the Company under the Plan shall be made to the
participant, if living. Except as otherwise provided herein, in the event of a
participant's death prior to the receipt of all payments hereunder, all
subsequent payments to be made under the Plan shall be made to the beneficiary
designated by the participant, and, unless otherwise specified in the
participant's beneficiary designation, in the event a beneficiary dies before
receiving all payments due to such beneficiary pursuant to this Plan, the then
remaining payments shall be paid to the legal representatives of the
beneficiary's estate. The participant shall designate a beneficiary, or during
the participant's lifetime change such designation, by filing a written notice
of such designation with the Company in such form and subject to such rules and
regulations as the Executive Compensation Committee may prescribe. If the
participant's payments constitute community property, then any beneficiary
designation made by the participant other than a designation of such
participant's spouse shall not be effective if any such beneficiary or
beneficiaries are to receive more than fifty percent (50%) of the aggregate
benefits payable hereunder, unless such spouse shall approve such designation
in writing. If no beneficiary designation shall be in effect at the time when
any benefits payable under this Plan shall become due, the benefit payments
shall be made to the legal representative of the participant's estate.
Notwithstanding any provisions in this Plan to the contrary, the Executive
Compensation Committee may withhold any benefits payable to a beneficiary as a
result of the death of the participant (or the death of any beneficiary
designated by the participant) until such time as (i) the Committee is able to
determine whether a generation-skipping transfer tax, as defined in Chapter 13
of the Internal Revenue Code of 1986, or any substitute provision therefor, is
payable by the Company; and (ii) the Committee has determined the amount of
generation-skipping transfer tax that is due, including interest thereon. If
any such tax is payable, the Executive Compensation Committee shall reduce the
benefits otherwise payable hereunder to such beneficiary by an amount equal to
the generation-skipping transfer tax and any interest thereon that is payable
as a result of the death in question.
C-5
<PAGE>
Benefits payable under the Plan are not in any way subject to the debts or
other obligations of the persons entitled to those payments, whether the person
is a participant or a beneficiary. Benefits under the Plan may not voluntarily
or involuntarily be sold, transferred, or assigned.
C-6
<PAGE>
MINNESOTA POWER CORPORATE
ANNUAL INCENTIVE PLAN
EFFECTIVE JANUARY 1, 1995
<PAGE>
TABLE OF CONTENTS
Page
Corporate Annual Incentive Plan 1
Appendix A - Corporate Plan Illustration A-1
Appendix B - Definition of Plan Measurements B-1
Appendix C - Payment/Deferral Options and C-1
Administration
1
<PAGE>
I. INTRODUCTION
This amended and restated Minnesota Power & Light Company (Company)
Annual Incentive Plan (Plan) for a select group of management
employees is made effective as of January 1, 1995. This Plan
supersedes and replaces the Minnesota Power and Affiliated Company
Amended and Restated Incentive Compensation Plan dated January 1,
1994.
II. PLAN PURPOSES
. Provide a meaningful and competitive incentive opportunity geared to
the achievement of specified internal and external corporate,
business unit, and strategic goals.
. Vary performance criteria/goals and incentive award amounts to
reflect differences in business unit and individual participant
challenges and accomplishments.
III. CONCEPT
An annual incentive plan for key management employees where the
award opportunity is set at the beginning of each year. Actual
payments are based on the achievement of corporate (both internal
and external), business unit, and strategic goals.
IV. PARTICIPATION
Participation will be limited to those Key individuals whose actions
can have a substantial impact on Minnesota Power's success. This
group will consist of the officer group, directors, and management
employees in salary grades I and above.
V. INCENTIVE OPPORTUNITIES
A threshold, target, and maximum award opportunity will be
established for each salary range grouping. The "target" award will
be earned for achievement of above average performance (60th
percentile) as compared to the specified peer groups and for
achievement of budgeted performance of the electric utility group.
"Threshold" and "maximum" performance award levels then will be
developed in relation to the target performance award levels.
2
<PAGE>
The following table states the base award opportunity, as a percent
of base salary, for each management group and is exclusive of the
strategic award opportunity available for participants in salary
grades VIII and above. Actual participant awards can vary from 0 to
120 percent of the base award opportunity depending upon actual
corporate and business unit performance.
<TABLE>
<CAPTION>
---------------------------------------------------------------
Salary Grade Base Award Opportunities<F1>
---------------------------------------------------------------
<S> <C>
XI 60%
VIII-IX 40%
VI-VII 30%
IV-V 25%
I-III 15%
<FN>
---------------------------------------------
<F1> As a percent of base salary.
</FN>
---------------------------------------------------------------
</TABLE>
The Chief Executive Officer will suggest, and the Compensation
Committee will determine, the treatment of "extraordinary" gains or
losses and their impact on earnings per share (EPS) and operating
income in the Plan. Where possible, this determination will be made
prior to establishing the annual targets for EPS and operating
income.
VI. PERFORMANCE APPORTIONMENT
Performance will be assessed at two levels - corporate and business
unit. Corporate performance will be divided into internal and
external measures. The Chief Executive Officer will recommend, and
the Compensation Committee will approve, the weighting of incentive
opportunity. This apportionment will be determined by salary grade
and will be the same for each participant within that salary grade.
A participant's total incentive award will be equal to the sum of
the amounts earned from each portion of the incentive opportunity.
The weighting is illustrated below.
3
<PAGE>
---------------------------------------------------------------
Corporate Business
Salary Performance Unit Corporate
Grade Internal External EUO SSU Development*
I-XI 40% 30% 20% 10%
Corporate Development Participants
IV-VIII 40% 30% 30%
---------------
*Those participants in the corporate development area will have
individual acquisition-oriented goals, rather than business unit
goals relating to EUO and SSU.
---------------------------------------------------------------
VII. INTERNAL CORPORATE PERFORMANCE
Internal corporate performance will be measured based on earnings
per share (EPS). At the beginning of each plan year, a "target" EPS
goal will be established for the Company. "Threshold" and "maximum"
performance levels, for incentive award determination purposes, will
be set up in relation to this performance target.
EPS for the plan year must equal or exceed the "threshold" level of
performance before any incentive award is earned from this
performance measure. The "maximum" performance level, when achieved,
will produce the maximum incentive award opportunity achievable from
the EPS portion, as illustrated below.
<TABLE>
<CAPTION>
---------------------------------------------------------------
Percent of Corporate Internal
Performance EPS Performance Award Earned
---------------------------------------------------------------
<S> <C> <C>
Maximum $ 120%
-----
Target $ 60%
-----
Threshold $ 25%
-----
Below Threshold 0%
</TABLE>
---------------------------------------------------------------
Straight line interpolation will be used for determining results
between those specified in the table.
4
<PAGE>
VIII. EXTERNAL CORPORATE PERFORMANCE
External corporate performance will be based upon Minnesota Power's
total shareholder return (TSR), as measured against both a
diversified electric utility peer group consisting of the ten
companies identified in Appendix B (60% weighting) and the S&P 500
(40% weighting). TSR is defined in Appendix B. Minnesota Power's
TSR performance will be determined relative to the two peer groups
based on a ranking illustrated in the following table.
<TABLE>
<CAPTION>
Peer Group
Percentile Ranking
TSR to
S&P 500
(40% Percent of External Corporate
Weighting) Performance Award Earned
<S> <C> <C> <C> <C>
> or = 90th percentile 48% 63% 84% 120%
60th percentile 24% 39% 60% 96%
40th percentile 10% 25% 46% 82%
<40th percentile 0% 15% 36% 72%
<4 > or = 4 > or = 6 > or = 9
companies companies companies companies
</TABLE>
TSR to Diversified
Utility Peer Group
(60% weighting)
Straight-line interpolation will be used for determining results
between those specified in the table. No payouts will be made if
TSR performance is below the 40th percentile in the S&P 500 and TSR
performance is less than that of 4 companies in the utility peer
group.
IX. BUSINESS UNIT/CORPORATE DEVELOPMENT
Business unit goals will be based one-third on operating income for
the water resource operations group and two-thirds on operating
income for the electric utility operations group. For those
participants in the corporate development area, business unit
performance goals will
5
<PAGE>
instead be acquisition-oriented goals related to the participants'
area of responsibility.
A matrix has been established to determine award opportunities
based on various levels of achievement for the electric utility and
water resource operations groups, as illustrated in the following
table.
<TABLE>
<CAPTION>
SSU
Operating
Income
(1/3 Percent of Business Unit
weighting) Performance Award Earned
<S> <C> <C> <C> <C>
$(Maximum) 40% 57% 80% 120%
$(Target) 20% 37% 60% 100%
$(Threshold) 8% 25% 48% 88%
0% 17% 40% 80%
$(Threshold) $(Target) $(Maximum)
------------ --------- ----------
</TABLE>
EUO Operating Income
(2/3 weighting)
Straight-line interpolation will be used for determining results
between those specified in the table. No payouts will be made for
performance below threshold in each performance measure.
X. STRATEGIC AWARD
The purpose of including a strategic award is to recognize
individual performance and to reward those contributions that may
not be adequately reflected by financial measures. The strategic
award will be available to participants in salary grade VIII and
above only and will consist of an additional opportunity of up to 10
percent of base salary for participants in salary grades VIII-IX and
15 percent of base salary for participants in salary grade XI. Base
salary in place at the end of the Plan year in which the award is
earned will be used to calculate the strategic award.
At the beginning of the plan year, the specific strategic goals will
be set forth by the Chief Executive Officer (and by the Compensation
Committee for the Chief Executive Officer). Following year end, the
Chief Executive Officer, with the approval of the Compensation
Committee, shall determine the extent to which the strategic goals
have
6
<PAGE>
been accomplished. The Compensation Committee shall make this
determination for the Chief Executive Officer.
XI. AWARD DETERMINATION
See Appendix A for an illustrative award calculation.
XII. FORM AND TIMING OF PAYMENT
Cash awards will be paid as soon as practical following approval of
award amounts by the Compensation Committee. No portion of the
award shall be paid in employer stock.
XIII. AWARD DEFERRAL
Each participant may elect to defer receipt of all or a portion of
his or her earned award. The election must be made prior to the
beginning of the year in which the award is earned. The terms
related to such deferrals will correspond to those provisions
specified in Appendix C.
XIV. TERMINATION OF EMPLOYMENT DUE TO RETIREMENT, DEATH, OR DISABILITY
If a participant's employment is terminated due to retirement,
death, or active employment is terminated due to disability during a
plan year, the award earned shall be prorated based on the number of
months of participation within the plan year and be based upon
performance determined at year end.
XV. TERMINATION FOR ANY OTHER REASON
Termination of employment for reasons other than retirement, death,
or disability before the end of a plan year will result in
forfeiture of any associated award opportunity. However, the Chief
Executive Officer, with the approval of the Compensation Committee,
may waive such forfeiture provision.
XVI. TAX TREATMENT
Award payments are taxable to the participant in the year of
receipt.
7
<PAGE>
XVII. WITHHOLDING TAXES
The Company will have the right to deduct any Federal, state, or
local taxes required by law to be withheld.
XVIII. BENEFICIARY DESIGNATION
A participant may name a beneficiary or beneficiaries to whom any
benefit under this Plan is to be paid in the event of death.
XIX. EFFECT ON EMPLOYEE BENEFIT PLANS
Payments from this Plan shall not be included in calculating the
amount of employee benefits to be paid under the terms of any of the
Company's qualified employee benefit plans. Payments will be
included for calculating benefits under the Supplemental Executive
Retirement Plan (SERP).
XX. PARTICIPANT RIGHTS
Participation in this Plan shall not interfere with the Company's
right to terminate any participant's employment at any time. Rights
or interests of any participants in this Plan are nontransferable.
XXI. PLAN ADMINISTRATION
The Executive Compensation Committee of the Board of Directors will
have responsibility for administration of the Plan in accordance
with the provisions of the Plan, as specified in this Plan document
and these administrative plan specifications.
XXII. PLAN AMENDMENTS
The Compensation Committee may, in its sole discretion, modify,
amend, suspend, or terminate, in whole or in part, any or all of the
provisions of the Plan. However, no modification, amendment,
suspension, or termination may adversely affect a payment or
distribution accrued or credited to a participant.
8
<PAGE>
XXIII. BINDING AGREEMENT
The provisions of the Plan shall be binding upon the Participant,
his or her heirs, personal representatives and beneficiaries, and
subject to the rights granted to amend or terminate the Plan, the
provisions of the Plan shall also be binding upon the Company, its
successors and assigns.
XXIV. CONTRACTUAL OBLIGATIONS
It is intended that the Company is under a contractual obligation to
make payments to Participants or their beneficiaries from the
general funds and assets of the Company in accordance with the terms
and conditions of the Plan. A Participant or his/her beneficiary
shall have no rights to such payments, other than as a general,
unsecured creditor of the Company.
This Minnesota Power Corporate Annual Incentive Plan has been
approved, and is effective, as of January 1, 1995.
MINNESOTA POWER
By Arend J. Sandbulte
-----------------------------------
Its Chief Executive Officer
Attest:
By Philip R. Halverson
-----------------------------------
Its Secretary
9
<PAGE>
Appendix A - Corporate Plan Illustration
The following illustrates application of the Plan.
Assumptions
. Participant (salary grade VI-VII) Vice President
. Salary for 1995 $100,000
. Base award level 30%
. Internal corporate performance (40%) Maximum - 120%
(EPS at $2.60)
. External corporate performance (30%) Target - 60%
(both peer groups
at 60th percentile)
. Overall business unit performance (30%) Threshold - 25%
EUO (20%) (EUO at $ )
----- ----
SSU (10%) (SSU at $ )
----- ----
<TABLE>
Calculation of Award
<CAPTION>
Base Base Performance Performance Award
Salary Award Apportionment Achievement
<S> <C> <C> <C> <C> <C>
Internal $100,000 x 30% x 40% x 120% = $14,400
corporate
portion
External $100,000 x 30% x 30% x 60% = $5,400
corporate
portion
Business
Unit
portion $100,000 x 30% x 30% x 25% = $2,250
$22,050
=======
</TABLE>
A-1
<PAGE>
Appendix B - Definition of Plan Measurements
The diversified electric utility peer group used to compare TSR (60% weighting)
in the external corporate performance measure and to compare annual percentage
change in cost/kwh in the business unit performance measure is:
IES Industries, Inc.
Interstate Power Company
Iowa-Illinois Gas & Electric
Madison Gas & Electric Company
Midwest Resources
Northern States Power Company
Otter Tail Power Company
Wisconsin Energy Corporation
WPL Holdings, Inc.
Performance Measures Definition
. TSR is defined as:
TSR = Stock price appreciation + reinvested dividends
-----------------------------------------------
Initial stock price
The TSR is determined by means of combining the change in stock price over the
plan year with dividends which are assumed to be reinvested on each dividend
date.
- Stock prices for the beginning and end of the one-year period are the
closing prices on the New York Stock Exchange on the last business day of
the period (last business day prior to the start of the period for the
beginning prices).
- Dividends are assumed to be reinvested on the ex-dividend date at the
closing stock prices on that date.
- Calculation of TSR for the S&P 500 group is based on the companies
included in the S&P 500 Index as of the end of the period.
B-1
<PAGE>
Appendix C - Payment/Deferral Options
Except as hereinafter specifically provided, participants will be given
the following options to receive their award:
a) current payment of all or a portion of the award
b) payment deferred to a date specified by the participant (at which
time such award shall be paid in full), with the latest deferral date to be the
earlier of (i) six months after the participant's seventieth birthday or (ii)
such date selected by the participant up to five years after the date of the
participant's retirement; or
c) payment deferred to the earlier to occur of the following events:
(i) The retirement of the participant or, if elected up to five
years after retirement, but in no event later than age 70 1/2 (in which
case the participant may also elect to receive the award in equal monthly
installments commencing on the first day of the month following the date
of the participant's retirement or anniversary thereof if so elected, and
continuing thereafter for a period of fifteen (15), ten (10) or five (5)
years, as is elected by the participant).
(ii) the death of the participant,
(iii) the termination of the participant's employment.
The foregoing Elections must be made in writing to the Executive
Compensation Committee prior to the end of the calendar year preceding the year
in which the award is earned. Such election shall be irrevocable.
Participants who elect to receive their awards currently will be paid the
amount of their awards plus interest from January 1 following the Plan year to
the payment date, at the rate of 8 percent per annum.
Participants who elect to defer their awards will have the following three
options available under which their awards can be deferred (with the
irrevocable election of an option being made contemporaneously with the
election to defer):
a) Deferral in accordance with the participant's commitment under
the Company's Executive Investment Plan I or Executive Investment Plan II.
Amounts will be credited to the participant's account under such Plan(s)
effective January 1 following the Plan year.
C-1
<PAGE>
b) Deferral with interest paid on all amounts deferred effective
January 1 following the Plan year at a fixed rate of 8 percent per annum.
c) Deferral with interest paid on all amounts deferred effective
January 1 following the Plan year to the award payment date at the rate of
8 percent per annum and thereafter for the deferral period on all amounts
at a rate equivalent to the overall percentage return achieved as if the
deferred amounts had been invested in any of the following Mutual Funds,
which shall serve as a performance reference only:
(i) Nicholas Fund, Inc.
(ii) Fidelity Magellan Fund (Amounts deferred into this Fund
are subject to a 3% upfront sales charge)
(iii) Investment Advisors Incorporated (IAI) Emerging Growth
Fund
(iv) Investment Advisors Incorporated (IAI) International
Developed Market Fund
(v) Fidelity Balanced Fund
(vi) Vanguard Index Trust 500 Portfolio
(vii) Templeton International Emerging Market
Participants who choose deferral under either b) or c) above are permitted
annually to continue the accrual of interest on deferred awards using the
interest rate alternative chosen one year earlier, or to switch to an alternate
method of computing interest on all deferred awards during the succeeding year.
This does not in any way affect the period of the deferral chosen by the
participant.
If payments to a participant are to be made in installments, then the
unpaid amounts due to the participant shall continue to be credited based on
the participant's annual elections.
Notwithstanding anything to the contrary herein, if a participant dies
while employed by the Company, or if a participant who has terminated
employment dies before receiving all payments which such participant is
entitled to receive pursuant to an election hereunder, the amount then standing
to the credit of such participant under this Plan shall be paid in a single sum
within the first 30 days of the calendar year following the date of the
participant's death to the participant's beneficiary.
C-2
<PAGE>
In the event of a participant's financial hardship or unforeseen financial
emergency, the Executive Compensation Committee, in its sole and absolute
discretion may alter the timing or manner of payment of any benefits or
deferred amounts to be paid pursuant to the Plan, (provided, however, any such
alteration shall only occur with respect to these amounts reasonably required
to alleviate the participant's financial hardship or unforeseen emergency).
Financial hardship shall be deemed to have occurred in the event of the
participant's impending bankruptcy, a participant's or defendant's long and
serious illness or other events of similar magnitude. An unforeseeable
financial emergency shall mean an unexpected need for cash arising from
illness, casualty loss, sudden financial reversal or other such unforeseeable
occurrence. Normal expenditures for the vocational or college education of a
dependent, the purchase of a house or any similar expense, shall not be
considered a financial hardship or an unforeseeable financial emergency. The
Benefit Plans Committee's decision in passing upon the financial hardship or
unforeseeable financial emergency of the participant, and the manner in which,
if at all, the payment of any amounts pursuant to the Plan shall be altered or
modified, shall be final, conclusive and not subject to appeal. The
participant, the participant's spouse, if any, and the participant's
beneficiary waive all claims against the Benefit Plans Committee for
determinations made by the Benefit Plans Committee under this Section, and the
participant shall have no claim or right to make up any amount distributed or
transferred as a result of a determination of financial hardship or
unforeseeable financial emergency by the Benefit Plans Committee pursuant to
this Section. Any participant for whom the Benefit Plans Committee grants
relief under this Section may not re-enter the Plan, or make any deferral of
compensation under the Plan, until the Plan Year following the second
anniversary of the date on which such relief is granted to such participant.
If a participant's employment with the Company terminates for any reason
other than retirement, death or disability, the balance then standing to the
credit of such participant under this Plan, as of the end of the month
immediately preceding or coincident with the date of termination of employment,
shall be paid to the participant in a single sum upon the date of separation
from service, or within 30 days thereafter. If a participant entitled to a
benefit under this paragraph dies prior to receiving payment, then such payment
shall be made to the participant's beneficiary.
In years where deferred compensation elections are made available under
Executive Investment Plans I & II, each participant shall be entitled to
transfer unpaid awards under this plan as a Rollover Amount to the Minnesota
Power and Affiliated Companies Executive Investment Plan I or the Minnesota
Power and Affiliated Companies Executive Investment Plan II, all subject to the
specific terms and restrictions in said Plans. Provided, however, the transfer
of an unpaid award as a Rollover Amount shall not result in a deferral or
acceleration of the date
C-3
<PAGE>
or dates on which such Rollover Amount would have been received had no transfer
occurred.
"Retire" and "retirement" as used in this Plan shall mean a termination of
employment after attaining "Early Retirement Age" as defined in the
Supplemental Retirement Plan.
The administration of the Annual Incentive Plan will be under the overall
responsibility of the Executive Compensation Committee of the Board of
Directors. The Chief Executive Officer will be responsible for administering
the Plan on a routine basis (computing awards, measuring performance of the
comparator group, etc). Any revisions to the Plan will require review by the
Executive Compensation Committee and approval of the Board of Directors. The
Chief Executive Officer will involve those other individuals and departments as
required in the full and complete administration of the Plan, in accordance
with its terms.
In administering the Plan, the Executive Compensation Committee will apply
uniform rules to all participants similarly situated. If any claim for
benefits under the Plan is wholly or partially denied, the claimant shall be
given notice in writing, within a reasonable period of time after receipt of
the claim by the Plan, by registered or certified mail, of such denial, written
in a manner calculated to be understood by the claimant, setting forth the
specific reasons for such denial, specific reference to pertinent Plan
provisions on which the denial is based, a description of any additional
material or information necessary for the claimant to perfect the claim and an
explanation of why such material or information is necessary, and an
explanation of the Plan's claim review procedure. The claimant also shall be
advised that the claimant's duly authorized representative may request a
review, by the Executive Compensation Committee, of the decision denying the
claim by filing with the Executive Compensation Committee, within 65 days after
such notice has been received by the claimant, a written request for such
review, and that the claimant's duly authorized representative may review
pertinent documents, and submit issues and comments in writing within the same
65-day period. If such request is so filed, such review shall be made by the
Executive Compensation Committee within 60 days after receipt of such request;
and the claimant shall be given written notice of the decision resulting from
such review, and shall include specific reasons for the decision, written in a
manner calculated to be understood by the claimant, and specific references to
the pertinent Plan provisions on which the decision is based.
The Executive Compensation Committee may make payment to any participant
or any beneficiary of a participant, of any benefits or deferred amounts to be
paid under the Plan, in advance of the date when otherwise due, if, based on a
change in federal tax law or regulation, published rulings or similar
announcements by the Internal Revenue Service, decision by a court of competent
jurisdiction involving the Plan,
C-4
<PAGE>
or a closing agreement made under Section 7121 of the Internal Revenue Code of
1986 that involves the Plan, it determines that a participant or beneficiary
will recognize income for federal income tax purposes with respect to amounts
that are otherwise not then payable under the Plan. The Executive Compensation
Committee may also make such payments to any participant, or beneficiary of a
participant, in advance of the date when otherwise due, if it shall be
determined that the Plan is subject to the requirements of Parts 2 and 3 of
Subtitle B of Title I of the Employee Retirement Income Security Act of 1974,
because such Plan is not maintained primarily for the purpose of providing
deferred compensation for a select group of management or highly compensated
employees.
All payments to be made by the Company under the Plan shall be made to the
participant, if living. Except as otherwise provided herein, in the event of a
participant's death prior to the receipt of all payments hereunder, all
subsequent payments to be made under the Plan shall be made to the beneficiary
designated by the participant, and, unless otherwise specified in the
participant's beneficiary designation, in the event a beneficiary dies before
receiving all payments due to such beneficiary pursuant to this Plan, the then
remaining payments shall be paid to the legal representatives of the
beneficiary's estate. The participant shall designate a beneficiary, or during
the participant's lifetime change such designation, by filing a written notice
of such designation with the Company in such form and subject to such rules and
regulations as the Executive Compensation Committee may prescribe. If the
participant's payments constitute community property, then any beneficiary
designation made by the participant other than a designation of such
participant's spouse shall not be effective if any such beneficiary or
beneficiaries are to receive more than fifty percent (50%) of the aggregate
benefits payable hereunder, unless such spouse shall approve such designation
in writing. If no beneficiary designation shall be in effect at the time when
any benefits payable under this Plan shall become due, the benefit payments
shall be made to the legal representative of the participant's estate.
Notwithstanding any provisions in this Plan to the contrary, the Executive
Compensation Committee may withhold any benefits payable to a beneficiary as a
result of the death of the participant (or the death of any beneficiary
designated by the participant) until such time as (i) the Committee is able to
determine whether a generation-skipping transfer tax, as defined in Chapter 13
of the Internal Revenue Code of 1986, or any substitute provision therefor, is
payable by the Company; and (ii) the Committee has determined the amount of
generation-skipping transfer tax that is due, including interest thereon. If
any such tax is payable, the Executive Compensation Committee shall reduce the
benefits otherwise payable hereunder to such beneficiary by an amount equal to
the generation-skipping transfer tax and any interest thereon that is payable
as a result of the death in question.
C-5
<PAGE>
Benefits payable under the Plan are not in any way subject to the debts or
other obligations of the persons entitled to those payments, whether the person
is a participant or a beneficiary. Benefits under the Plan may not voluntarily
or involuntarily be sold, transferred, or assigned.
C-6
<PAGE>
<TABLE>
EXHIBIT 12
MINNESOTA POWER AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES AND
SUPPLEMENTAL RATIOS OF EARNINGS TO FIXED CHARGES
<CAPTION>
For the Year Ended
-----------------------------------------------------
December 31,
-----------------------------------------------------
1990 1991 1992
-------- --------- ---------
(In Thousands Except Ratios)
<S> <C> <C> <C>
Net income per consolidated $ 74,570 $ 75,481 $ 73,288
statement of income
Add (deduct)
Current income tax expense 26,951 15,970 26,617
Deferred income tax expense (benefit) (2,893) 12,635 1,940
Deferred investment tax credits (6,341) (1,615) (1,568)
Extraordinary item - - (4,831)
Undistributed income from less than
50% owned equity investment (3,558) (5,155) (5,733)
Minority interest - (129) 2,684
-------- -------- --------
88,729 97,187 92,397
-------- -------- --------
Fixed charges
Interest on long-term debt 43,698 43,748 44,008
Capitalized interest 803 - 422
Other interest charges - net 4,797 8,776 6,455
Interest component of all rentals 5,908 5,694 5,725
-------- -------- --------
Total fixed charges 55,206 58,218 56,610
-------- -------- --------
Earnings before income taxes and fixed
charges (excluding capitalized interest) $143,132 $155,405 $148,585
======== ======== ========
Ratio of earnings to fixed charges 2.59 2.67 2.62
======== ======== ========
Earnings before income taxes and fixed
charges (excluding capitalized interest) $143,132 $155,405 $148,585
Supplemental charges 16,767 16,846 16,017
-------- -------- --------
Earnings before income taxes and fixed
and supplemental charges (excluding
capitalized interest) $159,899 $172,251 $164,602
======== ======== ========
Total fixed charges $ 55,206 $ 58,218 $ 56,610
Supplemental charges 16,767 16,846 16,017
-------- -------- --------
Fixed and supplemental charges $ 71,973 $ 75,064 $ 72,627
======== ======== ========
Supplemental ratio of earnings to fixed
charges <F1> 2.22 2.29 2.27
======== ======== ========
<CAPTION>
For the Year Ended
-----------------------------------------------------
December 31,
-----------------------------------------------------
1993 1994
--------- ---------
(In Thousands Except Ratios)
<S> <C> <C>
Net income per consolidated $ 62,621 $ 61,333
statement of income
Add (deduct)
Current income tax expense 23,465 17,743
Deferred income tax expense (benefit) 5,517 6,201
Deferred investment tax credits (2,035) (2,478)
Extraordinary item - -
Undistributed income from less than
50% owned equity investment (6,559) (8,138)
Minority interest (83) (879)
-------- --------
82,926 73,782
-------- --------
Fixed charges
Interest on long-term debt 42,579 48,137
Capitalized interest 3,010 -
Other interest charges - net 3,570 7,382
Interest component of all rentals 5,736 5,737
-------- --------
Total fixed charges 54,895 61,256
-------- --------
Earnings before income taxes and fixed
charges (excluding capitalized interest) $134,811 $135,038
======== ========
Ratio of earnings to fixed charges 2.46 2.20
======== ========
Earnings before income taxes and fixed
charges (excluding capitalized interest) $134,811 $135,038
Supplemental charges 15,149 14,370
-------- --------
Earnings before income taxes and fixed
and supplemental charges (excluding
capitalized interest) $149,960 $149,408
======== ========
Total fixed charges $ 54,895 $ 61,256
Supplemental charges 15,149 14,370
-------- --------
Fixed and supplemental charges $ 70,044 $ 75,626
======== ========
Supplemental ratio of earnings to fixed
charges <F1> 2.14 1.98
======== ========
<FN>
----------------
<F1> The supplemental ratio of earnings to fixed charges includes the
Company's obligations under a contract with Square Butte Electric
Cooperative ("Square Butte") which extends through 2007, pursuant to
which the Company is purchasing 71% of the output of a generating unit
capable of generating up to 455 megawatts. The Company is obligated
to pay all of Square Butte's leasing, operating and debt service costs,
less any amounts collected from the sale of power or energy to others,
which shall not have been paid by Square Butte when due. (See Note 10.)
</FN>
</TABLE>
<PAGE>
MINNESOTA POWER 1994 ANNUAL REPORT
[PHOTO OF MARK PINNEY, ED MACKEY, TOM GEISELMAN, AND JOE REIS]
[PHOTO OF CINDY MCLEAN AND DEBBIE BULLOCH]
[PHOTO OF JACK HOKKANEN]
[PHOTO OF JIM JORDAN, SKIP VANDAMME, BOB FONGER, RON CLARK, RANDY BURKHART AND
BRIAN DENSTON]
[PHOTO OF SHARON ALECK]
[PHOTO OF MIKE COCHRAN, MARY SCHOENROCK, JOLYNN NILSON, KARLA STROMBECK, RUSS
SCHUMACHER, AND DIANE STUART]
[PHOTO OF STEVE HOVEY]
DIVIDENDS OF CHANGE
<PAGE>
[LOGO OF MINNESOTA POWER]
Electric Utility Operations
Minnesota Power is a diversified utility company headquartered in Duluth, Minn.
We provide electric service to 133,000 customers in northern Minnesota and
northwestern Wisconsin. Large industrial customers, which account for about
half our electric revenue, include paper mills and Minnesota's taconite
industry, which supplies most of the pelletized iron used in U.S. steel-making.
Wisconsin electric customers are served by our Superior Water, Light and Power
Company subsidiary. SWL&P also supplies water and natural gas to about 10,000
customers in the city of Superior and nearby areas. Another subsidiary, BNI
Coal, mines and sells lignite coal to two North Dakota mine-mouth generating
units, one of which supplies Minnesota Power with 71% of its output under a
long-term contract.
Water Utility Operations
Our Southern States Utilities subsidiary is the largest independent supplier of
water and wastewater utility service in Florida, serving more than 100
communities. Our Heater Utilities subsidiary provides water and wastewater
services in North Carolina and South Carolina. SSU and Heater serve a total of
139,000 water customers and 47,000 wastewater treatment customers. In addition,
a subsidiary of SSU supplies sanitation service to 12,000 customers in Lehigh
Acres, a community in southwest Florida.
Investments and Corporate Services
While electric and water utilities are our core businesses, non-regulated
investments supplement our earnings and, in some cases, perform an economic
development function in our electric utility service area. These investments -
and our ownership stake in them - include a securities portfolio that provides
funds for reinvestment and business acquisitions (100%); Capital Re
Corporation, a financial guaranty reinsurance company (21%); Lehigh Acquisition
Corp., southwest Florida real estate sales (80%); Lake Superior Paper
Industries, a Duluth paper mill (50%); and Superior Recycled Fiber Industries,
a Duluth recycled pulp production plant (88%).
[PHOTO OF M.L. HIBBARD POWER PLANT, WITH TRANSMISSION TOWERS.]
[PHOTO OF TWO COMPANY LINEMEN AND A ROLL OF ELECTRICAL CONDUCTOR.]
[PHOTO OF AN AERIAL SHOT OF A BNI COAL MINING AREA, SHOWING THE DRAGLINE.]
[PHOTO OF A HEATER UTILITIES' WATER TOWER.]
[PHOTO OF A SOUTHERN STATES UTILITIES WASTEWATER TREATMENT FACILITY.]
[PHOTO OF STACKED WOOD AT THE LAKE SUPERIOR PAPER INDUSTRIES MILL IN DULUTH.]
[PHOTO OF A COMPUTER MONITOR WITH A DISPLAY OF FINANCIAL LISTINGS.]
Contents
Financial Highlights . . . . . . . . . . . . 1
A Conversation with the CEO. . . . . . . . . 2
Management's Discussion and Analysis
Review and Outlook . . . . . . . . . . 6
Electric Utility Operations . . . . . . 9
Water Utility Operations . . . . . . .16
Investments and Corporate Services . .19
Liquidity and Capital Resources . . . .22
Financial Statements . . . . . . . . .25
Definitions of Acronyms and Abbreviations .39
Officers and Directors . . . . . . . . . . .40
Investor Information and Services . . . . .41
[RECYCLING LOGO] This report is printed on paper that contains a total of 50%
recycled fiber, including 10% de-inked post-consumer fiber produced by our
Superior Recycled Fiber Industries plant in Duluth.
<PAGE>
Dividends of Change
Change has been a friend to Minnesota Power. In the early 1980s, when we
recognized we could no longer stake our future mainly on selling electricity to
the iron mining industry, we began to diversify. We invested in water
utilities, coal mining, papermaking and other fields.
In all our businesses, old and new, we're dedicated to continuous
improvement. We're adapting to a changing regulatory climate, streamlining and
becoming more efficient in the way we work, and increasing reliance on team
dynamics and participatory management.
In the hands of motivated, goal-oriented men and women, change pays
important dividends. Some are intangible yet valuable, others have dramatic
financial impact such as the example below. Change has strengthened our
company. This report highlights 11 representative Dividends of Change.
[PHOTO OF ERIC NORBERG AND DAVE MCMILLAN.]
The Rewards of 'Partnering'
Most companies have both customers and suppliers. But not all have discovered
the economic advantage in building cooperative relationships with both groups.
As an example of "partnering" with a supplier, we've signed a new, more
flexible contract with our coal hauler, the Burlington Northern Railroad. It's
based on the assumption that we'll sell more power and buy more coal if we can
keep our costs down, benefiting our company, the BN, and our customers. Our
combined savings on the cost of coal and rail transportation is more than $20
million annually. Eric Norberg, left, and Dave McMillan represent the many
people of Minnesota Power who presented our case in this landmark negotiation.
<TABLE>
Financial Highlights
<CAPTION>
1994 1993 Change
<S> <C> <C> <C>
Operating Revenue
and Income $637,782,000 $589,607,000 8%
Net Income $61,333,000 $62,621,000 (2%)
Earnings Per Share $2.06 $2.20 (6%)
Average Shares of
Common Stock 28,239,000 26,987,000 5%
Dividends Per Share $2.02 $1.98 2%
Total Assets $1,807,798,000 $1,760,526,000 3%
Return on Common
Equity 10.5% 11.5% (9%)
</TABLE>
<TABLE>
Average Annual Shareholder Return Over Last 10 Years
(Graphic material omitted)
<CAPTION>
Percentage
<S> <C>
Minnesota Power 12.9
U.S. Electric Utilities 12.6
S&P 500 14.3
</TABLE>
Minnesota Power common stock bought in January 1985 and sold at year-end 1994
would have earned an average return of 12.9% per year - including dividends
paid and appreciation in value.
<TABLE>
Earnings and Dividends Per Share
(Graphic material omitted)
<CAPTION>
1985 1986 1987 1988 1989 1990 1991 1992 1993
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Earnings 2.34 2.77 2.34 2.35 2.90 2.37 2.46 2.47 2.20
Dividends 1.38 1.52 1.66 1.72 1.78 1.86 1.90 1.94 1.98
<CAPTION>
1994
<S> <C>
Earnings 2.06
Dividends 2.02
</TABLE>
While earnings declined in 1994, dividends rose to 98% of earnings. The
Company's earnings goal is $3.25 per share by the year 2000, with electric
utilities, water utilities and non-regulated investments each contributing
about a third.
<TABLE>
Assets
Millions of Dollars
(Graphic material omitted)
<CAPTION>
1983 1984 1985 1986 1987 1988 1989 1990
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Electric Utility 1,259 1,273 1,192 1,149 1,157 1,172 1,155 1,133
Water Utility 5 12 24 34 57 104 228 269
Investments and
Corporate Services 150 255 325 533 666 664 630 674
<CAPTION>
1991 1992 1993 1994
<S> <C> <C> <C> <C>
Electric Utility 1,121 1,129 1,170 1,181
Water Utility 292 322 329 326
Investments and
Corporate Services 639 639 727 778
</TABLE>
Increasing investments in water utilities and nonutility business activities
have steadily diversified Minnesota Power since 1983. This graph includes
shared/leased assets not shown on our balance sheet.
We've changed our financial statements this year to reflect changes in the way
we look at our business. Financial data from prior years has been reclassified
in this annual report to present comparable data in all periods.
1
<PAGE>
A CONVERSATION WITH THE CEO
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Arend Sandbulte
[PHOTO OF AREND SANDBULTE.]
How would you assess 1994's financial and operating results?
Earnings of $2.06 per share were disappointing, a 6% decrease from the previous
year and the lowest in a decade. The largest single reason for the lower
earnings was our securities portfolio. A consistent and substantial
contributor to our earnings for 10 years, the portfolio was hurt by lower
market returns, declines in the value of some of its holdings, and a 21-cent-
per-share write-off of one investment early in the year. Despite that rocky
start, it finished the year with an after-tax return of 3.8%, but compared with
the previous year, its income declined 55 cents per share.
Despite the lower earnings per share, 1994 also brought important, positive
developments for Minnesota Power that should help future earnings. Northeast
Minnesota's taconite plants and paper mills had a good year, and this spurred
our electric utility business to its second-highest kilowatt-hour sales ever.
Six of our nine largest power customers extended their contracts with us. We
received a rate increase, the first since 1981, and our rates remain well below
national and regional utility averages. BNI Coal broke records, and Superior
Recycled Fiber Industries was profitable its first year out of the gate. Lake
Superior Paper, with help from price increases, turned the corner in the fourth
quarter and is positioned for higher profits this year. Water utility earnings
were hurt by abnormally high rainfall; we continue upgrading water facilities,
improving customer service, and laying the groundwork for returns that more
fairly reflect our investment in the water business. Finally, we signed an
agreement to acquire 80% ownership in ADESA Corporation, a business we believe
will give us the growth we need to achieve our financial goals in the coming
years.
What are the Company's financial goals?
Our goal is to increase earnings to a minimum of $3.25 per share by the year
2000. We expect the earnings to come, approximately one-third each, from
electric utility operations, water utility operations, and other investments,
the largest of which would be ADESA. That may look like a stretch, but I'm
confident we can do it.
Minnesota Power's stock price has dropped roughly 30% from the highs it hit in
autumn 1993. Why?
The rising interest rates of the last year and a half have hurt most utility
stocks and probably account for much of our price decline. Beyond that, three
things happened. One was the National Steel taconite plant shutdown in late
1993 and, although the plant restarted last August, the stock market has not
yet given back to us the price drop that hit when the closing was announced.
Second, our first-quarter securities portfolio loss dashed expectations for
earnings growth in 1994. Finally, the announcement of our planned ADESA
acquisition in January 1995 created additional uncertainty that seemed to keep
our stock from sharing in some gains that other utility stocks enjoyed early
this year.
What is the Company doing to improve its stock price?
In the long run, of course, the most important thing will be performance: We
intend to increase our earnings by providing exceptional customer service at
competitive prices. In the shorter term, perception is also important, and I
think the stock price reflects some uneasiness analysts are currently feeling
about our Company. One problem is that diversification, which has benefited us
significantly for the past decade, has also made us more complex to understand.
That's where communication can help. We'll work hard in 1995 to help investors
understand our business prospects, and then hopefully they'll appraise our
future the way we do. As a diversified utility, Minnesota Power offers
investors an attractive combination - solid utility businesses coupled with
non-regulated investments that give us more growth potential than a "plain
vanilla" utility. That's the message we're carrying to Wall Street.
Are you concerned about the Company's high dividend payout?
In 1994 we paid out in dividends 98% of our earnings. That's high, but given
our cash resources and our lack of major utility construction needs, it should
not be detrimental. Longer-term, our goal is to reduce dividend payout to 70%
of earnings; unlike some utilities, however, we don't plan to do it by reducing
dividends but rather by increasing earnings. We're confident we can increase
earnings, and this is the message I believe our board of directors was sending
when we raised the dividend in January 1995.
Do you think market concerns about electric utility deregulation and
competition are hurting us?
It's possible. There's a perception in the market that retail electric
competition, if it comes, is going to be somewhat more difficult for us than
for the typical utility because we have large
2
<PAGE>
industrial customers who theoretically might be courted by other power
suppliers if there were full retail competition. I don't agree. In 1994 six of
our nine largest industrial power customers extended their long-term contracts;
this doubled the amount of revenue under contract between now and 2005, and the
average contract duration is now between six and seven years. Our customers
aren't signing with us just because we're nice folks (although we are).
They're doing it because our retail rates are the lowest in the region and
among the lowest in the country. Our customers are voting with their contract-
signing pens, and not with their feet.
How will you keep electric rates competitive?
Smart cost control is the answer. We'll be spending somewhat less on
construction over the next several years, compared with prior years. We're
being more aggressive in seeing if we can't use existing facilities longer than
we might have in the past. We're focusing expenditures in areas where there are
good possibilities for either substantial savings or revenue growth. A new
customer information system we put in place in 1994 will help us serve
customers better and more efficiently. A new energy management system,
beginning in 1995, will help us compete for regional electric sales and provide
new power-related services in the future.
Do you see growth opportunities for the electric utility?
If we serve our customers well, we'll do well. We will pursue any growth
initiatives, traditional or not, that have a reasonable chance of being
profitable. There are some growth constraints, however, such as demand-side
management, the conservation ethic, and the lack of customer growth in our
service area. On the other hand, there are processes in the steel and paper
industries that can be done electrically that are now being done less
efficiently with other energy forms. New electrotechnologies can mean sales
growth for us and solve problems for customers by removing production
bottlenecks and helping them remain competitive in their markets.
What's your assessment of utility competition/deregulation scenarios?
Generally, I feel fewer electric utility CEOs now believe there will be wide-
open retail competition than, say, a year ago. The shock wave from California's
deregulation proposal has subsided. Ironically, one factor tending to slow
retail competition is that utilities, including us, have been acting more and
more as if full competition and deregulation had already occurred. We've been
trimming costs and offering large industrial customers rate flexibility for
years. The gates of competition may open further, but many issues need to be
addressed first. Besides utilities themselves and their customers, myriad
federal and state regulatory bodies have stakes in the outcome and roles to
play. Sorting out the complexities and resolving the issues will not be easy,
and there will be reluctance to jeopardize the benefits traditional regulation
has given us. Hopefully, rationality and logic will prevail, as well as a sense
of fairness in how to handle utility investments made in good faith under the
present system of regulation.
What are the growth prospects for water utilities?
Customer growth in our water utility businesses has been running 3% to 4% per
year, not counting acquisitions or asset sales. There will probably be more
opportunities for water utility acquisitions because the industry is still
fragmented. Nationally, there's a trend toward privatization of smaller
municipal systems,
This ad ran in regional newspapers following the January 1995 announcement of
our dividend increase.
Minnesota Power's 25th Consecutive Dividend Increase
On the occasion of our 25th consecutive annual dividend increase*, we'd like to
tell you about our course for the future.
Some utilities have cut dividends. Not Minnesota Power. Our policy is to
maintain our dividend, and to keep raising it as earnings grow. It yields 8%
based on our current stock price of about $25.
In the mid-80s, we realized we should no longer rely exclusively on our
electric business. We have the financial strength to diversify, and we're doing
it with ingenuity and success. The new Minnesota Power has three main parts:
[CLIPART OF ELECTRICAL PLUG]
Our traditional electric utility base, including secure long-term contracts
with large industrial customers, and 11.6% authorized return.
[CLIPART OF WATER FAUCET]
Water utilities, growing and providing an increasingly valuable commodity in
Florida and the Carolinas.
[CLIPART OF THREE ARROWS]
Nonregulated affiliates, with potential growth and returns higher than
utilities.
* On January 25, Minnesota Power (NYSE:MPL) increased the dividend on its
common stock, equivalent to an annual rate of $2.04, compared with $2.02 paid
in 1994. This higher quarterly dividend is payable March 1 to shareholders of
record on February 15.
For more information about Minnesota Power, please write or call our
Shareholder Services Department.
[LOGO OF MINNESOTA POWER]
30 West Superior Street
Duluth, Minnesota 55802
1-800-535-3056
FAX: 218-720-2502
3
<PAGE>
and we may be able to either buy them or manage them for a fee. Beyond actual
utility operations, there are other water-related services and products we
could offer.
Does the pending ADESA acquisition signal a shift in
diversification strategy, in that it is so different from any
of our other businesses?
Certainly, the type of service ADESA performs is a departure, but ADESA is more
like other businesses we have than you might think - and in some very key ways.
Since 1983, financial services have been an important component of our Company;
our securities portfolio and Capital Re, the reinsurance firm of which we own
21%, are both examples. ADESA, too, provides a corporate service: It brings
auto buyers and sellers together, similar to a stock or commodity exchange.
ADESA does not own the vehicles it auctions, but rather provides services for
both buyers and sellers. It's a niche service business for the automotive
industry, which is huge. And ADESA is a large player in this niche.
This acquisition may have little to do with utilities, but it has a lot to do
with our profit strategy. I recently reviewed a Wall Street Journal article
from September of 1993 that talks about Cox Broadcasting, a private firm that
owns Manheim, the largest auto auction company. Cox is considered an astute
company. The article, in sum, said that auto auctions had nothing to do with
Cox's broadcasting business, but had a lot to do with its profits.
Headquartered in Indianapolis, ADESA operates auto auctions at Indianapolis,
Boston, Buffalo, Cleveland, Cincinnati/Dayton, Knoxville, Lexington, Memphis,
Charlotte, Birmingham, Sarasota/Bradenton, Miami and Austin. In Canada ADESA
auctions are at Montreal, Ottawa and Halifax, Nova Scotia.
[MAP INDICATING LOCATIONS OF ADESA'S AUTO AUCTIONS]
The ADESA File
Merger Proposal
Agreement is for us to buy an 80% stake in ADESA Corporation for $167 million
($162 million upon completing merger plus $5 million for stock owned prior to
merger agreement). The companies' boards have approved a definitive merger
agreement, and ADESA shareholders will vote on it by mid-1995.
The Business
North America's third-largest auto auction company, ADESA owns and operates 16
facilities in the U.S. and Canada. Auction buyers are car dealers; sellers
include domestic auto manufacturers, import auto makers, car dealers,
fleet/lease companies, banks and finance companies. Revenue comprises auction
fees paid by sellers and buyers and charges for auxiliary services that include
auto reconditioning, body and paint work, remarketing, dealer financing and
transportation services.
The Numbers
ADESA sold 410,000 vehicles in 1994, generating net income of $7.8 million on
revenue of $94 million. In 1992 it sold 184,000 cars, with net income of $3.6
million and revenue of $46 million.
Growth Strategy
To acquire and consolidate independent auto auctions and begin new ones.
Customer Philosophy
To have "a servant's attitude," ready to do whatever is necessary to serve
those who use ADESA auctions.
[PHOTO OF ADESA IN MEMPHIS]
ADESA's five-year-old Memphis auction: 145 acres, six auction lanes, 1,000
vehicles per week.
[PHOTO OF ADESA EMPLOYEE AND CAR ENGINE]
Auxiliary services include auto reconditioning, body and paint work, dealer
financing, remarketing and vehicle transport.
4
<PAGE>
But other utilities are not out buying car auctions.
The fact that a host of other utilities aren't following the same strategy we
are doesn't worry me, actually. I'm not a contrarian by nature, but I don't
think following the same path every other utility follows will necessarily lead
to success. A crowded path may mean there isn't that much revenue and earnings
growth available, and the competition will be intense. We've looked at a lot of
businesses in the 12 years since we decided to diversify, we've studied ADESA
in detail, and that's why we're confident it's a good buy for us and at a fair
price.
What was the process used to find ADESA?
First we worked through a firm that finds potential buys for companies that are
looking to expand through acquisition. We wanted a business with manageable
risk and the potential for growth and returns higher than those of a typical
utility business. We looked at firms in 25 to 30 different industries,
beginning with utility-related businesses and then gradually broadening our
scope. We considered international electric utility operations, but ruled them
out because we felt they were too risky. We looked at oil and gas exploration,
finally rejecting this business because it's too cyclical. We considered title
insurance, but that business, too, is cyclical and linked to interest rates.
Manufacturing was too capital-intensive. ADESA surfaced as a potential
acquisition in mid-1994 and appeared to meet most of our criteria. We studied
it thoroughly, involving our own corporate development people as well as
outside investment advisors. Our first impression, like many people's, was
colored by stereotypes about used car salesmen. A closer look dispelled the
stereotypes, however. And the closer we looked, the more we were impressed
with ADESA's business prospects and the better the financial fit we saw between
the two companies.
What do you like about ADESA?
Its business fundamentals are solid. It's not cyclical. It has good cash flow,
and its revenue and income growth have been in the range of 30% a year for the
past three years. Growth in the auto redistribution industry overall has
averaged about 10% a year for the past decade, reflecting a growing supply of
rental cars, a boom in leasing as well as the increasing price of new vehicles.
We also like that this business is not as capital-intensive as our utility
businesses. For example, our electric utility had over $3 invested in
facilities to earn $1 of revenue in 1994. In contrast, ADESA generated about
$1.25 in revenue for every $1 of capital it had invested in facilities. That's
an advantage when you're planning on expanding. Another thing we liked about
ADESA is that its values were compatible with ours.
What values do you mean?
I mean basic values: Ethics. Honesty. Being customer-oriented. Its auction
facilities are huge, modern, spotless. It reconditions the cars and does
repainting and body work. It delivers vehicles to and from customers, using its
own fleet of modern transport trailers. It provides remarketing services and
makes short-term loans to dealers until they sell the vehicles. It handles all
the paperwork, using computerized equipment to expedite the process at every
point. ADESA provides one-stop shopping for car dealers.
What does Minnesota Power bring to the merger?
Our primary role is to provide expansion capital in accordance with approved
business plans. We're not going to try to reculturize ADESA or make a utility
out of them. We want them to continue to do what they've been doing, only more
of it and even better. That's why we're retaining ADESA's key top managers;
they will run the business and direct its growth.
How will the company expand?
We believe the auto redistribution business, like the water utility business
since the mid-1980s, is in a period of consolidation. There are three large
players in the industry, of which ADESA is the third-largest. But over half the
13 million vehicles a year that go through auctions are handled by independent
companies that typically don't offer the breadth of service ADESA does. ADESA
will expand by acquiring independent auctions and starting up large, new
facilities. Its existing auctions can also become more profitable by handling
more cars.
Even if ADESA does well, how can you earn a good return when you pay such a
premium for the business?
It's true that if you divide the company's past-year income by the $167 million
we are paying to acquire 80% ownership, it works out to a single-digit return.
Believe me, we do not part with that much money easily. But we learned early
in our diversification efforts that you have to pay a premium for a good
business. The way you increase the return is through growth and expansion.
What do you look for in 1995 in terms of Minnesota Power's overall performance?
I look to 1995 for a better financial year for our paper and recycled fiber
businesses, better results in our water businesses, and continued good earnings
for the electric utility. We expect to close the ADESA deal and tell our story
effectively to investors so they fully understand our Company's strengths and
so our stock is fully valued in the market. And, of course, we'll prove that
value through performance.
I would like to take this opportunity to thank all Company employees for their
hard work over the past year. The 11 accomplishments featured in this report
are representative of the kind of work our employees do whether they live in
Minnesota, Wisconsin, Florida, the Carolinas or North Dakota. I would also
like to thank shareholders and ask for your continuing support as we try to
increase the value of your investment and make you proud to own part of
Minnesota Power.
Arend Sandbulte
Arend Sandbulte
Chairman, President and Chief Executive Officer
February 24, 1995
5
<PAGE>
REVIEW AND OUTLOOK
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Once exclusively an electric utility, Minnesota Power has in the past
decade invested in a variety of non-electric businesses.
Our purpose in diversifying was threefold: First, we wanted to reduce the
Company's heavy dependence on electric sales to a small number of large
customers in taconite mining, an industry whose fate is tied to steel
manufacturing. Second, we wanted to increase our growth potential beyond what
we projected for our electric business. Third, in the case of investments such
as our Duluth paper and recycled pulp plants, we also wanted to create jobs and
boost the economy in our electric utility service area.
We feel diversification has served us well and is a valid strategy for
meeting our future goals:
. To increase earnings to a minimum of $3.25 per share by the year
2000;
. To maintain our financial strength and increase the value of our
shareholders' investment; and
. To nurture a customer-driven, quality-oriented corporate culture
that is both internally cooperative and externally competitive.
To hit our earnings target, we will need to sustain the good financial
performance of our electric utility, achieving our authorized rate of return.
We will need earnings growth from our water utilities through customer growth,
additional acquisitions, and rates that reflect our investment in facilities to
meet increasing water demand and government-mandated environmental standards.
This won't be enough, however. We will need to supplement the regulated
income from our electric and water utilities with income growth and higher
returns from non-regulated businesses.
Our goal is that by the year 2000 each of our core businesses, electric
and water utilities, would provide about one-third of Minnesota Power's income.
The remaining third would come from non-regulated investments, including a
proposed acquisition we announced recently.In February 1995 Minnesota Power and
ADESA Corporation signed a merger agreement in which ADESA, an auto auction
firm with 16 outlets in the United States and Canada, would become our 80%-
owned subsidiary.
[PHOTO OF CINDY MCLEAN AND DEBBIE BULLOCH]
The Paper Goes
'Round and Round'
In 1994 Minnesota Power's electric utility operations collected and recycled
98,362 lbs. of white paper, 99,079 lbs. of mixed paper plus mountains of
magazines, phone books, cardboard, newsprint, aluminum, glass and plastic - all
because Cindy McLean decided one day in 1989 that "somebody should get us
organized." Most collected materials are sold. (Paper goes to our Superior
Recycled Fiber Industries operation.) The reduced cost of trash hauling is a
valuable bonus. In the photo, Cindy is pictured on the right with Debbie
Bulloch, who recently took over the leadership of the
recycling program.
6
<PAGE>
The $167 million transaction is scheduled for completion by mid-1995
following approval by ADESA shareholders.
ADESA's management will retain 20% ownership. Under the agreement, they
have the right to sell, and Minnesota Power has the right to buy, their 20% in
increments during the 1997-99 period at a price linked to ADESA's financial
performance.
The money for buying and expanding ADESA and the possible acquisition of
more water companies will come mainly from our securities portfolio. We expect
to retain our investment in Capital Re Corporation. We will continue selling
our southwest Florida real estate and expect to sell all or nearly all the
property by 2000.
Another shift in resources is possible in 1995. Pentair, Inc. - our
joint-venture partner in Lake Superior Paper Industries - has announced its
desire to exit the paper business, which would likely entail selling LSPI. We
believe a sale could improve the chances for expanding the Duluth mill, which
was originally designed for more than one paper machine. Our position as half-
owner is that we would join in a sale under the right conditions. If LSPI is
sold, it may be logical to also consider a simultaneous sale of Superior
Recycled Fiber Industries (SRFI), whose paper recycled fiber plant
is adjacent to and operated by LSPI.
1994 Performance
Earnings per share of common stock for 1994 were $2.06, compared with
$2.20 in 1993 and $2.47 in 1992.
The largest single factor in the lower earnings was a decline in the
performance of the Company's securities investment portfolio.
Though the portfolio was profitable for the year, its income was reduced
55 cents per share from the previous year due to lower returns, including
declines in the value of some securities, and the 21-cent-per-share write-off
of one investment. Also contributing to lower 1994 earnings was an 11-cent-per-
share loss from our investment in Reach All Partnership, a Duluth manufacturer
of truck-mounted lifting equipment in which the Company has an 82.5% interest.
Kilowatt-hour sales increased 4% in 1994, reflecting an increase in sales
to large industrial customers and resale customers. Despite this and higher
retail electric rates that went into effect on an interim basis March 1, 1994,
income from electric utility operations was down from the previous year.
The Company's water utility operations were helped by higher rates, but
that benefit was offset by heavy summer rains that reduced water consumption.
A $19.1 million gain from the sale of water plant facilities increased water
utility operations income over 1993, contributing 42 cents per share to income.
Minnesota Power's coal mining business and sales of Florida real estate
turned in solid performances in 1994,surpassing their 1993 income. Our Duluth
paper mill, helped by a rebound in paper prices last fall, went from a $3.7
million pre-tax loss in 1993 to a $3.1 million pre-tax profit for 1994; the
Company recognizes 50% of the mill's pre-tax earnings. SRFI, which began
operating in late 1993, contributed $906,000 to corporate earnings in 1994.
<TABLE>
Where 1994 Earnings Came From
<CAPTION>
Earnings Per Share 1994 1993 1992
<S> <C> <C> <C>
Electric Utility Operations
Electric $1.17 $1.32 $1.30
Coal Mining .11 .10 .09
------ ------ ------
1.28 1.42 1.39
Water Utility Operations .48 .08 (.05)
Investments and Corporate
Services
Portfolio and Reinsurance .08 .63 .92
Real Estate .36 .24 .35
Paper and Pulp .05 (.08) .01
Other Operations (.19) (.09) (.15)
------ ------ ------
.30 .70 1.13
Total Earnings Per Share $2.06 $2.20 $2.47
Average Shares of
Common Stock - 000s 28,239 26,987 29,442
</TABLE>
<TABLE>
Return on Common Equity
(Graphic material omitted)
<CAPTION>
Year Percentage
<S> <C>
1990 13.6
1991 15.4
1992 15.3
1993 11.5
1994 10.5
</TABLE>
In 1994 the Company earned 10.5% on common shareholders' equity, which
averaged $562 million during the year.
<TABLE>
Operating Revenue and Income
Millions of Dollars
(Graphic material omitted)
<CAPTION>
1992 1993 1994
<S> <C> <C> <C>
Electric 449.8 457.7 453.2
Water 53.6 65.5 91.2
Investments and
Corporate Services 72.8 66.4 93.4
----- ----- -----
576.2 589.6 637.8
</TABLE>
A sale of water facilities and revenue from SRFI's recycled fiber plant,
which started up in fall 1993, accounted for most of the increase in 1994
operating revenue and income.
7
<PAGE>
COMPARING FINANCIAL RESULTS FROM 1994, 1993 AND 1992
Operating Revenue and Income
Electric utility operations revenue was lower in 1994 than 1993, because
the Company recognized $5.1 million of unbilled revenue and recovered $14.6
million more of coal contract termination costs in 1993. Also, National Steel
Pellet Co., a taconite producer that purchases its electricity from the
Company, operated for seven months in 1993 compared with four months in 1994.
Additional revenue in 1994 of $11.1 million from the interim rate increase
partially offset the decreases in revenue. Revenue was higher in 1993 than
1992, because 1993 included $4 million more of the coal contract termination
cost recovery, $2.5 million more in unbilled revenue, and increased sales to
resale customers.
Water utility operations revenue was higher in 1994 than 1993 because of
higher water rates and a $19.1 million gain from the sale of water plant
assets. However, 1994 revenue from ongoing operations was less than expected
because abnormally high rainfall reduced consumption 8%. Revenue was higher in
1993 than 1992 because of higher water rates.
Investments and corporate services revenue was higher in 1994 than 1993
because SRFI, which began operating in November 1993, had $47.2 million more
revenue in 1994. The $10.1 million write-off of an investment, lower returns
and the decline in value of some securities due to higher interest rates
lowered 1994 income. 1993 income was increased by a $2.7 million gain on a
leveraged preferred stock investment but reduced by $8.1 million to reflect new
accounting rules for employee stock ownership plans. 1992 income includes a
$5.1 million gain from the redemption by the issuer of a preferred stock
investment.
Operating Expenses
Fuel and purchased power expenses were lower in 1994 than 1993 because the
monthly amortization of coal contract termination costs was completed in March
1994; 1993 included $14.6 million more of these costs than 1994. 1994 expenses
included additional purchased power to provide for unscheduled outages at our
Boswell power plant and to meet unexpected demand from three taconite
customers. Expenses were higher in 1993 than 1992 because additional purchased
power was used during scheduled maintenance at Company power plants.
Operations expenses were higher in 1994 than 1993, reflecting the fact
that SRFI began full operations in November 1993. Expenses were higher in 1993
than 1992 due to scheduled power plant maintenance and higher property taxes.
Administrative and general expenses were higher in 1994 than 1993 and 1992
due to salary and benefit increases.
Interest expense was higher in 1994 than 1993, reflecting $45 million of
new debt financing obtained for SRFI at the end of 1993. Expense was lower in
1993 than 1992 because of refinancings at lower interest rates.
Income from equity investments was higher in 1994 than 1993 because of
additional income from our increased ownership in Capital Re and improved
earnings from LSPI due to higher paper prices. Income was lower in 1993 than
1992 because of LSPI's loss. The Company recognized losses from its investment
in Reach All in all three years.
Income tax expense was lower in 1994 than 1993. Effective tax rates were
25.9% in 1994, 30.1% in 1993, and 26.9% in 1992. The effective tax rate was
lower in 1994 than 1993, due primarily to tax credits generated by affordable
housing investments and the recognition of income from escrow funds that had
been previously taxed. The effective tax rate was higher in 1993 than 1992,
reflecting a 1% increase in the federal income tax rate in 1993 and fewer tax
benefits generated by the investment portfolio.
[REPRODUCTION OF CONSOLIDATED STATEMENT OF INCOME AS ON PAGE 26 OF THIS REPORT.]
8
<PAGE>
ELECTRIC UTILITY OPERATIONS
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Electric utilities are undergoing a transformation as efforts to stimulate
competition begin to take effect. How far open competition will go and whether
it will apply to retail customers, however, is not clear.
Federal Energy Regulatory Commission proposals have altered the
competitive landscape, affecting transmission access and pricing. Under FERC's
transmission access policies, competitors can gain access to a utility's
transmission system, at rates set by FERC, to compete for sales to the
utility's wholesale customers. While utilities have commonly allowed use of
their lines for wholesale power transactions, most object to being required to
transmit or "wheel" a competing electric supplier's power to the utility's own
retail customers.
With our low rates, Minnesota Power is well positioned to meet
competition. However, we remain opposed to retail wheeling. We believe it would
benefit only a few large customers while causing smaller users' rates to rise
dramatically and shareholder returns to fail to pay for capacity built on the
strength of future promises of cost recovery. At present there are no
proposals that, in our view, adequately address this stranded investment issue.
Recent developments suggest that retail wheeling, if it comes, is not
expected for some time. Though Minnesota and other states are studying it -
the most publicized proposal has been in California - retail wheeling is in use
only in rare locations in this country. One disincentive is that states like
Minnesota require utilities to invest in social and environmental programs that
could be jeopardized if their electric utilities had to compete head-to-head
with outside energy suppliers. Moreover, Minnesota's generally low electric
rates, half those of California, provide little incentive to change a system
that has been working well.
Despite uncertainty about the ultimate outcome of change in our industry,
Minnesota Power is preparing for a more competive future.
Our methods include cost cutting, pursuing legislative and regulatory
reforms to assure we compete with other power suppliers on a level playing
field, realigning our business functions to make it easier to price and market
"unbundled" products and services, and cementing relationships with customers
through innovative pricing and excellent service. We will learn more about our
customers as well as our competitors and use that information strategically.
We expect to expand our product offerings and build our customer base through
economic development and other initiatives. We will continue working to extend
electric service contracts with our largest customers, a strategy that achieved
good results in 1994.
We see ourselves increasingly as energy service providers. We look at our
customers' objectives as joint challenges. By finding ways to help them
conserve energy and cut costs, we help them become more productive. And that
increased productivity, we have found, can result in increased electric power
use longer-term for industrial customers as they compete with other operations.
We also encourage energy-saving electrotechnologies. We are promoting
ground-source heat pumps in residential and commercial markets. More efficient
than conventional
[PHOTO OF HEIDI JAGODZINSKI AND JACK HOKKANEN]
Ashes to Ashes
The northern Minnesota community of Hibbing, a Minnesota Power wholesale
electric customer, had a problem. The city, which operates a power plant of
its own, was running out of landfill space for its 7,000 tons of ash per year.
We offered to dispose of it at the Boswell Energy Center ash pond. Trucks that
carry the ash away make the trip pay by back-hauling coal, which fuels
Hibbing's power plant. It's a creative, economical, environmentally sound
solution. Pictured: Heidi Jagodzinski, Boswell environmental engineer,
submitted the ash disposal plan to the state. Jack Hokkanen is a customer
representative for our large municipal accounts. Both credit others for making
the idea work.
9
<PAGE>
Our Competitive Picture
<TABLE>
Customer Favorability
(Graphic material omitted)
<CAPTION>
Percentage
<S> <C>
Minnesota Power 91
Typical U.S.
Electric Utility 71
</TABLE>
Our 1994 rate increase had no appreciable effect on our electric customers'
overall impression of us. In a 500-person telephone survey, 91% rated the
Company positively. A full 82% said they'd choose us in a competitive
situation. Only one in 25 said they'd switch suppliers if given the option;
nationally, five in 25 would.
<TABLE>
Average Price of Electricity - Residential
(Graphic material omitted)
<CAPTION>
Cents per Kilowatt-hour
<S> <C>
Minnesota Power 5.55
Northern States Power 7.40
Otter Tail Power 6.42
Interstate Power 8.01
National Average 8.85
Average Cooperatives 8.24
</TABLE>
On average, our residential customers paid 37% less for
electricity in 1994 than customers of other U.S. utilities.
<TABLE>
Average Price of Electricity - Overall
Cents per Kilowatt-hour
(Graphic material omitted)
<CAPTION>
Minnesota National
Power Average
<S> <C> <C>
Residential 5.55 8.85
Commercial 5.58 7.90
Industrial 3.66 5.14
Overall 4.08 7.25
</TABLE>
Averaging rates for all service classes, our customers paid 44% less for their
power than utility customers elsewhere in the country.
electric heating and cooling systems, ground-source heat pumps are especially
cost-effective where the user wants both air conditioning and heating. With
normal usage, energy savings will offset installation costs in three to five
years.
The continued financial health of Minnesota Power's electric utility
business depends on the financial viability of our large industrial customers,
particularly taconite producers and paper manufacturers.
Both industries compete in global markets and, therefore, need to control
costs and increase their productivity. Through energy audits, we have helped
our large industrial customers identify cost-effective conservation measures as
well as projects that will improve production efficiencies. These improvements
are funded through state-mandated Conservation Improvement Program grants.
In many ways, we have always competed to serve our large industrial
customers. Because of their size, they have had the option to generate their
own power if they felt they could do it more economically than buying from us.
Paper mills, which require steam for their manufacturing process, are ideal
candidates for building their own cogeneration facilities, which operate
efficiently by burning a fuel to make steam for papermaking as well as electric
generation. Federal law says that when cogenerators meet certain conditions,
utilities must purchase their surplus power.
In recent years, the Company has offered customers a wider choice of
electric service options. For example, interruptible rates for large
industrial customers offer a price discount in return for agreeing to have
service interrupted on occasion. Another example: state law allows us, with
Minnesota Public Utilities Commission approval, to offer lower rates to service
area customers who could otherwise obtain energy from an unregulated supplier
or generate their own electricity. The Company is exploring the joint
development of cogeneration facilities with some of its key customers to meet
future energy needs.
1994 Performance
The Company's electric utility business performed well in 1994. Kilowatt-
hour sales rose 4% to their second-highest level ever despite the idling of one
of our largest customers for seven months of the year.
Revenue was boosted by a 7% interim retail rate increase. Customers also
saw the full impact of savings from new coal purchase and transportation
contracts, which more than offset the final electric rate increase for our
largest customers and reduced it for others. In the
10
<PAGE>
second half of the year, six of our nine largest industrial customers extended
their electric service contracts, more than doubling the amount of revenue
committed to us in the 1995-2005 period.
We sharpened our focus on customer service, streamlining operations in
some areas while emphasizing others where there is the greatest potential for
growth and likelihood of competition. We also realigned the functions in our
electric utility business to address the more competitive future many are
predicting for our industry.
Two industries - taconite production and the manufacture of paper and wood
products - accounted for 49% of the Company's electric operating revenue in
1994, versus 48% in 1993 and 51% in 1992.
An encouraging development during 1994 was the dramatic turnaround in the
market for pulp and paper. Electric sales to paper and other wood-products
customers in 1994 were up 5% over 1993 and 3% over 1992. Paper and wood-
products firms provided 14% of electric operating revenue each of the last
three years.
The paper industry is in better condition than it has been in many years.
Its additional energy use benefited us, as we provide power to all four of
northern Minnesota's largest paper mills. During the year we extended power
contracts with Blandin Paper Co., Boise Cascade, and Lake Superior Paper
Industries. One existing customer, Potlatch Corporation's paper division in
Brainerd, signed a four-year contract as a Large Power customer for 10
megawatts through November 1999; MPUC approval has been requested.
Taconite production provided 35% of electric operating revenue in 1994,
34% in 1993 and 37% in 1992. An important raw material for steelmaking,
taconite pellets are made from iron-bearing rock. In an energy-intensive
process, the rock is blasted from the earth, crushed and ground into powder.
The iron is magnetically separated, concentrated and rolled into a pellet with
a uniform 65% iron content for shipping to steel mills on the lower Great
Lakes.
In 1994 the taconite industry recorded its best year since 1981, producing
more than 43 million tons of pellets, and it is expecting to produce
approximately 48 million tons in 1995. In August 1994 we resumed providing
power to National after a lapse of 12 months while the plant was idled. The
Keewatin, Minn., plant is now fully operational and is expected to produce 5
million tons of taconite pellets in 1995, more than 10% of Minnesota's total
projected shipments. Though we had largely compensated for the loss of this
business through tight cost controls and the sale of power to other utilities,
National's return is a boon to the region and sounds an encouraging note for
1995.
In addition to signing a 10-year contract with National, we renewed
contracts with USX's Minntac plant and Hibbing Taconite. In January 1995, we
extended our contract to supply power to Eveleth Mines through 1999.
In November the Minnesota Public Utilities Commission granted us a retail
rate increase, our first since 1981.
The new rates will increase annual revenue by about $19 million, beginning
in 1995. Our initial request, filed in January 1994, had been for a $34 million
increase, but we reduced it to $27 million for 1994 and $23 million for
[PHOTO OF ED MACKEY, JOE REIS, MARK PINNEY, AND TOM GEISELMAN]
Increased Coal-Handling Efficiency at Boswell
Teamwork is paying off in the coal yard at our largest power plant, Boswell
Energy Center, near Cohasset, Minn. By modifying their coal-handling system,
Boswell workers improved efficiency and eliminated the need for one dozer,
saving its leasing, fuel, and maintenance costs. A new stacker and changes in
conveyor routing make it possible to unload an entire train without moving coal
to remote stockpiles, adding flexibility and efficiency in feeding the coal to
the boilers. The improvement is too new to report cost savings, but they will
be substantial. Among key members of the changeover team are, from left, Mark
Pinney, fuels planner; Ed Mackey, utility operator; Tom Geiselman, engineer;
and Joe Reis, senior instrument and control specialist.
11
<PAGE>
Comparing Results from
1994 and 1993
Total electric sales increased 4% primarily because of increased sales to
large industrial customers, wholesale customers and other power suppliers.
Revenue increased $11.1 million from interim rates collected since March 1,
1994, and $7.8 million from the recovery of CIP expenses in 1994. Approval by
the MPUC initiated recovery of CIP expenses beginning Jan. 1, 1994. Revenue
was lowered by $12.4 million because of reduced demand revenue from National
and lower rates associated with interruptible service. The Company also
completed recovery of the remaining $3.9 million of coal contract buyout costs
in March 1994, whereas 1993 included $18.5 million, a full year of recovery.
Additionally, the unbilled revenue adjustment added $5.1 million to revenue in
1993.
Electric operations earned a return of 12.8% on average common equity
devoted to electric utility plant in 1994, compared with 12.4% in 1993.
Comparing Results from
1993 and 1992
Despite work stoppages at two of the Company's largest industrial
customers, revenue was slightly higher in 1993 due to increased sales to resale
and other customers. In addition, a $5.1 million adjustment relating to the
recognition of unbilled revenue increased 1993 electric utility operations
revenue.
Electric operations earned a 12.4% return on average common equity devoted
to the electric utility plant in 1993, compared with 14.4% in 1992. These
returns do not include the recognition of unbilled revenue. The recognition of
a $3.4 million revenue credit from a court decision contributed to the higher
return in 1992.
<TABLE>
Why Electric Utility Operations Revenue Increased or Decreased
<CAPTION>
1994 1993
(Change from previous year - in millions)
<S> <C> <C>
Energy Sales $(12.4) $11.1
(including demand and energy charges)
Unbilled Revenue (5.1) 1.9
Rate Increases and Regulatory
Adjustments 11.1 (3.9)
Conservation Cost Recovery 7.8 -
Fuel Clause Adjustments (3.4) (5.3)
Coal Sales 2.4 .8
Other (4.9) 3.3
------ -----
$(4.5) $7.9
</TABLE>
<TABLE>
Electric Revenue by Customer Group
(Graphic material omitted)
<CAPTION>
1992 1993 1994
<S> <C> <C> <C>
Other 49% 52% 51%
Paper & Wood Products 14% 14% 14%
Taconite & Iron Mining 37% 34% 35%
--- --- ---
100% 100% 100%
</TABLE>
The taconite and iron mining industry, still the largest consumer of our power,
provided 35% of electric operating revenue in 1994. Ten years ago it provided
half.
<TABLE>
Electric Sales
Billions of Kilowatt-hours
(Graphic material omitted)
<CAPTION>
1992 1993 1994
<S> <C> <C> <C>
Residential 0.888 0.927 0.941
Commercial 0.918 0.966 1.011
Taconite/Paper 5.940 5.891 6.099
Other Industrial 0.752 0.811 0.805
Resale & Other 0.838 1.199 1.333
----- ----- ------
9.336 9.794 10.189
</TABLE>
The medium blue section of the bar includes power sold to customers in our
Large Power class that are served under long-term contracts.
1995 to reflect updated revenue and expense projections. The MPUC authorized an
11.6% return on equity invested in our electric utility.
Just as important to us for competitive reasons, the MPUC supported our
request that the increase be larger for residential customers to reflect the
higher cost of serving them and the need to keep the region's industrial
customers competitive in their global markets.
As a result of the rate increase, rates for large industrial customers
will rise less than 4%, while those for small businesses will go up 6.5%. The
increase for residential customers will be phased in over three years: 13.5%
beginning
12
<PAGE>
in 1995, 3.75% in January 1996 and another 3.75% in January 1997. Even after
the full increase, our residential customers will still pay nearly 25% less
than the 1994 national average.
The increase for large industrial users will be more than offset by
savings in coal purchase and transportation costs, savings we are passing on
to all customers. The savings result from new contracts negotiated with
suppliers in recent years and whose full effect began being felt in 1994.
The MPUC's 1994 rate decision also allows us to recover through rates $1.3
million a year to pay for decommissioning coal-fired power plants when they
reach the end of their useful lives.
The new rates are expected to go into effect in the second quarter of
1995. However, the Company began collecting an interim rate increase of 7% on
March 1, 1994. In second quarter 1995 we expect to determine amounts of
interim rate-related revenue, if any, the Company must refund with interest to
customers. As of Dec. 31, 1994, the Company had reserved $6.1 million of the
interim rate revenue for anticipated refunds.
The rate increase seems to have had little effect on the Company's good
standing with customers. A recent opinion survey indicates that we have a
favorable rating of 91% among residential customers, compared with 92% in 1993.
Across the nation, a typical favorability rating for electric utilities is 71%.
Minnesota requires electric utilities to spend 1.5% of their electric
revenue on conservation improvement programs (CIP) each year.
Because taconite and paper customers provide the bulk of Minnesota Power's
electric operating revenue, the largest of these programs are targeted at
them. CIP also funds demand-side management grants, awarded on a competitive
basis to commercial and small industrial customers, as well as energy
conservation initiatives aimed at all our customers. In 1995 we proposed a
program that would allow us to provide low-cost financing for energy-saving
investments.
State law allows utilities to recover state-approved conservation program
costs through an annual customer billing adjustment. In January 1994 the
Company began recovering ongoing 1994 CIP spending and $8.2 million of CIP
spending from previous years. The billing adjustment, which must be
reauthorized by the MPUC annually, has been allowing us to recover not only
what we spend on these energy-saving programs, but also "lost margins"
associated with power saved as a result of them. 1994 electric operating
revenue included $7.8 million of CIP-related revenue. About $5.7 million for
CIP expenditures was included in operating expenses.
SWL&P also offers electric and gas conservation programs to its Wisconsin
customers in accord with Wisconsin state policies.
Our nine largest customers, accounting for about 49% of electric operating
revenue, are served under long-term contracts.
The contracts, which in January 1995 averaged over six years in length,
each require 10 megawatts or more of power and have termination dates from
April 1997 to December 2005. Five of these customers are taconite producers and
four are paper manufacturers.
[PHOTO OF JIM JORDAN, SKIP VANDAMME, BOB FONGER, RON CLARK, RANDY BURKHART AND
BRIAN DENSTON]
Teamwork Works at SWL&P
While working at SWL&P's new water treatment plant, Brian Denston developed
forearm pain requiring treatment and physical therapy. He felt it was caused by
strain from raking sludge off the walls of the plant's reclaim clarifier. After
studying the problem, Brian and his colleagues decided to design an electric
pump to do the job. Ergonomic improvements like this help keep the lid on
insurance costs. Pictured, clockwise from left: Jim Jordan, Skip VanDamme, Bob
Fonger, Ron Clark, Randy Burkhart and Denston.
13
<PAGE>
The contracts provide that, even at low electric usage levels, these
customers will pay us enough to cover most of the fixed costs of having
capacity available to serve them, including a return on equity. The contracts
require four years notice before they can be cancelled, although the rates paid
under the contracts are subject to change through the regulatory process
governing all retail electric rates.
In December 1994 Minnesota Power asked the MPUC to approve two additional
rates for retail customers. First, an economic development rate would give
discounts to customers who invest in new capital improvements or equipment and
increase electrical load on our system. Second, an incremental sales rider to
an existing contract would allow more flexibility for some customers to operate
above their specified contract demand levels in certain months and pay only
energy charges for the incremental load.
For the next five years we are projecting relative stability in overall
kilowatt-hour sales. While taconite production in 1995 is expected to continue
at near-record levels, the longer-term future of this cyclical industry is less
certain. While we are doing all we can to help all our taconite customers
remain competitive, it is possible that production will decline gradually some
time after the year 2000.
Company generating stations in 1994 burned 3.4 million tons of coal, the
cost of which is our largest operating expense.
In December 1991 we paid Peabody Coal Company $35 million to terminate its
long-term coal contract two years ahead of the scheduled termination date. The
cost was amortized monthly and collected from customers through a fuel
adjustment provision until March 1994. Revenue collected this way amounted to
$3.9 million in 1994, $18.5 million in 1993, and $14.5 million in 1992. Savings
from the new coal supply agreements are being passed on to customers.
In 1993 Minnesota Power entered into a contract with Peabody that extends
through May 1997 for up to two-thirds of our coal needs. The rest will be
purchased on the spot market through one-year agreements, taking advantage of
favorable market conditions. We are exploring supply options beyond 1997 that
provide for a mix of long-, intermediate- and short-term purchases. We believe
adequate supplies of low-sulfur, sub-bituminous coal will continue to be
available.
In February 1993 the Company renegotiated two contracts with Burlington
Northern Railroad to deliver coal to our plants through December 2003 at
reduced rates. These new contracts also provide for better access to all major
coal production areas within the Powder River Basin of Montana and Wyoming.
<TABLE>
How Power Contracts Protect Us
Minimum Annual Revenue and Demand
under Contracts in effect as of Jan. 31, 1995
<CAPTION>
Minimum Revenue Megawatts
<S> <C> <C>
1995...........$90.5 million...........550
1996...........$78.1 million...........481
1997...........$75.5 million...........464
1998...........$61.5 million...........372
1999...........$32.3 million...........190
</TABLE>
The Company believes revenue from contracts with large industrial
customers will substantially exceed the minimum contract amounts. In fact,
assuming the new rates and large power contracts that are pending MPUC approval
are put in place, annual minimum revenue will increase $16
million to $28 million for each year through 1999.
<TABLE>
Sources of Electricity
(Graphic material omitted.)
<CAPTION>
Percentage
<S> <C>
Coal 52
Hydro 6
Purchased 20
Lignite 22
---
100
</TABLE>
Low-sulfur coal, our major fuel, comes from the Powder River Basin in Montana
and Wyoming.
<TABLE>
Annual Load Factor
(Graphic material omitted.)
<CAPTION>
1989 1990 1991 1992 1993 1994
<S> <C> <C> <C> <C> <C> <C>
Minnesota Power 80% 85% 82% 82% 86% 82%
Utility Industry Average 62% 60% 61% 61% 61% 61%
</TABLE>
Our annual load factor, the ratio of average electrical load to peak load, is
the highest of any major U.S. utility, mainly because of our large industrial
customers.
<TABLE>
Average Cost of Fuel for Electric Generation
Cents per Million BTU
(Graphic material omitted.)
<CAPTION>
1989 1990 1991 1992 1993 1994
<S> <C> <C> <C> <C> <C> <C>
Minnesota Power 112.1 113.6 114.5 118.9 115.6 97.0
West North Central Region 118.4 119.2 118.4 118.7 111.9
Total Electric Utility Industry 174.0 174.1 169.6 166.6 166.6
</TABLE>
The dip in average fuel costs in 1994 resulted from renegotiation of coal
supply and transportation contracts. Fuel costs from the Square Butte
generating unit are included in Minnesota Power fuel costs.
14
<PAGE>
A lignite-fired minemouth power plant in North Dakota provides us with an
economical supply of electricity.
Under an agreement extending through 2007, the Company purchases 71%
(about 307 megawatts during summer months and 322 megawatts during winter
months) of the output of a mine-mouth generating unit owned by the Square Butte
Electric Cooperative. The Square Butte unit is one of two units at Minnkota
Power Cooperative's Milton R. Young Generation Station near Center, N.D.
Square Butte has the option, upon five years advance notice, to reduce our
share of the unit's output to 49%. Minnesota Power has the option, though not
the obligation, to continue to purchase 49% of the output at market-based
prices after 2007 and through the end of the plant's economic life. Minnesota
Power must pay any Square Butte costs and expenses that have not been paid by
Square Butte when due, regardless of whether or not we receive any power from
that unit.
While many utilities and their customers will face higher costs to comply
with clean-air legislation, we expect to meet future requirements without major
spending.
Burning low-sulfur fuels and equipped with pollution control equipment,
our power plants already operate at or near the sulfur dioxide emission limits
set for the year 2000 by the Federal Clean Air Act Amendments of 1990. To meet
nitrogen oxide emission limits for 2000, we expect to install new burner
technology. Total clean-air compliance costs cannot be accurately estimated
yet, as regulations are not final.
A settlement was reached in 1994 in an Environmental Protection Agency
Superfund action to clean up pollution at a northern Minnesota oil refinery
site. Minnesota Power, along with roughly 130 other companies and several
government entities, agreed on a $37 million proposal, which was submitted for
approval to regulatory agencies.
Under the settlement, Minnesota Power's share of cleanup costs is about
$314,000, all of which has been paid. Other related legal and internal costs
have totaled about $550,000 since 1990, when the suit was initiated. Cleanup is
expected to begin in 1995. Minnesota Power's electric utility is not the
subject of any other environmental lawsuits.
BNI Coal mined a record 4.4 million tons of lignite coal, produced its
highest-ever net income of $3.1 million, and had no lost-time accidents in
1994.
Already North Dakota's lowest-cost producer of lignite - 24% less
expensive than the next-lowest supplier in terms of cost per British thermal
unit of energy in 1994 - BNI Coal should further increase its efficiency with
the addition of $5 million in new scrapers and bulldozers in 1995.
BNI Coal's lignite is burned at the nearby Milton R. Young Station's two
generating units. Thanks largely to its economical coal supply, the Young
plant in 1993, for the third consecutive year, achieved the second-lowest
production cost of any power plant in the United States. Its production cost
of 10.33 mills per kilowatt-hour was more than 47% lower than the average for
all coal-fired plants.
BNI Coal's reserves exceed 500 million tons, leaving ample supply for
expanded production if additional markets for lignite can be developed. This is
a challenge because lignite's high moisture content hampers long-distance
shipping. BNI Coal is working with Minnkota and other interested parties to
upgrade the quality of the lignite through a process that reduces moisture and
sulfur content.
[PHOTO OF STEVE HOVEY.]
BNI Cuts Haul Costs 20%
Minnesota Power's BNI Coal mine at Center, N.D., has replaced eight haul trucks
of varying capacities and speeds with five new ones that perform the same job
better. The Kress trucks, manufactured in Brimfield, Ill., carry 180 tons per
trip, operating faster, safer, and with less driver fatigue. The bottom line,
according to Pit Operations Manager Steve Hovey, who led the team that
justified and planned the changeover, is a 20% cut in average haul costs.
15
<PAGE>
WATER UTILITY OPERATIONS
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Southern States Utilities, which serves about 149,000 customers, is
Florida's largest privately held supplier of water and wastewater services,
four times as large as any other independent water utility in the state.
As such, SSU represents part of the solution to Florida's historically
fragmented water service, a welcome change in a state facing a serious
collective water supply challenge. The company is working with Florida
regulators and legislators to address concerns such as non-viable systems,
environmental care and conservation.
SSU has been granted cost-share funding from the South Florida Water
Management District to build an aquifer storage and recovery facility to help
meet long-term water needs of Marco Island, where the water supply is
deteriorating due to intrusion of brackish sea water. This facility will allow
SSU to store surplus fresh water in underground limestone formations until it
is needed in high-demand winter months. In addition, the Southwest Florida
Water Management District granted SSU cost-share funding for a wastewater reuse
project at our Spring Hill plant.
By concentrating on customer service, improved earnings, growth, working
with regulators, and leadership in solving Florida's water supply problems, SSU
demonstrates Minnesota Power's dedication to a long-term investment in water
services that will benefit customers, employees, shareholders and the natural
environment.
With its service area gaining population at 3% a year, SSU sees
opportunities for growth in its water business.
To stimulate internal growth, SSU encourages land developers to build
within or adjacent to existing service areas. External growth is expected
through further acquisitions and through offering management services to public
utilities that prefer to own, but not operate, their systems.
SSU continues to hold the line on expenses while adopting new measures to
improve performance, concentrating on high standards of customer service,
stewardship of water resources and the environment.
Strategic planning initiatives include continuing employee training in new
and evolving technology. Automation is helping increase productivity and
customer service. Periodic research asks customers to evaluate company
performance and guide SSU in making improvements.
A new water testing laboratory at Deltona, Fla., scheduled for July 1995
completion, will increase efficiency by centralizing most lab procedures,
reducing costs and dependence on outside providers. It will assure that SSU's
service meets or exceeds all state and federal water quality standards.
SSU did not file a general rate case in 1994, but plans in 1995 to request
an interim annual rate increase of about $10
[PHOTO OF SHARON ALECK]
Financial Health Counts, Too
When Sharon Aleck of our Heater Utilities affiliate saw an increase coming in
Heater's group medical premiums, she did a little actuarial calculating.
Finding that premiums had greatly exceeded claims in a recent period, Sharon
started negotiating with the insurance company. The result: what might have
been a $100,000-plus increase in annual premiums became an $18,000 decrease,
even though the number of employees covered grew from 68 to 77.
16
<PAGE>
million and could be seeking as much as $12 million in additional annual
revenue in final rates. New facilities added since 1992 are not yet included in
our rate base for earnings purposes. Further, mandated regulatory compliance
cost increases during the same period, particularly for environmental
protection, have raised operating expenses and should also be recovered in
rates.
Our 1995 filing will include innovations in rate design that will benefit
both customers and shareholders. In addition to the previously authorized
uniform rates, we will propose before the Florida Public Service Commission
(FPSC) water conservation incentives and a consistent policy on charges for
service availability. These measures, coupled with continuing efforts to
contain expenses, are expected to improve and provide more consistent earnings.
SSU applies uniform rates in most of the areas it serves. This rate design
policy, originally approved by the FPSC in 1993, was reaffirmed in August 1994.
Uniform rates recognize that SSU, operating as a statewide utility system,
provides economical service to all customers, regardless of their location. A
uniform rate policy, applied today in many other states, also prevents "rate
shock" by spreading the cost of capital improvements, reduces rate case
preparation expenses, and can help promote water conservation. In a state
facing a future water supply deficit, uniform rates represent sound public
policy and a long-term benefit to customers and shareholders.
By Florida law, water and wastewater utilities may make an annual index
filing to recover inflation in system operation and maintenance expenses, thus
delaying or avoiding the costs of full rate case filings. Similarly, another
Florida law allows water and wastewater utilities to file annually to recover
increased purchased water and wastewater treatment costs and property tax
increases. Through these filings in 1993 and 1994, SSU requested $3 million in
annual rate increases and was allowed $2.9 million.
From 1992 through 1994 our Heater Utilities subsidiary has been granted
annual water utility rate increases totaling $1.6 million of $2.4 million
requested since 1991 from regulatory authorities in North Carolina and South
Carolina. Rate decisions are expected by mid-1995 on additional requested rate
increases totaling $334,000. Heater is filing for rate increases affecting
about 19,000 customers in North Carolina early in 1995.
SSU's earnings reflected the sale of our water and wastewater facilities
at Venice Gardens to Sarasota County for $37.6 million, resulting in a $19.1
million gain.
This sale was negotiated in anticipation of an eminent domain action by
the County, which is purchasing private utilities in an effort to consolidate
services. Venice Gardens has about 15,500 customers.
In October 1994 SSU requested approval from the FPSC to buy Orange Osceola
Utilities, Inc. for about $13 million. Orange Osceola serves 17,000 customers
in a 2,800-acre residential development near Kissimmee, Fla., close to Walt
Disney World. SSU expects to conclude this acquisition in mid-1995.
<TABLE>
Revenue from Water Utility Operations
Millions of Dollars
(Graphic material omitted.)
<CAPTION>
1992 1993 1994
<S> <C> <C> <C>
Water 35.5 42.0 45.4
Wastewater 13.0 20.2 23.5
Sanitation 4.7 3.2 3.1
Gain on Sale of Assets 0.4 0.0 19.2
---- ---- ----
53.6 65.4 91.2
</TABLE>
The sale of our Venice Gardens facilities gave a lift to revenue in 1994, but
above-average rainfall cut water use in Florida and doused prospects for a
better return from ongoing water utility operations.
<TABLE>
Number of Water Utility Customers
In Thousands
(Graphic material omitted.)
<CAPTION>
1992 1993 1994
<S> <C> <C> <C>
Water 140.1 142.3 139.0
Wastewater 50.9 52.6 46.7
Sanitation 11.2 11.5 11.8
----- ----- -----
202.2 206.4 197.5
</TABLE>
Our water utility customer base shrank by 15,500 in 1994 with the sale of our
Venice Gardens water facilities to Sarasota County, Fla. Our pending purchase
of a utility in Kissimmee, near Walt Disney World, would add roughly that many
customers in 1995.
Upgrading Our Water Systems
1994 Florida Capital Expenditures
To meet regulatory requirements.........$11.2 million
To meet growth demands...................$6.9 million
To improve quality of service............$2.3 million
Other....................................$3.2 million
Total...................................$23.6 million
17
<PAGE>
1994 Financial Performance
Above-normal rainfall in Florida and customer conservation curtailed water
consumption in 1994, dampening anticipated returns from water utility
operations.
Although net income from continuing operations increased from 1993, it
still fell short of authorized rates of return. Narrowing the gap between
actual and allowed earnings is a continuing challenge. Without the gain from
the sale of the Venice Gardens facilities, SSU's return on equity in 1994 would
have been 2.8%.
In contrast to Florida's heavy rainfall, 1994 was a dry year in the
Carolinas, helping Heater Utilities achieve an 8.6% average return on equity.
Heater recorded about 5% growth in its overall customer base, which included
7.5% growth in the Raleigh-Durham area.
Heater may lose 3,300 customers in an eminent domain action begun in
January 1995 for its Seabrook, S.C., assets. The price Heater will receive
will be determined by court proceedings.
[REPRODUCTION OF NEWSPAPER CLIPPINGS FROM THE ORLANDO SENTINEL ARTICLES "RAIN
BRINGS TROUBLES TO ALL PARTS OF STATE" AND "IT HAS RAINED, IT HAS POURED
THROUGHOUT '94."]
1994 rainfall was 41% above average in the Orlando area, decreasing water
consumption and lowering SSU revenue. Authorities cautioned, however, that this
temporary replenishment of the Florida aquifer does not reduce the need for
continuing water management, conservation and action to address the sources of
the state's long-term water deficit.
[PHOTO OF RICH SULLO]
Works Better, Costs Less
Treatment of drinking water distributed by SSU includes adding a trace of
chlorine. When the Florida Department of Environmental Protection ordered
utilities to install chlorination alarms on unattended water facilities, Rich
Sullo, who works at SSU's Deltona Lakes Plant, had a better idea. He designed
an alarm system that assures proper chlorination and, if there's a problem,
shuts down the well and electronically notifies the main plant. This saves time
and water while maintaining quality standards. Commercially available alarms
monitor chlorine levels but lack the shutdown feature and cost three times as
much.
Comparing Financial Results from 1994, 1993 and 1992
The sale of Venice Gardens assets contributed a $19.1 million gain to
water utility operations revenue and income. Operating revenue increased
slightly due to new rates. Consumption levels in 1994 were 8% lower than 1993,
reflecting abnormally high rainfall in Florida during most of the last half of
the year.
SSU and Heater had combined net income of $13.3 million in 1994, $1.4
million in 1993 and a net loss of $2.3 million in 1992. The revenue from water
and wastewater treatment services increased approximately 8% in 1993 because of
higher water rates that have become effective at various dates since June 1992.
18
<PAGE>
INVESTMENTS AND CORPORATE SERVICES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For many years non-utility investments have contributed substantially to
Minnesota Power earnings. Their mission is twofold:
. To achieve a higher rate of return on investments than we are
limited to in the regulated sectors of our business; and,
. To keep funds available for reinvestment in existing businesses or
the acquisition of new businesses.
Over the past decade, our securities investment portfolio has contributed
more than $150 million in earnings. However, its contributions declined
significantly in 1994.
Reflecting the volatility of financial markets during the year, some of
the stocks in the portfolio declined in value. A more disturbing development,
however, was a $10.1 million, or 21-cent-per-share write-off of one specific
investment. The investment had been designed to protect the Company against
fluctuations caused by interest rate volatility, but we believe the fund
manager failed to follow the stated investment strategy and exposed the fund to
rising interest rates.
Investments and Corporate Services also includes our investment in Capital
Re Corp., a leading U.S. reinsurer of municipal bonds and other financial
guarantees.
While this firm primarily focuses on municipal bonds, it also reinsures
non-municipal debt obligations and private mortgages.
Primary insurance companies buy reinsurance from Capital Re to guarantee
the timely payment of principal and interest on investment-quality debt. Bonds
reinsured by Capital Re automatically receive an upgrade to a AAA credit
rating, which lowers the issuers' interest costs and provides an additional
level of comfort to investors. Minnesota Power owns 21% of Capital Re and
appoints two members of its board of directors.
Minnesota Power also owns 80% of Lehigh Acquisition Corp., which has
contributed substantially to our earnings in recent years.
Its real estate properties include 8,100 undeveloped home sites and an
additional 5,000 acres of unimproved property near and in the community of
Lehigh Acres, which is about 15 miles east of Fort Myers, Fla.
During the year, the community was enhanced by the opening of Lehigh
Senior High School on a site largely donated by the company. A massive new Wal-
Mart Center, roughly three times the size of a typical Wal-Mart outlet, is
under construction at a site near where Lehigh owns most of the remaining
commercially zoned land. A new medical center has also opened, and Lehigh
continues to recruit businesses for the community's industrial park.
Lehigh sells properties to certified developers who build and sell well-
designed, affordable homes.
Because Lehigh Acres is primarily an affordable first home and retirement
community, growth is partly driven by the ability of retirees in the Midwest
and Northeast to sell their existing homes. Rising economies in those areas
should boost sales. Also, with the introduction of direct flights from Germany
to Florida, Lehigh Acres is becoming a flourishing German community, complete
with German restaurants and newspapers, and German-speaking customer service
personnel.
In 1994 Lehigh formalized procedures to begin constructing $5.2 million in
water and wastewater facilities in Lehigh Acres using funds held in escrow. The
funds are restricted for payment of such construction expenditures. Based on
revised procedures, which accelerated use of the funds, and plans to build the
facilities over the next five years, Lehigh recognized approximately $4.5
million of income in March 1994. The Company's share of this income totaled
$3.6 million.
Lehigh, which contributed $10.2 million to corporate earnings in 1994,
continues to be highly profitable for Minnesota Power. The plan is to sell the
Lehigh property as opportunities arise. We anticipate the sales will be
completed over the next five years.
Income could receive a boost in 1995 from real estate-related tax benefits
that came with Minnesota Power's purchase of Lehigh Corp. in 1991. The
benefits are recorded on Lehigh's books as $26.9 million of net deferred tax
assets, offset by a reserve. In keeping with established accounting
principles, management reviews the assets quarterly; when it's deemed "more
likely than not" that any portion of them will be realized, that portion will
be recognized as income and the reserve reduced accordingly. A portion of the
assets may be recognized as income in 1995 as Lehigh reviews its business plan,
including the timing and sale of its real estate holdings.
19
<PAGE>
Lake Superior Paper Industries, jointly owned by subsidiaries of Pentair,
Inc. and Minnesota Power, rebounded in fourth quarter 1994 from the weak prices
of recent years.
Demand for its supercalendered groundwood paper is at a historical peak.
Economic recovery in Europe aided LSPI's turnaround by providing a market for
Finnish paper that had in recent years been shipped to the United States,
depressing prices here.
LSPI production for the year reached the record level of 241,000 tons,
exceeding the mill's designed capacity. Productivity outpaced all competing
supercalendered paper machines and resulted in the company's being named the
world's most efficient SCA mill. The eight-year-old mill achieved this without
investing additional capital. Breakthroughs came about as a result of empowered
employees continually finding better, more efficient ways of getting things
done.
LSPI should be able to capitalize on the favorable paper market industry
experts project to continue through at least 1996. No new paper-making
machines are scheduled to begin operations in that time period, and paper
prices have increased by 14 percent since September 1994. LSPI's goals are to
continually improve productivity and to further reduce costs while providing
high-quality customer service.
When we decided to go into the joint venture that led to the start-up of
LSPI, our goals were to create jobs, gain a new industrial customer for our
electric utility business, launch a business with expansion potential, and earn
a profit on our investment. These goals have largely been achieved. The plant
provides more than 300 jobs in the mill plus another 300 in logging and
trucking. It requires 48 megawatts of power.
Therefore, should a favorable opportunity arise through our joint venture
partner's pursuit of a sale of its interest in LSPI, Minnesota Power would
consider a sale of its interest. Among factors that would influence us in
favor of a sale would be the expectation that the new owner would ultimately
expand the mill to its full potential.
If LSPI is sold, the deal might also include the sale of Superior Recycled
Fiber Industries, the pulp production plant that is adjacent to and operated by
LSPI.
SRFI produces recycled pulp from office scrap paper. Commercial
operations began at SRFI in November 1993. It produced 84,000 tons of recycled
pulp and contributed $906,000 to Minnesota Power earnings in 1994.
As expected, demand for recycled paper gathered further momentum during the
year, and this in turn spurred intense production efforts at SRFI.
The $78 million plant produces high-quality recycled pulp for making
printing papers, such as Potlatch Corporation's Quintessence RemarqueTM used in
this report.
SRFI's production rate at the end of 1994 exceeded the plant's designed
capacity of 247 tons per day. The demand for recycled pulp will likely continue
to rise as federal agency requirements for copying paper containing at least
[PHOTO OF MIKE COCHRAN, MARY SCHOENROCK, JOLYNN NILSON, KARLA STROMBECK, RUSS
SCHUMACHER, AND DIANE STUART]
Improving Customer Service Spawns a New Business
"Know thy customer" is good advice for any business, and technology is helping
us do this. In 1989 we formed a team to evaluate potential new customer
information computer programs for our utility businesses. None of the available
options satisfied the standards set by our team, so they designed their own
system. After four years of hard work, Minnesota Power's Customer Information
System is not only on-line and performing well, it is being profitably licensed
to other companies around the world. Pictured, from left: Mike Cochran, Mary
Schoenrock, JoLynn Nilson, Karla Strombeck, Russ Schumacher, and Diane Stuart
helped organize and manage the project.
20
<PAGE>
20% post-consumer waste take effect. SRFI's production is virtually sold out
through 1995.
SRFI's goal is to increase production further by eliminating bottlenecks
and further improving efficiency.
The chief challenge to further expansion of SRFI's business is the
procurement of scrap paper. SRFI recycles nearly 10% of all office scrap paper
collected in the United States. Although office sector sources are reasonably
well developed, at least half of all scrap paper suitable for recycling is in
private homes and no systematic means of recapturing it exists at this time.
[PHOTO OF DAVE EVENS]
Baffling the Bubbles
At the front end of LSPI's paper machine, there's a large cylindrical tank
called a Deculator, where air bubbles are removed from water that carries pulp
into the machine. Too many bubbles cause defects in the paper. Bubbles and
turbulence problems had been increasing last year as LSPI sped up the machine.
So LSPI's Dave Evens built a plastic replica of the Deculator to learn what was
causing the excess turbulence, then designed modifying baffles to correct the
problem. Now the machine runs faster, LSPI is saving $35,000 a year on
defoaming additives, and the Finnish manufacturer of the Deculator is paying
our mill an annual royalty on the improvement: U.S. Patent No. 5,236,475.
Comparing Financial Results from 1994, 1993 and 1992
Income from the Company's investments declined $19.7 million in 1994
primarily due to unfavorable conditions in the securities markets and a 21-
cent-per-share write-off of the Company's $10.1 million investment in Granite
Partners, a limited partnership that filed for bankruptcy protection in 1994.
Capital Re contributed positively all three years. Investments and reinsurance
income was $13.4 million lower in 1993 than in 1992, reflecting the adoption of
new accounting principles, lower returns due to market conditions, and a $5.1
million gain from the redemption by the issuer of a preferred stock investment
in 1992.
Investment income includes revenue of $31.7 million in 1994, $31 million
in 1993, and $28.7 million in 1992 from operations and the sale of certain
assets by Lehigh.
In December 1992, $15.5 million of debt issued for the purchase of the
real estate properties and operations was extinguished, and Lehigh assumed some
contingent liabilities for which it had previously been indemnified by the
previous owner. This transaction resulted in a non-taxable extraordinary gain
to Lehigh of approximately $7.2 million. The Company's two-thirds share of this
gain contributed 16 cents to earnings per share in 1992.
LSPI returned to profitability in 1994, earning $3.1 million pre-tax,
compared with a pre-tax loss of $3.7 million in 1993 and pre-tax income of $3.4
million in 1992. LSPI had total sales of $152 million in 1994, $143 million in
1993, and $150 million in 1992. The mill shipped 241,000 tons of paper in
1994, compared with 235,000 tons in 1993, and 220,000 tons in 1992. The
Company's share of LSPI's pre-tax income was $1.5 million in 1994, compared
with a $1.8 million pre-tax loss in 1993, and $1.7 million pre-tax income in
1992.
The Company has an 82.5% ownership interest in Reach All, a manufacturer
of specialized truck-mounted lifting equipment used by utilities and
governmental entities. The Company recognized Reach All pre-tax losses of $5.2
million in 1994, $764,000 in 1993, and $3.1 million in 1992.
21
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As detailed in the consolidated statement of cash flows, cash flows from
operating activities in 1994 were affected by a number of factors
representative of normal operations.
The Company's Automatic Dividend Reinvestment and Stock Purchase Plan
(DRIP) was amended in January 1993 to allow the DRIP to meet its needs by
purchasing original-issue common shares from the Company or buying common
shares on the open market. The DRIP has been buying on the open market since
January 1994.
In 1994 SSU sold $10.3 million of inter-local tax-exempt bonds to finance
several water projects in Florida. The bonds carry a variable interest rate
currently at 3 1/2%. A portion of the proceeds from the Venice Gardens utility
sale was used to redeem SSU's $15 million of First Mortgage Bonds, 15 1/2%
Series due 1994.
The Company estimates its capital requirements through 2000 will be met
primarily with internally generated funds.
Working capital, if and when needed, generally is provided by the sale of
commercial paper. In addition, securities investments can be liquidated to
provide funds for reinvestment in existing businesses or acquisition of new
businesses, and approximately 900,000 original-issue shares of common stock are
available for issuance through the DRIP. If the ADESA transaction is approved
by ADESA shareholders, cash from the liquidation of investments is expected to
be used for the $167 million purchase.
The Company is committed to guarantee a portion of LSPI's lease obligation
to a maximum of $95 million and expects that short-term loans to LSPI will
fluctuate during 1995 but may approximate the $35 million note receivable
outstanding as of Dec. 31, 1994.
Minnesota Power's electric utility first mortgage bonds and secured
pollution control bonds are currently rated the following investment grades:
A3 by Moody's Investor Service, A- by Standard & Poor's, and A by Duff &
Phelps. The disclosure of these security ratings is not a recommendation to
buy, sell or hold the Company's securities.
In 1994 capital expenditures in our electric business consisted of routine
plant improvements and upgrades. Our power supply and projected demand are in
balance.
No new power plants or major changes to existing plants are expected in
the 1995-2009 period. Future water utility capital expenditures include
facility upgrades to meet environmental standards and new water and wastewater
treatment facilities to accommodate customer growth.
Consolidated capital expenditures in 1994 totaled $81 million, including
$45 million for the electric utility operations, $28 million for the water
utility operations, $3 mil-
[PHOTO OF JOAN ADLER]
The Value of Safety
Lehigh Acquisition Corporation, our Florida real estate affiliate, employs
people in building trades, site preparation, road construction and other jobs
considered high-risk by insurers. Determined to do something about accidents
and high workers' compensation premiums, Lehigh's Joan Adler designed a safety
incentive program that slashed accident rates, lowered premiums, and garnered a
premium refund of $99,116 in 1994. Another refund is expected in '95.
22
<PAGE>
lion for the pulp production plant, and $5 million for an affordable housing
project. Internally generated funds were used for capital expenditures for the
electric business. Water utility and affordable housing capital expenditures
were funded through long-term financing and with inter-
nally generated funds.
Capital expenditures are expected to be $65 million in 1995 and total
about $232 million for 1996 through 1999. The 1995 amount includes $30 million
for routine electric capital expenditures, $26 million for upgrades, water
reuse projects and new water facilities, and $9 million for coal mining
equipment and other capital expenditures. The Company expects to finance the
majority of its capital expenditures with internally generated funds.
We increased our common dividend in January 1995, the 25th consecutive
annual increase.
In 1994 the Company paid out 98% of its per-share earnings in dividends.
Given the lack of major construction needs and the liquidity of our securities
investment portfolio, we do not believe this high payout ratio to be
detrimental in the short run.
Over the longer term, Minnesota Power's goal is to reduce dividend payout
to 70% of earnings. We expect to do this by increasing earnings rather than
reducing dividends. Our goal is for earnings per share to grow from their 1994
level of $2.06 to a minimum of $3.25 by the year 2000. Our corporate strategic
plan calls for about one-third of earnings to come from electric utility
operations, another third from water utility operations, and the remainder from
our Investments and Corporate Services area.
<TABLE>
Capital Spending
Millions of Dollars
(Graphic material omitted.)
<CAPTION>
1992 1993 1994
<S> <C> <C> <C>
Electric Utility 45 58 45
Water Utility 32 20 28
Investments and
Corporate Services 32 43 9
--- --- --
109 121 82
</TABLE>
In 1994 capital spending totaled $81 million, 31% less than the previous year.
<TABLE>
Projected Capital Spending
(Graphic material omitted.)
<CAPTION>
1995 1996 1997 1998 1999
<S> <C> <C> <C> <C> <C>
Millions of Dollars 65 61 57 57 57
</TABLE>
Capital spending for the 1995-99 period is expected to average 39% below the
levels of the past five years. Most will be funded from internal sources.
<TABLE>
Price Ranges and Dividends Paid Per Share
<CAPTION>
New York Stock Exchange American Stock Exchange
---------------------------- ---------------------------
Common 5% Series Preferred
---------------------------- ---------------------------
Dividends Dividends
Quarter High Low Paid High Low Paid
---------------- ----- ----- ---------- ---- --- ----------
<S> <C> <C> <C> <C> <C> <C>
1994 - First $33 $28 $0.505 $73 $68 $1.25
Second 30 1/8 25 0.505 68 1/2 61 1.25
Third 28 1/8 25 0.505 64 60 1/4 1.25
Fourth 26 5/8 24 3/4 0.505 64 55 1.25
------ -----
Annual $2.02 $5.00
1993 - First $36 1/2 $32 5/8 $0.495 $72 1/2 $62 $1.25
Second 36 3/8 34 0.495 71 68 1/2 1.25
Third 36 1/2 35 1/4 0.495 73 1/2 69 1/4 1.25
Fourth 35 1/2 30 0.495 74 68 1/2 1.25
------ -----
Annual $1.98 $5.00
<CAPTION>
American Stock Exchange
----------------------------
$7.36 Series Preferred
----------------------------
Dividends
Quarter High Low Paid
---------------- ----- ----- ----------
<S> <C> <C> <C>
1994 - First $105 $100 $1.84
Second 101 93 3/4 1.84
Third 96 88 3/4 1.84
Fourth 91 5/8 84 3/4 1.84
-----
Annual $7.36
1993 - First $100 $95 1/2 $1.84
Second 103 97 1.84
Third 105 100 1.84
Fourth 104 99 1.84
-----
Annual $7.36
</TABLE>
The Company has paid dividends without interruption on its common stock since
1948, the date of initial distribution of the Company's common stock by
American Power & Light Company, the former holder of all such stock. Listed
above are dividends paid per share and the high and low prices for the
Company's common and preferred stock as reported by The Wall Street Journal,
Midwest Edition. On Dec. 31, 1994, there were approximately 27,000 common stock
shareholders. On Jan. 25, 1995, the Board of Directors declared a quarterly
dividend of 51 cents, payable March 1, 1995, to common stock shareholders of
record on Feb. 15, 1995.
23
<PAGE>
REPORTS
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Independent Accountant
To the Shareholders and
Board of Directors of Minnesota Power
In our opinion, the accompanying consolidated balance sheet and the
related consolidated statements of income, of retained earnings and of cash
flows present fairly, in all material respects, the financial position of
Minnesota Power and its subsidiaries 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. These financial statements are the responsibility of the
Company's management; our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our audits of these
statements in accordance with generally accepted auditing standards which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for the opinion expressed above.
Effective January 1, 1993, the Company changed its method of accounting
for income taxes and the employee stock ownership plan as discussed in Notes 13
and 15, respectively, to the consolidated financial statements.
Price Waterhouse LLP
Minneapolis, Minnesota
January 24, 1995
Management
The consolidated financial statements and other financial information were
prepared by management, which is responsible for their integrity and
objectivity. The financial statements have been prepared in conformity with
generally accepted accounting principles as applied to regulated utilities and
necessarily include some amounts that are based on informed judgments and best
estimates of management.
To meet its responsibilities with respect to financial information,
management maintains and enforces a system of internal accounting controls
designed to provide assurance, on a cost effective basis, that transactions are
carried out in accordance with management's authorizations and that assets are
safeguarded against loss from unauthorized use or disposition. The system
includes an organizational structure which provides an appropriate segregation
of responsibilities, careful selection and training of personnel, written
policies and procedures, and periodic reviews by the internal audit department.
In addition, the Company has a personnel policy which requires all employees to
maintain a high standard of ethical conduct. Management believes the system is
effective and provides reasonable assurance that all transactions are properly
recorded and have been executed in accordance with management's authorization.
Management modifies and improves its system of internal accounting controls in
response to changes in business conditions. The Company's internal audit staff
is charged with the responsibility for determining compliance with Company
procedures.
Five directors of the Company, not members of management, serve as the
Audit Committee. The Board of Directors, through its Audit Committee, oversees
management's responsibilities for financial reporting. The Audit Committee
meets regularly with management, the internal auditors and the independent
accountants to discuss auditing and financial matters and to assure that each
is carrying out its responsibilities. The internal auditors and the independent
accountants have full and free access to the Audit Committee without management
present.
Price Waterhouse LLP, independent accountants, is engaged to express an
opinion on the financial statements. Their audit is conducted in accordance
with generally accepted auditing standards and includes a review of internal
controls and a test of transactions to the extent necessary to allow them to
report on the fairness of the operating results and financial condition of the
Company.
Arend Sandbulte
Arend J. Sandbulte
Chairman and President
David G. Gartzke
David G. Gartzke
Chief Financial Officer
24
<PAGE>
CONSOLIDATED FINANCIAL STATEMENTS
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
<TABLE>
Minnesota Power
Consolidated Balance Sheet
<CAPTION>
December 31 1994 1993
---------------------------------------------------------------------------
In thousands
<S> <C> <C>
Assets
Plant and Other Assets
Electric utility operations $ 784,931 $ 780,207
Water utility operations 295,451 303,714
Investments and corporate services 362,006 319,924
---------- ----------
Total plant and other assets 1,442,388 1,403,845
---------- ----------
Current Assets
Cash and cash equivalents 27,001 31,674
Trading securities 74,046 98,244
Trade accounts receivable
(less reserve of $1,041 and $1,565) 51,105 50,336
Notes and other accounts receivable 61,654 48,362
Fuel, material and supplies 26,405 20,764
Prepayments and other 25,927 22,589
---------- ----------
Total current assets 266,138 271,969
---------- ----------
Deferred Charges
Regulatory 74,919 59,917
Other 24,353 24,795
---------- ----------
Total deferred charges 99,272 84,712
---------- ----------
Total Assets $1,807,798 $1,760,526
----------------------------------------------------------------------------
Capitalization and Liabilities
Capitalization
Common stock without par value, 65,000,000
shares authorized;
31,246,557 and 31,206,803
shares outstanding $ 371,178 $ 370,681
Unearned ESOP shares (76,727) (80,721)
Net unrealized gain (loss) on
securities investments (5,410) 1,488
Retained earnings 272,646 271,177
---------- ----------
Total common stock equity 561,687 562,625
Cumulative preferred stock 28,547 28,547
Redeemable serial preferred stock 20,000 20,000
Long-term debt 601,317 611,144
---------- ----------
Total capitalization 1,211,551 1,222,316
---------- ----------
Current Liabilities
Accounts payable 36,792 35,680
Accrued taxes 41,133 42,542
Accrued interest and dividends 14,157 13,812
Notes payable 54,098 20,475
Long-term debt due within one year 12,814 7,294
Other 23,799 10,542
---------- ----------
Total current liabilities 182,793 130,345
---------- ----------
Deferred Credits
Accumulated deferred income taxes 192,441 187,436
Contributions in aid of construction 87,036 97,190
Regulatory 55,996 60,520
Other 77,981 62,719
---------- ----------
Total deferred credits 413,454 407,865
---------- ----------
Commitments and Contingencies
---------- ----------
Total Capitalization and Liabilities $1,807,798 $1,760,526
---------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these statements.
25
<PAGE>
<TABLE>
Consolidated Statement of Income
<CAPTION>
For the year ended December 31 1994 1993 1992
------------------------------------------------------------------------------
In thousands except per share amounts
<S> <C> <C> <C>
Operating Revenue and Income
Electric utility operations $453,182 $457,719 $449,803
Water utility operations 91,224 65,463 53,595
Investments and corporate services 93,376 66,425 72,799
-------- -------- --------
Total operating revenue and income 637,782 589,607 576,197
-------- -------- --------
Operating Expenses
Fuel and purchased power 157,687 170,277 168,483
Operations 270,604 215,066 193,155
Administrative and general 79,922 75,091 75,986
Interest expense 52,070 43,534 47,479
-------- -------- --------
Total operating expenses 560,283 503,968 485,103
-------- -------- --------
Income from Equity Investments 5,300 3,929 4,352
-------- -------- --------
Operating Income 82,799 89,568 95,446
Income Tax Expense 21,466 26,947 26,989
-------- -------- --------
Income Before Extraordinary Item 61,333 62,621 68,457
Extraordinary gain on early
extinguishment of debt - - 4,831
-------- -------- --------
Net Income 61,333 62,621 73,288
Dividends on preferred stock (3,200) (3,342) (3,807)
Tax benefits of ESOP dividends - - 3,206
-------- -------- --------
Earnings Available for Common Stock $ 58,133 $ 59,279 $ 72,687
-------- -------- --------
Average Shares of Common Stock 28,239 26,987 29,442
Earnings Per Share of Common Stock
Before extraordinary item $2.06 $2.20 $2.31
Extraordinary item - - 0.16
-------- -------- --------
Total earnings per share $2.06 $2.20 $2.47
Dividends Per Share of Common Stock $2.02 $1.98 $1.94
------------------------------------------------------------------------------
</TABLE>
<TABLE>
Consolidated Statement of Retained Earnings
<CAPTION>
For the year ended December 31 1994 1993 1992
------------------------------------------------------------------------------
In thousands
<S> <C> <C> <C>
Balance at Beginning of Year $271,177 $265,648 $252,926
Net income 61,333 62,621 73,288
Redemption and retirement of stock - (425) (2,847)
Tax benefits of ESOP dividends - - 3,206
-------- -------- --------
Total 332,510 327,844 326,573
-------- -------- --------
Dividends Declared
Preferred stock 3,200 3,342 3,807
Common stock 56,664 53,325 57,118
-------- -------- --------
Total 59,864 56,667 60,925
-------- -------- --------
Balance at End of Year $272,646 $271,177 $265,648
------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these statements.
26
<PAGE>
<TABLE>
Consolidated Statement of Cash Flows
<CAPTION>
For the year ended December 31 1994 1993 1992
------------------------------------------------------------------------------
In thousands
<S> <C> <C> <C>
Operating Activities
Net income $ 61,333 $ 62,621 $ 73,288
Depreciation 50,236 43,508 39,071
Amortization of coal contract
termination costs 3,920 18,460 14,553
Deferred income taxes 6,201 5,517 1,940
Deferred investment tax credits (2,478) (2,035) (1,568)
Pre-tax gain on sale of plant assets (19,147) (812) (360)
Extraordinary gain on early
extinguishment of debt - - (4,831)
Changes in operating assets and
liabilities
Notes and accounts receivable (14,061) (11,999) (21,623)
Fuel, material and supplies (5,641) 4,226 7,513
Accounts payable 1,112 (1,170) 1,628
Other current assets and
liabilities 29,133 2,473 (12,421)
Other deferred credit - unbilled
revenue - (5,070) 5,070
Other - net 5,857 7,024 (3,946)
------- ------- -------
Cash from operating activities 116,465 122,743 98,314
------- ------- -------
Investing Activities
Proceeds from sale of investments
in securities 59,339 242,950 275,284
Proceeds from sale of plant 37,361 6,584 2,745
Additions to investments (97,620) (266,276) (243,296)
Additions to plant (80,161) (68,156) (72,782)
Changes to other assets - net (10,699) (54,763) (31,215)
------- ------- -------
Cash for investing activities (91,780) (139,661) (69,264)
------- ------- -------
Financing Activities
Issuance of common stock 1,033 57,605 892
Issuance of long-term debt 21,982 171,571 295,286
Issuance of preferred stock - - 20,000
Changes in notes payable 33,623 (33,496) 24,105
Reductions of long-term debt (26,132) (105,256) (294,073)
Redemption of preferred stock - (2,000) (25,248)
Dividends on preferred and common stock (59,864) (56,667) (60,925)
Reacquired and retired common stock - - (1,567)
------- ------- -------
Cash (for) from financing
activities (29,358) 31,757 (41,530)
------- ------- -------
Change in Cash and Cash Equivalents (4,673) 14,839 (12,480)
Cash and Cash Equivalents at
Beginning of Period 31,674 16,835 29,315
------- ------- -------
Cash and Cash Equivalents at End of Period $ 27,001 $ 31,674 $ 16,835
-------- -------- --------
Supplemental Cash Flow Information
Cash paid during the period for
Interest (net of capitalized) $48,385 $41,840 $45,337
Income taxes $20,584 $24,490 $21,344
Noncash Investing and Financing Activities
(Note 2)
------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these statements.
27
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1 Business Segments
-------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Thousands Electric Water Utility
Consolidated Utility Operations Operations
------------ ------------------ -------------
For the Year Ended Dec. 31 Electric Coal
-------------------------- -------- ----
<S> <C> <C> <C> <C>
1994
Revenue and income $ 637,782 $426,183 $26,999 $ 91,224 <F1>
Operation and other expense 457,977 313,560 20,438 47,754
Depreciation expense 50,236 35,094 1,352 8,936
Interest expense 52,070 19,057 1,035 12,214
Income from equity investments 5,300 - - -
---------- -------- ------- --------
Operating income (loss) 82,799 58,472 4,174 22,320
Income tax expense (benefit) 21,466 23,140 1,114 8,733
---------- -------- ------- --------
Net income (loss) $ 61,333 $ 35,332 $ 3,060 $ 13,587
---------- -------- ------- --------
Capital expenditures $ 80,953 $ 42,705 $ 1,957 $ 27,636
Total assets $1,807,798 $933,784 $28,353 $326,015
Accumulated depreciation $ 582,075 $471,285 $17,598 $ 88,404
Construction work in progress $ 27,619 $ 21,736 - $ 5,883
------------------------------------------------------------------------------------------------
1993
Revenue and income $ 589,607 $433,117 $24,602 $ 65,463
Operation and other expense 415,839 318,813 18,609 42,550
Depreciation expense 44,595 32,774 1,095 9,792
Interest expense 43,534 18,860 1,024 9,997
Income from equity investments 3,929 - - -
---------- -------- ------- --------
Operating income (loss) 89,568 62,670 3,874 3,124
Income tax expense (benefit) 26,947 25,120 1,150 1,055
---------- -------- ------- --------
Net income (loss) $ 62,621 $ 37,550 $ 2,724 $ 2,069
---------- -------- ------- --------
Capital expenditures $ 120,696 $ 50,992 $ 6,670 $ 19,635
Total assets $1,760,526 $910,039 $27,998 $329,578
Accumulated depreciation $ 546,706 $443,285 $16,097 $ 86,609
Construction work in progress $ 31,227 $ 18,019 - $ 13,208
------------------------------------------------------------------------------------------------
1992
Revenue and income $ 576,197 $426,042 $23,761 $ 53,595
Operation and other expense 398,139 308,024 18,426 40,002
Depreciation expense 39,485 30,902 881 7,530
Interest expense 47,479 27,504 958 8,343
Income from equity investments 4,352 - - -
---------- -------- ------- --------
Operating income (loss) 95,446 59,612 3,496 (2,280)
Income tax expense (benefit) 26,989 18,849 1,007 (681)
Extraordinary item 4,831 - - -
---------- -------- ------- --------
Net income (loss) $ 73,288 $ 40,763 $ 2,489 $ (1,599)
---------- -------- ------- --------
Capital expenditures $ 109,432 $ 43,559 $ 1,562 $ 32,224
Total assets $1,625,504 $865,787 $22,806 $321,659
Accumulated depreciation $ 509,542 $419,751 $14,803 $ 74,971
Construction work in progress $ 28,552 $ 19,524 - $ 9,028
------------------------------------------------------------------------------------------------
<CAPTION>
Thousands
Investments and Corporate Services
----------------------------------------
Portfolio,
Reinsurance Paper &
For the Year Ended Dec. 31 & Other Real Estate Pulp
-------------------------- ----------- ----------- -------
<S> <C> <C> <C>
1994
Revenue and income $ 8,462 <F2> $31,653 $ 53,261
Operation and other expense 9,583 20,510 46,132
Depreciation expense 78 276 4,500
Interest expense 16,226 12 3,526
Income from equity investments 2,973 <F3> - 2,327
-------- ------- --------
Operating income (loss) (14,452) 10,855 1,430
Income tax expense (benefit) (12,597) 691 385
-------- ------- --------
Net income (loss) $ (1,855) $10,164 <F4> $ 1,045
-------- ------- --------
Capital expenditures $ 4,889 $569 $ 3,197
Total assets $308,612 $35,900 $175,134
Accumulated depreciation $ 74 - $ 4,714
Construction work in progress - - -
-----------------------------------------------------------------------------
1993
Revenue and income $ 29,570 $31,029 $ 5,826 <F5>
Operation and other expense 6,946 22,523 6,398
Depreciation expense 6 230 698
Interest expense 12,839 15 799
Income from equity investments 5,795 - (1,866)
-------- ------- --------
Operating income (loss) 15,574 8,261 (3,935)
Income tax expense (benefit) (371) 1,861 (1,868)
-------- ------- --------
Net income (loss) $ 15,945 $ 6,400 $ (2,067)
-------- ------- --------
Capital expenditures - - $ 43,399
Total assets $301,548 $31,801 $159,562
Accumulated depreciation - - $ 715
Construction work in progress - - -
-----------------------------------------------------------------------------
1992
Revenue and income $ 44,137 $28,662
Operation and other expense 9,233 21,387 $ 1,067
Depreciation expense 1 163 8
Interest expense 8,694 1,744 236
Income from equity investments 2,682 - 1,670
-------- ------- --------
Operating income (loss) 28,891 5,368 359
Income tax expense (benefit) 7,606 - 208
Extraordinary item - 4,831 <F6> -
-------- ------- --------
Net income (loss) $ 21,285 $10,199 $ 151
-------- ------- --------
Capital expenditures - - $ 32,087
Total assets $290,667 $31,633 $ 92,952
Accumulated depreciation - - $ 17
Construction work in progress - - -
-----------------------------------------------------------------------------
<FN>
<F1> Includes a $19.1 million pre-tax gain from the sale of certain water
plant assets.
<F2> Includes a $10.1 million pre-tax loss from the write-off of an
investment.
<F3> Includes a $5.2 million pre-tax loss from the equipment manufacturing
business.
<F4> Includes $3.6 million of net income related to escrow funds.
<F5> Pulp mill operations began in November 1993.
<F6> The extraordinary gain is a result of an early extinguishment of debt.
</FN>
</TABLE>
28
<PAGE>
2 Summary of Significant Accounting Policies
System of Accounts. The accounting records of Minnesota Power are
maintained in accordance with generally accepted accounting principles.
Principles of Consolidation. The consolidated financial statements
include the accounts of the Company and all of its majority owned subsidiary
companies. All material intercompany balances and transactions between
subsidiaries have been eliminated in consolidation. The prior years
consolidated financial statements have been reclassified to present comparable
information for all years.
Plant and Depreciation. Plant is recorded at original cost. The cost of
additions to plant and replacement of retirement units of property are
capitalized. Maintenance costs and replacements of minor items of property are
charged to expense as incurred. Costs of depreciable units of plant retired are
eliminated from the plant accounts. Such costs plus removal expenses less
salvage are charged to accumulated depreciation. Plant stated on the balance
sheet includes construction work in progress and is net of accumulated
depreciation. (See note 1.)
Various pollution abatement facilities are leased from municipalities
which have issued pollution control revenue bonds to finance the cost of the
facilities. The cost of the facilities and the related debt obligation, which
is guaranteed by the Company, has been recorded as electric plant and long-term
debt, respectively.
Depreciation of utility plant is computed using rates based on estimated
useful lives of the various classes of property. Provisions for book
depreciation of the average original cost of depreciable property approximated
3% in 1994, 2.9% in 1993 and 2.7% in 1992. In 1995 the Company will begin
recovering through rates approved by the MPUC in November 1994 approximately
$1.3 million each year to pay for decommissioning of coal-fired power plants.
Contributions in aid of construction (CIAC), recorded at estimated
original cost, relate to water and wastewater plant contributed to the Company
by developers and customers. CIAC is amortized on the straight-line method over
the estimated life of the asset to which it relates when placed in service.
Amortization of CIAC reduces depreciation expense.
The Company's water plant includes plant held for future use which
consists primarily of distribution and collection systems that will be placed
in service as additional customers are connected to the systems. These systems
are not depreciated until placed in service. The Company had $34.9 and $35.2
million of plant held for future use at Dec. 31, 1994 and 1993. CIAC funded
approximately $21 million of plant held for future use in 1994 and 1993.
Fuel, Material and Supplies. Fuel, materials and supplies are stated at
the lower of cost or market. Cost is determined by the average cost method.
Deferred Regulatory Charges and Credits. The Company is subject to the
provisions of SFAS 71, "Accounting for the Effects of Certain Types of
Regulation." The Company capitalizes as deferred regulatory charges incurred
costs which are expected to be recovered in future utility rates. Deferred
regulatory credits represent amounts expected to be credited to customers in
rates. (See note 3.)
Revenue and Income Recognition.
Electric Utility Operations. The Company files for periodic rate revisions
with the Minnesota Public Utilities Commission (MPUC), the Federal Energy
Regulatory Commission (FERC), and the Public Service Commission of Wisconsin.
The MPUC had regulatory authority over approximately 77% in 1994, 76% in 1993
and 79% in 1992 of the Company's total electric utility operations revenue.
Interim rates in Minnesota are placed into effect, subject to refund with
interest, pending a final decision by the MPUC.
Customer meters are read and bills are rendered on a cycle basis. Revenue
is accrued for service provided but not yet billed. The service rates of the
Company to all classes of customers include fuel adjustment clauses under which
fuel and purchased energy costs above or below the base levels in rate
schedules are billed or credited to customers. In addition, billings to retail
electric customers reflect an annual billing adjustment mechanism applied
monthly for recovery of CIP expenditures.
During 1994, 1993 and 1992, revenue derived from one major customer was
$60.2, $59.6 and $57.8 million, respectively. Revenue derived from another
major customer was $45.3, $45 and $47 million, respectively.
Water Utility Operations. The Company provides water service to
communities in Florida, North Carolina, South Carolina and Wisconsin. Water
rates are under the jurisdiction of various state and county regulatory
authorities. Billings are rendered on a cycle basis. Revenue is accrued for
water sold but not billed.
Investments and Corporate Services. Investments and corporate services
includes revenue from the sale of pulp and real estate, and income from
securities investments. Pulp and real estate revenue is recognized on the
accrual basis. Securities investments are accounted for in accordance with SFAS
115, adopted on Dec. 31, 1993. (See note 4.)
Income Taxes. Investment tax credits for utility property are amortized
over the service life of the related property. Deferred taxes are provided on
temporary differences between the book and tax basis of assets and liabilities
which will have a future impact on taxable income.
Unamortized Expense, Discount and Premium on Debt. Expense, discount and
premium on debt are deferred and amortized over the lives of the related
issues.
Statement of Cash Flows. The Company considers all investments purchased
with maturities of three months or less to be cash equivalents.
Noncash financing activities in 1994, 1993 and 1992 included $3.6, $3.7
and $2.7 million, respectively, relating to debt service on the ESOP promissory
note and the ESOP debt guaranteed by the Company. (See note 15.) Other noncash
financing activities in 1993 included the issuance of 140,648 shares of common
stock, with a market value at the time of issuance of approximately $4.9
million, in exchange for an additional 13.4% ownership interest in Lehigh.
29
<PAGE>
3 Regulatory Matters
Electric Utility Rate Proceedings. In January 1994 the Company filed with
the MPUC a request for a final annual rate increase from all retail electric
customers of $34 million, or 11.8%, and a 12.5% return on equity. In August
1994 the Company reduced its requested annual increase of $34 million to $27
million for 1994 and $23 million for 1995 because of reductions in the
projected cost of service and the addition of long-term contract commitments by
a taconite customer. On Feb. 17, 1994, the MPUC voted to approve the Company's
requested annual interim rate increase of $20 million, or 7%. This interim rate
increase began on March 1, 1994, subject to refund with interest, and will
continue until final rates are effective.
In November 1994, the MPUC granted the Company an increase in annual
electric operating revenue of $19 million and an 11.6% return on equity. Rates
for large industrial customers will increase less than 4%, while the rate for
small businesses will increase 6.5%. The rate increase for residential
customers will be phased in over three years: 13.5% beginning in 1995, 3.75% in
January 1996 and another 3.75% in January 1997. In 1994 the Company collected
$17.2 million of interim revenue subject to refund with interest. The Company
has reserved $6.1 million of the interim revenue for anticipated refunds. Final
rates are expected to be effective in the second quarter of 1995.
In January 1994 the Company began recovering ongoing 1994 CIP expenditures
and $8.2 million of deferred CIP expenditures incurred prior to Dec. 31, 1993,
through an annual billing adjustment mechanism approved by the MPUC. Through
the adjustment the Company is allowed to recover current and deferred CIP
expenditures and a lost margin associated with power saved as a result of these
programs. The adjustment is revised annually to reflect CIP expenditures that
differ from the base level included in the rate schedules. The Company
collected $7.8 million of CIP related revenue in 1994.
Water Utility Rate Proceedings. In 1993 the FPSC and certain Florida
counties approved final annual rate increases totaling $16 million of $21.2
million requested by SSU. The FPSC ordered uniform rates for 90 water and 37
wastewater systems in SSU's 1992 consolidated rate filing in Florida. Uniform
rates are based on companywide costs rather than costs related to individual
systems. In 1993 the FPSC initiated a separate investigation to determine if,
as a matter of policy, uniform rates are appropriate for Florida water
utilities. In August 1994 the FPSC reaffirmed the appropriateness of the
uniform rate structure.
Under Florida law, water and wastewater utilities may make an annual index
filing designed to recover inflationary costs associated with operation and
maintenance expenses. The law's intent is to provide inflationary relief to
utilities, thus delaying or avoiding the costs associated with full rate case
filings. Under another Florida law, water and wastewater utilities may make an
annual pass-through filing to recover increased purchased water and wastewater
treatment costs and property tax increases. The FPSC approved annual rate
increases totaling $2.9 million of the $3 million requested in SSU's 1993 and
1994 index filings and 1994 pass-through filings.
Peabody Contract Buyout. In 1991 Minnesota Power and Peabody Coal Company
(Peabody) executed an agreement to terminate the 1968 Coal Supply Contract
between the parties (the Coal Contract) two years ahead of the scheduled
termination date.
In accordance with orders issued by the MPUC and the FERC, the Company
used the retail and resale fuel adjustment clauses to pass through to electric
customers the $35 million charge (plus a return on the funds used to make the
payment) paid by the Company in December 1991 to terminate the Coal Contract.
The early termination allowed the Company to purchase lower-priced coal on the
open market and eliminated all of the Company's future responsibility relating
to the Coal Contract. The impact of this ratemaking treatment on the
consolidated income statement was the recognition of $3.9, $18.5, and $14.5
million in 1994, 1993, and 1992 of the Coal Contract termination costs as fuel
expense and the recovery of these costs in revenue through the fuel adjustment
clauses.
Deferred Regulatory Charges and Credits. Based on current rate treatment,
the Company believes it will continue to recover from ratepayers all deferred
regulatory charges.
<TABLE>
<CAPTION>
Summary of Deferred Regulatory Dec. 31,
Charges and Credits 1994 1993
----------------------------------------------------------------------
In thousands
<S> <C> <C>
Deferred Charges
SFAS 109 - Income taxes $22,977 $23,596
SFAS 106 - Postretirement benefits 12,834 6,549
CIP 10,471 8,172
Premium on reacquired debt 9,119 9,892
Other 19,518 11,708
------- -------
74,919 59,917
Deferred Credits
SFAS 109 - Income taxes 55,996 60,520
------- -------
Net deferred regulatory charges
and credits $18,923 $ (603)
----------------------------------------------------------------------
</TABLE>
30
<PAGE>
4 Financial Instruments
Securities Investments. The majority of the Company's securities
investments are investment-grade stocks of other utility companies and are
considered by the Company to be conservative investments.
The Company classifies its investments in equity and debt securities in
three categories: Trading securities are those bought and held principally for
near-term sale. They are recorded on the balance sheet at fair value as part of
current assets, with changes in fair value during the period included in
earnings. Held-to-maturity securities are those the Company has the ability and
intent to hold to maturity. They are recorded at amortized cost in investments
and corporate services on the balance sheet. Available-for-sale securities are
those that do not fit either of the previous two categories. They are recorded
at fair value in investments and corporate services on the balance sheet.
Changes in fair value during the period are recorded net of tax as a separate
component of common stock equity. If the fair value of any available-for-sale
or held-to-maturity securities declines below cost and the decline is
considered other than temporary, the securities are written down to fair value
and the losses charged to earnings. Realized gains and losses are computed on
each specific investment sold.
<TABLE>
<CAPTION>
Gross Unrealized Fair
-----------------
Summary of Securities Cost Gain (Loss) Value
--------------------------------------------------------------------------
In thousands
<S> <C> <C> <C> <C>
Dec. 31, 1994
Trading $ 74,046
--------
Available-for-sale
Common stock $ 10,636 $ 86 $(1,748) $ 8,974
Preferred stock 117,860 2,747 (3,893) 116,714
-------- ------ ------- --------
$128,496 $2,833 $(5,641) 125,688
Held-to-maturity
Leveraged preferred
stock $ 2,013 2,013
--------
Total securities investments $127,701
--------
----------------
Dec. 31, 1993
Trading $ 98,244
--------
Available-for-sale
Common stock $ 11,267 $ 306 $ (463) $ 11,110
Preferred stock 91,191 3,101 (407) 93,885
-------- ------ ------- --------
$102,458 $3,407 $ (870) 104,995
Held-to-maturity
Leveraged preferred
stock $ 7,179 7,179
--------
Total securities investments $112,174
---------------------------------------------------------------------------
</TABLE>
The net unrealized gain (loss) on securities investments on the balance
sheet at Dec. 31, 1994, includes $3.8 million from the Company's share of
Capital Re's unrealized holding losses.
<TABLE>
<CAPTION>
Year Ended
Dec. 31, 1994
--------------------------------------------------------------------------
In thousands
<S> <C>
Trading securities
Change in net unrealized holding gains
included in earnings $ 253
Available-for-sale securities
Proceeds from sales $53,559
Gross realized gains $ 1,194
Gross realized (losses) $(2,902)
--------------------------------------------------------------------------
</TABLE>
Off-Balance-Sheet Risks. In portfolio strategies designed to reduce market
risks, the Company sells common stock securities short and enters into short
sales of treasury futures contracts.
Selling common stock securities short is intended to reduce market price
risks associated with holding common stock securities in the Company's trading
securities portfolio. Transactions involving short sales of common stock are
completed on average within 90 days from when the transactions were entered
into. Realized and unrealized gains and losses from short sales of common stock
securities are included in investment income.
Treasury futures are used as a cross hedge to reduce interest rate risks
associated with holding fixed dividend preferred stocks included in the
Company's available-for-sale portfolio. Changes in market values of treasury
futures are recognized as an adjustment to the carrying amount of the
underlying hedged item. Gains and losses on treasury futures are deferred and
recognized in investment income concurrently with gains and losses arising from
the underlying hedged item. Generally, treasury futures contracts entered into
have a maturity date of 90 days.
In 1994 SSU entered into a three year interest rate swap agreement to
lower its overall cost of borrowing. SSU agreed with a counterparty to
exchange, at specified intervals, the difference between fixed-rate and
floating-rate interest amounts calculated by reference to a notional principal
amount. The differential paid or received is accrued and recognized as
adjustments to interest expense. The interest rate swap is subject to market
risk as interest rates fluctuate.
The notional amounts summarized below do not represent amounts exchanged
and are not a measure of the Company's financial exposure. The amounts
exchanged are calculated on the basis of these notional amounts and other terms
which relate to the change in interest rates and securities prices. The Company
continually evaluates the credit standing of counterparties and market
conditions with respect to its off-balance-sheet financial instruments. The
Company does not expect any counterparties to fail to meet their obligations or
any material adverse impact to its financial position from these financial
instruments.
<TABLE>
<CAPTION>
Summary of Off-Balance-Sheet Dec. 31,
Financial Instruments 1994 1993
-------------------------------------------------------------------------------
In thousands
<S> <C> <C>
Short stock sales outstanding $61,523 $79,081
Treasury futures $31,700 $12,600
Interest rate swap $20,000 -
-------------------------------------------------------------------------------
</TABLE>
31
<PAGE>
Fair Value of Financial Instruments. The carrying amount of cash and cash
equivalents, trading securities, notes and other accounts receivable, and notes
payable approximates fair value because of the short maturity of those
instruments. The Company records its trading and available-for-sale securities
at fair value based on quoted market prices. The fair values for all other
financial instruments were based on quoted market prices for the same or
similar issues.
<TABLE>
<CAPTION>
Summary of Fair Values Dec. 31, 1994 Dec. 31, 1993
---------------------------------------------------------------------------------------
In thousands
Carrying Fair Carrying Fair
Amount Value Amount Value
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Long-term debt $(601,317) $(559,859) $(611,144) $(620,166)
Redeemable serial
preferred stock $ (20,000) $ (19,550) $ (20,000) $ (21,450)
Short stock sales
outstanding (trading) - $ 59,691 - $ 79,448
Treasury futures - $ 31,433 - $ 14,420
Interest rate swap - $ (589) - -
---------------------------------------------------------------------------------------
</TABLE>
Concentration of Credit Risk. Financial instruments that subject the
Company to concentrations of credit risk consist primarily of trade and other
receivables. The Company sells electricity to about 17 customers in northern
Minnesota's taconite and paper industries. At Dec. 31, 1994 and 1993,
receivables from these customers totaled $8.5 and $7.6 million. The Company
sells recycled pulp to about 20 paper manufacturers that are geographically
dispersed. At Dec. 31, 1994 and 1993, receivables from these customers totaled
$13.5 and $3.6 million. The Company does not obtain collateral to support
receivables, but monitors the credit standing of major customers. The Company
has not incurred and does not expect to incur significant credit losses.
5 Investment in Unconsolidated Affiliates
Capital Re Corporation. The Company has an equity ownership investment in
Capital Re, a company engaged in financial guaranty reinsurance. In 1994 the
Company purchased an additional 417,100 shares of Capital Re common stock for
$8.8 million, which increased its ownership interest to 21.4%. The Company
accounts for this investment under the equity method.
<TABLE>
<CAPTION>
Summary of Capital Re Year Ended Dec. 31,
Financial Information 1994 1993 1992
----------------------------------------------------------------------------
In thousands
<S> <C> <C> <C>
Investment portfolio $650,200 $523,000 $443,700
Other assets 181,800 167,900 94,100
Liabilities 154,900 125,300 111,200
Deferred revenue 272,000 254,100 147,100
Net revenue 100,300 75,200 58,400
Net income 39,800 34,900 30,200
----------------------------------------------------------------------------
Company's equity
in earnings from Capital Re $ 8,138 $ 6,559 $ 5,733
Company's equity
investment in Capital Re $ 72,054 $ 60,216 $ 54,214
Fair value of the Company's equity
investment in Capital Re $ 86,662 $ 70,778 $ 58,409
----------------------------------------------------------------------------
</TABLE>
Lake Superior Paper Industries. The Company is an equal participant with
Pentair Duluth Corp., a wholly owned subsidiary of Pentair, Inc., in LSPI, a
joint venture supercalendered paper mill in Duluth, Minn.
LSPI is obligated for approximately $33.4 million of annual lease payments
for a 25-year operating lease extending to 2012 for paper mill equipment. LSPI
sold the paper mill equipment in a sale-leaseback transaction at a gain that is
being amortized over the lease term.
The Company is required to contribute capital to LSPI of at least $16
million in the form of equity or debt. As of Dec. 31, 1994, the Company had
contributed $14.5 million of that investment in the form of equity. At Dec. 31,
1994 and 1993, the Company had a $35.1 and a $30.8 million short-term interest
bearing note receivable from LSPI. The Company is committed to a maximum
guaranty of $95 million to ensure its portion of LSPI's lease obligation.
The Company also is the guarantor of project compliance with environmental
standards. The obligations of the Company are several and not joint with
Pentair Duluth Corp. and Pentair, Inc. The Company accounts for the investment
in LSPI by the equity method.
<TABLE>
<CAPTION>
Summary of LSPI Year Ended Dec. 31,
Financial Information 1994 1993 1992
----------------------------------------------------------------------------
In thousands
<S> <C> <C> <C>
Current assets $ 50,425 $ 49,120 $ 42,048
Noncurrent assets 158,756 148,011 140,400
Current liabilities 32,972 34,769 60,726
Deferred gain 30,776 32,486 34,195
Other liabilities 73,500 61,000 15,000
Net sales 152,227 143,041 150,252
Gross profit 15,370 4,506 10,908
Partnership earnings (loss) 3,056 (3,650) 3,364
----------------------------------------------------------------------------
Company's equity
in earnings from LSPI $ 1,528 $ (1,813) $ 1,670
Company's equity
investment in LSPI $ 35,967 $ 34,440 $ 36,252
----------------------------------------------------------------------------
</TABLE>
Undistributed earnings. The Company's accumulated equity in the
undistributed earnings of all unconsolidated affiliates included in
consolidated retained earnings amounted to $51.2, $43.6 and $38.8 million at
Dec. 31, 1994, 1993 and 1992.
6 Common Stock and Retained Earnings Restrictions
The Articles of Incorporation, mortgage, and preferred stock purchase
agreements contain provisions that, under certain circumstances, would restrict
the payment of common stock dividends. As of Dec. 31, 1994, no retained
earnings were restricted as a result of these provisions.
32
<PAGE>
<TABLE>
<CAPTION>
Summary of Common Stock Shares Equity
-------------------------------------------------------------------------------
In thousands
<S> <C> <C>
Balance Dec. 31, 1991 29,475 $307,166
1992 ESPP 29 892
Reacquired and retired stock (51) (441)
Other - 473
------ --------
Balance Dec. 31, 1992 29,453 308,090
1993 Public offering 1,000 34,570
ESPP 25 925
DRIP 588 20,805
Earned ESOP adjustment - 995
Other 141 5,296
------ --------
Balance Dec. 31, 1993 31,207 370,681
1994 ESPP 40 1,033
Other - (536)
------ --------
Balance Dec. 31, 1994 31,247 $371,178
-------------------------------------------------------------------------------
</TABLE>
In 1993 the Company changed the method of accounting for its ESOP. Under
the new method, the difference between the market value of the shares committed
to be released from collateral when earned and the cost of the shares to the
ESOP is recorded in common stock equity. (See note 15.)
In September 1993 the Company issued one million shares of new common
stock in a public offering for $34.6 million. The net proceeds were used to
fund a portion of the Company's investment in SRFI and for other corporate
purposes.
In June 1993 the Company issued 140,648 shares of new common stock with a
market value at the time of issuance of approximately $4.9 million in exchange
for an additional 13.4% ownership interest in Lehigh.
In January 1993 the Company amended its Automatic Dividend Reinvestment
and Stock Purchase Plan (DRIP). The amendment gave the Company the option to
issue new common stock shares or continue to purchase shares on the open market
for the DRIP. At Dec. 31, 1994, the Company had 912,281 shares of common stock
authorized to be issued pursuant to the DRIP.
7 Preferred Stock
<TABLE>
<CAPTION>
Dec. 31,
Summary of Cumulative Preferred Stock 1994 1993
-----------------------------------------------------------------------------
In thousands
<S> <C> <C>
Preferred stock, $100 par value,
116,000 shares authorized;
5% Series - 113,358 shares outstanding,
callable at $102.50 per share $11,492 $11,492
Serial preferred stock, without par value,
1,000,000 shares authorized;
$7.36 Series - 170,000 shares outstanding,
callable at $103.34 per share 17,055 17,055
------- -------
Total cumulative preferred stock $28,547 $28,547
-----------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Dec. 31,
Summary of Redeemable Serial Preferred Stock 1994 1993
-----------------------------------------------------------------------------
In thousands
<S> <C> <C>
Serial preferred stock A, without par value,
2,500,000 shares authorized;
$6.70 Series - 100,000 shares
outstanding, noncallable,
redeemable in 2000
at $100 per share $10,000 $10,000
$7.125 Series - 100,000 shares
outstanding,noncallable,
redeemable in 2000
at $100 per share 10,000 10,000
------- -------
Total redeemable serial preferred stock $20,000 $20,000
-----------------------------------------------------------------------------
</TABLE>
8 Long-Term Debt
<TABLE>
<CAPTION> Dec. 31,
Schedule of Long-Term Debt 1994 1993
---------------------------------------------------------------------------------
In thousands
<S> <C> <C>
Minnesota Power
First mortgage bonds
7 3/8% Series due 1997 $ 60,000 $ 60,000
6 1/2% Series due 1998 18,000 18,000
6 1/4% Series due 2003 25,000 25,000
7 1/2% Series due 2007 35,000 35,000
7 3/4% Series due 2007 55,000 55,000
7% Series due 2008 50,000 50,000
6% Pollution control Series E due 2022 111,000 111,000
Pollution control revenue bonds due 1995-2010 35,405 36,125
Leveraged ESOP loan due 1995-2004 13,786 14,549
Other long-term debt 17,054 16,903
Subsidiary companies
First mortgage bonds, 8.73% due 2013 45,000 45,000
Notes payable, 7.65% due 2003 41,864 45,000
Notes payable, 10.44% due 1999 30,000 30,000
Utility mortgage bonds, 15 1/2% - 15,000
Other long-term debt 77,022 61,861
Less due within one year (12,814) (7,294)
-------- --------
Total long-term debt $601,317 $611,144
---------------------------------------------------------------------------------
</TABLE>
Aggregate amounts of long-term debt maturing during each of the next five
years are $12.8, $9.1, $72, $28.2 and $40.2 million in 1995, 1996, 1997, 1998
and 1999.
The sinking fund provision of the Company's Mortgage relating to the First
Mortgage Bonds, 6 1/2% Series due 1998, requires the Company to deliver
annually to the trustee cash and/or such bonds equal to $225,000, subject to
certain adjustments. Property additions equal to 166.67% of principal amounts
of bonds, otherwise required to be so redeemed, may be applied in lieu of cash
or bonds. The Company has consistently pledged property additions to meet the
sinking fund requirements.
Substantially all Company electric and water plant is subject to the lien
of the mortgages securing various first mortgage bonds. The Company's 88%
ownership of SRFI is subject to a lien securing certain nonrecourse long-term
debt obligations.
In December 1994 SSU retired $15 million of 15 1/2% First Mortgage Bonds.
A portion of the proceeds from the sale of certain water plant assets was used
to fund the retirement.
33
<PAGE>
9 Short-Term Borrowings and Compensating Balances
The Company had bank lines of credit, which make short-term financing
available through short-term bank loans and provide support for commercial
paper, aggregating approximately $72 million at Dec. 31, 1994 and 1993. At Dec.
31, 1994 and 1993, the Company had issued commercial paper with face values of
$54 and $20 million, respectively, supported by bank lines of credit and
liquidity provided by the Company's securities portfolio. Certain lines of
credit require payment of a 1/8 of 1% commitment fee and others require
maintenance of 5% compensating balances. Interest rates on commercial paper and
borrowings under the lines of credit range from 5.5% to 9.5% at Dec. 31, 1994,
and 3.5% to 7.5% at Dec. 31, 1993. The weighted average interest rate on short-
term borrowings at Dec. 31, 1994 and 1993, was 5.7% and 3.5%. The total amount
of compensating balances at Dec. 31, 1994 and 1993, was immaterial.
10 Square Butte
Purchased Power Contract
Under the terms of a 30-year contract with Square Butte that extends
through 2007, the Company is purchasing 71% of the output from a mine-mouth,
lignite-fired generating plant capable of generating up to 455 megawatts. This
generating unit (Project) is located near Center, N.D. Reductions to about 49%
of the output are provided for in the contract and, at the option of Square
Butte, could begin after a five-year advance notice to the Company and continue
for the remaining economic life of the Project. The Company has the option but
not the obligation to continue to purchase 49% of the output after 2007.
The Project is leased to Square Butte through Dec. 31, 2007, by certain
banks and their affiliates which have beneficial ownership in the Project.
Square Butte has options to renew the lease after 2007 for essentially the
entire remaining economic life of the Project.
The Company is obligated to pay Square Butte all Square Butte's leasing,
operating and debt service costs (less any amounts collected from the sale of
power or energy to others) that shall not have been paid by Square Butte when
due. These costs include the price of lignite coal purchased by Square Butte
under a cost-plus contract with BNI Coal. The Company's cost of power and
energy purchased from Square Butte during 1994, 1993 and 1992 was $55.4, $56.5
and $54.1 million, respectively. The leasing costs of Square Butte included in
the cost of power delivered to the Company totaled $19.3 million in 1994, $19.7
million in 1993 and $19.6 million in 1992, which included approximately $12,
$12.5 and $12.9 million, respectively, of interest expense. The annual fixed
lease obligations of the Company to Square Butte are $19.4 million from 1995
through 1999. At Dec. 31, 1994, Square Butte had total debt outstanding of $219
million. The Company's obligation is absolute and unconditional whether or not
any power is actually delivered to the Company.
The Company's payments to Square Butte for power and energy are approved
as purchased power expense for ratemaking purposes by both the MPUC and the
FERC.
One principal reason the Company entered into the agreement with Square
Butte was to obtain a power supply for large industrial customers. Present
electric service contracts with these customers require payment of minimum
monthly demand charges that cover most of the fixed costs associated with
having capacity available to serve them. These contracts minimize the negative
impact on earnings that could result from significant reductions in kilowatt-
hour sales to industrial customers. The minimum contract term for the large
industrial customers is 10 years, with a four-year cancellation notice required
for termination of the contract at or beyond the end of the 10th year. Under
terms of existing contracts, the Company would collect approximately $90.5,
$78.1, $75.5, $61.5 and $32.3 million under current rate levels for firm power
during the years 1995, 1996, 1997, 1998 and 1999, respectively, even if no
power or energy were supplied to these customers after Dec. 31, 1994. However,
following implementation of rate increases approved by the MPUC in November
1994, and the anticipated MPUC approval of pending contract amendments, this
minimum contract revenue is expected to increase $16 to $28 million in each
year. The minimum contract provisions are expressed in megawatts of demand, and
if rates change, the amounts the Company would collect under the contracts will
change in proportion to the change in the demand rate.
11 Jointly Owned Electric Facility
The Company owns 80% of Boswell Unit 4. While the Company operates the
plant, certain decisions with respect to the operations of Boswell Unit 4 are
subject to the oversight of a committee on which the Company and Wisconsin
Public Power, Inc. SYSTEM (WPPI), the owner of the other 20% of Boswell Unit 4,
have equal representation and voting rights. Each owner must provide its own
financing and is obligated to pay its ownership share of operating costs. The
Company's share of direct operating expenses of Boswell Unit 4 is included in
the corresponding operating expense on the consolidated statement of income.
The Company's 80% share of the original cost recorded in plant in service at
Dec. 31, 1994 and 1993, was $306 million. The corresponding provisions for
accumulated depreciation were $119 and $111 million.
12 Sale of Water Plant Assets
In December 1994 SSU sold all of the assets of its Venice Gardens water
and wastewater utilities to Sarasota County in Florida, (the County) for $37.6
million. The sale increased 1994 net income by $11.8 million and contributed 42
cents to 1994 earnings per share. Water utility operations on the consolidated
statement of income includes a pre-tax gain of $19.1 million from the sale.
This sale was negotiated in anticipation of an eminent domain action by the
County, which is purchasing private utilities in an effort to consolidate
services.
34
<PAGE>
13 Income Tax Expense
<TABLE>
<CAPTION>
Schedule of Income Tax
Expense (Benefit) 1994 1993 1992
----------------------------------------------------------------------------
In thousands
<S> <C> <C> <C>
Current tax expense
Federal $14,656 $20,089 $20,593
State 3,087 3,376 6,024
------- ------- -------
17,743 23,465 26,617
------- ------- -------
Deferred tax expense
Federal 5,166 4,066 1,640
State 1,035 1,451 300
------- ------- -------
6,201 5,517 1,940
------- ------- -------
Deferred tax credits (2,478) (2,035) (1,568)
------- ------- -------
Total income tax expense $21,466 $26,947 $26,989
----------------------------------------------------------------------------
</TABLE>
Total income tax expense produced effective tax rates of 25.9%, 30.1% and
26.9% in 1994, 1993 and 1992, as compared to the federal statutory rate of 35%
in 1994 and 1993, and 34% in 1992.
<TABLE>
<CAPTION>
Reconciliation of Federal Statutory
Rate to Effective Tax Rate 1994 1993 1992
----------------------------------------------------------------------------
In thousands
<S> <C> <C> <C>
Tax computed at federal
statutory rate $28,979 $31,333 $34,139
Increases (decreases) in tax from
State income taxes, net of
federal income tax
benefit 2,608 3,684 4,205
Basis difference in land (2,433) - -
Income from unconsolidated
subsidiaries (985) (2,885) (5,277)
Income from escrow funds (1,550) - -
Dividend received deduction (2,867) (3,295) (4,888)
Tax credits (2,478) (2,097) (1,568)
Other 192 207 378
------- ------- -------
Total income tax expense $21,466 $26,947 $26,989
----------------------------------------------------------------------------
</TABLE>
Adoption of SFAS 109. The Company adopted SFAS 109, "Accounting for Income
Taxes" on a prospective basis in January 1993. The adoption of SFAS 109 changed
the Company's method of accounting for income taxes from the deferred method
(Accounting Principles Board Opinion No. 11) to an asset and liability
approach. Prior to the adoption of SFAS 109, the Company had deferred the tax
effects of timing differences between income for financial reporting purposes
and taxable income. The asset and liability approach requires the recognition
of deferred tax assets and liabilities for the expected future tax
consequences of temporary differences between the carrying amounts
(book value) and the tax basis of assets and liabilities.
<TABLE>
<CAPTION>
Schedule of Deferred Tax Dec. 31,
Assets and Liabilities 1994 1993
-----------------------------------------------------------------------------
In thousands
<S> <C> <C>
Deferred tax assets
Contributions in aid of construction $18,378 $15,808
Lehigh basis difference 26,878 31,475
Deferred compensation plans 7,856 7,104
Minimum tax credit carryover 11,094 8,008
Deferred gain 12,359 12,972
Depreciation 10,472 -
Investment tax credits 24,144 25,085
Other 22,289 9,865
------- -------
Gross deferred tax assets 133,470 110,317
Deferred asset valuation allowance (26,878) (31,475)
------- -------
Total deferred tax assets 106,592 78,842
------- -------
Deferred tax liabilities
Depreciation 198,174 174,613
AFDC 20,526 19,238
Capital lease 11,432 9,294
Investment tax credits 35,982 37,563
Other 32,919 25,570
------- -------
Total deferred tax liabilities 299,033 266,278
------- -------
Accumulated deferred income taxes $192,441 $187,436
-----------------------------------------------------------------------------
</TABLE>
At Dec. 31, 1994, approximately $26.9 million of net deferred tax assets
resulting from the original purchase of Lehigh are included on the Company's
balance sheet. These assets are fully offset by the deferred asset valuation
allowance because under the standards of SFAS 109 it is currently "more likely
than not" that the value of these assets will not be realized. Management
reviews the appropriateness of the valuation allowance quarterly. A reduction
in the valuation allowance will result in recognition of income during the
respective period.
A provision has not been made for taxes on $19.1 million of undistributed
earnings which were earned prior to 1993 by Capital Re, an investment accounted
for under the equity method. Those earnings have been and are expected to
continue to be reinvested. The Company estimates that $7.9 million of tax would
be payable on the pre-1993 undistributed earnings of Capital Re if the Company
should sell its investment. The Company has recognized the income tax impact on
undistributed earnings of Capital Re earned since Jan. 1, 1993.
35
<PAGE>
14 Pension Plans and Benefits
Pension Plans. The Company's Minnesota, Wisconsin and Florida utility
operations have noncontributory defined benefit pension plans covering eligible
employees. Pension benefits for employees in Minnesota and Wisconsin are fully
vested after five years and are based on years of service and the highest
average monthly compensation earned during four consecutive years within the
last 15 years of employment. Employees in Florida are fully vested after five
years of credited service, with benefits based on years of service and average
earnings. Company policy is to fund accrued pension costs, including
amortization of past service costs over 5 to 30 years. Part of pension cost is
capitalized as a cost of plant construction.
<TABLE>
<CAPTION>
Schedule of Pension Costs 1994 1993 1992
----------------------------------------------------------------------------
In thousands
<S> <C> <C> <C>
Service cost $ 4,130 $ 3,436 $ 3,211
Interest cost 11,753 11,969 11,416
Actual return on assets (15,103) (30,590) (19,630)
Net amortization 454 17,372 7,268
------- -------- -------
Net cost $ 1,234 $ 2,187 $ 2,265
----------------------------------------------------------------------------
</TABLE>
At Dec. 31, 1994, approximately 54% of pension plan assets were invested
in equity securities, 28% in fixed income securities, 11% in other investments
and 7% in Company common stock.
<TABLE>
<CAPTION>
Oct. 1,
Pension Plans Funded Status 1994 1993
----------------------------------------------------------------------------
In thousands
<S> <C> <C>
Actuarial present value
of benefit obligations
Vested benefit obligation $(126,250) $(126,275)
Nonvested benefit obligation (8,975) (9,761)
--------- ---------
Accumulated benefit obligation (135,225) (136,036)
Excess of projected benefit obligation
over accumulated benefit obligation (26,820) (34,673)
--------- ---------
Projected benefit obligation (162,045) (170,709)
Plan assets at fair value 195,942 200,862
--------- ---------
Plan assets in excess of
projected benefit obligation 33,897 30,153
Unrecognized net gain (33,767) (27,678)
Prior service cost not yet recognized
in net periodic pension cost 6,647 3,091
Unrecognized net obligation
at Oct. 1, 1985, being recognized
over 20 years 2,104 2,310
--------- ---------
Prepaid pension cost recognized on the
consolidated balance sheet $ 8,881 $ 7,876
----------------------------------------------------------------------------
</TABLE>
The weighted average discount rate for 1994 and 1993 was 8.25% and 7%.
Projected pension obligations assume pay increases averaging 6% for each of
1994 and 1993. The assumed long-term rate of return on assets was 8.75% for
1994 and 8.5% for 1993 and 1992.
BNI Coal and Heater have defined contribution pension plans covering
eligible employees. The aggregate annual pension cost for these plans was about
$600,000 in 1994 and $700,000 in 1993 and in 1992.
Postretirement Benefits. The Company provides certain health care and life
insurance benefits for retired employees. SFAS 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions," adopted Jan. 1, 1993, changed the
Company's method of accounting for these costs requiring that they be
recognized during employment. Prior to the adoption of SFAS 106, the Company
recognized these costs as they were paid. Postretirement benefit costs
recognized in 1992 under the Company's prior accounting method were $918,000.
As of Dec. 31, 1994, the Company has deferred $12.8 million of
postretirement benefit costs in excess of those allowed in existing rates.
Pursuant to a rate order issued by the MPUC in November 1994, the Company will
recover in electric rates, the retail portion ($11.7 million) of these deferred
costs over a five year period beginning in 1995.
<TABLE>
<CAPTION>
Schedule of Postretirement Benefit Costs 1994 1993
----------------------------------------------------------------------------
In thousands
<S> <C> <C>
Service cost $2,545 $2,609
Interest cost 4,389 4,875
Actual return on plan assets (125) (321)
Amortization of transition obligation 3,085 3,133
------ ------
Net periodic cost 9,894 10,296
Net deferral (6,285) (6,549)
------ ------
Net cost $3,609 $3,747
----------------------------------------------------------------------------
</TABLE>
Company policy is to fund the net periodic postretirement costs and the
amortization of the costs deferred as the amounts are collected in rates. The
Company will fund these benefits using Voluntary Employee Benefit Association
(VEBA) trusts and an irrevocable grantor trust. The Company will make the
maximum tax deductible contributions to the VEBAs. The remainder of the funds
will be placed in the irrevocable grantor trust until the funds can be used to
make tax deductible contributions to the VEBAs. The funds in the irrevocable
grantor trust do not qualify as plan assets for purposes of SFAS 106.
<TABLE>
<CAPTION>
Dec. 31,
Postretirement Benefit Plan Funded Status 1994 1993
------------------------------------------------------------------------------
In thousands
<S> <C> <C>
Accumulated postretirement benefit obligation
Retirees $(18,879) $(18,631)
Fully eligible participants (17,221) (16,029)
Other active participants (25,151) (29,454)
-------- --------
(61,251) (64,114)
Plan assets 2,486 720
-------- --------
Accumulated postretirement benefit
in excess of plan assets (58,765) (63,394)
Unrecognized transition obligation 45,040 51,948
-------- --------
Accrued postretirement benefit obligation $(13,725) $(11,446)
------------------------------------------------------------------------------
</TABLE>
For measurement purposes, it was assumed per capita health care benefit
costs would increase 13.3% in 1994 and that cost increases would thereafter
decrease 1% each year until stabilizing at 5.3% in 2002. Accelerating the rate
of assumed health care cost increases by 1% each year would raise the 1994
transition obligation by $8.1 million and service and interest costs by a total
of $1.4 million. The weighted average discount rate used in estimating
accumulated postretirement benefit obligations was 8.25% for 1994 and 7% for
1993. The expected long-term rate of return on plan assets was 8.75% for 1994
and 8.5% for 1993.
36
<PAGE>
Postemployment Benefits. The Company provides certain postemployment
benefits to employees and their dependents during the time period following
employment but before retirement. On Jan. 1, 1994, the Company adopted SFAS
112, "Employers' Accounting for Postemployment Benefits," which recognizes the
estimated future cost of providing postemployment benefits on an accrual basis
over the active service life of employees. Adoption of SFAS 112 resulted in a
$2.2 million transition obligation. As a result of a rate order issued by the
MPUC in November 1994, the Company deferred $1.6 million of the transition
obligation which is being recovered in electric rates over a three-year period
beginning in 1994. Prior to the 1994 adoption of SFAS 112, the Company
recognized postemployment benefit expenses as they were paid.
15 Employee Stock Plans
Employee Stock Ownership Plan. The Company has sponsored an ESOP since
1975, amending it in 1989 and 1990 to establish two leveraged accounts.
The 1989 leveraged ESOP account covers all non-union Minnesota and
Wisconsin employees who work more than 1,000 hours per year and have one year
of service. The ESOP used the proceeds from a $16.5 million, 15-year loan at
9.125%, guaranteed by the Company, to purchase 633,489 shares of Minnesota
Power common stock on the open market in early 1990. These shares fund employee
benefits totaling not less than 2% of the participants' salaries.
The 1990 leveraged ESOP account covers Minnesota and Wisconsin employees
who participated in the non-leveraged ESOP plan prior to Aug. 4, 1989. The ESOP
issued a $75 million promissory note at 10.25% with a term not to exceed 25
years to the Company (Employer Loan) as consideration for 2.8 million shares of
newly issued Minnesota Power common stock in November 1990. These shares are
used to fund a benefit at least equal to the value of the following: (a)
dividends on shares held in participants' 1990 leveraged ESOP accounts which
are used to make loan payments, and (b) the tax savings generated from
deducting all dividends paid on shares currently in the ESOP which were held by
the plan on Aug. 4, 1989.
The loans will be repaid with dividends received by the ESOP and with
employer contributions. ESOP shares acquired with the loans were initially
pledged as collateral for the loans. The ESOP shares are released from
collateral and allocated to participants based on the portion of total debt
service paid in the year.
The Company accounts for the ESOP in accordance with the American
Institute of Certified Public Accountants' (AICPA) Statement of Position 93-6
(SOP 93-6).
The adoption in 1993 of SOP 93-6 decreased 1993 net income by $5.2 million
and reduced the average number of shares outstanding for the 1993 EPS
calculation by 3,114,067 shares. The net impact was a 6 cent increase in 1993
earnings per share.
Prior to 1993, the Company accounted for the ESOP in accordance with AICPA
Statement of Position 76-3. ESOP loans, the note receivable and unallocated
ESOP shares pledged as collateral for the loans were recorded in the financial
statements the same as under SOP 93-6. All ESOP shares were treated as
outstanding. The Company recognized interest income and interest expense on the
Employer Loan to the ESOP in the financial statements. The Company calculated
interest and compensation expense by first reducing interest expense and then
compensation expense by the amount of dividends paid on leveraged shares
charged to retained earnings. Compensation expense was computed using the cost
basis to the ESOP of the shares. In 1992, the Company realized $3.2 million in
tax benefits from the deduction of dividends paid on the unallocated shares
used to make the debt service payments. These tax benefits were recorded
directly to retained earnings and included in the EPS computation. Under SOP
93-6, these tax benefits are included in income tax expense.
<TABLE>
<CAPTION>
Schedule of ESOP Year Ended Dec. 31,
Compensation and Interest Expense 1994 1993 1992
----------------------------------------------------------------------------
In thousands
<S> <C> <C> <C>
Interest expense $1,328 $1,361 $9,351
Dividends used to pay debt service - - (8,201)
------ ------ ------
Net interest expense 1,328 1,361 1,150
Compensation expense 2,037 2,396 3,235
------ ------ ------
Total $3,365 $3,757 $4,385
----------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Dec. 31,
Schedule of ESOP Shares 1994 1993
-----------------------------------------------------------------------------
In thousands
<S> <C> <C>
Allocated shares 1,635 1,664
Shares released for allocation 49 40
Unreleased shares 2,903 3,055
------- --------
Total ESOP shares 4,587 4,759
-----------------------------------------------------------------------------
Fair value of unreleased shares $73,305 $100,039
-----------------------------------------------------------------------------
</TABLE>
Employee Stock Purchase Plan. The Company has an Employee Stock Purchase
Plan (ESPP). At Dec. 31, 1994, 254,553 shares of common stock were held in
reserve for future issuance under the ESPP. The ESPP permits each employee to
buy up to $23,750 per year in Company common stock. Purchases are at 95% of the
stock's closing market price on the first day of each month. At Dec. 31, 1994,
389,739 shares had been issued under the ESPP.
37
<PAGE>
16 Quarterly Financial Data
(Unaudited)
Information for any one quarterly period is not necessarily indicative of
the results which may be expected for the year. Previously reported quarterly
information has been revised to reflect reclassifications to conform with the
1994 method of presentation. These reclassifications had no effect on
previously reported consolidated net income.
The first quarter ended March 31, 1994, included a decrease in net income
of $6 million from the write-off of an investment and an increase in net income
of $3.6 million related to escrow funds. Net income for the fourth quarter
ended Dec. 31, 1994, included an increase of $11.8 million from the sale of
certain water plant assets and a decrease of $2.2 million from the Company's
equipment manufacturing business.
The first quarter ended March 31, 1993, included $1.7 million in net
income from the redemption of a preferred stock investment. The third quarter
ended Sept. 30, 1993, included $2.2 million from the one-time adjustment
relating to deferred revenue for electric service provided but not yet billed.
<TABLE>
<CAPTION>
Quarter Ended
March 31 June 30 Sept. 30 Dec. 31
-----------------------------------------------------------------------------
In thousands except earnings per share
<S> <C> <C> <C> <C>
1994
Operating revenue
and income $150,568 $152,304 $155,822 $179,088
Operating income 10,845 18,740 20,202 33,012
Net income 9,368 12,970 15,199 23,796
Earnings available
for common stock 8,568 12,170 14,399 22,996
Earnings per share
of common stock 0.30 0.44 0.51 0.81
1993
Operating revenue
and income $151,913 $144,908 $140,878 $151,908
Operating income 27,183 19,179 24,569 18,637
Net income 17,749 13,116 17,347 14,409
Earnings available
for common stock 16,898 12,270 16,501 13,610
Earnings per share
of common stock 0.64 0.46 0.61 0.49
-----------------------------------------------------------------------------
</TABLE>
38
<PAGE>
DEFINITIONS
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Abbreviations or
Acronyms Term
BNI Coal BNI Coal, Ltd.
Boswell Boswell Energy Center Units No. 1, 2, 3 and 4
BTUs British thermal units
Capital Re Capital Re Corporation
CIP Conservation Improvement Programs
Company Minnesota Power & Light Company and its Subsidiaries
DRIP Automatic Dividend Reinvestment and Stock
Purchase Plan
Energy Act National Energy Policy Act of 1992
ESOP Employee Stock Ownership Plan
ESPP Employee Stock Purchase Plan
FERC Federal Energy Regulatory Commission
FPSC Florida Public Service Commission
Heater Heater Utilities, Inc.
Lehigh Lehigh Acquisition Corporation
LSPI Lake Superior Paper Industries
Minnesota Power Minnesota Power & Light Company and its Subsidiaries
MPCA Minnesota Pollution Control Agency
MPUC Minnesota Public Utilities Commission
MW Megawatt(s)
MWh Megawatt-hour
National National Steel Pellet Co.
Note ___ Note ___ to the consolidated financial statements in
the Minnesota Power 1994 Annual Report
Peabody Peabody Coal Company
Reach All Reach All Partnership
SFAS Statement of Financial Accounting Standards
Square Butte Square Butte Electric Cooperative
SRFI Superior Recycled Fiber Industries Joint Venture
SSU Southern States Utilities, Inc.
SWL&P Superior Water, Light and Power Company
These abbreviations or acronyms are used throughout this document.
39
<PAGE>
DIRECTORS
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Merrill K. Cragun
President, Cragun Corp.
(resort and conference center), Brainerd
Director since 1991
Dennis E. Evans
President and Chief Executive Officer,
Hanrow Financial Group, Ltd.
(merchant banking), Minneapolis
Director since 1986
Sister Kathleen Hofer
President and Chief Executive Officer, St. Mary's Medical Center (hospital) and
Chair and Chief Executive Officer of the Benedictine Health System (parent
corporation for a number of nonprofit health care providers), Duluth
Director since 1994
Peter J. Johnson
President and Chief Executive Officer,
Hoover Construction Co. (highway and heavy construction contractor) and
Chairman, Michigan Limestone Operations (producer of limestone for steel and
construction industries), Tower, Minn.
Director since 1994
Mary E. Junck
Publisher and CEO of The Baltimore Sun
(daily and Sunday newspapers), Baltimore
Director since 1992
Robert S. Mars, Jr.
Chairman, W.P. & R.S. Mars Co.
(industrial equipment and supply)
and President, Conveyor Belt Service, Inc.
(conveyor belt maintenance and repair), Duluth
Director since 1970
Paula F. McQueen
President and Treasurer - Secretary
PGI Incorporated (real estate development), Partner of Webb, McQueen & Co.
(accounting firm) and Chief Executive Officer of Allied Engineering & Testing
Inc. (engineering and materials testing), Punta Gorda, Fla.
Director since 1993
Robert S. Nickoloff
Chairman, Medical Innovation Capital, Inc. and General Partner of Medical
Innovation Fund (venture capital firms) and self-employed as an attorney, St.
Paul
Director since 1986
Jack I. Rajala
President, Rajala Lumber Co. and Rajala Mill Co. (lumber manufacturing and
trading), Grand Rapids
Director since 1985
Charles A. Russell
President and Chief Executive Officer,
Norwest Bank Minnesota North, N.A., Duluth
Director since 1985
Arend J. Sandbulte
Chairman, President and Chief Executive Officer, Minnesota Power, Duluth
Director since 1983, President since 1984, CEO since 1988 and Chairman since
1989
Donald C. Wegmiller
President and Chief Executive Officer ,
Management Compensation Group/HealthCare (national executive compensation and
benefits consulting firm), Minneapolis
Director since 1992
-------------------------------------------------------------------------------
Executive Committee
Sandbulte - Chairman; Hofer, Junck, McQueen and Russell
Audit Committee
Wegmiller - Chairman; Junck, McQueen, Russell and Hofer
Executive Compensation Committee
Nickoloff - Chairman; Evans, Russell and Wegmiller
Electric Utility Operations Committee
Sandbulte - Chairman; Cragun, Hofer, Johnson and Mars
Principal Corporate, Subsidiary and Joint Venture Officers
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Executive Management Team
Arend J. Sandbulte, 61
Chairman, President and Chief Executive Officer
Robert D. Edwards, 50
Executive Vice President and Chief Operating Officer
Jack R. McDonald, 57
Executive Vice President - Finance and Corporate Development
Donnie R. Crandell, 51
Senior Vice President - Corporate Development
David G. Gartzke, 51
Senior Vice President - Finance and Chief Financial Officer
Allen D. Harmon, 43
Group Vice President - Electric Utility Operations
Warren L. Candy, 45
Vice President - Boswell Energy Center
Roger P. Engle, 46
Vice President - Customer Operations
Eugene G. McGillis, 60
Vice President
President - Superior Water, Light and Power
Gerald B. Ostroski, 54
Vice President
President - Synertec
Charles M. Reichert, 57
Vice President
President - BNI Coal, Ltd.
Kevin G. Robb, 48
Vice President - Generation
President - Rainy River Energy Corp.
Stephen D. Sherner, 44
Vice President - Power Marketing and Delivery
Geraldine R. VanTassel, 53
Vice President - Corporate Resource Planning
John J. Carhart, Jr., 53
President and Chief Executive Officer - Reach All
William E. Grantmyre, 49
President - Heater Utilities
Philip R. Halverson, 46
General Counsel and Corporate Secretary
John C. Hosler, 48
Interim President - Lake Superior Paper Industries
William I. Livingston, 48
President - Lehigh Corporation
Mark A. Schober, 39
Corporate Controller
Scott W. Vierima, 43
Interim President - Southern States Utilities
James K. Vizanko, 41
Corporate Treasurer
Dennis L. Hollingsworth, 60
Assistant Vice President - Corporate Development
Steven W. Tyacke, 43
Assistant General Counsel
40
<PAGE>
INVESTOR INFORMATION AND SERVICES
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For shareholder information and assistance, write to Shareholder Services at
our corporate headquarters address or call:
Toll-free phone: 1-800-535-3056
Duluth area number: 723-3974
FAX: 218-720-2502
Dividend Reinvestment Plan
Shareholders and our electric utility customers may buy Company common stock by
reinvesting their dividends or by making cash payments of from $10 per payment
to $10,000 a quarter. No brokerage fee or commission is charged. To enroll in
the Automatic Dividend Reinvestment and Stock Purchase Plan, contact
Shareholder Services. We belong to the National Association of Investors
Corporation and participate in NAIC's Low Cost Investment Plan.
Direct Dividend Deposit
At your request, we'll automatically deposit dividends in your checking or
savings account. To sign up for this free service, request an authorization
form from Shareholder Services. They'll also need a voided personal check
(write "VOID" across its face) or a bank deposit slip showing the number of the
account to receive your dividends.
Ending Duplicate Mailings
If you're getting duplicate mailings from us and would prefer not to, contact
Shareholder Services.
Replacing Dividend Checks,
Stock Certificates
If you don't receive your dividend check within 10 days of the payment date, or
if your check has been lost or destroyed, call Shareholder Services. Call us
also if a stock certificate is lost, destroyed or stolen; we'll send you the
necessary forms needed to replace it. Replacing certificates takes time and
involves some expense.
Stock as a Gift
Minnesota Power stock makes a good gift for birthdays, graduation and other
special occasions. Shareholder Services will provide, on request, a special
gift letter to accompany a gift of Minnesota Power stock.
Change of Address
Please let Shareholder Services know if your address changes.
Form 10-K and Statistical Supplement
The Company's Form 10-K Annual Report to the Securities and Exchange Commission
is available upon request. A Statistical Supplement to the 1994 Annual Report
is also available. Contact Shareholder Services for them; there's no charge.
Analyst Inquiries
Security analysts seeking information about the Company may contact Timothy J.
Thorp, Manager-Investor Relations. Phone 218-723-3953/FAX 218-723-3940.
Annual Meeting
Our Annual Meeting of Shareholders is held the second Tuesday in May.
Shareholders are invited to attend the 1995 Annual Meeting, beginning at 2 p.m.
May 9 at the Duluth Entertainment Convention Center, 350 Harbor Drive, Duluth.
Stock Exchange Listings
Minnesota Power common stock is listed on the New York Stock Exchange under the
symbol MPL. The American Stock Exchange lists our 5% Preferred Stock (MPL pf
5) and Serial Preferred Stock, $7.36 Series (MPL pf 7.36). Daily price quotes
on our common stock may be found in many newspapers under the New York Stock
Exchange composite transactions listing.
Transfer Agents for Common and
Preferred Stocks
Minnesota Power, Duluth
Norwest Bank Minnesota, N.A.
Registrars for Common and Preferred Stocks
First Bank National Association
Norwest Bank Minnesota, N.A.
Common Stock Dividend Payment Dates
March 1, June 1, Sept. 1 and Dec. 1
Preferred Stock Payment Dates
Jan. 1, April 1, July 1 and Oct. 1
Annual Report
This annual report and the financial statements it contains are submitted for
the general information of the shareholders of the Company and not in
connection with the sale or offer for sale of, or solicitation of an offer to
buy, any securities.
[LOGO OF MINNESOTA POWER]
Corporate Headquarters
30 W. Superior Street
Duluth, MN 55802
<PAGE>
[PHOTO OF DAVE EVENS]
[PHOTO OF RICH SULLO]
[PHOTO OF JOAN ADLER]
[PHOTO OF ERIC NORBERG AND DAVE MCMILLAN]
Bulk Rate
U.S. Postage
PAID
[LOGO OF MINNESOTA POWER] Minnesota Power
30 West Superior Street
Duluth, Minnesota 55802-2093
<PAGE>
EXHIBIT 23(a)
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Registration
Statement on Form S-8 (No. 33-51989) of the Minnesota Power and Affiliated
Companies Employee Stock Purchase Plan of our report dated January 24, 1995,
appearing on page 24 of the Annual Report to Shareholders which is incorporated
in this Annual Report on Form 10-K. We also consent to the incorporation by
reference of our report on the Financial Statement Schedule which appears on
page 31 of this Form 10-K.
We also consent to the incorporation by reference in the Registration Statement
on Form S-8 (No. 33-32033) of the Minnesota Power and Affiliated Companies
Supplemental Retirement Plan of our report dated January 24, 1995, appearing on
page 24 of the Annual Report to Shareholders which is incorporated in this
Annual Report on Form 10-K. We also consent to the incorporation by reference
of our report on the Financial Statement Schedule which appears on page 31 of
this Form 10-K.
We also consent to the incorporation by reference in the Prospectus
constituting part of the Registration Statement on Form S-3 (No. 33-51941) of
the Minnesota Power & Light Company Common Stock of our report dated January
24, 1995, appearing on page 24 of the Annual Report to Shareholders which is
incorporated in this Annual Report on Form 10-K. We also consent to the
incorporation by reference of our report on the Financial Statement Schedule
which appears on page 31 of this Form 10-K.
We also consent to the incorporation by reference in the Prospectus
constituting part of the Registration Statement on Form S-3 (No. 33-50143) of
the Minnesota Power & Light Company Common Stock of our report dated January
24, 1995, appearing on page 24 of the Annual Report to Shareholders which is
incorporated in this Annual Report on Form 10-K. We also consent to the
incorporation by reference of our report on the Financial Statement Schedule
which appears on page 31 of this Form 10-K.
We also consent to the incorporation by reference in the Prospectus
constituting part of the Registration Statement on Form S-3 (No. 33-56134) of
the Minnesota Power & Light Company Automatic Dividend Reinvestment and Stock
Purchase Plan of our report dated January 24, 1995, appearing on page 24 of the
Annual Report to Shareholders which is incorporated in this Annual Report on
Form 10-K. We also consent to the incorporation by reference of our report on
the Financial Statement Schedule which appears on page 31 of this Form 10-K.
We also consent to the incorporation by reference in the Prospectus
constituting part of the Registration Statement on Form S-3 (No. 33-55240) of
the Minnesota Power & Light Company First Mortgage Bonds of our report dated
January 24, 1995, appearing on page 24 of the Annual Report to Shareholders
which is incorporated in this Annual Report on Form 10-K. We also consent to
the incorporation by reference of our report on the Financial Statement
Schedule which appears on page 31 of this Form 10-K.
We also consent to the incorporation by reference in the Prospectus
constituting part of the Registration Statement on Form S-3 (No. 33-45551) of
the Minnesota Power & Light Company Serial Preferred Stock, Cumulative, Without
Par Value of our report dated January 24, 1995, appearing on page 24 of the
Annual Report to Shareholders which is incorporated in this Annual Report on
Form 10-K. We also consent to the incorporation by reference of our report on
the Financial Statement Schedule which appears on page 31 of this Form 10-K.
PRICE WATERHOUSE LLP
Minneapolis, Minnesota
March 24, 1995
<PAGE>
EXHIBIT 23(b)
CONSENT OF GENERAL COUNSEL
The statements of law and legal conclusions under "Item 1. Business" in
the Company's Annual Report on Form 10-K for the year ended December 31, 1994,
have been reviewed by me and are set forth therein in reliance upon my opinion
as an expert.
I hereby consent to the incorporation by reference of such statements of
law and legal conclusions in Registration Statement Nos. 33-51941, 33-50143,
33-56134, 33-55240, and 33-45551 on Form S-3, and Registration Statement Nos.
33-51989 and 33-32033 on Form S-8.
Philip R. Halverson
Duluth, Minnesota
March 24, 1995
