SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of Earliest Event Reported) - February 27, 1995
Commission File No. 1-3548
MINNESOTA POWER & LIGHT COMPANY
A Minnesota Corporation
IRS Employer Identification No. 41-0418150
30 West Superior Street
Duluth, Minnesota 55802
Telephone - (218) 722-2641
MINNESOTA POWER & LIGHT COMPANY
INDEX
Page
Item 7. Financial Statements and Exhibits
Financial Statements
Signatures 2
Conversation with the CEO 6
Management Discussion and Analysis of Financial Condition
and Results of Operations 10
Report of Independent Accountants 28
Consolidated Balance Sheet -
December 31, 1994 and 1993 29
Consolidated Statement of Income -
For the year ended December 31, 1994, 1993 and 1992 30
Consolidated Statement of Retained Earnings -
For the year ended December 31, 1994, 1993 and 1992 30
Consolidated Statement of Cash Flows -
For the year ended December 31, 1994, 1993 and 1992 31
Notes to Consolidated Financial Statements 32
Exhibits
24(a) - Consent of Independent Accountants
27 - Financial Data Schedule
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SIGNATURES
Pursuant to the requirements 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)
February 27, 1995 D. G. Gartzke
-----------------------------------------
D. G. Gartzke
Senior Vice President - Finance
and Chief Financial Officer
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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
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[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.
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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.
Financial Highlights
1994 1993 Change
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%)
Average Annual Shareholder Return Over Last 10 Years
(Graphic material omitted)
Percentage
Minnesota Power 12.9
U.S. Electric Utilities 12.6
S&P 500 14.3
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.
Earnings and Dividends Per Share
(Graphic material omitted)
1985 1986 1987 1988 1989 1990 1991 1992 1993
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
1994
Earnings 2.06
Dividends 2.02
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.
Assets
Millions of Dollars
(Graphic material omitted)
1983 1984 1985 1986 1987 1988 1989 1990
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
1991 1992 1993 1994
Electric Utility 1,121 1,129 1,170 1,181
Water Utility 292 322 329 326
Investments and
Corporate Services 639 639 727 778
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.
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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
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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
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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 in April.
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.
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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
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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.
- 10 -
The $167 million transaction is scheduled for completion in the second quarter
of 1995 following approval by ADESA shareholders.
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 recycling/pulp production 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.
Where 1994 Earnings Came From
Earnings Per Share 1994 1993 1992
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
Return on Common Equity
(Graphic material omitted)
Year Percentage
1990 13.6
1991 15.4
1992 15.3
1993 11.5
1994 10.5
In 1994 the Company earned 10.5% on common shareholders' equity, which
averaged $562 million during the year.
Operating Revenue and Income
Millions of Dollars
(Graphic material omitted)
1992 1993 1994
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
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.
- 11 -
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 30 OF THIS REPORT.]
- 12 -
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.
- 13 -
Our Competitive Picture
Customer Favorability
(Graphic material omitted)
Percentage
Minnesota Power 91
Typical U.S.
Electric Utility 71
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.
Average Price of Electricity - Residential
(Graphic material omitted)
Cents per Kilowatt-hour
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
On average, our residential customers paid 37% less for
electricity in 1994 than customers of other U.S. utilities.
Average Price of Electricity - Overall
Cents per Kilowatt-hour
(Graphic material omitted)
Minnesota National
Power Average
Residential 5.55 8.85
Commercial 5.58 7.90
Industrial 3.66 5.14
Overall 4.08 7.25
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
- 14 -
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 MARK PINNEY, ED MACKEY, TOM GEISELMAN, AND JOE REIS]
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.
- 15 -
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.
Why Electric Utility Operations Revenue Increased or Decreased
1994 1993
(Change from previous year - in millions)
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
Electric Revenue by Customer Group
(Graphic material omitted)
1992 1993 1994
Other 49% 52% 51%
Paper & Wood Products 14% 14% 14%
Taconite & Iron Mining 37% 34% 35%
--- --- ---
100% 100% 100%
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.
Electric Sales
Billions of Kilowatt-hours
(Graphic material omitted)
1992 1993 1994
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
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
- 16 -
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.
- 17 -
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.
How Power Contracts Protect Us
Minimum Annual Revenue and Demand
under Contracts in effect as of Jan. 31, 1995
Minimum Revenue Megawatts
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
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.
Sources of Electricity
(Graphic material omitted.)
Percentage
Coal 52
Hydro 6
Purchased 20
Lignite 22
---
100
Low-sulfur coal, our major fuel, comes from the Powder River Basin in Montana
and Wyoming.
Annual Load Factor
(Graphic material omitted.)
1989 1990 1991 1992 1993 1994
Minnesota Power 80% 85% 82% 82% 86% 82%
Utility Industry Average 62% 60% 61% 61% 61% 61%
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.
Average Cost of Fuel for Electric Generation
Cents per Million BTU
(Graphic material omitted.)
1989 1990 1991 1992 1993 1994
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
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.
- 18 -
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.
- 19 -
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.
- 20 -
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.
Revenue from Water Utility Operations
Millions of Dollars
(Graphic material omitted.)
1992 1993 1994
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
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.
Number of Water Utility Customers
In Thousands
(Graphic material omitted.)
1992 1993 1994
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
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
- 21 -
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.
- 22 -
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.
- 23 -
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.
- 24 -
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.
- 25 -
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:
A2 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.
- 26 -
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.
Capital Spending
Millions of Dollars
(Graphic material omitted.)
1992 1993 1994
Electric Utility 45 58 45
Water Utility 32 20 28
Investments and
Corporate Services 32 43 9
--- --- --
109 121 82
In 1994 capital spending totaled $81 million, 31% less than the previous year.
Projected Capital Spending
(Graphic material omitted.)
1995 1996 1997 1998 1999
Millions of Dollars 65 61 57 57 57
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.
Price Ranges and Dividends Paid Per Share
New York Stock Exchange American Stock Exchange
---------------------------- ---------------------------
Common 5% Series Preferred
---------------------------- ---------------------------
Dividends Dividends
Quarter High Low Paid High Low Paid
- ---------------- ----- ----- ---------- ---- --- ----------
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
American Stock Exchange
----------------------------
$7.36 Series Preferred
----------------------------
Dividends
Quarter High Low Paid
- ---------------- ----- ----- ----------
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
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.
- 27 -
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
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
- 28 -
CONSOLIDATED FINANCIAL STATEMENTS
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Minnesota Power
Consolidated Balance Sheet
December 31 1994 1993
- ---------------------------------------------------------------------------
In thousands
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
- ---------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
- 29 -
Consolidated Statement of Income
For the year ended December 31 1994 1993 1992
- ------------------------------------------------------------------------------
In thousands except per share amounts
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
- ------------------------------------------------------------------------------
Consolidated Statement of Retained Earnings
For the year ended December 31 1994 1993 1992
- ------------------------------------------------------------------------------
In thousands
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
- ------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
- 30 -
Consolidated Statement of Cash Flows
For the year ended December 31 1994 1993 1992
- ------------------------------------------------------------------------------
In thousands
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)
Pretax 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)
- ------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
- 31 -
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1 Business Segments
- -------------------------------------------------------------------------------
Thousands Electric Water Utility
Consolidated Utility Operations Operations
------------ ------------------ -------------
For the Year Ended Dec. 31 Electric Coal
- -------------------------- -------- ----
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
- ------------------------------------------------------------------------------------------------
Thousands
Investments and Corporate Services
----------------------------------------
Portfolio,
Reinsurance Paper &
For the Year Ended Dec. 31 & Other Real Estate Pulp
- -------------------------- ----------- ----------- -------
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>
- 32 -
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.
- 33 -
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.
Summary of Deferred Regulatory Dec. 31,
Charges and Credits 1994 1993
- ----------------------------------------------------------------------
In thousands
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)
- ----------------------------------------------------------------------
- 34 -
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.
Gross Unrealized Fair
-----------------
Summary of Securities Cost Gain (Loss) Value
- --------------------------------------------------------------------------
In thousands
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
- ---------------------------------------------------------------------------
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.
Year Ended
Dec. 31, 1994
- --------------------------------------------------------------------------
In thousands
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)
- --------------------------------------------------------------------------
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.
Summary of Off-Balance-Sheet Dec. 31,
Financial Instruments 1994 1993
- -------------------------------------------------------------------------------
In thousands
Short stock sales outstanding $61,523 $79,081
Treasury futures $31,700 $12,600
Interest rate swap $20,000 -
- -------------------------------------------------------------------------------
- 35 -
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.
Summary of Fair Values Dec. 31, 1994 Dec. 31, 1993
- ---------------------------------------------------------------------------------------
In thousands
Carrying Fair Carrying Fair
Amount Value Amount Value
---------- ---------- ---------- ----------
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) - -
- ---------------------------------------------------------------------------------------
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.
Summary of Capital Re Year Ended Dec. 31,
Financial Information 1994 1993 1992
- ----------------------------------------------------------------------------
In thousands
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
- ----------------------------------------------------------------------------
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.
Summary of LSPI Year Ended Dec. 31,
Financial Information 1994 1993 1992
- ----------------------------------------------------------------------------
In thousands
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
- ----------------------------------------------------------------------------
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.
- 36 -
Summary of Common Stock Shares Equity
- -------------------------------------------------------------------------------
In thousands
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
- -------------------------------------------------------------------------------
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
Dec. 31,
Summary of Cumulative Preferred Stock 1994 1993
- -----------------------------------------------------------------------------
In thousands
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
- -----------------------------------------------------------------------------
Dec. 31,
Summary of Redeemable Serial Preferred Stock 1994 1993
- -----------------------------------------------------------------------------
In thousands
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
- -----------------------------------------------------------------------------
8 Long-Term Debt
Dec. 31,
Schedule of Long-Term Debt 1994 1993
- ---------------------------------------------------------------------------------
In thousands
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
- ---------------------------------------------------------------------------------
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 were used
to fund the retirement.
- 37 -
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.
- 38 -
13 Income Tax Expense
Schedule of Income Tax
Expense (Benefit) 1994 1993 1992
- ----------------------------------------------------------------------------
In thousands
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
- ----------------------------------------------------------------------------
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.
Reconciliation of Federal Statutory
Rate to Effective Tax Rate 1994 1993 1992
- ----------------------------------------------------------------------------
In thousands
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
- ----------------------------------------------------------------------------
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.
Schedule of Deferred Tax Dec. 31,
Assets and Liabilities 1994 1993
- -----------------------------------------------------------------------------
In thousands
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
- -----------------------------------------------------------------------------
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.
- 39 -
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.
Schedule of Pension Costs 1994 1993 1992
- ----------------------------------------------------------------------------
In thousands
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
- ----------------------------------------------------------------------------
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.
Oct. 1,
Pension Plans Funded Status 1994 1993
- ----------------------------------------------------------------------------
In thousands
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
- ----------------------------------------------------------------------------
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.
Schedule of Postretirement Benefit Costs 1994 1993
- ----------------------------------------------------------------------------
In thousands
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
- ----------------------------------------------------------------------------
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.
Dec. 31,
Postretirement Benefit Plan Funded Status 1994 1993
- ------------------------------------------------------------------------------
In thousands
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)
- ------------------------------------------------------------------------------
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.
- 40 -
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.
Schedule of ESOP Year Ended Dec. 31,
Compensation and Interest Expense 1994 1993 1992
- ----------------------------------------------------------------------------
In thousands
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
- ----------------------------------------------------------------------------
Dec. 31,
Schedule of ESOP Shares 1994 1993
- -----------------------------------------------------------------------------
In thousands
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
- -----------------------------------------------------------------------------
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.
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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.
Quarter Ended
March 31 June 30 Sept. 30 Dec. 31
- -----------------------------------------------------------------------------
In thousands except earnings per share
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
- -----------------------------------------------------------------------------
- 42 -
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.
- 43 -
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, Minnesota 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
- 44 -
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
- 45 -
[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
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