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FORM 10-K
United States
Securities and Exchange Commission
Washington, D.C. 20549
(Mark One)
/X/ Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended DECEMBER 31, 2004
/ / Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from ______________ to ______________
Commission File No. 1-3548
ALLETE, INC.
(Exact name of registrant as specified in its charter)
MINNESOTA 41-0418150
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
30 WEST SUPERIOR STREET, DULUTH, MINNESOTA 55802-2093
(Address of principal executive offices, including zip code)
(218) 279-5000
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
Name of Each Stock Exchange
Title of Each Class on Which Registered
------------------- -------------------
Common Stock, without par value New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes /X/ No / /
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. /X/
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).
Yes /X/ No / /
The aggregate market value of voting stock held by nonaffiliates on June 30,
2004 was $2,937,852,029.
As of February 1, 2005, there were 29,677,133 shares of ALLETE Common Stock,
without par value, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the 2005 Annual Meeting of Shareholders are
incorporated by reference in Part III.
INDEX
DEFINITIONS.................................................................. 2
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT
OF 1995...................................................................... 3
PART I
Item 1. Business ........................................................... 4
Regulated Utility.............................................. 5
Electric Sales............................................. 6
Purchased Power............................................ 8
Fuel....................................................... 8
Regulatory Issues.......................................... 9
Competition................................................ 11
Franchises................................................. 11
Nonregulated Energy Operations................................. 11
Real Estate.................................................... 13
Regulation................................................. 14
Competition................................................ 14
Other.......................................................... 15
Environmental Matters.......................................... 15
Employees...................................................... 17
Executive Officers of the Registrant........................... 18
Item 2. Properties.......................................................... 19
Item 3. Legal Proceedings................................................... 19
Item 4. Submission of Matters to a Vote of Security Holders................. 19
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities...................... 20
Item 6. Selected Financial Data............................................. 21
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.......................................... 23
Executive Summary................................................... 23
Net Income.......................................................... 25
2004 Compared to 2003............................................... 26
2003 Compared to 2002............................................... 28
Critical Accounting Policies........................................ 29
Outlook............................................................. 30
Liquidity and Capital Resources..................................... 32
Capital Requirements................................................ 34
Environmental and Other Matters..................................... 34
Market Risk......................................................... 34
New Accounting Standards............................................ 36
Factors that May Affect Future Results.............................. 36
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.......... 41
Item 8. Financial Statements and Supplementary Data......................... 41
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure........................................... 41
Item 9A. Controls and Procedures............................................. 41
Item 9B. Other Information................................................... 41
PART III
Item 10. Directors and Executive Officers of the Registrant.................. 42
Item 11. Executive Compensation.............................................. 42
Item 12. Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters................................ 42
Item 13. Certain Relationships and Related Transactions...................... 42
Item 14. Principal Accountant Fees and Services.............................. 42
PART IV
Item 15. Exhibits and Financial Statement Schedules.......................... 43
SIGNATURES................................................................... 46
CONSOLIDATED FINANCIAL STATEMENTS............................................ 47
Page 1 ALLETE 2004 Form 10-K
DEFINITIONS
The following abbreviations or acronyms are used in the text. References in this
report to "we," "us" and "our" are to ALLETE, Inc. and its subsidiaries,
collectively.
ABBREVIATION OR ACRONYM TERM
- --------------------------------------------------------------------------------
ADESA ADESA, Inc.
AICPA American Institute of Certified Public
Accountants
ALLETE ALLETE, Inc.
ALLETE Properties ALLETE Properties, Inc.
APB Accounting Principles Board
Aqua America Aqua America, Inc.
BNI Coal BNI Coal, Ltd.
Boswell Boswell Energy Center
CIP Conservation Improvement Programs
Company ALLETE, Inc. and its subsidiaries
Constellation Energy Commodities Constellation Energy Commodities Group,
Inc.
DOC Minnesota Department of Commerce
EITF Emerging Issues Task Force
Enventis Telecom Enventis Telecom, Inc.
EPA Environmental Protection Agency
ESOP Employee Stock Ownership Plan
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
Florida Water Florida Water Services Corporation
Form 8-K ALLETE Current Report on Form 8-K
Form 10-K ALLETE Annual Report on Form 10-K
Form 10-Q ALLETE Quarterly Report on Form 10-Q
FPSC Florida Public Service Commission
FSP Financial Accounting Standards Board Staff
Position
GAAP Accounting Principles Generally Accepted
in the United States
Hibbard Hibbard Energy Center
Invest Direct ALLETE's Direct Stock Purchase and
Dividend Reinvestment Plan
IPO Initial Public Offering
kWh Kilowatthour(s)
kV Kilovolt(s)
Laskin Laskin Energy Center
LSP-Kendall Energy LSP-Kendall Energy, LLC
MAPP Mid-Continent Area Power Pool
MBtu Million British thermal units
Minnesota Power An operating division of ALLETE, Inc.
Minnkota Power Minnkota Power Cooperative, Inc.
MISO Midwest Independent Transmission System
Operator, Inc.
Moody's Moody's Investors Service, Inc.
MPCA Minnesota Pollution Control Agency
MPUC Minnesota Public Utilities Commission
MW Megawatt(s)
MWh Megawatthour(s)
Note ___ Note ___ to the consolidated financial
statements in this Form 10-K
NPDES National Pollutant Discharge Elimination
System
NYSE New York Stock Exchange
PSCW Public Service Commission of Wisconsin
Rainy River Energy Rainy River Energy Corporation
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting
Standards No.
Split Rock Energy Split Rock Energy LLC
Square Butte Square Butte Electric Cooperative
Standard & Poor's Standard & Poor's Ratings Services, a
division of The McGraw-Hill Companies,
Inc.
SWL&P Superior Water, Light and Power Company
Taconite Harbor Taconite Harbor Energy Center
WDNR Wisconsin Department of Natural Resources
WPPI Wisconsin Public Power, Inc.
ALLETE 2004 Form 10-K Page 2
SAFE HARBOR STATEMENT
UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
In connection with the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995, we are hereby filing cautionary statements
identifying important factors that could cause our actual results to differ
materially from those projected in forward-looking statements (as such term is
defined in the Private Securities Litigation Reform Act of 1995) made by or on
behalf of ALLETE in this Annual Report on Form 10-K, in presentations, in
response to questions or otherwise. Any statements that express, or involve
discussions as to, expectations, beliefs, plans, objectives, assumptions or
future events or performance (often, but not always, through the use of words or
phrases such as "anticipates," "believes," "estimates," "expects," "intends,"
"plans," "projects," "will likely result," "will continue" or similar
expressions) are not statements of historical facts and may be forward-looking.
Forward-looking statements involve estimates, assumptions, risks and
uncertainties and are qualified in their entirety by reference to, and are
accompanied by, the following important factors, which are difficult to predict,
contain uncertainties, are beyond our control and may cause actual results or
outcomes to differ materially from those contained in forward-looking
statements:
- our ability to successfully implement our strategic objectives;
- prevailing governmental policies and regulatory actions, including
those of the United States Congress, state legislatures, the FERC, the
MPUC, the FPSC, the PSCW, and various local and county regulators, and
city administrators, about allowed rates of return, financings,
industry and rate structure, acquisition and disposal of assets and
facilities, real estate development, operation and construction of
plant facilities, recovery of purchased power and capital investments,
present or prospective wholesale and retail competition (including but
not limited to transmission costs), and zoning and permitting of land
held for resale;
- effects of restructuring initiatives in the electric industry;
- economic and geographic factors, including political and economic
risks;
- changes in and compliance with environmental and safety laws and
policies;
- weather conditions;
- natural disasters;
- war and acts of terrorism;
- wholesale power market conditions;
- population growth rates and demographic patterns;
- the effects of competition, including competition for retail and
wholesale customers;
- pricing and transportation of commodities;
- changes in tax rates or policies or in rates of inflation;
- unanticipated project delays or changes in project costs;
- unanticipated changes in operating expenses and capital expenditures;
- global and domestic economic conditions;
- capital market conditions;
- changes in interest rates and the performance of the financial markets;
- competition for economic expansion or development opportunities;
- our ability to manage expansion and integrate acquisitions; and
- the outcome of legal and administrative proceedings (whether civil or
criminal) and settlements that affect the business and profitability of
ALLETE.
Additional disclosures regarding factors that could cause our results and
performance to differ from results or performance anticipated by this report are
discussed in Item 7 under the heading "Factors that May Affect Future Results"
beginning on page 36 of this Form 10-K. Any forward-looking statement speaks
only as of the date on which such statement is made, and we undertake no
obligation to update any forward-looking statement to reflect events or
circumstances after the date on which that statement is made or to reflect the
occurrence of unanticipated events. New factors emerge from time to time, and it
is not possible for management to predict all of these factors, nor can it
assess the impact of each of these factors on the businesses of ALLETE or the
extent to which any factor, or combination of factors, may cause actual results
to differ materially from those contained in any forward-looking statement.
Readers are urged to carefully review and consider the various disclosures made
by us in our 2004 Form 10-K and in our other reports filed with the SEC that
attempt to advise interested parties of the factors that may affect our
business.
Page 3 ALLETE 2004 Form 10-K
PART I
ITEM 1. BUSINESS
ALLETE has been incorporated under the laws of Minnesota since 1906. ALLETE's
corporate headquarters are in Duluth, Minnesota. As of December 31, 2004, we had
approximately 1,500 employees, 100 of which were part-time. Statistical
information is presented as of December 31, 2004, unless otherwise indicated.
All subsidiaries are wholly owned unless otherwise specifically indicated.
References in this report to "we," "us" and "our" are to ALLETE and its
subsidiaries, collectively.
ALLETE files annual, quarterly, and other reports and information with the SEC.
You can read and copy any information filed by ALLETE with the SEC at the SEC's
Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. You can
obtain additional information about the Public Reference Room by calling the SEC
at 1-800-SEC-0330. In addition, the SEC maintains an Internet site (www.sec.gov)
that contains reports, proxy and information statements, and other information
regarding issuers that file electronically with the SEC, including ALLETE.
ALLETE also maintains an Internet site (www.allete.com) that contains documents
as soon as reasonably practicable after such material is electronically filed
with or furnished to the SEC.
ALLETE's operations are comprised of four business segments. REGULATED UTILITY
includes retail and wholesale rate regulated electric, water and gas services in
northeastern Minnesota and northwestern Wisconsin under the jurisdiction of
state and federal regulatory authorities. NONREGULATED ENERGY OPERATIONS
includes nonregulated generation (non-rate base generation sold at market-based
rates to the wholesale market) consisting primarily of generation from Taconite
Harbor in northern Minnesota, and our coal mining activities in North Dakota.
Nonregulated Energy Operations also includes generation secured through the
Kendall County power purchase agreement, which is expected to be transferred in
April 2005. (See Item 7 - Outlook.) REAL ESTATE includes our Florida real estate
operations. OTHER includes our telecommunications activities, investments in
emerging technologies, earnings on cash, and general corporate charges and
interest not specifically related to any one business segment. General corporate
charges include employee salaries and benefits, as well as legal and other
outside service fees. Discontinued Operations includes our Automotive Services
business that was spun off on September 20, 2004, our Water Services businesses,
the majority of which were sold in 2003, and costs incurred by ALLETE associated
with the spin-off of ADESA.
For a detailed discussion of results of operations and trends, see Item 7
Management's Discussion and Analysis of Financial Condition and Results of
Operations. For business segment information, see Notes 1 and 2.
YEAR ENDED DECEMBER 31 2004 2003 2002
- -------------------------------------------------------------------------------------------------------------------
Consolidated Operating Revenue - Millions $751 $692 $643
- -------------------------------------------------------------------------------------------------------------------
Percentage of Consolidated Operating Revenue
Regulated Utility
Industrial
Taconite Producers 23% 22% 23%
Paper and Wood Products 9 8 10
Pipelines and Other Industries 6 6 6
- -------------------------------------------------------------------------------------------------------------------
Total Industrial 38 36 39
Residential 10 10 11
Commercial 11 11 11
Other Power Suppliers 5 7 7
Other Revenue 10 10 10
- -------------------------------------------------------------------------------------------------------------------
Total Regulated Utility 74 74 78
Nonregulated Energy Operations 14 15 13
Real Estate 6 6 5
Other 6 5 4
- -------------------------------------------------------------------------------------------------------------------
100% 100% 100%
- -------------------------------------------------------------------------------------------------------------------
ALLETE 2004 Form 10-K Page 4
SPIN-OFF OF AUTOMOTIVE SERVICES. On September 20, 2004, the spin-off of
Automotive Services was completed by distributing to ALLETE shareholders all of
ALLETE's shares of ADESA common stock. Through a June 2004 IPO, our Automotive
Services business, doing business as ADESA, Inc. (NYSE: KAR), issued 6.3 million
shares of common stock. This represented 6.6% of ADESA's common stock
outstanding. ALLETE owned the remaining 93.4% of ADESA until the spin-off was
completed. (See Note 3.)
Discontinued operations included the operating results of our Automotive
Services business until the spin-off. Automotive Services, which does business
independently as ADESA, operates businesses that are integral parts of the
vehicle redistribution industry in North America. Those businesses include used
and salvage vehicle auctions and related services, and dealer financing. ADESA's
SEC filings are available through the SEC's website at www.sec.gov.
SALE OF WATER PLANT ASSETS. In mid-2004, we completed the sales of our North
Carolina water and wastewater assets, and our remaining 72 water and wastewater
systems in Florida. In early 2005, we sold our wastewater services business in
Georgia. The net cash proceeds from the sale of all water and wastewater assets
in 2003 and 2004, after transaction costs, retirement of most Florida Water debt
and payment of income taxes, were approximately $300 million. The transaction
relating to the sale of 63 water and wastewater systems in Florida to Aqua
America remains subject to regulatory approval by the FPSC. The approval process
may result in an adjustment to the final purchase price, based on the FPSC's
determination of plant investment for the systems. A decision is expected in
late 2005.
REGULATED UTILITY
MINNESOTA POWER, an operating division of ALLETE, provides regulated utility
electric service in a 26,000 square mile service territory in northeastern
Minnesota. Minnesota Power supplies regulated utility electric service to
136,000 retail customers and wholesale electric service to 16 municipalities.
SWL&P provides regulated utility electric, natural gas and water service in
northwestern Wisconsin. SWL&P has 14,000 electric customers, 12,000 natural gas
customers and 10,000 water customers.
Minnesota Power had an annual net peak load of 1,498 MW on January 30, 2004. Our
regulated power supply sources are listed below.
FOR THE YEAR ENDED
REGULATED UTILITY UNIT YEAR NET WINTER DECEMBER 31, 2004
POWER SUPPLY NO. INSTALLED CAPABILITY ELECTRIC REQUIREMENTS
- -------------------------------------------------------------------------------------------------------------------------
MW MWH %
Steam
Coal-Fired
Boswell Energy Center 1 1958 69
near Grand Rapids, MN 2 1960 69
3 1973 350
4 1980 430
- -------------------------------------------------------------------------------------------------------------------------
918 5,814,505 48.4%
- -------------------------------------------------------------------------------------------------------------------------
Laskin Energy Center 1 1953 55
in Hoyt Lakes, MN 2 1953 55
- -------------------------------------------------------------------------------------------------------------------------
110 626,478 5.2
- -------------------------------------------------------------------------------------------------------------------------
Purchased Steam
Hibbard Energy Center in Duluth, MN 3 & 4 1949, 1951 46 69,521 0.6
- -------------------------------------------------------------------------------------------------------------------------
Total Steam 1,074 6,510,504 54.2
- -------------------------------------------------------------------------------------------------------------------------
Hydro
Group consisting of ten stations in MN Various 115 454,713 3.8
- -------------------------------------------------------------------------------------------------------------------------
Purchased Power
Square Butte burns lignite coal near Center, ND 322 2,005,776 16.7
All Other - Net - 3,047,401 25.3
- -------------------------------------------------------------------------------------------------------------------------
Total Purchased Power 322 5,053,177 42.0
- -------------------------------------------------------------------------------------------------------------------------
Total 1,511 12,018,394 100.0%
- -------------------------------------------------------------------------------------------------------------------------
We have electric transmission and distribution lines of 500 kV (8 miles), 230 kV
(606 miles), 161 kV (43 miles), 138 kV (66 miles), 115 kV (1,300 miles) and less
than 115 kV (6,767 miles). We own and operate 184 substations with a total
capacity of 8,868 megavoltamperes. Some of our transmission and distribution
lines interconnect with other utilities.
Page 5 ALLETE 2004 Form 10-K
We own offices and service buildings, an energy control center and repair shops,
and lease offices and storerooms in various localities. Substantially all of our
electric plant is subject to mortgages, which collateralize the outstanding
first mortgage bonds of Minnesota Power and of SWL&P. Generally, we hold fee
interest in our real properties subject only to the lien of the mortgages. Most
of our electric lines are located on land not owned in fee, but are covered by
appropriate easement rights or by necessary permits from governmental
authorities. WPPI owns 20% of Boswell Unit 4. WPPI has the right to use our
transmission line facilities to transport its share of Boswell generation. (See
Note 10.)
SPLIT ROCK ENERGY was a joint venture between Minnesota Power and Great River
Energy. In March 2004, we terminated our ownership interest upon receipt of FERC
approval.
ELECTRIC SALES
Our regulated utility operations include retail and wholesale activities under
the jurisdiction of state and federal regulatory authorities. (See Regulatory
Issues.)
REGULATED UTILITY ELECTRIC SALES
YEAR ENDED DECEMBER 31 2004 2003 2002
- ------------------------------------------------------------------------------------------------------------------
MILLIONS OF KILOWATTHOURS
Retail and Municipals
Residential 1,053 1,065 1,044
Commercial 1,282 1,286 1,257
Industrial 7,071 6,558 6,946
Municipals and Other 902 921 898
- ------------------------------------------------------------------------------------------------------------------
10,308 9,830 10,145
Other Power Suppliers 918 1,314 987
- ------------------------------------------------------------------------------------------------------------------
11,226 11,144 11,132
- ------------------------------------------------------------------------------------------------------------------
Minnesota Power has wholesale contracts with 16 municipal customers, SWL&P and
Dahlberg Light & Power Company in rural Wisconsin. (See Regulatory Issues -
Federal Energy Regulatory Commission.)
Approximately 60% of the ore consumed by integrated steel facilities in the
United States originates from six taconite customers of Minnesota Power.
Taconite, an iron-bearing rock of relatively low iron content that is abundantly
available in Minnesota, is an important domestic source of raw material for the
steel industry. Taconite processing plants use large quantities of electric
power to grind the ore-bearing rock, and agglomerate and pelletize the iron
particles into taconite pellets. Strong worldwide steel demand, driven largely
by extensive infrastructure development in China, has resulted in very robust
world iron ore and steel pricing and has consequently resulted in very high
demand for iron ore and steel. This globalization of demand has positively
impacted Minnesota taconite producers, which all produced near their rated
capacities in 2004. Annual taconite production in Minnesota was 41 million tons
in 2004 (35 million tons in 2003; 39 million tons in 2002). Recent consolidation
activities, combined with the strong steel market, have placed the Minnesota
taconite producers in a strong position. Cleveland-Cliffs Inc and U.S. Steel
Corp. have each announced planned significant capital investments to either
bring mothballed pellet production capacity back on line or to ensure existing
capacity continues to operate with an investment in required pollution control
equipment.
In addition to serving the taconite industry, Minnesota Power also serves a
number of customers in the paper and pulp and wood products industry. In total,
we serve four major paper and pulp mills directly and one paper mill indirectly
by providing wholesale service to the retail provider of the mill. Minnesota
Power also serves four wood products manufacturers.
After suffering through a consecutive number of down years since 2000, the North
American paper industry rebounded in 2004. The reasons for the rebound included
the decline of the dollar in comparison to the Euro, which resulted in fewer
imports to the United States, a recovering economy and closing some capacity
over the past several years. The past trend of the mills in Minnesota Power's
service territory being acquired by new owners continued in 2004. In 2004, Boise
Cascade sold its paper, wood products and timber holdings to Madison Dearborn
Partners, including the International Falls paper mill which Minnesota Power
serves, the former Potlatch-Brainerd/Missota Paper mill was acquired by
Wausau-Mosinee Paper Corporation, and Potlatch's oriented strand board (plywood
substitute) plants, including the Grand Rapids plant served by Minnesota Power,
were purchased by Ainsworth Lumber Company Ltd. of Vancouver, Canada.
ALLETE 2004 Form 10-K Page 6
LARGE POWER CUSTOMER CONTRACTS. Minnesota Power has large power customer
contracts with 12 customers (Large Power Customers), 11 of which require 10 MW
or more of generating capacity and one of which requires 8 MW or more of
generating capacity. Large Power Customer contracts require Minnesota Power to
have a certain amount of generating capacity available. (See Minimum Revenue and
Demand Under Contract table.) In turn, each Large Power Customer is required to
pay a minimum monthly demand charge that covers the fixed costs associated with
having this capacity available to serve the customer, including a return on
common equity. Most contracts allow customers to establish the level of
megawatts subject to a demand charge on a biannual (power pool season) basis and
require that a portion of their megawatt needs be committed on a take-or-pay
basis for at least a portion of the agreement. In addition to the demand charge,
each Large Power Customer is billed an energy charge for each kilowatthour used
that recovers the variable costs incurred in generating electricity. Six of the
Large Power Customers have interruptible service for a portion of their needs,
which provides a discounted demand rate and energy priced at Minnesota Power's
incremental cost after serving all firm power obligations. Minnesota Power also
provides incremental production service for customer demand levels above the
contract take-or-pay levels. There is no demand charge for this service and
energy is priced at an increment above Minnesota Power's cost. Incremental
production service is interruptible. Contracts with 8 of the 12 Large Power
Customers provide for deferral without interest of one-half of demand charge
obligations incurred during the first three months of a strike or illegal
walkout at a customer's facilities, with repayment required over the 12-month
period following resolution of the work stoppage.
All contracts continue past the contract termination date, unless the required
advance notice of cancellation has been given. The advance notice of
cancellation varies from one to four years. Such contracts minimize the impact
on earnings that otherwise would result from significant reductions in
kilowatthour sales to such customers. Large Power Customers are required to
purchase all electric service requirements from Minnesota Power for the duration
of their contracts. The rates and corresponding revenue associated with capacity
and energy provided under these contracts are subject to change through the same
regulatory process governing all retail electric rates. (See Regulatory Issues -
Electric Rates.)
The MPUC allows Minnesota Power to require taconite-producing Large Power
Customers to pay weekly for electric usage based on monthly energy usage
estimates. A normal thirty-day billing cycle with a 15-day payment period left
Minnesota Power greatly exposed to a significant revenue loss if the customer
did not or could not make payment due to discontinued operations, or delayed
making payment for electric service pending a Chapter 11 bankruptcy filing. The
customers receive estimated bills based on Minnesota Power's prediction of the
customer's energy usage, forecasted energy prices, and fuel clause adjustment
estimates. Minnesota Power's five taconite-producing Large Power Customers have
generally predictable energy usage on a week-to-week basis, which makes the
variance between the estimated usage and actual usage small. Taconite-producing
Large Power Customers subject to weekly billings receive interest on the money
paid to Minnesota Power within the billing cycle.
MINIMUM REVENUE AND DEMAND UNDER CONTRACT MINIMUM MONTHLY
AS OF FEBRUARY 1, 2005 ANNUAL REVENUE MEGAWATTS
- ----------------------------------------------------------------------------------------------------------------------
2005 $69.1 421
2006 $39.4 210
2007 $32.5 178
2008 $25.8 148
2009 $5.8 36
- ----------------------------------------------------------------------------------------------------------------------
Based on past experience, we believe revenue from our Large Power Customers will be substantially in excess of
the minimum contract amounts.
Page 7 ALLETE 2004 Form 10-K
CONTRACT STATUS FOR MINNESOTA POWER LARGE POWER CUSTOMERS
AS OF FEBRUARY 1, 2005
EARLIEST
CUSTOMER INDUSTRY LOCATION OWNERSHIP TERMINATION DATE
- ---------------------------------------------------------------------------------------------------------------------------------
Hibbing Taconite Co. , Taconite Hibbing, MN 62.3% International Steel February 28, 2009
Group Inc.
23% Cleveland-Cliffs Inc
14.7% Stelco Inc.
Ispat Inland Mining Company , Taconite Virginia, MN Ispat Inland Mining Company February 28, 2009
U.S. Steel Corp. (USS) Minntac Taconite Mt. Iron, MN U.S. Steel Corp. February 28, 2009
USS Keewatin Taconite Taconite Keewatin, MN U.S. Steel Corp. February 28, 2009
United Taconite LLC Taconite Eveleth, MN 70% Cleveland-Cliffs Inc February 28, 2009
30% Laiwu Steel Group
UPM, Blandin Paper Mill Paper Grand Rapids, MN UPM-Kymmene Corporation April 30, 2007
Boise White Paper, LLC Paper International Falls, MN Madison Dearborn December 31, 2008
Partnership
Sappi Cloquet LLC Paper Cloquet, MN Sappi Limited February 28, 2009
Stora Enso North America, Paper and Pulp Duluth, MN Stora Enso Oyj April 30, 2009
Duluth Paper Mill and
Duluth Recycled Pulp Mill
USG Interiors, Inc. Manufacturer Cloquet, MN USG Corporation February 28, 2006
Enbridge Energy Company, Pipeline Deer River, MN Enbridge Energy Company, February 28, 2006
Limited Partnership Floodwood, MN Limited Partnership
Minnesota Pipeline Company Pipeline Staples, MN 60% Koch Pipeline Co. L.P. February 28, 2006
Little Falls, MN 40% Marathon Ashland
Park Rapids, MN Petroleum LLC
- ---------------------------------------------------------------------------------------------------------------------------------
The contract will terminate four years from the date of written notice from either Minnesota Power or the customer. No
notice of contract cancellation has been given by either party. Thus, the earliest date of cancellation is February 28,
2009.
In 2004, Ispat International and International Steel Group (ISG) announced a merger. At the same time, Ispat International
changed its name to Mittal Steel Company N.V. (Mittal Steel). The merger of Mittal Steel and ISG is anticipated to be
completed in the first quarter of 2005. A successful merger will result in Mittal Steel becoming the world's largest steel
producer. Mittal Steel is expected to become the owner of the Ispat Inland Mining Company and will be the majority partner
in Hibbing Taconite.
The contract will terminate one year from the date of written notice from either Minnesota Power or the customer. No
notice of contract cancellation has been given by either party. Thus, the earliest date of cancellation is February 28,
2006.
PURCHASED POWER
Minnesota Power has contracts to purchase capacity and energy from various
entities. The largest contract is with Square Butte. Under an agreement with
Square Butte expiring at the end of 2026, Minnesota Power is currently entitled
to approximately 71% (66% beginning in 2006; 60% in 2007) of the output of a
455-MW coal-fired generating unit located near Center, North Dakota. (See Note
11.)
FUEL
Minnesota Power purchases low-sulfur, sub-bituminous coal from the Powder River
Basin coal field located in Montana. Coal consumption in 2004 for electric
generation at Minnesota Power's coal-fired generating stations was about 5.1
million tons. As of December 31, 2004, Minnesota Power had a coal inventory of
about 516,000 tons. Minnesota Power has three coal supply agreements with
various expiration dates extending through 2009. Under these agreements,
Minnesota Power has the tonnage flexibility to procure 70% to 100% of its total
coal requirements. In 2005, Minnesota Power will obtain coal under these coal
supply agreements and in the spot market. This diversity in coal supply options
allows Minnesota Power to manage market price and supply risk and to take
advantage of favorable spot market prices. Minnesota Power is exploring future
coal supply options. We believe that adequate supplies of low-sulfur,
sub-bituminous coal will continue to be available.
In 2001, Minnesota Power and Burlington Northern and Santa Fe Railway Company
(Burlington Northern) entered into a long-term agreement under which Burlington
Northern transports all of Minnesota Power's coal by unit train from the Powder
River Basin directly to Minnesota Power's generating facilities or to a
designated interconnection point. Minnesota Power also has agreements with the
Canadian National Railway and Midwest Energy Resources Company to transport coal
from the Burlington Northern interconnection point to certain Minnesota Power
facilities.
ALLETE 2004 Form 10-K Page 8
COAL DELIVERED TO MINNESOTA POWER
YEAR ENDED DECEMBER 31 2004 2003 2002
- -------------------------------------------------------------------------------------------------
Average Price per Ton $19.01 $20.02 $21.48
Average Price per MBtu $1.04 $1.12 $1.19
- -------------------------------------------------------------------------------------------------
The Square Butte generating unit operated by Minnkota Power burns North Dakota
lignite coal supplied by BNI Coal, in accordance with the terms of a contract
expiring in 2027. Square Butte's cost of lignite burned in 2004 was
approximately 74 cents per MBtu. The lignite acreage that has been dedicated to
Square Butte by BNI Coal is located on lands essentially all of which are under
private control and presently leased by BNI Coal. This lignite supply is
sufficient to provide the fuel for the anticipated useful life of the generating
unit.
REGULATORY ISSUES
We are exempt from regulation under the Public Utility Holding Company Act of
1935 (PUHCA), except as to Section 9(a)(2), which relates to acquisition of
securities of public utility companies. Efforts to repeal PUHCA continue at the
national level. We cannot predict the future of these legislative efforts.
We are subject to the jurisdiction of various regulatory authorities. The MPUC
has regulatory authority over Minnesota Power's service area in Minnesota,
retail rates, retail services, issuance of securities and other matters. The
FERC has jurisdiction over the licensing of hydroelectric projects, the
establishment of rates and charges for the sale of electricity for resale and
transmission of electricity in interstate commerce, and certain accounting and
record keeping practices. The PSCW has regulatory authority over the retail
sales of electricity, water and gas by SWL&P. The MPUC, FERC and PSCW had
regulatory authority over 56%, 7% and 7%, respectively, of our 2004 consolidated
operating revenue.
ELECTRIC RATES. Minnesota Power has historically designed its electric service
rates based on cost of service studies under which allocations are made to the
various classes of customers. Nearly all retail sales include billing adjustment
clauses, which adjust electric service rates for changes in the cost of fuel and
purchased energy, and recovery of current and deferred CIP expenditures.
In addition to Large Power Customer contracts, Minnesota Power also has
contracts with large industrial and commercial customers with monthly demands of
more than 2 MW but less than 10 MW of capacity. The terms of these contracts
vary depending upon the customer's demand for power and the cost of extending
Minnesota Power's facilities to provide electric service.
Minnesota Power requires that all large industrial and commercial customers
under contract specify the date when power is first required. Thereafter, the
customer is generally billed monthly for at least the minimum power for which
they contracted. These conditions are part of all contracts covering power to be
supplied to new large industrial and commercial customers and to current
customers as their contracts expire or are amended. All rates and other contract
terms are subject to approval by appropriate regulatory authorities.
FEDERAL ENERGY REGULATORY COMMISSION. The FERC has jurisdiction over our
wholesale electric service and operations. Minnesota Power's hydroelectric
facilities, which are located in Minnesota, are licensed by the FERC. (See
Environmental Matters - Water.)
Minnesota Power has contracts with 16 Minnesota municipalities receiving
wholesale electric service. One contract is for service through 2005 (8,000 MWh
purchased in 2004) and one expires in 2006, while the other 14 are for service
through at least 2007. In 2004, these municipal customers purchased 712,000 MWh
from Minnesota Power. Minnesota Power also has a contract for wholesale service
to Dahlberg Light & Power Company in Wisconsin. Dahlberg purchased 106,000 MWh
in 2004.
Minnesota Power and SWL&P are members of the MISO. MISO was the first regional
transmission organization (RTO) approved by FERC as meeting its Order No. 2000
criteria. Minnesota Power and SWL&P retain ownership of their respective
transmission assets and control area functions, but their transmission network
is under the regional operational control of the MISO, and they take and provide
transmission service under the MISO open access transmission tariff. MISO
continues its efforts to standardize rates, terms and conditions of transmission
service over the broad region encompassing all or parts of 15 states and one
Canadian province, and over 100,000 MW of generating capacity. MISO operations
were phased in during the first half of 2002. In late 2003, MISO and PJM
Interconnection LLC, a RTO serving all or parts of Pennsylvania, New Jersey, the
District of Columbia, Maryland, Ohio, Virginia, West Virginia, Delaware,
Illinois, Indiana and Kentucky, executed a joint operating agreement. The joint
operating agreement, filed with the FERC, provides detailed information about
each RTO's operations and establishes procedures to strengthen and coordinate
reliability. MISO has continued to develop and implement its operations,
focusing on enhancing transmission system reliability and its performance of
independent market monitoring functions.
Page 9 ALLETE 2004 Form 10-K
Under MISO Day 2, the method by which Minnesota Power transacts wholesale energy
will change, with both Minnesota Power load and generation participating in
MISO's day-ahead and real-time markets. Generation will also become subject to
MISO economic dispatch authority. MISO Day 2 will start up on April 1, 2005. As
a result of MISO Day 2 implementation, energy transactions to serve retail
customers will be sourced by wholesale transactions with MISO as the counter
party. Minnesota Power anticipates filing with the MPUC in February 2005 a
petition to amend the fuel clause to accommodate costs and revenue related to
MISO Day 2 market implementation. We are unable to predict the outcome of this
pending matter.
On November 9, 2004, Minnesota Power and Rainy River Energy jointly filed their
triennial market power analysis with FERC. This filing is a requirement for
Minnesota Power and Rainy River Energy to maintain their market-based rate sales
authority, and the two entities must prove that they lack the ability to
exercise market power. Revised FERC screening methods generally result in
failure to meet one of the screens by integrated utilities that are not
participating in qualified RTOs. A mitigating factor that should allow the
companies to maintain their market-based rate authority is their membership in
MISO, and MISO's move to the Day 2 market (which includes a central energy
market and FERC-approved market power monitoring and mitigation program) in
April 2005.
Minnesota Power also participates in MAPP, a power pool operating in parts of
eight states in the Upper Midwest and in two provinces in Canada. MAPP functions
include a regional transmission committee and a generation reserve-sharing pool.
Minnesota Power is also a member of the Midwest Reliability Organization that
was established as a regional reliability council within the North American
Electric Reliability Council on January 1, 2005.
MINNESOTA PUBLIC UTILITIES COMMISSION. Minnesota Power's retail rates are based
on a 1994 MPUC retail rate order that allows for an 11.6% return on common
equity dedicated to utility plant. Minnesota Power does not expect to file a
request to increase rates for its retail utility operations during 2005. We
will, however, continue to monitor the costs of serving our retail customers and
evaluate the need for a rate filing in the future.
As required by the MPUC, on December 23, 2004, Minnesota Power filed for
approval of a Rider for Distributed Generation Services, along with a revised
Rider for Standby Services, necessary to implement state law and the MPUC's
order regarding the establishment of generic standards for utility tariffs for
interconnection and operation of distributed generation facilities. Distributed
generation is small-scale, customer-based generation. Minnesota Power's filing
utilizes the statewide generic interconnection agreement format, while
implementing a distributed generation rider that is particular to Minnesota
Power's system for the costs of connecting distributed generation systems to
Minnesota Power's distribution system.
In June 2003, the MPUC initiated an investigation into the continuing usefulness
of the fuel clause as a regulatory tool for electric utilities. Minnesota
Power's initial comments on the proposed scope and procedure of the
investigation were filed in July 2003. In November 2003, the MPUC approved the
initial scope and procedure of the investigation. The investigation will focus
on whether the fuel clause continues to be an appropriate regulatory tool. The
initial steps will be to review the clause's original purpose, structure and
rationale (including its current operation and relevance in today's regulatory
environment), and then address its ongoing appropriateness and other issues if
the need for continued use of the fuel adjustment clause is shown. In April
2004, the DOC issued comments providing a wide array of alternatives, including
closing the investigation as one option and eliminating the fuel clause as
another. The MPUC has not taken action on any proposal and, as a result, we are
unable to predict the outcome or impact of this proceeding at this time.
Minnesota requires investor-owned electric utilities to spend a minimum of 1.5%
of gross annual retail electric revenue on CIP each year. These investments are
recovered from retail customers through a billing adjustment and amounts
included in retail base rates. The MPUC allows utilities to accumulate, in a
deferred account for future recovery, all CIP expenditures, as well as a
carrying charge on the deferred account balance. Minnesota Power's CIP
investment goal was $3.1 million for 2004 ($2.9 million for 2003 and 2002), with
actual spending of $3.1 million in 2004 ($5.0 million in 2003; $4.0 million in
2002). These amounts satisfied current spending requirements and all prior
years' spending shortfalls.
In September 2004, Minnesota Power filed our Integrated Resource Plan (Resource
Plan), which predicts that energy demand by customers in our service territory
will increase at an average annual rate of 1.7% over the next decade. Growth of
20 MW to 30 MW per year primarily from residential and smaller commercial
expansion and a positive outlook from Large Power Customers in northeastern
Minnesota, such as taconite processing facilities and paper mills, is included
in the Resource Plan. Minnesota Power will also realize a reduction in
generating resource supply over the next three years, under the terms of a
long-term energy supply contract with Square Butte. The combination of increased
demand and reduced supply means Minnesota Power will need to secure additional
capacity and energy to serve our customers in future years. In the Resource
Plan, we provide several options designed to meet the predicted growing demand
in the region. The options range from purchasing additional power to building
new energy generation facilities. In January 2005, at the DOC's request,
Minnesota Power filed a supplement to the main filing that described a
"representative" resource plan for the DOC's analysis. This plan is considered
preliminary according to the supplemental filing, since Minnesota Power is still
in the process of gathering and analyzing information on potential resources for
actual resource decision-making.
ALLETE 2004 Form 10-K Page 10
A Request for Proposal (RFP) to external bidders for additional supply was
issued by Minnesota Power in October 2004. In December 2004, Minnesota Power
received bids for renewable and non-renewable resources, as well as short- and
long-term purchase offers. All RFP bids are being reviewed for completeness and
compliance with our requirements. A simultaneous, though separate, analysis of
Minnesota Power's self-build and turnkey plant options is also occurring to
arrive at a refined list of those options. Once the RFP bids and
self-build/turnkey options are screened to identify the best choices among them,
a portfolio analysis process will occur, looking at combinations of supply
alternatives to meet our forecasted resource need. We will continue to work with
state regulators and other stakeholders over the next several months to further
develop the Resource Plan and anticipate that the MPUC will formally consider
the Resource Plan during 2005.
PUBLIC SERVICE COMMISSION OF WISCONSIN. SWL&P's current electric retail rates
are based on a September 2001 PSCW retail rate order that allows for a 12.25%
return on common equity and resulted in an average rate decrease of 3.4%.
In June 2004, SWL&P filed an application with the PSCW for authority to increase
retail utility rates an average of 6.1%. This average increase is comprised of a
4.0% increase in electric rates, a 7.0% increase in gas rates and a 12.1%
increase in water rates. The proposed increases are due to increased operating
costs, primarily pension, insurance, gross receipts tax and parent company
service costs. SWL&P is requesting a 12.25% return on common equity. Hearings
took place in January 2005 and a final order is anticipated in the first half of
2005.
In December 2003, the PSCW unanimously approved the revised $420 million cost
estimate for the Wausau-to-Duluth electric transmission line. Minnesota Power
and transmission planners throughout the region believe the 220-mile, 345-kV
transmission line is necessary. Minnesota Power has been actively involved in
the permitting. Construction activities in Minnesota began in January 2004.
Minnesota Power does not intend to finance or own the proposed line.
COMPETITION
INDUSTRY RESTRUCTURING. State efforts across the country to restructure the
electric utility industry have slowed. Legislation or regulation that would
allow retail customer choice of their electric service provider has not gained
momentum in either Minnesota or Wisconsin.
At the national level, the FERC continues in its efforts to have companies join
an RTO. FERC's sweeping Standard Market Design rulemaking, renamed Wholesale
Market Platform, appears to have stalled, although FERC remains committed to
implementing most of the rule in a more piecemeal fashion. Minnesota Power
supports the creation of a robust wholesale electric market.
Potential federal energy legislation would seek to maintain reliability,
increase investments in new transmission capacity and energy supply, and address
wholesale price volatility, while encouraging wholesale competition. These types
of provisions remain the subject of significant controversy. We cannot predict
the timing or substance of any future legislation or regulation.
FRANCHISES
Minnesota Power holds franchises to construct and maintain an electric
distribution and transmission system in 90 cities and towns located within its
electric service territory. SWL&P holds similar franchises for electric, natural
gas and/or water systems in 15 cities and towns within its service territory.
The remaining cities and towns served do not require a franchise to operate
within their boundaries. Our exclusive service territories are established by
state regulatory agencies.
NONREGULATED ENERGY OPERATIONS
BNI COAL owns and operates a lignite mine in North Dakota. BNI Coal is the
lowest-cost supplier of lignite in North Dakota, producing about 4 million tons
annually. Two electric generating cooperatives, Minnkota Power and Square Butte,
presently consume virtually all of BNI Coal's production of lignite under
cost-plus, fixed fee, coal supply agreements expiring in 2027. (See Fuel and
Note 11.) The mining process disturbs and reclaims approximately 210 acres per
year. The law requires that the reclaimed land be at least as productive as it
was prior to mining. That means if the land we mine once grew crops, it must be
able to do so again after reclamation. The cost to reclaim one acre of land
averages about $15,000 and can run as high as $30,000. BNI Coal has the
equipment necessary for the reclamation process. In September 2004, BNI Coal
entered into a master lease agreement with Farm Credit Leasing Services
Corporation (Farm Credit). Under this new agreement, BNI Coal leases a new
dragline that went into operation in October 2004. BNI Coal is obligated to make
lease payments totaling $2.8 million annually for the 23-year lease term, which
expires in 2027. BNI Coal will have the option at the end of the lease term to
renew the lease at a fair market rental, to purchase the dragline at fair market
value, or to surrender the dragline to Farm Credit and pay a $3.0 million
termination fee. With lignite reserves of an estimated 600 million tons combined
with new dragline equipment, BNI Coal has ample capacity to expand production.
Page 11 ALLETE 2004 Form 10-K
NONREGULATED GENERATION. Nonregulated generation is primarily non-rate base
generation sold at market-based rates to the wholesale market. In addition, we
have 18,600 acres of land acquired in 2001 at the time we purchased Taconite
Harbor from LTV Steel Mining Co., which is available for sale. (See Regulated
Utility - Federal Energy Regulatory Commission for MISO Day 2 discussion.)
TACONITE HARBOR. In 2002, we commenced operation of the Taconite Harbor
generating facilities, which we purchased in 2001. The generation output is
primarily being sold in the wholesale market and is sold in limited
circumstances to Minnesota Power's utility customers.
KENDALL COUNTY. In 1999, Rainy River Energy entered into a 15-year power
purchase agreement (Kendall County). The Kendall County agreement includes the
purchase of the output of one entire unit (approximately 275 MW) of a four-unit
(approximately 1,100 MW) natural gas-fired combined cycle generation facility
located near Chicago, Illinois. Construction of the generation facility was
completed in 2002. Rainy River Energy's obligation to pay fixed capacity related
charges began May 1, 2002 and would end in September 2017, unless assigned as
described below. We currently have 130 MW of long-term capacity and energy sales
contracts for the Kendall County generation, with 50 MW expiring in April 2012
and 80 MW expiring in September 2017.
In December 2004, Rainy River Energy entered into an agreement to assign its
Kendall County agreement to Constellation Energy Commodities. Under the terms of
the agreement, Rainy River Energy will pay Constellation Energy Commodities $73
million in cash (approximately $47 million after taxes) to assume the Kendall
County agreement. The proposed transaction is subject to the approvals of
LSP-Kendall Energy, the owner of the energy generation facility, as well as of
its project lenders and the FERC. Pending these approvals, the transaction is
scheduled to close in April 2005. The long-term capacity and energy sales
contracts will also be transferred to Constellation Energy Commodities at
closing.
RAINY RIVER ENERGY is engaged in the acquisition and development of nonregulated
generation and wholesale power marketing. Rainy River Energy is a party to the
15-year Kendall County agreement that is expected to be assigned in April 2005.
(See Nonregulated Generation - Kendall County.)
RAINY RIVER ENERGY CORPORATION - WISCONSIN continues to study the feasibility of
the construction of a natural gas-fired electric generating facility in
Superior, Wisconsin. In accordance with the PSCW's final order approving the
project, Rainy River Energy Corporation - Wisconsin undertook preliminary site
preparation work in late 2003.
In 2004, we sold 1.5 million MWh of nonregulated generation (1.5 million in
2003; 1.2 million in 2002).
UNIT YEAR YEAR NET
NONREGULATED POWER SUPPLY NO. INSTALLED ACQUIRED CAPABILITY
- ------------------------------------------------------------------------------------------------------------------------
MW
Steam
Coal-Fired
Taconite Harbor Energy Center 1, 2 & 3 1957, 1957, 1967 2001 200
in Taconite Harbor, MN
Cloquet Energy Center 5 2001 2001 23
in Cloquet, MN
Rapids Energy Center 6 & 7 1980 2000 29
in Grand Rapids, MN
- ------------------------------------------------------------------------------------------------------------------------
Hydro
Conventional Run-of-River
Rapids Energy Center 4 & 5 1917 2000 1
in Grand Rapids, MN
- ------------------------------------------------------------------------------------------------------------------------
Power Purchase Agreement
Kendall County (Rainy River Energy) 3 2002 2002 275
located southwest of Chicago, IL
- ------------------------------------------------------------------------------------------------------------------------
The net generation is primarily dedicated to the needs of one customer.
Expected to be transferred in April 2005.
ALLETE 2004 Form 10-K Page 12
REAL ESTATE
ALLETE Properties is our real estate business that has operated in Florida since
1991. ALLETE Properties acquires real estate portfolios and large land tracts at
bulk prices, adds value through entitlements and/or infrastructure improvements,
and resells the property over time to developers, end-users and investors.
Management at ALLETE Properties uses their business relationships, understanding
of real estate markets and expertise in the land development and sales processes
to provide revenue and earnings growth opportunities to ALLETE.
ALLETE Properties is headquartered in Fort Myers, Florida, the location of its
southwest Florida regional office. We also have a regional office in Palm Coast,
Florida, which oversees northeast Florida operations.
Southwest Florida operations consist of land sales and third-party brokerage
businesses, with limited land development activities. Inventory includes
commercial and residential land located in Lehigh Acres and Cape Coral. The
property represents the remaining properties acquired in 1991 from the
Resolution Trust Corporation and in 1999 from Avatar Properties, Inc. The
operation also generates rental income from a 186,000 square foot retail
shopping center located in Winter Haven, Florida. The center is anchored by
Burdines-Macy's and Belk's department stores, along with Staples.
Northeast Florida operations focus on land sales and development activities.
Development activities involve mainly zoning, permitting, platting and master
infrastructure construction. Development costs are financed through a
combination of community development districts, bank loans, and company funds.
Our three major development projects include Town Center at Palm Coast, Palm
Coast Park and Ormond Crossings.
Town Center at Palm Coast is a mixed-use, planned development with a
neo-traditional downtown design. Surrounded by major arterial roads, including
Interstate 95, the development was selected as the site for the City of Palm
Coast's new city hall and is adjacent to the local hospital, county airport and
high school. At build-out, the development is expected to include 2,950
residential units, 2.2 million square feet of commercial space, and 1.4 million
square feet of office space. Actual build-out will depend on future market
conditions. All major land use approvals for the project have been received.
Platting, infrastructure construction and marketing efforts continue.
Palm Coast Park is a mixed-use, planned development located in northwest Palm
Coast along U.S. Highway 1, one mile south of its intersection with Interstate
95, with major rail line access. At build-out, the project is expected to
include 3,600 residential units, 1.6 million square feet of commercial space,
800,000 square feet of office space and 800,000 square feet of industrial use.
Actual build-out will depend on future market conditions. In December 2004, we
received development order approval for the project. Platting and infrastructure
design are proceeding.
Ormond Crossings is a mixed-use, planned development located along Interstate
95, at its interchange with U.S. Highway 1, in northwest Ormond Beach. This
property has three miles of frontage on the east and west sides of Interstate
95, is adjacent to the local airport and has access to a major railroad line. In
2004, the property was annexed into the City of Ormond Beach and land-use
approvals are in progress. Once approvals are received, the project build-out
mix can be estimated.
In addition to the major development projects, land inventories in Florida
include 5,200 acres of property. Several smaller development projects are under
way to plat these properties, and modify and enhance existing zonings.
Property sale prices may vary depending on location; parcel size; whether
parcels are sold as raw land, partially developed land or individually developed
lots; degree and status of entitlement; and whether the land is ultimately
purchased for residential, commercial or other form of development.
ALLETE Properties occasionally provides seller financing, and outstanding
finance receivables were $9.7 million at December 31, 2004, with maturities
ranging up to ten years. Outstanding finance receivables accrue interest at
market-based rates.
SUMMARY OF DEVELOPMENT PROJECTS TOTAL RESIDENTIAL COMMERCIAL OFFICE INDUSTRIAL
AT DECEMBER 31, 2004 OWNERSHIP ACRES UNITS SQ. FT. SQ. FT. SQ. FT.
- --------------------------------------------------------------------------------------------------------------------------------
Town Center at Palm Coast 80% 1,550 2,950 2,175,000 1,350,000 -
Palm Coast Park 100% 4,705 3,600 1,600,000 800,000 800,000
Ormond Crossings 100% 5,850 - - - -
- --------------------------------------------------------------------------------------------------------------------------------
12,105 6,550 3,775,000 2,150,000 800,000
- --------------------------------------------------------------------------------------------------------------------------------
Acreage amounts are approximate and shown on a gross basis, including wetlands and minority interest. Acreage amounts may
vary due to platting or surveying activity. Wetland amounts vary by property and are often not formally determined prior
to sale.
Estimated and includes minority interest. The actual property breakdown at full build-out may be different than the
estimates.
Units and square footage have not been determined.
Page 13 ALLETE 2004 Form 10-K
SUMMARY OF OTHER LAND INVENTORIES
AT DECEMBER 31, 2004 OWNERSHIP TOTAL MIXED USE RESIDENTIAL COMMERCIAL AGRICULTURAL
- ------------------------------------------------------------------------------------------------------------------------
ACRES
Palm Coast Holdings 80% 3,099 2,040 513 291 255
Lehigh 80% 1,082 840 140 93 9
Cape Coral 100% 104 - 1 103 -
Other 100% 908 - - - 908
- ------------------------------------------------------------------------------------------------------------------------
5,193 2,880 654 487 1,172
- ------------------------------------------------------------------------------------------------------------------------
Acreage amounts are approximate and shown on a gross basis, including wetlands and minority interest. Acreage
amounts may vary due to platting or surveying activity. Wetland amounts vary by property and are often not
formally determined prior to sale. The actual property breakdown at full build-out may be different than the
estimates.
REGULATION
A substantial portion of our development properties in Florida is subject to
federal, state and local regulations, and restrictions that may impose
significant costs or limitations on our ability to develop the properties. Much
of our property is vacant land and some is located in areas where development
may affect the natural habitats of various protected wildlife species or in
sensitive environmental areas such as wetlands.
Development of real property in Florida entails an extensive approval process
involving overlapping regulatory jurisdictions. Real estate projects must
generally comply with the provisions of the Local Government Comprehensive
Planning and Land Development Regulation Act (Growth Management Act). In
addition, development projects that exceed certain specified regulatory
thresholds require approval of a comprehensive Development of Regional Impact
(DRI) application. The Growth Management Act requires counties and cities to
adopt comprehensive plans guiding and controlling future real property
development in their respective jurisdictions. The DRI review process includes
an evaluation of a project's impact on the environment, infrastructure and
government services, and requires the involvement of numerous state and local
environmental, zoning and community development agencies. Compliance with the
Growth Management Act and the DRI process is usually lengthy and costly.
COMPETITION
The real estate industry is very competitive. Our properties are located in
Florida, which continues to attract competitive real estate operations at many
different levels in the land development pipeline. Competitors include local and
out of state institutional investors, real estate investment trusts and real
estate operators, among others. These competitors, both public and private
alike, compete with us in seeking real estate for acquisition, resources for
development and sales to prospective buyers. Consequently, competitive market
conditions may influence the timing and profitability of our real estate
transactions.
ALLETE 2004 Form 10-K Page 14
OTHER
Our Other segment consists of our telecommunications business, investments in
emerging technologies related to the electric utility industry, earnings on
cash, and general corporate charges and interest not specifically related to any
one business segment. General corporate charges include employee salaries and
benefits, as well as legal and other outside service fees.
ENVENTIS TELECOM is an integrated data services provider offering fiber
optic-based communication and advanced data services to businesses and
communities in the Upper Midwest. Enventis Telecom provides converged IP (or
Internet Protocol) services that allow all communications (voice, video and
data) to use the same fiber optic-based delivery technology. Enventis Telecom
owns or has rights to approximately 1,600 route miles of fiber optic cable.
These route miles contain multiple fibers that total approximately 47,000 fiber
miles. We also have extensive local fiber optic rings that directly connect
Enventis Telecom network with its larger clients (health care, government,
education, etc.). Other local fiber rings connect Enventis Telecom's network to
the local telephone company's central offices, from which locations Enventis
Telecom can utilize the telephone company's connections to access our smaller
clients. Enventis Telecom also owns optronic and data switching equipment that
is used to "light up" the fiber optic cable. We serve customers from facilities
that are primarily leased from third parties. Enventis Telecom has offices in
Duluth, Rochester, Plymouth and Bloomington, Minnesota. Enventis Telecom has a
strong business relationship with Cisco Systems, Inc. and is recognized by Cisco
Systems as a Gold Partner. Enventis Telecom is a regional leader in deploying
leading edge technologies such as Voice over Internet (VoIP) technology and IP
Call Centers.
EMERGING TECHNOLOGY PORTFOLIO. As part of our emerging technology portfolio, we
have several minority investments in venture capital funds and direct
investments in privately-held, start-up companies. Since 1985, we have invested
in start-up companies, which are developing technologies that may be utilized by
the electric utility industry. We are committed to invest an additional $4.5
million at various times through 2007 and do not have plans to make any
additional investments. The investments were first made through emerging
technology funds (Funds) initiated by other electric utilities and us. We have
also made investments directly in privately-held companies.
Companies in the Funds' portfolios may complete IPOs, and the Funds may, in some
instances, distribute publicly tradable shares to us. Some restrictions on sales
may apply, including but not limited to underwriter lock-up periods that
typically extend for 180 days following an IPO. As companies included in our
emerging technology portfolio are sold, we will recognize a gain or loss.
We account for our investment in venture capital funds under the equity method
and account for our direct investment in privately-held companies under the cost
method. The total carrying value of our emerging technology portfolio was $13.6
million at December 31, 2004, down $23.9 million from December 31, 2003. The
decline was primarily due to a change to the equity method of accounting for the
venture capital funds (see Note 14) and impairments related to investments in
privately-held companies. Our policy is to review these investments quarterly
for impairment by assessing such factors as continued commercial viability of
products, cash flow and earnings. Any impairment would reduce the carrying value
of the investment. In 2004, we recorded $6.5 million ($4.1 million after tax) of
impairment losses primarily related to direct investments in certain
privately-held, start-up companies whose future business prospects have
diminished significantly. Recent developments at these companies indicated that
future commercial viability is unlikely, as is new financing necessary to
continue development.
ENVIRONMENTAL MATTERS
Our businesses are subject to regulation by various federal, state and local
authorities concerning environmental matters. We consider our businesses to be
in substantial compliance with those environmental regulations currently
applicable to their operations and believe all necessary permits to conduct such
operations have been obtained. We anticipate that potential expenditures for
environmental matters will be material in the future, due to stricter
environmental requirements through legislation and/or rulemakings that are
expected to require significant capital investments. We are unable to predict if
and when any such stricter environmental requirements will be imposed and the
impact they will have on the Company. We review environmental matters on a
quarterly basis. Accruals for environmental matters are recorded when it is
probable that a liability has been incurred and the amount of the liability can
be reasonably estimated, based on current law and existing technologies. These
accruals are adjusted periodically as assessment and remediation efforts
progress or as additional technical or legal information becomes available.
Accruals for environmental liabilities are included in the balance sheet at
undiscounted amounts and exclude claims for recoveries from insurance or other
third parties. Costs related to environmental contamination treatment and
cleanup are charged to expense unless recoverable in rates from customers.
AIR. CLEAN AIR ACT. Minnesota Power's generating facilities mainly burn
low-sulfur western sub-bituminous coal and the Square Butte generating facility,
located in North Dakota, burns lignite coal. All of these facilities are
equipped with pollution control equipment such as scrubbers, baghouses or
electrostatic precipitators. The federal Clean Air Act Amendments of 1990 (Clean
Air Act) created emission allowances for sulfur dioxide. Each allowance is an
authorization to emit one ton of sulfur dioxide, and each utility must have
sufficient allowances to cover its annual emissions. Emission requirements are
currently being met by all of Minnesota Power's generating facilities. Most
Minnesota Power facilities
Page 15 ALLETE 2004 Form 10-K
have surplus sulfur dioxide emission allowances. Taconite Harbor is meeting its
sulfur dioxide emission allowance requirements by annually purchasing
allowances, since it receives no allowance allocation. The Square Butte
generating facility is meeting its sulfur dioxide emission allowance
requirements through increased use of existing scrubbers.
In accordance with the Clean Air Act, the EPA has established nitrogen oxide
limitations for electric generating units. To meet nitrogen oxide limitations,
Minnesota Power installed advanced low-emission burner technology and associated
control equipment to operate the Boswell and Laskin facilities at or below the
compliance emission limits. Nitrogen oxide limitations at Taconite Harbor and
Square Butte are being met by combustion tuning.
MERCURY EMISSIONS. In December 2000, the EPA announced its decision to regulate
mercury emissions from coal and oil-fired power plants under Section 112 of the
Clean Air Act. Section 112 will require all such power plants in the United
States to adhere to the EPA maximum achievable control technology standards for
mercury. The EPA issued a proposed rule in December 2003. Final regulations
defining control requirements are planned for March 2005. The proposed rule
offers two different types of regulation: (1) imposition of an annual average
mercury emission limitation applied at each unit or facility average under
Section 112; and (2) imposition of a cap and trade program under Section 111,
where an allocation of mercury credits would be assigned and utilities would
need to provide for a combination of emission reductions and credit purchases to
demonstrate compliance. The EPA has solicited comments about these approaches.
In either approach, continuous monitoring of mercury stack emissions is required
to be in service around 2008. Minnesota Power's preliminary estimates suggest
that all of our affected facilities can be outfitted with continuous mercury
emission monitors for under $2 million. Our unit mercury emissions tests
indicate that all of our units are expected to comply with the proposed unit
specific target emission rate without significant additional cost. Cost
estimates about mercury cap and trade program impacts are premature at this
time. The EPA is still reviewing comments about this proposed alternative
program and associated final mercury credit allocations to units that have not
yet been defined.
NEW SOURCE REVIEW RULES. In December 2002, the EPA issued changes to the
existing New Source Review rules. These rules changed the procedures for MPCA
review of projects at our electric generating facilities. In October 2003, the
EPA announced changes clarifying the application of certain sections of the New
Source Review rules. These changes are not expected to have a material impact on
Minnesota Power. In December 2003, the U.S. Court of Appeals for the District of
Columbia Circuit stayed the implementation of the October 2003 rule pending
their further review, which is expected in 2006. Subsequently, the EPA has
announced they are accepting further public comments on the proposed New Source
Review rule revisions.
The EPA is pursuing an industry-wide investigation assessing compliance with the
New Source Review and the New Source Performance Standards (emissions standards
that apply to new and changed units) of the Clean Air Act at electric generating
stations. There is also ongoing litigation involving the EPA and other electric
utilities for alleged violations of these rules. It is expected that the outcome
of some of the cases could provide the utility industry direction on this topic.
We are unable to predict what actions, if any, may be required.
In June 2002, Minnkota Power, the operator of Square Butte, received a Notice of
Violation from the EPA regarding alleged New Source Review violations at the
M.R. Young Station, which includes the Square Butte generating unit. The EPA
claims certain capital projects completed by Minnkota Power should have been
reviewed pursuant to the New Source Review regulations, potentially resulting in
new air permit operating conditions. Discussions with the EPA are ongoing and we
are unable to predict the outcome or cost impacts. If Square Butte is required
to make significant capital expenditures to comply with EPA requirements, we
expect such capital expenditures to be debt financed. Our future cost of
purchased power would include our pro rata share of this additional debt
service. (See Note 11.)
WATER. The Federal Water Pollution Control Act requires National Pollutant
Discharge Elimination System (NPDES) permits to be obtained from the EPA (or,
when delegated, from individual state pollution control agencies) for any
wastewater discharged into navigable waters. Minnesota Power has obtained all
necessary NPDES permits, including NPDES storm water permits for applicable
facilities, to conduct its electric operations.
FERC LICENSES. Minnesota Power holds FERC licenses authorizing the ownership and
operation of seven hydroelectric generating projects with a total generating
capacity of about 115 MW. In June 1996, Minnesota Power filed in the U.S. Court
of Appeals for the District of Columbia Circuit a petition for review of the
license as issued by the FERC for Minnesota Power's St. Louis River Hydro
Project. Separate petitions for review were also filed by the U.S. Department of
the Interior and the Fond du Lac Band of Lake Superior Chippewa (Fond du Lac
Band), two intervenors in the licensing proceedings. Beginning in 1996, and most
recently in February 2005, Minnesota Power filed requests with the FERC for
extensions of time to comply with certain plans and studies required by the
license that might conflict with settlement discussions. The Fond du Lac Band,
the U.S. Department of the Interior and Minnesota Power have reached a
settlement agreement for the St. Louis River Hydro Project. This settlement must
be approved by the FERC. Upon approval, the FERC would then amend the project
license to reflect the conditions of the settlement agreement. Minnesota Power
submitted an application for amendment of the FERC license, based upon the terms
and conditions of the settlement agreement in November 2004. In addition to a
one-time retroactive payment of approximately $600,000, the Company estimates
that it will spend $100,000 to $250,000 per year for the use of tribal lands, to
fund fishery and natural resource enhancements by the Fond du Lac Band and the
Minnesota Department of Natural Resources, and to conduct a mercury study under
the terms of the settlement.
ALLETE 2004 Form 10-K Page 16
CLEAN WATER ACT - AQUATIC ORGANISMS. In July 2004, the EPA issued Section 316(b)
Phase II Rule of the Clean Water Act to ensure that the location, design,
construction and capacity of cooling water intake structures at electric
generating facilities reflect the best technology available to protect aquatic
organisms from being killed or injured by impingement (being pinned against
screens or other parts of a cooling water intake structure) or entrainment
(being drawn into cooling water systems and subjected to thermal, physical or
chemical stresses). It requires electric generating facilities that withdraw
more than 50 million gallons of cooling water per day and that use 25% of
withdrawn water for cooling purposes only to reduce fish impingement by 80% to
95% and fish entrainment by 60% to 90%. The new rule for fish impingement
requirements apply to the Boswell, Laskin, Hibbard and Square Butte generating
facilities. The impingement and entrainment requirements apply to Taconite
Harbor because it is located on Lake Superior. The rule requires biological
studies and engineering analyses to be performed within the 2005 to 2008 time
frame. The estimated total cost of these studies for our facilities is expected
to be in the range of $0.5 million to $1.0 million. If modifications and/or
installation of intake structure technology (wedge-wire screens, fine mesh
traveling screens, etc.) are needed, these capital costs are not expected to be
incurred until 2009 to 2011. Due to the flexibility of compliance options and
litigation activities related to the new rule, it is not possible to estimate
the capital expenditures that may be required.
SOLID AND HAZARDOUS WASTE. The Resource Conservation and Recovery Act of 1976
regulates the management and disposal of solid wastes and hazardous wastes. As a
result of this legislation, the EPA has promulgated various hazardous waste
rules. Minnesota Power is required to notify the EPA of hazardous waste activity
and routinely submits the necessary annual reports to the EPA. The MPCA and the
Wisconsin Department of Natural Resources (WDNR) are responsible for
administering solid and hazardous waste rules on the state level with oversight
by the EPA.
PCB INVENTORIES. In response to the EPA Region V's request for utilities to
participate in the Great Lakes Initiative by voluntarily removing remaining
polychlorinated biphenyl (PCB) inventories, Minnesota Power has scheduled
replacement of PCB capacitor banks and PCB-contaminated oil by the end of 2005.
The total cost is expected to be about $2 million, of which $1.5 million was
spent through December 31, 2004.
SWL&P MANUFACTURED GAS PLANT. In May 2001, SWL&P received notice from the WDNR
that the City of Superior had found soil contamination on property adjoining a
former Manufactured Gas Plant (MGP) site owned and operated by SWL&P's
predecessors from 1889 to 1904. The WDNR requested SWL&P to initiate an
environmental investigation. The WDNR also issued SWL&P a Responsible Party
letter in February 2002. The environmental investigation is under way. In
February 2003, SWL&P submitted a Phase II environmental site investigation
report to the WDNR. This report identified some MGP-like chemicals that were
found in the soil near the former plant site. During March and April 2003,
sediment samples were taken from nearby Superior Bay. The report on the results
of this sampling was completed and sent to the WDNR during the first quarter of
2004. The next phase of the investigation is to determine any impact to soil or
ground water between the former MGP site and Superior Bay. The site work for
this phase of the investigation was performed during October 2004, and the final
report is expected to be sent to the WDNR during the first quarter of 2005. It
is anticipated that additional site investigation will be needed during 2005.
Although it is not possible to quantify the potential clean-up cost until the
investigation is completed, a $0.5 million liability was recorded in December
2003 to address the known areas of contamination. We have recorded a
corresponding dollar amount as a regulatory asset to offset this liability. The
PSCW has approved SWL&P's deferral of these MGP environmental investigation and
potential clean-up costs for future recovery in rates, subject to a regulatory
prudency review. ALLETE maintains pollution liability insurance coverage that
includes coverage for SWL&P. A claim has been filed with respect to this matter.
The insurance carrier has issued a reservation of rights letter and we continue
to work with the insurer to determine the availability of insurance coverage.
EMPLOYEES
At December 31, 2004, ALLETE had 1,500 employees, of which 1,400 were full-time.
Minnesota Power, SWL&P and Enventis Telecom have 621 employees who are members
of the International Brotherhood of Electrical Workers (IBEW), Local 31. A
two-year labor agreement between Minnesota Power and Local 31, which includes
Enventis Telecom, is in effect through January 31, 2006, as is the agreement
with SWL&P. The agreements provided wage increases of 3.25% in each of the two
contract years.
BNI Coal has 95 employees who are members of the IBEW Local 1593. BNI Coal and
Local 1593 have a labor agreement, which expires on March 31, 2005. Negotiations
are under way for a new contract.
Page 17 ALLETE 2004 Form 10-K
EXECUTIVE OFFICERS OF THE REGISTRANT
EXECUTIVE OFFICERS INITIAL EFFECTIVE DATE
- --------------------------------------------------------------------------------------------------------------------------
DONALD J. SHIPPAR, Age 55
President and Chief Executive Officer - ALLETE January 21, 2004
Executive Vice President - ALLETE and President - Minnesota Power May 13, 2003
President and Chief Operating Officer - Minnesota Power January 1, 2002
DEBORAH A. AMBERG, Age 39
Vice President, General Counsel and Secretary March 8, 2004
WARREN L. CANDY, Age 55
Senior Vice President - Utility Operations February 1, 2004
LAURA A. HOLQUIST, Age 43
President - ALLETE Properties September 6, 2001
DAVID J. MCMILLAN, Age 43
Senior Vice President - Marketing and Public Affairs October 2, 2003
MARK A. SCHOBER, Age 49
Senior Vice President and Controller February 1, 2004
Vice President and Controller April 18, 2001
Controller March 1, 1993
DONALD W. STELLMAKER, Age 47
Treasurer July 24, 2004
TIMOTHY J. THORP, Age 50
Vice President - Investor Relations July 1, 2004
Vice President - Investor Relations and Corporate Communications November 16, 2001
JAMES K. VIZANKO, Age 51
Senior Vice President and Chief Financial Officer July 24, 2004
Senior Vice President, Chief Financial Officer and Treasurer January 21, 2004
Vice President, Chief Financial Officer and Treasurer August 28, 2001
Vice President and Treasurer April 18, 2001
Treasurer March 1, 1993
CLAUDIA SCOTT WELTY, Age 52
Senior Vice President and Chief Administrative Officer February 1, 2004
All of the executive officers have been employed by us for more than five years
in executive or management positions. Prior to election to the positions shown
above, the following executives held other positions with the Company during the
past five years.
MR. SHIPPAR was chief operating officer of Minnesota Power.
MS. AMBERG was a senior attorney.
MR. CANDY was a vice president of Minnesota Power.
MS. HOLQUIST was senior vice president of MP Real Estate Holdings, Inc.,
and vice president and chief financial officer of Lehigh Acquisition
Corporation.
MR. MCMILLAN was senior vice president strategic accounts and governmental
affairs, and a vice president of Minnesota Power.
MR. STELLMAKER was director of financial planning, and manager of corporate
finance, planning and budgets.
MR. THORP was director of investor relations.
MS. WELTY was vice president strategy and technology development.
There are no family relationships between any of the executive officers. All
officers and directors are elected or appointed annually.
The present term of office of the executive officers listed above extends to the
first meeting of our Board of Directors after the next annual meeting of
shareholders. Both meetings are scheduled for May 10, 2005.
ALLETE 2004 Form 10-K Page 18
ITEM 2. PROPERTIES
Properties are included in the discussion of our business in Item 1 and are
incorporated by reference herein.
ITEM 3. LEGAL PROCEEDINGS
Material legal and regulatory proceedings are included in the discussion of our
business in Item 1 and are incorporated by reference herein.
We are involved in litigation arising in the normal course of business. Also in
the normal course of business, we are involved in tax, regulatory and other
governmental audits, inspections, investigations and other proceedings that
involve state and federal taxes, safety, compliance with regulations, rate base
and cost of service issues, among other things. While the resolution of such
matters could have a material effect on earnings and cash flows in the year of
resolution, none of these matters are expected to change materially our present
liquidity position, nor have a material adverse effect on our financial
condition.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth
quarter of 2004.
Page 19 ALLETE 2004 Form 10-K
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
We have paid dividends without interruption on our common stock since 1948. A
quarterly dividend of $0.30 per share on our common stock will be paid on March
1, 2005 to the holders of record on February 15, 2005. Our common stock is
listed on the New York Stock Exchange under the symbol ALE and our CUSIP number
is 018522300 (formerly 018522102). Dividends paid per share, and the high and
low prices for our common stock for the periods indicated as reported by the New
York Stock Exchange on its NYSEnet website, are in the accompanying chart.
The amount and timing of dividends payable on our common stock are within the
sole discretion of our Board of Directors. In 2004, we paid out 77% of our per
share earnings in dividends.
Our Articles of Incorporation, and Mortgage and Deed of Trust contain
provisions, which under certain circumstances would restrict the payment of
common stock dividends. As of December 31, 2004, no retained earnings were
restricted as a result of these provisions. At February 1, 2005, there were
approximately 33,000 common stock shareholders of record.
2004 2003
--------------------------------------------------------------------------------------------
PRICE RANGE DIVIDENDS PRICE RANGE DIVIDENDS
QUARTER HIGH LOW PAID HIGH LOW PAID
- -----------------------------------------------------------------------------------------------------------------------------
First $35.52 $30.00 $0.8475 $24.05 $18.75 $0.8475
Second 36.71 31.62 0.8475 26.70 20.50 0.8475
Third 27.86 25.45 0.8475
July 1 - Sept. 20 33.70 26.02 0.8475
Sept. 21 - Sept. 30 32.54 30.76 -
Fourth 37.46 32.20 0.3000 31.00 27.05 0.8475
- -----------------------------------------------------------------------------------------------------------------------------
Annual Total $2.8425 $3.39
- -----------------------------------------------------------------------------------------------------------------------------
Price ranges prior to September 21, 2004 are not comparable due to the spin-off of Automotive Services on September 20,
2004 (see Note 3) and do not reflect the one-for-three reverse stock split (see Note 9).
Adjusted for the September 20, 2004 one-for-three reverse stock split.
TOTAL NUMBER MAXIMUM
OF SHARES NUMBER OF
PURCHASED AS SHARES THAT
PART OF MAY YET BE
TOTAL PUBLICLY PURCHASED
ALLETE COMMON STOCK REPURCHASES NUMBER OF AVERAGE ANNOUNCED UNDER THE
FOR THE QUARTER ENDED SHARES PRICE PAID PLANS OR PLANS OR
DECEMBER 31, 2004 PURCHASED PER SHARE PROGRAMS PROGRAMS
- -----------------------------------------------------------------------------------------------------------------------
For the Calendar Month
October 80,600 $33.65 - -
November 669,578 $35.05 - -
December 262,600 $35.93 - -
- -----------------------------------------------------------------------------------------------------------------------
1,012,778 $35.16 - -
- -----------------------------------------------------------------------------------------------------------------------
Reflected shares of ALLETE common stock repurchased pursuant to the ALLETE Retirement Savings and Stock Ownership
Plan in connection with the spin-offof ADESA. (See Note 17.)
ALLETE 2004 Form 10-K Page 20
ITEM 6. SELECTED FINANCIAL DATA
Operating results of our Water Services businesses, our Automotive Services
business, and our retail stores are included in discontinued operations, and
accordingly, amounts have been adjusted for all periods presented. (See Note 3.)
Common share and per share amounts have also been adjusted for all periods to
reflect our September 20, 2004 one-for-three common stock reverse split.
2004 2003 2002 2001 2000
- ----------------------------------------------------------------------------------------------------------------------------
MILLIONS
BALANCE SHEET
Assets
Current Assets $ 366.1 $ 223.3 $ 190.7 $ 320.4 $ 266.2
Discontinued Operations - Current 2.0 476.7 471.4 575.1 464.8
Property, Plant and Equipment 883.1 919.3 880.5 877.3 792.4
Investments 124.5 175.7 170.9 155.4 116.5
Other Assets 52.8 59.0 62.0 67.6 60.1
Discontinued Operations - Other 2.9 1,247.3 1,371.7 1,286.7 1,214.0
- ----------------------------------------------------------------------------------------------------------------------------
$1,431.4 $3,101.3 $3,147.2 $3,282.5 $2,914.0
- ----------------------------------------------------------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current Liabilities $ 96.7 $ 185.5 $ 438.7 $ 343.7 $ 430.3
Discontinued Operations - Current 12.0 340.7 299.5 360.8 276.7
Long-Term Debt 390.2 514.7 567.7 836.0 720.5
Mandatorily Redeemable Preferred Securities - - 75.0 75.0 75.0
Other Liabilities 302.0 305.4 296.4 274.8 261.4
Discontinued Operations - 294.8 237.5 248.4 249.3
Shareholder's Equity 630.5 1,460.2 1,232.4 1,143.8 900.8
- ----------------------------------------------------------------------------------------------------------------------------
$1,431.4 $3,101.3 $3,147.2 $3,282.5 $2,914.0
- ----------------------------------------------------------------------------------------------------------------------------
INCOME STATEMENT
Operating Revenue
Regulated Utility $555.0 $510.0 $497.9 $535.0 $528.0
Nonregulated Energy Operations 106.8 106.6 84.7 50.4 49.0
Real Estate 41.9 42.6 33.6 61.1 52.5
Other 47.7 33.1 26.8 23.7 2.4
- ----------------------------------------------------------------------------------------------------------------------------
751.4 692.3 643.0 670.2 631.9
- ----------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Fuel and Purchased Power 287.9 252.5 234.8 230.7 229.0
Operating and Maintenance 285.1 263.1 250.9 254.1 227.3
Depreciation 49.7 51.2 48.9 46.2 46.7
Taxes Other than Income 28.9 29.4 30.2 24.9 33.3
- ----------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 651.6 596.2 564.8 555.9 536.3
- ----------------------------------------------------------------------------------------------------------------------------
Operating Income from Continuing Operations 99.8 96.1 78.2 114.3 95.6
- ----------------------------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest Expense (31.8) (50.6) (49.3) (47.7) (43.8)
Other (12.1) 2.5 8.1 16.6 29.2
Income from Investment in ACE Limited - - - - 48.0
- ----------------------------------------------------------------------------------------------------------------------------
Total Other Income (Expense) (43.9) (48.1) (41.2) (31.1) 33.4
- ----------------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations
Before Income Taxes 55.9 48.0 37.0 83.2 129.0
Income Tax Expense 16.8 18.2 12.3 29.1 42.0
- ----------------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations Before
Change in Accounting Principle 39.1 29.8 24.7 54.1 87.0
Income from Discontinued Operations - Net of Tax 73.1 206.6 112.5 84.6 61.6
Change in Accounting Principle - Net of Tax (7.8) - - - -
- ----------------------------------------------------------------------------------------------------------------------------
Net Income 104.4 236.4 137.2 138.7 148.6
Preferred Dividends - - - - 0.9
- ----------------------------------------------------------------------------------------------------------------------------
Earnings Available for Common Stock 104.4 236.4 137.2 138.7 147.7
Common Stock Dividends 79.7 93.2 89.2 81.8 74.5
- ----------------------------------------------------------------------------------------------------------------------------
Retained in Business $ 24.7 $143.2 $48.0 $56.9 $73.2
- ----------------------------------------------------------------------------------------------------------------------------
See Note 14.
Page 21 ALLETE 2004 Form 10-K
2004 2003 2002 2001 2000
- ----------------------------------------------------------------------------------------------------------------------------
Shares Outstanding - Million
Year-End 29.7 29.1 28.5 28.0 24.9
Average
Basic 28.3 27.6 27.0 25.3 23.3
Diluted 28.4 27.8 27.2 25.5 23.4
Diluted Earnings (Loss) Per Share
Continuing Operations $1.37 $1.08 $0.91 $2.12 $3.69
Discontinued Operations 2.57 7.44 4.13 3.32 2.63
Change in Accounting Principle (0.27) - - - -
- ----------------------------------------------------------------------------------------------------------------------------
$3.67 $8.52 $5.04 $5.44 $6.32
- ----------------------------------------------------------------------------------------------------------------------------
Return on Common Equity 8.3% 17.7% 11.4% 13.3% 17.1%
Common Equity Ratio 61.7% 64.4% 51.7% 49.9% 46.3%
Dividends Paid Per Share $2.8425 $3.39 $3.30 $3.21 $3.21
Dividend Payout 77% 40% 66% 59% 51%
Book Value Per Share at Year-End $21.23 $50.18 $43.24 $40.85 $36.18
Employees 1,515 13,115 14,181 13,763 12,633
Net Income (Loss)
Regulated Utility $ 42.8 $ 37.9 $ 50.4 $ 49.4 $ 43.4
Nonregulated Energy Operations (0.3) 3.7 (8.7) 0.7 1.3
Real Estate 14.7 14.1 11.2 20.8 12.9
Other (18.1) (25.9) (28.2) (16.8) 29.4
- ----------------------------------------------------------------------------------------------------------------------------
Continuing Operations 39.1 29.8 24.7 54.1 87.0
Discontinued Operations 73.1 206.6 112.5 84.6 61.6
Change in Accounting Principle (7.8) - - - -
- ----------------------------------------------------------------------------------------------------------------------------
$104.4 $236.4 $137.2 $138.7 $148.6
- ----------------------------------------------------------------------------------------------------------------------------
Average Electric Customers - Thousands 150.1 148.2 146.8 145.7 144.0
Electric Sales - Millions of MWh
Regulated Utility 11.2 11.1 11.1 10.9 11.7
Nonregulated Energy Operations 1.5 1.5 1.2 0.2 0.2
Company Use and Losses 0.9 0.7 0.7 0.7 0.6
- ----------------------------------------------------------------------------------------------------------------------------
13.6 13.3 13.0 11.8 12.5
- ----------------------------------------------------------------------------------------------------------------------------
Power Supply - Millions of MWh
Regulated Utility
Steam Generation 6.5 7.1 7.2 6.9 6.4
Hydro Generation 0.5 0.4 0.5 0.5 0.5
Long-Term Purchases - Square Butte 2.0 2.3 2.3 1.9 2.3
Purchased Power 3.0 1.9 1.8 2.3 3.1
- ----------------------------------------------------------------------------------------------------------------------------
12.0 11.7 11.8 11.6 12.3
- ----------------------------------------------------------------------------------------------------------------------------
Nonregulated Energy Operations
Steam 1.2 1.2 0.8 - -
Hydro 0.1 0.1 0.1 0.2 0.2
Purchased Power 0.3 0.3 0.3 - -
- ----------------------------------------------------------------------------------------------------------------------------
1.6 1.6 1.2 0.2 0.2
- ----------------------------------------------------------------------------------------------------------------------------
13.6 13.3 13.0 11.8 12.5
- ----------------------------------------------------------------------------------------------------------------------------
Coal Sold - Millions of Tons 4.2 4.3 4.6 4.1 4.4
Capital Expenditures - Millions
Continuing Operations $63.0 $ 73.6 $ 86.6 $ 59.9 $ 64.1
Discontinued Operations 16.2 62.7 114.6 89.3 104.6
- ----------------------------------------------------------------------------------------------------------------------------
$79.2 $136.3 $201.2 $149.2 $168.7
- ----------------------------------------------------------------------------------------------------------------------------
Excludes unallocated ESOP shares.
Included a $10.9 million, or $0.38 per share, after-tax debt prepayment cost incurred as part of ALLETE's financial
restructuring in preparation for the spin-off of ADESA and an $11.5 million, or $0.41 per share, gain on the sale of
ADESA shares related to ALLETE's Retirement Savings and Stock Ownership Plan.
Included a $71.6 million, or $2.59 per share, gain on the sale of the Water Services businesses.
Included a $5.5 million, or $0.20 per share, charge related to the indefinite delay of a generation project in
Superior, Wisconsin.
Included an $11.1 million, or $0.45 per share, gain on the sale of the Company's largest single real estate
transaction ever.
Included a $30.4 million, or $1.32 per share, gain on the sale of 4.7 million shares of ACE Limited.
ALLETE 2004 Form 10-K Page 22
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion should be read in conjunction with our consolidated
financial statements and notes to those statements and the other financial
information appearing elsewhere in this report. In addition to historical
information, the following discussion and other parts of this report contain
forward-looking information that involves risks and uncertainties.
EXECUTIVE SUMMARY
ALLETE went through a significant transformation in 2004, and at the same time,
performed exceptionally well. We are stronger as a result, and from what we have
accomplished, we are poised for substantial earnings growth in 2005, excluding
an anticipated one-time charge related to the Kendall County agreement. (See -
Outlook.) Two significant strategic objectives were achieved--the spin-off of
our Automotive Services business and the sale of our Water Services businesses.
On September 20, 2004, we spun off our Automotive Services business by
distributing to ALLETE shareholders all of ALLETE's shares of ADESA common
stock. In June 2004, our Automotive Services business, doing business as ADESA,
Inc. (NYSE: KAR), completed an IPO through the issuance and sale of 6.3 million
shares of its common stock. This represented 6.6% of ADESA's common stock
outstanding. ALLETE owned the remaining 93.4% of ADESA until the spin-off was
completed. (See Note 3.) ADESA's SEC filings are available through the SEC's
website at www.sec.gov.
In mid-2004, we completed the sales of our North Carolina water and wastewater
assets, and the remaining 72 water and wastewater systems in Florida. In early
2005, we sold our wastewater services business in Georgia. The net cash proceeds
from the sale of all water and wastewater assets in 2003 and 2004, after
transaction costs, retirement of most Florida Water debt and payment of income
taxes, were approximately $300 million.
Using a combination of internally generated funds, proceeds from the sale of our
Water Services assets and proceeds received from ADESA, we repaid $183.1 million
in outstanding debt in 2004 ($356.5 million of debt and $75 million of
mandatorily redeemable preferred securities in 2003), which significantly
strengthened our balance sheet and reduced interest expense in 2004. Our debt to
total capital ratio was 38% at December 31, 2004.
Income from continuing operations represents the activities that are part of
ALLETE subsequent to the spin-off of ADESA and the sale of our Water Services
businesses. REGULATED UTILITY includes retail and wholesale rate-regulated
electric, water and gas services in northeastern Minnesota and northwestern
Wisconsin under the jurisdiction of state and federal regulatory authorities.
NONREGULATED ENERGY OPERATIONS includes nonregulated generation (non-rate base
generation sold at market-based rates to the wholesale market) consisting
primarily of generation from Taconite Harbor in northern Minnesota and
generation secured through the Kendall County power purchase agreement.
Nonregulated Energy Operations also includes our coal mining activities in North
Dakota. REAL ESTATE includes our Florida real estate operations. OTHER includes
our telecommunications activities, investments in emerging technologies,
earnings on cash, and general corporate charges and interest not specifically
related to any one business segment. General corporate charges include employee
salaries and benefits, as well as legal and other outside service fees.
Income from continuing operations before the change in accounting principle was
$39.1 million, or $1.37 per diluted share, for 2004 ($29.8 million, or $1.08 per
diluted share, for 2003; $24.7 million, or $0.91 per diluted share, for 2002).
Strong earnings in 2004 were attributed to increased sales to our industrial
customers, as a result of their higher production levels, and a significant
reduction in interest expense due to lower debt balances. The following
significant factors impact the comparisons between years:
- DEBT PREPAYMENT COST. In 2004, we incurred a $10.9 million, or $0.38 per
share, after-tax debt prepayment cost as part of ALLETE's financial
restructuring in preparation for the spin-off of ADESA.
- GAIN ON ADESA SHARES. In 2004, we recognized an $11.5 million, or $0.41
per share, gain on the sale of ADESA shares related to our ESOP. (See
Note 17.)
- CHARGE. In 2002, Nonregulated Energy Operations incurred a $5.5 million,
or $0.20 per share, after-tax charge related to the indefinite delay of
a generation project in Superior, Wisconsin.
In total, net income and diluted earnings per share for 2004 decreased 56% and
57%, respectively, from 2003. The decrease was primarily attributable to reduced
earnings from discontinued operations, which included both Water Services and
Automotive Services. The decrease also reflected a $7.8 million non-cash
after-tax charge for a change in accounting principle related to investments in
our emerging technology portfolio. (See Note 14.) Gains recognized in 2003 on
the sale of substantially all of our water and wastewater systems in Florida
contributed to higher earnings in 2003, as did a full year of Automotive
Services operations.
Page 23 ALLETE 2004 Form 10-K
2004 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT PER SHARE AMOUNTS
Operating Revenue
Regulated Utility $555.0 $510.0 $497.9
Nonregulated Energy Operations 106.8 106.6 84.7
Real Estate 41.9 42.6 33.6
Other 47.7 33.1 26.8
- ---------------------------------------------------------------------------------------------------------------------------
$751.4 $692.3 $643.0
- ---------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Regulated Utility $468.2 $430.2 $403.7
Nonregulated Energy Operations 107.6 100.8 100.6
Real Estate 16.5 18.2 15.5
Other 59.3 47.0 45.0
- ---------------------------------------------------------------------------------------------------------------------------
$651.6 $596.2 $564.8
- ---------------------------------------------------------------------------------------------------------------------------
Interest Expense
Regulated Utility $18.5 $20.4 $20.6
Nonregulated Energy Operations 1.5 1.8 0.3
Real Estate 0.3 0.2 -
Other 11.5 28.2 28.4
- ---------------------------------------------------------------------------------------------------------------------------
$31.8 $50.6 $49.3
- ---------------------------------------------------------------------------------------------------------------------------
Other Income (Expense)
Regulated Utility $ 0.1 $2.9 $7.7
Nonregulated Energy Operations 0.6 1.9 0.6
Real Estate - - -
Other (12.8) (2.3) (0.2)
- ---------------------------------------------------------------------------------------------------------------------------
$(12.1) $2.5 $8.1
- ---------------------------------------------------------------------------------------------------------------------------
Net Income (Loss)
Regulated Utility $ 42.8 $ 37.9 $ 50.4
Nonregulated Energy Operations (0.3) 3.7 (8.7)
Real Estate 14.7 14.1 11.2
Other (18.1) (25.9) (28.2)
- ---------------------------------------------------------------------------------------------------------------------------
Continuing Operations 39.1 29.8 24.7
Discontinued Operations 73.1 206.6 112.5
Change in Accounting Principle (7.8) - -
- ----------------------------------------------------------------------------------------------------------------- ---------
$104.4 $236.4 $137.2
- ---------------------------------------------------------------------------------------------------------------------------
Diluted Average Shares of Common Stock 28.4 27.8 27.2
- ---------------------------------------------------------------------------------------------------------------------------
Diluted Earnings (Loss) Per Share of Common Stock
Continuing Operations $1.37 $1.08 $0.91
Discontinued Operations 2.57 7.44 4.13
Change in Accounting Principle (0.27) - -
- ---------------------------------------------------------------------------------------------------------------------------
$3.67 $8.52 $5.04
- ---------------------------------------------------------------------------------------------------------------------------
Return on Common Equity 8.3% 17.7% 11.4%
- ---------------------------------------------------------------------------------------------------------------------------
ALLETE 2004 Form 10-K Page 24
2004 2003 2002
- -------------------------------------------------------------------------------------------------------------------------
MILLIONS
Kilowatthours Sold
Regulated Utility
Retail and Municipals
Residential 1,053 1,065 1,044
Commercial 1,282 1,286 1,257
Industrial 7,071 6,558 6,946
Municipals 823 842 820
Other 79 79 78
- -------------------------------------------------------------------------------------------------------------------------
10,308 9,830 10,145
Other Power Suppliers 918 1,314 987
- -------------------------------------------------------------------------------------------------------------------------
11,226 11,144 11,132
Nonregulated Energy Operations 1,496 1,462 1,149
- -------------------------------------------------------------------------------------------------------------------------
12,722 12,606 12,281
- -------------------------------------------------------------------------------------------------------------------------
NET INCOME
REGULATED UTILITY contributed net income of $42.8 million in 2004 ($37.9 million
in 2003; $50.4 million in 2002). The 13% increase in 2004 net income from 2003
reflected an 8% increase in kilowatthour sales to our industrial customers.
Higher expenses for pension, and increased costs associated with maintenance
outages at Company generating facilities and a scheduled outage at the Square
Butte generating facility, were partially offset by lower depreciation and
interest expense. Overall, regulated utility kilowatthour sales in 2004 were
similar to 2003 and 2002. In 2004, a 5% increase in sales to retail and
municipal customers reduced the energy available for sale to other power
suppliers. In addition, Regulated Utility net income in 2004 also reflected the
absence of equity income from Split Rock Energy, a joint venture which we
terminated in March 2004 ($1.7 million in 2003; $4.3 million in 2002). Equity
income from Split Rock Energy in 2003 included a $2.3 million charge to exit the
joint venture. In 2002, a $2.3 million one-time deferral of costs recoverable
through the regulated utility fuel clause increased income.
NONREGULATED ENERGY OPERATIONS reported a $0.3 million net loss in 2004 (net
income of $3.7 million in 2003; an $8.7 million net loss in 2002). The decrease
in 2004 net income was primarily due to a reduction in net income at Taconite
Harbor and a one-time cost to terminate a transmission contract related to the
Kendall County power purchase agreement. Net income at Taconite Harbor in 2004
decreased, primarily due to costs associated with a scheduled maintenance outage
in 2004 and increased costs for sulfur dioxide emission allowances. In addition,
wholesale power prices were lower in 2004. Generation at Taconite Harbor first
came online at various times during the first half of 2002. Wholesale power
prices were higher in 2003 compared to 2002.
Generation secured through the Kendall County power purchase agreement began in
May 2002. An after-tax loss of approximately $8 million, which included a $0.7
million cost to terminate a transmission contract, was recognized in 2004. In
December 2004, we entered into an agreement to assign this power purchase
agreement to Constellation Energy Commodities. (See Outlook.)
In 2002, a $5.5 million charge related to the indefinite delay of a generation
project in Superior, Wisconsin, reduced income, while 2003 reflected a $0.5
million reduction in the 2002 charge related to that project.
REAL ESTATE contributed net income of $14.7 million in 2004 ($14.1 million in
2003; $11.2 million in 2002). A strong southwest Florida real estate market
starting in the fall of 2003 and continuing into 2004 was the main reason for
higher net income in 2004 and 2003, as well as an increase in the number and the
profitability of real estate sales. The timing of the closing of real estate
sales varies from period to period and impacts comparisons between years.
OTHER reflected a net loss of $18.1 million in 2004, down from a $25.9 million
net loss in 2003 ($28.2 million net loss in 2002). A $9.8 million reduction in
interest expense resulting from lower debt balances was the main reason for the
improvement in 2004. Financial results for 2004 also included an $11.5 million
gain on the sale of ADESA stock related to our ESOP (see Note 17), a $10.9
million debt prepayment cost associated with the retirement of long-term debt as
a part of our financial restructuring in preparation for the spin-off of ADESA
(see Note 8) and $4.1 million of impairment losses related to our emerging
technologies portfolio. In addition, $1.6 million of equity losses on emerging
technology funds were recognized in 2004. In 2003, we reported net losses on the
sale of shares we held directly in publicly-traded, emerging technology
investments. Financial results for 2002 included net gains on the sale of
certain emerging technology investments and losses related to our trading
securities portfolio, which was liquidated during the second half of 2002.
Page 25 ALLETE 2004 Form 10-K
DISCONTINUED OPERATIONS includes our Automotive Services business that was spun
off on September 20, 2004, our Water Services businesses, the majority of which
were sold in 2003, costs incurred by ALLETE associated with the spin-off of
ADESA, and our retail stores, which we exited in 2002.
Automotive Services contributed net income of $74.4 million in 2004 ($113.6
million in 2003; $88.2 million in 2002). Net income in 2004 was down $39.2
million from 2003, reflecting a 6.6% reduction in our ownership of ADESA since
the June 2004 IPO and the absence of ADESA operations since the spin-off on
September 20, 2004. Net income in 2004 was also down due to debt prepayment
costs related to the early redemption of ADESA debt in August 2004, ALLETE's
costs associated with the business separation, and additional corporate charges
and separation expenses incurred by ADESA as it prepared to be a stand-alone,
publicly-traded company. In addition, 2004 net income included $4.1 million of
charges in connection with a lawsuit related to ADESA's vehicle import business.
Net income in 2003 reflected strong vehicle sales, fee increases, the
introduction and expansion of service offerings, lower interest expense due to
lower debt balances at the time, gains on sale of property and strong receivable
portfolio management at the floorplan financing business. Net income in 2003
also included a $1.3 million recovery from the settlement of a lawsuit
associated with ADESA's vehicle transport business. Net income in 2002 included
a $2.7 million exit charge related to ADESA's vehicle transport business.
Water Services financial results were a $1.3 million net loss in 2004 (net
income of $93.0 million in 2003; net income of $25.5 million in 2002). Net
income in 2004 decreased $94.3 million from 2003, primarily because 2003
included the sale of substantially all of our water and wastewater systems
serving various counties and communities in Florida. A $71.6 million after-tax
gain was recognized on the sale of these systems in 2003, net of all selling,
transaction and employee termination benefit expenses, as well as impairment
losses on certain remaining assets at the time. Gains in 2004 from the sale of
our North Carolina assets and the remaining systems in Florida were offset by an
adjustment to gains reported in 2003, resulting in an overall net loss of $0.5
million in 2004. The adjustment to gains reported in 2003 resulted primarily
from an arbitration award in December 2004 relating to a gain-sharing provision
on a system sold in 2003. Net income was also down from 2003, due to the absence
of operations from water and wastewater systems sold. The majority of Florida
systems were sold in the fourth quarter of 2003. North Carolina assets were sold
in June 2004.
Financial results for 2002 included a $1.2 million loss related to our retail
stores, primarily due to an exit charge.
CHANGE IN ACCOUNTING PRINCIPLE reflected the cumulative effect on prior years
(to December 31, 2003) of changing to the equity method of accounting for
investments in limited liability companies included in our emerging technology
portfolio. (See Note 14.)
2004 COMPARED TO 2003
REGULATED UTILITY
OPERATING REVENUE was up $45.0 million, or 9%, in 2004, primarily due to
higher fuel clause recoveries resulting from increased purchased power
costs (see operating expenses below) and increased retail sales. Overall,
regulated utility kilowatthour sales were similar to 2003 (up 1%) as a 5%
increase in sales to retail and municipal customers reduced the energy
available for sale to other power suppliers. Much of the increase in retail
and municipal electric sales was attributable to large industrial
customers, due to their higher production levels in 2004. Outages at
Company generating facilities and a scheduled maintenance outage at the
Square Butte generating facility (see operating expenses) also contributed
to less energy being available for sale to other power suppliers.
OPERATING EXPENSES in total were up $38.0 million, or 9%, in 2004,
primarily due to a $34.3 million increase in fuel and purchased power
expense. Increased purchased power was necessitated by outages at Company
generating facilities and the Square Butte generating facility. In February
2004, we experienced a generator failure at our 534-MW Boswell Unit 4. Unit
4 came back into service in June 2004. As a result of the failure, we
replaced significant components of the generator at a capital cost of
approximately $6 million. The majority of the replacement cost was covered
by insurance, subject to a deductible of $1 million. We entered into power
purchase agreements to replace the power lost during the Unit 4 outage. The
cost of this additional power was recovered through the regulated utility
fuel adjustment clause in Minnesota. While Unit 4 was down, some work
originally planned for 2005 and 2006 was done during the outage to minimize
future outages. This outage did not have a material impact on our results
of operations. Two multi-week scheduled maintenance outages also took place
at our 55-MW Laskin Unit 1 and at the Square Butte generating facility.
Operating and maintenance expense was $3.2 million higher in 2004,
primarily due to outages at our generating facilities. Our pro rata share
of the Square Butte maintenance outage costs was approximately $5 million.
In addition, 2004 reflected a $4.4 million increase in pension expense and
a $1.7 million decrease in depreciation expense. In 2004, the MPUC approved
longer depreciable lives for certain Company generating assets.
INTEREST EXPENSE was down $1.9 million from 2003, due to lower debt
balances in 2004.
ALLETE 2004 Form 10-K Page 26
2004 COMPARED TO 2003 (CONTINUED)
REGULATED UTILITY (CONTINUED)
OTHER INCOME (EXPENSE) reflected $2.8 million less income in 2004,
primarily due to the absence of equity in net income from Split Rock
Energy. Minnesota Power withdrew from Split Rock Energy trading activities,
effective November 1, 2003, and terminated the joint venture in March 2004.
NONREGULATED ENERGY OPERATIONS
OPERATING REVENUE in 2004 was similar to 2003 as a 2% increase in
kilowatthour sales was offset by lower wholesale prices. Kilowatthour sales
were up 8% at Taconite Harbor despite a fourth quarter 2004 scheduled
maintenance outage, while kilowatthour sales at Kendall County were down
26% from 2003.
OPERATING EXPENSES were up $6.8 million, or 7%, in 2004, due to $1.3
million of costs associated with a scheduled maintenance outage at Taconite
Harbor, a $1.2 million transmission contract termination charge to exit the
Kendall County agreement and a $0.9 million increase in costs for sulfur
dioxide emission allowances. Expenses in 2003 reflected a $0.9 million
reduction in costs accrued in 2002 related to the indefinite delay of a
generation project in Superior, Wisconsin.
OTHER INCOME (EXPENSE) reflected $1.3 million of less income in 2004. The
decrease was attributable to a reduction in gains on prior Minnesota land
sales due to an MPUC required land reevaluation.
REAL ESTATE
OPERATING REVENUE was down $0.7 million, or 2%, in 2004. In 2004, we sold
1,479 acres and 211 lots for $35.8 million (1,394 acres and 265 lots for
$36.0 million in 2003). At December 31, 2004, total land sales under
contract were $71 million, of which $30 million were for properties in the
Town Center development project at Palm Coast. Revenue in 2003 also
included the recovery of a partially reserved receivable.
OPERATING EXPENSES were down $1.7 million, or 9%, in 2004 because the cost
of property sold in 2004 was lower than in 2003. Cost of sales in 2004 was
$6.5 million ($7.9 million in 2003).
OTHER
OPERATING REVENUE was up $14.6 million, or 44%, in 2004, reflecting
increased revenue from our telecommunications business due to more
equipment sales.
OPERATING EXPENSES were up $12.3 million, or 26%, in 2004, mostly due to
higher cost of goods sold associated with increased sales at our
telecommunications business. Corporate charges were down $2.2 million
($12.6 million in 2004; $14.8 million in 2003). Lower corporate charges as
a result of the spin-off of Automotive Services and an insurance refund
partially offset higher incentive compensation and benefit costs, and
expenses related to the reverse stock split.
INTEREST EXPENSE (not specifically related to any one business segment) was
down $16.8 million from 2003 ($11.2 million in 2004; $28.0 million in
2003), primarily due to lower debt balances. We repaid $25 million of 6
1/4% First Mortgage Bonds in July 2003; $50 million of 7 3/4% First
Mortgage Bonds in November 2003; $75 million of mandatorily redeemable
preferred securities in December 2003; $3.5 million of Industrial
Development Revenue Bonds in January 2004; and $125 million of 7.80% Senior
Notes in July 2004. In addition, $111 million of Pollution Control
Refunding Revenue Bonds were refinanced at a lower rate in August 2004 and
a $250 million credit agreement entered into in July 2003 was paid off
early ($197 million in 2003; $53 million in April 2004). A combination of
internally-generated funds, proceeds from the sale of our Water Services
assets and proceeds received from ADESA were used to repay the debt.
OTHER INCOME (EXPENSE) reflected $10.5 million of additional expense in
2004, primarily due to an $18.5 million debt prepayment cost related to the
early redemption of $125 million in senior notes in 2004 and $6.5 million
of impairment losses recorded related to our emerging technology
investments. In addition, $1.7 million of equity losses on emerging
technology funds were recognized in 2004. These decreases were partially
offset by an $11.5 million gain on the sale of ADESA shares held in our
ESOP. (See Note 17.) In 2003, we recognized $3.5 million of losses related
to the sale of shares we held directly in publicly-traded emerging
technology investments.
Page 27 ALLETE 2004 Form 10-K
2003 COMPARED TO 2002
REGULATED UTILITY
OPERATING REVENUE was up $12.1 million, or 2%, in 2003, mainly due to
higher fuel clause recoveries and natural gas prices. Regulated utility
kilowatthour sales were similar to 2002. Fuel clause recoveries increased,
due to higher purchased power costs.
OPERATING EXPENSES were up $26.5 million, or 7%, in 2003, primarily due to
a $5.8 million increase in fuel and purchased power expense, a $4.4 million
increase in natural gas expense and a $4.8 million increase in employee
pension and benefit expenses. Higher purchased power costs resulted from
both increased wholesale prices and quantities purchased. Planned
maintenance outages at our generating stations and lower output from our
hydro facilities as a result of drier weather necessitated higher
quantities of purchased power in 2003. Natural gas expense was higher in
2003, due to increased prices. Expenses for pension and post-retirement
health benefits increased, mainly due to lower discount rates and expected
rates of return on plan assets. Operating expenses in 2002 included a $4
million one-time deferral of costs recoverable through the utility fuel
adjustment clause.
OTHER INCOME (EXPENSE) reflected $4.8 million less income in 2003,
primarily due to less equity income from our joint venture in Split Rock
Energy ($2.9 million in 2003; $7.3 million in 2002). Our 2003 equity in net
income from Split Rock Energy reflected a $2.3 million charge accrued at
the time we reached an agreement to withdraw from this joint venture.
NONREGULATED ENERGY OPERATIONS
OPERATING REVENUE was up $21.9 million, or 26%, in 2003, primarily due to
increased sales of nonregulated generation from our Taconite Harbor
facility and improved wholesale power prices. Increased sales of
nonregulated generation resulted from Taconite Harbor being available for a
full 12 months in 2003. Taconite Harbor generation first came online at
various times during the first half of 2002.
OPERATING EXPENSES were up $0.2 million, or less than 1%, in 2003, mainly
due to fuel and purchased power expenses for nonregulated generation that
came online during the first half of 2002. Purchased power expense in 2003
included a full 12 months of demand charges related to the Kendall County
power purchase agreement, while 2002 included only eight months. Operating
expenses in 2002 included a $9.5 million charge related to the indefinite
delay of the generation project in Superior, Wisconsin.
INTEREST EXPENSE was up $1.5 million, predominantly due to more interest
capitalized in 2002.
REAL ESTATE
OPERATING REVENUE was up $9 million, or 27%, in 2003, as a result of more
land sales. In 2003, we sold 1,394 acres and 265 lots for $36.0 million
(641 acres and 1,425 lots for $29.9 million in 2002). Revenue in 2003 also
included the recovery of a partially reserved receivable.
OPERATING EXPENSES were up $2.7 million, or 17%, in 2003 because the cost
of property sold in 2003 and selling expenses were higher than in 2002.
Cost of sales in 2003 was $7.9 million ($6.8 million in 2002).
OTHER
OPERATING REVENUE was up $6.3 million, or 24%, in 2003, reflecting
increased revenue from our telecommunications business, due to more
equipment sales.
OPERATING EXPENSES were up $2.0 million, or 4%, in 2003, reflecting higher
cost of goods sold associated with increased sales at our
telecommunications business, partially offset by a $2.2 million decrease in
corporate charges ($14.8 million in 2003; $17.0 million in 2002).
INTEREST EXPENSE was down $0.2 million, or less than 1%, in 2003 and
reflected interest expense not specifically related to any one business
segment ($28.0 million in 2003; $28.2 million in 2002).
OTHER INCOME (EXPENSE) reflected $2.1 million less income in 2003,
primarily due to a $3.5 million loss related to the sale of shares the
Company held directly in publicly-traded emerging technology investments.
In 2002, we recognized a $3.3 million gain on the sale of certain emerging
technology investments, which was more than offset by losses on our trading
securities portfolio that was liquidated during the second half of 2002.
ALLETE 2004 Form 10-K Page 28
CRITICAL ACCOUNTING POLICIES
Certain accounting measurements under applicable generally accepted accounting
principles involve management's judgment about subjective factors and estimates,
the effects of which are inherently uncertain. These policies are reviewed with
the audit committee of our Board of Directors on a regular basis. The following
summarizes those accounting measurements we believe are most critical to our
reported results of operations and financial condition.
IMPAIRMENT OF LONG-LIVED ASSETS. We annually review our assets for impairment.
SFAS 144, "Accounting for the Impairment and Disposal of Long-Lived Assets," is
the basis for these analyses. Judgments and uncertainties affecting the
application of accounting for asset impairment include economic conditions
affecting market valuations, changes in our business strategy, and changes in
our forecast of future operating cash flows and earnings.
We account for our long-lived assets at depreciated historical cost. A
long-lived asset is tested for recoverability whenever events or changes in
circumstances indicate that its carrying amount may not be recoverable. We would
recognize an impairment loss only if the carrying amount of a long-lived asset
is not recoverable from its undiscounted cash flows. Management judgment is
involved in both deciding if testing for recoverability is necessary and in
estimating undiscounted cash flows. As of December 31, 2004, no write-downs were
required.
PENSION AND POSTRETIREMENT HEALTH AND LIFE ACTUARIAL ASSUMPTIONS. We account for
our pension and postretirement benefit obligations in accordance with the
provisions of SFAS 87, "Employers' Accounting for Pensions," and SFAS 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions." These
standards require the use of assumptions in determining the obligations and
annual cost. An important actuarial assumption for pension and other
postretirement benefit plans is the expected long-term rate of return on plan
assets. In establishing this assumption, we consider the diversification and
allocation of plan assets, the actual long-term historical performance for the
type of securities invested in, the actual long-term historical performance of
plan assets and the impact of current economic conditions, if any, on long-term
historical returns. Our pension asset allocation is approximately 70% equity and
30% fixed-rate securities. Equity securities consist of a mix of market
capitalization sizes and also include investments in real estate and venture
capital. We currently use an expected long-term rate of return of 9% in our
pension actuarial study. We annually review our expected long-term rate of
return assumption and will adjust it to respond to any changing market
conditions. A 1/2% decrease in the expected long-term rate of return would
increase the annual expense for pension and other postretirement benefits by
approximately $1 million after tax; likewise, a 1/2% increase in the expected
long-term rate of return would decrease the annual expense by approximately $1
million after tax. (See Note 16 for additional detail on our pension and
postretirement health and life plans.)
VALUATION OF INVESTMENTS. As part of our emerging technology portfolio, we have
several minority investments in venture capital funds and privately-held,
start-up companies. We account for our investment in venture capital funds under
the equity method and account for our direct investment in privately-held
companies under the cost method. These investments are included in Investments
on our consolidated balance sheet. Our policy is to quarterly review these
investments for impairment by assessing such factors as continued commercial
viability of products, cash flow and earnings. Any impairment would reduce the
carrying value of the investment and be recognized as a loss. In 2004, we
recorded $6.5 million pretax of impairment losses on these investments ($0 in
2003; $1.5 million pretax in 2002).
PROVISION FOR ENVIRONMENTAL REMEDIATION. Our businesses are subject to
regulation by various federal, state and local authorities concerning
environmental matters. We review environmental matters on a quarterly basis.
Accruals for environmental matters are recorded when it is probable that a
liability has been incurred and the amount of the liability can be reasonably
estimated, based on current law and existing technologies. These accruals are
adjusted periodically as assessment and remediation efforts progress, or as
additional technical or legal information becomes available. Accruals for
environmental liabilities are included in the balance sheet at undiscounted
amounts and exclude claims for recoveries from insurance or other third parties.
Costs related to environmental contamination treatment and cleanup are charged
to expense. We do not currently anticipate that potential expenditures for
environmental matters will be material; however, if we become subject to more
stringent remediation at known sites, if we discover additional contamination or
previously unknown sites, or if we become subject to related personal or
property damage, we could incur material costs in connection with our
environmental remediation.
TAXATION. We are required to make judgments regarding the potential tax effects
of various financial transactions and our ongoing operations to estimate our
obligations to taxing authorities. These tax obligations include income, real
estate and use taxes. These judgments include reserves for potential adverse
outcomes regarding tax positions that we have taken. We must also assess our
ability to generate capital gains to realize tax benefits associated with
capital losses expected to be generated in future periods. Capital losses may be
deducted only to the extent of capital gains realized during the year of the
loss or during the three prior or five succeeding years. As of December 31,
2004, we have, where appropriate, recorded an allowance against our deferred tax
assets associated with impairment losses, which will become capital losses when
realized for income tax purposes. While we believe the resulting tax reserve
balances as of December 31, 2004 reflect the most likely probable expected
outcome of these tax matters in accordance with SFAS 5, "Accounting for
Contingencies," and SFAS 109, "Accounting for Income Taxes," the ultimate
outcome of such matters could result in additional adjustments to our
consolidated financial statements and such adjustments could be material.
Page 29 ALLETE 2004 Form 10-K
OUTLOOK
In the last 10 years, our average annual total shareholder return is 16%.
Approximately 4% of this average was attributed to dividends. A $100 investment
in ALLETE stock at the end of 1994 would have been worth $439 at the end of
2004, assuming reinvestment of dividends and shares received in the ADESA
distribution were sold and reinvested in ALLETE. By comparison, the Standard &
Poor's 500 Index averaged 12% for the same period, of which approximately 2% of
the average was attributed to dividends. A $100 investment in the Standard &
Poor's 500 Index at the end of 1994 would have been worth $312 at the end of
2004, assuming reinvestment of dividends.
Having completed the spin-off of our Automotive Services business and the sale
of our Water Services businesses, our transformation in 2004 has made us a
stronger company and positioned us for substantial growth in 2005.
2005 EARNINGS GUIDANCE. We expect ALLETE's earnings per share from continuing
operations to grow by 45% to 50% in 2005. The growth is expected to come from
continued strong real estate sales, lower interest expense and the transfer of
the Kendall County purchased power agreement. The earnings expectation excludes
an anticipated one-time charge related to the Kendall County agreement.
The ESOP has been using proceeds from the sale of ADESA stock to purchase ALLETE
common stock on the open market. Pursuant to AICPA Statement of Position 93-6,
"Employers' Accounting for Employee Stock Ownership Plans," unallocated ALLETE
common stock currently held and purchased by the ESOP will be treated as
unearned ESOP shares and not considered as outstanding for earnings per share
computations. ESOP shares are included in earnings per share computations after
they are allocated to participants. At December 31, 2004, the ESOP had purchased
1.0 million shares of ALLETE common stock and had $30.3 million of restricted
cash. During January 2005, the ESOP purchased an additional 0.5 million shares
of ALLETE common stock and had $8.9 million of restricted cash at January 31,
2005. (See Note 17.)
REGULATED UTILITY AND NONREGULATED ENERGY OPERATIONS. Over the next five years,
we believe electric utilities will face three major issues: ongoing changes in
regional transmission structure; the probable enactment of stricter
environmental regulations; and possible federal legislation impacting the
structure and organization of the electric utility industry. The FERC may
consolidate transmission regions, which could impact states' transmission
regulation rights and create a more standardized wholesale power market to
oversee how transmission prices are determined. As part of this larger policy
effort, MISO will launch day-ahead and real-time energy market operations on
April 1, 2005. We are not yet able to predict the impact of the soon-to-be
initiated MISO Day 2 market on the Company's operations. We have been diligently
participating with MISO in market launch preparations and tests, and our systems
and procedures for operating within the new market are in place. Stricter
environmental requirements through legislation and/or rulemakings are expected
to require significant capital investments in the 2008 to 2012 timeframe. The
expenditures will relate to new emission controls on existing generating units.
Congress is expected to take up energy legislation in 2005. Repeal of the Public
Utility Holding Company Act (PUHCA) is likely to be one of the electric utility
sector reforms addressed in the bill. PUHCA imposes geographic restrictions on
large electric and gas utility operations and limits diversification into
non-utility businesses. More electric industry consolidation could occur and new
players could enter the industry if PUHCA is repealed.
We believe our Regulated Utility and Nonregulated Energy Operations businesses
are well positioned to successfully deal with the issues we have described and
to compete successfully. Our access to and ownership of low-cost power are our
greatest strengths. We anticipate securing additional competitive resources for
our forecasted load growth. We anticipate that we will have ready access to
sufficient capital for general business purposes. We believe electric industry
deregulation is unlikely in Minnesota or Wisconsin in the next five years.
REGULATED UTILITY STRATEGY. We will leverage the strengths of our Regulated
Utility business to improve the Company's strategic and financial outlook. In
addition, we will evaluate growth opportunities through merger, acquisition or
asset additions in our region.
RESOURCE PLAN. In 2004, we filed an integrated resource plan (Resource Plan)
with the MPUC, detailing our retail energy demand projections and our energy
sourcing options to meet the projected demand over the next 15 years. In the
Resource Plan, we predict that retail demand by customers in our service
territory will increase at an average annual rate of 1.7% to 2019. The Resource
Plan forecasts growth of 20 MW to 30 MW per year, primarily from residential and
smaller commercial expansion, and a positive outlook from Large Power Customers
in northeastern Minnesota, such as taconite processing facilities and paper
mills. We expect to realize a reduction in generating resource supply over the
next few years under the terms of our long-term energy supply contract with
Square Butte. The combination of increased demands and reduced supply means we
will need to secure additional base load energy to serve our customers in future
years.
The Resource Plan sets forth several options designed to meet our predicted
retail base load demand growth. Options range from purchasing additional power
to building new base load energy generation facilities. We will further analyze
portfolio alternatives for meeting our forecast and work with state regulators
and other stakeholders over the next several months to further develop the
Resource Plan. We anticipate that the MPUC will formally consider the Resource
Plan during 2005.
ALLETE 2004 Form 10-K Page 30
RATE CASE. In other regulatory activity, SWL&P filed a request with the PSCW in
2004 to increase retail rates. A ruling is anticipated during the first half of
2005. Minnesota Power does not expect to file a request to increase rates for
its retail utility operations during 2005. We will, however, continue to monitor
the costs of serving our retail customers and evaluate the need for a rate
filing in the future.
INDUSTRIAL CUSTOMERS. Approximately 50% of our regulated utility electric sales
is made to taconite producers, paper producers and oil pipeline operators.
During 2004, the multi-year domestic integrated-steel industry consolidation
began to reach operating fruition. Combined with improving markets, a
consolidated steel industry should continue to stabilize and potentially even
increase the demand for taconite as a raw material in steel production. Based on
our research of the taconite industry, Minnesota taconite production for 2005 is
again anticipated to be about 41 million tons (41 million tons in 2004; 35
million tons in 2003; 39 million tons in 2002). Although the current taconite
pellet market looks strong, the taconite industry is cyclical and subject to
several factors, which could dramatically change this forecast. In the event of
a significant change in the taconite markets, we expect that any excess energy
not used by our retail customers will be marketed primarily to the regional
wholesale market. Paper prices have also improved and we anticipate a more
profitable outlook for the domestic paper industry over the next few years.
Since 2001, Mesabi Nugget, owned by Kobe Steel, Ltd., Cleveland-Cliffs Inc and
Steel Dynamics, Inc., has been testing the technology of converting taconite
into pig iron at a pilot plant in Silver Bay, Minnesota. Environmental
permitting on a full-scale production plant in northeast Minnesota is under way
and such plant would be a significant energy user. In 2004, UPM-Kymmene, a Large
Power Customer, began a year-long economic and environmental study to assess the
feasibility of expanding its Blandin Paper mill in Grand Rapids, Minnesota. A
new paper machine would require an additional 100 MW of electricity by 2008. The
addition of these two potential major industrial energy users in northern
Minnesota is positive for the Company, as well as the communities we serve.
Our strong relationships with industrial customers are unique in the electric
industry and enable us to work closely with them to help ensure their success.
We continue to maintain these relationships with this group of customers to help
retain a solid industrial base in our region. We continue to make investments to
maintain and improve the integrity of our generating, transmission and
distribution assets, and maintain environmental compliance.
FUEL CLAUSE. In 2003, the MPUC initiated an investigation into the continuing
usefulness of the fuel clause as a regulatory tool for electric utilities. The
initial steps of the investigation were to review the clause's original purpose,
structure and rationale (including its current operation and relevance in
today's regulatory environment), and then address its ongoing appropriateness
and other issues if the need for continued use of the fuel adjustment clause is
shown. The MPUC has not taken action on any proposal and, as a result, we are
unable to predict the outcome or impact of this proceeding at this time.
KENDALL COUNTY. To eliminate ongoing losses from capacity charges for generation
secured through the Kendall County power purchase agreement, in December 2004,
we entered into an agreement to assign this power purchase agreement to
Constellation Energy Commodities. Under the terms of the agreement, we will pay
Constellation Energy Commodities $73 million in cash (approximately $47 million
after taxes) to assume the power purchase agreement, which is in effect through
mid-September 2017. The proposed transaction is subject to the approvals of
LSP-Kendall Energy, as well as of its project lenders and the FERC. Pending
these approvals, the transaction is scheduled to close in April 2005. We
currently have approximately 130 MW of long-term capacity sales contracts for
the Kendall County generation, which will also be transferred to Constellation
Energy Commodities at closing.
TACONITE HARBOR. A majority of the output from our Taconite Harbor generating
unit is sold under long-term wholesale contracts through mid-2010. Remaining
Taconite Harbor energy is sold on a shorter-term basis into the wholesale
market.
NONREGULATED ENERGY OPERATIONS STRATEGY. Following the anticipated disposition
of the Kendall County contractual position in April 2005, this business segment
will be composed of generating assets in northeastern Minnesota and BNI Coal in
North Dakota. Our strategy is to enhance the profitability of these operations
where possible and seek growth opportunities in close geographic proximity to
existing operations in Minnesota, North Dakota and Wisconsin.
REAL ESTATE. With an inventory of land in desirable Florida locations, ALLETE
Properties is poised for a growing and consistent contribution to earnings and
cash flow. A large portion of our real estate inventory is located in Florida's
Flagler and Volusia Counties, an area with one of the fastest growing
populations in the United States. We expect this population growth to continue,
which will increase the demand for real estate in the area.
We have three major planned developments under way. They are Town Center at Palm
Coast, which will be a new downtown for Palm Coast, Palm Coast Park, located in
northwest Palm Coast, and Ormond Crossings, located in Ormond Beach along
Interstate 95. As property within these developments is made available for sale,
we expect that these projects will contribute a significant amount of net income
for our real estate business. Other ongoing land sales and rental income at the
retail shopping center in Winter Haven provide additional revenue.
Page 31 ALLETE 2004 Form 10-K
ALLETE Properties plans to maximize the value of the property it currently owns
through entitlement and infrastructure improvements, and then sell it at market
prices. In addition to managing its current real estate inventory, ALLETE
Properties will focus on identifying, acquiring and entitling vacant land in the
coastal southeast United States.
OTHER. We have the potential to recognize gains or losses on the sale of
investments in our emerging technology portfolio. We plan to sell investments in
our emerging technology portfolio as shares are distributed to us. Some
restrictions on sales may apply, including but not limited to underwriter
lock-up periods that typically extend for 180 days following an initial public
offering. We have committed to make additional investments in certain emerging
technology holdings. The total future commitment was $4.5 million at December
31, 2004 and is expected to be invested at various times through 2007. We do not
have plans to make any additional investments beyond this commitment.
DIVERSIFICATION. We have a long history of both acquiring and selling companies
in a variety of industries, and these activities have contributed significantly
to overall financial results. We will seek to diversify our earnings stream to
mitigate potential downside exposure to industrial customers in our Regulated
Utility business and to provide additional earnings growth.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW ACTIVITIES
A primary goal of our strategic plan is to improve cash flow from operations.
Our strategy includes growing our businesses both internally by expanding
facilities, services and operations (see Capital Requirements), and externally
through acquisitions.
We believe our financial condition is strong, as evidenced by cash and cash
equivalents of $194.1 million and a debt to total capital ratio of 38% at
December 31, 2004. We continued to generate strong cash flow from operating
activities, which amounted to $62.3 million in 2004, excluding discontinued
operations ($118.0 million in 2003; $226.5 million in 2002). Cash from operating
activities was lower in 2004, due to a $6.7 million outstanding receivable from
American Transmission Company for work on the Duluth-to-Wausau transmission
line. This receivable was paid in January 2005. Cash from operating activities
in 2003 included the receipt of a $20.9 million outstanding receivable in 2002
related to a turbine generator sold following the indefinite delay of a
generation project in Superior, Wisconsin. Cash from operating activities in
2002 included proceeds from the liquidation of our trading securities portfolio;
the proceeds were used to pay down short-term debt.
Cash from investing activities, excluding discontinued operations, was higher in
2004, primarily due to $12.0 million received from Split Rock Energy upon
termination of the joint venture and lower additions to property, plant and
equipment, which vary from year to year depending on special projects. Additions
to property, plant and equipment in 2003 included expenses related to BNI Coal's
dragline project; 2002 included expenses related to a generation project in
Superior, Wisconsin.
Cash for financing activities, excluding discontinued operations, reflected
significant debt repayment in all periods presented ($183.1 million in 2004;
$431.5 million in 2003; $171.5 million in 2002). A combination of
internally-generated funds, proceeds from the sale of our Water Services assets
in 2003 and 2004, and proceeds received from ADESA in 2004 were used to repay
the debt in 2003 and 2004. See Note 8 for additional detail on debt repaid. The
reduction in 2002 debt was primarily the repayment of commercial paper with
proceeds from the liquidation of our trading securities portfolio.
WORKING CAPITAL. Additional working capital, if and when needed, generally is
provided by the sale of commercial paper. Approximately 1 million original issue
shares of our common stock are available for issuance through INVEST DIRECT, our
direct stock purchase and dividend reinvestment plan. We have bank lines of
credit aggregating $111.5 million, the majority of which expire in December
2007. These bank lines of credit provide credit support for our commercial paper
program. The amount and timing of future sales of our securities will depend
upon market conditions and our specific needs. We may sell securities to meet
capital requirements, to provide for the retirement or early redemption of
issues of long-term debt, to reduce short-term debt and for other corporate
purposes.
Our lines of credit and long-term debt agreements contain various financial
covenants. The most restrictive of these covenants are discussed in Note 8.
ALLETE 2004 Form 10-K Page 32
SECURITIES
In March 2001, ALLETE, ALLETE Capital II and ALLETE Capital III, jointly filed a
registration statement with the SEC, pursuant to Rule 415 under the Securities
Act of 1933. The registration statement, which has been declared effective by
the SEC, relates to the possible issuance of a remaining aggregate amount of
$387 million of securities, which may include ALLETE common stock, first
mortgage bonds and other debt securities, and ALLETE Capital II and ALLETE
Capital III preferred trust securities. ALLETE also previously filed a
registration statement, which has been declared effective by the SEC, relating
to the possible issuance of $25 million of first mortgage bonds and other debt
securities. We may sell all or a portion of the remaining registered securities
if warranted by market conditions and our capital requirements. Any offer and
sale of the above mentioned securities will be made only by means of a
prospectus meeting the requirements of the Securities Act of 1933 and the rules
and regulations thereunder.
OFF-BALANCE SHEET ARRANGEMENTS
Off-balance sheet arrangements are discussed in Note 11.
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
Our long-term debt obligations, including long-term debt due within one year,
represent the principal amount of bonds, notes and loans which are recorded on
our consolidated balance sheet, plus interest. The following table assumes the
interest rate in effect at December 31, 2004 remains constant through remaining
term.
Unconditional purchase obligations represent our Square Butte and Kendall County
power purchase agreements, and minimum purchase commitments under coal and rail
contracts.
Under our power purchase agreement with Square Butte that extends through 2026,
we are obligated to pay our pro rata share of Square Butte's costs based on our
entitlement to the output of Square Butte's 455 MW coal-fired generating unit
near Center, North Dakota. Our payment obligation is suspended if Square Butte
fails to deliver any power, whether produced or purchased, for a period of one
year. Square Butte's fixed costs consist primarily of debt service. The table
below reflects our share of future debt service based on our output entitlement
of approximately 71% in 2005, 66% in 2006 and 60% thereafter. Upon compliance
with a two-year advance notice requirement, Minnkota Power has the option to
reduce our entitlement by approximately 5% annually, to a minimum of 50%. (See
Note 11.)
Under the Kendall County agreement, we pay a fixed capacity charge for the
right, but not the obligation, to utilize one 275 MW generating unit near
Chicago, Illinois. We are responsible for arranging the natural gas fuel supply
and are entitled to the electricity produced. In December 2004, we entered into
an agreement to assign this power purchase agreement to Constellation Energy
Commodities. Pending certain approvals, the proposed transaction is scheduled to
close in April 2005. The following table assumes the fixed capacity charge ends
April 1, 2005. (See Note 11.)
PAYMENTS DUE BY PERIOD
--------------------------------------------------------------------------
LESS THAN 1 TO 3 4 TO 5 AFTER
CONTRACTUAL OBLIGATIONS TOTAL 1 YEAR YEARS YEARS 5 YEARS
- -----------------------------------------------------------------------------------------------------------------------
MILLIONS
Long-Term Debt $ 593.7 $24.1 $229.2 $34.3 $306.1
Capital Lease Obligations - - - - -
Operating Lease Obligations 76.2 6.3 16.5 8.6 44.8
Unconditional Purchase Obligations 434.9 55.4 79.4 37.0 263.1
- -----------------------------------------------------------------------------------------------------------------------
$1,104.8 $85.8 $325.1 $79.9 $614.0
- -----------------------------------------------------------------------------------------------------------------------
In 2005, we expect to contribute approximately $6 million to our postretirement
health and life plans. We are not required to make any contributions to our
defined benefit pension plans in 2005. We are unable to predict contribution
levels after 2005.
EMERGING TECHNOLOGY PORTFOLIO. We have investments in emerging technologies
through the minority investments in venture capital funds and privately-held,
start-up companies. We have committed to make additional investments in certain
emerging technology holdings. The total future commitment was $4.5 million at
December 31, 2004 ($4.8 million at December 31, 2003) and is expected to be
invested at various times through 2007. We do not have plans to make any
additional investments beyond this commitment.
Page 33 ALLETE 2004 Form 10-K
CREDIT RATINGS
Our securities have been rated by Standard & Poor's and by Moody's. Rating
agencies use both quantitative and qualitative measures in determining a
company's credit rating. These measures include business risk, liquidity risk,
competitive position, capital mix, financial condition, predictability of cash
flows, management strength and future direction. Some of the quantitative
measures can be analyzed through a few key financial ratios, while the
qualitative ones are more subjective. The disclosure of these credit ratings is
not a recommendation to buy, sell or hold our securities. Ratings are subject to
revision or withdrawal at any time by the assigning rating organization. Each
rating should be evaluated independently of any other rating.
CREDIT RATINGS STANDARD & POOR'S MOODY'S
- ---------------------------------------------------------------------------------------------------------------------
Issuer Credit Rating BBB+ Baa2
Commercial Paper A-2 P-2
Senior Secured
First Mortgage Bonds A Baa1
Pollution Control Bonds A Baa1
Unsecured Debt
Collier County Industrial Development Revenue Bonds BBB -
- ---------------------------------------------------------------------------------------------------------------------
PAYOUT RATIO
In 2004, we paid out 77% (40% in 2003; 66% in 2002) of our per share earnings in
dividends.
CAPITAL REQUIREMENTS
CONTINUING OPERATIONS. Capital expenditures for 2004 totaled $63.0 million
($73.6 million in 2003; $86.6 million in 2002). Expenditures for 2004 included
$41.7 million for Regulated Utility, $15.7 million for Nonregulated Energy
Operations and $5.6 million for Other, which consisted of $5.2 million for our
telecommunications business and $0.4 million for general corporate purposes.
Except for BNI Coal's new dragline, which was funded with an operating lease,
internally-generated funds were the source of funding for these expenditures.
Capital expenditures are expected to be $61 million in 2005 and total about $500
million for 2006 through 2009. The 2005 amount includes $48 million for system
component replacement and upgrades within Regulated Utility, $11 million for
system component replacement and upgrades, and coal handling equipment within
Nonregulated Energy Operations and $2 million for telecommunication fiber within
Other. We expect to use internally-generated funds to fund all capital
expenditures. Although the regulations have not yet been finalized, we believe
that approximately half of the estimated expenditures for 2006 through 2009 may
be necessary for environmental upgrades at our generation facilities.
DISCONTINUED OPERATIONS. Capital expenditures for discontinued operations for
2004 totaled $16.2 million ($62.7 million in 2003; $114.6 million in 2002).
Expenditures for 2004 included $13.1 million for Automotive Services capital
expenditures incurred prior to the September 2004 spin-off and $3.1 million to
maintain our remaining Water Services businesses while they were in the process
of being sold.
ENVIRONMENTAL AND OTHER MATTERS
As previously mentioned in our Critical Accounting Policies section, our
businesses are subject to regulation by various federal, state and local
authorities concerning environmental matters. We anticipate that potential
expenditures for environmental matters will be material in the future, due to
stricter environmental requirements through legislation and/or rulemakings that
are expected to require significant capital investments. We are unable to
predict the outcome of the issues discussed in Note 11.
MARKET RISK
SECURITIES INVESTMENTS
Our securities investments include certain securities held for an indefinite
period of time, which are accounted for as available-for-sale securities.
Available-for-sale securities are recorded at fair value with unrealized gains
and losses included in accumulated other comprehensive income, net of tax.
Unrealized losses that are other than temporary are recognized in earnings.
ALLETE 2004 Form 10-K Page 34
At December 31, 2004, our available-for-sale securities portfolio consisted of
securities in a grantor trust established to fund certain employee benefits. Our
available-for-sale securities portfolio had a fair value of $30.2 million at
December 31, 2004 ($25.5 million at December 31, 2003) and a total unrealized
after-tax gain of $1.5 million at December 31, 2004 ($0.8 million at December
31, 2003). We use the specific identification method as the basis for
determining the cost of securities sold. Our policy is to review on a quarterly
basis available-for-sale securities for other than temporary impairment by
assessing such factors as the continued viability of products offered, cash
flow, share price trends and the impact of overall market conditions. As a
result of our periodic assessments, we did not record any impairment write-down
on available-for-sale securities in 2004 or 2003.
As part of our emerging technology portfolio, we have several minority
investments in venture capital funds and direct investments in privately-held,
start-up companies. We account for our investment in venture capital funds under
the equity method and account for our direct investment in privately-held
companies under the cost method. The total carrying value of our emerging
technology portfolio was $13.6 million at December 31, 2004, down $23.9 million
from December 31, 2003. The decline was primarily due to a change to the equity
method of accounting for the venture capital funds (see Note 14) and impairments
related to investments in privately-held companies. Our basis in cost method
investments included in the emerging technology portfolio was $4.5 million
($11.0 million in 2003). Our policy is to review these investments quarterly for
impairment by assessing such factors as continued commercial viability of
products, cash flow and earnings. Any impairment would reduce the carrying value
of the investment. In 2004, we recorded $6.5 million ($4.1 million after tax) of
impairment losses related to direct investments in certain privately-held,
start-up companies whose future business prospects have diminished
significantly. Recent developments at these companies indicated that future
commercial viability is unlikely, as is new financing necessary to continue
development. We did not record any impairment loss on these investments in 2003
($1.5 million pretax in 2002).
INTEREST RATE SENSITIVE FINANCIAL INSTRUMENTS
PRINCIPAL CASH FLOW BY EXPECTED MATURITY DATE
-----------------------------------------------------------------------------------
FAIR
2005 2006 2007 2008 2009 THEREAFTER TOTAL VALUE
- -------------------------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS
Long-Term Debt
Fixed Rate $0.9 $1.6 $115.9 $56.6 $1.3 $155.4 $331.7 $336.3
Average Interest Rate - % 7.1 6.2 7.1 7.0 6.7 5.4 6.3
Variable Rate $0.9 $0.8 $3.3 $0.8 $9.0 $45.5 $60.3 $60.4
Average Interest Rate - % 3.8 3.8 2.6 3.8 2.4 2.4 2.5
- -------------------------------------------------------------------------------------------------------------------------
Assumes rate in effect at December 31, 2004 remains constant through remaining term.
COMMODITY PRICE RISK
Our regulated utility operations in Minnesota and Wisconsin incur costs for fuel
(primarily coal), power and natural gas purchased for resale in our regulated
service territories, and related transportation. Our regulated utilities'
exposure to price risk for these commodities is significantly mitigated by the
current ratemaking process and regulatory environment which generally allows a
fuel clause surcharge if costs are in excess of those in our last rate filing.
Conversely, costs below those in our last rate filing result in a rate credit.
We seek to prudently manage our customers' exposure to price risk by entering
into contracts of various durations and terms for the purchase of coal and power
(in Minnesota), power and natural gas (in Wisconsin), and related transportation
costs.
POWER MARKETING
Our power marketing activities consist of (1) purchasing energy in the wholesale
market for resale in our regulated service territories when retail energy
requirements exceed generation output, and (2) selling excess available
regulated utility generation and purchased power, as well as selling
nonregulated generation.
From time to time, our regulated utility operations may have excess generation
that is temporarily not required by retail and municipal customers in our
regulated service territory. We actively sell this generation to the wholesale
market to optimize the value of our generating facilities. This generation is
generally sold in the spot market or under short-term contracts at market
prices.
We have approximately 500 MW of nonregulated generation available for sale to
the wholesale markets. This primarily consists of about 200 MW at our Taconite
Harbor facility in northern Minnesota and 275 MW obtained through a 15-year
power purchase agreement with an independent power producer at a facility in
Kendall County near Chicago, Illinois.
Page 35 ALLETE 2004 Form 10-K
Taconite Harbor's capability of approximately 200 MW has been sold through
various short-term and long-term capacity and energy contracts. Short term, we
have approximately 116 MW of capacity and energy sales contracts, all of which
expire on April 30, 2005. Long term, we have entered into two capacity and
energy sales contracts totaling 175 MW (201 MW including a 15% reserve), which
are effective May 1, 2005 and expire on April 30, 2010. Both contracts contain
fixed monthly capacity charges and fixed minimum energy charges. One contract
provides for an annual escalator to the energy charge based on increases in our
cost of coal, subject to a small minimum annual escalation. The other contract
provides that the energy charge will be the greater of a fixed minimum charge or
an amount based on the variable production cost of a combined-cycle, natural gas
unit. Our exposure in the event of a full or partial outage at our Taconite
Harbor facility is significantly limited under both contracts. When the buyer is
notified at least two months prior to an outage, there is no exposure. Outages
with less than two months' notice are subject to an annual duration limitation
typical of this type of contract. We also have a 50 MW capacity and energy sales
contract that extends through April 2008 and a 15 MW energy sales contract that
extends through May 2007. The 50 MW capacity and energy sales contract has fixed
pricing through January 2006 and market-based pricing thereafter.
Under the Kendall County agreement, which expires in September 2017, we pay a
fixed capacity charge for the right, but not the obligation, to capacity and
energy from a 275-MW generating unit. We are responsible for arranging the
natural gas fuel supply. To date, this power purchase agreement has resulted in
losses to us due to negative spark spreads (the differential between electric
and natural gas prices) in the wholesale power market and our resulting
inability to cover the fixed capacity charge on the unsold capacity (currently
145 MW). To eliminate ongoing losses from generation secured through the Kendall
County agreement, in December 2004, we entered into an agreement to assign this
power purchase agreement to Constellation Energy Commodities. Pending certain
approvals, the transaction is scheduled to close in April 2005. We currently
have approximately 130 MW of long-term capacity sales contracts for the Kendall
County generation, which will also be transferred to Constellation Energy
Commodities at closing.
NEW ACCOUNTING STANDARDS
New accounting standards are discussed in Note 2.
------------------------
FACTORS THAT MAY AFFECT FUTURE RESULTS
READERS ARE CAUTIONED THAT FORWARD-LOOKING STATEMENTS, INCLUDING THOSE CONTAINED
IN THIS FORM 10-K, SHOULD BE READ IN CONJUNCTION WITH OUR DISCLOSURES UNDER THE
HEADING: "SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM
ACT OF 1995" LOCATED ON PAGE 3 OF THIS FORM 10-K AND THE FACTORS DESCRIBED
BELOW. THE RISKS AND UNCERTAINTIES DESCRIBED IN THIS FORM 10-K ARE NOT THE ONLY
ONES FACING OUR COMPANY. ADDITIONAL RISKS AND UNCERTAINTIES THAT WE ARE NOT
PRESENTLY AWARE OF, OR THAT WE CURRENTLY CONSIDER IMMATERIAL, MAY ALSO AFFECT
OUR BUSINESS OPERATIONS. OUR BUSINESS, FINANCIAL CONDITION OR RESULTS OF
OPERATIONS COULD SUFFER IF THE CONCERNS SET FORTH BELOW ARE REALIZED.
IF OUR SIGNIFICANT CUSTOMERS ARE NEGATIVELY IMPACTED BY WORLD ECONOMICS, OUR
REVENUE MAY BE NEGATIVELY IMPACTED.
Our industrial customers are impacted by world economics that affect their
competitive position and profitability. Taconite producers, and paper and wood
products customers served by Minnesota Power compete in this world marketplace.
Their inability to compete in their global markets could have a material adverse
effect on their operations and continuation as a business. Any such failure
could have a material adverse effect on our results of operations and the
communities we serve.
OUR ENERGY BUSINESS IS SUBJECT TO INCREASED COMPETITION.
The independent power industry includes numerous strong and capable competitors,
many of which have extensive experience in the operation, acquisition and
development of power generation facilities. Our competition is based primarily
on price and reputation for quality, safety and reliability. The electric
utility and natural gas industries are also experiencing increased competitive
pressures as a result of consumer demands, technological advances, deregulation,
greater availability of natural gas-fired generation and other factors.
ALLETE 2004 Form 10-K Page 36
WE ARE SUBJECT TO EXTENSIVE GOVERNMENTAL REGULATIONS THAT MAY HAVE A NEGATIVE
IMPACT ON OUR BUSINESS AND RESULTS OF OPERATIONS.
We are subject to prevailing governmental policies and regulatory actions,
including those of the United States Congress, state legislatures, the FERC, the
MPUC, the FPSC, the PSCW, and various local and county regulators, and city
administrators. These governmental regulations relate to allowed rates of
return, financings, industry and rate structure, acquisition and disposal of
assets and facilities, real estate development, operation and construction of
plant facilities, recovery of purchased power and capital investments, and
present or prospective wholesale and retail competition (including but not
limited to transmission costs). These governmental regulations significantly
influence our operating environment and may affect our ability to recover costs
from our customers. We are required to have numerous permits, approvals and
certificates from the agencies that regulate our business. We believe the
necessary permits, approvals and certificates have been obtained for existing
operations and that our business is conducted in accordance with applicable
laws; however, we are unable to predict the impact on operating results from the
future regulatory activities of any of these agencies. Changes in regulations or
the imposition of additional regulations could have an adverse impact on our
results of operations.
OUR REGULATED UTILITY AND NONREGULATED ENERGY OPERATIONS POSE CERTAIN
ENVIRONMENTAL RISKS WHICH COULD ADVERSELY AFFECT OUR RESULTS OF OPERATIONS AND
FINANCIAL CONDITION.
We are subject to extensive environmental laws and regulations affecting many
aspects of our present and future operations, including air quality, water
quality, waste management, reclamation and other environmental considerations.
These laws and regulations can result in increased capital, operating, and other
costs, as a result of compliance, remediation, containment and monitoring
obligations, particularly with regard to laws relating to power plant emissions.
These laws and regulations generally require us to obtain and comply with a wide
variety of environmental licenses, permits, inspections and other approvals.
Both public officials and private individuals may seek to enforce applicable
environmental laws and regulations. We cannot predict the financial or
operational outcome of any related litigation that may arise.
There are no assurances that existing environmental regulations will not be
revised or that new regulations seeking to protect the environment will not be
adopted or become applicable to us. Revised or additional regulations, which
result in increased compliance costs or additional operating restrictions,
particularly if those costs are not fully recoverable from customers, could have
a material effect on our results of operations.
We cannot predict with certainty the amount or timing of all future expenditures
related to environmental matters because of the difficulty of estimating such
costs. There is also uncertainty in quantifying liabilities under environmental
laws that impose joint and several liability on all potentially responsible
parties. (See Note 11.)
THE OPERATION AND MAINTENANCE OF OUR GENERATING FACILITIES INVOLVES RISKS THAT
COULD SIGNIFICANTLY INCREASE THE COST OF DOING BUSINESS.
The operation of generating facilities involves many risks, including start-up
risks, breakdown or failure of facilities, lack of sufficient capital to
maintain the facilities, the dependence on a specific fuel source, or the impact
of unusual or adverse weather conditions or other natural events, as well as the
risk of performance below expected levels of output or efficiency, the
occurrence of any of which could result in lost revenue and/or increased
expenses. A significant portion of Minnesota Power's facilities was constructed
many years ago. In particular, older generating equipment, even if maintained in
accordance with good engineering practices, may require significant capital
expenditures to keep it operating at peak efficiency. This equipment is also
likely to require periodic upgrading and improvement. Minnesota Power could be
subject to costs associated with any unexpected failure to produce power,
including failure caused by breakdown or forced outage, as well as repairing
damage to facilities due to storms, natural disasters, wars, terrorist acts and
other catastrophic events. Further, our ability to successfully and timely
complete capital improvements to existing facilities or other capital projects
is contingent upon many variables and subject to substantial risks. Should any
such efforts be unsuccessful, we could be subject to additional costs and/or the
write-off of our investment in the project or improvement.
WE MUST HAVE ADEQUATE AND RELIABLE TRANSMISSION AND DISTRIBUTION FACILITIES TO
DELIVER OUR ELECTRICITY TO OUR CUSTOMERS.
Minnesota Power depends on transmission and distribution facilities owned and
operated by other utilities, as well as its own such facilities, to deliver the
electricity it produces and sells to its customers, as well as to other energy
suppliers. If transmission capacity is inadequate, our ability to sell and
deliver electricity may be hindered, we may have to forgo sales or we may have
to buy more expensive wholesale electricity that is available in the
capacity-constrained area. The cost to provide service to these customers may
exceed the cost to serve other customers, resulting in lower gross margins. In
addition, any infrastructure failure that interrupts or impairs delivery of
electricity to our customers could negatively impact the satisfaction of our
customers with our service.
Page 37 ALLETE 2004 Form 10-K
THE PRICE OF ONE OF OUR MAJOR PRODUCTS, ELECTRICITY, AND/OR ONE OF OUR MAJOR
EXPENSES, FUEL, MAY BE VOLATILE.
Volatility in market prices for electricity and fuel may result from:
- severe or unexpected weather conditions;
- seasonality;
- changes in electricity usage;
- the current diminished liquidity in the wholesale power markets, as well as
any future illiquidity in these or other markets;
- transmission or transportation constraints, inoperability or
inefficiencies;
- availability of competitively priced alternative energy sources;
- changes in supply and demand for energy commodities;
- changes in power production capacity;
- outages at Minnesota Power's generating facilities or those of our
competitors;
- changes in production and storage levels of natural gas, lignite, coal, and
crude oil and refined products;
- natural disasters, wars, sabotage, terrorist acts and other catastrophic
events; and
- federal, state, local and foreign energy, environmental, and other
regulation and legislation.
Since fluctuations in fuel expense related to our regulated utility operations
are passed on to customers through our fuel clause, risk of volatility in market
prices for fuel and electricity mainly impacts our nonregulated operations at
this time.
WE ARE DEPENDENT ON GOOD LABOR RELATIONS.
We believe our relations to be good with our approximately 1,500 employees.
Approximately 700 of these employees are members of either the International
Brotherhood of Electrical Workers Local 31 or Local 1593. Failure to
successfully renegotiate labor agreements could adversely affect the services we
provide and our results of operations. The labor agreements with Local 31 expire
on January 31, 2006. The labor agreement with Local 1593 at BNI Coal ends on
March 31, 2005, and negotiations are under way for a new contract.
A DOWNTURN IN ECONOMIC CONDITIONS COULD ADVERSELY AFFECT OUR REAL ESTATE
BUSINESS.
The ability of our real estate business to generate revenue is directly related
to the Florida real estate market, the national and local economy in general,
and changes in interest rates. While real estate market conditions have remained
healthy in our regions of development, continued demand for land is dependent on
long-term prospects for strong, in-migration population expansion.
Over the last several years, investors have increasingly utilized real estate as
an investment. Florida real estate has particularly benefited from this trend,
creating demand for our land. If this trend were to lessen, the demand for our
land could decline, potentially impacting selling prices.
WE ARE EXPOSED TO RISKS ASSOCIATED WITH REAL ESTATE DEVELOPMENT.
Our real estate development activities entail risks that include construction
delays or cost overruns, which may increase project development costs.
In addition, our real estate development activities require significant capital
expenditures. We obtain funds for our capital expenditures through cash flow
from operations and financings. We cannot be sure that the funds available from
these sources will be sufficient to fund our required or desired capital
expenditures for development. If we are unable to obtain sufficient funds, we
may have to defer or otherwise limit our development activities. If we are
unsuccessful in our selling efforts, we may not be able to recover these capital
expenditures.
OUR REAL ESTATE BUSINESS IS SUBJECT TO EXTENSIVE REGULATION, WHICH MAKES IT
DIFFICULT AND EXPENSIVE FOR US TO CONDUCT OUR OPERATIONS.
Development of real property in Florida entails an extensive approval process
involving overlapping regulatory jurisdictions. Real estate projects must
generally comply with the provisions of the Local Government Comprehensive
Planning and Land Development Regulation Act (Growth Management Act). In
addition, development projects that exceed certain specified regulatory
thresholds require approval of a comprehensive Development of Regional Impact
(DRI) application. Compliance with the Growth Management Act and the DRI process
is usually lengthy and costly and can be expected to materially affect our real
estate development activities.
ALLETE 2004 Form 10-K Page 38
The Growth Management Act requires counties and cities to adopt comprehensive
plans guiding and controlling future real property development in their
respective jurisdictions. After a local government adopts its comprehensive
plan, all development orders and development permits must be consistent with the
plan. Each plan must address such topics as future land use, capital
improvements, traffic circulation, sanitation, sewerage, potable water, drainage
and solid waste disposal. The local governments' comprehensive plans must also
establish "levels of service" with respect to certain specified public
facilities and services to residents. Local governments are prohibited from
issuing development orders or permits if facilities and services are not
operating at established levels of service, or if the projects for which permits
are requested will reduce the level of service for public facilities below the
level of service established in the local government's comprehensive plan. If
the proposed development would reduce the established level of services below
the level set by the plan, the development order will require that, at the
outset of the project, the developer either sufficiently improve the services to
meet the required level or provide financial assurances that the additional
services will be provided as the project progresses.
The Growth Management Act, in some instances, can significantly affect the
ability of developers to obtain local government approval in Florida. In many
areas, infrastructure funding has not kept pace with growth. As a result,
substandard facilities and services can delay or prevent the issuance of
permits. Consequently, the Growth Management Act could adversely affect our
ability to develop our real estate projects.
The DRI review process includes an evaluation of a project's impact on the
environment, infrastructure and government services, and requires the
involvement of numerous state and local environmental, zoning and community
development agencies. Local government approval of any DRI is subject to appeal
to the Governor and Cabinet by the Florida Department of Community Affairs, and
adverse decisions by the Governor or Cabinet are subject to judicial appeal. The
DRI approval process is usually lengthy and costly, and conditions, standards or
requirements may be imposed on a developer with respect to a particular project,
which may materially increase the cost of the project. The DRI approval process
is expected to have a material impact on our real estate development activities
in the future.
ENVIRONMENTAL AND OTHER REGULATIONS MAY HAVE AN ADVERSE EFFECT ON OUR REAL
ESTATE BUSINESS.
A substantial portion of our development properties in Florida is subject to
federal, state, and local regulations and restrictions that may impose
significant costs or limitations on our ability to develop our properties. Much
of our property is vacant land and some is located in areas where development
may affect the natural habitats of various protected wildlife species or in
sensitive environmental areas such as wetlands.
RISKS ASSOCIATED WITH ACQUISITIONS MAY HINDER OUR ABILITY TO INCREASE REVENUE
AND EARNINGS.
The energy industry is considered a mature industry in which low, single-digit
growth is expected in industry unit sales. Accordingly, our future growth
depends in large part on our ability to increase our volumes relative to our
competition, acquire additional businesses, replenish land inventories for our
real estate business, manage expansion, control costs in our operations,
introduce new services and consolidate future acquisitions into existing
operations. In pursuing a strategy of acquiring other businesses, we face risks
commonly encountered with growth through acquisitions. These risks include, but
are not limited to:
- incurring significantly higher capital expenditures and operating expenses;
- failing to assimilate the operations and personnel of the acquired
businesses;
- entering new, unfamiliar markets;
- potential undiscovered liabilities at acquired businesses;
- disrupting our ongoing business;
- diverting our limited management resources;
- failing to maintain uniform standards, controls and policies;
- impairing relationships with employees and customers as a result of changes
in management; and
- increasing expenses for accounting and computer systems, as well as
integration difficulties.
We may not adequately anticipate all of the demands that our growth will impose
on our systems, procedures and structures, including our financial and reporting
control systems, data processing systems and management structure. If we cannot
adequately anticipate and respond to these demands, our business could be
materially harmed.
Although we conduct what we believe to be a prudent level of investigation
regarding the operating condition of the businesses we purchase, in light of the
circumstances of each transaction, an unavoidable level of risk remains
regarding the actual operating condition of these businesses. Until we actually
assume operating control of such business assets, we may not be able to
ascertain the actual value of the acquired entity.
Page 39 ALLETE 2004 Form 10-K
WE CAN OFFER YOU NO ASSURANCES THAT WE WILL BE ABLE TO EXECUTE AN ACQUISITION
STRATEGY WITHOUT THE COSTS OF FUTURE ACQUISITIONS ESCALATING.
Although there are potential acquisition candidates that fit our acquisition
criteria, we are not certain that we will be able to consummate any such
transactions in the future or identify those candidates that would result in the
most successful combinations, or that future acquisitions will be able to be
consummated at acceptable prices and terms. In addition, increased competition
for acquisition candidates could result in fewer acquisition opportunities for
us and higher acquisition prices. The magnitude, timing, pricing and nature of
future acquisitions will depend upon various factors, including:
- the availability of suitable acquisition candidates;
- competition with other industry groups or new industry consolidators for
suitable acquisitions;
- the negotiation of acceptable terms;
- our financial capabilities;
- the availability of skilled employees to manage the acquired companies; and
- general economic and business conditions.
OUR CREDIT RATINGS COULD BE REVISED DOWNWARD.
The current credit ratings for our long-term debt are investment grade. A rating
reflects only the view of a rating agency, and it is not a recommendation to
buy, sell or hold securities. Any rating can be revised upward or downward at
any time by a rating agency if such rating agency decides that circumstances
warrant such a change. If Standard & Poor's or Moody's were to downgrade our
long-term ratings, particularly below investment grade, borrowing costs would
increase and the potential pool of investors and funding sources would likely
decrease.
WE RELY HEAVILY ON TECHNOLOGY TO AUTOMATE AND MAXIMIZE THE EFFICIENCIES OF OUR
BUSINESSES. TECHNOLOGY IS CONSTANTLY EVOLVING AND IN ORDER FOR US TO REMAIN
COMPETITIVE WE WILL EMBRACE NEW TECHNOLOGIES AS THEY BECOME PROVEN AND ARE
ECONOMICALLY VIABLE.
Technology is an integral part of the operating and administrative functions of
our businesses. The information systems and processes necessary to support
business areas such as risk management, sales, customer service, and procurement
and supply are complex and are constantly evolving. To successfully compete in
our businesses, we must adapt to the evolving market by continually improving
the responsiveness, functionality, and features of our services and systems to
meet our customers' and other stakeholders' needs. Increased automation through
proven, economically viable technologies is among the primary tools that we use
to enhance our competitive position; without these technologies, our businesses
would not be able to safely operate or adequately respond to customer and other
stakeholder needs.
TAX RESERVES AND THE RECOVERABILITY OF OUR DEFERRED TAX ASSETS MAY HAVE A
SIGNIFICANT IMPACT ON OUR RESULTS OF OPERATIONS.
We are required to make judgments regarding the potential tax effects of various
financial transactions and our ongoing operations to estimate our obligations to
taxing authorities. These tax obligations include income, real estate, use and
employment-related taxes. These judgments include reserves for potential adverse
outcomes regarding tax positions that we have taken. We must also assess our
ability to generate capital gains to realize tax benefits associated with
capital losses expected to be generated in future periods. Capital losses may be
deducted only to the extent of capital gains realized during the year of the
loss or during the three prior or five succeeding years. As of December 31,
2004, we have, where appropriate, recorded an allowance against our deferred tax
assets associated with impairment losses, which will become capital losses when
realized for income tax purposes. The ultimate outcome of such matters could
result in adjustments to our consolidated financial statements and such
adjustments could be material.
ADEQUATE INSURANCE PROTECTION MAY NOT BE COST EFFECTIVE OR AVAILABLE TO MINIMIZE
RISK.
Insurance, warranties or performance guarantees may not cover any or all of the
lost revenue or increased expenses, including the cost of replacement power.
Likewise, our ability to obtain insurance, and the cost of and coverage provided
by such insurance, could be affected by events outside our control.
IF WE ARE NOT ABLE TO RETAIN OUR EXECUTIVE OFFICERS AND KEY EMPLOYEES, WE MAY
NOT BE ABLE TO IMPLEMENT OUR BUSINESS STRATEGY AND OUR BUSINESS COULD SUFFER.
The success of our business heavily depends on the leadership of our executive
officers, all of whom are employees-at-will and none of whom are subject to any
agreements not to compete. If we lose the service of one or more of our
executive officers or key employees, or if one or more of them decides to join a
competitor or otherwise compete directly or indirectly with us, we may not be
able to successfully manage our business or achieve our business objectives. We
may have difficulty in retaining and attracting customers, developing new
services, negotiating favorable agreements with customers and providing
acceptable levels of customer service.
ALLETE 2004 Form 10-K Page 40
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See Item 7. Management's Discussion and Analysis of Results of Operations and
Financial Condition - Market Risk for information related to quantitative and
qualitative disclosure about market risk.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See our consolidated financial statements as of December 31, 2004 and 2003 and
for each of the three years in the period ended December 31, 2004, and
supplementary data, also included, which are indexed in Item 15(a).
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
ITEM 9A. CONTROLS AND PROCEDURES
CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES
Under the supervision and with the participation of our management, including
our principal executive officer and principal financial officer, we conducted an
evaluation of our disclosure controls and procedures, as such term is defined
under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as
amended (the Exchange Act). Based on this evaluation, our principal executive
officer and our principal financial officer concluded that our disclosure
controls and procedures were effective as of the end of the period covered by
this annual report.
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal
control over financial reporting, as such term is defined in Exchange Act Rule
13a-15(f). Under the supervision and with the participation of our management,
including our principal executive officer and principal financial officer, we
conducted an evaluation of the effectiveness of our internal control over
financial reporting based on the framework in Internal Control--Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. Based on our evaluation under the framework in Internal
Control--Integrated Framework, our management concluded that our internal
control over financial reporting was effective as of December 31, 2004.
Our management's assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2004, has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as
stated in their report which is included herein.
ITEM 9B. OTHER INFORMATION
On December 14, 2004, ALLETE entered into a committed, syndicated, unsecured,
revolving credit facility with LaSalle Bank, National Association for $100
million (Line). The Line matures on December 14, 2007. The Line may be used by
ALLETE for general corporate purposes, working capital and to provide liquidity
in support of the ALLETE's commercial paper program. ALLETE may prepay amounts
outstanding under the Line in whole or in part at its discretion. Additionally,
ALLETE may irrevocably terminate or reduce the size of the Line prior to
maturity.
ALLETE has agreed to certain financial covenants related to the Line. The most
restrictive covenants require ALLETE (1) to not exceed a maximum ratio of funded
debt to total capital of .65 to 1.00; and (2) to maintain an interest coverage
ratio of not less than 3.00 to 1.00. The Line also contains a cross-default
provision, under which an event of default would arise if other ALLETE
obligations in excess of $5.0 million were in default. (See Note 8.)
Page 41 ALLETE 2004 Form 10-K
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Unless otherwise stated, the information required for this Item is incorporated
by reference herein from our Proxy Statement for the 2005 Annual Meeting of
Shareholders (2005 Proxy Statement) under the following headings:
- DIRECTORS. The information regarding directors will be included in the
"Election of Directors" section;
- AUDIT COMMITTEE FINANCIAL EXPERT. The information regarding the audit
committee financial expert will be included in the "Report of the Audit
Committee" section;
- AUDIT COMMITTEE MEMBERS. The identity of the audit committee members is
included in the "Report of the Audit Committee" section;
- EXECUTIVE OFFICERS. The information regarding executive officers is included
in Part I of this Form 10-K; and
- SECTION 16(A) COMPLIANCE. The information regarding Section 16(a)
compliance will be included in the "Section 16(a) Beneficial Ownership
Reporting Compliance" section.
Our 2005 Proxy Statement will be filed with the SEC within 120 days after the
end of our 2004 fiscal year.
CODE OF ETHICS. We have adopted a written Code of Ethics that applies to all of
our employees, including our chief executive officer, chief financial officer
and controller. A copy of our Code of Ethics is available on our website at
www.allete.com and print copies are available upon request without charge. Any
amendment to the Code of Ethics or any waiver of the Code of Ethics will be
disclosed on our website at www.allete.com promptly following the date of such
amendment or waiver.
CORPORATE GOVERNANCE. The following documents are available on our website at
www.allete.com and print copies are available upon request:
- Corporate Governance Guidelines;
- Audit Committee Charter;
- Executive Compensation Committee Charter; and
- Corporate Governance and Nominating Committee Charter.
Any amendment to these documents will be disclosed on our website at
www.allete.com promptly following the date of such amendment.
ITEM 11. EXECUTIVE COMPENSATION
The information required for this Item is incorporated by reference herein from
the "Compensation of Executive Officers" and the "Director Compensation"
sections in our 2005 Proxy Statement.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The information required for this Item is incorporated by reference herein from
the "Security Ownership of Certain Beneficial Owners and Management" and the
"Equity Compensation Plan Information" sections in our 2005 Proxy Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this Item is incorporated by reference herein from
the "Report of the Audit Committee" section in our 2005 Proxy Statement.
ALLETE 2004 Form 10-K Page 42
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Certain Documents Filed as Part of this Form 10-K.
(1) Financial Statements Page
ALLETE
Report of Independent Registered Public Accounting Firm.......... 47
Consolidated Balance Sheet at December 31, 2004 and 2003......... 48
For the Three Years Ended December 31, 2004
Consolidated Statement of Income............................ 49
Consolidated Statement of Cash Flows........................ 50
Consolidated Statement of Shareholders' Equity.............. 51
Notes to Consolidated Financial Statements....................... 52-76
(2) Financial Statement Schedules
Schedule II - ALLETE Valuation and Qualifying Accounts and Reserves.. 77
All other schedules have been omitted either because the information is not
required to be reported by ALLETE or because the information is included in
the consolidated financial statements or the notes.
(3) Exhibits including those incorporated by reference.
EXHIBIT NUMBER
*2 - Stock Purchase Agreement (without Exhibits and Schedules),
dated November 20, 2003, by and between Philadelphia Suburban
Corporation (now Aqua America, Inc.), as Purchaser, and ALLETE
Water Services, Inc., as Shareholder, related to the sale of
Heater Utilities, Inc. (filed as Exhibit 2(b) to the 2003 Form
10-K, File No. 1-3548).
*3(a)1 - Articles of Incorporation, amended and restated as of May 8,
2001 (filed as Exhibit 3(b) to the March 31, 2001 Form 10-Q,
File No. 1-3548).
*3(a)2 - Amendment to Articles of Incorporation, effective 12:00 p.m.
Eastern Time on September 20, 2004 (filed as Exhibit 3 to the
September 21, 2004 Form 8-K, File No. 1-3548).
*3(a)3 - Amendment to Certificate of Assumed Name, filed with the
Minnesota Secretary of State on May 8, 2001 (filed as Exhibit
3(a) to the March 31, 2001 Form 10-Q, File No. 1-3548).
*3(b) - Bylaws, as amended effective August 24, 2004 (filed as Exhibit
3 to the August 25, 2004 Form 8-K, File No. 1-3548). *4(a)1 -
Mortgage and Deed of Trust, dated as of September 1, 1945,
between Minnesota Power & Light Company (now ALLETE) and
The Bank of New York (formerly Irving Trust Company) and
Douglas J. MacInnes (successor to Richard H. West), Trustees
(filed as Exhibit 7(c), File No. 2-5865).
*4(a)2 - Supplemental Indentures to ALLETE's Mortgage and Deed of
Trust:
NUMBER DATED AS OF REFERENCE FILE EXHIBIT
First March 1, 1949 2-7826 7(b)
Second July 1, 1951 2-9036 7(c)
Third March 1, 1957 2-13075 2(c)
Fourth January 1, 1968 2-27794 2(c)
Fifth April 1, 1971 2-39537 2(c)
Sixth August 1, 1975 2-54116 2(c)
Seventh September 1, 1976 2-57014 2(c)
Eighth September 1, 1977 2-59690 2(c)
Ninth April 1, 1978 2-60866 2(c)
Tenth August 1, 1978 2-62852 2(d)2
Eleventh December 1, 1982 2-56649 4(a)3
Twelfth April 1, 1987 33-30224 4(a)3
Thirteenth March 1, 1992 33-47438 4(b)
Fourteenth June 1, 1992 33-55240 4(b)
Fifteenth July 1, 1992 33-55240 4(c)
Sixteenth July 1, 1992 33-55240 4(d)
Seventeenth February 1, 1993 33-50143 4(b)
Eighteenth July 1, 1993 33-50143 4(c)
Nineteenth February 1, 1997 1-3548 (1996 Form 10-K) 4(a)3
Twentieth November 1, 1997 1-3548 (1997 Form 10-K) 4(a)3
Twenty-first October 1, 2000 333-54330 4(c)3
Twenty-second July 1, 2003 1-3548 (June 30, 2003 Form 10-Q) 4
Twenty-third August 1, 2004 1-3548 (Sept. 30, 2004 Form 10-Q) 4(a)
Page 43 ALLETE 2004 Form 10-K
EXHIBIT NUMBER
*4(b)1 - Indenture of Trust, dated as of August 1, 2004, between the
City of Cohasset, Minnesota and U.S. Bank National
Association, as Trustee relating to $111 Million
Collateralized Pollution Control Refunding Revenue Bonds
(filed as Exhibit 4(b) to the September 30, 2004 Form 10-Q,
File No. 1-3548).
*4(b)2 - Loan Agreement, dated as of August 1, 2004, between the City
of Cohasset, Minnesota and ALLETE relating to $111 Million
Collateralized Pollution Control Refunding Revenue Bonds
(filed as Exhibit 4(c) to the September 30, 2004 Form 10-Q,
File No. 1-3548).
*4(c)1 - Mortgage and Deed of Trust, dated as of March 1, 1943, between
Superior Water, Light and Power Company and Chemical Bank &
Trust Company and Howard B. Smith, as Trustees, both succeeded
by U.S. Bank Trust N.A., as Trustee (filed as Exhibit 7(c),
File No. 2-8668).
*4(c)2 - Supplemental Indentures to Superior Water, Light and Power
Company's Mortgage and Deed of Trust:
NUMBER DATED AS OF REFERENCE FILE EXHIBIT
First March 1, 1951 2-59690 2(d)(1)
Second March 1, 1962 2-27794 2(d)1
Third July 1, 1976 2-57478 2(e)1
Fourth March 1, 1985 2-78641 4(b)
Fifth December 1, 1992 1-3548 (1992 Form 10-K) 4(b)1
Sixth March 24, 1994 1-3548 (1996 Form 10-K) 4(b)1
Seventh November 1, 1994 1-3548 (1996 Form 10-K) 4(b)2
Eighth January 1, 1997 1-3548 (1996 Form 10-K) 4(b)3
*4(d)1 - Rights Agreement, dated as of July 24, 1996, between Minnesota
Power & Light Company (now ALLETE) and the Corporate Secretary
of the Company, as Rights Agent (filed as Exhibit 4 to the
August 2, 1996 Form 8-K, File No. 1-3548).
*4(d)2 - Certificate of Adjustment to the Rights Agreement as amended,
dated as of July 24, 1996, between Minnesota Power & Light
Company (now ALLETE) and the Corporate Secretary of the
Company, as Rights Agent (filed as Exhibit 4(d) to the
September 30, 2004 Form 10-Q, File No. 1-3548).
*10(a) - Power Purchase and Sale Agreement, dated as of May 29, 1998,
between Minnesota Power, Inc. (now ALLETE) and Square Butte
Electric Cooperative (filed as Exhibit 10 to the June 30, 1998
Form 10-Q, File No. 1-3548).
*10(b) - Amended and Restated Withdrawal Agreement (without Exhibits
and Schedules), dated January 30, 2004, by and between Great
River Energy and Minnesota Power (now ALLETE) (filed as
Exhibit 10(p) to the 2003 Form 10-K, File No. 1-3548).
10(c) - Master Agreement (without Appendices and Exhibits), dated
December 28, 2004, by and between Rainy River Energy
Corporation and Constellation Energy Commodities Group, Inc.
*10(d)1 - Third Amended and Restated Committed Facility Letter (without
Exhibits), dated December 23, 2003, to ALLETE from LaSalle
Bank National Association, as Agent (filed as Exhibit 10(s) to
the 2003 Form 10-K, File No. 1-3548).
10(d)2 - First Amendment to Third Amended and Restated Committed
Facility Letter, dated December 14, 2004, by and among ALLETE
and LaSalle Bank National Association, as Agent.
*10(e) - Master Separation Agreement, dated June 4, 2004, between
ALLETE, Inc. and ADESA, Inc. (filed as Exhibit 10.1 to ADESA,
Inc.'s June 30, 2004 Form 10-Q, File No. 1-32198).
+*10(f)1 - Minnesota Power (now ALLETE) Executive Annual Incentive Plan,
as amended, effective January 1, 1999 with amendments through
January 2003 (filed as Exhibit 10 to the September 30, 2003
Form 10-Q, File No. 1-3548).
+*10(f)2 - November 2003 Amendment to the ALLETE Executive Annual
Incentive Plan (filed as Exhibit 10(t)2 to the 2003 Form 10-K,
File No. 1-3548).
+*10(f)3 - July 2004 Amendment to the ALLETE Executive Annual Incentive
Plan (filed as Exhibit 10(a) to the June 30, 2004 Form 10-Q,
File No. 1-3548).
+*10(g) - ALLETE and Affiliated Companies Supplemental Executive
Retirement Plan, as amended and restated, effective January 1,
2004 (filed as Exhibit 10(u) to the 2003 Form 10-K, File No.
1-3548).
+*10(h)1 - Executive Investment Plan I, as amended and restated,
effective November 1, 1988 (filed as Exhibit 10(c) to the 1988
Form 10-K, File No. 1-3548).
+*10(h)2 - Amendments through December 2003 to the Minnesota Power and
Affiliated Companies Executive Investment Plan I (filed as
Exhibit 10(v)2 to the 2003 Form 10-K, File No. 1-3548).
+*10(h)3 - July 2004 Amendment to the Minnesota Power and Affiliated
Companies Executive Investment Plan I (filed as Exhibit 10(b)
to the June 30, 2004 Form 10-Q, File No. 1-3548).
ALLETE 2004 Form 10-K Page 44
EXHIBIT NUMBER
+*10(i)1 - Executive Investment Plan II, as amended and restated,
effective November 1, 1988 (filed as Exhibit 10(d) to the 1988
Form 10-K, File No. 1-3548).
+*10(i)2 - Amendments through December 2003 to the Minnesota Power and
Affiliated Companies Executive Investment Plan II (filed as
Exhibit 10(w)2 to the 2003 Form 10-K, File No. 1-3548).
+*10(i)3 - July 2004 Amendment to the Minnesota Power and Affiliated
Companies Executive Investment Plan II (filed as Exhibit 10(c)
to the June 30, 2004 Form 10-Q, File No. 1-3548).
+*10(j) - Deferred Compensation Trust Agreement, as amended and
restated, effective January 1, 1989 (filed as Exhibit 10(f) to
the 1988 Form 10-K, File No. 1-3548).
+*10(k)1 - Minnesota Power (now ALLETE) Executive Long-Term Incentive
Compensation Plan, effective January 1, 1996 (filed as Exhibit
10(a) to the June 30, 1996 Form 10-Q, File No. 1-3548).
+*10(k)2 - Amendments through January 2003 to the Minnesota Power (now
ALLETE) Executive Long-Term Incentive Compensation Plan (filed
as Exhibit 10(z)2 to the 2002 Form 10-K, File No. 1-3548).
+*10(k)3 - July 2004 Amendment to the ALLETE Executive Long-Term
Incentive Compensation Plan (filed as Exhibit 10(d) to the
June 30, 2004 Form 10-Q, File No. 1-3548).
+10(k)4 - Form of ALLETE Executive Long-Term Incentive Compensation Plan
Nonqualified Stock Option Grant.
+10(k)5 - Form of ALLETE Executive Long-Term Incentive Compensation Plan
Performance Share Grant.
+*10(l)1 - Minnesota Power (now ALLETE) Director Stock Plan, effective
January 1, 1995 (filed as Exhibit 10 to the March 31, 1995
Form 10-Q, File No. 1-3548).
+*10(l)2 - Amendments through December 2003 to the Minnesota Power (now
ALLETE) Director Stock Plan (filed as Exhibit 10(z)2 to the
2003 Form 10-K, File No. 1-3548).
+*10(l)3 - July 2004 Amendment to the ALLETE Director Stock Plan (filed
as Exhibit 10(e) to the June 30, 2004 Form 10-Q, File No.
1-3548).
+*10(m)1 - Minnesota Power (now ALLETE) Director Compensation Deferral
Plan Amended and Restated, effective January 1, 1990 (filed as
Exhibit 10(ac) to the 2002 Form 10-K, File No. 1-3548).
+*10(m)2 - October 2003 Amendment to the Minnesota Power (now ALLETE)
Director Compensation Deferral Plan (filed as Exhibit 10(aa)2
to the 2003 Form 10-K, File No. 1-3548).
+*10(n) - ALLETE Director Compensation Trust Agreement, effective
October 11, 2004 (filed as Exhibit 10(a) to the September 30,
2004 Form 10-Q, File No. 1-3548).
12 - Computation of Ratios of Earnings to Fixed Charges.
*21 - Subsidiaries of the Registrant (reference is made to ALLETE's
Form U-3A-2 for the year ended December 31, 2004, File No.
69-78).
23(a) - Consent of Independent Registered Public Accounting Firm.
23(b) - Consent of General Counsel.
31(a) - Rule 13a-14(a)/15d-14(a) Certification by the Chief Executive
Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
31(b) - Rule 13a-14(a)/15d-14(a) Certification by the Chief Financial
Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
32 - Section 1350 Certification of Annual Report by the Chief
Executive Officer and Chief Financial Officer Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
We are a party to other long-term debt instruments that, pursuant to Regulation
S-K, Item 601(b)(4)(iii), are not filed as exhibits since the total amount of
debt authorized under each such omitted instrument does not exceed 10% of our
total consolidated assets. These instruments include the following:
- $38,995,000 City of Cohasset, Minnesota, Variable Rate Demand
Revenue Refunding Bonds (ALLETE, formerly Minnesota Power &
Light Company, Project) Series 1997A, Series 1997B, Series
1997C and Series 1997D.
- $35,105,000 Collier County Industrial Development Authority,
6.50% Industrial Development Refunding Revenue Bonds (Florida
Water Services Corporation, formerly Southern States
Utilities, Inc., Project) Series 1996.
We will furnish copies of these instruments to the SEC upon its request.
- -----------------------------
* Incorporated herein by reference as indicated.
+ Management contract or compensatory plan or arrangement required to be filed
as an exhibit to this report pursuant to Item 15(c) of Form 10-K.
Page 45 ALLETE 2004 Form 10-K
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
ALLETE, INC.
Dated: February 11, 2005 By Donald J. Shippar
------------------------------------------
Donald J. Shippar
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
- -------------------------------------------------------------------------------------------------------------------------
Donald J. Shippar President, Chief Executive Officer February 11, 2005
- ----------------------------------------
Donald J. Shippar and Director
James K. Vizanko Senior Vice President and Chief Financial Officer February 11, 2005
- ----------------------------------------
James K. Vizanko
Mark A. Schober Senior Vice President and Controller February 11, 2005
- ----------------------------------------
Mark A. Schober
Heidi J. Eddins Director February 11, 2005
- ----------------------------------------
Heidi J. Eddins
Peter J. Johnson Director February 11, 2005
- ----------------------------------------
Peter J. Johnson
Madeleine W. Ludlow Director February 11, 2005
- ----------------------------------------
Madeleine W. Ludlow
George L. Mayer Director February 11, 2005
- ----------------------------------------
George L. Mayer
Roger D. Peirce Director February 11, 2005
- ----------------------------------------
Roger D. Peirce
Jack I. Rajala Director February 11, 2005
- ----------------------------------------
Jack I. Rajala
Nick Smith Director February 11, 2005
- ----------------------------------------
Nick Smith
Bruce W. Stender Chairman and Director February 11, 2005
- ----------------------------------------
Bruce W. Stender
ALLETE 2004 Form 10-K Page 46
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of ALLETE, Inc.:
We have completed an integrated audit of ALLETE, Inc.'s 2004 consolidated
financial statements and of its internal control over financial reporting as of
December 31, 2004 and audits of its 2003 and 2002 consolidated financial
statements in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Our opinions, based on our audits, are
presented below.
Consolidated financial statements and financial statement schedule
- ------------------------------------------------------------------
In our opinion, the consolidated financial statements listed in the index
appearing under Item 15(a)(1) present fairly, in all material respects, the
financial position of ALLETE, Inc. at December 31, 2004 and 2003, and the
results of its operations and its cash flows for each of the three years in
the period ended December 31, 2004 in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion,
the financial statement schedule listed in the accompanying index under Item
15(a)(2) presents fairly, in all material respects, the information set forth
therein when read in conjunction with the related consolidated financial
statements. These financial statements and financial statement schedule are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements and financial statement schedule based on
our audits. We conducted our audits of these statements in accordance with the
standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit of financial statements 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 our opinion.
As discussed in Note 14 to the financial statements, in 2004 the Company changed
its method of accounting for investments in limited liability companies in
accordance with EITF 03-16, "Accounting for Investments in Limited Liability
Companies."
Internal control over financial reporting
- -----------------------------------------
Also, in our opinion, management's assessment, included in Management's Report
on Internal Control Over Financial Reporting appearing under Item 9A, that the
Company maintained effective internal control over financial reporting as of
December 31, 2004 based on criteria established in Internal Control--Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), is fairly stated, in all material respects, based on those
criteria. Furthermore, in our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31,
2004, based on criteria established in Internal Control--Integrated Framework
issued by the COSO. The Company's management is responsible for maintaining
effective internal control over financial reporting and for its assessment of
the effectiveness of internal control over financial reporting. Our
responsibility is to express opinions on management's assessment and on the
effectiveness of the Company's internal control over financial reporting based
on our audit. We conducted our audit of internal control over financial
reporting in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. An audit of internal control over financial reporting includes
obtaining an understanding of internal control over financial reporting,
evaluating management's assessment, testing and evaluating the design and
operating effectiveness of internal control, and performing such other
procedures as we consider necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (i) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (ii)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the
company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Minneapolis, Minnesota
February 7, 2005
Page 47 ALLETE 2004 Form 10-K
CONSOLIDATED FINANCIAL STATEMENTS
ALLETE CONSOLIDATED BALANCE SHEET
DECEMBER 31 2004 2003
- ----------------------------------------------------------------------------------------------------------------------
MILLIONS
ASSETS
Current Assets
Cash and Cash Equivalents $ 194.1 $ 110.2
Restricted Cash 30.3 -
Accounts Receivable (Less Allowance of $2.0 and $1.3) 86.1 63.4
Inventories 34.0 31.8
Prepayments and Other 21.6 17.9
Discontinued Operations 2.0 476.7
- ----------------------------------------------------------------------------------------------------------------------
Total Current Assets 368.1 700.0
Property, Plant and Equipment - Net 883.1 919.3
Investments 124.5 175.7
Other Assets 52.8 59.0
Discontinued Operations 2.9 1,247.3
- ----------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $1,431.4 $3,101.3
- ----------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
LIABILITIES
Current Liabilities
Accounts Payable $ 40.0 $ 38.5
Accrued Taxes 23.3 18.3
Accrued Interest 6.9 11.5
Notes Payable - 53.0
Long-Term Debt Due Within One Year 1.8 35.6
Other 24.7 28.6
Discontinued Operations 12.0 340.7
- ----------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 108.7 526.2
Long-Term Debt 390.2 514.7
Accumulated Deferred Income Taxes 143.9 150.8
Other Liabilities 158.1 154.6
Discontinued Operations - 294.8
Commitments and Contingencies
- ----------------------------------------------------------------------------------------------------------------------
Total Liabilities 800.9 1,641.1
- ----------------------------------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Common Stock Without Par Value, 43.3 Shares Authorized
29.7 and 29.1 Shares Outstanding 400.1 859.2
Unearned ESOP Shares (51.4) (45.4)
Accumulated Other Comprehensive Loss - Continuing Operations (11.4) (9.0)
Accumulated Other Comprehensive Gain - Discontinued Operations - 23.5
Retained Earnings 293.2 631.9
- ----------------------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 630.5 1,460.2
- ----------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $1,431.4 $3,101.3
- ----------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
ALLETE 2004 Form 10-K Page 48
ALLETE CONSOLIDATED STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31 2004 2003 2002
- ------------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT PER SHARE AMOUNTS
OPERATING REVENUE $751.4 $692.3 $643.0
- ------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Fuel and Purchased Power 287.9 252.5 234.8
Operating and Maintenance 285.1 263.1 250.9
Depreciation 49.7 51.2 48.9
Taxes Other than Income 28.9 29.4 30.2
- ------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 651.6 596.2 564.8
- ------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME FROM CONTINUING OPERATIONS 99.8 96.1 78.2
- ------------------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE)
Interest Expense (31.8) (50.6) (49.3)
Other (12.1) 2.5 8.1
- ------------------------------------------------------------------------------------------------------------------------
Total Other Expense (43.9) (48.1) (41.2)
- ------------------------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES 55.9 48.0 37.0
INCOME TAX EXPENSE 16.8 18.2 12.3
- ------------------------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE
CHANGE IN ACCOUNTING PRINCIPLE 39.1 29.8 24.7
INCOME FROM DISCONTINUED OPERATIONS - NET OF TAX 73.1 206.6 112.5
CHANGE IN ACCOUNTING PRINCIPLE - NET OF TAX (7.8) - -
- ------------------------------------------------------------------------------------------------------------------------
NET INCOME $104.4 $236.4 $137.2
- ------------------------------------------------------------------------------------------------------------------------
AVERAGE SHARES OF COMMON STOCK
Basic 28.3 27.6 27.0
Diluted 28.4 27.8 27.2
- ------------------------------------------------------------------------------------------------------------------------
BASIC EARNINGS (LOSS) PER SHARE OF COMMON STOCK
Continuing Operations $1.39 $1.08 $0.91
Discontinued Operations 2.58 7.48 4.16
Change in Accounting Principle (0.28) - -
- ------------------------------------------------------------------------------------------------------------------------
$3.69 $8.56 $5.07
- ------------------------------------------------------------------------------------------------------------------------
DILUTED EARNINGS (LOSS) PER SHARE OF COMMON STOCK
Continuing Operations $1.37 $1.08 $0.91
Discontinued Operations 2.57 7.44 4.13
Change in Accounting Principle (0.27) - -
- ------------------------------------------------------------------------------------------------------------------------
$3.67 $8.52 $5.04
- ------------------------------------------------------------------------------------------------------------------------
DIVIDENDS PER SHARE OF COMMON STOCK $2.8425 $3.39 $3.30
- ------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
Page 49 ALLETE 2004 Form 10-K
ALLETE CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31 2004 2003 2002
- -------------------------------------------------------------------------------------------------------------------------
MILLIONS
OPERATING ACTIVITIES
Income from Continuing Operations $ 31.3 $ 29.8 $ 24.7
Change in Accounting Principle 7.8 - -
Depreciation 49.7 51.2 48.9
Deferred Income Taxes (1.9) 10.8 9.4
Changes in Operating Assets and Liabilities
Accounts Receivable (22.7) 15.1 4.1
Trading Securities - 1.8 153.8
Inventories (2.2) 0.2 (4.3)
Prepayments and Other (3.7) (1.6) (5.1)
Accounts Payable 1.5 6.5 (1.7)
Other Current Liabilities (3.5) 4.6 (17.2)
Other Assets 6.2 (0.6) 6.0
Other Liabilities (0.2) 0.2 7.9
Net Operating Activities from Discontinued Operations 106.2 129.4 227.0
- -------------------------------------------------------------------------------------------------------------------------
Cash from Operating Activities 168.5 247.4 453.5
- -------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Proceeds from Sale of Available-For-Sale Securities 1.6 7.4 1.9
Changes to Investments 18.9 (16.6) (24.9)
Additions to Property, Plant and Equipment (63.0) (73.6) (86.6)
Other 2.3 4.3 1.9
Net Investing Activities from (for) Discontinued Operations 69.4 288.8 (137.1)
- -------------------------------------------------------------------------------------------------------------------------
Cash from (for) Investing Activities 29.2 210.3 (244.8)
- -------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Issuance of Common Stock 49.0 44.3 43.2
Issuance of Long-Term Debt 9.8 37.3 16.4
Reacquired Common Stock (5.8) - -
Changes in Notes Payable - Net (53.0) (20.8) (163.4)
Reductions of Long-Term Debt (130.1) (335.7) (8.1)
Dividends on Common Stock (79.7) (93.2) (89.2)
Redemption of Mandatorily Redeemable Preferred Securities - (75.0) -
Net Financing Activities for Discontinued Operations (18.9) (27.6) (41.5)
- -------------------------------------------------------------------------------------------------------------------------
Cash for Financing Activities (228.7) (470.7) (242.6)
- -------------------------------------------------------------------------------------------------------------------------
EFFECT OF EXCHANGE RATE CHANGES ON CASH - DISCONTINUED OPERATIONS - 39.2 2.7
- -------------------------------------------------------------------------------------------------------------------------
CHANGE IN CASH AND CASH EQUIVALENTS (31.0) 26.2 (31.2)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 226.3 200.1 231.3
- -------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 195.3 $226.3 $200.1
- -------------------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL CASH FLOW INFORMATION
Cash Paid During the Period for
Interest - Net of Capitalized $46.7 $69.2 $71.9
Income Taxes $75.7 $87.4 $49.2
- -------------------------------------------------------------------------------------------------------------------------
Included $1.2 million of cash from Discontinued Operations at December 31, 2004 ($116.1 million at December 31,
2003; $138.0 million at December 31,2002).
The accompanying notes are an integral part of these statements.
ALLETE 2004 Form 10-K Page 50
ALLETE CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
ACCUMULATED
TOTAL OTHER UNEARNED
SHAREHOLDERS' RETAINED COMPREHENSIVE ESOP COMMON
EQUITY EARNINGS INCOME (LOSS) SHARES STOCK
- ------------------------------------------------------------------------------------------------------------------------
MILLIONS
Balance at December 31, 2001 $1,143.8 $440.7 $(14.5) $(52.7) $770.3
Comprehensive Income
Net Income 137.2 137.2
Other Comprehensive Income - Net of Tax
Unrealized Gains on Securities - Net (8.1) (8.1)
Interest Rate Swap 1.3 1.3
Foreign Currency Translation Adjustments 2.6 2.6
Additional Pension Liability (3.5) (3.5)
---------
Total Comprehensive Income 129.5
Common Stock Issued - Net 44.6 44.6
Dividends Declared (89.2) (89.2)
ESOP Shares Earned 3.7 3.7
- ------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2002 1,232.4 488.7 (22.2) (49.0) 814.9
Comprehensive Income
Net Income 236.4 236.4
Other Comprehensive Income - Net of Tax
Unrealized Gains on Securities - Net 3.6 3.6
Interest Rate Swap 0.2 0.2
Foreign Currency Translation Adjustments 39.2 39.2
Additional Pension Liability (6.3) (6.3)
---------
Total Comprehensive Income 273.1
Common Stock Issued - Net 44.3 44.3
Dividends Declared (93.2) (93.2)
ESOP Shares Earned 3.6 3.6
- ------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2003 1,460.2 631.9 14.5 (45.4) 859.2
Comprehensive Income
Net Income 104.4 104.4
Other Comprehensive Income - Net of Tax
Unrealized Gains on Securities - Net 0.7 0.7
Foreign Currency Translation Adjustments (23.5) (23.5)
Additional Pension Liability (3.1) (3.1)
---------
Total Comprehensive Income 78.5
Common Stock Issued - Net 43.2 43.2
ADESA IPO 70.1 70.1
Spin-Off of ADESA (963.6) (363.4) (600.2)
Receipt of ADESA Stock by ESOP 54.3 26.5 27.8
Purchase of ALLETE Shares by ESOP (35.6) (35.6)
Dividends Declared (79.7) (79.7)
ESOP Shares Earned 3.1 3.1
- ------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2004 $ 630.5 $293.2 $(11.4) $(51.4) $400.1
- ------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
Page 51 ALLETE 2004 Form 10-K
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. BUSINESS SEGMENTS
NONREGULATED
REGULATED ENERGY REAL
FOR THE YEAR ENDED DECEMBER 31 CONSOLIDATED UTILITY OPERATIONS ESTATE OTHER
- ------------------------------------------------------------------------------------------------------------------------
MILLIONS
2004
Operating Revenue $751.4 $555.0 $106.8 $41.9 $ 47.7
Fuel and Purchased Power 287.9 246.8 41.1 - -
Other Operating Expenses 314.0 181.9 59.3 16.4 56.4
Depreciation Expense 49.7 39.5 7.2 0.1 2.9
- ------------------------------------------------------------------------------------------------------------------------
Operating Income (Loss) from Continuing
Operations 99.8 86.8 (0.8) 25.4 (11.6)
Interest Expense (31.8) (18.5) (1.5) (0.3) (11.5)
Other Income (Expense) (12.1) 0.1 0.6 - (12.8)
- ------------------------------------------------------------------------------------------------------------------------
Income (Loss) from Continuing Operations
Before Income Taxes 55.9 68.4 (1.7) 25.1 (35.9)
Income Tax Expense (Benefit) 16.8 25.6 (1.4) 10.4 (17.8)
- ------------------------------------------------------------------------------------------------------------------------
Income (Loss) from Continuing Operations 39.1 $ 42.8 $ (0.3) $14.7 $(18.1)
--------------------------------------------------------
Income from Discontinued Operations -
Net of Tax 73.1
Change in Accounting Principle - Net of Tax (7.8)
- --------------------------------------------------------
Net Income $104.4
- --------------------------------------------------------
Total Assets $1,431.4 $902.8 $161.4 $75.1 $287.2
Capital Expenditures $79.2 $41.7 $15.7 - $5.6
- ------------------------------------------------------------------------------------------------------------------------
2003
Operating Revenue $692.3 $510.0 $106.6 $42.6 $ 33.1
Fuel and Purchased Power 252.5 212.5 40.0 - -
Other Operating Expenses 292.5 176.5 53.4 18.1 44.5
Depreciation Expense 51.2 41.2 7.4 0.1 2.5
- ------------------------------------------------------------------------------------------------------------------------
Operating Income (Loss) from Continuing
Operations 96.1 79.8 5.8 24.4 (13.9)
Interest Expense (50.6) (20.4) (1.8) (0.2) (28.2)
Other Income (Expense) 2.5 2.9 1.9 - (2.3)
- ------------------------------------------------------------------------------------------------------------------------
Income (Loss) from Continuing Operations
Before Income Taxes 48.0 62.3 5.9 24.2 (44.4)
Income Tax Expense (Benefit) 18.2 24.4 2.2 10.1 (18.5)
- ------------------------------------------------------------------------------------------------------------------------
Income (Loss) from Continuing Operations 29.8 $ 37.9 $ 3.7 $14.1 $(25.9)
--------------------------------------------------------
Income from Discontinued Operations -
Net of Tax 206.6
- --------------------------------------------------------
Net Income $236.4
- --------------------------------------------------------
Total Assets $3,101.3 $917.3 $194.7 $78.6 $186.7
Capital Expenditures $136.3 $42.2 $26.5 - $4.9
- ------------------------------------------------------------------------------------------------------------------------
2002
Operating Revenue $643.0 $497.9 $84.7 $33.6 $ 26.8
Fuel and Purchased Power 234.8 206.7 28.1 - -
Other Operating Expenses 281.1 156.5 66.3 15.4 42.9
Depreciation Expense 48.9 40.5 6.2 0.1 2.1
- ------------------------------------------------------------------------------------------------------------------------
Operating Income (Loss) from Continuing
Operations 78.2 94.2 (15.9) 18.1 (18.2)
Interest Expense (49.3) (20.6) (0.3) - (28.4)
Other Income (Expense) 8.1 7.7 0.6 - (0.2)
- ------------------------------------------------------------------------------------------------------------------------
Income (Loss) from Continuing Operations
Before Income Taxes 37.0 81.3 (15.6) 18.1 (46.8)
Income Tax Expense (Benefit) 12.3 30.9 (6.9) 6.9 (18.6)
- ------------------------------------------------------------------------------------------------------------------------
Income (Loss) from Continuing Operations 24.7 $ 50.4 $(8.7) $11.2 $(28.2)
--------------------------------------------------------
Income from Discontinued Operations -
Net of Tax 112.5
- --------------------------------------------------------
Net Income $137.2
- --------------------------------------------------------
Total Assets $3,147.2 $902.8 $170.1 $84.1 $147.1
Capital Expenditures $201.2 $33.6 $42.1 - $10.9
- ------------------------------------------------------------------------------------------------------------------------
Discontinued Operations represented $4.9 million of total assets in 2004 ($1,724.0 million in 2003; $1,843.1
million in 2002) and $16.2 million of capital expenditures in 2004 ($62.7 million in 2003; $114.6 million in 2002).
ALLETE 2004 Form 10-K Page 52
NOTE 2. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES
FINANCIAL STATEMENT PREPARATION. References in this report to "we," "us" and
"our" are to ALLETE and its subsidiaries, collectively. We prepare our financial
statements in conformity with accounting principles generally accepted in the
United States of America. These principles require management to make informed
judgments, best estimates and assumptions that affect the reported amounts of
assets, liabilities, revenue and expenses. Actual results could differ from
those estimates.
PRINCIPLES OF CONSOLIDATION. Our consolidated financial statements include the
accounts of ALLETE and all of our majority-owned subsidiary companies. All
material intercompany balances and transactions have been eliminated in
consolidation. Information for prior periods has been reclassified to present
comparable information for all periods.
BUSINESS SEGMENTS. Our Regulated Utility, Nonregulated Energy Operations and
Real Estate segments were determined based on products and services provided. We
measure performance of our operations through careful budgeting and monitoring
of contributions to consolidated net income by each business segment.
Discontinued Operations includes our Automotive Services business that was spun
off in September 2004, our Water Services businesses, the majority of which were
sold in 2003, costs associated with the spin-off of ADESA incurred by ALLETE,
and our retail stores, which we exited in 2002.
REGULATED UTILITY includes retail and wholesale rate-regulated electric, water
and gas services in northeastern Minnesota and northwestern Wisconsin. Minnesota
Power, an operating division of ALLETE, and SWL&P, a wholly-owned subsidiary,
provide regulated utility electric service to 150,000 retail customers in
northeastern Minnesota and northwestern Wisconsin. Approximately 45% of
regulated utility electric revenue is from Large Power Customers (32% of
consolidated revenue). Large Power Customers consist of five taconite producers,
four paper and pulp mills, two pipeline companies and one manufacturer under
all-requirements contracts with expiration dates extending from February 2006
through April 2009. Revenue of $88.3 million (11.8% of consolidated revenue) was
received from one taconite producer in 2004 (less than 10% in 2003 and 2002).
Regulated utility rates are under the jurisdiction of various state and federal
regulatory authorities. Billings are rendered on a cycle basis. Revenue is
accrued for service provided but not billed. Regulated utility electric rates
include adjustment clauses that bill or credit customers for fuel and purchased
energy costs above or below the base levels in rate schedules and that bill
retail customers for the recovery of CIP expenditures not collected in base
rates.
Minnesota Power withdrew from Split Rock Energy, a joint venture with Great
River Energy, in 2004. Upon withdrawal, we received a $12.0 million distribution
in 2004. We accounted for our 50% ownership interest in Split Rock Energy under
the equity method of accounting. For the year ended December 31, 2004, our
pre-tax equity income from Split Rock Energy was less than $0.1 million ($2.9
million in 2003; $7.3 million in 2002). In 2004, prior to our withdrawal, we
made power purchases from Split Rock Energy of $6.2 million ($50.9 million in
2003; $34.3 million in 2002) and power sales to Split Rock Energy of $1.9
million ($19.6 million in 2003; $14.5 million in 2002).
NONREGULATED ENERGY OPERATIONS includes nonregulated generation (non-rate base
generation sold at market-based rates to the wholesale market), consisting
primarily of generation from Taconite Harbor in northern Minnesota and
generation secured through the Kendall County power purchase agreement. Subject
to certain approvals, we expect to transfer the Kendall power purchase agreement
to Constellation Energy Commodities in April 2005. (See Note 11.) Revenue for
nonregulated generation is recognized under terms of contracts and as energy is
delivered. Nonregulated Energy Operations also includes our coal mining
activities in North Dakota. BNI Coal, a wholly-owned subsidiary, mines and sells
lignite coal to two North Dakota mine-mouth generating units, one of which is
Square Butte. Square Butte supplies approximately 71% (323 MW) of its output to
Minnesota Power under a long-term contract. (See Note 11.) Coal sales are
recognized when delivered at the cost of production plus a specified profit per
ton of coal delivered.
REAL ESTATE includes our Florida real estate operations. Our real estate
operations include several wholly-owned subsidiaries and an 80% ownership in
Lehigh Acquisition Corporation, which are consolidated in ALLETE's financial
statements. All of our Florida real estate companies are principally engaged in
real estate acquisitions, development and sales. Full profit recognition is
recorded on sales upon closing, provided cash collections are at least 20% of
the contract price and the other requirements of SFAS 66, "Accounting for Sales
of Real Estate," are met. Costs of real estate sales include capitalized costs
incurred since acquisition and the allocated cost of the underlying real estate
determined at acquisition. Land held for sale is recorded at the lower of cost
or fair value determined by the evaluation of individual land parcels.
OTHER includes our telecommunications activities, investments in emerging
technologies related to the electric utility industry, earnings on cash, and
general corporate charges and interest not specifically related to any one
business segment. General corporate charges include employee salaries and
benefits, as well as legal and other outside service fees. Enventis Telecom, a
wholly-owned subsidiary, is our telecommunications business, which is an
integrated data services provider offering fiber optic-based communication and
advanced data services to businesses and communities in Minnesota and Wisconsin.
Revenue is generally recognized when equipment is delivered and when services
are completed under short-term contracts. Revenue from fiber-optic sales is
recognized under the straight-line basis for contracts over 12 months.
Other included Operation and Other Expense totaling $12.6 million in 2004 ($14.8
million in 2003; $17.0 million in 2002) for general corporate expenses such as
employee salaries and benefits, and legal and other outside contract service
fees, and Interest Expense of $11.2 million in 2004 ($28.0 million in 2003;
$28.2 million in 2002).
Page 53 ALLETE 2004 Form 10-K
PROPERTY, PLANT AND EQUIPMENT. Property, plant and equipment are recorded at
original cost and are reported on the balance sheet net of accumulated
depreciation. Expenditures for additions and significant replacements and
improvements are capitalized; maintenance and repair costs are expensed as
incurred. Expenditures for major plant overhauls are also accounted for using
this same policy. Gains or losses on nonregulated property, plant and equipment
are recognized when they are retired or otherwise disposed of. When regulated
utility property, plant and equipment are retired or otherwise disposed of, no
gain or loss is recognized. Our Regulated Utility operations capitalize an
allowance for funds used during construction, which includes both an interest
and equity component. Our other operations capitalize interest during the course
of a construction project.
LONG-LIVED ASSET IMPAIRMENTS. We annually review our assets for impairment. SFAS
144, "Accounting for the Impairment and Disposal of Long-Lived Assets," is the
basis for these analyses. Judgments and uncertainties affecting the application
of accounting for asset impairment include economic conditions affecting market
valuations, changes in our business strategy, and changes in our forecast of
future operating cash flows and earnings.
We account for our long-lived assets at depreciated historical cost. A
long-lived asset is tested for recoverability whenever events or changes in
circumstances indicate that its carrying amount may not be recoverable. We would
recognize an impairment loss only if the carrying amount of a long-lived asset
is not recoverable from its undiscounted cash flows. Management judgment is
involved in both deciding if testing for recoverability is necessary and in
estimating undiscounted cash flows. As of December 31, 2004, no write-downs were
required.
ACCOUNTS RECEIVABLE. Accounts receivable are reported on the balance sheet net
of an allowance for doubtful accounts. The allowance is based on our evaluation
of the receivable portfolio under current conditions, the size of the portfolio,
overall portfolio quality, review of specific problems and such other factors
that, in our judgment, deserve recognition in estimating losses.
ACCOUNTS RECEIVABLE
DECEMBER 31 2004 2003
- --------------------------------------------------------------------------------
MILLIONS
Trade Accounts Receivable
Billed $77.4 $54.0
Unbilled 10.2 9.7
Less: Allowance for Doubtful Accounts 2.0 1.3
- --------------------------------------------------------------------------------
85.6 62.4
Finance Receivables - Net 0.5 1.0
- --------------------------------------------------------------------------------
Total Accounts Receivable - Net $86.1 $63.4
- --------------------------------------------------------------------------------
Finance receivables consist of short-term seller financing at our real estate
operations.
INVENTORIES. Inventories are stated at the lower of cost or market. Cost is
determined by the average cost method.
INVENTORIES
DECEMBER 31 2004 2003
- --------------------------------------------------------------------------------
MILLIONS
Fuel $11.4 $12.2
Materials and Supplies 20.4 19.3
Other 2.2 0.3
- --------------------------------------------------------------------------------
$34.0 $31.8
- --------------------------------------------------------------------------------
UNAMORTIZED EXPENSE, DISCOUNT AND PREMIUM ON DEBT. Expense, discount and premium
on debt are deferred and amortized over the lives of the related issues.
CASH AND CASH EQUIVALENTS. We consider all investments purchased with maturities
of three months or less to be cash equivalents.
RESTRICTED CASH. We sponsor a leveraged ESOP as part of our Retirement Savings
and Stock Ownership Plan. The ESOP had $30.3 million in cash, which is being
used to purchase ALLETE common stock on the open market. We reflected the cash
held by the ESOP as Restricted Cash on our consolidated balance sheet. (See Note
17.)
ACCOUNTING FOR STOCK-BASED COMPENSATION. We have elected to account for
stock-based compensation under the intrinsic value method in accordance with APB
Opinion No. 25, "Accounting for Stock Issued to Employees." Accordingly, we
recognize expense for performance share awards granted and do not recognize
expense for employee stock options granted. The after-tax expense recognized for
performance share awards was approximately $1 million in 2004 ($3 million in
2003). The following table illustrates the effect on net income and earnings per
share if we had applied the fair value recognition provisions of SFAS 123,
"Accounting for Stock-Based Compensation."
ALLETE 2004 Form 10-K Page 54
EFFECT OF SFAS 123
ACCOUNTING FOR STOCK-BASED COMPENSATION
FOR THE YEAR ENDED DECEMBER 31 2004 2003 2002
- ---------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT PER SHARE AMOUNTS
Net Income
As Reported $104.4 $236.4 $137.2
Less: Employee Stock Compensation Expense
Determined Under SFAS 123 - Net of Tax (0.3) (0.5) (1.4)
- ---------------------------------------------------------------------------------------------------------------
Pro Forma $104.1 $235.9 $135.8
- ---------------------------------------------------------------------------------------------------------------
Basic Earnings Per Share
As Reported $3.69 $8.56 $5.07
Pro Forma $3.68 $8.55 $5.03
Diluted Earnings Per Share
As Reported $3.67 $8.52 $5.04
Pro Forma $3.66 $8.49 $4.99
- ---------------------------------------------------------------------------------------------------------------
In the previous table, the expense for employee stock options granted determined
under SFAS 123 was calculated using the Black-Scholes option pricing model and
the following assumptions:
2004 2003 2002
- ---------------------------------------------------------------------------------------------------------------
Risk-Free Interest Rate 3.3% 3.1% 4.4%
Expected Life - Years 5 5 5
Expected Volatility 28.1% 25.2% 24.2%
Dividend Growth Rate 2% 2% 2%
- ---------------------------------------------------------------------------------------------------------------
FOREIGN CURRENCY TRANSLATION. Results of operations for our Canadian and Mexican
automotive subsidiaries prior to the spin-off were translated into United States
dollars using the average exchange rates. Assets and liabilities were translated
into United States dollars using the exchange rate on the balance sheet date.
Resulting translation adjustments were recorded in the Accumulated Other
Comprehensive Gain - Discontinued Operations section of Shareholders' Equity on
our consolidated balance sheet.
OTHER LIABILITIES
DECEMBER 31 2004 2003
- ---------------------------------------------------------------------------------------------------------------
MILLIONS
Deferred Regulatory Credits (See Note 5) $ 35.9 $ 39.3
Deferred Compensation and Accrued Postretirement Benefits 66.3 62.2
Asset Retirement Obligations (See Note 4) 22.4 20.7
Other 33.5 32.4
- ---------------------------------------------------------------------------------------------------------------
$158.1 $154.6
- ---------------------------------------------------------------------------------------------------------------
ENVIRONMENTAL LIABILITIES. We review environmental matters on a quarterly basis.
Accruals for environmental matters are recorded when it is probable that a
liability has been incurred and the amount of the liability can be reasonably
estimated, based on current law and existing technologies. These accruals are
adjusted periodically as assessment and remediation efforts progress or as
additional technical or legal information becomes available. Accruals for
environmental liabilities are included in the balance sheet at undiscounted
amounts and exclude claims for recoveries from insurance or other third parties.
Costs related to environmental contamination treatment and cleanup are charged
to expense.
INCOME TAXES. We file a consolidated federal income tax return. Income taxes are
allocated to each subsidiary based on their taxable income. We account for
income taxes using the liability method as prescribed by SFAS 109, "Accounting
for Income Taxes." Under the liability method, deferred income tax liabilities
are established for all temporary differences in the book and tax basis of
assets and liabilities, based upon enacted tax laws and rates applicable to the
periods in which the taxes become payable. Due to the effects of regulation on
Minnesota Power, certain adjustments made to deferred income taxes are, in turn,
recorded as regulatory assets or liabilities. Investment tax credits have been
recorded as deferred credits and are being amortized to income tax expense over
the service lives of the related property.
EXCISE TAXES. We collect excise taxes from our customers levied by government
entities. These taxes are stated separately on the billing to the customer and
recorded as a liability to be remitted to the government entity. We account for
the collection and payment of these taxes on the net basis and neither the
amounts collected or paid are reflected on our consolidated statement of income.
Page 55 ALLETE 2004 Form 10-K
NEW ACCOUNTING STANDARDS. In December 2004, the FASB issued SFAS 123(R),
"Share-Based Payment," which will be effective for public entities as of the
first interim or annual reporting period that begins after June 15, 2005. SFAS
123(R) replaces SFAS 123, "Accounting for Stock-Based Compensation," and
supersedes APB Opinion No. 25, "Accounting for Stock Issued to Employees." The
new standard requires that the compensation cost relating to share-based payment
be recognized in financial statements at fair value. As such, reporting employee
stock options under the intrinsic value-based method prescribed by APB 25 will
no longer be allowed. We have historically elected to use the intrinsic value
method and have not recognized expense for employee stock options granted. We
estimate that the impact of adoption of SFAS 123(R) in 2005 will be an
additional expense of approximately $0.2 million after tax. We also have an
Employee Stock Purchase Plan that provides a discount of 5% from market price.
Current accounting rules do not require the recognition of compensation expense
for employee stock purchase plans such as ours, and SFAS 123(R) continues this
exception.
NOTE 3. DISCONTINUED OPERATIONS
AUTOMOTIVE SERVICES. On September 20, 2004, the spin-off of Automotive Services
was completed by distributing to ALLETE shareholders all of ALLETE's shares of
ADESA common stock. One share of ADESA common stock was distributed for each
outstanding share of ALLETE common stock held at the close of business on the
September 13, 2004 record date. The distribution was made from ALLETE's retained
earnings to the extent of ADESA's undistributed earnings ($363.4 million), with
the remainder made from common stock ($600.2 million).
In June 2004, ADESA issued 6.3 million shares of common stock through an IPO
priced at $24.00 per share, which netted proceeds of $136.0 million after
transaction costs, issued $125 million of senior notes and borrowed $275 million
under a new $525 million credit facility. With these funds, ADESA repaid
previously existing debt and all intercompany debt outstanding to ALLETE. The
IPO represented 6.6% of ADESA's 94.9 million shares then outstanding. As a
result of the IPO, ALLETE recorded a $70.1 million increase to Common Stock with
no gain recognized pursuant to SEC Staff Accounting Bulletin Topic 5H,
"Accounting for Sales of Stock by a Subsidiary." We accounted for the 6.6%
public ownership of ADESA as a minority interest and continued to own and
consolidate the remaining portion of ADESA until the spin-off was completed on
September 20, 2004.
In accordance with SFAS 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets," we have reported our Automotive Services business in
Discontinued Operations.
WATER SERVICES. During 2003, we sold, under condemnation or imminent threat of
condemnation, substantially all of our water assets in Florida for a total sales
price of approximately $445 million. Income from discontinued operations for
2003 included a $71.6 million after-tax gain on the sale of substantially all
our Water Services businesses. The gain was net of all selling, transaction and
employee termination benefit expenses, as well as impairment losses on certain
remaining assets.
In June 2004, we essentially concluded our strategy to exit our Water Services
businesses when we completed the sale of our North Carolina water assets and the
sale of the remaining 72 water and wastewater systems in Florida. Aqua America
purchased our North Carolina water assets for $48 million and assumed
approximately $28 million in debt, and also purchased 63 of our water and
wastewater systems in Florida for $14 million. Seminole County purchased the
remaining 9 Florida systems for a total of $4 million. The FPSC approved the
Seminole County transaction in September 2004. The transaction relating to the
sale of 63 water and wastewater systems in Florida to Aqua America remains
subject to regulatory approval by the FPSC. The approval process may result in
an adjustment to the final purchase price, based on the FPSC's determination of
plant investment for the systems. A decision is expected in late 2005. Gains in
2004 from the sale of our North Carolina assets and the remaining systems in
Florida were offset by an adjustment to gains reported in 2003, resulting in an
overall net loss of $0.5 million in 2004. The adjustment to gains reported in
2003 resulted primarily from an arbitration award in December 2004 relating to a
gain-sharing provision on a system sold in 2003; $5.1 million was recorded in
2004 ($1.2 million in 2003). We sold our wastewater assets in Georgia in
February 2005.
The net cash proceeds from the sale of all water assets in 2003 and 2004, after
transaction costs, retirement of most Florida Water debt and payment of income
taxes, were approximately $300 million. These net proceeds were used to retire
debt at ALLETE.
In accordance with SFAS 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets," we suspended depreciating our Water Services assets when
they were classified as held-for-sale in 2001. Had we not suspended
depreciation, depreciation expense at our Water Services businesses would have
been $2.6 million in 2004 ($12.9 million in 2003; $14.7 million in 2002).
ELECTRIC ODYSSEY. In 2002 we exited our retail stores.
ALLETE 2004 Form 10-K Page 56
SUMMARY OF DISCONTINUED OPERATIONS
- ----------------------------------------------------------------------------------------------------------------------------
MILLIONS
INCOME STATEMENT
FOR THE YEAR ENDED DECEMBER 31 2004 2003 2002
- ----------------------------------------------------------------------------------------------------------------------------
Operating Revenue
Automotive Services $681.7 $ 924.1 $852.2
Water Services 18.5 107.4 117.2
Electric Odyssey - - 0.4
- ----------------------------------------------------------------------------------------------------------------------------
$700.2 $1,031.5 $969.8
- ----------------------------------------------------------------------------------------------------------------------------
Pre-Tax Income (Loss) from Operations
Automotive Services $132.5 $185.4 $149.2
Water Services (1.7) 34.4 41.8
- ----------------------------------------------------------------------------------------------------------------------------
130.8 219.8 191.0
- ----------------------------------------------------------------------------------------------------------------------------
Income Tax Expense (Benefit)
Automotive Services 54.0 73.1 58.3
Water Services (0.9) 13.0 16.3
- ----------------------------------------------------------------------------------------------------------------------------
53.1 86.1 74.6
- ----------------------------------------------------------------------------------------------------------------------------
Total Net Income from Operations 77.7 133.7 116.4
- ----------------------------------------------------------------------------------------------------------------------------
Gain (Loss) on Disposal
Automotive Services (6.7) 2.0 (3.7)
Water Services 6.2 110.1 -
Electric Odyssey - - (2.1)
- ----------------------------------------------------------------------------------------------------------------------------
(0.5) 112.1 (5.8)
- ----------------------------------------------------------------------------------------------------------------------------
Income Tax Expense (Benefit)
Automotive Services (2.6) 0.7 (1.0)
Water Services 6.7 38.5 -
Electric Odyssey - - (0.9)
- ----------------------------------------------------------------------------------------------------------------------------
4.1 39.2 (1.9)
- ----------------------------------------------------------------------------------------------------------------------------
Net Gain (Loss) on Disposal (4.6) 72.9 (3.9)
- ----------------------------------------------------------------------------------------------------------------------------
Income from Discontinued Operations $ 73.1 $206.6 $112.5
- ----------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET INFORMATION
DECEMBER 31 2004 2003
- ----------------------------------------------------------------------------------------------------------------------------
Assets of Discontinued Operations
Cash and Cash Equivalents $1.2 $116.1
Other Current Assets $0.8 $360.6
Property, Plant and Equipment $2.9 $660.9
Investments - $34.5
Goodwill - $511.0
Other Intangibles - $33.3
Other Assets - $7.6
Liabilities of Discontinued Operations
Current Liabilities $12.0 $340.7
Long-Term Debt - $252.8
Other Liabilities - $42.0
Foreign Currency Translation Adjustment - $23.5
- ----------------------------------------------------------------------------------------------------------------------------
Page 57 ALLETE 2004 Form 10-K
NOTE 4. PROPERTY, PLANT AND EQUIPMENT
PROPERTY, PLANT AND EQUIPMENT
DECEMBER 31 2004 2003
- ---------------------------------------------------------------------------------------------------------
MILLIONS
Regulated Utility $1,431.9 $1,409.5
Construction Work in Progress 10.4 11.9
Accumulated Depreciation (716.4) (692.3)
- ---------------------------------------------------------------------------------------------------------
Regulated Utility Plant - Net 725.9 729.1
- ---------------------------------------------------------------------------------------------------------
Nonregulated Energy Operations 155.5 185.4
Construction Work in Progress 1.1 1.6
Accumulated Depreciation (39.6) (35.8)
- ---------------------------------------------------------------------------------------------------------
Nonregulated Energy Operations Plant - Net 117.0 151.2
- ---------------------------------------------------------------------------------------------------------
Other Plant - Net 40.2 39.0
- ---------------------------------------------------------------------------------------------------------
Property, Plant and Equipment - Net $ 883.1 $ 919.3
- ---------------------------------------------------------------------------------------------------------
Depreciation is computed using the straight-line method over the estimated
useful lives of the various classes of plant. The MPUC and the PSCW have
approved depreciation rates for our Regulated Utility plant.
ESTIMATED USEFUL LIVES OF PROPERTY, PLANT AND EQUIPMENT
- ---------------------------------------------------------
Regulated Utility - Generation 5 to 30 years
Transmission 40 to 60 years
Distribution 30 to 70 years
Nonregulated Energy Operations 5 to 35 years
Other Plant 5 to 40 years
- ---------------------------------------------------------
ASSET RETIREMENT OBLIGATIONS. Pursuant to SFAS 143, "Accounting for Asset
Retirement Obligations," we recognize, at fair value, obligations associated
with the retirement of tangible, long-lived assets that result from the
acquisition, construction or development and/or normal operation of the asset.
The associated retirement costs are capitalized as part of the related
long-lived asset and depreciated over the useful life of the asset. Asset
retirement obligations relate primarily to the decommissioning of our utility
steam generating facilities and reclamation at BNI Coal, and are included in
Other Liabilities on our consolidated balance sheet. Removal costs associated
with certain distribution and transmission assets have not been recognized as
these facilities have been determined to have indeterminate useful lives. Prior
to the adoption of SFAS 143, utility decommissioning obligations were accrued
through depreciation expense at depreciation rates approved by the MPUC. Upon
implementation of SFAS 143, we reclassified previously recorded liabilities of
$12.5 million from Accumulated Depreciation and capitalized a net asset
retirement cost of $6.7 million.
ASSET RETIREMENT OBLIGATION
- --------------------------------------------------------------------------------
MILLIONS
Obligation at December 31, 2002 -
Initial Obligation Upon Adoption of SFAS 143 $19.0
Accretion Expense 0.7
Additional Liabilities Incurred in 2003 1.0
- --------------------------------------------------------------------------------
Obligation at December 31, 2003 20.7
Accretion Expense 1.2
Additional Liabilities Incurred in 2004 0.5
- --------------------------------------------------------------------------------
Obligation at December 31, 2004 $22.4
- --------------------------------------------------------------------------------
ALLETE 2004 Form 10-K Page 58
NOTE 5. REGULATORY MATTERS
Entities within our regulated utility segment file for periodic rate revisions
with the MPUC, the FERC or the PSCW. Minnesota Power's last retail rate filing
with the MPUC was in 1994. SWL&P's current retail rates are based on a 2001 PSCW
retail rate order. During 2004, SWL&P filed an application with the PSCW to
increase retail utility rates by an average of approximately 6%. New rates, if
approved, are expected to go into effect in the first half of 2005. In 2004, 70%
of our consolidated operating revenue was under regulatory authority (69% in
2003; 73% in 2002). The MPUC had regulatory authority over approximately 56% of
our consolidated operating revenue in 2004 (54% in 2003; 58% in 2002).
ELECTRIC RATES. Federal legislation and FERC regulations have been proposed that
aim to maintain reliability, assure adequate energy supply, and address
wholesale price volatility while encouraging wholesale competition. Legislation
or regulation that initiates a process which may lead to retail customer choice
of their electric service provider currently lacks momentum in both Minnesota
and Wisconsin. Legislative and regulatory activity, as well as the actions of
competitors, affect the way Minnesota Power strategically plans for its future.
We cannot predict the timing or substance of any future legislation or
regulation.
DEFERRED REGULATORY CHARGES AND CREDITS. Our regulated utility operations are
subject to the provisions of SFAS 71, "Accounting for the Effects of Certain
Types of Regulation." We capitalize as deferred regulatory charges incurred
costs which are probable of recovery in future utility rates. Deferred
regulatory credits represent amounts expected to be credited to customers in
rates. Deferred regulatory charges and credits are included in Other Assets and
Other Liabilities on our consolidated balance sheet.
DEFERRED REGULATORY CHARGES AND CREDITS
DECEMBER 31 2004 2003
- --------------------------------------------------------------------------------
MILLIONS
Deferred Charges
Income Taxes $ 13.7 $ 14.1
Conservation Improvement Programs 0.6 1.5
Premium on Reacquired Debt 4.1 3.8
Other 0.6 0.5
- --------------------------------------------------------------------------------
19.0 19.9
Deferred Credits - Income Taxes 35.9 39.3
- --------------------------------------------------------------------------------
Net Deferred Regulatory Liabilities $(16.9) $(19.4)
- --------------------------------------------------------------------------------
NOTE 6. INVESTMENTS
At December 31, 2004, Investments included the real estate assets of ALLETE
Properties, debt and equity securities consisting primarily of securities held
for employee benefits, and our emerging technology investments.
INVESTMENTS
DECEMBER 31 2004 2003
- --------------------------------------------------------------------------------
MILLIONS
Real Estate Assets $ 75.1 $ 78.6
Debt and Equity Securities 35.8 59.6
Emerging Technology Investments (See Note 7) 13.6 37.5
- --------------------------------------------------------------------------------
$124.5 $ 175.7
- --------------------------------------------------------------------------------
REAL ESTATE. At December 31, 2004, real estate assets included land of $47.2
million ($50.7 million at December 31, 2003), long-term finance receivables of
$9.7 million ($9.6 million at December 31, 2003) and $18.2 million ($18.3
million at December 31, 2003) of other assets, which consisted primarily of a
shopping center. Finance receivables have maturities ranging up to ten years,
accrue interest at market-based rates and are net of an allowance for doubtful
accounts of $0.7 million at December 31, 2004 ($1.2 million at December 31,
2003). Minority interest associated with real estate operations was $5.6 million
at December 31, 2004 ($7.5 million at December 31, 2003).
Page 59 ALLETE 2004 Form 10-K
NOTE 7. FINANCIAL INSTRUMENTS
SECURITIES INVESTMENTS. At December 31, 2004, Investments included securities
accounted for as available-for-sale under SFAS 115, "Accounting for Certain
Investments in Debt and Equity Securities," and securities in our emerging
technology portfolio. Income and realized gains and losses from securities
investments were included in Other Income (Expense) on our consolidated income
statement.
AVAILABLE-FOR-SALE SECURITIES. At December 31, 2004, our available-for-sale
securities portfolio consisted of securities in a grantor trust established to
fund certain employee benefits. Available-for-sale securities are recorded at
fair value with unrealized gains and losses included in accumulated other
comprehensive income, net of tax. Unrealized losses that are other than
temporary are recognized in earnings. We use the specific identification method
as the basis for determining the cost of securities sold. Our policy is to
review on a quarterly basis available-for-sale securities for other than
temporary impairment by assessing such factors as the continued viability of
products offered, cash flow, share price trends and the impact of overall market
conditions. As a result of our periodic assessments, we did not record any
impairment write-down on available-for-sale securities in 2004 or 2003.
During the fourth quarter of 2004, we sold 3.3 million shares of ADESA stock
received by our ESOP plan (see Note 17) as a result of the September 2004
spin-off of ADESA. In total, the ESOP received total proceeds of $65.9 million,
resulting in a gain of $11.5 million, which we recognized during the fourth
quarter. We accounted for the ADESA stock as available-for-sale.
During the second quarter of 2003, we sold the publicly-traded investments held
in our emerging technology portfolio and recognized a $2.3 million after-tax
loss. These publicly-traded emerging technology investments were accounted for
as available-for-sale securities prior to sale.
AVAILABLE-FOR-SALE SECURITIES
- -------------------------------------------------------------------------------------------------
MILLIONS
GROSS UNREALIZED
AT DECEMBER 31 COST GAIN (LOSS) FAIR VALUE
- -------------------------------------------------------------------------------------------------
2004 $27.2 $3.1 $(0.1) $30.2
2003 $24.1 $1.4 - $25.5
2002 $25.4 $0.7 $(5.2) $20.9
- -------------------------------------------------------------------------------------------------
NET
UNREALIZED
GAIN (LOSS)
IN OTHER
YEAR ENDED SALES GROSS REALIZED COMPREHENSIVE
DECEMBER 31 PROCEEDS GAIN (LOSS) INCOME
- -------------------------------------------------------------------------------------------------
2004 $65.9 $11.5 - $1.6
2003 $6.4 $1.2 $(4.7) $2.4
2002 $12.1 $1.0 - $(11.8)
- -------------------------------------------------------------------------------------------------
EMERGING TECHNOLOGY PORTFOLIO. As part of our emerging technology portfolio, we
have several minority investments in venture capital funds and direct
investments in privately-held, start-up companies. We account for our investment
in venture capital funds under the equity method and account for our direct
investment in privately-held companies under the cost method. The total carrying
value of our emerging technology portfolio was $13.6 million at December 31,
2004, down $23.9 million from December 31, 2003. The decline was primarily due
to a change to the equity method of accounting for the venture capital funds
(see Note 14) and impairments related to investments in privately-held
companies. Our basis in cost method investments included in the emerging
technology portfolio was $4.5 million ($11.0 million in 2003). Our policy is to
review these investments quarterly for impairment by assessing such factors as
continued commercial viability of products, cash flow and earnings. Any
impairment would reduce the carrying value of the investment. In 2004, we
recorded $6.5 million ($4.1 million after tax) of impairment losses related to
direct investments in certain privately-held, start-up companies whose future
business prospects have diminished significantly. Recent developments at these
companies indicated that future commercial viability is unlikely, as is new
financing necessary to continue development. We did not record any impairment
loss on these investments in 2003 ($1.5 million pretax in 2002).
OTHER. During the second half of 2002, we substantially liquidated our trading
securities portfolio and incurred a $2.9 million after-tax loss. Prior to
liquidation, the trading securities portfolio consisted primarily of the common
stock of various publicly traded companies and was included in current assets at
fair value.
ALLETE 2004 Form 10-K Page 60
FAIR VALUE OF FINANCIAL INSTRUMENTS. With the exception of the items listed
below, the estimated fair values of all financial instruments approximate the
carrying amount. The fair values for the items below were based on quoted market
prices for the same or similar instruments.
FINANCIAL INSTRUMENTS
DECEMBER 31 CARRYING AMOUNT FAIR VALUE
- --------------------------------------------------------------------------------
MILLIONS
Long-Term Debt
2004 $392.0 $396.7
2003 $550.3 $587.4
- --------------------------------------------------------------------------------
CONCENTRATION OF CREDIT RISK. Financial instruments that subject us to
concentrations of credit risk consist primarily of accounts receivable.
Minnesota Power sells electricity to 12 Large Power Customers. Receivables from
these customers totaled approximately $9 million at December 31, 2004 ($9
million at December 31, 2003). Minnesota Power does not obtain collateral to
support utility receivables, but monitors the credit standing of major
customers. In addition, our taconite-producing Large Power Customers are on a
weekly billing cycle.
NOTE 8. SHORT-TERM AND LONG-TERM DEBT
SHORT-TERM DEBT. Total short-term debt outstanding at December 31, 2004 was $1.8
million ($88.6 million at December 31, 2003.) This consisted of $0 in Notes
Payable ($53 million at December 31, 2003) and $1.8 million of Long-Term Debt
Due Within One Year ($35.6 million at December 31, 2003).
In July 2003, ALLETE entered into a one-year credit agreement for $250 million.
The proceeds were used to redeem $250 million of the Company's Floating Rate
First Mortgage Bonds due October 20, 2003. In April 2004, ALLETE used internally
generated funds and proceeds from the sale of water assets to repay $53.0
million outstanding under this credit agreement. The credit agreement contained
certain mandatory prepayment provisions, including a requirement to repay an
amount equal to 75% of the net proceeds from the sale of water assets. In
accordance with these provisions, $197.0 million was repaid in 2003.
We have bank lines of credit aggregating $111.5 million ($176.5 million at
December 31, 2003), the majority of which will expire in December 2007. These
bank lines of credit make financing available through short-term bank loans and
provide credit support for commercial paper. At December 31, 2004, $111.5
million was available for use ($176.5 million at December 31, 2003). Certain
lines of credit require a commitment fee of 0.15%. There was no commercial paper
issued as of December 31, 2004 or December 31, 2003.
Our lines of credit contain financial covenants. The most restrictive covenants
require ALLETE (1) to not exceed a maximum ratio of funded debt to total capital
of .60 to 1.0 and (2) to maintain an interest coverage ratio of not less than
3.00 to 1.00. Failure to meet these covenants could give rise to an event of
default, if not corrected after notice from the lender, in which event ALLETE
may need to pursue alternative sources of funding. Certain of ALLETE's lines of
credit contain cross-default provisions under which an event of default would
arise if other ALLETE obligations in excess of $5.0 million were in default. As
of December 31, 2004, ALLETE was in compliance with these financial covenants.
Page 61 ALLETE 2004 Form 10-K
LONG-TERM DEBT. The aggregate amount of long-term debt maturing during 2005 is
$1.8 million ($2.4 million in 2006; $119.2 million in 2007; $57.5 million in
2008; $10.3 million in 2009; and $200.8 million thereafter). Substantially all
of our electric plant is subject to the lien of the mortgages securing various
first mortgage bonds.
At December 31, 2003, BNI Coal had a $28.8 million long-term bank line of credit
outstanding. The amount was repaid in 2004 when BNI Coal entered into a new
operating lease agreement. (See Note 11.)
In January 2004, we used internally-generated funds to retire approximately $3.5
million in principal amount of Industrial Development Revenue Bonds Series
1994-A, due January 1, 2004.
In July 2004, we repaid $125 million in principal amount of 7.80% Senior Notes
due 2008. Proceeds from the sale of our water assets and proceeds received from
ADESA were used to repay this debt. As a result of the redemption, we recognized
an expense of $18.5 million in the third quarter of 2004 comprised of an early
redemption premium and the write-off of unamortized debt issuance costs.
In August 2004, we issued $111 million in principal amount of 4.95%
Collateralized Pollution Control Refunding Revenue Bonds Series 2004 due 2022.
Proceeds were used to redeem $111 million in principal amount of 6%
Collateralized Pollution Control Refunding Revenue Bonds Series E due 2022.
ALLETE's letters of credit supporting certain long-term debt arrangements
contain financial covenants. The most restrictive covenant requires ALLETE not
to exceed a maximum ratio of funded debt to total capital of .65 to 1.0. Failure
to meet these covenants may give rise to an event of default, if not corrected
after notice from the trustee or security holder. Some of ALLETE's long-term
debt arrangements contain "cross-default" provisions that would result in an
event of default if there is a failure under other financing arrangements to
meet payment terms or to observe other covenants that would result in an
acceleration of payments due. As of December 31, 2004, ALLETE was in compliance
with these financial covenants.
DECEMBER 31 2004 2003
- ---------------------------------------------------------------------------------------------------
MILLIONS
First Mortgage Bonds
6.68% Series Due 2007 $ 20.0 $20.0
7% Series Due 2007 60.0 60.0
7 1/2% Series Due 2007 35.0 35.0
7% Series Due 2008 50.0 50.0
6% Pollution Control Series E Due 2022 - 111.0
4.95% Pollution Control Series F Due 2022 111.0 -
Senior Notes, 7.80% - 125.0
Variable Demand Revenue Refunding Bonds
Series 1997 A, B, C and D Due 2007 - 2020 39.0 39.0
Industrial Development Revenue Bonds 6.5% Due 2025 35.1 35.1
Other Long-Term Debt, 2.0% - 8.5% Due 2005 - 2025 41.9 75.2
- ---------------------------------------------------------------------------------------------------
Total Long-Term Debt 392.0 550.3
Less Due Within One Year 1.8 35.6
- ---------------------------------------------------------------------------------------------------
Net Long-Term Debt $390.2 $514.7
- ---------------------------------------------------------------------------------------------------
The 6.68% Series Due 2007 and the 7% Series Due 2007 cannot be redeemed prior to
maturity. The 7 1/2% Series Due 2007 are redeemable after August 1, 2005, and
the 7% Series Due 2008 are redeemable after March 1, 2006. The remaining debt
may be redeemed in whole or in part at our option, according to the terms of the
obligations.
ALLETE 2004 Form 10-K Page 62
NOTE 9. COMMON STOCK AND EARNINGS PER SHARE
Our Articles of Incorporation and mortgages contain provisions that, under
certain circumstances, would restrict the payment of common stock dividends. As
of December 31, 2004, no retained earnings were restricted as a result of these
provisions.
REVERSE COMMON STOCK SPLIT. On September 20, 2004, our one-for-three reverse
common stock split became effective. All common share and per share amounts have
been adjusted for all periods to reflect the one-for-three reverse stock split.
SUMMARY OF COMMON STOCK SHARES EQUITY
- --------------------------------------------------------------------------------
MILLIONS
Balance at December 31, 2001 28.0 $ 770.3
2002 Employee Stock Purchase Plan 0.0 1.4
Invest Direct 0.3 19.6
Other 0.2 23.6
- --------------------------------------------------------------------------------
Balance at December 31, 2002 28.5 814.9
2003 Employee Stock Purchase Plan 0.0 1.4
Invest Direct 0.3 19.9
Other 0.3 23.0
- --------------------------------------------------------------------------------
Balance at December 31, 2003 29.1 859.2
2004 Employee Stock Purchase Plan 0.0 1.0
Invest Direct 0.3 18.1
ADESA IPO (See Note 3) - 70.1
Spin-off of ADESA (See Note 3) - (600.2)
Receipt of ADESA Stock by ESOP - 27.8
Reacquired (0.1) (5.8)
Other 0.4 29.9
- --------------------------------------------------------------------------------
Balance at December 31, 2004 29.7 $ 400.1
- --------------------------------------------------------------------------------
Invest Direct is ALLETE's direct stock purchase and dividend reinvestment
plan.
SHAREHOLDER RIGHTS PLAN. In 1996, we adopted a rights plan that provides for a
dividend distribution of one preferred share purchase right (Right) to be
attached to each share of common stock.
The Rights, which are currently not exercisable or transferable apart from our
common stock, entitle the holder to purchase one-and-a-half of one-hundredth
(three two-hundredths) of a share of ALLETE's Junior Serial Preferred Stock A,
without par value. The purchase price as defined in the Rights Plan, remains at
$90. These Rights would become exercisable if a person or group acquires
beneficial ownership of 15% or more of our common stock or announces a tender
offer which would increase the person's or group's beneficial ownership interest
to 15% or more of our common stock, subject to certain exceptions. If the 15%
threshold is met, each Right entitles the holder (other than the acquiring
person or group) to purchase common stock (or, in certain circumstances, cash,
property or other securities of ours) having a market price equal to twice the
exercise price of the Right. If we are acquired in a merger or business
combination, or 50% or more of our assets or earning power are sold, each
exercisable Right entitles the holder to purchase common stock of the acquiring
or surviving company having a value equal to twice the exercise price of the
Right. Certain stock acquisitions will also trigger a provision permitting the
Board of Directors to exchange each Right for one share of our common stock.
The Rights, which expire on July 23, 2006, are nonvoting and may be redeemed by
us at a price of $0.005 per Right at any time they are not exercisable. One
million shares of Junior Serial Preferred Stock A have been authorized and are
reserved for issuance under the plan.
Page 63 ALLETE 2004 Form 10-K
EARNINGS PER SHARE. The difference between basic and diluted earnings per share
arises from outstanding stock options and performance share awards granted under
our Executive and Director Long-Term Incentive Compensation Plans.
RECONCILIATION OF BASIC AND DILUTED
EARNINGS PER SHARE DILUTIVE
FOR THE YEAR ENDED DECEMBER 31 BASIC SECURITIES DILUTED
- --------------------------------------------------------------------------------
MILLIONS EXCEPT PER SHARE AMOUNTS
2004
Net Income from Continuing Operations
Before Change in Accounting Principle $39.1 - $39.1
Common Shares 28.3 0.1 28.4
Per Share from Continuing Operations $1.39 - $1.37
2003
Net Income from Continuing Operations $29.8 - $29.8
Common Shares 27.6 0.2 27.8
Per Share from Continuing Operations $1.08 - $1.08
2002
Net Income from Continuing Operations $24.7 - $24.7
Common Shares 27.0 0.2 27.2
Per Share from Continuing Operations $0.91 - $0.91
- --------------------------------------------------------------------------------
NOTE 10. JOINTLY-OWNED ELECTRIC FACILITY
We own 80% of the 537-MW Boswell Energy Center Unit 4 (Boswell Unit 4). While we
operate the plant, certain decisions about the operations of Boswell Unit 4 are
subject to the oversight of a committee on which we and Wisconsin Public Power,
Inc. (WPPI), the owner of the other 20% of Boswell Unit 4, have equal
representation and voting rights. Each of us must provide our own financing and
is obligated to pay our ownership share of operating costs. Our share of direct
operating expenses of Boswell Unit 4 is included in operating expense on our
consolidated statement of income. Our 80% share of the original cost included in
property, plant and equipment at December 31, 2004 was $309 million ($308
million at December 31, 2003). The corresponding accumulated depreciation
balance was $157 million at December 31, 2004 ($154 million at December 31,
2003).
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES
SQUARE BUTTE POWER PURCHASE AGREEMENT. Minnesota Power has a power purchase
agreement with Square Butte that extends through 2026 (Agreement). It provides a
long-term supply of low-cost energy to customers in our electric service
territory and enables Minnesota Power to meet power pool reserve requirements.
Square Butte, a North Dakota cooperative corporation, owns a 455-MW coal-fired
generating unit (Unit) near Center, North Dakota. The Unit is adjacent to a
generating unit owned by Minnkota Power, a North Dakota cooperative corporation
whose Class A members are also members of Square Butte. Minnkota Power serves as
the operator of the Unit and also purchases power from Square Butte.
Minnesota Power is entitled to approximately 71% of the Unit's output under the
Agreement. After 2005, and upon compliance with a two-year advance notice
requirement, Minnkota Power has the option to reduce Minnesota Power's
entitlement by approximately 5% annually, to a minimum of 50%. In December 2004
and 2003, we received notices from Minnkota Power that they will reduce our
output entitlement by approximately 5% in 2006 and 2007, to 66% and 60%,
respectively.
Minnesota Power is obligated to pay its pro rata share of Square Butte's costs
based on Minnesota Power's entitlement to Unit output. Minnesota Power's payment
obligation will be suspended if Square Butte fails to deliver any power, whether
produced or purchased, for a period of one year. Square Butte's fixed costs
consist primarily of debt service. At December 31, 2004, Square Butte had total
debt outstanding of $314.9 million. Total annual debt service for Square Butte
is expected to be approximately $25 million in each of the years 2005 through
2009. Variable operating costs include the price of coal purchased from BNI
Coal, our subsidiary, under a long-term contract.
Minnesota Power's cost of power purchased from Square Butte during 2004 was
$56.1 million ($52.3 million in 2003 and $60.9 million in 2002). This reflects
Minnesota Power's pro rata share of total Square Butte costs, based on the 71%
output entitlement in 2004, 2003 and 2002. Included in this amount was Minnesota
Power's pro rata share of interest expense of $12.6 million in 2004 ($12.8
million in 2003; $13.7 million in 2002). Minnesota Power's payments to Square
Butte are approved as a purchased power expense for ratemaking purposes by both
the MPUC and the FERC.
ALLETE 2004 Form 10-K Page 64
LEASING AGREEMENTS. In September 2004, BNI Coal entered into an operating lease
agreement for a new dragline that was placed in service at BNI Coal's mine on
September 30, 2004. BNI Coal is obligated to make lease payments totaling $2.8
million annually for the lease term which expires in 2027. BNI Coal has the
option at the end of the lease term to renew the lease at a fair market rental,
to purchase the dragline at fair market value, or to surrender the dragline and
pay a $3.0 million termination fee.
We lease other properties and equipment under operating lease agreements with
terms expiring through 2013. The aggregate amount of minimum lease payments for
all of these other operating leases is $6.3 million in 2005, $6.0 million in
2006, $5.6 million in 2007, $4.9 million in 2008 and $53.4 million thereafter.
Total rent expense was $2.8 million in 2004 ($3.8 million in 2003; $3.2 million
in 2002).
KENDALL COUNTY POWER PURCHASE AGREEMENT. We have 275 MW of nonregulated
generation (non rate-base generation sold at market-based rates to the wholesale
market) through an agreement with LSP-Kendall Energy that extends through
mid-September 2017. Under the agreement, we pay a fixed capacity charge for the
right, but not the obligation, to capacity and energy from a 275-MW generating
unit at a facility in Kendall County near Chicago, Illinois. We currently have
130 MW of long-term capacity sales contracts for the Kendall County generation,
with 50 MW expiring in April 2012 and 80 MW expiring in September 2017. To date,
this power purchase agreement has resulted in losses to us due to negative spark
spreads (the differential between electric and natural gas prices) in the
wholesale power market and our resulting inability to cover the fixed capacity
charge on unsold capacity (currently 145 MW). An after-tax loss of approximately
$8 million was recognized in 2004.
In December 2004, we entered into an agreement to assign this power purchase
agreement to Constellation Energy Commodities. Under the terms of the agreement,
we will pay Constellation Energy Commodities $73 million in cash to assume the
power purchase agreement. The proposed transaction is subject to the approvals
of LSP-Kendall Energy, as well as of its project lenders and the FERC. Pending
these approvals, the transaction is scheduled to close in April 2005. The 130 MW
of long-term capacity sales contracts will also be transferred to Constellation
Energy Commodities at closing. We will recognize an after-tax loss of
approximately $47 million upon the closing of this transaction.
COAL AND SHIPPING CONTRACTS. We have three coal supply agreements with various
expiration dates ranging from December 2006 to December 2009. We also have rail
and shipping agreements for transportation of all of our coal, with various
expiration dates ranging from December 2005 to December 2011. Our minimum annual
obligation under these coal and shipping agreements ranges from approximately
$32 million in 2005 to $6 million in 2009.
EMERGING TECHNOLOGY PORTFOLIO. We have investments in emerging technologies
through minority investments in venture capital funds structured as limited
liability companies, and direct investments in privately-held, start-up
companies. We have committed to make additional investments in certain emerging
technology holdings. The total future commitment was $4.5 million at December
31, 2004 ($4.8 million at December 31, 2003) and is expected to be invested at
various times through 2007. We do not have plans to make any additional
investments beyond this commitment.
ENVIRONMENTAL MATTERS. Our businesses are subject to regulation by various
federal, state and local authorities concerning environmental matters. We
anticipate that potential expenditures for environmental matters will be
material in the future, due to stricter environmental requirements through
legislation and/or rulemakings that are expected to require significant capital
investments. We are unable to predict if and when any such stricter
environmental requirements will be imposed and the impact they will have on the
Company. We review environmental matters on a quarterly basis. Accruals for
environmental matters are recorded when it is probable that a liability has been
incurred and the amount of the liability can be reasonably estimated, based on
current law and existing technologies. These accruals are adjusted periodically
as assessment and remediation efforts progress or as additional technical or
legal information becomes available. Accruals for environmental liabilities are
included in the balance sheet at undiscounted amounts and exclude claims for
recoveries from insurance or other third parties. Costs related to environmental
contamination treatment and cleanup are charged to expense unless recoverable in
rates from customers.
SWL&P MANUFACTURED GAS PLANT. In May 2001, SWL&P received notice from the WDNR
that the City of Superior had found soil contamination on property adjoining a
former Manufactured Gas Plant (MGP) site owned and operated by SWL&P's
predecessors from 1889 to 1904. The WDNR requested SWL&P to initiate an
environmental investigation. The WDNR also issued SWL&P a Responsible Party
letter in February 2002. The environmental investigation is under way. In
February 2003, SWL&P submitted a Phase II environmental site investigation
report to the WDNR. This report identified some MGP-like chemicals that were
found in the soil near the former plant site. During March and April 2003,
sediment samples were taken from nearby Superior Bay. The report on the results
of this sampling was completed and sent to the WDNR during the first quarter of
2004. The next phase of the investigation is to determine any impact to soil or
ground water between the former MGP site and Superior Bay. The site work for
this phase of the investigation was performed during October 2004, and the final
report is expected to be sent to the WDNR during the first quarter of 2005. It
is anticipated that additional site investigation will be needed during 2005.
Although it is not possible to quantify the potential clean-up cost until the
investigation is completed, a $0.5 million liability was recorded in December
2003 to address the known areas of contamination. We have recorded a
corresponding dollar amount as a regulatory asset to offset this liability. The
PSCW has approved SWL&P's deferral of these MGP environmental investigation and
potential clean-up costs for future recovery in rates, subject to a regulatory
prudency review. ALLETE maintains pollution liability insurance coverage that
includes coverage for SWL&P. A claim has been filed with respect to this matter.
The insurance carrier has issued a reservation of rights letter and we continue
to work with the insurer to determine the availability of insurance coverage.
Page 65 ALLETE 2004 Form 10-K
SQUARE BUTTE GENERATING FACILITY. In June 2002, Minnkota Power, the operator of
Square Butte, received a Notice of Violation from the EPA regarding alleged New
Source Review violations at the M.R. Young Station, which includes the Square
Butte generating unit. The EPA claims certain capital projects completed by
Minnkota Power should have been reviewed pursuant to the New Source Review
regulations, potentially resulting in new air permit operating conditions.
Minnkota Power has held several meetings with the EPA to discuss the alleged
violations. Discussions with the EPA are ongoing and we are unable to predict
the outcome or cost impacts. If Square Butte is required to make significant
capital expenditures to comply with EPA requirements, we expect such capital
expenditures to be debt financed. Our future cost of purchased power would
include our pro rata share of this additional debt service.
OTHER. We are involved in litigation arising in the normal course of business.
Also in the normal course of business, we are involved in tax, regulatory and
other governmental audits, inspections, investigations and other proceedings
that involve state and federal taxes, safety, compliance with regulations, rate
base and cost of service issues, among other things. While the resolution of
such matters could have a material effect on earnings and cash flows in the year
of resolution, none of these matters are expected to change materially our
present liquidity position, nor have a material adverse effect on our financial
condition.
NOTE 12. OTHER INCOME (EXPENSE)
FOR THE YEAR ENDED DECEMBER 31 2004 2003 2002
- ----------------------------------------------------------------------------------------------------------
MILLIONS
Debt Prepayment Premium and Unamortized Debt
Issuance Costs (See Note 8) $(18.5) - -
Gain on ESOP's Sale of ADESA Stock (See Note 17) 11.5 - -
Income (Loss) on Emerging Technology Investments (8.6) $(3.4) $1.9
Split Rock Energy Equity Income (See Note 2) - 2.9 7.3
Investments and Other Income (Loss) 3.5 3.0 (1.1)
- ----------------------------------------------------------------------------------------------------------
$(12.1) $ 2.5 $8.1
- ----------------------------------------------------------------------------------------------------------
NOTE 13. INCOME TAX EXPENSE
INCOME TAX EXPENSE
YEAR ENDED DECEMBER 31 2004 2003 2002
- ----------------------------------------------------------------------------------------------------------
MILLIONS
Current Tax Expense
Federal $11.4 $ 4.2 $ 0.6
State 6.4 3.1 2.2
- ----------------------------------------------------------------------------------------------------------
17.8 7.3 2.8
- ----------------------------------------------------------------------------------------------------------
Deferred Tax Expense (Benefit)
Federal 1.7 10.2 9.5
State (2.3) 2.0 1.3
- ----------------------------------------------------------------------------------------------------------
(0.6) 12.2 10.8
- ----------------------------------------------------------------------------------------------------------
Change in Valuation Allowance 0.9 0.1 0.1
Deferred Tax Credits (1.3) (1.4) (1.4)
- ----------------------------------------------------------------------------------------------------------
Income Tax from Continuing Operations 16.8 18.2 12.3
Income Tax from Discontinued Operations 57.2 125.3 72.7
Change in Accounting Principle (5.5) - -
- ----------------------------------------------------------------------------------------------------------
Total Income Tax Expense $68.5 $143.5 $85.0
- ----------------------------------------------------------------------------------------------------------
ALLETE 2004 Form 10-K Page 66
RECONCILIATION OF TAXES FROM FEDERAL STATUTORY
RATE TO TOTAL INCOME TAX EXPENSE FOR CONTINUING OPERATIONS
YEAR ENDED DECEMBER 31 2004 2003 2002
- --------------------------------------------------------------------------------------------------------------------------
MILLIONS
Income from Continuing Operations Before Income Taxes $55.9 $48.0 $37.0
Statutory Federal Income Tax Rate 35% 35% 35%
- --------------------------------------------------------------------------------------------------------------------------
Income Taxes Computed at 35% Statutory Federal Rate 19.6 16.8 13.0
Increase (Decrease) in Tax Due to:
Sale of ADESA Stock by ESOP (4.1) - -
Amortization of Deferred Investment Tax Credits (1.3) (1.4) (1.4)
State Income Taxes - Net of Federal Income Tax Benefit 3.6 2.9 3.0
Depletion (0.6) (0.7) (0.7)
Other (0.4) 0.6 (1.6)
- --------------------------------------------------------------------------------------------------------------------------
Total Income Tax Expense for Continuing Operations $16.8 $18.2 $12.3
- --------------------------------------------------------------------------------------------------------------------------
DEFERRED TAX ASSETS AND LIABILITIES
DECEMBER 31 2004 2003
- --------------------------------------------------------------------------------------------------------------------------
MILLIONS
Deferred Tax Assets
Employee Benefits and Compensation $ 47.5 $ 44.2
Property Related 29.5 29.4
Investment Tax Credits 13.8 14.8
Unrealized Loss Booked Through Equity 8.2 6.4
Excess of Tax Value Over Book Value 4.9 0.3
Other 10.6 13.5
- --------------------------------------------------------------------------------------------------------------------------
Gross Deferred Tax Assets 114.5 108.6
Deferred Tax Asset Valuation Allowance (1.1) (0.2)
- --------------------------------------------------------------------------------------------------------------------------
Total Deferred Tax Assets 113.4 108.4
- --------------------------------------------------------------------------------------------------------------------------
Deferred Tax Liabilities
Property Related 216.3 213.4
Investment Tax Credits 19.7 21.0
Employee Benefits and Compensation 14.6 15.1
Other 6.7 9.7
- --------------------------------------------------------------------------------------------------------------------------
Total Deferred Tax Liabilities 257.3 259.2
- --------------------------------------------------------------------------------------------------------------------------
Accumulated Deferred Income Taxes $143.9 $150.8
- --------------------------------------------------------------------------------------------------------------------------
Included impairments related to the emerging technology portfolio.
Page 67 ALLETE 2004 Form 10-K
NOTE 14. CHANGE IN ACCOUNTING PRINCIPLE
In the third quarter of 2004, we adopted EITF 03-16, "Accounting for Investments
in Limited Liability Companies," which requires the use of the equity method of
accounting for investments in all limited liability companies, including
investments we have in venture capital funds within our emerging technology
portfolio. EITF 03-16 was issued in the second quarter of 2004. We had
previously accounted for these investments under the cost method of accounting.
EITF 03-16 is effective for reporting periods beginning after June 15, 2004.
Pursuant to EITF 03-16, the effect of adoption is reported as the cumulative
effect of a change in accounting principle. The cumulative effect of this change
on prior years was a loss of $13.3 million ($7.8 million after-tax), which was
recorded as a change in accounting principle and reflected in income for the
year ended December 31, 2004. During 2004, $1.6 million of current losses under
the equity method were recognized.
PRO FORMA AMOUNTS ASSUMING THE EQUITY METHOD
WAS APPLIED RETROACTIVELY
FOR THE YEAR ENDED DECEMBER 31 2003 2002
- --------------------------------------------------------------------------------
MILLIONS EXCEPT PER SHARE AMOUNTS
Net Income
As Reported $236.4 $137.2
Pro Forma Adjustment (2.3) (1.9)
- --------------------------------------------------------------------------------
Pro Forma $234.1 $135.3
- --------------------------------------------------------------------------------
Basic Earnings Per Share
As Reported $8.56 $5.07
Pro Forma Adjustment (0.08) (0.07)
- --------------------------------------------------------------------------------
Pro Forma $8.48 $5.00
- --------------------------------------------------------------------------------
Diluted Earnings Per Share
As Reported $8.52 $5.04
Pro Forma Adjustment (0.08) (0.07)
- --------------------------------------------------------------------------------
Pro Forma $8.44 $4.97
- --------------------------------------------------------------------------------
ALLETE 2004 Form 10-K Page 68
NOTE 15. OTHER COMPREHENSIVE INCOME (LOSS)
OTHER COMPREHENSIVE INCOME PRE-TAX TAX EXPENSE NET-OF-TAX
YEAR ENDED DECEMBER 31 AMOUNT (BENEFIT) AMOUNT
- ------------------------------------------------------------------------------------------------------------------------
MILLIONS
2004
Unrealized Gain (Loss) on Securities
Gain During the Year $ 13.1 $ 0.9 $ 12.2
Less: Gain Included in Net Income 11.5 - 11.5
- ------------------------------------------------------------------------------------------------------------------------
Net Unrealized Gain on Securities 1.6 0.9 0.7
Foreign Currency Translation Adjustments (23.5) - (23.5)
Additional Pension Liability (5.7) (2.6) (3.1)
- ------------------------------------------------------------------------------------------------------------------------
Other Comprehensive Loss $(27.6) $(1.7) $(25.9)
- ------------------------------------------------------------------------------------------------------------------------
2003
Unrealized Gain (Loss) on Securities
Gain During the Year $ 2.4 $ 1.0 $ 1.4
Add: Loss Included in Net Income 3.5 1.3 2.2
- ------------------------------------------------------------------------------------------------------------------------
Net Unrealized Gain on Securities 5.9 2.3 3.6
Interest Rate Swap 0.2 - 0.2
Foreign Currency Translation Adjustments 39.2 - 39.2
Additional Pension Liability (10.8) (4.5) (6.3)
- ------------------------------------------------------------------------------------------------------------------------
Other Comprehensive Income $ 34.5 $(2.2) $36.7
- ------------------------------------------------------------------------------------------------------------------------
2002
Unrealized Gain (Loss) on Securities
Loss During the Year $(11.8) $(4.3) $(7.5)
Less: Gain Included in Net Income 1.0 0.4 0.6
- ------------------------------------------------------------------------------------------------------------------------
Net Unrealized Loss on Securities (12.8) (4.7) (8.1)
Interest Rate Swap 2.3 1.0 1.3
Foreign Currency Transaction Adjustment 2.6 - 2.6
Additional Pension Liability (6.0) (2.5) (3.5)
- ------------------------------------------------------------------------------------------------------------------------
Other Comprehensive Loss $(13.9) $(6.2) $(7.7)
- ------------------------------------------------------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
DECEMBER 31 2004 2003
- -------------------------------------------------------------------------------------------------------------------
MILLIONS
Unrealized Gain on Securities $ 1.5 $ 0.8
Additional Pension Liability (12.9) (9.8)
Foreign Currency Translation Adjustment - Discontinued Operations - 23.5
- -------------------------------------------------------------------------------------------------------------------
$(11.4) $ 14.5
- -------------------------------------------------------------------------------------------------------------------
Page 69 ALLETE 2004 Form 10-K
NOTE 16. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
We have noncontributory defined benefit pension plans covering eligible
employees. The plans provide defined benefits based on years of service and
final average pay. We also have defined contribution pension plans covering
substantially all employees; employer contributions are made through our
employee stock ownership plan (see Note 17), except for BNI Coal, which made
cash contributions of $0.6 million in 2004 ($0.6 million in 2003).
We have postretirement health care and life insurance plans covering eligible
employees. The postretirement health plans are contributory with participant
contributions adjusted annually. Postretirement health and life benefits are
funded through a combination of Voluntary Employee Benefit Association trusts
(VEBAs), established under section 501(c)(9) of the Internal Revenue Code, and
an irrevocable grantor trust. Contributions deductible for income tax purposes
are made directly to the VEBAs; nondeductible contributions are made to the
irrevocable grantor trust. Amounts are transferred from the irrevocable grantor
trust to the VEBAs when they become deductible for income tax purposes.
We use a September 30 measurement date for the pension and postretirement health
and life plans.
PENSION OBLIGATION AND FUNDED STATUS
AT SEPTEMBER 30 2004 2003
- ------------------------------------------------------------------------------------------------------------
MILLIONS
Change in Benefit Obligation
Obligation, Beginning of Year $353.4 $297.9
Service Cost 8.4 6.7
Interest Cost 20.7 19.5
Actuarial Loss 10.0 43.7
Benefits Paid (17.3) (16.4)
Other 4.8 2.0
- ------------------------------------------------------------------------------------------------------------
Obligation, End of Year 380.0 353.4
- ------------------------------------------------------------------------------------------------------------
Change in Plan Assets
Fair Value, Beginning of Year 285.3 265.7
Actual Return on Assets 28.9 33.5
Employer Contribution 8.4 0.5
Benefits Paid (17.3) (16.4)
Other 4.8 2.0
- ------------------------------------------------------------------------------------------------------------
Fair Value, End of Year 310.1 285.3
- ------------------------------------------------------------------------------------------------------------
Funded Status (69.9) (68.1)
Unrecognized Amounts
Net Loss 89.3 82.3
Prior Service Cost 5.2 6.0
Transition Obligation - 0.3
- ------------------------------------------------------------------------------------------------------------
Net Asset Recognized $ 24.6 $ 20.5
- ------------------------------------------------------------------------------------------------------------
Amounts Recognized in Consolidated Balance Sheet Consist of:
Prepaid Pension Cost $33.3 $31.9
Accrued Benefit Liability (33.8) (31.2)
Intangible Asset 2.6 3.0
Accumulated Other Comprehensive Income 22.5 16.8
- ------------------------------------------------------------------------------------------------------------
Net Asset Recognized $24.6 $20.5
- ------------------------------------------------------------------------------------------------------------
COMPONENTS OF NET PERIODIC PENSION EXPENSE (INCOME)
YEAR ENDED DECEMBER 31 2004 2003 2002
- ------------------------------------------------------------------------------------------------------------
MILLIONS
Service Cost $ 8.4 $ 6.7 $ 5.6
Interest Cost 20.7 19.5 19.5
Expected Return on Assets (27.4) (28.8) (30.4)
Amortized Amounts
Unrecognized Loss (Gain) 1.4 - (1.4)
Prior Service Cost 0.8 0.9 0.8
Transition Obligation 0.3 0.2 0.2
- ------------------------------------------------------------------------------------------------------------
Net Pension Expense (Income) $ 4.2 $ (1.5) $ (5.7)
- ------------------------------------------------------------------------------------------------------------
ALLETE 2004 Form 10-K Page 70
INFORMATION FOR PENSION PLANS WITH AN
ACCUMULATED BENEFIT OBLIGATION IN EXCESS OF PLAN ASSETS
AT SEPTEMBER 30 2004 2003
- -------------------------------------------------------------------------------------------------------------------------
MILLIONS
Projected Benefit Obligation $163.1 $147.9
Accumulated Benefit Obligation $140.6 $124.6
Fair Value of Plan Assets $108.8 $95.1
- -------------------------------------------------------------------------------------------------------------------------
ADDITIONAL PENSION INFORMATION
YEAR ENDED DECEMBER 31 2004 2003 2002
- -------------------------------------------------------------------------------------------------------------------------
MILLIONS
Increase in Minimum Liability Included in Other Comprehensive Income $5.7 $10.8 $6.0
- -------------------------------------------------------------------------------------------------------------------------
The accumulated benefit obligation for all defined benefit pension plans was
$332.9 million and $303.5 million at September 30, 2004 and 2003, respectively.
POSTRETIREMENT HEALTH AND LIFE OBLIGATION AND FUNDED STATUS
AT SEPTEMBER 30 2004 2003
- -----------------------------------------------------------------------------------------
MILLIONS
Change in Benefit Obligation
Obligation, Beginning of Year $117.2 $ 99.5
Service Cost 3.9 3.7
Interest Cost 6.5 6.6
Actuarial Loss (Gain) (6.6) 10.8
Participation Contributions 1.1 0.9
Benefits Paid (4.9) (4.3)
- -----------------------------------------------------------------------------------------
Obligation, End of Year 117.2 117.2
- -----------------------------------------------------------------------------------------
Change in Plan Assets
Fair Value, Beginning of Year 50.9 39.5
Actual Return on Assets 6.3 6.6
Employer Contribution 5.0 8.2
Participation Contributions 1.1 0.9
Benefits Paid (4.9) (4.3)
- -----------------------------------------------------------------------------------------
Fair Value, End of Year 58.4 50.9
- -----------------------------------------------------------------------------------------
Funded Status (58.8) (66.3)
Unrecognized Amounts
Net Loss 15.5 23.9
Transition Obligation 20.0 22.4
- -----------------------------------------------------------------------------------------
Accrued Cost $(23.3) $(20.0)
- -----------------------------------------------------------------------------------------
Under SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," only assets in the VEBAs are treated as plan assets in the table
above for the purpose of determining funded status. In addition to the
postretirement health and life assets reported above, we had $24.4 million in an
irrevocable grantor trust at December 31, 2004 ($20.2 million at December 31,
2003). We consolidate the irrevocable grantor trust and it is included in
Investments on our consolidated balance sheet.
COMPONENTS OF NET PERIODIC POSTRETIREMENT
HEALTH AND LIFE EXPENSE
YEAR ENDED DECEMBER 31 2004 2003 2002
- -----------------------------------------------------------------------------------------
MILLIONS
Service Cost $3.9 $3.7 $2.9
Interest Cost 6.6 6.6 5.9
Expected Return on Assets (4.6) (4.0) (3.9)
Amortized Amounts
Unrecognized Loss (Gain) 0.4 0.1 (0.2)
Transition Obligation 2.4 2.4 2.4
- -----------------------------------------------------------------------------------------
Net Expense $8.7 $8.8 $7.1
- -----------------------------------------------------------------------------------------
Page 71 ALLETE 2004 Form 10-K
POSTRETIREMENT
ESTIMATED FUTURE BENEFIT PAYMENTS PENSION HEALTH AND LIFE
- ------------------------------------------------------------------------------------------------------------------------
MILLIONS
2005 $17 $4
2006 $17 $5
2007 $18 $5
2008 $19 $5
2009 $20 $6
Years 2010 - 2014 $113 $38
- ------------------------------------------------------------------------------------------------------------------------
WEIGHTED-AVERAGE ASSUMPTIONS
USED TO DETERMINE BENEFIT OBLIGATION
AT SEPTEMBER 30 2004 2003
- ------------------------------------------------------------------------------------------------------------------------
MILLIONS
Discount Rate 5.75% 6.0%
Rate of Compensation Increase 3.5 - 4.5% 3.5 - 4.5%
Health Care Trend Rates
Trend Rate 11% 10%
Ultimate Trend Rate 5% 5%
Year Ultimate Trend Rate Effective 2011 2008
- ------------------------------------------------------------------------------------------------------------------------
WEIGHTED-AVERAGE ASSUMPTIONS
USED TO DETERMINE NET PERIODIC BENEFIT COSTS
YEAR ENDED DECEMBER 31 2004 2003 2002
- ------------------------------------------------------------------------------------------------------------------------
Discount Rate 6.0% 6.75% 7.75%
Expected Long-Term Return on Plan Assets
Pension 9.0% 9.5% 10.0%
Postretirement Health and Life 7.2 - 9.0% 7.6 - 9.5% 8.0 - 10.0%
Rate of Compensation Increase 3.5 - 4.5% 3.5 - 4.5% 3.5 - 4.5%
- ------------------------------------------------------------------------------------------------------------------------
In establishing the expected long-term return on plan assets, we consider the
diversification and allocation of plan assets, the actual long-term historical
performance for the type of securities invested in, the actual long-term
historical performance of plan assets and the impact of current economic
conditions, if any, on long-term historical returns.
SENSITIVITY OF A ONE-PERCENTAGE-POINT ONE PERCENT ONE PERCENT
CHANGE IN HEALTH CARE TREND RATES INCREASE DECREASE
- ------------------------------------------------------------------------------------------------------------------------
MILLIONS
Effect on Total of Postretirement Health and Life Service and Interest Cost $0.7 $(0.5)
Effect on Postretirement Health and Life Obligation $14.2 $(12.1)
- ------------------------------------------------------------------------------------------------------------------------
POSTRETIREMENT
PENSION HEALTH AND LIFE
PLAN ASSET ALLOCATIONS 2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------------
Equity Securities 60.4% 61.6% 64.4% 62.2%
Debt Securities 30.9 27.8 34.9 36.3
Real Estate 2.2 2.8 - -
Venture Capital 5.2 5.6 - -
Cash 1.3 2.2 0.7 1.5
- ------------------------------------------------------------------------------------------------------------------------
100.0% 100.0% 100.0% 100.0%
- ------------------------------------------------------------------------------------------------------------------------
Included VEBAs and irrevocable grantor trust.
Pension plan equity securities include ALLETE common stock in the amounts of
$22.6 million (7.3% of total plan assets) and $25.8 million (9.1% of total plan
assets) at September 30, 2004 and 2003, respectively.
ALLETE 2004 Form 10-K Page 72
To achieve strong returns within managed risk, we diversify our asset portfolio
to approximate the target allocations in the table below. Equity securities are
diversified among domestic companies with large, mid and small market
capitalizations, as well as investments in international companies. In addition,
all debt securities must have a Standard & Poor's credit rating of A or higher.
POSTRETIREMENT
PLAN ASSET TARGET ALLOCATIONS PENSION HEALTH AND LIFE
- ---------------------------------------------------------------------------------------------
Equity Securities 58% 62%
Debt Securities 30 35
Real Estate 5 -
Venture Capital 6 -
Cash 1 3
- ---------------------------------------------------------------------------------------------
100% 100%
- ---------------------------------------------------------------------------------------------
Included VEBAs and irrevocable grantor trust.
We expect to contribute approximately $6 million to our postretirement health
and life plans in 2005. We are not required to make any contributions to our
defined benefit pension plans in 2005.
In May 2004, the FASB issued FSP 106-2, "Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug, Improvement and Modernization Act of
2003 (Act)," which provides accounting and disclosure guidance for employers
that sponsor postretirement health care plans that provide prescription drug
benefits. FSP 106-2 requires that the accumulated postretirement benefit
obligation and postretirement benefit cost reflect the impact of the Act upon
adoption. We provide postretirement health benefits that include prescription
drug benefits and have concluded that our prescription drug benefits will
qualify us for the federal subsidy to be provided for under the Act. We adopted
FSP 106-2 in the third quarter of 2004. The impact of adoption reduced our
after-tax postretirement medical expense by $1.6 million for 2004.
Page 73 ALLETE 2004 Form 10-K
NOTE 17. EMPLOYEE STOCK AND INCENTIVE PLANS
EMPLOYEE STOCK OWNERSHIP PLAN. We sponsor a leveraged employee stock ownership
plan (ESOP) within the Retirement Savings and Stock Ownership Plan (RSOP) that
covers certain eligible employees. In 1989, the ESOP used the proceeds from a
$16.5 million third-party loan, guaranteed by us, to purchase 0.4 million shares
of our common stock on the open market. This loan was fully repaid in 2004, and
all shares originally purchased with loan proceeds have been allocated to
participants. In 1990, the ESOP issued a $75 million note (term not to exceed 25
years at 10.25%) to us as consideration for 1.9 million shares of our newly
issued common stock. The Company makes annual contributions to the ESOP equal to
the ESOP's debt service less available dividends received by the ESOP. The
majority of dividends received by the ESOP are used to pay debt service, with
the balance distributed to participants. The ESOP shares were initially pledged
as collateral for its debt. As the debt is repaid, shares are released from
collateral and allocated to participants, based on the proportion of debt
service paid in the year. As shares are released from collateral, the Company
reports compensation expense equal to the current market price of the shares.
Dividends on allocated ESOP shares are recorded as a reduction of retained
earnings; available dividends on unallocated ESOP shares are recorded as a
reduction of debt and accrued interest. ESOP compensation expense was $5.0
million in 2004 ($3.7 million in 2003; $3.9 million in 2002).
As a result of the September 2004 spin-off of ADESA, the ESOP received 3.3
million shares of ADESA stock related to unearned ESOP shares that have not been
allocated to participants. The ESOP was required to sell the ADESA stock and use
the proceeds to purchase ALLETE common stock on the open market. In accordance
with a private letter ruling received from the Internal Revenue Service in
December 2004, the ESOP has until May 2006 to complete the sale of ADESA stock
and the purchase of ALLETE common stock. At December 31, 2004, the ESOP had sold
all of these ADESA shares. The 3.3 million ADESA shares sold by the ESOP in 2004
resulted in total proceeds of $65.9 million and an after-tax gain of $11.5
million, which we recognized in the fourth quarter of 2004. The ESOP used $35.6
million of the proceeds to purchase 1.0 million shares of ALLETE common stock
during the fourth quarter of 2004. Under the direction of an independent
trustee, the ESOP had $30.3 million of cash available at December 31, 2004 to
purchase ALLETE common stock; we reported the cash held by the ESOP as
Restricted Cash on our consolidated balance sheet. During January 2005, the
trustee purchased an additional 0.5 million shares of ALLETE common stock and
$8.9 million remains as Restricted Cash.
As of January 31, 2005, participants in the RSOP had $52.2 million, or 2.5
million shares, invested in ADESA common stock. Beginning later in 2005, the
RSOP trustee will be selling the ADESA common stock and purchasing ALLETE common
stock according to the requirements of the RSOP. Participants may transfer out
of the ADESA common stock fund at any time. That decision also initiates a sale
of ADESA common stock but may not initiate an ALLETE purchase, unless the
participant chooses to transfer to the ALLETE common stock fund.
Pursuant to AICPA Statement of Position 93-6, "Employers' Accounting for
Employee Stock Ownership Plans," unallocated ALLETE common stock currently held
and purchased by the ESOP will be treated as unearned ESOP shares and not
considered as outstanding for earnings per share computations. ESOP shares are
included in earnings per share computations after they are allocated to
participants.
YEAR ENDED DECEMBER 31 2004 2003 2002
- ---------------------------------------------------------------------------------------------
MILLIONS
ESOP Shares
Allocated 1.4 1.2 1.3
Unallocated 2.0 1.1 1.2
- ---------------------------------------------------------------------------------------------
Total 3.4 2.3 2.5
- ---------------------------------------------------------------------------------------------
Fair Value of Unallocated Shares $72.7 $105.0 $84.0
- ---------------------------------------------------------------------------------------------
STOCK OPTION AND AWARD PLANS. We have an Executive Long-Term Incentive
Compensation Plan (Executive Plan) and a Director Long-Term Stock Incentive Plan
(Director Plan). The Executive Plan allows for the grant of up to 3.2 million
shares of our common stock to key employees. To date, these grants have taken
the form of stock options, performance share awards and restricted stock awards.
The Director Plan allows for the grant of up to 0.1 million shares of our common
stock to nonemployee directors. Each nonemployee director may receive an annual
grant of 500 stock options and a biennial grant of performance shares equal to
$10,000 in value of common stock at the date of grant. No grants have been made
since 2003 under the Director Plan. Stock options are exercisable at the market
price of common shares on the date the options are granted and vest in equal
annual installments over two years, with expiration ten years from the date of
grant. Performance shares are earned over multi-year time periods and are
contingent upon the attainment of certain performance goals of ALLETE.
Restricted stock vests once certain periods of time have elapsed. At December
31, 2004, 1.3 million shares were held in reserve for future issuance under the
Executive Plan and Director Plan.
ALLETE 2004 Form 10-K Page 74
2004 2003 2002
--------------------------------------------------------------------------------
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
STOCK OPTION ACTIVITY OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
- ------------------------------------------------------------------------------------------------------------------------
OPTIONS IN MILLIONS
Outstanding, Beginning of Period 0.8 $64.47 0.8 $67.44 0.8 $60.54
Granted 0.1 $97.65 0.2 $61.77 0.2 $77.76
Exercised (0.4) $67.14 (0.2) $61.32 (0.2) $56.10
Cancelled - - - $68.13 - $71.31
- ------------------------------------------------------------------------------------------------------------------------
Outstanding, End of Period 0.5 $69.85 0.8 $64.47 0.8 $67.44
- ------------------------------------------------------------------------------------------------------------------------
Exercisable, End of Period - - 0.5 $67.26 0.4 $60.69
Fair Value of Options
Granted During the Period $20.01 $8.16 $13.65
- ------------------------------------------------------------------------------------------------------------------------
All amounts above are prior to the ADESA spin-off and the historical option and average exercise prices have been
adjusted for the one-for-three reverse stock split on September 20, 2004. The 2004 amounts are up to the
September 20, 2004 spin-off of ADESA.
2004
-------------------
AVERAGE
EXERCISE
STOCK OPTION ACTIVITY OPTIONS PRICE
- -------------------------------------------------------------------------------------------------
OPTIONS IN MILLIONS
Outstanding as of September 20, 2004, after spin-off 0.5 $28.56
Granted - -
Exercised (0.1) $24.40
Cancelled - -
- -------------------------------------------------------------------------------------------------
Outstanding, End of Year 0.4 $28.94
- -------------------------------------------------------------------------------------------------
Exercisable, End of Year 0.3 $26.57
- -------------------------------------------------------------------------------------------------
Amounts subsequent to the ADESA spin-off.
The employee stock options outstanding at the date of the spin-off were
converted to reflect the spin-off and one-for-three reverse stock split. This
conversion was done to preserve the noncompensatory nature of the options under
FASB Interpretation No. 44, "Accounting for Certain Transactions Involving Stock
Compensation."
At December 31, 2004, options outstanding consisted of less than 0.1 million
with an exercise price of $15.88 to $18.85, 0.3 million with an exercise price
of $23.79 to $29.79 and 0.1 million with an exercise price of $37.76. The
options with an exercise price of $23.79 to $29.79 have an average remaining
contractual life of 6.6 years, with 0.3 million exercisable on December 31,
2004, at an average price of $27.46. The options with an exercise price of
$37.76 have an average remaining contractual life of 9 years, with 0.1 million
exercisable on December 31, 2004.
A total of 0.1 million performance share grants were awarded in February 2004
for performance periods ending in 2005 and 2006. The ultimate issuance is
contingent upon the attainment of certain future performance goals of ALLETE
during the performance periods. The grant date fair value of the performance
share awards was $1.6 million.
A total of 0.1 million performance share grants were awarded in 2002 and 2003
for the performance period ended December 31, 2003. The grant date fair value of
the share awards was $8.3 million. In early 2004, 50% of the shares were issued
with the balance to be issued in 2005.
In February 2005, we granted stock options to purchase less than 0.1 million
shares of common stock (exercise price of $41.35 per share).
EMPLOYEE STOCK PURCHASE PLAN. We have an Employee Stock Purchase Plan that
permits eligible employees to buy up to $23,750 per year of our common stock at
95% of the market price. At December 31, 2004, 1.3 million shares had been
issued under the plan and 0.1 million shares were held in reserve for future
issuance.
Page 75 ALLETE 2004 Form 10-K
NOTE 18. QUARTERLY FINANCIAL DATA (UNAUDITED)
Information for any one quarterly period is not necessarily indicative of the
results which may be expected for the year. Financial results for the first
quarter of 2004 included a $7.8 million, or $0.27 per share, non-cash after-tax
charge for a change in accounting principle related to investments in our
emerging technology portfolio. Financial results for the third quarter of 2004
included a $10.9 million, or $0.38 per share, after-tax debt prepayment cost as
part of ALLETE's financial restructuring in preparation for the spin-off of
ADESA, which occurred on September 20, 2004. Financial results for the fourth
quarter of 2004 included an $11.5 million, or $0.41 per share, after-tax gain on
the sale of ADESA shares held by our ESOP. The ESOP received the ADESA shares as
a result of the spin-off.
Financial results for 2003 included a $71.6 million, or $2.59 per share,
after-tax gain on the sale of substantially all our Water Services businesses
($0.2 million first quarter and second quarter; $3.0 million, or $0.11 per
share, third quarter; $68.2 million, or $2.47 per share, fourth quarter). The
gain was net of all selling, transaction and employee termination benefit
expenses, as well as impairment losses on certain remaining assets.
QUARTER ENDED MAR. 31 JUN. 30 SEPT. 30 DEC. 31
- -------------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT EARNINGS PER SHARE
2004
Operating Revenue $209.0 $186.2 $177.6 $178.6
Operating Income from Continuing Operations $42.7 $18.8 $23.2 $15.1
Net Income (Loss) Continuing Operations $21.4 $ 2.4 $(0.6) $15.9
Discontinued Operations 31.3 34.3 13.7 (6.2)
Change in Accounting Principle (7.8) - - -
- -------------------------------------------------------------------------------------------------------------------------
$44.9 $36.7 $ 13.1 $9.7
Earnings Available for Common Stock $44.9 $36.7 $ 13.1 $9.7
Earnings (Loss) Per Share of Common Stock
Basic Continuing Operations $0.77 $0.08 $(0.03) $0.57
Discontinued Operations 1.11 1.21 0.48 (0.22)
Change in Accounting Principle (0.28) - - -
- -------------------------------------------------------------------------------------------------------------------------
$1.60 $1.29 $ 0.45 $0.35
Diluted Continuing Operations $0.76 $0.08 $(0.02) $0.55
Discontinued Operations 1.10 1.21 0.47 (0.21)
Change in Accounting Principle (0.27) - - -
- -------------------------------------------------------------------------------------------------------------------------
$1.59 $1.29 $ 0.45 $0.34
2003
Operating Revenue $186.0 $171.4 $169.0 $165.9
Operating Income from Continuing Operations $26.9 $20.3 $30.3 $18.6
Net Income Continuing Operations $11.3 $ 3.4 $10.9 $ 4.2
Discontinued Operations 33.0 41.0 36.7 95.9
- -------------------------------------------------------------------------------------------------------------------------
$44.3 $44.4 $47.6 $100.1
Earnings Available for Common Stock $44.3 $44.4 $47.6 $100.1
Earnings Per Share of Common Stock
Basic Continuing Operations $0.41 $0.12 $0.40 $0.15
Discontinued Operations 1.21 1.49 1.32 3.46
- -------------------------------------------------------------------------------------------------------------------------
$1.62 $1.61 $1.72 $3.61
Diluted Continuing Operations $0.41 $0.12 $0.40 $0.15
Discontinued Operations 1.20 1.49 1.31 3.44
- -------------------------------------------------------------------------------------------------------------------------
$1.61 $1.61 $1.71 $3.59
- -------------------------------------------------------------------------------------------------------------------------
ALLETE 2004 Form 10-K Page 76
SCHEDULE II
ALLETE
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
BALANCE AT ADDITIONS DEDUCTIONS BALANCE AT
BEGINNING CHARGED OTHER FROM END OF
FOR THE YEAR ENDED DECEMBER 31 OF YEAR TO INCOME CHANGES RESERVES PERIOD
- ------------------------------------------------------------------------------------------------------------------------
MILLIONS
Reserve Deducted from Related Assets
Reserve For Uncollectible Accounts
2004 Trade Accounts Receivable $1.3 $1.7 - $1.0 $2.0
Finance Receivables - Long-Term 1.2 - - 0.5 0.7
2003 Trade Accounts Receivable 2.2 (0.1) - 0.8 1.3
Finance Receivables - Long-Term 1.7 - - 0.5 1.2
2002 Trade Accounts Receivable 1.4 2.2 - 1.4 2.2
Finance Receivables - Long-Term 2.7 0.4 - 1.4 1.7
Deferred Asset Valuation Allowance
2004 Deferred Tax Assets 0.2 0.9 - - 1.1
2003 Deferred Tax Assets 0.1 0.1 - - 0.2
2002 Deferred Tax Assets 0.0 0.1 - - 0.1
- ------------------------------------------------------------------------------------------------------------------------
Included uncollectible accounts written off.
Page 77 ALLETE 2004 Form 10-K
EXHIBIT INDEX
EXHIBIT NUMBER
10(c) - Master Agreement (without Appendices and Exhibits),
dated December 28, 2004, by and between Rainy River Energy
Corporation and Constellation Energy Commodities Group, Inc.
10(d)2 - First Amendment to Third Amended and Restated Committed
Facility Letter, dated December 14, 2004, by and among ALLETE
and LaSalle Bank National Association, as Agent.
10(k)4 - Form of ALLETE Executive Long-Term Incentive Compensation
Plan Nonqualified Stock Option Grant.
10(k)5 - Form of ALLETE Executive Long-Term Incentive Compensation
Plan Performance Share Grant.
12 - Computation of Ratios of Earnings to Fixed Charges.
23(a) - Consent of Independent Registered Public Accounting Firm.
23(b) - Consent of General Counsel.
31(a) - Rule 13a-14(a)/15d-14(a) Certification by the Chief Executive
Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
31(b) - Rule 13a-14(a)/15d-14(a) Certification by the Chief Financial
Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
32 - Section 1350 Certification of Annual Report by the Chief
Executive Officer and Chief Financial Officer Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
ALLETE 2004 Form 10-K