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, 2005
/ / 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 if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act.
Yes /X/ No / /
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act.
Yes / / No /X/
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. / /
Indicate by check mark whether the registrant is a large accelerated filer, an
accelerated filer or a non-accelerated filer (as defined in Rule 12b-2 of the
Act).
Large Accelerated Filer /X/ Accelerated Filer / / Non-Accelerated Filer / /
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Act).
Yes / / No /X/
The aggregate market value of voting stock held by nonaffiliates on June 30,
2005, was $1,489,669,987.
As of February 1, 2006, there were 30,153,542 shares of ALLETE Common Stock,
without par value, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the 2006 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
Energy - Regulated Utility................................... 5
Electric Sales........................................... 6
Purchased Power.......................................... 8
Fuel..................................................... 8
Regulatory Issues........................................ 9
Competition.............................................. 13
Franchises............................................... 13
Energy - Nonregulated Energy Operations...................... 13
Energy - Investment in ATC .................................. 14
Real Estate.................................................. 15
Regulation............................................... 18
Competition.............................................. 18
Other........................................................ 18
Environmental Matters........................................ 19
Employees.................................................... 21
Executive Officers of the Registrant......................... 22
Item 1A. Risk Factors...................................................... 23
Item 1B. Unresolved Staff Comments......................................... 27
Item 2. Properties........................................................ 27
Item 3. Legal Proceedings................................................. 27
Item 4. Submission of Matters to a Vote of Security Holders............... 27
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities.................... 28
Item 6. Selected Financial Data........................................... 29
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations........................................ 31
Executive Summary................................................. 31
Net Income........................................................ 34
2005 Compared to 2004............................................. 36
2004 Compared to 2003............................................. 38
Non-GAAP Financial Measures....................................... 39
Critical Accounting Policies...................................... 40
Outlook........................................................... 42
Liquidity and Capital Resources................................... 46
Capital Requirements.............................................. 49
Environmental and Other Matters................................... 50
Market Risk....................................................... 50
New Accounting Standards.......................................... 51
Item 7A. Quantitative and Qualitative Disclosures about Market Risk........ 51
Item 8. Financial Statements and Supplementary Data....................... 52
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure......................................... 52
Item 9A. Controls and Procedures........................................... 52
Item 9B. Other Information................................................. 52
PART III
Item 10. Directors and Executive Officers of the Registrant................ 53
Item 11. Executive Compensation............................................ 53
Item 12. Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters.............................. 53
Item 13. Certain Relationships and Related Transactions.................... 53
Item 14. Principal Accountant Fees and Services............................ 53
PART IV
Item 15. Exhibits and Financial Statement Schedules........................ 54
SIGNATURES................................................................. 58
CONSOLIDATED FINANCIAL STATEMENTS.......................................... 59
Page 1 ALLETE 2005 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, LLC
APB Accounting Principles Board
Aqua Utilities Aqua Utilities Florida, Inc.
AREA Arrowhead Regional Emission Abatement
ATC American Transmission Company LLC
BNI Coal BNI Coal, Ltd.
Boswell Boswell Energy Center
Company ALLETE, Inc. and its subsidiaries
Constellation Energy Commodities Constellation Energy Commodities Group,
Inc.
DOC Minnesota Department of Commerce
DRI Development of Regional Impact
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 Landmark Florida Landmark Communities, Inc.
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
HickoryTech Hickory Tech Corporation
Invest Direct ALLETE's Direct Stock Purchase and
Dividend Reinvestment Plan
IPO Initial Public Offering
kV Kilovolt(s)
Laskin Laskin Energy Center
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 / MWh Megawatt(s) / Megawatthour(s)
NOX Nitrogen Oxide
Northwest Airlines Northwest Airlines, Inc.
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
PUHCA 1935 Public Utility Holding Company Act of 1935
PUHCA 2005 Public Utility Holding Company Act of 2005
Rainy River Energy Rainy River Energy Corporation
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting
Standards No.
SO2 Sulfur Dioxide
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
Town Center Town Center at Palm Coast development
project in Florida
WDNR Wisconsin Department of Natural Resources
ALLETE 2005 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," "could," "may,"
"potential," "target," "outlook" 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, in addition to any assumptions
and other factors referred to specifically in connection with such
forward-looking statements, 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;
- our ability to manage expansion and integrate acquisitions;
- 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;
- our ability to obtain viable real estate for development purposes;
- 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;
- our ability to access capital markets;
- changes in interest rates and the performance of the financial markets;
- competition for economic expansion or development opportunities;
- our ability to replace a mature workforce, and retain qualified,
skilled and experienced personnel; 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 1A under the heading "Risk Factors" beginning on page 23 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 this 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 2005 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, 2005, we had
approximately 1,500 employees, 100 of which were part-time. Statistical
information is presented as of December 31, 2005, 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 100 F Street, N.E., 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 free of charge.
ALLETE's operations focus on two core businesses--ENERGY and REAL ESTATE. In
addition, we have other operations that provide earnings to the Company.
ENERGY is comprised of Regulated Utility, Nonregulated Energy Operations and,
beginning in 2006, Investment in American Transmission Company LLC.
- 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 our coal mining activities in
North Dakota and nonregulated generation (non-rate base generation sold
at market-based rates to the wholesale market), which consisted primarily
of generation from Taconite Harbor in northern Minnesota. Pending MPUC
approval, Taconite Harbor will be integrated into our Regulated Utility
business effective retroactive to January 1, 2006, to help meet
forecasted base load energy requirements. Nonregulated Energy Operations
also included generation secured through the Kendall County power
purchase agreement, which was assigned to Constellation Energy
Commodities in April 2005.
- INVESTMENT IN ATC will include our estimated 9% ownership interest in
ATC. In December 2005, we entered into an agreement that provides for us
to invest $60 million in ATC by the end of 2006. The investment is
subject to review by the PSCW.
REAL ESTATE includes our Florida real estate operations.
OTHER includes our investments in emerging technologies, and earnings on cash,
cash equivalents and short-term investments.
YEAR ENDED DECEMBER 31 2005 2004 2003
- ----------------------------------------------------------------------------------------------------------------------
Consolidated Operating Revenue - Millions $737.4 $704.1 $659.6
- ----------------------------------------------------------------------------------------------------------------------
Percentage of Consolidated Operating Revenue
Regulated Utility
Industrial
Taconite Producers 23% 25% 23%
Paper and Wood Products 9 9 9
Pipelines and Other Industries 6 7 6
- ----------------------------------------------------------------------------------------------------------------------
Total Industrial 38 41 38
Residential 10 11 11
Commercial 11 11 11
Other Power Suppliers 7 5 7
Other Revenue 12 11 10
- ----------------------------------------------------------------------------------------------------------------------
Total Regulated Utility 78 79 77
Nonregulated Energy Operations 16 15 16
Real Estate 6 6 7
- ----------------------------------------------------------------------------------------------------------------------
100% 100% 100%
- ----------------------------------------------------------------------------------------------------------------------
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.
ALLETE 2005 Form 10-K Page 4
DISCONTINUED OPERATIONS. We successfully completed the spin-off of our
Automotive Services business, and the sales of our Water Services and our
telecommunications businesses.
SPIN-OFF OF AUTOMOTIVE SERVICES. Through a June 2004 IPO, our Automotive
Services business, doing business as ADESA, Inc. (NYSE: KAR), issued 6.3 million
shares of common stock, representing 6.6% of ADESA's common stock outstanding.
In September 2004, we spun off the business by distributing to ALLETE
shareholders all of ALLETE's remaining 93.4% of ADESA common stock.
SALE OF WATER SERVICES BUSINESSES. In early 2005, we completed the exit from our
Water Services businesses with the sale of our wastewater assets in Georgia. In
mid-2004, we sold our North Carolina water and wastewater assets, and our
remaining 72 water and wastewater systems in Florida. Substantially all of our
water assets in Florida were sold in 2003, under condemnation or imminent threat
of condemnation. 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. In
2005, the FPSC ordered a $1.7 million reduction to plant investment, which the
Company reserved for in 2005, and approved the transfer of 63 water and
wastewater systems from Florida Water to Aqua Utilities. Aqua Utilities filed a
protest and requested that the FPSC schedule evidentiary hearings. The FPSC's
decision on these issues may change the reduction to plant investment ordered in
2005 and could result in an adjustment to the final purchase price paid by Aqua
Utilities.
SALE OF ENVENTIS TELECOM. On December 30, 2005, we sold all the stock of our
telecommunications subsidiary, Enventis Telecom, to HickoryTech of Mankato,
Minnesota, for $35.5 million. The transaction resulted in an after-tax loss of
$3.6 million, which was included in our 2005 loss from discontinued operations.
Net cash proceeds realized from the sale were approximately $29 million after
transaction costs, repayment of debt and payment of income taxes.
ENERGY - 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 to 137,000 retail customers and wholesale electric service to 16
municipalities. SWL&P provides regulated utility electric, natural gas and water
service in northwestern Wisconsin to 14,000 electric customers, 12,000 natural
gas customers and 10,000 water customers.
Minnesota Power had an annual net peak load of 1,543 MW on December 20, 2005.
Our regulated power supply sources are listed below.
FOR THE YEAR ENDED
REGULATED UTILITY UNIT YEAR NET WINTER DECEMBER 31, 2005
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 351
4 1980 429
- --------------------------------------------------------------------------------------------------------------------------
918 6,450,016 53.4%
- --------------------------------------------------------------------------------------------------------------------------
Laskin Energy Center 1 1953 55
in Hoyt Lakes, MN 2 1953 55
- --------------------------------------------------------------------------------------------------------------------------
110 695,659 5.8
- --------------------------------------------------------------------------------------------------------------------------
Purchased Steam
Hibbard Energy Center in Duluth, MN 3 & 4 1949, 1951 47 76,128 0.6
- --------------------------------------------------------------------------------------------------------------------------
Total Steam 1,075 7,221,803 59.8
- --------------------------------------------------------------------------------------------------------------------------
Hydro
Group consisting of ten stations in MN Various 115 487,063 4.0
- --------------------------------------------------------------------------------------------------------------------------
Purchased Power
Square Butte burns lignite coal near Center, ND 322 2,268,397 18.8
Minnesota Power Nonregulated Energy Generation - 202,710 1.7
All Other - Net - 1,890,813 15.7
- --------------------------------------------------------------------------------------------------------------------------
Total Purchased Power 322 4,361,920 36.2
- --------------------------------------------------------------------------------------------------------------------------
Total 1,512 12,070,786 100.0%
- --------------------------------------------------------------------------------------------------------------------------
Page 5 ALLETE 2005 Form 10-K
ENERGY - REGULATED UTILITY (CONTINUED)
We have electric transmission and distribution lines of 500 kV (8 miles), 230 kV
(605 miles), 161 kV (43 miles), 138 kV (126 miles), 115 kV (1,209 miles) and
less than 115 kV (6,773 miles). We own and operate 185 substations with a total
capacity of 8,872 megavoltamperes. Some of our transmission and distribution
lines interconnect with other utilities.
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. Wisconsin Public Power, Inc. (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 9.)
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 2005 2004 2003
- -------------------------------------------------------------------------------------------------------------------
MILLIONS OF KILOWATTHOURS
Retail and Municipals
Residential 1,102 1,053 1,065
Commercial 1,327 1,282 1,286
Industrial 7,130 7,071 6,558
Municipals and Other 956 902 921
- -------------------------------------------------------------------------------------------------------------------
10,515 10,308 9,830
Other Power Suppliers 1,142 918 1,314
- -------------------------------------------------------------------------------------------------------------------
11,657 11,226 11,144
- -------------------------------------------------------------------------------------------------------------------
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 both 2005 and 2004. Annual taconite production in Minnesota was 41
million tons in 2005 (41 million tons in 2004; 35 million tons in 2003). Recent
consolidation activities, combined with the strong steel market, have placed the
Minnesota taconite producers in a strong position. During 2005, Cleveland-Cliffs
Inc and United States Steel Corporation invested significant capital to bring
production capacity back online and/or improve operating efficiencies. They also
invested in required pollution control equipment to help insure the longevity of
their operations.
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.
Minnesota Power's paper and pulp customers ran at or very near full capacity in
2005 despite the fact that after an economic rebound in 2004, the North American
paper industry had a somewhat more difficult year in 2005. As the industry faced
slightly lower demand, as well as increased fiber, chemical and energy costs,
Minnesota Power's customers benefited from the temporary or permanent idling of
capacity in North America at mills other than those served by Minnesota Power,
the strength of the Euro and a Finnish paper industry labor strike which
temporarily idled capacity.
ALLETE 2005 Form 10-K Page 6
ENERGY - REGULATED UTILITY (CONTINUED)
The pipeline and refining industry is the third key industrial segment served by
Minnesota Power with services provided to two crude oil pipelines and one
refinery. After years of near capacity operation in 2004 and 2005, both pipeline
operators are evaluating expansion alternatives to transport newly developed
Western Canadian crude oil reserves (Alberta Oil Sands) to United States
markets. Access to traditional Midwest markets is being expanded to southern
markets as the Canadian supply is displacing domestic production and deliveries
imported from the Gulf Coast.
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 that requires 8 MW or more of generating
capacity. In 2005, contracts were successfully renegotiated with five of our
Large Power Customers representing approximately 23% of 2005 regulated utility
revenue. The durations of these contracts were extended several years with the
termination dates ranging from February 28, 2010, to October 13, 2013. 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) or four-month 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.
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 take
all of their purchased 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.)
Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large
Power Customers to pay weekly for electric usage based on monthly energy usage
estimates. A normal 30-day billing cycle with a 15-day payment period left
Minnesota Power greatly exposed to a significant revenue loss if a customer did
not or could not make payment due to discontinued operations, or delayed making
an electric service payment pending a 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, 2006 ANNUAL REVENUE <F1><F2> MEGAWATTS
- -----------------------------------------------------------------------------------------------------------------------
2006 $61.3 million 375
2007 $33.3 million 178
2008 $28.7 million 161
2009 $26.9 million 154
2010 $22.3 million 124
- -----------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Based on past experience, we believe revenue from our Large Power Customers will be substantially in excess of
the minimum contract amounts. For example, in our 2004 Form 10-K we stated 2005 minimum annual revenue from
these Large Power Customers would be $69.1 million. Actual 2005 demand revenue from these Large Power Customers
was $115.5 million.
<F2> Although several contracts have a feature that allows demand to go to zero after a two-year advance notice of
a permanent closure, this minimum revenue summary does not reflect this occurrence happening in the forecasted
period because we believe it is unlikely.
</FN>
Page 7 ALLETE 2005 Form 10-K
ENERGY - REGULATED UTILITY (CONTINUED)
CONTRACT STATUS FOR MINNESOTA POWER LARGE POWER CUSTOMERS
AS OF FEBRUARY 1, 2006
EARLIEST
CUSTOMER INDUSTRY LOCATION OWNERSHIP TERMINATION DATE
- ------------------------------------------------------------------------------------------------------------------------------------
Hibbing Taconite Co. <F1> Taconite Hibbing, MN 62.3% Mittal Steel USA Inc. February 28, 2010
23% Cleveland-Cliffs Inc
14.7% Stelco Inc.
Mittal Steel USA - Minorca Mine Taconite Virginia, MN Mittal Steel USA Inc. December 31, 2012
United States Steel Corporation Taconite Mt. Iron, MN USS October 31, 2013
(USS) Minntac
USS Keewatin Taconite Taconite Keewatin, MN USS October 31, 2013
United Taconite LLC <F1> Taconite Eveleth, MN 70% Cleveland-Cliffs Inc February 28, 2010
30% Laiwu Steel Group
UPM, Blandin Paper Mill <F1><F2> Paper Grand Rapids, MN UPM-Kymmene Corporation February 28, 2010
Boise White Paper, LLC Paper International Falls, MN Madison Dearborn December 31, 2008
Partnership
Sappi Cloquet LLC <F1> Paper Cloquet, MN Sappi Limited February 28, 2010
Stora Enso North America, Paper and Pulp Duluth, MN Stora Enso Oyj August 31, 2013
Duluth Paper Mill and
Duluth Recycled Pulp Mill <F2>
USG Interiors, Inc. <F3> Manufacturer Cloquet, MN USG Corporation February 28, 2007
Enbridge Energy Company, Pipeline Deer River, MN Enbridge Energy Company, February 28, 2007
Limited Partnership <F3> Floodwood, MN Limited Partnership
Minnesota Pipeline Company <F3> Pipeline Staples, MN 60% Koch Pipeline Co. L.P. February 28, 2007
Little Falls, MN 40% Marathon Ashland
Park Rapids, MN Petroleum LLC
- ------------------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> 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, 2010.
<F2> Minnesota Power filed with the MPUC a petition for approval of these newly executed contracts and anticipates approval during
the first half of 2006.
<F3> 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, 2007.
</FN>
PURCHASED POWER
Minnesota Power has contracts to purchase capacity and energy from various
entities, the largest is with Square Butte. Under an agreement with Square Butte
expiring at the end of 2026, Minnesota Power is currently entitled to
approximately 66% (60% beginning in 2007; 55% in 2008) of the output of a 455-MW
coal-fired generating unit located near Center, North Dakota. (See Note 10.)
In May 2005, Minnesota Power entered into a 25-year agreement with an affiliate
of FPL Energy, LLC to purchase all of the renewable energy from an approximately
50-MW (nameplate) wind facility to be built in North Dakota. FPL Energy, LLC
expects the facility to be operational in the fall of 2006. The wind facility
will be comprised of 22 new 2.3 MW wind turbines interconnected to the Square
Butte substation in Center, North Dakota, near the BNI Coal mine. On December
20, 2005, the MPUC approved the power purchase agreement. In addition, Minnesota
Power is continuing to pursue the purchase of renewable energy from a new wind
facility that would be located in northern Minnesota. The project, expected to
be operational in 2007, would be similar in size to the North Dakota project and
would be subject to a power purchase agreement, as well as regulatory approvals.
The Minnesota project also needs to be operational by the end of 2007 to be
eligible for federal production tax credits which are essential to provide
acceptable pricing.
FUEL
Minnesota Power purchases low-sulfur, sub-bituminous coal from the Powder River
Basin coal field located in Montana. Coal consumption in 2005 for electric
generation at Minnesota Power's coal-fired generating stations was about 5.1
million tons. As of December 31, 2005, Minnesota Power had a coal inventory of
about 464,000 tons. Minnesota Power has two coal supply agreements with
expiration dates extending through 2009 and one contract expiring December 31,
2006. Under these agreements, Minnesota Power has the tonnage flexibility to
procure 70% to 100% of its total coal requirements. In 2006, 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.
ALLETE 2005 Form 10-K Page 8
ENERGY - REGULATED UTILITY (CONTINUED)
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 an agreement with the
Canadian National Railway and is negotiating a new agreement with Midwest Energy
Resources Company to transport coal from the Burlington Northern interconnection
point to certain Minnesota Power facilities.
COAL DELIVERED TO MINNESOTA POWER
YEAR ENDED DECEMBER 31 2005 2004 2003
- -----------------------------------------------------------------------------------------------------------------------
Average Price per Ton $19.76 $19.01 $20.02
Average Price per MBtu $1.08 $1.04 $1.12
- -----------------------------------------------------------------------------------------------------------------------
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 2005 was
approximately 75 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 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%, 8% and 8%, respectively, of our 2005 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 conservation improvement
program 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.)
On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005
(EPAct 2005), which repealed PUHCA 1935 and enacted PUHCA 2005. PUHCA 2005 gives
FERC certain authority over books and records of public utility holding
companies and their affiliates. It also addresses FERC review and authorization
of the allocation of costs for non-power goods, or administrative or management
services when requested by a holding company system or state commission. In
addition, EPAct 2005 directs the FERC to issue certain rules addressing
electricity reliability, investment in energy infrastructure, fuel diversity for
electric generation, and a promotion of energy efficiency and wise energy use.
The FERC is currently in the process of rulemakings effectuating EPAct 2005.
These include (among others):
- the implementation of long-term transmission rights;
- the development of electric reliability organizations and delegated
authority to regional entities for proposing and enforcing reliability
standards;
- rules specifying the form for applications for federal construction
permits to be issued in the exercise of federal backstop siting authority
for transmission projects;
- establishment of rules requiring unregulated transmitting utilities to
provide open access to their transmission systems;
- the development of procedures for expeditious consideration of merger
applications under the revised Federal Power Act Section 203;
Page 9 ALLETE 2005 Form 10-K
ENERGY - REGULATED UTILITY (CONTINUED)
- the establishment of regional joint boards to consider economic dispatch;
- the issuance of rules necessary for FERC to facilitate transmission
market transparency; and
- the manipulation of the energy market.
We continue to monitor FERC activity in these and other proceedings.
MUNICIPAL CUSTOMERS. Minnesota Power has contracts with 16 Minnesota
municipalities receiving wholesale electric service. One contract, currently
being renegotiated, expires March 1, 2006 (168,000 MWh purchased in 2005), while
the other 15 are for service through at least 2007, with the majority extending
through at least 2010. In 2005, these municipal customers purchased 756,000 MWh
from Minnesota Power. Minnesota Power also has a contract for wholesale service
to Dahlberg Light & Power Company in Wisconsin. Dahlberg purchased 110,000 MWh
in 2005.
MIDWEST INDEPENDENT TRANSMISSION SYSTEM OPERATOR, INC. (MISO). Minnesota Power
and SWL&P are members of 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.
Effective April 1, 2005, the method by which Minnesota Power engages in
wholesale energy transactions changed, with both Minnesota Power load and
generation participating in MISO's day-ahead and real-time markets (MISO Day 2).
Generation also became subject to MISO economic dispatch authority. As a result
of MISO Day 2 implementation, energy transactions to serve retail customers are
sourced by wholesale transactions with MISO as the counterparty. The MPUC
initially denied cost recovery of certain MISO Day 2 costs through the fuel
clause in an order dated December 21, 2005 (see Minnesota Public Utilities
Commission - Fuel Clause Recovery of MISO Day 2 Costs below). As a result of
this order, the Company filed a Notice of Intent to Withdraw from MISO in
December 2005 and is exploring alternatives to MISO. Withdrawal from MISO would
also require MPUC and FERC approval.
MID-CONTINENT AREA POWER POOL (MAPP). 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 2006. We
will, however, continue to monitor the costs of serving our retail customers and
evaluate the need for a rate filing in the future.
INVESTIGATION OF THE USEFULNESS OF THE FUEL CLAUSE. 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.
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
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.
FUEL CLAUSE RECOVERY OF MISO DAY 2 COSTS. Minnesota Power filed a petition with
the MPUC in February 2005 to amend its fuel clause to accommodate costs and
revenue related to MISO Day 2. On April 7, 2005, the MPUC approved interim
accounting treatment of MISO Day 2 costs to be accounted for on a net basis and
recovered through the fuel clause, subject to refund with interest. This interim
treatment has continued while the MPUC has addressed the cost recovery petitions
from Xcel Energy Inc., Otter Tail Power Company, Alliant Energy Corporation and
Minnesota Power.
On December 21, 2005, the MPUC issued an order which denied recovery through the
fuel clause of uplift charges, congestion revenue and expenses, and
administrative costs related to Minnesota Power's MISO Day 2 market activities.
Minnesota Power requested rehearing of the order in a filing made with the MPUC
on January 10, 2006. The other three utilities affected by the order also filed
for rehearing, as did the DOC and MISO. In a hearing on February 9, 2006, the
MPUC granted rehearing of the MISO Day 2 docket and suspended the refund
obligation. The MPUC will review the MISO Day 2 costs to determine which costs
should be recovered on a current basis through the fuel clause and which costs
are more appropriately deferred for potential recovery through base rates. The
Company is unable to predict the outcome of this matter.
ALLETE 2005 Form 10-K Page 10
ENERGY - REGULATED UTILITY (CONTINUED)
LARGE POWER CONTRACTS. On September 9, 2005, the MPUC approved Minnesota Power's
new electric service agreement with United States Steel Corporation for combined
service to the Minntac and Keewatin Taconite facilities through October 31,
2013. On September 21, 2005, Minnesota Power filed with the MPUC a petition for
approval of its new electric service agreement with the Mittal Steel USA -
Minorca Mine that was approved by the MPUC on November 15, 2005 for service
through December 31, 2012. On December 23, 2005, Minnesota Power filed with the
MPUC a petition for approval of its new electric service agreement through
August 31, 2013, with Stora Enso's Duluth mills. On January 25, 2006, Minnesota
Power filed with the MPUC a petition for approval of its new electric service
agreement through February 28, 2010, with Blandin Paper's Grand Rapids
facilities.
RESOURCE PLAN. In September 2004, Minnesota Power filed our Integrated Resource
Plan (Resource Plan). An October 2005 update to that plan provided a revised
forecast that energy demand by customers in our service territory will increase
at an average annual rate of 1.5% to 2019. We project a load growth of
approximately 150 MW by 2010 with another 200 MW of growth anticipated by 2015.
The forecasted growth of 15 MW to 28 MW per year is 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. Minnesota Power also expects to 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 provided
several options designed to meet the predicted growing demand in the region.
In October 2005, Minnesota Power proposed to the MPUC a comprehensive solution
to meet generation needs through 2010 that includes the following key
components:
- a transition of the Taconite Harbor generating facility from nonregulated
energy operations to regulated utility to help meet the utility's
forecasted base load energy requirements;
- a 50-MW long-term power purchase agreement to meet near-term energy
needs; and
- various resource additions to help meet forecasted base load, support the
expansion of renewable generating assets and help meet Minnesota's
Renewable Energy Objective that seeks a 10% supply of qualified renewable
energy resources by 2015 for each Minnesota utility.
The proposal to transition Taconite Harbor to a regulated utility asset is
supported by the DOC and a group of our Large Power Customers. Minnesota Power
has received approval of a power purchase agreement for 50 MW of wind energy
purchased from a wind facility in North Dakota. Minnesota Power is also
continuing to pursue an agreement for an additional 50 MW of wind energy from a
new facility being planned for Minnesota, and is proposing to obtain 10 MW of
additional hydro generation through an expansion of the Fond du Lac
hydroelectric station.
On November 16, 2005, the MPUC issued a Notice of Comment Period in Minnesota
Power's Resource Plan docket that requested information on how the Resource Plan
and the Arrowhead Regional Emission Abatement proposal (discussed below) are
affected by the agreement reached between Minnesota Power, the Large Power
Customer group and the DOC, along with information on how the MPUC should
procedurally schedule the three identified items. Minnesota Power filed initial
comments in response to the Notice on December 16, 2005, and filed reply
comments on January 11, 2006. Final regulatory approval of our Resource Plan and
the transition of Taconite Harbor is expected in mid 2006.
We are exploring various construction and purchase options for our anticipated
resource needs in 2015. These options include:
- NORTH DAKOTA GENERATION STUDY. On December 7, 2005, Minnesota Power,
Basin Electric Power Cooperative, Minnkota Power and Montana-Dakota
Utilities Company announced a project development agreement to evaluate
the feasibility of a joint lignite-fueled generating resource in the
vicinity of the existing Milton R. Young generating station near Center,
North Dakota. The feasibility study, which is underway, is expected to
take about one year to complete. Any final resource decision by Minnesota
Power is subject to MPUC and other approvals.
- MESABA ENERGY PROJECT. Excelsior Energy Inc. (Excelsior) is a Minnesota-
based independent energy development company. Excelsior has proposed to
construct a 600 MW (net) coal-gasification generation facility in
northern Minnesota. By utilizing new technology, Excelsior says it will
be able to provide base load electric power supply with fewer emissions
than traditional coal-fired generation facilities. This project is in the
early development stages. Excelsior has yet to obtain necessary permits
and financing, but says the facility could be operational in 2011.
Page 11 ALLETE 2005 Form 10-K
ENERGY - REGULATED UTILITY (CONTINUED)
In 2003, the Minnesota legislature enacted several provisions that
provide Excelsior with special considerations. This was done as part of
Xcel Energy Inc.'s (Xcel) Prairie Island nuclear waste storage
reauthorization. Excelsior is "entitled" to enter into a 450-MW power
sales agreement with Xcel, subject to MPUC approval. On December 23,
2005, Excelsior filed with the MPUC a petition for approval of terms and
conditions for the sale of power to Xcel under these statutory
provisions. Other utilities in the state, including Minnesota Power,
"must consider" Excelsior before pursuing new resource additions within
the state.
On January 30, 2006, Minnesota Power filed comments with the MPUC in
Excelsior's proposed power purchase agreement proceeding. Our comments
focus on the importance to the state of maintaining a range of base load
energy options including multiple fuel types and generating technologies.
- NORTHEAST MINNESOTA FACILITY. A joint study with Minnesota Power, Xcel
and another utility is underway to evaluate the environmental and
economic merits of an advanced design super critical pulverized coal unit
in northeastern Minnesota.
- NATURAL GAS COMBINED CYCLE GENERATION. Minnesota Power is also continuing
to study the feasibility of the construction of a natural gas-fired
electric generating facility which could be located in northwestern
Wisconsin or northeastern Minnesota.
ARROWHEAD REGIONAL EMISSION ABATEMENT (AREA) PLAN. In October 2005, Minnesota
Power announced a $60 million environmental initiative proposing current rate
recovery for emission reductions pursuant to Minnesota statute. If approved by
the MPUC, the AREA plan is expected to significantly reduce emissions from
Taconite Harbor and Laskin. The AREA plan is designed to further reduce
emissions while maintaining a reliable and reasonably-priced energy supply to
meet the needs of our customers. The Company believes that control and abatement
technologies applicable to these plants have matured to the point where further
significant air emission reductions can be attained in a relatively
cost-effective manner.
If approved, Taconite Harbor will employ innovative multi-emission reduction
technology, while Laskin will receive a retrofit focused on lowering NOX
emissions. The Company estimates an emission reduction of over 60% for NOX at
both facilities and a 65% reduction in SO2 at Taconite Harbor. Laskin already
has relatively low emission levels of SO2 due to existing emission reduction
technology. Additionally, with the emerging technology being applied at Taconite
Harbor, there is the potential for a 90% reduction in mercury.
On December 13, 2005, a second filing detailing the rate rider cost recovery for
the plan was submitted to the MPUC. The rate impact on residential and general
service customers is expected to be about 2%, and about 3% for Large Power
Customers when the plan is fully implemented at the end of 2008. We are seeking
approval prior to June 30, 2006, when the statutory authorization for emission
reduction riders sunsets. On January 17, 2006, the MPCA submitted its assessment
of Minnesota Power's AREA plan from an environmental perspective to the MPUC.
The MPCA supports the plan as a cost-effective means of reducing emissions at
Taconite Harbor and Laskin.
CONSERVATION IMPROVEMENT PROGRAMS (CIP). 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 $3.2 million for 2005 ($3.1 million
for 2004; $2.9 million for 2003), with actual spending of $3.6 million in 2005
($3.1 million in 2004; $5.0 million in 2003).
PUBLIC SERVICE COMMISSION OF WISCONSIN. SWL&P's current electric retail rates
are based on a May 2005 PSCW retail rate order that allows for an 11.7% return
on common equity and resulted in an average rate increase of 3.9%. In 2006,
SWL&P plans to file for an increase in rates to be effective beginning in 2007
for its electric, water and gas utility services.
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 were completed in 2005.
Construction commenced in Wisconsin in August 2005, and is scheduled to be
completed in June 2008.
ALLETE 2005 Form 10-K Page 12
ENERGY - REGULATED UTILITY (CONTINUED)
COMPETITION
We believe the overall impact of the EPAct 2005 on the electric utility industry
will be positive and are evaluating the effects on our business as this
legislation is being implemented. This federal legislation is designed to bring
more certainty to energy markets that ALLETE participates in, as well as
provides investment incentives for energy efficiency, energy infrastructure
(such as electric transmission lines) and energy production. The FERC has the
responsibility of implementing numerous new standards as a result of the
promulgation of EPAct 2005. So far the FERC's regulatory efforts appear to be
generally positive for the utility industry.
EPAct 2005's repeal of the PUHCA 1935 should result in more capital flowing into
the industry while providing additional operational flexibility. The PUHCA 1935
repeal may also allow an acceleration of merger activity, although that is
speculative and difficult to predict.
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.
ENERGY - 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 4.5 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 10.) The mining process disturbs and reclaims approximately 210 acres per
year. Laws require 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. Reclamation costs are included in
the cost of coal. 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 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.
NONREGULATED GENERATION. Nonregulated generation is primarily non-rate base
generation sold at market-based rates to the wholesale market.
TACONITE HARBOR. In 2002, we commenced operation of the Taconite Harbor
generating facilities, which we purchased in 2001. The generation output was
primarily sold in the wholesale market and was sold in limited circumstances to
Minnesota Power's retail utility customers.
In October 2005, Minnesota Power proposed to the MPUC a comprehensive solution
to meet generation needs through 2010 that includes transitioning the Taconite
Harbor generating facility from wholesale sales to retail sales to help meet the
utility's forecasted base load energy requirements. With MPUC approval, our
proposal would make the integration of Taconite Harbor into Minnesota Power's
regulated utility business effective retroactive to January 1, 2006. (See
Regulated Utility - Minnesota Public Utilities Commission.)
RAINY RIVER ENERGY has been engaged in the acquisition and development of
nonregulated generation and wholesale power marketing. On April 1, 2005, Rainy
River Energy completed the assignment of its power purchase agreement with
LSP-Kendall Energy, LLC, the owner of an energy generation facility located in
Kendall County, Illinois, to Constellation Energy Commodities. Rainy River
Energy paid Constellation Energy Commodities $73 million in cash to assume the
power purchase agreement, which is in effect through mid-September 2017. The
payment resulted in a charge to our operating income in the second quarter of
2005. The tax benefits of the payment will be realized through a capital loss
carryback for federal income tax purposes and have been recorded as current
deferred income tax assets. The tax benefits are expected to be realized in
2006. In addition, consent, advisory and closing costs of $4.9 million were
incurred to complete the transaction. As a result of this transaction, ALLETE
incurred a $77.9 million ($50.4 million after tax, or $1.84 per diluted share)
charge in 2005.
Page 13 ALLETE 2005 Form 10-K
ENERGY - NONREGULATED ENERGY OPERATIONS (CONTINUED)
RAINY RIVER ENERGY CORPORATION - WISCONSIN continues to study the feasibility of
the construction of a natural gas-fired electric generating facility in
northwestern 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 2005, we sold 1.5 million MWh of nonregulated generation (1.5 million in
2004; 1.5 million in 2003).
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 <F1>
Cloquet Energy Center 5 2001 2001 23
in Cloquet, MN
Rapids Energy Center <F2> 6 & 7 1969, 1980 2000 25
in Grand Rapids, MN
- -----------------------------------------------------------------------------------------------------------------------
Hydro
Conventional Run-of-River
Rapids Energy Center <F2> 4 & 5 1917 2000 1
in Grand Rapids, MN
- -----------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Effective January 1, 2006, the operating assets were transferred to Regulated Utility operations, pending MPUC
approval.
<F2> The net generation is primarily dedicated to the needs of one customer.
</FN>
MINNESOTA LAND. We have about 18,000 acres of land in northern Minnesota, which
is available for sale. We acquired this land in 2001 at the time we purchased
Taconite Harbor from LTV Steel Mining Co. The cost basis of this land was $4.9
million at December 31, 2005.
ENERGY - INVESTMENT IN ATC
In December 2005, ALLETE entered into an agreement with Wisconsin Public Service
Corporation and WPS Investments, LLC that provides for ALLETE, through its
Wisconsin subsidiary Rainy River Energy Corporation - Wisconsin, to invest $60
million in ATC by the end of 2006. ATC is a Wisconsin-based public utility that
owns and maintains electric transmission assets in parts of Wisconsin, Michigan,
Minnesota and Illinois. ATC provides transmission service under rates regulated
by the FERC that are set to further the FERC's policy of establishing the
independent operation and ownership of, and investment in, transmission
facilities. ALLETE's investment is expected to represent an estimated 9%
ownership interest in ATC. The investment by ALLETE's subsidiary in ATC is
subject to review by the PSCW. The FERC approved the transaction in December
2005.
ALLETE 2005 Form 10-K Page 14
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.
ALLETE Properties is focused on acquiring vacant land in the coastal southeast
United States. 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 a third-party brokerage
business, with limited land development activities. Inventory includes
commercial and residential land located in Lehigh Acres and Cape Coral. The
inventory 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
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 district bonds, bank loans and
internally-generated funds. Our three major development projects include Town
Center at Palm Coast, Palm Coast Park and Ormond Crossings.
TOWN CENTER. Town Center 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 2,800
residential units and 3.6 million square feet of commercial 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. The major infrastructure improvements include 3.6
miles of roads, a storm water management system, with lakes and ponds located
throughout the property, and underground utilities. Construction began in March
2005 and is expected to be completed in late 2006.
In March 2005, the Town Center at Palm Coast Community Development District
(Town Center District) issued $26.4 million of tax-exempt, 6% Capital
Improvement Revenue Bonds, Series 2005, due May 1, 2036. The bonds were issued
to fund a portion of the Town Center at Palm Coast development project.
Approximately $21 million of the bond proceeds will be used for construction of
infrastructure improvements at Town Center, with the remaining funds to be used
for capitalized interest, a debt service reserve fund and costs of issuance. The
bonds are payable from and secured by the revenue derived from assessments
imposed, levied and collected by the Town Center District. The assessments
represent an allocation of the costs of the improvements, including bond
financing costs, to the lands within the Town Center District benefiting from
the improvements. The assessments will be included in the annual property tax
bills of landowners beginning in November 2006. To the extent that we still own
land at the time of the assessment, we will recognize an expense for our pro
rata portion of assessments based upon our ownership of benefited property. At
December 31, 2005, we owned approximately 92% of the assessable land in the Town
Center District.
Additional Town Center development costs not funded through Town Center District
bond financing, estimated at approximately $26 million (up to $11 million of
which are reimbursable through traffic impact fee credits), will be financed
with an $8.5 million revolving development loan of Florida Landmark, which is
guaranteed by Lehigh Acquisition Corporation. Florida Landmark is a wholly-owned
subsidiary of Lehigh Acquisition Corporation, which is an 80% owned subsidiary
of ALLETE. The initial term of the revolving development loan is 36 months.
Traffic impact fee credits are provided to the developer as mitigation payments
are made to the city. We are reimbursed after the land is sold and a subsequent
property owner constructs vertical improvements on the site. We recognize
revenue resulting from these reimbursed fees when they are received.
The Town Center District is an independent unit of local government, created and
established in accordance with Florida's Uniform Community Development District
Act of 1980 (Act). The Act provides legal authority for a community development
district to finance the construction of major infrastructure for community
development with general obligation, revenue and special assessment revenue debt
obligations.
Florida Landmark has an agreement with Developers Realty Corporation (DRC) to
develop the first phase of the urban core area of our Town Center. The agreement
also includes the development of a 51-acre commercial retail site. DRC is a
regional commercial developer with strong ties to national retailers and has
experience developing "lifestyle center" projects.
During the initial phase of the Town Center project, our primary focus is to
develop the major infrastructure, most of the development tracts, as well as
plat lots for a variety of uses. The marketing program has targeted an
appropriate blend and quantity of office, commercial, residential and mixed-use
projects. Sites for all land uses that are planned in the initial phase are
already sold or under contract, except adult housing. Negotiations are underway
with several developers that
Page 15 ALLETE 2005 Form 10-K
REAL ESTATE (CONTINUED)
specialize in adult housing units. After the next few years, once the market has
substantially absorbed the land uses that are currently in the design phase,
additional sites will be released for sale in order to maintain an orderly
build-out of Town Center. Pacing the growth of Town Center consistent with
absorption rates for each unit type will assure that our customers, the Town
Center project developers, will be successful. This is expected to create and
maximize value for the developers, end-users and investors.
PALM COAST PARK. Palm Coast Park is a 4,700-acre 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 3.2 million square feet of commercial space and
3,600 residential units ranging from affordable condominium units and apartments
to estate golf homes. Actual build-out will depend on future market conditions.
In December 2004, we received development order approval for the project.
In August 2005, Florida's governor and cabinet voted unanimously to approve the
creation of Palm Coast Park Community Development District. Bonds are expected
to be issued by the district by mid-2006 to fund construction of infrastructure
improvements for the project. The major infrastructure improvements, consisting
primarily of utility extensions and a linear park along the U.S. Highway 1
frontage, are being permitted in anticipation of this bond financing, after
which construction of the improvements will commence.
Platting is underway and is expected to be completed in early 2007. One
residential development tract is under contract and negotiations are underway to
sell two other residential development tracts. Commercial sites will be
available for sale beginning in 2007.
ORMOND CROSSINGS. Ormond Crossings is a 6,000-acre 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.
A Development of Regional Impact (DRI) Application for Development Approval was
submitted in August 2005 to the East Central Florida Regional Planning Council
for the project. Development uses and densities proposed in the DRI include 5
million square feet of commercial opportunities, along with up to 4,400
residential units. We anticipate that the DRI approval process will be concluded
in late 2006, at which time we would receive a Development Order from the City
of Ormond Beach. Engineering, design and permitting will continue through 2007.
It is not anticipated that any sales will be made at Ormond Crossings until
2008.
OTHER LAND. In addition to the major development projects, land inventories in
Florida include 4,200 acres of other property. Several smaller development
projects are under way to plat these properties, add infrastructure and modify
and enhance existing entitlements.
Property sale prices may vary depending on location; physical characteristics;
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. In addition to minimum base price contracts, certain contracts
allow us to receive participation revenue to the extent that an agreed upon
percentage of gross revenue from land sales by our purchaser exceeds the minimum
base price.
ALLETE Properties occasionally provides seller financing. At December 31, 2005,
outstanding finance receivables were $7.4 million, with maturities ranging up to
ten years. These finance receivables accrue interest at market-based rates and
are collateralized by the financed properties.
ALLETE 2005 Form 10-K Page 16
REAL ESTATE (CONTINUED)
SUMMARY OF DEVELOPMENT PROJECTS TOTAL RESIDENTIAL COMMERCIAL
AT DECEMBER 31, 2005 OWNERSHIP ACRES <F1> UNITS <F2> SQ. FT. <F2><F3>
- ---------------------------------------------------------------------------------------------------------------------------
Town Center 80%
At December 31, 2004 1,550 2,950 3,525,000
Property Sold (70) - (643,000)
Change in Estimate <F1> - (117) 45,700
- ---------------------------------------------------------------------------------------------------------------------------
1,480 2,833 2,927,700
- ---------------------------------------------------------------------------------------------------------------------------
Palm Coast Park 100% 4,705 3,600 3,200,000
- ---------------------------------------------------------------------------------------------------------------------------
Ormond Crossings 100%
At December 31, 2004 5,850 <F4> <F4>
Change in Estimate <F1> 110
- ---------------------------------------------------------------------------------------------------------------------------
5,960
- ---------------------------------------------------------------------------------------------------------------------------
12,145 6,433 6,127,700
- ---------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> 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.
<F2> Estimated and includes minority interest. The actual property breakdown at full build-out may be different than
these estimates.
<F3> Includes industrial, office and retail square footage.
<F4> The DRI submitted in August 2005 proposed 4,400 residential units and 5 million square feet of commercial space,
and is subject to approval by regulating governmental entities.
</FN>
SUMMARY OF OTHER LAND INVENTORIES
AT DECEMBER 31, 2005 OWNERSHIP TOTAL MIXED USE RESIDENTIAL COMMERCIAL AGRICULTURAL
- ----------------------------------------------------------------------------------------------------------------------
ACRES <F1>
Palm Coast Holdings 80%
At December 31, 2004 3,099 2,040 513 291 255
Property Sold (533) (348) (167) (10) (8)
- ----------------------------------------------------------------------------------------------------------------------
2,566 1,692 346 281 247
- ----------------------------------------------------------------------------------------------------------------------
Lehigh 80%
At December 31, 2004 1,082 840 140 93 9
Property Sold (469) (450) - (19) -
- ----------------------------------------------------------------------------------------------------------------------
613 390 140 74 9
- ----------------------------------------------------------------------------------------------------------------------
Cape Coral 100%
At December 31, 2004 104 - 1 103 -
Property Sold (63) - - (63) -
- ----------------------------------------------------------------------------------------------------------------------
41 - 1 40 -
- ----------------------------------------------------------------------------------------------------------------------
Other 100%
At December 31, 2004 908 - - - 908
Property Sold (37) - - - (37)
Contributed Land (30) - - - (30)
Change in Estimate <F1> 103 - - - 103
- ----------------------------------------------------------------------------------------------------------------------
944 - - - 944
- ----------------------------------------------------------------------------------------------------------------------
4,164 2,082 487 395 1,200
- ----------------------------------------------------------------------------------------------------------------------
<FN>
<F1> 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 these
estimates.
</FN>
Page 17 ALLETE 2005 Form 10-K
REAL ESTATE (CONTINUED)
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), which
requires counties and cities to adopt comprehensive plans guiding and
controlling future real property development in their respective jurisdictions.
In addition, development projects that exceed certain specified regulatory
thresholds require approval of a comprehensive Development of Regional Impact
(DRI) application. 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.
OTHER
Our Other segment consists of investments in emerging technologies related to
the electric utility industry, and earnings on cash, cash equivalents and
short-term investments.
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 $3.1
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 a loss.
We account for our investment in venture capital funds under the equity method
(see Note 15) and account for our direct investment in privately-held companies
under the cost method because of our ownership percentage. The total carrying
value of our emerging technology portfolio was $9.2 million at December 31, 2005
($13.6 million at December 31, 2004). 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. Our basis in direct investments in
privately-held companies included in the emerging technology portfolio was zero
at December 31, 2005 ($4.5 million at December 31, 2004). In 2005, we recorded
$5.1 million ($3.3 million after tax) of impairments that related to direct
investments in certain privately-held, start-up companies whose future business
prospects had significantly diminished. Developments at these companies
indicated that future commercial viability was unlikely, as was new financing
necessary to continue development. In 2004, we recorded $6.5 million ($4.1
million after tax) of impairments.
ALLETE 2005 Form 10-K Page 18
ENVIRONMENTAL MATTERS
Our businesses are subject to regulation of environmental matters by various
federal, state and local authorities. 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. Due to future stricter environmental requirements through
legislation and/or rulemaking, we anticipate that potential expenditures for
environmental matters will be material and will require significant capital
investments. (See Item 7 - Capital Requirements.) 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. Square Butte, located in North Dakota,
burns lignite coal. All of these facilities are equipped with pollution control
equipment such as scrubbers, bag houses or electrostatic precipitators.
Permitted emission requirements are currently being met. The federal Clean Air
Act Amendments of 1990 (Clean Air Act) created emission allowances for SO2. Each
allowance is an authorization to emit one ton of SO2, and each utility must have
sufficient allowances to cover its annual emissions. Most Minnesota Power
facilities have surplus SO2 emission allowances. Square Butte is meeting its SO2
emission allowance requirements through increased use of its existing scrubber.
During 2005, Taconite Harbor purchased SO2 emission allowances to meet these
requirements. Taconite Harbor does not expect to purchase SO2 emission
allowances in 2006 if the MPUC approves the transfer of its generating assets to
regulated utility operations retroactive to January 1, 2006.
In accordance with the Clean Air Act, the EPA has established NOX limitations
for electric generating units. To meet NOX 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. NOX limitations at Taconite Harbor and Square Butte
are being met by combustion tuning.
CLEAN AIR INTERSTATE RULE AND CLEAN AIR MERCURY RULE. In March 2005, the EPA
announced the final Clean Air Interstate Rule (CAIR) that reduces and
permanently caps emissions of SO2 and NOX in many of the eastern United States.
The CAIR includes Minnesota as one of the 28 states it considers an "eastern"
state. The EPA also announced the final Clean Air Mercury Rule (CAMR) that
reduces and permanently caps electric utility mercury emissions in the
continental United States. The CAIR and the CAMR regulations have been
challenged in the court system, which may delay implementation or modify
provisions. Minnesota Power is participating in a legal challenge to the CAIR,
but is not participating in the challenge of the CAMR. However, if the CAMR and
the CAIR do go into effect, Minnesota Power expects to be required to (1) make
emissions reductions, (2) purchase mercury, SO2 and NOX allowances through the
EPA's cap-and-trade system, or (3) use a combination of both.
We believe that the CAIR contains flaws in its methodology and application,
which will cause Minnesota Power to incur significantly higher compliance costs.
Consequently, on July 11, 2005, Minnesota Power filed a Petition for Review with
the U.S. Court of Appeals for the District of Columbia Circuit. The Company also
filed a Petition for Reconsideration with the EPA. If the litigation and/or the
Petition for Reconsideration are successful, we expect to incur lower compliance
costs, consistent with the rules applicable to those states considered as
"western" states under the CAIR. On November 22, 2005, the EPA agreed to
reconsider certain aspects of its CAIR, including the Minnesota Power petition
addressing modeling used to determine Minnesota's inclusion in the CAIR region
and claims about inequities in the SO2 allowance methodology. The EPA has stated
it anticipates making a decision regarding the petitions in mid-March 2006.
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 would require all such power plants in the United
States to adhere to the EPA maximum achievable control technology (MACT)
standards for mercury. However, on March 15, 2005, the EPA removed electric
utilities from the Section 112(c) list of source categories subject to MACT
requirements, instead referencing how the EPA is regulating utility emissions of
mercury under Section 111 and how the EPA is providing for additional SO2 and
NOX emission reductions that will deliver mercury reductions as a co-benefit of
controls under the March 10, 2005 final CAIR. The EPA has assigned a mercury
emission budget to each state that is based on achieving an approximate 70%
overall reduction in baseline utility mercury emissions by the start of the
second phase of the CAMR in 2018. The MPCA is now required to provide an
implementation plan for EPA approval in 2006, by which time Minnesota will have
determined if it will participate in the EPA's proposed mercury cap and trade
program. The EPA's determination not to list electric utilities under Section
112(c) has already been subjected to court challenge. The Minnesota mercury
emissions budget under the first phase of the CAMR is close to current
emissions. The second phase allocation, effective 2018, will require that
Minnesota sources provide for substantial mercury emission reductions or procure
mercury emission credits from other sources that have a surplus of allowances.
Continuous emission monitoring of mercury stack emissions will be required on
larger units while smaller units with low mercury emissions may not require
continuous monitoring. Minnesota Power is continuing to review the new mercury
rule and considers the outcome of legal challenges as being critical before
specific compliance measures can be established or assessed. Minnesota Power's
Page 19 ALLETE 2005 Form 10-K
ENVIRONMENTAL MATTERS (CONTINUED)
preliminary estimates suggest that all of our affected facilities can be
outfitted with continuous mercury emission monitors for under $2 million. Cost
estimates about mercury cap and trade program impacts are premature at this
time. In October 2005, Minnesota Power announced the AREA plan which, if
approved by the MPUC, includes installing multi-emission reduction technology at
Taconite Harbor that has the potential for a 90% reduction in mercury. (See
Regulatory Issues - Minnesota Public Utilities Commission - Arrowhead Regional
Emission Abatement.)
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. These changes have
been incorporated in Minnesota and have not had a material impact on our
operations. In October 2003, the EPA announced additional changes clarifying the
application of certain sections of the New Source Review rules. 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. These changes are not expected to have a material impact on
Minnesota Power.
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 and
possible significant capital expenditures to comply. Minnkota Power has held
several meetings with the EPA to discuss the alleged violations. Discussions
between Minnkota Power and 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 the 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.
GLOBAL CLIMATE CHANGE. Minnesota Power recognizes the international efforts to
study the science and economic implications of global climate change are a
work-in-progress. While the international forum continues its study and
negotiations to address the complexities of climate change concerns, Minnesota
Power believes it is appropriate to implement voluntary greenhouse gas emissions
reduction or offset measures that are consistent with peer-reviewed climate
science, provide a continued supply of competitive, low-cost power to our
customers, and continue responsible environmental stewardship. As of 2004,
Minnesota Power estimates that we offset the equivalent of over one million tons
of carbon dioxide annually, or about 9% of the greenhouse gas emissions
associated with the supply of electricity to its Minnesota retail customers.
Minnesota Power has been a participant along with other utilities in the
voluntary U.S. Department of Energy's Climate Challenge program since its
inception in 1991. The program is dedicated to the development of innovative
programs to reduce, limit, avoid or offset emissions of greenhouse gases.
Minnesota Power also supports Power Partners, a new voluntary program that is
replacing the Climate Challenge program.
Minnesota Power is voluntarily submitting annual reports to the U.S. Department
of Energy on activities outlined in Minnesota Power's Climate Challenge
Participation Accord. Minnesota Power implemented measures that helped improve
the energy efficiency of our generation and the energy used by our customers,
increased our use of renewable hydroelectric generation, wind and wood waste
fuel, established a waste paper recycling facility that reduces the demand on
forest resources and landfills and helped establish a tree planting program in
Minnesota that will mediate greenhouse gas emissions while providing Minnesota
with another tool for good forestry management.
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. We have obtained all necessary
NPDES permits, including NPDES storm water permits for applicable facilities, to
conduct our 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. 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. In connection with such approval, the FERC would 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 $750,000, 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. Beginning in 1996, and most recently in
February 2006, 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 the settlement agreement.
ALLETE 2005 Form 10-K Page 20
ENVIRONMENTAL MATTERS (CONTINUED)
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 reduce fish
mortality due to 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). The new rule
for fish impingement mortality 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 timeframe. The biological studies were initiated in
2005. 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. At this time, we cannot
estimate the capital and/or aquatic restoration expenditures that may be
required to comply with the Section 316(b) Phase II Rule.
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. We are required to notify the EPA of hazardous waste activity and,
consequently, routinely submit the necessary reports to the EPA. State
environmental agencies are responsible for administering solid and hazardous
waste rules on the local level with oversight by the EPA. We are in material
compliance with these rules.
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 replaced its
remaining PCB capacitor banks in 2005. It is expected that PCB-contaminated oil
in substation equipment will be largely replaced by the end of 2006. The total
cost is expected to be about $2 million, of which $1.6 million was spent through
December 31, 2005.
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 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. 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 was to determine any impact to soil or
ground water between the former MGP site and Superior Bay. Site work for this
phase of the investigation was performed during October 2004, and the final
report was sent to the WDNR in March 2005. Additional site investigation was
performed during September and October 2005. It is anticipated that additional
site work will be performed in 2006. 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. The Company has 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. In May
2005, the PSCW approved the collection through rates of $150,000 of site
investigation costs that had been incurred at the time SWL&P filed their most
recent rate request. 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 the
Company continues to work with the insurer to determine the availability of
insurance coverage.
EMPLOYEES
At December 31, 2005, ALLETE had 1,500 employees, of which 1,400 were full-time.
Minnesota Power and SWL&P have 597 employees who are members of the
International Brotherhood of Electrical Workers (IBEW), Local 31. The labor
agreements with Local 31 expired on January 31, 2006, and a tentative agreement
has been reached. The members of IBEW Local 31 are expected to vote on the
tentative agreement by the end of February 2006.
BNI Coal has 94 employees who are members of the IBEW Local 1593. BNI Coal and
Local 1593 have a labor agreement, which expires on March 31, 2008.
Page 21 ALLETE 2005 Form 10-K
EXECUTIVE OFFICERS OF THE REGISTRANT
EXECUTIVE OFFICERS INITIAL EFFECTIVE DATE
- ---------------------------------------------------------------------------------------------------------------------------
DONALD J. SHIPPAR, AGE 56
Chairman, President and Chief Executive Officer January 1, 2006
President and Chief Executive Officer 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 40
Senior Vice President, General Counsel and Secretary January 1, 2006
Vice President, General Counsel and Secretary March 8, 2004
WARREN L. CANDY, AGE 56
Senior Vice President - Utility Operations February 1, 2004
LAURA A. HOLQUIST, AGE 44
President - ALLETE Properties September 6, 2001
DAVID J. MCMILLAN, AGE 44
Senior Vice President - Marketing, Regulatory and Public Affairs - ALLETE and
Executive Vice President - Minnesota Power January 1, 2006
Senior Vice President - Marketing and Public Affairs October 2, 2003
MARK A. SCHOBER, AGE 50
Senior Vice President and Controller February 1, 2004
Vice President and Controller April 18, 2001
Controller March 1, 1993
DONALD W. STELLMAKER, AGE 48
Treasurer July 24, 2004
TIMOTHY J. THORP, AGE 51
Vice President - Investor Relations July 1, 2004
Vice President - Investor Relations and Corporate Communications November 16, 2001
JAMES K. VIZANKO, AGE 52
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 53
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 ALLETE Properties.
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 9, 2006.
ALLETE 2005 Form 10-K Page 22
ITEM 1A. RISK FACTORS
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.
OUR RESULTS OF OPERATIONS COULD BE NEGATIVELY IMPACTED IF OUR LARGE POWER
CUSTOMERS EXPERIENCE AN ECONOMIC DOWN CYCLE OR FAIL TO COMPETE EFFECTIVELY IN
THE GLOBAL ECONOMY.
Our 12 Large Power Customers account for approximately 32% of our 2005
consolidated operating revenue (one of these customers alone accounts for more
than 11%). These customers are involved in cyclical industries that by nature
are adversely impacted by economic downturns and are subject to strong
competition in the global marketplace. An economic downturn or failure to
compete effectively in the global economy could have a material adverse effect
on their operations and, consequently, could negatively impact our results of
operations and the communities that 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
and other factors.
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, 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 our 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 10.)
Page 23 ALLETE 2005 Form 10-K
RISK FACTORS (CONTINUED)
THE OPERATION AND MAINTENANCE OF OUR GENERATING FACILITIES INVOLVE 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, 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,
increased expenses or both. 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 operating at peak efficiency.
This equipment is also likely to require periodic upgrading and improvement.
(See Item I - Environmental Matters). 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 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, and 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.
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;
- 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,
or crude oil and refined products;
- natural disasters, wars, sabotage, terrorist acts or other catastrophic
events; and
- federal, state, local and foreign energy, environmental, or 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
expired on January 31, 2006, and a tentative agreement has been reached. The
members of IBEW Local 31 are expected to vote on the tentative agreement by the
end of February 2006. The labor agreement with Local 1593 at BNI Coal expires on
March 31, 2008.
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.
ALLETE 2005 Form 10-K Page 24
RISK FACTORS (CONTINUED)
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.
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, sewage, 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 future 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.
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.
THE OCCURRENCE OF NATURAL DISASTERS IN FLORIDA COULD ADVERSELY AFFECT OUR
BUSINESS.
The occurrence of natural disasters in Florida, such as hurricanes, floods,
fires, unusually heavy or prolonged rain or droughts, could have a material
adverse effect on our ability to develop and sell properties or realize income
from our projects. The occurrence of natural disasters could also cause
increases in property insurance rates and deductibles, which could reduce demand
or selling price for our properties.
Page 25 ALLETE 2005 Form 10-K
RISK FACTORS (CONTINUED)
RISKS ASSOCIATED WITH ACQUISITIONS MAY HINDER OUR ABILITY TO INCREASE REVENUE
AND EARNINGS.
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 support services 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.
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 AND TO COMPLY WITH REGULATIONS IN A COST-EFFECTIVE MANNER. 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. With increasing regulatory
requirements related to our operations, technology is also a key component to
achieving and monitoring compliance. 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.
ALLETE 2005 Form 10-K Page 26
RISK FACTORS (CONTINUED)
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 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 for federal purposes, and fifteen succeeding
years for Minnesota. As of December 31, 2005, we have, where appropriate,
recorded an allowance against our deferred tax assets associated with realized
capital losses, and 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.
IF WE ARE NOT ABLE TO REPLACE OUR MATURE WORKFORCE WITH QUALIFIED PERSONNEL, WE
MAY NOT BE ABLE TO OPERATE AND MAINTAIN OUR BUSINESS AND THE RESULTS OF OUR
OPERATIONS WOULD BE NEGATIVELY IMPACTED.
The success of our business also depends on our talented workforce that operates
and maintains our business and processes. If we are unable to attract and retain
new personnel to replace our mature workforce, we may not be able to
successfully operate and manage our business or achieve our business objectives.
We may have difficulty effectively and efficiently running our business
operations, maintaining existing services, meeting regulatory requirements,
developing new services and providing acceptable levels of customer service.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
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 materially change 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 2005.
Page 27 ALLETE 2005 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 $0.3625 per share on our common stock will be paid on
March 1, 2006, to the holders of record on February 15, 2006. Our common stock
is listed on the New York Stock Exchange under the symbol ALE and our CUSIP
number is 018522300. 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 2005, we paid out 259% of our per
share earnings in dividends. The payout ratio in 2005 was impacted by a $1.84
per diluted share charge to assign the Kendall County power purchase agreement
to Constellation Energy Commodities in April 2005. (See Note 11.)
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, 2005, no retained earnings were
restricted as a result of these provisions. At February 1, 2006, there were
approximately 32,000 common stock shareholders of record.
2005 2004
------------------------------------------------------------------------------------------
PRICE RANGE DIVIDENDS PRICE RANGE <F1> DIVIDENDS
QUARTER HIGH LOW PAID HIGH LOW PAID <F2>
- ---------------------------------------------------------------------------------------------------------------------------
First $44.40 $35.65 $0.3000 $35.52 $30.00 $0.8475
Second 50.33 40.12 0.3150 36.71 31.62 0.8475
Third 51.70 42.80 0.3150
July 1 - Sept. 20 33.70 26.02 0.8475
Sept. 21 - Sept. 30 32.54 30.76 -
Fourth 47.36 41.28 0.3150 37.46 32.20 0.3000
- ---------------------------------------------------------------------------------------------------------------------------
Annual Total $1.2450 $2.8425
- ---------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Price ranges prior to September 21, 2004, are not comparable due to the spin-off of Automotive Services on September
20, 2004, (see Note 14) and do not reflect the one-for-three reverse stock split (see Note 8).
<F2> Adjusted for the September 20, 2004, one-for-three reverse stock split.
</FN>
We did not repurchase any ALLETE common stock during the fourth quarter of 2005.
ALLETE 2005 Form 10-K Page 28
ITEM 6. SELECTED FINANCIAL DATA
Operating results of our Water Services businesses, our Automotive Services
business, our telecommunications business and our retail stores are included in
discontinued operations, and accordingly, amounts have been restated for all
periods presented. (See Note 14.) 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.
2005 2004 2003 2002 2001
- --------------------------------------------------------------------------------------------------------------------------
MILLIONS
BALANCE SHEET
Assets
Current Assets $ 373.5 $ 355.0 $ 216.1 $ 184.8 $ 313.7
Discontinued Operations - Current 0.4 13.1 483.9 477.3 581.8
Property, Plant and Equipment 860.4 849.6 888.2 852.0 851.6
Investments 117.7 124.5 175.7 170.9 155.4
Other Assets 44.6 52.8 59.0 61.9 67.3
Discontinued Operations - Other 2.2 36.4 1,278.4 1,400.3 1,312.7
- --------------------------------------------------------------------------------------------------------------------------
$1,398.8 $1,431.4 $3,101.3 $ 3,147.2 $3,282.5
- --------------------------------------------------------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current Liabilities $ 106.7 $ 91.7 $ 182.1 $ 436.2 $ 340.5
Discontinued Operations - Current 13.0 24.5 344.1 302.0 364.0
Long-Term Debt 387.8 389.4 513.9 566.9 835.2
Mandatorily Redeemable Preferred Securities - - - 75.0 75.0
Other Liabilities 288.5 295.3 300.1 292.2 271.6
Discontinued Operations - - 300.9 242.5 252.4
Shareholders' Equity 602.8 630.5 1,460.2 1,232.4 1,143.8
- --------------------------------------------------------------------------------------------------------------------------
$1,398.8 $1,431.4 $3,101.3 $ 3,147.2 $3,282.5
- --------------------------------------------------------------------------------------------------------------------------
INCOME STATEMENT
Operating Revenue
Regulated Utility $575.6 $555.0 $510.0 $497.9 $535.0
Nonregulated Energy Operations 113.9 106.8 106.6 84.7 50.4
Real Estate 47.5 41.9 42.6 33.6 61.1
Other 0.4 0.4 0.4 0.3 0.4
- --------------------------------------------------------------------------------------------------------------------------
737.4 704.1 659.6 616.5 646.9
- --------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Fuel and Purchased Power 273.1 286.2 252.5 234.8 230.7
Operating and Maintenance 293.5 270.1 260.5 254.4 257.3
Kendall County Charge 77.9 - - - -
Depreciation 47.8 46.9 48.9 47.0 45.2
- --------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 692.3 603.2 561.9 536.2 533.2
- --------------------------------------------------------------------------------------------------------------------------
Operating Income from Continuing Operations 45.1 100.9 97.7 80.3 113.7
- --------------------------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest Expense (26.4) (31.7) (50.5) (49.3) (47.7)
Other 1.1 (12.2) 2.3 6.9 16.6
- --------------------------------------------------------------------------------------------------------------------------
Total Other Expense (25.3) (43.9) (48.2) (42.4) (31.1)
- --------------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations
Before Minority Interest and Income Taxes 19.8 57.0 49.5 37.9 82.6
Minority Interest 2.7 2.1 2.6 1.0 1.2
- --------------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations
Before Income Taxes 17.1 54.9 46.9 36.9 81.4
Income Tax Expense (Benefit) (0.5) 16.4 17.7 12.3 28.7
- --------------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations Before
Change in Accounting Principle 17.6 38.5 29.2 24.6 52.7
Income (Loss) from Discontinued Operations - Net of Tax (4.3) 73.7 207.2 112.6 86.0
Change in Accounting Principle - Net of Tax - (7.8) - - -
- --------------------------------------------------------------------------------------------------------------------------
Net Income 13.3 104.4 236.4 137.2 138.7
Common Stock Dividends 34.4 79.7 93.2 89.2 81.8
- --------------------------------------------------------------------------------------------------------------------------
Earnings Retained in (Distributed from) Business $(21.1) $ 24.7 $143.2 $ 48.0 $ 56.9
- --------------------------------------------------------------------------------------------------------------------------
Page 29 ALLETE 2005 Form 10-K
2005 2004 2003 2002 2001
- ---------------------------------------------------------------------------------------------------------------------------
Shares Outstanding - Millions
Year-End 30.1 29.7 29.1 28.5 28.0
Average <F1>
Basic 27.3 28.3 27.6 27.0 25.3
Diluted 27.4 28.4 27.8 27.2 25.5
Diluted Earnings (Loss) Per Share
Continuing Operations $0.64 <F2><F3> $1.35 <F4> $1.05 $0.91 <F6> $2.07 <F7>
Discontinued Operations (0.16) 2.59 7.47 <F5> 4.13 3.37
Change in Accounting Principle - (0.27) - - -
- ---------------------------------------------------------------------------------------------------------------------------
$0.48 $3.67 $8.52 $5.04 $5.44
- ---------------------------------------------------------------------------------------------------------------------------
Return on Common Equity 2.2% <F2><F3> 8.3% 17.7% 11.4% 13.3%
Common Equity Ratio 60.7% 61.7% 64.4% 51.7% 49.9%
Dividends Paid Per Share $1.2450 $2.8425 $3.3900 $3.3000 $3.2100
Dividend Payout 259% <F2><F3> 77% 40% 66% 59%
Book Value Per Share at Year-End $20.03 $21.23 $50.18 $43.24 $40.85
Employees at Year-End 1,459 1,515 13,115 14,181 13,763
Income (Loss) <F8>
Regulated Utility $ 45.7 $ 37.7 $ 32.4 $ 46.0 $ 45.3
Nonregulated Energy Operations (48.5) <F2> (2.9) 1.1 (11.3) <F6> (0.6)
Real Estate 17.5 14.3 13.6 10.8 20.4 <F7>
Other 2.9 <F3> (10.6) <F4> (17.9) (20.9) (12.4)
- ---------------------------------------------------------------------------------------------------------------------------
Continuing Operations 17.6 38.5 29.2 24.6 52.7
Discontinued Operations (4.3) 73.7 207.2 <F5> 112.6 86.0
Change in Accounting Principle - (7.8) - - -
- ---------------------------------------------------------------------------------------------------------------------------
Net Income $ 13.3 $104.4 $236.4 $137.2 $138.7
- ---------------------------------------------------------------------------------------------------------------------------
Average Electric Customers - Thousands 151.8 150.1 148.2 146.8 145.7
Electric Sales - Millions of MWh
Regulated Utility 11.7 11.2 11.1 11.1 10.9
Nonregulated Energy Operations 1.5 1.5 1.5 1.2 0.2
Company Use and Losses 0.5 0.9 0.7 0.7 0.7
- ---------------------------------------------------------------------------------------------------------------------------
13.7 13.6 13.3 13.0 11.8
- ---------------------------------------------------------------------------------------------------------------------------
Power Supply - Millions of MWh
Regulated Utility
Steam Generation 7.2 6.5 7.1 7.2 6.9
Hydro Generation 0.5 0.5 0.4 0.5 0.5
Long-Term Purchases - Square Butte 2.3 2.0 2.3 2.3 1.9
Purchased Power 2.1 3.0 1.9 1.8 2.3
- ---------------------------------------------------------------------------------------------------------------------------
12.1 12.0 11.7 11.8 11.6
- ---------------------------------------------------------------------------------------------------------------------------
Nonregulated Energy Operations
Steam 1.3 1.2 1.2 0.8 -
Hydro 0.1 0.1 0.1 0.1 0.2
Purchased Power 0.2 0.3 0.3 0.3 -
- ---------------------------------------------------------------------------------------------------------------------------
1.6 1.6 1.6 1.2 0.2
- ---------------------------------------------------------------------------------------------------------------------------
13.7 13.6 13.3 13.0 11.8
- ---------------------------------------------------------------------------------------------------------------------------
Coal Sold - Millions of Tons 4.5 4.2 4.3 4.6 4.1
Real Estate Sales
Town Center - Commercial Square Feet 643,000 - - - -
EQUIVALENT ACRES 70 - - - -
Other Land - Acres 1,102 1,479 1,394 641 N/A
Lots 7 211 265 1,425 N/A
- ---------------------------------------------------------------------------------------------------------------------------
Capital Expenditures - Millions
Continuing Operations $58.6 $57.8 $ 68.7 $ 81.7 $ 51.0
Discontinued Operations 4.5 21.4 67.6 119.5 98.2
- ---------------------------------------------------------------------------------------------------------------------------
$63.1 $79.2 $136.3 $201.2 $149.2
- ---------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Excludes unallocated ESOP shares.
<F2> Impacted by a $50.4 million, or $1.84 per share, charge related to the assignment of the Kendall County power
purchase agreement.
<F3> Impacted by a $2.5 million, or $0.09 per share, deferred tax benefit due to comprehensive tax planning initiatives
and a $3.7 million, or $0.13 per share, current tax benefit due to a positive resolution of income tax audit issues.
<F4> 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 Automotive Services and an $11.5 million, or $0.41 per share, gain
on the sale of ADESA shares related to the Company's ESOP.
<F5> Included a $71.6 million, or $2.59 per share, gain on the sale of the Water Services businesses.
<F6> Included a $5.5 million, or $0.20 per share, charge related to the indefinite delay of a generation project in
Superior, Wisconsin.
<F7> Included an $11.1 million, or $0.45 per share, gain on the sale of the Company's largest single real estate
transaction ever.
<F8> In 2005, we began allocating corporate charges and interest expense to our business segments. For comparative
purposes, segment information for prior periods has been restated to reflect the new allocation method.
</FN>
ALLETE 2005 Form 10-K Page 30
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. Readers are
cautioned that forward-looking statements should be read in conjunction with our
disclosures in this Form 10-K under the headings: "Safe Harbor Statement Under
the Private Securities Litigation Reform Act of 1995" located on page 3 and
"Risk Factors" located in Item 1A. 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.
EXECUTIVE SUMMARY
In 2005, ALLETE's operations were 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 our coal mining activities in North Dakota and nonregulated
generation (non-rate base generation sold at market-based rates to the wholesale
market) primarily from Taconite Harbor in northern Minnesota. Nonregulated
Energy Operations also included generation secured through the Kendall County
power purchase agreement, which was assigned to Constellation Energy Commodities
in April 2005. REAL ESTATE includes our Florida real estate operations. OTHER
includes our investments in emerging technologies, and earnings on cash, cash
equivalents and short-term investments. DISCONTINUED OPERATIONS includes our
Automotive Services business, costs incurred by ALLETE associated with the
spin-off of ADESA, our Water Services businesses and our telecommunications
business.
In 2005, ALLETE was successful both financially and operationally with our
utility power sales higher across all customer classes and robust Florida real
estate sales. We also achieved a number of milestones and accomplished important
strategic objectives, which included:
- Assigning the Kendall County power purchase agreement to Constellation
Energy Commodities, which eliminated projected after-tax operating losses
of approximately $8 million per year;
- Entering into an agreement to invest $60 million in ATC by the end of
2006, which is expected to be a significant and consistent earnings
contributor in our energy business;
- Extending electric contracts with five of our Minnesota Power customers
in the taconite processing, and paper and pulp industries for an
additional four to eight years;
- Announcing a $60 million plan to reduce air emissions at two generating
stations while requesting current cost recovery;
- Entering an agreement to purchase renewable energy from a new wind
facility to be built in North Dakota and continuing to pursue the
purchase of renewable energy from a new wind facility being planned for
northern Minnesota;
- Recording our first real estate sales at the Town Center development
project, signing our first sales contract for the Palm Coast Park
development, and beginning the Development of Regional Impact process for
Ormond Crossings, our third major real estate development;
- Completing the exit from our Water Services businesses by selling our
wastewater assets in Georgia; and
- Selling our telecommunications business, Enventis Telecom, a transaction
that provided approximately $29 million in cash.
Page 31 ALLETE 2005 Form 10-K
EXECUTIVE SUMMARY (CONTINUED)
2005 2004 2003
- --------------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT PER SHARE AMOUNTS
Operating Revenue
Regulated Utility $575.6 $555.0 $510.0
Nonregulated Energy Operations 113.9 106.8 106.6
Real Estate 47.5 41.9 42.6
Other 0.4 0.4 0.4
- --------------------------------------------------------------------------------------------------------------------------
$737.4 $704.1 $659.6
- --------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Regulated Utility $486.0 $476.3 $439.1
Nonregulated Energy Operations 186.6 <F1> 108.6 102.2
Real Estate 15.6 15.1 16.4
Other 4.1 3.2 4.2
- --------------------------------------------------------------------------------------------------------------------------
$692.3 $603.2 $561.9
- --------------------------------------------------------------------------------------------------------------------------
Interest Expense
Regulated Utility $17.4 $18.5 $20.4
Nonregulated Energy Operations 6.6 4.9 4.8
Real Estate 0.1 0.3 0.2
Other 2.3 8.0 25.1
- --------------------------------------------------------------------------------------------------------------------------
$26.4 $31.7 $50.5
- --------------------------------------------------------------------------------------------------------------------------
Other Income (Expense)
Regulated Utility $0.7 $0.1 $2.9
Nonregulated Energy Operations 1.7 0.6 1.9
Other (1.3) (12.9) <F3> (2.5)
- --------------------------------------------------------------------------------------------------------------------------
$1.1 $(12.2) $2.3
- --------------------------------------------------------------------------------------------------------------------------
Income (Loss)
Regulated Utility $ 45.7 $ 37.7 $ 32.4
Nonregulated Energy Operations (48.5) <F1> (2.9) 1.1
Real Estate 17.5 14.3 13.6
Other 2.9 <F2> (10.6) <F3> (17.9)
- --------------------------------------------------------------------------------------------------------------------------
Continuing Operations 17.6 38.5 29.2
Discontinued Operations (4.3) 73.7 207.2
Change in Accounting Principle - (7.8) -
- --------------------------------------------------------------------------------------------------------------------------
Net Income $ 13.3 $104.4 $236.4
- --------------------------------------------------------------------------------------------------------------------------
Diluted Average Shares of Common Stock 27.4 28.4 27.8
- --------------------------------------------------------------------------------------------------------------------------
Diluted Earnings (Loss) Per Share of Common Stock
Continuing Operations $0.64 <F1><F2> $1.35 <F3> $1.05
Discontinued Operations (0.16) 2.59 7.47
Change in Accounting Principle - (0.27) -
- --------------------------------------------------------------------------------------------------------------------------
$0.48 $3.67 $8.52
- --------------------------------------------------------------------------------------------------------------------------
Return on Common Equity 2.2% <F1><F2> 8.3% 17.7%
- --------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Impacted by a $77.9 million ($50.4 million after tax, or $1.84 per share) charge related to the assignment of the
Kendall County power purchase agreement in April 2005. (See Note 11.)
<F2> Impacted by a $2.5 million, or $0.09 per share, deferred tax benefit due to comprehensive tax planning initiatives
and a $3.7 million, or $0.13 per share, current tax benefit due to a positive resolution of income tax audit
issues.
<F3> Included an $18.5 million ($10.9 million after tax, or $0.38 per share) debt prepayment cost incurred as part of
ALLETE's financial restructuring in preparation for the spin-off of Automotive Services and an $11.5 million, or
$0.41 per share, gain on the sale of ADESA shares related to our ESOP.
</FN>
In 2005, we began allocating corporate charges and interest expense to our
business segments. For comparative purposes, segment information for 2004 and
2003 has been restated to reflect the new allocation method used in 2005 for
corporate charges and interest expense. This restatement had no impact on
consolidated net income or earnings per share.
ALLETE 2005 Form 10-K Page 32
EXECUTIVE SUMMARY (CONTINUED)
Reported net income in total for 2005 was $13.3 million, or $0.48 per diluted
share ($104.4 million, or $3.67 per diluted share for 2004; $236.4 million, or
$8.52 per diluted share for 2003). In 2005, a $50.4 million, or $1.84 per
diluted share, charge to assign our Kendall County power purchase agreement to
Constellation Energy Commodities (see Note 11) reduced net income, as did the
absence of operations from our Automotive Services business spun off in
September 2004 and the exit from our Water Services businesses, the majority of
which were sold in 2003. Automotive Services contributed $74.4 million to income
in 2004 ($113.6 million in 2003). Net income in 2003 included a $71.6 million
net gain on the sale of substantially all of our Water Services assets. A $7.8
million non-cash after-tax charge for a change in accounting principle related
to investments in our emerging technology portfolio also impacted 2004 net
income. (See Note 15.)
Net income in 2005 reflected continued strong electric sales, higher Florida
real estate sales, increased earnings on excess cash, the benefits of lower
interest expense due to reduced debt balances, expense reductions following the
spin-off of Automotive Services and exit from the Water Services businesses in
2004, tax savings due to comprehensive tax planning initiatives implemented in
2005, and positive resolution of income tax audit issues.
Earnings per share for 2005 were favorably impacted by ALLETE common stock
purchased pursuant to the Company's Retirement Savings and Stock Ownership Plan.
(See Note 18.)
Financial results for continuing operations for the periods discussed in this
Form 10-K were significantly impacted by the following five transactions not
representative of ongoing operations:
- KENDALL COUNTY CHARGE. In 2005, we incurred a $77.9 million ($50.4
million after tax, or $1.84 per share) charge due to the assignment of
the Kendall County power purchase agreement to Constellation Energy
Commodities (Kendall County Charge).
- POSITIVE RESOLUTION OF TAX AUDIT ISSUES. In 2005, we recognized a $3.7
million, or $0.13 per share, current tax benefit due to a positive
resolution of income tax audit issues.
- TAX PLANNING INITIATIVES. In 2005, we implemented comprehensive tax
planning initiatives, which resulted in current and ongoing tax savings,
and a deferred tax benefit of $2.5 million, or $0.09 per share.
- DEBT PREPAYMENT COST. In 2004, we incurred an $18.5 million ($10.9
million after tax, or $0.38 per share) debt prepayment cost as part of
ALLETE's financial restructuring in preparation for the spin-off of
Automotive Services.
- GAIN ON SALE OF 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 18.)
Reported income from continuing operations before the change in accounting
principle was $17.6 million, or $0.64 per diluted share, for 2005, a decrease of
$20.9 million, or $0.71 per diluted share from 2004. The decrease was attributed
to the $50.4 million, or $1.84 per diluted share, Kendall County Charge. A 4%
increase in total electric sales, higher Florida real estate land sales, a $1.9
million increase in earnings on excess cash, a $3.1 million decrease in interest
expense and expense reductions following the spin-off of Automotive Services and
exit from our Water Services businesses in 2004 partially offset the negative
impact of the Kendall County Charge. In addition, comprehensive tax planning
initiatives implemented in 2005 resulted in current and ongoing tax savings, and
a deferred tax benefit equaling $2.5 million, or $0.09 per share. We also
recognized $3.7 million, or $0.13 per share, current tax benefit due to a
positive resolution of income tax audit issues.
2005 2004 2003
- --------------------------------------------------------------------------------------------------------------------------
MILLIONS
Kilowatthours Sold
Regulated Utility
Retail and Municipals
Residential 1,102 1,053 1,065
Commercial 1,327 1,282 1,286
Industrial 7,130 7,071 6,558
Municipals 877 823 842
Other 79 79 79
- --------------------------------------------------------------------------------------------------------------------------
10,515 10,308 9,830
Other Power Suppliers 1,142 918 1,314
- --------------------------------------------------------------------------------------------------------------------------
11,657 11,226 11,144
Nonregulated Energy Operations 1,521 1,496 1,462
- --------------------------------------------------------------------------------------------------------------------------
13,178 12,722 12,606
- --------------------------------------------------------------------------------------------------------------------------
Page 33 ALLETE 2005 Form 10-K
EXECUTIVE SUMMARY (CONTINUED)
2005 2004 2003
---------------------------------------------------------------------------------------
REAL ESTATE
REVENUE AND SALES ACTIVITY QTY AMOUNT QTY AMOUNT QTY AMOUNT
- --------------------------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS
Revenue from Land Sales
Town Center Sales
Commercial Sq. Ft. 643,000 <F1> $15.2 - - - -
Other Land Sales
Acres 1,102 38.1 1,479 $32.8 1,394 $32.0
Lots 7 0.4 211 4.5 265 4.0
- --------------------------------------------------------------------------------------------------------------------------
Contract Sales Price <F2> 53.7 37.3 36.0
Deferred Revenue (10.0) (1.5) -
Adjustments <F3> (1.7) - -
- --------------------------------------------------------------------------------------------------------------------------
Revenue from Land Sales 42.0 35.8 36.0
Other Revenue 5.5 6.1 6.6
- --------------------------------------------------------------------------------------------------------------------------
$47.5 $41.9 $42.6
- --------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> For the year ended December 31, 2005, 70 acres were sold.
<F2> Reflected total contract sales price on closed land transactions. Land sales are recorded using a percentage-of-
completion method. (See Critical Accounting Policies and Note 2.)
<F3> Contributed development dollars, which are credited to cost of real estate sold.
</FN>
NET INCOME
REGULATED UTILITY contributed income of $45.7 million in 2005 ($37.7 million in
2004; $32.4 million in 2003). Income was higher in 2005 due to a 4% increase in
overall regulated utility kilowatthour electric sales. Healthier economic
conditions in Minnesota Power's service territory combined with warmer weather
in the summer of 2005 contributed to the increase in kilowatthour sales. Higher
pension expense ($1.0 million) and an increase in maintenance expense ($2.0
million) were partially offset by the absence of Split Rock Energy expenses
($1.2 million), and lower interest expense ($0.6 million).
Overall, regulated utility kilowatthour electric sales in 2004 were similar to
2003. Sales to retail and municipal customers were up 5% from 2003, which
reduced the energy available for sale to other power suppliers in 2004. The
increase in retail and municipal sales was due to an 8% increase in sales to
industrial customers as a result of our industrial customers operating at high
production levels, with taconite and paper production at or near capacity.
In 2003, Regulated Utility income also included $1.7 million of equity income
from Split Rock Energy, a joint venture which we terminated in March 2004.
Equity income from Split Rock Energy in 2003 included a $2.3 million charge to
exit the joint venture.
NONREGULATED ENERGY OPERATIONS reported a $48.5 million loss in 2005 (loss of
$2.9 million in 2004; income of $1.1 million in 2003), reflecting the $50.4
million charge to assign the Kendall County power purchase agreement to
Constellation Energy Commodities in April 2005. The absence of operating losses
from Kendall County favorably impacted 2005 financial results. Kendall County
operating losses were $1.9 million in 2005 ($8.5 million in 2004; $8.2 million
in 2003). In 2004, the Kendall County operating loss included a $0.7 million
cost to terminate a transmission contract.
Income from Taconite Harbor was lower in 2005 than 2004, reflecting increased
demand revenue offset by higher operating expenses. Demand revenue was higher
primarily as a result of two new 5-year contracts. Contract services were up
$0.6 million from 2004 as a result of a longer than anticipated scheduled outage
as well as unscheduled outages in 2005. SO2 emission allowances expense was up
$1.3 million from 2004. Depreciation expense was up $0.7 million as a result of
capitalized projects being completed and placed into operation. Income at
Taconite Harbor was lower in 2004 than 2003, primarily due to a $0.8 million
increase in costs associated with a scheduled maintenance outage in 2004 and a
$0.5 million increase in costs for SO2 emission allowances. In addition,
wholesale power prices were lower in 2004 compared to 2003.
In 2005, income from our coal operations was up $1.3 million from 2004,
primarily due to a 7% increase in tons of coal sold. In 2004, coal sales were
lower than 2003 due to an outage at the Square Butte generating facility, BNI
Coal's primary customer.
ALLETE 2005 Form 10-K Page 34
NET INCOME (CONTINUED)
REAL ESTATE contributed income of $17.5 million in 2005 ($14.3 million in 2004;
$13.6 million in 2003), reflecting continued strong demand for real estate in
Florida. In 2005, we also began selling property from our Town Center
development project in northeast Florida. Since land is being sold before
completion of the project infrastructure, revenue and cost of real estate sold
are recorded using a percentage-of-completion method. (See Note 2.) As of
December 31, 2005, we had $8.6 million of deferred profit on sales of real
estate, before taxes and minority interest, on our balance sheet. We expect most
of this deferred profit will be reflected in income during the next 12 months.
The timing of the closing of real estate sales varies from period to period and
impacts comparisons between years.
At December 31, 2005, total pending land sales under contract were $94.9 million
and are anticipated to close at various times through 2012. Pricing on these
contracts range from $20 to $50 per commercial square foot, $15,000 to $40,000
per residential unit and $1,000 to $524,000 per acre for all other properties.
Prices per acre are stated on a gross acreage basis and are dependent on the
type and location of the properties sold. The majority of the other properties
under contract are zoned commercial or mixed use. In addition to minimum base
price contracts, certain contracts allow us to receive participation revenue to
the extent that an agreed upon percentage of gross revenue from land sales by
our purchaser exceeds the minimum base price.
REAL ESTATE
PENDING CONTRACTS CONTRACT
AT DECEMBER 31, 2005 QUANTITY SALES PRICE
- ---------------------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS
Town Center
Commercial Sq. Ft. 1,321,200 $38.2
Residential Units 1,212 25.5
Palm Coast Park
Residential Units 500 7.5
Other Land
Acres 1,116 23.7
- ---------------------------------------------------------------------------------------------------------------------
$94.9
- ---------------------------------------------------------------------------------------------------------------------
OTHER reflected income of $2.9 million in 2005 ($10.6 million loss in 2004;
$17.9 million loss in 2003). Improved financial results reflected a $3.7 million
current tax benefit due to the positive resolution of income tax audit issues, a
$2.5 million deferred tax benefit recorded in 2005 due to comprehensive tax
planning initiatives, the decline in interest expense as a result of lower debt
balances and increased earnings on excess cash. Interest expense was $1.3
million in 2005 ($4.7 million in 2004; $14.7 million in 2003). Earnings on
excess cash were $3.2 million in 2005 ($1.3 million in 2004; $0.9 million in
2003). Cash was higher in 2005 and 2004 than in 2003 due to proceeds received
from the sale of our Water Services businesses in 2004 and 2003, proceeds
received from ADESA in 2004 and proceeds received from the sale of Enventis
Telecom in 2005.
Financial results related to our emerging technology investments were better in
2005. Equity losses related to investments in venture capital funds declined in
2005 ($0 in 2005; $1.6 million in 2004). Impairments related to our emerging
technology investment were also lower in 2005 ($3.3 million in 2005; $4.1
million in 2004). In 2003, we reported $2.3 million of net losses on the sale of
shares we held directly in publicly-traded, emerging technology investments.
Financial results for 2004 also included an $11.5 million gain on the sale of
ADESA stock related to our ESOP (see Note 18), which was partially offset by 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.
DISCONTINUED OPERATIONS includes our Automotive Services business that was spun
off on September 20, 2004, costs incurred by ALLETE associated with the spin-off
of ADESA, our Water Services businesses, the majority of which were sold in
2003, and our telecommunications business, which we sold in December 2005.
Earnings from discontinued operations were lower in 2005, primarily due to the
absence of operations from Automotive Services. Automotive Services contributed
income of $74.4 million in 2004 ($113.6 million in 2003). 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 following the
spin-off. 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 income included $4.1 million of charges in connection
with a lawsuit related to ADESA's vehicle import business. 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. Income in 2003 also included a $1.3 million
recovery from the settlement of a lawsuit associated with ADESA's vehicle
transport business.
Page 35 ALLETE 2005 Form 10-K
NET INCOME (CONTINUED)
Water Services financial results reflected a $2.5 million loss in 2005 (loss of
$1.3 million in 2004; income of $93.0 million in 2003). In 2005, administrative
and other expenses were incurred to support Florida Water transfer proceedings.
A $1.0 million rate-base settlement charge related to the sale of 63 of Florida
Water systems to Aqua Utilities was also recorded in 2005. 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
impairments 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. Financial results for Water Services were
also lower in 2004 and 2005 due to the absence of operations from water and
wastewater systems sold. The majority of our Florida systems were sold in the
fourth quarter of 2003. North Carolina assets were sold in June 2004. Our
wastewater assets in Georgia were sold in February 2005.
Financial results for our telecommunications business reflected a loss of $1.8
million in 2005 (income of $0.6 million in each of the years 2004 and 2003). In
2005, we recorded a $3.6 million loss on the sale of this business to
HickoryTech. In 2005, income from operations was $1.2 million higher than 2004
primarily due to increased margins on telecommunication services.
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 15.)
2005 COMPARED TO 2004
REGULATED UTILITY
OPERATING REVENUE was up $20.6 million, or 4%, from 2004. Revenue from
other power suppliers was up $15.4 million from 2004 due to a 24% increase
in kilowatthour sales and higher market prices. In 2005, changes in
scheduled plant outages resulted in more energy available for sale than in
2004. Transmission revenue was up $4.2 million from 2004, reflecting
increased MISO-related revenue. In 2005, the Company recovered $12.1
million of other MISO expenses, subject to refund with interest, through
the fuel clause. (See Outlook.) Revenue from sales to retail and municipal
customers was down $2.4 million, primarily due to lower fuel clause
recoveries in 2005. (See operating expenses below.) Kilowatthour sales to
retail and municipal customers remained strong--up 2% from 2004, reflecting
increased usage. Residential and municipal customer usage was higher in
2005 due to higher than normal summer temperatures in 2005. Commercial
usage was higher due to stronger economic conditions in our electric
service territory in 2005. Sales to industrial customers were similar to
last year because, as in 2004, the Company's industrial customers were
operating at high production levels, with taconite and paper production at
or near capacity. Overall, regulated utility kilowatthour sales were up 4%
from 2004. Revenue from gas sales was up $2.5 million due to increased
prices in the natural gas component of sales.
OPERATING EXPENSES were up $9.7 million, or 2%, from 2004. Fuel and
purchased power expense was down $1.4 million from 2004 due to fewer
outages. In 2004, increased purchased power was necessitated by outages at
Company generating facilities and the Square Butte generating facility.
Maintenance expense was up $3.4 million from 2004, reflecting planned
maintenance performed at Boswell Units 1, 2 and 3 during 2005, partially
offset by lower maintenance expense related to Boswell Unit 4 and Laskin
Unit 1. In 2004, maintenance expense increased due to maintenance scheduled
for 2005 and 2006 that was performed while Boswell Unit 4 was down as a
result of a generator failure. Other operating expenses were $7.7 million
higher in 2005--MISO transmission costs increased $4.1 million, gas
purchases increased $2.6 million due to higher prices and pension expense
increased $1.7 million due to a change in the discount rate (5.50% in 2005;
5.75% in 2004). These increases were partially offset by the absence of
$2.0 million of expenses related to Split Rock Energy, which we exited in
March 2004.
INTEREST EXPENSE was down $1.1 million from 2004, primarily due to lower
effective interest rates (6.07% in 2005; 6.67% in 2004).
ALLETE 2005 Form 10-K Page 36
2005 COMPARED TO 2004 (CONTINUED)
NONREGULATED ENERGY OPERATIONS
OPERATING REVENUE was up $7.1 million, or 7%, from 2004. Revenue from
Taconite Harbor increased $14.0 million from 2004, primarily due to higher
demand as a result of two 5-year contracts (175 MW in total) that began in
May 2005. Coal revenue, realized under a cost-plus contract, was up $5.0
million from 2004, reflecting a 7% increase in tons of coal sold and an 8%
increase in the delivery price per ton due to higher coal production
expenses. (See operating expenses below.) BNI Coal sold fewer tons of coal
in 2004 due to a scheduled outage at the Square Butte generating facility.
Revenue from Kendall County was down $13.4 million from 2004, reflecting
the absence of operations since April 2005 when the Kendall County power
purchase agreement was assigned to Constellation Energy Commodities.
Overall, nonregulated kilowatthour sales were up 2% from 2004.
OPERATING EXPENSES were up $78.0 million from 2004, primarily due to the
$77.9 million charge related to the assignment of the Kendall County power
purchase agreement to Constellation Energy Commodities in April 2005.
Nonregulated generation fuel and purchased power expense was down $11.7
million from 2004, reflecting the absence of Kendall County operations.
Operating and maintenance expenses at Taconite Harbor were higher in 2005,
reflecting a $2.3 million increase in SO2 emission allowance expense, a
$1.0 million increase in contract services due to a longer than anticipated
scheduled outage as well as unscheduled outages, and a $1.2 million
increase in depreciation expense as a result of capitalized projects being
completed and placed into operation. Expenses related to our coal
operations were up $3.9 million, in part due to higher expenses associated
with equipment repairs, increased fuel costs and a $2.1 million increase in
lease expense related to the dragline.
INTEREST EXPENSE was up $1.7 million from 2004, reflecting higher
allocations in 2005.
OTHER INCOME (EXPENSE) reflected $1.1 million more income in 2005. Income
from customer contract services was up $0.4 million from 2004. Income from
Minnesota land sales was up $0.7 million from 2004, primarily due to an
adjustment recorded as a result of an MPUC land reevaluation.
REAL ESTATE
OPERATING REVENUE was up $5.6 million, or 13%, from 2004, reflecting strong
land sales offset by the deferral of revenue associated with certain real
estate sales. Revenue from land sales was $42.0 million in 2005 ($35.8
million in 2004). Town Center land sales accounted for $4.5 million of land
sale revenue in 2005. In 2005, revenue of $10.0 million, primarily related
to Town Center land sales, was deferred until development obligations are
completed ($1.5 million in 2004). Revenue from lot sales was lower in 2005
because in January 2004 we sold the remaining 184 lots at Sugarmill Woods
for $3.9 million, essentially exiting the lot sales business. In 2005,
1,172 acres and 7 lots were sold, of which 70 acres were located in Town
Center. Town Center sales included assignments of rights to build up to
643,000 square feet of commercial space. In 2004, 1,479 acres and 211 lots
were sold. Revenue from our brokerage business, Cape Properties, Inc., was
down $0.7 million, reflecting unusually strong sales in 2004.
OPERATING EXPENSES were up $0.5 million, or 3%, from 2004. Cost of real
estate sold was $2.1 million higher in 2005 ($8.6 million in 2005; $6.5
million in 2004) due to the type and location of real estate sold. In 2005,
cost of real estate sold totaling $2.2 million ($0.4 million in 2004) and
selling expense of $0.3 million, primarily related to Town Center land
sales, were deferred until development obligations are completed. Expenses
for our brokerage business were down $0.2 million due to unusually strong
sales in 2004. Selling expenses were down $1.1 million from 2004 due to
lower transaction costs and fewer brokerage commissions on 2005 sales.
Property taxes were down $0.3 million from 2004, reflecting a reduction in
land owned.
OTHER
OPERATING EXPENSES were up $0.9 million, or 28%, from 2004, primarily due
to increased compensation.
INTEREST EXPENSE was down $5.7 million from 2004, primarily due to lower
debt balances. The Company repaid a $53 million balance on a credit
agreement in April 2004 and $125 million of 7.80% Senior Notes in July
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 $11.6 million less expense in 2005. Other
income (expense) in 2005 reflected a $3.2 million increase in earnings on
excess cash, a $1.2 million decrease in equity losses from our emerging
technology investments and a $1.0 million charge to recognize the probable
payment under our guarantee of Northwest Airlines debt. We also recorded
$5.1 million of impairments related to our emerging technology investments
in 2005 ($6.5 million in 2004). In 2004, other income (expense) included an
$18.5 million debt prepayment cost related to the early redemption of $125
million in senior notes, an $11.5 million gain on the sale of ADESA shares
held in our ESOP (see Note 18), and $0.9 million of income from a rabbi
trust, established to secure certain deferred executive compensation.
Page 37 ALLETE 2005 Form 10-K
2005 COMPARED TO 2004 (CONTINUED)
INCOME TAXES. The effective tax rate from continuing operations before minority
interest was a 2.5% benefit in 2005 (28.8% expense in 2004). Income taxes in
2005 were affected by three major items, the adjustment of our deferred taxes
from comprehensive tax planning initiatives, a current tax benefit from the
positive resolution of audit issues and the inability to use state capital loss
carryforwards. The adjustment of our deferred tax assets and liabilities
resulted in a deferred tax benefit of $2.5 million. We received an audit report
resolving open issues that resulted in a current tax benefit of $3.7 million.
These items decreased our overall tax expense. The emerging technology
investment impairments recorded in March 2005 and the Kendall County Charge
recorded in April 2005 created capital losses. The current benefit for these
items was limited to a federal benefit for income tax purposes. The state tax
benefit from these items is not expected to be realized currently or in future
periods. The benefit related to these state net capital loss carryforwards was
fully offset by a valuation allowance. This resulted in an increase in our
overall tax expense. Current taxes also increased in 2005 due to the expiration
of the accelerated depreciation deduction allowed by the Jobs and Growth Tax
Relief Act of 2003, which expired December 31, 2004. An increase in the Federal
Medicare subsidy and the new Domestic Manufacturing Deduction contributed to
lower taxes in 2005. Income taxes for 2004 were primarily affected as a result
of the benefit of the nontaxable gain from the sale of ADESA common stock in our
ESOP. (See Note 13.)
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 below) also contributed
to less energy being available for sale to other power suppliers.
OPERATING EXPENSES in total were up $37.2 million, or 8%, in 2004,
primarily due to a $32.6 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 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.
Maintenance expense was $3.2 million higher in 2004, primarily due to the
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, $1.7 million of
MISO related expenses, a $2.6 million decrease in Split Rock Energy
expenses as a result of our exiting the joint venture in March 2004 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
and lower effective interest rates (6.67% in 2004; 6.88% in 2003).
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 mostly 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 $6.4 million, or 6%, in 2004 due to a $1.1
million increase in fuel and purchased power expense, $1.3 million of costs
associated with a scheduled maintenance outage at Taconite Harbor, a $1.2
million transmission contract termination charge to exit a Kendall County
agreement and a $0.9 million increase in costs for SO2 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.
ALLETE 2005 Form 10-K Page 38
2004 COMPARED TO 2003 (CONTINUED)
REAL ESTATE
OPERATING REVENUE was down $0.7 million, or 2%, in 2004. Revenue from land
sales in 2004 was similar to 2003, reflecting a strong southwest Florida
real estate market that began in the fall of 2003 and continued into 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). In 2004, land sales revenue of
$1.5 million was deferred until development obligations are completed. 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 a $1.1 million
recovery of a partially reserved receivable.
OPERATING EXPENSES were down $1.3 million, or 8%, in 2004 because the cost
of property sold in 2004 was lower than in 2003. Cost of real estate sold
in 2004 was $6.5 million ($7.9 million in 2003). In 2004, cost of real
estate sold totaling $0.4 million was deferred until development
obligations are completed.
OTHER
OPERATING EXPENSES were down $1.0 million, or 24%, in 2004, reflecting a
reduction in expenses following the spin-off of Automotive Services and
exit from the Water Services businesses in 2003.
INTEREST EXPENSE was down $17.1 million from 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 $10.4 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 impairments 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 18.)
In 2003, we recognized $3.5 million of losses related to the sale of shares
we held directly in publicly-traded emerging technology investments.
INCOME TAXES. Income taxes for 2004 were primarily affected as a result of the
benefit of the nontaxable gain from the sale of ADESA common stock in our ESOP.
Income taxes for 2003 were slightly lower than the statutory rate due to the
effects of investment tax credits.
NON-GAAP FINANCIAL MEASURES
We prepare financial statements in accordance with GAAP. Along with this
information, we disclose and discuss certain non-GAAP financial information in
our quarterly earnings releases, on investor conference calls and during
investor conferences and related events. Management believes that non-GAAP
financial data supplements our GAAP financial statements by providing investors
with additional information which enhances the investors' overall understanding
of our financial performance and the comparability of our operating results from
period to period. The presentation of this additional information is not meant
to be considered in isolation or as a substitute for our results of operations
prepared and presented in accordance with GAAP.
As earlier mentioned, financial results for 2005 were significantly impacted by
the following transactions:
- A $50.4 million after tax, or $1.84 per share, charge due to the
assignment of the Kendall County power purchase agreement to
Constellation Energy Commodities (see Note 11);
- A $3.7 million, or $0.13 per share, current tax benefit due to a positive
resolution of income tax audit issues; and
- A $2.5 million, or $0.09 per share, deferred tax benefit due to
comprehensive tax planning initiatives.
In 2004, financial results were significantly impacted by the following
transactions:
- A $10.9 million after tax, or $0.38 per share, debt prepayment cost as
part of ALLETE's financial restructuring in preparation for the spin-off
of Automotive Services (see Note 12); and
- An $11.5 million after tax, or $0.41 per share, gain on the sale of ADESA
shares related to our ESOP (see Note 18).
Page 39 ALLETE 2005 Form 10-K
NON-GAAP FINANCIAL MEASURES (CONTINUED)
Since these transactions significantly impacted the financial results from
continuing operations in 2005 and 2004, we believe that for comparative purposes
and a more accurate reflection of our ongoing operations, it is useful to
present diluted earnings per share from continuing operations for each
applicable period excluding the impact of these items. The table below
reconciles actual reported diluted earnings per share from continuing operations
before change in accounting principle to the adjusted results that exclude these
transactions in the respective periods.
FOR THE YEAR ENDED DECEMBER 31 2005 2004
- -------------------------------------------------------------------------------------------------------------------------
DILUTED EARNINGS PER SHARE OF COMMON STOCK
Continuing Operations Before Change in Accounting Principle $0.64 $1.35
Add: Kendall County Charge 1.84 -
Debt Prepayment Cost - 0.38
Less: Gain on Sale of ADESA Shares - 0.41
Positive Resolution of Tax Audit Issues 0.13 -
Tax Planning Initiatives 0.09 -
- -------------------------------------------------------------------------------------------------------------------------
$2.26 $1.32
- -------------------------------------------------------------------------------------------------------------------------
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.
REAL ESTATE REVENUE AND EXPENSE RECOGNITION. We account for sales of real estate
in accordance with SFAS 66, "Accounting for Sales of Real Estate." Revenue from
commercial, office, industrial and residential properties is recorded at the
time of closing using the full profit recognition method, provided that cash
collections are at least 20% of the contract price and the other requirements of
SFAS 66 are met. However, if we are obligated to perform significant development
activities subsequent to the date of the sale, we recognize revenue using the
percentage-of-completion method. This method of accounting requires that we
recognize gross profit based upon the relationship of development costs incurred
to the total estimated costs to develop the parcels. During each reporting
period, we must estimate the total costs to be incurred until project
completion, including development overhead and interest capitalization costs.
These total cost estimates will impact the recognition of profit on sales. The
costs are allocated to each lot or parcel based on the relative sales value
method. These estimates affect the amount of costs relieved as each lot is sold
and incorrect estimates may result in a misstatement of the cost of real estate
sold. Additionally, we must estimate the selling price of each individual lot or
parcel that is included in inventory for inclusion in the inventory cost model.
If the estimated selling prices of the lots are inaccurate, a material
difference in the timing of recording cost of real estate sold for the lots sold
could occur.
We record land held for sale at the lower of cost or fair value, which is
determined by the evaluation of individual land parcels. Real estate costs
include the cost of land acquired, subsequent development costs and costs of
improvements, capitalized development period interest, real estate taxes and
payroll costs of certain employees devoted directly to the development effort.
Based on the relative sales value of the parcels within each development
project, we capitalize the real estate costs incurred to the cost of real estate
parcels in accordance with SFAS 67, "Accounting for Costs and Initial Rental
Operations of Real Estate Projects." When real estate is sold, we include the
actual costs incurred and the estimate of future completion costs allocated to
the parcel(s) sold, based upon the relative sales value method in the cost of
real estate sold. We include land held for sale in Investments on our
consolidated balance sheet. Traffic impact fee credits are provided to the
developer as mitigation payments are made to the city. We are reimbursed after
the land is sold and a subsequent property owner constructs vertical
improvements on the site. We recognize revenue resulting from these reimbursed
fees when they are received.
We annually review the real estate carrying value for impairment. If
circumstances indicate that the carrying value may not be recoverable, we record
the impairment and adjust the related assets to their estimated fair value less
costs to sell.
IMPAIRMENT OF LONG-LIVED ASSETS. 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 conduct this assessment using SFAS 144, "Accounting
for the Impairment and Disposal of Long-Lived Assets." 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 would recognize an impairment loss only if the carrying amount of a
long-lived asset is not recoverable from its undiscounted future cash flows.
Management judgment is involved in both deciding if testing for recoverability
is necessary and in estimating undiscounted cash flows.
ALLETE 2005 Form 10-K Page 40
CRITICAL ACCOUNTING POLICIES (CONTINUED)
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; conversely, a 1/2% increase in the expected
long-term rate of return would decrease the annual expense by approximately $1
million after tax. Currently for plan valuation purposes, we use a discount rate
of 5.5%. The discount rate is determined considering high-quality long-term
corporate bond rates at the valuation date. The discount rate is compared to
various bond indices for reasonableness. We believe the bonds used in this
comparison do not materially differ in duration and cash flows for our pension
obligation. The Audit Committee of the Board of Directors annually reviews and
approves the rate of return and discount rate used for pension valuation and
accounting purposes. (See Note 17 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 because of our ownership percentage. 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 2005, we recorded $5.1 million pretax of impairment
losses on these investments ($6.5 million pretax in 2004; $0 in 2003).
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 remediation and cleanup 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 for federal purposes,
and fifteen succeeding years for Minnesota. As of December 31, 2005, we have,
where appropriate, recorded an allowance against our deferred tax assets
associated with realized capital losses, and 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, 2005, reflect the most
likely 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 41 ALLETE 2005 Form 10-K
OUTLOOK
Our vision is to forge a vibrant business that will sustain the confidence of
investors, while maintaining the trust of communities we have energized for a
century. We will pursue consistent growth in our energy and real estate
businesses, and invest in other diverse business ventures that bring value to
shareholders.
We believe our shareholders are best served by a company with sustainable
earnings growth and cash flow that supports dividend and stock price growth. We
believe our shareholders are best served by a business mix that mitigates
economic cycles, and a company that maintains the respect and admiration of
regulators and policy makers.
We value earning a return that rewards our shareholders, reinvests in our
business and sustains our growth. In the last 10 years, our average annual total
shareholder return was 16%. Approximately 5% of this average was attributed to
dividends. A $100 investment in ALLETE stock at the end of 1995 would have been
worth $443 at the end of 2005, 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 9% 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 1995 would have been
worth $238 at the end of 2005, assuming reinvestment of dividends. We also value
serving customers in a manner which meets their needs, promotes their
satisfaction and supports our mutual long-term success.
EARNINGS GUIDANCE. In 2006, we expect ALLETE's earnings per share from
continuing operations to grow by 15% to 20%. The growth is expected to come from
continued strong electric sales, increased real estate sales, the elimination of
projected operating losses from Kendall County and our investment in ATC. In
addition, we do not anticipate recording impairments related to our emerging
technology portfolio. This earnings expectation is based on a 2005 diluted
earnings per share from continuing operations of $2.26, which excludes the $1.84
per share Kendall County charge, a $0.13 per share current tax benefit due to
the positive resolution of income tax audit issues and a $0.09 per share
deferred tax benefit due to comprehensive tax planning initiatives. (See
Non-GAAP Financial Measures.) Our 2006 earnings expectation does not include
earnings from additional investments we may make in growth initiatives.
ENERGY. Over the next several years, we believe electric utilities will be
facing the unfolding impacts of three major developments that occurred in 2005:
changes in regional transmission operation; the start of rulemaking on the
enactment of stricter environmental regulations; and federal legislation
impacting the structure and organization of the electric utility industry. The
FERC has consolidated many transmission regions, which impacts states'
transmission regulation rights and is intended to result in more standardized
wholesale power markets to oversee how transmission and energy market prices are
determined. As part of this larger policy effort, MISO launched day-ahead and
real-time energy market operations on April 1, 2005 (MISO Day 2). While the
initial mechanics of the market launch were accomplished successfully, the
market itself is still evolving. Consequently, as we work through these matters,
we will be assessing the longer term impact of the MISO Day 2 market on
Minnesota Power's operations. Rulemakings for stricter environmental
requirements on several pollutants were issued by the EPA in 2005 and the final
outcomes of these regulatory processes 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. In August 2005, Congress
passed the Energy Policy Act of 2005, which included the repeal of PUHCA 1935
and enacted PUHCA 2005. PUHCA 1935 imposed geographic restrictions on large
electric and gas utility operations and limited diversification into non-utility
businesses. While the exact impact of PUHCA 2005 is unknown, more electric
industry consolidation could occur and new investors could enter the industry.
We believe our energy 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 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.
MISO AND FUEL CLAUSE. As a result of MISO Day 2 implementation in April 2005,
energy transactions to serve retail customers are sourced through wholesale
transactions with MISO as the counterparty. We filed a petition with the MPUC in
February 2005 to amend our fuel clause to accommodate costs and revenue related
to MISO Day 2 market implementation. In March 2005, the MPUC approved interim
ratemaking treatment of MISO Day 2 costs, which allowed these costs to be
recovered through the fuel clause, subject to refund with interest.
In December 2005, the MPUC issued an order that denied recovery of uplift
charges, congestion revenue and expenses, and administrative costs related to
our MISO Day 2 market activities through the fuel clause. As a result of that
order, we filed a Notice of Intent to Withdraw from MISO on December 29, 2005,
and began exploring alternatives to MISO. Withdrawal from MISO would also
require MPUC and FERC approval.
ALLETE 2005 Form 10-K Page 42
OUTLOOK (CONTINUED)
We requested rehearing of the order in a filing made with the MPUC in January
2006. Three other utilities in the state affected by the order also filed for
rehearing, as did the DOC and MISO. On February 9, 2006, the MPUC granted
rehearing of the MISO Day 2 docket and suspended the refund obligation. The MPUC
will review the MISO Day 2 costs to determine which costs should be recovered on
a current basis through the fuel clause and which costs are more appropriately
deferred for potential recovery through base rates.
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 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.
RATE CASE. Minnesota Power does not expect to file a request to increase rates
for its retail utility operations during 2006. We will, however, continue to
monitor the costs of serving our retail customers and evaluate the need for a
rate filing in the future. Minnesota Power's retail rates are based on a 1994
MPUC retail rate order. SWL&P's electric retail rates are based on a May 2005
PSCW retail rate order. In 2006, SWL&P plans to file for an increase in rates to
be effective beginning in 2007 for its electric, water and gas utility services.
INDUSTRIAL CUSTOMERS. Approximately 50% of our regulated utility electric sales
are made to our Large Power Customers in the taconite, paper and pulp, and
pipeline industries. Based on our research of the taconite industry, Minnesota
taconite production for 2006 is again anticipated to be about 41 million tons
(41 million tons in each of the years 2005 and 2004; 35 million tons in 2003).
Although the current taconite pellet market is strong, the taconite industry is
cyclical and subject to several factors, which could change this forecast. Some
paper industry analysts are cautiously optimistic about either price
stabilization or a small increase in paper prices during 2006 due to temporary
or permanent closures of capacity that occurred in 2005. For the North American
paper industry, the potential for either of these positive developments to occur
will, in large part, depend upon the level of imports and what happens to fiber,
chemical and energy costs. If there is a significant change in the major
industries served by Minnesota Power, we expect that any excess energy not used
by our retail customers will be marketed primarily to the regional wholesale
market.
Several natural resource-based companies have been making significant progress
developing new projects in northeastern Minnesota. Minnesota Power has actively
supported these projects which include paper, ferrous and non-ferrous
developments projected to be constructed and on-line within the next several
years. If these projects proceed, Minnesota Power could serve between 100 MW and
500 MW of new load.
In 2005, we reached new long-term, all requirements agreements with five of our
Large Power Customers, extending contracts for an additional four to eight
years. The extension of our electric supply contracts is an important
achievement for both our Large Power Customers and Minnesota Power. Electric
power is a key component in the production of taconite and paper, and these
industries represent more than half of Minnesota Power's regulated utility
electric sales. These agreements help to provide planning certainty for both our
customers and us. 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.
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 projected demand over the next 15 years. In an updated
forecast to that plan, we predict that retail demand by customers in our service
territory will increase at an average annual rate of 1.5% to 2019. We project a
load growth of approximately 150 MW by 2010 with another 200 MW of growth
anticipated by 2015. The forecasted growth of 15 MW to 28 MW per year, is
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 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.
We have been working with regulators and other stakeholders to determine the
best way to meet our projected customer needs for more electricity reliably,
cost-effectively and in an environmentally responsible way. In October 2005, we
proposed to the MPUC a comprehensive solution to meet our generation needs
through 2010 that includes the following key components:
- Transitioning our Taconite Harbor generating facility from nonregulated
energy operations to regulated utility to help meet our forecasted base
load energy requirements. With MPUC approval, our proposal would make the
integration of Taconite Harbor into Minnesota Power's regulated utility
business effective retroactive to January 1, 2006. Current wholesale
contracts sourced from Taconite Harbor will be honored through their
terms,
Page 43 ALLETE 2005 Form 10-K
OUTLOOK (CONTINUED)
which extend through mid-2010. Taconite Harbor would then meet the
majority of our near-term increased demand for electricity without
requiring the construction of new assets.
- Supplementing Taconite Harbor generation with a 50-MW long-term power
purchase agreement to meet near-term energy needs.
- Supporting the expansion of our renewable generating assets and helping
to meet Minnesota's Renewable Energy Objective that seeks a 10% supply of
qualified renewable energy resources in the state by 2015 for each
Minnesota utility. We have received regulatory approval of a power
purchase agreement for 50 MW of energy purchased from a wind facility in
North Dakota. We are also continuing to pursue an agreement for an
additional 50 MW of wind energy from facilities located in northern
Minnesota (see Wind Power) and are proposing to obtain 10 MW of
additional hydro generation through an expansion of one of our
hydroelectric stations.
Final regulatory approval of our Resource Plan and the transition of Taconite
Harbor is expected in mid 2006.
We are also exploring construction and purchase options for our anticipated
resource needs by 2015. In 2005, Minnesota Power, Basin Electric Power
Cooperative, Minnkota Power and Montana-Dakota Utilities Company announced a
project development agreement to evaluate the feasibility of a joint
lignite-fueled generating resource in the vicinity of the existing Milton R.
Young generating station near Center, North Dakota. The North Dakota feasibility
study is expected to take about one year to complete. A formal study is underway
for a facility in northeastern Minnesota. Any final resource decision by
Minnesota Power is subject to MPUC and other approvals. We continue to study the
feasibility of the construction of a natural gas-fired electric generating
facility which could be located in northwestern Wisconsin or northeastern
Minnesota.
Excelsior Energy Inc. (Excelsior) has proposed to construct a 600 MW (net)
coal-gasification generation facility in northern Minnesota. The project is in
the early development stages but may be an option for our long-term forecasted
energy and capacity needs. Excelsior says the facility could be operational in
2011, but needs to obtain the necessary permits and financing. In 2003, the
Minnesota legislature enacted several provisions that provide Excelsior with
special considerations, including requiring utilities within the state to
"consider" Excelsior before pursuing new resource additions within Minnesota. In
December 2005, Excelsior filed a petition with the MPUC seeking approval of an
unexecuted power purchase agreement with Xcel Energy Inc. In January 2006,
Minnesota Power filed comments with the MPUC in Excelsior's proposed power
purchase agreement proceeding, focusing on the importance to the state of
maintaining a range of base load energy options including multiple fuel types
and generating technologies.
WIND POWER. In 2005, we added a significant resource to our Regulated Utility
generation portfolio when we entered into a 25-year agreement to purchase
approximately 50 MW of wind power from a new wind facility to be built in North
Dakota by an affiliate of FPL Energy, LLC. FPL Energy expects the facility to be
operational in the fall of 2006. The wind facility will include approximately 22
new wind turbines interconnected to the Square Butte substation in Center, North
Dakota. The MPUC approved the power purchase agreement in December 2005. In
addition, we are continuing to pursue the purchase of renewable energy from a
new wind facility that would be located in northern Minnesota. This project,
expected to be operational in 2007, would be similar in size to the North Dakota
project and would be subject to a power purchase agreement, as well as
regulatory approvals. The Minnesota project also needs to be operational by the
end of 2007 to be eligible for federal production tax credits which are
essential to provide acceptable pricing.
AREA PLAN. In October 2005, we announced a $60 million environmental initiative
which is expected to significantly reduce emissions from two of our electric
generating facilities in northeastern Minnesota. Our Arrowhead Regional Emission
Abatement (AREA) Plan is designed to reduce emissions while maintaining a
reliable and reasonably-priced energy supply to meet the needs of our customers.
We believe that control and abatement technologies applicable to these plants
have matured to the point where further significant air emission reductions can
be attained in a relatively cost-effective manner.
At Taconite Harbor, we plan to employ innovative multi-emission reduction
technology, while at Laskin we plan to install a retrofit to lower NOX
emissions. Upon project completion, we estimate an emission reduction of over
60% for NOX at both facilities and a 65% reduction in SO2 at Taconite Harbor.
Laskin already has relatively low emission levels of SO2 due to existing
emission reduction technology. Additionally, with the emerging technology being
proposed for Taconite Harbor, there is the potential for a 90% reduction in
mercury emissions.
In October 2005, we filed the AREA plan with the MPUC followed by a second
filing detailing current cost recovery outside of a rate case in December 2005.
If approved by the MPUC, the rate impact on residential and general service
customers is expected to be about 2% and about 3% for Large Power Customers when
the plan is fully implemented at the end of 2008. We are seeking approval prior
to June 30, 2006, when the statutory authorization for current cost recovery on
utility emission reduction investments sunsets. In January 2006, the MPCA
submitted its assessment of our AREA plan from an environmental perspective to
the MPUC. The MPCA supports the plan as a cost-effective means of reducing
emissions at Taconite Harbor and Laskin. Given the emission reduction that would
be achieved and the reasonable costs of the proposal, the MPCA believes it is
appropriate to allow current cost recovery for this project.
ALLETE 2005 Form 10-K Page 44
OUTLOOK (CONTINUED)
CAIR AND CAMR. In March 2005, the EPA issued its Clean Air Interstate Rule
(CAIR) which would reduce emissions of SO2 and NOX. In November 2005, EPA
granted reconsideration of the CAIR. Minnesota Power filed comments for
reconsideration arguing that the State of Minnesota did not belong in CAIR and
that SO2 allocations proposed under the CAIR were unfair. The CAIR comment
period closed in January 2006 and a final rule is expected in 2006. In March
2005, EPA issued its Clean Air Mercury Rule (CAMR). EPA granted reconsideration
of the CAMR in October 2005. Comments on reconsideration closed in December
2005. A final ruling on CAMR is anticipated in 2006. The final outcomes of these
regulatory proceedings are expected to require significant capital investments
in the 2008 to 2012 timeframe. (See Capital Requirements.)
ENERGY POLICY ACT. In August 2005, the Energy Policy Act of 2005 was signed into
law. Key provisions in the law include: mandatory electric reliability
standards; FERC backstop siting authority for transmission corridors of national
interest, as well as giving the U.S. Department of Energy (DOE) "lead agency"
authority to coordinate federal agencies involved in siting transmission lines;
and the repeal of the PUHCA 1935 and the enactment of PUHCA 2005. The law also
reforms the hydro licensing process and supports the DOE's clean coal/FutureGen
program. We believe the overall impact on the electric utility industry will be
positive and are evaluating the effects on our business as this legislation is
being implemented.
INVESTMENT IN ATC. In 2005, we announced plans to invest $60 million in ATC by
the end of 2006. Our investment will represent an estimated 9% ownership
interest in ATC and is expected to be a significant contributor to future
earnings. Our investment in ATC is subject to review by the PSCW.
STRATEGY. As part of our strategy, we will leverage the strengths of our
Regulated Utility business to improve our strategic and financial outlook and
seek growth opportunities in close geographic proximity to existing operations
in Minnesota, North Dakota and Wisconsin. In addition, we will evaluate growth
opportunities through merger, acquisition or asset additions in our region.
REAL ESTATE. With an inventory of land in desirable Florida locations (see Item
1 - Real Estate), 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, 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 income for our real
estate business. Other ongoing land sales and rental income at the retail
shopping center in Winter Haven provide additional revenue.
ALLETE Properties plans to maximize the value of the property it currently owns
through entitlement and infrastructure improvements. In addition to managing its
current real estate inventory, ALLETE Properties is focused on identifying,
acquiring and entitling vacant land in the coastal southeast United States.
As of December 31, 2005, we had $8.6 million of deferred profit on sales of real
estate, before taxes and minority interest, on our balance sheet. We expect most
of this deferred profit will be reflected in income during the next 12 months.
TOWN CENTER. Ground was broken on the Town Center development in early 2005. At
December 31, 2005, pending land sales under contract for properties at Town
Center totaled $63.7 million. Florida Landmark has an agreement with Developers
Realty Corporation (DRC) to develop the first phase of the urban core area of
Town Center. The agreement also includes the development of a 51-acre commercial
retail site. Revenue associated with this agreement is anticipated to be $21.8
million over the life of the contract, which extends to September 2012.
During the initial phase of the Town Center project, our primary focus is to
develop the major infrastructure, most of the development tracts, as well as
plat lots for a variety of uses. The marketing program has targeted an
appropriate blend and quantity of office, commercial, residential and mixed-use
projects. Sites for all land uses that are planned in the initial phase are
already sold or under contract, except adult housing. Negotiations are underway
with several developers that specialize in adult housing units. After the next
few years, once the market has substantially absorbed the land uses that are
currently in the design phase, additional sites will be released for sale in
order to maintain an orderly build-out of Town Center. Pacing the growth of Town
Center consistent with absorption rates for each unit type will assure that our
customers, the Town Center project developers, will be successful. This is
expected to create and maximize value for the developers, end-users and
investors.
Page 45 ALLETE 2005 Form 10-K
OUTLOOK (CONTINUED)
PALM COAST PARK. Designing has been completed and permitting is proceeding on
the Palm Coast Park development, with infrastructure construction slated to
begin in 2006. Development order approval from the City of Palm Coast was
received in late 2005. Also in 2005, the State of Florida granted the Palm Coast
Park Community Development District authority to issue special assessment
revenue bonds to fund construction of infrastructure improvements for the
project. The bonds are expected to be issued by the district by mid 2006. The
major infrastructure improvements, consisting primarily of utility extensions
and a linear park along the U.S. Highway 1 frontage, are being permitted in
anticipation of this bond financing, after which construction of the
improvements will commence. Platting is underway and expected to be completed in
early 2007. Commercial sites will be available for sale beginning in 2007. At
December 31, 2005, pending land sales under contract for properties at Palm
Coast Park totaled $7.5 million. Negotiations are underway to sell two other
residential development tracts.
ORMOND CROSSINGS. In 2005, a Development of Regional Impact (DRI) Application
for Development Approval was submitted to the East Central Florida Regional
Planning Council for the 6,000-acre Ormond Crossings project. Development uses
and densities proposed in the DRI include 5 million square feet of commercial
opportunities along with up to 4,400 residential units. We anticipate that the
DRI review will be concluded and a development order will be issued by the City
of Ormond Beach by the end of 2006. Engineering, design and permitting will
continue through 2007. It is not anticipated that any sales will be made at
Ormond Crossings until 2008. The Ormond Crossings DRI application represents the
launch of our third major real estate development in Florida and the largest in
terms of available commercial square feet and residential units.
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 $3.1 million at December
31, 2005, 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 $89.6 million, $116.9 million of short-term investments and a
debt to total capital ratio of 39% at December 31, 2005.
OPERATING ACTIVITIES. Cash flow from operating activities was $53.5 million for
2005 ($175.0 million for 2004; $247.4 million for 2003). Cash from operating
activities was lower in 2005, primarily due to the absence of cash from
discontinued operations ($2.3 million in 2005; $108.8 million in 2004; $133.3
million in 2003). In 2004, we spun off our Automotive Services business and
essentially completed the exit from our Water Services businesses. Cash from
operating activities was also lower in 2005 due to a $50.4 million Kendall
County Charge in 2005. In 2005, cash from operating activities was higher than
in 2004 due to the collection in January 2005 of a $6.7 million outstanding
receivable at December 31, 2004, from ATC for work on the Duluth-to-Wausau
transmission line and other receivables, and an additional $7.5 million of
deferred profit on real estate activities. 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.
INVESTING ACTIVITIES. Cash flow from investing activities was $3.9 million for
2005 (cash flow for investing activities of $126.5 million for 2004; cash flow
from investing activities of $210.3 million for 2003). Cash from investing
activities was higher in 2005 than 2004, primarily due to a $179.9 million
increase in net proceeds received from the sale of short-term investments. Gross
proceeds from the sale of available-for-sale securities were $376.0 million in
2005 ($1.9 million in 2004; $7.4 million in 2003) and purchases were $343.7
million ($149.5 million in 2004; $0 in 2003). Cash from investing activities for
2005 was also higher by $35.5 million from the sale of Enventis Telecom. The
increase was offset by $66.0 million proceeds received in 2004 from the sale of
our remaining Water Services businesses. The increase was also offset by $12.0
million received from Split Rock Energy in 2004 upon termination of the joint
venture. Additions to property, plant and equipment 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. Cash flow from
investing activities was lower in 2004 than 2003, primarily due to purchases of
available-for-sales securities in 2004 ($149.5 million) and $445 million of
proceeds received in 2003 from the sale of a major portion of our Water Services
businesses.
ALLETE 2005 Form 10-K Page 46
LIQUIDITY AND CAPITAL RESOURCES (CONTINUED)
FINANCING ACTIVITIES. Cash flow for financing activities was $13.9 million for
2005 ($228.7 million for 2004; $470.7 million for 2003). The decrease in cash
for financing activities was primarily attributed to significant debt repayment
($35.7 million in 2005; $241.1 million in 2004; $335.7 million in 2003). In
2005, we refinanced $35 million of first mortgage bonds at a lower rate. In
2004, we repaid $3.5 million of industrial development revenue bonds and $125
million of senior notes, and refinanced $111 million of pollution control
refunding revenue bonds at a lower rate. In 2003, we repaid $75 million of first
mortgage bonds and $75 million of mandatorily redeemable preferred securities.
In addition, a $250 million credit agreement entered into in July 2003 was paid
off early ($197 million in 2003; $53 million in April 2004). 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. Cash for financing
activities also decreased in 2005 and 2004 due to lower dividends paid following
the spin-off of Automotive Services.
Our Town Center development project in Florida is being financed with a
revolving development loan and tax-exempt bonds issued by the Town Center at
Palm Coast Community Development District (Town Center District). In March 2005,
Florida Landmark entered into an $8.5 million revolving development loan with
CypressCoquina Bank to fund approximately $26 million of Town Center development
costs. The loan has an interest rate equal to the prime rate, with an initial
term of 36 months. The term of the loan may be extended 24 months if certain
conditions are met. Also in March 2005, the Town Center District issued $26.4
million of tax-exempt, 6% Capital Improvement Revenue Bonds, Series 2005, due
May 1, 2036 (Bonds). Approximately $21 million of the Bond proceeds will be used
for construction of infrastructure improvements at Town Center, with the
remaining funds to be used for capitalized interest, a debt service reserve fund
and costs of issuance. The Bonds are payable from and secured by the revenue
derived from assessments to be imposed, levied and collected by the Town Center
District. The assessments represent an allocation of the costs of the
improvements, including bond financing costs, to the lands within the Town
Center District benefiting from the improvements. The assessments will be
included in the annual property tax bills of landowners in the development
project beginning in November 2006. To the extent that we still own land at the
time of the assessment, we will recognize an expense for our pro rata portion of
assessments, based upon our ownership of benefited property. At December 31,
2005, we owned approximately 92% of the assessable land in the Town Center
District. The Town Center District is an independent unit of local government,
created and established in accordance with Florida's Uniform Community
Development District Act of 1980 (Act). The Act provides legal authority for a
community development district to finance the construction of major
infrastructure for community development with general obligation, revenue and
special assessment revenue debt obligations.
WORKING CAPITAL. Additional working capital, if and when needed, generally is
provided by the sale of commercial paper. We have 0.8 million original issue
shares of our common stock available for issuance through INVEST DIRECT, our
direct stock purchase and dividend reinvestment plan. We have bank lines of
credit aggregating $170.0 million, the majority of which expire in January 2011.
In January 2006, we renewed, increased and extended a committed, syndicated,
unsecured revolving credit facility with LaSalle Bank National Association, as
Agent, for $150 million (Line). The Line matures on January 11, 2011. At our
request and subject to certain conditions, the Line may be increased to $200
million and extended for two additional 12-month periods. We may prepay amounts
outstanding under the Line in whole or in part at our discretion. Additionally,
we may irrevocably terminate or reduce the size of the Line prior to maturity.
The Line may be used for general corporate purposes, working capital and to
provide liquidity in support of 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.
SALE OF ENVENTIS TELECOM. In 2005, we sold all the stock of Enventis Telecom to
HickoryTech of Mankato, Minnesota, for $35.5 million. The transaction resulted
in an after-tax loss of $3.6 million, which was included in our 2005 earnings
from discontinued operations. Net cash proceeds realized from the sale were
approximately $29 million after transaction costs, repayment of debt and payment
of income taxes.
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.
In August 2005, we issued $35 million in principal amount of First Mortgage
Bonds, 5.28% due 2020. Proceeds were used to redeem $35 million in principal
amount of First Mortgage Bonds, 7 1/2% Series originally due 2007.
Page 47 ALLETE 2005 Form 10-K
LIQUIDITY AND CAPITAL RESOURCES (CONTINUED)
In October 2005, we accepted an offer from certain institutional buyers in the
private placement market to purchase $50 million in principal amount of our
first mortgage bonds. When issued, on or about March 1, 2006, the bonds will
carry an interest rate of 5.69% and will have a term of 30 years. On January 30,
2006, we called for redemption on March 2, 2006, $50 million in principal amount
of First Mortgage Bonds, 7% Series due 2008.
FINANCIAL COVENANTS
Our lines of credit and letters of credit supporting certain long-term debt
arrangements contain financial covenants. The most restrictive covenant requires
ALLETE to maintain a quarterly ratio of its funded debt to total capital of less
than or equal to .65 to 1.00. Failure to meet this covenant 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. Some of ALLETE's
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, 2005, ALLETE was in compliance
with its financial covenants.
OFF-BALANCE SHEET ARRANGEMENTS
Off-balance sheet arrangements are discussed in Note 10.
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 table below assumes the
interest rate in effect at December 31, 2005, remains constant through the
remaining term.
Unconditional purchase obligations represent our Square Butte power purchase
agreement, 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
following table reflects our share of future debt service based on our output
entitlement of approximately 66% in 2006, 60% in 2007 and 55% 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 10.)
Under an agreement with Wisconsin Public Service Corporation and WPS
Investments, LLC, we have a commitment to invest $60 million in ATC by the end
of 2006. (See Note 10.) Our investment will represent an estimated 9% ownership
interest in ATC. Our investment in ATC is subject to review by the PSCW.
PAYMENTS DUE BY PERIOD
-------------------------------------------------------------------------------
CONTRACTUAL OBLIGATIONS LESS THAN 1 TO 3 4 TO 5 AFTER
AS OF DECEMBER 31, 2006 TOTAL 1 YEAR YEARS YEARS 5 YEARS
- --------------------------------------------------------------------------------------------------------------------------
MILLIONS
Long-Term Debt $ 601.6 $ 24.9 $196.1 $30.2 $350.4
Operating Lease Obligations 73.2 6.4 15.8 7.9 43.1
Unconditional Purchase Obligations 374.7 57.8 71.0 29.0 216.9
Investment in ATC 60.0 60.0 - - -
- --------------------------------------------------------------------------------------------------------------------------
$1,109.5 $149.1 $282.9 $67.1 $610.4
- --------------------------------------------------------------------------------------------------------------------------
In 2006, we expect to contribute approximately $8 million to our postretirement
health and life plans and approximately $10 million to our defined benefit
pension plans. We are unable to predict contribution levels after 2006.
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 $3.1 million at
December 31, 2005 ($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.
ALLETE 2005 Form 10-K Page 48
LIQUIDITY AND CAPITAL RESOURCES (CONTINUED)
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 2005, we paid out 259% (77% in 2004; 40% in 2003) of our per share earnings
in dividends. The payout ratio in 2005 was impacted by a $1.84 per diluted share
charge to assign the Kendall County power purchase agreement to Constellation
Energy Commodities in April 2005. (See Note 11.)
On January 25, 2006, our Board of Directors increased the dividend on ALLETE
common stock by 15%, declaring a dividend of 36.25 cents per share payable March
1, 2006, to shareholders of record at the close of business February 15, 2006.
CAPITAL REQUIREMENTS
CONTINUING OPERATIONS. Capital expenditures for 2005 totaled $58.6 million
($57.8 million in 2004; $68.7 million in 2003). Expenditures for 2005 included
$46.5 million for Regulated Utility and $12.1 million for Nonregulated Energy
Operations. Internally-generated funds were the source of funding for these
expenditures.
Capital expenditures are expected to be $107 million in 2006 and total $630
million for 2007 through 2010. The 2006 amount includes $105 million for system
component replacement and upgrades, and environmental upgrades within Regulated
Utility, and $2 million for coal handling equipment and system component
replacement, and upgrades within Nonregulated Energy Operations. Starting in
2006, Taconite Harbor's capital expenditures will be combined with Regulated
Utility expenditures. Over the next five years, we expect to use
internally-generated funds and new issue debt to fund our projected capital
expenditures. Approximately $280 million of the estimated expenditures for 2007
through 2010 relate to environmental upgrades at our generation facilities,
primarily due to the promulgation of two new EPA rules in 2005. Our
environmental compliance plan incorporates a combination of solutions that
include both technology and emission allowance purchases, and timing and
scheduling of environmental retrofit during this period.
Real estate development expenditures are and will be funded with a revolving
development loan and tax-exempt bonds issued by community development districts.
The Town Center at Palm Coast Community Development District issued $26.4
million of tax-exempt bonds in 2005. Approximately $21 million of the bond
proceeds will be used for construction of infrastructure improvements at Town
Center, with the remaining funds to be used for capitalized interest, a debt
service reserve fund and costs of issuance. We anticipate that the Palm Coast
Park Community Development District will issue tax-exempt bonds to fund
construction of infrastructure improvements for our Palm Coast Park project in
mid-2006. Expenditures related to our real estate developments in Florida
increase the value of our land assets, which are classified as Investments on
our consolidated balance sheet.
DISCONTINUED OPERATIONS. Capital expenditures for discontinued operations for
2005 totaled $4.5 million ($21.4 million in 2004; $67.6 million in 2003).
Expenditures for 2005 related to our telecommunications business.
Page 49 ALLETE 2005 Form 10-K
ENVIRONMENTAL AND OTHER MATTERS
As previously mentioned in our Critical Accounting Policies section, our
businesses are subject to regulation of environmental matters by various
federal, state and local authorities. Due to future stricter environmental
requirements through legislation and/or rulemaking, we anticipate that potential
expenditures for environmental matters will be material and will require
significant capital investments. We are unable to predict the outcome of the
issues discussed in Note 10. (See Item 1 - Environmental Matters.)
MARKET RISK
SECURITIES INVESTMENTS
AVAILABLE-FOR-SALE SECURITIES. At December 31, 2005, our available-for-sale
securities portfolio consisted of securities in a grantor trust established to
fund certain employee benefits included in Investments, and various auction rate
municipal bonds and variable rate municipal demand notes included as Short-Term
Investments. Our available-for-sale securities portfolio had a fair value of
$139.5 million at December 31, 2005 ($179.4 million at December 31, 2004) and a
total unrealized after-tax gain of $2.1 million at December 31, 2005 ($1.5
million at December 31, 2004).
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 share price trends and the impact of overall market
conditions. As a result of our periodic assessments, we did not record any
impairment of available-for-sale securities in 2005 or 2004.
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 because of our
ownership percentage. The total carrying value of our emerging technology
portfolio was $9.2 million at December 31, 2005 ($13.6 million at December 31,
2004). 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.
Our basis in direct investments in privately-held companies included in the
emerging technology portfolio was zero at December 31, 2005 ($4.5 million at
December 31, 2004). In 2005, we recorded $5.1 million ($3.3 million after tax)
of impairments that related to direct investments in certain privately-held,
start-up companies whose future business prospects had significantly diminished.
Developments at these companies indicated that future commercial viability was
unlikely, as was new financing necessary to continue development. In 2004, we
recorded $6.5 million ($4.1 million after tax) of impairments. We did not record
any impairments in 2003.
INTEREST RATE SENSITIVE FINANCIAL INSTRUMENTS
PRINCIPAL CASH FLOW BY EXPECTED MATURITY DATE
- --------------------------------------------------------------------------------------------------------------------------
FAIR
2006 2007 2008 2009 2010 THEREAFTER TOTAL VALUE
- --------------------------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS
Long-Term Debt
Fixed Rate $0.9 $80.9 $56.6 $1.6 $0.5 $189.4 $329.9 $331.9
Average Interest Rate - % 7.1 6.9 7.0 6.7 6.8 5.4 6.0
Variable Rate $1.8 $3.3 $0.8 $9.0 $4.4 $41.3 $60.6 $60.6
Average Interest Rate - % 5.4 3.9 5.1 3.6 3.8 3.8 3.9
- --------------------------------------------------------------------------------------------------------------------------
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.
ALLETE 2005 Form 10-K Page 50
MARKET RISK (CONTINUED)
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
generation and purchased power.
From time to time, our 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 MISO market at market prices.
We have approximately 200 MW of generation available for sale to the wholesale
markets at our Taconite Harbor facility in northern Minnesota, which has been
sold through various short-term and long-term capacity and energy contracts.
Approximately 116 MW of existing capacity and energy sales contracts expired 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 were 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 had fixed
pricing through January 2006, with formula pricing based on variable production
cost of a combustion-turbine, natural gas unit thereafter.
In addition to generation, Taconite Harbor will meet its sales contract
obligations with two contracts that began in May 2005. We have a 50 MW capacity
and energy purchase contract that extends through April 2006, with fixed
capacity payments and the right to purchase energy at market price. We also had
a 25 MW fixed-priced energy purchase contract that extended through January
2006.
NEW ACCOUNTING STANDARDS
New accounting standards are discussed in Note 2.
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.
Page 51 ALLETE 2005 Form 10-K
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See our consolidated financial statements as of December 31, 2005 and 2004, and
for each of the three years in the period ended December 31, 2005, 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, 2005.
Our management's assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2005, 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
None.
ALLETE 2005 Form 10-K Page 52
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 2006 Annual Meeting of
Shareholders (2006 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 2006 Proxy Statement will be filed with the SEC within 120 days after the
end of our 2005 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 2006 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," the "Security Ownership
of Management" and the "Equity Compensation Plan Information" sections in our
2006 Proxy Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required for this Item is incorporated by reference herein from
the "Corporate Governance" section in our 2006 Proxy Statement.
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 2006 Proxy Statement.
Page 53 ALLETE 2005 Form 10-K
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....... 59
Consolidated Balance Sheet at December 31, 2005 and 2004...... 60
For the Three Years Ended December 31, 2005
Consolidated Statement of Income......................... 61
Consolidated Statement of Cash Flows..................... 62
Consolidated Statement of Shareholders' Equity........... 63
Notes to Consolidated Financial Statements.................... 64-92
(2) Financial Statement Schedules
Schedule II - ALLETE Valuation and Qualifying Accounts
and Reserves.................................................. 93
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
*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)
Twenty-fourth March 1, 2005 1-3548 (March 31, 2005 Form 10-Q) 4
*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).
ALLETE 2005 Form 10-K Page 54
EXHIBIT NUMBER
*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.
(filed as Exhibit 10(c) to the 2004 Form 10-K, File No.
1-3548).
*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 (filed as
Exhibit 10(d)2 to the 2004 Form 10-K, File No. 1-3548).
*10(e) - Fourth Amended and Restated Committed Facility Letter
(without Exhibits), dated January 11, 2006, by and among
ALLETE and LaSalle Bank National Association, as Agent (filed
as Exhibit 10 to the January 17, 2006, Form 8-K, File No.
1-3548).
*10(f) - 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(g) - Agreement (without Exhibit) dated December 16, 2005, among
ALLETE, Wisconsin Public Service Corporation and WPS
Investments, LLC (filed as Exhibit 10 to the December 21, 2005
Form 8-K, File No. 1-3548).
+*10(h)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(h)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(h)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(h)4 - Form of ALLETE Executive Annual Incentive Plan 2005 Award
(filed as Exhibit 10(a)1 to the March 31, 2005, Form 10-Q,
File No. 1-3548).
+*10(h)5 - ALLETE Executive Annual Incentive Plan 2005 Goals (filed as
Exhibit 10(a)2 to the March 31, 2005, Form 10-Q, File No.
1-3548).
+*10(h)6 - Form of ALLETE Executive Annual Incentive Plan 2006 Award -
President of ALLETE Properties (filed as Exhibit 10(b) to the
January 30, 2006, Form 8-K, File No. 1-3548).
Page 55 ALLETE 2005 Form 10-K
EXHIBIT NUMBER
+*10(i)1 - 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(i)2 - January 2005 Amendment to the ALLETE and Affiliated Companies
Supplemental Executive Retirement Plan (filed as Exhibit 10(b)
to the March 31, 2005, Form 10-Q, File No. 1-3548).
+*10(j)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(j)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(j)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).
+*10(k)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(k)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(k)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(l) - 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(m)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(m)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(m)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(m)4 - Form of ALLETE Executive Long-Term Incentive Compensation
Plan 2005 Nonqualified Stock Option Grant (filed as Exhibit
10(k)4 to the 2004 Form 10-K, File No. 1-3548).
+*10(m)5 - Form of ALLETE Executive Long-Term Incentive Compensation
Plan 2005 Performance Share Grant (filed as Exhibit 10(k)5 to
the 2004 Form 10-K, File No. 1-3548).
+*10(n)1 - ALLETE Executive Long-Term Incentive Compensation Plan as
amended and restated effective January 1, 2006 (filed as
Exhibit 10 to the May 16, 2005, Form 8-K, File No. 1-3548).
+*10(n)2 - Form of ALLETE Executive Long-Term Incentive Compensation
Plan 2006 Nonqualified Stock Option Grant (filed as Exhibit
10(a)1 to the January 30, 2006, Form 8-K, File No. 1-3548).
+*10(n)3 - Form of ALLETE Executive Long-Term Incentive Compensation
Plan 2006 Performance Share Grant (filed as Exhibit 10(a)2 to
the January 30, 2006, Form 8-K, File No. 1-3548).
+*10(n)4 - Form of ALLETE Executive Long-Term Incentive Compensation
Plan 2006 Long-Term Cash Incentive Award - President of ALLETE
Properties (filed as Exhibit 10(a)3 to the January 30, 2006,
Form 8-K, File No. 1-3548).
+*10(n)5 - Form of ALLETE Executive Long-Term Incentive Compensation Plan
2006 Stock Grant - President of ALLETE Properties (filed as
Exhibit 10(a)4 to the January 30, 2006, Form 8-K, File No.
1-3548).
+*10(o)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(o)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(o)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(o)4 - ALLETE Director Compensation Summary (filed as Exhibit 10 to
the June 30, 2005, Form 10-Q, File No. 1-3548).
+*10(p)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(p)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(p)3 - January 2005 Amendment to the ALLETE Director Compensation
Deferral Plan (filed as Exhibit 10(c) to the March 31, 2005,
Form 10-Q, File No. 1-3548).
ALLETE 2005 Form 10-K Page 56
EXHIBIT NUMBER
+*10(q) - 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.
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 57 ALLETE 2005 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 17, 2006 By Donald J. Shippar
-------------------------------------------
Donald J. Shippar
Chairman, President and Chief
Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
- -----------------------------------------------------------------------------------------------------------
Donald J. Shippar Chairman, President, Chief Executive February 17, 2006
- -------------------------------- Officer and Director
Donald J. Shippar
James K. Vizanko Senior Vice President and February 17, 2006
- -------------------------------- Chief Financial Officer
James K. Vizanko
Mark A. Schober Senior Vice President and Controller February 17, 2006
- --------------------------------
Mark A. Schober
Heidi J. Eddins Director February 17, 2006
- --------------------------------
Heidi J. Eddins
Peter J. Johnson Director February 17, 2006
- --------------------------------
Peter J. Johnson
Madeleine W. Ludlow Director February 17, 2006
- --------------------------------
Madeleine W. Ludlow
George L. Mayer Director February 17, 2006
- --------------------------------
George L. Mayer
Roger D. Peirce Director February 17, 2006
- --------------------------------
Roger D. Peirce
Jack I. Rajala Director February 17, 2006
- --------------------------------
Jack I. Rajala
Nick Smith Director February 17, 2006
- --------------------------------
Nick Smith
Bruce W. Stender Director February 17, 2006
- --------------------------------
Bruce W. Stender
ALLETE 2005 Form 10-K Page 58
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of ALLETE, Inc.
We have completed integrated audits of ALLETE, Inc.'s 2005 and 2004 consolidated
financial statements and of its internal control over financial reporting as of
December 31, 2005, and an audit of its 2003 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. and its subsidiaries at December 31, 2005 and
2004, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2005 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 15 to the consolidated 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, 2005 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,
2005, 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 13, 2006
Page 59 ALLETE 2005 Form 10-K
CONSOLIDATED FINANCIAL STATEMENTS
ALLETE CONSOLIDATED BALANCE SHEET
DECEMBER 31 2005 2004
- -------------------------------------------------------------------------------------------------------------------------
MILLIONS
ASSETS
Current Assets
Cash and Cash Equivalents $ 89.6 $ 43.7
Restricted Cash - 30.3
Short-Term Investments 116.9 149.2
Accounts Receivable (Less Allowance of $1.0 for 2005 and 2004) 79.1 78.7
Inventories 33.1 31.8
Prepayments and Other 23.8 21.3
Deferred Income Taxes 31.0 -
Discontinued Operations 0.4 13.1
- -------------------------------------------------------------------------------------------------------------------------
Total Current Assets 373.9 368.1
Property, Plant and Equipment - Net 860.4 849.6
Investments 117.7 124.5
Other Assets 44.6 52.8
Discontinued Operations 2.2 36.4
- -------------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $1,398.8 $1,431.4
- -------------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
LIABILITIES
Current Liabilities
Accounts Payable $ 44.7 $ 36.4
Accrued Taxes 19.1 22.4
Accrued Interest 7.4 6.9
Long-Term Debt Due Within One Year 2.7 1.8
Deferred Profit on Sales of Real Estate 8.6 1.1
Other 24.2 23.1
Discontinued Operations 13.0 24.5
- -------------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 119.7 116.2
Long-Term Debt 387.8 389.4
Deferred Income Taxes 138.4 139.2
Other Liabilities 144.1 150.5
Minority Interest 6.0 5.6
- -------------------------------------------------------------------------------------------------------------------------
Total Liabilities 796.0 800.9
- -------------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
- -------------------------------------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Common Stock Without Par Value, 43.3 Shares Authorized
30.1 and 29.7 Shares Outstanding 421.1 400.1
Unearned ESOP Shares (77.6) (51.4)
Accumulated Other Comprehensive Loss (12.8) (11.4)
Retained Earnings 272.1 293.2
- -------------------------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 602.8 630.5
- -------------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $1,398.8 $1,431.4
- -------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
ALLETE 2005 Form 10-K Page 60
ALLETE CONSOLIDATED STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31 2005 2004 2003
- -------------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT PER SHARE AMOUNTS
OPERATING REVENUE $737.4 $704.1 $659.6
- -------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Fuel and Purchased Power 273.1 286.2 252.5
Operating and Maintenance 293.5 270.1 260.5
Kendall County Charge 77.9 - -
Depreciation 47.8 46.9 48.9
- -------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 692.3 603.2 561.9
- -------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME FROM CONTINUING OPERATIONS 45.1 100.9 97.7
- -------------------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE)
Interest Expense (26.4) (31.7) (50.5)
Other 1.1 (12.2) 2.3
- -------------------------------------------------------------------------------------------------------------------------
Total Other Expense (25.3) (43.9) (48.2)
- -------------------------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS
BEFORE MINORITY INTEREST AND INCOME TAXES 19.8 57.0 49.5
MINORITY INTEREST 2.7 2.1 2.6
- -------------------------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES 17.1 54.9 46.9
INCOME TAX EXPENSE (BENEFIT) (0.5) 16.4 17.7
- -------------------------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS
BEFORE CHANGE IN ACCOUNTING PRINCIPLE 17.6 38.5 29.2
INCOME (LOSS) FROM DISCONTINUED OPERATIONS - NET OF TAX (4.3) 73.7 207.2
CHANGE IN ACCOUNTING PRINCIPLE - NET OF TAX - (7.8) -
- -------------------------------------------------------------------------------------------------------------------------
NET INCOME $ 13.3 $104.4 $236.4
- -------------------------------------------------------------------------------------------------------------------------
AVERAGE SHARES OF COMMON STOCK
Basic 27.3 28.3 27.6
Diluted 27.4 28.4 27.8
- -------------------------------------------------------------------------------------------------------------------------
BASIC EARNINGS (LOSS) PER SHARE OF COMMON STOCK
Continuing Operations $0.65 $1.37 $1.06
Discontinued Operations (0.16) 2.60 7.50
Change in Accounting Principle - (0.28) -
- -------------------------------------------------------------------------------------------------------------------------
$0.49 $3.69 $8.56
- -------------------------------------------------------------------------------------------------------------------------
DILUTED EARNINGS (LOSS) PER SHARE OF COMMON STOCK
Continuing Operations $0.64 $1.35 $1.05
Discontinued Operations (0.16) 2.59 7.47
Change in Accounting Principle - (0.27) -
- -------------------------------------------------------------------------------------------------------------------------
$0.48 $3.67 $8.52
- -------------------------------------------------------------------------------------------------------------------------
DIVIDENDS PER SHARE OF COMMON STOCK $1.2450 $2.8425 $3.3900
- -------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
Page 61 ALLETE 2005 Form 10-K
ALLETE CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31 2005 2004 2003
- -------------------------------------------------------------------------------------------------------------------------
MILLIONS
OPERATING ACTIVITIES
Net Income $ 13.3 $104.4 $236.4
(Income) Loss from Discontinued Operations 4.3 (73.7) (207.2)
Change in Accounting Principle - 7.8 -
Loss on Impairment of Investments 5.1 6.5 -
Depreciation 47.8 46.9 48.9
Deferred Income Taxes (34.2) (1.1) 9.9
Minority Interest 2.7 2.1 2.6
Stock Compensation Expense 1.5 1.0 3.0
Bad Debt Expense 1.1 0.9 0.6
Changes in Operating Assets and Liabilities
Accounts Receivable (1.4) (22.9) 16.5
Trading Securities - - 1.8
Inventories (1.3) (0.3) 0.2
Prepayments and Other (2.5) (3.6) (1.7)
Accounts Payable 4.9 0.2 7.3
Other Current Liabilities 5.8 (4.8) 2.9
Other Assets 8.2 6.2 (0.6)
Other Liabilities (4.1) (3.4) (6.5)
Net Operating Activities from Discontinued Operations 2.3 108.8 133.3
- -------------------------------------------------------------------------------------------------------------------------
Cash from Operating Activities 53.5 175.0 247.4
- -------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Proceeds from Sale of Available-For-Sale Securities 376.0 1.9 7.4
Payments for Purchase of Available-For-Sale Securities (343.7) (149.5) -
Changes to Investments (1.1) 12.4 (16.6)
Additions to Property, Plant and Equipment (58.6) (57.8) (68.7)
Other 0.6 2.0 3.7
Net Investing Activities from Discontinued Operations 30.7 64.5 284.5
- -------------------------------------------------------------------------------------------------------------------------
Cash from (for) Investing Activities 3.9 (126.5) 210.3
- -------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Issuance of Common Stock 21.0 49.0 44.3
Issuance of Long-Term Debt 35.0 120.8 37.3
Reacquired Common Stock - (5.8) -
Changes in Notes Payable - Net - (53.0) (20.8)
Reductions of Long-Term Debt (35.7) (241.1) (335.7)
Dividends on Common Stock and Distributions to Minority Shareholders (36.7) (79.7) (93.2)
Redemption of Mandatorily Redeemable Preferred Securities - - (75.0)
Net Increase in Book Overdrafts 3.4 - -
Net Financing Activities for Discontinued Operations (0.9) (18.9) (27.6)
- -------------------------------------------------------------------------------------------------------------------------
Cash for Financing Activities (13.9) (228.7) (470.7)
- -------------------------------------------------------------------------------------------------------------------------
EFFECT OF EXCHANGE RATE CHANGES ON CASH - DISCONTINUED OPERATIONS - - 39.2
- -------------------------------------------------------------------------------------------------------------------------
CHANGE IN CASH AND CASH EQUIVALENTS 43.5 (180.2) 26.2
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 46.1 226.3 200.1
- -------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD <F1> $ 89.6 $ 46.1 $226.3
- -------------------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL CASH FLOW INFORMATION
Cash Paid During the Period for
Interest - Net of Amounts Capitalized $34.9 $46.7 $69.2
Income Taxes $27.1 $75.7 $87.4
- -------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Included $0 of cash from Discontinued Operations at December 31, 2005 ($2.4 million at December 31, 2004; $116.1
million at December 31, 2003).
</FN>
The accompanying notes are an integral part of these statements.
ALLETE 2005 Form 10-K Page 62
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, 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
Comprehensive Income
Net Income 13.3 13.3
Other Comprehensive Income - Net of Tax
Unrealized Gains on Securities - Net 0.6 0.6
Additional Pension Liability (2.0) (2.0)
---------
Total Comprehensive Income 11.9
Common Stock Issued - Net 21.0 21.0
Dividends Declared (34.4) (34.4)
Purchase of ALLETE Shares by ESOP (30.3) (30.3)
ESOP Shares Earned 4.1 4.1
- ------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2005 $ 602.8 $272.1 $(12.8) $(77.6) $421.1
- ------------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
Page 63 ALLETE 2005 Form 10-K
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. BUSINESS SEGMENTS
Presented below are the operating results and other financial information
related to our reporting segments. For a description of our reporting segments,
see Note 2.
In 2005, we began allocating corporate charges and interest expense to our
business segments. For comparative purposes, segment information for 2004 and
2003 has been restated to reflect the new allocation method used in 2005 for
corporate charges and interest expense. This restatement had no impact on
consolidated net income or earnings per share.
NONREGULATED
REGULATED ENERGY REAL
FOR THE YEAR ENDED DECEMBER 31 CONSOLIDATED UTILITY OPERATIONS ESTATE OTHER
- ------------------------------------------------------------------------------------------------------------------------------
MILLIONS
2005
Operating Revenue $737.4 $575.6 $113.9 $47.5 $ 0.4
Fuel and Purchased Power 273.1 243.7 29.4 - -
Operating and Maintenance 293.5 202.9 71.2 15.5 3.9
Kendall County Charge 77.9 - 77.9 - -
Depreciation Expense 47.8 39.4 8.1 0.1 0.2
- ------------------------------------------------------------------------------------------------------------------------------
Operating Income (Loss) from Continuing Operations 45.1 89.6 (72.7) 31.9 (3.7)
Interest Expense (26.4) (17.4) (6.6) (0.1) (2.3)
Other Income (Expense) 1.1 0.7 1.7 - (1.3)
- ------------------------------------------------------------------------------------------------------------------------------
Income (Loss) from Continuing Operations
Before Minority Interest and Income Taxes 19.8 72.9 (77.6) 31.8 (7.3)
Minority Interest 2.7 - - 2.7 -
- ------------------------------------------------------------------------------------------------------------------------------
Income (Loss) from Continuing Operations
Before Income Taxes 17.1 72.9 (77.6) 29.1 (7.3)
Income Tax Expense (Benefit) (0.5) 27.2 (29.1) 11.6 (10.2)
- ------------------------------------------------------------------------------------------------------------------------------
Income (Loss) from Continuing Operations 17.6 $ 45.7 $(48.5) $17.5 $ 2.9
----------------------------------------------------------
Loss from Discontinued Operations - Net of Tax (4.3)
- --------------------------------------------------------------
Net Income $ 13.3
- --------------------------------------------------------------
Total Assets $1,398.8 <F1> $909.5 $185.2 $73.7 $227.8
Capital Expenditures $63.1 <F1> $46.5 $12.1 - -
- ------------------------------------------------------------------------------------------------------------------------------
2004
Operating Revenue $704.1 $555.0 $106.8 $41.9 $ 0.4
Fuel and Purchased Power 286.2 245.1 41.1 - -
Operating and Maintenance 270.1 191.7 60.3 15.0 3.1
Depreciation Expense 46.9 39.5 7.2 0.1 0.1
- ------------------------------------------------------------------------------------------------------------------------------
Operating Income (Loss) from Continuing Operations 100.9 78.7 (1.8) 26.8 (2.8)
Interest Expense (31.7) (18.5) (4.9) (0.3) (8.0)
Other Income (Expense) (12.2) 0.1 0.6 - (12.9)
- ------------------------------------------------------------------------------------------------------------------------------
Income (Loss) from Continuing Operations
Before Minority Interest and Income Taxes 57.0 60.3 (6.1) 26.5 (23.7)
Minority Interest 2.1 - - 2.1 -
- ------------------------------------------------------------------------------------------------------------------------------
Income (Loss) from Continuing Operations
Before Income Taxes 54.9 60.3 (6.1) 24.4 (23.7)
Income Tax Expense (Benefit) 16.4 22.6 (3.2) 10.1 (13.1)
- ------------------------------------------------------------------------------------------------------------------------------
Income (Loss) from Continuing Operations 38.5 $ 37.7 $ (2.9) $14.3 $(10.6)
----------------------------------------------------------
Income from Discontinued Operations - Net of Tax 73.7
Change in Accounting Principle - Net of Tax (7.8)
- --------------------------------------------------------------
Net Income $104.4
- --------------------------------------------------------------
Total Assets $1,431.4 <F1> $902.8 $161.4 $75.1 $242.6
Capital Expenditures $79.2 <F1> $41.7 $15.7 - $0.4
- ------------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Discontinued Operations represented $2.6 million of total assets in 2005 ($49.5 million in 2004) and $4.5 million of
capital expenditures in 2005 ($21.4 million in 2004).
</FN>
ALLETE 2005 Form 10-K Page 64
NOTE 1. BUSINESS SEGMENTS (CONTINUED)
NONREGULATED
REGULATED ENERGY REAL
FOR THE YEAR ENDED DECEMBER 31 CONSOLIDATED UTILITY OPERATIONS ESTATE OTHER
- ------------------------------------------------------------------------------------------------------------------------------
MILLIONS
2003
Operating Revenue $659.6 $510.0 $106.6 $42.6 $ 0.4
Fuel and Purchased Power 252.5 212.5 40.0 - -
Operating and Maintenance 260.5 185.4 54.8 16.3 4.0
Depreciation Expense 48.9 41.2 7.4 0.1 0.2
- ------------------------------------------------------------------------------------------------------------------------------
Operating Income (Loss) from Continuing Operations 97.7 70.9 4.4 26.2 (3.8)
Interest Expense (50.5) (20.4) (4.8) (0.2) (25.1)
Other Income (Expense) 2.3 2.9 1.9 - (2.5)
- ------------------------------------------------------------------------------------------------------------------------------
Income (Loss) from Continuing Operations
Before Minority Interest and Income Taxes 49.5 53.4 1.5 26.0 (31.4)
Minority Interest 2.6 - - 2.6 -
- ------------------------------------------------------------------------------------------------------------------------------
Income (Loss) from Continuing Operations
Before Income Taxes 46.9 53.4 1.5 23.4 (31.4)
Income Tax Expense (Benefit) 17.7 21.0 0.4 9.8 (13.5)
- ------------------------------------------------------------------------------------------------------------------------------
Income (Loss) from Continuing Operations 29.2 $ 32.4 $ 1.1 $13.6 $(17.9)
----------------------------------------------------------
Income from Discontinued Operations - Net of Tax 207.2
- --------------------------------------------------------------
Net Income $236.4
- --------------------------------------------------------------
Total Assets $3,101.3 <F1> $917.3 $194.7 $78.6 $148.4
Capital Expenditures $136.3 <F1> $42.2 $26.5 - -
- ------------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Discontinued Operations represented $1,762.3 million of total assets and $67.6 million of capital expenditures.
</FN>
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. Certain reclassifications have been made to prior years' amounts
to conform to current year classifications. We revised our Consolidated
Statement of Cash Flows for the years ended December 31, 2004 and 2003, to
reconcile Net Income to Cash from Operating Activities. Previously, we
reconciled Income from Continuing Operations to Cash from Operating Activities.
In addition, we have reclassified certain amounts in our balance sheet, income
statement, cash flows and segment information to reflect discontinued operations
treatment for the sale of our telecommunications business. These
reclassifications had no effect on previously reported net income, shareholders'
equity, comprehensive income or cash flows.
REVISION IN THE CLASSIFICATION OF CERTAIN SECURITIES. In the quarterly period
ended June 30, 2005, we concluded that it was appropriate to reclassify our
auction rate municipal bonds and variable rate municipal demand notes as
short-term investments. Previously, such investments had been classified as cash
and cash equivalents. Accordingly, we now report these securities as short-term
investments in a separate line item on our Consolidated Balance Sheet as of
December 31, 2004. We have also made corresponding adjustments to our
Consolidated Statement of Cash Flows for the period ended December 31, 2004, to
reflect the gross purchases and sales of these securities as investing
activities rather than as a component of cash and cash equivalents. This change
in classification does not affect our previously reported Consolidated
Statements of Income for any period.
For the year ended December 31, 2004, net cash used in investing activities
related to these short-term investments of $149.2 million was included in cash
and cash equivalents in our Consolidated Statement of Cash Flows.
BUSINESS SEGMENTS. Our Regulated Utility, Nonregulated Energy Operations and
Real Estate segments were determined based on products and services provided and
the manner in which we monitor and manage the business. We measure performance
of our operations through budgeting and monitoring of contributions to
consolidated net income by each business segment. Discontinued Operations
includes our telecommunications business, which we sold on December 30, 2005,
our Automotive Services business that was spun off in September 2004, costs
associated with the spin-off of ADESA incurred by ALLETE, and our Water Services
businesses, the majority of which were sold in 2003.
Page 65 ALLETE 2005 Form 10-K
NOTE 2. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
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 151,000 retail customers in
northeastern Minnesota and northwestern Wisconsin. Approximately 41% 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 2007
through December 2014. Revenue of $83.5 million (11.3% of consolidated revenue)
was received from one taconite producer in 2005 (12.6% in 2004; 10.0% in 2003).
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 conservation improvement program
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). In 2004, prior to our withdrawal, we made power purchases from
Split Rock Energy of $6.2 million ($50.9 million in 2003) and power sales to
Split Rock Energy of $1.9 million ($19.6 million in 2003).
NONREGULATED ENERGY OPERATIONS includes our coal mining activities in North
Dakota and nonregulated generation (non-rate base generation sold at
market-based rates to the wholesale market) consisting primarily of Taconite
Harbor in northern Minnesota. Pending MPUC approval, Taconite Harbor will be
integrated into our Regulated Utility business effective retroactive to January
1, 2006, to help meet forecasted base load energy requirements. Nonregulated
generation also included generation secured through the Kendall County power
purchase agreement, which was assigned to Constellation Energy Commodities in
April 2005. (See Note 11.)
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. In certain cases, where
there are obligations to perform significant development activities after the
date of sale, we recognize profit on a percentage-of-completion basis in
accordance with SFAS 66. Pursuant to this method of accounting, gross profit is
recognized based upon the relationship of development costs incurred as of that
date to the total estimated costs to develop the parcels, including all related
amenities or common costs of the entire project. Revenue and cost of real estate
sold in excess of the amount recognized based on the percentage-of-completion
method is deferred and recognized as revenue and cost of real estate sold during
the period in which the related development costs are incurred. Revenue and cost
of real estate sold are recorded net as Deferred Profit on Sales of Real Estate
on our consolidated balance sheet.
Traffic impact fee credits are provided to the developer as mitigation payments
are made to the city. We are reimbursed after the land is sold and a subsequent
property owner constructs vertical improvements on the site. We recognize
revenue resulting from these reimbursed fees when they are received.
Land held for sale is recorded at the lower of cost or fair value determined by
the evaluation of individual land parcels and is included in Investments on our
consolidated balance sheet. Real estate costs include the cost of land acquired,
subsequent development costs and costs of improvements, capitalized development
period interest, real estate taxes and payroll costs of certain employees
devoted directly to the development effort. These real estate costs incurred are
capitalized to the cost of real estate parcels based upon the relative sales
value of parcels within each development project in accordance with SFAS 67,
"Accounting for Costs and Initial Rental Operations of Real Estate Projects."
When real estate is sold, the cost of real estate sold includes the actual costs
incurred and the estimate of future completion costs allocated to the real
estate sold based upon the relative sales value method.
Whenever events or circumstances indicate that the carrying value of the real
estate may not be recoverable, impairments would be recorded and the related
assets would be adjusted to their estimated fair value, less costs to sell.
OTHER includes investments in emerging technologies, and earnings on cash, cash
equivalents and short-term investments. 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 because of
our ownership percentage. Short-term investments consist of auction rate
municipal bonds and variable rate municipal demand notes, and are classified as
available-for-sale securities. All income generated from these short-term
investments is recorded as interest income.
ALLETE 2005 Form 10-K Page 66
NOTE 2. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
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. When regulated
utility property, plant and equipment are retired or otherwise disposed, no gain
or loss is recognized, pursuant to SFAS 71, "Accounting for the Effects of
Certain Types of Regulations." 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 a
construction project.
LONG-LIVED ASSET IMPAIRMENTS. 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 conduct this assessment using SFAS 144, "Accounting
for the Impairment and Disposal of Long-Lived Assets." 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 would recognize an impairment loss only if the carrying amount of a
long-lived asset is not recoverable from its undiscounted future cash flows.
Management judgment is involved in both deciding if testing for recoverability
is necessary and in estimating undiscounted cash flows.
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 2005 2004
- --------------------------------------------------------------------------------
MILLIONS
Trade Accounts Receivable
Billed $69.2 $69.5
Unbilled 10.9 10.2
Less: Allowance for Doubtful Accounts 1.0 1.0
- --------------------------------------------------------------------------------
Total Accounts Receivable - Net $79.1 $78.7
- --------------------------------------------------------------------------------
INVENTORIES. Inventories are stated at the lower of cost or market. Cost is
determined by the average cost method.
INVENTORIES
DECEMBER 31 2005 2004
- --------------------------------------------------------------------------------
MILLIONS
Fuel $11.0 $11.4
Materials and Supplies 22.1 20.4
- --------------------------------------------------------------------------------
Total Inventories $33.1 $31.8
- --------------------------------------------------------------------------------
UNAMORTIZED EXPENSE, DISCOUNT AND PREMIUM ON DEBT. Discount and premium on debt
are deferred and amortized over the terms of the related debt instruments using
the effective interest method.
CASH AND CASH EQUIVALENTS. We consider all investments purchased with original
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. At December 31, 2004, the ESOP had $30.3 million in
cash, which was used to purchase ALLETE common stock on the open market during
2005. We reflected the cash held by the ESOP as Restricted Cash on our
consolidated balance sheet. (See Note 18.) There was no restricted cash at
December 31, 2005.
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 fixed employee stock options granted. The after-tax expense
recognized for performance share awards was approximately $1.5 million in 2005
($1.0 million in 2004; $3.0 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."
Page 67 ALLETE 2005 Form 10-K
NOTE 2. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
EFFECT OF SFAS 123
ACCOUNTING FOR STOCK-BASED COMPENSATION
FOR THE YEAR ENDED DECEMBER 31 2005 2004 2003
- --------------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT PER SHARE AMOUNTS
Net Income
As Reported $13.3 $104.4 $236.4
Plus: Employee Stock Compensation Expense
Included in Net Income - Net of Tax 1.5 1.0 3.0
Less: Employee Stock Compensation Expense
Determined Under SFAS 123 - Net of Tax 1.5 1.3 3.5
- --------------------------------------------------------------------------------------------------------------------------
Pro Forma $13.3 $104.1 $235.9
- --------------------------------------------------------------------------------------------------------------------------
Basic Earnings Per Share
As Reported $0.49 $3.69 $8.56
Pro Forma $0.49 $3.68 $8.55
Diluted Earnings Per Share
As Reported $0.48 $3.67 $8.52
Pro Forma $0.48 $3.66 $8.49
- --------------------------------------------------------------------------------------------------------------------------
In the previous table, the pro forma expense for employee stock options granted
determined under SFAS 123 was calculated using the Black-Scholes option pricing
model and the following assumptions:
2005 2004 2003
- --------------------------------------------------------------------------------------------------------------------------
Risk-Free Interest Rate 3.7% 3.3% 3.1%
Expected Life - Years 5 5 5
Expected Volatility 20.0% 28.1% 25.2%
Dividend Growth Rate 5% 2% 2%
- --------------------------------------------------------------------------------------------------------------------------
FOREIGN CURRENCY TRANSLATION. Results of operations for our Canadian and Mexican
automotive subsidiaries prior to the spin-off in 2004 were translated into
United States dollars using the average exchange rates during the applicable
periods. Assets and liabilities were translated into United States dollars using
the exchange rate on the balance sheet date. Resulting translation adjustments
were recorded in Accumulated Other Comprehensive Income (Loss) in Shareholders'
Equity on our consolidated financial statements.
OTHER LIABILITIES
DECEMBER 31 2005 2004
- --------------------------------------------------------------------------------------------------------------------------
MILLIONS
Deferred Regulatory Credits (See Note 4) $ 31.8 $ 35.9
Deferred Compensation and Accrued Postretirement Benefits 59.5 66.3
Asset Retirement Obligations (See Note 3) 25.3 22.4
Other 27.5 25.9
- --------------------------------------------------------------------------------------------------------------------------
Total Other Liabilities $144.1 $150.5
- --------------------------------------------------------------------------------------------------------------------------
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 operating expense unless recoverable in rates from customers.
INCOME TAXES. We file a consolidated federal income tax return. 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 assets and
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.
ALLETE 2005 Form 10-K Page 68
NOTE 2. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
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.
NEW ACCOUNTING STANDARDS. SFAS 123(R). In December 2004, the FASB issued SFAS
123(R), "Share-Based Payment," which will be effective for enterprises beginning
with the first interim or annual reporting period of the registrants' first
fiscal year beginning on or 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 Opinion No. 25 will no longer be
allowed. Historically, we have elected to use the intrinsic value method and
have not recognized expense for employee stock options granted. We implemented
SFAS 123(R) January 1, 2006, using the modified prospective basis. We do not
anticipate changing compensation plans for this accounting treatment. We do not
believe it will have a material impact on our financial position, results of
operations or cash flows.
The FASB has clarified the adoption of SFAS 123(R) with FSP SFAS 123(R)-1
"Classification and Measurement of Freestanding Financial Instruments Originally
Issued in Exchange for Employee Services under FASB Statement No. 123(R)" and
FSP SFAS 123(R)-2 "Practical Accommodation to the Application of Grant Date as
Defined in FASB Statement No. 123(R)." These staff positions clarify the
implementation of SFAS 123(R). We do not believe they will have a material
impact on our financial position, results of operations or cash flows.
The FASB has proposed FSP SFAS 123(R)-c "Transition Election Related to
Accounting for the Tax Effects of Share-Based Payment Awards." This proposed
staff position provides for an alternate method for the implementation of SFAS
123(R). We do not believe it will have a material impact on the Company.
Interpretation No. 47. In March 2005, the FASB issued Interpretation No. 47,
"Accounting for Conditional Asset Retirement Obligations." Interpretation No. 47
clarifies that the term "conditional asset retirement obligation" as used in
SFAS 143, "Accounting for Asset Retirement Obligations," refers to a legal
obligation to perform an asset retirement activity in which the timing and/or
method of settlement are conditional on a future event that may or may not be
within the control of the entity. However, the obligation to perform the asset
retirement activity is unconditional even though uncertainty exists about the
timing and/or method of settlement. Interpretation No. 47 requires that the
uncertainty about the timing and/or method of settlement of a conditional asset
retirement obligation be factored into the measurement of the liability when
sufficient information exists. Interpretation No. 47 also clarifies when an
entity would have sufficient information to reasonably estimate the fair value
of an asset retirement obligation. Interpretation No. 47 is effective for fiscal
years ending after December 15, 2005. We have applied Interpretation No. 47 on a
prospective basis.
SFAS 153. In December 2004, the FASB issued SFAS 153, "Exchanges of Nonmonetary
Assets--An Amendment of APB Opinion No. 29, Accounting for Nonmonetary
Transactions." SFAS 153 eliminates the exception from fair value measurement for
nonmonetary exchanges of similar productive assets in paragraph 21(b) of APB
Opinion No. 29, Accounting for Nonmonetary Transactions, and replaces it with an
exception for exchanges that do not have commercial substance. SFAS 153
specifies that a nonmonetary exchange has commercial substance if the future
cash flows of the entity are expected to change significantly as a result of the
exchange. SFAS 153 is effective for fiscal periods beginning after June 15,
2005, and is required to be adopted beginning on January 1, 2006. We are
currently evaluating the effect that the adoption of SFAS 153 will have on our
consolidated results of operations and financial condition but do not expect it
to have a material impact.
SFAS 154. In May 2005, the FASB issued SFAS 154, "Accounting Changes and Error
Corrections" (SFAS 154) which replaces APB Opinion No. 20 "Accounting Changes"
and SFAS 3, "Reporting Accounting Changes in Interim Financial Statements--An
Amendment of APB Opinion No. 28." SFAS 154 provides guidance on the accounting
for and reporting of accounting changes and error corrections. It establishes
retrospective application, or the latest practicable date, as the required
method for reporting a change in accounting principle and the reporting of a
correction of an error. SFAS 154 is effective for accounting changes and
corrections of errors made in fiscal years beginning after December 15, 2005. We
are currently evaluating the effect that the adoption of SFAS 154 will have on
our consolidated results of operations and financial condition but do not expect
that adoption will have a material impact.
Page 69 ALLETE 2005 Form 10-K
NOTE 3. PROPERTY, PLANT AND EQUIPMENT
PROPERTY, PLANT AND EQUIPMENT
DECEMBER 31 2005 2004
- -------------------------------------------------------------------------------------------------------------------------
MILLIONS
Regulated Utility $1,457.4 $1,431.9
Construction Work in Progress 21.2 10.4
Accumulated Depreciation (743.5) (716.4)
- -------------------------------------------------------------------------------------------------------------------------
Regulated Utility Plant - Net 735.1 725.9
- -------------------------------------------------------------------------------------------------------------------------
Nonregulated Energy Operations 160.6 155.5
Construction Work in Progress 3.7 1.1
Accumulated Depreciation (43.9) (39.6)
- -------------------------------------------------------------------------------------------------------------------------
Nonregulated Energy Operations Plant - Net 120.4 117.0
- -------------------------------------------------------------------------------------------------------------------------
Other Plant - Net 4.9 6.7
- -------------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment - Net $ 860.4 $ 849.6
- -------------------------------------------------------------------------------------------------------------------------
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 4 to 31 years
Transmission 40 to 60 years
Distribution 30 to 70 years
Nonregulated Energy Operations 5 to 35 years
Other Plant 5 to 30 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.
Conditional asset retirement obligations have been identified for treated wood
poles and remaining polychlorinated biphenyl and asbestos-containing assets,
however, removal costs have not been recognized due to indeterminate settlement
dates.
ASSET RETIREMENT OBLIGATION
- --------------------------------------------------------------------------------
MILLIONS
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
Accretion Expense 1.6
Additional Liabilities Incurred in 2005 1.3
- --------------------------------------------------------------------------------
Obligation at December 31, 2005 $25.3
- --------------------------------------------------------------------------------
ALLETE 2005 Form 10-K Page 70
NOTE 4. REGULATORY MATTERS
ELECTRIC RATES. 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 2005 PSCW retail rate order. In 2005, 72% of our consolidated
operating revenue was under regulatory authority (75% in 2004; 73% in 2003). The
MPUC had regulatory authority over approximately 56% of our consolidated
operating revenue in 2005 (60% in 2004; 57% in 2003).
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 2005 2004
- --------------------------------------------------------------------------------
MILLIONS
Deferred Charges
Income Taxes $ 12.0 $ 12.9
Premium on Reacquired Debt 3.5 4.1
Other 1.7 2.0
- --------------------------------------------------------------------------------
17.2 19.0
Deferred Credits - Income Taxes 31.8 35.9
- --------------------------------------------------------------------------------
Net Deferred Regulatory Liabilities $(14.6) $(16.9)
- --------------------------------------------------------------------------------
NOTE 5. FINANCIAL INSTRUMENTS
SECURITIES INVESTMENTS. At December 31, 2005, 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. Short-Term Investments included various auction rate
municipal bonds and variable rate municipal demand notes. Income and realized
gains and losses from these investments were included in Other Income (Expense)
on our consolidated income statement.
AVAILABLE-FOR-SALE SECURITIES. At December 31, 2005, our available-for-sale
securities portfolio consisted of securities in a grantor trust established to
fund certain employee benefits included in Investments and various auction rate
municipal bonds and variable rate municipal demand notes included as Short-Term
Investments. Available-for-sale securities are recorded at fair value with
unrealized gains and losses included in accumulated other comprehensive income
(loss), net of tax. Unrealized losses that are other than temporary are
recognized in earnings. Our short-term investments classified as
available-for-sale securities, however, are recorded at cost, which approximates
fair market value due to their variable interest rates and typically reset every
7 to 35 days. Despite the long-term nature of their stated contractual
maturities, we have the ability to quickly liquidate these securities. As a
result, we had no cumulative gross unrealized holding gains (losses) or gross
realized gains (losses) from our short-term investments. All income generated
from these short-term investments was recorded as interest income. 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
share price trends and the impact of overall market conditions. As a result of
our periodic assessments, we did not record any impairment of available-for-sale
securities in 2005 or 2004.
During the fourth quarter of 2004, we sold 3.3 million shares of ADESA stock
received by our ESOP plan (see Note 18) 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 of 2004. 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.
Page 71 ALLETE 2005 Form 10-K
NOTE 5. FINANCIAL INSTRUMENTS (CONTINUED)
AVAILABLE-FOR-SALE SECURITIES
- -----------------------------------------------------------------------------------------------------------------------
MILLIONS
GROSS UNREALIZED
AT DECEMBER 31 COST GAIN (LOSS) FAIR VALUE
- -----------------------------------------------------------------------------------------------------------------------
2005 $135.2 $4.4 $(0.1) $139.5
2004 $176.4 $3.1 $(0.1) $179.4
2003 $24.1 $1.4 - $25.5
- -----------------------------------------------------------------------------------------------------------------------
NET
UNREALIZED
GAIN (LOSS)
IN OTHER
YEAR ENDED SALES GROSS REALIZED COMPREHENSIVE
DECEMBER 31 PROCEEDS GAIN (LOSS) INCOME
- -----------------------------------------------------------------------------------------------------------------------
2005 $32.3 - - $1.3
2004 $65.9 $11.5 - $1.6
2003 $6.4 $1.2 $(4.7) $2.4
- -----------------------------------------------------------------------------------------------------------------------
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 (see Note 15) and account for
our direct investment in privately-held companies under the cost method because
of our ownership percentage. The total carrying value of our emerging technology
portfolio was $9.2 million at December 31, 2005 ($13.6 million at December 31,
2004). 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.
Our basis in direct investments in privately-held companies included in the
emerging technology portfolio was zero at December 31, 2005 ($4.5 million at
December 31, 2004). In 2005, we recorded $5.1 million ($3.3 million after tax)
of impairments that related to direct investments in certain privately-held,
start-up companies whose future business prospects had significantly diminished.
Developments at these companies indicated that future commercial viability was
unlikely, as was new financing necessary to continue development. In 2004, we
recorded $6.5 million ($4.1 million after tax) of impairments. We did not record
any impairments in 2003.
FAIR VALUE OF FINANCIAL INSTRUMENTS. With the exception of the items listed
below, the estimated fair value of all financial instruments approximates the
carrying amount. The fair value 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
2005 $390.5 $392.5
2004 $391.2 $395.9
- --------------------------------------------------------------------------------
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 $10 million at December 31, 2005 ($9
million at December 31, 2004). 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, which allows us to closely manage collection of amounts
due.
ALLETE 2005 Form 10-K Page 72
NOTE 6. INVESTMENTS
At December 31, 2005, 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 2005 2004
- --------------------------------------------------------------------------------
MILLIONS
Real Estate Assets $ 73.7 $ 75.1
Debt and Equity Securities 34.8 35.8
Emerging Technology Investments (See Note 5) 9.2 13.6
- --------------------------------------------------------------------------------
Total Investments $117.7 $124.5
- --------------------------------------------------------------------------------
REAL ESTATE ASSETS 2005 2004
- --------------------------------------------------------------------------------
MILLIONS
Land Held for Sale Beginning Balance $47.2 $50.7
Additions during period: Capitalized Improvements 9.4 2.9
Deductions during period: Cost of Real Estate Sold (8.6) (6.4)
- --------------------------------------------------------------------------------
Land Held for Sale Ending Balance 48.0 47.2
Long-Term Finance Receivables 7.4 9.7
Other <F1> 18.3 18.2
- --------------------------------------------------------------------------------
Total Real Estate Assets $73.7 $75.1
- --------------------------------------------------------------------------------
<FN>
<F1> Consisted primarily of a shopping center.
</FN>
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 $0.6
million at December 31, 2005 ($0.7 million at December 31, 2004). Minority
interest associated with real estate operations was $6.0 million at December 31,
2005 ($5.6 million at December 31, 2004).
NOTE 7. SHORT-TERM AND LONG-TERM DEBT
SHORT-TERM DEBT. Total short-term debt outstanding at December 31, 2005, was
$2.7 million ($1.8 million at December 31, 2004) and consisted of Long-Term Debt
Due Within One Year.
As of December 31, 2005, we had bank lines of credit aggregating $120.0 million
($111.5 million at December 31, 2004), the majority of which were to expire in
December 2007. These bank lines of credit made financing available through
short-term bank loans and provided credit support for commercial paper. At
December 31, 2005, $1.1 million ($0 at December 31, 2004) was drawn on our lines
of credit leaving a $118.9 million balance available for use ($111.5 million at
December 31, 2004). The $1.1 million drawn amount relates to an $8.5 million
revolving development loan with CypressCoquina Bank that we entered into in
March 2005. The revolving development loan has an interest rate equal to the
prime rate, with an initial term of 36 months. The term of the loan may be
extended 24 months if certain conditions are met. The loan is guaranteed by
Lehigh Acquisition Corporation. Certain lines of credit required a commitment
fee of 0.15%. There was no commercial paper issued as of December 31, 2005, or
December 31, 2004.
In January 2006, we renewed, increased and extended a committed, syndicated,
unsecured revolving credit facility (Line) with LaSalle Bank National
Association for $150 million ($100 million at December 31, 2004). The Line
matures on January 11, 2011, and requires a commitment fee of 0.125%. At our
request and subject to certain conditions, the Line may be increased to $200
million and extended for two additional 12-month periods. The Line may be used
for general corporate purposes, working capital and to provide liquidity in
support of our commercial paper program. We may prepay amounts outstanding under
the Line in whole or in part at our discretion. Additionally, we may irrevocably
terminate or reduce the size of the Line prior to maturity.
Page 73 ALLETE 2005 Form 10-K
NOTE 7. SHORT-TERM AND LONG-TERM DEBT (CONTINUED)
LONG-TERM DEBT. The aggregate amount of long-term debt maturing during 2006 is
$2.7 million ($84.1 million in 2007; $57.4 million in 2008; $10.6 million in
2009; $4.9 million in 2010; and $230.8 million thereafter). Substantially all of
our electric plant is subject to the lien of the mortgages securing various
first mortgage bonds.
In August 2005, we issued $35 million in principal amount of First Mortgage
Bonds, 5.28% due 2020. Proceeds were used to redeem $35 million in principal
amount of First Mortgage Bonds, 7 1/2% Series originally due 2007.
In October 2005, we accepted an offer from certain institutional buyers in the
private placement market to purchase $50 million in principal amount of our
first mortgage bonds. When issued, on or about March 1, 2006, the bonds will
carry an interest rate of 5.69% and will have a term of 30 years. On January 30,
2006, we called for redemption on March 2, 2006, $50 million in principal amount
of First Mortgage Bonds, 7% Series due 2008.
LONG-TERM DEBT
DECEMBER 31 2005 2004
- --------------------------------------------------------------------------------
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
7% Series Due 2008 50.0 50.0
5.28% Series Due 2020 35.0 -
4.95% Pollution Control Series F Due 2022 111.0 111.0
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 2006 - 2025 40.4 41.1
- --------------------------------------------------------------------------------
Total Long-Term Debt 390.5 391.2
Less Due Within One Year 2.7 1.8
- --------------------------------------------------------------------------------
Net Long-Term Debt $387.8 $389.4
- --------------------------------------------------------------------------------
The 6.68% Series Due 2007 and the 7% Series Due 2007 cannot be redeemed prior to
maturity. The remaining debt may be redeemed in whole or in part at our option,
according to the terms of the obligations.
FINANCIAL COVENANTS. Our lines of credit and letters of credit supporting
certain long-term debt arrangements contain financial covenants. The most
restrictive covenant requires ALLETE to maintain a quarterly ratio of its funded
debt to total capital of less than or equal to .65 to 1.00. Failure to meet this
covenant 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. Some of ALLETE's 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.
ALLETE 2005 Form 10-K Page 74
NOTE 8. 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, 2005, 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, 2002 28.5 $814.9
2003 Employee Stock Purchase Plan 0.0 1.4
Invest Direct <F1> 0.3 19.9
Options and Stock Awards 0.3 23.0
- --------------------------------------------------------------------------------
Balance at December 31, 2003 29.1 859.2
2004 Employee Stock Purchase Plan 0.0 1.0
Invest Direct <F1> 0.3 18.1
ADESA IPO (See Note 14) - 70.1
Spin-Off of ADESA (See Note 14) - (600.2)
Receipt of ADESA Stock by ESOP - 27.8
Reacquired (0.1) (5.8)
Options and Stock Awards 0.4 29.9
- --------------------------------------------------------------------------------
Balance at December 31, 2004 29.7 400.1
2005 Employee Stock Purchase Plan 0.0 0.5
Invest Direct <F1> 0.2 10.5
Options and Stock Awards 0.2 10.0
- --------------------------------------------------------------------------------
Balance at December 31, 2005 30.1 $421.1
- --------------------------------------------------------------------------------
<FN>
<F1> Invest Direct is ALLETE's direct stock purchase and dividend reinvestment
plan.
</FN>
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.
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. For 2005, no
options to purchase shares of common stock were excluded from the computation of
diluted earnings per share because they were anti-dilutive due to the option
exercise prices being greater than the average market price of the common shares
during the period (0.1 million shares were excluded for 2004; 0 shares were
excluded for 2003).
Page 75 ALLETE 2005 Form 10-K
NOTE 8. COMMON STOCK AND EARNINGS PER SHARE (CONTINUED)
RECONCILIATION OF BASIC AND DILUTED
EARNINGS PER SHARE DILUTIVE
FOR THE YEAR ENDED DECEMBER 31 BASIC SECURITIES DILUTED
- ------------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT PER SHARE AMOUNTS
2005
Income from Continuing Operations $17.6 - $17.6
Common Shares 27.3 0.1 27.4
Per Share from Continuing Operations $0.65 - $0.64
2004
Income from Continuing Operations
Before Change in Accounting Principle $38.5 - $38.5
Common Shares 28.3 0.1 28.4
Per Share from Continuing Operations $1.37 - $1.35
2003
Income from Continuing Operations $29.2 - $29.2
Common Shares 27.6 0.2 27.8
Per Share from Continuing Operations $1.06 - $1.05
- ------------------------------------------------------------------------------------------------------------------------
NOTE 9. JOINTLY-OWNED ELECTRIC FACILITY
We own 80% of the 536-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., 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 of Boswell Unit 4, which
is included in property, plant and equipment at December 31, 2005, was $310
million ($309 million at December 31, 2004). The corresponding accumulated
depreciation balance was $162 million at December 31, 2005 ($157 million at
December 31, 2004).
NOTE 10. COMMITMENTS, GUARANTEES AND CONTINGENCIES
OFF-BALANCE SHEET ARRANGEMENTS. 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 was 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 2005,
2004 and 2003, we received notices from Minnkota Power that they will reduce our
output entitlement by approximately 5% on January 1, 2006, 2007, and 2008, to
66%, 60% and 55% 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, 2005, Square Butte had total
debt outstanding of $310.7 million. Total annual debt service for Square Butte
is expected to be approximately $26 million in each of the years 2006 through
2010. 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 2005 was
$56.4 million ($56.1 million in 2004 and $52.3 million in 2003). This reflects
Minnesota Power's pro rata share of total Square Butte costs, based on the 71%
output entitlement in 2005, 2004 and 2003. Included in this amount was Minnesota
Power's pro rata share of interest expense of $13.6 million in 2005 ($12.6
million in 2004; $12.8 million in 2003). 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 2005 Form 10-K Page 76
NOTE 10. COMMITMENTS, GUARANTEES AND CONTINGENCIES (CONTINUED)
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 operating leases is $6.4 million in
2006, $5.9 million in 2007, $5.2 million in 2008, $4.7 million in 2009, $4.2
million in 2010 and $46.9 million thereafter. Total rent expense was $6.2
million in 2005 ($3.8 million in 2004; $3.2 million in 2003).
COAL, RAIL 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 2006 to December 2011. Our
minimum annual payment obligations under these coal, rail and shipping
agreements are currently $40.5 million in 2006, $9.7 million in 2007, $10.1
million in 2008, $6.1 million in 2009 and no specific commitments beyond 2009.
Our minimum annual payment obligations will increase when annual nominations are
made for coal deliveries in future years.
FUEL CLAUSE RECOVERY OF MISO DAY 2 COSTS. Minnesota Power filed a petition with
the MPUC in February 2005 to amend its fuel clause to accommodate costs and
revenue related to MISO Day 2. On April 7, 2005, the MPUC approved interim
accounting treatment of MISO Day 2 costs to be accounted for on a net basis and
recovered through the fuel clause, subject to refund with interest. This interim
treatment has continued while the MPUC has addressed the cost recovery petitions
from Xcel Energy Inc., Otter Tail Power Company, Alliant Energy Corporation and
Minnesota Power.
On December 21, 2005, the MPUC issued an order which denied recovery through the
fuel clause of uplift charges, congestion revenue and expenses, and
administrative costs related to Minnesota Power's MISO Day 2 market activities.
Minnesota Power requested rehearing of the order in a filing made with the MPUC
on January 10, 2006. The other three utilities affected by the order also filed
for rehearing, as did the DOC and MISO. In a hearing on February 9, 2006, the
MPUC granted rehearing of the MISO Day 2 docket and suspended the refund
obligation. The MPUC will review the MISO Day 2 costs to determine which costs
should be recovered on a current basis through the fuel clause and which costs
are more appropriately deferred for potential recovery through base rates. The
Company is unable to predict the outcome of this matter.
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. The carrying value of our direct investments in privately-held,
start-up companies was zero at December 31, 2005 ($4.5 million at December 31,
2004). We have committed to make additional investments in certain emerging
technology venture capital funds. The total future commitment was $3.1 million
at December 31, 2005 ($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.
INVESTMENT IN ATC. On December 16, 2005, ALLETE entered into an agreement with
Wisconsin Public Service Corporation and WPS Investments, LLC that provides for
ALLETE, through its Wisconsin subsidiary, Rainy River Energy Corporation -
Wisconsin, to invest $60 million in ATC by the end of 2006. ALLETE's investment
will represent an estimated 9% ownership interest in ATC. The investment by
ALLETE's subsidiary in ATC is subject to review by the PSCW.
ENVIRONMENTAL MATTERS. Our businesses are subject to regulation of environmental
matters by various federal, state and local authorities. Due to future stricter
environmental requirements through legislation and/or rulemaking, we anticipate
that potential expenditures for environmental matters will be material and will
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.
Page 77 ALLETE 2005 Form 10-K
NOTE 10. COMMITMENTS, GUARANTEES AND CONTINGENCIES (CONTINUED)
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 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. 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 was to determine any impact to soil or
ground water between the former MGP site and Superior Bay. Site work for this
phase of the investigation was performed during October 2004, and the final
report was sent to the WDNR in March 2005. Additional site investigation was
performed during September and October 2005. It is anticipated that additional
site work will be performed in 2006. 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. The Company has 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. In May
2005, the PSCW approved the collection through rates of $150,000 of site
investigation costs that had been incurred at the time SWL&P filed their most
recent rate request. 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 the
Company continues to work with the insurer to determine the availability of
insurance coverage.
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 and
possible significant capital expenditures to comply. Minnkota Power has held
several meetings with the EPA to discuss the alleged violations. Discussions
between Minnkota Power and 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 the 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.
CLEAN WATER ACT - FISH IMPINGEMENT/ENTRAINMENT REDUCTION STANDARDS. 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 reduce fish mortality due to 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). The new rule for fish impingement mortality 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 timeframe. The
biological studies were initiated in 2005. 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. At this time, we cannot estimate the capital and/or aquatic
restoration expenditures that may be required to comply with the Section 316 (b)
Phase II Rule.
EPA CLEAN AIR INTERSTATE RULE AND CLEAN AIR MERCURY RULE. In March 2005, the EPA
announced the final Clean Air Interstate Rule (CAIR) that reduces and
permanently caps emissions of SO2 and NOX in many of the eastern United States.
The CAIR includes Minnesota as one of the 28 states it considers an "eastern"
state. The EPA also announced the final Clean Air Mercury Rule (CAMR) that
reduces and permanently caps electric utility mercury emissions in the
continental United States. The CAIR and the CAMR regulations have been
challenged in the court system, which may delay implementation or modify
provisions. Minnesota Power is participating in a legal challenge to the CAIR,
but is not participating in the challenge of the CAMR. However, if the CAMR and
the CAIR do go into effect, Minnesota Power expects to be required to (1) make
emissions reductions, (2) purchase mercury, SO2 and NOX allowances through the
EPA's cap-and-trade system, or (3) use a combination of both.
We believe that the CAIR contains flaws in its methodology and application,
which will cause Minnesota Power to incur significantly higher compliance costs.
Consequently, on July 11, 2005, Minnesota Power filed a Petition for Review with
the U.S. Court of Appeals for the District of Columbia Circuit. The Company also
filed a Petition for Reconsideration with the EPA. If the litigation and/or the
Petition for Reconsideration are successful, we expect to incur lower compliance
costs, consistent with the rules applicable to those states considered as
"western" states under the CAIR. On November 22, 2005, the EPA agreed to
reconsider certain aspects of its CAIR, including the Minnesota Power petition
addressing modeling used to determine Minnesota's inclusion in the CAIR region
and claims about inequities in the SO2 allowance methodology. The EPA
anticipates making a decision regarding the petitions in mid-March 2006.
ALLETE 2005 Form 10-K Page 78
NOTE 10. COMMITMENTS, GUARANTEES AND CONTINGENCIES (CONTINUED)
COMMUNITY DEVELOPMENT DISTRICT OBLIGATIONS. In March 2005, the Town Center at
Palm Coast Community Development District (Town Center District) issued $26.4
million of tax-exempt, 6% Capital Improvement Revenue Bonds, Series 2005, due
May 1, 2036. The bonds were issued to fund a portion of the Town Center
development project. Approximately $21 million of the bond proceeds will be used
for construction of infrastructure improvements at Town Center, with the
remaining funds to be used for capitalized interest, a debt service reserve fund
and costs of issuance. The bonds are payable from and secured by the revenue
derived from assessments imposed, levied and collected by the Town Center
District. The assessments represent an allocation of the costs of the
improvements, including bond financing costs, to the lands within the Town
Center District benefiting from the improvements. The assessments will be
included in the annual property tax bills of landowners beginning in November
2006. To the extent that we still own land at the time of the assessment, in
accordance with EITF 91-10, we will recognize an expense for our pro rata
portion of assessments, based upon our ownership of benefited property. At
December 31, 2005, we owned approximately 92% of the assessable land in the Town
Center District.
GUARANTEE. ALLETE guarantees $1.0 million of Northwest Airlines, Inc.'s
(Northwest Airlines) payments of principal and interest on $24.7 million of
"Duluth Airport Lease Revenue Bonds" (to be paid out of lease revenue from
Northwest Airlines to the Duluth Economic Development Authority). In 2005,
following Northwest Airlines' bankruptcy filing and its default on other
obligations, we recorded a $1.0 million ($0.6 million after tax) charge to
recognize the probable payments on this guarantee. In January 2006, Northwest
Airlines was delinquent in their rent payments and the bond trustee drew $62,000
on ALLETE's letter of credit that collateralized ALLETE's guarantee to make the
payment.
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 materially change our
present liquidity position, nor have a material adverse effect on our financial
condition.
NOTE 11. KENDALL COUNTY CHARGE
On April 1, 2005, Rainy River Energy, a wholly-owned subsidiary of ALLETE,
completed the assignment of its power purchase agreement with LSP-Kendall
Energy, LLC, the owner of an energy generation facility located in Kendall
County, Illinois, to Constellation Energy Commodities. Rainy River Energy paid
Constellation Energy Commodities $73 million in cash to assume the power
purchase agreement that remains in effect through mid-September 2017. The
payment resulted in a charge to our operating income in the second quarter of
2005. The tax benefits of the payment will be realized through a capital loss
carryback for federal income tax purposes and have been recorded as current
deferred income tax assets. The tax benefits are expected to be realized in
2006. In addition, consent, advisory and closing costs of $4.9 million were
incurred to complete the transaction. As a result of this transaction, ALLETE
incurred a charge to operating expenses totaling $77.9 million ($50.4 million
after tax, or $1.84 per diluted share) in the second quarter of 2005.
Page 79 ALLETE 2005 Form 10-K
NOTE 12. OTHER INCOME (EXPENSE)
FOR THE YEAR ENDED DECEMBER 31 2005 2004 2003
- ---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Debt Prepayment Premium and Unamortized Debt
Issuance Costs - $(18.5) -
Gain on ESOP's Sale of ADESA Stock (See Note 18) - 11.5 -
Loss on Emerging Technology Investments $(6.1) (8.6) $(3.4)
Split Rock Energy Equity Income (See Note 2) - - 2.9
Investments and Other Income 7.2 3.4 2.8
- ---------------------------------------------------------------------------------------------------------------------------
Total Other Income (Expense) $ 1.1 $(12.2) $ 2.3
- ---------------------------------------------------------------------------------------------------------------------------
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.
NOTE 13. INCOME TAX EXPENSE
INCOME TAX EXPENSE
YEAR ENDED DECEMBER 31 2005 2004 2003
- ---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Current Tax Expense
Federal $27.2 <F1> $11.2 $ 4.6
State 6.5 <F1> 6.3 3.2
- ---------------------------------------------------------------------------------------------------------------------------
Total Current Tax Expense 33.7 17.5 7.8
- ---------------------------------------------------------------------------------------------------------------------------
Deferred Tax Expense (Benefit)
Federal (26.4) <F1> 1.6 9.4
State (9.5) (2.3) 1.8
- ---------------------------------------------------------------------------------------------------------------------------
Total Deferred Tax Expense (Benefit) (35.9) (0.7) 11.2
- ---------------------------------------------------------------------------------------------------------------------------
Change in Valuation Allowance 3.0 0.9 0.1
Deferred Tax Credits (1.3) (1.3) (1.4)
- ---------------------------------------------------------------------------------------------------------------------------
Income Tax Expense (Benefit) for Continuing Operations (0.5) 16.4 17.7
Income Tax Expense for Discontinued Operations 3.4 57.6 125.8
Change in Accounting Principle - (5.5) -
- ---------------------------------------------------------------------------------------------------------------------------
Total Income Tax Expense $ 2.9 $68.5 $143.5
- ---------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Included a current federal tax benefit of $1.3 million, current state tax benefit of $0.4 million and a deferred
federal tax benefit of $25.8 million related to the Kendall County Charge. (See Note 11.)
</FN>
ALLETE 2005 Form 10-K Page 80
NOTE 13. INCOME TAX EXPENSE (CONTINUED)
RECONCILIATION OF TAXES FROM FEDERAL STATUTORY
RATE TO TOTAL INCOME TAX EXPENSE FOR CONTINUING OPERATIONS
YEAR ENDED DECEMBER 31 2005 2004 2003
- ---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Income from Continuing Operations
Before Minority Interest and Income Taxes $19.8 $57.0 $49.5
Statutory Federal Income Tax Rate 35% 35% 35%
- ---------------------------------------------------------------------------------------------------------------------------
Income Taxes Computed at 35% Statutory Federal Rate 6.9 20.0 17.3
Increase (Decrease) in Tax Due to:
Sale of ADESA Stock by ESOP - (4.1) -
Amortization of Deferred Investment Tax Credits (1.3) (1.3) (1.4)
State Income Taxes - Net of Federal Income Tax Benefit 1.1 3.6 2.8
Depletion (1.0) (0.6) (0.7)
Employee Benefits (0.5) (0.4) -
Domestic Manufacturing Deduction (0.4) - -
Regulatory Differences for Utility Plant (0.6) (0.6) 0.1
Positive Resolution of Audit Issues (3.7) - -
Other (1.0) (0.2) (0.4)
- ---------------------------------------------------------------------------------------------------------------------------
Total Income Tax Expense (Benefit) for Continuing Operations $ (0.5) $16.4 $17.7
- ---------------------------------------------------------------------------------------------------------------------------
The effective tax rate on income from continuing operations before minority
interest was a 2.5% benefit for 2005; (28.8% expense for 2004; 35.8% expense for
2003). The 2005 effective rate was impacted by three major items. Deferred taxes
were adjusted by $2.5 million to reflect comprehensive tax planning initiatives.
Current taxes were adjusted by $3.7 million to reflect the receipt of a positive
audit report. The 2005 effective rate also reflected an increase in taxes due to
the inability to recognize any state benefit for capital loss carryforwards.
DEFERRED TAX ASSETS AND LIABILITIES
DECEMBER 31 2005 2004
- -----------------------------------------------------------------------------------------------
MILLIONS
Deferred Tax Assets
Employee Benefits and Compensation $ 47.6 $ 46.9
Property Related 31.0 29.4
Kendall County Capital Loss 30.5 -
Investment Tax Credits 12.9 13.8
Unrealized Loss Booked Through Equity 8.8 8.2
Excess of Tax Value Over Book Value <F1> 5.6 4.9
Other 9.0 10.0
- -----------------------------------------------------------------------------------------------
Gross Deferred Tax Assets 145.4 113.2
Deferred Tax Asset Valuation Allowance (4.1) (1.1)
- -----------------------------------------------------------------------------------------------
Total Deferred Tax Assets 141.3 112.1
- -----------------------------------------------------------------------------------------------
Deferred Tax Liabilities
Property Related 210.8 210.5
Investment Tax Credits 18.3 19.7
Employee Benefits and Compensation 12.6 14.4
Fuel Clause Adjustment 5.4 2.8
Other 1.6 3.9
- -----------------------------------------------------------------------------------------------
Total Deferred Tax Liabilities 248.7 251.3
- -----------------------------------------------------------------------------------------------
Accumulated Deferred Income Taxes $107.4 $139.2
- -----------------------------------------------------------------------------------------------
Recorded as:
Current Deferred Tax Assets $ 31.0 -
Long-Term Deferred Tax Liabilities 138.4 $139.2
- -----------------------------------------------------------------------------------------------
Net Deferred Tax Liabilities $107.4 $139.2
- -----------------------------------------------------------------------------------------------
<FN>
<F1> Included impairments related to the emerging technology portfolio.
</FN>
Page 81 ALLETE 2005 Form 10-K
NOTE 14. DISCONTINUED OPERATIONS
ENVENTIS TELECOM. On December 30, 2005, we sold all the stock of our
telecommunications subsidiary, Enventis Telecom, to HickoryTech of Mankato,
Minnesota, for $35.5 million. The transaction resulted in an after-tax loss of
$3.6 million, which was included in our 2005 loss from discontinued operations.
Net cash proceeds realized from the sale were approximately $29 million after
transaction costs, repayment of debt and payment of income taxes. In accordance
with SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets,"
we have reported our telecommunications business in discontinued operations for
all periods presented. Our telecommunications business was previously included
in our business segment identified as Other.
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
September 13, 2004, the 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 Utilities
purchased our North Carolina water assets for $48 million and assumed
approximately $28 million in debt. Aqua Utilities 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. On December 20, 2005, the FPSC
ordered a $1.7 million reduction to plant investment, which the Company reserved
for in 2005, and approved the transfer of the remaining 63 water and wastewater
systems from Florida Water to Aqua Utilities. Aqua Utilities filed a protest and
requested that the FPSC schedule evidentiary hearings. The FPSC's decision on
these issues may change the reduction to plant investment ordered in 2005 and
could result in an adjustment to the final purchase price paid by Aqua
Utilities. 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).
In February 2005, we completed the exit from our Water Services businesses with
the sale of our wastewater assets in Georgia for an immaterial gain. In 2005, we
also incurred administrative and other expenses to support Florida Water
transfer proceedings and recorded the $1.7 million rate-base settlement charge
related to the sale of 63 of Florida Water systems to Aqua Utilities mentioned
above.
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 and $12.9 million in 2003.
ALLETE 2005 Form 10-K Page 82
NOTE 14. DISCONTINUED OPERATIONS (CONTINUED)
SUMMARY DISCONTINUED OPERATIONS
- ---------------------------------------------------------------------------------------------------------
MILLIONS
SUMMARY INCOME STATEMENT
FOR THE YEAR ENDED DECEMBER 31 2005 2004 2003
- ---------------------------------------------------------------------------------------------------------
Operating Revenue
Automotive Services - $681.7 $ 924.1
Water Services - 18.5 107.4
Enventis Telecom $50.7 47.3 32.7
- ---------------------------------------------------------------------------------------------------------
Total Operating Revenue $50.7 $747.5 $1,064.2
- ---------------------------------------------------------------------------------------------------------
Pre-Tax Income (Loss) from Operations
Automotive Services - $132.5 $185.4
Water Services - (1.7) 34.4
Enventis Telecom $ 3.0 1.0 1.1
- ---------------------------------------------------------------------------------------------------------
3.0 131.8 220.9
- ---------------------------------------------------------------------------------------------------------
Income Tax Expense (Benefit)
Automotive Services - 54.0 73.1
Water Services - (0.9) 13.0
Enventis Telecom 1.2 0.4 0.5
- ---------------------------------------------------------------------------------------------------------
1.2 53.5 86.6
- ---------------------------------------------------------------------------------------------------------
Total Net Income from Operations 1.8 78.3 134.3
- ---------------------------------------------------------------------------------------------------------
Gain (Loss) on Disposal
Automotive Services - (6.7) 2.0
Water Services (4.5) 6.2 110.1
Enventis Telecom 0.6 - -
- ---------------------------------------------------------------------------------------------------------
(3.9) (0.5) 112.1
- ---------------------------------------------------------------------------------------------------------
Income Tax Expense (Benefit)
Automotive Services - (2.6) 0.7
Water Services (2.0) 6.7 38.5
Enventis Telecom 4.2 - -
- ---------------------------------------------------------------------------------------------------------
2.2 4.1 39.2
- ---------------------------------------------------------------------------------------------------------
Net Gain (Loss) on Disposal (6.1) (4.6) 72.9
- ---------------------------------------------------------------------------------------------------------
Income (Loss) from Discontinued Operations $(4.3) $ 73.7 $207.2
- ---------------------------------------------------------------------------------------------------------
SUMMARY BALANCE SHEET INFORMATION
DECEMBER 31 2005 2004
- ---------------------------------------------------------------------------------------------------------
Assets of Discontinued Operations
Cash and Cash Equivalents - $2.4
Other Current Assets $0.4 $10.7
Property, Plant and Equipment $2.2 $36.4
Liabilities of Discontinued Operations
Current Liabilities $13.0 $24.5
- ---------------------------------------------------------------------------------------------------------
Page 83 ALLETE 2005 Form 10-K
NOTE 15. 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 ($0 in 2005).
PRO FORMA AMOUNTS ASSUMING THE EQUITY METHOD WAS APPLIED RETROACTIVELY
FOR THE YEAR ENDED DECEMBER 31 2003
- --------------------------------------------------------------------------------
MILLIONS EXCEPT PER SHARE AMOUNTS
Net Income
As Reported $236.4
Pro Forma Adjustment (2.3)
- --------------------------------------------------------------------------------
Pro Forma $234.1
- --------------------------------------------------------------------------------
Basic Earnings Per Share
As Reported $8.56
Pro Forma Adjustment (0.08)
- --------------------------------------------------------------------------------
Pro Forma $8.48
- --------------------------------------------------------------------------------
Diluted Earnings Per Share
As Reported $8.52
Pro Forma Adjustment (0.08)
- --------------------------------------------------------------------------------
Pro Forma $8.44
- --------------------------------------------------------------------------------
ALLETE 2005 Form 10-K Page 84
NOTE 16. OTHER COMPREHENSIVE INCOME (LOSS)
OTHER COMPREHENSIVE INCOME PRE-TAX TAX EXPENSE NET-OF-TAX
YEAR ENDED DECEMBER 31 AMOUNT (BENEFIT) AMOUNT
- ------------------------------------------------------------------------------------------------------------------------
MILLIONS
2005
Unrealized Gain on Securities During the Year $ 1.3 $ 0.7 $ 0.6
Additional Pension Liability (3.4) (1.4) (2.0)
- ------------------------------------------------------------------------------------------------------------------------
Other Comprehensive Loss $(2.1) $(0.7) $(1.4)
- ------------------------------------------------------------------------------------------------------------------------
2004
Unrealized Gain 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 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
- ------------------------------------------------------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
DECEMBER 31 2005 2004
- ------------------------------------------------------------------------------------------------------------------------
MILLIONS
Unrealized Gain on Securities $ 2.1 $ 1.5
Additional Pension Liability (14.9) (12.9)
- ------------------------------------------------------------------------------------------------------------------------
Total Accumulated Other Comprehensive Loss $(12.8) $(11.4)
- ------------------------------------------------------------------------------------------------------------------------
Page 85 ALLETE 2005 Form 10-K
NOTE 17. 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 18), except for BNI Coal, which made
cash contributions of $0.7 million in 2005 ($0.6 million in each of the years
2004 and 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. In
December 2005, after the measurement date, $11.4 million was transferred from
the grantor trust to the VEBAs.
We use a September 30 measurement date for the pension and postretirement health
and life plans.
PENSION OBLIGATION AND FUNDED STATUS
AT SEPTEMBER 30 2005 2004
- ----------------------------------------------------------------------------------------------------------
MILLIONS
Change in Benefit Obligation
Obligation, Beginning of Year $380.0 $353.4
Service Cost 8.7 8.4
Interest Cost 21.3 20.7
Actuarial Loss 16.6 10.0
Benefits Paid (18.9) (17.3)
Other 4.7 4.8
- ----------------------------------------------------------------------------------------------------------
Obligation, End of Year 412.4 380.0
- ----------------------------------------------------------------------------------------------------------
Change in Plan Assets
Fair Value, Beginning of Year 310.1 285.3
Actual Return on Assets 40.6 28.9
Employer Contribution 0.6 8.4
Benefits Paid (18.9) (17.3)
Other 4.7 4.8
- ----------------------------------------------------------------------------------------------------------
Fair Value, End of Year 337.1 310.1
- ----------------------------------------------------------------------------------------------------------
Funded Status (75.3) (69.9)
Unrecognized Amounts
Net Loss 90.6 89.3
Prior Service Cost 4.5 5.2
Transition Obligation (0.1) -
- ----------------------------------------------------------------------------------------------------------
Net Assets Recognized $ 19.7 $ 24.6
- ----------------------------------------------------------------------------------------------------------
Amounts Recognized in Consolidated Balance Sheet Consist of:
Prepaid Pension Cost $33.8 $33.3
Accrued Benefit Liability (42.3) (33.8)
Intangible Assets 2.3 2.6
Accumulated Other Comprehensive Income 25.9 22.5
- ----------------------------------------------------------------------------------------------------------
Net Assets Recognized $19.7 $24.6
- ----------------------------------------------------------------------------------------------------------
COMPONENTS OF NET PERIODIC PENSION EXPENSE (INCOME)
YEAR ENDED DECEMBER 31 2005 2004 2003
- ------------------------------------------------------------------------------------------------------------
MILLIONS
Service Cost $ 8.7 $ 8.4 $ 6.7
Interest Cost 21.3 20.7 19.5
Expected Return on Assets (28.2) (27.4) (28.8)
Amortized Amounts
Unrecognized Loss 3.1 1.4 -
Prior Service Cost 0.2 0.8 0.9
Transition Obligation 0.6 0.3 0.2
- ------------------------------------------------------------------------------------------------------------
Net Pension Expense (Income) $ 5.7 $ 4.2 $(1.5)
- ------------------------------------------------------------------------------------------------------------
ALLETE 2005 Form 10-K Page 86
NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (CONTINUED)
INFORMATION FOR PENSION PLANS WITH AN
ACCUMULATED BENEFIT OBLIGATION IN EXCESS OF PLAN ASSETS
AT SEPTEMBER 30 2005 2004
- -------------------------------------------------------------------------------------------------------------------------
MILLIONS
Projected Benefit Obligation $177.5 $163.1
Accumulated Benefit Obligation $157.7 $140.6
Fair Value of Plan Assets $116.3 $108.8
- -------------------------------------------------------------------------------------------------------------------------
ADDITIONAL PENSION INFORMATION
YEAR ENDED DECEMBER 31 2005 2004 2003
- -------------------------------------------------------------------------------------------------------------------------
MILLIONS
Increase in Minimum Liability Included in Other Comprehensive Income $3.4 $5.7 $10.8
- -------------------------------------------------------------------------------------------------------------------------
The accumulated benefit obligation for all defined benefit pension plans was
$369.5 million and $332.9 million at September 30, 2005 and 2004, respectively.
POSTRETIREMENT HEALTH AND LIFE OBLIGATION AND FUNDED STATUS
AT SEPTEMBER 30 2005 2004
- -------------------------------------------------------------------------------------------------------------------------
MILLIONS
Change in Benefit Obligation
Obligation, Beginning of Year $117.2 $117.2
Service Cost 4.0 3.9
Interest Cost 6.6 6.5
Actuarial Loss (Gain) 13.1 (6.6)
Participation Contributions 1.3 1.1
Benefits Paid (5.3) (4.9)
- -------------------------------------------------------------------------------------------------------------------------
Obligation, End of Year 136.9 117.2
- -------------------------------------------------------------------------------------------------------------------------
Change in Plan Assets
Fair Value, Beginning of Year 54.1 46.9
Actual Return on Assets 7.1 6.1
Employer Contribution 3.6 4.9
Participation Contributions 1.4 1.1
Benefits Paid (5.3) (4.9)
- -------------------------------------------------------------------------------------------------------------------------
Fair Value, End of Year 60.9 54.1
- -------------------------------------------------------------------------------------------------------------------------
Funded Status (76.0) (63.1)
Unrecognized Amounts
Net Loss 25.8 15.5
Transition Obligation 17.4 20.0
- -------------------------------------------------------------------------------------------------------------------------
Accrued Cost $(32.8) $(27.6)
- -------------------------------------------------------------------------------------------------------------------------
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 $22.6 million in an
irrevocable grantor trust at December 31, 2005 ($28.8 million at December 31,
2004). 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 2005 2004 2003
- -------------------------------------------------------------------------------------------------------------------------
MILLIONS
Service Cost $4.0 $3.9 $3.7
Interest Cost 6.7 6.6 6.6
Expected Return on Assets (4.8) (4.6) (4.0)
Amortized Amounts
Unrecognized Loss 0.7 0.4 0.1
Transition Obligation 2.4 2.4 2.4
- -------------------------------------------------------------------------------------------------------------------------
Net Expense $9.0 $8.7 $8.8
- -------------------------------------------------------------------------------------------------------------------------
Page 87 ALLETE 2005 Form 10-K
NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (CONTINUED)
POSTRETIREMENT
ESTIMATED FUTURE BENEFIT PAYMENTS PENSION HEALTH AND LIFE
- -------------------------------------------------------------------------------------------------------------------------
MILLIONS
2006 $19 $5
2007 $19 $5
2008 $20 $6
2009 $21 $6
2010 $22 $7
Years 2011 - 2015 $129 $42
- -------------------------------------------------------------------------------------------------------------------------
WEIGHTED-AVERAGE ASSUMPTIONS
USED TO DETERMINE BENEFIT OBLIGATION
AT SEPTEMBER 30 2005 2004
- -------------------------------------------------------------------------------------------------------------------------
Discount Rate 5.50% 5.75%
Rate of Compensation Increase 3.5 - 4.5% 3.5 - 4.5%
Health Care Trend Rates
Trend Rate 10% 11%
Ultimate Trend Rate 5% 5%
Year Ultimate Trend Rate Effective 2010 2011
- -------------------------------------------------------------------------------------------------------------------------
WEIGHTED-AVERAGE ASSUMPTIONS
USED TO DETERMINE NET PERIODIC BENEFIT COSTS
YEAR ENDED DECEMBER 31 2005 2004 2003
- -------------------------------------------------------------------------------------------------------------------------
Discount Rate 5.75% 6.0% 6.75%
Expected Long-Term Return on Plan Assets
Pension 9.0% 9.0% 9.5%
Postretirement Health and Life 5.0 - 9.0% 7.2 - 9.0% 7.6 - 9.5%
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.
Currently for plan valuation purposes, the discount rate is determined
considering high-quality long-term corporate bond rates at the valuation date.
The discount rate is compared to various bond indices for reasonableness.
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 $1.6 $(1.3)
Effect on Postretirement Health and Life Obligation $17.5 $(14.4)
- -------------------------------------------------------------------------------------------------------------------------
POSTRETIREMENT
PENSION HEALTH AND LIFE <F1>
PLAN ASSET ALLOCATIONS 2005 2004 2005 2004
- -------------------------------------------------------------------------------------------------------------------------
Equity Securities 64.9% 60.4% 68.6% 64.4%
Debt Securities 29.6 30.9 30.5 34.9
Real Estate 1.3 2.2 - -
Venture Capital 2.9 5.2 - -
Cash 1.3 1.3 0.9 0.7
- -------------------------------------------------------------------------------------------------------------------------
100.0% 100.0% 100.0% 100.0%
- -------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Included VEBAs and irrevocable grantor trust.
</FN>
Pension plan equity securities include ALLETE common stock in the amount of
$22.6 million (7.3% of total plan assets) at September 30, 2004. Pension plan
equity securities did not include ALLETE common stock at September 30, 2005.
ALLETE 2005 Form 10-K Page 88
NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (CONTINUED)
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 <F1>
- ----------------------------------------------------------------------------------------------------------------------
Equity Securities 62% 66%
Debt Securities 30 33
Real Estate 2 -
Venture Capital 5 -
Cash 1 1
- ----------------------------------------------------------------------------------------------------------------------
100% 100%
- ----------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Included VEBAs and irrevocable grantor trust.
</FN>
We expect to contribute approximately $8 million to our postretirement health
and life plans and approximately $10 million to our defined benefit pension
plans in 2006.
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 $3.5 million for 2005 ($1.6 million
for 2004).
In 2005, we determined that our postretirement health care plans meet the
requirements of the Centers for Medicare and Medicaid Services' (CMS)
regulations, and enrolled with the CMS to begin recovering the subsidy. We
expect to receive the first subsidy check in early 2007 for 2006 credits.
NOTE 18. 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 0.6 million shares
(0.4 million shares adjusted for stock splits) 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 2.8 million shares (1.9 million shares adjusted for stock
splits) 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 less dividends on allocated 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 $5.5 million in 2005 ($5.0 million in
2004; $3.7 million in 2003).
As a result of the September 2004 spin-off of ADESA, the ESOP received 3.3
million shares of ADESA common stock related to unearned ESOP shares that had
not been allocated to participants. The ESOP was required to sell the ADESA
common stock and use the proceeds to purchase ALLETE common stock on the open
market. 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. (See Note 12.)
Under the direction of an independent trustee, the ESOP began using the proceeds
to purchase shares of ALLETE common stock in October 2004. As of February 15,
2005, the remaining proceeds ($30.3 million classified as Restricted Cash at
December 31, 2004) had been used to purchase ALLETE common stock, which were
recorded using the treasury method as Unearned ESOP Shares within Shareholders'
Equity as presented on our consolidated balance sheet.
Page 89 ALLETE 2005 Form 10-K
NOTE 18. EMPLOYEE STOCK AND INCENTIVE PLANS (CONTINUED)
SUMMARY OF ALLETE COMMON STOCK PURCHASES SHARES AMOUNT
- ---------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT SHARES
2004 October 80,600 $ 2.7
November 669,578 23.5
December 262,600 9.4
2005 January 544,797 21.4
February 214,928 8.9
- ---------------------------------------------------------------------------------------------------------------------
1,772,503 $65.9
- ---------------------------------------------------------------------------------------------------------------------
In September 2005, the ESOP's independent trustee directed the sale of
approximately 1.4 million shares of ADESA common stock that remained invested in
the RSOP participants' ADESA common stock funds at September 1, 2005. Proceeds
from the sale of the ADESA common stock were $30.4 million, of which the
majority was used to purchase ALLETE common stock as required by the terms of
the RSOP. The process was completed on October 26, 2005. Proceeds totaling $28.5
million were used to purchase a total of 644,450 shares of ALLETE common stock
(289,900 shares in September 2005; 354,550 shares in October 2005).
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 2005 2004 2003
- --------------------------------------------------------------------------------------------------------------------------
MILLIONS
ESOP Shares
Allocated 1.9 1.4 1.2
Unallocated 2.6 2.0 1.1
- --------------------------------------------------------------------------------------------------------------------------
Total 4.5 3.4 2.3
- --------------------------------------------------------------------------------------------------------------------------
Fair Value of Unallocated Shares $115.0 $72.7 $105.0
- --------------------------------------------------------------------------------------------------------------------------
STOCK OPTION AND AWARD PLANS. We have an Executive Long-Term Incentive
Compensation Plan (Executive Plan) that 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. 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
three years, with expiration ten years from the date of the 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, 2005, 1.1 million shares
were held in reserve for future issuance under the Executive Plan.
We had a Director Long-Term Stock Incentive Plan (Director Plan) which expired
on January 1, 2006. No grants have been made since 2003 under the Director Plan.
Approximately 9,900 options were outstanding at December 31, 2005.
2004 2003
------------------------------------------------------
WEIGHTED WEIGHTED
AVERAGE AVERAGE
EXERCISE EXERCISE
STOCK OPTION ACTIVITY <F1> OPTIONS PRICE OPTIONS PRICE
- ---------------------------------------------------------------------------------------------------------------------------
OPTIONS IN MILLIONS
Outstanding, Beginning of Period 0.8 $64.47 0.8 $67.44
Granted 0.1 $97.65 0.2 $61.77
Exercised (0.4) $67.14 (0.2) $61.32
Cancelled - - - $68.13
- ---------------------------------------------------------------------------------------------------------------------------
Outstanding, End of Period 0.5 $69.85 0.8 $64.47
- ---------------------------------------------------------------------------------------------------------------------------
Exercisable, End of Period - - 0.5 $67.26
Fair Value of Options Granted During the Period $20.01 $8.16
- ---------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> All amounts above are prior to the ADESA spin-off and the historical option and weighted 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.
</FN>
ALLETE 2005 Form 10-K Page 90
NOTE 18. EMPLOYEE STOCK AND INCENTIVE PLANS (CONTINUED)
2004
--------------------
WEIGHTED
AVERAGE
EXERCISE
STOCK OPTION ACTIVITY <F1> 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
- -----------------------------------------------------------------------------------------------------
<FN>
<F1> Amounts subsequent to the ADESA spin-off.
</FN>
2005
--------------------
WEIGHTED
AVERAGE
EXERCISE
STOCK OPTION ACTIVITY OPTIONS PRICE
- -----------------------------------------------------------------------------------------------------
OPTIONS IN MILLIONS
Outstanding, Beginning of Year 0.4 $28.94
Granted 0.1 $41.35
Exercised (0.1) $26.74
Cancelled - -
- -----------------------------------------------------------------------------------------------------
Outstanding, End of Year 0.4 $34.29
- -----------------------------------------------------------------------------------------------------
Exercisable, End of Year 0.2 $28.35
Fair Value of Options Granted During the Year $6.51
- -----------------------------------------------------------------------------------------------------
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, 2005, options outstanding consisted of less than 0.1 million
with exercise prices ranging from $15.88 to $18.85, 0.1 million with exercise
prices ranging from $23.79 to $29.79 and 0.2 million with exercise prices
ranging from $37.76 to $41.35. The options with exercise prices ranging from
$23.79 to $29.79 have an average remaining contractual life of 5.7 years, with
0.1 million exercisable on December 31, 2005, at a weighted average price of
$26.85. The options with exercise prices ranging from $37.76 to $41.35 have an
average remaining contractual life of 8.6 years, with less than 0.1 million
exercisable on December 31, 2005 at a weighted average price of $37.87.
Less than 0.1 million performance share grants were awarded in February 2005 for
performance periods ending in 2007. 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 $1.0
million.
A total of 0.1 million performance share grants were awarded in February 2004
for the performance periods ended December 31, 2005 and 2006. The grant date
fair value of the share awards was $1.6 million. Performance share grants
related to the 2005 period will be issued in early 2006.
In February 2006, we granted stock options to purchase 0.1 million shares of
common stock (exercise price of $44.15 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, 2005, 0.5 million shares had been
issued under the plan and 0.1 million shares were held in reserve for future
issuance.
Page 91 ALLETE 2005 Form 10-K
NOTE 19. 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 second
quarter of 2005 included a $50.4 million, or $1.84 per share, charge related to
the assignment of the Kendall County purchase power agreement. (See Note 11.)
Financial results for the fourth quarter of 2005 included a $2.5 million, or
$0.09 per share, deferred tax benefit due to comprehensive tax planning
initiatives and a $3.7 million, or $0.13 per share, current tax benefit due to a
positive resolution of income tax audit issues.
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.
QUARTER ENDED MAR. 31 JUN. 30 SEPT. 30 DEC. 31
- -------------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT EARNINGS PER SHARE
2005
Operating Revenue $193.3 $174.4 $177.4 $192.3
- -------------------------------------------------------------------------------------------------------------------------
Operating Income (Loss) from Continuing Operations $41.1 $(56.0) $32.7 $27.3
- -------------------------------------------------------------------------------------------------------------------------
Income (Loss) Continuing Operations $17.4 $(39.8) $15.8 $24.2
Discontinued Operations - (0.5) (0.6) (3.2)
- -------------------------------------------------------------------------------------------------------------------------
Net Income (Loss) $17.4 $(40.3) $15.2 $21.0
- -------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) Per Share of Common Stock
Basic Continuing Operations $0.64 $(1.46) $0.58 $0.89
Discontinued Operations - (0.02) (0.02) (0.12)
- -------------------------------------------------------------------------------------------------------------------------
$0.64 $(1.48) $0.56 $0.77
- -------------------------------------------------------------------------------------------------------------------------
Diluted Continuing Operations $0.64 $(1.46) $0.58 $0.88
Discontinued Operations - (0.02) (0.02) (0.12)
- -------------------------------------------------------------------------------------------------------------------------
$0.64 $(1.48) $0.56 $0.76
- -------------------------------------------------------------------------------------------------------------------------
2004
Operating Revenue $198.0 $170.4 $166.9 $168.8
- -------------------------------------------------------------------------------------------------------------------------
Operating Income from Continuing Operations $44.2 $18.6 $22.5 $15.6
- -------------------------------------------------------------------------------------------------------------------------
Income (Loss) Continuing Operations $21.4 $ 2.0 $(1.0) $16.1
Discontinued Operations 31.3 34.7 14.1 (6.4)
Change in Accounting Principle (7.8) - - -
- -------------------------------------------------------------------------------------------------------------------------
Net Income $44.9 $36.7 $13.1 $ 9.7
- -------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) Per Share of Common Stock
Basic Continuing Operations $0.77 $0.06 $(0.03) $0.57
Discontinued Operations 1.11 1.23 0.48 (0.22)
Change in Accounting Principle (0.28) - - -
- -------------------------------------------------------------------------------------------------------------------------
$1.60 $1.29 $ 0.45 $0.35
- -------------------------------------------------------------------------------------------------------------------------
Diluted Continuing Operations $0.76 $0.06 $(0.03) $0.56
Discontinued Operations 1.10 1.23 0.48 (0.22)
Change in Accounting Principle (0.27) - - -
- -------------------------------------------------------------------------------------------------------------------------
$1.59 $1.29 $ 0.45 $0.34
- -------------------------------------------------------------------------------------------------------------------------
ALLETE 2005 Form 10-K Page 92
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 <F1> PERIOD
- ----------------------------------------------------------------------------------------------------------------------------
MILLIONS
Reserve Deducted from Related Assets
Reserve For Uncollectible Accounts
2005 Trade Accounts Receivable $1.0 $1.1 - $1.1 $1.0
Finance Receivables - Long-Term 0.7 - - 0.1 0.6
2004 Trade Accounts Receivable 1.1 0.9 - 1.0 1.0
Finance Receivables - Long-Term 1.2 - - 0.5 0.7
2003 Trade Accounts Receivable 2.1 0.6 - 1.6 1.1
Finance Receivables - Long-Term 1.7 - - 0.5 1.2
Deferred Asset Valuation Allowance
2005 Deferred Tax Assets 1.1 3.8 - 0.8 4.1
2004 Deferred Tax Assets 0.2 0.9 - - 1.1
2003 Deferred Tax Assets 0.1 0.1 - - 0.2
- ----------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Included uncollectible accounts written off.
</FN>
Page 93 ALLETE 2005 Form 10-K
EXHIBIT INDEX
EXHIBIT NUMBER
12 - Computation of Ratios of Earnings to Fixed Charges.
21 - Subsidiaries of the Registrant.
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 2005 Form 10-K