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, 2006
/ / 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. /X/
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,
2006, was $1,427,346,731.
As of February 1, 2007, there were 30,446,854 shares of ALLETE Common Stock,
without par value, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the 2007 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..................................................................... 4
PART I
Item 1. Business...................................................... 5
Energy - Regulated Utility................................ 6
Electric Sales........................................ 7
Purchased Power....................................... 9
Fuel.................................................. 10
Regulatory Issues..................................... 10
Competition........................................... 14
Franchises............................................ 14
Energy - Nonregulated Energy Operations................... 14
Energy - Investment in ATC................................ 15
Real Estate............................................... 15
Regulation............................................ 19
Competition........................................... 19
Other..................................................... 19
Environmental Matters..................................... 20
Employees................................................. 22
Executive Officers of the Registrant...................... 23
Item 1A. Risk Factors.................................................. 24
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
2006 Compared to 2005......................................... 36
2005 Compared to 2004......................................... 38
Non-GAAP Financial Measures................................... 40
Critical Accounting Estimates................................. 40
Outlook....................................................... 42
Liquidity and Capital Resources............................... 46
Capital Requirements.......................................... 50
Environmental and Other Matters............................... 50
Market Risk................................................... 50
New Accounting Standards...................................... 51
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.... 52
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, Executive Officers and Corporate Governance........ 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, and
Director Independence..................................... 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
1 ALLETE 2006 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
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
FPL Energy FPL Energy, LLC
FPSC Florida Public Service Commission
FSP Financial Accounting Standards Board Staff
Position
GAAP Accounting Principles Generally Accepted
in the United States
Invest Direct ALLETE's Direct Stock Purchase and
Dividend Reinvestment Plan
IPO Initial Public Offering
kV Kilovolt(s)
Laskin Laskin Energy Center
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)
ALLETE 2006 Form 10-K 2
DEFINITIONS (CONTINUED)
ABBREVIATION OR ACRONYM TERM
--------------------------------------------------------------------------------
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
OAG Office of the Attorney General
Oliver Wind I Oliver Wind I Energy Center
Oliver Wind II Oliver Wind II Energy Center
Palm Coast Park Palm Coast Park development project in
Florida
Palm Coast Park District Palm Coast Park Community Development
District
PolyMet Mining PolyMet Mining, Inc.
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
Town Center District Town Center at Palm Coast Community
Development District
WDNR Wisconsin Department of Natural Resources
3 ALLETE 2006 Form 10-K
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 the 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, which are beyond our control and may cause actual results or
outcomes to differ materially from those that may be projected. These statements
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:
- 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 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 laws and policies;
- weather conditions;
- natural disasters and pandemic diseases;
- war and acts of terrorism;
- wholesale power market conditions;
- population growth rates and demographic patterns;
- effects of competition, including competition for retail and wholesale
customers;
- changes in the real estate market;
- pricing and transportation of commodities;
- changes in tax rates or policies or in rates of inflation;
- unanticipated project delays or changes in project costs;
- availability of construction materials and skilled construction labor
for capital projects;
- unanticipated changes in operating expenses and capital expenditures;
- global and domestic economic conditions;
- our ability to access capital markets and bank financing;
- changes in interest rates and the performance of the financial markets;
- 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 24 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.
ALLETE 2006 Form 10-K 4
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, 2006, we had
approximately 1,500 employees, 100 of which were part-time. Statistical
information is presented as of December 31, 2006, 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 makes its SEC filings, including its annual report on Form 10-K,
quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments
to those reports, available free of charge on ALLETE's Website www.allete.com,
as soon as reasonably practicable after they are electronically filed with or
furnished to the SEC.
ALLETE is a diversified company providing fundamental products and services.
This includes our two core businesses--ENERGY and REAL ESTATE, as well as former
operations in the water, paper, telecommunication and automotive industries.
ENERGY is comprised of Regulated Utility, Nonregulated Energy Operations and
Investment in ATC.
- REGULATED UTILITY includes retail and wholesale rate regulated
electric, natural gas and water 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, approximately 50 MW of nonregulated generation and
Minnesota land sales.
In 2004 and 2005, Nonregulated Energy Operations also included
nonregulated generation from our Taconite Harbor facility in northern
Minnesota, and generation secured through the Kendall County power
purchase agreement. Effective January 1, 2006, Taconite Harbor was
integrated into our Regulated Utility business to help meet forecasted
base load energy requirements. In April 2005, the Kendall County power
purchase agreement was assigned to Constellation Energy Commodities.
- INVESTMENT IN ATC includes our equity ownership interest in ATC.
REAL ESTATE includes our Florida real estate operations.
OTHER includes our investments in emerging technologies, and earnings on cash
and short-term investments.
YEAR ENDED DECEMBER 31 2006 2005 2004
------------------------------------------------------------------------------------------------------------------------------------
Consolidated Operating Revenue - Millions $767.1 $737.4 $704.1
------------------------------------------------------------------------------------------------------------------------------------
Percentage of Consolidated Operating Revenue
Regulated Utility
Industrial
Taconite Producers 24% 23% 25%
Paper and Wood Products 9 9 9
Pipelines and Other Industries 6 6 7
------------------------------------------------------------------------------------------------------------------------------------
Total Industrial 39 38 41
Residential 10 10 11
Commercial 11 11 11
Municipals 5 5 4
Other Power Suppliers 12 7 5
Other Revenue 6 7 7
------------------------------------------------------------------------------------------------------------------------------------
Total Regulated Utility 83 78 79
Nonregulated Energy Operations 9 16 15
Real Estate 8 6 6
------------------------------------------------------------------------------------------------------------------------------------
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.
5 ALLETE 2006 Form 10-K
DISCONTINUED OPERATIONS. In the past five years, we also had business
operations in the automotive, water and telecommunications industries.
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, after transaction costs, retirement of most Florida Water debt and
payment of income taxes, were approximately $300 million.
SALE OF ENVENTIS TELECOM. On December 30, 2005, we sold all the stock of our
telecommunications subsidiary, Enventis Telecom 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 140,000 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 1,586 MW on July 28, 2006. Our
regulated power supply sources are listed below.
FOR THE YEAR ENDED
REGULATED UTILITY UNIT YEAR NET WINTER DECEMBER 31, 2006
POWER SUPPLY NO. INSTALLED CAPABILITY ELECTRIC REQUIREMENTS
------------------------------------------------------------------------------------------------------------------------------------
MW MWh %
Steam
Coal-Fired
Boswell Energy Center 1 1958 69
in Cohasset, MN 2 1960 69
3 1973 351
4 1980 428
------------------------------------------------------------------------------------------------------------------------------------
917 6,380,647 48.9%
------------------------------------------------------------------------------------------------------------------------------------
Laskin Energy Center 1 1953 55
in Hoyt Lakes, MN 2 1953 55
------------------------------------------------------------------------------------------------------------------------------------
110 623,975 4.8
------------------------------------------------------------------------------------------------------------------------------------
Taconite Harbor Energy Center 1, 2 & 3 1957, 1957
in Taconite Harbor, MN 1967 220 1,466,803 11.2
------------------------------------------------------------------------------------------------------------------------------------
Purchased Steam
Hibbard Energy Center in Duluth, MN 3 & 4 1949, 1951 50 79,731 0.6
------------------------------------------------------------------------------------------------------------------------------------
Total Steam 1,297 8,551,156 65.5
------------------------------------------------------------------------------------------------------------------------------------
Hydro
Group consisting of ten stations in MN Various 115 343,729 2.6
------------------------------------------------------------------------------------------------------------------------------------
Total Company Generation 1,412 8,894,885 68.1
------------------------------------------------------------------------------------------------------------------------------------
Purchased Power
Square Butte burns lignite coal near Center, ND 299 2,069,700 15.9
Oliver Wind I Energy Center near Center, ND 50 12,696 -
All Other - Net - 2,071,481 16.0
------------------------------------------------------------------------------------------------------------------------------------
Total Purchased Power 349 4,153,877 31.9
------------------------------------------------------------------------------------------------------------------------------------
Total 1,761 13,048,762 100.0%
------------------------------------------------------------------------------------------------------------------------------------
ALLETE 2006 Form 10-K 6
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 (6,875 miles). We own and operate 169 substations with a total
capacity of 9,525 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 4.)
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 2006 2005 2004
------------------------------------------------------------------------------------------------------------------------
MILLIONS OF KILOWATTHOURS
Retail and Municipals
Residential 1,100 1,102 1,053
Commercial 1,335 1,327 1,282
Industrial 7,206 7,130 7,071
Municipals and Other 990 956 902
------------------------------------------------------------------------------------------------------------------------
10,631 10,515 10,308
Other Power Suppliers 2,153 1,142 918
------------------------------------------------------------------------------------------------------------------------
12,784 11,657 11,226
------------------------------------------------------------------------------------------------------------------------
Effective January 1, 2006, Taconite Harbor was redirected from Nonregulated Energy Operations to Regulated Utility.
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 demand and steel pricing. This globalization of demand has
positively impacted Minnesota taconite producers, which all produced near their
rated capacities in both 2006 and 2005. Annual taconite production in Minnesota
was 40 million tons in 2006 (41 million tons in both 2005 and 2004) and is
estimated to be 40 million tons in 2007. Recent consolidation activities,
combined with the strong steel market, have placed the Minnesota taconite
producers in a strong competitive position.
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. In 2006, approximately 90%
of our revenue from this industry sector came from the paper and pulp producers,
and 10% came from the wood products customers.
Minnesota Power's paper and pulp customers ran at or very near full capacity in
2006 despite the fact that the industry continued to face high fiber, chemical
and energy costs as well as competition from exports in certain grades.
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
and from the strength of the Euro. Wood products customers ran at reduced
capacity levels or were temporarily idled in the last third of 2006 because of
high wood prices and a decreasing number of new housing starts.
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. These customers have a common reliance on the importation of Canadian
crude oil. After years of near capacity operation in 2005 and 2006, both
pipeline operators are executing expansion plans 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.
7 ALLETE 2006 Form 10-K
ENERGY - REGULATED UTILITY (CONTINUED)
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 at least 8 MW of generating
capacity. In 2006, a contract for approximately 70 MW was successfully
negotiated with PolyMet Mining, a new customer planning to start a copper,
nickel and precious metals (non-ferrous) mining operation by late 2008. If
PolyMet's environmental permits are received and start-up is achieved, the
contract with PolyMet Mining will run through at least 2018. The PolyMet Mining
contract requires MPUC approval.
Large Power Customer contracts require Minnesota Power to have a certain amount
of generating capacity available. (See Minimum Revenue and Demand Under Contract
table below.) 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. 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 ANNUAL MONTHLY
AS OF FEBRUARY 1, 2007 DEMAND REVENUE MEGAWATTS
------------------------------------------------------------------------------------------------------------------------------------
2007 $62.5 million 390
2008 $29.3 million 167
2009 $25.9 million 148
2010 $25.8 million 148
2011 $16.1 million 88
------------------------------------------------------------------------------------------------------------------------------------
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 2005 Form 10-K we stated 2006 minimum annual revenue from these Large Power Customers
would be $61.3 million. Actual 2006 demand revenue from these Large Power Customers was $116.9 million.
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.
ALLETE 2006 Form 10-K 8
ENERGY - REGULATED UTILITY (CONTINUED)
CONTRACT STATUS FOR MINNESOTA POWER LARGE POWER CUSTOMERS
AS OF FEBRUARY 1, 2007
EARLIEST
CUSTOMER INDUSTRY LOCATION OWNERSHIP TERMINATION DATE
------------------------------------------------------------------------------------------------------------------------------------
Hibbing Taconite Co. Taconite Hibbing, MN 62.3% Mittal Steel USA Inc. February 28, 2011
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 Taconite Eveleth, MN 70% Cleveland-Cliffs Inc February 28, 2011
30% Laiwu Steel Group
UPM, Blandin Paper Mill Paper Grand Rapids, MN UPM-Kymmene Corporation February 28, 2011
Boise White Paper, LLC Paper International Falls, MN Madison Dearborn December 31, 2008
Partnership
Sappi Cloquet LLC Paper Cloquet, MN Sappi Limited February 28, 2011
Stora Enso North America, Paper and Pulp Duluth, MN Stora Enso Oyj August 31, 2013
Duluth Paper Mill and
Duluth Recycled Pulp Mill
USG Interiors, Inc. Manufacturer Cloquet, MN USG Corporation February 28, 2008
Enbridge Energy Company, Pipeline Deer River, MN Enbridge Energy Company, February 28, 2008
Limited Partnership Floodwood, MN Limited Partnership
Minnesota Pipeline Company Pipeline Staples, MN 60% Koch Pipeline Co. L.P. February 28, 2008
Little Falls, MN 40% Marathon Ashland
Park Rapids, MN Petroleum LLC
------------------------------------------------------------------------------------------------------------------------------------
The contract will terminate four years from the date of written notice from either Minnesota Power or the customer. No notice
of contract cancellation has been given by either party. Thus, the earliest date of cancellation is February 28, 2011.
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, 2008.
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 60% (55% beginning in 2008; 50% in 2009 and thereafter) of the
output of a 455-MW coal-fired generating unit located near Center, North Dakota.
(See Note 8.)
In May 2005, Minnesota Power entered into a 25-year agreement with an affiliate
of FPL Energy to purchase all of the renewable energy from Oliver Wind I, an
approximately 50-MW (nameplate) wind facility in North Dakota. Oliver Wind I
commenced commercial operation in late December 2006 and is comprised of 22 new
2.3-MW wind turbines. In addition, in December 2006, Minnesota Power and an
affiliate of FPL Energy reached an agreement for Minnesota Power to purchase an
additional 48 MW of wind energy from an expansion of Oliver Wind I. If
regulatory approvals and permits are received, FPL Energy expects the expansion,
Oliver Wind II, to be operational by late 2007. Minnesota Power is also
continuing to pursue additional agreements for wind energy from new facilities
being planned within Minnesota Power's service territory. The projects, expected
to be operational in late 2007 or 2008, would be smaller in size than the North
Dakota projects and would be subject to negotiation and execution of power
purchase agreements, as well as regulatory approvals.
9 ALLETE 2006 Form 10-K
ENERGY - REGULATED UTILITY (CONTINUED)
FUEL
Minnesota Power purchases low-sulfur, sub-bituminous coal from the Powder River
Basin coal region located in Montana and Wyoming. Coal consumption in 2006 for
electric generation at Minnesota Power's coal-fired generating stations was
about 5 million tons. As of December 31, 2006, Minnesota Power had a coal
inventory of about 800,000 tons. Minnesota Power has two coal supply agreements
with expiration dates extending through 2009 and one contract with an initial
term expiring in 2008. Under these agreements, Minnesota Power has the tonnage
flexibility to procure 70% to 100% of its total coal requirements. In 2007,
Minnesota Power will obtain coal under these coal supply agreements and in the
spot market. This diversity in coal supply options allows Minnesota Power to
manage market price and supply risk and to take advantage of favorable spot
market prices. Minnesota Power is exploring future coal supply options. We
believe that adequate supplies of low-sulfur, sub-bituminous coal will continue
to be available.
In 2001, Minnesota Power and Burlington Northern and Santa Fe Railway Company
(Burlington Northern) entered into a long-term agreement under which Burlington
Northern transports all of Minnesota Power's coal by unit train from the Powder
River Basin directly to Minnesota Power's generating facilities or to a
designated interconnection point. Minnesota Power also has agreements with the
Canadian National Railway and Midwest Energy Resources Company to transport coal
from the Burlington Northern interconnection point to certain Minnesota Power
facilities.
COAL DELIVERED TO MINNESOTA POWER
YEAR ENDED DECEMBER 31 2006 2005 2004
---------------------------------------------------------------------------------------------------------------------------
Average Price per Ton $20.19 $19.76 $19.01
Average Price per MBtu $1.10 $1.08 $1.04
---------------------------------------------------------------------------------------------------------------------------
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 2006 was
approximately 85 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 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, natural gas and water by SWL&P. The MPUC, FERC and PSCW
had regulatory authority over 56%, 8% and 8%, respectively, of our 2006
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, recovery of current and deferred conservation improvement
program expenditures, and recovery of certain environmental 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.
ALLETE 2006 Form 10-K 10
ENERGY - REGULATED UTILITY (CONTINUED)
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.
In August 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 promotion of energy efficiency and wise energy use. The
FERC is currently in the process of implementing EPAct 2005. These include
(among others):
- rulemaking for implementing long-term transmission rights;
- dockets pertaining to the development and certification of electric
reliability organizations, including delegated authority to regional
entities for proposing and enforcing reliability standards;
- rules specifying the form of applications for federal construction
permits to be issued in the exercise of federal backstop siting
authority for transmission projects;
- rulemaking requiring unregulated transmitting utilities to provide open
access to their transmission systems;
- various rulemakings regarding the consideration of merger applications
under the revised Federal Power Act Section 203;
- a U.S. Department of Energy study/report on the benefits of economic
dispatch and a report on recommendations of regional joint boards that
considered economic dispatch;
- rulemaking to facilitate transmission market transparency; and
- the energy market manipulation rulemaking.
We continue to monitor FERC activity in these and other proceedings.
MUNICIPAL AND WHOLESALE CUSTOMERS. Minnesota Power has contracts with 16
Minnesota municipalities receiving wholesale electric service. One contract
expires April 2008 (31,000 MWh purchased in 2006), while the other 15 are for
service through at least January 2011. In 2006, these municipal customers
purchased 813,000 MWh from Minnesota Power. Minnesota Power also has a contract
for wholesale service with Dahlberg Light & Power Company (Dahlberg) in
Wisconsin. Dahlberg purchased 111,000 MWh in 2006.
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 the 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 MISO, and they take and provide transmission
service under MISO open access transmission tariff. MISO continues its efforts
to standardize rates, terms and conditions of transmission service over its
broad region, which encompasses all or parts of 15 states and one Canadian
province, and over 100,000 MW of generating capacity.
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 2007. We
will, however, continue to monitor the costs of serving our retail customers and
evaluate the need for a rate filing in the future. Retail rates will be adjusted
without a rate proceeding to reflect recovery of costs related to the Arrowhead
Regional Emission Abatement plan (see AREA Plan).
LARGE POWER CONTRACTS. In 2006, the MPUC approved Minnesota Power's new electric
service agreement through August 2013 with Stora Enso's Duluth mills and a new
electric service agreement through February 2011 with Blandin Paper's Grand
Rapids facilities. Also in 2006, Minnesota Power reached an agreement with
PolyMet Mining to provide all of its electric service needs through at least
2018. PolyMet Mining plans to begin commercial operations by late 2008, pending
completion of financing arrangements and receipt of regulatory approvals. Once
fully operational, it is anticipated that PolyMet will require approximately 70
MW. The PolyMet Mining electric service agreement requires MPUC approval.
11 ALLETE 2006 Form 10-K
ENERGY - REGULATED UTILITY (CONTINUED)
RESOURCE PLAN. In September 2004, Minnesota Power filed its Integrated Resource
Plan (Resource Plan) with the MPUC. A November 2006 update to our Advance
Forecast contained a revised projection showing our winter peak demand by
customers in our service territory is expected to increase at an average annual
growth rate of 1.5% through 2011. We project an additional capacity need of
approximately 150 MW by 2010, with another 200 MW of capacity need anticipated
by 2015. These forecasted capacity needs are a combination of increased customer
demand and decreases in our existing capacity supply. Increased demand is
anticipated from residential and smaller commercial growth as well as from a
positive outlook for our Large Power Customers in northeastern Minnesota.
Minnesota Power will also realize a reduction in generating resource supply over
the next two 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 replace the Square Butte reductions and meet the predicted growing
demand in the region.
In 2006, the MPUC approved our Resource Plan. One of the key components of the
Resource Plan was the redirection of our Taconite Harbor generating facility
from Nonregulated Energy Operations to Regulated Utility operations effective
January 1, 2006. We have also entered into a 50-MW long-term power purchase
agreement with Manitoba Hydro, which will be effective from May 2009 to April
2015. This agreement was executed in June 2006 and filed for approval with the
MPUC in January 2007. The MPUC also approved expansion of our renewable
generating assets to meet Minnesota's Renewable Energy Objective which seeks a
10% supply of qualified renewable energy resources for each Minnesota utility by
2015. In 2006, Oliver Wind I, a 50-MW wind facility in North Dakota, was
constructed and placed in service. We began purchasing Oliver Wind I output
under a 25-year power purchase agreement with an affiliate of FPL Energy in late
December 2006.
Minnesota Power has executed a power purchase agreement for an additional 48 MW
of wind energy from an expansion of Oliver Wind I. The expansion, Oliver Wind
II, is expected to be completed and operational by late 2007. Minnesota Power is
also pursuing additional agreements for wind energy from new facilities being
planned within Minnesota Power's service territory and is considering 10 MW of
additional hydro generation through an expansion of the Fond du Lac
hydroelectric station.
The Company is required to file its next Resource Plan with the MPUC by November
1, 2007.
We are exploring various construction and purchase options for our anticipated
resource needs in 2015. These options include:
- NORTH DAKOTA GENERATION STUDY. In December 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 (which
includes Square Butte) near Center, North Dakota. The feasibility study
is currently underway and 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 two 600-MW (net) coal-gasification generation
units in northern Minnesota. This 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 it needs to obtain 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
fossil-fuel-fired resource additions. 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. In December 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 fossil-fuel-fired
resource additions. In January 2006, Minnesota Power filed comments
with the MPUC in Excelsior's proposed power purchase agreement
proceeding. Our comments focused on the importance to the state of
maintaining a range of base load energy options including multiple fuel
types and generating technologies. In April 2006, the MPUC referred
Excelsior's petition to an administrative law proceeding to further
develop the record in the case for subsequent MPUC deliberations.
Minnesota Power continues to be a participant in these proceedings,
focusing its comments on energy policy and infrastructure impacts.
- 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.
ALLETE 2006 Form 10-K 12
ENERGY - REGULATED UTILITY (CONTINUED)
ARROWHEAD REGIONAL EMISSION ABATEMENT PLAN (AREA PLAN). In May 2006, the MPUC
approved Minnesota Power's $60 million environmental initiative. The AREA Plan
approval allows Minnesota Power to recover Minnesota jurisdictional costs for
SO2, NOX and mercury emission reductions made at its Taconite Harbor and Laskin
facilities without a rate proceeding. The Minnesota cost recovery includes
return on investment, depreciation, and incremental operations and maintenance
expenses. The AREA Plan is expected to significantly reduce emissions from
Taconite Harbor and Laskin, 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.
Taconite Harbor will employ an 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 emissions 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 emissions.
Minnesota Power completed installation of new equipment at the first of two
Laskin units in November 2006, with the first of three Taconite Harbor unit
installations anticipated to be completed by mid-2007. Work on all units at
Taconite Harbor and Laskin is anticipated to be completed by the end of 2008.
Cost recovery filings are required to be made 90 days prior to the anticipated
in-service date for the equipment at each unit, with rate recovery beginning the
month following the in-service date. We began cost recovery of AREA plan costs
in December 2006 with the placement in service of Laskin Unit 2. We filed with
the MPUC for cost recovery on Laskin Unit 1 in January 2007 and expect to begin
cost recovery in May 2007. We anticipate beginning cost recovery on Taconite
Harbor Unit 2 in mid-2007 and Taconite Harbor Units 1 and 3 in 2008. AREA plan
expenditures as of December 31, 2006, were $11.4 million.
BOSWELL UNIT 3 EMISSION REDUCTION PLAN. In May 2006, we announced plans to make
emission reduction investments at our Boswell Unit 3 generating unit. Plans
include reductions of particulate, SO2, NOX and mercury emissions to meet
pending federal and state requirements. The estimated capital cost for these
reductions is approximately $200 million, of which $14 million was spent in 2006
for design engineering and related costs. The balance is expected to be spent
from 2007 through 2009. In October 2006, we submitted a filing to the MPCA for
approval of the Boswell Unit 3 emission reduction plan. A filing with the MPUC
for approval of Minnesota jurisdictional related expenditures on Boswell Unit 3
was made in January 2007 to allow cost recovery on these investments without a
rate proceeding. MPUC approval would authorize a cash return on construction
work in progress during the construction phase and allow recovery for a return
on investment, depreciation, and incremental operations and maintenance expenses
once the unit is placed into service in late 2009. We expect to begin cost
recovery on construction work in progress in 2008. In 2007, we will be filing
with the MPUC a request to extend the asset life for depreciation purposes on
Boswell Unit 3 from 8 years to 29 years. We anticipate approval of this filing
in 2007.
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 2006 ($3.2 million
for 2005; $3.1 million for 2004), with actual spending of $3.8 million in 2006
($3.6 million in 2005; $3.1 million in 2004).
PUBLIC SERVICE COMMISSION OF WISCONSIN. SWL&P's current retail rates are based
on a December 2006 PSCW retail rate order that became effective January 1, 2007,
and allows for an 11.1% return on common equity. New rates reflect a 2.8%
average increase in retail utility rates for SWL&P customers (a 2.8% increase in
electric rates, a 1.4% increase in natural gas rates and an 8.6% increase in
water rates). SWL&P originally requested an average increase in retail utility
rates of 5.2% in its 2006 application. The approved rates were lower than
originally requested due to the subsequent removal of costs for a new water
tower and electric substation from the original request. Both of these projects
are now estimated to be in service in late 2008 because of delays in obtaining
all the necessary construction approvals. SWL&P plans to file for another rate
increase request in 2008. Previously, SWL&P's retail rates were based on a 2005
PSCW retail order that allowed for an 11.7% return on common equity.
13 ALLETE 2006 Form 10-K
ENERGY - REGULATED UTILITY (CONTINUED)
COMPETITION
We believe the overall impact of the EPAct 2005 on the electric utility industry
has been positive and are continuing to evaluate the effects on our business as
this legislation is being implemented. This federal legislation is designed to
bring more certainty to energy markets in which ALLETE participates, as well as
to provide 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, as well as spawn moves
by state regulators to adopt PUHCA-like regulations, although both events are
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 a
low-cost supplier of lignite in North Dakota, producing about 4 million tons
annually. Two electric generating cooperatives, Minnkota Power and Square Butte,
presently consume virtually all of BNI Coal's production of lignite under cost
plus a fixed fee coal supply agreements expiring in 2027. (See Fuel and Note 8.)
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. The average cost to reclaim one acre of land is about $15,000, however,
could be as high as $30,000. Reclamation costs are included in the cost of coal
passed through to customers. In September 2004, BNI Coal entered into a master
lease agreement with Farm Credit Leasing Services Corporation (Farm Credit).
Under this agreement, BNI Coal leases a dragline that went into operation
September 30, 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 and new dragline equipment, BNI Coal
has ample capacity to expand production.
NONREGULATED GENERATION consists of approximately 50 MW of generation, the
majority of which is dedicated to the needs of one customer. In 2006, we sold
0.2 million MWh of nonregulated generation (1.5 million in 2005; 1.5 million in
2004). Effective January 1, 2006, Taconite Harbor was redirected from our
Nonregulated Energy Operations segment to our Regulated Utility segment in
accordance with the Company's Resource Plan, as approved by the MPUC.
UNIT YEAR YEAR NET
NONREGULATED POWER SUPPLY NO. INSTALLED ACQUIRED CAPABILITY
------------------------------------------------------------------------------------------------------------------------------------
MW
Steam
Wood-Fired
Cloquet Energy Center 5 2001 2001 22
in Cloquet, MN
Rapids Energy Center 6 & 7 1969, 1980 2000 30
in Grand Rapids, MN
------------------------------------------------------------------------------------------------------------------------------------
Hydro
Conventional Run-of-River
Rapids Energy Center 4 & 5 1917 2000 1
in Grand Rapids, MN
------------------------------------------------------------------------------------------------------------------------------------
Supplemented by coal.
The net generation is primarily dedicated to the needs of one customer.
ALLETE 2006 Form 10-K 14
ENERGY - NONREGULATED ENERGY OPERATIONS (CONTINUED)
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. Under the terms of our Resource
Plan, we have operated the Taconite Harbor facility as a rate-based asset within
the Minnesota retail jurisdiction since January 1, 2006. Prior to January 1,
2006, we operated our Taconite Harbor facility as nonregulated generation. (See
Energy - 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. 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.
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.
MINNESOTA LAND. We have about 15,000 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 $4.3
million at December 31, 2006.
ENERGY - INVESTMENT IN ATC
In December 2005, we entered into an agreement with Wisconsin Public Service
Corporation and WPS Investments, LLC that provides for our Wisconsin subsidiary,
Rainy River Energy Corporation - Wisconsin, to invest $60 million in ATC. 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 in
accordance with the FERC's policy of establishing the independent operation and
ownership of, and investment in, transmission facilities. In May 2006, the PSCW
reviewed and approved the request that allows us to invest in ATC. During 2006,
we invested $51.4 million in ATC. We plan to invest an additional $8.6 million
in ATC in early 2007 to reach our $60 million investment commitment and
estimated 8% ownership interest. As of December 31, 2006, our equity investment
balance in ATC was $53.7 million, representing approximately a 7% ownership
interest. (See Note 6.) We will have the opportunity to make additional
investments in ATC through general capital calls based upon our pro-rata
investment level in ATC.
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 Florida and other parts
of the 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.
15 ALLETE 2006 Form 10-K
REAL ESTATE (CONTINUED)
TOWN CENTER. Town Center, which is located in the city of Palm Coast, is a
mixed-use development with a neo-traditional downtown core area. Surrounded by
major arterial roads, including Interstate 95, Town Center is adjacent to the
Florida Hospital-Flagler, the Flagler County Airport and the Flagler Palm Coast
High School. Sites have also been set aside for a new city hall, an arts and
entertainment center, and other public uses. At build-out, Town Center is
expected to include over 2,900 residential units, including lodging facilities,
and 3.7 million square feet of various types of commercial space, including a
movie theater. Future market conditions will determine how quickly Town Center
is built out.
Construction of the major infrastructure improvements commenced in March 2005
and was substantially complete at the end of 2006. Infrastructure improvements
include 3.6 miles of roads, a master storm water management system, underground
utilities, street lights, sidewalks and bike paths, and extensive landscaping.
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, which are payable over 31 years (by May
1, 2036). The bond proceeds (less capitalized interest, a debt service reserve
fund and cost of issuance) were used to pay for the construction of a portion of
the major infrastructure improvements at Town Center. The bonds are being repaid
by special assessments on all buildable land within Town Center. The special
assessments were billed to Town Center landowners beginning in November 2006. To
the extent that we still own land at the time of the assessment, we recognize
the cost of our portion of these assessments based upon our ownership of
benefited property. At December 31, 2006, we owned approximately 73% of the
assessable land in the Town Center District. As we sell property, the obligation
to pay special assessments will pass to the new landowners.
Additional Town Center development costs not funded through the Town Center
District bond financing, estimated at $30 million (up to $11 million can be
offset through traffic impact fee credits received over the life of the
project), are being partially funded through an $8.5 million revolving
development loan. The borrower is Florida Landmark. The development loan 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.
Pending land sales under contract for properties at Town Center were $40.1
million at December 31, 2006. We have the opportunity to receive participation
revenue as part of one of these sales contracts. Among the pending Town Center
sales contracts is a contract with Developers Realty Corporation (DRC) to
develop projects in the downtown core area and a large retail shopping center on
a 50-acre tract. DRC has entered into an agreement to form a joint venture with
Weingarten Realty Investors (Weingarten). DRC/Weingarten has a commitment from a
major national retail anchor for the retail shopping center.
Throughout 2005 and 2006, we focused on platting phases 1 and 2, which include
the major roads and lots for a variety of uses, and developing the major
infrastructure at Town Center. During that period, our marketing program
targeted a blend of office, retail, commercial, residential and mixed-use
project developers. In December 2006, a Publix grocery store anchored retail
center opened and construction started on an 84,000 square foot medical center.
Twenty other projects are in the permitting stage, 11 of which are expected to
break ground in 2007. Future marketing efforts will focus on attracting the
following additional land uses to Town Center: residential apartments, assisted
living facilities, business park uses, and restaurants.
PALM COAST PARK. Palm Coast Park, which is located in the city of Palm Coast, is
a 4,700-acre mixed-use development bisected by a 6-mile segment of U.S. Highway
1 about one mile from an existing Interstate 95 interchange and bounded on the
west by a Florida East Coast Railroad rail line. At build-out, the project will
include approximately 3.2 million square feet of commercial space and about
3,900 residential units ranging from affordable condominium units and apartments
to estate golf course homes. Future market conditions will determine how quickly
Palm Coast Park is built out.
In May 2006, the Palm Coast Park Community Development District (Palm Coast Park
District) issued $31.8 million of tax exempt, 5.7% Special Assessment Bonds,
Series 2006, which are payable over 31 years (by May 1, 2037). The bond proceeds
(less capitalized interest, a debt service reserve fund and cost of issuance)
are being used to pay for the construction of the major infrastructure
improvements at Palm Coast Park and to mitigate traffic and environmental
impacts. The bonds will be repaid by special assessments on all buildable land
within Palm Coast Park. The special assessments will be billed to Palm Coast
Park landowners beginning in November 2007. To the extent that we still own land
at the time of the assessment, we will recognize the cost of our portion of
these assessments based upon our ownership of benefited property. At December
31, 2006, we owned approximately 97% of the assessable land in the Palm Coast
Park District. As we sell property, the obligation to pay special assessments
will pass to the new landowners.
We are funding certain platting and permitting costs; however, the majority of
ongoing and future development costs will be funded by Palm Coast Park District
bond proceeds. We anticipate that the Palm Coast Park District will need to
issue additional bonds to pay for the development of retail commercial, office
and industrial lots.
Major infrastructure construction began in December 2006 and is expected to be
completed in 2007. Commercial and industrial lots will be offered for sale in
2007, with closings anticipated to begin in 2008.
ALLETE 2006 Form 10-K 16
REAL ESTATE (CONTINUED)
Pending land sales under contract for properties at Palm Coast Park were $62.8
million at December 31, 2006. We have the opportunity to receive participation
revenue as part of these sales contracts. One of the pending sales contracts is
for the sale of five residential tracts and one commercial tract for $52.5
million. That sales contract provides for closings in 2007, 2008 and 2009. The
project, which is named Sawmill Creek, will include up to 1,469 residential
housing units, a championship golf course and neighborhood retail office space,
along with a community park and elementary school. Other contracts include a
residential tract for an affordable condominium project and a 600-unit
single-family residential project that will be connected to the existing
Matanzas Woods golf course neighborhood.
ORMOND CROSSINGS. Ormond Crossings is a 6,000-acre mixed-use development that is
located in both the city of Ormond Beach in Volusia County and unincorporated
Flagler County. The site is bisected by Interstate 95 and a Florida East Coast
Railroad rail line and is adjacent to the city of Ormond Beach airport. Ormond
Crossings has three miles of frontage on the east and west sides of Interstate
95 and will have two main entrances each within a mile from an existing U.S.
Highway 1 and Interstate 95 interchange.
The Development of Regional Impact (DRI) development order for Ormond Crossings
was approved by the city of Ormond Beach in December 2006, and provides for 5
million square feet of various types of commercial land uses and up to 3,700
residential units to be built in four phases. The Flagler County DRI development
order is under review by the Flagler County Commission and, if approved, we will
receive entitlements for up to 700 additional residential units. Actual
build-out, however, will consider market demand as well as infrastructure and
mitigation costs. Most of the developable part of Ormond Crossings is located in
the city of Ormond Beach, so the project is not dependent upon receiving any
further land use approvals from Flagler County. The Flagler County portion of
the project will be mainly permitted for a wetland mitigation bank. Applications
to permit the wetland mitigation bank were submitted in 2006 to St. Johns River
Water Management District and the U.S. Army Corps of Engineers. Wetland
mitigation credits will be used in connection with the permitting of development
at Ormond Crossings and can also be sold to other developers.
After an agreement is finalized with the Florida Department of Transportation
concerning traffic mitigation costs, we will determine the best economic
build-out of the project. The agreement and economic analysis are expected to be
completed in 2007.
Engineering design and permitting will be ongoing as the project is developed.
We anticipate Ormond Crossings land sales closings starting in 2009.
OTHER LAND. In addition to the major development projects, land inventories in
Florida include 3,300 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 from land sales to third parties if
various formula-based criteria are achieved.
ALLETE Properties occasionally provides seller financing. At December 31, 2006,
outstanding finance receivables were $18.3 million, with maturities ranging up
to ten years. These finance receivables accrue interest at market-based rates
and are collateralized by the financed properties.
17 ALLETE 2006 Form 10-K
REAL ESTATE (CONTINUED)
SUMMARY OF DEVELOPMENT PROJECTS
FOR THE YEAR ENDED TOTAL RESIDENTIAL COMMERCIAL
DECEMBER 31, 2006 OWNERSHIP ACRES UNITS SQ. FT.
-----------------------------------------------------------------------------------------------------------------------------
Town Center 80%
At December 31, 2005 1,480 2,833 2,927,700
Property Sold (124) (773) (401,971)
Change in Estimate - 162 179,581
-----------------------------------------------------------------------------------------------------------------------------
1,356 2,222 2,705,310
-----------------------------------------------------------------------------------------------------------------------------
Palm Coast Park 100%
At December 31, 2005 4,705 3,600 3,200,000
Property Sold (368) (200) -
Change in Estimate - 360 (43,200)
-----------------------------------------------------------------------------------------------------------------------------
4,337 3,760 3,156,800
-----------------------------------------------------------------------------------------------------------------------------
Ormond Crossings 100%
At December 31, 2005 5,960
Change in Estimate -
-----------------------------------------------------------------------------------------------------------------------------
5,960
-----------------------------------------------------------------------------------------------------------------------------
11,653 5,982 5,862,110
-----------------------------------------------------------------------------------------------------------------------------
Acreage amounts are approximate and shown on a gross basis, including wetlands and minority interest. Acreage amounts may
vary due to platting or surveying activity. Wetland amounts vary by property and are often not formally determined prior
to sale.
Estimated and includes minority interest. The actual property breakdown at full build-out may be different than these
estimates.
Includes industrial, office and retail square footage.
A development order approval from the city of Ormond Crossings was received in December 2006, for up to 3,700 residential
units and 5 million commercial square feet. A development order from Flagler County is currently under review, and if
approved, Ormond Crossings will receive entitlements for up to 700 additional residential units. Actual build-out,
however, will consider market demand as well as infrastructure and mitigation costs.
SUMMARY OF OTHER LAND INVENTORIES
FOR THE YEAR ENDED
DECEMBER 31, 2006 OWNERSHIP TOTAL MIXED USE RESIDENTIAL COMMERCIAL AGRICULTURAL
------------------------------------------------------------------------------------------------------------------------------
ACRES
Palm Coast Holdings 80%
At December 31, 2005 2,566 1,692 346 281 247
Property Sold (321) (288) - (30) (3)
Contributed Land (12) - - (4) (8)
Change in Estimate (97) - - - (97)
------------------------------------------------------------------------------------------------------------------------------
2,136 1,404 346 247 139
------------------------------------------------------------------------------------------------------------------------------
Lehigh 80%
At December 31, 2005 613 390 140 74 9
Property Sold (390) (390) - - -
------------------------------------------------------------------------------------------------------------------------------
223 - 140 74 9
------------------------------------------------------------------------------------------------------------------------------
Cape Coral 100%
At December 31, 2005 41 - 1 40 -
Property Sold (11) - - (11) -
------------------------------------------------------------------------------------------------------------------------------
30 - 1 29 -
------------------------------------------------------------------------------------------------------------------------------
Other 100%
At December 31, 2005 944 - - - 944
Property Sold (10) - - - (10)
------------------------------------------------------------------------------------------------------------------------------
934 - - - 934
------------------------------------------------------------------------------------------------------------------------------
3,323 1,404 487 350 1,082
------------------------------------------------------------------------------------------------------------------------------
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.
Includes land located in Ormond Beach, Florida, and other land located in Palm Coast, Florida not included in development
projects.
ALLETE 2006 Form 10-K 18
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 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. We are focused on acquiring additional vacant land in Florida and other
parts of the southeast United States. This region 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, 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 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 $2.5
million in 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.
We account for our investment in venture capital funds under the equity method
(see Note 15) and account for our direct investments 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,
2006, and December 31, 2005. 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, 2006, and
December 31, 2005. In 2005, we recorded $5.1 million ($3.3 million after tax) of
impairments related to our 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.
19 ALLETE 2006 Form 10-K
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, which were sufficient to cover
the transfer of Taconite Harbor's generating assets to our Regulated Utility
effective January 1, 2006, as approved by the MPUC. Square Butte is meeting its
SO2 emission allowance requirements through increased use of its existing
scrubber.
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 currently 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 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 nationwide. 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 CAIR contains flaws in its methodology and application, which
will cause Minnesota Power to incur significantly higher compliance costs.
Minnesota Power petitioned that the EPA review its CAIR determinations that
affected Minnesota. In July 2005, Minnesota Power also 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. In November
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. In March 2006, the EPA announced that it would not make any changes
to the CAIR as a result of the Petitions for Reconsideration. Petitions for
Review, including Minnesota Power's, remain pending at the Court of Appeals. If
the Petition for Review is successful, the Company expects to incur lower
compliance costs, consistent with the rules applicable to those states
considered "western" states under the CAIR. Resolution of the CAIR Petition for
Review with the Court of Appeals is anticipated in 2008.
MERCURY EMISSIONS. The Minnesota mercury emissions budget under the first phase
of the CAMR, requiring roughly a 20% reduction in nationwide utility mercury
emissions beginning in 2010, is similar to current Minnesota statewide emissions
requirements. The second phase allocation, requiring approximately a 70%
reduction in nationwide utility mercury emissions effective in 2018, will
require that Minnesota generation sources provide for substantial mercury
emission reductions or procure mercury emission credits from other sources that
have a surplus of allowances. However, mercury emission reductions expected as a
result of implementing AREA at Taconite Harbor, and implementation of the 2006
Minnesota Mercury Emission Reduction Law which applies to Boswell Units 3 and 4,
are anticipated to meet Minnesota Power's 2018 emission reduction requirements
of the second phase of CAMR. (See Minnesota Mercury Emission Law.) 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.
ALLETE 2006 Form 10-K 20
ENVIRONMENTAL MATTERS (CONTINUED)
MINNESOTA MERCURY EMISSION LAW. This legislation requires Minnesota Power to
file mercury emission reduction plans for its Boswell Units 3 and 4. The Boswell
Unit 3 emission reduction plan was filed with the MPCA in October 2006.
Minnesota Power is required to install mercury emission reduction technology and
equipment by December 31, 2010. The next step will be to file a mercury
emissions reduction plan for Boswell Unit 4 by July 1, 2011, with implementation
no later than December 31, 2014. One plan must attain the mercury reduction goal
of 90%. Alternate mercury plans, with the percentage of reduction elected by the
utility, are also required to be filed. Minnesota Power may apply mercury
emissions achieved under its Arrowhead Regional Emission Abatement plan at
Taconite Harbor toward the reduction goal required under approved plans for
Boswell Units 3 and 4. Filed plans must be reviewed and approved by the MPCA and
the MPUC under criteria that include, among other things, technical feasibility,
environmental benefit, cost effectiveness and rate impact. The new law
encourages multi-emission reduction plans and also extends a statutory provision
for current cost recovery outside of a rate case for approved emission reduction
expenditures, including mercury and other types of emissions, from 2006 through
2013. The legislation generally comports with Minnesota Power's plans for its
Boswell Units 3 and 4 mercury and other emission reduction retrofits. Total
pollution control capital costs planned for Boswell Unit 3 are estimated at
approximately $200 million, of which $14 million was spent in 2006 for design
engineering and related costs. The balance is expected to be spent from 2007
through 2009. The Boswell Unit 3 emission reduction plan provides significant
cost-effective emission reductions through the use of integrated control
technologies appropriate for the size, location and use of Boswell Unit 3.
Minnesota Power anticipates that costs for these expenditures will be recovered
from retail customers on a current basis, subject to approval by the MPUC. (See
Regulatory Issues - Minnesota Public Utilities Commission - Boswell Unit 3
Emission Reduction Plan.)
NEW SOURCE REVIEW RULES. In December 2002, the EPA issued changes to the
existing New Source Review rules, which modified 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 (Court) stayed the
implementation of the October 2003 rule pending further review. In March 2006,
the Court vacated most of the EPA's 2003 rule. These changes are not expected to
have a material impact on Minnesota Power.
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.
LASKIN NPDES PERMIT MODIFICATION. In June 2006, Minnesota Power filed an
application with the MPCA for a variance from a wastewater discharge standard
for mercury included in its NPDES permit for Laskin. The variance requested an
extension for Laskin to meet mercury discharge requirements which will become
effective March 23, 2007, as set forth in Laskin's NPDES permit issued by the
MPCA in May 2005. In view of the EPA's proposed changes relating to the
implementation of mercury water policy and recent developments in mercury
treatment technologies, the MPCA believes it is more appropriate at this time to
forego the processing of mercury variances. Instead, a permit modification will
be used which will contain a compliance schedule that specifies interim actions
and limits that lead to compliance with the final limits by March 31, 2010. This
approach will allow Minnesota Power to further investigate treatment
alternatives. In October 2006, Minnesota Power submitted a letter withdrawing
its variance request. However, we are continuing discussions on interim limits
with the MPCA. The MPCA placed a draft permit modification on 30-day public
notice on December 20, 2006. The comment period for the draft permit
modification closes March 7, 2007.
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. PCB-contaminated oil in substation
equipment was largely replaced by the end of 2006.
21 ALLETE 2006 Form 10-K
ENVIRONMENTAL MATTERS (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. The investigation continued
through the fall of 2006. It is anticipated that the final report for this
portion of the investigation will be completed during the first quarter of 2007.
Although it is not possible to quantify the total potential clean-up costs until
the investigation is completed, a $0.5 million liability was recorded in
December 2003 based on initial studies to address the known areas of
contamination. The Company has recorded a corresponding amount as a regulatory
asset. 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 its 2006 rate request. In December 2006, the PSCW approved
the recovery of an additional $186,000 of site investigation costs that were
incurred through 2005. 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, 2006, ALLETE had approximately 1,500 employees, of which 1,400
were full-time.
Minnesota Power and SWL&P have 612 employees who are members of the
International Brotherhood of Electrical Workers (IBEW), Local 31. The labor
agreement with Local 31 expires on January 31, 2009.
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.
ALLETE 2006 Form 10-K 22
EXECUTIVE OFFICERS OF THE REGISTRANT
EXECUTIVE OFFICERS INITIAL EFFECTIVE DATE
------------------------------------------------------------------------------------------------------------------------------------
DONALD J. SHIPPAR, Age 57
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 41
Senior Vice President, General Counsel and Secretary January 1, 2006
Vice President, General Counsel and Secretary March 8, 2004
STEVEN Q. DEVINCK, Age 47
Controller July 12, 2006
LAURA A. HOLQUIST, Age 45
President - ALLETE Properties September 6, 2001
MARK A. SCHOBER, Age 51
Senior Vice President and Chief Financial Officer July 1, 2006
Senior Vice President and Controller February 1, 2004
Vice President and Controller April 18, 2001
DONALD W. STELLMAKER, Age 49
Treasurer July 24, 2004
TIMOTHY J. THORP, Age 52
Vice President - Investor Relations July 1, 2004
Vice President - Investor Relations and Corporate Communications November 16, 2001
CLAUDIA SCOTT WELTY, Age 54
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.
MS. AMBERG was a Senior Attorney.
MR. DEVINCK was Director of Nonutility Business Development, and Assistant
Controller.
MR. STELLMAKER was Director of Financial Planning.
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 8, 2007.
23 ALLETE 2006 Form 10-K
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 4 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 REGULATED UTILITY 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 33% of our 2006
consolidated operating revenue (one of these customers accounted for 12%). These
customers are involved in cyclical industries that by their 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 REGULATED UTILITY IS 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 and the PSCW. These governmental regulations relate to allowed rates of
return, financings, industry and rate structure, acquisition and disposal of
assets and facilities, 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 COULD BE SIGNIFICANTLY
IMPACTED BY INITIATIVES DESIGNED TO REDUCE THE IMPACT OF GREENHOUSE GAS
EMISSIONS SUCH AS CARBON DIOXIDE FROM OUR GENERATING FACILITIES.
Proposals for voluntary initiatives and mandatory controls are being discussed
both in the United States and worldwide to reduce greenhouse gases such as
carbon dioxide, a by-product of burning fossil fuels. We currently use coal as
the primary fuel in 96% of the energy produced by our generating facilities.
We have implemented greenhouse gas emission reduction or offset measures at our
Regulated Utility and Nonregulated Energy Operations generating facilities.
These efforts currently result in over one million tons of carbon dioxide
reductions or offsets annually. We are participating in research and study
initiatives to mitigate the potential impact to our business. There is no
assurance that our current reduction efforts will mitigate the impact of any new
regulations.
We cannot be certain whether new laws or regulations will be adopted to reduce
greenhouse gases and what effect any such laws or regulations would have on
us. If any new laws or regulations are implemented, they could have a material
effect on our results of operations, particularly if those costs are not fully
recoverable from customers.
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.
ALLETE 2006 Form 10-K 24
RISK FACTORS (CONTINUED)
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.
THE OPERATION AND MAINTENANCE OF OUR GENERATING FACILITIES IN OUR REGULATED
UTILITY AND NONREGULATED ENERGY OPERATIONS 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 improvements due
to changing environmental standards and technological advances. (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.
OUR REGULATED UTILITY AND NONREGULATED ENERGY OPERATIONS MUST HAVE ADEQUATE AND
RELIABLE TRANSMISSION AND DISTRIBUTION FACILITIES TO DELIVER ELECTRICITY TO ITS
CUSTOMERS.
Minnesota Power depends on transmission and distribution facilities owned by
other utilities, and transmission facilities primarily operated by MISO, 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 forego sales or we may have to buy more expensive wholesale electricity
that is available in the capacity-constrained area. The cost to acquire or
provide service 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.
IN OUR REGULATED UTILITY AND NONREGULATED ENERGY OPERATIONS THE PRICE OF
ELECTRICITY AND 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;
- 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.
25 ALLETE 2006 Form 10-K
RISK FACTORS (CONTINUED)
WE ARE DEPENDENT ON GOOD LABOR RELATIONS.
We believe our relations to be good with our approximately 1,500 employees.
Failure to successfully renegotiate labor agreements could adversely affect the
services we provide and our results of operations. Approximately 700 of these
employees are members of either the International Brotherhood of Electrical
Workers Local 31 or Local 1593. The labor agreement with Local 31 at Minnesota
Power and SWL&P expires on January 31, 2009, and 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 conditions in the Florida real estate
market may fluctuate over time, continued demand for land is dependent on
long-term prospects for strong, in-migration population expansion.
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, the effects of the rebuilding efforts due to destructive weather,
including hurricanes, could cause increased prices for construction materials
and create labor shortages which could increase our development costs.
Our real estate development activities require significant capital expenditures.
We obtain funds for our capital expenditures through cash flow from operations
and financings, including the financings of the community development districts
in which our development projects are located. We cannot be certain 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.
OUR REAL ESTATE BUSINESS IS SUBJECT TO EXTENSIVE REGULATION THROUGH FLORIDA LAWS
REGULATING PLANNING AND LAND DEVELOPMENT 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 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 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 Florida's Governor and Cabinet by the Florida Department of Community
Affairs, and adverse decisions by the Governor and 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.
Changes in the Growth Management Act or DRI review process or the enactment of
new laws regarding the development of real property could adversely affect our
ability to develop future real estate projects.
ALLETE 2006 Form 10-K 26
RISK FACTORS (CONTINUED)
COMPETITION FOR LAND COULD ADVERSELY AFFECT OUR REAL ESTATE BUSINESS.
Over the past few years, we have experienced an increase in competition for
suitable land in the southeast United States real estate market. The
availability of undeveloped land for purchase that meets our internal criteria
depends on a number of factors outside our control, including land availability
in general, competition with other developers and land buyers for desirable
property, inflation in land prices, zoning, allowable development density and
other regulatory requirements. Our long-term ability to acquire land suitable
for development at reasonable prices in locations where we feel there is a
viable market is crucial in maintaining our business success.
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.
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. We do not expect the outcome of
these matters to have a material effect on our financial position or results of
operations.
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 2006.
27 ALLETE 2006 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 $0.41 per share on our common stock will be paid on March
1, 2007, to the holders of record on February 15, 2007. 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 2006, we paid out 53% of our per
share earnings in dividends.
Our Articles of Incorporation, and Mortgage and Deed of Trust contain
provisions, which under certain circumstances would restrict the payment of
common stock dividends. As of December 31, 2006, no retained earnings were
restricted as a result of these provisions. At February 1, 2007, there were
approximately 31,000 common stock shareholders of record.
2006 2005
-----------------------------------------------------------------------------------------
PRICE RANGE DIVIDENDS PRICE RANGE DIVIDENDS
QUARTER HIGH LOW PAID HIGH LOW PAID
-------------------------------------------------------------------------------------------------------------------------
First $47.81 $42.99 $0.3625 $44.40 $35.65 $0.3000
Second 48.55 44.34 0.3625 50.33 40.12 0.3150
Third 49.30 43.26 0.3625 51.70 42.80 0.3150
Fourth 47.84 42.55 0.3625 47.36 41.28 0.3150
-------------------------------------------------------------------------------------------------------------------------
Annual Total $1.4500 $1.2450
-------------------------------------------------------------------------------------------------------------------------
COMMON STOCK REPURCHASES. We did not repurchase any ALLETE common stock during
the fourth quarter of 2006.
ALLETE 2006 Form 10-K 28
ITEM 6. SELECTED FINANCIAL DATA
Financial results by segment for the periods presented were impacted by the
integration of our Taconite Harbor facility into the Regulated Utility segment
effective January 1, 2006. The redirection of Taconite Harbor from our
Nonregulated Energy Operations segment to our Regulated Utility segment was in
accordance with the Company's Resource Plan, as approved by the MPUC. Under the
terms of our Resource Plan, we have operated the Taconite Harbor facility as a
rate-based asset within the Minnesota retail jurisdiction since January 1, 2006.
Prior to January 1, 2006, we operated our Taconite Harbor facility as
nonregulated generation (non-rate base generation sold at market-based rates
primarily to the wholesale market). Historical financial results of Taconite
Harbor for periods prior to the 2006 redirection are included in our
Nonregulated Energy Operations segment.
Operating results of our Water Services businesses, our Automotive Services
business and our telecommunications business are included in discontinued
operations, and accordingly, amounts have been restated for all periods
presented. (See Note 13.) 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.
2006 2005 2004 2003 2002
----------------------------------------------------------------------------------------------------------------------------
MILLIONS
BALANCE SHEET
Assets
Current Assets $ 287.7 $ 373.5 $ 355.0 $ 216.1 $ 184.8
Discontinued Operations - Current - 0.4 13.1 483.9 477.3
Property, Plant and Equipment 921.6 860.4 849.6 888.2 852.0
Investments 189.1 117.7 124.5 175.7 170.9
Other Assets 135.0 44.6 52.8 59.0 61.9
Discontinued Operations - Other - 2.2 36.4 1,278.4 1,400.3
----------------------------------------------------------------------------------------------------------------------------
$1,533.4 $1,398.8 $1,431.4 $3,101.3 $3,147.2
----------------------------------------------------------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current Liabilities $ 143.5 $ 106.7 $ 91.7 $ 182.1 $ 436.2
Discontinued Operations - Current - 13.0 24.5 344.1 302.0
Long-Term Debt 359.8 387.8 389.4 513.9 566.9
Mandatorily Redeemable Preferred Securities - - - - 75.0
Other Liabilities 364.3 288.5 295.3 300.1 292.2
Discontinued Operations - - - 300.9 242.5
Shareholders' Equity 665.8 602.8 630.5 1,460.2 1,232.4
----------------------------------------------------------------------------------------------------------------------------
$1,533.4 $1,398.8 $1,431.4 $3,101.3 $3,147.2
----------------------------------------------------------------------------------------------------------------------------
INCOME STATEMENT
Operating Revenue
Regulated Utility $639.2 $575.6 $555.0 $510.0 $497.9
Nonregulated Energy Operations 65.0 113.9 106.8 106.6 84.7
Real Estate 62.6 47.5 41.9 42.6 33.6
Other 0.3 0.4 0.4 0.4 0.3
----------------------------------------------------------------------------------------------------------------------------
Total Operating Revenue 767.1 737.4 704.1 659.6 616.5
----------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Fuel and Purchased Power 281.7 273.1 286.2 252.5 234.8
Operating and Maintenance 296.0 293.5 270.1 260.5 254.4
Kendall County Charge - 77.9 - - -
Depreciation 48.7 47.8 46.9 48.9 47.0
----------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 626.4 692.3 603.2 561.9 536.2
----------------------------------------------------------------------------------------------------------------------------
Operating Income from Continuing Operations 140.7 45.1 100.9 97.7 80.3
----------------------------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest Expense (27.4) (26.4) (31.7) (50.5) (49.3)
Other 14.9 1.1 (12.2) 2.3 6.9
----------------------------------------------------------------------------------------------------------------------------
Total Other Expense (12.5) (25.3) (43.9) (48.2) (42.4)
----------------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations
Before Minority Interest and Income Taxes 128.2 19.8 57.0 49.5 37.9
Minority Interest 4.6 2.7 2.1 2.6 1.0
----------------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations Before Income Taxes 123.6 17.1 54.9 46.9 36.9
Income Tax Expense (Benefit) 46.3 (0.5) 16.4 17.7 12.3
----------------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations Before
Change in Accounting Principle 77.3 17.6 38.5 29.2 24.6
Income (Loss) from Discontinued Operations - Net of Tax (0.9) (4.3) 73.7 207.2 112.6
Change in Accounting Principle - Net of Tax - - (7.8) - -
----------------------------------------------------------------------------------------------------------------------------
Net Income 76.4 13.3 104.4 236.4 137.2
Common Stock Dividends 40.7 34.4 79.7 93.2 89.2
----------------------------------------------------------------------------------------------------------------------------
Earnings Retained in (Distributed from) Business $ 35.7 $(21.1) $ 24.7 $143.2 $ 48.0
----------------------------------------------------------------------------------------------------------------------------
Included $86.1 million of assets and $107.6 million of liabilities reflecting the adoption of SFAS 158 "Employers'
Accounting for Defined Benefit Pension and Other Postretirement Plans." (See Notes 2 and 16.)
Reflected the cumulative effect on prior years (to December 2003) of changing to the equity method of accounting
for investments in limited liability companies included in our emerging technology portfolio. (See Note 15.)
29 ALLETE 2006 Form 10-K
2006 2005 2004 2003 2002
-------------------------------------------------------------------------------------------------------------------------------
Shares Outstanding - Millions
Year-End 30.4 30.1 29.7 29.1 28.5
Average (a)
Basic 27.8 27.3 28.3 27.6 27.0
Diluted 27.9 27.4 28.4 27.8 27.2
Diluted Earnings (Loss) Per Share
Continuing Operations $2.77 $0.64 $1.35 $1.05 $0.91
Discontinued Operations (0.03) (0.16) 2.59 7.47 4.13
Change in Accounting Principle - - (0.27) - -
-------------------------------------------------------------------------------------------------------------------------------
$2.74 $0.48 $3.67 $8.52 $5.04
-------------------------------------------------------------------------------------------------------------------------------
Return on Common Equity 12.1% 2.2% 8.3% 17.7% 11.4%
Common Equity Ratio 63.1% 60.7% 61.7% 64.4% 51.7%
Dividends Paid Per Share $1.4500 $1.2450 $2.8425 $3.3900 $3.3000
Dividend Payout Ratio 53% 259% 77% 40% 66%
Book Value Per Share at Year-End $21.90 $20.03 $21.23 $50.18 $43.24
Employees at Year-End 1,468 1,459 1,515 13,115 14,181
Income (Loss)
Regulated Utility $46.8 $ 45.7 $ 37.7 $ 32.4 $ 46.0
Nonregulated Energy Operations 3.7 (48.5) (2.9) 1.1 (11.3)
Investment in ATC 1.9 - - - -
Real Estate 22.8 17.5 14.3 13.6 10.8
Other 2.1 2.9 (10.6) (17.9) (20.9)
-------------------------------------------------------------------------------------------------------------------------------
Continuing Operations 77.3 17.6 38.5 29.2 24.6
Discontinued Operations (0.9) (4.3) 73.7 207.2 112.6
Change in Accounting Principle - - (7.8) - -
-------------------------------------------------------------------------------------------------------------------------------
Net Income $76.4 $ 13.3 $104.4 $236.4 $137.2
-------------------------------------------------------------------------------------------------------------------------------
Average Electric Customers - Thousands 153.7 151.8 150.1 148.2 146.8
Electric Sales - Millions of MWh
Regulated Utility 12.8 11.7 11.2 11.1 11.1
Nonregulated Energy Operations 0.2 1.5 1.5 1.5 1.2
Company Use and Losses 0.3 0.5 0.9 0.7 0.7
-------------------------------------------------------------------------------------------------------------------------------
13.3 13.7 13.6 13.3 13.0
-------------------------------------------------------------------------------------------------------------------------------
Power Supply - Millions of MWh
Regulated Utility
Steam Generation 8.6 7.2 6.5 7.1 7.2
Hydro Generation 0.3 0.5 0.5 0.4 0.5
Long-Term Purchases - Square Butte 2.1 2.3 2.0 2.3 2.3
Purchased Power 2.1 2.1 3.0 1.9 1.8
-------------------------------------------------------------------------------------------------------------------------------
13.1 12.1 12.0 11.7 11.8
-------------------------------------------------------------------------------------------------------------------------------
Nonregulated Energy Operations
Steam 0.2 1.4 1.3 1.3 0.9
Purchased Power - 0.2 0.3 0.3 0.3
-------------------------------------------------------------------------------------------------------------------------------
0.2 1.6 1.6 1.6 1.2
-------------------------------------------------------------------------------------------------------------------------------
13.3 13.7 13.6 13.3 13.0
-------------------------------------------------------------------------------------------------------------------------------
Coal Sold - Millions of Tons 4.2 4.5 4.2 4.3 4.6
Real Estate Sales
Town Center - Commercial Square Feet 401,971 643,000 - - -
Residential Units 773 - - - -
Palm Coast - Residential Units 200 - - - -
Other Land - Acres 732 1,102 1,479 1,394 641
Lots - 7 211 265 1,425
-------------------------------------------------------------------------------------------------------------------------------
Capital Additions - Millions
Continuing Operations $109.4 $58.6 $57.8 $ 68.7 $ 81.7
Discontinued Operations - 4.5 21.4 67.6 119.5
-------------------------------------------------------------------------------------------------------------------------------
$109.4 $63.1 $79.2 $136.3 $ 201.2
-------------------------------------------------------------------------------------------------------------------------------
Excludes unallocated ESOP shares.
Effective January 1, 2006, our Taconite Harbor generating facility was redirected from Nonregulated Energy Operations
to Regulated Utility.
Impacted by a $50.4 million, or $1.84 per share, charge related to the assignment of the Kendall County power
purchase agreement. (See Note 10.)
Impacted by a $2.5 million, or $0.09 per share, deferred tax benefit due to comprehensive state 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.
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 (see Note 11) and an $11.5 million, or
$0.41 per share, gain on the sale of ADESA shares related to the Company's ESOP (see Note 17).
Reflected the cumulative effect on prior years (to December 2003) of changing to the equity method of accounting
for investments in limited liability companies included in our emerging technology portfolio. (See Note 15.)
Included a $71.6 million, or $2.59 per share, gain on the sale of the Water Services businesses.
Included a $5.5 million, or $0.20 per share, charge related to the indefinite delay of a generation project in
Superior, Wisconsin.
ALLETE 2006 Form 10-K 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 4 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 in
this Form 10-K are realized.
EXECUTIVE SUMMARY
ALLETE is a diversified company providing fundamental products and services
since 1906. This includes our two core businesses--ENERGY and REAL ESTATE, as
well as our former operations in the water, paper, telecommunications and
automotive industries.
ENERGY is comprised of Regulated Utility, Nonregulated Energy Operations and
Investment in ATC.
- REGULATED UTILITY includes retail and wholesale rate regulated electric,
natural gas and water 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, approximately 50 MW of nonregulated generation and
Minnesota land sales.
In 2004 and 2005, Nonregulated Energy Operations also included
nonregulated generation (non-rate base generation sold at market-based
rates primarily to the wholesale market) from our Taconite Harbor
facility in northern Minnesota, and generation secured through the
Kendall County power purchase agreement.
- INVESTMENT IN ATC includes our equity ownership interest in ATC.
REAL ESTATE includes our Florida real estate operations.
OTHER includes our investments in emerging technologies, and earnings on cash
and short-term investments.
We are committed to earning a financial return that rewards our shareholders,
allows for reinvestment in our businesses, and sustains our growth. We strive to
grow earnings and dividends that will result in a total shareholder return that
is superior to that of similar companies. Our goal is to earn a financial return
that will allow us to provide dividend increases while at the same time fund our
growth initiatives.
Our management believes that we can best grow earnings through the combined
financial performance of a limited number of significant business units. In
addition to providing earnings growth opportunities, this mix of diverse
businesses helps mitigate the potential financial risk inherent in the economic
cycles of each individual business.
We believe that, in order to enhance our ability to achieve our long-term annual
earnings growth goals, we must pursue a strategy of further expansion of our
energy and/or real estate businesses, and/or a new industry segment outside of
these two businesses. We will be disciplined and patient in our approach, with
the direct involvement of our senior executives and Board of Directors.
We have provided fundamental products and services for 100 years, and we expect
that our diversification efforts beyond our existing Energy and Real Estate
businesses will generally be similarly focused. We currently anticipate that the
size of an investment in a new industry segment could be in the range of $100
million to $500 million.
We achieved several milestones during 2006 that lay the groundwork for future
success. These achievements include:
- Commencing ALLETE's investment in ATC;
- Starting construction on an aggressive air emissions control plan with
current cost recovery;
- Purchasing electricity from a new 50-MW wind facility in North Dakota
and signing an agreement to purchase power from a second 48-MW wind
facility;
- Maintaining a high level of electric sales to industrial customers;
- Signing a long-term contract for approximately 70 MW with a new large
industrial customer, PolyMet Mining;
- Receiving development order approval for our Ormond Crossings real
estate project; and
- Closing the first sales contracts at our Palm Coast Park development.
31 ALLETE 2006 Form 10-K
EXECUTIVE SUMMARY (CONTINUED)
2006 2005 2004
----------------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT PER SHARE AMOUNTS
Operating Revenue
Regulated Utility $639.2 $575.6 $555.0
Nonregulated Energy Operations 65.0 113.9 106.8
Real Estate 62.6 47.5 41.9
Other 0.3 0.4 0.4
----------------------------------------------------------------------------------------------------------------------------
$767.1 $737.4 $704.1
----------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Regulated Utility $543.8 $486.0 $476.3
Nonregulated Energy Operations 61.4 186.6 108.6
Real Estate 18.3 15.6 15.1
Other 2.9 4.1 3.2
----------------------------------------------------------------------------------------------------------------------------
$626.4 $692.3 $603.2
----------------------------------------------------------------------------------------------------------------------------
Interest Expense
Regulated Utility $20.2 $17.4 $18.5
Nonregulated Energy Operations 3.3 6.6 4.9
Real Estate - 0.1 0.3
Other 3.9 2.3 8.0
----------------------------------------------------------------------------------------------------------------------------
$27.4 $26.4 $31.7
----------------------------------------------------------------------------------------------------------------------------
Other Income (Expense)
Regulated Utility $ 0.9 $0.7 $ 0.1
Nonregulated Energy Operations 2.2 1.7 0.6
Investment in ATC 3.0 - -
Other 8.8 (1.3) (12.9)
----------------------------------------------------------------------------------------------------------------------------
$14.9 $1.1 $(12.2)
----------------------------------------------------------------------------------------------------------------------------
Income (Loss)
Regulated Utility $46.8 $45.7 $ 37.7
Nonregulated Energy Operations 3.7 (48.5) (2.9)
Investment in ATC 1.9 - -
Real Estate 22.8 17.5 14.3
Other 2.1 2.9 (10.6)
----------------------------------------------------------------------------------------------------------------------------
Continuing Operations 77.3 17.6 38.5
Discontinued Operations (0.9) (4.3) 73.7
Change in Accounting Principle - - (7.8)
----------------------------------------------------------------------------------------------------------------------------
Net Income $76.4 $13.3 $104.4
----------------------------------------------------------------------------------------------------------------------------
Diluted Average Shares of Common Stock 27.9 27.4 28.4
----------------------------------------------------------------------------------------------------------------------------
Diluted Earnings (Loss) Per Share of Common Stock
Continuing Operations $2.77 $0.64 $1.35
Discontinued Operations (0.03) (0.16) 2.59
Change in Accounting Principle - - (0.27)
----------------------------------------------------------------------------------------------------------------------------
$2.74 $0.48 $3.67
----------------------------------------------------------------------------------------------------------------------------
Return on Common Equity 12.1% 2.2% 8.3%
----------------------------------------------------------------------------------------------------------------------------
Effective January 1, 2006, our Taconite Harbor generating facility was redirected from Nonregulated Energy Operations
to Regulated Utility.
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 10.)
Impacted by a $2.5 million, or $0.09 per share, deferred tax benefit due to comprehensive state 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.
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.
ALLETE 2006 Form 10-K 32
EXECUTIVE SUMMARY (CONTINUED)
Net income for 2006 was $76.4 million, or $2.74 per diluted share ($13.3
million, or $0.48 per diluted share for 2005; $104.4 million, or $3.67 per
diluted share for 2004). Net income for 2006 was up $63.1 million from 2005
reflecting:
- the absence of the Kendall County Charge ($50.4 million recorded in
2005);
- the absence of Kendall County operating losses ($1.9 million recorded in
2005);
- the absence of emerging technology impairments ($3.3 million recorded in
2005);
- the absence of the loss on the sale of our telecommunication business
($3.6 million recorded in 2005);
- increased income from Real Estate ($5.3 million);
- increased earnings on cash and short-term investments ($2.6 million);
- income from our investment in ATC ($1.9 million in 2006); and
- increased income from Regulated Utility ($1.1 million).
These factors were partially offset by the absence of tax benefits recorded in
2005--a $3.7 million current tax benefit due to the positive resolution of
income tax audit issues and a $2.5 million deferred tax benefit due to
comprehensive state tax planning initiatives.
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). (See Note 10.)
- 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.
- STATE TAX PLANNING INITIATIVES. In 2005, we implemented comprehensive
state 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 a nontaxable $11.5
million, or $0.41 per share, gain on the sale of
ADESA shares related to our ESOP. (See Note 17.)
Income from continuing operations was $77.3 million, or $2.77 per diluted share,
for 2006, an increase of $59.7 million, or $2.13 per diluted share, from 2005.
Excluding the three 2005 transactions not representative of ongoing operations
mentioned above, 2006 diluted earnings per share from continuing operations was
up 23% from 2005, exceeding our expected earnings growth for 2006 of 15% to 20%.
(See Non-GAAP Financial Measures.)
Financial results by segment for the periods presented and discussed in this
Form 10-K were impacted by the integration of our Taconite Harbor facility into
the Regulated Utility segment effective January 1, 2006. The redirection of
Taconite Harbor from our Nonregulated Energy Operations segment to our Regulated
Utility segment was in accordance with the Company's Resource Plan, as approved
by the MPUC, to help meet forecasted base load energy requirements. Under the
terms of our Resource Plan, we have operated the Taconite Harbor facility as a
rate-based asset within the Minnesota retail jurisdiction since January 1, 2006.
Prior to January 1, 2006, we operated our Taconite Harbor facility as
nonregulated generation. Historical financial results of Taconite Harbor for
periods prior to the 2006 redirection are included in our Nonregulated Energy
Operations segment.
KILOWATTHOURS SOLD 2006 2005 2004
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Regulated Utility
Retail and Municipals
Residential 1,100 1,102 1,053
Commercial 1,335 1,327 1,282
Industrial 7,206 7,130 7,071
Municipals 911 877 823
Other 79 79 79
---------------------------------------------------------------------------------------------------------------------------
Total Retail and Municipals 10,631 10,515 10,308
Other Power Suppliers 2,153 1,142 918
---------------------------------------------------------------------------------------------------------------------------
Total Regulated Utility 12,784 11,657 11,226
Nonregulated Energy Operations 240 1,521 1,496
---------------------------------------------------------------------------------------------------------------------------
Total Kilowatthours Sold 13,024 13,178 12,722
---------------------------------------------------------------------------------------------------------------------------
33 ALLETE 2006 Form 10-K
EXECUTIVE SUMMARY (CONTINUED)
REAL ESTATE 2006 2005 2004
REVENUE AND SALES ACTIVITY QUANTITY AMOUNT QUANTITY AMOUNT QUANTITY AMOUNT
---------------------------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS
Revenue from Land Sales
Town Center Sales
Commercial Sq. Ft. 401,971 $10.8 643,000 $15.2 - -
Residential Units 773 12.9 - - - -
Palm Coast Park
Residential Unit 200 3.0 - - - -
Other Land Sales
Acres 732 24.4 1,102 38.1 1,479 $32.8
Lots - - 7 0.4 211 4.5
---------------------------------------------------------------------------------------------------------------------------
Contract Sales Price 51.1 53.7 37.3
Revenue Recognized from
Previously Deferred Sales 9.7 - -
Deferred Revenue (3.8) (10.0) (1.5)
Adjustments (0.9) (1.7) -
---------------------------------------------------------------------------------------------------------------------------
Revenue from Land Sales 56.1 42.0 35.8
Other Revenue 6.5 5.5 6.1
---------------------------------------------------------------------------------------------------------------------------
$62.6 $47.5 $41.9
---------------------------------------------------------------------------------------------------------------------------
Reflected total contract sales price on closed land transactions. Land sales are recorded using a percentage-
of-completion method. (See Critical Accounting Estimates and Note 2.)
Contributed development dollars, which are credited to cost of real estate sold.
NET INCOME
REGULATED UTILITY contributed income of $46.8 million in 2006 ($45.7 million in
2005; $37.7 million in 2004). Earnings were slightly higher in 2006 than 2005 as
demand from our industrial customers continued to be strong. Kilowatthour sales
to industrial customers increased 76 million, or 1%, in 2006. Overall, Regulated
Utility kilowatthour sales increased 1,127 million, or 10%, reflecting the
inclusion of Taconite Harbor and its pre-existing wholesale energy sales
obligations in Regulated Utility since January 1, 2006.
In 2005, income was higher than 2004 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).
NONREGULATED ENERGY OPERATIONS reported income of $3.7 million in 2006 (a loss
of $48.5 million in 2005; a loss of $2.9 million in 2004). In April 2005, we
completed the assignment of our Kendall County power purchase agreement to
Constellation Energy Commodities. As a result of this transaction, we incurred a
charge to operating expenses totaling $50.4 million after tax in the second
quarter of 2005. In 2006, financial results reflected the absence of income from
Taconite Harbor, which is now reported as part of Regulated Utility, and
operating losses from Kendall County ($1.9 million in 2005; $8.5 million in
2004). In 2004, the Kendall County operating loss included a $0.7 million cost
to terminate a transmission contract.
Income from our coal operations was up $0.2 million from 2005 primarily due to a
16% increase in the delivery price per ton reflecting higher reimbursable coal
production expenses. Tons of coal sold were down 7% from 2005 in part due to an
outage at Minnkota Power's Unit 1 in 2006. 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.
INVESTMENT IN ATC contributed income of $1.9 million in 2006. We began investing
in ATC in May 2006. As of December 31, 2006, our equity investment balance in
ATC was $53.7 million, representing approximately a 7% ownership interest. (See
Notes 6 and 8.)
ALLETE 2006 Form 10-K 34
NET INCOME (CONTINUED)
REAL ESTATE contributed income of $22.8 million in 2006 ($17.5 million in 2005;
$14.3 million in 2004), reflecting continued strong demand for real estate in
Florida. Income was higher in 2006 primarily due to the recognition of deferred
earnings from prior land sales. The timing of the closing of real estate sales
varies from period to period and impacts comparisons between years. As of
December 31, 2006, we had $4.1 million of deferred profit on sales of real
estate, before taxes and minority interest, on our balance sheet. Most of this
deferred profit relates to Town Center which will be recognized over the next
several years as development obligations are completed. 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 as development
obligations are completed. (See Note 2.)
REAL ESTATE
PENDING CONTRACTS CONTRACT
AT DECEMBER 31, 2006 QUANTITY SALES PRICE
---------------------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS
Town Center
Commercial Sq. Ft. 786,400 $ 24.2
Residential Units 1,010 15.9
Palm Coast Park
Commercial Sq. Ft. 50,000 2.5
Residential Units 2,409 60.3
Other Land
Acres 196 10.9
---------------------------------------------------------------------------------------------------------------------
Total Pending Land Sales Under Contract $113.8
---------------------------------------------------------------------------------------------------------------------
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. Commercial square feet and residential units are estimated and include minority interest. The actual property
allocation at full build-out may be different than these estimates.
Includes land located in Ormond Beach and Palm Coast in northeast Florida and other land located in Cape Coral in
southwest Florida, all of which are not included in development projects.
At December 31, 2006, total pending land sales under contract were $113.8
million and are anticipated to close at various times through 2012. Prices on
these contracts range from $20 to $50 per commercial square foot, $8,000 to
$34,000 per residential unit and $11,000 to $1,774,200 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 from land sales to third parties if various formula-based
criteria are achieved.
If a purchaser defaults under terms of a contract, our remedies generally
include retention of the purchaser's deposit and the ability to remarket the
property to other prospective buyers. In many cases, the purchaser has also
incurred significant costs in planning, designing and marketing of the property
under contract before the contract closes.
OTHER reflected income of $2.1 million in 2006 ($2.9 million of income in 2005;
a $10.6 million loss in 2004). In 2006, income from Other was down $0.8 million
from 2005 primarily due to the absence of tax benefits recorded in 2005--a $3.7
million current tax benefit due to the positive resolution of income tax audit
issues and a $2.5 million deferred tax benefit due to comprehensive state tax
planning initiatives. In addition, a $0.9 million increase in interest expense
was more than offset by a $2.6 increase in earnings on cash and short-term
investments, the absence of impairments of $3.3 million related to certain
investments in our emerging technology portfolio and the absence of a $0.6
million charge recognized in 2005 for the probable payment under our guarantee
of Northwest Airlines debt.
In 2005, income from Other was up $13.5 million from 2004. Financial results for
2005 reflected the $3.7 million current tax benefit and the $2.5 million
deferred tax benefit previously mentioned, a $3.4 million decline in interest
expense as a result of lower debt balances, and a $1.9 million increase in
earnings on cash and short-term investments. Cash was higher in 2005 than 2004
due to proceeds received from the sale of Enventis Telecom in 2005 as well as
earnings on proceeds received from the sale of our Water Services businesses in
2004 and 2003, and proceeds received from ADESA in 2004. Equity losses related
to investments in venture capital funds declined in 2005 ($0 in 2005; $1.6
million in 2004) as did impairments related to certain investments in our
emerging technology portfolio ($3.3 million in 2005; $4.1 million in 2004).
Financial results for 2004 also included an $11.5 million gain on the sale of
ADESA stock related to our ESOP (see Note 17), 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.
35 ALLETE 2006 Form 10-K
NET INCOME (CONTINUED)
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 that we sold over the three-year period
from 2003 to 2005 and our telecommunications business, which we sold in December
2005. Discontinued operations reflected a $0.9 million loss in 2006 (a $4.3
million loss in 2005; $73.7 million of income in 2004).
In 2006, discontinued operations reflected a $0.9 million loss resulting from
additional legal and administrative expenses related to exiting the Water
Services businesses (a $2.5 million loss in 2005; a $1.3 million loss in 2004).
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 Florida, Inc. was
also recorded in 2005. Gains in 2004 from the sale of our North Carolina assets
and the remaining systems in Florida were offset by an adjustment to gains
reported in 2003. 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. 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.
Automotive Services contributed income of $74.4 million in 2004.
Financial results for our telecommunications business reflected a loss of $1.8
million in 2005 (income of $0.6 million in 2004). In 2005, we recorded a $3.6
million loss on the sale of this business. 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.)
2006 COMPARED TO 2005
REGULATED UTILITY
OPERATING REVENUE was up $63.6 million, or 11%, from 2005, reflecting
increased kilowatthour sales and increased fuel clause recoveries. Electric
sales increased 1,127 million kilowatthours, or 10%, mostly due to the
addition of Taconite Harbor wholesale power obligations to the Regulated
Utility segment effective January 1, 2006. In 2006, the majority of
Taconite Harbor sales are reflected in sales to other power suppliers.
Sales to other power suppliers were 2,153 million kilowatthours and $94.3
million (1,142 million kilowatthours and $52.8 million in 2005). Absent the
inclusion of pre-existing Taconite Harbor wholesale energy sales
obligations, sales to other power suppliers were down reflecting less
excess energy available for sale due to more planned outages at Company
generating facilities in 2006 than 2005. Electric sales to retail and
municipal customers increased 116 million kilowatthours, or 1%, and $23.5
million, mainly due to strong demand from industrial customers. Fuel clause
recoveries were higher in 2006 as a result of increased fuel and purchased
power expenses in 2006. Natural gas revenue was down $2.8 million from 2005
reflecting decreased usage due to warmer weather in 2006.
OPERATING EXPENSES were up $57.8 million, or 12%, from 2005.
FUEL AND PURCHASED POWER EXPENSE. Fuel and purchased power expense was up
$38.0 million from 2005, reflecting the inclusion of Taconite Harbor
operations beginning in 2006 ($22.8 million) and increased purchased power
expense due to higher prices paid for purchased power, less Company hydro
generation available as a result of below normal precipitation levels, and
planned maintenance at Company generating facilities in 2006.
OTHER OPERATING EXPENSES. In total, other operating expenses were up $19.8
million from 2005. Employee compensation was up $7.3 million primarily due
to the inclusion of Taconite Harbor, annual wage increases and the
inclusion of union employees in our results sharing compensation awards
program. Depreciation expense increased $4.8 million primarily due to the
inclusion of Taconite Harbor and a full year of depreciation of projects
capitalized in 2005. In total, plant maintenance expense increased $4.7
million reflecting the inclusion of Taconite Harbor maintenance in 2006
($4.0 million), increased planned maintenance expense at Boswell Unit 4
($1.6 million) and increased equipment fuel expenses ($0.9 million)
partially offset by a decrease in maintenance expense at Boswell Unit 3
($1.8 million). In 2005, planned maintenance was performed at Boswell Unit
3 while the unit was down due to a cooling tower failure. Pension expense
increased $2.2 million primarily due to a reduction in the discount rate
(5.50% in 2006; 5.75% in 2005). Insurance expense was up $1.0 million due
to increased premiums. Vegetation management expense was up $0.7 million
due to more completed in 2006. Property taxes were up $0.7 million due to
higher mill rates in 2006. Purchased natural gas expense was down $2.7
million due to decreased natural gas sales.
INTEREST EXPENSE was up $2.8 million, or 16%, from 2005, reflecting the
inclusion of Taconite Harbor in 2006 partially offset by lower effective
interest rates (5.92% in 2006; 6.07% in 2005).
ALLETE 2006 Form 10-K 36
2006 COMPARED TO 2005 (CONTINUED)
NONREGULATED ENERGY OPERATIONS
OPERATING REVENUE was down $48.9 million, or 43%, from 2005 due to the
absence of revenue from Taconite Harbor ($55.1 million in 2005) and Kendall
County ($3.1 million in 2005). Effective January 1, 2006, Taconite Harbor
is reported as part of Regulated Utility. Kendall County operations ceased
to be included with our operations effective April 1, 2005, when the
Company assigned the power purchase agreement to Constellation Energy
Commodities. Coal revenue, realized under cost plus a fixed fee agreements,
was up $3.7 million from 2005 reflecting a 16% increase in the delivery
price per ton due to higher reimbursable coal production expenses (see
operating expenses below). In 2006, tons of coal sold were down 7% from
2005 in part due to an outage at Minnkota Power's Unit 1 in 2006.
OPERATING EXPENSES were down $125.2 million, or 67%, from 2005 reflecting
the absence of a $77.9 million charge related to the assignment of the
Kendall County power purchase agreement to Constellation Energy Commodities
on April 1, 2005, expenses related to Taconite Harbor ($49.3 million in
2005) and other expenses related to Kendall County ($6.3 million in 2005)
that were incurred prior to April 1, 2005. Expenses related to coal
operations were up $3.4 million reflecting increased equipment lease costs
($1.3 million), higher fuel expenses ($0.6 million) and increased parts and
supplies ($0.9 million).
INTEREST EXPENSE was down $3.3 million, or 50%, primarily due to the
absence of Taconite Harbor in 2006.
OTHER INCOME (EXPENSE) reflected $0.5 million more income in 2006 due to
increased Minnesota land sales.
INVESTMENT IN ATC
OTHER INCOME (EXPENSE) reflected $3.0 million of income in 2006 from our
equity investment in ATC, resulting from our share of ATC's earnings.
REAL ESTATE
OPERATING REVENUE was up $15.1 million, or 32%, from 2005, due to the
recognition of revenue from prior land sales at our Town Center development
project, which are accounted for under the percentage-of-completion method.
Revenue from land sales was $56.1 million in 2006 which included $9.7
million of previously deferred revenue. In 2005, revenue from land sales
was $42.0 million. Sales at Town Center represented 773 residential units
and the rights to build up to 401,971 square feet of commercial space in
2006 (643,000 commercial square feet in 2005). Sales at Palm Coast Park
represented 200 residential units in 2006. In 2006, 732 acres of other land
were sold (1,102 acres and 7 lots in 2005). The first land sales for Town
Center were recorded in June 2005 and the first land sales at Palm Coast
Park were recorded in August 2006. At December 31, 2006, revenue of $5.6
million ($11.5 million at December 31, 2005) was deferred and will be
recognized on a percentage-of-completion basis as development obligations
are completed.
OPERATING EXPENSES were up $2.7 million, or 17%, from 2005 reflecting a
$1.6 million increase in the cost of real estate sold ($10.2 million in
2006; $8.6 million in 2005) due to the recognition of the cost of real
estate sold at our Town Center development project which were previously
deferred under the percentage-of-completion method. Selling expenses
increased $0.6 million due to higher broker commission in 2006 and
recognition of prior year's selling expenses at our Town Center development
project which were previously deferred under the percentage-of-completion
method. Property tax expense was $0.2 million higher in 2006 due to
increased assessment values and higher rates. At December 31, 2006, cost of
real estate sold totaling $1.3 million ($2.2 million at December 31, 2005)
and selling expenses of $0.2 million ($0.3 million at December 31, 2005),
primarily related to Town Center land sales, were deferred until
development obligations are completed.
OTHER
OPERATING EXPENSES were down $1.2 million, or 29%, from 2005, reflecting
lower general and administrative expenses in 2006.
INTEREST EXPENSE was up $1.6 million, or 70%, from 2005, reflecting
interest on additional taxes owed on the gain on the sale of our Florida
Water assets and state tax audits, and higher variable rates in 2006.
OTHER INCOME (EXPENSE) reflected $10.1 million more income in 2006 due to a
$4.4 million increase in earnings on cash and short-term investments due to
higher rates and higher average balances in 2006, the absence of $5.1
million of impairments related to certain investments in our emerging
technology portfolio recorded in 2005 and the absence of a $1.0 million
charge recognized in 2005 for the probable payment under our guarantee of
Northwest Airlines debt.
37 ALLETE 2006 Form 10-K
2006 COMPARED TO 2005 (CONTINUED)
INCOME TAXES
For the year ended December 31, 2006, the effective tax rate from
continuing operations before minority interest was 36.1% (2.5% benefit for
the year ended December 31, 2005). The increase in the effective rate
compared to last year was primarily due to the lower income from continuing
operations in 2005 as a result of the Kendall County Charge, and one-time
tax benefits realized in 2005 for adjustments to our deferred tax assets
and liabilities as a result of comprehensive state tax planning
initiatives, and positive resolution of audit issues. The effective rate of
36.1% for the year ended December 31, 2006, was less than the combined
state and federal statutory rate because of investment tax credits,
deductions for Medicare health subsidies, depletion and the expected use of
state capital loss carryforwards.
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 224 million,
or 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. 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 207 million, or
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 431 million, or 4%, from 2004. Revenue
from natural 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, natural gas
purchases increased $2.6 million due to higher prices and pension expense
increased $1.7 million primarily due to a reduction in the discount rate
(5.75% in 2005; 6.00% 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).
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 cost plus a fixed fee agreements,
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
reimbursable 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, or 72%, 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.
ALLETE 2006 Form 10-K 38
2005 COMPARED TO 2004 (CONTINUED)
NONREGULATED ENERGY OPERATIONS (CONTINUED)
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,
1,102 acres and 7 lots were sold. 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 expenses.
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 certain investments in our emerging
technology portfolio 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 17), and $0.9 million
of income from a rabbi trust established to secure certain deferred
executive compensation.
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 state 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. We received an audit report resolving open
issues that resulted in a current tax benefit. 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.)
39 ALLETE 2006 Form 10-K
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 10);
- 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 state 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 11); 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 17).
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 2006 2005 2004
-------------------------------------------------------------------------------------------------------------------------
DILUTED EARNINGS PER SHARE OF COMMON STOCK
Continuing Operations Before Change in Accounting Principle $2.77 $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 -
State Tax Planning Initiatives - 0.09 -
-------------------------------------------------------------------------------------------------------------------------
$2.77 $2.26 $1.32
-------------------------------------------------------------------------------------------------------------------------
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements and related disclosures in conformity
with generally accepted accounting principles requires management to make
various estimates and assumptions that affect amounts reported in the
consolidated financial statements. These estimates and assumptions may be
revised, which may have a material effect on the consolidated financial
statements. Thus, actual results could differ from the amounts reported and
disclosed herein. These policies are discussed with the Audit Committee of our
Board of Directors on a regular basis. The following represent the policies we
believe are most critical to our business and the understanding of our results
of operations.
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 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.
ALLETE 2006 Form 10-K 40
CRITICAL ACCOUNTING ESTIMATES (CONTINUED)
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. In certain cases, we pay fees or construct
improvements to mitigate offsite traffic impacts. In return, we receive traffic
impact fee credits. We recognize revenue from the sale of traffic impact fee
credits when payment is received. In addition to minimum base price contracts,
certain contracts allow us to receive participation revenue from land sales to
third parties if various formula-based criteria are achieved.
We annually review the real estate carrying value for impairment. If
circumstances indicate that the carrying value may not be recoverable, we record
an 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 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 future cash flows.
PENSION AND POSTRETIREMENT HEALTH AND LIFE ACTUARIAL ASSUMPTIONS. We account for
our pension and postretirement benefit obligations in accordance with the
provisions of SFAS 158, "Employers' Accounting for Defined Benefit Pension and
Other Postretirement Plans," 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 our
obligations and annual cost of our pension and postretirement benefits. 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 65% equity, 30% fixed-rate and 5%
other securities. Equity securities consist of a mix of market capitalization
sizes and also include investments in real estate and venture capital funds. We
currently use an expected long-term rate of return of 9% in our actuarial
determination of our pension and other postretirement expense. 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 5.75%. The
discount rate is determined considering high-quality long-term corporate bond
rates at the valuation date. The discount rate is compared to the Citigroup
Pension Discount Curve adjusted for ALLETE's specific cash flows. We believe the
adjusted discount curve used in this comparison does 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 16.)
REGULATORY ACCOUNTING. Our regulated utility operations are subject to the
provisions of SFAS 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS 71). SFAS 71 requires us to reflect the effect of regulatory
decisions in our financial statements. Regulatory assets or liabilities arise as
a result of a difference between accounting principles generally accepted in the
U.S. and the accounting principles imposed by the regulatory agencies.
Regulatory assets generally represent incurred costs that have been deferred as
they are probable of recovery in customer rates. Regulatory liabilities
generally represent obligations to make refunds to customers and amounts
collected in rates for which the related costs have not yet been incurred.
We recognize regulatory assets and liabilities in accordance with applicable
state and federal regulatory rulings. The recoverability of regulatory assets is
periodically assessed by considering factors such as, but not limited to,
changes in regulatory rules and rate orders issued by applicable regulatory
agencies. The assumptions and judgments used by regulatory authorities may have
an impact on the recovery of costs, the rate of return on invested capital, and
the timing and amount of assets to be recovered by rates. A change in these
assumptions may result in a material impact on our results of operations. (See
Note 5.)
41 ALLETE 2006 Form 10-K
CRITICAL ACCOUNTING ESTIMATES (CONTINUED)
VALUATION OF 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 investments 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 review these investments for impairment on a
quarterly basis 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 2006, we did not record an
impairment loss on these investments ($5.1 million pretax in 2005).
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 purposes. As of December 31, 2006, we
have, where appropriate, recorded a valuation allowance against our deferred tax
assets associated with realized capital losses and impairments to reduce the
deferred tax assets to the amount we estimate is more likely than not to be
realized. While we believe the resulting tax reserve balances as of December 31,
2006, reflect the most likely outcome of these tax matters in accordance with
SFAS 109, "Accounting for Income Taxes," the ultimate amount of capital losses
resulting in tax benefits could differ from the net amount of deferred tax
assets at December 31, 2006.
OUTLOOK
ALLETE is committed to earning a financial return that rewards its shareholders,
allows for reinvestment in its businesses and sustains growth. In the last 10
years, our average annual total shareholder return was 17%. By comparison, the
Standard & Poor's 500 Index averaged 8% for the same period. We believe that, in
order to enhance our ability to achieve our long-term annual earnings growth
goals, we must pursue a strategy of further expansion of our energy and/or real
estate businesses, and/or a new industry segment outside of these two
businesses.
EARNINGS GUIDANCE. In 2007, we expect ALLETE's diluted earnings per share from
continuing operations to be in the range of $2.95 to $3.05. The growth in
earnings per share is expected to come primarily from our larger full-year
investment in ATC. We also expect increased sales at our Real Estate operations
and continued strong sales at our Regulated Utility operations. This earnings
projection does not include an impact from any investment we may make in new
growth opportunities.
ENERGY. 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 the
Midwest. In addition, we will evaluate growth opportunities through merger,
acquisition or asset additions in our region. We believe our energy businesses
are well positioned to successfully deal with the issues affecting the electric
utility industry 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 funds for capital investments. We believe electric industry
deregulation is unlikely in Minnesota or Wisconsin in the next five years.
RATE CASES. Minnesota Power does not expect to file a request to increase rates
for its retail utility operations during 2007. 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.
ALLETE 2006 Form 10-K 42
OUTLOOK (CONTINUED)
In May 2006, SWL&P filed an application with the PSCW for authority to increase
retail utility rates on its electric, natural gas and water services an average
of 5.2%, and requested an 11.7% return on common equity. An order was issued in
December 2006 that allows for an 11.1% return on common equity. New rates became
effective January 1, 2007, and reflect a 2.8% average increase in retail utility
rates for SWL&P customers (a 2.8% increase in electric rates, a 1.4% increase in
natural gas rates and an 8.6% increase in water rates). The rate case allowed
for a $1.7 million increase in annual revenue requirements. The approved rates
were lower than originally requested due to the subsequent removal of costs for
a new water tower and electric substation from the original request. Both of
these projects are now estimated to be in service in late 2008 because of delays
in obtaining all the necessary construction approvals. SWL&P plans to file for
another rate increase request in 2008.
INDUSTRIAL CUSTOMERS. Approximately 50% of our Regulated Utility kilowatthour
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 2007 is anticipated to be about 40 million tons
(production was 40 million tons in 2006; 41 million tons in 2005 and in 2004).
There was a slight slowdown for two of our customers in the paper industry in
late December 2006 and early January 2007 due to slightly lower demand for their
products and a need to balance orders with inventory. It is not known whether
this trend will continue further into 2007. In addition, the wood products
industry is operating at reduced levels reflecting a decrease in the number of
new housing starts.
Our pipeline customers continued to operate at or above historic pumping levels
during 2006 and forecast operating at record pumping levels in 2007. As Western
Canadian oil sands reserves continue to develop and expand, pipeline operators
served by the Company are executing expansion plans to transport additional
crude oil supply to United States markets. We believe we are strategically
positioned to serve these expanding pipeline facilities as Canadian supply
continues to grow and displace domestic and imported Gulf Coast production.
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. If some or all of these projects are completed, Minnesota Power
could serve between 100 MW and 400 MW of new load. In 2006, a contract for
approximately 70 MW was successfully negotiated with PolyMet Mining, a new
customer planning to start a copper, nickel and precious metals (non-ferrous)
mining operation in late 2008. If PolyMet's environmental permits are received
and start-up is achieved, the contract with PolyMet Mining will run through at
least 2018. The PolyMet Mining electric service agreement requires MPUC
approval.
ADDITIONAL GENERATION NEEDS. In 2006, the MPUC approved our Resource Plan, which
detailed our forecasted retail energy needs and our projected demand along with
our energy sourcing options to meet these projected requirements. We project an
additional capacity need of approximately 150 MW by 2010, with another 200 MW of
capacity needed by 2015. One of the key components in meeting our future needs
was the redirection of our Taconite Harbor generating facility from Nonregulated
Energy Operations to Regulated Utility operations effective January 1, 2006. We
have also entered into a 50-MW long-term power purchase agreement with Manitoba
Hydro which extends from May 2009 to April 2015 that is pending regulatory
approval. We began purchasing the output from the 50-MW Oliver Wind I project in
North Dakota under a 25-year power purchase agreement with an affiliate of FPL
Energy in late December 2006. In January 2007, we announced plans for a second,
48-MW North Dakota wind project (Oliver Wind II) that is expected to be
operational by the end of 2007, pending regulatory and other approvals. In
addition, we are continuing to pursue the purchase of renewable energy from a
new 25-MW to 30-MW wind facility that would be located in northeastern
Minnesota, subject to a power purchase agreement and regulatory approvals.
We are also exploring construction and purchase options for our anticipated
resource needs by 2015. Minnesota Power, Basin Electric Power Cooperative,
Minnkota Power and Montana-Dakota Utilities Company are continuing a study that
will evaluate the feasibility of a joint lignite-fueled generating resource in
the vicinity of the existing Milton R. Young generating station (which includes
Square Butte) near Center, North Dakota. We are 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. Any final resource decision by Minnesota Power is subject to MPUC and
other approvals.
We anticipate that our winter peak demand requirements by customers in our
service territory will increase at an average annual growth rate of 1.5% through
2011. We continue to make investments to maintain and improve the integrity of
our generating, transmission and distribution assets, and maintain environmental
compliance.
43 ALLETE 2006 Form 10-K
OUTLOOK (CONTINUED)
AREA AND BOSWELL UNIT 3 EMISSION REDUCTION PLANS. In May 2006, the MPUC approved
our filing for cost recovery of planned expenditures to reduce emissions to meet
pending federal requirements at Taconite Harbor and Laskin under the AREA Plan.
The AREA Plan approval allows Minnesota Power to recover Minnesota
jurisdictional costs for SO2, NOX and mercury emission reductions made at these
facilities without a rate proceeding. Minnesota cost recovery from retail
customers will include return on investment, depreciation, and incremental
operations and maintenance expenses. Minnesota Power completed installation of
new equipment at the first of two Laskin units at the end of November 2006, with
the first of three Taconite Harbor unit installations anticipated to be
completed by mid-2007. Work on all units at Taconite Harbor and Laskin is
anticipated to be completed by the end of 2008. Cost recovery filings are
required to be made 90 days prior to the anticipated in-service date for the
equipment at each unit, with rate recovery beginning the month following the
in-service date. We began cost recovery of AREA plan costs in December 2006 with
the placement in service of Laskin Unit 2. We filed with the MPUC for cost
recovery on Laskin Unit 1 in January 2007 and expect to begin cost recovery in
May 2007. We anticipate beginning cost recovery on Taconite Harbor Unit 2 in
mid-2007 and Taconite Harbor Units 1 and 3 in 2008. AREA plan expenditures as of
December 31, 2006, were $11.4 million.
In May 2006, we announced plans to make emission reduction investments at our
Boswell Unit 3 generating unit. Plans include reductions of particulate, SO2,
NOX and mercury emissions to meet pending federal and state requirements. The
estimated capital cost for these reductions is approximately $200 million, $14
million of which was spent in 2006 for design engineering and related costs. The
balance is expected to be spent from 2007 through 2009 and is included in the
$233 million the Company expects to spend for environmental upgrades from 2007
through 2011. (See Capital Requirements.) In October 2006, we submitted a filing
to the MPCA for approval of the Boswell Unit 3 emission reduction plan. A filing
with the MPUC for approval of Minnesota jurisdictional related expenditures on
Boswell Unit 3 was made in January 2007 to allow cost recovery on these
investments from retail customers without a rate proceeding. MPUC approval would
authorize a cash return on construction work in progress during the construction
phase and allow recovery for a return on investment, depreciation, and
incremental operations and maintenance expenses once the unit is placed into
service in late 2009. We expect to begin cost recovery on construction work in
progress in 2008. In 2007, we will be filing with the MPUC a request to extend
the asset life for depreciation purposes on Boswell Unit 3 from 8 years to 29
years. We anticipate approval of this filing in 2007. This extension will reduce
2007 depreciation expense by approximately $5 million.
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, the 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. CAIR was finalized by
the EPA in March 2006 when the EPA determined it would not make any changes to
the CAIR as a result of the petitions for reconsideration. Petitions for Review,
including Minnesota Power's, remain pending at the Court of Appeals, with
resolution of the Petitions for Review anticipated in 2008. In March 2005, the
EPA issued its Clean Air Mercury Rule (CAMR). The EPA granted reconsideration of
the CAMR in October 2005 and finalized the rule in early 2006. Minnesota Power
is not participating in the Petitions for Review of the CAMR. The final outcomes
of these regulatory proceedings are expected to require significant capital
investments in the 2008 to 2012 timeframe. (See Capital Requirements.)
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 April 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 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.
This denial created a refund obligation. Minnesota Power requested rehearing of
the order in a filing made with the MPUC in January 2006. Three other Minnesota
utilities affected by the order also filed for rehearing, as did the DOC and
MISO. In February 2006, the MPUC granted rehearing of the MISO Day 2 docket and
suspended the refund obligation for charges recovered through the fuel clause
denied in the December 2005 order. The MPUC also ordered a review of MISO Day 2
costs to determine which costs should be recovered on a current basis through
the fuel clause and which costs were more appropriately deferred for potential
recovery through base rates. The Company worked with other Minnesota utilities,
the DOC and other stakeholders to review MISO Day 2 costs and to prepare a joint
report and recommendations. The joint report and recommendations were filed with
the MPUC in June 2006. A technical conference on the report was held with the
MPUC on October 31, 2006. At a hearing November 9, 2006, the MPUC approved
current recovery of nearly all MISO Day 2 charges.
ALLETE 2006 Form 10-K 44
OUTLOOK (CONTINUED)
On December 20, 2006, the MPUC issued an order allowing Minnesota Power and the
other utilities involved in the MISO Day 2 proceeding to continue recovering
MISO Day 2 charges through the Minnesota retail fuel clause except for MISO Day
2 administrative charges. On January 8, 2007, this order was challenged by the
Minnesota OAG, which has sought reconsideration. The rehearing has been opposed
by Minnesota Power and the other utilities, as well as MISO. The reconsideration
request is currently pending before the MPUC. The MPUC has until March 9, 2007,
to act on the Minnesota OAG's request. The order, if upheld, grants deferred
accounting treatment for three MISO Day 2 charge types that were determined to
be administrative charges. Under the order, Minnesota Power would refund through
customer bills approximately $2 million of administrative charges previously
collected through the fuel clause between April 1, 2005, and December 31, 2006,
and record these administrative charges as a regulatory asset. Minnesota Power
would be permitted to continue accumulating MISO Day 2 administrative charges
after December 31, 2006, as a regulatory asset until it files its next rate
case, at which time recovery for such charges will be determined. This order
would remove the subject to refund requirement of the two interim orders, and
include extensive fuel clause reporting requirements that would be reviewed in
Minnesota Power's monthly and annual fuel clause filings with the MPUC. There
would be no impact on earnings as a result of this ruling. The Company is unable
to predict the outcome of this matter.
As a result of the MPUC's December 2006 order allowing recovery of nearly all
MISO Day 2 charges through the fuel clause, on December 28, 2006, Minnesota
Power rescinded its December 2005 Letter of Intent to Withdraw from MISO.
INVESTMENT IN ATC. In December 2005, we entered into an agreement with Wisconsin
Public Service Corporation and WPS Investments, LLC that provides for our
Wisconsin subsidiary, Rainy River Energy Corporation - Wisconsin, to invest $60
million in ATC. In May 2006, the PSCW reviewed and approved the request that
allows us to invest in ATC. During 2006, we invested $51.4 million in ATC. We
plan to invest an additional $8.6 million in ATC in early 2007 to reach our $60
million investment commitment and estimated 8% ownership interest. As of
December 31, 2006, our equity investment balance in ATC was $53.7 million,
representing approximately a 7% ownership interest. (See Note 6.) We will have
the opportunity to make additional investments in ATC through general capital
calls based upon our pro-rata investment level in ATC.
REAL ESTATE. We have a diversified mix of property under contract and available
for sale--residential, commercial and industrial--in desirable Florida locations
(see Item 1 - Real Estate). 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.
Rapid residential growth over the past few years in our markets has created a
steady demand for our commercial properties. As of December 31, 2006, we had
$113.8 million of pending contracts scheduled to close over the next several
years. We believe the long-term growth indicators for Florida real estate remain
strong.
Progress continues on our three major planned development projects in
Florida--Town Center, which will be a new downtown for Palm Coast; Palm Coast
Park, which is located in northwest Palm Coast; and Ormond Crossings, which is
located in Ormond Beach along Interstate 95. Other ongoing land sales and rental
income at the retail shopping center in Winter Haven provide us with additional
revenue.
ALLETE Properties plans to maximize the value of the property it currently owns
through entitlement, infrastructure improvements and orderly sales of
properties. In addition to managing its current real estate inventory, ALLETE
Properties is focused on identifying, acquiring and entitling vacant land in
Florida and other parts of the southeast United States.
As of December 31, 2006, we had $4.1 million of deferred profit on sales of real
estate, before taxes and minority interest, on our balance sheet. Most of the
deferred profit relates to Town Center which will be recognized over the next
several years as development obligations are completed.
TOWN CENTER. Throughout 2005 and 2006, our marketing program targeted a blend of
office, retail commercial, residential and mixed-use project developers. In
2006, a Publix grocery store anchored retail center opened and construction
started on an 84,000 square foot medical center. Twenty other projects are in
the permitting stage, 11 of which are expected to break ground in 2007. Future
marketing efforts will focus on attracting the following additional land uses to
Town Center: residential apartments, assisted living facilities, business park
uses and restaurants.
Pending land sales under contract for properties at Town Center totaled $40.1
million at December 31, 2006. We have the opportunity to receive participation
revenue as part of one of these sales contracts. Among the pending Town Center
sales contracts is a contract with Developers Realty Corporation (DRC) to
develop projects in the downtown core area and a large retail shopping center on
a 50-acre tract. DRC has entered into an agreement to form a joint venture with
Weingarten Realty Investors (Weingarten). DRC/Weingarten has a commitment from a
major national retail anchor for the retail shopping center.
Sites have also been set aside for a new city hall, an arts and entertainment
center, and other public uses. At build-out, Town Center is expected to include
over 2,900 residential units, including lodging facilities and 3.7 million
square feet of various types of commercial space, including a movie theater.
Future market conditions will determine how quickly Town Center is built out.
45 ALLETE 2006 Form 10-K
OUTLOOK (CONTINUED)
PALM COAST PARK. We began selling property at Palm Coast Park in August 2006.
Three developers who have purchased land at Palm Coast Park have started
planning, engineering design and permitting of their respective projects. 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.
In 2006, the Palm Coast Park District issued $31.8 million of tax-exempt, 5.7%
Special Assessment Bonds, the majority of which will be used to fund the
construction of the major infrastructure improvements at Palm Coast Park, and to
mitigate traffic and environmental impacts at Palm Coast Park. Major
infrastructure construction began in December 2006 and is expected to be
completed in 2007. Commercial and industrial lots will be offered for sale in
2007, with closings anticipated to begin in 2008. We anticipate that the Palm
Coast Park District will need to issue additional bonds to pay for the
development of residential and commercial properties.
At December 31, 2006, pending land sales under contract for properties at Palm
Coast Park totaled $62.8 million. We have the opportunity to receive
participation revenue as part of these sales contracts. One of the pending sales
contracts, for the sale of five residential tracts and one commercial tract for
a total of $52.5 million, provides for closings in 2007, 2008 and 2009. The
project, which is named Sawmill Creek, will include up to 1,469 residential
housing units, a championship golf course and neighborhood retail office space,
along with a community park and an elementary and middle school. Other pending
land sale contracts include a residential tract for an affordable condominium
project and a 600-unit single-family residential project that will be connected
to the existing Matanzas Woods golf course neighborhood.
ORMOND CROSSINGS. In December 2006, we received DRI approval from the city of
Ormond Beach for our 6,000-acre Ormond Crossings project. This is a key approval
necessary to develop up to 3,700 residential units and 5 million commercial
square feet within Ormond Crossings. Most of Ormond Crossings is located in the
city of Ormond Beach in Volusia County; the remainder of the development is an
adjacent piece of unincorporated land in neighboring Flagler County. A
development order from Flagler County is under review by the Flagler County
Commission and, if approved, we will receive entitlements for up to 700
additional residential units. Actual build-out of Ormond Crossings, however,
will consider market demand as well as infrastructure and mitigation costs.
After an agreement is finalized with the Florida Department of Transportation
concerning traffic mitigation costs, we will determine the best economic
build-out of the project. The agreement and economic analysis are expected to be
completed in 2007.
Engineering design and permitting will be ongoing as the project is developed
and sites are sold. We anticipate Ormond Crossings land sales closings starting
in 2009.
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 $2.5 million at December
31, 2006, and is expected to be invested in 2007. We do not have plans to make
any additional investments beyond this commitment.
INCOME TAXES. ALLETE's aggregate federal and multi-state statutory tax rate is
expected to be approximately 40% for 2007. On an ongoing basis ALLETE, has
certain tax credits and other tax adjustments that will reduce the expected
effective tax rate to approximately 38% for 2007. These tax credits and
adjustments historically have included items such as investment tax credits,
depletion allowances, Medicare prescription reimbursement as well as other
items. The effective rate will also be impacted by such items as changes in
income from operations before minority interest and income taxes, state and
federal tax law changes that become effective during the year, business
combinations and configuration changes, tax planning initiatives and resolution
of prior years' tax matters. Based upon our earnings per share guidance for
2007, we expect our effective tax rate for 2007 to approximate 38%.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW ACTIVITIES
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 $44.8 million, $104.5 million of short-term investments and a
debt to total capital ratio of 37% at December 31, 2006.
ALLETE 2006 Form 10-K 46
LIQUIDITY AND CAPITAL RESOURCES (CONTINUED)
OPERATING ACTIVITIES. Cash from operating activities was $142.5 million for 2006
($53.5 million for 2005; $175.0 million for 2004). Cash from operating
activities was higher in 2006 than 2005, primarily due to the $77.9 million
Kendall County Charge in 2005 and related $24.3 million federal tax refund
received in 2006. Cash also increased $4.4 million in 2006 due to the collection
of customer receivables which were up as a result of colder weather in December
2005. Other differences between 2006 and 2005 include an additional $9 million
cash used for inventories in 2006 and the payment of approximately $13 million
of 2005 accrued liabilities. Additional inventories primarily reflect coal
purchases in anticipation of maintenance on coal handling equipment.
Cash from operating activities was lower in 2005 than 2004 due to the absence of
cash from discontinued operations ($2.3 million in 2005; $108.8 million in
2004). In 2004, we spun off our Automotive Services business and essentially
completed the exit from our Water Services businesses. The lower cash from
operations was partially offset by the collection 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.
INVESTING ACTIVITIES. Cash used for investing activities was $154.7 million for
2006 (cash from investing activities of $3.9 million for 2005; cash used for
investing activities of $126.5 million for 2004). Gross proceeds from the sale
of available-for-sale securities were $608.8 million in 2006 ($376.0 million in
2005; $1.9 million in 2004) and purchases were $596.4 million ($343.7 million in
2005; $149.5 million in 2004). Cash used for investing activities was higher in
2006 than 2005, primarily due to $51.4 million invested in ATC and a $43.7
million increase in expenditures for property, plant and equipment due to major
environmental construction projects.
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 and $35.5 million received from the sale of Enventis Telecom. These
increases were partially offset by the absence of $66.0 million proceeds
received in 2004 from the sale of our remaining Water Services businesses and
$12.0 million received from Split Rock Energy in 2004 upon termination of the
joint venture.
FINANCING ACTIVITIES. Cash used for financing activities was $32.6 million for
2006 ($13.9 million for 2005; $228.7 million for 2004). Cash used for financing
activities was higher in 2006 than 2005 primarily due to an additional $7.2
million in dividends paid as a result of more shares outstanding, a higher
dividend rate and fewer shares of common stock issued under our long-term
incentive compensation plan. In 2006, we refinanced $77.8 million of long-term
debt at lower rates.
Cash used for financing activities was lower in 2005 than 2004 primarily due to
significant debt repayment ($35.7 million in 2005; $241.1 million in 2004). In
2005, we refinanced $35 million of long-term debt 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 addition, $53 million from a previous credit agreement
was paid off early in 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 2004. Cash used for financing activities was also lower in 2005 than
2004 due to lower dividends paid following the spin-off of Automotive Services.
In 2006, our Town Center development project was financed with tax-exempt bonds
issued by the Town Center District and a revolving development loan. In March
2005, the Town Center District issued $26.4 million of tax-exempt, 6% Capital
Improvement Revenue Bonds, Series 2005, which are payable over 31 years (by May
1, 2036). The bond proceeds (less capitalized interest, a debt service reserve
fund and cost of issuance) were used to pay for the construction of a portion of
the major infrastructure improvements at Town Center. 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 were billed to Town Center landowners beginning in November 2006. To
the extent that we still own land at the time of the assessment, we recognize
the cost of our portion of these assessments, based upon our ownership of
benefited property. At December 31, 2006, we owned approximately 73% of the
assessable land in the Town Center District.
Our Palm Coast Park development project in Florida is being financed with
tax-exempt bonds issued by the Palm Coast Park District. In May 2006, Palm Coast
Park District issued $31.8 million of tax-exempt, 5.7% Special Assessment Bonds,
Series 2006 which are payable over 31 years (by May 1, 2037). The bond proceeds
(less capitalized interest, a debt service reserve fund and cost of issuance)
are being used to fund the construction of the major infrastructure improvements
at Palm Coast Park, and to mitigate traffic and environmental impacts. The bonds
are payable from and secured by the revenue derived from assessments imposed,
levied and collected by the Palm Coast Park District. The assessments represent
an allocation of the costs of the improvements, including bond financing costs,
to the lands within the Palm Coast Park District benefiting from the
improvements. The assessments will be billed to Palm Coast Park landowners
beginning in November 2007. To the extent that we still own land at the time of
the assessment, we will recognize the cost of our portion of these assessments,
based upon our ownership of benefited property. At December 31, 2006, we owned
97% of the assessable land in the Palm Coast Park District.
47 ALLETE 2006 Form 10-K
LIQUIDITY AND CAPITAL RESOURCES (CONTINUED)
WORKING CAPITAL. Additional working capital, if and when needed, generally is
provided by the sale of commercial paper. We have 0.6 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 2012.
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) with a maturity date of January 11, 2011. The
Line was subsequently extended for an additional year in December 2006 and
currently matures on January 11, 2012. 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.
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 March 2006, we issued $50 million in principal amount of First Mortgage
Bonds, 5.69% Series due March 1, 2036, in the private placement market. Proceeds
were used to redeem $50 million in principal amount of First Mortgage Bonds, 7%
Series due March 1, 2008.
In July 2006, the Collier County Industrial Development Authority (Authority or
Issuer) issued $27.8 million of Industrial Development Variable Rate Demand
Refunding Revenue Bonds Series 2006 due 2025 (Refunding Bonds) on behalf of
ALLETE. The interest rate on these bonds was 3.94% at December 31, 2006.
Pursuant to a financing agreement between the Authority and ALLETE dated as of
July 1, 2006, ALLETE is obligated to make payments to the Issuer sufficient to
pay all principal and interest on the Refunding Bonds. ALLETE's obligations
under the financing agreement are supported by a direct pay letter of credit.
Proceeds from the Refunding Bonds and internally generated funds were used to
redeem $29.1 million of outstanding Collier County Industrial Development
Refunding Revenue Bonds 6.5% Series 1996 due 2025 on August 9, 2006. As a result
of an early redemption premium, we recognized a $0.6 million pre-tax charge to
other expense in the third quarter of 2006.
On February 1, 2007, we issued $60 million in principal amount of First Mortgage
Bonds, 5.99% Series due February 1, 2027, in the private placement market.
Proceeds were used to retire $60 million in principal amount of First Mortgage
Bonds, 7% Series on February 15, 2007.
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, 2006, ALLETE was in compliance
with its financial covenants.
OFF-BALANCE SHEET ARRANGEMENTS
Off-balance sheet arrangements are discussed in Note 8.
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, 2006, remains constant through the
remaining term.
ALLETE 2006 Form 10-K 48
LIQUIDITY AND CAPITAL RESOURCES (CONTINUED)
Unconditional purchase obligations represent our Square Butte power purchase
agreements, and minimum purchase commitments under coal and rail contracts.
Under our power purchase agreement with Square Butte that extends through 2026,
we are obligated to pay our pro rata share of Square Butte's costs based on our
entitlement to the output of Square Butte's 455 MW coal-fired generating unit
near Center, North Dakota. Our payment obligation is suspended if Square Butte
fails to deliver any power, whether produced or purchased, for a period of one
year. Square Butte's fixed costs consist primarily of debt service. The
following table reflects our share of future debt service based on our output
entitlement of approximately 60% in 2007, 55% in 2008 and 50% thereafter. (See
Note 8.)
Under an agreement with Wisconsin Public Service Corporation and WPS
Investments, LLC, we have a commitment to invest $60 million in ATC. During
2006, we invested $51.4 million in ATC. We plan to invest an additional $8.6
million in ATC in early 2007 to reach our $60 million investment commitment.
(See Notes 6 and 8.)
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 $ 639.7 $ 46.7 $ 65.1 $31.2 $496.7
Operating Lease Obligations 86.5 8.2 21.1 11.4 45.8
Unconditional Purchase Obligations 321.2 53.7 58.0 26.2 183.3
Investment in ATC 8.6 8.6 - - -
-------------------------------------------------------------------------------------------------------------------------
$1,056.0 $117.2 $144.2 $68.8 $725.8
-------------------------------------------------------------------------------------------------------------------------
Includes interest and assumes variable interest rate in effect at December 31, 2006, remains constant through
remaining term.
We expect to contribute approximately $6 million to our postretirement health
and life plans in 2007. We are not required to make any contributions to our
defined benefit pension plans in 2007. We are unable to predict contribution
levels to our defined benefit pension plans after 2007.
EMERGING TECHNOLOGY PORTFOLIO. We have investments in emerging technologies
through 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 $2.5 million at
December 31, 2006 ($3.1 million at December 31, 2005; $4.5 million at December
31, 2004) and is expected to be invested in 2007. We do not have plans to make
any additional investments beyond this commitment.
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 - Fixed Rate BBB -
------------------------------------------------------------------------------------------------------------------------
PAYOUT RATIO
In 2006, we paid out 53% (259% in 2005; 77% in 2004) of our per share earnings
in dividends. The payout ratio in 2005 was impacted by a $1.84 per diluted share
charge resulting from our assignment of the Kendall County power purchase
agreement to Constellation Energy Commodities in April 2005. (See Note 10.)
On January 26, 2007, our Board of Directors increased the dividend on ALLETE
common stock by 13%, declaring a dividend of $0.41 per share payable March 1,
2007, to shareholders of record at the close of business February 15, 2007.
49 ALLETE 2006 Form 10-K
CAPITAL REQUIREMENTS
CONTINUING OPERATIONS. Capital additions for 2006 totaled $109.4 million ($58.6
million in 2005; $57.8 million in 2004). Expenditures for 2006 included $107.5
million for Regulated Utility and $1.9 million for Nonregulated Energy
Operations. Internally-generated funds were the source of funding for these
expenditures.
Capital additions are expected to be $179 million in 2007 and estimated to total
about $700 million for 2008 through 2011. The 2007 amount includes $88 million
for federal or state required environmental compliance projects at generation
facilities (primarily for our AREA and Boswell Unit 3 emission reduction plans),
$86 million for other regulated system component replacements and upgrades and
$5 million for upgrades within Nonregulated Energy Operations. Over the next
five years, we expect to use internally-generated funds and new issue debt to
fund our projected capital additions. Approximately $145 million of the
estimated capital additions for 2008 through 2011 relate to federal or state
required environmental upgrades at our generation facilities, $450 million is
for other regulated system replacements and upgrades, while $95 million is for
possible generation resource additions linked to potential load growth
identified in our Resource Plan filing.
Real estate development expenditures are and will be funded with a revolving
development loan and tax-exempt bonds issued by community development districts.
The Palm Coast Park District issued $31.8 million of tax-exempt bonds in May
2006. Bond proceeds of $26.3 million will be used for environmental and traffic
mitigation, and the construction of infrastructure improvements at Palm Coast
Park, 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 District will need to issue additional bonds to pay for the development of
retail commercial, office and industrial lots at Palm Coast Park. Company
expenditures related to our real estate developments in Florida increase the
carrying value of our land assets, which are classified as Investments on our
consolidated balance sheet.
DISCONTINUED OPERATIONS. There were no capital additions for discontinued
operations in 2006 ($4.5 million in 2005; $21.4 million in 2004).
ENVIRONMENTAL AND OTHER MATTERS
As previously mentioned in our Critical Accounting Estimates 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 8. (See Item 1 - Environmental Matters.)
MARKET RISK
SECURITIES INVESTMENTS
AVAILABLE-FOR-SALE SECURITIES. At December 31, 2006, 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
bonds and variable rate demand notes included as Short-Term Investments. Our
available-for-sale securities portfolio had a fair value of $130.1 million at
December 31, 2006 ($139.5 million at December 31, 2005) and a total unrealized
after-tax gain of $4.0 million at December 31, 2006 ($2.1 million at December
31, 2005).
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
impairments on our available-for-sale securities in 2006 or 2005.
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
investments 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, 2006, and December 31, 2005. 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, 2006, and at December 31, 2005. In
2005, we recorded $5.1 million ($3.3 million after tax) of impairments related
to our 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 2006 Form 10-K 50
MARKET RISK (CONTINUED)
INTEREST RATE RISK
We are exposed to risks resulting from changes in interest rates as a result of
our issuance of variable rate debt. We manage our interest rate risk by varying
the issuance and maturity dates of our fixed rate debt, limiting the amount of
variable rate debt, and continually monitoring the effects of market changes in
interest rates. The table below presents the long-term debt obligations and the
corresponding weighted average interest rate at December 31, 2006.
PRINCIPAL CASH FLOW BY EXPECTED MATURITY DATE
------------------------------------------------------------------------------------------------------------------------
INTEREST RATE SENSITIVE FAIR
FINANCIAL INSTRUMENTS 2007 2008 2009 2010 2011 THEREAFTER TOTAL VALUE
------------------------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS
Long-Term Debt
Fixed Rate $21.3 $7.0 $2.0 $0.9 $0.9 $275.6 $307.7 $305.8
Average Interest Rate - % 6.7 7.1 5.4 6.5 6.5 5.7 5.8
Variable Rate $8.4 - $8.2 $3.6 - $61.6 $81.8 $81.8
Average Interest Rate - % 5.9 - 3.9 3.6 - 3.9 4.1
------------------------------------------------------------------------------------------------------------------------
Assumes rate in effect at December 31, 2006, remains constant through remaining term.
The interest rate on variable rate long-term debt is reset on a periodic basis
reflecting current market conditions. Based on the variable rate debt
outstanding at December 31, 2006, and assuming no other changes to our financial
structure, an increase or decrease of 100 basis points would impact the amount
of pretax interest expense by $0.8 million. This amount was determined by
considering the impact of a hypothetical 100 basis point change to the average
variable interest rate on the variable rate debt held as of December 31, 2006.
COMMODITY PRICE RISK
Our regulated utility operations in Minnesota and Wisconsin incur costs for fuel
(primarily coal), power and natural gas purchased for resale in our regulated
service territories, and related transportation. Our regulated utilities'
exposure to price risk for these commodities is significantly mitigated by the
current ratemaking process and regulatory environment, which generally allows a
fuel clause surcharge if costs are in excess of those in our last rate filing.
Conversely, costs below those in our last rate filing result in a rate credit.
We seek to prudently manage our customers' exposure to price risk by entering
into contracts of various durations and terms for the purchase of coal and power
(in Minnesota), power and natural gas (in Wisconsin), and related transportation
costs.
POWER MARKETING
Our power marketing activities consist of (1) purchasing energy in the wholesale
market for resale in our regulated service territories when retail energy
requirements exceed generation output, and (2) selling excess available
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.
Approximately 200 MW of generation from our Taconite Harbor facility in northern
Minnesota has been sold through various long-term capacity and energy contracts.
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, with formula pricing based on variable production cost of a
combustion-turbine, natural gas unit.
NEW ACCOUNTING STANDARDS
New accounting standards are discussed in Note 2.
51 ALLETE 2006 Form 10-K
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See Item 7 Management's Discussion and Analysis of Results of Operations and
Financial Condition - Market Risk for information related to quantitative and
qualitative disclosure about market risk.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See our consolidated financial statements as of December 31, 2006 and 2005, and
for each of the three years in the period ended December 31, 2006, 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 (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, 2006.
Our management's assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2006, 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 2006 Form 10-K 52
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Unless otherwise stated, the information required for this Item is incorporated
by reference herein from our Proxy Statement for the 2007 Annual Meeting of
Shareholders (2007 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 2007 Proxy Statement will be filed with the SEC within 120 days after the
end of our 2006 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," the "Compensation Committee Report"
and the "Director Compensation" sections in our 2007 Proxy Statement. The
"Compensation of Executive Officers" section will include our Compensation
Discussion and Analysis.
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
2007 Proxy Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
The information required for this Item is incorporated by reference herein from
the "Corporate Governance" section in our 2007 Proxy Statement.
We have adopted a Related Person Transaction Policy which is available on our
Website at www.allete.com. Print copies are available, free of charge, upon
request. Any amendment to this policy will be disclosed on our Website at
www.allete.com promptly following the date of such amendment.
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 2007 Proxy Statement.
53 ALLETE 2006 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, 2006 and 2005........... 60
For the Three Years Ended December 31, 2006
Consolidated Statement of Income.............................. 61
Consolidated Statement of Cash Flows.......................... 62
Consolidated Statement of Shareholders' Equity................ 63
Notes to Consolidated Financial Statements......................... 64-95
(2) Financial Statement Schedules
Schedule II - ALLETE Valuation and Qualifying Accounts and Reserves... 96
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
Twenty-fifth December 1, 2005 1-3548 (March 31, 2006 Form 10-Q) 4
4(a)3 - Twenty-Sixth Supplemental Indenture, dated as of October 1,
2006, between ALLETE and The Bank of New York and Douglas J.
MacInnes, as Trustees.
ALLETE 2006 Form 10-K 54
EXHIBIT NUMBER
*4(b)1 - Indenture of Trust, dated as of August 1, 2004, between the
City of Cohasset, Minnesota and U.S. Bank National Association,
as Trustee relating to $111 Million Collateralized Pollution
Control Refunding Revenue Bonds (filed as Exhibit 4(b) to the
September 30, 2004, Form 10-Q, File No. 1-3548).
*4(b)2 - Loan Agreement, dated as of August 1, 2004, between the City of
Cohasset, Minnesota and ALLETE relating to $111 Million
Collateralized Pollution Control Refunding Revenue Bonds (filed
as Exhibit 4(c) to the September 30, 2004, Form 10-Q, File No.
1-3548).
*4(c)1 - Mortgage and Deed of Trust, dated as of March 1, 1943, between
Superior Water, Light and Power Company and Chemical Bank &
Trust Company and Howard B. Smith, as Trustees, both succeeded
by U.S. Bank Trust N.A., as Trustee (filed as Exhibit 7(c),
File No. 2-8668).
*4(c)2 - Supplemental Indentures to Superior Water, Light and Power
Company's Mortgage and Deed of Trust:
NUMBER DATED AS OF REFERENCE FILE EXHIBIT
First March 1, 1951 2-59690 2(d)(1)
Second March 1, 1962 2-27794 2(d)1
Third July 1, 1976 2-57478 2(e)1
Fourth March 1, 1985 2-78641 4(b)
Fifth December 1, 1992 1-3548 (1992 Form 10-K) 4(b)1
Sixth March 24, 1994 1-3548 (1996 Form 10-K) 4(b)1
Seventh November 1, 1994 1-3548 (1996 Form 10-K) 4(b)2
Eighth January 1, 1997 1-3548 (1996 Form 10-K) 4(b)3
*4(d) - Amended and Restated Rights Agreement, dated as of July 12,
2006, between ALLETE and the Corporate Secretary of ALLETE, as
Rights Agent (filed as Exhibit 4 to the July 14, 2006, Form
8-K, 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 - 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(d)2 - First Amendment to Fourth Amended and Restated Committed
Facility Letter dated June 19, 2006, by and among ALLETE and
LaSalle Bank National Association, as Agent (filed as Exhibit
10(a) to the June 30, 2006, Form 10-Q, File No. 1-3548).
10(d)3 - Second Amendment to Fourth Amended and Restated Committed
Facility Letter dated December 14, 2006, by and among ALLETE
and LaSalle Bank National Association, as Agent.
*10(e)1 - Financing Agreement between Collier County Industrial
Development Authority and ALLETE dated as of July 1, 2006
(filed as Exhibit 10(b)1 to the June 30, 2006, Form 10-Q, File
No. 1-3548).
*10(e)2 - Letter of Credit Agreement, dated as of July 5, 2006, among
ALLETE, the Participating Banks and Wells Fargo Bank, National
Association, as Administrative Agent and Issuing Bank (filed as
Exhibit 10(b)2 to the June 30, 2006, Form 10-Q, 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).
55 ALLETE 2006 Form 10-K
EXHIBIT NUMBER
+10(h)4 - January 2007 Amendment to the ALLETE Executive Annual Incentive
Plan.
+*10(h)5 - 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).
+*10(h)6 - Form of ALLETE Executive Annual Incentive Plan 2006 Award
(filed as Exhibit 10 to the February 17, 2006, Form 8-K,
File No. 1-3548).
+10(h)7 - Form of ALLETE Executive Annual Incentive Plan Awards Effective
2007.
+*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(i)3 - August 2006 Amendments to the ALLETE and Affiliated Companies
Supplemental Executive Retirement Plan (filed as Exhibit 10(a)
to the September 30, 2006, Form 10-Q, File No. 1-3548).
+10(i)4 - December 2006 Amendments to the ALLETE and Affiliated Companies
Supplemental Executive Retirement Plan.
+*10(j)1 - Minnesota Power and Affiliated Companies 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(j)4 - August 2006 Amendment to the Minnesota Power and Affiliated
Companies Executive Investment Plan I (filed as Exhibit 10(b)
to the September 30, 2006, Form 10-Q, File No. 1-3548).
+*10(k)1 - Minnesota Power and Affiliated Companies 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(k)4 - August 2006 Amendment to the Minnesota Power and Affiliated
Companies Executive Investment Plan II (filed as Exhibit 10(c)
to the September 30, 2006, 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 - 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(m)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(m)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(m)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(m)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(m)6 - Form of ALLETE Executive Long-Term Incentive Compensation Plan
Nonqualified Stock Option Grant Effective 2007.
+10(m)7 - Form of ALLETE Executive Long-Term Incentive Compensation Plan
Performance Share Grant Effective 2007.
+10(m)8 - Form of ALLETE Executive Long-Term Incentive Compensation Plan
Long-Term Cash Incentive Award Effective 2007.
+10(m)9 - Form of ALLETE Executive Long-Term Incentive Compensation Plan
Stock Grant Effective 2007.
+*10(n)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(n)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).
ALLETE 2006 Form 10-K 56
EXHIBIT NUMBER
+*10(n)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(n)4 - January 2007 Amendment to the ALLETE Director Stock Plan.
+*10(n)5 - ALLETE Director Compensation Summary Effective May 1, 2005
(filed as Exhibit 10 to the June 30, 2005, Form 10-Q, File No.
1-3548).
+10(n)6 - ALLETE Non-Management Director Compensation Summary Effective
February 15, 2007.
+*10(o)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(o)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(o)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).
+*10(o)4 - August 2006 Amendment to the ALLETE Director Compensation
Deferral Plan (filed as Exhibit 10(d) to the September 30,
2006, Form 10-Q, File No. 1-3548).
+*10(p) - 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.
99 - ALLETE News Release dated February 16, 2007, announcing 2006
earnings. (THIS EXHIBIT HAS BEEN FURNISHED AND SHALL NOT BE
DEEMED "FILED" FOR PURPOSES OF SECTION 18 OF THE SECURITIES
EXCHANGE ACT OF 1934, NOR SHALL IT BE DEEMED INCORPORATED BY
REFERENCE IN ANY FILING UNDER THE SECURITIES ACT OF 1933,
EXCEPT AS SHALL BE EXPRESSLY SET FORTH BY SPECIFIC REFERENCE IN
SUCH FILING.)
We are a party to another long-term debt instrument, $38,995,000 of 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 that, pursuant to Regulation S-K, Item
601(b)(4)(iii), is not filed as an exhibit since the total amount of debt
authorized under this omitted instrument does not exceed 10% of our total
consolidated assets. We will furnish copies of this instrument 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.
57 ALLETE 2006 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 16, 2007 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 Officer February 16, 2007
---------------------------------------- and Director
Donald J. Shippar
Mark A. Schober Senior Vice President and Chief Financial Officer February 16, 2007
----------------------------------------
Mark A. Schober
Steven Q. DeVinck Controller February 16, 2007
----------------------------------------
Steven Q. DeVinck
Kathleen A. Brekken Director February 16, 2007
----------------------------------------
Kathleen A. Brekken
Heidi J. Eddins Director February 16, 2007
----------------------------------------
Heidi J. Eddins
James J. Hoolihan Director February 16, 2007
----------------------------------------
James J. Hoolihan
Peter J. Johnson Director February 16, 2007
----------------------------------------
Peter J. Johnson
Madeleine W. Ludlow Director February 16, 2007
----------------------------------------
Madeleine W. Ludlow
George L. Mayer Director February 16, 2007
----------------------------------------
George L. Mayer
Roger D. Peirce Director February 16, 2007
----------------------------------------
Roger D. Peirce
Jack I. Rajala Director February 16, 2007
----------------------------------------
Jack I. Rajala
Nick Smith Director February 16, 2007
----------------------------------------
Nick Smith
Bruce W. Stender Director February 16, 2007
----------------------------------------
Bruce W. Stender
ALLETE 2006 Form 10-K 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 consolidated financial
statements and of its internal control over financial reporting as of December
31, 2006, 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 (the Company) at
December 31, 2006 and 2005, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2006 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." As discussed in Note 16 to the consolidated financial
statements, in 2006 the Company adopted SFAS 158, "Employer's Accounting for
Defined Benefit Pension and Other Postretirement Plans." As discussed in Note 17
to the consolidated financial statements, in 2006 the Company changed the manner
in which it accounts for share-based compensation.
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, 2006 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,
2006, 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 12, 2007, except as to Note 7 for which the date is February 15, 2007
59 ALLETE 2006 Form 10-K
CONSOLIDATED FINANCIAL STATEMENTS
ALLETE CONSOLIDATED BALANCE SHEET
DECEMBER 31 2006 2005
-----------------------------------------------------------------------------------------------------------------------------
MILLIONS
ASSETS
Current Assets
Cash and Cash Equivalents $ 44.8 $ 89.6
Short-Term Investments 104.5 116.9
Accounts Receivable (Less Allowance of $1.1 and $1.0) 70.9 79.1
Inventories 43.4 33.1
Prepayments and Other 23.8 23.8
Deferred Income Taxes 0.3 31.0
Discontinued Operations - 0.4
-----------------------------------------------------------------------------------------------------------------------------
Total Current Assets 287.7 373.9
Property, Plant and Equipment - Net 921.6 860.4
Investments 189.1 117.7
Other Assets 135.0 44.6
Discontinued Operations - 2.2
-----------------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $1,533.4 $1,398.8
-----------------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
LIABILITIES
Current Liabilities
Accounts Payable $ 53.5 $ 44.7
Accrued Taxes 23.3 19.1
Accrued Interest 8.6 7.4
Long-Term Debt Due Within One Year 29.7 2.7
Deferred Profit on Sales of Real Estate 4.1 8.6
Other 24.3 24.2
Discontinued Operations - 13.0
-----------------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 143.5 119.7
Long-Term Debt 359.8 387.8
Deferred Income Taxes 130.8 138.4
Other Liabilities 226.1 144.1
Minority Interest 7.4 6.0
-----------------------------------------------------------------------------------------------------------------------------
Total Liabilities 867.6 796.0
-----------------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
-----------------------------------------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Common Stock Without Par Value, 43.3 Shares Authorized
30.4 and 30.1 Shares Outstanding 438.7 421.1
Unearned ESOP Shares (71.9) (77.6)
Accumulated Other Comprehensive Loss (8.8) (12.8)
Retained Earnings 307.8 272.1
-----------------------------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 665.8 602.8
-----------------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $1,533.4 $1,398.8
-----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
ALLETE 2006 Form 10-K 60
ALLETE CONSOLIDATED STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31 2006 2005 2004
-----------------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT PER SHARE AMOUNTS
OPERATING REVENUE $767.1 $737.4 $704.1
-----------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Fuel and Purchased Power 281.7 273.1 286.2
Operating and Maintenance 296.0 293.5 270.1
Kendall County Charge - 77.9 -
Depreciation 48.7 47.8 46.9
-----------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 626.4 692.3 603.2
-----------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME FROM CONTINUING OPERATIONS 140.7 45.1 100.9
-----------------------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE)
Interest Expense (27.4) (26.4) (31.7)
Other 14.9 1.1 (12.2)
-----------------------------------------------------------------------------------------------------------------------------
Total Other Expense (12.5) (25.3) (43.9)
-----------------------------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS
BEFORE MINORITY INTEREST AND INCOME TAXES 128.2 19.8 57.0
MINORITY INTEREST 4.6 2.7 2.1
-----------------------------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES 123.6 17.1 54.9
INCOME TAX EXPENSE (BENEFIT) 46.3 (0.5) 16.4
-----------------------------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS
BEFORE CHANGE IN ACCOUNTING PRINCIPLE 77.3 17.6 38.5
INCOME (LOSS) FROM DISCONTINUED OPERATIONS - NET OF TAX (0.9) (4.3) 73.7
CHANGE IN ACCOUNTING PRINCIPLE - NET OF TAX - - (7.8)
-----------------------------------------------------------------------------------------------------------------------------
NET INCOME $ 76.4 $ 13.3 $104.4
-----------------------------------------------------------------------------------------------------------------------------
AVERAGE SHARES OF COMMON STOCK
Basic 27.8 27.3 28.3
Diluted 27.9 27.4 28.4
-----------------------------------------------------------------------------------------------------------------------------
BASIC EARNINGS (LOSS) PER SHARE OF COMMON STOCK
Continuing Operations $2.78 $0.65 $1.37
Discontinued Operations (0.03) (0.16) 2.60
Change in Accounting Principle - - (0.28)
-----------------------------------------------------------------------------------------------------------------------------
$2.75 $0.49 $3.69
-----------------------------------------------------------------------------------------------------------------------------
DILUTED EARNINGS (LOSS) PER SHARE OF COMMON STOCK
Continuing Operations $2.77 $0.64 $1.35
Discontinued Operations (0.03) (0.16) 2.59
Change in Accounting Principle - - (0.27)
-----------------------------------------------------------------------------------------------------------------------------
$2.74 $0.48 $3.67
-----------------------------------------------------------------------------------------------------------------------------
DIVIDENDS PER SHARE OF COMMON STOCK $1.4500 $1.2450 $2.8425
-----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
61 ALLETE 2006 Form 10-K
ALLETE CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31 2006 2005 2004
-----------------------------------------------------------------------------------------------------------------------------
MILLIONS
OPERATING ACTIVITIES
Net Income $ 76.4 $ 13.3 $104.4
(Income) Loss from Discontinued Operations 0.9 4.3 (73.7)
Income from Equity Investments (1.8) - -
Change in Accounting Principle - - 7.8
Loss on Impairment of Investments - 5.1 6.5
Depreciation 48.7 47.8 46.9
Deferred Income Taxes 27.8 (34.2) (1.1)
Minority Interest 4.6 2.7 2.1
Stock Compensation Expense 1.8 1.5 1.0
Bad Debt Expense 0.7 1.1 0.9
Changes in Operating Assets and Liabilities
Accounts Receivable 7.5 (1.4) (22.9)
Inventories (10.3) (1.3) (0.3)
Prepayments and Other (2.3) (2.5) (3.6)
Accounts Payable 5.1 4.9 0.2
Other Current Liabilities 0.2 5.8 (4.8)
Other Assets (4.3) 8.2 6.2
Other Liabilities 1.0 (4.1) (3.4)
Net Operating Activities from Discontinued Operations (13.5) 2.3 108.8
-----------------------------------------------------------------------------------------------------------------------------
Cash from Operating Activities 142.5 53.5 175.0
-----------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Proceeds from Sale of Available-For-Sale Securities 608.8 376.0 1.9
Payments for Purchase of Available-For-Sale Securities (596.4) (343.7) (149.5)
Changes to Investments (52.0) (1.1) 12.4
Expenditures for Property, Plant and Equipment (102.3) (58.6) (57.8)
Other (15.0) 0.6 2.0
Net Investing Activities from Discontinued Operations 2.2 30.7 64.5
-----------------------------------------------------------------------------------------------------------------------------
Cash from (for) Investing Activities (154.7) 3.9 (126.5)
-----------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Issuance of Common Stock 15.8 21.0 49.0
Issuance of Long-Term Debt 77.8 35.0 120.8
Reacquired Common Stock - - (5.8)
Changes in Notes Payable - Net - - (53.0)
Reductions of Long-Term Debt (78.9) (35.7) (241.1)
Dividends on Common Stock and Distributions to Minority Shareholders (43.9) (36.7) (79.7)
Net Increase (Decrease) in Book Overdrafts (3.4) 3.4 -
Net Financing Activities for Discontinued Operations - (0.9) (18.9)
-----------------------------------------------------------------------------------------------------------------------------
Cash for Financing Activities (32.6) (13.9) (228.7)
-----------------------------------------------------------------------------------------------------------------------------
CHANGE IN CASH AND CASH EQUIVALENTS (44.8) 43.5 (180.2)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 89.6 46.1 226.3
-----------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 44.8 $ 89.6 $ 46.1
-----------------------------------------------------------------------------------------------------------------------------
Included $2.4 million of cash from Discontinued Operations at December 31, 2004.
The accompanying notes are an integral part of these statements.
ALLETE 2006 Form 10-K 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, 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
Comprehensive Income
Net Income 76.4 76.4
Other Comprehensive Income - Net of Tax
Unrealized Gains on Securities - Net 1.9 1.9
Additional Pension Liability 6.4 6.4
--------
Total Comprehensive Income 84.7
Adjustment to initially apply SFAS 158 -
Net of Tax (4.3) (4.3)
Common Stock Issued - Net 17.6 17.6
Dividends Declared (40.7) (40.7)
ESOP Shares Earned 5.7 5.7
-----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2006 $ 665.8 $307.8 $(8.8) $(71.9) $438.7
-----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
63 ALLETE 2006 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.
Financial results by segment for the periods presented were impacted by the
integration of our Taconite Harbor facility into the Regulated Utility segment,
effective January 1, 2006. The redirection of Taconite Harbor from our
Nonregulated Energy Operations segment to our Regulated Utility segment was in
accordance with the Company's Resource Plan, as approved by the MPUC. Under the
terms of our Resource Plan, we have operated the Taconite Harbor facility as a
rate-based asset within the Minnesota retail jurisdiction since January 1, 2006.
Prior to January 1, 2006, we operated our Taconite Harbor facility as
nonregulated generation (non-rate base generation sold at market-based rates
primarily to the wholesale market). Historical financial results of Taconite
Harbor for periods prior to the 2006 redirection are included in our
Nonregulated Energy Operations segment.
Effective the third quarter of 2006, financial results for our equity investment
in ATC have been reported as a separate segment. 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 in accordance with the FERC's
policy of establishing the independent operation and ownership of, and
investment in, transmission facilities. (See Note 6.)
ENERGY
-------------------------------------
NONREGULATED
REGULATED ENERGY INVESTMENT REAL
CONSOLIDATED UTILITY OPERATIONS IN ATC ESTATE OTHER
-----------------------------------------------------------------------------------------------------------------------
MILLIONS
2006
Operating Revenue $767.1 $639.2 $65.0 - $62.6 $0.3
Fuel and Purchased Power 281.7 281.7 - - - -
Operating and Maintenance 296.0 217.9 57.1 - 18.2 2.8
Depreciation Expense 48.7 44.2 4.3 - 0.1 0.1
-----------------------------------------------------------------------------------------------------------------------
Operating Income (Loss) from
Continuing Operations 140.7 95.4 3.6 - 44.3 (2.6)
Interest Expense (27.4) (20.2) (3.3) - - (3.9)
Other Income 14.9 0.9 2.2 $3.0 - 8.8
-----------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations
Before Minority Interest
and Income Taxes 128.2 76.1 2.5 3.0 44.3 2.3
Minority Interest 4.6 - - - 4.6 -
-----------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations
Before Income Taxes 123.6 76.1 2.5 3.0 39.7 2.3
Income Tax Expense (Benefit) 46.3 29.3 (1.2) 1.1 16.9 0.2
-----------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations 77.3 $ 46.8 $ 3.7 $1.9 $22.8 $2.1
----------------------------------------------------------------
Loss from Discontinued Operations -
Net of Tax (0.9)
----------------------------------------------------
Net Income $ 76.4
----------------------------------------------------
Total Assets $1,533.4 $1,143.3 $81.3 $53.7 $89.8 $165.3
Capital Additions $109.4 $107.5 $1.9 - - -
-----------------------------------------------------------------------------------------------------------------------
ALLETE 2006 Form 10-K 64
NOTE 1. BUSINESS SEGMENTS (CONTINUED)
ENERGY
-------------------------------------
NONREGULATED
REGULATED ENERGY INVESTMENT REAL
CONSOLIDATED UTILITY OPERATIONS IN ATC 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 $909.5 $185.2 - $73.7 $227.8
Capital Additions $63.1 $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 $902.8 $161.4 - $75.1 $242.6
Capital Additions $79.2 $41.7 $15.7 - - $0.4
-----------------------------------------------------------------------------------------------------------------------
Discontinued Operations represented $2.6 million of total assets in 2005($49.5 million in 2004) and $4.5 million
of capital additions in 2005 ($21.4 million in 2004).
65 ALLETE 2006 Form 10-K
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.
BUSINESS SEGMENTS. Our Regulated Utility, Nonregulated Energy Operations, Real
Estate, Investment in ATC and Other segments were determined in accordance with
SFAS 131, "Disclosures about Segments of an Enterprise and Related Information."
Segmentation is based on the manner in which we operate, assess, and allocate
resources to 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.
REGULATED UTILITY includes retail and wholesale rate-regulated electric, natural
gas and water 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 154,000 retail
customers in northeastern Minnesota and northwestern Wisconsin. Approximately
39% of regulated utility electric revenue is from Large Power Customers (33% 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 2008
through October 2013. Revenue of $89.0 million (11.6% of consolidated revenue)
was received from one taconite producer in 2006 (11.3% in 2005; 12.6% in 2004).
Regulated utility rates are under the jurisdiction of Minnesota and Wisconsin,
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: (1) bill or credit customers for
fuel and purchased energy costs above or below the base levels in rate
schedules; (2) bill retail customers for the recovery of conservation
improvement program expenditures not collected in base rates; and (3) bill
customers for the recovery of certain environmental expenditures. Fuel and
purchased power expense is deferred to match the period in which the revenue for
fuel and purchased power expense is collected from customers pursuant to the
fuel adjustment clause.
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. In
2004, prior to our withdrawal, we made power purchases from Split Rock Energy of
$6.2 million and power sales to Split Rock Energy of $1.9 million.
NONREGULATED ENERGY OPERATIONS includes our coal mining activities in North
Dakota, approximately 50 MW of nonregulated generation and Minnesota land sales.
BNI Coal, a wholly-owned subsidiary, mines and sells lignite coal to two North
Dakota mine-mouth generating units, one of which is Square Butte. Square Butte
supplies approximately 60% (323 MW) of its output to Minnesota Power under a
long-term contract. (See Note 8.) Coal sales are recognized when delivered at
the cost of production plus a specified profit per ton of coal delivered.
In 2004 and 2005, Nonregulated Energy Operations included nonregulated
generation (non-rate base generation sold at market-based rates to the wholesale
market) from our Taconite Harbor facility in northern Minnesota and generation
secured through the Kendall County power purchase agreement. To help meet
forecasted base load energy requirements effective January 1, 2006, Taconite
Harbor was integrated into our Regulated Utility business in accordance with the
terms of our Resource Plan, as approved by the MPUC. The Kendall County power
purchase agreement was assigned to Constellation Energy Commodities in April
2005. (See Note 10.)
INVESTMENT IN ATC includes our approximate 7% equity ownership interest in ATC,
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 in
accordance with the FERC's policy of establishing the independent operation and
ownership of, and investment in, transmission facilities. (See Note 6 and 8.)
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
ALLETE 2006 Form 10-K 66
NOTE 2. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
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. In addition to minimum base price contracts,
certain contracts allow us to receive participation revenue from land sales to
third parties if various formula-based criteria are achieved.
In certain cases, we pay fees or construct improvements to mitigate offsite
traffic impacts. In return, we receive traffic impact fee credits. We recognize
revenue from the sale of traffic impact fee credits when payment is 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 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 investments in
privately-held companies under the cost method because of our ownership
percentage. Short-term investments consist of auction rate bonds and variable
rate demand notes, and are classified as available-for-sale securities. All
income generated from these short-term investments is recorded as interest
income.
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.
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 future 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 overall portfolio quality,
review of specific problems and such other factors that, in our judgment,
deserve recognition in estimating losses.
ACCOUNTS RECEIVABLE
DECEMBER 31 2006 2005
--------------------------------------------------------------------------------------------------------------------------
MILLIONS
Trade Accounts Receivable
Billed $58.5 $65.5
Unbilled 13.5 14.6
Less: Allowance for Doubtful Accounts 1.1 1.0
--------------------------------------------------------------------------------------------------------------------------
Total Accounts Receivable - Net $70.9 $79.1
--------------------------------------------------------------------------------------------------------------------------
67 ALLETE 2006 Form 10-K
NOTE 2. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
INVENTORIES. Inventories are stated at the lower of cost or market.
INVENTORIES
DECEMBER 31 2006 2005
--------------------------------------------------------------------------------------------------------------------------
MILLIONS
Fuel $18.9 $11.0
Materials and Supplies 24.5 22.1
--------------------------------------------------------------------------------------------------------------------------
Total Inventories $43.4 $33.1
--------------------------------------------------------------------------------------------------------------------------
UNAMORTIZED 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.
SUPPLEMENTAL STATEMENT OF CASH FLOW INFORMATION. Amounts presented for 2005 and
2004 have been revised to eliminate intercompany interest payments from cash
paid during the period for Interest - Net of Amounts Capitalized.
CONSOLIDATED STATEMENT OF CASH FLOWS
SUPPLEMENTAL DISCLOSURE
FOR THE YEAR ENDED DECEMBER 31 2006 2005 2004
--------------------------------------------------------------------------------------------------------------------------
MILLIONS
Cash Paid During the Period for
Interest - Net of Amounts Capitalized $25.3 $24.6 $41.2
Income Taxes $34.5 $27.1 $75.7
Noncash Investing Activities
Accounts Payable for Capital Additions to
Property Plant and Equipment $7.1 - -
--------------------------------------------------------------------------------------------------------------------------
Net of a $24.3 million cash refund.
AVAILABLE-FOR-SALE SECURITIES. 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 auction rate securities and variable
rate demand notes classified as available-for-sale securities, however, are
recorded at cost. Their cost approximates fair market value as they 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. 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.
ACCOUNTING FOR STOCK-BASED COMPENSATION. Effective January 1, 2006, we adopted
the fair value recognition provisions of SFAS 123R, "Share-Based Payment," using
the modified prospective transition method. Under this method, we recognize
compensation expense for all share-based payments granted after January 1, 2006,
and those granted prior to but not yet vested as of January 1, 2006. Under the
fair value recognition provisions of SFAS 123R, we recognize stock-based
compensation net of an estimated forfeiture rate and only recognize compensation
expense for those shares expected to vest over the required service period of
the award. Prior to our adoption of SFAS 123R, we accounted for share-based
payments under Accounting Principles Board Opinion No. 25, "Accounting for Stock
Issued to Employees" and related interpretations. (See Note 17.)
FOREIGN CURRENCY TRANSLATION. Results of operations for our Canadian and Mexican
automotive subsidiaries prior to the spin-off of ADESA 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.
ALLETE 2006 Form 10-K 68
NOTE 2. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
PREPAYMENTS AND OTHER CURRENT ASSETS
DECEMBER 31 2006 2005
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Deferred Fuel Adjustment Clause $15.1 $13.5
Other 8.7 10.3
---------------------------------------------------------------------------------------------------------------------------
Total Prepayments and Other Current Assets $23.8 $23.8
---------------------------------------------------------------------------------------------------------------------------
OTHER ASSETS
DECEMBER 31 2006 2005
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Plans $ 86.1 -
Other 48.9 $44.6
---------------------------------------------------------------------------------------------------------------------------
Total Other Assets $135.0 $44.6
---------------------------------------------------------------------------------------------------------------------------
OTHER LIABILITIES
DECEMBER 31 2006 2005
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Deferred Regulatory Credits (See Note 5) $ 33.8 $ 31.8
Deferred Compensation 34.2 34.8
Future Benefit Obligation Under
Defined Benefit Pension and Other Postretirement Plans 107.6 27.2
Asset Retirement Obligations (See Note 3) 27.2 25.3
Other 23.3 25.0
---------------------------------------------------------------------------------------------------------------------------
Total Other Liabilities $226.1 $144.1
---------------------------------------------------------------------------------------------------------------------------
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.
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. INTERPRETATION NO. 48. In June 2006, the FASB issued
Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an
Interpretation of FASB Statement No. 109" (Interpretation No. 48).
Interpretation No. 48 clarifies the accounting for uncertain tax positions in
accordance with SFAS 109, "Accounting for Income Taxes." Pursuant to
Interpretation No. 48, we will be required to recognize in our financial
statements the largest tax benefit of a tax position that is
"more-likely-than-not" to be sustained, on audit, based solely on the technical
merits of the position as of the reporting date. Only tax positions that meet
the "more-likely-than-not" threshold at that date may be recognized. The term
"more-likely-than-not" means a likelihood of more than 50%. Interpretation No.
48 also provides guidance on new disclosure requirements, reporting and accrual
of interest and penalties, accounting in interim periods and transition. The
cumulative effect of initially applying Interpretation No. 48 will be recognized
as a change in accounting principle as of the date of adoption. We are currently
evaluating the impact of applying this interpretation as of January 1, 2007, the
effective date of the interpretation. We do not expect Interpretation No. 48 to
have a material impact on our financial position, results of operations or cash
flows.
69 ALLETE 2006 Form 10-K
NOTE 2. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
SFAS 157. In September 2006, the FASB issued SFAS 157, "Fair Value Measurements"
(SFAS 157), to increase consistency and comparability in fair value measurements
by defining fair value, establishing a framework for measuring fair value in
generally accepted accounting principles, and expanding disclosures about fair
value measurements. SFAS 157 emphasizes that fair value is a market-based
measurement, not an entity-specific measurement. It clarifies the extent to
which fair value is used to measure recognized assets and liabilities, the
inputs used to develop the measurements, and the effect of certain measurements
on earnings for the period. SFAS 157 is effective for financial statements
issued for fiscal years beginning after November 15, 2007, and will be applied
on a prospective basis. We are currently evaluating the impact that the adoption
of SFAS 157 will have on our financial position, results of operations and cash
flows.
NOTE 3. PROPERTY, PLANT AND EQUIPMENT
PROPERTY, PLANT AND EQUIPMENT
DECEMBER 31 2006 2005
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Regulated Utility $1,575.8 $1,457.4
Construction Work in Progress 71.4 21.2
Accumulated Depreciation (781.3) (743.5)
---------------------------------------------------------------------------------------------------------------------------
Regulated Utility Plant - Net 865.9 735.1
---------------------------------------------------------------------------------------------------------------------------
Nonregulated Energy Operations 88.5 160.6
Construction Work in Progress 2.6 3.7
Accumulated Depreciation (40.1) (43.9)
---------------------------------------------------------------------------------------------------------------------------
Nonregulated Energy Operations Plant - Net 51.0 120.4
---------------------------------------------------------------------------------------------------------------------------
Other Plant - Net 4.7 4.9
---------------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment - Net $ 921.6 $ 860.4
---------------------------------------------------------------------------------------------------------------------------
Effective January 1, 2006, our Taconite Harbor generating facility was redirected from Nonregulated Energy Operations
to Regulated Utility.
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 3 to 30 years Nonregulated Energy Operations 5 to 35 years
Transmission 40 to 60 years Other Plant 5 to 30 years
Distribution 30 to 70 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 retirement
settlement dates.
ASSET RETIREMENT OBLIGATION
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
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
Accretion Expense 1.8
Additional Liabilities Incurred in 2006 0.1
---------------------------------------------------------------------------------------------------------------------------
Obligation at December 31, 2006 $27.2
---------------------------------------------------------------------------------------------------------------------------
ALLETE 2006 Form 10-K 70
NOTE 4. 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, 2006, was $314
million ($310 million at December 31, 2005). The corresponding accumulated
depreciation balance was $168 million at December 31, 2006 ($162 million at
December 31, 2005).
NOTE 5. 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 2006 PSCW retail rate order, effective January 1, 2007. In 2006, 72%
of our consolidated operating revenue was under regulatory authority (72% in
2005; 75% in 2004). The MPUC had regulatory authority over approximately 56% of
our consolidated operating revenue in 2006 (56% in 2005; 60% in 2004).
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 2006 2005
------------------------------------------------------------------------------------------------------------------------
MILLIONS
Deferred Charges
Income Taxes $11.6 $ 12.0
Premium on Reacquired Debt 2.8 3.5
Future Benefit Obligations Under
Defined Benefit Pension and Other Postretirement Plans (See Note 16) 86.1 -
Other 3.1 1.7
------------------------------------------------------------------------------------------------------------------------
103.6 17.2
Deferred Credits - Income Taxes 33.8 31.8
------------------------------------------------------------------------------------------------------------------------
Net Deferred Regulatory Assets (Liabilities) $69.8 $(14.6)
------------------------------------------------------------------------------------------------------------------------
NOTE 6. INVESTMENTS
AVAILABLE-FOR-SALE INVESTMENTS. We account for our available-for-sale portfolio
in accordance with SFAS 115, "Accounting for Certain Investments in Debt and
Equity Securities." 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 (see below).
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. Their cost approximates fair market value as they
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 2006, 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 17) as a result of the September 2004
spin-off of ADESA. In total, the ESOP received total proceeds of $65.9 million,
resulting in a gain of $11.5 million, which we recognized during the fourth
quarter of 2004. We accounted for the ADESA stock as available-for-sale.
71 ALLETE 2006 Form 10-K
NOTE 6. INVESTMENTS (CONTINUED)
AVAILABLE-FOR-SALE SECURITIES
-------------------------------------------------------------------------------------------------------------------------
MILLIONS
GROSS UNREALIZED
AT DECEMBER 31 COST GAIN (LOSS) FAIR VALUE
-------------------------------------------------------------------------------------------------------------------------
2006 $123.2 $7.0 $(0.1) $130.1
2005 $135.2 $4.4 $(0.1) $139.5
2004 $176.4 $3.1 $(0.1) $179.4
-------------------------------------------------------------------------------------------------------------------------
NET
UNREALIZED
GAIN (LOSS)
IN OTHER
YEAR ENDED SALES GROSS REALIZED COMPREHENSIVE
DECEMBER 31 PROCEEDS GAIN (LOSS) INCOME
-------------------------------------------------------------------------------------------------------------------------
2006 $12.4 - - $2.7
2005 $32.3 - - $1.3
2004 $65.9 $11.5 - $1.6
-------------------------------------------------------------------------------------------------------------------------
SHORT-TERM INVESTMENTS. At December 31, 2006, we held $104.5 million of
short-term investments ($116.9 million at December 31, 2005) consisting of
various auction rate municipal bonds and variable rate municipal demand notes.
INVESTMENTS. At December 31, 2006, our long-term investment portfolio included
the real estate assets of ALLETE Properties, our investment in ATC, debt and
equity securities consisting primarily of securities held to fund employee
benefits, and our emerging technology portfolio.
INVESTMENTS
DECEMBER 31 2006 2005
-------------------------------------------------------------------------------------------------------------------------
MILLIONS
Real Estate Assets $ 89.8 $ 73.7
Debt and Equity Securities 36.4 34.8
Investment in ATC 53.7 -
Emerging Technology Portfolio 9.2 9.2
-------------------------------------------------------------------------------------------------------------------------
Total Investments $189.1 $ 117.7
-------------------------------------------------------------------------------------------------------------------------
REAL ESTATE ASSETS 2006 2005
-------------------------------------------------------------------------------------------------------------------------
MILLIONS
Land Held for Sale Beginning Balance $48.0 $47.2
Additions during period: Capitalized Improvements 18.8 9.4
Purchases 1.4 -
Deductions during period: Cost of Real Estate Sold (10.2) (8.6)
-------------------------------------------------------------------------------------------------------------------------
Land Held for Sale Ending Balance 58.0 48.0
Long-Term Finance Receivables 18.3 7.4
Other 13.5 18.3
-------------------------------------------------------------------------------------------------------------------------
Total Real Estate Assets $89.8 $73.7
-------------------------------------------------------------------------------------------------------------------------
Consisted primarily of a shopping center.
Finance receivables, which are collateralized by land, have maturities ranging
up to ten years, accrue interest at market-based rates and are net of an
allowance for doubtful accounts of $0.2 million at December 31, 2006 ($0.6
million at December 31, 2005). Minority interest associated with real estate
operations was $7.4 million at December 31, 2006 ($6.0 million at December 31,
2005).
INVESTMENT IN ATC. We have an equity ownership interest in ATC, 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 in
accordance with the FERC's policy of establishing the independent operation and
ownership of, and investment in, transmission facilities. We account for our
investment in ATC under the equity method of accounting, pursuant to EITF 03-16,
"Accounting for Investments in Limited Liability Companies."
ALLETE 2006 Form 10-K 72
NOTE 6. INVESTMENTS (CONTINUED)
ALLETE'S INTEREST IN ATC
FOR THE YEAR ENDED DECEMBER 31, 2006
-----------------------------------------------------------------------------------------------------
MILLIONS
Equity in Earnings $3.0
Accumulated Equity in Undistributed Earnings $2.3
Equity Investment Balance $53.7
Equity Ownership 7%
-----------------------------------------------------------------------------------------------------
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
investments 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, 2006, and December 31, 2005. 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 both December 31, 2006, and December 31, 2005.
We did not record any impairments in 2006. In 2005, we recorded $5.1 million
($3.3 million after tax) of impairments related to our 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.
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
2006 $389.5 $387.6
2005 $390.5 $392.5
-----------------------------------------------------------------------------------------------------
CONCENTRATION OF CREDIT RISK. Financial instruments that subject us to
concentrations of credit risk consist primarily of accounts receivable.
Minnesota Power sells electricity to 12 Large Power Customers. Receivables from
these customers totaled approximately $9 million at December 31, 2006 ($10
million at December 31, 2005). 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.
NOTE 7. SHORT-TERM AND LONG-TERM DEBT
SHORT-TERM DEBT. Total short-term debt outstanding at December 31, 2006, was
$29.7 million ($2.7 million at December 31, 2005) and consisted of Long-Term
Debt Due Within One Year.
As of December 31, 2006, we had bank lines of credit aggregating $170.0 million
($120.0 million at December 31, 2005), the majority of which expire in January
2012. These bank lines of credit made financing available through short-term
bank loans and provided credit support for commercial paper. At December 31,
2006, $2.9 million ($1.1 million at December 31, 2005) was drawn on our lines of
credit leaving a $167.1 million balance available for use ($118.9 million at
December 31, 2005). The drawn amounts at December 31, 2006 and 2005, related 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. There was no commercial paper issued as of
December 31, 2006, or December 31, 2005.
In January 2006, we renewed, increased and extended a committed, syndicated,
unsecured revolving credit facility (Line) with LaSalle Bank National
Association, as Agent, for $150 million ($100 million at December 31, 2005). The
Line was subsequently extended for an additional year in December 2006 and
currently matures in January 2012. 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
and 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 without premium or penalty. Additionally, we may irrevocably
terminate or reduce the size of the Line prior to maturity without premium or
penalty. No funds were drawn under this Line at December 31, 2006.
73 ALLETE 2006 Form 10-K
NOTE 7. SHORT-TERM AND LONG-TERM DEBT (CONTINUED)
LONG-TERM DEBT. The aggregate amount of long-term debt maturing during 2007 is
$29.7 million ($7.0 million in 2008; $10.2 million in 2009; $4.5 million in
2010; $0.9 million in 2011; and $337.2 million thereafter). Substantially all of
our electric plant is subject to the lien of the mortgages collateralizing
various first mortgage bonds.
In March 2006, we issued $50 million in principal amount of First Mortgage
Bonds, 5.69% Series due March 1, 2036, in the private placement market. Proceeds
were used to redeem $50 million in principal amount of First Mortgage Bonds, 7%
Series due March 1, 2008.
In July 2006, the Collier County Industrial Development Authority (Authority or
Issuer) issued $27.8 million of Industrial Development Variable Rate Demand
Refunding Revenue Bonds Series 2006 due 2025 (Refunding Bonds) on behalf of
ALLETE. The interest rate on these bonds was 3.94% at December 31, 2006.
Pursuant to a financing agreement between the Authority and ALLETE dated as of
July 1, 2006, ALLETE is obligated to make payments to the Issuer sufficient to
pay all principal and interest on the Refunding Bonds. ALLETE's obligations
under the financing agreement are supported by a direct pay letter of credit.
Proceeds from the Refunding Bonds and internally generated funds were used to
redeem $29.1 million of outstanding Collier County Industrial Development
Refunding Revenue Bonds 6.5% Series 1996 due 2025 on August 9, 2006. As a result
of an early redemption premium, we recognized a $0.6 million pre-tax charge to
other expense in the third quarter of 2006.
On February 1, 2007, we issued $60 million in principal amount of First Mortgage
Bonds, 5.99% Series due February 1, 2027, in the private placement market.
Proceeds were used to retire $60 million in principal amount of First Mortgage
Bonds, 7% Series on February 15, 2007.
LONG-TERM DEBT
DECEMBER 31 2006 2005
-----------------------------------------------------------------------------------------------------------------------
MILLIONS
First Mortgage Bonds
6.68% Series Due 2007 $ 20.0 $ 20.0
7% Series Due 2007 60.0 60.0
7% Series Due 2008 - 50.0
5.28% Series Due 2020 35.0 35.0
4.95% Pollution Control Series F Due 2022 111.0 111.0
5.69% Series Due 2036 50.0 -
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 6.0 35.1
Industrial Development Variable Rate Demand Refunding
Revenue Bonds Series 2006 Due 2025 27.8 -
Other Long-Term Debt, 2.0% - 8.5% Due 2007 - 2025 40.7 40.4
-----------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt 389.5 390.5
Less Due Within One Year 29.7 2.7
-----------------------------------------------------------------------------------------------------------------------
Net Long-Term Debt $359.8 $387.8
-----------------------------------------------------------------------------------------------------------------------
Retired on February 15, 2007.
The 6.68% Series Due 2007 cannot be redeemed prior to November 15, 2007. 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 2006 Form 10-K 74
NOTE 8. 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 prior to 2006. Beginning in 2006, Minnkota Power exercised its option
to reduce Minnesota Power's entitlement by approximately 5% annually, to 66%. We
received notices from Minnkota Power that they further reduced our output
entitlement by approximately 5% annually to 60% on January 1, 2007, 55% on
January 1, 2008, and 50% on January 1, 2009, and thereafter. Minnkota Power has
no further option to reduce Minnesota Power's entitlement below 50%.
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, 2006, Square Butte had total
debt outstanding of $303.7 million. Total annual debt service for Square Butte
is expected to be approximately $26 million in each of the years 2007 through
2011. 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 2006 was
$57.9 million ($56.4 million in 2005; $56.1 million in 2004). This reflects
Minnesota Power's pro rata share of total Square Butte costs, based on the 66%
output entitlement in 2006 and the 71% output entitlement in 2005 and 2004.
Included in this amount was Minnesota Power's pro rata share of interest expense
of $12.6 million in 2006 ($13.6 million in 2005; $12.6 million in 2004).
Minnesota Power's payments to Square Butte are approved as a purchased power
expense for ratemaking purposes by both the MPUC and the FERC.
LEASING AGREEMENTS. BNI Coal is obligated to make lease payments for a dragline
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 $8.2
million in 2007, $7.6 million in 2008, $7.0 million in 2009, $6.5 million in
2010, $6.0 million in 2011 and $51.2 million thereafter. Total rent expense was
$6.8 million in 2006 ($6.2 million in 2005; $3.8 million in 2004).
COAL, RAIL AND SHIPPING CONTRACTS. We have three coal supply agreements with
various expiration dates ranging from December 2008 to December 2009. We also
have rail and shipping agreements for the transportation of all of our coal,
with various expiration dates ranging from December 2007 to December 2011. Our
minimum annual payment obligations under these coal, rail and shipping
agreements are currently $37.8 million in 2007, $11.2 million in 2008, $5.8
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 the MISO Day 2 energy market, the market through which
Minnesota Power engages in wholesale energy transactions in MISO's day-ahead and
real-time markets (MISO Day 2). In April 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.
In December 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.
This denial created a refund obligation. Minnesota Power requested rehearing of
the order in a filing made with the MPUC in January 2006. The other three
utilities affected by the order also filed for rehearing, as did the DOC and
MISO. In February 2006, the MPUC granted rehearing of the MISO Day 2 docket and
suspended the refund obligation for charges recovered through the fuel clause
denied in the December 2005 order. The MPUC also ordered review of 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 worked with other Minnesota utilities,
the DOC and other stakeholders to review MISO Day 2 costs and to prepare a joint
report and recommendations. The joint report and recommendations were filed with
the MPUC in June 2006. A technical conference on the report was held with the
MPUC on October 31, 2006. At a hearing November 9, 2006, the MPUC approved
current recovery of nearly all MISO Day 2 charges.
75 ALLETE 2006 Form 10-K
NOTE 8. COMMITMENTS, GUARANTEES AND CONTINGENCIES (CONTINUED)
On December 20, 2006, the MPUC issued an order allowing Minnesota Power and the
other utilities involved in the MISO Day 2 proceeding to continue recovering
MISO Day 2 charges through the Minnesota retail fuel clause except for MISO Day
2 administrative charges. On January 8, 2007, this order was challenged by the
Minnesota OAG, which has sought reconsideration. The rehearing has been opposed
by Minnesota Power and the other utilities, as well as MISO. The reconsideration
request is currently pending before the MPUC. The MPUC has until March 9, 2007,
to act on the Minnesota OAG's request. The order, if upheld, grants deferred
accounting treatment for three MISO Day 2 charge types that were determined to
be administrative charges. Under the order, Minnesota Power would refund through
customer bills approximately $2 million of administrative charges previously
collected through the fuel clause between April 1, 2005, and December 31, 2006,
and record these administrative charges as a regulatory asset. Minnesota Power
would be permitted to continue accumulating MISO Day 2 administrative charges
after December 31, 2006, as a regulatory asset until it files its next rate
case, at which time recovery for such charges will be determined. This order
would remove the subject to refund requirement of the two interim orders, and
include extensive fuel clause reporting requirements that would be reviewed in
Minnesota Power's monthly and annual fuel clause filings with the MPUC. There
would be no impact on earnings as a result of this ruling. 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. We have committed to make additional investments in certain emerging
technology venture capital funds. The total future commitment was $2.5 million
at December 31, 2006 ($3.1 million at December 31, 2005), and will be invested
in 2007. We do not have plans to make any additional investments beyond this
commitment.
INVESTMENT IN ATC. In December 2005, we entered into an agreement with Wisconsin
Public Service Corporation and WPS Investments, LLC that provides for our
Wisconsin subsidiary, Rainy River Energy Corporation - Wisconsin, to invest $60
million in ATC. In May 2006, the PSCW reviewed and approved the request that
allows us to invest in ATC. During 2006, we invested $51.4 million in ATC. We
plan to invest an additional $8.6 million in ATC in early 2007 to reach our $60
million investment commitment and estimated 8% ownership interest. As of
December 31, 2006, our equity investment balance in ATC was $53.7 million,
representing approximately a 7% ownership interest. (See Note 6.)
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 review environmental matters on a
quarterly basis. Accruals for environmental matters are recorded when it is
probable that a liability has been incurred and the amount of the liability can
be reasonably estimated, based on current law and existing technologies. These
accruals are adjusted periodically as assessment and remediation efforts
progress or as additional technical or legal information becomes available.
Accruals for environmental liabilities are included in the balance sheet at
undiscounted amounts and exclude claims for recoveries from insurance or other
third parties. Costs related to environmental contamination treatment and
cleanup are charged to expense unless recoverable in rates from customers.
SWL&P MANUFACTURED GAS PLANT. In May 2001, SWL&P received notice from the WDNR
that the city of Superior had found soil contamination on property adjoining a
former Manufactured Gas Plant (MGP) site owned and operated by SWL&P 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. The investigation continued
through the fall of 2006. It is anticipated that the final report for this
portion of the investigation will be completed during the first quarter of 2007.
Although it is not possible to quantify the total potential clean-up costs until
the investigation is completed, a $0.5 million liability was recorded in
December 2003 based on initial studies to address the known areas of
contamination. The Company has recorded a corresponding amount as a regulatory
asset. 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 its 2006 rate request. In December 2006, the PSCW approved
the recovery of an additional $186,000 of site investigation costs that were
incurred through 2005. 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.
ALLETE 2006 Form 10-K 76
NOTE 8. COMMITMENTS, GUARANTEES AND CONTINGENCIES (CONTINUED)
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 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 nationwide. The CAIR and the
CAMR regulations have been challenged in the federal 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 a challenge to 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.
Minnesota Power petitioned the EPA to review their CAIR determinations affecting
Minnesota. In July 2005, Minnesota Power also filed a Petition for Review with
the U.S. Court of Appeals for the District of Columbia Circuit (Court of
Appeals). In November 2005, the EPA agreed to reconsider certain aspects of the
CAIR, including the Minnesota Power petition addressing modeling used to
determine Minnesota's inclusion in the CAIR region and our claims about
inequities in the SO2 allowance methodology. In March 2006, the EPA announced
that it would not make any changes to the CAIR as a result of the petitions for
reconsideration. Petitions for Review, including Minnesota Power's, remain
pending at the Court of Appeals. If the Petitions for Review filed with the
Court of Appeals are successful, we expect to incur lower compliance costs,
consistent with the rules applicable to those states considered "western" states
under the CAIR. Resolution of the CAIR Petition for Review with the Court of
Appeals is anticipated in 2008.
COMMUNITY DEVELOPMENT DISTRICT OBLIGATIONS. TOWN CENTER. In March 2005, the Town
Center District issued $26.4 million of tax-exempt, 6% Capital Improvement
Revenue Bonds, Series 2005, which are payable over 31 years (by May 1, 2036).
The bond proceeds (less capitalized interest, a debt service reserve fund and
cost of issuance) were used to pay for the construction of a portion of the
major infrastructure improvements at Town Center. 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 were
billed to Town Center 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 recognize the cost of our portion of these assessments, based upon our
ownership of benefited property. At December 31, 2006, we owned approximately
73% of the assessable land in the Town Center District.
PALM COAST PARK. In May 2006, the Palm Coast Park District issued $31.8 million
of tax-exempt, 5.7% Special Assessment Bonds, Series 2006, which are payable
over 31 years (by May 1, 2037). The bond proceeds (less capitalized interest, a
debt service reserve fund and cost of issuance) are being used to pay for the
construction of the major infrastructure improvements at Palm Coast Park and to
mitigate traffic and environmental impacts. The bonds are payable from and
secured by the revenue derived from assessments imposed, levied and collected by
the Palm Coast Park District. The assessments represent an allocation of the
costs of the improvements, including bond financing costs, to the lands within
the Palm Coast Park District benefiting from the improvements. The assessments
will be billed to Palm Coast Park landowners beginning in November 2007. To the
extent that we still own land at the time of the assessment, in accordance with
EITF 91-10, we will recognize the cost of our portion of these assessments,
based upon our ownership of benefited property. At December 31, 2006, we owned
97% of the assessable land in the Palm Coast Park District.
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, or have a material adverse effect on our financial
condition.
77 ALLETE 2006 Form 10-K
NOTE 9. COMMON STOCK AND EARNINGS PER SHARE
Our Articles of Incorporation and mortgages contain provisions that, under
certain circumstances, would restrict the payment of common stock dividends. As
of December 31, 2006, 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
--------------------------------------------------------------------------------------------------------------------------
THOUSANDS MILLIONS
Balance at December 31, 2003 29,099 $859.2
2004 Employee Stock Purchase Plan 14 1.0
Invest Direct 247 18.1
ADESA IPO (See Note 13) - 70.1
Spin-Off of ADESA (See Note 13) - (600.2)
Receipt of ADESA Stock by ESOP - 27.8
Reacquired (70) (5.8)
Options and Stock Awards 361 29.9
--------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2004 29,651 400.1
2005 Employee Stock Purchase Plan 13 0.5
Invest Direct 238 10.5
Options and Stock Awards 241 10.0
--------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2005 30,143 421.1
2006 Employee Stock Purchase Plan 12 0.5
Invest Direct 218 10.0
Options and Stock Awards 63 7.1
--------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2006 30,436 $438.7
--------------------------------------------------------------------------------------------------------------------------
Invest Direct is ALLETE's direct stock purchase and dividend reinvestment plan.
SHAREHOLDER RIGHTS PLAN. In 1996, we adopted a rights plan that provides for a
dividend distribution of one preferred share purchase right (Right) to be
attached to each share of common stock. In July 2006, we amended the rights plan
to extend the expiration of the Rights to July 11, 2009. The amendment also
provides that the Company may not consolidate, merge, or sell a majority of its
assets or earning power if doing so would be counter to the intended benefits of
the Rights or would result in the distribution of Rights to the shareholders of
the other parties to the transaction. Finally, the amendment provides for the
creation of a committee of independent directors to annually review the terms
and conditions of the amended rights plan (Rights Plan), as well as to consider
whether termination or modification of the Rights Plan would be in the best
interests of the shareholders and to make a recommendation based on such review
to the Board of Directors.
The Rights, which are currently not exercisable or transferable apart from our
common stock, entitle the holder to purchase one-and-a-half one-hundredths
(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 receive, upon payment of the purchase price, the number of
shares of common stock (or, in certain circumstances, cash, property or other
securities of ours) having a market value equal to twice the exercise price of
the Right. If we are acquired in a merger or business combination, or more than
50% of our assets or earning power are sold, each exercisable Right entitles the
holder to receive, upon payment of the purchase price, the number of shares of
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 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
Rights Plan.
ALLETE 2006 Form 10-K 78
NOTE 9. COMMON STOCK AND EARNINGS PER SHARE (CONTINUED)
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 2006 and
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 shares were excluded for 2004).
RECONCILIATION OF BASIC AND DILUTED
EARNINGS PER SHARE DILUTIVE
FOR THE YEAR ENDED DECEMBER 31 BASIC SECURITIES DILUTED
---------------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT PER SHARE AMOUNTS
2006
Income from Continuing Operations $77.3 - $77.3
Common Shares 27.8 0.1 27.9
Per Share from Continuing Operations $2.78 - $2.77
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
---------------------------------------------------------------------------------------------------------------------------
NOTE 10. 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
federal tax benefits of the payment were realized through a $24.3 million
capital loss carryback refund in the third quarter of 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.
79 ALLETE 2006 Form 10-K
NOTE 11. OTHER INCOME (EXPENSE)
FOR THE YEAR ENDED DECEMBER 31 2006 2005 2004
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Loss on Emerging Technology Investments $(0.9) $(6.1) $ (8.6)
Income from Investment in ATC (See Note 6) 3.0 - -
Debt Prepayment Premium and Unamortized Debt Issuance Costs (0.6) - (18.5)
Gain on ESOP's Sale of ADESA Stock (See Note 17) - - 11.5
Investments and Other Income 13.4 7.2 3.4
---------------------------------------------------------------------------------------------------------------------------
Total Other Income (Expense) $14.9 $ 1.1 $(12.2)
---------------------------------------------------------------------------------------------------------------------------
In August 2006, we redeemed $29.1 million of outstanding Collier County
Industrial Development Refunding Revenue Bonds 6.5% Series 1996 due 2025 with
proceeds from the issuance of $27.8 million of Collier County Industrial
Development Variable Rate Demand Refunding Revenue Bonds Series 2006 due 2025
and internally generated funds. As a result of an early redemption premium, we
recognized an expense of $0.6 million in the third quarter of 2006.
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 12. INCOME TAX EXPENSE
INCOME TAX EXPENSE
YEAR ENDED DECEMBER 31 2006 2005 2004
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Current Tax Expense
Federal $ 8.9 $ 27.2 $11.2
State 9.6 6.5 6.3
---------------------------------------------------------------------------------------------------------------------------
Total Current Tax Expense 18.5 33.7 17.5
---------------------------------------------------------------------------------------------------------------------------
Deferred Tax Expense (Benefit)
Federal 28.0 (26.4) 1.6
State 2.0 (9.5) (2.3)
---------------------------------------------------------------------------------------------------------------------------
Total Deferred Tax Expense (Benefit) 30.0 (35.9) (0.7)
---------------------------------------------------------------------------------------------------------------------------
Change in Valuation Allowance (1.1) 3.0 0.9
Deferred Tax Credits (1.1) (1.3) (1.3)
---------------------------------------------------------------------------------------------------------------------------
Income Tax Expense (Benefit) for Continuing Operations 46.3 (0.5) 16.4
Income Tax Expense (Benefit) for Discontinued Operations (0.6) 3.4 57.6
Change in Accounting Principle - - (5.5)
---------------------------------------------------------------------------------------------------------------------------
Total Income Tax Expense $45.7 $2.9 $68.5
---------------------------------------------------------------------------------------------------------------------------
Included a current federal tax benefit of $24.3 million and a deferred federal tax expense of $24.3 million related to
the refund from the Kendall County capital loss carryback. (See Note 10.)
Included a current federal tax benefit of $1.3 million, current state tax benefit of $0.4 million and deferred federal
tax benefit of $25.8 million related to the Kendall County charge. (See Note 10.)
ALLETE 2006 Form 10-K 80
NOTE 12. INCOME TAX EXPENSE (CONTINUED)
RECONCILIATION OF TAXES FROM FEDERAL STATUTORY
RATE TO TOTAL INCOME TAX EXPENSE FOR CONTINUING OPERATIONS
YEAR ENDED DECEMBER 31 2006 2005 2004
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Income from Continuing Operations
Before Minority Interest and Income Taxes $128.2 $19.8 $57.0
Statutory Federal Income Tax Rate 35% 35% 35%
---------------------------------------------------------------------------------------------------------------------------
Income Taxes Computed at 35% Statutory Federal Rate 44.9 6.9 20.0
Increase (Decrease) in Tax Due to:
Amortization of Deferred Investment Tax Credits (1.1) (1.3) (1.3)
State Income Taxes - Net of Federal Income Tax Benefit 6.5 1.1 3.6
Depletion (1.1) (1.0) (0.6)
Employee Benefits 0.1 (0.5) (0.4)
Domestic Manufacturing Deduction (0.6) (0.4) -
Regulatory Differences for Utility Plant (0.7) (0.6) (0.6)
Positive Resolution of Audit Issues - (3.7) -
Sale of ADESA Stock by ESOP - - (4.1)
Other (1.7) (1.0) (0.2)
---------------------------------------------------------------------------------------------------------------------------
Total Income Tax Expense (Benefit) for Continuing Operations $ 46.3 $(0.5) $16.4
---------------------------------------------------------------------------------------------------------------------------
The effective tax rate on income from continuing operations before minority
interest was a 36.1% expense for 2006; (2.5% benefit for 2005; 28.8% expense for
2004). The 2006 effective rate was impacted by investment tax credits,
deductions for Medicare health subsidies, depletion and the expected use of
state capital loss carryforwards, of which a $1.1 million benefit was included
in the state tax provision. The 2005 effective rate was impacted by three major
items--a $2.5 million deferred tax adjustment to reflect comprehensive state tax
planning initiatives, a $3.7 million current tax adjustment to reflect the
receipt of a positive audit report and an increase in taxes due to the inability
to recognize certain state benefits for capital loss carryforwards.
DEFERRED TAX ASSETS AND LIABILITIES
DECEMBER 31 2006 2005
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Deferred Tax Assets
Employee Benefits and Compensation $ 95.5 $ 58.0
Property Related 32.8 31.0
Kendall County Capital Loss 4.3 30.5
Investment Tax Credits 12.1 12.9
Excess of Tax Value Over Book Value 4.7 5.6
Other 8.9 9.0
---------------------------------------------------------------------------------------------------------------------------
Gross Deferred Tax Assets 158.3 147.0
Deferred Tax Asset Valuation Allowance (3.6) (4.1)
---------------------------------------------------------------------------------------------------------------------------
Total Deferred Tax Assets 154.7 142.9
---------------------------------------------------------------------------------------------------------------------------
Deferred Tax Liabilities
Property Related 204.7 210.8
Regulatory Asset for Benefit Obligations 34.8 -
Investment Tax Credits 17.2 18.3
Employee Benefits and Compensation 13.2 12.6
Fuel Clause Adjustment 6.0 5.4
Other 9.3 3.2
---------------------------------------------------------------------------------------------------------------------------
Total Deferred Tax Liabilities 285.2 250.3
---------------------------------------------------------------------------------------------------------------------------
Accumulated Deferred Income Taxes $130.5 $107.4
---------------------------------------------------------------------------------------------------------------------------
Recorded as:
Current Deferred Tax Assets $ 0.3 $ 31.0
Long-Term Deferred Tax Liabilities 130.8 138.4
---------------------------------------------------------------------------------------------------------------------------
Net Deferred Tax Liabilities $130.5 $107.4
---------------------------------------------------------------------------------------------------------------------------
Included Unfunded Employee Benefits
Included impairments related to the emerging technology portfolio.
81 ALLETE 2006 Form 10-K
NOTE 13. DISCONTINUED OPERATIONS
ENVENTIS TELECOM. On December 30, 2005, we sold all the stock of our
telecommunications subsidiary, Enventis Telecom, to Hickory Tech Corporation 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.
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 impairments 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
Florida, Inc. (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. On March 15, 2006, the Company paid Aqua Utilities the adjustment
refund amount of $1.7 million. 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.
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. If we had not suspended
depreciation, depreciation expense at our Water Services businesses would have
been $2.6 million in 2004.
Financial results for 2006 reflected additional legal and administrative
expenses incurred by the Company to exit the Water Services businesses.
ALLETE 2006 Form 10-K 82
NOTE 13. DISCONTINUED OPERATIONS (CONTINUED)
DISCONTINUED OPERATIONS
SUMMARY INCOME STATEMENT
FOR THE YEAR ENDED DECEMBER 31 2006 2005 2004
-------------------------------------------------------------------------------------------------------------------------
MILLIONS
Operating Revenue
Automotive Services - - $681.7
Water Services - - 18.5
Enventis Telecom - $50.7 47.3
-------------------------------------------------------------------------------------------------------------------------
Total Operating Revenue - $50.7 $747.5
-------------------------------------------------------------------------------------------------------------------------
Pre-Tax Income (Loss) from Operations
Automotive Services - - $132.5
Water Services - - (1.7)
Enventis Telecom - $ 3.0 1.0
-------------------------------------------------------------------------------------------------------------------------
- 3.0 131.8
-------------------------------------------------------------------------------------------------------------------------
Income Tax Expense (Benefit)
Automotive Services - - 54.0
Water Services - - (0.9)
Enventis Telecom - 1.2 0.4
-------------------------------------------------------------------------------------------------------------------------
- 1.2 53.5
-------------------------------------------------------------------------------------------------------------------------
Total Income from Operations - 1.8 78.3
-------------------------------------------------------------------------------------------------------------------------
Loss on Disposal
Automotive Services - - (6.7)
Water Services $(1.5) (4.5) 6.2
Enventis Telecom - 0.6 -
-------------------------------------------------------------------------------------------------------------------------
(1.5) (3.9) (0.5)
-------------------------------------------------------------------------------------------------------------------------
Income Tax Expense (Benefit)
Automotive Services - - (2.6)
Water Services (0.6) (2.0) 6.7
Enventis Telecom - 4.2 -
-------------------------------------------------------------------------------------------------------------------------
(0.6) 2.2 4.1
-------------------------------------------------------------------------------------------------------------------------
Net Loss on Disposal (0.9) (6.1) (4.6)
-------------------------------------------------------------------------------------------------------------------------
Income (Loss) from Discontinued Operations $(0.9) $(4.3) $ 73.7
-------------------------------------------------------------------------------------------------------------------------
DISCONTINUED OPERATIONS
SUMMARY BALANCE SHEET INFORMATION
DECEMBER 31 2005
-------------------------------------------------------------------------------------------------------------------------
MILLIONS
Assets of Discontinued Operations
Other Current Assets $0.4
Property, Plant and Equipment $2.2
Liabilities of Discontinued Operations
Current Liabilities $13.0
-------------------------------------------------------------------------------------------------------------------------
83 ALLETE 2006 Form 10-K
NOTE 14. OTHER COMPREHENSIVE INCOME (LOSS)
OTHER COMPREHENSIVE INCOME (LOSS) PRE-TAX TAX EXPENSE NET-OF-TAX
YEAR ENDED DECEMBER 31 AMOUNT (BENEFIT) AMOUNT
-------------------------------------------------------------------------------------------------------------------------
MILLIONS
2006
Unrealized Gain on Securities During the Year $ 2.5 $0.6 $1.9
Additional Pension Liability 11.0 4.6 6.4
-------------------------------------------------------------------------------------------------------------------------
Other Comprehensive Income $13.5 $5.2 $8.3
-------------------------------------------------------------------------------------------------------------------------
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)
-------------------------------------------------------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
DECEMBER 31 2006 2005
-------------------------------------------------------------------------------------------------------------------------
MILLIONS
Unrealized Gain on Securities $ 4.0 $ 2.1
Defined Benefit Pension and Other Postretirement Plans (12.8) -
Additional Pension Liability - (14.9)
-------------------------------------------------------------------------------------------------------------------------
Total Accumulated Other Comprehensive Loss $ (8.8) $(12.8)
-------------------------------------------------------------------------------------------------------------------------
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. 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 2006, $0.2 million of
current losses after-tax under the equity method were recognized ($0 in 2005;
$1.6 million loss in 2004).
ALLETE 2006 Form 10-K 84
NOTE 16. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
We have noncontributory defined benefit pension plans covering eligible
employees. The plans provide defined benefits based on years of service and
final average pay. We also have defined contribution pension plans covering
substantially all employees; employer contributions are made through our
employee stock ownership plan (see Note 17), except for BNI Coal, which made
cash contributions of $0.7 million in 2006 ($0.7 million in 2005; $0.6 million
in 2004). In July 2006, we made an $8.3 million contribution to ALLETE's defined
benefit plan.
On August 9, 2006, ALLETE's Board of Directors approved amendments to the
Minnesota Power and Affiliated Companies Retirement Plan A (Retirement Plan A)
and the Minnesota Power and Affiliated Companies Retirement Savings and Stock
Ownership Plan (RSOP). Retirement Plan A was amended to suspend further
crediting service pursuant to the plan, effective as of September 30, 2006, and
to close Retirement Plan A to new participants. Participants will continue to
accrue benefits under the plan for future pay increases. In conjunction with
this change, the Board of Directors took action to increase benefits employees
will receive under the RSOP. The modification of Retirement Plan A required us
to re-measure our pension expense as of August 9, 2006. As a result of the
re-measurement, Retirement Plan A pension expense for 2006 was reduced by $0.2
million.
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 2006, after the measurement date, $3.6 million was transferred from the
grantor trust to the VEBAs ($11.4 million in 2005).
In September 2006, the FASB issued SFAS 158, "Employers' Accounting for Defined
Benefit Pension and Other Postretirement Plans" (SFAS 158). SFAS 158 requires
that employers recognize on a prospective basis the funded status of their
defined benefit pension and other postretirement plans on their consolidated
balance sheet and recognize as a component of other comprehensive income, net of
tax, the gains or losses and prior service costs or credits that arise during
the period but that are not recognized as components of net periodic benefit
cost. SFAS 158 also requires additional disclosures in the notes to financial
statements. SFAS 158 is effective for fiscal years ending after December 15,
2006.
INCREMENTAL EFFECT OF APPLYING SFAS 158 SFAS 158
ON INDIVIDUAL LINE ITEMS IN THE BALANCE SHEET PRE- ADOPTION POST-
YEAR ENDED DECEMBER 31, 2006 SFAS 158 ADJUSTMENTS SFAS 158
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Prepayments and Other Current Assets $25.9 $(2.1) $23.8
Other Assets $48.9 $86.1 $135.0
Total Assets $1,449.4 $84.0 $1,533.4
Other Current Liabilities $24.3 - $24.3
Deferred Income Tax Liabilities $133.5 $(2.7) $130.8
Other Liabilities $135.4 $90.7 $226.1
Total Liabilities $779.6 $88.0 $867.6
Accumulated Other Comprehensive Loss - Net of Tax $(4.5) $(4.3) $(8.8)
Total Shareholders' Equity $670.1 $(4.3) $665.8
---------------------------------------------------------------------------------------------------------------------------
Approximately 84% of the defined benefit pension and 71% of the postretirement
health and life benefit costs recognized annually by our regulated companies are
recovered through rates filed with our regulatory jurisdictions. It is expected
that these costs will continue to be recovered in future rates in accordance
with the requirements of SFAS 71. As a result, these amounts that are required
to otherwise be recognized in accumulated other comprehensive income under the
provisions of SFAS 158 have been recognized as a long-term regulatory asset on
our consolidated balance sheet. The remaining 16% of the defined benefit pension
and 29% of the postretirement health and life benefit costs relate to costs
associated with our nonregulated operations and, accordingly, have been
recognized as a charge to accumulated other comprehensive income at December 31,
2006.
85 ALLETE 2006 Form 10-K
NOTE 16. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (CONTINUED)
We use a September 30 measurement date for the pension and postretirement health
and life plans. Pursuant to SFAS 158, we are required to change our measurement
date to December 31 during the year ending December 31, 2008.
PENSION OBLIGATION AND FUNDED STATUS
AT SEPTEMBER 30 2006 2005
---------------------------------------------------------------------------------------------------------------------
MILLIONS
Change in Benefit Obligation
Obligation, Beginning of Year $412.4 $380.0
Service Cost 9.1 8.7
Interest Cost 22.2 21.3
Actuarial Loss (Gain) (12.2) 16.6
Benefits Paid (19.8) (18.9)
Other 6.0 4.7
---------------------------------------------------------------------------------------------------------------------
Obligation, End of Year 417.7 412.4
---------------------------------------------------------------------------------------------------------------------
Change in Plan Assets
Fair Value, Beginning of Year 337.1 310.1
Actual Return on Assets 32.5 40.6
Employer Contribution 8.9 0.6
Benefits Paid (19.8) (18.9)
Other 6.0 4.7
---------------------------------------------------------------------------------------------------------------------
Fair Value, End of Year 364.7 337.1
---------------------------------------------------------------------------------------------------------------------
Funded Status $(53.0) (75.3)
------
Amounts
Net Loss 90.6
Prior Service Cost 4.5
Transition Obligation (0.1)
---------------------------------------------------------------------------------------------------------------------
Net Assets Recognized $ 19.7
---------------------------------------------------------------------------------------------------------------------
Amounts Recognized in Consolidated Balance Sheet Consist of:
Prepaid Pension Cost $33.8
Accrued Benefit Liability (42.3)
Intangible Assets 2.3
Accumulated Other Comprehensive Income 25.9
---------------------------------------------------------------------------------------------------------------------
Net Assets Recognized $19.7
---------------------------------------------------------------------------------------------------------------------
The pension costs reported on our consolidated balance sheet as regulatory
long-term assets and accumulated other comprehensive income consist of the
following:
PENSION COSTS
YEAR ENDED DECEMBER 31 2006
---------------------------------------------------------------------------------------------------------------------
MILLIONS
Net Loss $69.9
Prior Service Cost 3.9
Transition Obligation (0.1)
---------------------------------------------------------------------------------------------------------------------
$73.7
---------------------------------------------------------------------------------------------------------------------
ALLETE 2006 Form 10-K 86
NOTE 16. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (CONTINUED)
COMPONENTS OF NET PERIODIC PENSION EXPENSE (INCOME)
YEAR ENDED DECEMBER 31 2006 2005 2004
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Service Cost $ 9.1 $ 8.7 $ 8.4
Interest Cost 22.2 21.3 20.7
Expected Return on Assets (28.6) (28.2) (27.4)
Amortized Amounts
Loss 4.6 3.1 1.4
Prior Service Cost 0.6 0.6 0.8
Transition Obligation - 0.2 0.3
---------------------------------------------------------------------------------------------------------------------------
Net Pension Expense $ 7.9 $ 5.7 $ 4.2
---------------------------------------------------------------------------------------------------------------------------
INFORMATION FOR PENSION PLANS WITH AN
ACCUMULATED BENEFIT OBLIGATION IN EXCESS OF PLAN ASSETS
AT SEPTEMBER 30 2006 2005
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Projected Benefit Obligation $180.4 $177.5
Accumulated Benefit Obligation $160.6 $157.7
Fair Value of Plan Assets $130.9 $116.3
---------------------------------------------------------------------------------------------------------------------------
ADDITIONAL PENSION INFORMATION
YEAR ENDED DECEMBER 31 2006 2005 2004
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Increase (Decrease) in Additional Pension Liability
Included in Other Comprehensive Income $11.0 $(3.4) $(5.7)
---------------------------------------------------------------------------------------------------------------------------
The accumulated benefit obligation for all defined benefit pension plans was
$376.1 million and $369.5 million at September 30, 2006 and 2005, respectively.
POSTRETIREMENT HEALTH AND LIFE OBLIGATION AND FUNDED STATUS
AT SEPTEMBER 30 2006 2005
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Change in Benefit Obligation
Obligation, Beginning of Year $136.9 $117.2
Service Cost 4.4 4.0
Interest Cost 7.4 6.6
Actuarial Loss (Gain) (4.7) 13.1
Participation Contributions 1.4 1.3
Benefits Paid (6.4) (5.3)
Amendments (0.1) -
---------------------------------------------------------------------------------------------------------------------------
Obligation, End of Year 138.9 136.9
---------------------------------------------------------------------------------------------------------------------------
Change in Plan Assets
Fair Value, Beginning of Year 60.9 54.1
Actual Return on Assets 5.8 7.1
Employer Contribution 17.2 3.6
Participation Contributions 1.4 1.4
Benefits Paid (6.4) (5.3)
---------------------------------------------------------------------------------------------------------------------------
Fair Value, End of Year 78.9 60.9
---------------------------------------------------------------------------------------------------------------------------
Funded Status $(60.0) (76.0)
------
Amounts
Net Loss 25.8
Transition Obligation 17.4
---------------------------------------------------------------------------------------------------------------------------
Net Liabilities Recognized $(32.8)
---------------------------------------------------------------------------------------------------------------------------
87 ALLETE 2006 Form 10-K
NOTE 16. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (CONTINUED)
Under SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," only assets in the VEBAs are treated as plan assets in the previous
table for the purpose of determining funded status. In addition to the
postretirement health and life assets reported in the previous table, we had
$25.6 million in an irrevocable grantor trust at December 31, 2006 ($22.6
million at December 31, 2005). We consolidate the irrevocable grantor trust and
it is included in Investments on our consolidated balance sheet.
The postretirement health and life costs reported on our consolidated balance
sheet as regulatory long-term assets and accumulated other comprehensive income
consist of the following:
POSTRETIREMENT HEALTH AND LIFE COSTS
YEAR ENDED DECEMBER 31 2006
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Net Loss $19.2
Prior Service Cost (0.1)
Transition Obligation 15.0
---------------------------------------------------------------------------------------------------------------------------
$34.1
---------------------------------------------------------------------------------------------------------------------------
COMPONENTS OF NET PERIODIC POSTRETIREMENT HEALTH AND LIFE EXPENSE
YEAR ENDED DECEMBER 31 2006 2005 2004
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Service Cost $ 4.4 $4.0 $3.9
Interest Cost 7.4 6.7 6.6
Expected Return on Assets (5.6) (4.8) (4.6)
Amortized Amounts
Loss 1.7 0.7 0.4
Transition Obligation 2.4 2.4 2.4
---------------------------------------------------------------------------------------------------------------------------
Net Expense $10.3 $9.0 $8.7
---------------------------------------------------------------------------------------------------------------------------
POSTRETIREMENT
ESTIMATED FUTURE BENEFIT PAYMENTS PENSION HEALTH AND LIFE
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
2007 $20 $5
2008 $21 $5
2009 $22 $6
2010 $22 $7
2011 $23 $7
Years 2012 - 2016 $138 $45
---------------------------------------------------------------------------------------------------------------------------
The pension and postretirement health and life costs recorded in other long-term
assets and accumulated other comprehensive income expected to be recognized as a
component of net pension and postretirement benefit costs for the year ending
December 31, 2007, are as follows:
POSTRETIREMENT
PENSION HEALTH AND LIFE
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
Net Loss (Gain) $3.4 $0.9
Prior Service Costs $0.7 -
Transition Obligations $(0.1) $2.5
---------------------------------------------------------------------------------------------------------------------------
ALLETE 2006 Form 10-K 88
NOTE 16. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (CONTINUED)
WEIGHTED-AVERAGE ASSUMPTIONS
USED TO DETERMINE BENEFIT OBLIGATION
AT SEPTEMBER 30 2006 2005
---------------------------------------------------------------------------------------------------------------------------
Discount Rate 5.75% 5.50%
Rate of Compensation Increase 3.5 - 4.5% 3.5 - 4.5%
Health Care Trend Rates
Trend Rate 10% 10%
Ultimate Trend Rate 5% 5%
Year Ultimate Trend Rate Effective 2011 2010
---------------------------------------------------------------------------------------------------------------------------
WEIGHTED-AVERAGE ASSUMPTIONS
USED TO DETERMINE NET PERIODIC BENEFIT COSTS
YEAR ENDED DECEMBER 31 2006 2005 2004
---------------------------------------------------------------------------------------------------------------------------
Discount Rate 5.50% 5.75% 6.00%
Expected Long-Term Return on Plan Assets
Pension 9.0% 9.0% 9.0%
Postretirement Health and Life 5.0 - 9.0% 5.0 - 9.0% 7.2 - 9.0%
Rate of Compensation Increase 3.5 - 4.5% 3.5 - 4.5% 3.5 - 4.5%
---------------------------------------------------------------------------------------------------------------------------
In establishing the expected long-term return on plan assets, we consider the
diversification and allocation of plan assets, the actual long-term historical
performance for the type of securities invested in, the actual long-term
historical performance of plan assets and the impact of current economic
conditions, if any, on long-term historical returns.
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 the Citigroup Pension Discount Curve adjusted
for ALLETE's specific cash flows.
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 $1.9 $(1.5)
Effect on Postretirement Health and Life Obligation $17.5 $(14.3)
---------------------------------------------------------------------------------------------------------------------------
POSTRETIREMENT
PENSION HEALTH AND LIFE
PLAN ASSET ALLOCATIONS 2006 2005 2006 2005
---------------------------------------------------------------------------------------------------------------------------
Equity Securities 65.1% 64.9% 68.9% 68.6%
Debt Securities 29.6 29.6 30.6 30.5
Real Estate 0.8 1.3 - -
Venture Capital 4.2 2.9 - -
Cash 0.3 1.3 0.5 0.9
---------------------------------------------------------------------------------------------------------------------------
100.0% 100.0% 100.0% 100.0%
---------------------------------------------------------------------------------------------------------------------------
Included VEBAs and irrevocable grantor trust.
Pension plan equity securities did not include ALLETE common stock at September
30, 2006, or September 30, 2005.
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.
89 ALLETE 2006 Form 10-K
NOTE 16. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (CONTINUED)
POSTRETIREMENT
PLAN ASSET TARGET ALLOCATIONS PENSION HEALTH AND LIFE
---------------------------------------------------------------------------------------------------------------------------
Equity Securities 60% 69%
Debt Securities 24 30
Real Estate 9 -
Venture Capital 6 -
Cash 1 1
---------------------------------------------------------------------------------------------------------------------------
100% 100%
---------------------------------------------------------------------------------------------------------------------------
Included VEBAs and irrevocable grantor trust.
We expect to contribute approximately $6 million to our postretirement health
and life plans in 2007. We are not required to make any contributions to our
defined benefit pension plans in 2007.
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 deduction for Medicare health
subsidies reduced our after-tax postretirement medical expense by $2.4 million
for 2006 ($3.5 million in 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 payment in mid-2007 for 2006 credits.
NOTE 17. EMPLOYEE STOCK AND INCENTIVE PLANS
EMPLOYEE STOCK OWNERSHIP PLAN. We sponsor a leveraged employee stock ownership
plan (ESOP) within the Retirement Savings and Stock Ownership Plan (RSOP) that
covers certain eligible employees. In 1989, the ESOP used the proceeds from a
$16.5 million third-party loan, guaranteed by us, to purchase 0.6 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 note was refinanced in 2006 at 6%.
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 $4.6
million in 2006 ($5.5 million in 2005; $5.0 million in 2004).
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 11.) Under the direction of an independent
trustee, the ESOP used the proceeds to purchase shares of ALLETE common stock in
late 2004 and early 2005, which were recorded using the treasury method as
Unearned ESOP Shares within Shareholders' Equity as presented on our
consolidated balance sheet.
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
-----------------------------------------------------------------------------------------------------------------------
ALLETE 2006 Form 10-K 90
NOTE 17. EMPLOYEE STOCK AND INCENTIVE PLANS (CONTINUED)
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 2006 2005 2004
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
ESOP Shares
Allocated 1.7 1.9 1.4
Unallocated 2.5 2.6 2.0
---------------------------------------------------------------------------------------------------------------------------
Total 4.2 4.5 3.4
---------------------------------------------------------------------------------------------------------------------------
Fair Value of Unallocated Shares $115.2 $115.0 $72.7
---------------------------------------------------------------------------------------------------------------------------
STOCK-BASED COMPENSATION. Effective January 1, 2006, we adopted the fair value
recognition provisions of SFAS 123R, "Share-Based Payment," using the modified
prospective transition method. Under this method, we recognize compensation
expense for all share-based payments granted after January 1, 2006, and those
granted prior to but not yet vested as of January 1, 2006. Under the fair value
recognition provisions of SFAS 123R, we recognize stock-based compensation net
of an estimated forfeiture rate and only recognize compensation expense for
those shares expected to vest over the required service period of the award.
Prior to our adoption of SFAS 123R, we accounted for share-based payments under
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees" and related interpretations.
STOCK INCENTIVE PLAN. Under our Executive Long-Term Incentive Compensation Plan
(Executive Plan), share-based awards may be issued to key employees via a broad
range of methods, including non-qualified and incentive stock options,
performance shares, performance units, restricted stock, stock appreciation
rights and other awards. There are 3.2 million shares of common stock reserved
for issuance under the Executive Plan, with 1.5 million of these shares
available for issuance as of December 31, 2006.
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 9,000 options were outstanding under the Director Plan at December
31, 2006.
We currently have the following types of share-based awards outstanding:
NON-QUALIFIED STOCK OPTIONS. The options allow for the purchase of shares
of common stock at a price equal to the market value of our common stock at
the date of grant. Options become exercisable beginning one year after the
grant date, with one-third vesting each year over three years. Options may
be exercised up to ten years following the date of grant. In the case of
qualified retirement, death or disability, options vest immediately and the
period over which the options can be exercised is three years. Employees
have up to three months to exercise vested options upon voluntary
termination or involuntary termination without cause. All options are
cancelled upon termination for cause. All options vest immediately upon
retirement, death, disability or a change of control, as defined in the
award agreement. We determine the fair value of options using the
Black-Scholes option-pricing model. The estimated fair value of options,
including the effect of estimated forfeitures, is recognized as expense on
the straight-line basis over the options' vesting periods, or the
accelerated vesting period if the employee is retirement eligible.
The following assumptions were used in determining the fair value of stock
options granted during 2006, under the Black-Scholes option-pricing model:
2006
--------------------------------------------------------------------------------
Risk-Free Interest Rate 4.5%
Expected Life 5 Years
Expected Volatility 20%
Dividend Growth Rate 5%
--------------------------------------------------------------------------------
91 ALLETE 2006 Form 10-K
NOTE 17. EMPLOYEE STOCK AND INCENTIVE PLANS (CONTINUED)
The risk-free interest rate for periods within the contractual life of the
option is based on the U.S. Treasury yield curve in effect at the grant
date. Expected volatility is estimated based on the historic volatility of
our stock and the stock of our peer group companies. We utilize historical
option exercise and employee pre-vesting termination data to estimate the
option life. The dividend growth rate is based upon historic growth rates
in our dividends.
PERFORMANCE SHARES. Under these awards, the number of shares earned is
contingent upon attaining specific performance targets over a three-year
performance period. In the case of qualified retirement, death or
disability during a performance period, a pro-rata portion of the award
will be earned at the conclusion of the performance period based on the
performance goals achieved. In the case of termination of employment for
any reason other than qualified retirement, death or disability, no award
will be earned. If there is a change in control, a pro-rata portion of the
award will be paid based on the greater of actual performance up to the
date of the change in control or target performance. The fair value of
these awards is equal to the grant date fair value which is estimated based
upon the assumed share-based payment three years from the date of grant.
Compensation cost is recognized over the three-year performance period
based on our estimate of the number of shares which will be earned by the
award recipients.
EMPLOYEE STOCK PURCHASE PLAN (ESPP). Under our ESPP, eligible employees may
purchase ALLETE common stock at a 5% discount from the market price. Because the
discount is not greater than 5%, we are not required by SFAS 123R to apply fair
value accounting to these awards.
RSOP. Shares held in our RSOP are excluded from SFAS 123R and are accounted for
in accordance with the American Institute of Certified Public Accountants'
Statement of Position No. 93-6, "Employers' Accounting for Employee Stock
Ownership Plans."
The following share-based compensation expense amounts were recognized in our
consolidated statement of income for the periods presented since our adoption of
SFAS 123R.
SHARE-BASED COMPENSATION EXPENSE
FOR THE YEAR ENDED DECEMBER 31 2006
-----------------------------------------------------------------------------------------------------------------------
MILLIONS
Stock Options $0.8
Performance Shares 1.0
-----------------------------------------------------------------------------------------------------------------------
Total Share-Based Compensation Expense $1.8
-----------------------------------------------------------------------------------------------------------------------
Income Tax Benefit $0.7
-----------------------------------------------------------------------------------------------------------------------
There were no capitalized stock-based compensation costs at December 31, 2006.
As of December 31, 2006, the total unrecognized compensation cost for
performance share awards not yet recognized in our statements of income was $1.3
million. This amount is expected to be recognized over a weighted-average period
of 1.31 years.
The following table presents the pro forma effect of stock-based compensation
had we applied the provisions of SFAS 123 for the years ended December 31, 2005
and 2004.
PRO FORMA EFFECT OF SFAS 123
ACCOUNTING FOR STOCK-BASED COMPENSATION 2005 2004
-----------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT PER SHARE AMOUNTS
Net Income
As Reported $13.3 $104.4
Less: Employee Stock Compensation Expense
Determined Under SFAS 123 - Net of Tax 1.5 1.3
Plus: Employee Stock Compensation Expense
Included in Net Income - Net of Tax 1.5 1.0
-----------------------------------------------------------------------------------------------------------------------
Pro Forma Net Income $13.3 $104.1
-----------------------------------------------------------------------------------------------------------------------
Basic Earnings Per Share
As Reported $0.49 $3.69
Pro Forma $0.49 $3.68
Diluted Earnings Per Share
As Reported $0.48 $3.67
Pro Forma $0.48 $3.66
-----------------------------------------------------------------------------------------------------------------------
ALLETE 2006 Form 10-K 92
NOTE 17. EMPLOYEE STOCK AND INCENTIVE PLANS (CONTINUED)
In the previous table, the pro forma expense determined under SFAS 123 for
employee stock options granted was calculated using the Black-Scholes
option-pricing model with the following assumptions:
2005 2004
-----------------------------------------------------------------------------------------------------------------------
Risk-Free Interest Rate 3.7% 3.3%
Expected Life 5 Years 5 Years
Expected Volatility 20.0% 28.1%
Dividend Growth Rate 5% 2%
-----------------------------------------------------------------------------------------------------------------------
The following table presents information regarding our outstanding stock options
for the year ended December 31, 2006.
WEIGHTED-AVERAGE
WEIGHTED-AVERAGE AGGREGATE REMAINING
NUMBER OF EXERCISE INTRINSIC CONTRACTUAL
OPTIONS PRICE VALUE TERM
--------------------------------------------------------------------------------------------------------------------------
MILLIONS
Outstanding at December 31, 2005 357,827 $34.29 $3.5 7.4 years
Granted 115,653 $44.15
Exercised (28,896) $26.47
Forfeited (6,233) $38.25
--------------------------------------------------------------------------------------------------------------------------
Outstanding at December 31, 2006 438,351 $37.35 $4.0 7.2 years
--------------------------------------------------------------------------------------------------------------------------
Exercisable at December 31, 2006 238,640 $33.18 $3.2 6.2 years
--------------------------------------------------------------------------------------------------------------------------
Fair Value of Options
Granted During the Year $7.28
--------------------------------------------------------------------------------------------------------------------------
The weighted-average grant-date fair value of options was $6.48 for 2006. The
intrinsic value of a stock award is the amount by which the fair value of the
underlying stock exceeds the exercise price of the award. The total intrinsic
value of options exercised was $0.6 million during 2006.
At December 31, 2006, options outstanding consisted of less than 0.1 million
with exercise prices ranging from $15.88 to $19.21, 0.1 million with exercise
prices ranging from $23.79 to $27.40 and 0.3 million with exercise prices
ranging from $35.78 to $41.35. The options with exercise prices ranging from
$23.79 to $27.40 have an average remaining contractual life of 4.8 years, with
0.1 million exercisable on December 31, 2006, at a weighted average price of
$25.32. The options with exercise prices ranging from $35.78 to $41.35 have an
average remaining contractual life of 7.7 years, with 0.2 million exercisable on
December 31, 2006, at a weighted average price of $39.29.
2005
--------------------------
WEIGHTED
AVERAGE
EXERCISE
STOCK OPTION ACTIVITY OPTIONS PRICE
--------------------------------------------------------------------------------------------------------------------------
Outstanding, Beginning of Year 437,965 $28.94
Granted 119,077 $41.35
Exercised (199,215) $26.74
Forfeited - -
--------------------------------------------------------------------------------------------------------------------------
Outstanding, End of Year 357,827 $34.29
--------------------------------------------------------------------------------------------------------------------------
Exercisable, End of Year 178,332 $28.35
Fair Value of Options Granted During the Year $6.51
--------------------------------------------------------------------------------------------------------------------------
93 ALLETE 2006 Form 10-K
NOTE 17. EMPLOYEE STOCK AND INCENTIVE PLANS (CONTINUED)
2004
--------------------------
WEIGHTED
AVERAGE
EXERCISE
STOCK OPTION ACTIVITY OPTIONS PRICE
--------------------------------------------------------------------------------------------------------------------------
Outstanding, Beginning of Period 760,026 $64.47
Granted 39,759 $97.65
Exercised (295,359) $67.14
Forfeited (7,396) $63.06
--------------------------------------------------------------------------------------------------------------------------
Outstanding, End of Period 497,030 $69.85
--------------------------------------------------------------------------------------------------------------------------
Exercisable, End of Period - -
Fair Value of Options Granted During the Period $20.01
--------------------------------------------------------------------------------------------------------------------------
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.
2004
--------------------------
WEIGHTED
AVERAGE
EXERCISE
STOCK OPTION ACTIVITY OPTIONS PRICE
--------------------------------------------------------------------------------------------------------------------------
Outstanding as of September 20, 2004, after spin-off 478,054 $28.56
Granted - -
Exercised (40,089) $24.40
Forfeited - -
--------------------------------------------------------------------------------------------------------------------------
Outstanding, End of Year 437,965 $28.94
--------------------------------------------------------------------------------------------------------------------------
Exercisable, End of Year 287,711 $26.57
--------------------------------------------------------------------------------------------------------------------------
Amounts subsequent to the ADESA spin-off.
The employee stock options outstanding at the date of the ADESA 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."
In February 2007, we granted stock options to purchase 0.1 million shares of
common stock (exercise price of $48.65 per share).
PERFORMANCE SHARES. The following table presents information regarding our
nonvested performance shares for the year ended December 31, 2006.
WEIGHTED-AVERAGE
NUMBER OF GRANT DATE
SHARES FAIR VALUE
--------------------------------------------------------------------------------------------------------------------------
Nonvested at December 31, 2005 97,884 $38.63
Granted 26,967 $43.87
Awarded (49,076) $37.76
Forfeited (4,771) $41.53
--------------------------------------------------------------------------------------------------------------------------
Nonvested at December 31, 2006 71,004 $41.03
--------------------------------------------------------------------------------------------------------------------------
Less than 0.1 million performance share grants were awarded in February 2006 for
performance periods ending in 2008. 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.
Less than 0.1 million performance share grants were awarded in February 2005 for
the performance periods ending in 2007. The grant date fair value of the share
awards was $1.0 million. Performance share grants related to the 2006 period
will be issued in early 2007.
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, 2006, 0.5 million shares had been
issued under the plan and 0.1 million shares were held in reserve for future
issuance.
ALLETE 2006 Form 10-K 94
NOTE 18. QUARTERLY FINANCIAL DATA (UNAUDITED)
Information for any one quarterly period is not necessarily indicative of the
results which may be expected for the year. Financial results for the 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 10.)
Financial results for the fourth quarter of 2005 included a $2.5 million, or
$0.09 per share, deferred tax benefit due to comprehensive state 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.
QUARTER ENDED MAR. 31 JUN. 30 SEPT. 30 DEC. 31
--------------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT EARNINGS PER SHARE
2006
Operating Revenue $192.5 $178.3 $199.1 $197.2
--------------------------------------------------------------------------------------------------------------------------
Operating Income from Continuing Operations $36.4 $26.3 $38.7 $39.3
--------------------------------------------------------------------------------------------------------------------------
Income (Loss) Continuing Operations $18.8 $13.6 $21.9 $23.0
Discontinued Operations - (0.4) (0.1) (0.4)
--------------------------------------------------------------------------------------------------------------------------
Net Income $18.8 $13.2 $21.8 $22.6
--------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) Per Share of Common Stock
Basic Continuing Operations $0.68 $0.50 $0.78 $0.82
Discontinued Operations - (0.02) - (0.01)
--------------------------------------------------------------------------------------------------------------------------
$0.68 $0.48 $0.78 $0.81
--------------------------------------------------------------------------------------------------------------------------
Diluted Continuing Operations $0.68 $0.49 $0.78 $0.82
Discontinued Operations - (0.02) - (0.01)
--------------------------------------------------------------------------------------------------------------------------
$0.68 $0.47 $0.78 $0.81
--------------------------------------------------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------------------------------------------------
95 ALLETE 2006 Form 10-K
SCHEDULE II
ALLETE
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
BALANCE AT ADDITIONS DEDUCTIONS BALANCE AT
BEGINNING CHARGED OTHER FROM END OF
FOR THE YEAR ENDED DECEMBER 31 OF YEAR TO INCOME CHANGES RESERVES PERIOD
--------------------------------------------------------------------------------------------------------------------------
MILLIONS
Reserve Deducted from Related Assets
Reserve For Uncollectible Accounts
2006 Trade Accounts Receivable $1.0 $0.7 - $0.6 $1.1
Finance Receivables - Long-Term 0.6 - - 0.4 0.2
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
Deferred Asset Valuation Allowance
2006 Deferred Tax Assets 4.1 (1.1) $0.6 - 3.6
2005 Deferred Tax Assets 1.1 3.8 - 0.8 4.1
2004 Deferred Tax Assets 0.2 0.9 - - 1.1
--------------------------------------------------------------------------------------------------------------------------
Included uncollectible accounts written off.
ALLETE 2006 Form 10-K 96
EXHIBIT INDEX
EXHIBIT NUMBER
4(a)3 - Twenty-Sixth Supplemental Indenture, dated as of October 1,
2006, between ALLETE and The Bank of New York and Douglas J.
MacInnes, as Trustees.
10(d)3 - Second Amendment to Fourth Amended and Restated Committed
Facility Letter dated December 14, 2006, by and among ALLETE
and LaSalle Bank National Association, as Agent.
10(h)4 - January 2007 Amendment to the ALLETE Executive Annual
Incentive Plan.
10(h)7 - Form of ALLETE Executive Annual Incentive Plan Awards
Effective 2007.
10(i)4 - December 2006 Amendments to the ALLETE and Affiliated
Companies Supplemental Executive Retirement Plan.
10(m)6 - Form of ALLETE Executive Long-Term Incentive Compensation Plan
Nonqualified Stock Option Grant Effective 2007.
10(m)7 - Form of ALLETE Executive Long-Term Incentive Compensation Plan
Performance Share Grant Effective 2007.
10(m)8 - Form of ALLETE Executive Long-Term Incentive Compensation Plan
Long-Term Cash Incentive Award Effective 2007.
10(m)9 - Form of ALLETE Executive Long-Term Incentive Compensation Plan
Stock Grant Effective 2007.
10(n)4 - January 2007 Amendment to the ALLETE Director Stock Plan.
10(n)6 - ALLETE Non-Management Director Compensation Summary Effective
February 15, 2007.
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.
99 - ALLETE News Release dated February 16, 2007, announcing 2006
earnings. (THIS EXHIBIT HAS BEEN FURNISHED AND SHALL NOT BE
DEEMED "FILED" FOR PURPOSES OF SECTION 18 OF THE SECURITIES
EXCHANGE ACT OF 1934, NOR SHALL IT BE DEEMED INCORPORATED BY
REFERENCE IN ANY FILING UNDER THE SECURITIES ACT OF 1933,
EXCEPT AS SHALL BE EXPRESSLY SET FORTH BY SPECIFIC REFERENCE
IN SUCH FILING.)
ALLETE 2006 Form 10-K