<PAGE>

                                    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.


<PAGE>


                                      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
<PAGE>

                                   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

<PAGE>

                             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
<PAGE>

                              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

<PAGE>

                                     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.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31                                                   2006              2005             2004
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>               <C>              <C>
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%
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

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
<PAGE>

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.

<TABLE>
<CAPTION>
                                                                                                 FOR THE YEAR ENDED
REGULATED UTILITY                                    UNIT       YEAR         NET WINTER           DECEMBER 31, 2006
POWER SUPPLY                                          NO.     INSTALLED      CAPABILITY         ELECTRIC REQUIREMENTS
------------------------------------------------------------------------------------------------------------------------------------
                                                                                 MW               MWh              %
<S>                                                <C>       <C>             <C>              <C>               <C>
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%
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

ALLETE 2006 Form 10-K                                                          6

<PAGE>

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.)

<TABLE>
<CAPTION>
REGULATED UTILITY ELECTRIC SALES
YEAR ENDED DECEMBER 31                              2006                       2005                       2004
------------------------------------------------------------------------------------------------------------------------
MILLIONS OF KILOWATTHOURS

<S>                                                 <C>                       <C>                        <C>
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 <F1>                           2,153                     1,142                        918
------------------------------------------------------------------------------------------------------------------------

                                                    12,784                    11,657                     11,226
------------------------------------------------------------------------------------------------------------------------

<FN>
<F1>  Effective January 1, 2006, Taconite Harbor was redirected from Nonregulated Energy Operations to Regulated Utility.
</FN>
</TABLE>

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
<PAGE>

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.

<TABLE>
<CAPTION>
MINIMUM REVENUE AND DEMAND UNDER CONTRACT                             MINIMUM ANNUAL                       MONTHLY
AS OF FEBRUARY 1, 2007                                             DEMAND REVENUE <F1><F2>                MEGAWATTS
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                                <C>                                    <C>
     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
------------------------------------------------------------------------------------------------------------------------------------
<FN>
<F1>  Based on past experience, we believe revenue from our Large  Power Customers will  be substantially  in excess of the  minimum
      contract amounts. For example, in our 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.
<F2>  Although several contracts have a feature that allows demand to go to  zero after a  two-year  advance  notice of a  permanent
      closure, this minimum revenue summary does not reflect this occurrence happening in  the forecasted period because we  believe
      it is unlikely.
</FN>
</TABLE>

ALLETE 2006 Form 10-K                                                          8
<PAGE>


ENERGY - REGULATED UTILITY (CONTINUED)

<TABLE>
CONTRACT STATUS FOR MINNESOTA POWER LARGE POWER CUSTOMERS
AS OF FEBRUARY 1, 2007
<CAPTION>
                                                                                                               EARLIEST
CUSTOMER                         INDUSTRY          LOCATION                  OWNERSHIP                     TERMINATION DATE
------------------------------------------------------------------------------------------------------------------------------------
<S>                              <C>               <C>                       <C>                           <C>
Hibbing Taconite Co. <F1>        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 <F1>         Taconite          Eveleth, MN               70% Cleveland-Cliffs Inc      February 28, 2011
                                                                             30% Laiwu Steel Group

UPM, Blandin Paper Mill <F1>     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 <F1>           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. <F2>         Manufacturer      Cloquet, MN               USG Corporation               February 28, 2008

Enbridge Energy Company,         Pipeline          Deer River, MN            Enbridge Energy Company,      February 28, 2008
    Limited Partnership <F2>                       Floodwood, MN                  Limited Partnership

Minnesota Pipeline Company <F2>  Pipeline          Staples, MN               60% Koch Pipeline Co. L.P.    February 28, 2008
                                                   Little Falls, MN          40% Marathon Ashland
                                                   Park Rapids, MN                Petroleum LLC
------------------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> The contract will terminate four years from the date of written notice from either Minnesota Power or  the  customer. No notice
     of contract cancellation has been given by either party. Thus, the earliest date of cancellation is February 28, 2011.
<F2> 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.
</FN>
</TABLE>

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

<PAGE>

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.

<TABLE>
<CAPTION>
COAL DELIVERED TO MINNESOTA POWER
YEAR ENDED DECEMBER 31                                                   2006              2005             2004
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>               <C>               <C>
Average Price per Ton                                                   $20.19            $19.76            $19.01
Average Price per MBtu                                                   $1.10             $1.08             $1.04
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

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

<PAGE>

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

<PAGE>

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

<PAGE>

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

<PAGE>

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.

<TABLE>
<CAPTION>
                                                   UNIT                  YEAR                YEAR              NET
NONREGULATED POWER SUPPLY                           NO.                INSTALLED           ACQUIRED        CAPABILITY
------------------------------------------------------------------------------------------------------------------------------------
                                                                                                               MW
<S>                                                <C>                <C>                  <C>             <C>
Steam
     Wood-Fired <F1>
         Cloquet Energy Center                       5                   2001                2001              22
         in Cloquet, MN

         Rapids Energy Center <F2>                 6 & 7              1969, 1980             2000              30
         in Grand Rapids, MN
------------------------------------------------------------------------------------------------------------------------------------

Hydro
     Conventional Run-of-River
         Rapids Energy Center <F2>                 4 & 5                 1917                2000               1
         in Grand Rapids, MN
------------------------------------------------------------------------------------------------------------------------------------
<FN>
<F1>  Supplemented by coal.
<F2>  The net generation is primarily dedicated to the needs of one customer.
</FN>
</TABLE>

ALLETE 2006 Form 10-K                                                         14

<PAGE>

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

<PAGE>

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
<PAGE>

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

<PAGE>

REAL ESTATE (CONTINUED)

<TABLE>
<CAPTION>
SUMMARY OF DEVELOPMENT PROJECTS
FOR THE YEAR ENDED                                           TOTAL              RESIDENTIAL          COMMERCIAL
DECEMBER 31, 2006                        OWNERSHIP           ACRES <F1>          UNITS <F2>          SQ. FT. <F2><F3>
-----------------------------------------------------------------------------------------------------------------------------

<S>                                      <C>                <C>                 <C>                  <C>
Town Center                                 80%
     At December 31, 2005                                    1,480                2,833              2,927,700
     Property Sold                                            (124)                (773)              (401,971)
     Change in Estimate <F1>                                     -                  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 <F1>                                     -                  360                (43,200)
-----------------------------------------------------------------------------------------------------------------------------
                                                             4,337                3,760              3,156,800
-----------------------------------------------------------------------------------------------------------------------------

Ormond Crossings                           100%
     At December 31, 2005                                    5,960                 <F4>                   <F4>
     Change in Estimate <F1>                                     -
-----------------------------------------------------------------------------------------------------------------------------
                                                             5,960
-----------------------------------------------------------------------------------------------------------------------------
                                                            11,653                5,982              5,862,110
-----------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Acreage amounts are approximate and shown on a gross basis, including wetlands and minority interest. Acreage amounts may
     vary due to platting or surveying activity. Wetland amounts vary by property and are often not formally determined  prior
     to sale.
<F2> Estimated and  includes  minority  interest. The actual  property breakdown at full build-out may be different than these
     estimates.
<F3> Includes industrial, office and retail square footage.
<F4> 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.
</FN>
</TABLE>

<TABLE>
<CAPTION>
SUMMARY OF OTHER LAND INVENTORIES
FOR THE YEAR ENDED
DECEMBER 31, 2006                     OWNERSHIP     TOTAL     MIXED USE    RESIDENTIAL   COMMERCIAL   AGRICULTURAL
------------------------------------------------------------------------------------------------------------------------------
ACRES <F1>

<S>                                   <C>           <C>       <C>          <C>           <C>          <C>
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 <F1>                           (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 <F2>                              100%
     At December 31, 2005                              944           -            -             -          944
     Property Sold                                     (10)          -            -             -          (10)
------------------------------------------------------------------------------------------------------------------------------

                                                       934           -            -             -          934
------------------------------------------------------------------------------------------------------------------------------

                                                     3,323       1,404          487           350        1,082
------------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Acreage amounts are approximate and shown on a gross basis, including wetlands and minority interest. Acreage amounts may
     vary due to platting or surveying activity. Wetland amounts vary by property and are often  not formally determined prior
     to sale. The actual property breakdown at full build-out may be different than these estimates.
<F2> Includes land located in Ormond Beach, Florida, and other land located in Palm Coast, Florida not included in development
     projects.
</FN>
</TABLE>

ALLETE 2006 Form 10-K                                                         18

<PAGE>

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

<PAGE>

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
<PAGE>

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

<PAGE>

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

<PAGE>

EXECUTIVE OFFICERS OF THE REGISTRANT

<TABLE>
<CAPTION>

EXECUTIVE OFFICERS                                                                               INITIAL EFFECTIVE DATE
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                              <C>
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
</TABLE>

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
<PAGE>

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

<PAGE>

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
<PAGE>

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

<PAGE>

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

<PAGE>


                                     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.
<TABLE>
<CAPTION>
                                                 2006                                            2005
                                -----------------------------------------------------------------------------------------

                                       PRICE RANGE          DIVIDENDS                   PRICE RANGE         DIVIDENDS
     QUARTER                        HIGH          LOW         PAID                  HIGH          LOW         PAID
-------------------------------------------------------------------------------------------------------------------------
<S>                                <C>          <C>         <C>                    <C>          <C>          <C>
     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
-------------------------------------------------------------------------------------------------------------------------
</TABLE>

COMMON STOCK  REPURCHASES.  We did not repurchase any ALLETE common stock during
the fourth quarter of 2006.

ALLETE 2006 Form 10-K                                                         28

<PAGE>

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.

<TABLE>
<CAPTION>
                                                            2006         2005         2004          2003           2002
----------------------------------------------------------------------------------------------------------------------------
MILLIONS

<S>                                                      <C>          <C>          <C>           <C>             <C>
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 <F1>    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 <F1>   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) <F2>       -               -
----------------------------------------------------------------------------------------------------------------------------

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
----------------------------------------------------------------------------------------------------------------------------
<FN>
<F1>  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.)
<F2>  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.)
</FN>
</TABLE>

29                                                         ALLETE 2006 Form 10-K
<PAGE>

<TABLE>
<CAPTION>

                                                           2006         2005             2004          2003          2002
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                      <C>          <C>             <C>           <C>           <C>
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 <F3><F4>  $1.35 <F5>    $1.05         $0.91 <F8>
     Discontinued Operations                               (0.03)       (0.16)           2.59          7.47 <F7>     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% <F3><F4>   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% <F3><F4>    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 <F2>  $ 45.7          $ 37.7        $ 32.4        $ 46.0
     Nonregulated Energy Operations                          3.7 <F2>   (48.5) <F3>      (2.9)          1.1         (11.3) <F8>
     Investment in ATC                                       1.9            -               -             -             -
     Real Estate                                            22.8         17.5            14.3          13.6          10.8
     Other                                                   2.1          2.9 <F4>      (10.6) <F5>   (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 <F7>    112.6
     Change in Accounting Principle                            -            -            (7.8) <F6>       -             -
-------------------------------------------------------------------------------------------------------------------------------

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 <F2>    11.7            11.2          11.1          11.1
     Nonregulated Energy Operations                          0.2 <F2>     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 <F2>     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 <F2>     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
-------------------------------------------------------------------------------------------------------------------------------
<FN>
<F1>  Excludes unallocated ESOP shares.
<F2>  Effective January 1, 2006, our Taconite Harbor generating  facility was  redirected  from  Nonregulated Energy Operations
      to Regulated Utility.
<F3>  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.)
<F4>  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.
<F5>  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).
<F6>  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.)
<F7>  Included a $71.6 million, or $2.59 per share, gain on the sale of the Water Services businesses.
<F8>  Included a  $5.5  million, or  $0.20  per  share, charge  related  to  the indefinite  delay of  a generation  project in
      Superior, Wisconsin.
</FN>
</TABLE>

ALLETE 2006 Form 10-K                                                         30
<PAGE>

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
<PAGE>

EXECUTIVE SUMMARY (CONTINUED)
<TABLE>
<CAPTION>
                                                                          2006 <F1>         2005              2004
----------------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT PER SHARE AMOUNTS

<S>                                                                       <C>               <C>               <C>
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 <F2>        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) <F4>
----------------------------------------------------------------------------------------------------------------------------

                                                                           $14.9              $1.1            $(12.2)
----------------------------------------------------------------------------------------------------------------------------

Income (Loss)
     Regulated Utility                                                     $46.8             $45.7            $ 37.7
     Nonregulated Energy Operations                                          3.7             (48.5) <F2>        (2.9)
     Investment in ATC                                                       1.9                 -                 -
     Real Estate                                                            22.8              17.5              14.3
     Other                                                                   2.1               2.9 <F3>        (10.6) <F4>
----------------------------------------------------------------------------------------------------------------------------

     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 <F2><F3>    $1.35 <F4>
     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% <F2><F3>     8.3%
----------------------------------------------------------------------------------------------------------------------------
<FN>
<F1>  Effective January 1, 2006, our Taconite  Harbor generating facility was redirected from Nonregulated Energy Operations
      to Regulated Utility.
<F2>  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.)
<F3>  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.
<F4>  Included an $18.5 million  ($10.9 million after tax, or $0.38 per share) debt  prepayment  cost  incurred  as  part of
      ALLETE's financial  restructuring  in  preparation  for the spin-off of Automotive Services  and an $11.5 million,  or
      $0.41 per share, gain on the sale of ADESA shares related to our ESOP.
</FN>
</TABLE>

ALLETE 2006 Form 10-K                                                         32

<PAGE>


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.

<TABLE>
<CAPTION>
KILOWATTHOURS SOLD                                                            2006             2005              2004
---------------------------------------------------------------------------------------------------------------------------
MILLIONS

<S>                                                                         <C>               <C>               <C>
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
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

33                                                         ALLETE 2006 Form 10-K

<PAGE>

EXECUTIVE SUMMARY (CONTINUED)

<TABLE>
<CAPTION>
REAL ESTATE                                2006                           2005                          2004
REVENUE AND SALES ACTIVITY          QUANTITY     AMOUNT           QUANTITY      AMOUNT          QUANTITY     AMOUNT
---------------------------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS
<S>                                 <C>          <C>              <C>           <C>             <C>          <C>
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<F1>                       51.1                           53.7                         37.3

    Revenue Recognized from
       Previously Deferred Sales                    9.7                              -                            -

    Deferred Revenue                               (3.8)                         (10.0)                        (1.5)

    Adjustments <F2>                               (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
---------------------------------------------------------------------------------------------------------------------------
<FN>
<F1>  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.)
<F2>  Contributed development dollars, which are credited to cost of real estate sold.
</FN>
</TABLE>

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

<PAGE>

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.)

<TABLE>
<CAPTION>
REAL ESTATE
PENDING CONTRACTS                                                                                      CONTRACT
AT DECEMBER 31, 2006                                          QUANTITY <F1>                           SALES PRICE
---------------------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS
<S>                                                           <C>                                     <C>
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 <F2>
     Acres                                                           196                                  10.9
---------------------------------------------------------------------------------------------------------------------

     Total Pending Land Sales Under Contract                                                            $113.8
---------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Acreage amounts are approximate and shown on a gross basis, including wetlands and minority interest. Acreage amounts may
     vary due to platting or surveying activity. Wetland amounts vary by property and are often  not formally determined prior
     to  sale. 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.
<F2> 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.
</FN>
</TABLE>

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
<PAGE>

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

<PAGE>

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

<PAGE>

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

<PAGE>

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

<PAGE>

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.

<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31                                                2006             2005              2004
-------------------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>              <C>               <C>
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
-------------------------------------------------------------------------------------------------------------------------
</TABLE>

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

<PAGE>

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

<PAGE>

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

<PAGE>

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

<PAGE>


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

<PAGE>

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

<PAGE>


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

<PAGE>

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

<PAGE>

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

<PAGE>

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.)

<TABLE>
<CAPTION>

                                                                       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
<S>                                          <C>            <C>              <C>             <C>             <C>
Long-Term Debt <F1>                          $  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
-------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Includes  interest  and  assumes  variable  interest  rate in  effect at December 31, 2006, remains constant through
     remaining term.
</FN>
</TABLE>

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.

<TABLE>
<CAPTION>
CREDIT RATINGS                                                                STANDARD & POOR'S            MOODY'S
------------------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>                          <C>
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                      -
------------------------------------------------------------------------------------------------------------------------
</TABLE>

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

<PAGE>

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

<PAGE>

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.

<TABLE>
<CAPTION>

                                                       PRINCIPAL CASH FLOW BY EXPECTED MATURITY DATE
------------------------------------------------------------------------------------------------------------------------
INTEREST RATE SENSITIVE                                                                                          FAIR
FINANCIAL INSTRUMENTS                  2007      2008      2009      2010     2011     THEREAFTER     TOTAL      VALUE
------------------------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS
<S>                                   <C>        <C>       <C>       <C>      <C>      <C>            <C>       <C>
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 - % <F1>     5.9         -       3.9       3.6        -          3.9          4.1
------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Assumes rate in effect at December 31, 2006, remains constant through remaining term.
</FN>
</TABLE>

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

<PAGE>

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

<PAGE>

                                    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

<PAGE>

                                     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

<PAGE>

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

<PAGE>

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

<PAGE>

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

<PAGE>

                                   SIGNATURES

Pursuant to the  requirements of Section 13 or 15(d) of the Securities  Exchange
Act of 1934,  the  registrant  has duly  caused  this report to be signed on its
behalf by the undersigned, thereunto duly authorized.

                                                       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.

<TABLE>
<CAPTION>

                SIGNATURE                                          TITLE                                   DATE
------------------------------------------------------------------------------------------------------------------------------------
<S>                                          <C>                                                   <C>


            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

</TABLE>

ALLETE 2006 Form 10-K                                                         58

<PAGE>

             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

<PAGE>

                                             CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
ALLETE CONSOLIDATED BALANCE SHEET
<CAPTION>
DECEMBER 31                                                                           2006                       2005
-----------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                                 <C>                        <C>
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.
</TABLE>

ALLETE 2006 Form 10-K                                                         60

<PAGE>

<TABLE>
ALLETE CONSOLIDATED STATEMENT OF INCOME
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31                                                2006                2005              2004
-----------------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT PER SHARE AMOUNTS
<S>                                                                         <C>                 <C>               <C>
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.
</TABLE>

61                                                         ALLETE 2006 Form 10-K

<PAGE>
<TABLE>
ALLETE CONSOLIDATED STATEMENT OF CASH FLOWS
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31                                                2006                2005              2004
-----------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                         <C>                 <C>               <C>
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 <F1>                             $  44.8             $  89.6           $  46.1
-----------------------------------------------------------------------------------------------------------------------------
<FN>
<F1>  Included $2.4 million of cash from Discontinued Operations at December 31, 2004.
</FN>

                               The accompanying notes are an integral part of these statements.
</TABLE>

ALLETE 2006 Form 10-K                                                         62

<PAGE>

<TABLE>
ALLETE CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
<CAPTION>
                                                                                ACCUMULATED
                                                     TOTAL                         OTHER         UNEARNED
                                                 SHAREHOLDERS'    RETAINED     COMPREHENSIVE       ESOP         COMMON
                                                    EQUITY        EARNINGS     INCOME (LOSS)      SHARES         STOCK
-----------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                              <C>              <C>          <C>               <C>            <C>
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.
</TABLE>

63                                                         ALLETE 2006 Form 10-K

<PAGE>

                   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.)

<TABLE>
<CAPTION>
                                                                       ENERGY
                                                       -------------------------------------
                                                                  NONREGULATED
                                                       REGULATED     ENERGY       INVESTMENT     REAL
                                       CONSOLIDATED     UTILITY    OPERATIONS       IN ATC      ESTATE        OTHER
-----------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                    <C>             <C>        <C>             <C>           <C>          <C>
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             -            -            -
-----------------------------------------------------------------------------------------------------------------------
</TABLE>

ALLETE 2006 Form 10-K                                                         64

<PAGE>

NOTE 1.    BUSINESS SEGMENTS (CONTINUED)

<TABLE>
<CAPTION>
                                                                       ENERGY
                                                       -------------------------------------
                                                                  NONREGULATED
                                                       REGULATED     ENERGY       INVESTMENT     REAL
                                      CONSOLIDATED      UTILITY    OPERATIONS       IN ATC      ESTATE        OTHER
-----------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                   <C>              <C>        <C>             <C>           <C>          <C>

2005

Operating Revenue                          $737.4        $575.6      $113.9            -         $47.5       $  0.4
Fuel and Purchased Power                    273.1         243.7        29.4            -             -            -
Operating and Maintenance                   293.5         202.9        71.2            -          15.5          3.9
Kendall County Charge                        77.9             -        77.9            -             -            -
Depreciation Expense                         47.8          39.4         8.1            -           0.1          0.2
-----------------------------------------------------------------------------------------------------------------------

Operating Income (Loss) from
     Continuing Operations                   45.1          89.6       (72.7)           -          31.9         (3.7)
Interest Expense                            (26.4)        (17.4)       (6.6)           -          (0.1)        (2.3)
Other Income (Expense)                        1.1           0.7         1.7            -             -         (1.3)
-----------------------------------------------------------------------------------------------------------------------

Income (Loss) from
     Continuing Operations Before
     Minority Interest and Income Taxes      19.8          72.9       (77.6)           -          31.8         (7.3)
Minority Interest                             2.7             -           -            -           2.7            -
-----------------------------------------------------------------------------------------------------------------------

Income (Loss) from
     Continuing Operations
     Before Income Taxes                     17.1          72.9       (77.6)           -          29.1         (7.3)
Income Tax Expense (Benefit)                 (0.5)         27.2       (29.1)           -          11.6        (10.2)
-----------------------------------------------------------------------------------------------------------------------

Income (Loss) from Continuing Operations     17.6        $ 45.7      $(48.5)           -         $17.5       $  2.9
                                                       ----------------------------------------------------------------
Loss from Discontinued Operations -
     Net of Tax                              (4.3)
----------------------------------------------------

Net Income                                 $ 13.3
----------------------------------------------------

Total Assets                             $1,398.8 <F1>   $909.5      $185.2            -         $73.7       $227.8
Capital Additions                           $63.1 <F1>    $46.5       $12.1            -             -            -
-----------------------------------------------------------------------------------------------------------------------


2004

Operating Revenue                          $704.1        $555.0      $106.8            -         $41.9       $  0.4
Fuel and Purchased Power                    286.2         245.1        41.1            -             -            -
Operating and Maintenance                   270.1         191.7        60.3            -          15.0          3.1
Depreciation Expense                         46.9          39.5         7.2            -           0.1          0.1
-----------------------------------------------------------------------------------------------------------------------

Operating Income (Loss)
     from Continuing Operations             100.9          78.7        (1.8)           -          26.8         (2.8)
Interest Expense                            (31.7)        (18.5)       (4.9)           -          (0.3)        (8.0)
Other Income (Expense)                      (12.2)          0.1         0.6            -             -        (12.9)
-----------------------------------------------------------------------------------------------------------------------

Income (Loss) from
     Continuing Operations Before
     Minority Interest and Income Taxes      57.0          60.3        (6.1)           -          26.5        (23.7)
Minority Interest                             2.1             -           -            -           2.1            -
-----------------------------------------------------------------------------------------------------------------------

Income (Loss) from Continuing Operations
     Before Income Taxes                     54.9          60.3        (6.1)           -          24.4        (23.7)
Income Tax Expense (Benefit)                 16.4          22.6        (3.2)           -          10.1        (13.1)
-----------------------------------------------------------------------------------------------------------------------

Income (Loss) from Continuing Operations     38.5        $ 37.7      $ (2.9)           -         $14.3       $(10.6)
                                                       ----------------------------------------------------------------

Income from Discontinued Operations -
     Net of Tax                              73.7

Change in Accounting Principle -
     Net of Tax                              (7.8)
----------------------------------------------------

Net Income                                 $104.4
----------------------------------------------------

Total Assets                             $1,431.4 <F1>   $902.8      $161.4            -         $75.1       $242.6
Capital Additions                           $79.2 <F1>    $41.7       $15.7            -             -         $0.4
-----------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Discontinued Operations represented $2.6 million of total assets in 2005($49.5 million in 2004) and $4.5  million
     of capital additions in 2005 ($21.4 million in 2004).
</FN>
</TABLE>

65                                                         ALLETE 2006 Form 10-K

<PAGE>

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

<PAGE>

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.

<TABLE>
<CAPTION>
ACCOUNTS RECEIVABLE
DECEMBER 31                                                                           2006                     2005
--------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                                   <C>                      <C>
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
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

67                                                         ALLETE 2006 Form 10-K

<PAGE>

NOTE 2.    OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

INVENTORIES. Inventories are stated at the lower of cost or market.

<TABLE>
<CAPTION>
INVENTORIES
DECEMBER 31                                                                           2006                     2005
--------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                                   <C>                      <C>
Fuel                                                                                  $18.9                    $11.0
Materials and Supplies                                                                 24.5                     22.1
--------------------------------------------------------------------------------------------------------------------------

Total Inventories                                                                     $43.4                    $33.1
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

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.

<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF CASH FLOWS
SUPPLEMENTAL DISCLOSURE
FOR THE YEAR ENDED DECEMBER 31                                                2006                2005            2004
--------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                           <C>                 <C>            <C>
Cash Paid During the Period for
     Interest - Net of Amounts Capitalized                                    $25.3               $24.6          $41.2
     Income Taxes                                                             $34.5 <F1>          $27.1          $75.7

Noncash Investing Activities
     Accounts Payable for Capital Additions to
         Property Plant and Equipment                                          $7.1                   -              -
--------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Net of a $24.3 million cash refund.
</FN>
</TABLE>

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

<PAGE>

NOTE 2.    OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

<TABLE>
<CAPTION>
PREPAYMENTS AND OTHER CURRENT ASSETS
DECEMBER 31                                                                           2006                     2005
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                                   <C>                      <C>
Deferred Fuel Adjustment Clause                                                       $15.1                    $13.5
Other                                                                                   8.7                     10.3
---------------------------------------------------------------------------------------------------------------------------

Total Prepayments and Other Current Assets                                            $23.8                    $23.8
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
OTHER ASSETS
DECEMBER 31                                                                           2006                     2005
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                                  <C>                       <C>
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
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
OTHER LIABILITIES
DECEMBER 31                                                                           2006                     2005
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                                  <C>                      <C>
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
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

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

<PAGE>

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

<TABLE>
<CAPTION>
PROPERTY, PLANT AND EQUIPMENT
DECEMBER 31                                                                           2006 <F1>                2005
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                                 <C>                      <C>
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
---------------------------------------------------------------------------------------------------------------------------
<FN>
<F1>  Effective January 1, 2006, our Taconite Harbor generating facility was redirected from Nonregulated Energy Operations
      to Regulated Utility.
</FN>
</TABLE>

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.

<TABLE>
<CAPTION>
ESTIMATED USEFUL LIVES OF PROPERTY, PLANT AND EQUIPMENT
---------------------------------------------------------------------------------------------------------------------------
<S>                                        <C>                     <C>                                     <C>
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
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

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.

<TABLE>
<CAPTION>
ASSET RETIREMENT OBLIGATION
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                                                          <C>
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
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

ALLETE 2006 Form 10-K                                                         70

<PAGE>

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.

<TABLE>
<CAPTION>
DEFERRED REGULATORY CHARGES AND CREDITS
DECEMBER 31                                                                            2006                    2005
------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                                   <C>                     <C>
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)
------------------------------------------------------------------------------------------------------------------------
</TABLE>


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

<PAGE>

NOTE 6.    INVESTMENTS (CONTINUED)

<TABLE>
<CAPTION>
AVAILABLE-FOR-SALE SECURITIES
-------------------------------------------------------------------------------------------------------------------------
MILLIONS
                                                                  GROSS UNREALIZED
AT DECEMBER 31                       COST                      GAIN             (LOSS)                  FAIR VALUE
-------------------------------------------------------------------------------------------------------------------------
<S>                                 <C>                        <C>              <C>                     <C>
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
-------------------------------------------------------------------------------------------------------------------------
<CAPTION>
                                                                                                            NET
                                                                                                        UNREALIZED
                                                                                                        GAIN (LOSS)
                                                                                                         IN OTHER
YEAR ENDED                           SALES                         GROSS REALIZED                      COMPREHENSIVE
DECEMBER 31                        PROCEEDS                    GAIN             (LOSS)                    INCOME
-------------------------------------------------------------------------------------------------------------------------
<S>                                <C>                        <C>               <C>                    <C>
2006                                 $12.4                        -                 -                       $2.7
2005                                 $32.3                        -                 -                       $1.3
2004                                 $65.9                    $11.5                 -                       $1.6
-------------------------------------------------------------------------------------------------------------------------
</TABLE>

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.

<TABLE>
<CAPTION>
INVESTMENTS
DECEMBER 31                                                                           2006                     2005
-------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                                  <C>                     <C>
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
-------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
REAL ESTATE ASSETS                                                                    2006                     2005
-------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                                   <C>                      <C>
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 <F1>                                                                             13.5                     18.3
-------------------------------------------------------------------------------------------------------------------------

Total Real Estate Assets                                                              $89.8                    $73.7
-------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Consisted primarily of a shopping center.
</FN>
</TABLE>


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

<PAGE>

NOTE 6.    INVESTMENTS (CONTINUED)

<TABLE>
<CAPTION>
ALLETE'S INTEREST IN ATC
FOR THE YEAR ENDED DECEMBER 31, 2006
-----------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                                         <C>
Equity in Earnings                                                                           $3.0
Accumulated Equity in Undistributed Earnings                                                 $2.3
Equity Investment Balance                                                                   $53.7
Equity Ownership                                                                               7%
-----------------------------------------------------------------------------------------------------
</TABLE>

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.


<TABLE>
<CAPTION>
FINANCIAL INSTRUMENTS
DECEMBER 31                                          CARRYING AMOUNT           FAIR VALUE
-----------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                  <C>                       <C>
Long-Term Debt
    2006                                                 $389.5                   $387.6
    2005                                                 $390.5                   $392.5
-----------------------------------------------------------------------------------------------------
</TABLE>

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

<PAGE>

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.

<TABLE>
<CAPTION>
LONG-TERM DEBT
DECEMBER 31                                                                           2006                     2005
-----------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                                  <C>                      <C>
First Mortgage Bonds
     6.68% Series Due 2007                                                           $ 20.0                   $ 20.0
     7% Series Due 2007 <F1>                                                           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
-----------------------------------------------------------------------------------------------------------------------
<FN>
<F1>  Retired on February 15, 2007.
</FN>
</TABLE>

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

<PAGE>

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

<PAGE>

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

<PAGE>

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

<PAGE>

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.

<TABLE>
<CAPTION>
SUMMARY OF COMMON STOCK                                                               SHARES                 EQUITY
--------------------------------------------------------------------------------------------------------------------------
                                                                                     THOUSANDS               MILLIONS
<S>                                                                                  <C>                     <C>
Balance at December 31, 2003                                                          29,099                  $859.2
2004     Employee Stock Purchase Plan                                                     14                     1.0
         Invest Direct <F1>                                                              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 <F1>                                                              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 <F1>                                                              218                    10.0
         Options and Stock Awards                                                         63                     7.1
--------------------------------------------------------------------------------------------------------------------------

Balance at December 31, 2006                                                          30,436                  $438.7
--------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Invest Direct is ALLETE's direct stock purchase and dividend reinvestment plan.
</FN>
</TABLE>

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

<PAGE>

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).

<TABLE>
<CAPTION>
RECONCILIATION OF BASIC AND DILUTED
EARNINGS PER SHARE                                                                     DILUTIVE
FOR THE YEAR ENDED DECEMBER 31                                    BASIC               SECURITIES              DILUTED
---------------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT PER SHARE AMOUNTS
<S>                                                               <C>                 <C>                     <C>
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
---------------------------------------------------------------------------------------------------------------------------
</TABLE>


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

<PAGE>

NOTE 11.   OTHER INCOME (EXPENSE)

<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31                                                2006             2005              2004
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                          <C>              <C>               <C>
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)
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

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

<TABLE>
<CAPTION>
INCOME TAX EXPENSE
YEAR ENDED DECEMBER 31                                                       2006               2005              2004
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                         <C>                <C>               <C>
Current Tax Expense
     Federal                                                                $ 8.9 <F1>         $  27.2 <F2>      $11.2
     State                                                                    9.6                  6.5 <F2>        6.3
---------------------------------------------------------------------------------------------------------------------------

         Total Current Tax Expense                                           18.5                 33.7            17.5
---------------------------------------------------------------------------------------------------------------------------

Deferred Tax Expense (Benefit)
     Federal                                                                 28.0 <F1>           (26.4) <F2>       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
---------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> 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.)
<F2> 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.)
</FN>
</TABLE>

ALLETE 2006 Form 10-K                                                         80

<PAGE>

NOTE 12.   INCOME TAX EXPENSE (CONTINUED)

<TABLE>
<CAPTION>
RECONCILIATION OF TAXES FROM FEDERAL STATUTORY
RATE TO TOTAL INCOME TAX EXPENSE FOR CONTINUING OPERATIONS
YEAR ENDED DECEMBER 31                                                        2006             2005              2004
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                          <C>               <C>               <C>
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
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

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.

<TABLE>
<CAPTION>
DEFERRED TAX ASSETS AND LIABILITIES
DECEMBER 31                                                                                    2006              2005
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                                           <C>              <C>
Deferred Tax Assets
     Employee Benefits and Compensation <F1>                                                  $ 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 <F2>                                                    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
---------------------------------------------------------------------------------------------------------------------------
<FN>
<F1>  Included Unfunded Employee Benefits
<F2>  Included impairments related to the emerging technology portfolio.
</FN>
</TABLE>

81                                                         ALLETE 2006 Form 10-K

<PAGE>

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

<PAGE>


NOTE 13.   DISCONTINUED OPERATIONS (CONTINUED)

<TABLE>
<CAPTION>
DISCONTINUED OPERATIONS
SUMMARY INCOME STATEMENT
FOR THE YEAR ENDED DECEMBER 31                                                2006             2005               2004
-------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                          <C>               <C>               <C>
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
-------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
DISCONTINUED OPERATIONS
SUMMARY BALANCE SHEET INFORMATION
DECEMBER 31                                                                                    2005
-------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                                            <C>
Assets of Discontinued Operations
     Other Current Assets                                                                       $0.4
     Property, Plant and Equipment                                                              $2.2

Liabilities of Discontinued Operations
     Current Liabilities                                                                       $13.0
-------------------------------------------------------------------------------------------------------------------------
</TABLE>

83                                                         ALLETE 2006 Form 10-K

<PAGE>

NOTE 14.   OTHER COMPREHENSIVE INCOME (LOSS)

<TABLE>
<CAPTION>
OTHER COMPREHENSIVE INCOME (LOSS)                             PRE-TAX              TAX EXPENSE            NET-OF-TAX
YEAR ENDED DECEMBER 31                                        AMOUNT                (BENEFIT)               AMOUNT
-------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                            <C>                 <C>                    <C>
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)
-------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
DECEMBER 31                                                                2006                  2005
-------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                       <C>                  <C>
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)
-------------------------------------------------------------------------------------------------------------------------
</TABLE>


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

<PAGE>

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.

<TABLE>
<CAPTION>
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
<S>                                                                        <C>              <C>                <C>
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
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

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

<PAGE>


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.

<TABLE>
<CAPTION>
PENSION OBLIGATION AND FUNDED STATUS
AT SEPTEMBER 30                                                                   2006                       2005
---------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                              <C>                        <C>
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
---------------------------------------------------------------------------------------------------------------------
</TABLE>

The pension costs reported on our consolidated balance sheet as regulatory
long-term assets and accumulated other comprehensive income consist of the
following:

<TABLE>
<CAPTION>
PENSION COSTS
YEAR ENDED DECEMBER 31                                                                                        2006
---------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                                                          <C>
Net Loss                                                                                                     $69.9
Prior Service Cost                                                                                             3.9
Transition Obligation                                                                                         (0.1)
---------------------------------------------------------------------------------------------------------------------

                                                                                                             $73.7
---------------------------------------------------------------------------------------------------------------------
</TABLE>

ALLETE 2006 Form 10-K                                                         86

<PAGE>

NOTE 16.   PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (CONTINUED)

<TABLE>
<CAPTION>
COMPONENTS OF NET PERIODIC PENSION EXPENSE (INCOME)
YEAR ENDED DECEMBER 31                                                       2006              2005               2004
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                          <C>               <C>               <C>
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
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
INFORMATION FOR PENSION PLANS WITH AN
ACCUMULATED BENEFIT OBLIGATION IN EXCESS OF PLAN ASSETS
AT SEPTEMBER 30                                                                   2006                       2005
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                              <C>                        <C>
Projected Benefit Obligation                                                     $180.4                     $177.5
Accumulated Benefit Obligation                                                   $160.6                     $157.7
Fair Value of Plan Assets                                                        $130.9                     $116.3
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
ADDITIONAL PENSION INFORMATION
YEAR ENDED DECEMBER 31                                                        2006              2005             2004
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                          <C>               <C>              <C>
Increase (Decrease) in Additional Pension Liability
      Included in Other Comprehensive Income                                 $11.0             $(3.4)           $(5.7)
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

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.

<TABLE>
<CAPTION>
POSTRETIREMENT HEALTH AND LIFE OBLIGATION AND FUNDED STATUS
AT SEPTEMBER 30                                                                   2006                        2005
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                              <C>                         <C>
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)
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

87                                                         ALLETE 2006 Form 10-K

<PAGE>

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:

<TABLE>
<CAPTION>
POSTRETIREMENT HEALTH AND LIFE COSTS
YEAR ENDED DECEMBER 31                                                                                       2006
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                                                          <C>
Net Loss                                                                                                     $19.2
Prior Service Cost                                                                                            (0.1)
Transition Obligation                                                                                         15.0
---------------------------------------------------------------------------------------------------------------------------

                                                                                                             $34.1
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
COMPONENTS OF NET PERIODIC POSTRETIREMENT HEALTH AND LIFE EXPENSE
YEAR ENDED DECEMBER 31                                                        2006              2005             2004
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                          <C>               <C>              <C>
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
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
                                                                                                       POSTRETIREMENT
ESTIMATED FUTURE BENEFIT PAYMENTS                                                PENSION               HEALTH AND LIFE
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                              <C>                   <C>
2007                                                                               $20                        $5
2008                                                                               $21                        $5
2009                                                                               $22                        $6
2010                                                                               $22                        $7
2011                                                                               $23                        $7
Years 2012 - 2016                                                                 $138                       $45
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

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:

<TABLE>
<CAPTION>
                                                                                                       POSTRETIREMENT
                                                                                 PENSION               HEALTH AND LIFE
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                              <C>                   <C>
Net Loss (Gain)                                                                    $3.4                      $0.9
Prior Service Costs                                                                $0.7                         -
Transition Obligations                                                            $(0.1)                     $2.5
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

ALLETE 2006 Form 10-K                                                         88

<PAGE>

NOTE 16.   PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (CONTINUED)

<TABLE>
<CAPTION>
WEIGHTED-AVERAGE ASSUMPTIONS
USED TO DETERMINE BENEFIT OBLIGATION
AT SEPTEMBER 30                                                                   2006                      2005
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>                        <C>
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
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
WEIGHTED-AVERAGE ASSUMPTIONS
USED TO DETERMINE NET PERIODIC BENEFIT COSTS
YEAR ENDED DECEMBER 31                                                    2006               2005            2004
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>               <C>               <C>
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%
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

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.

<TABLE>
<CAPTION>
SENSITIVITY OF A ONE-PERCENTAGE-POINT                                          ONE PERCENT               ONE PERCENT
CHANGE IN HEALTH CARE TREND RATES                                               INCREASE                  DECREASE
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                            <C>                       <C>
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)
---------------------------------------------------------------------------------------------------------------------------
</TABLE>


<TABLE>
<CAPTION>
                                                                                                 POSTRETIREMENT
                                                           PENSION                             HEALTH AND LIFE <F1>
PLAN ASSET ALLOCATIONS                              2006            2005                      2006             2005
---------------------------------------------------------------------------------------------------------------------------
<S>                                                <C>             <C>                       <C>              <C>
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%
---------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Included VEBAs and irrevocable grantor trust.
</FN>
</TABLE>

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

<PAGE>

NOTE 16.   PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (CONTINUED)

<TABLE>
<CAPTION>
                                                                                                   POSTRETIREMENT
PLAN ASSET TARGET ALLOCATIONS                                       PENSION                      HEALTH AND LIFE <F1>
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>                          <C>
Equity Securities                                                     60%                                69%
Debt Securities                                                       24                                 30
Real Estate                                                            9                                  -
Venture Capital                                                        6                                  -
Cash                                                                   1                                  1
---------------------------------------------------------------------------------------------------------------------------

                                                                     100%                               100%
---------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> Included VEBAs and irrevocable grantor trust.
</FN>
</TABLE>

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.

<TABLE>
<CAPTION>
SUMMARY OF ALLETE COMMON STOCK PURCHASES                                     SHARES                    AMOUNT
-----------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT SHARES
<S>                                                                        <C>                         <C>
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
-----------------------------------------------------------------------------------------------------------------------
</TABLE>

ALLETE 2006 Form 10-K                                                         90

<PAGE>

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.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31                                                        2006              2005              2004
---------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                          <C>               <C>               <C>
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
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

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:

<TABLE>
<CAPTION>
                                                                     2006
--------------------------------------------------------------------------------
<S>                                                                 <C>
     Risk-Free Interest Rate                                           4.5%
     Expected Life                                                  5 Years
     Expected Volatility                                                20%
     Dividend Growth Rate                                                5%
--------------------------------------------------------------------------------
</TABLE>

91                                                         ALLETE 2006 Form 10-K

<PAGE>

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.

<TABLE>
<CAPTION>
SHARE-BASED COMPENSATION EXPENSE
FOR THE YEAR ENDED DECEMBER 31                                                                                  2006
-----------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                                                                             <C>
Stock Options                                                                                                   $0.8
Performance Shares                                                                                               1.0
-----------------------------------------------------------------------------------------------------------------------

Total Share-Based Compensation Expense                                                                          $1.8
-----------------------------------------------------------------------------------------------------------------------

Income Tax Benefit                                                                                              $0.7
-----------------------------------------------------------------------------------------------------------------------
</TABLE>

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.

<TABLE>
<CAPTION>
PRO FORMA EFFECT OF SFAS 123
ACCOUNTING FOR STOCK-BASED COMPENSATION                                               2005                     2004
-----------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT PER SHARE AMOUNTS
<S>                                                                                   <C>                     <C>
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
-----------------------------------------------------------------------------------------------------------------------
</TABLE>

ALLETE 2006 Form 10-K                                                         92

<PAGE>


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:

<TABLE>
<CAPTION>
                                                                                      2005                     2004
-----------------------------------------------------------------------------------------------------------------------
<S>                                                                                  <C>                     <C>
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%
-----------------------------------------------------------------------------------------------------------------------
</TABLE>

The following table presents information regarding our outstanding stock options
for the year ended December 31, 2006.

<TABLE>
<CAPTION>

                                                                                                      WEIGHTED-AVERAGE
                                                             WEIGHTED-AVERAGE        AGGREGATE            REMAINING
                                             NUMBER OF           EXERCISE            INTRINSIC           CONTRACTUAL
                                              OPTIONS              PRICE               VALUE                TERM
--------------------------------------------------------------------------------------------------------------------------
                                                                                     MILLIONS
<S>                                          <C>             <C>                     <C>              <C>
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
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

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.

<TABLE>
<CAPTION>
                                                                                                          2005
                                                                                                --------------------------
                                                                                                              WEIGHTED
                                                                                                               AVERAGE
                                                                                                              EXERCISE
STOCK OPTION ACTIVITY                                                                            OPTIONS        PRICE
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                                              <C>          <C>
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
--------------------------------------------------------------------------------------------------------------------------
</TABLE>



93                                                         ALLETE 2006 Form 10-K

<PAGE>

NOTE 17.   EMPLOYEE STOCK AND INCENTIVE PLANS (CONTINUED)

<TABLE>
<CAPTION>
                                                                                                          2004
                                                                                                --------------------------
                                                                                                              WEIGHTED
                                                                                                               AVERAGE
                                                                                                              EXERCISE
STOCK OPTION ACTIVITY <F1>                                                                       OPTIONS        PRICE
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                                             <C>           <C>
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
--------------------------------------------------------------------------------------------------------------------------
<FN>
<F1>  All amounts above are prior to the ADESA spin-off and the historical option and  weighted  average  exercise  prices
      have  been  adjusted for the one-for-three reverse stock split on September 20, 2004. The 2004 amounts are up to the
      September 20, 2004, spin-off of ADESA.
</FN>
</TABLE>

<TABLE>
<CAPTION>

                                                                                                          2004
                                                                                                --------------------------
                                                                                                              WEIGHTED
                                                                                                               AVERAGE
                                                                                                              EXERCISE
STOCK OPTION ACTIVITY <F1>                                                                       OPTIONS        PRICE
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                                              <C>          <C>
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
--------------------------------------------------------------------------------------------------------------------------
<FN>
<F1>  Amounts subsequent to the ADESA spin-off.
</FN>
</TABLE>

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.

<TABLE>
<CAPTION>
                                                                                                      WEIGHTED-AVERAGE
                                                                                    NUMBER OF            GRANT DATE
                                                                                     SHARES              FAIR VALUE
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>               <C>
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
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

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

<PAGE>


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.

<TABLE>
<CAPTION>

QUARTER ENDED                                               MAR. 31          JUN. 30          SEPT. 30         DEC. 31
--------------------------------------------------------------------------------------------------------------------------
MILLIONS EXCEPT EARNINGS PER SHARE
<S>                                                         <C>              <C>              <C>              <C>
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
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

95                                                         ALLETE 2006 Form 10-K

<PAGE>


                                                                     SCHEDULE II
<TABLE>
ALLETE
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
<CAPTION>


                                                     BALANCE AT          ADDITIONS            DEDUCTIONS   BALANCE AT
                                                      BEGINNING     CHARGED       OTHER          FROM        END OF
FOR THE YEAR ENDED DECEMBER 31                         OF YEAR     TO INCOME     CHANGES     RESERVES <F1>   PERIOD
--------------------------------------------------------------------------------------------------------------------------
MILLIONS
<S>                                                  <C>           <C>           <C>         <C>           <C>
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
--------------------------------------------------------------------------------------------------------------------------
<FN>
<F1>  Included uncollectible accounts written off.
</FN>
</TABLE>

ALLETE 2006 Form 10-K                                                         96

<PAGE>
                                  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