ALLETE
ALLETE INC (Form: 10-Q, Received: 08/05/2009 08:04:41)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

 
FORM 10-Q

(Mark One)
 
T
Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the quarterly period ended June 30, 2009
 
or
 
£
Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the transition period from ______________ to ______________


Commission File Number 1-3548

ALLETE, Inc.
 (Exact name of registrant as specified in its charter)

Minnesota
 
41-0418150
(State or other jurisdiction of incorporation or organization)
 
(IRS Employer Identification No.)

30 West Superior Street
Duluth, Minnesota 55802-2093
(Address of principal executive offices)
(Zip Code)

(218) 279-5000
(Registrant’s telephone number, including area code)

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.      T Yes      £ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    £ Yes      £ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer T
Accelerated Filer £
Non-Accelerated Filer £
Smaller Reporting Company  £

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).      £ Yes      T No
Common Stock, no par value,
34,100,096 shares outstanding
as of June 30, 2009

 
 
 
 

 

INDEX

     
Page
       
   
       
       
 
       
   
       
   
   
       
   
   
       
   
   
       
 
       
 
       
 
       
 
       
 
       
 
       
 
       
 
       
 
       
 
       
 
       
 
       
   


 
 
ALLETE Second Quarter 2009 Form 10-Q
 
2

 

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
AFUDC
Allowance for Funds Used During Construction – consisting of the cost of both the debt and equity funds used to finance utility plant additions during construction periods
ALLETE
ALLETE, Inc.
ALLETE Properties
ALLETE Properties, LLC and its subsidiaries
APB
Accounting Principles Board
AREA
Arrowhead Regional Emission Abatement
ARS
Auction Rate Securities
ATC
American Transmission Company LLC
BNI Coal
BNI Coal, Ltd.
BNSF
BNSF Railway Company
Boswell
Boswell Energy Center
Company
ALLETE, Inc. and its subsidiaries
DC
Direct Current
EITF
Emerging Issues Task Force
EPA
Environmental Protection Agency
ESOP
Employee Stock Ownership Plan
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
Form 10-K
ALLETE Annual Report on Form 10-K
Form 10-Q
ALLETE Quarterly Report on Form 10-Q
FSP
FASB Staff Position
FTR
Financial Transmission Rights
GAAP
United States Generally Accepted Accounting Principles
GHG
Greenhouse Gases
IBEW Local 31
International Brotherhood of Electrical Workers Local 31
Invest Direct
ALLETE’s Direct Stock Purchase and Dividend Reinvestment Plan
kV
Kilovolt(s)
Laskin
Laskin Energy Center
Minnesota Power
An operating division of ALLETE, Inc.
Minnkota Power
Minnkota Power Cooperative, Inc.
MISO
Midwest Independent Transmission System Operator, Inc.
MPCA
Minnesota Pollution Control Agency
MPUC
Minnesota Public Utilities Commission
MW / MWh
Megawatt(s) / Megawatt-hour(s)
Non-residential
Retail commercial, non-retail commercial, office, industrial, warehouse, storage and institutional
NO X
Nitrogen Oxide
Note ___
Note ___ to the consolidated financial statements in this Form 10-Q
OES
Minnesota Office of Energy
Oliver Wind I
Oliver Wind I Energy Center
Oliver Wind II
Oliver Wind II Energy Center

 
 
ALLETE Second Quarter 2009 Form 10-Q
 
3

 

Definitions (Continued)
Abbreviation or Acronym
Term
Palm Coast Park
Palm Coast Park development project in Florida
Palm Coast Park District
Palm Coast Park Community Development District
PSCW
Public Service Commission of Wisconsin
Rainy River Energy
Rainy River Energy Corporation - Wisconsin
SEC
Securities and Exchange Commission
SFAS
Statement of Financial Accounting Standards No.
SO 2
Sulfur Dioxide
Square Butte
Square Butte Electric Cooperative
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

 
ALLETE Second Quarter 2009 Form 10-Q
 
4

 

Safe Harbor Statement
Under the Private Securities Litigation Reform Act of 1995

Statements in this report that are not statements of historical facts may be considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. Any statements that express, or involve discussions as to, future expectations, risks, beliefs, plans, objectives, assumptions, events, uncertainties, financial performance, or growth strategies (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 words of similar meaning) are not statements of historical facts and may be forward-looking.

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, or expectations suggested, in forward-looking statements made by or on behalf of ALLETE in this Quarterly Report on Form 10-Q, in presentations, on our website, in response to questions or otherwise. 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 in connection with such forward-looking statements:

·
our ability to successfully implement our strategic objectives;
·
our ability to manage expansion and integrate acquisitions;
·
prevailing governmental policies, regulatory actions, and legislation 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, capital investments and other expenses, present or prospective wholesale and retail competition (including but not limited to transmission costs), zoning and permitting of land held for resale and environmental matters;
·
the potential impacts of climate change and future regulation to restrict the emissions of GHG on our Regulated Operations ;
·
effects of restructuring initiatives in the electric industry;
·
economic and geographic factors, including political and economic risks;
·
changes in and compliance with laws and regulations;
·
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;
·
project delays or changes in project costs;
·
availability and management   of construction materials and skilled construction labor for capital projects;
·
changes in operating expenses , capital and land development expenditures;
·
global and domestic economic conditions affecting us or our customers;
·
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 20 of our 2008 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-Q and in our other reports filed with the SEC that attempt to advise interested parties of the factors that may affect our business.

 
ALLETE Second Quarter 2009 Form 10-Q
 
5

 

 
PART I.  FINANCIAL INFORMATION
 
ITEM 1.  FINANCIAL STATEMENTS

ALLETE
CONSOLIDATED BALANCE SHEET
Millions – Unaudited
     
June 30,
 December 31,
     
2009
2008
         
Assets
     
Current Assets
   
 
Cash and Cash Equivalents
$72.4
$102.0
 
Accounts Receivable (Less Allowance of $0.7 at June 30, 2009
   
   
and $0.7 at December 31, 2008)
80.7
76.3
 
Inventories
53.6
49.7
 
Prepayments and Other
25.7
24.3
   
Total Current Assets
232.4
252.3
Property, Plant and Equipment - Net
1,481.7
1,387.3
Investment in ATC
82.1
76.9
Other Investments
135.6
136.9
Other Assets
285.8
281.4
Total Assets
$2,217.6
$2,134.8
         
Liabilities and Equity
   
Liabilities
   
Current Liabilities
   
 
Accounts Payable
$59.0
$75.7
 
Accrued Taxes
15.8
12.9
 
Accrued Interest
12.0
8.9
 
Long-Term Debt Due Within One Year
13.0
10.4
 
Notes Payable
6.0
6.0
 
Other
40.1
36.8
   
Total Current Liabilities
145.9
150.7
Long-Term Debt
627.2
588.3
Deferred Income Taxes
199.3
169.6
Other Liabilities
360.4
389.3
 
Total Liabilities
1,332.8
1,297.9
         
Commitments and Contingencies (Note 14)
   
         
Equity
   
ALLETE’s Equity
   
Common Stock Without Par Value, 80.0 Shares Authorized, 34.1 and 32.6
   
 
Shares Outstanding
575.1
534.1
Unearned ESOP Shares
(48.3)
(54.9)
Accumulated Other Comprehensive Loss
(31.6)
(33.0)
Retained Earnings
380.0
380.9
 
Total ALLETE’s Equity
875.2
827.1
Non-Controlling Interest in Subsidiaries
9.6
9.8
 
Total Equity
884.8
836.9
Total Liabilities and Equity
$2,217.6
$2,134.8



The accompanying notes are an integral part of these statements.

 
ALLETE Second Quarter 2009 Form 10-Q
 
6

 

ALLETE
CONSOLIDATED STATEMENT OF INCOME
Millions Except Per Share Amounts – Unaudited
     
        Quarter Ended
 
         Six Months Ended
     
               June 30,
 
        June 30,
     
           2009
           2008
 
           2009
           2008
               
Operating Revenue
         
 
Operating Revenue
$167.0
$189.8
 
$371.9
$403.2
 
Prior Year Rate Refunds
(2.3)
 
(7.6)
   
Total Operating Revenue
164.7
189.8
 
364.3
403.2
               
Operating Expenses
         
 
Fuel and Purchased Power
56.8
75.0
 
129.6
161.3
 
Operating and Maintenance
76.7
84.4
 
157.2
167.5
 
Depreciation
15.5
12.9
 
30.7
25.6
   
Total Operating Expenses
149.0
172.3
 
317.5
354.4
               
Operating Income
15.7
17.5
 
46.8
48.8
               
Other Income (Expense)
         
 
Interest Expense
(8.4)
(6.6)
 
(17.1)
(12.6)
 
Equity Earnings in ATC
4.3
3.6
 
8.5
7.0
 
Other
1.9
2.5
 
3.0
11.1
   
Total Other Income (Expense)
(2.2)
(0.5)
 
(5.6)
5.5
               
Income Before Non-Controlling Interest and  Income Taxes
13.5
17.0
 
41.2
54.3
Income Tax Expense
4.2
6.2
 
15.0
19.9
Net Income
9.3
10.8
 
26.2
34.4
 
Less: Non-Controlling Interest in Subsidiaries
(0.1)
0.1
 
(0.1)
0.1
Net Income Attributable to ALLETE
$9.4
$10.7
 
$26.3
$34.3
               
Average Shares of Common Stock
         
 
Basic
31.8
28.8
 
31.3
28.7
 
Diluted
31.8
28.9
 
31.4
28.8
           
Basic and Diluted Earnings Per Share of Common Stock
$0.29
$0.37
 
$0.84
$1.19
               
Dividends Per Share of Common Stock
$0.44
$0.43
 
$0.88
$0.86

 
The accompanying notes are an integral part of these statements.



 
ALLETE Second Quarter 2009 Form 10-Q
 
7

 

ALLETE
CONSOLIDATED STATEMENT OF CASH FLOWS
Millions - Unaudited
 
Six Months Ended
 
June 30,
     
     2009
           2008
         
Operating Activities
   
 
Net Income
$26.2
$34.4
 
Allowance for Funds Used During Construction
(2.9)
(2.0)
 
Income from Equity Investments, Net of Dividends
(0.5)
(1.0)
 
Gain on Sale of Assets
(4.6)
 
Gain on Sale of Available-for-Sale Securities
(6.5)
 
Depreciation Expense
30.7
25.6
 
Amortization of Debt Issuance Costs
0.4
0.4
 
Deferred Income Tax Expense
24.0
9.1
 
Stock Compensation Expense
1.1
0.8
 
Bad Debt Expense
0.6
0.5
 
Changes in Operating Assets and Liabilities
   
   
Accounts Receivable
(5.0)
19.7
   
Inventories
(3.9)
(4.2)
   
Prepayments and Other
(1.5)
11.1
   
Accounts Payable
(3.5)
(15.5)
   
Other Current Liabilities
9.4
(0.6)
 
Other Assets
(4.3)
(4.9)
 
Other Liabilities
(7.1)
(7.6)
   
Cash from Operating Activities
63.7
54.7
         
Investing Activities
   
 
Proceeds from Sale of Available-for-Sale Securities
0.9
52.3
 
Payments for Purchase of Available-for-Sale Securities
(0.9)
(39.3)
 
Investment in ATC
(3.5)
(2.8)
 
Changes to Other Investments
5.2
6.5
 
Additions to Property, Plant and Equipment
(133.3)
(130.5)
 
Proceeds from Sale of Assets
20.2
 
Other
(3.4)
(3.0)
   
Cash for Investing Activities
(135.0)
(96.6)
         
Financing Activities
   
 
Proceeds from Issuance of Common Stock
27.9
7.9
 
Proceeds from Issuance of Long-Term Debt
43.3
138.7
 
Reductions of Long-Term Debt
(1.8)
(8.2)
 
Debt Issuance Costs
(0.5)
(1.1)
 
Dividends on Common Stock
(27.2)
(25.6)
 
Changes in Notes Payable
6.0
   
Cash from Financing Activities
41.7
117.7
         
Change in Cash and Cash Equivalents
(29.6)
75.8
Cash and Cash Equivalents at Beginning of Period
102.0
23.3
         
Cash and Cash Equivalents at End of Period
$72.4
$99.1

 
The accompanying notes are an integral part of these statements.

 
ALLETE Second Quarter 2009 Form 10-Q
 
8

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X and do not include all of the information and notes required by GAAP for complete financial statements. Similarly, the December 31, 2008 consolidated balance sheet was derived from audited financial statements but does not include all disclosures required by GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Certain prior year amounts within operating activities in our consolidated statement of cash flows have been reclassified between line items for comparative purposes. The reclassifications did not affect our net income or cash flows from operating activities. In the opinion of management, the accompanying unaudited consolidated financial statements contain all normal and recurring adjustments necessary to make a fair statement of the consolidated financial position, results of operations and cash flows of ALLETE for the interim periods presented. Operating results for the period ended June 30, 2009, are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2009. For further information, refer to the consolidated financial statements and notes included in our 2008 Form 10-K and Form 10-K/A.

Subsequent Events. The Company performed an evaluation of subsequent events for potential recognition and disclosure through the time of issuing the financial statements on August 5, 2009.


NOTE 1.  OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

Inventories. Inventories are stated at the lower of cost or market. Amounts removed from inventory are recorded on an average cost basis.


 
June 30,
December 31,
Inventories
2009
2008
Millions
   
     
Fuel
$21.7
$16.6
Materials and Supplies
31.9
33.1
Total Inventories
$53.6
$49.7

Other Assets and Other Liabilities.

 
June 30,
December 31,
Other Assets
2009
2008
Millions
   
     
Deferred Regulatory Assets
$253.2
$249.3
Other
32.6
32.1
Total Other Assets
$285.8
$281.4

Other Liabilities
   
Millions
   
     
Future Benefit Obligation Under Defined Benefit Pension and
Other Postretirement Plans
$221.8
$251.8
Deferred Regulatory Liabilities
60.6
50.0
Asset Retirement Obligation
43.3
39.5
Other
34.7
48.0
Total Other Liabilities
$360.4
$389.3
 
 
 
ALLETE Second Quarter 2009 Form 10-Q
 
9

 

NOTE 1.  OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Supplemental Statement of Cash Flows Information.

For the Six Months Ended June 30,
2009
2008
Millions
   
     
Cash Paid During the Period for
   
Interest – Net of Amounts Capitalized
$13.6
$11.8
Income Taxes
$0.8
$4.2
     
Noncash Investing and Financing Activities
   
Change in Accounts Payable for Capital Additions to Property Plant and Equipment
$(13.2)
$12.0
ALLETE Common Stock contributed to the Pension Plan
$(12.0)

New Accounting Standards. FSP FAS 157-2 . In February 2008, the FASB issued FSP FAS 157-2, "Effective Date of FASB Statement 157,” which delayed the effective date of SFAS 157 for all nonrecurring fair value measurements of nonfinancial assets and liabilities until fiscal years beginning after November 15, 2008. The implementation of FSP FAS 157-2 did not have a material impact on our consolidated financial position, results of operations or cash flows. (See Note 5. Fair Value.)

SFAS 160. In December 2007, the FASB issued SFAS 160, “Non-controlling Interests in Consolidated Financial Statements – an amendment of Accounting Research Bulletin (ARB) 51,” to improve the relevance, comparability, and transparency of the financial information a reporting entity provides in its consolidated financial statements. SFAS 160 amends ARB 51 to establish accounting and reporting standards for non-controlling interests in subsidiaries and to make certain consolidation procedures consistent with the requirements of SFAS 141R. SFAS 160 defines a non-controlling interest in a subsidiary as an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS 160 changes the presentation of the consolidated income statement by requiring consolidated net income to include amounts attributable to the parent and the non-controlling interest. SFAS 160 establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary which do not result in deconsolidation. SFAS 160 also requires expanded disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners of a subsidiary. SFAS 160 is effective for financial statements issued for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years. SFAS 160 shall be applied prospectively, with the exception of the presentation and disclosure requirements, which shall be applied retrospectively for all periods presented. SFAS 160 was adopted on January 1, 2009. ALLETE Properties does have certain non-controlling interests in consolidated subsidiaries. SFAS 160 impacted the presentation, but did not have a material impact on our consolidated financial position, results of operations or cash flows.

SFAS 161.   In March 2008, the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement 133.” SFAS 161 amends and expands the disclosure requirements of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” by requiring enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS 161 was adopted on January 1, 2009. As SFAS 161 provides only disclosure requirements, the adoption of this standard did not have an impact on our consolidated financial position, results of operations or cash flows. (See Note 4. Derivatives.)

FSP FAS 132(R)-1. In December 2008, the FASB issued FSP FAS 132(R)-1. This FSP amends SFAS 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” to provide guidance on an employer’s disclosures about plan assets, including employers’ investment strategies, major categories of plan assets, concentrations of risk within plan assets, and valuation techniques used to measure the fair value of plan assets. This FSP is effective for fiscal years ending after December 15, 2009. Upon initial adoption, the provisions of this FSP are not required for earlier periods that are presented for comparative purposes. As FSP FAS 132(R)-1 provides only disclosure requirements, the adoption of this standard will not have an impact on our consolidated financial position, results of operations or cash flows.

 
ALLETE Second Quarter 2009 Form 10-Q
 
10

 

NOTE 1.  OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

FSP FAS 107-1 and APB 28-1. In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” which amends SFAS 107, “Disclosures about Fair Value of Financial Instruments” and APB Opinion 28, “Interim Financial Reporting,” respectively, to require disclosure about fair value of financial instruments for interim reporting periods of publicly traded companies in addition to annual financial statements. FSP FAS 107-1 and APB 28-1 was adopted on June 30, 2009. As FSP FAS 107-1 and APB 28-1 provide only disclosure requirements, the adoption of this standard did not have a material impact on our consolidated financial position, results of operations or cash flows. (See Note 5. Fair Value.)

FSP FAS 157-4 . In April 2009, the FASB issued FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” which provides additional guidance for applying the provisions of SFAS 157. SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants under current market conditions. This FSP requires an evaluation of whether there has been a significant decrease in the volume and level of activity for the asset or liability in relation to normal market activity for the asset or liability. If there has, transactions or quoted prices may not be indicative of fair value and a significant adjustment may need to be made to those prices to estimate fair value. Additionally, an entity must consider whether the observed transaction was orderly (that is, not distressed or forced). If the transaction was orderly, the obtained price can be considered a relevant observable input for determining fair value. If the transaction is not orderly, other valuation techniques must be used when estimating fair value. FSP FAS 157-4 was adopted on June 30, 2009, and did not have a material impact on our consolidated financial position, results of operations or cash flows.

FSP FAS 115-2 and FAS 124-2 . In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments,” which amends SFAS 115, “Accounting for Certain Investments in Debt and Equity Securities” and SFAS 124, “Accounting for Certain Investments Held by Not-for-Profit Organizations.” This standard establishes a different other-than-temporary impairment indicator for debt securities than previously prescribed. If it is more likely than not that an impaired security will be sold before the recovery of its cost basis, either due to the investor’s intent to sell or because it will be required to sell the security, the entire impairment is recognized in earnings. Otherwise, only the portion of the impaired debt security related to estimated credit losses is recognized in earnings, while the remainder of the impairment is recorded in other comprehensive income and recognized over the remaining life of the debt security. In addition, the standard expands the presentation and disclosure requirements for other-than-temporary impairments for both debt and equity securities. FSP FAS 115-2 and FAS 124-2 was adopted on June 30, 2009, and did not have an impact on our consolidated financial position, results of operations or cash flows.

SFAS 165. In May 2009, the FASB issued SFAS 165, “Subsequent Events,” to provide guidance on accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Entities are required to disclose the date through which subsequent events have been evaluated and the basis for that date. SFAS 165 was adopted on June 30, 2009, and did not have a material impact on our consolidated financial position, results of operations, or cash flows.

SFAS 166. In June 2009, the FASB issued SFAS 166 “Accounting for Transfers of Financial Assets, an amendment of SFAS 140.” SFAS 166 amends current guidance for accounting for the transfers of financial assets, and was issued with the objective of improving the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. Key provisions of SFAS 166 include (1) the removal of the concept of qualifying special purpose entities, (2) the introduction of the concept of a participating interest, in circumstances in which a portion of a financial asset has been transferred, and (3) the requirement that to qualify for sale accounting, the transferor must evaluate whether it maintains effective control over transferred financial assets either directly or indirectly. Further, SFAS 166 requires enhanced disclosures about transfers of financial assets and a transferor’s continuing involvement. SFAS 166 is effective January 1, 2010, and is required to be applied prospectively. We are currently assessing the impact of SFAS 166 on our consolidated financial position, results of operations and cash flows, but we do not believe it will have a material impact on the Company.


 
ALLETE Second Quarter 2009 Form 10-Q
 
11

 

NOTE 1.  OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

SFAS 167. In June 2009, the FASB issued SFAS 167 “Amendments to FASB Interpretation No. 46(R).” SFAS 167 amends the manner in which entities evaluate whether consolidation is required for variable interest entities (VIEs). A company must first perform a qualitative analysis in determining whether it must consolidate a VIE, and if the qualitative analysis is not determinative, must perform a quantitative analysis. Further, SFAS 167 requires that companies continually evaluate VIEs for consolidation, rather than assessing based upon the occurrence of triggering events. SFAS 167 also requires enhanced disclosures about how an entity’s involvement with a VIE affects its financial statements and exposure to risks. SFAS 167 is effective January 1, 2010. We are currently assessing the impact of SFAS 167 on our consolidated financial position, results of operations and cash flows, but we do not believe it will have a material impact on the Company.

SFAS 168. In June 2009, the FASB approved the FASB Accounting Standards Codification (Codification) as the single source of authoritative nongovernmental GAAP. The Codification is an online research system that reorganizes the thousands of GAAP pronouncements into a topical structure. The Codification was launched on July 1, 2009; at which time all existing accounting standard documents were superseded and all accounting literature not included in the Codification were considered non-authoritative, except for guidance issued by the SEC. The Codification is effective for interim and annual periods ending after September 15, 2009.


NOTE 2.  BUSINESS SEGMENTS

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate business. This segment also includes Emerging Technology Investments, a small amount of non-rate base generation, approximately 7,000 acres of land for sale in Minnesota, and earnings on cash and short-term investments.

 
               Regulated
           Investments
 
                 Consolidated
                    Operations
           and Other
Millions
     
For the Quarter Ended June 30, 2009
     
Operating Revenue
$167.0
$147.4
$19.6
Prior Year Rate Refunds
(2.3)
(2.3)
Total Operating Revenue
164.7
145.1
19.6
Fuel and Purchased Power
56.8
56.8
Operating and Maintenance
76.7
56.9
19.8
Depreciation Expense
15.5
14.3
1.2
Operating Income (Loss)
15.7
17.1
(1.4)
Interest Expense
(8.4)
(6.6)
(1.8)
Equity Earnings in ATC
4.3
4.3
Other Income
1.9
1.7
0.2
Income (Loss) Before Non-Controlling Interest and   Income Taxes
13.5
16.5
(3.0)
Income Tax Expense (Benefit)
4.2
5.8
(1.6)
Net Income (Loss)
9.3
10.7
(1.4)
Less: Non-Controlling Interest in Subsidiaries
(0.1)
(0.1)
Net Income (Loss) Attributable to ALLETE
$9.4
$10.7
$(1.3)


 
ALLETE Second Quarter 2009 Form 10-Q
 
12

 

NOTE 2.  BUSINESS SEGMENTS (Continued)

 
           Regulated
           Investments
 
           Consolidated
           Operations
           and Other
Millions
     
For the Quarter Ended June 30, 2008
     
Operating Revenue
$189.8
$163.5
$26.3
Fuel and Purchased Power
75.0
75.0
Operating and Maintenance
84.4
63.5
20.9
Depreciation Expense
12.9
11.7
1.2
Operating Income
17.5
13.3
4.2
Interest Expense
(6.6)
(5.6)
(1.0)
Equity Earnings in ATC
3.6
3.6
Other Income
2.5
1.1
1.4
Income Before Non-Controlling Interest and Income Taxes
17.0
12.4
4.6
Income Tax Expense
6.2
5.2
1.0
Net Income
10.8
7.2
3.6
Less: Non-Controlling Interest in Subsidiaries
0.1
0.1
Net Income Attributable to ALLETE
$10.7
$7.2
$3.5


 
           Regulated
           Investments
 
           Consolidated
           Operations
           and Other
Millions
     
For the Six Months Ended June 30, 2009
     
Operating Revenue
$371.9
$333.8
$38.1
Prior Year Rate Refunds
(7.6)
(7.6)
Total Operating Revenue
364.3
326.2
38.1
Fuel and Purchased Power
129.6
129.6
Operating and Maintenance
157.2
119.7
37.5
Depreciation Expense
30.7
28.4
2.3
Operating Income (Loss)
46.8
48.5
(1.7)
Interest Expense
(17.1)
(13.9)
(3.2)
Equity Earnings in ATC
8.5
8.5
Other Income
3.0
2.9
0.1
Income (Loss) Before Non-Controlling Interest and
Income Taxes
41.2
46.0
(4.8)
Income Tax Expense (Benefit)
15.0
17.6
(2.6)
Net Income (Loss)
26.2
28.4
(2.2)
Less: Non-Controlling Interest in Subsidiaries
(0.1)
(0.1)
Net Income (Loss) Attributable to ALLETE
$26.3
$28.4
$(2.1)
       
As of June 30, 2009
     
Total Assets
$2,217.6
$1,947.6
$270.0
Property, Plant and Equipment – Net
$1,481.7
$1,429.7
$52.0
Accumulated Depreciation
$875.2
$824.5
$50.7
Capital Additions
$122.5
$121.3
$1.2


 
ALLETE Second Quarter 2009 Form 10-Q
 
13

 

NOTE 2.  BUSINESS SEGMENTS (Continued)

 
           Regulated
           Investments
 
           Consolidated
           Operations
           and Other
Millions
     
For the Six Months Ended June 30, 2008
     
Operating Revenue
$403.2
$356.8
$46.4
Fuel and Purchased Power
161.3
161.3
Operating and Maintenance
167.5
126.0
41.5
Depreciation Expense
25.6
23.2
2.4
Operating Income
48.8
46.3
2.5
Interest Expense
(12.6)
(11.4)
(1.2)
Equity Earnings in ATC
7.0
7.0
Other Income
11.1
2.2
8.9
Income Before Non-Controlling Interest and Income Taxes
54.3
44.1
10.2
Income Tax Expense
19.9
16.8
3.1
Net Income
34.4
27.3
7.1
Less: Non-Controlling Interest in Subsidiaries
0.1
0.1
Net Income Attributable to ALLETE
$34.3
$27.3
$7.0
       
As of June 30, 2008
     
Total Assets
$1,788.8
$1,483.0
$305.8
Property, Plant and Equipment – Net
$1,224.3
$1,170.7
$53.6
Accumulated Depreciation
$858.8
$811.8
$47.0
Capital Additions
$144.3
$140.9
$3.4


NOTE 3.  INVESTMENTS

Investments. Our long-term investment portfolio includes the real estate assets of ALLETE Properties, debt and equity securities consisting primarily of securities held to fund employee benefits, ARS, our Emerging Technology Investments, and land held-for-sale in Minnesota.

 
June 30,
December 31,
Investments
2009
2008
Millions
   
ALLETE Properties
$88.3
$84.9
Available-for-Sale Securities
34.0
32.6
Emerging Technology Investments
6.2
7.4
Other
7.1
12.0
Total Investments
$135.6
$136.9


 
June 30,
December 31,
ALLETE Properties
2009
2008
Millions
   
Land Held-for-Sale Beginning Balance
$71.2
$62.6
Additions During Period: Capitalized Improvements
1.4
10.5
Deductions During Period: Cost of Real Estate Sold
(0.6)
(1.9)
Land Held-for-Sale Ending Balance
72.0
71.2
Long-Term Finance Receivables
13.4
13.6
Other
2.9
0.1
Total Real Estate Assets
$88.3
$84.9

Land Held-for-Sale.  Land held-for-sale is recorded at the lower of cost or fair value determined by the evaluation of individual land parcels. Land values are reviewed for impairment and no impairments have been recorded for the six months ended June 30, 2009 (none in 2008).


 
ALLETE Second Quarter 2009 Form 10-Q
 
14

 

NOTE 3.  INVESTMENTS (Continued)

Long-Term Finance Receivables. Long-term finance receivables, which are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts of $0.1 million at June 30, 2009 ($0.1 million at December 31, 2008). The majority are receivables having maturities up to four years. Finance receivables totaling $7.8 million at June 30, 2009, were due from an entity which filed for voluntary Chapter 11 bankruptcy protection in June 2009. The estimated fair value of the collateral relating to these receivables was greater than the $7.8 million amount due and no impairment was recorded. Due to the lack of recent market activity, we estimated fair value based primarily on recent property tax assessed values. This valuation technique constitutes a Level 3 non-recurring fair value measurement.

Auction Rate Securities. Included in Available-for-Sale Securities, as of June 30, 2009, are $14.3 million ($15.2 million at December 31, 2008) of three auction rate municipal bonds with stated maturity dates ranging between 15 and 27 years. These ARS consist of guaranteed student loans insured or reinsured by the federal government. These ARS were historically auctioned every 35 days to set new rates and provided a liquidating event in which investors could either buy or sell securities. Beginning in 2008, the auctions have been unable to sustain themselves due to the overall lack of market liquidity and we have been unable to liquidate all of our ARS. As a result, we have classified the ARS as long-term investments and have the ability to hold these securities to maturity, until called by the issuer, or until liquidity returns to this market. In the meantime, these securities will pay a default rate which is above market interest rates.

The Company used a discounted cash flow model to determine the estimated fair value of its investment in the ARS as of June 30, 2009. The assumptions used in preparing the discounted cash flow model include the following: estimated interest rates, estimated discount rates (using yields of comparable traded instruments adjusted for illiquidity and other risk factors), amount of cash flows, and expected holding periods of the ARS. These inputs reflect the Company’s judgments about assumptions that market participants would use in pricing ARS including assumptions about risk. Based upon the results of the discounted cash flow model, the fact that these ARS consist of guaranteed student loans insured or reinsured by the federal government and recent market activity, no other-than-temporary impairment loss has been reported.


NOTE 4.  DERIVATIVES

In 2009, we entered into financial derivative instruments to manage price risk for certain power marketing contracts. These derivative instruments are recorded on our consolidated balance sheet at fair value. Changes in the derivatives’ fair value are recognized currently in earnings unless specific hedge accounting criteria is met. As of June 30, 2009, we recorded approximately $2.3 million of derivatives in other assets on our consolidated balance sheet. Changes in fair value of $0.3 million were recorded in operating revenue on our consolidated statement of income in the first quarter, and $0.1 million was recorded in the second quarter.

A total of $0.1 million has been designated as a cash flow hedge and any mark-to-market fluctuations have been recorded in other comprehensive income on the consolidated balance sheet. The derivative instrument designated as a cash flow hedge relates to an energy sale that includes pricing based on daily natural gas prices. The remaining $2.2 million of derivative instruments include $1.8 million of FTRs and $0.4 million relating to an energy swap. The FTRs were purchased to manage congestion risk for forward power sales contracts. Each of these derivative instruments expire at various times through out 2009 and the first five months of 2010.


 
ALLETE Second Quarter 2009 Form 10-Q
 
15

 

NOTE 5.  FAIR VALUE

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observability of those inputs. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. This category includes primarily mutual fund investments held to fund employee benefits.

Level 2 Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date.  The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities. This category includes deferred compensation, fixed income securities, and derivative instruments.

Level 3 — Significant inputs that are generally less observable from objective sources.  The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value. This category includes ARS consisting of guaranteed student loans and derivative instruments of FTRs.

The following tables set forth by level within the fair value hierarchy our assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2009 and December 31, 2008. Each asset and liability is classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

 
Fair Value as of June 30, 2009
Recurring Fair Value Measures
     Level 1
     Level 2
     Level 3
     Total
Millions
       
Assets:
       
Equity Securities
$13.9
$13.9
Corporate Debt Securities
$6.7
6.7
Derivatives
0.1
0.4
$1.8
2.3
Debt Securities Issued by States of the United States (ARS)
14.3
14.3
Money Market Funds
4.2
4.2
Total Fair Value of Assets
$18.2
$7.1
$16.1
$41.4
         
Liabilities:
       
Deferred Compensation
$14.4
$14.4
Total Fair Value of Liabilities
$14.4
$14.4
Total Net Fair Value of Assets (Liabilities)
$18.2
$(7.3)
$16.1
$27.0


 
ALLETE Second Quarter 2009 Form 10-Q
 
16

 

NOTE 5.  FAIR VALUE (Continued)

 
Fair Value as of December 31, 2008
Recurring Fair Value Measures
     Level 1
     Level 2
     Level 3
     Total
Millions
       
Assets:
       
Equity Securities
$13.5
$13.5
Corporate Debt Securities
$3.3
3.3
Debt Securities Issued by States of the United States (ARS)
$15.2
15.2
Money Market Funds
10.6
10.6
Total Fair Value of Assets
$24.1
$3.3
$15.2
$42.6
         
Liabilities:
       
Deferred Compensation
$13.5
$13.5
Total Fair Value of Liabilities
$13.5
$13.5
Total Net Fair Value of Assets (Liabilities)
$24.1
$(10.2)
$15.2
$29.1


Recurring Fair Value Measures
Derivatives
Auction Rate Securities
Activity in Level 3
     2009
     2008
     2009
     2008
Millions
       
Balance as of December 31, 2008 and December 31, 2007, respectively
$15.2
Purchases, Sales, Issuances and Settlements, Net
$1.8
(0.9)
$(5.9)
Level 3 Transfers In
25.2
Balance as of June 30,
$1.8
$14.3
$19.3

The fair value for the items below were based on quoted market prices for the same or similar instruments.

Financial Instruments
Carrying Amount
Fair Value
Millions
   
Long-Term Debt, Including Current Portion
   
December 31, 2008
$598.7
$561.6
June 30, 2009
$640.2
$609.4


NOTE 6.  REGULATORY MATTERS

Electric Rates. Entities within our Regulated Operations segment file for periodic rate revisions with the MPUC, the FERC or the PSCW.

Minnesota Power’s wholesale customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P, a wholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a wholesale customer of Minnesota Power. In 2008, Minnesota Power entered into new contracts with all of our wholesale customers with the exception of one small customer whose contract is now in the cancellation period. The new contracts transitioned each customer to formula-based rates, which means rates can be adjusted annually based on changes in cost. The new agreements with the private utilities in Wisconsin are subject to PSCW approval. In February 2009, the FERC approved our municipal contracts, including the formula-based rate provision. A 9.5 percent rate increase for our municipal customers was implemented on February 1, 2009 under the formula-based rate provision. Incremental revenue from this rate increase is expected to be approximately $7 million on an annualized basis.

On May 2, 2008, Minnesota Power filed a rate increase request with the MPUC. On May 4, 2009, the MPUC issued its order (May Order) on the rate filing, and on June 25, 2009, the MPUC reconsidered the May Order. While the reconsideration order has not been issued, we expect the MPUC reconsideration to result in an authorized rate increase of $20.4 million (slightly below the $21.1 million outcome in its May Order). The May Order allowing a 10.74 percent return on common equity and a capital structure consisting of 54.79 percent equity and 45.21 percent debt remains unchanged.
 

 
ALLETE Second Quarter 2009 Form 10-Q
 
17

 

NOTE 6.  REGULATORY MATTERS (Continued)

The reconsideration decision reduced Minnesota Power’s interim rates, which are in effect between August 2008 and the date final rates are implemented, by $6.3 million annually to approximately $15 million. This increases Minnesota Power’s refunding obligation for 2008 and 2009. Any party may appeal the final order to the Minnesota Court of Appeals. We will continue collecting interim rates until the new rates go into effect, which will be after the appeal period and all compliance filings are completed and accepted. Appeal of the final order or modifications during compliance could affect the final rate increase.

With the May Order, the MPUC also approved the stipulation and settlement agreement that affirmed the Company’s continued recovery of fuel and purchased power costs under the former base cost of fuel that was in effect prior to the retail rate filing. The transition to the former base cost of fuel will occur upon implementation of final rates. Any revenue impact associated with the transition will be identified in the fourth quarter.

As of June 30, 2009, we recorded a $16.4 million liability, including interest, for refunds anticipated to be paid to our customers as a result of the MPUC decision on our retail rate filing. Current year rate refunds totaling $8.3 million have been recorded on our consolidated statement of income and prior year rate refunds totaling $7.6 million are stated separately. Interest expense of $0.5 million was also recorded on our consolidated statement of income related to rate refunds. Refunds will commence when final rates are effective.

SWL&P’s current retail rates are based on a December 2008 PSCW retail rate order that became effective January 1, 2009, and allows for an 11.1 percent return on equity. The new rates reflect a 3.5 percent average increase in retail utility rates for SWL&P customers (a 13.4 percent increase in water rates, a 4.7 percent increase in electric rates, and a 0.6 percent decrease in natural gas rates). On an annualized basis, the rate increase will generate approximately $3 million in additional revenue.


NOTE 7.  INVESTMENT IN ATC

Our wholly-owned subsidiary Rainy River Energy owns approximately 8 percent of ATC, a Wisconsin-based 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. On July 31, 2009, we invested an additional $1.9 million in ATC.

ALLETE’s Interest in ATC
 
Millions
 
Equity Investment Balance as of December 31, 2008
$76.9
Cash Investments
3.5
Equity in ATC Earnings
8.5
Distributed ATC Earnings
(6.8)
Equity Investment Balance as of June 30, 2009
$82.1

ATC's summarized financial data for the quarter and six months ended June 30, 2009 and 2008, is as follows:

 
Quarter Ended
 
Six Months Ended
ATC Summarized Financial Data
June 30,
 
June 30,
Income Statement Data
     2009
     2008
 
     2009
     2008
Millions
         
Revenue
$129.0
$116.1
 
$255.2
$225.2
Operating Expense
56.6
53.2
 
113.7
104.2
Other Expense
19.7
17.2
 
37.9
32.9
Net Income
$52.7
$45.7
 
$103.6
$88.1
           
ALLETE’s Equity in Net Income
$4.3
$3.6
 
$8.5
$7.0


 
ALLETE Second Quarter 2009 Form 10-Q
 
18

 

NOTE 8.  SHORT-TERM AND LONG-TERM DEBT

Long-Term Debt. In January 2009, we issued $42.0 million in principal amount of First Mortgage Bonds (Bonds) in the private placement market. The Bonds mature January 15, 2019, and carry a coupon rate of 8.17 percent. We have the option to prepay all or a portion of the Bonds at our discretion, subject to a make-whole provision. The Bonds are subject to additional terms and conditions which are customary for this type of transaction. We are using the proceeds from the sale of the Bonds to fund utility capital expenditures and for general corporate purposes.


NOTE 9.  OTHER INCOME (EXPENSE)

 
Quarter Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
     2009
     2008
 
     2009
     2008
Millions
         
Loss on Emerging Technology Investments
$(0.1)
$(0.1)
 
$(1.2)
$(0.6)
AFUDC Equity
1.7
1.0
 
2.9
2.0
Investment and Other Income (a)
0.3
1.6
 
1.3
9.7
Total Other Income
$1.9
$2.5
 
$3.0
$11.1

(a)
In 2008, Investment and Other Income included a gain from the sale of certain available-for-sale securities. The gain was triggered when securities were sold to reallocate investments to meet defined investment allocations based upon an approved investment strategy.


NOTE 10.  INCOME TAX EXPENSE

 
Quarter Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2009
2008
 
2009
2008
Millions
         
Current Tax Expense (Benefit)
         
 
Federal (a)
$(8.1)
$3.2
 
$(8.8)
$8.0
 
State
(1.2)
 
(0.2)
2.8
 
Total Current Tax Expense (Benefit)
(9.3)
3.2
 
(9.0)
10.8
Deferred Tax Expense
         
 
Federal (a)
11.6
2.7
 
20.9
8.1
 
State
2.1
0.6
 
3.6
1.5
 
Deferred Tax Credits
(0.2)
(0.3)
 
(0.5)
(0.5)
 
Total Deferred Tax Expense
13.5
3.0
 
24.0
9.1
Total Income Tax Expense
$4.2
$6.2
 
$15.0
$19.9

(a)
Due to the bonus depreciation provisions in the American Recovery and Reinvestment Act of 2009, we expect to be in a net operating loss position for the current year. The loss will be utilized by carrying it back against prior year’s taxable income.

For the six months ended June 30, 2009, the effective tax rate was 36.4 percent (36.6 percent for the six months ended June 30, 2008). The 2009 effective tax rate deviated from the statutory rate of approximately 41 percent primarily due to deductions for Medicare health subsidies, AFUDC-Equity, investment tax credits, wind production tax credits, and depletion.

Uncertain Tax Positions. Under the provisions of FIN 48, “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement 109,” we have gross unrecognized tax benefits of $8.7 million as of June 30, 2009. Of this total, $1.3 million (net of federal tax benefit on state issues) represents the amount of unrecognized tax benefits that, if recognized, would favorably impact the effective income tax rate.

We expect that the total amount of unrecognized tax benefits as of June 30, 2009 will change by less than $1.0 million in the next 12 months.
 
 
ALLETE Second Quarter 2009 Form 10-Q
 
19

 

NOTE 11.  OTHER COMPREHENSIVE INCOME

The components of total comprehensive income were as follows:

 
Quarter Ended
Six Months Ended
Other Comprehensive Income
June 30,
June 30
Net of Tax
     2009
     2008
     2009
     2008
Millions
       
Net Income Attributable to ALLETE
$9.4
$10.7
$26.3
$34.3
Other Comprehensive Income
       
 
Unrealized Gain (Loss) on Securities
1.9
0.6
0.9
(0.8)
 
Reclassification Adjustment for Gains Included in Income (a)
(0.1)
(0.1)
(3.8)
 
Defined Benefit Pension and Other Postretirement Plans
0.2
0.8
0.6
1.3
Total Other Comprehensive Income (Loss)
2.0
1.4
1.4
(3.3)
Total Comprehensive Income
$11.4
$12.1
$27.7
$31.0

(a)
Reclassification adjustments include $0.1 million relating to derivatives in 2009 and $3.8 million relating to the sale of certain available-for-sale securities in 2008.


NOTE 12.  EARNINGS PER SHARE AND COMMON STOCK

The difference between basic and diluted earnings per share, if any, arises from outstanding stock options and performance share awards granted under our Executive and Director Long-Term Incentive Compensation Plans. In accordance with SFAS 128, “Earnings per Share,” for the quarter and six months ended June 30, 2009, 0.6 million options to purchase shares of common stock were excluded from the computation of diluted earnings per share because the option exercise prices were greater than the average market prices, and therefore, their effect would have been anti-dilutive. For the quarter and six months ended June 30, 2008, 0.2 million options to purchase shares of common stock were excluded from the computation of diluted earnings per share.

Authorized Common Stock. On May 12, 2009, shareholders approved an amendment to the Company’s Amended and Restated Articles of Incorporation to increase the number of authorized shares of common stock from 43,333,333 to 80,000,000.

Shareholder Rights Plan . On July 25, 1996, ALLETE adopted a shareholder rights plan, which was amended and restated on July 12, 2006 (collectively, the “Rights Plan”). The amendment to the Rights Plan, among other things, extended the final expiration date of the Rights Plan to July 11, 2009. The Rights Plan expired according to its terms on July 11, 2009. As a result, ALLETE’s preferred share purchase rights issued in accordance with the Rights Plan are no longer outstanding.

   
2009
     
2008
 
Reconciliation of Basic and Diluted
 
Dilutive
     
Dilutive
 
Earnings Per Share
Basic
Securities
Diluted
 
Basic
Securities
Diluted
Millions Except Per Share Amounts
             
               
For the Quarter Ended June 30,
             
Net Income
$9.4
$9.4
 
$10.7
$10.7
Common Shares
31.8
31.8
 
28.8
0.1
28.9
Earnings Per Share
$0.29
$0.29
 
$0.37
$0.37

For the Six Months Ended June 30,
             
Net Income
$26.3
$26.3
 
$34.3
$34.3
Common Shares
31.3
0.1
31.4
 
28.7
0.1
28.8
Earnings Per Share
$0.84
$0.84
 
$1.19
$1.19

 
 
ALLETE Second Quarter 2009 Form 10-Q
 
20

 

NOTE 13.  PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

 
Pension
Postretirement
 Health and Life
Components of Net Periodic Benefit Expense
           2009
           2008
           2009
           2008
Millions
       
         
For the Quarter Ended June 30,
       
Service Cost
$1.5
$1.4
$1.1
$1.0
Interest Cost
6.6
6.3
2.5
2.4
Expected Return on Plan Assets
(8.5)
(8.1)
(2.1)
(1.8)
Amortization of Prior Service Costs
0.2
0.1
Amortization of Net Loss
0.8
0.4
0.6
0.4
Amortization of Transition Obligation
0.6
0.6
Net Periodic Benefit Expense
$0.6
$0.1
$2.7
$2.6

For the Six Months Ended June 30,
       
Service Cost
$2.9
$2.9
$2.1
$2.0
Interest Cost
13.1
12.6
5.0
4.8
Expected Return on Plan Assets
(16.9)
(16.2)
(4.2)
(3.6)
Amortization of Prior Service Costs
0.3
0.3
Amortization of Net Loss
1.7
0.8
1.2
0.8
Amortization of Transition Obligation
1.3
1.2
Net Periodic Benefit Expense
$1.1
$0.4
$5.4
$5.2


Employer Contributions. For the six months ended June 30, 2009, we contributed $24.0 million to our pension plan; $12.0 million was contributed through the issuance of 463,000 shares of ALLETE common stock. We also contributed $9.3 million to our postretirement health and life plan. We expect to make additional contributions of $8.9 million to our pension plan and no additional contributions to our postretirement health and life plan in 2009.

We provide postretirement health benefits that include prescription drug benefits which qualify us for the federal subsidy under the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The expected reimbursement for Medicare health subsidies reduced our after-tax postretirement medical expense by $2.0 million for 2009 ($1.2 million for 2008). For the six months ended June 30, 2009, we have received $0.3 million in prescription drug reimbursements.
 
 
NOTE 14.  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 is obligated to pay its pro rata share of Square Butte’s costs based on Minnesota Power’s entitlement to Unit output. Our output entitlement under the Agreement is 50 percent for the remainder of the contract. 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 June 30, 2009, Square Butte had total debt outstanding of $365.0 million. Total annual debt service for Square Butte is expected to be approximately $29 million in each of the years 2009 through 2013. Variable operating costs include the price of coal purchased from BNI Coal, our subsidiary, under a long-term contract.


 
ALLETE Second Quarter 2009 Form 10-Q
 
21

 

NOTE 14.  COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

North Dakota Wind Project. On July 7, 2009, the MPUC approved our plan petition to qualify for current cost recovery of investments and expenditures related to our Bison I Wind Project (Bison I) and associated transmission upgrades. We anticipate filing a petition with the MPUC in the near future to establish cost recovery and customer billing rates. Bison I is the first portion of several hundred MWs of our North Dakota Wind Project, which upon completion will complete the 2025 renewable energy supply requirement for our retail load. Bison I will be located near Center, North Dakota and will be comprised of 33 wind turbines with a total nameplate capacity of 75.9 MWs. In September 2008, we signed an agreement to purchase an existing 250 kV DC transmission line for approximately $80 million to transport this wind energy to our customers while gradually reducing the supply of energy currently delivered to our system on this same transmission line from Square Butte’s Unit. The transaction is subject to regulatory approvals and is anticipated to close in 2009. On May 14, 2009, we filed a petition with the MPUC for approval of the DC transmission line purchase and the restructuring of the power purchase agreement with Square Butte.

Wind Power Purchase Agreements. We have two wind power purchase agreements with an affiliate of NextEra Energy to purchase the output from two wind facilities, Oliver Wind I (50 MWs) and Oliver Wind II (48 MWs) located near Center, North Dakota. Each agreement is for 25 years and provides for the purchase of all output from the facilities.

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 2016. The aggregate amount of minimum lease payments for all operating leases is $8.3 million in 2009, $8.2 million in 2010, $8.3 million in 2011, $8.2 million in 2012, $7.8 million in 2013 and $52.9 million thereafter.

Coal, Rail and Shipping Contracts . We have three primary coal supply agreements with various expiration dates ranging from December 2009 to December 2011. We also have rail and shipping agreements for the transportation of all of our coal, with various expiration dates ranging from December 2009 to January 2012. Our remaining minimum payment obligation as of June 30, 2009, under these coal, rail and shipping agreements for 2009 is $23.5 million. Annual payment obligations for 2010 and 2011 are $11.7 million and $7.6 million, respectively, with no specific commitments beyond 2011. Our minimum annual payment obligations will increase when annual nominations are made for coal deliveries in future years.

On January 24, 2008, we received a letter from BNSF alleging that the Company defaulted on a material obligation under the Company’s Coal Transportation Agreement (CTA). In the notice, BNSF claimed we underpaid approximately $1.6 million for coal transportation services in 2006 and that failure to pay such amount plus interest may result in BNSF’s termination of the CTA. On April 1, 2008, to ensure that BNSF did not attempt to terminate the CTA, we paid under protest the full amount claimed by BNSF and filed a demand for arbitration of the issue. On April 22, 2008, BNSF filed a counterclaim in the arbitration disputing our position that we are entitled to a refund from BNSF of $1.5 million plus interest for amounts that we overpaid for 2007 deliveries. On March 11, 2009, the Company and BNSF resolved the disputes with no resulting associated Company liability or loss contingencies, and by an order dated March 27, 2009, the arbitrator dismissed the case. The delivered costs of fuel for the Company’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

Emerging Technology Investments. 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 $0.5 million in additional investments in certain emerging technology venture capital funds. We do not have plans to make any additional investments beyond this commitment.


 
ALLETE Second Quarter 2009 Form 10-Q
 
22

 

NOTE 14.  COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

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 currently applicable environmental regulations and believe all necessary permits to conduct such operations have been obtained. Due to future restrictive 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 for disclosure 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 our consolidated 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.

EPA Clean Air Interstate Rule. In March 2005, the EPA announced the Clean Air Interstate Rule (CAIR) that sought to reduce and permanently cap emissions of SO 2 , NO X , and particulates in the eastern United States. Minnesota was included as one of the 28 states considered as “significantly contributing” to air quality standards non-attainment in other downwind states. On July 11, 2008, the United States Court of Appeals for the District of Columbia Circuit (Court) vacated the CAIR and remanded the rulemaking to the EPA for reconsideration while also granting our petition that the EPA reconsider including Minnesota as a CAIR state. In September 2008, the EPA and others petitioned the Court for a rehearing or alternatively requested that the CAIR be remanded without a court order. In December 2008, the Court granted the request that the CAIR be remanded without a court order, effectively reinstating a January 1, 2009, compliance date for the CAIR, including Minnesota. However, in the May 12, 2009 Federal Register the EPA issued a proposed rule that would amend the CAIR to stay its effectiveness with respect to Minnesota until completion of the EPA’s determination of whether Minnesota should be included as a CAIR state. The EPA took public comment through June 11, 2009 and is expected to render a final decision pending evaluation of comments received.

Minnesota Regional Haze. The regional haze rule requires states to submit state implementation plans (SIPs) to the EPA to address regional haze visibility impairment in 156 federally-protected parks and wilderness areas. Under the regional haze rule, certain large stationary sources of visibility-impairing emissions that were put in place between 1962 and 1977 are required to install emission controls, known as best available retrofit technology (BART). We have certain steam units, Boswell Unit 3 and Taconite Harbor Unit 3, which are subject to BART requirements.

Pursuant to the regional haze rule, Minnesota was required to develop its SIP by December 2007. As a mechanism for demonstrating progress towards meeting the long-term regional haze goal, in April 2007, the MPCA advanced a draft conceptual SIP which relied on the implementation of the CAIR. However, a formal SIP was never filed due to the Court’s review of CAIR as more fully described above under “EPA Clean Air Interstate Rule.” Subsequently, the MPCA has requested that companies with BART eligible units complete and submit a BART emissions control retrofit study, which was done on Taconite Harbor Unit 3 in November 2008 in order to develop a final SIP for submission to the EPA. The retrofit work currently underway on Boswell Unit 3 meets the BART requirement for that unit. It is uncertain what controls will ultimately be required at Taconite Harbor Unit 3 in connection with the regional haze rule.

EPA Clean Air Mercury Rule. In March 2005, the EPA also announced the Clean Air Mercury Rule (CAMR) that would have reduced and permanently capped electric utility mercury emissions in the continental United States through a cap and trade program. In February 2008, the Court vacated the CAMR and remanded the rulemaking to the EPA for reconsideration. In October 2008, the Department of Justice, on behalf of the EPA, petitioned the Supreme Court to review the Court’s decision in the CAMR case. In January 2009, the EPA withdrew their petition, paving the way for possible regulation of mercury emissions through Section 112 of the Clean Air Act, setting Maximum Achievable Control Technology standards for the utility sector. Cost estimates for complying with potential future mercury regulations under the Clean Air Act are premature at this time.


 
ALLETE Second Quarter 2009 Form 10-Q
 
23

 

NOTE 14.  COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

New Source Review. On August 8, 2008, Minnesota Power received a Notice of Violation (NOV) from the United States EPA asserting violations of the New Source Review (NSR) requirements of the Clean Air Act at Boswell Units 1-4 and Laskin Unit 2. The NOV also asserts that the Boswell Unit 4 Title V permit was violated. The NOV asserts that seven projects undertaken at these coal-fired plants between the years 1981 and 2000 should have been reviewed under the NSR requirements. Minnesota Power believes the projects were in full compliance with the Clean Air Act, NSR requirements and applicable permits.

The EPA has been conducting a nationwide enforcement initiative since 1999 relating to NSR requirements. In 2000, 2001, and 2002 Minnesota Power received requests from the EPA pursuant to Section 114(a) of the Clean Air Act seeking information regarding capital expenditures with respect to Boswell and Laskin. Minnesota Power responded to these requests; however, we had no further communications from the EPA regarding the information provided until receipt of the NOV.

We are engaged in discussions with the EPA regarding resolution of these matters, but we are unable to predict the outcome of these discussions. Since 2006, Minnesota Power has significantly reduced, and continues to reduce, emissions at Boswell and Laskin. The resolution could result in civil penalties and the installation of control technology, some of which is already planned or completed for other regulatory requirements. Any costs of installing pollution control technology would likely be eligible for recovery in rates over time subject to MPUC and FERC approval in a rate proceeding. We are unable to predict the ultimate financial impact or the resolution of these matters at this time.

Manufactured Gas Plant Site.  We are reviewing and addressing environmental conditions at a former manufactured gas plant site within the City of Superior, Wisconsin and formerly operated by SWL&P. We have been working with the WDNR to determine the extent of contamination and the remediation of contaminated locations. We have accrued a $0.5 million liability for this site as of June 30, 2009, and have recorded a corresponding regulatory asset as we expect recovery of remediation costs to be allowed by the PSCW.

BNI Coal.  As of June 30, 2009, BNI Coal had surety bonds outstanding of $18.5 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although the coal supply agreements obligate the customers to provide for the closing costs, an additional guarantee is required by federal and state regulations. In addition to the surety bond, BNI has secured a Letter of Credit with CoBank for an additional $10.0 million to meet the requirements for BNI’s total reclamation liability currently estimated at $27.6 million.

ALLETE Properties. As of June 30, 2009, ALLETE Properties, through its subsidiaries, had surety bonds outstanding of $18.9 million primarily related to performance and maintenance obligations for governmental entities to construct improvements in the Company’s various projects. The cost of the remaining work to be completed on these improvements is estimated to be approximately $11.1 million, and ALLETE Properties does not believe it is likely that any of these outstanding bonds will be drawn upon.

Community Development District Obligations. In March 2005, the Town Center District issued $26.4 million of tax-exempt, 6 percent Capital Improvement Revenue Bonds, Series 2005; and in May 2006, the Palm Coast Park District issued $31.8 million of tax-exempt, 5.7 percent Special Assessment Bonds, Series 2006. The Capital Improvement Revenue Bonds and the Special Assessment Bonds are payable through property tax assessments on the land owners over 31 years (by May 1, 2036 and 2037 respectively). The bond proceeds were used to pay for the construction of a portion of the major infrastructure improvements in each district, 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 each district. The assessments were billed to the landowners in November 2006, for Town Center and November 2007, for Palm Coast Park. To the extent that we still own land at the time of the assessment, in accordance with EITF 91-10, “Accounting for Special Assessments and Tax Increment Financing Entities,” we will incur the cost of our portion of these assessments, based upon our ownership of benefited property. At June 30, 2009, we owned 69 percent of the assessable land in the Town Center District (69 percent at December 31, 2008) and 86 percent of the assessable land in the Palm Coast Park District (86 percent at December 31, 2008). As we sell property, the obligation to pay special assessments will pass to the new landowners. Under current accounting rules, these bonds are not reflected as debt on our consolidated balance sheet.


 
ALLETE Second Quarter 2009 Form 10-Q
 
24

 

NOTE 14.  COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

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.


ITEM 2.  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, notes to those statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations from the 2008 Form 10-K and the other financial information appearing elsewhere in this report. In addition to historical information, the following discussion and other parts of this Form 10-Q 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-Q under the heading: “Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995” located on page 5 and “Risk Factors” located in Part I, Item 1A, page 20 of our 2008 Form 10-K. The risks and uncertainties described in this Form 10-Q and our 2008 Form 10-K are not the only risks 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 are realized.

OVERVIEW

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in Northeastern Minnesota to 144,000 retail customers and wholesale electric service to 16 municipalities. SWL&P provides regulated electric service, natural gas and water service in northwestern Wisconsin to 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities.

Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate business. This segment also includes Emerging Technology Investments ($6.2 million at June 30, 2009), a small amount of non-rate base generation, approximately 7,000 acres of land for sale in Minnesota, and earnings on cash and short-term investments.

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of June 30, 2009, 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.

Financial Overview

(See Note 2. Business Segments for financial results by segment.)

The following net income discussion summarizes a comparison of the six months ended June 30, 2009 to the six months ended June 30, 2008.

Net income for 2009 was $26.3 million, or $0.84 per diluted share compared to $34.3 million, or $1.19 per diluted share for 2008. Earnings per diluted share decreased approximately $0.07 compared to 2008 as a result of additional shares of common stock outstanding in 2009. (See Note 12. Earnings Per Share.)


 
ALLETE Second Quarter 2009 Form 10-Q
 
25

 

Financial Overview (Continued)

Regulated Operations contributed income of $28.4 million in 2009 ($27.3 million in 2008). The increase in earnings is primarily due to increased earnings from our investment in ATC as a result of additional investments we have made to fund our pro-rata share of ATC’s capital expansion program. Higher retail and FERC approved wholesale rates were offset by accrued retail rate refunds related to 2008 and higher depreciation and interest expense.

In addition, lower sales to our large power customers were mostly offset by higher sales to Other Power Suppliers.

Investments and Other reflected a net loss of $2.1 million in 2009 ($7.0 million net income in 2008). The decrease in 2009 is primarily due to the sale of certain available-for-sale securities in the first quarter of 2008, and a net loss at ALLETE Properties of $2.4 million ($2.0 million net income 2008), which continues to experience difficult real estate market conditions in Florida.


COMPARISON OF THE QUARTERS ENDED JUNE 30, 2009 AND 2008

(See Note 2 – Business Segments for financial results by segment.)

Regulated Operations

Operating revenue decreased $18.4 million, or 11 percent, from 2008 due to lower fuel and purchased power recoveries, lower retail and municipal kilowatt-hour sales, lower natural gas sales, which are primarily a pass-through (See Operating and Maintenance Expense discussion below), and the accrual of estimated prior year retail rate refunds related to our 2008 retail rate case. These decreases were partially offset by higher sales to Other Power Suppliers and higher rates.

Lower fuel and purchased power recoveries along with a decrease in retail and municipal kilowatt-hour sales combined for a total revenue reduction of $39.7 million. Fuel and purchased power recoveries decreased due to a $18.2 million reduction in fuel and purchased power expense. (See Fuel and Purchased Power Expense discussion below.) Total kilowatt-hour sales to retail and municipal customers decreased 35.4 percent from 2008 primarily due to idle production lines and plant closures at some of our taconite customers.

Estimated prior year retail rate refunds based on the June 25, 2009, MPUC rate reconsideration decision in the quarter total $2.3 million.

The decrease in kilowatt-hour sales to retail and municipal customers was mostly offset by revenue from electric sales to Other Power Suppliers which increased $21.0 million in 2009. Sales to Other Power Suppliers are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements of various durations.

Higher rates resulting from the August 1, 2008, interim rate increase for retail customers in Minnesota increased revenue by $1.1 million, net of estimated refunds, and the FERC approved wholesale rate increase for our municipal customers on February 1, 2009, increased revenue by $1.4 million.


Kilowatt-hours Sold
 
     Quantity
     %
Quarter Ended June 30,
           2009
           2008
     Variance
     Variance
Millions
       
Regulated Utility
       
 
Retail and Municipals
       
   
Residential
242
239
3
1.3 %
   
Commercial
331
327
4
1.2 %
   
Industrial
874
1,789
(915)
(51.2) %
   
Municipals
222
227
(5)
(2.2) %
     
Total Retail and Municipals
1,669
2,582
(913)
 (35.4) %
 
Other Power Suppliers
1,107
375
732
195.2 %
Total Regulated Utility Kilowatt-hours Sold
2,776
2,957
(181)
(6.1) %


 
ALLETE Second Quarter 2009 Form 10-Q
 
26

 

COMPARISON OF THE QUARTERS ENDED JUNE 30, 2009 AND 2008 (Continued)
Regulated Operations (Continued)

Revenue from electric sales to taconite customers accounted for 13 percent of consolidated operating revenue in 2009 (26 percent in 2008). The decrease in revenue from our taconite customers was partially offset by revenue from electric sales to Other Power Suppliers which accounted for 23 percent of consolidated operating revenue in 2009 (9 percent in 2008). Revenue from electric sales to paper and pulp mills accounted for 10 percent of consolidated operating revenue in 2009 (10 percent in 2008). Revenue from electric sales to pipelines and other industrials accounted for 8 percent of consolidated operating revenue in 2009 (7 percent in 2008).

Operating expenses decreased $22.2 million, or 15 percent, from 2008.

Fuel and Purchased Power Expense decreased $18.2 million, or 24 percent, from 2008 primarily due to a decrease in purchased power expense reflecting lower market prices for energy.

Operating and Maintenance Expense decreased $6.6 million from 2008 reflecting lower natural gas costs due to a decline in the price and quantity of natural gas and lower contract and professional services related to a prior year planned outage at our Boswell Unit 4 facility.

Depreciation Expense increased $2.6 million, or 22 percent, from 2008 reflecting higher property, plant, and equipment balances placed in service and higher annual depreciation rates for distribution and transmission.

Interest expense increased $1.0 million, or 18 percent, from 2008 primarily due to additional long-term debt issued to fund new capital investments.

Investments and Other

Operating revenue decreased $6.7 million, or 25 percent, from 2008 primarily due to a decrease in revenue at ALLETE Properties reflecting the sale of the retail shopping center in Winter Haven, Florida in the second quarter of 2008.

ALLETE Properties
2009
2008
Revenue and Sales Activity
Quantity
Amount
Quantity
Amount
Dollars in Millions
       
Revenue from Land Sales
       
Acres (a)
49
$2.6
Contract Sales Price (b)
 
 
2.6
Deferred Revenue
 
 
Revenue from Land Sales
 
 
2.6
Other Revenue (c)
 
$0.1
 
5.3
 Total ALLETE Properties Revenue
 
$0.1
 
$7.9

(a)
Acreage amounts are shown on a gross basis, including wetlands and non-controlling interest.
(b)
Reflects total contract sales price on closed land transactions. Land sales are recorded using a percentage-of-completion method.
(c)
Included a $4.5 million pre-tax gain from the sale of a shopping center in Winter Haven, Florida in 2008.

Operating expenses decreased $1.1 million, or 5 percent, from 2008 reflecting a decrease in the cost of real estate sold and decreased selling expenses.

Interest expense increased $0.8 million from 2008 primarily due to additional long-term debt issued to fund new capital investments.

Other income decreased $1.2 million from 2008 primarily due to lower average cash balances.


 
ALLETE Second Quarter 2009 Form 10-Q
 
27

 

COMPARISON OF THE QUARTERS ENDED JUNE 30, 2009 AND 2008 (Continued)

Income Taxes – Consolidated

For the quarter ended June 30, 2009, the effective tax rate was 31.5 percent (36.5 percent for the quarter ended June 30, 2008). The effective tax rate in both years deviated from the statutory rate (approximately 41 percent) primarily due to deductions for Medicare health subsidies, AFUDC-Equity, investment tax credits, wind production tax credits, and depletion. In addition, the effective tax rate for the second quarter of 2009 was impacted by lower pre-tax income and a state income tax refund. We expect the effective tax rate for 2009 to be approximately 35 percent.


COMPARISON OF THE SIX MONTHS ENDED JUNE 30, 2009 AND 2008

Regulated Operations

Operating revenue decreased $30.6 million, or 9 percent, from 2008 due to lower fuel and purchased power recoveries, lower retail and municipal kilowatt-hour sales, lower natural gas sales, which are primarily a pass-through (See Operating and Maintenance Expense discussion below), and the accrual of estimated prior year retail rate refunds related to our 2008 retail rate case. These decreases were partially offset by higher sales to Other Power Suppliers and higher rates.

Lower fuel and purchased power recoveries along with a decrease in retail and municipal kilowatt-hour sales combined for a total revenue reduction of $68.1 million. Fuel and purchased power recoveries decreased due to a $31.7 million reduction in fuel and purchased power expense. (See Fuel and Purchased Power Expense discussion below.) Total kilowatt-hour sales to retail and municipal customers decreased 26 percent from 2008 primarily due to idled production lines and plant closures at some of our taconite customers.

Estimated prior year retail rate refunds based on the MPUC May Order and the June 25, 2009, MPUC rate reconsideration decision total $7.6 million.

The decrease in kilowatt-hour sales to retail and municipal customers has been mostly offset by revenue from electric sales to Other Power Suppliers which increased $36.0 million in 2009. Sales to Other Power Suppliers are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements of various durations.

Higher rates resulting from the August 1, 2008 interim rate increase for retail customers in Minnesota increased revenue by $5.9 million, net of estimated refunds, and the FERC approved wholesale rate increases for our municipal customers on March 1, 2008 and February 1, 2009 increased revenue by $3.8 million.
 
 
Kilowatt-hours Sold
 
Quantity
%
Six Months Ended June 30,
2009
2008
Variance
Variance
Millions
       
Regulated Utility
       
 
Retail and Municipals
       
   
Residential
617
602
15
 2.5 %
   
Commercial
709
709
 – %
   
Industrial
2,197
3,612
(1,415)
(39.2) %
   
Municipals
487
499
(12)
(2.4) %
     
Total Retail and Municipals
4,010
5,422
(1,412)
 (26.1) %
 
Other Power Suppliers
2,024
779
1,245
159.8 %
Total Regulated Utility Kilowatt-hours Sold
6,034
6,201
(167)
(2.7) %

Revenue from electric sales to taconite customers accounted for 16 percent of consolidated operating revenue in 2009 (26 percent in 2008). The decrease in revenue from our taconite customers was partially offset by revenue from electric sales to Other Power Suppliers which accounted for 20 percent of consolidated operating revenue in 2009 (9 percent in 2008). Revenue from electric sales to paper and pulp mills accounted for 9 percent of consolidated operating revenue in 2009 (9 percent in 2008). Revenue from electric sales to pipelines and other industrials accounted for 7 percent of consolidated operating revenue in 2009 (7 percent in 2008).

 
ALLETE Second Quarter 2009 Form 10-Q
 
28

 

COMPARISON OF THE SIX MONTHS ENDED JUNE 30, 2009 AND 2008 (Continued)
Regulated Operations (Continued)

Operating expenses decreased $32.8 million, or 11 percent, from 2008.

Fuel and Purchased Power Expense decreased $31.7 million, or 20 percent, from 2008 primarily due to a decrease in purchased power expense reflecting lower market prices for energy.

Operating and Maintenance Expense decreased $6.3 million from 2008 primarily due to $5.5 million in lower natural gas costs due to a decline in the price and quantity of natural gas.

Depreciation Expense increased $5.2 million, or 22 percent, from 2008 reflecting higher property, plant, and equipment balances placed in service and higher annual depreciation rates for distribution and transmission.

Interest expense   increased $2.5 million, or 22 percent, from 2008 primarily due to additional long-term debt issued to fund new capital investments and $0.5 million related to estimated retail rate refunds.

Investments and Other

Operating revenue decreased $8.3 million, or 18 percent, from 2008 primarily due to a decrease in revenue at ALLETE Properties reflecting the sale of the retail shopping center in Winter Haven, Florida in the second quarter of 2008.

ALLETE Properties
2009
2008
Revenue and Sales Activity
     Quantity
     Amount
     Quantity
     Amount
Dollars in Millions
       
Revenue from Land Sales
       
Acres (a)
19
$2.2
51
$3.9
Contract Sales Price (b)
 
2.2
 
3.9
Deferred Revenue
 
(0.6)
 
Revenue from Land Sales
 
1.6
 
3.9
Other Revenue (c)
 
0.2
 
6.7
 Total ALLETE Properties Revenue
 
$1.8
 
$10.6

(a)
Acreage amounts are shown on a gross basis, including wetlands and non-controlling interest.
(b)
Reflects total contract sales price on closed land transactions. Land sales are recorded using a percentage-of-completion method.
(c)
Included a $4.5 million pre-tax gain from the sale of a shopping center in Winter Haven, Florida in 2008.

Operating expenses decreased $4.1 million, or 9 percent, from 2008 reflecting a decrease in the cost of real estate sold and decreased selling expenses.

Interest expense increased $2.0 million from 2008 primarily due to additional long-term debt issued to fund new capital investments.

Other income decreased $8.8 million from 2008 primarily due to the absence of a $6.8 million gain realized from the sale of certain available-for-sale securities in the first quarter of 2008.

Income Taxes – Consolidated

For the six months ended June 30, 2009, the effective tax rate was 36.4 percent (36.6 percent for the six months ended June 30, 2008). The effective tax rate in each period deviated from the statutory rate (approximately 41 percent) primarily due to deductions for Medicare health subsidies, AFUDC-Equity, investment tax credits, wind production tax credits, and depletion.
 
 
 
ALLETE Second Quarter 2009 Form 10-Q
 
29

 

CRITICAL ACCOUNTING ESTIMATES

Certain accounting measurements under applicable GAAP involve management’s judgment about subjective factors and estimates, the effects of which are inherently uncertain. Accounting measurements that we believe are most critical to our reported results of operations and financial condition include: regulatory accounting, valuation of investments, pension and postretirement health and life actuarial assumptions, and taxation. These policies are reviewed with the Audit Committee of our Board of Directors on a regular basis and summarized in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2008 Form 10-K.

OUTLOOK

ALLETE is committed to earning a financial return that rewards our shareholders, allows for reinvestment in our businesses and sustains growth. Minnesota Power’s industrial customers are facing weak conditions in the markets for their products, and have and may continue to reduce the amount of energy they use. We will work to sell any released energy in the wholesale markets, and believe that our ability to produce energy at low cost will be a competitive advantage. Our focus will be to maintain the competitively-priced production of energy, while meeting environmental requirements. Minnesota Power will also focus on maintaining competitive retail rates, as we believe this is important to the success of our customers.

Our strategy going forward is to focus on growth opportunities within our core business as we expect to continue making significant investments to comply with renewable and environmental requirements, maintain our existing low-cost generation fleet, and strengthen and enhance the regional transmission grid. We will also look for additional transmission and renewable energy opportunities which take advantage of our geographical location between sources of renewable energy and growing energy markets. Earnings from our investment in ATC are expected to grow as we anticipate making additional investments to fund our pro-rata share of ATC’s capital expansion program. We expect to invest approximately $8 million in ATC throughout 2009.

Regulated Operations. Minnesota Power expects significant rate base growth over the next several years as it continues its program to comply with renewable energy requirements and environmental mandates, as well as make significant investments in our existing low-cost generation fleet to provide for continued future operations. We anticipate our capital investments will be recovered through a combination of current cost recovery riders and anticipated increased base electric rates.

Rate Cases . Entities within our Regulated Operations segment file for periodic rate revisions with the MPUC, the FERC or the PSCW.

Minnesota Power’s wholesale customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P, a wholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a wholesale customer of Minnesota Power. In 2008, Minnesota Power entered into new contracts with all of our wholesale customers with the exception of one small customer whose contract is now in the cancellation period. The new contracts transition each customer to formula-based rates, which means rates can be adjusted annually based on changes in costs. The new agreements with the private utilities in Wisconsin are subject to PSCW approval. In February 2009, the FERC approved our municipal contracts, including the formula-based rate provision. A 9.5 percent rate increase for our municipal customers was implemented on February 1, 2009 under the formula-based rate provision. Incremental revenue from this rate increase is expected to be approximately $7 million on an annualized basis.

On May 2, 2008, Minnesota Power filed a rate increase request with the MPUC. On May 4, 2009, the MPUC issued its order (May Order) on the rate filing, and on June 25, 2009, the MPUC reconsidered the May Order. While the reconsideration order has not been issued, we expect the MPUC reconsideration to result in an authorized rate increase of $20.4 million (slightly below the $21.1 million outcome in its May Order). The May Order allowing a 10.74 percent return on common equity and a capital structure consisting of 54.79 percent equity and 45.21 percent debt remains unchanged.


 
ALLETE Second Quarter 2009 Form 10-Q
 
30

 

OUTLOOK (Continued)
Regulated Operations (Continued)

The reconsideration decision reduced Minnesota Power’s interim rates, which are in effect between August 2008 and the date final rates are implemented, by $6.3 million annually to approximately $15 million. This increases Minnesota Power’s refunding obligation for 2008 and 2009. Any party may appeal the final order to the Minnesota Court of Appeals. We will continue collecting interim rates until the new rates go into effect, which will be after the appeal period and all compliance filings are completed and accepted. Appeal of the final order or modifications during compliance could affect the final rate increase.

With the May Order, the MPUC also approved the stipulation and settlement agreement that affirmed the Company’s continued recovery of fuel and purchased power costs under the former base cost of fuel that was in effect prior to the retail rate filing. The transition to the former base cost of fuel will occur upon implementation of final rates. Any revenue impact associated with the transition will be identified in the fourth quarter.

As of June 30, 2009, we recorded a $16.4 million liability, including interest, for refunds anticipated to be paid to our customers as a result of the MPUC decision on our retail rate filing. Current year rate refunds totaling $8.3 million have been recorded on our consolidated statement of income and prior year rate refunds totaling $7.6 million are stated separately. Interest expense of $0.5 million was also recorded on our consolidated statement of income related to rate refunds. Refunds will commence when final rates are effective.

Ongoing capital investments necessary to meet state-mandated renewable energy and environmental standards, as well as to maintain our low-cost generation fleet and enhance the regional transmission grid will require continual cost recovery filings with the MPUC. These will take the form of current cost recovery filings and general rate cases. Minnesota Power anticipates filing a general rate case late in 2009.

SWL&P’s current retail rates are based on a December 2008 PSCW retail rate order that became effective January 1, 2009, and allows for an 11.1 percent return on equity. The new rates reflect a 3.5 percent average increase in retail utility rates for SWL&P customers (a 13.4 percent increase in water rates, a 4.7 percent increase in electric rates, and a 0.6 percent decrease in natural gas rates). On an annualized basis, the rate increase will generate approximately $3 million in additional revenue.

Industrial Customers. Electric power is one of several key inputs in the taconite mining, paper production, and pipeline industries. Approximately 36 percent of our Regulated Utility kilowatt-hour sales were made to our industrial customers through the six months ended June 30, 2009, which includes the taconite, paper and pulp, and pipeline industries.

Strong worldwide steel demand, driven largely by extensive infrastructure development in China, resulted in very robust world iron ore demand and steel pricing for nearly a six year period which lasted through the summer of 2008. Between 2004 and 2008, annual taconite production averaged just over 40 million tons per year from taconite mines in Northeastern Minnesota. Beginning in the fall of 2008, worldwide steel makers began to dramatically cut steel production in response to reduced demand driven largely by the world credit situation. Currently, domestic raw steel production is at approximately 50 percent of capacity reflecting an increasing demand in automobiles, durable goods, structural, and other steel products. In late 2008, Minnesota taconite producers began to feel the impacts of decreased steel demand. As a result, reduced taconite production levels are occurring in 2009. Consequently, 2009 demand nominations for power from our taconite customers are lower by approximately 40 percent from 2008 levels. We continue to remarket available power to Other Power Suppliers in an effort to mitigate the earnings impact of these lower industrial sales. These sales are dependent upon the availability of generation and are sold at market based prices into the MISO market on a daily basis or through bilateral agreements of various durations. For 2009, we have successfully mitigated approximately 85 percent of the earnings impact.


 
ALLETE Second Quarter 2009 Form 10-Q
 
31

 

OUTLOOK (Continued)
Regulated Operations (Continued)

Renewable Generation Sources. In February 2007, Minnesota enacted a law requiring Minnesota Power to generate or procure 25 percent of its energy from renewable energy sources by 2025. The law also requires Minnesota Power to meet interim milestones of 12 percent by 2012, 17 percent by 2016, and 20 percent by 2020. The law allows the MPUC to modify or delay a standard obligation if implementation will cause significant ratepayer cost or technical reliability issues. If a utility is not in compliance with a standard, the MPUC may order the utility to construct facilities, purchase renewable energy or purchase renewable energy credits. Minnesota Power was developing and making renewable supply additions as part of its generation planning strategy prior to the enactment of this law and this activity continues. Minnesota Power believes it will meet the requirements of this legislation.

The areas in which we operate have strong wind, water, and biomass resources and provide us with opportunities to develop a number of renewable forms of generation. Our electric service area in Northeastern Minnesota is situated for delivery of renewable energy that is generated here and in adjoining regions. We intend to secure the most cost competitive and geographically advantageous renewable energy resources available. We believe that the demand for these resources is likely to grow, and the costs of the resources to generate renewable energy will continue to escalate. While we intend to maintain our disciplined approach to developing generation assets, we also believe that by acting sooner rather than later we can deliver lower cost power to our customers and maintain or improve our cost competitiveness among regional utilities. We will continue to work with our customers, our regulators and the communities we serve to develop generation options that reflect the needs of our customers as well as the environment. We believe that our location and our proactive leadership in developing renewable generation provide us with a competitive advantage. For more than a century, we have been Minnesota’s leading producer of renewable hydroelectric energy.

We are executing our renewable energy and environmental compliance strategy. Taconite Ridge Wind I, a $50 million, 25-MW wind facility located in Northeastern Minnesota became operational in 2008. In 2006 and 2007, we entered into two long-term purchase power agreements for a total of 98 MWs of wind energy constructed in North Dakota (Oliver Wind I and II); 366,945 megawatt-hours were purchased under these agreements in 2008.

North Dakota Wind Project. On July 7, 2009, the MPUC approved our plan petition to qualify for current cost recovery of investments and expenditures related to our Bison I Wind Project (Bison I) and associated transmission upgrades. We anticipate filing a petition with the MPUC in the near future to establish cost recovery and customer billing rates. Bison I is the first portion of several hundred MWs of our North Dakota Wind Project, which upon completion will complete the 2025 renewable energy supply requirement for our retail load. Bison I will be located near Center, North Dakota and will be comprised of 33 wind turbines with a total nameplate capacity of 75.9 MWs. In September 2008, we signed an agreement to purchase an existing 250 kV DC transmission line for approximately $80 million to transport this wind energy to our customers while gradually reducing the supply of energy currently delivered to our system on this same transmission line from Square Butte’s Unit. The transaction is subject to regulatory approvals and is anticipated to close in 2009. On May 14, 2009, we filed a petition with the MPUC for approval of the DC transmission line purchase and the restructuring of the power purchase agreement with Square Butte.

Integrated Resource Plan. On October 31, 2007, Minnesota Power filed its Integrated Resource Plan (IRP), a comprehensive estimate of future capacity needs within the Minnesota Power service territory. In October 2008, the MPUC issued an order approving our request to re-file the IRP by October 1, 2009 in order to incorporate the North Dakota Wind Project and otherwise update our load forecasting and modeling in the IRP.

Climate Change . We believe that future regulations may restrict the emissions of GHGs from our generation facilities. Several proposals at the Federal level to “cap” the amount of GHG emissions have been made. On June 26, 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act of 2009. H.R. 2454 is a comprehensive energy bill that also includes a cap and trade program. H.R. 2454 allocates a significant number of allowances to the electric utility sector to mitigate cost impacts on consumers. Congress may consider proposals other than cap and trade programs to address GHG emissions. We are unable to predict the outcome of H.R. 2454 or other efforts that Congress may make with respect to GHG emissions, and the impact that any GHG emission regulations may have on the Company.


 
ALLETE Second Quarter 2009 Form 10-Q
 
32

 

OUTLOOK (Continued)
Regulated Operations (Continued)

CapX 2020.   Minnesota Power is a participant in the CapX 2020 initiative which represents an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX 2020, which includes Minnesota’s largest transmission owners, consists of electric cooperatives, municipals and investor-owned utilities, and has assessed the transmission system and projected growth in customer demand for electricity through 2020. Studies show that the region's transmission system will require major upgrades and expansion to accommodate increased electricity demand as well as support renewable energy expansion through 2020.

The CapX 2020 participants filed a request for a Certificate of Need for three 345 kV lines and associated system interconnections with the MPUC in August 2007. The MPUC issued the Certificate of Need for these 345 kV lines in May 2009. The MPUC must now determine routes for the new lines in subsequent proceedings. Portions of the 345 kV lines will also require approvals by federal officials and by regulators in North Dakota, South Dakota and Wisconsin. A fourth line, a 70-mile, 230 kV line in north central Minnesota, is also among the CapX 2020 projects. A request for a Certificate of Need for this line was filed in March 2008, and a Route Permit application was filed in June 2008. The MPUC issued the Certificate of Need for the 230 kV line on July 9, 2009. The MPUC decision on routing is expected in 2010.

Minnesota Power may invest in two of the lines, a 250-mile 345 kV line between Fargo, North Dakota and Monticello, Minnesota, and a 70-mile, 230 kV line between Bemidji and Grand Rapids, Minnesota. Our total investment in these two lines is expected to be approximately $80 million. Upon receipt of the required Certificates of Need, we intend to include these costs in an annual filing with the MPUC for current cost recovery of the expenditures related to our investment in the lines under a Minnesota Power transmission cost recovery tariff rider mechanism authorized by Minnesota legislation. Construction of the lines is targeted to begin in 2010 and last approximately three to four years.

Boswell Unit 3 Emission Reduction Plan. We are making emission reduction investments at our Boswell Unit 3 generating unit. The investments in pollution control equipment will reduce particulates, SO 2 , NO X , and mercury emissions to meet future federal and state requirements. The MPUC has authorized a cash return on construction work in progress during the construction phase in lieu of AFUDC and allows for a return on investment and current cost recovery of incremental operations and maintenance expenses once the new equipment is installed and the unit is placed back in service in late 2009. We began cost recovery on January 1, 2008. In September 2008, we filed a petition with the MPUC to approve the Boswell Unit 3 billing factor adjustment for 2009. Pending approval, customers will continue to be billed under the 2008 billing factor previously approved by the MPUC.

Boswell NO X Reduction Plan. In September 2008, we submitted to the MPCA and MPUC a $92 million environmental initiative proposing cost recovery for NO X emission reductions from Boswell Units 1, 2, and 4. If approved by the MPUC, the Boswell NO X Reduction Plan is expected to significantly reduce NO X emissions from these units. In conjunction with the NO X reduction, we plan to install an efficiency improvement to the existing turbine/generator at Boswell Unit 4, adding approximately 60 MWs of total output with no additional emissions. Cost recovery for these projects will occur either through a current cost recovery rider or a rate case.

Transmission. In September 2008, in connection with our existing cost recovery rider for transmission expenditures, we filed a petition with the MPUC to approve our 2009 billing factor adjustment for ongoing transmission expenditures. The annual billing factor allows us to charge our retail customers on a current basis for the costs of constructing these facilities plus a return on the capital invested. These expenditures include the Badoura and Tower transmission projects and certain statutorily authorized MISO related transmission facility charges. The Badoura and Tower transmission projects are being developed to address transmission inadequacies in Northeastern Minnesota. Both projects will provide regional transmission benefits through increased voltage support and additional line capacity. The MPUC approved the 2009 billing factor adjustment in June 2009 allowing new rates to go into effect July 1, 2009.


 
ALLETE Second Quarter 2009 Form 10-Q
 
33

 

OUTLOOK (Continued)
Regulated Operations (Continued)

Investment in ATC. At June 30, 2009, our equity investment was $82.1 million, representing an approximate 8 percent ownership interest. 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. ATC rates are based on a 12.2 percent return on common equity dedicated to utility plant. ATC has identified $2.7 billion in future projects needed over the next 10 years to improve the adequacy and reliability of the electric transmission system. These investments are expected to be funded through a combination of internal cash, debt and investor contributions. As additional opportunities arise, we plan to make additional investments in ATC through general capital calls based upon our pro-rata ownership interest in ATC; these future capital investments are voluntary and not a long-term binding commitment. As of July 31, 2009, we have invested $5.4 million of the approximately $8 million for 2009.

Investments and Other

BNI Coal.   BNI Coal anticipates selling approximately 4.5 million tons of coal in 2009 (4.5 million tons were sold in 2008) and has sold approximately 2.2 million tons through June 30, 2009 (2.2 million tons sold as of June 30, 2008).

ALLETE Properties.   ALLETE Properties is our real estate business that has operated in Florida since 1991. Our current strategy is to complete and maintain key entitlements and infrastructure improvements which enhance values without requiring significant additional investment, and position the current property portfolio for a maximization of value and cash flow.

Our two major development projects include Town Center and Palm Coast Park. A third proposed development project, Ormond Crossings, is in the permitting and planning stage. 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.

Summary of Development Projects
   
                 Residential
           Non-residential
Land Available-for-Sale
Ownership
                 Acres (a)
                 Units (b)
           Sq. Ft. (b, c)
         
Current Development Projects
       
Town Center
80%
991
2,289
2,228,200
Palm Coast Park
100%
3,436
3,239
3,116,800
Total Current Development Projects
 
4,427
5,528
5,345,000
         
Proposed Development Project
       
Ormond Crossings
100%
5,968
(d)
(d)
         
Total of Development Projects
 
10,395
5,528
5,345,000

(a)
Acreage amounts are approximate and shown on a gross basis, including wetlands and non-controlling interest.
(b)
Estimated and includes non-controlling interest. Density at build out may differ from these estimates.
(c)
Depending on the project, non-residential includes retail commercial, non-retail commercial, office, industrial, warehouse, storage and institutional.
(d)
A development order approved by the City of Ormond Beach includes up to 3,700 residential units and 5 million square feet of non-residential space. We estimate the first two phases of Ormond Crossings will include 2,500-3,200 residential units and 2.5 million - 3.5 million square feet of various types of non-residential space.   Density of the residential and non-residential components of the project will be determined based upon market and traffic mitigation cost considerations. Approximately 2,000 acres will be devoted to a regionally significant wetlands mitigation bank.


Other Land Available-for-Sale (a)
Total
Mixed Use
Residential
Non-Residential
Agricultural
Acres (b)
         
Other Land
1,327
353
114
376
484

(a)
Other land available-for-sale   includes land located in Palm Coast, Florida not included in development projects and land held by Lehigh Acquisition Corporation and Cape Coral Holdings, Inc.
(b)
Acreage amounts are approximate and shown on a gross basis, including wetlands and non-controlling interest.

 
ALLETE Second Quarter 2009 Form 10-Q
 
34

 

OUTLOOK (Continued)
Investments and Other (Continued)

At June 30, 2009, total pending land sales under contract were $8.4 million ($12.4 million at December 31, 2008) and are scheduled to close at various times through 2010. However, given current market conditions it may be difficult to complete these closings by 2010. We continue to have discussions with our buyers under pending contracts. Our objective is to proactively assist our buyers through this current period of weak market conditions, as we believe the long-term prospects for our properties are favorable. Our discussions sometimes result in adjustments to contract terms, and may include extending closing dates, revised pricing or termination. If a purchaser defaults on a sales contract, the legal remedy is usually limited to terminating the contract and retaining the purchaser’s deposit. The property is then available for resale. In many cases, contract purchasers incur significant costs during due diligence, planning, designing and marketing the property before the contract closes, therefore they have substantially more at risk than the deposit.

At June 30, 2009, our finance receivables included $7.8 million due from an entity which filed for voluntary Chapter 11 bankruptcy protection in June 2009. The estimated fair value of the collateral relating to these receivables was greater than the $7.8 million amount due and no impairment was recorded.

Emerging Technology. We have the potential to recognize gains or losses on the sale of investments in our Emerging Technology Investments. We plan to sell investments in our Emerging Technology Investments when publicly traded 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 up to $0.5 million in additional investments in certain emerging technology holdings. 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 approximately 41 percent for 2009. On an ongoing basis, ALLETE has certain tax credits and other tax adjustments that will reduce the statutory rate to the expected effective tax rate. These tax credits and adjustments historically have included items such as investment tax credits, wind production tax credits, AFUDC-Equity, domestic manufacturer’s deduction, depletion, Medicare prescription reimbursement, as well as other items. The annual effective rate can also be impacted by such items as changes in income from operations before non-controlling 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. We expect our effective tax rate to be approximately 35 percent for 2009.


LIQUIDITY AND CAPITAL RESOURCES

Cash Flow Activities

ALLETE is well-positioned to meet the Company’s immediate cash flow needs, including the payment of future dividends. With our cash balance of approximately $72 million, $160.0 million in lines-of-credit which includes a committed, syndicated, unsecured revolving line of credit of $150.0 million, and a debt-to-capital ratio of 42 percent at June 30, 2009, we project sufficient capital availability through the immediate term. If needed, we have the flexibility to reduce our planned capital expenditure program to meet changing capital market conditions.

Operating Activities. Cash from operating activities was $63.7 million for the six months ended June 30, 2009 ($54.7 million for the six months ended June 30, 2008). Cash from operating activities was higher in 2009 due to higher depreciation and deferred tax expense in 2009 and the exclusion of non-operating asset sales in 2008. These increases were partially offset by lower net income and higher working capital requirements in 2009.

Investing Activities. Cash used for investing activities was $135.0 million for the six months ended June 30, 2009 ($96.6 million for the six months ended June 30, 2008). Cash used for investing activities was lower in 2008 due to the proceeds from the sale of assets (retail shopping center) in Winter Haven, Florida and available-for-sale securities.


 
ALLETE Second Quarter 2009 Form 10-Q
 
35

 

LIQUIDITY AND CAPITAL RESOURCES (Continued)

Financing Activities. Cash from financing activities was $41.7 million for the six months ended June 30, 2009 ($117.7 million for the six months ended June 30, 2008). Cash from financing activities was lower in 2009 than 2008 due to less debt issuance which was partially offset by the issuance of 1.5 million shares of common stock with net proceeds of approximately $27.9 million

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. Additionally, we have 4.2 million original issue shares of common stock available for issuance through a Distribution Agreement with KCCI, Inc. We have consolidated bank lines of credit aggregating $160.0 million, the majority of which expire in January 2012. 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.

Auction Rate Securities. Included in Available-for-Sale Securities, as of June 30, 2009, are $14.3 million ($15.2 million at December 31, 2008) of three auction rate municipal bonds with stated maturity dates ranging between 15 and 27 years. These ARS consist of guaranteed student loans insured or reinsured by the federal government. These ARS were historically auctioned every 35 days to set new rates and provided a liquidating event in which investors could either buy or sell securities. Beginning in 2008, the auctions have been unable to sustain themselves due to the overall lack of market liquidity and we have been unable to liquidate all of our ARS. As a result, we have classified the ARS as long-term investments and have the ability to hold these securities to maturity, until called by the issuer, or until liquidity returns to this market. In the meantime, these securities will pay a default rate which is above market interest rates.

The Company used a discounted cash flow model to determine the estimated fair value of its investment in the ARS as of June 30, 2009. The assumptions used in preparing the discounted cash flow model include the following: estimated interest rates, estimated discount rates (using yields of comparable traded instruments adjusted for illiquidity and other risk factors), amount of cash flows, and expected holding periods of the ARS. These inputs reflect the Company’s judgments about assumptions that market participants would use in pricing ARS including assumptions about risk. Based upon the results of the discounted cash flow model, the fact that these ARS consist of guaranteed student loans insured or reinsured by the federal government and recent market activity, no other-than-temporary impairment loss has been reported.

Securities. In January 2009, we issued $42.0 million in principal amount of First Mortgage Bonds (Bonds) in the private placement market. The Bonds mature January 15, 2019 and carry a coupon rate of 8.17 percent. We have the option to prepay all or a portion of the Bonds at our discretion, subject to a make-whole provision. The Bonds are subject to additional terms and conditions which are customary for this type of transaction. We are using the proceeds from the sale of the Bonds to fund utility capital expenditures and for general corporate purposes.

In February 2008, we entered into a Distribution Agreement with KCCI, Inc. with respect to the issuance and sale of up to 2.5 million shares of our common stock. In February 2009, we amended and restated the Distribution Agreement with KCCI, Inc. such that it now provides for the issuance and sale of up to 5.0 million shares of our common stock, without par value. The shares may be offered for sale, from time to time, in accordance with the terms of the agreement. For the six months ended June 30, 2009, 0.8 million shares of common stock were issued under this agreement resulting in net proceeds of $21.5 million.

In March 2009, we contributed 463,000 shares of ALLETE common stock, with an aggregate value of $12.0 million, to our pension plan. On May 19, 2009, we registered the 463,000 shares of ALLETE common stock with the SEC pursuant to Rule 424(b)(7).


 
ALLETE Second Quarter 2009 Form 10-Q
 
36

 

LIQUIDITY AND CAPITAL RESOURCES (Continued)

Financial Covenants. Our long-term debt arrangements contain customary covenants. In addition, 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 ratio of its Funded Debt to Total Capital of less than or equal to 0.65 to 1.00 measured quarterly. As of June 30, 2009 our ratio was approximately 0.40 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 June 30, 2009, ALLETE was in compliance with its financial covenants.

Off-Balance Sheet Arrangements

Off-balance sheet arrangements are summarized in our 2008 Form 10-K, with additional disclosure discussed in Note 14. Commitments, Guarantees and Contingencies of this Form 10-Q.

Capital Requirements

For the six months ended June 30, 2009, capital expenditures totaled $122.5 million ($144.3 million at June 30, 2008). The expenditures were primarily made in the Regulated Operations segment. Internally generated funds and additional long-term debt and equity issuances were the primary sources of funding.


ENVIRONMENTAL MATTERS AND OTHER

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. Due to restrictive environmental requirements through legislation and/or rulemaking in the future, 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 matters discussed in Note 14. Commitments, Guarantees and Contingencies of this Form 10-Q.


NEW ACCOUNTING STANDARDS

New accounting standards are discussed in Note 1. Operations and Significant Accounting Policies of this Form 10-Q.


ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

SECURITIES INVESTMENTS

Available-For-Sale Securities . As of June 30, 2009, our available-for-sale securities portfolio consisted of securities in a grantor trust, established to fund certain employee benefits, and ARS. (See Note 3. Investments.)

Emerging Technology Investments .   As part of our Emerging Technology Investments, we have several minority investments in venture capital funds and direct investments in privately-held, start-up companies.


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 credit to our ratepayers. We seek to prudently manage our customers’ exposure to price risk by entering into contracts of various durations and terms for the purchase of coal and power (in Minnesota), power and natural gas (in Wisconsin), and related transportation costs.
 
 
ALLETE Second Quarter 2009 Form 10-Q
37

 
ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (Continued)

POWER MARKETING

Our power marketing activities consist of (1) purchasing energy in the wholesale market for resale in our regulated service territories when retail energy requirements exceed generation output and (2) selling excess available energy and purchased power. From time to time, our utility operations may have excess energy that is temporarily not required by retail and wholesale customers in our regulated service territory. We actively sell this energy to the wholesale market to optimize the value of our generating facilities.

Demand nominations for power from our taconite customers in 2009 are lower by approximately 40 percent from 2008 levels. We continue to remarket available power to Other Power Suppliers in an effort to mitigate the earnings impact of these lower industrial sales. These sales are dependent upon the availability of generation and are sold at market based prices into the MISO market on a daily basis or through bilateral agreements of various durations. For 2009, we have successfully mitigated approximately 85 percent of the earnings impact.

In 2009, we have entered into financial and commodity swap derivative instruments to manage price risk for certain power marketing contracts. These derivative instruments are recorded on our consolidated balance sheet at fair value. Changes in the derivatives’ fair value are recognized currently in earnings unless specific hedge accounting criteria is met. As of June 30, 2009, we have recorded approximately $2.3 million of derivatives in other assets on our consolidated balance sheet. Of this total, $0.1 million has been designated as a cash flow hedge and any mark-to-market fluctuations have been recorded in other comprehensive income on the consolidated balance sheet. (See Note 4. Derivatives.)

Approximately 200 MWs of capacity and energy from our Taconite Harbor facility in northern Minnesota has been sold through two sales contracts totaling 175 MWs (201 MWs including a 15 percent 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 the fixed minimum charge or an annual 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 liability. Outages with less than two months notice are subject to an annual duration limitation typical of this type of contract. These contracts qualify for the normal purchase normal sale exception under SFAS 133 “Accounting for Derivative Instruments and Hedging Activities” and are not required to be recorded at fair value.

We are exposed to credit risk primarily through our power marketing activities. We use credit policies to manage credit risk, which includes utilizing an established credit approval process and monitoring counterparty limits.

INTEREST RATE RISK

We are also 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. Interest rates on variable rate long-term debt are reset on a periodic basis reflecting current market conditions. Based on the variable rate debt outstanding at June 30, 2009, and assuming no other changes to our financial structure, an increase or decrease of 100 basis points in interest rates 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 outstanding as of June 30, 2009.


 
ALLETE Second Quarter 2009 Form 10-Q
 
38

 

ITEM 4.  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures. As of June 30, 2009, evaluations were performed, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of the design and operation of ALLETE’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)). Based upon those evaluations, our principal executive officer and principal financial officer have concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in ALLETE’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Controls. While we continue to enhance our internal control over financial reporting, there has been no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.


PART II.  OTHER INFORMATION


ITEM 1.  LEGAL PROCEEDINGS

None.


ITEM 1A.  RISK FACTORS

None.


ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.


ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

None.


ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

(a)              We held our Annual Meeting of Shareholders on May 12, 2009.

(b)              Included in (c) below.

(c)
The election of directors, the ratification of the appointment of PricewaterhouseCoopers LLP as the Company’s independent registered public accounting firm for 2009, and the amendment of Article III and the deletion of Article V of ALLETE’s Amended and Restated Articles of Incorporation were voted on at the 2009 Annual Meeting of Shareholders.

 
ALLETE Second Quarter 2009 Form 10-Q
 
39

 

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS (Continued)

The results were as follows:

 
                 Votes For
                       Withheld
   
Directors
       
         
Kathleen A. Brekken
26,944,114
359,750
   
Heidi J. Eddins
26,991,269
312,594
   
Sidney W. Emery, Jr.
26,953,869
349,994
   
James J. Hoolihan
26,833,220
470,644
   
Madeleine W. Ludlow
26,972,791
331,072
   
George L. Mayer
26,897,929
405,934
   
Douglas C. Neve
27,018,456
285,407
   
Jack I. Rajala
20,938,156
6,365,708
   
Leonard C. Rodman
26,895,550
408,313
   
Donald J. Shippar
26,803,979
499,884
   
Bruce W. Stender
26,824,142
479,721
   


 
                 Votes For
                       Votes
                       Against
           Abstentions
           Broker
           Nonvotes
Independent Registered
Public Accounting Firm
       
         
PricewaterhouseCoopers LLP
27,010,433
558,949
151,120


 
                 Votes For
                       Votes
                       Against
           Abstentions
           Broker
           Nonvotes
ALLETE’s Amended and Restated Articles of Incorporation
       
         
Amend Article III
22,092,287
5,374,224
253,990
Delete Article V
25,628,952
1,711,893
379,657

(d)              Not applicable.


ITEM 5.  OTHER INFORMATION

Reference is made to our 2008 Form 10-K for background information on the following updates.

Ref. Page 12 – Regulated Operations, Minnesota Public Utilities Commission – First Paragraph

On May 2, 2008, Minnesota Power filed a rate increase request with the MPUC. On May 4, 2009, the MPUC issued its order (May Order) on the rate filing, and on June 25, 2009, the MPUC reconsidered the May Order. While the reconsideration order has not been issued, we expect the MPUC reconsideration to result in an authorized rate increase of $20.4 million (slightly below the $21.1 million outcome in its May Order). The May Order allowing a 10.74 percent return on common equity and a capital structure consisting of 54.79 percent equity and 45.21 percent debt remains unchanged.

The reconsideration decision reduced Minnesota Power’s interim rates, which are in effect between August 2008 and the date final rates are implemented, by $6.3 million annually to approximately $15 million. This increases Minnesota Power’s refunding obligation for 2008 and 2009. Any party may appeal the final order to the Minnesota Court of Appeals. We will continue collecting interim rates until the new rates go into effect, which will be after the appeal period and all compliance filings are completed and accepted. Appeal of the final order or modifications during compliance could affect the final rate increase.


 
ALLETE Second Quarter 2009 Form 10-Q
 
40

 

ITEM 5.  OTHER INFORMATION (Continued)

With the May Order, the MPUC also approved the stipulation and settlement agreement that affirmed the Company’s continued recovery of fuel and purchased power costs under the former base cost of fuel that was in effect prior to the retail rate filing. The transition to the former base cost of fuel will occur upon implementation of final rates. Any revenue impact associated with the transition will be identified in the fourth quarter.

As of June 30, 2009, we recorded a $16.4 million liability, including interest, for refunds anticipated to be paid to our customers as a result of the MPUC decision on our retail rate filing. Current year rate refunds totaling $8.3 million have been recorded on our consolidated statement of income and prior year rate refunds totaling $7.6 million are stated separately. Interest expense of $0.5 million was also recorded on our consolidated statement of income related to rate refunds. Refunds will commence when final rates are effective.

Ref. Page 18 – Employees – Second Paragraph

Minnesota Power, SWL&P and IBEW Local 31, continue to work under contract extensions of the agreements which expired on January 31, 2009. On April 10, 2009, IBEW Local 31 requested binding arbitration in accordance with the provisions of the contracts. The contracts also provide Minnesota Power and SWL&P with the protections of no strike clauses. Arbitrations are scheduled in October with final resolutions anticipated in November 2009. We remain optimistic that we will achieve a fair and equitable result in both agreements.

Ref. Page 20 – Executive Officers of the Registrant

Executive Officer
Initial Effective Date
Donald J. Shippar , Age 60
 
Chairman and Chief Executive Officer
May 12, 2009
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
   
Alan R. Hodnik , Age 50
 
President – ALLETE
May 12, 2009
Chief Operating Officer – Minnesota Power
May 8, 2007
Senior Vice President – Minnesota Power Operations
September 22, 2006
Vice President – Minnesota Power Generation
May 1, 2005



 
ALLETE Second Quarter 2009 Form 10-Q
 
41

 

ITEM 6.  EXHIBITS

Exhibit
Number

 





 

 


 
 
ALLETE Second Quarter 2009 Form 10-Q
 
42

 

 


Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


   
ALLETE, INC.
     
     
     
     
August 5, 2009
 
/s/ Mark A. Schober
   
Mark A. Schober
   
Senior Vice President and Chief Financial Officer
     
     
     
     
     
August 5, 2009
 
/s/ Steven Q. DeVinck
   
Steven Q. DeVinck
   
Controller


 
ALLETE Second Quarter 2009 Form 10-Q
 
43

 

Exhibit 3

ARTICLES OF AMENDMENT
OF
ALLETE, INC.
 

 
Amending paragraph 1, Article III and Deleting Article V
of ALLETE, Inc.’s Articles of Incorporation
as Amended and Restated as of May 8, 2001
and as previously amended as of September 20, 2004



ARTICLE III

1.           The total authorized number of shares of capital stock of this Corporation shall be 83,616,000 of which 116,000 shares of the par value of $100 each shall be 5% Preferred Stock, 1,000,000 shares without par value shall be Serial Preferred Stock, 2,500,000 shares without par value shall be Serial Preferred Stock A and 80,000,000 shares without par value shall be Common Stock. Any of the aforesaid shares may be issued and disposed of by the Board of Directors at any time and from time to time, to such persons, firms, corporations, or associations, upon such terms and for such consideration as the Board of Directors may, in its discretion, determine, except as may be limited by law or by these Articles of Incorporation.


ARTICLE V

[Deleted and intentionally reserved.]


 
 

 

Exhibit 10(a)
 
 
 
 
 
 
 
 
ALLETE
 
 
AMENDED AND RESTATED
 
 
NON-EMPLOYEE DIRECTOR COMPENSATION DEFERRAL PLAN II
 
 
Effective May 1, 2009
 
 
 
 
 
 
 
 
 
 
 
 
 

 
 

 

TABLE OF CONTENTS
 

 
HEADING
PAGE
       
ARTICLE 1
Establishment and Purpose
1
       
ARTICLE 2
Administration
1
 
2.1
Administrator
1
 
2.2
Duties
1
 
2.3
Agents
1
 
2.4
Binding Effect of Decisions
2
 
2.5
Company Information
2
       
ARTICLE 3
Participation
2
       
ARTICLE 4
Deferral Elections
2
 
4.1
Annual Deferral Election
2
 
4.2
Initial Deferral Election
2
 
4.3
Cancellations of Deferral Elections due to Unforeseeable Emergency
3
       
ARTICLE 5
Accounts
3
 
5.1
Accounts
3
 
5.2
Cash Account
3
   
5.2.1
Establishment of Cash Account
3
   
5.2.2
Timing of Credits to Cash Accounts
3
   
5.2.3
Investments
3
   
5.2.4
Valuation Date
4
 
5.3
Stock Account
4
   
5.3.1
Establishment of Stock Account
4
   
5.3.2
Credits to Stock Accounts
4
   
5.3.3
Dividend Equivalents
4
   
5.3.4
Adjustments in Case of Changes in Common Stock
4
       
ARTICLE 6
Distributions
5
 
6.1
Distributions
5
   
6.1.1
Specified Year
5
   
6.1.2
Separation from Service
6
   
6.1.3
Unforeseeable Emergency
6
 
6.2
Additional Distribution Rules
6
   
6.2.1
Medium of Payment
6
   
6.2.2
Default Time and Form of Payment
6
   
6.2.3
Rules Applicable to All Distributions
6
   
6.2.4
Installment Payments
7
   
6.2.5
Death After Commencement of Distributions
7
 
6.3
Subsequent Changes in Time and Form of Payment
7
       
ARTICLE 7
Payment Acceleration and Delay
8
 
7.1
Permitted Accelerations of Payment
8
 
7.2
Permissible Distribution Delays
8
 
7.3
Suspension Not Allowed
8
       
ARTICLE 8
Beneficiary Designation
9
 
8.1
Beneficiary
9
 
8.2
No Beneficiary Designation
9
       
ARTICLE 9
Claims Procedures
9
       
ARTICLE 10
Amendment or Termination
10
       
ARTICLE 11
Miscellaneous Provisions
10
 
11.1
Unsecured General Creditor
10
 
11.2
Trust Fund
10
 
11.3
Section 409A Compliance
10
 
11.4
Company’s Liability
10
 
11.5
Nonassignability
11
 
11.6
No Right to Board Position
11
 
11.7
Incompetency
11
 
11.8
Furnishing Information
11
 
11.9
Notice
11
 
11.10
Compliance with Government Regulations
11
 
11.11
Exchange Act Exemption
12
 
11.12
Gender and Number
12
 
11.13
Headings
12
 
11.14
Applicable Law and Construction
12
 
11.15
Invalid or Unenforceable Provisions
12
 
11.16
Successors
12
       
ARTICLE 12
Definitions
13


 

 


ALLETE
AMENDED AND RESTATED
NON-EMPLOYEE DIRECTOR COMPENSATION DEFERRAL PLAN II

 
Effective May 1, 2009
 
ARTICLE 1
 
Establishment and Purpose
 
This document includes the terms of the ALLETE Amended and Restated Non-Employee Director Compensation Deferral Plan II, the purpose of which is to provide Directors an opportunity to elect to defer his or her Annual Retainer.  The Plan is a successor to the ALLETE Director Compensation Deferral Plan (the “Predecessor Plan”).  On December 31, 2004, the Company froze the Predecessor Plan, and on January 1, 2005, the Company established the Plan to govern amounts initially deferred after December 31, 2004 and investment earnings thereon.  From January 1, 2005 to the effective date hereof, the Company operated and administered the Plan in all material respects in good faith compliance with the applicable requirements of Section 409A, the final and proposed Treasury Regulations, IRS Notice 2005-1, and all other IRS guidance.  Effective January 1, 2009, the Company amended and restated the Plan in its entirety to comply with Section 409A.  Effective May 1, 2009, the Company further amends and restates the Plan to expand the types of compensation that Directors may defer.  Capitalized terms, unless otherwise defined herein, shall have the meaning provided in Article 12.
 
ARTICLE 2
 
Administration
 
2.1  
Administrator .   The Executive Compensation Committee of the Board shall administer the Plan.  Notwithstanding the foregoing, the Administrator may delegate any of its duties to such other person or persons from time to time as it may designate.  Members of the Executive Compensation Committee may participate in the Plan; however, any Director serving on the Executive Compensation Committee shall not vote or act on any matter relating solely to himself or herself.
 
2.2  
Duties .   The Administrator has the authority to construe and interpret all provisions of the Plan, to resolve any ambiguities, to adopt rules and practices concerning the administration of the Plan, to make any determinations and calculations necessary or appropriate hereunder, and, to the maximum extent permitted by Section 409A, the authority to remedy any errors, inconsistencies or omissions.  The Company shall pay all expenses and liabilities incurred in connection with Plan administration.
 
2.3  
Agents .   The Administrator may engage the services of accountants, attorneys, actuaries, investment consultants, and such other professional personnel as are deemed necessary or advisable to assist in fulfilling the Administrator’s responsibilities.  The Administrator, the Company and the Board may rely upon the advice, opinions or valuations of any such persons.
 
 
1

 
2.4  
Binding Effect of Decisions .   The decision or action of the Administrator with respect to any question arising out of or in connection with the administration, interpretation and application of the Plan and the rules and regulations promulgated hereunder shall be final, conclusive and binding upon all persons having any interest in the Plan.  Neither the Administrator, its delegates, nor the Board shall be personally liable for any good faith action, determination or interpretation with respect to the Plan, and each shall be fully protected by the Company in respect of any such action, determination or interpretation.
 
2.5  
Company Information .   To enable the Administrator to perform its duties, the Company shall supply full and timely information to the Administrator on all matters relating to the Annual Retainer, the Directors, the date and circumstances of a Director’s Separation from Service, and other pertinent information as the Administrator may reasonably require.
 
ARTICLE 3
 
Participation
 
Directors may participate in the Plan.  Each Plan Year, the Administrator shall notify Directors of their eligibility to participate in the Plan and defer compensation to be paid on account of services as a Director during the next Service Period.  A Director who is eligible to participate shall become a participant by completing an election form on which the Director elects to defer some or all of his or her Annual Retainer and delivering the completed form to the Company as specified in the Plan.  The terms of this Plan shall continue to govern a Director’s Accounts until the Accounts are paid in full.
 
ARTICLE 4
 
Deferral Elections
 
4.1  
Annual Deferral Election .   Each Plan Year, a Director may elect:  (i) to defer some or all of the Director’s Annual Cash Retainer, the Annual Stock Retainer, or both, attributable to the next Service Period; and (ii) to the extent permitted by this Plan, the time and form of distribution of Cash Deferrals and Stock Deferrals.  Elections become irrevocable no later than the date specified by the Administrator, but in any event before the beginning of the Plan Year with which or during which occurs the Service Period to which the elections relate.  A Director’s election will become effective only if the forms required by the Administrator have been properly completed and signed by the Director, timely delivered to, and accepted by, the Administrator.  A Director who fails to file the election before the required date will be treated as having elected not to defer any portion of the Annual Retainer for the following Service Period.
 
4.2  
Initial Deferral Election.   A Director who first becomes eligible to participate in the Plan during a Plan Year may elect to defer some or all of the Director’s Annual Cash Retainer and Annual Stock Retainer by filing a signed election form with the Administrator no later than 30 days after the Director first becomes eligible to participate in the Plan.  Such election shall be effective only with respect to the Director’s Annual Retainer earned after the filing of such election.  The election shall become irrevocable with respect to the Service Period covered by the election on the 30th day following the date on which the Director first becomes eligible to participate in the Plan.  This election relating to initial participation in the Plan is available only to Directors who do not participate in any other nonqualified deferred compensation elective account balance plans (within the meaning of Section 409A) maintained by the Company or any Related Company.  If a Director whose participation in the Plan is terminated again becomes a Director, he or she may elect to defer pursuant to this Section only if the Director was ineligible to defer compensation in this Plan and all other Related Company elective account balance plans for the 24 months preceding the date on which the Director again became eligible to participate in this Plan.
 
 
2

 
4.3  
Cancellations of Deferral Elections due to Unforeseeable Emergency.   If a Director experiences an Unforeseeable Emergency, the Director may submit to the Administrator a written request to cancel Deferrals for the Service Period to satisfy the Unforeseeable Emergency.  If the Administrator either approves the Director’s request to cancel Deferrals for the Service Period, or approves a request for a distribution of prior Deferrals in accordance with Section 6.1.3, then effective as of the date the request is approved the Administrator shall cancel the Director’s deferral elections for the remainder of the Service Period.  A Director whose Deferrals are canceled in accordance with this section may elect Deferrals for the following Service Period.
 
ARTICLE 5
 
Accounts
 
5.1  
Accounts .   The Company will establish notional accounts and sub-accounts for each Director as the Administrator deems necessary or advisable from time to time.  The Company will establish a Director’s Accounts during the year in which the Director first elects to defer any amounts.  All amounts in a Director’s Accounts are fully vested at all times.
 
5.2   
Cash Account .
 
5.2.1  
Establishment of Cash Account .   The Company shall establish and maintain a Cash Account for each Director who has elected to defer any portion of the Annual Cash Retainer.  A Director’s Cash Account shall be credited as appropriate for Cash Deferrals and earnings with respect to Cash Deferrals and debited for distributions from the Cash Account.
 
5.2.2  
Timing of Credits to Cash Accounts .   No later than the end of the calendar year during which the Company would otherwise have paid the Annual Cash Retainer to the Director but for the Director’s deferral election, the Administrator shall credit the Director’s Cash Account with an amount equal to the portion of the Annual Cash Retainer that the Director elected to defer.
 
5.2.3  
Investments .   The Administrator may select investment funds to use for measuring notional gains and losses with respect to Cash Deferrals.  The Administrator will establish, from time to time, rules and procedures for allowing each Director who has not had a Separation from Service to designate which one or more of the selected investment funds will be used to determine the notional gains and losses credited or debited to the Director’s Cash Account prior to Separation from Service.
 
 
3