ALLETE
ALLETE INC (Form: 10-Q, Received: 08/05/2011 08:02:40)
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, 2011
 
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).    T 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,
36,454,263 shares outstanding
as of June 30, 2011

 
 
 
 

 

INDEX

     
Page
       
Definitions
   
3
       
Safe Harbor Statement   Under the Private Securities Litigation Reform Act of 1995
5
       
Part I.
Financial Information
 
       
 
Item 1.
Financial Statements (Unaudited)
 
       
 
Consolidated Balance Sheet -
 
   
June 30, 2011 and December 31, 2010
6
       
 
Consolidated Statement of Income -
 
   
Quarter and Six Months Ended June 30, 2011 and 2010
7
       
 
Consolidated Statement of Cash Flows -
 
   
Six Months Ended June 30, 2011 and 2010
8
       
 
Notes to Consolidated Financial Statements
9
       
 
Item 2.
Management’s Discussion and Analysis of Financial Condition
and Results of Operations
27
       
 
Item 3.
Quantitative and Qualitative Disclosures about Market Risk
41
       
 
Item 4.
Controls and Procedures
42
       
Part II.
Other Information
 
       
 
Item 1.
Legal Proceedings
42
       
 
Item 1A.
Risk Factors
42
       
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
42
       
 
Item 3.
Defaults Upon Senior Securities
43
       
 
Item 4.
Reserved
43
       
 
Item 5.
Other Information
43
       
 
Item 6.
Exhibits
43
       
Signatures
   
44
 

ALLETE Second Quarter 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
 
AC
Alternating Current
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
ARS
Auction Rate Securities
ATC
American Transmission Company LLC
Bison 1
Bison 1 Wind Project
Bison 2
Bison 2 Wind Project
Bison 3
Bison 3 Wind Project
BNI Coal
BNI Coal, Ltd.
Boswell
Boswell Energy Center
CO 2
Carbon Dioxide
Company
ALLETE, Inc. and its subsidiaries
DC
Direct Current
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
GAAP
United States Generally Accepted Accounting Principles
GHG
Greenhouse Gases
Hibbard
Hibbard Renewable Energy Center
Invest Direct
ALLETE’s Direct Stock Purchase and Dividend Reinvestment Plan
kV
Kilovolt(s)
Laskin
Laskin Energy Center
Manitoba Hydro
Manitoba Hydro-Electric Board
Medicare Part D
Medicare Part D provision of the Patient Protection and Affordable Care Act of 2010
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)


ALLETE Second Quarter Form 10-Q
 
3

 
 
Definitions (Continued)
 
Abbreviation or Acronym
 
Term
NAAQS
National Ambient Air Quality Standards
NDPSC
North Dakota Public Service Commission
Non-residential
Retail commercial, non-retail commercial, office, industrial, warehouse, storage and institutional
NO 2
Nitrogen Dioxide
NO X
Nitrogen Oxide
Note ___
Note ___ to the consolidated financial statements in this Form 10-Q
NPDES
National Pollutant Discharge Elimination System
Oliver Wind I
Oliver Wind I Energy Center
Oliver Wind II
Oliver Wind II Energy Center
Palm Coast Park
Palm Coast Park development project in Florida
Palm Coast Park District
Palm Coast Park Community Development District
PPA
Power Purchase Agreement
PPACA
The Patient Protection and Affordable Care Act of 2010
PSCW
Public Service Commission of Wisconsin
Rainy River Energy
Rainy River Energy Corporation - Wisconsin
SEC
Securities and Exchange Commission
SO 2
Sulfur Dioxide
Square Butte
Square Butte Electric Cooperative
SWL&P
Superior Water, Light and Power Company
Taconite Harbor
Taconite Harbor Energy Center
Taconite Ridge
Taconite Ridge 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 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;
  ·
prevailing governmental policies, regulatory actions, and legislation, including those of the United States Congress, state legislatures, the FERC, the MPUC, the PSCW, the NDPSC, the EPA and various state, 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;
  ·
our ability to manage expansion and integrate acquisitions;
  ·
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 and capital 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 22 of our 2010 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 Form 10-Q
 
5

 

PART I.  FINANCIAL INFORMATION
ITEM 1.  FINANCIAL STATEMENTS

ALLETE
CONSOLIDATED BALANCE SHEET
Millions – Unaudited

 
June 30,
December 31,
 
2011
2010
     
Assets
   
Current Assets
   
Cash and Cash Equivalents
$79.4
$44.9
Short-Term Investments
6.7
Accounts Receivable (Less Allowance of $1.0 and $0.9)
71.9
99.5
Inventories
61.3
60.0
Prepayments and Other
20.6
28.6
Total Current Assets
233.2
239.7
Property, Plant and Equipment - Net
1,861.1
1,805.6
Regulatory Assets
290.2
310.2
Investment in ATC
96.3
93.3
Other Investments
129.0
126.0
Other Non-Current Assets
35.7
34.3
Total Assets
$2,645.5
$2,609.1
     
Liabilities and Equity
   
Liabilities
   
Current Liabilities
   
Accounts Payable
$44.4
$75.4
Accrued Taxes
19.8
22.0
Accrued Interest
12.8
13.4
Long-Term Debt Due Within One Year
12.9
13.4
Notes Payable
2.5
1.0
Other
23.6
33.7
Total Current Liabilities
116.0
158.9
Long-Term Debt
770.7
771.6
Deferred Income Taxes
353.8
325.2
Regulatory Liabilities
43.4
43.6
Defined Benefit Pension and Other Postretirement Benefit Plans
222.9
231.4
Other Non-Current Liabilities
100.9
93.4
Total Liabilities
1,607.7
1,624.1
     
Commitments and Contingencies (Note 13)
   
     
Equity
   
ALLETE’s Equity
   
Common Stock Without Par Value, 80.0 Shares Authorized, 36.5 and 35.8 Shares Outstanding
660.1
636.1
Unearned ESOP Shares
(32.4)
(36.8)
Accumulated Other Comprehensive Loss
(21.3)
(23.2)
Retained Earnings
422.6
399.9
Total ALLETE Equity
1,029.0
976.0
Non-Controlling Interest in Subsidiaries
8.8
9.0
Total Equity
1,037.8
985.0
Total Liabilities and Equity
$2,645.5
$2,609.1

The accompanying notes are an integral part of these statements.

 
ALLETE Second Quarter Form 10-Q
 
6

 

ALLETE
CONSOLIDATED STATEMENT OF INCOME
Millions Except Per Share Amounts – Unaudited

 
Quarter Ended
Six Months Ended
 
June 30,
June 30,
 
2011
2010
2011
2010
         
Operating Revenue
$219.9
$211.2
$462.1
$444.8
         
Operating Expenses
       
Fuel and Purchased Power
76.0
74.3
155.0
154.1
Operating and Maintenance
95.7
85.4
185.8
173.1
Depreciation
22.1
19.8
44.4
39.8
Total Operating Expenses
193.8
179.5
385.2
367.0
         
Operating Income
26.1
31.7
76.9
77.8
         
Other Income (Expense)
       
Interest Expense
(11.0)
(9.5)
(21.7)
(18.4)
Equity Earnings in ATC
4.6
4.4
9.0
8.9
Other
1.0
2.2
1.8
3.2
Total Other Expense
(5.4)
(2.9)
(10.9)
(6.3)
         
Income Before Non-Controlling Interest and Income Taxes
20.7
28.8
66.0
71.5
Income Tax Expense
3.8
9.4
12.0
29.3
Net Income
16.9
19.4
54.0
42.2
Less: Non-Controlling Interest in Subsidiaries
(0.1)
(0.2)
(0.2)
Net Income Attributable to ALLETE
$17.0
$19.4
$54.2
$42.4
         
Average Shares of Common Stock
       
Basic
35.0
34.1
34.8
34.0
Diluted
35.1
34.2
34.9
34.1
         
Basic Earnings Per Share of Common Stock
$0.49
$0.57
$1.56
$1.25
Diluted Earnings Per Share of Common Stock
$0.48
$0.57
$1.55
$1.25
         
Dividends Per Share of Common Stock
$0.445
$0.44
$0.89
$0.88

The accompanying notes are an integral part of these statements.


ALLETE Second Quarter Form 10-Q
 
7

 
 
ALLETE
CONSOLIDATED STATEMENT OF CASH FLOWS
Millions – Unaudited

 
Six Months Ended
 
June 30,
 
2011
2010
     
Operating Activities
   
Net Income
$54.0
$42.2
Allowance for Funds Used During Construction
(1.1)
(2.1)
Income from Equity Investments, Net of Dividends
(0.9)
(1.4)
Gain on Sale of Assets
(0.7)
(0.7)
Depreciation Expense
44.4
39.8
Amortization of Debt Issuance Costs
0.5
0.5
Deferred Income Tax Expense
11.8
23.1
Share-Based Compensation Expense
1.1
1.1
ESOP Compensation Expense
3.6
3.5
Bad Debt Expense
0.5
0.5
Changes in Operating Assets and Liabilities
   
Accounts Receivable
27.2
10.1
Inventories
(1.3)
(0.1)
Prepayments and Other
8.0
2.4
Accounts Payable
(17.7)
(10.4)
Other Current Liabilities
(10.1)
(3.7)
Changes in Regulatory and Other Non-Current Assets
(2.5)
5.1
Changes in Defined Benefit Pension and Other Postretirement Benefit Plans
(8.5)
(0.4)
Changes in Regulatory and Other Non-Current Liabilities
21.7
(1.0)
Cash from Operating Activities
130.0
108.5
     
Investing Activities
   
Proceeds from Sale of Available-for-sale Securities
7.2
0.5
Payments for Purchase of Available-for-sale Securities
(1.2)
(1.4)
Investment in ATC
(1.4)
(1.2)
Changes to Other Investments
(1.4)
(0.6)
Additions to Property, Plant and Equipment
(91.6)
(79.5)
Proceeds from Sale of Assets
1.4
Cash for Investing Activities
(87.0)
(82.2)
     
Financing Activities
   
Proceeds from Issuance of Common Stock
22.9
15.2
Proceeds from Issuance of Long-Term Debt
80.0
Payments on Long-Term Debt
(1.5)
(69.9)
Debt Issuance Costs
(0.7)
Dividends on Common Stock
(31.4)
(30.8)
Changes in Notes Payable
1.5
(0.5)
Cash for Financing Activities
(8.5)
(6.7)
     
Change in Cash and Cash Equivalents
34.5
19.6
Cash and Cash Equivalents at Beginning of Period
44.9
25.7
     
Cash and Cash Equivalents at End of Period
$79.4
$45.3

The accompanying notes are an integral part of these statements.

 
ALLETE Second Quarter 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, 2010, 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. Operating results for the periods ended June 30, 2011, are not necessarily indicative of results that may be expected for any other interim periods or for the year ending December 31, 2011. For further information, refer to the consolidated financial statements and notes included in our 2010 Form 10-K.


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
2011
2010
Millions
   
Fuel
$23.5
$22.9
Materials and Supplies
37.8
37.1
Total Inventories
$61.3
$60.0


 
June 30,
December 31,
Prepayments and Other Current Assets
2011
2010
Millions
   
Deferred Fuel Adjustment Clause
$15.0
$20.6
Other
5.6
8.0
Total Prepayments and Other Current Assets
$20.6
$28.6


 
June 30,
December 31,
Other Non-Current Liabilities
2011
2010
Millions
   
Asset Retirement Obligation
$52.0
$50.3
Other
48.9
43.1
Total Other Non-Current Liabilities
$100.9
$93.4

Supplemental Statement of Cash Flows Information.

For the Six Months Ended June 30,
2011
2010
Millions
   
Cash Paid During the Period for Interest – Net of Amounts Capitalized
$21.9
$16.3
Cash Paid During the Period for Income Taxes
$0.4
$1.5
     
Noncash Investing and Financing Activities
   
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment
$(13.2)
$4.4
AFUDC – Equity
$1.1
$2.1

Subsequent Events. The Company performed an evaluation of subsequent events for potential recognition and disclosure through the time of the financial statements issuance.

New Accounting Standards.

Fair Value. In May 2011, the FASB issued an accounting standards update on fair value measurement. This update requires disclosure of a sensitivity analysis for fair value measurements within Level 3 and the valuation processes used. This guidance is effective for the quarter ended March 31, 2012, and is not expected to have a material impact on our consolidated financial position, results of operations or cash flows.

 
ALLETE Second Quarter Form 10-Q
 
9

 

NOTE 1.  OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Statement of Comprehensive Income. In June 2011, the FASB issued an accounting standards update on the presentation of comprehensive income. This guidance will be effective for the quarter ended March 31, 2012 and will modify our presentation of other comprehensive income, moving it from the footnotes to the face of the financial statements in a single, continuous statement of comprehensive income. The components of net income and other comprehensive income are unchanged and EPS continues to be based on net income.


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 investment. This segment also includes a small amount of non-rate base generation, land available-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, 2011
     
Operating Revenue
$219.9
$201.8
$18.1
Fuel and Purchased Power Expense
76.0
76.0
Operating and Maintenance Expense
95.7
77.2
18.5
Depreciation Expense
22.1
20.9
1.2
Operating Income (Loss)
26.1
27.7
(1.6)
Interest Expense
(11.0)
(9.1)
(1.9)
Equity Earnings in ATC
4.6
4.6
Other Income
1.0
0.6
0.4
Income (Loss) Before Non-Controlling Interest and Income
Taxes
20.7
23.8
(3.1)
Income Tax Expense (Benefit)
3.8
5.5
(1.7)
Net Income (Loss)
16.9
18.3
(1.4)
Less: Non-Controlling Interest in Subsidiaries
(0.1)
(0.1)
Net Income (Loss) Attributable to ALLETE
$17.0
$18.3
$(1.3)


 
Regulated
Investments
 
Consolidated
Operations
and Other
Millions
     
For the Quarter Ended June 30, 2010
     
Operating Revenue
$211.2
$194.1
$17.1
Fuel and Purchased Power Expense
74.3
74.3
Operating and Maintenance Expense
85.4
69.3
16.1
Depreciation Expense
19.8
18.7
1.1
Operating Income (Loss)
31.7
31.8
(0.1)
Interest Expense
(9.5)
(7.7)
(1.8)
Equity Earnings in ATC
4.4
4.4
Other Income
2.2
1.1
1.1
Income (Loss) Before Non-Controlling Interest and Income
Taxes
28.8
29.6
(0.8)
Income Tax Expense (Benefit)
9.4
11.4
(2.0)
Net Income
19.4
18.2
1.2
Less: Non-Controlling Interest in Subsidiaries
Net Income Attributable to ALLETE
$19.4
$18.2
$1.2


ALLETE Second Quarter Form 10-Q
 
10

 

NOTE 2.  BUSINESS SEGMENTS (Continued)

 
Regulated
Investments
 
Consolidated
Operations
and Other
Millions
     
For the Six Months Ended June 30, 2011
     
Operating Revenue
$462.1
$424.8
$37.3
Fuel and Purchased Power Expense
155.0
155.0
Operating and Maintenance Expense
185.8
148.4
37.4
Depreciation Expense
44.4
42.1
2.3
Operating Income (Loss)
76.9
79.3
(2.4)
Interest Expense
(21.7)
(17.7)
(4.0)
Equity Earnings in ATC
9.0
9.0
Other Income
1.8
1.2
0.6
Income (Loss) Before Non-Controlling Interest and Income
Taxes
66.0
71.8
(5.8)
Income Tax Expense (Benefit)
12.0
15.1
(3.1)
Net Income (Loss)
54.0
56.7
(2.7)
Less: Non-Controlling Interest in Subsidiaries
(0.2)
(0.2)
Net Income (Loss) Attributable to ALLETE
$54.2
$56.7
$(2.5)
       
As of June 30, 2011
     
Total Assets
$2,645.5
$2,381.6
$263.9
Property, Plant and Equipment – Net
$1,861.1
$1,808.9
$52.2
Accumulated Depreciation
$1,062.6
$1,011.3
$51.3
Capital Additions
$79.7
$69.3
$10.4


 
Regulated
Investments
 
Consolidated
Operations
and Other
Millions
     
For the Six Months Ended June 30, 2010
     
Operating Revenue
$444.8
$410.2
$34.6
Fuel and Purchased Power Expense
154.1
154.1
Operating and Maintenance Expense
173.1
139.1
34.0
Depreciation Expense
39.8
37.7
2.1
Operating Income (Loss)
77.8
79.3
(1.5)
Interest Expense
(18.4)
(15.3)
(3.1)
Equity Earnings in ATC
8.9
8.9
Other Income
3.2
2.3
0.9
Income (Loss) Before Non-Controlling Interest and Income
    Taxes
71.5
75.2
(3.7)
Income Tax Expense (Benefit)
29.3
32.1
(2.8)
Net Income (Loss)
42.2
43.1
(0.9)
Less: Non-Controlling Interest in Subsidiaries
(0.2)
(0.2)
Net Income (Loss) Attributable to ALLETE
$42.4
$43.1
$(0.7)
       
As of June 30, 2010
     
Total Assets
$2,447.8
$2,211.2
$236.6
Property, Plant and Equipment – Net
$1,671.7
$1,627.4
$44.3
Accumulated Depreciation
$1,007.5
$959.4
$48.1
Capital Additions
$85.1
$85.0
$0.1

 
ALLETE Second Quarter Form 10-Q
 
11

 

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 and land held-for-sale in Minnesota.

 
June 30,
December 31,
Investments
2011
2010
Millions
   
ALLETE Properties
$92.7
$94.0
Available-for-sale Securities
30.5
25.2
Other
5.8
6.8
Total Investments
$129.0
$126.0


 
June 30,
December 31,
ALLETE Properties
2011
2010
Millions
   
Land Held-for-sale Beginning Balance (January 1, 2011 and 2010, respectively)
$86.0
$74.9
Deeds to Collateralized Property
1.6
9.9
Capitalized Improvements and Other
1.2
Cost of Real Estate Sold
(0.3)
Land Held-for-sale Ending Balance
87.3
86.0
Long-Term Finance Receivables (net of allowances of $0.9 and $0.8)
2.1
3.7
Other
3.3
4.3
Total Real Estate Assets
$92.7
$94.0

Land Held-for-sale.  Land held-for-sale is recorded at the lower of cost or fair value as determined by the evaluation of individual land parcels. Land values are reviewed for impairment on a quarterly basis and no impairments were recorded for the quarter ended June 30, 2011 (none in 2010).

Long-Term Finance Receivables. As of June 30, 2011, long-term finance receivables were $2.1 million net of allowance ($3.7 million net of allowance as of December 31, 2010). The decrease is primarily the result of the transfer of property back to ALLETE Properties by deed-in-lieu of foreclosure, in satisfaction of amounts previously owed under long-term financing receivables. Long-term finance receivables are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts.

Long-Term Finance Receivables
  Real
Allowance Roll-Forward
  Estate
Millions
 
Beginning Balance as of December 31, 2010
$0.8
Additional Reserve
0.1
Ending Balance as of June 30, 2011
$0.9


NOTE 4.  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. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. 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). Descriptions of the three levels of the fair value hierarchy are discussed in Note 8. Fair Value to the consolidated financial statements in our 2010 Form 10-K.


ALLETE Second Quarter Form 10-Q
 
12

 

NOTE 4.  FAIR VALUE (Continued)

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, 2011, and December 31, 2010. 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, 2011
Recurring Fair Value Measures
Level 1
Level 2
Level 3
Total
Millions
       
Assets:
       
Equity Securities
$21.4
$21.4
Available-for-sale Securities – Corporate Debt Securities
$8.0
8.0
Money Market Funds
3.6
3.6
Total Fair Value of Assets
$25.0
$8.0
 –
$33.0
         
Liabilities:
       
Deferred Compensation
$14.6
$14.6
Total Fair Value of Liabilities
$14.6
$14.6
         
Total Net Fair Value of Assets (Liabilities)
$25.0
$(6.6)
 –
$18.4


 
Fair Value as of December 31, 2010
Recurring Fair Value Measures
Level 1
Level 2
Level 3
Total
Millions
       
Assets:
       
Equity Securities
$19.4
$19.4
Available-for-sale Securities
       
     Corporate Debt Securities
$7.5
7.5
     Debt Securities Issued by States of the United States (ARS)
$6.7
6.7
          Total Available-for-sale Securities
7.5
6.7
14.2
Money Market Funds
0.8
0.8
Total Fair Value of Assets
$20.2
$7.5
$6.7
$34.4
         
Liabilities:
       
Deferred Compensation
$13.3
$13.3
Total Fair Value of Liabilities
$13.3
$13.3
         
Total Net Fair Value of Assets (Liabilities)
$20.2
$(5.8)
$6.7
$21.1


Recurring Fair Value Measures
Activity in Level 3
Derivatives
Debt Securities
Issued by States
of the United
States (ARS)
Millions
       
Balance as of December 31, 2010 and December 31, 2009, respectively
$0.7
$6.7
$6.7
Redeemed During the Period
(0.7)
(6.7)
Balance as of June 30, 2011 and June 30, 2010, respectively
$6.7

On January 5, 2011, the remaining $6.7 million of ARS were redeemed at carrying value.

The Company’s policy is to recognize transfers in and transfers out as of the actual date of the event or of the change in circumstances that caused the transfer. For the six months ended June 30, 2011 and 2010, there were no transfers in or out of Levels 1, 2 or 3.


ALLETE Second Quarter Form 10-Q
 
13

 

NOTE 4.  FAIR VALUE (Continued)

Fair Value of Financial Instruments. With the exception of the items listed below, the estimated fair value of all financial instruments approximates the carrying amount. The fair value for the items listed below was based on quoted market prices for the same or similar instruments.

Financial Instruments
Carrying Amount
Fair Value
Millions
   
Long-Term Debt, Including Current Portion
   
June 30, 2011
$783.6
$807.8
December 31, 2010
$785.0
$796.7


NOTE 5.  REGULATORY MATTERS

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

2010 Rate Case. On November 2, 2009, Minnesota Power filed an $81 million retail rate increase request to recover the costs of significant investments to ensure current and future system reliability, enhance environmental performance and bring new renewable energy to northeastern Minnesota. Interim rates were put into effect on January 1, 2010, and were originally estimated to increase revenues by $48.5 million in 2010. In April 2010, we adjusted our initial filing for events that had occurred since November 2009 – primarily increased sales to our industrial customers – resulting in a retail rate increase request of $72 million, a return on equity request of 11.25 percent and a capital structure consisting of 54.29 percent equity and 45.71 percent debt.

On November 2, 2010, Minnesota Power received a written order from the MPUC approving a retail rate increase of $53.5 million, a 10.38 percent return on common equity and a 54.29 percent equity ratio, subject to reconsideration. On May 24, 2011, the MPUC issued an order authorizing Minnesota Power to implement final rates of $53.5 million, effective June 1, 2011. The May 24, 2011 order authorized Minnesota Power to collect a $3.2 million differential between interim rates and final rates for the period from November 2, 2010, through June 1, 2011, all of which was recorded in the second quarter of 2011.

Under the terms of a stipulation and settlement agreement approved by the MPUC as part of this rate case, Minnesota Power agreed to forgo collection of $20.5 million in revenue receivable that it was entitled to under a prior rider for the Boswell Unit 3 environmental retrofit. The agreement required the Company to capitalize, as part of rate base, the $20.5 million to property, plant and equipment representing AFUDC. In conjunction with the settlement agreement, and upon receipt of the final rate order in February 2011, the Company reversed a $6.2 million deferred tax liability related to the revenue receivable Minnesota Power agreed to forgo. The $20.5 million revenue receivable was previously included in Regulatory Assets on the Company’s consolidated balance sheet.

On February 22, 2011, Minnesota Power timely filed an appeal of the MPUC’s interim rate decision in the Company’s 2010 rate case with the Minnesota Court of Appeals. The Company is appealing the MPUC’s finding of exigent circumstances in the interim rate decision with the primary arguments that the MPUC exceeded its statutory authority, made its decision without the support of a body of record evidence and that the decision violated public policy. The Company desires to resolve whether the MPUC’s finding of exigent circumstances was lawful for application in future rate cases. The briefing schedule is complete and oral argument is scheduled for September 21, 2011. If the appeal is successful, the Minnesota Court of Appeals would remand the case to the MPUC for further action consistent with its decision. The Company cannot predict the outcome of the matter at this time.


ALLETE Second Quarter Form 10-Q
 
14

 

NOTE 5.  REGULATORY MATTERS (Continued)

FERC-Approved Wholesale Rates. Minnesota Power’s non-affiliated municipal 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 customer of Minnesota Power. In 2008, Minnesota Power entered into formula-based rate contracts with these customers. In February 2011, Minnesota Power entered into a new formula-based contract with the City of Nashwauk, effective May 1, 2012, through April 30, 2022, and in June 2011, Minnesota Power entered into restated contracts, effective July 1, 2011, through June 30, 2019, with the remaining 15 Minnesota municipal customers. The rates included in these contracts are calculated using a cost-based formula methodology that is set each July using estimated costs and provides for a true-up calculation for actual costs. The contract terms include a termination clause requiring a three-year notice to terminate. Under the restated contracts, no termination notices may be given prior to June 30, 2016.

2010 Wisconsin Rate Increase.   SWL&P’s 2011 retail rates are based on a 2010 PSCW retail rate order, effective January 1, 2011, that allows for a 10.9 percent return on common equity. The new rates reflect a 2.4 percent average increase in retail utility rates for SWL&P customers (a 12.8 percent increase in water rates, a 2.5 percent increase in natural gas rates and a 0.7 percent increase in electric rates). On an annualized basis, the rate increase will generate approximately $2 million in additional revenue.

The Patient Protection and Affordable Care Act of 2010 (PPACA). In March 2010, PPACA was signed into law. One of the provisions changed the tax treatment for retiree prescription drug expenses by eliminating the tax deduction for expenses that are reimbursed under Medicare Part D, beginning January 1, 2013. Based on this provision, we are subject to additional taxes in the future and were required to reverse previously recorded tax benefits in the first quarter of 2010. Consequently, the reversal of the previously recorded tax benefit resulted in a non-recurring charge to net income of $4.0 million in the first quarter of 2010. In October 2010, we submitted a filing with the MPUC requesting deferral of the retail portion of the tax charge taken in 2010 resulting from PPACA. On May 24, 2011, the MPUC approved our request for deferral until the next rate case and as a result we recorded an income tax benefit of $2.9 million in the second quarter of 2011, and a related regulatory asset of $5.0 million. (See also Note 9. Income Tax Expense.)

Regulatory Assets and Liabilities. Our regulated utility operations are subject to the accounting guidance for Regulated Operations. We capitalize incurred costs as regulatory assets, which are probable of recovery in future utility rates. Regulatory liabilities   represent amounts expected to be credited to customers in rates. No regulatory assets or liabilities are currently earning a return.

 
June 30,
December 31,
Regulatory Assets and Liabilities
2011
2010
Millions
   
Current Regulatory Assets (a)
   
Deferred Fuel
$15.0
$20.6
Total Current Regulatory Assets
15.0
20.6
Non-Current Regulatory Assets
   
Future Benefit Obligations Under
   
Defined Benefit Pension and Other Postretirement Benefit Plans
249.5
257.9
Boswell Unit 3 Environmental Rider
20.5
Income Taxes
22.1
17.3
Asset Retirement Obligation
8.7
7.8
Medicare Part D
5.0
Premium on Reacquired Debt
1.7
1.8
Rate Case Expenses
1.0
1.4
Other
2.2
3.5
Total Non-Current Regulatory Assets
290.2
310.2
Total Regulatory Assets
$305.2
$330.8
     
Non-Current Regulatory Liabilities
   
Income Taxes
$22.2
$23.4
Plant Removal Obligations
16.4
16.9
Other
4.8
3.3
Total Non-Current Regulatory Liabilities
$43.4
$43.6
(a)
Current regulatory assets are included in prepayments and other on the consolidated balance sheet.


ALLETE Second Quarter Form 10-Q
 
15

 

NOTE 6.  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 rates are FERC approved and are based on a 12.2 percent return on common equity dedicated to utility plant. We account for our investment in ATC under the equity method of accounting. On July 29, 2011, we invested an additional $0.6 million in ATC for a total investment of $2.0 million in 2011.

ALLETE’s Investment in ATC
 
Millions
 
Equity Investment Balance as of December 31, 2010
$93.3
Cash Investments
1.4
Equity in ATC Earnings
9.0
Distributed ATC Earnings
(7.4)
Equity Investment Balance as of June 30, 2011
$96.3

ATC's summarized financial data for the quarter and six months ended June 30, 2011 and 2010, is as follows:

 
Quarter Ended
Six Months Ended
ATC Summarized Financial Data
June 30,
June 30,
Income Statement Data
2011
2010
2011
2010
Millions
       
Revenue
$138.2
$138.7
$277.8
$277.1
Operating Expense
63.0
62.9
126.1
125.7
Other Expense
19.6
21.7
41.9
42.2
Net Income
$55.6
$54.1
$109.8
$109.2
         
ALLETE’s Equity in Net Income
$4.6
$4.4
$9.0
$8.9


NOTE 7.  SHORT-TERM AND LONG-TERM DEBT

Short-Term Debt. As of June 30, 2011, total short-term debt outstanding was $15.4 million ($14.4 million as of December 31, 2010) and consisted of long-term debt due within one year and notes payable.

On May 25, 2011, BNI Coal amended its Promissory Note and Supplement (Line of Credit) with CoBANK, ACB. The Line of Credit was increased from $3.0 million to $10.0 million and is being used for general corporate purposes. As of June 30, 2011, $2.5 million was drawn on the Line of Credit.

Long-Term Debt. As of June 30, 2011, total long-term debt outstanding was $770.7 million ($771.6 million as of December 31, 2010).

On May 25, 2011, we entered into a new $250 million Credit Agreement (Agreement) with JPMorgan Chase Bank, N.A., as Administrative Agent, and several other lenders that are parties thereto. The Agreement was effective July 1, 2011, and replaced our previous $150 million credit facility. The Agreement is unsecured and has a maturity date of June 30, 2015, which may be extended for one year. Such extension is subject to bank approvals. Advances from the Agreement may be used for general corporate purposes, to provide liquidity in support of ALLETE’s commercial paper program and to issue up to $40 million in letters of credit.


ALLETE Second Quarter Form 10-Q
 
16

 

NOTE 7.  SHORT-TERM AND LONG-TERM DEBT (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. Our compliance with financial covenants is not dependent on debt ratings. The most restrictive covenant requires ALLETE to maintain a ratio of Indebtedness to Total Capitalization (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to 0.65 to 1.00 measured quarterly. As of June 30, 2011, our ratio was approximately 0.42 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from a 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, 2011, ALLETE was in compliance with its financial covenants.


NOTE 8.  OTHER INCOME (EXPENSE)

 
Quarter Ended
Six Months Ended
 
June 30,
June 30,
 
2011
2010
2011
2010
Millions
       
AFUDC Equity
$0.5
$0.9
$1.1
$2.1
Investment and Other Income
0.5
1.3
0.7
1.1
Total Other Income
$1.0
$2.2
$1.8
$3.2


NOTE 9.  INCOME TAX EXPENSE

 
Quarter Ended
Six Months Ended
 
June 30,
June 30,
 
2011
2010
2011
2010
Millions
       
Current Tax Expense (Benefit)
       
Federal (a)
 –
$7.2
State (a)
$0.1
$(1.9)
$0.2
(1.0)
Total Current Tax Expense (Benefit)
0.1
(1.9)
0.2
6.2
Deferred Tax Expense
       
Federal (b)
4.0
8.2
10.8
18.0
State (b)
3.3
1.5
5.5
Deferred Tax Credits
(0.3)
(0.2)
(0.5)
(0.4)
Total Deferred Tax Expense
3.7
11.3
11.8
23.1
Total Income Tax Expense
$3.8
$9.4
$12.0
$29.3
(a)
For the quarter and six months ended June 30, 2011, the federal and state current tax expense was affected by a net operating loss (NOL) which resulted primarily from the bonus depreciation provision of tax legislation passed in 2010. The 2011 federal and state NOL will be carried forward to offset future taxable income. For the six months ended June 30, 2010, we recorded federal current tax expense, as the 2010 tax legislation allowing bonus depreciation was not enacted until the third quarter of 2010. The state current benefit for the quarter and six months ended June 30, 2010, was due to the completion of a state audit and state renewable tax credits.
(b)
The quarter ended June 30, 2011, includes a $2.9 million income tax benefit related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 resulting from PPACA. The six months ended June 30, 2011, includes the second quarter item above and the reversal in the first quarter of 2011 of a $6.2 million deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case. Included in the six months ended June 30, 2010, is a charge of $4.0 million as a result of PPACA (See Note 5. Regulatory Matters).

For the six months ended June 30, 2011, the effective tax rate was 18.2 percent (41.0 percent for the six months ended June 30, 2010). The effective tax rate for the six months ended June 30, 2011, was lowered by 4.4 percent due to the non-recurring income tax benefit related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 resulting from PPACA and by 9.4 percent due to the non-recurring reversal of the deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case. The effective tax rate deviated from the statutory rate of approximately 41 percent primarily due to non-recurring items discussed above, deductions for AFUDC-Equity, investment tax credits, renewable tax credits and depletion.

 
ALLETE Second Quarter Form 10-Q
 
17

 

NOTE 9.  INCOME TAX EXPENSE (Continued)

Uncertain Tax Positions. As of June 30, 2011, we had gross unrecognized tax benefits of $11.3 million. Of this total, $0.6 million 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, 2011, will change by an immaterial amount in the next 12 months.


NOTE 10.  COMPREHENSIVE INCOME

The components of total comprehensive income were as follows:


 
Quarter Ended
Six Months Ended
 
June 30,
June 30,
Comprehensive Income (Loss)
2011
2010
2011
2010
Millions
       
Net Income
$16.9
$19.4
$54.0
$42.2
Other Comprehensive Income (Loss)
       
    Unrealized Gain (Loss) on Securities
   Net of income taxes of $0.2, $(0.4), $0.8 and $(0.4)
0.2
(0.6)
1.1
(0.5)
    Defined Benefit Pension and Other Postretirement Plans
   Net of income taxes of $0.2, $0.2, $0.5 and $0.4
0.4
0.3
0.8
0.6
Total Other Comprehensive Income (Loss)
0.6
(0.3)
1.9
0.1
Total Comprehensive Income
$17.5
$19.1
$55.9
$42.3
Less: Non-Controlling Interest in Subsidiaries
(0.1)
(0.2)
(0.2)
Comprehensive Income Attributable to ALLETE
$17.6
$19.1
$56.1
$42.5


NOTE 11.  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. For the quarter and six months ended June 30, 2011 and 2010, 0.3 million and 0.6 million, respectively, 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; therefore, their effect would have been anti-dilutive.

   
2011
     
2010
 
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 Attributable to ALLETE
$17.0
 
$17.0
 
$19.4
 
$19.4
Common Shares
35.0
0.1
35.1
 
34.1
0.1
34.2
Earnings Per Share
$0.49
 
$0.48
 
$0.57
 
$0.57
               
For the Six Months Ended June 30,
             
Net Income Attributable to ALLETE
$54.2
 
$54.2
 
$42.4
 
$42.4
Common Shares
34.8
0.1
34.9
 
34.0
0.1
34.1
Earnings Per Share
$1.56
 
$1.55
 
$1.25
 
$1.25
 

ALLETE Second Quarter Form 10-Q
 
18

 

NOTE 12.  PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

 
Pension
Other
Postretirement
Components of Net Periodic Benefit Expense
2011
2010
2011
2010
Millions
       
For the Quarter Ended June 30,
       
Service Cost
$1.9
$1.6
$0.9
$1.2
Interest Cost
6.8
6.5
2.7
2.8
Expected Return on Plan Assets
(8.6)
(8.4)
(2.5)
(2.4)
Amortization of Prior Service Costs
0.1
0.1
(0.5)
Amortization of Net Loss
3.0
1.7
2.2
1.2
Amortization of Transition Obligation
0.1
0.6
Net Periodic Benefit Expense
$3.2
$1.5
$2.9
$3.4
         
For the Six Months Ended June 30,
       
Service Cost
$3.8
$3.1
$1.9
$2.4
Interest Cost
13.7
13.1
5.4
5.5
Expected Return on Plan Assets
(17.3)
(16.8)
(4.9)
(4.8)
Amortization of Prior Service Costs
0.2
0.2
(0.9)
Amortization of Net Loss
6.0
3.3
4.3
2.4
Amortization of Transition Obligation
0.1
1.2
Net Periodic Benefit Expense
$6.4
$2.9
$5.9
$6.7

Employer Contributions. For the six months ended June 30, 2011, no contributions were made to our defined benefit pension plan (no contributions were made for the six months ended June 30, 2010). For the six months ended June 30, 2011, $10.9 million was contributed to our other postretirement benefit plan ($2.6 million for the six months ended June 30, 2010). On July 15, 2011, $0.2 million was contributed to our defined benefit pension plan. We expect to make approximately $2 million in contributions to our defined benefit pension plan and an additional $1 million to our other postretirement benefit plan in 2011.

Accounting and disclosure requirements for the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) provides guidance for employers that sponsor postretirement health care plans that provide prescription drug benefits. We provide postretirement health benefits that include prescription drug benefits, which qualify us for the federal subsidy under the Act. For the six months ended June 30, 2011, we received $0.2 million in prescription drug reimbursements.


NOTE 13.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

Power Purchase Agreements. Our long-term PPAs have been evaluated under the accounting guidance for variable interest entities. We have determined that either we have no variable interest in the PPA or where we do have variable interests, we are not the primary beneficiary; therefore, consolidation is not required. These conclusions are based on the fact that we do not have both control over activities that are most significant to the entity and an obligation to absorb losses or receive benefits from the entity’s performance. Our financial exposure relating to these PPAs is limited to our fixed capacity and energy payments.

Square Butte PPA. Minnesota Power has a PPA with Square Butte that extends through 2026 (Agreement). It provides a long-term supply of 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.


ALLETE Second Quarter Form 10-Q
 
19

 

NOTE 13.  COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Power Purchase Agreements (Continued)

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, subject to the provisions of the Minnkota Power sales agreement described below. 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 costs consist primarily of debt service, operating and maintenance, depreciation and fuel expenses. We expect debt service, operating and maintenance and depreciation expenses for Square Butte to increase in 2011 due to environmental compliance obligations. As of June 30, 2011, Square Butte had total debt outstanding of $424.1 million. Annual debt service for Square Butte is expected to be approximately $39 million in each of the five years, 2011 through 2015, of which Minnesota Power’s obligation is 50 percent. Fuel expenses are recoverable through our fuel adjustment clause and include the cost of coal purchased from BNI Coal, our subsidiary, under a long-term contract.

Minnkota Power Sales Agreement. In conjunction with the purchase of the existing 250 kV DC transmission line from Square Butte in December 2009, Minnesota Power entered into a power sales agreement with Minnkota Power. Under the power sales agreement, Minnesota Power will sell a portion of its output from Square Butte to Minnkota Power, resulting in Minnkota Power’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of 2025.

No power will be sold under this agreement until Minnkota Power has placed in service a new AC transmission line, which is anticipated to occur in 2013. This new AC transmission line will allow Minnkota Power to transmit its entitlement from Square Butte directly to its customers, which, in turn, will enable Minnesota Power to transmit new wind generation on the DC transmission line.

Wind PPAs. In 2006 and 2007, Minnesota Power entered into two long-term wind PPAs with an affiliate of NextEra Energy, Inc., to purchase the output from Oliver Wind I (50 MW) and Oliver Wind II (48 MW) – wind facilities located near Center, North Dakota. Each agreement is for 25 years and provides for the purchase of all output from the facilities at fixed prices. There are no fixed capacity charges and we only pay for energy as it is delivered to us.

Hydro PPAs. Minnesota Power has a PPA with Manitoba Hydro that expires in April 2015. Under this agreement Minnesota Power is purchasing 50 MW of capacity and the energy associated with that capacity. Both the capacity price and the energy price are adjusted annually by the change in a governmental inflationary index.

Minnesota Power has a separate PPA with Manitoba Hydro to purchase surplus energy beginning in May 2011 through April 2022. This energy-only transaction primarily consists of surplus hydro energy on Manitoba Hydro’s system that is delivered to Minnesota Power on a non-firm basis. The pricing is based on forward market prices. Under this agreement Minnesota Power will be purchasing at least one million MWh of energy over the contract term. On March 11, 2011, the MPUC approved this PPA with Manitoba Hydro.

North Dakota Wind Development . In December 2009, we purchased an existing 250 kV DC transmission line from Square Butte. The 465-mile transmission line runs from Center, North Dakota, to Duluth, Minnesota. We use this line to transport increasing amounts of wind energy from North Dakota, while gradually phasing out coal-based electricity currently being delivered to our system over this transmission line from Square Butte’s coal-fired generating unit.

Bison 1 is a two phase, 82 MW wind project in North Dakota. All permitting has been received and the first phase was completed in 2010. Phase one included the construction of a 22-mile, 230 kV transmission line and the installation of sixteen 2.3-MW wind turbines. Phase two is expected to be completed in late 2011 and consists of the installation of fifteen 3.0-MW wind turbines. Bison 1 is expected to have a total capital cost of approximately $177 million, of which $137.4 million was spent through June 30, 2011. In 2009, the MPUC approved Minnesota Power’s petition seeking current cost recovery for investments and expenditures related to Bison 1 and in July 2010, the MPUC approved our petition establishing rates effective August 1, 2010. On March 31, 2011, Minnesota Power petitioned the MPUC to update the rates for additional investments and expenditures related to Bison 1.


ALLETE Second Quarter Form 10-Q
 
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NOTE 13.  COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
North Dakota Wind Development (Continued)

Bison 2 and Bison 3 are both 105 MW wind projects in North Dakota which, if approved by the MPUC, are expected to be completed by the end of 2012. Total project costs for Bison 2 and Bison 3 are estimated to be approximately $160 million each. Construction would begin upon the receipt of appropriate regulatory and permitting approvals. Requests for approval of Bison 2 and Bison 3 were filed with the MPUC on March 24, 2011, and June 21, 2011, respectively. Site permit applications were submitted to the NDPSC on April 6, 2011, and July 7, 2011, respectively. Approvals of the site permit applications are expected in the third quarter of 2011. We will file for current cost recovery for Bison 2 and Bison 3 with the MPUC once the projects and related permitting have been approved.

Coal, Rail and Shipping Contracts. We have coal supply agreements and transportation agreements providing for the purchase and delivery of a significant portion of our coal requirements. These coal and transportation agreements, including option terms, expire in various years between late 2011 and 2015. Our minimum annual payment obligation is $31.8 million in 2011, $15.8 million in 2012 and $16.3 million in 2013. Our minimum annual payment obligations will increase when annual nominations are made for coal deliveries in future years. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

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 fair market value, purchase the dragline at fair market value or 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 $8.1 million in 2011, $8.4 million in 2012, $8.5 million in 2013, $8.7 million in 2014, $8.4 million in 2015 and $44.7 million thereafter.

Transmission . We are making investments in Upper Midwest transmission opportunities that strengthen or enhance the regional transmission grid. These investments include the CapX2020 initiative, investments in our transmission assets and our investment in ATC.

Transmission Investments. We have an approved cost recovery rider in place for certain transmission expenditures and the continued use of our 2009 billing factor was approved by the MPUC on May 11, 2011. The billing factor allows us to charge our retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. On June 29, 2011, we filed an updated billing factor that includes additional transmission projects and expenses, which we expect to be approved in late 2011.

CapX2020 .   Minnesota Power is a participant in the CapX2020 initiative which represents an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX2020, which consists of electric cooperatives, municipals and investor-owned utilities, including Minnesota’s largest transmission owners, 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.

Minnesota Power is currently participating in three CapX2020 projects: the Fargo to St. Cloud project, the Monticello to St. Cloud project, which together total a 238-mile, 345 kV line from Fargo to Monticello, and the 70-mile, 230 kV line between Bemidji and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota. Based on projected costs of the three transmission lines and the percentage agreements among participating utilities, Minnesota Power plans to invest between $100 million and $125 million in the CapX2020 initiative through 2015, of which $17.5 million was spent through June 30, 2011. As future CapX2020 projects are identified, Minnesota Power may elect to participate on a project-by-project basis.

In July 2010, the MPUC granted a route permit for the 28-mile, 345 kV line between Monticello and St. Cloud. Construction of the project is expected to be completed in late 2011. On June 10, 2011, the MPUC approved the route permit for the Minnesota portion of the St. Cloud to Fargo project. The North Dakota permitting process is underway. The entire 238-mile, 345 kV line from St. Cloud to Fargo is expected to be in service by 2015. Construction for the Bemidji to Grand Rapids 230 kV line project commenced in January 2011.

 
ALLETE Second Quarter Form 10-Q
 
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NOTE 13.  COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Transmission (Continued)
 
In November 2010, the MPUC approved a route permit for the Bemidji to Grand Rapids line. The Leech Lake Band of Ojibwe (LLBO) subsequently requested that the MPUC suspend or revoke the route permit and also served the CapX2020 utilities with a tribal court complaint asserting adjudicatory and regulatory authority over the project. The CapX2020 utilities filed a request for declaratory judgment in federal court that the project does not require the LLBO consent to the line crossing non-tribal land within the Leech Lake reservation. In response, the LLBO filed a motion to dismiss at the federal court scheduled for hearing on September 16, 2011. The MPUC has taken no action in the matter in light of ongoing litigation in federal and tribal court. On June 22, 2011, the Federal Judge issued a preliminary injunction directing the LLBO to cease and desist its claims of tribal court jurisdiction or from taking other actions to interfere with regulatory review, approval or project construction. The CapX2020 utilities are vigorously defending against the LLBO actions.


Environmental Matters

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. Currently, a number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements are under consideration by both Congress and the EPA. Minnesota Power’s fossil fuel facilities will likely be subject to regulation under these proposals. Our intention is to reduce our exposure to these requirements by reshaping our generation portfolio over time to reduce our reliance on coal.

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 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. Accruals are adjusted as assessment and remediation efforts progress or as additional technical or legal information become available. Accruals for environmental liabilities are included in the 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.

Air. The electric utility industry is heavily regulated both at the federal and state level to address air emissions. Minnesota Power’s generating facilities mainly burn low-sulfur western sub-bituminous coal. Square Butte, located in North Dakota, burns lignite coal. All of Minnesota Power’s generating facilities are equipped with pollution control equipment such as scrubbers, bag houses and low NO x technologies. At this time, these facilities are substantially compliant with applicable emission requirements.

New Source Review . In August 2008, Minnesota Power received a Notice of Violation (NOV) from the 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 asserts that seven projects undertaken at these coal-fired plants between the years 1981 and 2000 should have been reviewed under the NSR requirements and that the Boswell Unit 4 Title V permit was violated. In April 2011, Minnesota Power received a NOV alleging that two projects undertaken at Rapids Energy Center in 2004 and 2005 should have been reviewed under the NSR requirements and that the Rapids Energy Center’s Title V permit was violated. Minnesota Power believes the projects in both NOVs were in full compliance with the Clean Air Act, NSR requirements and applicable permits. We are engaged in discussions with the EPA regarding resolution of these matters, but we are unable to predict the outcome of these discussions.


ALLETE Second Quarter Form 10-Q
 
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NOTE 13.  COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

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. Since 2006, Minnesota Power has significantly reduced emissions at Laskin and Boswell and continues to reduce emissions at Boswell.

Cross-State Air Pollution Rule (CSAPR) . On July 6, 2011, the EPA finalized the CSAPR; however, it has not yet been published in the Federal Register. The CSAPR requires 27 states to significantly improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states. This final rule, referred to as the Transport Rule during the proposal stage, replaces the EPA’s 2005 Clean Air Interstate Rule (CAIR). Minnesota participation in the CAIR was stayed by EPA administrative action while the EPA completed review of air quality modeling issues in conjunction with development of a final, replacement rule. In their final determination, the EPA has listed Minnesota as a CSAPR-affected state based on new, 24-hour fine particulate NAAQS analysis. The CSAPR-related emission restrictions become effective for Minnesota utilities in 2012.

Since 2006, we have made substantial investments in pollution control equipment at our Laskin, Taconite Harbor and Boswell generating units which have significantly reduced emissions. Ongoing analysis of the CSAPR preliminarily indicates our recent emission reductions may satisfy Minnesota Power’s SO 2 and NO x emission compliance obligations with respect to the CSAPR requirements. We are unable to predict any additional CSAPR compliance costs we might incur at this time.

Minnesota Regional Haze . The federal 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, put in place between 1962 and 1977, with emissions contributing to visibility impairment are required to install emission controls, known as Best Available Retrofit Technology (BART). We have two 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 CAIR. However, a formal SIP was not filed at that time due to the United States Court of Appeals for the District of Columbia Circuit’s remand of CAIR. Subsequently, the MPCA requested that companies with BART eligible units complete and submit a BART emissions control retrofit study, which was completed for Taconite Harbor Unit 3 in November 2008. The retrofit work completed in 2009 at Boswell Unit 3 meets the BART requirements for that unit. In December 2009, the MPCA approved the Minnesota SIP for submittal to the EPA for its review and approval. The Minnesota SIP incorporates information from the BART emissions control retrofit studies that were completed as requested by the MPCA. A decision by the EPA is pending on whether to approve the Minnesota SIP. If approved, Minnesota Power will have up to five years to bring Taconite Harbor Unit 3 into compliance. It is uncertain what controls will ultimately be required at Taconite Harbor Unit 3 in connection with the regional haze rule.

EPA National Emission Standards for Hazardous Air Pollutants (NESHAPs) for Coal- and Oil-fired Electric Utility Steam Generating Units (EUSGU) . Under Section 112 of the Clean Air Act, the EPA is required to set emission standards for hazardous air pollutants for certain source categories. The EPA released their proposed EUSGU NESHAPs rule on March 16, 2011. As part of the NESHAPs rulemaking, the EPA will develop Maximum Achievable Control Technology standards for utilities. The final rule is expected to be issued in November 2011. Costs for complying with potential future mercury and other hazardous air pollutant regulations under the Clean Air Act cannot be estimated at this time.


ALLETE Second Quarter Form 10-Q
 
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NOTE 13.  COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

EPA National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters . In March 2011, the final rules were published in the Federal Register. The rule was stayed by the EPA on May 16, 2011, to allow the EPA time to consider additional comments received. The EPA currently plans to re-propose the rule, with a final rule expected in April 2012. Major sources have three years to achieve compliance with the final rules. These rules may result in additional control measures being required at Rapids Energy Center and Hibbard. Costs for complying with these proposed rules cannot be estimated at this time.

Minnesota Mercury Emission Reduction Act . Under Minnesota law, a mercury emissions reduction plan for Boswell Unit 4 is required to be submitted by July 1, 2015, with implementation no later than December 31, 2018. The statute also calls for an evaluation of a mercury control alternative which provides for environmental and public health benefits without imposing excessive costs on the utility’s customers. Costs for the Boswell Unit 4 emission reduction plan cannot be estimated at this time. Until Minnesota Power files its mercury emission reduction plan for Boswell 4, it must file an annual report updating the MPUC and other stakeholders on the status of emission reduction planning for Boswell 4. The first such update was filed with the MPUC on June 30, 2011.

Proposed and Finalized National Ambient Air Quality Standards (NAAQS). The EPA is required to review the NAAQS every five years. If the EPA determines that a state’s air quality is not in compliance with a NAAQS, the state is required to adopt plans describing how they will reduce emissions to attain the NAAQS. These state plans often include more stringent air emission limitations on sources of air pollutants. Four NAAQS have either recently been revised or are currently proposed for revision, as described below.

Ozone NAAQS. The EPA is proposing to more stringently control emissions that result in ground level ozone. In January 2010, the EPA proposed to reduce the eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. The EPA was scheduled to decide upon the standard at the end of July 2011, however the decision has been delayed. As proposed, states have until early 2014 to submit plans outlining how they will meet the standards.

Particulate Matter NAAQS.   The EPA finalized the NAAQS Particulate Matter standards in September 2006. The EPA established a more stringent 24-hour average fine particulate (PM 2.5 ) standard and kept the annual average fine particulate matter standard and the 24-hour coarse particulate matter standard unchanged. The District of Columbia Circuit Court of Appeals has remanded the PM 2.5 standard to the EPA, requiring consideration of lower annual average standard values. The EPA plans to finalize the new PM 2.5 standards in 2011 and state attainment status determination will likely not occur prior to 2013. As early as late 2014, affected sources would have to take additional control measures if modeling demonstrates non-compliance at the property boundary. The EPA has indicated that ambient air quality monitoring for 2008 through 2010 will be used as a basis for states to characterize their attainment status.

SO 2 and NO 2 NAAQS. During 2010, the EPA finalized a new one-hour NAAQS for SO 2 and NO 2 . Monitoring data indicates that Minnesota will likely be in compliance with these new standards; however, the SO 2 NAAQS also requires the EPA to evaluate modeling data to determine attainment. MPCA intends to have this modeling effort completed by the end of 2011, using facility data Minnesota Power provides for all of our steam generating facilities. It is unclear what the outcome of this evaluation will be. These NAAQS could also result in more stringent emission limits on our steam generating facilities, possibly resulting in additional control measures on some of our units.

We are unable to predict the nature or timing of any additional NAAQS regulation or compliance costs we might incur at this time.

 
ALLETE Second Quarter Form 10-Q
 
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NOTE 13.  COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

Climate Change. Minnesota Power is addressing climate change by taking the following steps that also ensure reliable and environmentally compliant generation resources to meet our customers’ requirements:

·  
Expand our renewable energy supply;
·  
Improve the efficiency of our coal-based generation facilities, as well as other process efficiencies;
·  
Provide energy conservation initiatives for our customers and engage in other demand side efforts;
·  
Support research of technologies to reduce carbon emissions from generation facilities and support carbon sequestration efforts; and
·  
Achieve overall carbon emission reductions.

The scientific community generally accepts that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risk. These physical risks could include, but are not limited to, increased or decreased precipitation and water levels in lakes and rivers; increased temperatures; and the intensity and frequency of extreme weather events. These all have the potential to affect the Company’s business and operations.

EPA Regulation of GHG Emissions.  In May 2010, the EPA issued the final Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). The PSD/Tailoring Rule establishes permitting thresholds required to address GHG emissions for new facilities, at existing facilities that undergo major modifications and at other facilities characterized as major sources under the Clean Air Act’s Title V program.

For our existing facilities, the rule does not require amending our existing Title V Operating Permits to include GHG requirements. Implementation of the requirement to add GHG provisions to permits will be completed at the state level in Minnesota by the MPCA when the Title V permits are renewed. However, installation of new units or modification of existing units resulting in a significant increase in GHG emissions will require obtaining PSD permits and amending our operating permits to demonstrate that Best Available Control Technology (BACT) is being used at the facility to control GHG emissions. The EPA has defined significant emissions increase for existing sources as a GHG increase of 75,000 tons or more per year of total GHG on a CO 2 equivalent basis.

In late 2010, the EPA issued guidance to permitting authorities and affected sources to facilitate incorporation of the Tailoring Rule permitting requirements into the Title V and PSD permitting programs. The guidance stated that the project-specific top-down BACT determination process used for other pollutants will also be used to determine BACT for GHG emissions. Through sector-specific white papers, the EPA also provided examples and technical summaries of GHG emission control technologies and techniques the EPA considers available or likely to be available to sources. It is possible these control technologies could be determined to be BACT on a project-by-project basis. In the near term, one option appears to be energy efficiency maximization.

Legal challenges to the EPA’s regulation of GHG emissions, including the Tailoring Rule, have been filed by others and are awaiting judicial determination. Comments to the permitting guidance were also submitted by Minnesota Power and others and may be addressed by the EPA in the form of revised guidance documents.

We cannot predict the nature or timing of any additional GHG legislation or regulation. Although we are unable to predict the compliance costs we might incur, the costs could have a material impact on our financial results.

Water. The Clean Water Act requires NPDES permits to be obtained from the EPA (or, when delegated, from individual state pollution control agencies) for any wastewater discharged into navigable waters. We have obtained all necessary NPDES permits, including NPDES storm water permits for applicable facilities, to conduct our operations. We are in substantial compliance with these permits.


ALLETE Second Quarter Form 10-Q
 
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NOTE 13.  COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

Clean Water Act - Aquatic Organisms. On April 20, 2011, the EPA published in the Federal Register proposed regulations under section 316(b) of the Clean Water Act that set standards applicable to cooling water intake structures for the protection of aquatic organisms. The proposed regulations would require existing large power plants and manufacturing facilities that withdraw greater than 25 percent of water from adjacent water bodies for cooling purposes to limit the number of aquatic organisms that are killed when they are pinned against the facility’s intake structure or that are drawn into the facility’s cooling system. The section 316(b) standards would be implemented through NPDES permits issued to the covered facilities. The EPA has re-opened the comment period and is accepting public comments on the proposed rule through August 18, 2011. The EPA is obligated to finalize the rule by July 27, 2012. Minnesota Power is in the process of evaluating the potential impacts the proposed rule may have on its facilities. We are unable to predict the compliance costs we might incur; however, the costs could have a material impact on our financial results.

Solid and Hazardous Waste. The Resource Conservation and Recovery Act of 1976 regulates the management and disposal of solid and hazardous wastes. We are required to notify the EPA of hazardous waste activity and, consequently, routinely submit the necessary reports to the EPA.

Coal Ash Management Facilities . Minnesota Power generates coal ash at all five of its steam electric generating facilities. Two facilities store ash in onsite impoundments (ash ponds) with engineered liners and containment dikes. Another facility stores dry ash in a landfill with an engineered liner and leachate collection system. Two facilities generate a combined wood and coal ash that is either land applied as an approved beneficial use or trucked to state permitted landfills. In June 2010, the EPA proposed regulations for coal combustion residuals generated by the electric utility sector. The proposal sought comments on three general regulatory schemes for coal ash. Comments on the proposed rule were due in November 2010. It is estimated that the final rule will be published in late 2012 or early 2013. We are unable to predict the compliance costs we might incur; however, the costs could have a material impact on our financial results.

Manufactured Gas Plant Site.  We are reviewing and addressing environmental conditions at a former manufactured gas plant site in 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. As of June 30, 2011, we have a $0.5 million liability for this site and a corresponding regulatory asset as we expect recovery of remediation costs to be allowed by the PSCW.


Other Matters

BNI Coal. As of June 30, 2011, BNI Coal had surety bonds outstanding of $29.7 million related to the reclamation liability for closing costs associated with its mine and mine facilities which meet the requirements for BNI Coal’s total reclamation liability. BNI Coal does not believe it is likely that any of these outstanding bonds will be drawn upon.

ALLETE Properties. As of June 30, 2011, ALLETE Properties, through its subsidiaries, had surety bonds outstanding of $10.2 million primarily related to performance and maintenance obligations to 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 $8.0 million and ALLETE Properties does not believe it is likely that any of these outstanding bonds will be drawn upon.


ALLETE Second Quarter Form 10-Q
 
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NOTE 13.  COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Community Development District Obligations. In March 2005, the Town Center District issued $26.4 million of tax-exempt, 6 percent capital improvement revenue bonds and in May 2006, the Palm Coast Park District issued $31.8 million of tax-exempt, 5.7 percent special assessment bonds. The capital improvement revenue bonds and the special assessment bonds are payable over 31 years (by May 1, 2036 and 2037, respectively) and secured by special assessments on the benefitted land. 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 assessments were billed to the landowners beginning 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, we will incur the cost of our portion of these assessments, based upon our ownership of benefited property. At June 30, 2011, we owned 73 percent of the assessable land in the Town Center District (69 percent at December 31, 2010) and 93 percent of the assessable land in the Palm Coast Park District (93 percent at December 31, 2010). At these ownership levels, our annual assessments are approximately $1.5 million for Town Center and $2.2 million for Palm Coast Park. 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.

Legal Proceedings. In January 2011, the Company was named as a defendant in a lawsuit in the Sixth Judicial District for the State of Minnesota by one of our customer’s, United Taconite, LLC, property and business interruption insurers. In October 2006, United Taconite experienced a fire as a result of the failure of certain electrical protective equipment. The equipment at issue in the incident was not owned, designed or installed by Minnesota Power, but Minnesota Power had provided testing and calibration services related to the equipment. The lawsuit alleges approximately $20 million in damages related to the fire. The Company believes that it has strong defenses to the lawsuit and intends to vigorously assert such defenses. An expense related to any damages that may result from the lawsuit has not been recorded as of June 30, 2011, because a potential loss is not currently probable or reasonably estimable; however, the Company believes it has adequate insurance coverage for any potential loss.

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 affect 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 affect 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 2010 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 22 of our 2010 Form 10-K. The risks and uncertainties described in this Form 10-Q and our 2010 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.


ALLETE Second Quarter Form 10-Q
 
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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. Minnesota Power also provides regulated utility electric service to 1 private utility in Wisconsin. SWL&P provides regulated electric, 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 investment. This segment also includes a small amount of non-rate base generation, approximately 5,500 acres of land available-for-sale in Minnesota and earnings on cash and investments.

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of June 30, 2011, 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

The following net income discussion summarizes a comparison of the six months ended June 30, 2011, to the six months ended June 30, 2010.

Net income attributable to ALLETE for the six months ended June 30, 2011, was $54.2 million, or $1.55 per diluted share, compared to $42.4 million, or $1.25 per diluted share, for the same period of 2010. The first six months of 2011 included the reversal of a $6.2 million, or $0.18 per share, deferred tax liability related to a revenue receivable Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case, and the recognition of a $2.9 million, or $0.08 per share, income tax benefit related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 resulting from PPACA (See Note 5. Regulatory Matters). Net income for the first six months of 2010 was reduced by a $4.0 million, or $0.12 per share, income tax charge resulting from PPACA which eliminated the deduction for expenses reimbursed under Medicare Part D. 2011 also included increases in MWh sales and current cost recovery rider revenue over 2010, which were offset by lower power marketing margins and higher expenses.

Regulated Operations net income attributable to ALLETE was $56.7 million for the first six months of 2011, compared to $43.1 million for the same period of 2010. The first six months of 2011 included the reversal of a $6.2 million deferred tax liability related to a revenue receivable Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case and the recognition of a $2.9 million income tax benefit related to the MPUC approval of our request to defer a portion of the tax charge taken in 2010 resulting from PPACA. Net income for the first six months of 2010 was reduced by a $3.6 million income tax charge resulting from PPACA. The remaining increase over 2010 is attributable to an increase in MWh sales, the implementation of final rates and an increase in current cost recovery rider revenue, offset by lower power marketing margins and higher expenses.

Investments and Other reflected a net loss attributable to ALLETE of $2.5 million in the first six months of 2011, compared to a net loss of $0.7 million in 2010. Net income for 2010 included an income tax benefit of $1.1 million (including interest) resulting from the completion of a state income tax audit. In addition, higher interest and investment-related expenses contributed to a greater net loss in 2011. 2010 was also reduced by a $0.4 million charge resulting from PPACA.

 
ALLETE Second Quarter Form 10-Q
 
28

 

COMPARISON OF THE QUARTERS ENDED JUNE 30, 2011 AND 2010

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

Regulated Operations

Operating revenue increased $7.7 million, or 4 percent, from 2010 primarily due to increased sales to our retail and municipal customers, higher fuel clause recoveries, implementation of final rates and increased current cost recovery rider revenue. These increases were partially offset by lower sales to Other Power Suppliers.

Revenue and kilowatt-hour sales to retail and municipal customers increased $8.4 million and 2.6 percent, respectively, from 2010 primarily due to increased sales to industrial customers and the implementation of final rates. Increased revenue from those sales was offset by a $7.2 million and a 16.6 percent decrease in revenue and kilowatt-hour sales, respectively, to Other Power Suppliers. 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.
 
Kilowatt-hours Sold
 
Quantity
%
Quarter Ended June 30,
2011
2010
Variance
Variance
Millions
       
Regulated Utility
       
 
Retail and Municipals
       
   
Residential
238
229
9
3.9%
   
Commercial
328
327
1
0.3%
   
Industrial
1,782
1,728
54
3.1%
   
Municipals
230
228
2
0.9%
     
Total Retail and Municipals
2,578
2,512
66
2.6%
 
Other Power Suppliers
614
736
(122)
(16.6)%
Total Regulated Utility Kilowatt-hours Sold
3,192
3,248
(56)
(1.7)%

Revenue from electric sales to taconite customers accounted for 27 percent of consolidated operating revenue in 2011 (26 percent in 2010). Revenue from electric sales to paper and pulp mills accounted for 9 percent of consolidated operating revenue in 2011 (9 percent in 2010). Revenue from electric sales to pipelines and other industrials accounted for 8 percent of consolidated operating revenue in 2011 (6 percent in 2010).
 
Fuel adjustment clause recoveries increased $3.9 million, or 23 percent, primarily due to higher fuel and purchased power expense resulting from a 2.6 percent increase in kilowatt-hour sales to our retail and municipal customers. (See Operating Expenses.)

Transmission and renewable rider revenue increased by $0.9 million due to higher capital expenditures related to our Bison 1 and CapX2020 projects.

Operating expenses increased $11.8 million, or 7 percent, from 2010.

Fuel and Purchased Power Expense increased $1.7 million, or 2 percent, from 2010 reflecting increased costs under our Square Butte PPA and increased coal prices, partially offset by lower purchased power prices.

Operating and Maintenance Expense increased $7.9 million, or 11 percent, from 2010 primarily reflecting increased property taxes, plant expenses due to timing of scheduled maintenance, and salaries and benefit expenses.

Depreciation Expense increased $2.2 million, or 12 percent, from 2010 reflecting additional property, plant and equipment in service.

Interest expense increased $1.4 million, or 18 percent, from 2010 primarily due to higher long-term debt balances.


ALLETE Second Quarter Form 10-Q
 
29

 

COMPARISON OF THE QUARTERS ENDED JUNE 30, 2011 AND 2010
Regulated Operations (Continued)

Income tax expense decreased $5.9 million, or 52 percent, from 2010 primarily due to the recognition of a $2.9 million income tax benefit related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 resulting from PPACA. Also contributing to the decrease were additional renewable tax credits in 2011.

Investments and Other

Operating revenue increased $1.0 million, or 6 percent, from 2010 primarily due to a $1.6 million increase in revenue at BNI Coal, which operates under a cost-plus contract and recorded higher sales revenue as a result of higher expenses in 2011. (See Operating Expense.)

Revenue at ALLETE Properties decreased $0.7 million from 2010 primarily due to a $0.7 million pre-tax gain in the second quarter of 2010.

ALLETE Properties
2011
2010
Revenue and Sales Activity
Quantity
Amount
Quantity
Amount
Dollars in Millions
       
Revenue from Land Sales
       
Acres
Revenue from Land Sales
 
 
Other Revenue (a)
 
$0.5
 
$1.2
 Total ALLETE Properties Revenue
 
$0.5
 
$1.2
(a)  
For the quarter ended June 30, 2011, Other Revenue includes a forfeited deposit due to the transfer of property back to ALLETE Properties by deed-in-lieu of foreclosure, in satisfaction of amounts previously owed under long-term financing receivables. For the quarter ended June 30, 2010, Other Revenue primarily includes a $0.7 million pre-tax gain resulting from the transfer of property back to ALLETE Properties by deed-in-lieu of foreclosure, in satisfaction of amounts previously owed under long-term financing receivables from an entity which filed for bankruptcy in June 2009.

Operating expenses increased $2.5 million, or 15 percent, from 2010 reflecting higher expenses at BNI Coal of $1.3 million primarily due to higher fuel costs and equipment repairs; these costs are recovered through the cost-plus contract. (See Operating Revenue.) 2011 also included higher investment-related expenses of $1.1 million.
 
Income Taxes – Consolidated

For the quarter ended June 30, 2011, the effective tax rate was 18.4 percent (32.6 percent for the quarter ended June 30, 2010). The effective tax rate for the quarter ended June 30, 2011, was lowered by 14.0 percent due to the non-recurring income tax benefit related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 resulting from the PPACA. The effective tax rate for both years deviated from the statutory rate (approximately 41 percent) due to non-recurring items discussed above, deductions for AFUDC-Equity, investment tax credits, renewable tax credits and depletion. We expect the effective tax rate for the full year 2011 to be approximately 25 percent. (See Note 9. Income Tax Expense.)


COMPARISON OF THE SIX MONTHS ENDED JUNE 30, 2011 AND 2010

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

Regulated Operations

Operating revenue increased $14.6 million, or 4 percent, from 2010 primarily due to increased sales to our retail and municipal customers, higher fuel clause recoveries, implementation of final rates and increased current cost recovery rider revenue. These increases were partially offset by lower sales to Other Power Suppliers.

 
ALLETE Second Quarter Form 10-Q
 
30

 

COMPARISON OF THE SIX MONTHS ENDED JUNE 30, 2011 AND 2010
Regulated Operations (Continued)

Revenue and kilowatt-hour sales to retail and municipal customers increased $18.2 million and 9.9 percent, respectively, from 2010 primarily due to a 14.7 percent increase in sales to our industrial customers and the implementation of final rates. Increased revenue from those sales was offset by a $19.6 million and a 25.0 percent decrease in revenue and kilowatt-hour sales, respectively, to Other Power Suppliers. 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.

Kilowatt-hours Sold
 
Quantity
%
Six Months Ended June 30,
2011
2010
Variance
Variance
Millions
       
Regulated Utility
       
 
Retail and Municipals
       
   
Residential
600
586
14
2.4%
   
Commercial
704
699
5
0.7%
   
Industrial
3,620
3,157
463
14.7%
   
Municipals
499
493
6
1.2%
     
Total Retail and Municipals
5,423
4,935
488
9.9%
 
Other Power Suppliers
1,154
1,539
(385)
(25.0)%
Total Regulated Utility Kilowatt-hours Sold
6,577
6,474
103
1.6%

Revenue from electric sales to taconite customers accounted for 26 percent of consolidated operating revenue in 2011 (23 percent in 2010). Revenue from electric sales to paper and pulp mills accounted for 9 percent of consolidated operating revenue in 2011 (9 percent in 2010). Revenue from electric sales to pipelines and other industrials accounted for 7 percent of consolidated operating revenue in 2011 (6 percent in 2010).

Fuel adjustment clause recoveries increased $10.4 million, or 28 percent, primarily due a 9.9 percent increase in kilowatt-hour sales to our retail and municipal customers.
 
Transmission and renewable rider revenue increased by $3.6 million due to higher capital expenditures related to our Bison 1 and CapX2020 projects.
 
Operating expenses increased $14.6 million, or 4 percent, from 2010.

Fuel and Purchased Power Expense increased $0.9 million, or 1 percent, from 2010 as a result of increased costs under our Square Butte PPA and increased coal prices which were mostly offset by lower purchased power prices. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause (See Operating Revenue) and increased due to higher kilowatt-hour sales to these customers.

Operating and Maintenance Expense increased $9.3 million, or 7 percent, from 2010 primarily reflecting increased property taxes, higher plant expenses due to timing of scheduled maintenance, and salaries and benefit expenses.

Depreciation Expense increased $4.4 million, or 12 percent, from 2010 reflecting additional property, plant and equipment in service.

Interest expense increased $2.4 million, or 16 percent, from 2010 primarily due to higher long-term debt balances.

Income tax expense decreased $17.0 million, or 53 percent, from 2010 primarily due the reversal of a $6.2 million deferred tax liability related to a revenue receivable Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case and the recognition of a $2.9 million income tax benefit related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 resulting from PPACA. Also contributing to the decrease were additional renewable tax credits in 2011, as well as a non-recurring income tax charge of $3.6 million resulting from PPACA in the first quarter of 2010.


ALLETE Second Quarter Form 10-Q
 
31

 

COMPARISON OF THE SIX MONTHS ENDED JUNE 30, 2011 AND 2010

Investments and Other

Operating revenue increased $2.7 million, or 8 percent, from 2010 primarily due to a $2.9 million increase in revenue at BNI Coal, which operates under a cost-plus contract and recorded higher sales revenue as a result of higher expenses in 2011. (See Operating Expense.)

ALLETE Properties
2011
2010
Revenue and Sales Activity
Quantity
Amount
Quantity
Amount
Dollars in Millions
       
Revenue from Land Sales
       
Acres (a)
3
$0.4
Revenue from Land Sales
 
0.4
 
Other Revenue (b)
 
0.7
 
$1.3
 Total ALLETE Properties Revenue
 
$1.1
 
$1.3
(a)  
Acreage amounts are shown on a gross basis, including wetlands and non-controlling interest.
(b)  
For the six months ended June 30, 2011, Other Revenue includes a forfeited deposit due to the transfer of property back to ALLETE Properties by deed-in-lieu of foreclosure, in satisfaction of amounts previously owed under long-term financing receivables. For the six months ended June 30, 2010, Other Revenue primarily includes a $0.7 million pre-tax gain resulting from the  transfer of property back to ALLETE Properties by deed-in-lieu of foreclosure, in satisfaction of amounts previously owed under long-term financing receivables from an entity which filed for bankruptcy in June 2009.
 
Operating expenses increased $3.6 million, or 10 percent, from 2010 reflecting higher expenses at BNI Coal of $2.6 million primarily due to higher fuel costs and equipment repairs; these costs were recovered through the cost-plus contract. (See Operating Revenue.) 2011 also included higher investment-related expenses of $1.5 million. These increases were offset by decreased expenses at ALLETE Properties of $1.0 million primarily due to reduction in operating expenses.
 
Income Taxes – Consolidated

For the six months ended June 30, 2011, the effective tax rate was 18.2 percent (41.0 percent for the six months ended June 30, 2010). The effective tax rate for the six months ended June 30, 2011, was lowered by 4.4 percent due to the income tax benefit related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 resulting from the PPACA and by 9.4 percent due to the reversal of the deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case. The effective tax rate deviated from the statutory rate (approximately 41 percent) due to non-recurring items discussed above, deductions for AFUDC-Equity, investment tax credits, renewable tax credits and depletion. We expect the effective tax rate for the full year 2011 to be approximately 25 percent. (See Note 9. Income Tax Expense.)


CRITICAL ACCOUNTING ESTIMATES

Certain accounting measurements under 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 2010 Form 10-K.


ALLETE Second Quarter Form 10-Q
 
32

 

OUTLOOK

For additional information see our 2010 Form 10-K.

ALLETE is an energy company committed to earning a financial return that rewards our shareholders, allows for reinvestment in our businesses and sustains growth. The Company has a key long-term objective of achieving a minimum average earnings per share growth of 5 percent per year and maintaining a competitive dividend payout. To accomplish this, we intend to take the actions necessary to earn our allowed rate of return in our regulated businesses, while we pursue growth initiatives in renewable energy, transmission and other energy-centric businesses.

We believe that, over the long-term, less carbon intensive and more sustainable renewable energy sources will play an increasingly important role in our nation’s energy mix. Minnesota Power intends to develop additional renewable resources which will be used to meet regulated renewable supply requirements. In addition, in July 2011, we established ALLETE Clean Energy Inc., a wholly-owned subsidiary of ALLETE. ALLETE Clean Energy will operate independently of Minnesota Power to acquire or develop new projects aimed at delivering energy with minimal environmental impact, including wind, hydro, biomass, solar and natural gas. ALLETE Clean Energy intends to market to electric utilities, cooperatives, municipalities, independent power marketers and large end-users across North America and will be subject to appropriate state and federal regulatory approvals.

For wind development, we will capitalize on our existing presence in North Dakota through BNI Coal, our recently acquired DC transmission line and our Bison 1, 2 and 3 wind projects. We have a long-term business presence and established landowner relationships in North Dakota. See Renewable Energy below for more discussion on the DC line acquisition and our Bison 1, 2 and 3 wind projects.

We also plan to make investments in Upper Midwest transmission opportunities that strengthen or enhance the regional transmission grid or take advantage of our geographical location between sources of renewable energy and end users. Minnesota Power is participating with other regional utilities in making regional transmission investments as a member of the CapX2020 initiative. In addition, we plan to make additional investments to fund our pro rata share of ATC’s future capital expansion program. Both the CapX2020 initiative and our investment in ATC are discussed in more detail under Transmission below.

We are also exploring investing in other energy-centric businesses that will complement our non-regulated renewable energy business or leverage demand trends related to transmission, environmental control or energy efficiency.

ALLETE intends to sell its Florida land assets at reasonable prices, over time or in bulk transactions, and reinvest the proceeds in its growth initiatives. ALLETE Properties does not intend to acquire additional real estate.

Regulated Operations. Minnesota Power’s long-term strategy is to maintain its competitively priced production of energy, while complying with environmental permit conditions and renewable requirements, and to earn our allowed rate of return. Keeping the cost of energy production competitive enables Minnesota Power to effectively compete in the wholesale power markets and minimizes retail rate increases to help maintain the viability of its customers. As part of maintaining cost competitiveness, Minnesota Power intends to reduce its exposure to possible future carbon and GHG legislation by reshaping its generation portfolio, over time, to reduce its reliance on coal. We will monitor and review proposed environmental regulations and may challenge those that add considerable cost with limited environmental benefit. Current economic conditions require a very careful balancing of the benefit of further environmental controls with the impacts of the costs of those controls on our customers as well as on the Company and its competitive position. We will pursue current cost recovery rider approval for environmental and renewable investments, and will work with our legislators and regulators to earn a fair return. We project that our Regulated Operations will not earn its allowed rate of return in 2011.

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

 
ALLETE Second Quarter Form 10-Q
 
33

 

OUTLOOK (Continued)
Rates (Continued)

2010 Rate Case. On February 22, 2011, Minnesota Power timely filed an appeal of the MPUC’s interim rate decision in the Company’s 2010 rate case with the Minnesota Court of Appeals. The Company is appealing the MPUC’s finding of exigent circumstances in the interim rate decision with the primary arguments that the MPUC exceeded its statutory authority, made its decision without the support of a body of record evidence and that the decision violated public policy. The Company desires to resolve whether the MPUC’s finding of exigent circumstances was lawful for application in future rate cases. The briefing schedule is complete and oral argument is scheduled for September 21, 2011. If the appeal is successful, the Minnesota Court of Appeals will remand the case to the MPUC for further action consistent with its decision. The Company cannot predict the outcome of the matter at this time.

FERC-Approved Wholesale Rates. Minnesota Power’s non-affiliated municipal 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 customer of Minnesota Power. In 2008, Minnesota Power entered into formula-based rate contracts with these customers. In February 2011, the Minnesota Power entered into a new formula-based contract with the City of Nashwauk, effective May 1, 2012, through April 30, 2022, and in June 2011, Minnesota Power entered into restated contracts, effective July 1, 2011, through June 30, 2019, with the remaining 15 Minnesota municipal customers. The rates included in these contracts are calculated using a cost-based formula methodology that is set each July using estimated costs and provides for a true-up calculation for actual costs. The contract terms include a termination clause requiring a three-year notice to terminate. Under the restated contracts, no termination notices may be given prior to June 30, 2016.

Industrial Customers. Electric power is one of several key inputs in the taconite mining, paper production and pipeline industries. Approximately 55 percent of our Regulated Utility kilowatt-hour sales in the six months ended June 30, 2011 (49 percent in the six months ended June 30, 2010) were made to our industrial customers, which include the taconite, paper and pulp and pipeline industries.

During 2010, the domestic steel industry rebounded from the low levels of production seen in 2009. According to the American Iron and Steel Institute (AISI), an association of North American steel producers, United States raw steel production operated at approximately 70 percent of capacity in 2010. AISI projects that U.S. steel production levels will be at about 75 percent of capacity in 2011 (for the six months ended June 30, 2011, steel production was at 74 percent). There has been a general historical correlation between U.S. steel production and Minnesota taconite production. Based on these projections, 2011 taconite production levels in Minnesota are on track to exceed 2010 production levels (36 million tons). We will market available power to Other Power Suppliers, when necessary, in an effort to mitigate the earnings impact of any lower industrial sales. Other Power Supply 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.

City of Nashwauk. In February 2011, the Company entered into a new formula-based wholesale electric sales agreement with the City of Nashwauk for all of the City’s electric service requirements, effective May 1, 2012, through April 30, 2022. On July 27, 2011, the City of Nashwauk entered into a long-term electric service agreement with Essar Steel Ltd. for service beginning in 2012, for Essar’s proposed taconite facility of 70 to 110 MW, which is currently under construction, as well as an expansion to include a direct reduced iron and steelmaking facility expected in 2015.

Renewable Energy. In February 2007, Minnesota enacted a law requiring 25 percent of Minnesota Power’s total retail energy sales in Minnesota to come 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. Minnesota Power has developed a plan to meet the renewable goals set by Minnesota and has included this plan in its 2010 Integrated Resource Plan. The MPUC approved our Integrated Resource Plan at its April 7, 2011 hearing and issued its final order on May 6, 2011. The law allows the MPUC to modify or delay meeting a milestone if implementation will cause significant ratepayer cost or technical reliability issues. If a utility is not in compliance with a milestone, the MPUC may order the utility to construct facilities, purchase renewable energy or purchase renewable energy credits. We are currently on track to meet the 12 percent renewable energy sales milestone by 2012.


ALLETE Second Quarter Form 10-Q
 
34

 

OUTLOOK (Continued)
Renewable Energy (Continued)

Minnesota Power has taken several steps to begin executing its renewable energy strategy through key renewable projects that will ensure we meet the identified state mandate. We have executed two long-term power purchase agreements with an affiliate of NextEra Energy, Inc., for wind energy in North Dakota (Oliver Wind I and II). Other steps include Taconite Ridge, our wind facility located in northeastern Minnesota, our Bison 1, 2 and 3 wind development projects and our Hibbard biomass upgrade project.

North Dakota Wind Development. In December 2009, we purchased an existing 250 kV DC transmission line from Square Butte. The 465-mile transmission line runs from Center, North Dakota, to Duluth, Minnesota. We use this line to transport increasing amounts of wind energy from North Dakota, while gradually phasing out coal-based electricity currently being delivered to our system over this transmission line from Square Butte’s coal-fired generating unit.

Bison 1 is a two phase, 82 MW wind project in North Dakota. All permitting has been received and the first phase was completed in 2010. Phase one included the construction of a 22-mile, 230 kV transmission line and the installation of sixteen 2.3-MW wind turbines. Phase two is expected to be completed in late 2011 and consists of the installation of fifteen 3.0-MW wind turbines. Bison 1 is expected to have a total capital cost of approximately $177 million, of which $137.4 million was spent through June 30, 2011. In 2009, the MPUC approved Minnesota Power’s petition seeking current cost recovery for investments and expenditures related to Bison 1 and in July 2010, the MPUC approved our petition establishing rates effective August 1, 2010. On March 31, 2011, Minnesota Power petitioned the MPUC to update the rates for additional investments and expenditures related to Bison 1.

Bison 2 and Bison 3 are both 105 MW wind projects in North Dakota which, if approved by the MPUC, are expected to be completed by the end of 2012. Total project costs for Bison 2 and Bison 3 are estimated to be approximately $160 million each. Construction would begin upon the receipt of appropriate regulatory and permitting approvals. Requests for approval of Bison 2 and Bison 3 were filed with the MPUC on March 24, 2011, and June 21, 2011, respectively. Site permit applications were submitted to the NDPSC on April 6, 2011, and July 7, 2011, respectively. Approvals of the site permit applications are expected in the third quarter of 2011. We will file for current cost recovery for Bison 2 and Bison 3 with the MPUC once the projects and related permitting have been approved.

Manitoba Hydro. Minnesota Power has a long-term PPA with Manitoba Hydro, for the purchase of 50 MW of capacity and energy associated with that capacity, which expires in 2015. In addition, in April 2010, Minnesota Power signed a PPA with Manitoba Hydro to purchase surplus energy through April 2022. This energy-only transaction primarily consists of surplus hydro energy on Manitoba Hydro’s system that is delivered to Minnesota Power on a non-firm basis. The pricing is based on forward market prices. Under this agreement with Manitoba Hydro, Minnesota Power will be purchasing at least one million MWh of energy over the contract term. On March 11, 2011, the MPUC approved this PPA with Manitoba Hydro.

On May 19, 2011, Minnesota Power and Manitoba Hydro signed a long-term PPA. The PPA, subject to regulatory approval, calls for Manitoba Hydro to sell 250 MWs of capacity and energy to Minnesota Power under a power sales and an energy exchange agreement for 15 years beginning in 2020 and requires construction of additional transmission capacity between Manitoba and the United States. The capacity price is adjusted annually until 2020 by a change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed price component adjusted for a change in a governmental inflationary index and a natural gas index, as well as market prices.


ALLETE Second Quarter Form 10-Q
 
35

 

OUTLOOK (Continued)

Integrated Resource Plan . In October 2009, Minnesota Power filed with the MPUC its 2010 Integrated Resource Plan, a comprehensive estimate of future capacity needs within Minnesota Power’s service territory. Minnesota Power does not anticipate the need for new base load generation within the Minnesota Power service territory through 2025 and plans to meet estimated future customer demand while achieving:

·  
Increased system flexibility to adapt to volatile business cycles and varied future industrial load scenarios;
·  
Reductions in the emission of GHGs (primarily CO 2 ); and
·  
Compliance with mandated renewable energy standards.

To achieve these objectives over the coming years, we plan to reshape our generation portfolio by adding approximately 300 MW of renewable energy to our generation mix and exploring options to incorporate peaking or intermediate resources. The first phase of the Bison 1 wind project in North Dakota was put into service in 2010 and the second phase is expected to be in service in late 2011, increasing our renewable generation by a total of 82 MW. The Bison 2 105 MW and the Bison 3 105 MW wind projects, if approved by the MPUC, along with the Hibbard Biomass Upgrade Project, will continue our expansion into renewable energy to meet our Integrated Resource Plan goals.

We project average annual long-term growth, excluding prospective additional load from industrial and municipal customers, of approximately one percent in electric usage through 2025. We will also focus on conservation and demand side management to meet the energy savings goals established in Minnesota legislation. The MPUC approved our Integrated Resource Plan in its final order issued on May 6, 2011. Minnesota Power is required to file a baseload diversification study within nine months of receiving the final order. Minnesota Power’s next Integrated Resource Plan must be filed with the MPUC no later than July 1, 2013.

Transmission . We are making investments in Upper Midwest transmission opportunities that strengthen or enhance the regional transmission grid. These investments include the CapX2020 initiative, investments in our transmission assets and our investment in ATC.

Transmission Investments. We have an approved cost recovery rider in place for certain transmission expenditures and the continued use of our 2009 billing factor was approved by the MPUC on May 11, 2011. The billing factor allows us to charge our retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. On June 29, 2011, we filed an updated billing factor that includes additional transmission projects and expenses which we expect to be approved in late 2011.

CapX2020 .   Minnesota Power is a participant in the CapX2020 initiative which represents an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX2020, which consists of electric cooperatives, municipals and investor-owned utilities, including Minnesota’s largest transmission owners, 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.

Minnesota Power is currently participating in three CapX2020 projects: the Fargo to St. Cloud project, the Monticello to St. Cloud project, which together total a 238-mile, 345 kV line from Fargo to Monticello, and the 70-mile, 230 kV line between Bemidji and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota. Based on projected costs of the three transmission lines and the percentage agreements among participating utilities, Minnesota Power plans to invest between $100 million and $125 million in the CapX2020 initiative through 2015, of which $17.5 million was spent through June 30, 2011. As future CapX2020 projects are identified, Minnesota Power may elect to participate on a project-by-project basis.

In July 2010, the MPUC granted a route permit for the 28-mile, 345 kV line between Monticello and St. Cloud. Construction of the project is expected to be completed in late 2011. On June 10, 2011, the MPUC approved the route permit for the Minnesota portion of the St. Cloud to Fargo project. The North Dakota permitting process is underway. The entire 238-mile, 345 kV line from St. Cloud to Fargo is expected to be in service by 2015. Construction for the Bemidji to Grand Rapids 230 kV line project commenced in January 2011.

 
ALLETE Second Quarter Form 10-Q
 
36

 

OUTLOOK (Continued)
Transmission (Continued)

In November 2010, the MPUC approved a route permit for the Bemidji to Grand Rapids line. The Leech Lake Band of Ojibwe (LLBO) subsequently requested that the MPUC suspend or revoke the route permit and also served the CapX2020 utilities with a tribal court complaint asserting adjudicatory and regulatory authority over the project. The CapX2020 utilities filed a request for declaratory judgment in federal court that the project does not require the LLBO consent to the line crossing non-tribal land within the Leech Lake reservation. In response, the LLBO filed a motion to dismiss at the federal court scheduled for hearing on September 16, 2011. The MPUC has taken no action in the matter in light of ongoing litigation in federal and tribal court. On June 22, 2011, the Federal Judge issued a preliminary injunction directing the LLBO to cease and desist its claims of tribal court jurisdiction or from taking other actions to interfere with regulatory review, approval or project construction. The CapX2020 utilities are vigorously defending against the LLBO actions.

Investment in ATC. As of June 30, 2011, our equity investment in ATC was $96.3 million, representing an approximate 8 percent ownership interest. ATC rates are based on a FERC approved 12.2 percent return on common equity dedicated to utility plant. ATC has identified $3.4 billion in future projects needed over the next 10 years to improve the adequacy and reliability of the electric transmission system as well as to meet regional needs based on economic benefits and public policy initiatives for renewable energy. This investment is expected to be funded through a combination of internally generated 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. On July 29, 2011, we invested an additional $0.6 million in ATC for a total investment of $2.0 million in 2011. (See Note 6. Investment in ATC.)

On April 13, 2011, ATC and Duke Energy Corporation announced the creation of a joint venture that intends to build, own and operate new electric transmission infrastructure in the United States and Canada. The joint venture will be subject to the rules and regulations of FERC, MISO and various other independent system operators and state regulatory authorities. We are unable to predict how this joint venture will affect ATC operations. We intend to maintain our approximate 8 percent ownership interest in ATC.

Investments and Other

BNI Coal.   BNI Coal anticipates selling approximately 4 million tons of coal in 2011 (3.8 million tons were sold in 2010) and has sold 2.1 million tons through June 30, 2011 (2.2 million tons were sold as of June 30, 2010).

ALLETE Properties.   ALLETE Properties represents our Florida real estate investment. Our current strategy for the assets is to complete and maintain key entitlements and infrastructure improvements without requiring significant additional investment, and sell the portfolio over time or in bulk transactions. ALLETE intends to sell its Florida land assets at reasonable prices when opportunities arise, and reinvest the proceeds in its growth initiatives. ALLETE does not intend to acquire additional Florida real estate.

Our two major development projects are Town Center and Palm Coast Park. Another major project, Ormond Crossings, is currently in the planning stage. The City of Ormond Beach, Florida, approved a Development Agreement for Ormond Crossings which will facilitate development of the project as currently planned. Separately, the Lake Swamp wetland mitigation bank was permitted on land that was previously part of Ormond Crossings.

 
ALLETE Second Quarter Form 10-Q
 
37

 

OUTLOOK (Continued)
Investments and Other (Continued)

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%
963
2,373
2,225,200
Palm Coast Park
100%
3,842
3,564
3,056,800
Total Current Development Projects
 
4,805
5,937
5,282,000
         
Planned Development Project
       
Ormond Crossings
100%
2,924
2,950
3,215,000
Other
       
Lake Swamp Wetland Mitigation Project
100%
3,049
(d)
(d)
Total of Development Projects
 
10,778
8,887
8,497,000
(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)
The Lake Swamp wetland mitigation bank is a permitted, regionally significant wetlands mitigation bank. Wetland mitigation credits will be used at Ormond Crossings and will also be available-for-sale to developers of other projects that are located in the bank’s service area.

In addition to the three development projects and the mitigation bank, ALLETE Properties has 1,976 acres of other land available-for-sale.

ALLETE intends to sell its Florida land assets at reasonable prices when opportunities arise. However, if weak market conditions continue for an extended period of time, the impact on our future operations would be the continuation of little or no sales while still incurring operating expenses and carrying costs such as community development district assessments and property taxes.

Income Taxes .   ALLETE’s aggregate federal and multi-state statutory tax rate is approximately 41 percent for 2011. 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, renewable tax credits, AFUDC-Equity, domestic manufacturer’s deduction, depletion and other items. The annual effective rate can also be impacted by such items as changes in income 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, regulatory action and resolution of prior years’ tax matters. We expect the effective tax rate for the full year 2011 to be approximately 25 percent. (See Note 9. Income Tax Expense.)


LIQUIDITY AND CAPITAL RESOURCES

Liquidity Position. ALLETE is well-positioned to meet the Company’s cash flow needs. As of June 30, 2011, we had a cash balance of $79.4 million, $158.5 million in available consolidated lines of credit which included a committed, syndicated, unsecured revolving line of credit of $150 million and a debt-to-capital ratio of 43 percent. Effective July 1, 2011, we replaced our $150 million line of credit with a new $250 million credit facility. (See Note 7. Short-Term and Long-Term Debt.)

Capital Structure. ALLETE’s capital structure is as follows:

 
June 30,
 
December 31,
 
 
2011
%
2010
%
Millions
       
ALLETE Equity
$1,029.0
56
$976.0
55
Non-Controlling Interest in Subsidiaries
8.8
1
9.0
1
Long-Term Debt (Including Current Maturities)
783.6
43
785.0
44
Short-Term Debt
2.5
1.0
 
$1,823.9
100
$1,771.0
100


ALLETE Second Quarter Form 10-Q
 
38

 

LIQUIDITY AND CAPITAL RESOURCES (Continued)

Cash Flows. Selected information from ALLETE’s Consolidated Statement of Cash Flows is as follows:

For the Six Months Ended June 30,
2011
2010
Millions
   
Cash and Cash Equivalents at Beginning of Period
$44.9
$25.7
Cash Flows from (used for)
   
Operating Activities
130.0
108.5
Investing Activities
(87.0)
(82.2)
Financing Activities
(8.5)
(6.7)
    Change in Cash and Cash Equivalents
34.5
19.6
Cash and Cash Equivalents at End of Period
$79.4
$45.3

Operating Activities. Cash from operating activities was $130.0 million for the six months ended June 30, 2011 ($108.5 million for the six months ended June 30, 2010). Cash from operating activities was higher in 2011 primarily due to higher net income as a result of strong operations. Also contributing to the increase over 2010 were income tax refunds of $14.2 million.

Investing Activities. Cash used for investing activities was $87.0 million for the six months ended June 30, 2011 ($82.2 million for the six months ended June 30, 2010). Higher capital expenditures in 2011 were offset by the $6.7 million redemption of ARS in January 2011.

Financing Activities. Cash used for financing activities was $8.5 million for the six months ended June 30, 2011 ($6.7 million for the six months ended June 30, 2010). In 2010, cash from financing activities included $15 million of net proceeds from the issuance of long-term debt. There were no debt issuances in 2011. This was partially offset by higher proceeds from issuances of common stock of $7.7 million in 2011.

Working Capital .   Additional working capital, if and when needed, generally is provided by consolidated bank lines of credit or the sale of securities or commercial paper. As of June 30, 2011, we had available consolidated bank lines of credit aggregating $158.5 million, the majority of which expire in January 2012. On May 25, 2011, ALLETE entered into a $250 million Credit Agreement (Agreement) to replace our $150 million credit facility. The new Agreement, effective July 1, 2011, is unsecured and has a maturity date of June 30, 2015, and replaced the $150 million line of credit expiring in January 2012. In addition, we have 1.7 million original issue shares of our common stock available for issuance through Invest Direct, our direct stock purchase and dividend reinvestment plan, and 2.7 million original issue shares of common stock available for issuance through a Distribution Agreement with KCCI, Inc. The amount and timing of future sales of our securities will depend upon market conditions and our specific needs.

Securities. We entered into a distribution agreement with KCCI, Inc., in February 2008, as amended, with respect to the issuance and sale of up to an aggregate of 6.6 million shares of our common stock, without par value. For the six months ended June 30, 2011, 0.4 million shares of common stock were issued under this agreement, for net proceeds of $14.7 million (0.2 million shares were issued for the six months ended June 30, 2010, for net proceeds of $6.0 million). As of June 30, 2011, 2.7 million shares of common stock remain available for issuance pursuant to the amended distribution agreement. The shares issued in 2011 and 2010 were offered for sale, from time to time, in accordance with the terms of the amended distribution agreement pursuant to Registration Statement Nos. 333-170289 and 333-147965. The remaining shares may be offered for sale, from time to time, in accordance with the terms of the amended distribution agreement pursuant to Registration Statement No. 333-170289.

In 2011, we issued 0.3 million shares of common stock through Invest Direct, the Employee Stock Purchase Plan and the Retirement Savings and Stock Ownership Plan resulting in net proceeds of $8.2 million. These shares of common stock were registered under Registration Statement Nos. 333-150681, 333-105225, and 333-162890, respectively.

Financial Covenants. See Note 7. Short-Term and Long-Term Debt for information regarding our financial covenants.


ALLETE Second Quarter Form 10-Q
 
39

 

LIQUIDITY AND CAPITAL RESOURCES (Continued)

Pension and Other Postretirement Benefit Plans . Management considers various factors when making funding decisions, such as regulatory requirements, actuarially determined minimum contribution requirements and contributions required to avoid benefit restrictions for the defined benefit pension plans. We expect to make approximately $2 million in contributions to our defined benefit pension plan and an additional $1 million to our other postretirement benefit plan in 2011. (See Note 12. Pension and Other Postretirement Benefit Plans.)

Off-Balance Sheet Arrangements

Off-balance sheet arrangements are summarized in our 2010 Form 10-K, with additional disclosure in Note 13. Commitments, Guarantees and Contingencies of this Form 10-Q.

Capital Requirements

Our capital expenditures for 2011 are expected to be $278 million. For the six months ended June 30, 2011, capital expenditures totaled $79.7 million ($85.1 million for the six months ended June 30, 2010). The expenditures were primarily made in the Regulated Operations segment.

ALLETE’s projected capital expenditures for the years 2011 through 2015 are presented in the table below. Actual capital expenditures may vary from the estimates due to changes in forecasted plant maintenance, regulatory decisions or approvals, future environmental requirements, base load growth, capital market conditions or executions of new business strategies.

Capital Expenditures
2011
2012
2013
2014
2015
Total
Millions
           
Regulated Utility Operations
           
 
Base and Other
$107
$97
$92
$94
$99
$489
 
Current Cost Recovery   (a)
           
   
Renewable (b)
124
291
4
8
1
428
   
Transmission (c)
26
26
32
20
11
115
 
Total Current Cost Recovery
150
317
36
28
12
543
Regulated Utility Capital Expenditures
257
414
128
122
111
1,032
Other
 
21
25
14
8
8
76
Total Capital Expenditures
$278
$439
$142
$130
$119
$1,108
(a)  
Estimated current capital expenditures recoverable outside of a rate case.
(b)  
Renewable riders include Bison 1, Bison 2, Bison 3 and Hibbard Projects.
(c)  
Transmission capital expenditures include CapX2020 projects.

Pending environmental regulations could result in significant capital expenditures in the future that are not included in the table above. Currently, future CapX2020 transmission projects are under discussions. Minnesota Power may elect to participate on a project-by-project basis.


OTHER

Environmental Matters

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. Environmental Matters are summarized in our 2010 Form 10-K, with additional disclosure in Note 13. Commitments, Guarantees and Contingencies of this Form 10-Q. We are unable to predict the outcome of the matters discussed.

Employees

BNI Coal’s labor agreement with the International Brotherhood of Electrical Workers Local 1593 was accepted on March 1, 2011. The contract went into effect on April 1, 2011, and expires on March 31, 2014.

 
ALLETE Second Quarter Form 10-Q
 
40

 

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, 2011, our available-for-sale securities portfolio consisted of securities established to fund certain employee benefits. (See Note 3. Investments.)


COMMODITY PRICE RISK

Our regulated utility operations incur costs for power and fuel (primarily coal and related transportation) in Minnesota and power and natural gas purchased for resale in our regulated service territory in Wisconsin. Our Minnesota regulated utility’s exposure to price risk for these commodities is significantly mitigated by the current ratemaking process and regulatory environment, which allows recovery of fuel costs in excess of those included in base rates. Conversely, costs below those in base rates 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 power and coal and related transportation costs (in Minnesota) and natural gas (in Wisconsin).


POWER MARKETING

Power Marketing . Our power marketing activities consist of (1) purchasing energy in the wholesale market to serve our regulated service territory 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 to the wholesale market to optimize the value of our generating facilities.

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 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 prevailing market conditions. Based on the variable rate debt outstanding at June 30, 2011, and assuming no other changes to our financial structure, an increase of 100 basis points in interest rates would impact the amount of pretax interest expense by $0.7 million. This amount was determined by considering the impact of a hypothetical 100 basis point increase to the average variable interest rate on the variable rate debt outstanding as of June 30, 2011.


ALLETE Second Quarter Form 10-Q
 
41

 

ITEM 4.  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures. As of June 30, 2011, 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. 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. The Company is undertaking a project with the objective of improving business process and information systems. The focus of the project is the upgrade or addition of certain financial and supply-chain applications; these changes are not the result of any identified deficiencies in our internal control over financial reporting. The Company expects the project to result in greater efficiencies and enhance the processes used by employees to record financial transactions, purchase materials and service, process payments and analyze data. Implementation is expected in the first quarter of 2012.


PART II.  OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

Interim Rate Decision. On February 22, 2011, Minnesota Power timely filed an appeal of the MPUC’s interim rate decision in the Company’s 2010 rate case with the Minnesota Court of Appeals. The Company is appealing the MPUC’s finding of exigent circumstances in the interim rate decision with the primary arguments that the MPUC exceeded its statutory authority, made its decision without the support of a body of record evidence and that the decision violated public policy. The Company desires to resolve whether the MPUC’s finding of exigent circumstances was lawful for application in future rate cases. The briefing schedule is complete and oral argument is scheduled for September 21, 2011. If the appeal is successful, the Minnesota Court of Appeals will remand the case to the MPUC for further action consistent with its decision. The Company cannot predict the outcome of the matter at this time.

CapX2020 Bemidji to Grand Rapids Line. In November 2010, the MPUC approved a route permit for the Bemidji to Grand Rapids line. The Leech Lake Band of Ojibwe (LLBO) subsequently requested the MPUC suspend or revoke the route permit and also served the CapX2020 owners with a tribal court complaint asserting adjudicatory and regulatory authority over the project. The CapX2020 owners filed a declaratory judgment in federal court that the project does not require LLBO consent to cross non-tribal land within the reservation. In response, the LLBO filed a motion to dismiss at the federal court scheduled for hearing on September 16, 2011. The MPUC has taken no action in the matter in light of ongoing litigation in federal and tribal court. On June 22, 2011, the Federal Judge issued a preliminary injunction directing the LLBO to cease and desist its claims of tribal court jurisdiction or from taking other actions to interfere with regulatory review, approval or project construction. The CapX2020 utilities are vigorously defending against LLBO actions.


ITEM 1A.  RISK FACTORS

There have been no material changes from the risk factors disclosed in Part 1, Item 1A Risk Factors of our 2010 Form 10-K.


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

None.

 
ALLETE Second Quarter Form 10-Q
 
42

 

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

None.


ITEM 4.  RESERVED


ITEM 5.  OTHER INFORMATION

Submission of Matters to a Vote of Security Holders. At its meeting on July 19, 2011, the Board of Directors of the Company determined to hold future non-binding shareholder advisory votes on executive compensation on an annual basis until the next vote on the frequency of shareholder votes on executive compensation. Such determination is consistent with the previous recommendation of the Board of Directors and the preference of Company shareholders, as represented by their votes at the annual meeting of shareholders on May 10, 2011.

Mine Safety Disclosures – Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act. The Dodd-Frank Act requires issuers to include in periodic reports filed with the SEC certain information relating to citations or orders for violations of standards under the Federal Mine Safety and Health Act of 1977 (Mine Safety Act).

For the six months ended June 30, 2011, there were no citations, orders or notices received under Sections 104, 104(b), 104(d), 107(a) or 104(e) of the Mine Safety Act, no violations of Section 110(b)(2) of the Mine Safety Act and there were no fatalities. In May 2011, BNI Coal received one citation under Section 104(a) for $873.


ITEM 6.  EXHIBITS

Exhibit
Number

 
10(a)
 
Credit Agreement dated as of May 25, 2011 among ALLETE, Inc., as Borrower, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and JPMorgan Securities LLC, as Sole Lead Arranger and Sole Book Runner (filed as Exhibit 10 to the May 27, 2011, Form 8-K, File No. 1-3548).

 
10(b)
 
Amended and Restated Letter of Credit Agreement, dated as of June 3, 2011, among ALLETE, the Participating Banks and Wells Fargo Bank, National Association, as Administrative Agent and Issuing Bank.

 
31(a)
 
Rule 13a-14(a)/15d-14(a) Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 
31(b)
 
Rule 13a-14(a)/15d-14(a) Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 
32
 
Section 1350 Certification of Periodic Report by the Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS
XBRL Instance
101.SCH
XBRL Schema
101.CAL
XBRL Calculation
101.DEF
XBRL Definition
101.LAB
XBRL Label
101.PRE
XBRL Presentation

 
ALLETE Second Quarter Form 10-Q
 
43

 

SIGNATURES


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, 2011
 
/s/ Mark A. Schober
   
Mark A. Schober
   
Senior Vice President and Chief Financial Officer
     
     
     
     
     
August 5, 2011
 
/s/ Steven Q. DeVinck
   
Steven Q. DeVinck
   
Controller and Vice President – Business Support


ALLETE Second Quarter Form 10-Q
 
44

 

Exhibit 31(a)


Rule 13a-14(a)/15d-14(a) Certification by the Chief Executive Officer
Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002


I, Alan R. Hodnik, of ALLETE, Inc. (ALLETE), certify that:

1.  
I have reviewed this quarterly report on Form 10-Q for the quarterly period ended June 30, 2011, of ALLETE;
 
2.  
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3.  
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4.  
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e))  and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
 
 
a.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
 
b.
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
 
 
c.
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
 
d.
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
 
5.  
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
 
 
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
 
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
 

Date:  August 5, 2011
Alan R. Hodnik
 
 
 
Alan R. Hodnik
 
President and Chief Executive Officer
 
Exhibit 31(b)


Rule 13a-14(a)/15d-14(a) Certification by the Chief Financial Officer
Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002


I, Mark A. Schober, of ALLETE, Inc. (ALLETE), certify that:

1.
I have reviewed this quarterly report on Form 10-Q for the quarterly period ended June 30, 2011, of ALLETE;
 
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
 
 
a.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
 
b.
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
 
 
c.
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
 
d.
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
 
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
 
 
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
 
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
 

Date:  August 5, 2011
Mark A. Schober
 
 
 
Mark A. Schober
 
Senior Vice President and Chief Financial Officer

Exhibit 32


Section 1350 Certification of Periodic Report
By the Chief Executive Officer and Chief Financial Officer
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, each of the undersigned officers of ALLETE, Inc. (ALLETE), does hereby certify that:
 
1.  
The Quarterly Report on Form 10-Q of ALLETE for the quarterly period ended June 30, 2011, (Report) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 (15 U.S.C. 78m); and
 
2.  
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of ALLETE.
 


Date:  August 5, 2011
Alan R. Hodnik
 
 
 
Alan R. Hodnik
 
President and Chief Executive Officer




Date:  August 5, 2011
Mark A. Schober
 
 
 
Mark A. Schober
 
Senior Vice President and Chief Financial Officer



This certification shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to liability pursuant to that section. Such certification shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that ALLETE specifically incorporates it by reference.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to ALLETE and will be retained by ALLETE and furnished to the Securities and Exchange Commission or its staff upon request.
 
 
 

 
 
 
 
 
 

AMENDED AND RESTATED LETTER OF CREDIT AGREEMENT
 
Dated as of June 3, 2011
 
Among
 
ALLETE, INC.
(formerly known as Minnesota Power, Inc.)
 
THE PARTICIPATING BANKS PARTY HERETO
 
and
 
WELLS FARGO BANK, NATIONAL ASSOCIATION,
as Administrative Agent and Issuing Bank
 
 
 
 
 


 
 
 
 
 
 
 
 

 
 
 
TABLE OF CONTENTS
 
 
Page
   
ARTICLE I DEFINITIONS 1
   Se c t ion 1.1 Definitions 1
   
ARTICLE II LETTER OF CREDIT 13
    
Section 2.1
Section 2.2
Section 2.3
 
Section 2.4
Section 2.5
Section 2.6
S ection 2.7
Section 2.8
Section 2.9
Section 2.10
Section 2.11
Section 2.12
Section 2.13
Section 2.14
Section 2.15
Section 2.16
Section 2.17
Issuance of L/C Extension
Letter of Credit Drawings
Company Reimbursement Obligations; Participating Bank Payments
     in Respect of the Letter of Credit; Drawing Loans
Agreement of the Company and Each Participating Bank
Interest Rates and Payment Dates
Payments
Security Interest in Pledged Bonds
Fees
Method of Payment
Lending Offices and Funding
Computation of Interest
Payment Due on Non-Business Day to be made on Next Business Day
Late Payments
Source of Funds
Extension of Stated Expiration Date
Provisions Applicable to LIBOR Drawing Loans
Rescission of Payments
13
14
 
14
16
16
17
18
18
19
19
19
19
20
20
20
21
22
   
ARTICLE III CONDITIONS PRECEDENT 22
  Section 3.1
Section 3.2
Conditions Precedent to Issuance of the L/C Extension
Conditions Precedent to Drawing Loans
22
23
   
ARTICLE IV REPRESENTATIONS AND WARRANTIES 24
  Section 4.1 Company’s Representations 24
   
ARTICLE V COVENANTS 26
  Section 5.1
Section 5.2
Section 5.3
Section 5.4
Section 5.5
Section 5.6
Section 5.7
Section 5.8
Section 5.9
Section 5.10
Section 5.11
Section 5.12
Information
Maintenance of Property; Insurance
Maintenance of Existence
Compliance with Laws
Inspection of Property, Books and Records
Use of Proceeds
Taxes
Negative Pledge
Prohibition of Fundamental Changes
Maximum Ratio of Total Indebtedness to Total Capitalization
Bond Documents
Official Statement
27
28
28
28
28
29
29
29
31
31
31
31
 
 
 
i

 
 
  Section 5.13
Section 5.14
Section 5.15
Section 5.16
Optional Redemptions
Conversion
Pari Passu
Patriot Act Compliance
32
32
32
32
       
 ARTICLE VI EVENTS OF DEFAULT 32
 
Section 6.1
Section 6.2
Section 6.3
Events of Default
Remedies
Pledge of Special Deposit Account
  32
34
35
       
 ARTICLE VII MISCELLANEOUS 35
  Section 7.1
Section 7.2
Section 7.3
Section 7.4
Section 7.5
Section 7.6
Section 7.7
Section 7.8
Section 7.9
Section 7.10
Section 7.11
Section 7.12
Section 7.13
Section 7.14
Section 7.15
Section 7.16
Section 7.17
Section 7.18
Section 7.19
Section 7.20
Section 7.21
Section 7.22
Section 7.23
Taxes
Increased Costs
Right of Setoff; Other Collateral
Indemnity; Costs and Expenses
Non-Controlled Persons
Obligations Absolute
Liability of the Issuing Bank
Participants, Etc.
Survival of this Agreement
Amendments and Waivers
Waiver of Rights by the Banks
Severability
Governing Law; Submission to Jurisdiction
Notices
Survival of Certain Obligations
Taxes and Expenses
Pleadings
Counterparts
Waiver of Jury Trial
Register
Adjustments; Set-off
Patriot Act Notice
Restatement
  35
36
38
39
42
42
42
43
44
44
45
45
45
45
47
47
47
47
47
47
48
48
48
       
 ARTICLE VIII THE ADMINISTRATIVE AGENT 48
  Section 8.1
Section 8.2
Section 8.3
Section 8.4
Section 8.5
Section 8.6
Section 8.7
Appointment and Authorization of Administrative Agent
Administrative Agent and its Affiliates
Action by Administrative Agent
Consultation with Experts
Liability of Administrative Agent; Credit Decision
Indemnity
Resignation of Administrative Agent and Successor Administrative Agent
  48
49
49
49
49
50
50
       
 
Exhibit A
Exhibit B
Form of Extension of Letter of Credit
Participating Bank Commitment Percentages
       

 
ii

 

 
AMENDED AND RESTATED LETTER OF CREDIT AGREEMENT
 
 
This Agreement is entered into as of June 3, 2011 by and among ALLETE, Inc., a Minnesota corporation (as more fully defined below, the “ Company ”), Wells Fargo Bank, National Association, a national banking association ( “Wells Fargo” ), in its capacity as letter of credit issuer (in such capacity, the “Issuing Bank” ) and as administrative agent for the Participating Banks hereunder (in such capacity, the “ Administrative Agent ”), and the financial institutions from time to time party hereto (each a “ Participating Bank ”).
 
At the request of the Company, the Collier County Industrial Authority, a public body corporate and politic organized and existing under the laws of the State of Florida (the “Issuer” ) issued its Industrial Development Variable Rate Demand Refunding Revenue Bonds (ALLETE, Inc. Project), Series 2006 (the “Bonds” ) in the principal amount of $27,800,000 pursuant to an Indenture of Trust dated as of July 1, 2006 (as amended or supplemented in accordance with the terms hereof and thereof, the “Indenture” ) between the Issuer and U.S. Bank National Association, as trustee for the purchasers of the Bonds (the “Trustee” ).
 
The Company and the Issuer executed a Financing Agreement dated July 5, 2006 (as amended or supplemented in accordance with the terms hereof and thereof, the “Financing Agreement” ), under which the Issuer agreed to lend the proceeds of the Bonds to the Company.
 
Pursuant to a Letter of Credit Agreement dated July 5, 2006 among the Company, Wells Fargo, as Issuing Bank and Administrative Agent, and the Participating Banks, as defined therein (the “2006 Letter of Credit Agreement” ), the Issuing Bank issued its Irrevocable Letter of Credit No. NZS569069, dated July 5, 2006 (the “Letter of Credit” ), and the Company agreed to reimburse the Issuing Bank for any draws under the Letter of Credit.
 
The stated Expiration Date of the Letter of Credit is July 5, 2011. The Company has requested that the Issuing Bank extend the Letter of Credit by issuing its extension of the Letter of Credit in the form of Exhibit A (the “L/C Extension” ).
 
The Issuing Bank has agreed to extend the requested letter of credit, and the Participating Banks have agreed to participate in the risk of such letter of credit on the terms and subject to the conditions set forth herein.
 
ACCORDINGLY, in consideration of the mutual covenants contained herein and in related documents, the parties hereby agree as follows:
 
 
ARTICLE I
DEFINITIONS
 
Section 1.1     Definitions.  As used in this Agreement:
 
“2006 Letter of Credit Agreement” has the meaning specified in the preamble.
 
Administrative Agent ” has the meaning specified in the preamble to this Agreement.
 
 
 

 
 
Agreement ” means this Amended and Restated Letter of Credit Agreement, as amended or supplemented from time to time.
 
“Applicable Hedge Agreement” means any Hedge Agreement engaged in by a Person as part of its normal business operations with the purpose and effect of hedging and protecting such Person against fluctuations or adverse changes in the prices of electricity, gas, fuel or other commodities, interest rates or currency exchange rates, which Hedge Agreement is part of a risk management strategy and not for purposes of speculation and not intended primarily as a borrowing of funds.
 
Applicable Margin ” means (i) 0.850% per annum for any day Level I Status exists; (ii) 1.075% per annum for any day Level II Status exists; (iii) 1.300% per annum for any day Level III Status exists; (iv) 1.525% per annum for any day Level IV Status exists; (v) 1.750% per annum for any day Level V Status exists; and (vi) 1.500% per annum for any day Level VI Status exists.
 
“Authorizing Order” means any order of the MPUC or any other regulatory body having jurisdiction over the Company or any affiliate of the Company authorizing and/or restricting the indebtedness that may be created from time to time hereunder.
 
 “ Available Amount ” means, at any time, the amount available for drawing under the Letter of Credit, after giving effect to any payments thereunder, reductions thereof, and reinstatements thereof.
 
Banks ” means, collectively, the Issuing Bank, the Administrative Agent and the Participating Banks.
 
Base Rate ” means for any day the greatest of:
          (i)