ALE 9-30-2012 10-Q
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 September 30, 2012
  
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,
38,845,290 shares outstanding
as of September 30, 2012




INDEX
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
September 30, 2012 and December 31, 2011
 
 
 
 
 
 
 
 
Quarter and Nine Months Ended September 30, 2012 and 2011
 
 
 
 
 
 
 
 
Quarter and Nine Months Ended September 30, 2012 and 2011
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2012 and 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

ALLETE Third Quarter 2012 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 Clean Energy
ALLETE Clean Energy, Inc.
ALLETE Properties
ALLETE Properties, LLC, and its subsidiaries
ARS
Auction Rate Securities
ATC
American Transmission Company, LLC
Bison 1
Bison 1 Wind Facility
Bison 2
Bison 2 Wind Project
Bison 3
Bison 3 Wind Project
BNI Coal
BNI Coal, Ltd.
Boswell
Boswell Energy Center
CAIR
Clean Air Interstate Rule
CO2
Carbon Dioxide
Company
ALLETE, Inc., and its subsidiaries
CSAPR
Cross-State Air Pollution Rule
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
Item ___
Item ___ of this Form 10-Q
kV
Kilovolt(s)
Laskin
Laskin Energy Center
LIBOR
London Interbank Offered Rate
MACT
Maximum Achievable Control Technology
Manitoba Hydro
Manitoba Hydro-Electric Board
MATS
Mercury and Air Toxics Standards
Medicare Part D
Medicare Part D provision of The Patient Protection and Affordable Care Act of 2010
Mesabi Nugget
Mesabi Nugget Delaware, LLC
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

ALLETE Third Quarter 2012 Form 10-Q
3



Definitions (Continued)
 
Abbreviation or Acronym
Term
MPUC
Minnesota Public Utilities Commission
MW / MWh
Megawatt(s) / Megawatt-hour(s)
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
NO2
Nitrogen Dioxide
NOX
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
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
SIP
State Implementation Plan
SO2
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
U.S.
United States of America
USS Corporation
United States Steel Corporation
WDNR
Wisconsin Department of Natural Resources


ALLETE Third Quarter 2012 Form 10-Q
4



Forward-Looking Statements

Statements in this report that are not statements of historical facts are 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,” “likely,” “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 providing this cautionary statement to identify important factors that could cause our actual results to differ materially from those indicated in forward-looking statements made by or on behalf of ALLETE in this 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 that could cause our actual results to differ materially from those indicated in the forward-looking statements:

our ability to successfully implement our strategic objectives;
regulatory or legislative actions, including changes in governmental policies 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, capital structure, 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;
our industrial customers’ ability to execute potential expansion plans;
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, acts of terrorism and cyber attacks;
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.

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 26 of our 2011 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 Third Quarter 2012 Form 10-Q
5



PART I.  FINANCIAL INFORMATION
ITEM 1.  FINANCIAL STATEMENTS
ALLETE
CONSOLIDATED BALANCE SHEET
Millions – Unaudited
 
September 30,
2012
 
December 31,
2011
 
 
 
 
Assets
 
 
 
Current Assets
 
 
 
Cash and Cash Equivalents

$104.3

 

$101.1

Accounts Receivable (Less Allowance of $1.1 and $0.9)
73.2

 
79.7

Inventories
76.7

 
69.1

Prepayments and Other
23.8

 
27.1

Total Current Assets
278.0

 
277.0

Property, Plant and Equipment - Net
2,239.9

 
1,982.7

Regulatory Assets
334.6

 
345.9

Investment in ATC
105.5

 
98.9

Other Investments
139.7

 
132.3

Other Non-Current Assets
40.4

 
39.2

Total Assets

$3,138.1

 

$2,876.0

 
 
 
 
Liabilities and Equity
 
 
 
Liabilities
 
 
 
Current Liabilities
 
 
 
Accounts Payable

$57.4

 

$71.8

Accrued Taxes
22.5

 
26.4

Accrued Interest
14.2

 
12.8

Long-Term Debt Due Within One Year
67.3

 
5.4

Notes Payable
0.3

 
1.1

Other
53.1

 
45.6

Total Current Liabilities
214.8

 
163.1

Long-Term Debt
947.6

 
857.9

Deferred Income Taxes
400.0

 
373.6

Regulatory Liabilities
54.8

 
43.5

Defined Benefit Pension and Other Postretirement Benefit Plans
254.0

 
253.5

Other Non-Current Liabilities
109.4

 
105.1

Total Liabilities
1,980.6

 
1,796.7

 
 
 
 
Commitments, Guarantees and Contingencies (Note 13)

 

 
 
 
 
Equity
 
 
 
Common Stock Without Par Value, 80.0 Shares Authorized, 38.8 and 37.5 Shares Outstanding
759.4

 
705.6

Unearned ESOP Shares
(22.8
)
 
(29.0
)
Accumulated Other Comprehensive Loss
(26.7
)
 
(28.9
)
Retained Earnings
447.6

 
431.6

Total Equity
1,157.5

 
1,079.3

Total Liabilities and Equity

$3,138.1

 

$2,876.0

The accompanying notes are an integral part of these statements.

ALLETE Third Quarter 2012 Form 10-Q
6



ALLETE
CONSOLIDATED STATEMENT OF INCOME
Millions Except Per Share Amounts – Unaudited
 
Quarter Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012
2011
 
2012
2011
 
 
 
 
 
 
Operating Revenue

$248.8


$226.9

 

$705.2


$689.0

 
 
 
 
 
 
Operating Expenses
 
 
 
 
 
Fuel and Purchased Power
79.5

74.8

 
228.7

229.8

Operating and Maintenance
98.7

90.5

 
294.8

276.3

Depreciation
25.0

22.7

 
74.4

67.1

Total Operating Expenses
203.2

188.0

 
597.9

573.2

 
 
 
 
 
 
Operating Income
45.6

38.9

 
107.3

115.8

 
 
 
 
 
 
Other Income (Expense)
 
 
 
 
 
Interest Expense
(12.3
)
(10.9
)
 
(33.4
)
(32.6
)
Equity Earnings in ATC
4.9

4.7

 
14.3

13.7

Other
1.5

0.5

 
3.4

2.3

Total Other Expense
(5.9
)
(5.7
)
 
(15.7
)
(16.6
)
 
 
 
 
 
 
Income Before Non-Controlling Interest and Income Taxes
39.7

33.2

 
91.6

99.2

Income Tax Expense
10.3

12.7

 
23.4

24.7

Net Income
29.4

20.5

 
68.2

74.5

Less: Non-Controlling Interest in Subsidiaries


 

(0.2
)
Net Income Attributable to ALLETE

$29.4


$20.5

 

$68.2


$74.7

 
 
 
 
 
 
Average Shares of Common Stock
 
 
 
 
 
Basic
37.7

35.6

 
37.3

35.1

Diluted
37.8

35.7

 
37.3

35.2

 
 
 
 
 
 
Basic Earnings Per Share of Common Stock

$0.78


$0.57

 

$1.83


$2.13

Diluted Earnings Per Share of Common Stock

$0.78


$0.57

 

$1.83


$2.12

 
 
 
 
 
 
Dividends Per Share of Common Stock

$0.46


$0.445

 

$1.38


$1.335

The accompanying notes are an integral part of these statements.

ALLETE Third Quarter 2012 Form 10-Q
7



ALLETE
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Millions – Unaudited


 
Quarter Ended
 
Nine Months Ended
 
September 30,
 
September 30,
Comprehensive Income (Loss)
2012
 
2011
 
2012
 
2011
Millions
 
 
 
 
 
 
 
Net Income

$29.4

 

$20.5

 

$68.2

 

$74.5

Other Comprehensive Income (Loss)
 
 
 
 
 
 
 
Unrealized Gain (Loss) on Securities
 
 
 
 
 
 
 
Net of Income Taxes of $0.5, $(1.1), $0.7 and $(0.3)
0.5

 
(1.4
)
 
1.0

 
(0.3
)
Unrealized Loss on Derivatives
 
 
 
 


 


Net of Income Taxes of $(0.1), $(0.2), $(0.2) and $(0.2)

 
(0.3
)
 
(0.2
)
 
(0.3
)
Defined Benefit Pension and Other Postretirement Benefit Plans
 
 
 
 
 
 
 
 Net of Income Taxes of $0.2, $0.3, $0.9 and $0.8
0.4

 
0.3

 
1.4

 
1.1

Total Other Comprehensive Income (Loss)
0.9

 
(1.4
)
 
2.2

 
0.5

Total Comprehensive Income

$30.3

 

$19.1

 

$70.4

 

$75.0

Less: Non-Controlling Interest in Subsidiaries

 

 

 
(0.2
)
Comprehensive Income Attributable to ALLETE

$30.3

 

$19.1

 

$70.4

 

$75.2

The accompanying notes are an integral part of these statements.


ALLETE Third Quarter 2012 Form 10-Q
8



ALLETE
CONSOLIDATED STATEMENT OF CASH FLOWS
Millions – Unaudited
 
Nine Months Ended
 
September 30,
 
2012
 
2011
 
 
 
 
Operating Activities
 
 
 
Net Income

$68.2

 

$74.5

Allowance for Funds Used During Construction
(3.4
)
 
(1.7
)
Income from Equity Investments, Net of Dividends
(2.7
)
 
(1.9
)
Gain on Sale of Assets

 
(0.9
)
Depreciation Expense
74.4

 
67.1

Amortization of Debt Issuance Costs
0.7

 
0.7

Deferred Income Tax Expense
23.4

 
24.6

Share-Based Compensation Expense
1.7

 
1.7

ESOP Compensation Expense
5.5

 
5.3

Defined Benefit Pension and Postretirement Benefit Expense
20.6

 
18.5

Bad Debt Expense
0.9

 
1.0

Changes in Operating Assets and Liabilities
 
 
 
Accounts Receivable
5.6

 
22.8

Inventories
(7.6
)
 
(9.1
)
Prepayments and Other
3.3

 
5.8

Accounts Payable
(1.3
)
 
(16.5
)
Other Current Liabilities
7.4

 
(4.4
)
Cash Contributions to Defined Benefit Pension and Other Postretirement Benefit Plans

 
(17.5
)
Changes in Regulatory and Other Non-Current Assets
(5.0
)
 
0.6

Changes in Regulatory and Other Non-Current Liabilities
3.8

 
14.5

Cash from Operating Activities
195.5

 
185.1

 
 
 
 
Investing Activities
 
 
 
Proceeds from Sale of Available-for-sale Securities
1.2

 
7.4

Payments for Purchase of Available-for-sale Securities
(1.5
)
 
(1.6
)
Investment in ATC
(3.9
)
 
(2.0
)
Changes to Other Investments
(5.5
)
 
(4.1
)
Additions to Property, Plant and Equipment
(331.9
)
 
(156.8
)
Proceeds from Sale of Assets

 
2.2

Cash for Investing Activities
(341.6
)
 
(154.9
)
 
 
 
 
Financing Activities
 
 
 
Proceeds from Issuance of Common Stock
52.1

 
30.1

Proceeds from Issuance of Long-Term Debt
175.6

 
75.0

Proceeds (Payments) from (for) Notes Payable
(0.8
)
 
4.6

Payments for Long-Term Debt
(24.1
)
 
(2.8
)
Debt Issuance Costs
(1.3
)
 

Dividends on Common Stock
(52.2
)
 
(46.9
)
Cash from Financing Activities
149.3

 
60.0

 
 
 
 
Change in Cash and Cash Equivalents
3.2

 
90.2

Cash and Cash Equivalents at Beginning of Period
101.1

 
44.9

 
 
 
 
Cash and Cash Equivalents at End of Period

$104.3

 

$135.1

The accompanying notes are an integral part of these statements.

ALLETE Third Quarter 2012 Form 10-Q
9



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, 2011, 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 period ended September 30, 2012, are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2012. For further information, refer to the consolidated financial statements and notes included in our 2011 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.
Inventories
September 30,
2012

 
December 31,
2011

Millions
 
 
 
Fuel

$31.3

 

$28.6

Materials and Supplies
45.4

 
40.5

Total Inventories

$76.7

 

$69.1


Prepayments and Other Current Assets
September 30,
2012

 
December 31,
2011

Millions
 
 
 
Deferred Fuel Adjustment Clause

$18.2

 

$17.5

Other
5.6

 
9.6

Total Prepayments and Other Current Assets

$23.8

 

$27.1


Other Current Liabilities
September 30,
2012

 
December 31,
2011

Millions
 
 
 
Customer Deposits

$28.8

 

$16.3

Other
24.3

 
29.3

Total Other Current Liabilities

$53.1

 

$45.6


Other Non-Current Liabilities
September 30,
2012

 
December 31,
2011

Millions
 
 
 
Asset Retirement Obligation

$61.7

 

$57.0

Other
47.7

 
48.1

Total Other Non-Current Liabilities

$109.4

 

$105.1


Supplemental Statement of Cash Flows Information.

For the Nine Months Ended September 30,
2012

 
2011

Millions
 
 
 
Cash Paid During the Period for Interest – Net of Amounts Capitalized

$32.3

 

$32.4

Cash Paid (Received) During the Period for Income Taxes

$0.2

 
$(11.1)
Noncash Investing and Financing Activities
 
 
 
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment
$(13.1)
 
$(14.8)
AFUDC – Equity

$3.4

 

$1.7


ALLETE Third Quarter 2012 Form 10-Q
10


NOTE 1.  OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Accounts Receivable. Accounts receivable are reported on the Consolidated Balance Sheet net of an allowance for doubtful accounts. The allowance is based on our evaluation of the receivable portfolio under current conditions, overall portfolio quality, review of specific problems and such other factors that, in our judgment, deserve recognition in estimating losses. In the third quarter of 2011, one of Minnesota Power’s Large Power Customers, NewPage Corporation (NewPage), filed for Chapter 11 bankruptcy protection. Minnesota Power had a pre-bankruptcy petition receivable of $3.2 million as of September 30, 2012. In September 2012, NewPage submitted a motion to the bankruptcy court to approve amended and restated service agreements and payment of the pre-petition amount, which was approved on October 16, 2012. The agreement is now pending approval by the MPUC, at which time the pre-petition amount will be paid.

Based on our assessment of the facts and circumstances existing as of September 30, 2012, we have determined that it is not probable that the pre-petition receivable has been impaired. This customer’s operations have continued without interruption and we continue to provide electric and steam service to this customer. We have received payment of scheduled post-petition receivable balances and we expect continued payment of all other post-petition receivables.

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 process used. No retrospective application of this guidance is required. If we utilize Level 3 fair value measurements in the future, this guidance would significantly increase our disclosures in this area. This guidance was effective beginning with the quarter ended March 31, 2012, and did not have a material impact on our consolidated financial position, results of operations or cash flows.

Statement of Comprehensive Income. In June 2011, the FASB issued an accounting standards update on the presentation of comprehensive income. This guidance was effective beginning with the quarter ended March 31, 2012, and modified our presentation of other comprehensive income, moving it from the footnotes to the face of the financial statements in a separate Consolidated Statement of Comprehensive Income immediately following the Consolidated Statement of Income. The components of net income and other comprehensive income are unchanged and earnings per share continues to be based on net income.



ALLETE Third Quarter 2012 Form 10-Q
11


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, ALLETE Properties, our Florida real estate investment, and ALLETE Clean Energy, aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. The Investments and Other 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.

 
Consolidated
 
Regulated Operations
 
Investments and Other
Millions
 
 
 
 
 
For the Quarter Ended September 30, 2012
 
 
 
 
 
Operating Revenue

$248.8

 

$226.4

 

$22.4

Fuel and Purchased Power Expense
79.5

 
79.5

 

Operating and Maintenance Expense
98.7

 
76.4

 
22.3

Depreciation Expense
25.0

 
23.5

 
1.5

Operating Income (Loss)
45.6

 
47.0

 
(1.4
)
Interest Expense
(12.3
)
 
(10.2
)
 
(2.1
)
Equity Earnings in ATC
4.9

 
4.9

 

Other Income
1.5

 
1.5

 

Income (Loss) Before Non-Controlling Interest and Income Taxes
39.7

 
43.2

 
(3.5
)
Income Tax Expense (Benefit)
10.3

 
13.9

 
(3.6
)
Net Income
29.4

 
29.3

 
0.1

Less: Non-Controlling Interest in Subsidiaries

 

 

Net Income Attributable to ALLETE

$29.4

 

$29.3

 

$0.1


 
Consolidated
 
Regulated Operations
 
Investments and Other
Millions
 
 
 
 
 
For the Quarter Ended September 30, 2011
 
 
 
 
 
Operating Revenue

$226.9

 

$207.4

 

$19.5

Fuel and Purchased Power Expense
74.8

 
74.8

 

Operating and Maintenance Expense
90.5

 
70.4

 
20.1

Depreciation Expense
22.7

 
21.4

 
1.3

Operating Income (Loss)
38.9

 
40.8

 
(1.9
)
Interest Expense
(10.9
)
 
(9.2
)
 
(1.7
)
Equity Earnings in ATC
4.7

 
4.7

 

Other Income (Expense)
0.5

 
0.6

 
(0.1
)
Income (Loss) Before Non-Controlling Interest and Income Taxes
33.2

 
36.9

 
(3.7
)
Income Tax Expense (Benefit)
12.7

 
13.1

 
(0.4
)
Net Income (Loss)
20.5

 
23.8

 
(3.3
)
Less: Non-Controlling Interest in Subsidiaries

 

 

Net Income (Loss) Attributable to ALLETE

$20.5

 

$23.8

 
$(3.3)


ALLETE Third Quarter 2012 Form 10-Q
12


NOTE 2. BUSINESS SEGMENTS (Continued)

 
Consolidated
 
Regulated Operations
 
Investments and Other
Millions
 
 
 
 
 
For the Nine Months Ended September 30, 2012
 
 
 
 
 
Operating Revenue

$705.2

 

$642.0

 

$63.2

Fuel and Purchased Power Expense
228.7

 
228.7

 

Operating and Maintenance Expense
294.8

 
230.6

 
64.2

Depreciation Expense
74.4

 
70.1

 
4.3

Operating Income (Loss)
107.3

 
112.6

 
(5.3
)
Interest Expense
(33.4
)
 
(29.7
)
 
(3.7
)
Equity Earnings in ATC
14.3

 
14.3

 

Other Income (Expense)
3.4

 
3.5

 
(0.1
)
Income (Loss) Before Non-Controlling Interest and Income Taxes
91.6

 
100.7

 
(9.1
)
Income Tax Expense (Benefit)
23.4

 
32.6

 
(9.2
)
Net Income
68.2

 
68.1

 
0.1

Less: Non-Controlling Interest in Subsidiaries

 

 

Net Income Attributable to ALLETE

$68.2

 

$68.1

 

$0.1

 
 
 
 
 
 
As of September 30, 2012
 
 
 
 
 
Total Assets

$3,138.1

 

$2,830.9

 

$307.2

Property, Plant and Equipment – Net

$2,239.9

 

$2,180.8

 

$59.1

Accumulated Depreciation

$1,146.7

 

$1,091.5

 

$55.2

Capital Additions

$318.3

 

$312.6

 

$5.7


 
Consolidated
 
Regulated Operations
 
Investments and Other
Millions
 
 
 
 
 
For the Nine Months Ended September 30, 2011
 
 
 
 
 
Operating Revenue

$689.0

 

$632.2

 

$56.8

Fuel and Purchased Power Expense
229.8

 
229.8

 

Operating and Maintenance Expense
276.3

 
218.8

 
57.5

Depreciation Expense
67.1

 
63.5

 
3.6

Operating Income (Loss)
115.8

 
120.1

 
(4.3
)
Interest Expense
(32.6
)
 
(26.9
)
 
(5.7
)
Equity Earnings in ATC
13.7

 
13.7

 

Other Income
2.3

 
1.8

 
0.5

Income (Loss) Before Non-Controlling Interest and Income Taxes
99.2

 
108.7

 
(9.5
)
Income Tax Expense (Benefit)
24.7

 
28.2

 
(3.5
)
Net Income (Loss)
74.5

 
80.5

 
(6.0
)
Less: Non-Controlling Interest in Subsidiaries
(0.2
)
 

 
(0.2
)
Net Income (Loss) Attributable to ALLETE

$74.7

 

$80.5

 
$(5.8)
 
 
 
 
 
 
As of September 30, 2011
 

 
 

 
 

Total Assets

$2,754.4

 

$2,436.0

 

$318.4

Property, Plant and Equipment – Net

$1,902.1

 

$1,847.1

 

$55.0

Accumulated Depreciation

$1,079.0

 

$1,028.6

 

$50.4

Capital Additions

$143.5

 

$128.4

 

$15.1


ALLETE Third Quarter 2012 Form 10-Q
13



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 available-for-sale in Minnesota.

Investments
September 30,
2012

 
December 31,
2011

Millions
 
 
 
ALLETE Properties

$91.1

 

$91.3

Available-for-sale Securities
27.9

 
24.7

Other
20.7

 
16.3

Total Investments

$139.7

 

$132.3


ALLETE Properties
September 30,
2012

 
December 31,
2011

Millions
 
 
 
Land Inventory Beginning Balance (January 1, 2012 and 2011, respectively)

$86.0

 

$86.0

Deeds to Collateralized Property
0.5

 
1.8

Land Impairment

 
(1.7
)
Capitalized Improvements and Other
0.1

 
0.2

Cost of Real Estate Sold
(0.2
)
 
(0.3
)
Land Inventory Ending Balance
86.4

 
86.0

Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)
1.4

 
2.0

Other
3.3

 
3.3

Total Real Estate Assets

$91.1

 

$91.3


Land Inventory. Land inventory is accounted for as held for use and is recorded at cost, unless the carrying value is determined not to be recoverable in accordance with the accounting standards for property, plant and equipment, in which case the land inventory is written down to fair value. Land values are reviewed for impairment on a quarterly basis and no impairments were recorded for the nine months ended September 30, 2012 ($1.7 million as of December 31, 2011). In the fourth quarter of 2011, an impairment analysis of estimated future undiscounted cash flows was conducted and indicated that the cash flows were not adequate to recover the carrying basis of certain properties not strategic to our three major development projects. Consequently, we reduced the cost basis to estimated fair value resulting in a pretax impairment charge of $1.7 million. Fair value was determined based on property tax assessed values, discounted cash flow analysis, or a combination thereof.

Long-Term Finance Receivables. As of September 30, 2012, long-term finance receivables were $1.4 million net of allowance ($2.0 million net of allowance as of December 31, 2011). Long-term finance receivables are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts. As of September 30, 2012, we had an allowance for doubtful accounts of $0.6 million ($0.6 million as of December 31, 2011).



ALLETE Third Quarter 2012 Form 10-Q
14


NOTE 4. DERIVATIVES

During the third quarter of 2011, we entered into a variable-to-fixed interest rate swap (Swap), designated as a cash flow hedge, in order to manage the interest rate risk associated with a $75.0 million Term Loan. The Term Loan has a variable interest rate equal to the one-month LIBOR plus 1.00 percent, has a maturity of August 25, 2014, and represents approximately 8 percent of the Company’s outstanding long-term debt as of September 30, 2012. (See Note 8. Short-Term and Long-Term Debt.) The Swap agreement has a notional amount equal to the underlying debt principal and matures on August 25, 2014. The Swap agreement involves the receipt of variable rate amounts in exchange for fixed rate interest payments over the life of the agreement without an exchange of the underlying notional amount. The variable rate of the Swap is equal to the one-month LIBOR and the fixed rate is equal to 0.825 percent. Cash flows from the interest rate swap are expected to be highly effective in offsetting the variable interest expense of the debt attributable to fluctuations in the one-month LIBOR interest rate over the life of the Swap. If it is determined that a derivative is not or has ceased to be effective as a hedge, the Company prospectively discontinues hedge accounting with respect to that derivative. The shortcut method is used to assess hedge effectiveness. At inception, all shortcut method requirements were satisfied; thus changes in the value of the Swap are deemed 100 percent effective. As a result, there was no ineffectiveness recorded for the quarter and nine months ended September 30, 2012. The mark-to-market fluctuation on the cash flow hedge was recorded in accumulated other comprehensive income on the Consolidated Balance Sheet. As of September 30, 2012, the fair value of the Swap was a $0.8 million liability (a $0.4 million liability as of December 31, 2011) and is included in other non-current liabilities on the Consolidated Balance Sheet. Cash flows from derivative activities are presented in the same category as the item being hedged on the Consolidated Statement of Cash Flows. Amounts recorded in other comprehensive income related to cash flow hedges will be recognized in earnings when the hedged transactions occur or when it is probable that the hedged transactions will not occur. Gains or losses on interest rate hedging transactions are reflected as a component of interest expense on the Consolidated Statement of Income.


NOTE 5. FAIR VALUE

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. 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 9. Fair Value to the consolidated financial statements in our 2011 Form 10-K.

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 September 30, 2012 and December 31, 2011. 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. The estimated fair value of cash and cash equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore are excluded from the recurring fair value measures in the table below.

ALLETE Third Quarter 2012 Form 10-Q
15


NOTE 5. FAIR VALUE (Continued)

 
Fair Value as of September 30, 2012
Recurring Fair Value Measures
Level 1
 
Level 2
 
Level 3
 
Total
Millions
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Investments
 
 
 
 
 
 
 
Available-for-sale – Equity Securities

$19.1

 

 

 

$19.1

Available-for-sale – Corporate Debt Securities

 

$8.8

 

 
8.8

Cash Equivalents
16.6

 

 

 
16.6

Total Fair Value of Assets

$35.7

 

$8.8

 

 

$44.5

 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
Deferred Compensation

 

$14.8

 

 

$14.8

Derivatives – Interest Rate Swap

 
0.8

 

 
0.8

Total Fair Value of Liabilities

 

$15.6

 

 

$15.6

 
 
 
 
 
 
 
 
Total Net Fair Value of Assets (Liabilities)

$35.7

 
$(6.8)
 

 

$28.9


 
Fair Value as of December 31, 2011
Recurring Fair Value Measures
Level 1
 
Level 2
 
Level 3
 
Total
Millions
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Investments
 
 
 
 
 
 
 
Available-for-sale – Equity Securities

$17.6

 

 

 

$17.6

Available-for-sale – Corporate Debt Securities

 

$8.2

 

 
8.2

Cash Equivalents
11.4

 

 

 
11.4

Total Fair Value of Assets

$29.0

 

$8.2

 

 

$37.2

 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
Deferred Compensation

 

$12.8

 

 

$12.8

Derivatives – Interest Rate Swap

 
0.4

 

 
0.4

Total Fair Value of Liabilities

 

$13.2

 

 

$13.2

 
 
 
 
 
 
 
 
Total Net Fair Value of Assets (Liabilities)

$29.0

 
$(5.0)
 

 

$24.0


Recurring Fair Value Measures
Activity in Level 3
 
Debt Securities
Issued by States
of the United
States (ARS)
Millions
 
 
 
 
Balance as of December 31, 2011 and 2010, respectively
 

 

$6.7

Redeemed During the Period (a)
 

 
(6.7
)
Balance as of September 30, 2012 and 2011, respectively
 

 

(a)
The remaining ARS were redeemed at carrying value on January 5, 2011.

The Company’s policy is to recognize transfers in and transfers out of a given hierarchy level as of the actual date of the event or of the change in circumstances that caused the transfer. For the nine months ended September 30, 2012 and 2011, there were no transfers in or out of Levels 1, 2 or 3.

ALLETE Third Quarter 2012 Form 10-Q
16


NOTE 5. FAIR VALUE (Continued)

Fair Value of Financial Instruments. With the exception of the item listed below, the estimated fair value of all financial instruments approximates the carrying amount. The fair value for the item listed below was based on quoted market prices for the same or similar instruments (Level 2).

Financial Instruments
Carrying Amount
 
Fair Value
Millions
 
 
 
Long-Term Debt, Including Current Portion
 
 
 
September 30, 2012
$1,014.9
 
$1,144.9
December 31, 2011
$863.3
 
$966.4


NOTE 6.  REGULATORY MATTERS

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

2010 Minnesota Rate Case. Minnesota Power’s current retail rates are based on a 2011 MPUC retail rate order, effective June 1, 2011, that allowed for a 10.38 percent return on common equity and a 54.29 percent equity ratio.

In February 2011, Minnesota Power appealed the MPUC’s interim rate decision in the Company’s 2010 rate case with the Minnesota Court of Appeals. The Company appealed 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. In December 2011, the Minnesota Court of Appeals concluded that the MPUC did not err in finding exigent circumstances and properly exercised its discretion in setting interim rates. On January 4, 2012, the Company filed a petition for review at the Minnesota Supreme Court (Court). On February 14, 2012, the Court granted the petition for review and oral arguments were held before the Court on October 9, 2012. A decision is expected in early 2013; however, we cannot predict the outcome 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. Minnesota Power’s formula-based contract with the City of Nashwauk is effective April 1, 2013 through June 30, 2024, and the restated formula-based contracts with the remaining 15 Minnesota municipal customers and SWL&P are effective through June 30, 2019. The rates included in these contracts are calculated using a cost-based formula methodology that is set each July 1, using estimated costs and a rate of return that is equal to our authorized rate of return for Minnesota retail customers (currently 10.38 percent). The formula-based rate methodology also provides for a yearly true-up calculation for actual costs incurred. The contract terms include a termination clause requiring a three-year notice to terminate. Under the City of Nashwauk contract, no termination notice may be given prior to July 1, 2021. Under the restated contracts, no termination notices may be given prior to June 30, 2016. A two-year cancellation notice is required for the one private non-affiliated utility in Wisconsin, and on December 31, 2011, this customer submitted a cancellation notice with termination effective on December 31, 2013. The 17 MW of average monthly demand provided to this customer is expected to be used to supply energy to prospective additional load customers beginning in 2014.

2012 Wisconsin Rate Case. SWL&P’s current retail rates are based on a 2010 PSCW retail rate order, effective January 1, 2011, that allowed for a 10.9 percent return on common equity. In May 2012, SWL&P filed a rate increase request with the PSCW seeking an average overall increase of 2.5 percent for retail customers (a 1.2 percent increase in electric rates, a 0.7 percent increase in natural gas rates, and a 13.4 percent increase in water rates). The rate filing seeks an overall return on equity of 10.9 percent, and a capital structure consisting of approximately 55 percent equity and 45 percent debt. On an annualized basis, the requested rate increase would generate approximately $1.8 million in additional revenue. Evidentiary and public hearings were held on September 17, 2012. The Company anticipates new rates will take effect during the first quarter of 2013. We cannot predict the level of rates that may be approved by the PSCW.


ALLETE Third Quarter 2012 Form 10-Q
17


NOTE 6. REGULATORY MATTERS (Continued)

ALLETE Clean Energy. In August 2011, the Company filed with the MPUC for approval of certain affiliated interest agreements between ALLETE and ALLETE Clean Energy. These agreements relate to various relationships between the parties, including the accounting for certain shared services, as well as the transfer of transmission and wind development rights in North Dakota to ALLETE Clean Energy. These transmission and wind development rights are separate and distinct from those needed by Minnesota Power to meet Minnesota’s renewable energy standard requirements. On July 23, 2012, the MPUC issued an order approving certain administrative items related to accounting for shared services as well as the approval of the transfer of meteorological towers, while deferring decisions related to transmission and wind development rights pending the MPUC’s further review of Minnesota Power’s future retail electric service needs.

The Patient Protection and Affordable Care Act of 2010 (PPACA). In March 2010, the 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 which resulted in a non-recurring charge to net income of $4.0 million in 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 the 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 and a related regulatory asset of $5.0 million in the second quarter of 2011.

Pension. In December 2011, the Company filed a petition with the MPUC requesting a mechanism to recover the cost of capital associated with the prepaid pension asset (or liability) created by the required contributions under the pension plan in excess of (or less than) annual pension expense. The Company further requested a mechanism to defer pension expenses in excess of (or less than) those currently being recovered in base rates. If our petition is successful, the impact would be deferred in a regulatory asset (or liability) for recovery (or refund) in the Company’s next general rate case. We cannot predict the outcome at this time.

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

Regulatory Assets and Liabilities
September 30,
2012

 
December 31,
2011

Millions
 
 
 
Current Regulatory Assets (a)
 
 
 
Deferred Fuel

$18.2

 

$17.5

Total Current Regulatory Assets
18.2

 
17.5

Non-Current Regulatory Assets
 
 
 
Future Benefit Obligations Under
 
 
 
Defined Benefit Pension and Other Postretirement Benefit Plans
276.6

 
292.8

Income Taxes
28.2

 
28.6

Asset Retirement Obligation
11.5

 
9.8

Cost Recovery Riders (b)
11.4

 
0.7

PPACA Income Tax Deferral
5.0

 
5.0

Other (c)
1.9

 
9.0

Total Non-Current Regulatory Assets
334.6

 
345.9

 
 
 
 
Total Regulatory Assets

$352.8

 

$363.4

 
 
 
 
Non-Current Regulatory Liabilities
 
 
 
Income Taxes

$19.8

 

$21.9

Plant Removal Obligations
17.5

 
15.0

Wholesale and Retail Contra AFUDC
11.1

 
1.5

Other
6.4

 
5.1

Total Non-Current Regulatory Liabilities

$54.8

 

$43.5

(a)
Current regulatory assets are included in prepayments and other on the Consolidated Balance Sheet.
(b)
The increase in cost recovery rider regulatory assets is primarily due to higher capital expenditures related to our Bison projects.
(c)
The decrease in Other is primarily due to the Conservation Improvement Program incentive recorded in 2011 and collected in 2012.

ALLETE Third Quarter 2012 Form 10-Q
18


NOTE 7.  INVESTMENT IN ATC

Our wholly-owned subsidiary, Rainy River Energy, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. ATC 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. As of September 30, 2012, our equity investment in ATC was $105.5 million ($98.9 million at December 31, 2011). In the first nine months of 2012, we invested $3.9 million in ATC, and on October 30, 2012, we invested an additional $0.8 million. We do not expect to make any additional investments in 2012.

ALLETE’s Investment in ATC
 
Millions
 
Equity Investment Balance as of December 31, 2011

$98.9

Cash Investments
3.9

Equity in ATC Earnings
14.3

Distributed ATC Earnings
(11.6
)
Equity Investment Balance as of September 30, 2012

$105.5


ATC’s summarized financial data for the quarters and nine months ended September 30, 2012 and 2011, is as follows:
 
Quarter Ended
 
Nine Months Ended
ATC Summarized Financial Data
September 30,
 
September 30,
Income Statement Data
2012
 
2011
 
2012
 
2011
Millions
 
 
 
 
 
 
 
Revenue
$150.3
 
$142.8
 

$450.1

 

$420.6

Operating Expense
68.8
 
66.4
 
210.1

 
192.5

Other Expense
21.0
 
19.7
 
62.1

 
61.6

Net Income

$60.5

 
$56.7
 

$177.9

 

$166.5

 
 
 
 
 
 
 
 
ALLETE’s Equity in Net Income
$4.9
 
$4.7
 

$14.3

 

$13.7



NOTE 8.  SHORT-TERM AND LONG-TERM DEBT

Short-Term Debt. As of September 30, 2012, total short-term debt outstanding was $67.6 million ($6.5 million as of December 31, 2011) and consisted of long-term debt due within one year and notes payable. Short-term debt increased from year end primarily due to $60 million of long-term debt maturing in April 2013, which is classified as short-term as of September 30, 2012.

Long-Term Debt. As of September 30, 2012, total long-term debt outstanding was $947.6 million ($857.9 million as of December 31, 2011).

On July 2, 2012, we issued $160.0 million of the Company’s First Mortgage Bonds (Bonds) in the private placement market in two series as follows:

Issue Date
Maturity Date
Principal Amount
Interest Rate
July 2, 2012
July 15, 2026
$75 Million
3.20%
July 2, 2012
July 15, 2042
$85 Million
4.08%


ALLETE Third Quarter 2012 Form 10-Q
19


NOTE 8.  SHORT-TERM AND LONG-TERM DEBT (Continued)

We have the option to prepay all or a portion of the 3.20 percent Bonds at our discretion at any time prior to January 15, 2026, subject to a make-whole provision, and at any time on or after January 15, 2026, at par, including, in each case, accrued and unpaid interest. We also have the option to prepay all or a portion of the 4.08 percent Bonds at our discretion at any time prior to January 15, 2042, subject to a make-whole provision, and at any time on or after January 15, 2042, at par, including, in each case, accrued and unpaid interest. The Bonds are subject to the additional terms and conditions of our utility mortgage. In July 2012, we used a portion of the proceeds from the sale of the Bonds to redeem $6.0 million of our 6.50 percent Industrial Development Revenue Bonds and to repay $14.0 million in outstanding borrowings on our $150.0 million line of credit. The remaining proceeds will be used to fund utility capital expenditures and/or for general corporate purposes. The Bonds were sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to certain institutional accredited investors.

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 financial 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 September 30, 2012, our ratio was approximately 0.46 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 September 30, 2012, ALLETE was in compliance with its financial covenants.


NOTE 9.  OTHER INCOME (EXPENSE)

 
 
Quarter Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2012
 
2011
 
2012
 
2011
Millions
 
 
 
 
 
 
 
 
AFUDC – Equity
 

$1.5

 

$0.6

 

$3.4

 

$1.7

Investment and Other Income (Expense)
 

 
(0.1
)
 

 
0.6

Total Other Income
 

$1.5

 

$0.5

 

$3.4

 

$2.3




ALLETE Third Quarter 2012 Form 10-Q
20




NOTE 10.  INCOME TAX EXPENSE
 
 
Quarter Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2012
 
2011
 
2012
 
2011
Millions
 
 
 
 
 
 
 
 
Current Tax Expense
 
 
 
 
 
 
 
 
Federal (a)
 

 

 

 

State (a)
 

 
$(0.1)
 

 

$0.1

Total Current Tax Expense (Benefit)
 

 
(0.1
)
 

 
0.1

Deferred Tax Expense (Benefit)
 
 
 
 
 
 
 
 
Federal (b)
 

$10.5

 
8.5

 

$24.2

 
19.3

State (b)
 
(0.7
)
 
4.5

 
(1.9
)
 
6.0

Change in Valuation Allowance (c)
 
0.7

 

 
1.7

 

Investment Tax Credit Amortization
 
(0.2
)
 
(0.2
)
 
(0.6
)
 
(0.7
)
Total Deferred Tax Expense
 
10.3

 
12.8

 
23.4

 
24.6

Total Income Tax Expense
 

$10.3

 

$12.7

 

$23.4

 

$24.7

(a)
For the quarter and nine months ended September 30, 2012, the federal and state current tax expense of zero and zero, respectively, ($(0.1) million and $0.1 million for the quarter and nine months ended September 30, 2011) is due to a net operating loss (NOL) which resulted primarily from the bonus depreciation provision of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010. The 2012 and 2011 federal and state NOLs will be carried forward to offset future taxable income.
(b)
For the quarter and nine months ended September 30, 2012, the state deferred tax benefit of $0.7 million and $1.9 million, respectively, is due to state renewable tax credits earned which will be carried forward to offset future state tax expense. The nine months ended September 30, 2011, included a second quarter income tax benefit of $2.9 million 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 a first quarter benefit for the reversal 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.
(c)
For the quarter and nine months ended September 30, 2012, the valuation allowance is due to state renewable tax credits earned in 2012 which are not expected to be utilized within their allowable tax carryforward period.

For the nine months ended September 30, 2012, the effective tax rate was 25.5 percent (24.9 percent for the nine months ended September 30, 2011; the effective tax rate for the nine months ended September 30, 2011, was lowered by 6.2 percentage points 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, and by 2.9 percentage points 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 increase in the effective tax rate from the effective tax rate for the nine months ended September 30, 2011, was primarily due to the 2011 non-recurring items above, partially offset by increased renewable tax credits in 2012. The effective tax rate deviated from the statutory rate of approximately 41 percent primarily due to deductions for AFUDC – Equity, investment tax credits, renewable tax credits and depletion, and in 2011, for the non-recurring items discussed above.
 
Uncertain Tax Positions. As of September 30, 2012, we had gross unrecognized tax benefits of $2.7 million ($11.4 million as of December 31, 2011). The $8.7 million decrease in the unrecognized tax benefits balance for the nine months ended September 30, 2012, was primarily due to the resolution of a federal audit matter for prior years’ activity. Of the total gross unrecognized tax benefits, $0.5 million represents the amount of unrecognized tax benefits included in the Consolidated Balance Sheet, that, if recognized, would favorably impact the effective income tax rate.

ALLETE’s IRS exam for tax years 2005 through 2009 is currently under review at the IRS appeals office. If the IRS appeals process is completed during the next twelve months, substantially all of the unrecognized tax benefits as of September 30, 2012, could be reversed. The unrecognized tax benefits are primarily due to tax positions which are timing in nature and therefore would have an immaterial impact on our effective tax rate if recognized.



ALLETE Third Quarter 2012 Form 10-Q
21


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 quarters and nine months ended September 30, 2012 and 2011, 0.2 million and 0.4 million options, respectively, 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.

 
 
 
2012
 
 
 
 
 
2011
 
 
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 September 30,
 
 
 
 
 
 
 
 
 
 
 
Net Income Attributable to ALLETE

$29.4

 
 
 

$29.4

 

$20.5

 
 
 

$20.5

Average Common Shares
37.7

 
0.1

 
37.8

 
35.6

 
0.1

 
35.7

Earnings Per Share

$0.78

 
 
 

$0.78

 

$0.57

 
 
 

$0.57

For the Nine Months Ended September 30,
 

 
 
 
 

 
 
 
 
 
 
Net Income Attributable to ALLETE

$68.2

 
 
 

$68.2

 

$74.7

 
 
 

$74.7

Average Common Shares
37.3

 

 
37.3

 
35.1

 
0.1

 
35.2

Earnings Per Share

$1.83

 
 
 

$1.83

 

$2.13

 
 
 

$2.12



NOTE 12.  PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

 
Pension
 
Other
Postretirement
Components of Net Periodic Benefit Expense
2012
 
2011
 
2012
 
2011
Millions
 
 
 
 
 
 
 
For the Quarter Ended September 30,
 
 
 
 
 
 
 
Service Cost

$2.3

 

$1.9

 

$1.0

 

$1.0

Interest Cost
6.6

 
6.8

 
2.4

 
2.7

Expected Return on Plan Assets
(8.9
)
 
(8.7
)
 
(2.5
)
 
(2.4
)
Amortization of Prior Service Costs

 
0.1

 
(0.4
)
 
(0.4
)
Amortization of Net Loss
4.4

 
3.1

 
1.9

 
2.1

Net Periodic Benefit Expense

$4.4

 

$3.2

 

$2.4

 

$3.0

 
 
 
 
 
 
 
 
For the Nine Months Ended September 30,
 
 
 
 
 
 
 
Service Cost

$6.9

 

$5.7

 

$3.1

 

$2.9

Interest Cost
19.8

 
20.5

 
7.1

 
8.1

Expected Return on Plan Assets
(26.6
)
 
(26.0
)
 
(7.5
)
 
(7.3
)
Amortization of Prior Service Costs
0.2

 
0.3

 
(1.3
)
 
(1.3
)
Amortization of Net Loss
13.1

 
9.1

 
5.7

 
6.4

Amortization of Transition Obligation

 

 
0.1

 
0.1

Net Periodic Benefit Expense

$13.4

 

$9.6

 

$7.2

 

$8.9


Employer Contributions. For the nine months ended September 30, 2012, no contributions were made to our defined benefit pension plan ($6.6 million for the nine months ended September 30, 2011). For the nine months ended September 30, 2012, no contributions were made to our other postretirement benefit plan ($10.9 million for the nine months ended September 30, 2011). We do not expect to make any contributions to our defined benefit pension plan in 2012, and we expect to contribute $8.7 million to our other postretirement benefit plan in 2012. In July 2012, Congress passed legislation which included a pension funding stabilization provision. The provision, which is designed to stabilize the discount rate used to determine funding requirements from the effects of interest rate volatility, will not have a material impact on our contributions in 2012.

Accounting and disclosure requirements for the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) provide 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 for the federal subsidy under the Act. For the nine months ended September 30, 2012, we received $0.3 million in prescription drug reimbursements.

ALLETE Third Quarter 2012 Form 10-Q
22




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 PPAs, 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 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 reserve requirements. Square Butte, a North Dakota cooperative corporation, owns a 455 MW coal-fired generating unit (Unit) near Center, North Dakota. The Unit is adjacent to a generating unit owned by Minnkota Power, a North Dakota cooperative corporation whose Class A members are also members of Square Butte. Minnkota Power serves as the operator of the Unit and also purchases power from Square Butte.

Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on Minnesota Power’s entitlement to Unit output. Our output entitlement under the Agreement is 50 percent for the remainder of the contract, 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. As of September 30, 2012, Square Butte had total debt outstanding of $417.4 million. Annual debt service for Square Butte is expected to be approximately $44 million in each of the five years, 2012 through 2016, 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, under a long-term contract.

Minnkota Power Sales Agreement. 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 the 2009 agreement until Minnkota Power has placed in service a new AC transmission line, which is anticipated to occur in late 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 the ability to transmit additional wind generation on the existing 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 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 purchase at least one million MWh of energy over the contract term. In March 2011, the MPUC approved this PPA with Manitoba Hydro.

In May 2011, Minnesota Power and Manitoba Hydro signed an additional PPA. The PPA calls for Manitoba Hydro to sell 250 MW of capacity and energy to Minnesota Power for 15 years beginning in 2020 and requires construction of additional transmission capacity between Manitoba and the U.S. 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. On January 26, 2012, the MPUC approved this PPA with Manitoba Hydro. In February 2012, Minnesota Power and Manitoba Hydro proposed construction of a 500 kV transmission line between Manitoba and Minnesota’s Iron Range in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy, which is expected to be in service in 2020. Total project cost and cost allocations are still to be determined.


ALLETE Third Quarter 2012 Form 10-Q
23


NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

North Dakota Wind Development. Minnesota Power uses the 465-mile, 250 kV DC transmission line that runs from Center, North Dakota, to Duluth, Minnesota to transport increasing amounts of wind energy from North Dakota while gradually phasing out coal-based electricity delivered to our system over this transmission line from Square Butte’s lignite coal-fired generating unit.

Bison 1 is an 82 MW wind facility in North Dakota, which was completed in two phases. The first phase was completed in 2010, and the second phase was completed in January 2012. The project also included construction of a 22-mile, 230 kV transmission line. Bison 1 had a total project cost of $174.3 million through September 30, 2012, including additional costs related to land restoration and completion of remaining associated upgrades for the 250 kV DC transmission line. The MPUC has approved cost recovery for Bison 1 investments and expenses, and current customer billing rates for Bison 1 are based on a November 2011 MPUC order.

Bison 2 and Bison 3 are both 105 MW wind projects in North Dakota which are expected to be completed by the end of 2012. Construction is currently underway for both projects and the total project costs for Bison 2 and Bison 3 are estimated to be approximately $160 million each, of which $129.2 million and $131.0 million, respectively, was spent through September 30, 2012. In September 2011 and November 2011, the MPUC approved Minnesota Power’s petitions seeking cost recovery for investments and expenses related to Bison 2 and Bison 3, respectively. We anticipate filing a petition with the MPUC in the fourth quarter of 2012 to establish customer billing rates for the approved cost recovery.

Coal, Rail and Shipping Contracts. We have coal supply agreements providing for the purchase of a significant portion of our coal requirements which expire in 2013. We also have coal transportation agreements in place for the delivery of a significant portion of our coal requirements with expiration dates through 2015. Our minimum annual payment obligation under these supply and transportation agreements for the remainder of 2012 is $12.8 million, and for 2013 is $26.2 million. 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, to purchase the dragline at fair market value, or to surrender the dragline and pay a $3 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 $10.9 million in 2012, $11.1 million in 2013, $11.4 million in 2014, $11.2 million in 2015, $9.2 million in 2016 and $43.0 million thereafter.

Transmission. We are making investments in Upper Midwest transmission opportunities that strengthen or enhance the regional transmission grid. This includes the CapX2020 initiative, investments in our own transmission assets, investments in other regional transmission assets (individually or in combination with others), 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 in May 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. In June 2011, we filed an updated billing factor that includes additional transmission projects and expenses, which we expect to be approved in late 2012.

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.


ALLETE Third Quarter 2012 Form 10-Q
24


NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Transmission (Continued)

Minnesota Power is participating in three CapX2020 projects: the Fargo, North Dakota to St. Cloud, Minnesota project, the Monticello, Minnesota to St. Cloud, Minnesota project, which together total a 238-mile, 345 kV line from Fargo, North Dakota to Monticello, Minnesota, and the 70-mile, 230 kV line between Bemidji, Minnesota and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota. The 28-mile 345 kV line between Monticello and St. Cloud was placed into service in December 2011 and the 70-mile 230 kV line between Bemidji, Minnesota and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota was placed into service in September 2012. In June 2011, the MPUC approved the route permit for the Minnesota portion of the Fargo to St. Cloud project. The North Dakota permitting process was completed on August 12, 2012. The entire 238-mile, 345 kV line from Fargo to Monticello is expected to be in service by 2015.

Based on projected costs of the three transmission lines and the allocation agreements among participating utilities, Minnesota Power plans to invest between $110 million and $120 million in the CapX2020 initiative through 2015. A total of $45.7 million was spent through September 30, 2012, of which $33.6 million was related to the Fargo, North Dakota to Monticello, Minnesota projects and $12.1 million was related to the Bemidji, Minnesota to Minnesota Power’s Boswell Energy Center project ($27.8 million as of December 31, 2011 of which $20.4 million was related to the Fargo, North Dakota to Monticello, Minnesota projects and $7.4 million was related to the Bemidji, Minnesota to Minnesota Power’s Boswell Energy Center project). As future CapX2020 projects are identified, Minnesota Power may elect to participate on a project-by-project basis.

In November 2010, the MPUC approved a route permit for the Bemidji to Grand Rapids, Minnesota line and construction for the 230 kV line project commenced in January 2011. The Leech Lake Band of Ojibwe (LLBO) subsequently petitioned the MPUC to suspend or revoke the route permit and also served the CapX2020 owners with a complaint filed in Leech Lake Tribal Court. The CapX2020 owners filed a request for declaratory judgment in the United States District Court for the District of Minnesota (District Court) that the project did not require LLBO consent to cross non-tribal land within the reservation. In June 2012, in a letter to the MPUC, the LLBO withdrew its petition to suspend or revoke the route permit issued to the CapX2020 owners. In August 2012, the LLBO executed and approved a consent decree dismissing the federal court actions and the District Court accepted the motion with prejudice.

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. Minnesota Power has evaluated various environmental compliance scenarios using possible ranges of future environmental regulations to determine prominent power supply trends and impacts on customers. All coal-fired generating facilities could potentially be impacted, with the possibility that additional environmental control installations will be needed. At Laskin and Taconite Harbor, we will also be considering options such as remissioning, repowering and retirement.

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 becomes 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 coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, bag houses and low NOX technologies. Under currently applicable environmental regulations, these facilities are substantially compliant with applicable emission requirements.


ALLETE Third Quarter 2012 Form 10-Q
25


NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

New Source Review (NSR). In August 2008, Minnesota Power received a Notice of Violation (NOV) from the EPA asserting violations of the NSR requirements of the Clean Air Act at Boswell Units 1, 2, 3 and 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 specified in the 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.

Resolution of the NOVs could result in civil penalties and the installation of control technology, some of which is already planned or which has been completed to comply with other regulatory requirements. At this time, the Company cannot reasonably estimate the range of loss (including potential penalties), if any, that may result from this matter. Therefore, the Company has not recorded an accrual in connection with the NOV as of September 30, 2012. Any costs of installing pollution control technology would likely be eligible for recovery in rates over time subject to regulatory approval in a rate proceeding.

Cross-State Air Pollution Rule (CSAPR). In July 2011, the EPA issued the CSAPR, which went into effect in October 2011. The final rule replaced the EPA’s 2005 Clean Air Interstate Rule (CAIR). However, on August 21, 2012, a three judge panel of the District of Columbia Circuit Court of Appeals vacated the CSAPR, ordering that the CAIR remain in effect while a CSAPR replacement rule is promulgated. The EPA and other parties to the case have requested that the matter be reheard by the full circuit court. The CSAPR would have required states in the CSAPR region, including Minnesota, to significantly improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states. The CSAPR did not directly require the installation of controls. Instead, the rule would have required facilities to have sufficient emission allowances to cover their emissions on an annual basis. These allowances would have been allocated to facilities from each state’s annual budget and would also have been able to be bought and sold.

The CAIR regulations similarly require certain states to improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states. The CAIR also created an allowance allocation and trading program rather than specifying pollution controls. Minnesota participation in the CAIR was stayed by EPA administrative action while the EPA completed a review of air quality modeling issues in conjunction with the development of a final replacement rule. While the CAIR remains in effect, Minnesota participation in the CAIR will continue to be stayed. It remains uncertain if emission restrictions similar to those contained in the CSAPR will become effective for Minnesota utilities due to the August 2012 District of Columbia Circuit Court of Appeals decision.

Since 2006, we have significantly reduced emissions at our Laskin, Taconite Harbor and Boswell generating units. Based on our expected generation rates, these emission reductions would have satisfied Minnesota Power’s SO2 and NOX emission compliance obligations with respect to the EPA-allocated CSAPR allowances for 2012. Minnesota Power will continue to track the EPA activity related to promulgation of a CSAPR replacement rule. We are unable to predict any additional compliance costs we might incur if the CSAPR is reinstated or if a CSAPR replacement rule is promulgated.

Regional Haze. The federal Regional Haze Rule requires states to submit SIPs to the EPA to address regional haze visibility impairment in 156 federally-protected parks and wilderness areas. Under the first phase of 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, that are subject to BART requirements.

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.


ALLETE Third Quarter 2012 Form 10-Q
26


NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

In December 2011, the EPA published in the Federal Register a proposal to approve the trading program in the CSAPR as an alternative to determining BART. However, as a result of the August 2012 District of Columbia Circuit Court of Appeals decision to vacate the CSAPR (See Cross-State Air Pollution Rule), Minnesota Power is now evaluating whether significant additional expenditures at Taconite Harbor Unit 3 will be required to comply with BART requirements under the Regional Haze Rule. If additional regional haze related controls are ultimately required, Minnesota Power will have up to five years from the final rule promulgation to bring Taconite Harbor Unit 3 into compliance with the Regional Haze Rule requirements. It is uncertain what controls would ultimately be required at Taconite Harbor Unit 3 under this scenario.

Mercury and Air Toxics Standards (MATS) Rule (formerly known as the Electric Generating Unit Maximum Achievable Control Technology (MACT) Rule). Under Section 112 of the Clean Air Act, the EPA is required to set emission standards for hazardous air pollutants (HAPs) for certain source categories. The EPA published the final MATS rule in the Federal Register on February 16, 2012, addressing such emissions from coal-fired utility units greater than 25 MW. There are currently 188 listed HAPs that the EPA is required to evaluate for establishment of MACT standards. In the final MATS rule, the EPA established categories of HAPs, including mercury, trace metals other than mercury, acid gases, dioxin/furans, and organics other than dioxin/furans. The EPA also established emission limits for the first three categories of HAPs, and work practice standards for the remaining categories. Affected sources must be in compliance with the rule by April 2015. States have the authority to grant sources a one-year extension and the EPA is assessing other means for granting additional extensions when justified. Compliance at our Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures totaling between $350 million to $400 million through 2016. Some additional controls for complying with the rule at our remaining coal-fired generating units may be required, the costs of which cannot be estimated at this time.

EPA National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters. In March 2011, a final rule was published in the Federal Register for industrial boiler maximum achievable control technology (Industrial Boiler MACT). The rule was stayed by the EPA in May 2011, to allow the EPA time to consider additional comments received. The EPA re-proposed the rule in December 2011. On January 9, 2012, the United States District Court for the District of Columbia ruled that the EPA stay of the Industrial Boiler MACT was unlawful, effectively reinstating the March 2011 rule and associated compliance deadlines. A final rule based on the December 2011 proposal, which will supersede the March 2011 rule, is expected in late 2012. Major sources are expected to have three years to achieve compliance with the final rule. Costs for complying with the final rule cannot be estimated at this time.