ALLETE has entered an agreement to be acquired by a partnership led by Canada Pension Plan Investment Board and Global Infrastructure Partners and start the process to become a private company. Learn more at www.ALLETEforward.com.
ALE 12/31/2014 - 10K

United States
Securities and Exchange Commission
Washington, D.C. 20549

Form 10-K
(Mark One)
 
 
T
Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
 
For the fiscal year ended December 31, 2014
 
 
 
 
£
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)
 
(I.R.S. Employer Identification No.)

30 West Superior Street, Duluth, Minnesota 55802-2093
(Address of principal executive offices, including zip code)
(218) 279-5000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common Stock, without par value
 
New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes x     No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨     No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes x     No ¨

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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 x    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 ¨     No x

The aggregate market value of voting stock held by nonaffiliates on June 30, 2014, was $2,175,249,161.

As of February 1, 2015, there were 45,953,851 shares of ALLETE Common Stock, without par value, outstanding.

Documents Incorporated By Reference
Portions of the Proxy Statement for the 2015 Annual Meeting of Shareholders are incorporated by reference in Part III.



Index
 
 
 
 
Part I
 
Item 1.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Part II
 
Item 5.
Item 6.
Item 7.
 
 
 
 
 
 
 
 
 
 
Item 7A.
Item 8.
Item 9.
Item 9A.


ALLETE, Inc. 2014 Form 10-K
2


Index
Item 9B.
Part III
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Part IV
 
 
Item 15.
 
 
 
 


ALLETE, Inc. 2014 Form 10-K
3


Definitions

The following abbreviations or acronyms are used in the text. References in this report to “we,” “us” and “our” are to ALLETE, Inc. and its subsidiaries, collectively.
Abbreviation or Acronym
Term
AFUDC
Allowance for Funds Used During Construction - the cost of both debt and equity funds used to finance utility plant additions during construction periods
ALLETE
ALLETE, Inc.
ALLETE Clean Energy
ALLETE Clean Energy, Inc. and its subsidiaries
ALLETE Properties
ALLETE Properties, LLC and its subsidiaries
ArcelorMittal
ArcelorMittal USA, Inc.
ATC
American Transmission Company LLC
Basin
Basin Electric Power Cooperative
Bison Wind Energy Center
Bison 1, 2, 3 & 4 Wind Facilities
Bison 4
Bison 4 Wind Facility
BNI Coal
BNI Coal, Ltd.
Boswell
Boswell Energy Center
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 8-K
ALLETE Current Report on Form 8-K
Form 10-K
ALLETE Annual Report on Form 10-K
Form 10-Q
ALLETE Quarterly Report on Form 10-Q
GAAP
Accounting Principles Generally Accepted in the United States
GHG
Greenhouse Gases
GNTL
Great Northern Transmission Line
IBEW
International Brotherhood of Electrical Workers
Invest Direct
ALLETE’s Direct Stock Purchase and Dividend Reinvestment Plan
Item ___
Item ___ of this Form 10-K
kV
Kilovolt(s)
kWh
Kilowatt-hour
Laskin
Laskin Energy Center
LIBOR
London Interbank Offered Rate
MACT
Maximum Achievable Control Technology
Magnetation
Magnetation, LLC
Manitoba Hydro
Manitoba Hydro-Electric Board
MATS
Mercury and Air Toxics Standards
MBtu
Million British thermal units
Mesabi Nugget
Mesabi Nugget Delaware, LLC
Minnesota Power
An operating division of ALLETE, Inc.
Minnkota Power
Minnkota Power Cooperative, Inc.
MISO
Midcontinent Independent System Operator, Inc.

ALLETE, Inc. 2014 Form 10-K
4


Definitions (continued)

Moody’s
Moody’s Investors Service, Inc.
MPCA
Minnesota Pollution Control Agency
MPUC
Minnesota Public Utilities Commission
MW / MWh
Megawatt(s) / Megawatt-hour(s)
NAAQS
National Ambient Air Quality Standards
NDPSC
North Dakota Public Service Commission
NERC
North American Electric Reliability Corporation
NOL
Net Operating Loss
Non-residential
Retail commercial, non-retail commercial, office, industrial, warehouse, storage and institutional
NO2
Nitrogen Dioxide
NOX
Nitrogen Oxides
Note ___
Note ___ to the consolidated financial statements in this Form 10-K
NPDES
National Pollutant Discharge Elimination System
NYSE
New York Stock Exchange
Oliver Wind I
Oliver Wind I Energy Center
Oliver Wind II
Oliver Wind II Energy Center
Palm Coast Park
Palm Coast Park development project in Florida
Palm Coast Park District
Palm Coast Park Community Development District
PolyMet
PolyMet Mining Corporation
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
RSOP
Retirement Savings and Stock Ownership Plan
SEC
Securities and Exchange Commission
SIP
State Implementation Plan
SO2
Sulfur Dioxide
Square Butte
Square Butte Electric Cooperative
Standard & Poor’s
Standard & Poor’s Ratings Services
SWL&P
Superior Water, Light and Power Company
Taconite Harbor
Taconite Harbor Energy Center
Taconite Ridge
Taconite Ridge Energy Center
Thomson
Thomson 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
U.S. Water Services
U.S. Water Services, Inc.
USS Corporation
United States Steel Corporation

ALLETE, Inc. 2014 Form 10-K
5


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 can be 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-K, 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;
global and domestic economic conditions affecting us or our customers;
wholesale power market conditions;
federal and state regulatory and legislative actions that impact regulated utility economics, including our allowed rates of return, capital structure, ability to secure financing, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities and utility infrastructure, recovery of purchased power, capital investments and other expenses, including present or prospective environmental matters;
changes in and compliance with laws and regulations;
effects of competition, including competition for retail and wholesale customers;
effects of restructuring initiatives in the electric industry;
changes in tax rates or policies or in rates of inflation;
the impacts on our Regulated Operations segment of climate change and future regulation to restrict the emissions of greenhouse gases;
the impacts of laws and regulations related to renewable and distributed generation;
the outcome of legal and administrative proceedings (whether civil or criminal) and settlements;
weather conditions, natural disasters and pandemic diseases;
our ability to access capital markets and bank financing;
changes in interest rates and the performance of the financial markets;
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 and our ability to recover these costs;
pricing, availability and transportation of fuel and other commodities and the ability to recover the costs of such commodities;
our ability to replace a mature workforce and retain qualified, skilled and experienced personnel;
effects of emerging technology;
war, acts of terrorism and cyber attacks;
our ability to manage expansion and integrate acquisitions;
our current and potential industrial and municipal customers’ ability to execute announced expansion plans;
population growth rates and demographic patterns; and
zoning and permitting of land held for resale, real estate development or changes in the real estate market.

Additional disclosures regarding factors that could cause our results or performance to differ from those anticipated by this report are discussed in Item 1A under the heading “Risk Factors” beginning on page 29 of this Form 10-K. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which that statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of these factors, nor can we assess the impact of each of these factors on our businesses or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. Readers are urged to carefully review and consider the various disclosures made by us in this Form 10-K and in our other reports filed with the SEC that attempt to identify the risks and uncertainties that may affect our business.


ALLETE, Inc. 2014 Form 10-K
6


Part I

Item 1. Business

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 approximately 144,000 retail customers. Minnesota Power also has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a customer of Minnesota Power. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 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 our Energy Infrastructure and Related Services businesses; ALLETE Clean Energy, our business which acquired four wind energy facilities in 2014 and is developing a wind facility to be sold in 2015, and BNI Coal, our coal mining operations in North Dakota. Investments and Other also includes ALLETE Properties, our Florida real estate investment, and other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,000 acres of land in Minnesota, and earnings on cash and investments. Our Energy Infrastructure and Related Services businesses will also include U.S. Water Services, which we acquired in February 2015. (See Outlook – Investments and Other.)

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2014, 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.

Year Ended December 31
2014

2013

2012

 
 
 
 
Consolidated Operating Revenue – Millions

$1,136.8


$1,018.4


$961.2

 
 
 
 
Percentage of Consolidated Operating Revenue
 
 
 
Regulated Operations
88
%
91
%
91
%
Investments and Other
12
%
9
%
9
%
 
100
%
100
%
100
%

For a detailed discussion of results of operations and trends, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. For business segment information, see Note 1. Operations and Significant Accounting Policies and Note 2. Business Segments.


Regulated Operations

Electric Sales / Customers

Regulated Utility Electric Sales
 
 
 
 
 
 
Year Ended December 31
2014

%
2013

%
2012

%
Millions of Kilowatt-hours
 
 
 
 
 
 
Retail and Municipal
 
 
 
 
 
 
Residential
1,204

9
1,177

9
1,132

9
Commercial
1,468

10
1,455

11
1,436

11
Industrial
7,487

54
7,338

55
7,502

57
Municipal
864

6
999

8
1,020

8
Total Retail and Municipal
11,023

79
10,969

83
11,090

85
Other Power Suppliers
2,904

21
2,278

17
1,999

15
Total Regulated Utility Electric Sales
13,927

100
13,247

100
13,089

100


ALLETE, Inc. 2014 Form 10-K
7


Regulated Operations (Continued)

Industrial Customers. In 2014, our industrial customers represented 54 percent of total Regulated Utility kilowatt-hour sales. Our industrial customers are primarily in the taconite mining, iron concentrate, paper, pulp and secondary wood products, and pipeline industries.
Industrial Customer Electric Sales
 
 
 
 
 
 
Year Ended December 31
2014

%
2013

%
2012

%
Millions of Kilowatt-hours
 
 
 
 
 
 
Taconite/Iron Concentrate
4,880

65
4,851

66
4,968

66
Paper, Pulp and Secondary Wood Products
1,499

20
1,505

21
1,571

21
Pipelines and Other Industrial
1,108

15
982

13
963

13
Total Industrial Customer Electric Sales
7,487

100
7,338

100
7,502

100

Seven Minnesota Power taconite and iron concentrate customers produce approximately 77 percent of the iron ore produced in the U.S. according to the U.S. Geological Survey’s 2012 Minerals Yearbook published in September 2014. Sales to taconite customers and iron concentrate customers represented 4,880 million kilowatt-hours, or 65 percent, of our total industrial sales in 2014. Taconite, an iron-bearing rock of relatively low iron content, is abundantly available in northern Minnesota and an important domestic source of raw material for the steel industry. Taconite processing plants use large quantities of electric power to grind the iron-bearing rock, and agglomerate and pelletize the iron particles into taconite pellets.

Five of Minnesota Power’s taconite customers have the capability to produce up to approximately 41 million tons of taconite pellets annually. Taconite pellets produced in Minnesota are primarily shipped to North American steel making facilities that are part of the integrated steel industry. Steel produced from these North American facilities is used primarily in the manufacture of automobiles, appliances, pipe and tube products for the gas and oil industry, and in the construction industry. Historically, less than five percent of Minnesota taconite production is exported outside of North America. Also, two of Minnesota Power’s iron concentrate customers have the capability to produce up to approximately 2 million metric tons of iron concentrate per year. Iron concentrate is used in the production of taconite pellets.

During 2014, the domestic steel industry’s production levels enabled Minnesota taconite producers to operate at, or near, full capacity for the entire year. According to the American Iron and Steel Institute (AISI), an association of North American steel producers, U.S. raw steel production operated at approximately 77 percent of capacity in 2014 (77 percent in 2013 and 75 percent in 2012).

The past four years, annual taconite production in Minnesota has remained strong at, or near, full production. The following table reflects Minnesota Power’s taconite customers’ production levels for the past ten years.

Minnesota Power Taconite Customer Production
Year
 
Tons (Millions)
2014*
 
39
2013
 
37
2012
 
39
2011
 
39
2010
 
35
2009
 
17
2008
 
39
2007
 
38
2006
 
39
2005
 
40
Source: Minnesota Department of Revenue 2014 Mining Tax Guide for years 2005 - 2013.
* Preliminary data from the Minnesota Department of Revenue.

ALLETE, Inc. 2014 Form 10-K
8


Regulated Operations (Continued)
Industrial Customers (Continued)

In addition to serving the taconite industry, Minnesota Power also serves a number of customers in the paper, pulp and secondary wood products industry, which represented 1,499 million kilowatt-hours, or 20 percent, of our total industrial sales in 2014. Three of the four major paper mills we serve reported operating at, or near, full capacity in 2014. In October 2013, Boise, Inc. (Boise) permanently shut down two paper machines representing approximately 20 percent of its paper making capacity. Boise’s reduction in paper making capacity did not have a material impact on the Company’s consolidated financial position, results of operations, or cash flows. On September 12, 2014, Boise provided the required one-year written notice of its intent to install additional generation at its International Falls, Minnesota, mill in late 2015. Boise’s reduction in demand is not expected to have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.

Large Power Customer Contracts. Minnesota Power has 10 Large Power Customer contracts, each serving requirements of 10 MW or more of customer load. The customers consist of five taconite producing facilities (two of which are owned by one company and are served under a single contract), one iron nugget plant, one concentrate reclamation facility, and four paper and pulp mills.

Large Power Customer contracts require Minnesota Power to have a certain amount of generating capacity available. In turn, each Large Power Customer is required to pay a minimum monthly demand charge that covers the fixed costs associated with having this capacity available to serve the customer, including a return on common equity. Most contracts allow customers to establish the level of megawatts subject to a demand charge on a four-month basis and require that a portion of their megawatt needs be committed on a take-or-pay basis for at least a portion of the term of the agreement. In addition to the demand charge, each Large Power Customer is billed an energy charge for each kilowatt-hour used that recovers the variable costs incurred in generating electricity. Three of the Large Power Customers have interruptible service which provides a discounted demand rate in exchange for the ability to interrupt the customers during system emergencies. Minnesota Power also provides incremental production service for customer demand levels above the contractual take-or-pay levels. There is no demand charge for this service and energy is priced at an increment above Minnesota Power’s cost. Incremental production service is interruptible.

All contracts with Large Power Customers continue past the contract termination date unless the required advance notice of cancellation has been given. The required advance notice of cancellation varies from one to four years. Such contracts minimize the impact on earnings that otherwise would result from significant reductions in kilowatt-hour sales to such customers. Large Power Customers are required to take all of their purchased electric service requirements from Minnesota Power for the duration of their contracts. The rates and corresponding revenue associated with capacity and energy provided under these contracts are subject to change through the same regulatory process governing all retail electric rates. (See Item 1. Business – Regulated Operations – Regulatory Matters – Electric Rates.)

Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates. These customers receive estimated bills based on Minnesota Power’s estimate of the customer’s energy usage, forecasted energy prices, and fuel clause adjustment estimates. Minnesota Power’s four taconite-producing Large Power Customers have generally predictable energy usage on a week-to-week basis, and any differences that occur are trued-up the following month.


ALLETE, Inc. 2014 Form 10-K
9


Regulated Operations (Continued)
Large Power Customer Contracts (Continued)

Contract Status for Minnesota Power Large Power Customers
As of February 1, 2015
Customer
Industry
Location
Ownership
Earliest
Termination Date
ArcelorMittal USA, Inc. – Minorca Mine (a)
Taconite
Virginia, MN
ArcelorMittal S.A.
January 31, 2019
Hibbing Taconite Co. (a)
Taconite
Hibbing, MN
62.3% ArcelorMittal S.A.
23.0% Cliffs Natural Resources Inc.
14.7% USS Corporation
January 31, 2019
United Taconite LLC (a)
Taconite
Eveleth, MN
Cliffs Natural Resources Inc.
January 31, 2019
USS Corporation
(USS – Minnesota Ore) (a,b)
Taconite
Mt. Iron, MN and Keewatin, MN
USS Corporation
January 31, 2019
Mesabi Nugget Delaware, LLC
Iron Nugget
Hoyt Lakes, MN
80% Steel Dynamics, Inc.
20% Kobe Steel USA, Inc.
December 31, 2023
Boise, Inc.
Paper
International Falls, MN
Packaging Corporation of America
December 31, 2023
UPM, Blandin Paper Mill (a)
Paper
Grand Rapids, MN
UPM-Kymmene Corporation
January 31, 2019
Verso Corporation (c)
Paper and Pulp
Duluth, MN
Verso Corporation
December 31, 2022
Sappi Cloquet LLC (a)
Paper and Pulp
Cloquet, MN
Sappi Limited
January 31, 2019
Magnetation, LLC (d)
Iron Concentrate

Coleraine, MN
50.1% Magnetation, Inc.
49.9% AK Steel Corporation
December 31, 2025
(a)
The contract will terminate four years from the date of written notice from either Minnesota Power or the customer. No notice of contract cancellation has been given by either party. Thus, the earliest date of cancellation is January 31, 2019.
(b)
USS Corporation owns both the Minntac Plant in Mountain Iron, MN, and the Keewatin Taconite Plant in Keewatin, MN.
(c)
On January 7, 2015, Verso Corporation acquired NewPage Corporation. This acquisition will not impact Minnesota Power’s electric service agreement with NewPage Corporation.
(d)
Production at this facility commenced in December 2014. (See Outlook – Regulated Operations – Industrial Customers and Prospective Additional Loads.)

Residential and Commercial Customers. In 2014, our residential and commercial customers represented 19 percent of total regulated utility kilowatt-hour sales. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 144,000 residential and commercial customers. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers.

Municipal Customers. In 2014, our municipal customers represented 6 percent of total regulated utility kilowatt-hour sales, which included 16 municipals in Minnesota.

Other Power Suppliers. The Company also enters into off-system sales with Other Power Suppliers. These sales are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements of various durations.

Basin Power Sales Agreement. Minnesota Power entered into an agreement to sell 100 MW of capacity and energy to Basin for a ten-year period which expires in April 2020. The capacity charge is based on a fixed monthly schedule with a minimum annual escalation provision. The energy charge is based on a fixed monthly schedule and provides for annual escalation based on our cost of fuel. The agreement allows us to recover a pro rata share of increased costs related to emissions that may occur during the last five years of the contract.

Minnkota Power Sales Agreement. Minnesota Power entered into a power sales agreement with Minnkota Power, which commenced June 1, 2014. Under the power sales agreement, Minnesota Power is selling 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. (See Note 12. Commitments, Guarantees and Contingencies.)

ALLETE, Inc. 2014 Form 10-K
10


Regulated Operations (Continued)

Seasonality

The operations of our industrial customers, which make up a large portion of our sales portfolio as reflected in the table above, are not typically subject to significant seasonal variations. As a result, Minnesota Power is generally not subject to significant seasonal fluctuations in electric sales.

Power Supply

In order to meet our customers’ electric requirements, we utilize a mix of Company generation and purchased power. At December 31, 2014, the Company’s generation is primarily coal-fired, but also includes approximately 105 MW of hydroelectric generation from ten hydro stations in Minnesota, 522 MW of nameplate capacity wind generation, and 81 MW of biomass co-fired generation. Purchased power consists of long-term coal, wind and hydro PPAs as well as market purchases. The following table reflects the Company’s generating capabilities as of December 31, 2014, and total electrical output for 2014. Minnesota Power had an annual net peak load of 1,637 MW on December 30, 2014.

ALLETE, Inc. 2014 Form 10-K
11



Regulated Operations (Continued)
Power Supply (Continued)
 
 
 
 
Year Ended
 
Unit
Year
Net
December 31, 2014
Regulated Utility Power Supply
No.
Installed
Capability
Generation and Purchases
 
 
 
MW
MWh
%
Coal-Fired
 
 
 
 
 
Boswell Energy Center
1
1958
67

 
 
in Cohasset, MN
2
1960
68

 
 
 
3
1973
362

 
 
 
4
1980
468

(a)
 
 
 
 
965

6,543,143

46.3
Laskin Energy Center
1
1953
43

(b)
 
in Hoyt Lakes, MN
2
1953
38

(b)
 
 
 
 
81

347,844

2.4
Taconite Harbor Energy Center
1
1957
76

 
 
in Schroeder, MN
2
1957
74

 
 
 
3
1967
81

(b)
 
 
 
 
231

1,089,924

7.7
Total Coal-Fired
 
 
1,277

7,980,911

56.4
Biomass/Coal/Natural Gas
 
 
 
 
 
Hibbard Renewable Energy Center in Duluth, MN
3 & 4
1949, 1951
58

19,635

0.1
Cloquet Energy Center in Cloquet, MN
5
2001
23

119,025

0.8
Total Biomass/Coal/Natural Gas
 
 
81

138,660

0.9
Hydro (c)
 
 
 
 
 
Group consisting of ten stations in MN
Multiple
Multiple
105

238,293

1.7
Wind (d)
 
 
 
 
 
Taconite Ridge Energy Center in Mt. Iron, MN
Multiple
2008
25

66,609

0.5
Bison Wind Energy Center in Oliver and Morton Counties, ND
Multiple
2010-2014
497

962,275

6.8
Total Wind
 
 
522

1,028,884

7.3
Total Company Generation
 
 
1,985

9,386,748

66.3
Long-Term Purchased Power
 
 
 
 
 
Lignite Coal - Square Butte near Center, ND
 
 
 
1,378,008

9.7
Wind - Oliver County, ND
 
 
 
365,940

2.6
Hydro - Manitoba Hydro in Manitoba, Canada
 
 
 
320,609

2.3
Total Long-Term Purchased Power
 
 


2,064,557

14.6
Other Purchased Power (e)
 
 
 
2,705,942

19.1
Total Purchased Power
 
 


4,770,499

33.7
Total
 
 
1,985

14,157,247

100.0
(a)
Boswell Unit 4 net capability shown above reflects Minnesota Power’s ownership percentage of 80 percent. WPPI Energy owns 20 percent of Boswell Unit 4. (See Note 4. Jointly-Owned Facilities and Projects.)
(b)
Future plans for our Laskin Energy Center and Taconite Harbor Unit 3 are included in our “EnergyForward” plan which includes the conversion of Laskin from coal to natural gas in the second quarter of 2015 and the retiring of Taconite Harbor Unit 3 in the second quarter of 2015. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Outlook EnergyForward.)
(c)
The Thomson Energy Center returned to partial generation in the fourth quarter of 2014. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Outlook Hydro Operations.)
(d)
Taconite Ridge consists of 10 wind turbine generator units with a total nameplate capacity of 25 MW. The Bison Wind Energy Center consists of 165 wind turbine generator units, with a total nameplate capacity of 497 MW. Bison 4 was placed in service in the fourth quarter of 2014 and approximately 45,000 MWh generated by Bison 4 is included in the table above. The net capability reflected in the table is the actual accredited capacity of the facility, which is the amount of net generating capability associated with the facility for which capacity credit was obtained using limited historical data. As more data is collected, actual accredited capacity may change.
(e)
Includes short-term market purchases in the MISO market and from Other Power Suppliers.

ALLETE, Inc. 2014 Form 10-K
12



Regulated Operations (Continued)

Fuel. Minnesota Power purchases low-sulfur, sub-bituminous coal from the Powder River Basin region located in Montana and Wyoming. Coal consumption in 2014 for electric generation at Minnesota Power’s coal-fired generating stations was 4.8 million tons. As of December 31, 2014, Minnesota Power had a coal inventory of 1.0 million tons (0.4 million tons as of December 31, 2013). Fuel inventory was low throughout much of 2014 due to rail service delays. Minnesota Power filed a notice of fuel supply emergency with the U.S. Department of Energy on September 22, 2014, in response to inadequate rail deliveries. Rail deliveries increased late in 2014, building inventories to normal levels by year end 2014. Minnesota Power’s coal supply agreements have expiration dates through 2015. In 2015, Minnesota Power expects to obtain coal under these coal supply agreements and in the spot market. Minnesota Power also continues to explore other future coal supply options. We believe that adequate supplies of low-sulfur, sub-bituminous coal will continue to be available.

Minnesota Power also has transportation agreements in place for the delivery of a significant portion of its coal requirements. These transportation agreements have expiration dates through 2015. Minnesota Power is currently in discussions regarding the extension of our coal supply and transportation contracts beyond 2015. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.

Coal Delivered to Minnesota Power
Year Ended December 31
2014

2013

2012

Average Price per Ton

$26.52


$28.90


$29.58

Average Price per MBtu

$1.47


$1.60


$1.64


Long-Term Purchased Power. Minnesota Power has contracts to purchase capacity and energy from various entities, including output from certain coal, wind and hydro generating facilities.

Square Butte PPA. Under the long-term agreement with Square Butte, which expires at the end of 2026, Minnesota Power is entitled to 50 percent of the output of a 455-MW coal-fired generating unit located near Center, North Dakota. (See Note 12. Commitments, Guarantees and Contingencies.) BNI Coal supplies lignite coal to Square Butte. This lignite supply is sufficient to provide fuel for the anticipated useful life of the generating unit. Square Butte’s cost of lignite burned in 2014 was approximately $1.63 per MBtu. (See Electric Sales/Customers–Minnkota Power Sales Agreement.)

Minnkota Power PPA. In December 2012, Minnesota Power entered into a long-term PPA with Minnkota Power. Under this agreement, Minnesota Power will purchase 50 MW of capacity and the energy associated with that capacity from June 2016 through May 2020. The agreement includes a fixed capacity charge and energy pricing that escalates at a fixed rate annually over the term.

Oliver Wind I and II PPAs. 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 that expire in 2031 and 2032, respectively. Each agreement provides for the purchase of all output from the facilities at fixed energy prices. There are no fixed capacity charges, and we only pay for energy as it is delivered to us.

Manitoba Hydro PPAs. Minnesota Power has a long-term PPA with Manitoba Hydro that expires in May 2020. 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. In addition, Minnesota Power has a separate long-term PPA with Manitoba Hydro to purchase surplus energy through April 2022. This energy-only agreement 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 May 2011, Minnesota Power and Manitoba Hydro signed an additional long-term PPA. The PPA provides for Minnesota Power to purchase 250 MW of capacity and energy from Manitoba Hydro for 15 years beginning in 2020. The agreement is subject to construction of additional transmission capacity between Manitoba and the U.S., along with construction of new hydroelectric generating capacity in Manitoba. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. (See Item 1. Business – Regulated Operations – Transmission and Distribution.) The capacity price is adjusted annually until 2020 by the change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed price component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices.

ALLETE, Inc. 2014 Form 10-K
13



Regulated Operations (Continued)
Long-Term Purchased Power (Continued)

In July 2014, Minnesota Power and Manitoba Hydro signed a long-term PPA that provides for Minnesota Power to purchase up to 133 MW of energy from Manitoba Hydro for 20 years beginning in 2020. The agreement was approved by the MPUC in an order dated January 30, 2015, and is subject to the construction of the GNTL.

Great River Energy PPAs. In August 2014 and January 2015, Minnesota Power and Great River Energy signed long-term PPAs that provide for Minnesota Power to purchase 50 MW of capacity and energy under the first PPA and 50 MW of capacity only under the second PPA. The PPAs commence in June 2016 and expire in May 2020. Both contracts have fixed capacity pricing. The energy price in the first PPA is based on a formula that includes an annual fixed price component adjusted for changes in a natural gas index as well as market prices. Both PPAs are subject to MPUC approval.

Transmission and Distribution

We have electric transmission and distribution lines of 500 kV (8 miles), 345 kV (107 miles), 250 kV (465 miles), 230 kV (714 miles), 161 kV (43 miles), 138 kV (130 miles), 115 kV (1,271 miles) and less than 115 kV (6,276 miles). We own and operate 174 substations with a total capacity of 10,651 megavoltamperes. Some of our transmission and distribution lines interconnect with other utilities.

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 and municipal 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.

Minnesota Power is currently participating in the construction of one CapX2020 transmission line project. Minnesota Power also participated in two CapX2020 projects which were previously completed and placed into service in 2011 and 2012. In June 2011, the MPUC approved the route permit for the Minnesota portion of the Fargo to St. Cloud project, of which the final phase is currently under construction and expected to be in service in the second quarter of 2015.
Based on projected costs of the three transmission line projects and the allocation agreements among participating utilities, in total Minnesota Power plans to invest approximately $105 million in the CapX2020 initiative through 2015, of which $99 million was spent through December 31, 2014. As future CapX2020 projects are identified, Minnesota Power may elect to participate on a project-by-project basis.

Great Northern Transmission Line (GNTL). As a condition of the long-term PPA signed in May 2011 with Manitoba Hydro, construction of additional transmission capacity is required. As a result, Minnesota Power and Manitoba Hydro proposed construction of the GNTL, an approximately 220-mile 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.

The GNTL is subject to various federal and state regulatory approvals. In October 2013, a Certificate of Need application was filed with the MPUC with respect to the GNTL. In an order dated January 8, 2014, the MPUC determined the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. On April 15, 2014, Minnesota Power filed a route permit application with the MPUC and a request for a presidential permit to cross the U.S.-Canadian border with the U.S. Department of Energy. In an order dated July 2, 2014, the MPUC determined the route permit application to be complete. Manitoba Hydro must also obtain regulatory and governmental approvals related to a new transmission line in Canada. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. Upon receipt of all applicable permits and approvals, construction of the GNTL is anticipated to begin in 2016, and to be completed in 2020. Total project cost in the U.S., including substation work, is estimated to be between $560 million and $710 million, depending on the final route of the line. Minnesota Power is expected to have majority ownership of the transmission line.




ALLETE, Inc. 2014 Form 10-K
14


Regulated Operations (Continued)

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 based on a FERC-approved 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 December 31, 2014, our equity investment in ATC was $121.1 million ($114.6 million at December 31, 2013). (See Note 6. Investment in ATC.)

In November 2013, several customer groups located within the MISO service area filed a complaint with the FERC requesting, among other things, a reduction in the base return on equity used by MISO transmission owners, including ATC, to 9.15 percent. ATC's current authorized return on equity is 12.2 percent. In the fourth quarter of 2014, FERC ordered formal hearing proceedings to begin and established a date for potential refunds from November 12, 2013. An initial decision in the complaint is expected by November 30, 2015. In the fourth quarter of 2014, ATC recorded approximately an$18 million refund liability as ATC believes that it is probable that a refund will be required upon ultimate resolution of this matter. The refund liability is subject to adjustment in future periods if assumptions in the estimate change. ATC’s refund liability negatively impacted our Equity Earnings in ATC by approximately $1 million after-tax in 2014. We own approximately 8 percent of ATC and estimate that for every 50 basis point reduction in ATC’s allowed return on equity our equity earnings in ATC would be impacted annually by approximately $0.5 million on an after-tax basis.

In October 2014, ATC updated its 10-year transmission assessment covering the years 2014 through 2023 which identifies a need for between $3.3 and $3.9 billion in transmission system investments. These investments by ATC are expected to be funded through a combination of internally generated cash, debt and investor contributions. As opportunities arise, we plan to make additional investments in ATC through general capital calls based upon our pro rata ownership interest in ATC.

In April 2011, ATC and Duke Energy Corporation announced the creation of a joint venture, Duke-American Transmission Co. (DATC) that intends to build, own and operate new electric transmission infrastructure in the U.S. and Canada. DATC is subject to the rules and regulations of the FERC, various independent system operators and state regulatory authorities.

Properties

We own office and service buildings, an energy control center, repair shops, and storerooms in various localities. All of our electric plants are subject to mortgages, which collateralize the outstanding first mortgage bonds of Minnesota Power and SWL&P. All of our generating plants and most of our substations are located on real property owned by us, subject to the lien of a mortgage, whereas most of our electric lines are located on real property owned by others with appropriate easement rights or necessary permits from governmental authorities. WPPI Energy owns 20 percent of Boswell Unit 4. WPPI Energy has the right to use our transmission line facilities to transport its share of Boswell generation. (See Note 4. Jointly-Owned Facilities and Projects.)

Regulatory Matters

We are subject to the jurisdiction of various regulatory authorities and other organizations. The MPUC has regulatory authority over Minnesota Power’s retail service area in Minnesota, retail rates, retail services, capital structure, issuance of securities and other matters. The FERC has jurisdiction over the licensing of hydroelectric projects, the establishment of rates and charges for transmission of electricity in interstate commerce and electricity sold at wholesale (including the rates for our municipal customers), natural gas transportation, certain accounting and record-keeping practices, certain activities of our regulated utilities, and the operations of ATC. The NERC has been certified by the FERC as the national electric reliability organization and has jurisdiction over certain aspects of the Company’s generation and transmission operations, including cybersecurity relating to generation and transmission reliability. The PSCW has regulatory authority over SWL&P’s retail sales of electricity, natural gas, water, issuances of securities, and other matters. The NDPSC has jurisdiction over site and route permitting of generation and transmission facilities necessary for construction in North Dakota.

Electric Rates. All rates and contract terms in our Regulated Operations are subject to approval by applicable regulatory authorities. Minnesota Power designs its retail electric service rates based on cost of service studies under which allocations are made to the various classes of customers as approved by the MPUC. Nearly all retail sales include billing adjustment clauses, which adjust electric service rates for changes in the cost of fuel and purchased energy, recovery of current and deferred conservation improvement program expenditures and recovery of certain environmental, transmission and renewable expenditures.


ALLETE, Inc. 2014 Form 10-K
15


Regulated Operations (Continued)
Regulatory Matters (Continued)

Information published by the Edison Electric Institute (Typical Bills and Average Rates Report – Summer 2014 and Rankings – July 1, 2014) ranked Minnesota Power as having the second lowest average retail rates out of 169 utilities in the U.S. and the lowest rates in Minnesota.

Minnesota Public Utilities Commission. The MPUC has regulatory authority over Minnesota Power’s retail service area in Minnesota, retail rates, retail services, capital structure, issuance of securities and other matters.

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

Renewable Cost Recovery Rider. Construction on the 205 MW Bison 4 wind facility in North Dakota was completed with project costs totaling approximately $333 million through December 31, 2014. With the completion of Bison 4, the Bison Wind Energy Center in North Dakota consists of 497 MW of nameplate capacity. On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. Customer billing rates for our Bison 1, 2, & 3 wind facilities were approved by the MPUC in a December 2013 order. On April 29, 2014 and November 10, 2014, we filed renewable resources factor filings which include updated costs associated with the Bison Wind Energy Center. Upon approval of the filings, we will be authorized to include updated billing rates on customer bills.

On January 29, 2015, the MPUC approved our petition seeking cost recovery for investments and expenditures related to the restoration and repair of Thomson through a renewable resources rider. The total project investment for Thomson is estimated to be approximately $90 million, net of insurance. (See Note 12. Commitments, Guarantees and Contingencies.)

Integrated Resource Plan. In a November 2013 order, the MPUC approved Minnesota Power’s 2013 Integrated Resource Plan which details our “EnergyForward” strategic plan (see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward), and includes an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. Significant elements of the “EnergyForward” plan include major wind investments in North Dakota which were completed in the fourth quarter of 2014 (see Renewable Cost Recovery Rider), installation of emissions control technology at Boswell Unit 4, planning for the proposed GNTL, conversion of Laskin from coal to natural gas in the second quarter of 2015 and retiring Taconite Harbor Unit 3 in the second quarter of 2015. We are required to submit our 2015 Integrated Resource Plan with the MPUC no later than September 1, 2015.

Boswell Mercury Emissions Reduction Plan. Minnesota Power is implementing a mercury emissions reduction project for Boswell Unit 4 in order to comply with the Minnesota Mercury Emissions Reduction Act and the Federal MATS rule. In August 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA. The plan proposed that Minnesota Power install pollution controls by early 2016 to address both the Minnesota Mercury Emissions Reduction Act requirements and the Federal MATS rule. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are included in the estimated capital expenditures required for compliance with the MATS rule and are estimated to be approximately $250 million, of which $145 million was spent through December 31, 2014. In November 2013, the MPUC issued an order approving the Boswell Unit 4 mercury emissions reduction plan and cost recovery, and establishing an environmental improvement rider. Also in November 2013, environmental intervenors filed a petition for reconsideration with the MPUC which was subsequently denied in an order dated January 17, 2014. The MPUC’s order was affirmed by the Minnesota Court of Appeals on November 3, 2014. In December 2013, Minnesota Power filed a petition with the MPUC to establish customer billing rates for the approved environmental improvement rider based on actual and estimated investments and expenditures, which was approved in an order dated July 2, 2014. On November 26, 2014, we filed an updated environmental improvement factor filing which included updated costs associated with Boswell Unit 4. Upon approval of this filing, we will be authorized to include updated billing rates on customer bills.

Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. In November 2013, the MPUC approved Minnesota Power’s updated billing factor which allows Minnesota Power to charge retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. We filed a petition on April 24, 2014, to include additional transmission investments and expenditures in customer billing rates, which was approved by the MPUC on January 29, 2015.

ALLETE, Inc. 2014 Form 10-K
16


Regulated Operations (Continued)
Regulatory Matters (Continued)

Great Northern Transmission Line (GNTL). Minnesota Power and Manitoba Hydro have proposed construction of the GNTL, an approximately 220-mile 500 kV transmission line, between Manitoba and Minnesota’s Iron Range. The GNTL is subject to various federal and state regulatory approvals. In October 2013, a Certificate of Need application was filed with the MPUC with respect to the GNTL. In an order dated January 8, 2014, the MPUC determined the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. On April 15, 2014, Minnesota Power filed a route permit application with the MPUC and a request for a presidential permit to cross the U.S.-Canadian border with the U.S. Department of Energy. In an order dated July 2, 2014, the MPUC determined the route permit application to be complete. Manitoba Hydro must also obtain regulatory and governmental approvals related to a new transmission line in Canada. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. Upon receipt of all applicable permits and approvals, construction of the GNTL is anticipated to begin in 2016, and to be completed in 2020. (See Item 1. Business – Regulated Operations – Transmission and Distribution.)

Conservation Improvement Program (CIP). Minnesota requires electric utilities to spend a minimum of 1.5 percent of net gross operating revenues from service provided in the state on energy CIPs each year. These investments are recovered from certain retail customers through a combination of the conservation cost recovery charge included in retail base rates and a conservation program adjustment, which is adjusted annually through the CIP consolidated filing. The MPUC allows utilities to accumulate, in a deferred account for future cost recovery, all CIP expenditures, any financial incentive earned for cost-effective program achievements, and a carrying charge on the deferred account balance. Minnesota’s Next Generation Energy Act of 2007 included, in addition to the minimum spending requirements, an energy-saving goal of 1.5 percent of net gross annual retail electric energy sales beginning with program year 2010. Minnesota Power refers to the collective conservation programs as the “Power of One”. In June 2013, Minnesota Power submitted a triennial filing for 2014 through 2016, which was subsequently approved by the Minnesota Department of Commerce. Minnesota Power’s CIP investment goal was $6.9 million for 2014 ($6.0 million for 2013 and 2012), with actual spending of $7.2 million in 2014 ($6.4 million in 2013; $6.8 million in 2012). The investment goal for 2015 and 2016 is $7.1 and $7.3 million, respectively.

As a result of the energy savings goal in the Next Generation Energy Act of 2007, the MPUC revised the utility performance incentive to recognize utilities for making progress toward and meeting the energy-savings goals established. This revised incentive mechanism became effective beginning with the 2010 program year. On April 1, 2014, Minnesota Power submitted its 2013 CIP filing that requested a CIP financial incentive of $8.7 million based upon MPUC procedures. The requested CIP financial incentive was approved by the MPUC in a hearing held on July 24, 2014, and was recorded as revenue and as a regulatory asset. The approved financial incentive will be recovered through customer billing rates in 2014 and 2015. In 2013, the CIP financial incentive of $7.1 million was recognized in the fourth quarter. CIP financial incentives are recognized in the period in which the MPUC approves the filing. The MPUC implemented certain limitation of amounts recoverable for the utility performance incentive program for plan years beginning in 2014.

Federal Energy Regulatory Commission. The FERC has jurisdiction over the licensing of hydroelectric projects, the establishment of rates and charges for transmission of electricity in interstate commerce and electricity sold at wholesale (including the rates for our municipal customers), natural gas transportation, certain accounting and record-keeping practices, certain activities of our regulated utilities, and the operations of ATC. FERC jurisdiction also includes enforcement of NERC mandatory electric reliability standards. Violations of FERC rules are subject to enforcement action by the FERC including financial penalties up to $1 million per day per violation.

Minnesota Power has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a customer of Minnesota Power. In April 2014, Minnesota Power amended its formula-based wholesale electric sales contract with the Nashwauk Public Utilities Commission, extending the term through June 30, 2026. The electric service agreements with the remaining 15 Minnesota municipal customers and SWL&P are effective through June 30, 2019. The rates included in these contracts are set each July 1 based on a cost-based formula methodology, 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 Nashwauk Public Utilities Commission agreement, no termination notice may be given prior to June 30, 2023. Under the agreements with the remaining 15 municipal customers and SWL&P, no termination notices may be given prior to June 30, 2016.

ALLETE, Inc. 2014 Form 10-K
17


Regulated Operations (Continued)
Regulatory Matters (Continued)

Public Service Commission of Wisconsin. The PSCW has regulatory authority over SWL&P’s retail sales of electricity, natural gas and water, issuances of securities and other matters.

SWL&P’s current retail rates are based on a 2012 PSCW retail rate order, effective January 1, 2013, that allows for a 10.9 percent return on common equity.

North Dakota Public Service Commission. The NDPSC has jurisdiction over site and route permitting of generation and transmission facilities in North Dakota.

Regional Organizations

Midcontinent Independent System Operator, Inc. Minnesota Power and SWL&P are members of MISO, a regional transmission organization. While Minnesota Power and SWL&P retain ownership of their respective transmission assets, their transmission networks are under the regional operational control of MISO. Minnesota Power and SWL&P take and provide transmission service under the MISO open access transmission tariff. MISO continues its efforts to standardize rates, terms, and conditions of transmission service over its region, which encompasses all or parts of 15 states and the Canadian province of Manitoba, and over 150,000 MW of generating capacity.

North American Electric Reliability Corporation. The NERC has been certified by the FERC as the national electric reliability organization. The NERC ensures the reliability of the North American bulk power system. The NERC oversees eight regional entities that establish requirements, approved by the FERC, for reliable operation and maintenance of power generation facilities and transmission systems. Minnesota Power is subject to these reliability requirements and can incur significant penalties for non-compliance.

Midwest Reliability Organization (MRO). Minnesota Power is a member of the MRO, one of the eight regional entities overseen by the NERC. MRO's primary responsibilities are to: ensure compliance with mandatory reliability standards by entities who own, operate, or use the interconnected, international Bulk Power System; conduct assessments of the grid's ability to meet electricity demand in the region; and analyze regional system events.

The MRO region spans the Canadian provinces of Saskatchewan and Manitoba, and all or parts of the states of Illinois, Iowa, Minnesota, Michigan, Montana, Nebraska, North Dakota, South Dakota and Wisconsin. The region includes more than 130 organizations that are involved in the production and delivery of power to more than 20 million people. These organizations include municipal utilities, cooperatives, investor-owned utilities, transmission system operators, a federal power marketing agency, Canadian Crown corporations, and independent power producers.

Minnesota Legislation

Renewable Energy. In February 2007, Minnesota enacted a law requiring 25 percent of Minnesota Power’s total retail and municipal energy sales in Minnesota to be from renewable energy sources by 2025. The law also requires Minnesota Power to meet interim milestones of 12 percent by 2012, 17 percent by 2016 and 20 percent by 2020. The law allows the MPUC to modify or delay 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.

Minnesota Power continues to execute its renewable energy strategy through key renewable projects that will ensure we meet the identified state mandate at the lowest cost for customers. Our wind energy facilities consist of our 497 MW Bison Wind Energy Center located in North Dakota placed in service in various phases between 2010 and 2014, and our 25 MW Taconite Ridge Energy Center located in northeastern Minnesota. We also have 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) located in North Dakota. Through the strategy outlined in Minnesota Power’s 2013 Integrated Resource Plan, 18 percent of the Company’s total retail and municipal energy sales were supplied by renewable energy sources in 2014. We expect 28 percent of the Company’s total retail and municipal energy sales will be supplied by renewable energy sources in 2015.

ALLETE, Inc. 2014 Form 10-K
18


Regulated Operations (Continued)
Minnesota Legislation (Continued)

Minnesota Solar Energy Standard. In May 2013, legislation was enacted by the state of Minnesota requiring at least 1.5 percent of total retail electric sales, excluding sales to certain industrial customers, to be generated by solar energy by the end of 2020. At least 10 percent of the 1.5 percent mandate must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 20 kilowatts or less. Minnesota Power is in the process of evaluating the potential impact of this legislation on our operations; however, any costs are expected to be recovered in customer rates.

Competition

Retail electric energy sales in Minnesota and Wisconsin are made to customers in assigned service territories. As a result, most retail electric customers in Minnesota do not have the ability to choose their electric supplier. Large energy users of 2 MW and above that are located outside of a municipality may be allowed to choose a supplier upon MPUC approval. Minnesota Power serves 11 Large Power facilities over 10 MW, none of which have engaged in a competitive rate process. No other large commercial or small industrial customers in Minnesota Power’s service territory have attempted to seek a provider outside Minnesota Power’s service territory since 1994. Retail electric and natural gas customers in Wisconsin do not have the ability to choose their energy supplier. In both states, however, electricity may compete with other forms of energy. Customers may also choose to generate their own electricity, or substitute other forms of energy for their manufacturing processes.

For the year ended December 31, 2014, 6 percent of the Company’s electric energy sales were to municipal customers in Minnesota by contract under a formula-based rate approved by FERC. These customers have the right to seek an energy supply from any wholesale electric service provider upon contract expiration. (See Item 1. Business – Regulated Operations – Regulatory Matters.)

The FERC has continued with its efforts to promote a more competitive wholesale market through open-access electric transmission and other means. As a result, our electric sales to Other Power Suppliers and our purchases to supply our retail and wholesale load are made in the competitive market.

Franchises

Minnesota Power holds franchises to construct and maintain an electric distribution and transmission system in 91 cities. The remaining cities, villages and towns served by us do not require a franchise to operate. SWL&P serves customers with electric, natural gas and/or water systems in 1 city and 16 villages or towns.

Investments and Other

Investments and Other is comprised primarily of our Energy Infrastructure and Related Services businesses; ALLETE Clean Energy and BNI Coal. Investments and Other also includes ALLETE Properties, other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,000 acres of land in Minnesota, and earnings on cash and investments. Our Energy Infrastructure and Related Services businesses will also include U.S. Water Services, which we acquired in February 2015. (See Outlook.)

ALLETE Clean Energy

ALLETE Clean Energy operates independently of Minnesota Power to develop or acquire capital projects aimed at creating energy solutions via wind, solar, biomass, midstream gas and oil infrastructure, among other energy-related projects. ALLETE Clean Energy intends to market to electric utilities, cooperatives, municipalities, independent power marketers and large end-users across North America through long-term contracts or other sale arrangements.

On January 30, 2014, ALLETE Clean Energy acquired wind energy facilities located in Lake Benton, Minnesota (Lake Benton), Storm Lake, Iowa (Storm Lake II) and Condon, Oregon (Condon) for $26.9 million. ALLETE Clean Energy also has an option to acquire a fourth wind energy facility in Armenia Mountain, Pennsylvania (Armenia Mountain), in June 2015.

Lake Benton, Storm Lake II and Condon have 104 MW, 77 MW and 50 MW of generating capability, respectively. Lake Benton and Storm Lake II began commercial operations in 1998, while Condon began operations in 2002. All three wind energy facilities have PPAs in place for their entire output, which expire in various years between 2019 and 2032. Pursuant to the acquisition agreement, ALLETE Clean Energy has an option to acquire the 101 MW Armenia Mountain wind energy facility in June 2015. Armenia Mountain began operations in 2009.


ALLETE, Inc. 2014 Form 10-K
19


Investments and Other (Continued)
ALLETE Clean Energy (Continued)

On November 20, 2014, ALLETE Clean Energy acquired a business for $27.0 million which is developing a wind facility near Hettinger, North Dakota. ALLETE Clean Energy will develop and construct a 107 MW wind farm using 43 turbines which will then be sold to Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., for approximately $200 million. Construction is expected to be completed in December 2015, and the sale is subject to regulatory approvals.

On December 17, 2014, ALLETE Clean Energy acquired a wind facility in Storm Lake, Iowa (Storm Lake I) for $15.0 million, subject to a working capital adjustment. Storm Lake I has 108 MW of generating capability and is located adjacent to Storm Lake II which was acquired in January 2014. The wind facility began commercial operations in 1999 and has a PPA in place for its entire output which expires in 2018.

On December 31, 2014, ALLETE Clean Energy signed a purchase agreement to acquire wind facilities in southern Minnesota for approximately $47.5 million. The facilities have 97.5 MW of generating capability and are located near our Lake Benton facility acquired in January 2014. The wind facilities began commercial operations in 2003 and have PPAs in place for the entire output, which expire in 2018 and 2023. The acquisition is expected to close in the first quarter of 2015.

BNI Coal

BNI Coal is a supplier of lignite in North Dakota, producing about 4 million tons annually and has lignite reserves of an estimated 650 million tons. Two electric generating cooperatives, Minnkota Power and Square Butte, presently consume virtually all of BNI Coal’s production of lignite under cost-plus fixed fee coal supply agreements extending to December 31, 2037. (See Item 1. Business – Regulated Operations – Power Supply – Long-Term Purchased Power and Note 12. Commitments, Guarantees and Contingencies.) The mining process disturbs and reclaims between 200 and 250 acres per year. Laws require that the reclaimed land be at least as productive as it was prior to mining. As of December 31, 2014, BNI Coal had a $20.3 million asset reclamation obligation ($12.4 million at December 31, 2013) included in Other Non-Current Liabilities on our Consolidated Balance Sheet. These costs are included in the cost-plus fixed fee contract, for which an asset reclamation cost receivable was included in Other Non-Current Assets on our Consolidated Balance Sheet. The asset reclamation obligation is guaranteed by surety bonds and a letter of credit. (See Note 12. Commitments, Guarantees and Contingencies.)

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, sell the portfolio when opportunities arise and reinvest the proceeds in our 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 in the permitting 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. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook for more information on ALLETE Properties’ land holdings.

Seller Financing. ALLETE Properties occasionally provides seller financing to certain qualified buyers. At December 31, 2014, outstanding finance receivables were $1.2 million, net of reserves, with maturities through 2015. These finance receivables accrue interest at market-based rates and are collateralized by the financed properties.

Regulation. A substantial portion of our development properties in Florida are subject to federal, state and local regulations, and restrictions that may impose significant costs or limitations on our ability to develop the properties. Much of our property is vacant land and some is located in areas where development may affect the natural habitats of various protected wildlife species or in sensitive environmental areas such as wetlands.


ALLETE, Inc. 2014 Form 10-K
20


Investments and Other (Continued)

Non-Rate Base Generation

As of December 31, 2014, non-rate base generation consists of 29 MW of generation at Rapids Energy Center. In 2014, we sold 0.1 million MWh of non-rate base generation (0.1 million MWh in 2013 and 2012).
Non-Rate Base Power Supply
Unit No.
Year
Installed
Year
Acquired
Net
Capability (MW)
Rapids Energy Center (a)
 
 
 
 
in Grand Rapids, MN
 
 
 
 
Steam – Biomass (b)
6 & 7
1969, 1980
2000
28
Hydro – Conventional Run-of-River
4 & 5
1917, 1948
2000
1
(a)
The net generation is primarily dedicated to the needs of one customer.
(b)
Rapids Energy Center’s fuel supply is supplemented by coal.

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 expected future restrictive environmental requirements imposed 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 project power supply trends and impacts on customers.

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 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. All of Minnesota Power’s coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, baghouses and low NOX technologies. Under currently applicable environmental regulations, these facilities are substantially compliant with applicable emission requirements.

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 asserted 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 Boswell Unit 4’s 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 reached a settlement with the EPA regarding these NOVs and entered into a Consent Decree which was approved by the U.S. District Court for the District of Minnesota (Court) on September 29, 2014. The Consent Decree covers Minnesota Power’s Boswell, Laskin, Taconite Harbor, and Rapids Energy Centers. The Consent Decree provides for more stringent emissions limits at all affected units, the option of refueling, retrofits or retirements at some units, and the addition of 200 MW of wind energy. Minnesota Power is required to spend $4.2 million on environmental mitigation projects over the next five years. Under the terms of the Consent Decree, Minnesota Power also paid a $1.4 million civil penalty which was recognized as an expense in 2013. In 2014, the Company recorded an expense associated with the environmental mitigation projects.

ALLETE, Inc. 2014 Form 10-K
21


Environmental Matters (Continued)
Air (Continued)

Since 2005, the Company has, and will, invest more than $600 million to reduce sulfur dioxide, nitrogen oxide, mercury and particulate matters emissions at its thermal generation facilities, and between 2010 and 2014 placed in service nearly 500 MW of renewable wind energy, which fulfills certain obligations under the Consent Decree. In addition, Minnesota Power’s EnergyForward plan addresses many of the requirements included in the Consent Decree. Under the EnergyForward plan, Minnesota Power intends to: 1) retire Taconite Harbor Unit 3, 2) convert Laskin from coal to natural gas, and 3) install emission controls at Boswell Unit 4.

The Consent Decree further requires that, by no later than December 31, 2018, Boswell Units 1 and 2 must be retired, refueled, repowered, or emissions rerouted to an existing Boswell scrubber. Minnesota Power estimates that if the units are not retired, capital expenditures could range between $20 million and $40 million. We are evaluating our options with regard to Boswell Units 1 and 2 to comply with the Consent Decree and future anticipated environmental regulations. We are required to notify the EPA no later than December 31, 2016, whether we will retire, refuel, repower or reroute Boswell Units 1 and 2. We believe that future capital expenditures or costs to retire would likely be eligible for recovery in rates over time subject to regulatory approval in a rate proceeding.

Cross-State Air Pollution Rule (CSAPR). On April 29, 2014, the U.S. Supreme Court issued an opinion reversing an August 2012 U.S. Court of Appeals for the D.C. Circuit decision that had vacated the CSAPR. The EPA filed a motion with the U.S. Court of Appeals for the D.C. Circuit on June 26, 2014, to have the stay of CSAPR lifted and the CSAPR compliance deadlines tolled by three years. On October 23, 2014, the U.S. Court of Appeals for the D.C. Circuit granted the EPA's motion, allowing the first compliance period, Phase I, to begin on January 1, 2015, with Phase II beginning in 2017. 

CSAPR requires five states in the eastern half of the United States, including Minnesota, to significantly improve air quality by reducing power plant emissions that contribute to ozone or fine particulate pollution in other states. These states are required to make summertime NOx reductions under the CSAPR ozone season control program. CSAPR does not require installation of controls; rather it requires that facilities have sufficient allowances to cover their emissions on an annual basis. These allowances will be allocated to facilities from each state’s annual budget and can be bought and sold.

In December 2014, the EPA distributed the CSAPR allowances to CSAPR-subject units for the Phase I years (2015 and 2016). Phase II allowances (2017-2020) have not been distributed. Based on our initial accounting of the NOx and SO2 Phase I allowances already issued, and our review of the CSAPR Phase II allowances not yet issued, we currently expect projected generation levels and emission rates will be in compliance in both Phase I and Phase II.

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, built 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, 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.

Due to legal challenges at both the state and federal levels, there is currently no applicable compliance deadline for the Regional Haze Rule. As part of our 2013 Integrated Resource Plan, which was approved by the MPUC in November 2013, we plan to retire Taconite Harbor Unit 3 in the second quarter of 2015. We believe that the Taconite Harbor Unit 3 retirement will be accomplished before any compliance deadline takes effect.

ALLETE, Inc. 2014 Form 10-K
22


Environmental Matters (Continued)
Air (Continued)

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 in February 2012, addressing such emissions from coal-fired utility units greater than 25 MW. There are currently 187 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. Minnesota Power was notified by the MPCA that it has approved Minnesota Power’s request for an additional year extending the date of compliance for the Boswell Unit 4 environmental upgrade to April 1, 2016. Compliance at Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures of approximately $250 million through 2016, of which $145 million was spent through December 31, 2014. Boswell Unit 3 is also subject to the MATS rule; however, the emission reduction investments completed in 2009 at our Boswell Unit 3 generating unit substantially meet the requirements of the MATS rule. Our “EnergyForward” plan, which was approved as part of our 2013 Integrated Resource Plan by the MPUC in a November 2013 order, also includes the conversion of Laskin Units 1 and 2 to natural gas in 2015 to position the Company for MATS compliance. On January 9, 2014, the MPCA approved Minnesota Power’s application to extend the deadline for Taconite Harbor Unit 3 to comply with MATS to June 1, 2015, in order to align the Unit 3 retirement with MISO’s resource planning year.

Minnesota Mercury Emissions Reduction Act. In order to comply with the 2006 Minnesota Mercury Emissions Reduction Act, Minnesota Power must implement a mercury emissions reduction project for Boswell Unit 4 by December 31, 2018. The Boswell Unit 4 environmental upgrade discussed above, which is required to be completed by April 1, 2016 (see Mercury and Air Toxics Standards (MATS) Rule), will fulfill the requirements of the Minnesota Mercury Emissions Reduction Act.

EPA National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters. A final rule issued by the EPA for Industrial Boiler Maximum Achievable Control Technology (Industrial Boiler MACT) became effective in December 2012. Major existing sources have until January 31, 2016, to achieve compliance with the final rule. Minnesota Power’s Hibbard Renewable Energy Center and Rapids Energy Center are subject to this rule. We expect compliance to consist largely of adjustments to our operating practices; therefore costs for complying with the final rule are not expected to be material at this time.

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 NAAQS, the state is required to adopt plans describing how it will reduce emissions to attain the NAAQS. These state plans often include more stringent air emission limitations on sources of air pollutants than the NAAQS. Four NAAQS have either recently been revised or are currently proposed for revision, as described below.

Ozone NAAQS. The EPA has proposed to more stringently control emissions that result in ground level ozone. In January 2010, the EPA proposed to revise the 2008 eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. On November 25, 2014, the EPA proposed a 65 to 70 parts per billion (ppb) NAAQS for ground level ozone. The EPA is proposing to update both the primary ozone standard and the secondary standard. Both standards would be 8-hour standards set within a range of 65 to 70 ppb. The EPA is also seeking comment on levels for the primary standard as low as 60 ppb. The EPA has announced it will accept comments on all aspects of the proposal, including retaining the existing standard. A final rule is expected to be issued in the fourth quarter of 2015. The costs for complying with the final ozone NAAQS cannot be estimated at this time.

ALLETE, Inc. 2014 Form 10-K
23


Environmental Matters (Continued)
Proposed and Finalized National Ambient Air Quality Standards (NAAQS) (Continued)

Particulate Matter NAAQS. The EPA finalized the Particulate Matter NAAQS in September 2006. Since then, the EPA has established more stringent 24-hour and annual average fine particulate matter (PM2.5) standards; the 24-hour coarse particulate matter standard has remained unchanged. In December 2012, the EPA issued a final rule implementing a more stringent annual PM2.5 standard, while retaining the current 24-hour PM2.5 standard. To implement the new annual PM2.5 standard, the EPA is also revising aspects of relevant monitoring, designation and permitting requirements. New projects and permits must comply with the new standard, which is generally demonstrated by modeling at the facility level.

Under the final rule, states will be responsible for additional PM2.5 monitoring, which will likely be accomplished by relocating or repurposing existing monitors. The EPA asked states to submit attainment designations by December 2013, based on already available monitoring data. The EPA issued designations of 2012 fine particulate attainment status on December 18, 2014. Minnesota retained attainment status; however, Minnesota sources may ultimately be required to reduce their emissions to assist with attainment in neighboring states. Accordingly, the costs for complying with the final Particulate Matter NAAQS cannot be estimated at this time.

SO2 and NO2 NAAQS. During 2010, the EPA finalized one-hour NAAQS for SO2 and NO2. Ambient monitoring data indicates that Minnesota will likely be in compliance with these new standards; however, the one-hour SO2 NAAQS also may require the EPA to evaluate modeling data to determine attainment. In April 2012, the MPCA notified Minnesota Power that modeling had been suspended as a result of the EPA’s announcement that the SIP submittals would not require modeling demonstrations for states, such as Minnesota, where ambient monitors indicate compliance with the new standard. The EPA notified states that their infrastructure SIPs for maintaining attainment of the standard were required to be submitted to the EPA for approval by June 2013. However, the State of Minnesota has delayed completing the documents pending EPA guidance to states for preparing the SIP submittal. The MPCA has indicated it will communicate with affected sources once it has more information on how the state will meet the EPA’s SIP requirements. Guidance was expected in 2013 but has been delayed. Currently, compliance with these new NAAQS is expected to be required as early as 2017. The costs for complying with the final standards cannot be estimated at this time.

In July 2014, the Fond du Lac Band of Lake Superior Chippewa (Band) announced that it had petitioned the EPA to redesignate its reservation air shed from Class II to Class I air quality pursuant to Section 164(c) of the Clean Air Act. The Band does not currently possess authority to directly regulate air quality. Federal Class I air shed status, if granted, would allow the Band to impose more stringent Clean Air Act protections within the boundaries of the Fond du Lac reservation, including the reservation air shed, near Cloquet, Minnesota. Five other reservations across the U.S. have applied for and received Class I status. A public hearing was held by the Band on October 2, 2014, and the public comment period on the petition expired on November 10, 2014. The Band is now preparing responses to the comments after which the Band will make a formal submittal request to the EPA. There is no deadline for the approval, denial, or modification of the request by the EPA. The Company has requested additional clarification from the Band and the MPCA on the final regulatory structure that may arise from a Class I redesignation. We are unable to determine the impact of potential Class I status on the Company’s operations at this time. 

Climate Change. The scientific community generally accepts that emissions of GHG are linked to global climate change which creates physical and financial risks. Physical risks could include, but are not limited to: increased or decreased precipitation and water levels in lakes and rivers; increased temperatures; and changes in the intensity and frequency of extreme weather events. These all have the potential to affect the Company’s business and operations. We are addressing climate change by taking the following steps that also ensure reliable and environmentally compliant generation resources to meet our customers’ requirements:

Expanding our renewable energy supply;
Providing energy conservation initiatives for our customers and engaging in other demand side efforts;
Improving efficiency of our energy generating facilities;
Supporting research of technologies to reduce carbon emissions from generation facilities and carbon sequestration efforts; and
Evaluating and developing less carbon intensive future generating assets such as efficient and flexible natural gas generating facilities.

President Obama’s Climate Action Plan. In June 2013, President Obama announced a Climate Action Plan (CAP) that calls for implementation of measures that reduce GHG emissions in the U.S., emphasizing means such as expanded deployment of renewable energy resources, energy and resource conservation, energy efficiency improvements and a shift to fuel sources that have lower emissions. Certain portions of the CAP directly address electric utility GHG emissions.


ALLETE, Inc. 2014 Form 10-K
24


Environmental Matters (Continued)
Climate Change (Continued)

EPA Regulation of GHG Emissions. In May 2010, the EPA issued the Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). The Tailoring Rule establishes permitting thresholds required to address GHG emissions for new facilities, existing facilities that undergo major modifications and 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. However, GHG requirements are likely to be added to our existing Title V operating permits by the MPCA as these permits are renewed or amended.

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 Best Available Control Technology (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 that these control technologies could be determined to be BACT on a project-by-project basis.

In June 2014, the U.S. Supreme Court invalidated the aspect of the Tailoring Rule that established lower permitting thresholds for GHG than for other pollutants subject to PSD. However, the court also upheld the EPA’s power to require BACT for GHG from sources already subject to regulation under PSD. Minnesota Power’s coal-fired generating facilities are already subject to regulation under PSD, so we anticipate that ultimately PSD for GHG will apply to our facilities, but the timing of the promulgation of a replacement for the Tailoring Rule is uncertain. The PSD applies to existing facilities only when they undertake a major modification that increases emissions. At this time, we are unable to predict the compliance costs that we might incur.

In March 2012, the EPA announced a proposed rule to apply CO2 emission New Source Performance Standards (NSPS), under Section 111(b) of the Clean Air Act, to new fossil fuel-fired electric generating units. The proposed NSPS would have applied only to new or re-powered units. Based on the volume of comments received, the EPA announced its intent to re-propose the rule. In September 2013, the EPA retracted its March 2012 proposal and announced the release of a revised NSPS for new or re-powered utility CO2 emissions.

In June 2014, the EPA announced a proposed rule under Section 111(d) of the Clean Air Act for existing power plants entitled “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units” (CPP). The EPA is expected to finalize such rules by the summer of 2015. In the CPP, the EPA proposes to set state-specific goals for CO2 emissions from the power sector. The EPA maintains such goals are achievable if a state undertakes a combination of measures across its power sector that constitute the EPA’s guideline for a Best System of Emission Reductions (BSER).

The EPA proposed that BSER is comprised of four building blocks: 1) improved fossil fuel power plant efficiency, 2) increased reliance on low-emitting power sources by generating more electricity from existing natural gas combined cycle units, 3) building more or preserving existing zero- and low-emitting power sources, including renewable and nuclear energy, and 4) more efficient electricity use by consumers.

The EPA then established state goals, expressed as a carbon intensity target in CO2 tons per megawatt hour, by estimating the achievability of the building blocks in each state. Using 2012 emissions data, the EPA derived interim goals for states to be met over the years 2020-2029, as well as a final goal to be met in 2030 and thereafter. Under the CPP, each state would be required to develop a state implementation plan by June 30, 2016. Minnesota Power is currently evaluating the CPP as it relates to the State of Minnesota and its potential impact on the Company. We submitted comments on the CPP to the EPA.

Minnesota has already initiated several measures consistent with those called for under the CAP and CPP. Minnesota Power is implementing its “EnergyForward” strategic plan that provides for significant emission reductions and diversifying its electricity generation mix to include more renewable and natural gas energy. (See Regulated Operations - EnergyForward.)

We are unable to predict the GHG emission compliance costs we might incur; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.


ALLETE, Inc. 2014 Form 10-K
25


Environmental Matters (Continued)
Climate Change (Continued)

Minnesota’s Next Generation Energy Act of 2007. On April 14, 2014, a U.S. District Court for the District of Minnesota ruled that part of Minnesota’s Next Generation Energy Act of 2007 violated the Commerce Clause of the U.S. Constitution. The portions of the law which were ruled unconstitutional prohibited the importation of power from a new CO2-producing facility outside of Minnesota and prohibited the entry into new long-term power purchase agreements that would increase CO2 emissions in Minnesota. The State of Minnesota appealed the decision to the U.S. Court of Appeals for the Eighth Circuit on May 16, 2014.

Water. The Clean Water Act requires NPDES permits 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.

Clean Water Act - Aquatic Organisms. In April 2011, the EPA announced 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, and have a design intake flow of greater than 2 million gallons per day, to limit the number of aquatic organisms that are impacted by the facility’s intake structure or cooling system. The Section 316(b) rule was published in the Federal Register on August 15, 2014, with an effective date of October 14, 2014. The Section 316(b) standards will be implemented through NPDES permits issued to the covered facilities with compliance timing dependent on individual NPDES renewal schedules. No NPDEC permits have been re-issued containing 316(b) requirements since the final rule was published, so at this time we are unable to determine the final cost of compliance; however, our preliminary assessment suggests costs of compliance could be up to approximately $15 million. We would seek recovery of any additional costs through a general rate case.

Steam Electric Power Generating Effluent Guidelines. In April 2013, the EPA announced proposed revisions to the federal effluent guidelines for steam electric power generating stations under the Clean Water Act. The proposed revisions would set limits on the level of toxic materials in wastewater discharged from seven waste streams: flue gas desulfurization wastewater, fly ash transport water, bottom ash transport water, combustion residual leachate, non-chemical metal cleaning wastes, coal gasification wastewater, and wastewater from flue gas mercury control systems. As part of this proposed rulemaking, the EPA is considering imposing rules to address “legacy” wastewater currently residing in ponds as well as rules to impose stringent best management practices for discharges from active coal combustion residual surface impoundments. The EPA’s proposed rulemaking would base effluent limitations on what can be achieved by available technologies. The proposed rule was published in the Federal Register in June 2013, and public comments were due in September 2013. The EPA is expected to issue the final rule by September 30, 2015. Compliance with the final rule, as proposed, would be required no later than July 1, 2022. We are reviewing the proposed rule and evaluating its potential impacts on our operations. We are unable to predict the compliance costs we might incur related to these or other potential future water discharge regulations; however, the costs could be material, including costs associated with retrofits for bottom ash handling, pond dewatering, pond closure, and wastewater treatment and/or reuse. We would seek recovery of any additional costs through cost recovery riders or in a general rate case

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 coal-fired 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 (CCR) generated by the electric utility sector. The proposal sought comments on three general regulatory schemes for coal ash under Subtitle D of Resource Conservation and Recovery Act (RCRA) (non-hazardous) or Subtitle C of RCRA (hazardous).



ALLETE, Inc. 2014 Form 10-K
26


Environmental Matters (Continued)
Solid and Hazardous Waste (Continued)

The EPA issued the final CCR rule on December 19, 2014 under Subtitle D (non-hazardous) of RCRA. The rule includes additional requirements for new landfill and impoundment construction as well as closure activities related to certain existing impoundments. The final rule also includes provisions that could incentivize early closure of existing impoundments within a three-year window. Costs of compliance, primarily for Boswell and Laskin, could be up to approximately $130 million. The Company continues to work on minimizing costs on behalf of customers through evaluation of beneficial re-use and recycling of CCR and CCR-related waters. We would seek recovery of any additional costs through a general rate case.

Employees

At December 31, 2014, ALLETE had 1,625 employees, of which 1,581 were full-time.

Minnesota Power and SWL&P have an aggregate of 586 employees who are members of the International Brotherhood of Electrical Workers (IBEW) Local 31. The current labor agreements with IBEW Local 31 expire on January 31, 2018.

BNI Coal has 172 employees, of which 125 are members of IBEW Local 1593. The current labor agreement with IBEW Local 1593 expires on March 31, 2019.

Availability of Information

ALLETE makes its SEC filings, including its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(e) or 15(d) of the Securities Exchange Act of 1934, available free of charge on ALLETE’s website, www.allete.com, as soon as reasonably practicable after they are electronically filed with or furnished to the SEC.



ALLETE, Inc. 2014 Form 10-K
27


Executive Officers of the Registrant

As of February 17, 2015, these are the executive officers of ALLETE:
Executive Officers
Initial Effective Date
 
 
Alan R. Hodnik, Age 55
 
Chairman, President and Chief Executive Officer
May 10, 2011
President and Chief Executive Officer
May 1, 2010
President
May 1, 2009
 
 
Robert J. Adams, Age 52
 
Vice President – Energy-Centric Businesses and Chief Risk Officer
June 23, 2014
Vice President – Business Development and Chief Risk Officer
May 13, 2008
 
 
Deborah A. Amberg, Age 49
 
Senior Vice President, General Counsel and Secretary
January 1, 2006
 
 
Steven Q. DeVinck, Age 55
 
Senior Vice President and Chief Financial Officer
March 3, 2014
Controller and Vice President – Business Support
December 5, 2009
 
 
David J. McMillan, Age 53
 
Senior Vice President – External Affairs
January 1, 2012
Senior Vice President – Marketing, Regulatory and Public Affairs
January 1, 2006
Executive Vice President – Minnesota Power
January 1, 2006
 
 
Steven W. Morris, Age 53
 
Controller
March 3, 2014
 
 
Donald W. Stellmaker, Age 57
 
Vice President and Corporate Treasurer
August 19, 2011
Treasurer
July 24, 2004

All of the executive officers have been employed by us for more than five years in executive or management positions. Prior to election to the position listed above, Mr. Morris held the following positions with the Company during the preceding five years: Director - Accounting; Director - Internal Audit.

There are no family relationships between any of the executive officers. All officers and directors are elected or appointed annually.

The present term of office of the executive officers listed above extends to the first meeting of our Board of Directors after the next annual meeting of shareholders. Both meetings are scheduled for May 12, 2015.

ALLETE, Inc. 2014 Form 10-K
28


Item 1A. Risk Factors

The risks and uncertainties discussed below could materially affect our business, financial position and results of operations and should be carefully considered by stakeholders. The risks and uncertainties in this section are not the only ones we face; additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations, financial position, results of operations and cash flows. Accordingly, the risks described below should be carefully considered together with other information set forth in this report and in future reports that are filed with the SEC.

Our results of operations could be negatively impacted if our Large Power Customers experience an economic downturn, incur work stoppages, fail to compete effectively in the economy or experience decreased demand for their product.

Minnesota Power’s 10 Large Power Customers accounted for 28 percent of our 2014 consolidated operating revenue (31 percent in 2013; 33 percent in 2012), of which one of these customers accounted for 10.8 percent of consolidated revenue in 2014 (12.0 percent in 2013; 12.3 percent in 2012). These customers are involved in cyclical industries that by their nature are adversely impacted by economic downturns and are subject to strong competition in the marketplace. Many of our Large Power Customers also have unionized workforces which put them at risk for work stoppages. In addition, the North American paper and pulp industry also faces declining demand due to the impact of electronic substitution for print and changing customer needs.

Accordingly, if our customers experience an economic downturn, incur a work stoppage (including strikes, lock-outs or other events), fail to compete effectively in the economy, or experience decreased demand for their product, there could be material adverse effects on their operations and, consequently, this could have a negative impact on our results of operations if we are unable to remarket at similar prices the energy that would otherwise have been sold to such Large Power Customers.

Our utility operations are subject to an extensive legal and regulatory framework under federal and state laws as well as regulations imposed by other organizations that may have a negative impact on our business and results of operations.

We are subject to an extensive legal and regulatory framework imposed under federal and state law including regulations administered by the FERC, the MPUC, the MPCA, the PSCW, the NDPSC and the EPA as well as regulations administered by other organizations including the NERC. These laws and regulations relate to allowed rates of return, capital structure, financings, rate and cost structure, acquisition and disposal of assets and facilities, construction and operation of generation, transmission and distribution facilities (including the ongoing maintenance and reliable operation of such facilities), recovery of purchased power costs and capital investments, approval of integrated resource plans and present or prospective wholesale and retail competition, among other things. Energy policy initiatives at the state or federal level could increase incentives for distributed generation, municipal utility ownership, or local initiatives could introduce generation or distribution requirements, that could change the current integrated utility model. Our transmission systems and electric generation facilities are subject to the NERC mandatory reliability standards, including cybersecurity standards. Compliance with these standards may lead to increased operating costs and capital expenditures. If it was determined that we were not in compliance with these mandatory reliability standards or other statutes, rules and orders, we could incur substantial monetary penalties and other sanctions, which could adversely affect our results of operations.

These laws and regulations significantly influence our operations and may affect our ability to recover costs from our customers. We are required to have numerous permits, licenses, approvals and certificates from the agencies and other organizations that regulate our business. We believe we have obtained the necessary permits, licenses, approvals and certificates for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies and other organizations. Changes in regulations or the imposition of additional regulations could have a material adverse impact on our results of operations.

Our ability to obtain rate adjustments to maintain reasonable rates of return depends upon regulatory action under applicable statutes and regulations, and we cannot provide assurance that rate adjustments will be obtained or reasonable authorized rates of return on capital will be earned. Minnesota Power and SWL&P, from time to time, file rate cases with, or otherwise seek cost recovery authorization from, federal and state regulatory authorities. If Minnesota Power and SWL&P do not receive an adequate amount of rate relief in rate cases, including if rates are reduced, if increased rates are not approved on a timely basis or costs are otherwise unable to be recovered through rates, or if cost recovery is not granted at the requested level, we may experience a material adverse impact on our financial position, results of operations and cash flows. We are unable to predict the impact on our business and results of operations from future legislation or regulatory activities of any of these agencies or organizations.


ALLETE, Inc. 2014 Form 10-K
29


Item 1A. Risk Factors (Continued)

Our operations pose certain environmental risks that could materially adversely affect our financial position and results of operations, including effects of environmental laws and regulations, physical risks associated with climate change and initiatives designed to reduce the impact of GHG emissions.

We are subject to extensive environmental laws and regulations affecting many aspects of our present and future operations, including air quality, water quality and usage, waste management, reclamation, hazardous wastes, avian mortality and natural resources. These laws and regulations can result in increased capital, environmental emission allowance trading, operating and other costs, as a result of compliance, remediation, containment and monitoring obligations, particularly with regard to laws relating to power plant emissions, coal ash, water discharge and wind generation facilities.

These laws and regulations could restrict the output of some existing facilities, limit the use of some fuels in the production of electricity, require the installation of additional pollution control equipment, require participation in environmental emission allowance trading, and/or lead to other environmental considerations and costs, which could have a material adverse impact on our business, operations and results of operations.

These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Both governmental authorities and private parties may seek to enforce applicable environmental laws and regulations. We cannot predict the financial or operational outcome of any related litigation that may arise.

Existing environmental regulations may be revised and new regulations seeking to protect the environment may be adopted or become applicable to us. Revised or additional regulations which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our results of operations.

The scientific community generally accepts that emissions of GHG are linked to global climate change. Physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, could affect some, or all, of our operations. Severe weather or other natural disasters could be destructive, which could result in increased costs. An extreme weather event within our utility service areas can also directly affect our capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. These all have the potential to materially adversely affect our business and operations.

Proposals for voluntary initiatives to reduce GHGs such as CO2, a by-product of burning fossil fuels, have been discussed within Minnesota, among a group of Midwestern states that includes Minnesota and in the United States Congress. In June 2013, President Obama announced a Climate Action Plan (CAP) that calls for implementation of measures that reduce GHG emissions in the U.S., emphasizing means such as expanded deployment of renewable energy resources, energy and resource conservation, energy efficiency improvements and a shift to fuel sources that have lower emissions. Certain portions of the CAP directly address electric utility GHG emissions. The implementation of the CAP could have a material impact on our results of operations if additional capital expenditures and operating costs are required and if those costs are not fully recovered from customers.

In June 2014, the EPA announced a proposed rule under Section 111(d) of the Clean Air Act for existing power plants (CPP). In the CPP, the EPA proposes to set state-specific rate-based goals for CO2 emissions from the power sector that the EPA maintains are achievable if a state undertakes a combination of measures across its power sector that constitute the EPA’s guideline for a Best System of Emission Reductions. Using 2012 emissions data, the EPA derived interim goals for states to be met over the years 2020-2029, as well as a final goal to be met in 2030 and thereafter. Under the CPP, each state would be required to develop a state implementation plan by June 30, 2016. The implementation of the CPP could have a material impact on our results of operations if additional capital expenditures and operating costs are required and if those costs are not fully recovered from customers.

There is significant uncertainty regarding whether new laws or regulations will be adopted to reduce GHGs and what effect any such laws or regulations would have on us. In 2014, coal was the primary fuel source for 85 percent of the energy produced by our generating facilities. Future limits on GHG emissions would likely require us to incur significant increases in capital expenditures and operating costs, which if significant, could result in the closure of certain coal-fired energy centers, impairment of assets, or otherwise materially adversely affect our results of operations, particularly if implementation costs are not fully recoverable from customers.

ALLETE, Inc. 2014 Form 10-K
30


Item 1A. Risk Factors (Continued)

We cannot predict the amount or timing of all future expenditures related to environmental matters because of uncertainty as to applicable regulations or requirements. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties. Violations of certain environmental statutes, rules and regulations could expose ALLETE to third party disputes and potentially significant monetary penalties, as well as other sanctions for non-compliance.

We rely on access to financing sources and capital markets. If we do not have access to sufficient capital in the amounts and at the times needed, our ability to execute our business plans, make capital expenditures or pursue other strategic actions that we may otherwise rely on for future growth could be materially adversely affected.

We rely on access to financing sources and capital markets as sources of liquidity for capital requirements not satisfied by our cash flow from operations. If we are not able to access capital on satisfactory terms, or at all, the ability to maintain our business or to implement our business plans may be materially adversely affected. Market disruptions or a downgrade of our credit ratings may increase the cost of borrowing or materially adversely affect our ability to access capital markets. Such disruptions could include a significant economic downturn, the financial distress of non-affiliated electric utility companies or financial services companies, a deterioration in capital market conditions, or volatility in commodity prices.

The operation and maintenance of our electric generation and transmission facilities are subject to operational risks that could materially adversely affect our financial position, results of operations and cash flows.

The operation of generating facilities involves many risks, including start-up operations risks, breakdown or failure of facilities, the dependence on a specific fuel source, inadequate fuel supply, or availability of fuel transportation, or the impact of unusual or adverse weather conditions or other natural events, as well as the risk of performance below expected levels of output or efficiency. A significant portion of our facilities were constructed many years ago. In particular, older generating equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to continue operating at peak efficiency. Generation and transmission facilities and equipment are also likely to require periodic upgrades and improvements due to changing environmental standards and technological advances. We could be subject to costs associated with any unexpected failure to produce and/or deliver power, including failure caused by breakdown or forced outage, as well as repairing damage to facilities due to storms, natural disasters, wars, sabotage, terrorist acts and other catastrophic events.

Our ability to successfully and timely complete capital improvements to existing facilities or other capital projects is contingent upon many variables.

We are, or may be, engaged in significant capital improvements to its existing electric generation facilities, including the installation of pollution control equipment and the conversion of certain coal-fired electric generation facilities to natural gas. We are also engaged in development and/or construction of new wind and transmission facilities. Should any such efforts be unsuccessful or not completed in a timely manner, we could be subject to additional costs or impairments which could have a material adverse impact on our financial position and results of operation.

Our electrical generating operations may not have access to adequate and reliable transmission and distribution facilities necessary to deliver electricity to our customers.

We depend on our own transmission and distribution facilities, and facilities owned by other utilities, to deliver the electricity produced and sold to our customers, and to other energy suppliers. If transmission capacity is inadequate, our ability to sell and deliver electricity may be limited. We may have to forgo sales or may have to buy more expensive wholesale electricity that is available in the capacity-constrained area. In addition, any infrastructure failure that interrupts or impairs delivery of electricity to our customers could negatively impact the satisfaction of our customers, which could have a material impact on our business, operations or results of operations.


ALLETE, Inc. 2014 Form 10-K
31


Item 1A. Risk Factors (Continued)

The price of electricity and fuel may be volatile.

Volatility in market prices for electricity and fuel could materially adversely impact our financial position and results of operations and may result from:

severe or unexpected weather conditions and natural disasters;
seasonality;
changes in electricity usage;
transmission or transportation constraints, inoperability or inefficiencies;
availability of competitively priced alternative energy sources;
changes in supply and demand for energy;
changes in power production capacity;
outages at our generating facilities or those of our competitors;
availability of fuel transportation;
changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products;
wars, sabotage, terrorist acts or other catastrophic events; and
federal, state, local and foreign energy, environmental, or other regulation and legislation.

Since fluctuations in fuel expense related to our regulated utility operations are passed on to customers through our fuel clause, risk of volatility in market prices for fuel and electricity primarily impacts our sales to Other Power Suppliers.

The inability to attract and retain a qualified workforce including, but not limited to, executive officers, key employees and employees with specialized skills, could have a material adverse effect on our operations.

The success of our business heavily depends on the leadership of our executive officers and key employees to implement our business strategy. The inability to maintain a qualified workforce including, but not limited to, executive officers, key employees and employees with specialized skills, may negatively affect our ability to service our existing or new customers, or successfully manage our business or achieve our business objectives. Personnel costs may increase due to competitive pressures or terms of collective bargaining agreements with union employees. We believe we have good relations with our members of IBEW Local 31 and IBEW Local 1593, and have contracts in place through January 31, 2018, and March 31, 2019, respectively.

Market performance and other changes could decrease the value of pension and postretirement benefit plan assets, which may result in significant additional funding requirements and increased annual expenses.

The performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations under our pension and postretirement benefit plans. We have significant obligations to these plans and the trusts hold significant assets. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected rates of return. A decline in the market value of the pension and postretirement benefit plan assets would increase the funding requirements under our benefit plans if asset returns do not recover. Additionally, our pension and postretirement benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit expense and funding requirements. Our pension and postretirement benefit plan costs are generally recoverable in our electric rates as allowed by our regulators. However, there is no certainty that regulators will continue to allow recovery of these rising costs in the future.

Emerging technologies may materially adversely affect our business operations.

While the pace of technology development has been increasing, the basic structure of energy production, sale and delivery upon which our business model is based has remained substantially unchanged. The development of new commercially viable technology in areas such as distributed generation, energy storage and energy conservation could significantly decrease demand for our current products and services.


ALLETE, Inc. 2014 Form 10-K
32


Item 1A. Risk Factors (Continued)

We may be vulnerable to acts of terrorism or cyber attacks.

Our generation plants, fuel storage facilities, and transmission and distribution facilities may be targets of terrorist activities, including cybersecurity attacks, which could result in the disruption of our ability to produce or distribute some portion of our energy products. We could be subject to computer viruses, terrorism, theft and sabotage, which may also disrupt our operations and/or materially adversely impact our results of operations. We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Our technology systems may be vulnerable to disability, failures or unauthorized access due to hacking, viruses, acts of war or terrorism and other causes. If our technology systems were to fail or be breached and we were unable to recover in a timely manner, we may be unable to fulfill critical business functions and sensitive, confidential and other data could be compromised, which could have a material adverse effect on our financial position, results of operations and cash flows.

The inability to successfully manage and grow our Energy Infrastructure and Related Services businesses could materially adversely affect our results of operations.

Our Energy Infrastructure and Related Services businesses consist of ALLETE Clean Energy, U.S. Water Services and BNI Coal. If we are unable to successfully integrate the U.S. Water Services’ business we acquired in February 2015, this could materially adversely affect our results of operations. U.S. Water Services principally relies upon recurring revenues from a diverse mix of industrial customers. If U.S. Water Services is unable to retain its existing customers and to add new industrial customers, this would prevent us from profitably operating this business and prevent us from achieving our future growth expectations.

In addition, ALLETE Clean Energy’s wind facilities are parties to long-term PPAs which expire prior to the end of the estimated useful lives of the facilities. If there is not a market for this energy subsequent to the expiration of the PPAs, this could adversely affect our results of operations.

The results from any acquisitions of assets or businesses made by us, or strategic investments that we may make, may not achieve the results that we expect or seek and may materially adversely affect our financial position and results of operations.

Acquisitions are subject to uncertainties. If we are unable to successfully manage future acquisitions or strategic investments, this could have a material adverse impact on our results of operations. Our actual results may also differ from our expectations due to factors such as the ability to obtain timely regulatory or governmental approvals, integration and operational issues and the ability to retain management and other key personnel.

We may not be able to successfully implement our strategic objectives of growing load at our utilities if current or potential industrial or municipal customers are unable to successfully implement expansion plans, including the inability to obtain necessary governmental permits.

As part of our long-term strategy, we pursue new wholesale and retail loads in and around our service territory. Currently, there are several companies in northeastern Minnesota that are in the process of developing natural resource-based projects that represent long-term growth potential and load diversity for Minnesota Power. These projects may include construction of new facilities and restarts of old facilities, both of which require permitting and/or approvals to be obtained before the projects can be successfully implemented. If a project does not obtain any necessary governmental (including environmental) permits and approvals, our long-term strategy and thus our results of operations could be materially adversely impacted. Furthermore, even if the necessary permits and approvals are obtained, our long-term strategy could be materially adversely impacted if these customers are unable to successfully implement expansion plans.

Real estate market conditions where our Florida real estate investment is located may affect our strategy to sell our Florida real estate.

We intend to sell our Florida land assets when opportunities arise. However, adverse market conditions could impact our future operations, which could result in little to no sales while still incurring operating expenses such as community development district assessments and property taxes, as well as continued annual net operating losses at ALLETE Properties. Furthermore, weak market conditions could put the properties at risk for impairment which could materially adversely impact our results of operations.



ALLETE, Inc. 2014 Form 10-K
33


Item 1B. Unresolved Staff Comments

None.


Item 2. Properties

A discussion of our properties is included in Item 1. Business and is incorporated by reference herein.


Item 3. Legal Proceedings

A discussion of material regulatory proceedings is included in Item 1. Business and is incorporated by reference herein.

Notice of Potential Clean Air Act Citizen Lawsuit. In July 2013, the Sierra Club submitted to Minnesota Power a notice of intent to file a citizen suit under the Clean Air Act, which it supplemented in March 2014. This notice of intent alleged violations of opacity and other permit requirements at our Boswell, Laskin, and Taconite Harbor energy centers. Minnesota Power intends to vigorously defend any lawsuit that may be filed by the Sierra Club. We are unable to predict the outcome of this matter. Accordingly, an accrual related to any damages that may result from the notice of intent has not been recorded as of December 31, 2014, because a potential loss is not currently probable or reasonably estimable.

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, and compliance with regulations, rate base and cost of service issues, among other things. We do not expect the outcome of these matters to have a material effect on our financial position, results of operations or cash flows.


Item 4. Mine Safety Disclosures

The Dodd-Frank Wall Street Reform and Consumer Protection Act (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). Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Act and this Item are included in Exhibit 95 to this Form 10-K.


Part II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is listed on the NYSE under the symbol ALE. We have paid dividends, without interruption, on our common stock since 1948. A quarterly dividend of $0.505 per share on our common stock is payable on March 1, 2015, to the shareholders of record on February 16, 2015. The timing and amount of future dividends will depend upon earnings, cash requirements, the financial condition of the Company, applicable government regulations and other factors deemed relevant by the ALLETE Board of Directors.

The following table shows dividends declared per share, and the high and low prices of our common stock for the periods indicated as reported by the NYSE:
 
 
2014
 
 
2013
 
 
Price Range
Dividends
Price Range
Dividends
Quarter
High
Low
Declared
High
Low
Declared
First
$52.73
$47.96

$0.49

$49.50
$41.39

$0.475

Second
$52.54
$47.51
0.49

$52.25
$46.85
0.475

Third
$51.56
$44.39
0.49

$54.14
$45.78
0.475

Fourth
$57.97
$44.19
0.49

$51.72
$47.48
0.475

Annual Total
 
 

$1.96

 
 

$1.90


At February 1, 2015, there were approximately 25,000 common stock shareholders of record.

ALLETE, Inc. 2014 Form 10-K
34


Item 6. Selected Financial Data

 
2014

2013

2012

2011

2010

Millions
 
 
 
 
 
Operating Revenue

$1,136.8


$1,018.4


$961.2


$928.2


$907.0

Operating Expenses
948.0

864.3

806.0

778.2

771.2

Net Income
125.5

104.7

97.1

93.6

74.8

Less: Non-Controlling Interest in Subsidiaries (a)
0.7



(0.2
)
(0.5
)
Net Income Attributable to ALLETE

$124.8


$104.7


$97.1


$93.8


$75.3

Common Stock Dividends

$83.8


$75.2


$69.1


$62.1


$60.8

Earnings Retained in Business

$41.0


$29.5


$28.0


$31.7


$14.5

Shares Outstanding – Millions
 
 
 
 
 
Year-End
45.9

41.4

39.4

37.5

35.8

Average (b)
 
 
 
 
 
Basic
42.9

39.7

37.6

35.3

34.2

Diluted
43.1

39.8

37.6

35.4

34.3

Diluted Earnings Per Share

$2.90


$2.63


$2.58


$2.65


$2.19

Total Assets

$4,360.8


$3,476.8


$3,253.4


$2,876.0


$2,609.1

Long-Term Debt

$1,272.8


$1,083.0


$933.6


$857.9


$771.6

Return on Common Equity
8.6
%
8.3
%
8.6
%
9.1
%
7.8
%
Common Equity Ratio
54
%
55
%
54
%
56
%
56
%
Dividends Declared per Common Share

$1.96


$1.90


$1.84


$1.78


$1.76

Dividend Payout Ratio
68
%
72
%
71
%
67
%
80
%
Book Value Per Share at Year-End

$35.04


$32.43


$30.50


$28.77


$27.25

Capital Expenditures by Segment
 
 
 
 
 
Regulated Operations

$583.5


$326.3


$418.2


$228.0


$256.4

Investments and Other
20.8

13.2

14.0

18.8

3.6

Total Capital Expenditures

$604.3


$339.5


$432.2


$246.8


$260.0

(a)
The 2014 non-controlling interest in subsidiaries relates to the January 2014 acquisition made by ALLETE Clean Energy. (See Note 7. Acquisitions.) In 2011, the ALLETE Properties non-controlling interest was purchased.
(b)
Excludes unallocated ESOP shares.


ALLETE, Inc. 2014 Form 10-K
35


Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with our consolidated financial statements and notes to those statements and the other financial information appearing elsewhere in this report. In addition to historical information, the following discussion and other parts of this report contain forward-looking information that involves risks and uncertainties. Readers are cautioned that forward-looking statements should be read in conjunction with our disclosures in this Form 10-K under the headings: “Forward-Looking Statements” located on page 6 and “Risk Factors” located in Item 1A. The risks and uncertainties described in this Form 10-K are not the only ones facing the 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 risks set forth in this Form 10-K are realized.

Overview

Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 144,000 retail customers. Minnesota Power also has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a customer of Minnesota Power. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 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. (See Item 1. Business – Regulated Operations – Regulatory Matters.)

Investments and Other is comprised primarily of our Energy Infrastructure and Related Services businesses; ALLETE Clean Energy, our business which acquired four wind energy facilities in 2014 and is developing a wind facility to be sold in 2015, and BNI Coal, our coal mining operations in North Dakota. Investments and Other also includes ALLETE Properties, our Florida real estate investment, and other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,000 acres of land in Minnesota, and earnings on cash and investments. Our Energy Infrastructure and Related Services businesses will also include U.S. Water Services, which we acquired in February 2015.

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2014, 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.

2014 Financial Overview

The following net income discussion summarizes a comparison of the year ended December 31, 2014, to the year ended December 31, 2013.

Net income attributable to ALLETE for 2014 was $124.8 million, or $2.90 per diluted share, compared to $104.7 million, or $2.63 per diluted share, for 2013. Net income for 2014 reflected a $1.4 million after-tax expense, or $0.03 per share, of acquisition costs for ALLETE Clean Energy’s wind energy facilities acquisition which closed in January 2014. (See Note 7. Acquisitions.) In addition, net income for 2014 reflected a $2.5 million after-tax expense, or $0.06 per share, reflecting a liability associated with environmental mitigation projects required as part of the EPA NOV Consent Decree settlement. (See Note 12. Commitments, Guarantees and Contingencies.) Net income for 2014 reflected higher net income at Minnesota Power and ALLETE Clean Energy. Earnings per share dilution was $0.23 due to additional shares of common stock outstanding as of December 31, 2014. (See Note 13. Common Stock and Earnings Per Share.)

Regulated Operations net income attributable to ALLETE was $124.4 million in 2014, compared to $104.9 million in 2013. Net income for 2014 reflected a $2.5 million after-tax expense, or $0.06 per share, reflecting a liability associated with environmental mitigation projects required as part of the EPA NOV Consent Decree settlement. Net income for 2014 reflected higher net income at Minnesota Power primarily due to higher cost recovery rider revenue and production tax credits, and higher power marketing sales as the Square Butte resale agreement with Minnkota Power commenced June 1, 2014. These increases were partially offset by higher operating and maintenance, depreciation, and interest expenses.

Investments and Other reflected net income attributable to ALLETE of $0.4 million in 2014, compared to a net loss of $0.2 million in 2013. Net income in 2014 reflected a $1.4 million after-tax expense, or $0.03 per share, of acquisition costs for ALLETE Clean Energy’s wind energy facilities acquisition in January 2014. Net income for 2014 reflected net income at ALLETE Clean Energy of $3.3 million (net loss of $3.4 million in 2013). BNI Coal recorded net income of $6.1 million in 2014 ($5.6 million in 2013). ALLETE Properties recorded a net loss of $2.3 million in 2014 (net loss of $2.7 million in 2013).

ALLETE, Inc. 2014 Form 10-K
36


2014 Compared to 2013

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

Regulated Operations

Operating Revenue increased $78.0 million, or 8 percent, from 2013 primarily due to a 5.1 percent increase in kilowatt-hour sales, higher cost recovery rider revenue, transmission revenue, gas sales, and fuel adjustment clause recoveries.

Revenue from Regulated Operations increased $30.5 million due to a 5.1 percent increase in kilowatt-hour sales. The increase was due primarily to a 27.5 percent increase in kilowatt-hour sales 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, and increased due to the commencement of the Minnkota Power sales agreement on June 1, 2014. (See Note 12. Commitments, Guarantees and Contingencies.) Also contributing to the increase were higher sales to industrial customers resulting from increased industrial production. The decrease in sales to our municipal customers reflects a wholesale customer contract expiration effective December 31, 2013.
 
Kilowatt-hours Sold
2014

2013

Quantity
Variance
%
Variance
Millions
 
 
 
 
Regulated Utility
 
 
 
 
Retail and Municipal
 
 
 
 
Residential
1,204

1,177

27

2.3

Commercial
1,468

1,455

13

0.9

Industrial
7,487

7,338

149

2.0

Municipal
864

999

(135
)
(13.5
)
Total Retail and Municipal
11,023

10,969

54

0.5

Other Power Suppliers
2,904

2,278

626

27.5

Total Regulated Utility Kilowatt-hours Sold
13,927

13,247

680

5.1


Revenue from electric sales to taconite and iron concentrate customers accounted for 23 percent of consolidated operating revenue in 2014 (25 percent in 2013). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 7 percent of consolidated operating revenue in 2014 (8 percent in 2013). Revenue from electric sales to pipelines and other industrial customers accounted for 7 percent of consolidated operating revenue in 2014 (6 percent in 2013).

Cost recovery rider revenue increased $29.4 million primarily due to higher capital expenditures related to the Bison Wind Energy Center and the Boswell Unit 4 environmental upgrade.

Transmission revenue increased $7.7 million primarily due to the commencement of recovery of our transmission investment related to the 230 kV transmission system upgrade that was placed into service in March 2013 (see Outlook Industrial Customers and Prospective Additional Load Nashwauk Public Utilities Commission) and higher MISO related revenue.

Revenue from gas sales at SWL&P increased $4.6 million as a result of the unseasonably cold weather during the first four months of 2014. (See Operating Expenses Operating and Maintenance Expense.)

Fuel adjustment clause recoveries increased $4.6 million due to higher fuel and purchased power costs attributable to our retail and municipal customers. (See Operating Expenses Fuel and Purchased Power Expense.)


ALLETE, Inc. 2014 Form 10-K
37


2014 Compared to 2013 (Continued)
Regulated Operations (Continued)

Operating Expenses increased $52.3 million, or 7 percent, from 2013.

Fuel and Purchased Power Expense increased $21.3 million, or 6 percent, from 2013 primarily due to an increase in purchased power resulting from higher kWh sales and higher wholesale prices. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause. (See Operating Revenue.)

Operating and Maintenance Expense increased $23.2 million, or 7 percent, from 2013. In 2014, a $4.2 million expense was recorded to reflect a liability associated with environmental mitigation projects required as part of the EPA NOV Consent Decree settlement. Operating and maintenance expense was also higher due to higher transmission expense, purchased gas, and property taxes partially offset by lower benefit expense. Transmission expense increased primarily due to higher MISO related expenses. Purchased gas expense increased due to higher gas sales in 2014; purchased gas expenses are recovered from our customers through a purchased gas adjustment clause. (See Operating Revenue.) Property tax expense increased as a result of higher taxable plant and rates. Benefit expense was lower due to higher discount rates in 2014 attributable to our defined benefit pension and other postretirement benefit plans.

Depreciation Expense increased $7.8 million, or 7 percent, from 2013 reflecting additional property, plant and equipment in service.

Interest Expense increased $4.8 million, or 11 percent, from 2013 primarily due to higher average long-term debt balances.

Other Income increased $3.1 million, or 66 percent, from 2013 primarily due to higher AFUDC-Equity.

Income Tax Expense increased $3.8 million, or 11 percent, from 2013 primarily due to higher pretax income in 2014, partially offset by higher federal production tax credits in 2014.

Investments and Other

Operating Revenue increased $40.4 million, or 43 percent, from 2013 primarily due to a $33.2 million increase in revenue from ALLETE Clean Energy due to the 2014 wind facility acquisitions. Also contributing to the increase was a $2.7 million increase in revenue at BNI Coal, which operates under cost-plus fixed fee contracts, resulting from increased coal deliveries and higher expenses in 2014. (See Operating Expenses.) ALLETE Properties revenue increased $1.8 million primarily due to higher wetland mitigation bank credit sales.

Operating Expenses increased $31.4 million, or 32 percent, from 2013 primarily due to higher operating and depreciation expenses of $20.3 million as a result of the ALLETE Clean Energy wind energy facilities acquisitions in 2014. Also contributing to the increase were higher expenses of $1.0 million at BNI Coal primarily due to higher salaries and repair expenses, which are recovered through the cost-plus fixed fee contracts. (See Operating Revenue.) ALLETE Properties had higher expense due to increased wetland mitigation bank credit sales. 2013 included a gain as a result of the termination of a legacy benefit plan.

Interest Expense decreased $0.3 million, or 4 percent, from 2013 primarily due to an increase in the proportion of ALLETE interest expense allocated to Minnesota Power. We record interest expense for our Regulated Operations based on Minnesota Power’s rate base and authorized capital structure, and allocate the remaining balance to Investments and Other.

Other Income decreased $3.8 million, or 83 percent, from 2013 primarily due to gains on sales of investments in 2013.

Income Tax Benefits decreased $4.2 million, or 57 percent, from 2013 primarily due to a decrease in pretax losses.

Income Taxes – Consolidated

For the year ended December 31, 2014, the effective tax rate was 22.6 percent (21.5 percent for the year ended December 31, 2013). The increase from the year ended December 31, 2013, was primarily due to higher pretax income in 2014, partially offset by increased federal production tax credits in 2014 related to additional wind generation. The effective tax rate deviated from the statutory rate of approximately 41 percent primarily due to deductions for AFUDC - Equity, investment tax credits, federal production tax credits, state income tax credits and depletion. (See Note 15. Income Tax Expense.)

ALLETE, Inc. 2014 Form 10-K
38


2013 Compared to 2012

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

Regulated Operations

Operating Revenue increased $51.1 million, or 6 percent, from 2012 primarily due to a 1.2 percent increase in kilowatt-hour sales, and higher fuel adjustment clause recoveries, transmission revenue, cost recovery rider revenue, gas sales, and municipal rates.

Fuel adjustment clause recoveries increased $13.5 million due to higher fuel and purchased power costs attributable to our retail and municipal customers. (See Operating Expenses Fuel and Purchased Power Expense.)

Transmission revenue increased $6.3 million primarily due to the commencement of recovery of our transmission investment related to the 230 kV transmission system upgrade that was placed into service in March 2013 (see Outlook Prospective Additional Load Nashwauk Public Utilities Commission) and higher MISO Regional Expansion Criteria and Benefits (RECB) revenue related to CapX2020 transmission projects.

Cost recovery rider revenue increased $5.3 million primarily due to higher capital expenditures related to our Bison Wind Energy Center, CapX2020 projects and the Boswell Unit 4 environmental upgrade. Our Bison 1, 2 and 3 wind facilities were completed in various phases through December 2012. Cost recovery for our Boswell Unit 4 mercury emissions reduction plan was approved by the MPUC in November 2013.

Revenue from gas sales at SWL&P increased $4.8 million as heating degree days in 2013 were approximately 22 percent higher than 2012. The increase was also due to higher purchased gas expenses. (See Operating Expenses Operating and Maintenance Expense.)

Revenue from our municipal customers increased $3.8 million as a result of higher rates under the cost-based formula primarily due to higher capital expenditures, as well as period-over-period fluctuations in the true-up for actual costs provisions of the contracts. The rates included in these contracts are calculated using a cost-based formula methodology that is set at July 1 each year using estimated costs and a true-up for actual costs the following year.

Revenue from Regulated Operations increased $13.8 million due to a 1.2 percent increase in kilowatt-hour sales. The increase was due primarily to a 14.0 percent increase in kilowatt-hour sales 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. Also contributing to the increase was higher sales to residential and commercial customers. Heating degree days in Duluth, Minnesota were approximately 22 percent higher in 2013 than 2012. Kilowatt-hour sales to industrial customers decreased 2.2 percent from 2012 primarily due to 154 million kilowatt-hours sold in 2012 through a short-term, fixed price contract.


ALLETE, Inc. 2014 Form 10-K
39


2013 Compared to 2012 (Continued)
Regulated Operations (Continued)

 
Kilowatt-hours Sold
2013

2012

Quantity
Variance
%
Variance
Millions
 
 
 
 
Regulated Utility
 
 
 
 
Retail and Municipal
 
 
 
 
Residential
1,177

1,132

45

4.0

Commercial
1,455

1,436

19

1.3

Industrial
7,338

7,502

(164
)
(2.2
)
Municipal
999

1,020

(21
)
(2.1
)
Total Retail and Municipal
10,969

11,090

(121
)
(1.1
)
Other Power Suppliers
2,278

1,999

279

14.0

Total Regulated Utility Kilowatt-hours Sold
13,247

13,089

158

1.2


Revenue from electric sales to taconite customers accounted for 25 percent of consolidated operating revenue in 2013 (26 percent in 2012). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 8 percent of consolidated operating revenue in 2013 (9 percent in 2012). Revenue from electric sales to pipelines and other industrials accounted for 6 percent of consolidated operating revenue in 2013 (6 percent in 2012).

Operating Expenses increased $54.8 million, or 8 percent, from 2012.

Fuel and Purchased Power Expense increased $26.1 million, or 8 percent, from 2012 primarily due to higher company generation, kilowatt-hours sold and 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.) A scheduled major outage in 2013 also increased costs under the Square Butte purchased power contract.

Operating and Maintenance Expense increased $12.4 million, or 4 percent, from 2012 primarily due to higher property tax expenses as a result of higher taxable plant and rates, higher transmission expense primarily due to higher MISO RECB expense, higher operating and maintenance expenses related to our Bison 1, 2 and 3 wind facilities, which were in service in 2013, and higher purchased gas expenses. Purchased gas expenses increased due to higher gas sales at SWL&P in 2013 as heating degree days in 2013 were approximately 22 percent higher than 2012; purchased gas costs are recovered from our customers through a purchased gas adjustment clause from customers. (See Operating Revenue.)

Depreciation Expense increased $16.3 million, or 17 percent, from 2012 reflecting additional property, plant and equipment in service.

Interest Expense increased $2.3 million, or 6 percent, from 2012 primarily due to higher average long-term debt balances.

Income Tax Expense decreased $14.3 million, or 28 percent, from 2012 primarily due to higher federal production tax credits in 2013 as our Bison Wind Energy Center was completed in various phases through December 2012 and in service in 2013.


Investments and Other

Operating Revenue increased $6.1 million, or 7 percent, from 2012 primarily due to a $3.6 million increase in revenue at BNI Coal and a $2.3 million increase in revenue at ALLETE Properties. BNI Coal, which operates under a cost-plus fixed fee contract, recorded higher revenue as a result of higher expenses in 2013 (see Operating Expenses), which was partially offset by fewer tons sold in 2013. The increase at ALLETE Properties was primarily due to land sales in 2013.


ALLETE, Inc. 2014 Form 10-K
40


2013 Compared to 2012 (Continued)
Investments and Other (Continued)

ALLETE Properties
2013
2012
Revenue and Sales Activity
Acres (a)
Amount
Acres (a)
Amount
Dollars in Millions
 
 
 
 
Revenue from Land Sales
293


$3.5



Other Revenue (b)
 
0.9

 

$2.1

Total ALLETE Properties Revenue
 

$4.4

 

$2.1

(a)
Acreage amounts are shown on a gross basis, including wetlands.
(b)
For the year ended December 31, 2012, Other Revenue includes wetland mitigation bank credit sales of $1.1 million.

Operating Expenses increased $3.5 million, or 4 percent, from 2012 reflecting higher expenses at BNI Coal of $5.0 million primarily due to higher repairs, fuel and labor costs; these costs are recovered through the cost-plus contract. (See Operating Revenue.) Operating expenses in 2013 also included $1.0 million of acquisition costs for the January 2014 ALLETE Clean Energy acquisition and higher cost of land sales at ALLETE Properties. These increases were partially offset by gains as a result of the termination of a legacy benefit plan and lower operating expenses related to our non-rate base generation.

Interest Expense increased $2.5 million from 2012 primarily due to the proportion of ALLETE interest expense allocated to Minnesota Power. We record interest expense for our Regulated Operations based on Minnesota Power’s rate base and authorized capital structure, and allocate the remaining balance to Investments and Other.

Other Income increased $3.7 million from 2012 primarily due to gains on sales of investments.

Income Tax Benefits decreased $5.0 million, or 40 percent, from 2012 primarily due to a decrease in pretax losses and higher state tax expense. State income tax expense was higher in 2013 as more North Dakota income tax credits attributable to our North Dakota capital investments were recognized in 2012.

Income Taxes – Consolidated

For the year ended December 31, 2013, the effective tax rate was 21.5 percent (28.1 percent for the year ended December 31, 2012). The decrease from the year ended December 31, 2012, was primarily due to increased federal production tax credits in 2013 related to additional wind generation assets in service during 2013. The effective tax rate deviated from the statutory rate of approximately 41 percent primarily due to deductions for AFUDC - Equity, investment tax credits, federal production tax credits, state income tax credits and depletion. (See Note 15. Income Tax Expense.)


Critical Accounting Policies

The preparation of financial statements and related disclosures in conformity with GAAP requires management to make various estimates and assumptions that affect amounts reported in the consolidated financial statements. These estimates and assumptions may be revised, which may have a material effect on the consolidated financial statements. Actual results may differ from these estimates and assumptions. These policies are discussed with the Audit Committee of our Board of Directors on a regular basis. The following represent the policies we believe are most critical to our business and the understanding of our results of operations.

Regulatory Accounting. Our regulated utility operations are accounted for in accordance with the accounting standards for the effects of certain types of regulation. These standards require us to reflect the effect of regulatory decisions in our financial statements. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. This assessment considers factors such as, but not limited to, changes in the regulatory environment and recent rate orders to other regulated entities under the same jurisdiction. If future recovery or refund of costs becomes no longer probable, the assets and liabilities would be recognized in current period net income or other comprehensive income. (See Note 5. Regulatory Matters.)


ALLETE, Inc. 2014 Form 10-K
41


Critical Accounting Policies (Continued)

Pension and Postretirement Health and Life Actuarial Assumptions. We account for our pension and postretirement benefit obligations in accordance with the accounting standards for defined benefit pension and other postretirement plans. These standards require the use of several important assumptions, including the expected long-term rate of return on plan assets, the discount rate, and mortality assumptions, among others, in determining our obligations and the annual cost of our pension and postretirement benefits. In establishing the expected long-term rate of return on plan assets, we determine the long-term historical performance of each asset class, adjust these for current economic conditions and, utilizing the target allocation of our plan assets, forecast the expected long-term rate of return. Our pension asset allocation at December 31, 2014 was approximately 48 percent equity securities, 39 percent debt, 8 percent private equity, and 5 percent real estate. Our postretirement health and life asset allocation at December 31, 2014, was approximately 58 percent equity securities, 34 percent debt, and 8 percent private equity. Equity securities consist of a mix of market capitalization sizes with domestic and international securities. In 2014, we used expected long-term rates of return of 8.00 percent in our actuarial determination of our pension expense and 6.40 percent to 8.00 percent in our actuarial determination of our other postretirement expense. The actuarial determination uses an asset smoothing methodology for actual returns to reduce the volatility of varying investment performance over time. We review our expected long-term rate of return assumption annually and will adjust it to respond to changing market conditions. A one-quarter percent decrease in the expected long-term rate of return would increase the annual expense for pension and other postretirement benefits by approximately $1.5 million, pretax.

The discount rate is computed using a yield curve adjusted for ALLETE’s projected cash flows to match our plan characteristics. The yield curve is determined using high-quality, long-term corporate bond rates at the valuation date. In 2014, we used discount rates of 4.93 percent and 4.96 percent in our actuarial determination of our pension and other postretirement expense, respectively. We review our discount rates annually and will adjust them to respond to changing market conditions. A one-quarter percent decrease in the discount rate would increase the annual expense for pension and other postretirement benefits by approximately $1.3 million, pretax.

The mortality assumptions used to calculate our pension and other postretirement benefit obligations as of December 31, 2014 considered a modified RP-2014 mortality table and an updated mortality projection scale. (See Note 17. Pension and Other Postretirement Benefit Plans.)

Impairment of Long-Lived Assets. We review our long-lived assets, which include the real estate assets of ALLETE Properties, for indicators of impairment in accordance with the accounting standards for property, plant and equipment on a quarterly basis.

In accordance with the accounting standards for property, plant and equipment, if indicators of impairment exist, we test our real estate assets for recoverability by comparing the carrying amount of the asset to the undiscounted future net cash flows expected to be generated by the asset. Cash flows are assessed at the lowest level of identifiable cash flows, which may be by each land parcel, combining various parcels, or other combinations thereof. Our consideration of possible impairment for our real estate assets requires us to make estimates of future net cash flows on an undiscounted basis. The undiscounted future net cash flows are impacted by trends and factors known to us at the time they are calculated and our expectations related to: management’s best estimate of future sales prices; holding period and timing of sales; method of disposition; and future expenditures necessary to develop and maintain the operations, including community development district assessments, property taxes and normal operation and maintenance costs. These estimates and expectations are specific to each land parcel or various bulk sales, may vary among each land parcel or bulk sale, and may change in the future. If the excess of undiscounted future net cash flows over the carrying amount of a property is small, there is a greater risk of future impairment in the event of such future changes and any resulting impairment charges could be material.

Taxation. We are required to make judgments regarding the potential tax effects of various financial transactions and our ongoing operations to estimate our obligations to taxing authorities. These tax obligations include income, real estate and sales/use taxes. Judgments related to income taxes require the recognition in our financial statements of the largest tax benefit of a tax position that is “more-likely-than-not” to be sustained on audit. Tax positions that do not meet the “more-likely-than-not” criteria are reflected as a tax liability in accordance with the accounting standards for uncertainty in income taxes. We record a valuation allowance against our deferred tax assets to the extent it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized.

ALLETE, Inc. 2014 Form 10-K
42


Critical Accounting Policies (Continued)
Taxation (Continued)

We are subject to income taxes in various jurisdictions. We make assumptions and judgments each reporting period to estimate our income tax assets, liabilities, benefits, and expenses. Judgments and assumptions are supported by historical data and reasonable projections. Our assumptions and judgments include projections of our future federal and state taxable income, and state apportionment, to determine our ability to utilize NOL and credit carryforwards prior to their expiration. Significant changes in assumptions regarding future federal and state taxable income or change in tax rates could require new or increased valuation allowances which could result in a material impact on our results of operations.


Outlook

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 long-term objectives of achieving minimum average earnings per share growth of 5 percent per year and providing a dividend payout competitive with our industry.

ALLETE is predominantly a regulated utility through Minnesota Power, SWL&P and an investment in ATC. Minnesota Power believes it is well positioned for the future as it executes on its EnergyForward initiative and serves a potentially growing industrial customer base. Minnesota Power will continue to pursue customer growth opportunities and cost recovery rider approval for environmental, renewable and transmission investments, as well as work with regulators to earn a fair rate of return. We believe that ATC is poised for future growth both organically and through its partnership with Duke Energy.

In February 2015, ALLETE acquired U.S. Water Services, consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services to complement its core regulated utility, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth. ALLETE will now focus its energy infrastructure and related service efforts on ALLETE Clean Energy, U.S. Water Services and BNI Coal. ALLETE Clean Energy has a growing portfolio of wind generating facilities, and U.S. Water Services provides integrated water management to a growing base of industrial and commercial customers. ALLETE’s Energy Infrastructure and Related Services businesses primarily have contracted or recurring revenues.

ALLETE is focused on providing sustainable solutions to our customers, as exemplified by the EnergyForward and Power of One initiatives at Minnesota Power, renewable energy investments at ALLETE Clean Energy, and investment in U.S. Water Services.

Regulated Operations. Minnesota Power’s long-term strategy is to be the leading electric energy provider in northeastern Minnesota by providing safe, reliable and cost-competitive electric energy, while complying with environmental permit conditions and renewable requirements. 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 customer viability. 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. (See Regulated Operations – EnergyForward.) We will monitor and review proposed environmental regulations and may challenge those that add considerable cost with limited environmental benefit. Minnesota Power will continue to pursue customer growth opportunities and cost recovery rider approval for environmental, renewable and transmission investments, as well as work with regulators to earn a fair rate of return. We project that Minnesota Power will not earn its allowed rate of return in 2015.

Regulatory Matters. Entities within our Regulated Operations segment are under the jurisdiction of the MPUC, the FERC, the PSCW or the NDPSC. See Item 1. Business – Regulated Operations – Regulatory Matters for discussion of regulatory matters within our Minnesota, FERC, Wisconsin and North Dakota jurisdictions.

Industrial Customers and Prospective Additional Load

Industrial Customers. Electric power is one of several key inputs in the taconite mining, iron concentrate, paper, pulp and secondary wood products, and pipeline industries. In 2014, 54 percent (55 percent in 2013) of our Regulated Utility kWh sales were made to our industrial customers in these industries.


ALLETE, Inc. 2014 Form 10-K
43


Outlook (Continued)
Industrial Customers and Prospective Additional Load (Continued)

Five of Minnesota Power’s taconite customers have the capability to produce up to approximately 41 million tons of taconite pellets annually. Taconite pellets produced in Minnesota are primarily shipped to North American steel making facilities that are part of the integrated steel industry. Steel produced from these North American facilities is used primarily in the manufacture of automobiles, appliances, pipe and tube products for the gas and oil industry, and in the construction industry. Historically, less than five percent of Minnesota taconite production is exported outside of North America. Also, two of Minnesota Power’s iron concentrate customers have the capability to produce up to approximately 2 million metric tons of iron concentrate per year. Iron concentrate is used in the production of taconite pellets.

There has been a general historical correlation between U.S. steel production and Minnesota taconite production. The World Steel Association, an association of approximately 170 steel producers, national and regional steel industry associations, and steel research institutes representing around 85 percent of world steel production, projected U.S. steel consumption in 2015 will be similar to 2014. The American Iron and Steel Institute (AISI), an association of North American steel producers, reported that U.S. raw steel production operated at approximately 77 percent of capacity in 2014 (77 percent in 2013; 75 percent in 2012). Based on these projections, 2015 taconite production levels in Minnesota are expected to be similar to 2014.

Minnesota Power Taconite Customer Production
Year
 
Tons (Millions)
2014*
 
39
2013
 
37
2012
 
39
2011
 
39
2010
 
35
2009
 
17
2008
 
39
2007
 
38
2006
 
39
2005
 
40
Source: Minnesota Department of Revenue 2014 Mining Tax Guide for years 2005 - 2013.
* Preliminary data from the Minnesota Department of Revenue.

Our taconite customers may experience annual variations in production levels due to such factors as economic conditions, short-term demand changes or maintenance outages. We estimate that a one million ton change in our taconite customers’ production would change our annual earnings per share by approximately $0.03, net of expected power marketing sales at 2014 year-end prices. Changes in wholesale electric prices or customer contractual demand nominations could impact this estimate. Long-term reductions in taconite production or a permanent shut down of a taconite customer may lead us to file a rate case to recover lost revenues.

Similar to our taconite customers, three of four major paper and pulp mills we serve reported operations at, or near, full capacity in 2014 and similar levels are expected in 2015. Boise, Inc. (Boise) operates a paper mill in International Falls, Minnesota. On September 12, 2014, Boise provided the required one-year written notice of its intent to install additional generation at its mill in late 2015. Boise’s reduction in demand is not expected to have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.

Prospective Additional LoadMinnesota Power is pursuing new wholesale and retail loads in and around its service territory. Currently, several companies in northeastern Minnesota continue to progress in the development of natural resource based projects that represent long-term growth potential and load diversity for Minnesota Power. These potential projects are in the ferrous and non-ferrous mining and pipeline industries and include Essar Steel Minnesota LLC (Essar), PolyMet Mining Corporation (PolyMet), Magnetation, LLC (Magnetation), and Enbridge, Inc. (Enbridge). We cannot predict the outcome of these projects.


ALLETE, Inc. 2014 Form 10-K
44


Outlook (Continued)
Industrial Customers and Prospective Additional Load (Continued)

Nashwauk Public Utilities Commission. In April 2014, the Company amended its formula-based wholesale electric sales agreement with the Nashwauk Public Utilities Commission for all of its electric service requirements, extending the term through June 30, 2026. A new Essar taconite facility is currently under construction in the city of Nashwauk, and the Nashwauk Public Utilities Commission also amended and extended its electric service agreement with Essar. Upon completion, this facility would result in approximately 110 MW of additional load for Minnesota Power. Under the terms of a facilities construction agreement, Minnesota Power constructed a 230 kV transmission system upgrade to serve the Essar load which was placed into service in March 2013. This upgrade will allow the Nashwauk Public Utilities Commission to provide electric service for Essar’s new taconite facility. Billings to Essar to recover our transmission investments began in April 2013. In October 2014, Essar announced the completion of project financing and stated that initial pellet production would commence in the second half of 2015.

PolyMet. Minnesota Power has executed a long-term contract with PolyMet, which is planning to start a new copper-nickel and precious metal (non-ferrous) mining operation in northeastern Minnesota. PolyMet began work on a Supplemental Draft Environmental Impact Statement (SDEIS) in 2010. The SDEIS addressed environmental issues, including those dealing with the land exchange between PolyMet and the U.S. Forest Service (USFS), which is critical to the mine site development. In December 2013, the Minnesota Department of Natural Resources (DNR) released PolyMet’s SDEIS. The Minnesota DNR has estimated that the SDEIS process could be completed in the first half of 2015. Minnesota Power could begin to supply between 45 MW and 50 MW of load through a ten-year power supply contract period that would begin upon start-up of the mining operations.

Magnetation. Magnetation produces iron ore concentrate from low-grade natural ore tailing basins, already mined stockpiles and newly mined iron formations. Magnetation’s facility near Taconite, Minnesota, is fully operational, and its new concentrate facility near Coleraine, Minnesota, commenced production in December 2014. On January 27, 2014, Minnesota Power and Magnetation entered into a new ten-year electric service agreement, which was approved by the MPUC on May 1, 2014, for the facility near Coleraine, Minnesota. This agreement is effective through December 31, 2025. In addition, a transmission service extension was required to be constructed by Minnesota Power. On June 19, 2014, Minnesota Power received MPUC approval of a transmission route for the service extension, permits were received on July 2, 2014, and construction was completed in the fourth quarter of 2014. Minnesota Power expects to supply approximately 20 MW of power to this new facility, making it a Large Power Customer of Minnesota Power. The new facility is expected to supply iron ore concentrate to Magnetation’s new pellet plant in Reynolds, Indiana, which is designed to produce about 3 million tons of taconite pellets annually for AK Steel. On September 29, 2014, Magnetation announced the Reynolds pellet plant commenced production.

Enbridge. Minnesota Power has a long-term contract with Enbridge that extends through December 31, 2020. Enbridge owns and operates generation and distribution systems within the energy industry in North America, including a crude oil and liquids transportation system. Enbridge plans to expand the capacity at two pumping stations located in Minnesota Power’s service territory in Deer River and Floodwood, Minnesota. The project is expected to be complete by 2016. Upon completion, Minnesota Power expects to supply between 5 to 10 MW of additional load. Enbridge also plans to construct a pipeline connecting its Beaver Lodge Station, near Tioga, North Dakota, to an existing terminal in Superior, Wisconsin by 2017. Upon completion of the pipeline, SWL&P expects to supply between 15 to 20 MW of additional load.

EnergyForward. In January 2013, Minnesota Power announced “EnergyForward”, a strategic plan for assuring reliability, protecting affordability and further improving environmental performance. The plan includes completed and planned investments in wind and hydroelectric power, the addition of natural gas as a generation fuel source, and the installation of emissions control technology. Significant elements of the “EnergyForward” plan include:

Major wind investments in North Dakota. Our Bison Wind Energy Center added 205 MW of capacity in the fourth quarter of 2014, bringing total capacity to 497 MW. (See Renewable Energy.)
Planned installation of approximately $250 million in emissions control technology at Boswell Unit 4 to further reduce emissions of SO2, particulates and mercury. (See Boswell Mercury Emission Reduction Plan.)
Planning for the proposed GNTL to deliver hydroelectric power from northern Manitoba by 2020. (See Transmission.)
The conversion of Laskin from coal to cleaner-burning natural gas in the second quarter of 2015.
Retiring Taconite Harbor Unit 3, one of three coal-fired units at Taconite Harbor, in the second quarter of 2015.

Integrated Resource Plan. In a November 2013 order, the MPUC approved Minnesota Power’s 2013 Integrated Resource Plan which details our “EnergyForward” strategic plan and includes an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. We are required to submit our 2015 Integrated Resource Plan with the MPUC no later than September 1, 2015. (See Item 1. Business – Regulated Operations – Regulatory Matters.)

ALLETE, Inc. 2014 Form 10-K
45


Outlook (Continued)
Energy Forward (Continued)

Renewable Energy. In February 2007, Minnesota enacted a law requiring 25 percent of Minnesota Power’s total retail and municipal energy sales in Minnesota to be from renewable energy sources by 2025. The law also requires Minnesota Power to meet interim milestones of 12 percent by 2012, 17 percent by 2016 and 20 percent by 2020. The law allows the MPUC to modify or delay 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.

Minnesota Power continues to execute its renewable energy strategy through key renewable projects that will ensure we meet the identified state mandate at the lowest cost for customers. Through the strategy outlined in Minnesota Power’s 2013 Integrated Resource Plan, 18 percent of the Company’s total retail and municipal energy sales were supplied by renewable energy sources in 2014. We expect 28 percent of the Company’s total retail and municipal energy sales will be supplied by renewable energy sources in 2015.

Minnesota Solar Energy Standard. In May 2013, legislation was enacted by the state of Minnesota requiring at least 1.5 percent of total retail electric sales, excluding sales to certain industrial customers, to be generated by solar energy by the end of 2020. At least 10 percent of the 1.5 percent mandate must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 20 kilowatts or less. Minnesota Power is in the process of evaluating the potential impact of this legislation on our operations; however, any costs are expected to be recovered in customer rates.

Wind Energy. Our wind energy facilities consist of the 497 MW Bison Wind Energy Center located in North Dakota, which was placed in service in various phases between 2010 and 2014, and our 25 MW Taconite Ridge Energy Center located in northeastern Minnesota. We also have 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) located in North Dakota.

On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. Customer billing rates for our Bison 1, 2, & 3 wind facilities were approved by the MPUC in a December 2013 order. On April 29, 2014 and November 10, 2014, we filed renewable resources factor filings which include updated costs associated with the Bison Wind Energy Center. Upon approval of the filings, we will be authorized to include updated billing rates on customer bills.

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. The DC transmission line capacity can be increased if renewable energy or transmission needs justify investments to upgrade the line.

Manitoba Hydro. Minnesota Power has a long-term PPA with Manitoba Hydro that expires in May 2020. 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. In addition, Minnesota Power has a separate long-term PPA with Manitoba Hydro to purchase surplus energy through April 2022. This energy-only agreement 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 May 2011, Minnesota Power and Manitoba Hydro signed an additional long-term PPA. The PPA provides for Minnesota Power to purchase 250 MW of capacity and energy from Manitoba Hydro for 15 years beginning in 2020. The agreement is subject to construction of additional transmission capacity between Manitoba and the U.S., along with construction of new hydroelectric generating capacity in Manitoba. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. 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. The agreement is subject to construction of additional transmission capacity between Manitoba and Minnesota’s Iron Range. (See Regulated Operations – Transmission.)


ALLETE, Inc. 2014 Form 10-K
46


Outlook (Continued)
Energy Forward (Continued)

In July 2014, Minnesota Power and Manitoba Hydro signed a long-term PPA that provides for Minnesota Power to purchase up to 133 MW of energy from Manitoba Hydro for 20 years beginning in 2020. The agreement was approved by the MPUC in an order dated January 30, 2015, and is subject to the construction of the GNTL.

Hydro Operations. In June 2012, record rainfall and flooding occurred near Duluth, Minnesota, and surrounding areas. The flooding impacted Minnesota Power’s St. Louis River hydro system, particularly Thomson, which had damage to the forebay canal and flooding at the facility. The forebay rebuild is complete and Minnesota Power commenced filling the forebay canal on October 9, 2014. Thomson returned to partial generation in the fourth quarter of 2014 and work is ongoing towards returning to full generation early in 2015. Total project costs are estimated to be approximately $90 million, net of insurance. On January 29, 2015, the MPUC approved our petition seeking cost recovery of investments and expenditures related to the restoration and repair of Thomson through a renewable resources rider.

Boswell Mercury Emissions Reduction Plan. Minnesota Power is implementing a mercury emissions reduction project for Boswell Unit 4 in order to comply with the Minnesota Mercury Emissions Reduction Act and the Federal MATS rule. In August 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA. The plan proposed that Minnesota Power install pollution controls by early 2016 to address both the Minnesota Mercury Emissions Reduction Act requirements and the Federal MATS rule. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are included in the estimated capital expenditures required for compliance with the MATS rule and are estimated to be approximately $250 million, of which $145 million was spent through December 31, 2014. In November 2013, the MPUC issued an order approving the Boswell Unit 4 mercury emissions reduction plan and cost recovery, establishing an environmental improvement rider. Also in November 2013, environmental intervenors filed a petition for reconsideration with the MPUC which was subsequently denied in an order dated January 17, 2014. The MPUC’s order was affirmed by the Minnesota Court of Appeals on November 3, 2014. In December 2013, Minnesota Power filed a petition with the MPUC to establish customer billing rates for the approved environmental improvement rider based on actual and estimated investments and expenditures, which was approved in an order dated July 2, 2014. On November 26, 2014, we filed an updated environmental improvement factor filing which included updated costs associated with Boswell Unit 4. Upon approval of this filing, we will be authorized to include updated billing rates on customer bills.

Transmission. We plan to make investments in transmission opportunities that strengthen or enhance the transmission grid or take advantage of our geographical location between sources of renewable energy and end users. These include the GNTL and the CapX2020 initiative, as well as investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others), and our investment in ATC. See also Item 1. Business – Regulated Operations.

Investments and Other

Investments and Other is comprised primarily of our Energy Infrastructure and Related Services businesses; ALLETE Clean Energy, U.S. Water Services and BNI Coal. Investments and Other also includes ALLETE Properties, other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,000 acres of land in Minnesota, and earnings on cash and investments.

ALLETE Clean Energy. ALLETE Clean Energy aims to develop or acquire capital projects that create energy solutions via wind, solar, biomass, midstream gas and oil infrastructure, among other energy-related projects.

On January 30, 2014, ALLETE Clean Energy acquired wind energy facilities located in Lake Benton, Minnesota (Lake Benton), Storm Lake, Iowa (Storm Lake II) and Condon, Oregon (Condon) for $26.9 million. ALLETE Clean Energy also has an option to acquire a fourth wind energy facility from AES in Armenia Mountain, Pennsylvania (Armenia Mountain), in June 2015.

Lake Benton, Storm Lake II and Condon have 104 MW, 77 MW and 50 MW of generating capability, respectively. Lake Benton and Storm Lake II began commercial operations in 1999, while Condon began operations in 2002. All three wind energy facilities have PPAs in place for their entire output, which expire in various years between 2019 and 2032. Pursuant to the acquisition agreement, ALLETE Clean Energy has an option to acquire the 101 MW Armenia Mountain wind energy facility in June 2015. Armenia Mountain began operations in 2009.

ALLETE, Inc. 2014 Form 10-K
47


Outlook (Continued)
ALLETE Clean Energy (Continued)

On November 20, 2014, ALLETE Clean Energy acquired a business for $27.0 million which is developing a wind facility near Hettinger, North Dakota. ALLETE Clean Energy will develop and construct a 107 MW wind farm using 43 turbines which will then be sold to Montana-Dakota Utilities Co. for approximately $200 million. Construction is expected to be completed in December 2015, and the sale is subject to regulatory approvals.

On December 17, 2014, ALLETE Clean Energy acquired a wind facility in Storm Lake, Iowa (Storm Lake I) for $15.0 million, subject to a working capital adjustment. Storm Lake I has 108 MW of generating capability and is located adjacent to Storm Lake II which was acquired in January 2014. The wind facility began commercial operations in 1999 and has a PPA in place for its entire output which expires in 2018.

On December 31, 2014, ALLETE Clean Energy entered into a purchase agreement to acquire wind facilities in southern Minnesota for approximately $47.5 million. The facilities have 97.5 MW of generating capability and are located near our Lake Benton facility acquired in January 2014. The wind facilities began commercial operations in 2003 and have PPAs in place for the entire output, which expire in 2018 and 2023. The acquisition is expected to close in the first quarter of 2015.

U.S. Water Services. In February 2015, ALLETE acquired U.S. Water Services. Headquartered in St. Michael, Minnesota, U.S. Water Services has a national footprint serving a growing and diverse mix of over 3,600 industrial customers, with recurring revenues and customer retention that exceeds 90 percent. U.S. Water Services provides integrated water management for industry, combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage and improve efficiency. U.S. Water Services helps customers achieve efficient and sustainable use of their energy systems, is a leading provider to the biofuels industry, and has a growing presence in the power generation and midstream oil and gas industries. The acquisition is not expected to have a material impact on 2015 earnings per share.

BNI Coal. In 2014, BNI Coal sold 4.0 million tons of coal (3.7 million tons in 2013) and anticipates 2015 sales will be similar to 2014. In 2013, a customer of BNI Coal incurred a scheduled major outage resulting in fewer tons sold. BNI Coal operates under cost-plus fixed fee agreements extending through December 31, 2037.

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, sell the portfolio when opportunities arise and reinvest the proceeds in our growth initiatives. Market conditions can impact land sales and could result in our inability to cover our operating expenses and fixed carrying costs such as community development district assessments and property taxes. 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 in the permitting 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, Inc. 2014 Form 10-K
48


Outlook (Continued)
ALLETE Properties (Continued)

Summary of Development Projects (100% Owned)
 
 
 
Residential
 
Non-residential
Land Available-for-Sale
 
Acres (a)
 
Units (b)
 
Sq. Ft. (b,c)
Current Development Projects
 
 
 
 
 
 
Town Center
 
958

 
2,412

 
2,236,700

Palm Coast Park
 
3,777

 
3,554

 
3,096,800

Total Current Development Projects
 
4,735

 
5,966

 
5,333,500

 
 
 
 
 
 
 
Planned Development Project
 
 
 
 
 
 
Ormond Crossings
 
2,914

 
2,950

 
3,215,000

Other
 
 
 
 
 
 
Lake Swamp Wetland Mitigation Project
 
3,044

 
(d)

 
(d)

Total of Development Projects
 
10,693

 
8,916

 
8,548,500

(a)
Acreage amounts are approximate and shown on a gross basis, including wetlands.
(b)
Units and square footage are estimated. 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 are 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 1,672 acres of other land available-for-sale.

Income Taxes. ALLETE’s aggregate federal and multi-state statutory tax rate is approximately 41 percent for 2014. On an ongoing basis, ALLETE has tax credits and other tax adjustments that reduce the statutory rate to the effective tax rate. These tax credits and adjustments historically have included items such as investment tax credits, renewable tax credits, AFUDC-Equity, depletion, as well as 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 and resolution of prior years’ tax matters. Due primarily to increased federal production tax credits as a result of wind generation, we expect our effective tax rate to be approximately 15 percent for 2015. We also expect that our effective tax rate will be lower than the statutory rate over the next ten years due to production tax credits attributable to our wind generation.

Liquidity and Capital Resources

Liquidity Position. ALLETE is well-positioned to meet the Company’s liquidity needs. As of December 31, 2014, we had cash and cash equivalents of $145.8 million, $357.2 million in available consolidated lines of credit and a debt-to-capital ratio of 46 percent.

Capital Structure. ALLETE’s capital structure for each of the last three years is as follows:

As of December 31
2014

       %
2013

       %
2012

       %
Millions
 
 
 
 
 
 
ALLETE Equity

$1,609.4

54

$1,342.9

55

$1,201.0

54
Non-Controlling Interest
1.8



Long-Term Debt (Including Current Maturities)
1,373.5

46
1,110.2

45
1,018.1

46
Notes Payable
3.7



 

$2,988.4

100

$2,453.1

100

$2,219.1

100


ALLETE, Inc. 2014 Form 10-K
49


Liquidity and Capital Resources (Continued)

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

Year Ended December 31
2014

2013

2012

Millions
 
 
 
Cash and Cash Equivalents at Beginning of Period

$97.3


$80.8


$101.1

Cash Flows from (for)
 
 
 
Operating Activities
269.8

239.4

239.6

Investing Activities
(625.7
)
(336.6
)
(420.1
)
Financing Activities
404.4

113.7

160.2

Change in Cash and Cash Equivalents
48.5

16.5

(20.3
)
Cash and Cash Equivalents at End of Period

$145.8


$97.3


$80.8


Operating Activities. Cash from operating activities in 2014 was higher than 2013 primarily due to higher net income, cash contributions of $10.8 million in 2013 to other postretirement benefit plans, and timing of accounts payable payments, which were partially offset by increased fuel inventory purchases in 2014.

Cash from operating activities in 2013 was similar to 2012 as higher net income and lower fuel inventory purchases were offset by decreased other current liabilities due to higher receipts of customer security deposits in 2012 and increased cost recovery rider revenue receivables in 2013.

Investing Activities. Cash used for investing activities in 2014 was higher than 2013 primarily due to higher capital expenditures and ALLETE Clean Energy acquisitions in 2014, partially offset by a transfer of cash included in Other Investments to Cash and Cash Equivalents in 2014.

The decrease in cash used for investing activities in 2013 from 2012 was primarily due to lower payments for capital expenditures and increased proceeds from sales of available-for-sale securities in 2013.

Financing Activities. Cash from financing activities in 2014 was higher than 2013 primarily due to proceeds from the issuance of long-term debt and the issuance of common stock in 2014, partially offset by increased payments on long-term debt and dividends on common stock in 2014.

The decrease in cash from financing activities in 2013 compared to 2012 was primarily due to lower proceeds from long-term debt issuances and the repayment of long-term debt which matured in 2013, partially offset by increased common stock issuances in 2013.
 
Working Capital. Additional working capital, if and when needed, generally is provided by consolidated bank lines of credit, the sale of securities or commercial paper. As of December 31, 2014, we had consolidated bank lines of credit aggregating $408.4 million ($406.4 million as of December 31, 2013), the majority of which expire in November 2018. We had $47.5 million outstanding in standby letters of credit and $3.7 million outstanding in draws under our lines of credit as of December 31, 2014 ($5.4 million in standby letters of credit and no draws outstanding as of December 31, 2013). In addition, as of December 31, 2014, we had 2.1 million original issue shares of our common stock available for issuance through Invest Direct, our direct stock purchase and dividend reinvestment plan, 1.3 million original issue shares of common stock available for issuance through a distribution agreement with Lampert Capital Markets, Inc. and 1.4 million original issue shares of common stock available for issuance under a forward sale agreement. (See Securities.) 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 Lampert Capital Markets, Inc., in February 2008, as amended most recently in May 2014, with respect to the issuance and sale of up to an aggregate of 9.6 million shares of our common stock, without par value, of which 1.3 million shares remain available for issuance. For the year ended December 31, 2014, 1.9 million shares of common stock were issued under this agreement, resulting in net proceeds of $90.0 million (1.3 million shares for net proceeds of $63.4 million for the year ended December 31, 2013; 1.3 million shares for net proceeds of $53.1 million for the year ended December 31, 2012). The shares sold in 2012 and through August 1, 2013, were offered and sold pursuant to Registration Statement No. 333-170289. On August 2, 2013, we filed Registration Statement No. 333-190335, pursuant to which the remaining shares will continue to be offered for sale, from time to time.

ALLETE, Inc. 2014 Form 10-K
50


Liquidity and Capital Resources (Continued)
Securities (Continued)

For the year ended December 31, 2014, we issued a total of 0.5 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 $25.4 million (0.7 million shares were issued for net proceeds of $34.8 million during the year ended December 31, 2013; 0.5 million shares were issued for net proceeds of $23.9 million during the year ended December 31, 2012). These shares of common stock were registered under Registration Statement Nos. 333-188315, 333-183051 and 333-162890.

On January 10, 2014, ALLETE contributed 0.4 million shares of ALLETE common stock to its pension plan. These shares of ALLETE common stock were contributed in reliance upon an exemption available pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended, and had an aggregate value of $19.5 million when contributed.

On February 26, 2014, ALLETE entered into a confirmation of forward sale agreement (Agreement) with a forward counterparty in connection with a public offering of 2.8 million shares of ALLETE common stock. Pursuant to the Agreement, the forward counterparty (or its affiliate) borrowed 2.8 million shares of ALLETE common stock from third parties and sold them to the underwriters. ALLETE had the right to elect physical, cash or net share settlement under the forward sales agreement, for all or a portion of its obligations under the Agreement. In the event that ALLETE elected physical settlement of the Agreement, it would deliver shares of its common stock in exchange for cash proceeds at the then-applicable forward sale price. The forward sale price was initially $48.01 per share, subject to adjustment as provided in the Agreement. On September 5, 2014, ALLETE physically settled a portion of its obligations under the Agreement by having delivered approximately 1.4 million shares of common stock in exchange for cash proceeds of $65.0 million. On February 4, 2015, ALLETE physically settled the remaining portion of its obligation under the Agreement by delivering approximately 1.4 million shares for cash proceeds of $65.4 million.

In connection with the public offering of the 2.8 million shares, ALLETE granted the underwriters an option to purchase up to an additional 0.4 million shares of ALLETE common stock (the option shares). The underwriters exercised the option in full and on March 4, 2014, the Company issued and sold the option shares to the underwriters at a price to ALLETE equal to the initial forward sale price for proceeds of $20.2 million.

During 2014, we issued $375.0 million of ALLETE first mortgage bonds (Bonds) in the private placement market in seven series. The Company used the proceeds from the sale of the Bonds to refinance debt, fund utility capital expenditures and/or for general corporate purposes. (See Note 11. Short-Term and Long-Term Debt.)

On July 1, 2014, we redeemed $111.0 million of pollution control bonds, at par, which were due on July 1, 2022.

Financial Covenants. See Note 11. Short-Term and Long-Term Debt for information regarding our financial covenants.

Off-Balance Sheet Arrangements. Off-balance sheet arrangements are discussed in Note 12. Commitments, Guarantees and Contingencies.


ALLETE, Inc. 2014 Form 10-K
51


Liquidity and Capital Resources (Continued)

Contractual Obligations and Commercial Commitments. ALLETE has contractual obligations and other commitments that will need to be funded in the future, in addition to its capital expenditure programs. Following is a summarized table of contractual obligations and other commercial commitments as of December 31, 2014.

 
Payments Due by Period
Contractual Obligations
 
Less than
1 to 3
4 to 5
After
As of December 31, 2014
Total
1 Year
Years
Years
5 Years
Millions
 
 
 
 
 
Long-Term Debt

$2,210.9


$159.1


$189.7


$201.7


$1,660.4

Pension (a)
398.5

36.5

75.3

78.9

207.8

Other Postretirement Benefit Plans (a)
93.1

8.0

17.3

18.4

49.4

Operating Lease Obligations
80.5

13.4

22.0

17.8

27.3

Uncertain Tax Positions (b)





Capital Purchase Obligations (c)
126.3

105.8

18.0

2.5


PPA Obligations (d)
459.5

57.5

119.9

125.0

157.1

Other Purchase Obligations
38.4

38.4




 

$3,407.2


$418.7


$442.2


$444.3


$2,102.0

(a)
Represents the estimated future benefit payments for our defined benefit pension and other postretirement plans through 2024.
(b)
Excludes $2.0 million of non-current unrecognized tax benefits due to uncertainty regarding the timing of future cash payments related to uncertain tax positions.
(c)
Consists mostly of capital expenditures related to the Boswell Unit 4 environmental upgrade.
(d)
Excludes the agreement with Manitoba Hydro expiring in 2022, as this contract is for surplus energy only, and the agreements with Manitoba Hydro commencing in 2020, as our obligations under these contracts is subject to the construction of a hydro generation facility by Manitoba Hydro and additional transmission capacity. Also, excludes Oliver Wind I and Oliver Wind II, as we only pay for energy as it is delivered to us. (See Item 1. Business – Regulated Operations – Power Supply.)

Long-Term Debt. Our long-term debt obligations, including long-term debt due within one year, represent the principal amount of bonds, notes and loans which are recorded on our Consolidated Balance Sheet, plus interest. The table above assumes that the interest rates in effect at December 31, 2014, remain constant through the remaining term. (See Note 11. Short-Term and Long-Term Debt.)

Pension and Other Postretirement Benefit Plans. Our pension and other postretirement benefit plan obligations represent our current estimate of future benefit payments through 2024. Pension contributions will be dependent on several factors including realized asset performance, future discount rate and other actuarial assumptions, IRS and other regulatory requirements, and contributions required to avoid benefit restrictions for the pension plans. Funding for the other postretirement benefit plans is impacted by realized asset performance, future discount rate and other actuarial assumptions, and utility regulatory requirements.

These amounts are estimates and will change based on actual market performance, changes in interest rates and any changes in governmental regulations. (See Note 17. Pension and Other Postretirement Benefit Plans.)

Capital Purchase Obligations. Capital purchase obligations represent our purchase obligations for certain capital expenditure projects. It includes capital expenditures related to the Boswell Unit 4 environmental upgrade and certain transmission projects. (See Note 12. Commitments, Guarantees and Contingencies.)

PPA Obligations. PPA obligations represent our Square Butte, Manitoba Hydro, Minnkota Power and other purchase power contracts. (See Note 12. Commitments, Guarantees and Contingencies.)

Under Minnesota Power’s PPA with Square Butte that extends through 2026, we are obligated to pay our pro rata share of Square Butte’s costs based on our entitlement to the output of Square Butte’s 455 MW coal-fired generating unit near Center, North Dakota. Minnesota Power’s payment obligation will be suspended if Square Butte fails to deliver any power, whether produced or purchased, for a period of one year. Square Butte’s fixed costs consist primarily of debt service. The table above reflects our share of future debt service based on our output entitlement of 50 percent.

ALLETE, Inc. 2014 Form 10-K
52


Liquidity and Capital Resources (Continued)
Contractual Obligations and Commercial Commitments (Continued)

Minnesota Power has a PPA with Manitoba Hydro that expires in May 2020. 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.

In December 2012, Minnesota Power entered into a long-term PPA with Minnkota Power. Under this agreement, Minnesota Power will purchase 50 MW of capacity and the energy associated with that capacity from June 2016 through May 2020. The agreement includes a fixed capacity charge and energy pricing that escalates at a fixed rate annually over the term.

Great River Energy PPAs. In August 2014 and January 2015, Minnesota Power and Great River Energy signed long-term PPAs that provide for Minnesota Power to purchase 50 MW of capacity and energy under the first PPA and 50 MW of capacity only under the second PPA. The PPAs commence in June 2016 and expire in May 2020. Both contracts have fixed capacity pricing. The energy price in the first PPA is based on a formula that includes an annual fixed price component adjusted for changes in a natural gas index as well as market prices. Both PPAs are subject to MPUC approval.

Other Purchase Obligations. Other purchase obligations represent our minimum purchase commitments under coal and rail contracts. (See Note 12. Commitments, Guarantees and Contingencies.)

Credit Ratings. Access to reasonably priced capital markets is dependent in part on credit and ratings. Our securities have been rated by Standard & Poor’s and by Moody’s. Rating agencies use both quantitative and qualitative measures in determining a company’s credit rating. These measures include business risk, liquidity risk, competitive position, capital mix, financial condition, predictability of cash flows, management strength and future direction. Some of the quantitative measures can be analyzed through a few key financial ratios, while the qualitative ones are more subjective. Our current credit ratings are listed in the table below:

Credit Ratings
Standard & Poor’s
Moody’s
Issuer Credit Rating
BBB+
A3
Commercial Paper
A-2
P-2
First Mortgage Bonds
A
A1

The disclosure of these credit ratings is not a recommendation to buy, sell or hold our securities. Ratings are subject to revision or withdrawal at any time by the assigning rating organization. Each rating should be evaluated independently of any other rating.

Common Stock Dividends. ALLETE is committed to providing a competitive dividend to its shareholders while at the same time funding its growth. The Company’s long-term objective is to maintain a dividend payout ratio similar to our peers and provide for future dividend increases. In 2014, we paid out 68 percent (72 percent in 2013; 71 percent in 2012) of our per share earnings in dividends. On January 22, 2015, our Board of Directors declared a dividend of $0.505 per share, which is payable on March 1, 2015, to shareholders of record at the close of business on February 16, 2015.


ALLETE, Inc. 2014 Form 10-K
53


Liquidity and Capital Resources (Continued)

Capital Requirements

ALLETE’s projected capital expenditures for the years 2015 through 2019 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
2015

2016

2017

2018

2019

Total

Millions
 
 
 
 
 
 
Regulated Utility Operations
 
 
 
 
 
 
 
Base and Other

$135


$170


$160


$205


$125


$795

 
Cost Recovery (a)
 
 
 
 
 
 
 
Environmental (b)
90

10




100

 
Renewable
10





10

 
Transmission (c)
15

25

70

105

120

335

 
Total Cost Recovery
115

35

70

105

120

445

Regulated Utility Capital Expenditures
250

205

230

310

245

1,240

Other
 
30

30

30

30

25

145

Total Capital Expenditures

$280


$235


$260


$340


$270


$1,385

(a)
Estimated capital expenditures eligible for cost recovery outside of a rate case.
(b)
Environmental capital expenditures primarily related to compliance with the MATS rule for Boswell Unit 4 which reflect Minnesota Power’s ownership percentage of 80 percent. (See Note 12. Commitments, Guarantees and Contingencies.)
(c)
Transmission capital expenditures related to construction of the GNTL are estimated at approximately $315 million through 2019. (See Outlook – Regulated Operations.)

We are well positioned to meet our financing needs due to adequate operating cash flows, available additional working capital, and access to capital markets. We will finance capital expenditures from a combination of internally generated funds and debt and equity issuance proceeds. We intend to maintain a capital structure with capital ratios near current levels. (See Liquidity and Capital Resources Capital Structure.) Based on our projected capital expenditures reflected above, we project our rate base to grow by approximately 15 percent from 2014 year-end through 2019.

Environmental and Other Matters

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. 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 are unable to predict the outcome of the issues discussed in Note 12. Commitments, Guarantees and Contingencies. (See Item 1. Business – Environmental Matters.)

Market Risk

Securities Investments

Available-for-Sale Securities. At December 31, 2014, our available-for-sale securities portfolio consisted of securities held in other postretirement plans to fund employee benefits. (See Note 8. Investments.)

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. We may also enter into derivative financial instruments, such as interest rate swaps, to mitigate interest rate exposure. The table below presents the long-term debt obligations and the corresponding weighted average interest rate at December 31, 2014.

ALLETE, Inc. 2014 Form 10-K
54


Liquidity and Capital Resources (Continued)
Market Risk (Continued)

 
Expected Maturity Date
Interest Rate Sensitive
Financial Instruments
2015

2016

2017

2018

2019

Thereafter

Total

Fair Value
Dollars in Millions
 
 
 
 
 
 
 
 
Long-Term Debt
 
 
 
 
 
 
 
 
Fixed Rate

$4.7


$24.9


$54.6


$54.8


$46.9


$1,050.3


$1,236.2


$1,347.2

Average Interest Rate – %
5.3

7.3

6.0

2.2

7.9

4.5

4.7

 
 
 
 
 
 
 
 
 
 
Variable Rate

$96.0






$41.3


$137.3


$137.3

Average Interest Rate – % (a)
1.1





0.1

0.8

 
(a)
The $75 million term loan matures in 2015. It has an effective fixed rate of 1.625 percent for the remaining term due to an interest rate swap.

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 December 31, 2014, 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 $0.6 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 December 31, 2014.

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 framework, 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 (Minnesota Power) and natural gas (SWL&P).

Power Marketing. Our power marketing activities consist of: (1) purchasing energy in the wholesale market to serve our regulated service territory when 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 municipal customers in our regulated service territory. We actively sell any excess energy 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 include utilizing an established credit approval process and monitoring counterparty limits.

Recently Adopted Accounting Standards.

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


Item 7A. Quantitative and Qualitative Disclosures about Market Risk

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk for information related to quantitative and qualitative disclosure about market risk.


Item 8. Financial Statements and Supplementary Data

See our consolidated financial statements as of December 31, 2014 and 2013, and for each of the three years in the period ended December 31, 2014, and supplementary data, which are indexed in Item 15(a).



ALLETE, Inc. 2014 Form 10-K
55


Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.


Item 9A. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of December 31, 2014, 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.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) or 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the updated Internal Control – Integrated Framework (2013 framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The 2013 framework supersedes the original framework issued in 1992 and is effective for all dates after December 15, 2014. Based on our evaluation under the 2013 framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2014.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2014, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

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 undergoing a project with the objective of improving customer information systems. The focus of the project is the upgrade and addition of certain customer information 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 track power consumption, invoice customers, process payments, and analyze data. Implementation is expected in the first half of 2015.


Item 9B. Other Information

Not applicable.



ALLETE, Inc. 2014 Form 10-K
56


Part III

Item 10. Directors, Executive Officers and Corporate Governance

Unless otherwise stated, the information required by this Item is incorporated by reference herein from our Proxy Statement for the 2015 Annual Meeting of Shareholders (2015 Proxy Statement) under the following headings:

Directors. The information regarding directors will be included in the “Election of Directors” section;

Audit Committee Financial Expert. The information regarding the Audit Committee financial expert will be included in the “Corporate Governance” section and the “Audit Committee Report” section;

Audit Committee Members. The identity of the Audit Committee members will be included in the “Corporate Governance” section and the “Audit Committee Report” section;

Executive Officers. The information regarding executive officers is included in Part I of this Form 10-K; and

Section 16(a) Compliance. The information regarding Section 16(a) compliance will be included in the “Ownership of ALLETE Common Stock – Section 16(a) Beneficial Ownership Reporting Compliance” section.

Our 2015 Proxy Statement will be filed with the SEC within 120 days after the end of our 2014 fiscal year.

Code of Ethics. We have adopted a written Code of Ethics that applies to all of our employees, including our chief executive officer, chief financial officer and controller. A copy of our Code of Ethics is available on our website at www.allete.com and print copies are available without charge upon request to ALLETE, Inc., Attention: Secretary, 30 West Superior St., Duluth, Minnesota 55802. Any amendment to the Code of Ethics or any waiver of the Code of Ethics will be disclosed on our website at www.allete.com promptly following the date of such amendment or waiver.

Corporate Governance. The following documents are available on our website at www.allete.com and print copies are available upon request:

Corporate Governance Guidelines;

Audit Committee Charter;

Executive Compensation Committee Charter; and

Corporate Governance and Nominating Committee Charter.

Any amendment to these documents will be disclosed on our website at www.allete.com promptly following the date of such amendment.


Item 11. Executive Compensation

The information required for this Item is incorporated by reference herein from the “Compensation Discussion and Analysis,” the “Compensation of Executive Officers,” the “Compensation Committee Report” and the “Director Compensation” sections in our 2015 Proxy Statement.


Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required for this Item is incorporated by reference herein from the “Ownership of ALLETE Common Stock – Securities Owned by Certain Beneficial Owners,” the “Ownership of ALLETE Common Stock – Securities Owned by Directors and Management” and the “Equity Compensation Plan Information” sections in our 2015 Proxy Statement.



ALLETE, Inc. 2014 Form 10-K
57


Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required for this Item is incorporated by reference herein from the “Corporate Governance” section in our 2015 Proxy Statement.

We have adopted a Related Person Transaction Policy which is available on our website at www.allete.com. Print copies are available without charge, upon request. Any amendment to this policy will be disclosed on our website at www.allete.com promptly following the date of such amendment.


Item 14. Principal Accounting Fees and Services

The information required for this Item is incorporated by reference herein from the “Audit Committee Report” section in our 2015 Proxy Statement.


Part IV


Item 15.     Exhibits and Financial Statement Schedules
(a)
Certain Documents Filed as Part of this Form 10-K.
 
(1)
Financial Statements
Page
 
ALLETE
 
 
 
Consolidated Balance Sheet at December 31, 2014 and 2013
 
For the Three Years Ended December 31, 2014
 
 
 
 
 
 
(2)
Financial Statement Schedules
 
 
 
All other schedules have been omitted either because the information is not required to be reported by ALLETE or because the information is included in the consolidated financial statements or the notes.
(3)
Exhibits including those incorporated by reference.
 


ALLETE, Inc. 2014 Form 10-K
58


Exhibit Number
*3(a)1
Articles of Incorporation, amended and restated as of May 8, 2001 (filed as Exhibit 3(b) to the March 31, 2001,
Form 10-Q, File No. 1-3548).
*3(a)2
Amendment to Articles of Incorporation, dated as of September 20, 2004 (filed as Exhibit 3 to the September 21, 2004, Form 8-K, File No. 1-3548).
*3(a)3
Amendment to Articles of Incorporation, dated as of May 12, 2009 (filed as Exhibit 3 to the June 30, 2009, Form 10-Q, File No. 1-3548).
*3(a)4
Amendment to Articles of Incorporation, dated as of May 11, 2010 (filed as Exhibit 3(a) to the May 14, 2010, Form 8-K, File No. 1-3548).
*3(a)5
Amendment to Certificate of Assumed Name, filed with the Minnesota Secretary of State on May 8, 2001 (filed as
Exhibit 3(a) to the March 31, 2001, Form 10-Q, File No. 1-3548).
*3(b)
Bylaws, as amended effective May 11, 2010 (filed as Exhibit 3(b) to the May 14, 2010, Form 8-K, File No. 1-3548).
*4(a)1
Mortgage and Deed of Trust, dated as of September 1, 1945, between Minnesota Power & Light Company (now ALLETE) and The Bank of New York Mellon (formerly Irving Trust Company) and Philip L. Watson (successor to Richard H. West), Trustees (filed as Exhibit 7(c), File No. 2-5865).
*4(a)2
Supplemental Indentures to ALLETE’s Mortgage and Deed of Trust:
 
 
Number
Dated as of
Reference File
Exhibit
 
 
First
March 1, 1949
2-7826
7(b)
 
 
Second
July 1, 1951
2-9036
7(c)
 
 
Third
March 1, 1957
2-13075
2(c)
 
 
Fourth
January 1, 1968
2-27794
2(c)
 
 
Fifth
April 1, 1971
2-39537
2(c)
 
 
Sixth
August 1, 1975
2-54116
2(c)
 
 
Seventh
September 1, 1976
2-57014
2(c)
 
 
Eighth
September 1, 1977
2-59690
2(c)
 
 
Ninth
April 1, 1978
2-60866
2(c)
 
 
Tenth
August 1, 1978
2-62852
2(d)2
 
 
Eleventh
December 1, 1982
2-56649
4(a)3
 
 
Twelfth
April 1, 1987
33-30224
4(a)3
 
 
Thirteenth
March 1, 1992
33-47438
4(b)
 
 
Fourteenth
June 1, 1992
33-55240
4(b)
 
 
Fifteenth
July 1, 1992
33-55240
4(c)
 
 
Sixteenth
July 1, 1992
33-55240
4(d)
 
 
Seventeenth
February 1, 1993
33-50143
4(b)
 
 
Eighteenth
July 1, 1993
33-50143
4(c)
 
 
Nineteenth
February 1, 1997
1-3548 (1996 Form 10-K)
4(a)3
 
 
Twentieth
November 1, 1997
1-3548 (1997 Form 10-K)
4(a)3
 
 
Twenty-first
October 1, 2000
333-54330
4(c)3
 
 
Twenty-second
July 1, 2003
1-3548 (June 30, 2003 Form 10-Q)
4
 
 
Twenty-third
August 1, 2004
1-3548 (Sept. 30, 2004 Form 10-Q)
4(a)
 
 
Twenty-fourth
March 1, 2005
1-3548 (March 31, 2005 Form 10-Q)
4
 
 
Twenty-fifth
December 1, 2005
1-3548 (March 31, 2006 Form 10-Q)
4
 
 
Twenty-sixth
October 1, 2006
1-3548 (2006 Form 10-K)
4
 
 
Twenty-seventh
February 1, 2008
1-3548 (2007 Form 10-K)
4(a)3
 
 
Twenty-eighth
May 1, 2008
1-3548 (June 30, 2008 Form 10-Q)
4
 
 
Twenty-ninth
November 1, 2008
1-3548 (2008 Form 10-K)
4(a)3
 
 
Thirtieth
January 1, 2009
1-3548 (2008 Form 10-K)
4(a)4
 
 
Thirty-first
February 1, 2010
1-3548 (March 31, 2010 Form 10-Q)
4
 
 
Thirty-second
August 1, 2010
1-3548 (Sept. 30, 2010 Form 10-Q)
4
 
 
Thirty-third
July 1, 2012
1-3548 (July 2, 2012 Form 8-K)
4
 
 
Thirty-fourth
April 1, 2013
1-3548 (April 2, 2013 Form 8-K)
4

ALLETE, Inc. 2014 Form 10-K
59


Exhibit Number
 
 
Thirty-fifth
March 1, 2014
1-3548 (March 31, 2014 Form 10-Q)
4
 
 
Thirty-sixth
June 1, 2014
1-3548 (June 30, 2014 Form 10-Q)
4
 
 
Thirty-seventh
September 1, 2014
1-3548 (Sept. 30, 2014 Form 10-Q)
4
*4(b)1

Mortgage and Deed of Trust, dated as of March 1, 1943, between Superior Water, Light and Power Company and Chemical Bank & Trust Company and Howard B. Smith, as Trustees, both succeeded by U.S. Bank National Association, as Trustee (filed as Exhibit 7(c), File No. 2-8668).
*4(b)2

Supplemental Indentures to Superior Water, Light and Power Company’s Mortgage and Deed of Trust:
 
 
Number
Dated as of
Reference File
Exhibit
 
 
First
March 1, 1951
2-59690
2(d)(1)
 
 
Second
March 1, 1962
2-27794
2(d)1
 
 
Third
July 1, 1976
2-57478
2(e)1
 
 
Fourth
March 1, 1985
2-78641
4(b)
 
 
Fifth
December 1, 1992
1-3548 (1992 Form 10-K)
4(b)1
 
 
Sixth
March 24, 1994
1-3548 (1996 Form 10-K)
4(b)1
 
 
Seventh
November 1, 1994
1-3548 (1996 Form 10-K)
4(b)2
 
 
Eighth
January 1, 1997
1-3548 (1996 Form 10-K)
4(b)3
 
 
Ninth
October 1, 2007
1-3548 (2007 Form 10-K)
4(c)3
 
 
Tenth
October 1, 2007
1-3548 (2007 Form 10-K)
4(c)4
 
 
Eleventh
December 1, 2008
1-3548 (2008 Form 10-K)
4(c)3
 
 
Twelfth
December 2, 2013
1-3548 (2013 Form 10-K)
4(c)3
*4(c)

Note Purchase Agreement, dated as of June 8, 2007, between ALLETE and Thrivent Financial for Lutherans and The Northwestern Mutual Life Insurance Company (filed as Exhibit 10(a) to the June 30, 2007, Form 10-Q, File No. 1-3548).
*4(d)

Term Loan Agreement, dated as of August 25, 2011, between ALLETE, Inc. and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 4 to the August 31, 2011, Form 8-K, File No. 1-3548).
*4(e)

First Amendment dated as of August 26, 2013, to Term Loan Agreement dated as of August 25, 2011, between ALLETE, Inc. and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 4 to the September 30, 2013,
Form 10-Q, File No. 1-3548).
*10(a)

Power Purchase and Sale Agreement, dated as of May 29, 1998, between Minnesota Power, Inc. (now ALLETE) and Square Butte Electric Cooperative (filed as Exhibit 10 to the June 30, 1998, Form 10-Q, File No. 1-3548).
*10(b)

Credit Agreement dated as of November 4, 2013 among ALLETE, 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 November 4, 2013, Form 8-K, File No. 1-3548).

*10(c)1

Financing Agreement between Collier County Industrial Development Authority and ALLETE dated as of July 1, 2006 (filed as Exhibit 10(b)1 to the June 30, 2006, Form 10-Q, File No. 1-3548).
*10(c)2

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 (filed as Exhibit 10(b) to the June 30, 2011, Form 10-Q, File No. 1-3548).
*10(c)3

First Amendment to Amended and Restated Letter of Credit Agreement, dated as of June 1, 2013, between ALLETE and Wells Fargo Bank, National Association, as Issuing Bank, Administrative Agent and sole Participating Bank (filed as Exhibit 10(b) to the June 30, 2013, Form 10-Q, File No. 1-3548).
*10(d)

Agreement dated December 16, 2005, among ALLETE, Wisconsin Public Service Corporation and WPS Investments, LLC (filed as Exhibit 10(g) to the 2009 Form 10-K, File No. 1-3548).
+*10(e)1

ALLETE Executive Annual Incentive Plan, as amended and restated, effective January 1, 2011 (filed as Exhibit 10(h)1 to the 2010 Form 10-K, File No. 1-3548).
+*10(e)2

ALLETE Executive Annual Incentive Plan Form of Awards Effective 2011 (filed as Exhibit 10(h)4 to the 2010
Form 10-K, File No. 1-3548).
+*10(e)3

ALLETE Executive Annual Incentive Plan Form of Awards Effective 2012 (filed as Exhibit 10(h)4 to the 2011
Form 10-K, File No. 1-3548).
+*10(e)4

ALLETE Executive Annual Incentive Plan Form of Awards Effective 2013 (filed as Exhibit 10(f)5 to the 2012
Form 10-K, File No. 1-3548).
+*10(e)5

ALLETE Executive Annual Incentive Plan Form of Awards Effective 2014 (filed as Exhibit 10(e)6 to the 2013 Form 10-K, File No. 1-3548).
+10(e)6

ALLETE Executive Annual Incentive Plan Form of Awards Effective 2015.
+*10(f)1

ALLETE and Affiliated Companies Supplemental Executive Retirement Plan (SERP I), as amended and restated, effective January 1, 2009 (filed as Exhibit 10(i)4 to the 2008 Form 10-K, File No. 1-3548).
+*10(f)2

Amendment to the ALLETE and Affiliated Companies Supplemental Executive Retirement Plan (SERP I), effective January 1, 2011 (filed as Exhibit 10(i)2 to the 2010 Form 10-K, File No. 1-3548).

ALLETE, Inc. 2014 Form 10-K
60


Exhibit Number
+10(f)3

ALLETE and Affiliated Companies Supplemental Executive Retirement Plan II (SERP II), as amended and restated, effective January 1, 2015.
+*10(g)1

Minnesota Power and Affiliated Companies Executive Investment Plan I, as amended and restated, effective November 1, 1988 (filed as Exhibit 10(c) to the 1988 Form 10-K, File No. 1-3548).
+*10(g)2

Amendments through December 2003 to the Minnesota Power and Affiliated Companies Executive Investment Plan I (filed as Exhibit 10(v)2 to the 2003 Form 10-K, File No. 1-3548).
+*10(g)3

July 2004 Amendment to the Minnesota Power and Affiliated Companies Executive Investment Plan I (filed as
Exhibit 10(b) to the June 30, 2004, Form 10-Q, File No. 1-3548).
+*10(g)4

August 2006 Amendment to the Minnesota Power and Affiliated Companies Executive Investment Plan I (filed as
Exhibit 10(b) to the September 30, 2006, Form 10-Q, File No. 1-3548).
+*10(h)1

Minnesota Power and Affiliated Companies Executive Investment Plan II, as amended and restated, effective November 1, 1988 (filed as Exhibit 10(d) to the 1988 Form 10-K, File No. 1-3548).
+*10(h)2

Amendments through December 2003 to the Minnesota Power and Affiliated Companies Executive Investment Plan II (filed as Exhibit 10(w)2 to the 2003 Form 10-K, File No. 1-3548).
+*10(h)3

July 2004 Amendment to the Minnesota Power and Affiliated Companies Executive Investment Plan II (filed as
Exhibit 10(c) to the June 30, 2004, Form 10-Q, File No. 1-3548).
+*10(h)4

August 2006 Amendment to the Minnesota Power and Affiliated Companies Executive Investment Plan II (filed as
Exhibit 10(c) to the September 30, 2006, Form 10-Q, File No. 1-3548).
+*10(i)

ALLETE Deferred Compensation Trust Agreement, as amended and restated, effective December 15, 2012 (filed as
Exhibit 10(j) to the 2012 Form 10-K, File No. 1-3548).
+*10(j)1

ALLETE Executive Long-Term Incentive Compensation Plan as amended and restated effective January 1, 2006 (filed as Exhibit 10 to the May 16, 2005, Form 8-K, File No. 1-3548).
+*10(j)2

Amendment to the ALLETE Executive Long-Term Incentive Compensation Plan, effective January 1, 2011 (filed as Exhibit 10(m)2 to the 2010 Form 10-K, File No. 1-3548).
+*10(j)3

Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2009 (filed as Exhibit 10(m)11 to the 2008 Form 10-K, File No. 1-3548).
+*10(j)4

Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2009 (filed as Exhibit 10(m)12 to the 2008 Form 10-K, File No. 1-3548).
+*10(j)5

Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2010 (filed as Exhibit 10(m)8 to the 2009 Form 10-K, File No. 1-3548).
+*10(j)6

Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2010 (filed as Exhibit 10(m)9 to the 2009 Form 10-K, File No. 1-3548).
+*10(j)7

Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2011 (filed as Exhibit 10(m)11 to the 2010 Form 10-K, File No. 1-3548).
+*10(j)8

Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2011 (filed as Exhibit 10(m)12 to the 2010 Form 10-K, File No. 1-3548).
+*10(j)9

Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2012 (filed as Exhibit 10(m)12 to the 2011 Form 10-K, File No. 1-3548).
+*10(j)10

Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2012 (filed as Exhibit 10(m)13 to the 2011 Form 10-K, File No. 1-3548).
+*10(j)11

Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2013 (filed as Exhibit 10(k)14 to the 2012 Form 10-K, File No. 1-3548).
+*10(j)12

Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2013 (filed as Exhibit 10(k)15 to the 2012 Form 10-K, File No. 1-3548).
+*10(j)14

Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2014 (filed as Exhibit 10(j)14 to the 2013 Form 10-K, File No. 1-3548).
+*10(j)15

Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2014 (filed as Exhibit 10(j)15 to the 213 Form 10-K, File No. 1-3548).
+10(j)16

Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2015.
+10(j)17

Form of ALLETE Executive Long-Term Incentive Compensation Plan Restricted Stock Unit Grant Effective 2015.
+*10(k)1

Minnesota Power (now ALLETE) Non-Employee Director Stock Plan, effective May 9, 1995 (filed as Exhibit 10 to the
March 31, 1995, Form 10-Q, File No. 1-3548).
+*10(k)2

Amendments through December 2003 to the Minnesota Power (now ALLETE) Non-Employee Director Stock Plan (filed as Exhibit 10(z)2 to the 2003 Form 10-K, File No. 1-3548).
+*10(k)3

July 2004 Amendment to the ALLETE Non-Employee Director Stock Plan (filed as Exhibit 10(e) to the June 30, 2004, Form 10-Q, File No. 1-3548).
+*10(k)4

January 2007 Amendment to the ALLETE Non-Employee Director Stock Plan (filed as Exhibit 10(n)4 to the 2006 Form 10‑K, File No. 1-3548).
+*10(k)5

May 2009 Amendment to the ALLETE Non-Employee Director Stock Plan (filed as Exhibit 10(b) to the June 30, 2009, Form 10-Q, File No. 1-3548).

ALLETE, Inc. 2014 Form 10-K
61


Exhibit Number
+*10(k)6

May 2010 Amendment to the ALLETE Non-Employee Director Stock Plan (filed as Exhibit 10(a) to the June 30, 2010, Form 10-Q, File No. 1-3548).
+*10(k)7

October 2010 Amendment to the ALLETE Non-Employee Director Stock Plan (filed as Exhibit 10 to the September 30, 2010, Form 10-Q, File No. 1-3548).
+*10(k)8

Amended and Restated ALLETE Non-Employee Director Stock Plan, effective May 15, 2013 (filed as Exhibit 10(a) to the June 30, 2013, Form 10-Q, File No. 1-3548).
+*10(l)1

ALLETE Non-Management Director Compensation Summary Effective May 1, 2010 (filed as Exhibit 10(b) to the March 31, 2010, Form 10-Q, File No. 1-3548).
+*10(l)2

ALLETE Non-Management Director Compensation Summary effective January 19, 2011 (filed as Exhibit 10(n)9 to the 2010 Form 10-K, File No. 1-3548).
+*10(l)3

ALLETE Non-Management Director Compensation Summary effective January 19, 2012 (filed as Exhibit 10(n)10 to the 2011 Form 10-K, File No. 1-3548).
+*10(l)4

ALLETE Non-Management Director Compensation Summary effective January 1, 2014 (filed as Exhibit 10(l)4 to the 2013 Form 10-K, File No. 1-3548).
+10(l)5

ALLETE Non-Employee Director Compensation Summary effective January 1, 2015.
+*10(m)1

Minnesota Power (now ALLETE) Non-Employee Director Compensation Deferral Plan Amended and Restated, effective
January 1, 1990 (filed as Exhibit 10(ac) to the 2002 Form 10-K, File No. 1-3548).
+*10(m)2

October 2003 Amendment to the Minnesota Power (now ALLETE) Non-Employee Director Compensation Deferral Plan (filed as Exhibit 10(aa)2 to the 2003 Form 10-K, File No. 1-3548).
+*10(m)3

January 2005 Amendment to the ALLETE Non-Employee Director Compensation Deferral Plan (filed as Exhibit 10(c) to the March 31, 2005, Form 10-Q, File No. 1-3548).
+*10(m)4

October 2006 Amendment to the ALLETE Non-Employee Director Compensation Deferral Plan (filed as Exhibit 10(d) to the September 30, 2006, Form 10-Q, File No. 1-3548).
+*10(m)5

July 2012 Amendment to the ALLETE Non-Employee Director Compensation Deferral Plan (filed as Exhibit 10(n)5 to the 2012 Form 10-K, File No. 1-3548).
+*10(n)1

ALLETE Non-Employee Director Compensation Deferral Plan II, effective May 1, 2009 (filed as Exhibit 10(a) to the June 30, 2009, Form 10-Q, File No. 1-3548).
+*10(n)2

ALLETE Non-Employee Director Compensation Deferral Plan II, as amended and restated, effective July 24, 2012 (filed as Exhibit 10(o)2 to the 2012 Form 10-K, File No. 1-3548).
+*10(o)1

ALLETE Non-Employee Director Compensation Trust Agreement, effective October 11, 2004 (filed as Exhibit 10(a) to the September 30, 2004, Form 10-Q, File No. 1-3548).
+*10(o)2

ALLETE Non-Employee Director Compensation Trust Agreement, as amended and restated, effective December 15, 2012 (filed as Exhibit 10(p)2 to the 2012 Form 10-K, File No. 1-3548).
+*10(p)

July 2013 ALLETE and Affiliated Companies Compensation Recovery Policy (filed as Exhibit 10(c) to the June 30, 2013, Form 10-Q, File No. 1-3548).
+*10(q)

ALLETE and Affiliated Companies Change in Control Severance Plan, as amended and restated, effective January 19, 2011 (filed as Exhibit 10(q) to the 2010 Form 10-K, File No. 1-3548).
12

Computation of Ratios of Earnings to Fixed Charges.
21

Subsidiaries of the Registrant.
23

Consent of Independent Registered Public Accounting Firm.
31(a)

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

Rule 13a-14(a)/15d-14(a) Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32

Section 1350 Certification of Annual Report by the Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
95

Mine Safety.
99

ALLETE News Release dated February 17, 2015, announcing earnings for the year ended December 31, 2014. (This exhibit has been furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, except as shall be expressly set forth by specific reference in such filing.)
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, Inc. 2014 Form 10-K
62


Exhibits (Continued)

ALLETE or its subsidiaries are obligors under various long-term debt instruments, including but not limited to, (1) $38,995,000 original principal amount, of City of Cohasset, Minnesota, Variable Rate Demand Revenue Refunding Bonds (ALLETE, formerly Minnesota Power & Light Company, Project) Series 1997A ($24,630,000 remaining principal balance); (2) $6,370,000 of City of Superior, Wisconsin, Collateralized Utility Revenue Refunding Bonds Series 2007A and $6,130,000 of City of Superior, Wisconsin, Collateralized Utility Revenue Bonds Series 2007B; and (3) other long-term debt instruments that, pursuant to Regulation S-K, Item 601(b)(4)(iii), are not filed as exhibits because the total amount of debt authorized under each of these omitted instruments does not exceed 10 percent of our total consolidated assets. We will furnish copies of these instruments to the SEC upon its request.

*
Incorporated herein by reference as indicated.
+
Management contract or compensatory plan or arrangement pursuant to Item 15(b).



ALLETE, Inc. 2014 Form 10-K
63


Signatures

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

 
 
ALLETE, Inc.
 
 
 
 
Dated:
February 17, 2015
By
 /s/ Alan R. Hodnik
 
 
Alan R. Hodnik
 
 
Chairman, President, Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature
 
Title
 
Date
 
 
 
 
 
/s/ Alan R. Hodnik
 
Chairman, President, Chief Executive Officer and Director
 
February 17, 2015
Alan R. Hodnik
 
(Principal Executive Officer)
 
 
 
 
 
 
 
/s/ Steven Q. DeVinck
 
Senior Vice President and Chief Financial Officer
 
February 17, 2015
Steven Q. DeVinck
 
(Principal Financial Officer)
 
 
 
 
 
 
 
/s/ Steven W. Morris
 
Controller
 
February 17, 2015
Steven W. Morris
 
(Principal Accounting Officer)
 
 

ALLETE, Inc. 2014 Form 10-K
64


Signatures (Continued)
Signature
 
Title
 
Date
 
 
 
 
 
/s/ Kathryn W. Dindo
 
Director
 
February 17, 2015
Kathryn W. Dindo
 
 
 
 
 
 
 
 
 
/s/ Sidney W. Emery, Jr.
 
Director
 
February 17, 2015
Sidney W. Emery, Jr.
 
 
 
 
 
 
 
 
 
/s/ George G. Goldfarb
 
Director
 
February 17, 2015
George G. Goldfarb
 
 
 
 
 
 
 
 
 
/s/ James S. Haines, Jr.
 
Director
 
February 17, 2015
James S. Haines, Jr.
 
 
 
 
 
 
 
 
 
/s/ James J. Hoolihan
 
Director
 
February 17, 2015
James J. Hoolihan
 
 
 
 
 
 
 
 
 
/s/ Heidi E. Jimmerson
 
Director
 
February 17, 2015
Heidi E. Jimmerson
 
 
 
 
 
 
 
 
 
/s/ Madeleine W. Ludlow
 
Director
 
February 17, 2015
Madeleine W. Ludlow
 
 
 
 
 
 
 
 
 
/s/ Douglas C. Neve
 
Director
 
February 17, 2015
Douglas C. Neve
 
 
 
 
 
 
 
 
 
/s/ Leonard C. Rodman
 
Director
 
February 17, 2015
Leonard C. Rodman
 
 
 
 


ALLETE, Inc. 2014 Form 10-K
65



Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of ALLETE, Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, shareholders’ equity and cash flows present fairly, in all material respects, the financial position of ALLETE, Inc. and its subsidiaries (the Company) at December 31, 2014 and December 31, 2013 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014 based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP
Minneapolis, Minnesota
February 17, 2015


ALLETE, Inc. 2014 Form 10-K
66


CONSOLIDATED FINANCIAL STATEMENTS

ALLETE Consolidated Balance Sheet

As of December 31
2014

2013

Millions
 
 
Assets
 
 
Current Assets
 
 
Cash and Cash Equivalents

$145.8


$97.3

Accounts Receivable (Less Allowance of $1.1 and $1.1)
103.0

96.3

Inventories
80.5

59.3

Prepayments and Other
82.0

35.1

Deferred Income Taxes
7.5

19.0

Total Current Assets
418.8

307.0

Property, Plant and Equipment – Net
3,286.4

2,576.5

Regulatory Assets
357.3

263.8

Investment in ATC
121.1

114.6

Other Investments
114.4

146.3

Other Non-Current Assets
62.8

68.6

Total Assets

$4,360.8


$3,476.8

Liabilities and Equity
 
 
Liabilities
 
 
Current Liabilities
 
 
Accounts Payable

$134.1


$99.9

Accrued Taxes
38.7

34.8

Accrued Interest
18.0

15.7

Long-Term Debt Due Within One Year
100.7

27.2

Notes Payable
3.7


Other
120.8

52.6

Total Current Liabilities
416.0

230.2

Long-Term Debt
1,272.8

1,083.0

Deferred Income Taxes
510.7

479.1

Regulatory Liabilities
94.2

81.0

Defined Benefit Pension and Other Postretirement Benefit Plans
190.9

133.4

Other Non-Current Liabilities
265.0

127.2

Total Liabilities
2,749.6

2,133.9

Commitments, Guarantees and Contingencies (Note 12)


Equity
 
 
ALLETE’s Equity
 
 
Common Stock Without Par Value, 80.0 Shares Authorized, 45.9 and 41.4 Shares Outstanding
1,107.6

885.2

Unearned ESOP Shares
(7.2
)
(14.3
)
Accumulated Other Comprehensive Loss
(21.1
)
(17.1
)
Retained Earnings
530.1

489.1

Total ALLETE Equity
1,609.4

1,342.9

Non-Controlling Interest in Subsidiaries
1.8


Total Equity
1,611.2

1,342.9

Total Liabilities and Equity

$4,360.8


$3,476.8


The accompanying notes are an integral part of these statements.

ALLETE, Inc. 2014 Form 10-K
67


ALLETE Consolidated Statement of Income

Year Ended December 31
2014

2013

2012

Millions Except Per Share Amounts
 
 
 
Operating Revenue

$1,136.8


$1,018.4


$961.2

Operating Expenses
 
 
 
Fuel and Purchased Power
356.1

334.8

308.7

Operating and Maintenance
456.2

412.9

397.1

Depreciation
135.7

116.6

100.2

Total Operating Expenses
948.0

864.3

806.0

Operating Income
188.8

154.1

155.2

Other Income (Expense)
 
 
 
Interest Expense
(54.8
)
(50.3
)
(45.5
)
Equity Earnings in ATC
19.6

20.3

19.4

Other
8.6

9.3

6.0

Total Other Expense
(26.6
)
(20.7
)
(20.1
)
Income Before Non-Controlling Interest and Income Taxes
162.2

133.4

135.1

Income Tax Expense
36.7

28.7

38.0

Net Income
125.5

104.7

97.1

Less: Non-Controlling Interest in Subsidiaries
0.7



Net Income Attributable to ALLETE

$124.8


$104.7


$97.1

Average Shares of Common Stock
 
 
 
Basic
42.9

39.7

37.6

Diluted
43.1

39.8

37.6

Basic Earnings Per Share of Common Stock

$2.91


$2.64


$2.59

Diluted Earnings Per Share of Common Stock

$2.90


$2.63


$2.58

Dividends Per Share of Common Stock

$1.96


$1.90


$1.84


The accompanying notes are an integral part of these statements.


ALLETE, Inc. 2014 Form 10-K
68


ALLETE Consolidated Statement of Comprehensive Income
 
 
 
 
Comprehensive Income
 
 
 
Year Ended December 31
2014

2013

2012

Millions
 
 
 
Net Income

$125.5


$104.7


$97.1

Other Comprehensive Income (Loss)
 
 
 
Unrealized Gain (Loss) on Securities
 
 
 
Net of Income Taxes of $(0.2), $– and $0.8
(0.2
)

1.2

Unrealized Gain (Loss) on Derivatives
 
 
 
Net of Income Taxes of $0.1, $– and $(0.1)
0.2

0.1

(0.2
)
Defined Benefit Pension and Other Postretirement Benefit Plans
 
 
 
Net of Income Taxes of $(2.8), $3.3 and $3.9
(4.0
)
4.8

5.9

Total Other Comprehensive Income (Loss)
(4.0
)
4.9

6.9

Total Comprehensive Income
121.5

109.6

104.0

Less: Non-Controlling Interest in Subsidiaries
0.7



Comprehensive Income Attributable to ALLETE

$120.8


$109.6


$104.0


The accompanying notes are an integral part of these statements.




ALLETE, Inc. 2014 Form 10-K
69


ALLETE Consolidated Statement of Cash Flows

Year Ended December 31
2014

2013

2012

Millions
 
 
 
Operating Activities
 
 
 
Net Income

$125.5


$104.7


$97.1

Allowance for Funds Used During Construction – Equity
(7.8
)
(4.6
)
(5.1
)
Income from Equity Investments, Net of Dividends
(2.6
)
(4.2
)
(3.7
)
Loss (Gain) on Sale of Assets / Investments
(0.2
)
(2.6
)
0.2

Depreciation Expense
135.7

116.6

100.2

Other Amortization
0.7

1.0

1.0

Amortization of Power Purchase Agreements
(12.7
)


Deferred Income Tax Expense
32.7

28.6

37.5

Share-Based Compensation Expense
2.3

2.4

2.1

ESOP Compensation Expense
9.1

8.4

7.7

Defined Benefit Pension and Other Postretirement Benefit Expense
12.8

21.0

27.5

Bad Debt Expense
1.8

1.3

1.0

Changes in Operating Assets and Liabilities
 
 
 
Accounts Receivable
(3.5
)
(8.6
)
(10.1
)
Inventories
(17.5
)
10.5

(0.7
)
Prepayments and Other
4.8

(1.4
)
(6.5
)
Accounts Payable
10.9

1.1

(1.5
)
Other Current Liabilities
(3.5
)
1.4

21.8

Cash Contributions to Defined Benefit Pension and Other
Postretirement Plans

(10.8
)
(8.8
)
Changes in Regulatory and Other Non-Current Assets
(21.3
)
(18.3
)
(20.9
)
Changes in Regulatory and Other Non-Current Liabilities
2.6

(7.1
)
0.8

Cash from Operating Activities
269.8

239.4

239.6

Investing Activities
 
 
 
Proceeds from Sale of Available-for-sale Securities
3.6

16.1

1.5

Payments for Purchase of Available-for-sale Securities
(5.0
)
(4.7
)
(1.8
)
Acquisitions of Subsidiaries – Net of Cash Acquired
(60.3
)


Investment in ATC
(3.9
)
(3.1
)
(4.7
)
Changes to Other Investments
33.0

(12.3
)
(9.6
)
Additions to Property, Plant and Equipment
(572.8
)
(328.5
)
(405.8
)
Construction Costs for Development Project
(25.7
)


Cash in Escrow for Acquisition
5.4

(5.4
)

Proceeds from Sale of Assets

1.3

0.3

Cash for Investing Activities
(625.7
)
(336.6
)
(420.1
)
Financing Activities
 
 
 
Proceeds from Issuance of Common Stock
200.6

98.2

77.0

Proceeds from Issuance of Long-Term Debt
375.0

169.8

180.6

Changes in Restricted Cash
(1.8
)


Changes in Notes Payable
3.7


(1.1
)
Reductions of Long-Term Debt
(134.5
)
(77.7
)
(25.9
)
Acquisition of Non-Controlling Interest
(6.0
)


Construction Deposits Received for Development Project
54.3



Debt Issuance Costs
(3.1
)
(1.4
)
(1.3
)
Dividends on Common Stock
(83.8
)
(75.2
)
(69.1
)
Cash from Financing Activities
404.4

113.7

160.2

Change in Cash and Cash Equivalents
48.5

16.5

(20.3
)
Cash and Cash Equivalents at Beginning of Period
97.3

80.8

101.1

Cash and Cash Equivalents at End of Period

$145.8


$97.3


$80.8


The accompanying notes are an integral part of these statements.

ALLETE, Inc. 2014 Form 10-K
70


ALLETE Consolidated Statement of Shareholders’ Equity

 
Total
Shareholders’
Equity
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Unearned
ESOP
Shares
Common
Stock
Millions
 
 
 
 
 
Balance as of December 31, 2011

$1,079.3


$431.6

$(28.9)
$(29.0)

$705.6

Comprehensive Income
 
 
 
 
 
Net Income
97.1

97.1

 
 
 
Other Comprehensive Income – Net of Tax
 
 
 
 
 
Unrealized Gain on Securities – Net
1.2

 
1.2

 
 
Unrealized Loss on Derivatives – Net
(0.2
)
 
(0.2
)
 
 
Defined Benefit Pension and Other Postretirement Plans – Net
5.9

 
5.9

 
 
Total Comprehensive Income Attributable to ALLETE
104.0

 
 
 
 
Common Stock Issued – Net
79.1

 
 
 
79.1

Dividends Declared
(69.1
)
(69.1
)
 
 
 
ESOP Shares Earned
7.7

 
 
7.7

 
Balance as of December 31, 2012
1,201.0

459.6

(22.0
)
(21.3
)
784.7

Comprehensive Income
 
 
 
 
 
Net Income
104.7

104.7

 
 
 
Other Comprehensive Income – Net of Tax
 
 
 
 
 
Unrealized Gain on Derivatives – Net
0.1

 
0.1

 
 
Defined Benefit Pension and Other Postretirement Plans – Net
4.8

 
4.8

 
 
Total Comprehensive Income Attributable to ALLETE
109.6

 
 
 
 
Common Stock Issued – Net
100.5

 
 
 
100.5

Dividends Declared
(75.2
)
(75.2
)
 
 
 
ESOP Shares Earned
7.0

 
 
7.0

 
Balance as of December 31, 2013
1,342.9

489.1

(17.1
)
(14.3
)
885.2

Comprehensive Income
 
 
 
 
 
Net Income
125.5

125.5

 
 
 
Other Comprehensive Income – Net of Tax
 
 
 
 
 
Unrealized Loss on Securities – Net
(0.2
)
 
(0.2
)
 
 
Unrealized Gain on Derivatives – Net
0.2

 
0.2

 
 
Defined Benefit Pension and Other Postretirement Plans – Net
(4.0
)
 
(4.0
)
 
 
Total Comprehensive Income
121.5

 
 
 
 
Non-Controlling Interest in Subsidiaries
(0.7
)
(0.7
)
 
 
 
Total Comprehensive Income Attributable to ALLETE
120.8

 
 
 
 
Common Stock Issued – Net
222.4

 
 
 
222.4

Dividends Declared
(83.8
)
(83.8
)
 
 
 
ESOP Shares Earned
7.1

 
 
7.1

 
Balance as of December 31, 2014

$1,609.4


$530.1

$(21.1)
$(7.2)

$1,107.6


The accompanying notes are an integral part of these statements.

ALLETE, Inc. 2014 Form 10-K
71


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Preparation. References in this report to “we,” “us,” and “our” are to ALLETE and its subsidiaries, collectively. We prepare our financial statements in conformity with accounting principles generally accepted in the United States of America. These principles require management to make informed judgments, best estimates, and assumptions that affect the reported amounts of assets, liabilities, revenue, and expenses. Actual results could differ from those estimates.

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

On February 10, 2015, ALLETE acquired U.S. Water Services for $168 million and a contingent amount to be paid in 2019 based on U.S. Water Services’ future earnings. U.S. Water Services, an integrated industrial water management company headquartered in St. Michael, Minnesota, has a national footprint serving a growing and diverse mix of over 3,600 industrial customers, with recurring revenues and customer retention that exceeds 90 percent. U.S. Water Services provides integrated water management for industry, combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage and improve efficiency. U.S. Water Services helps customers achieve efficient and sustainable use of their energy systems, is a leading provider to the biofuels industry, and has a growing presence in the power generation and midstream oil and gas industries. The acquisition of U.S. Water Services is consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services to complement its core regulated utility, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth. We expect to finalize the allocation of the purchase price during the first half of 2015. Transaction costs related to the acquisition were expensed as incurred and were not material to the 2014 Consolidated Statement of Income.

Principles of Consolidation. Our consolidated financial statements include the accounts of ALLETE and all of our majority-owned subsidiary companies. All material intercompany balances and transactions have been eliminated in consolidation.

Business Segments. Our Regulated Operations and Investments and Other segments were determined in accordance with the guidance on segment reporting. Segmentation is based on the manner in which we operate, assess, and allocate resources to the business. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.

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 approximately 144,000 retail customers. Minnesota Power also has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a customer of Minnesota Power. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 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 our Energy Infrastructure and Related Services businesses; ALLETE Clean Energy and BNI Coal. Investments and Other also includes ALLETE Properties, other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,000 acres of land in Minnesota, and earnings on cash and investments.

ALLETE Clean Energy, a wholly-owned subsidiary of ALLETE, operates independently of Minnesota Power to develop or acquire capital projects aimed at creating energy solutions via wind, solar, biomass, midstream gas and oil infrastructure, among other energy-related projects. ALLETE Clean Energy intends to market to electric utilities, cooperatives, municipalities, independent power marketers and large end-users across North America through long-term contracts or other sale arrangements, and will be subject to applicable state and federal regulatory jurisdictions.

BNI Coal, a wholly-owned subsidiary, mines and sells lignite coal to two North Dakota mine-mouth generating units, one of which is Square Butte. In 2014, Square Butte supplied 50 percent (227.5 MW) of its output to Minnesota Power under long-term contracts. (See Note 12. Commitments, Guarantees and Contingencies.) Coal sales are recognized when delivered at the cost of production plus a specified profit per ton of coal delivered.


ALLETE, Inc. 2014 Form 10-K
72


NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

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, sell the portfolio when opportunities arise and reinvest the proceeds in our growth initiatives. ALLETE does not intend to acquire additional Florida real estate.

Full profit recognition is recorded on sales of real estate upon closing, provided that cash collections are at least 20 percent of the contract price and the other requirements under the guidance for sales of real estate are met. In certain cases, where there are obligations to perform significant development activities after the date of sale, we recognize profit on a percentage-of-completion basis. From time to time, certain contracts with customers allow us to receive participation revenue from land sales to third parties if various formula-based criteria are achieved.

In certain cases, we pay fees or construct improvements to mitigate offsite traffic impacts. In return, we receive traffic impact fee credits as a result of some of these expenditures. We recognize revenue from the sale of traffic impact fee credits when payment is received.

Land inventories are accounted for in accordance with the accounting standards for property, plant and equipment, and are included in Other Investments on our Consolidated Balance Sheet. Real estate costs include the cost of land acquired, subsequent development costs and costs of improvements, capitalized development period interest, real estate taxes and payroll costs of certain employees devoted directly to the development effort. These real estate costs incurred are capitalized to the cost of real estate parcels based upon the relative sales value of parcels within each development project in accordance with the accounting standards for real estate. The cost of real estate sold includes the actual costs incurred and the estimate of future completion costs allocated to the real estate sold based upon the relative sales value method. Whenever events or circumstances indicate that the carrying value of the real estate may not be recoverable, impairments are recorded and the related assets are adjusted to their estimated fair value. (See Note 8. Investments.)

Cash and Cash Equivalents. We consider all investments purchased with original maturities of three months or less to be cash equivalents.

Supplemental Statement of Cash Flow Information
Consolidated Statement of Cash Flows
 
 
 
Year Ended December 31
2014

2013

2012

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

$51.3


$47.5


$42.7

Cash Paid During the Period for Income Taxes

$5.1


$0.5


Noncash Investing and Financing Activities
 
 
 
Increase in Accounts Payable for Capital Additions to Property, Plant and Equipment

$21.7


$8.3

$20.2
Capitalized Asset Retirement Costs

$22.4

$(0.7)

$17.1

AFUDC – Equity

$7.8


$4.6


$5.1

ALLETE Common Stock Contributed to the Defined Benefit Pension Plan

$19.5




Accounts Receivable. Accounts receivable are reported on the balance sheet net of an allowance for doubtful accounts. The allowance is based on our evaluation of the receivable portfolio under current conditions, overall portfolio quality, review of specific problems and such other factors that, in our judgment, deserve recognition in estimating losses.
Accounts Receivable
 
 
 
As of December 31
2014

 
2013

Millions
 
 
 
Trade Accounts Receivable
 
 
 
Billed

$85.5

 

$78.7

Unbilled
18.6

 
18.7

Less: Allowance for Doubtful Accounts
1.1

 
1.1

Total Accounts Receivable

$103.0

 

$96.3


ALLETE, Inc. 2014 Form 10-K
73


NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Concentration of Credit Risk. Financial instruments that subject us to concentrations of credit risk consist primarily of accounts receivable. Minnesota Power sells electricity to 10 Large Power Customers. Receivables from these customers totaled $14.7 million at December 31, 2014 ($14.2 million at December 31, 2013). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power’s taconite-producing Large Power Customers are on a weekly billing cycle, which allows us to closely manage collection of amounts due. One of these customers accounted for 10.8 percent of consolidated revenue in 2014 (12.0 percent in 2013; 12.3 percent in 2012).

Long-Term Finance Receivables. Long-term finance receivables relating to our real estate operations are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts. We assess delinquent finance receivables by comparing the balance of such receivables to the estimated fair value of the collateralized property. If the fair value of the property is less than the finance receivable, we record a reserve for the difference. We estimate fair value based on recent property tax assessed values or current appraisals. (See Note 8. Investments.)

Available-for-Sale Securities. Available-for-sale securities are recorded at fair value with unrealized gains and losses included in accumulated other comprehensive income (loss), net of tax. Unrealized losses that are other than temporary are recognized in earnings. We use the specific identification method as the basis for determining the cost of securities sold. Our policy is to review available-for-sale securities for other than temporary impairment on a quarterly basis by assessing such factors as the share price trends and the impact of overall market conditions. (See Note 8. Investments.)

Inventories. Inventories are stated at the lower of cost or market. Amounts removed from inventory are recorded on an average cost basis.
Inventories
 
 
 
As of December 31
2014

 
2013

Millions
 
 
 
Fuel (a)

$29.0

 

$13.1

Materials and Supplies
51.5

 
46.2

Total Inventories

$80.5

 

$59.3

(a)
Fuel inventory was lower at December 31, 2013 primarily due to the timing of coal shipments.

Property, Plant and Equipment. Property, plant and equipment are recorded at original cost and are reported on the balance sheet net of accumulated depreciation. Expenditures for additions, significant replacements, improvements and major plant overhauls are capitalized; maintenance and repair costs are expensed as incurred. Gains or losses on non-rate base property, plant and equipment are recognized when they are retired or otherwise disposed. When regulated utility property, plant and equipment are retired or otherwise disposed, no gain or loss is recognized in accordance with the accounting standards for the effects of certain types of regulation. Our Regulated Operations capitalize AFUDC, which includes both an interest and equity component. AFUDC represents the cost of both debt and equity funds used to finance utility plant additions during construction periods. AFUDC amounts capitalized are included in rate base and are recovered from customers as the related property is depreciated. Upon MPUC approval of cost recovery, the recognition of AFUDC ceases. (See Note 3. Property, Plant and Equipment.)

We believe that long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed for the recovery of the remaining book value of retired plant assets. We expect to retire Taconite Harbor Unit 3 and convert Laskin to natural gas in the second quarter of 2015, which were included in our 2013 Integrated Resource Plan approved by the MPUC in a November 2013 order. Accordingly, we do not expect any impairment charge as a result of the retirement of Taconite Harbor Unit 3 or conversion of Laskin.

Impairment of Long-Lived Assets. Land inventory is accounted for as held for use and is recorded at cost. We review our long-lived assets, which include the real estate assets of ALLETE Properties, for indicators of impairment in accordance with the accounting standards for property, plant and equipment on a quarterly basis.


ALLETE, Inc. 2014 Form 10-K
74


NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

In accordance with the accounting standards for property, plant and equipment, if indicators of impairment exist, we test our real estate assets for recoverability by comparing the carrying amount of the asset to the undiscounted future net cash flows expected to be generated by the asset. Cash flows are assessed at the lowest level of identifiable cash flows, which may be by each land parcel, combining various parcels, or other combinations thereof. Our consideration of possible impairment for our real estate assets requires us to make estimates of future net cash flows on an undiscounted basis. The undiscounted future net cash flows are impacted by trends and factors known to us at the time they are calculated and our expectations related to: management’s best estimate of future sales prices; holding period and timing of sales; method of disposition; and future expenditures necessary to develop and maintain the operations, including community development district assessments, property taxes and normal operation and maintenance costs. These estimates and expectations are specific to each land parcel or various bulk sales, may vary among each land parcel or bulk sale, and may change in the future. If the excess of undiscounted future net cash flows over the carrying amount of a property is small, there is a greater risk of future impairment in the event of such future changes and any resulting impairment charges could be material.

In recent years, market conditions for real estate in Florida have required us to review our land inventories for impairment. Our undiscounted future net cash flow analysis was estimated using management’s current intent for disposition of each property, which is an estimated selling period of five to ten years based on a December 2014 asset management and disposition plan (Plan) which is reviewed annually for adjustment or modification. Future selling prices have been estimated through management’s best estimate of future sales prices in collaboration and consultation with outside advisors, and based on the best use of the properties over the expected period of sale. Our analysis assumes retail land sales are followed by project bulk sales over a five-year period. If our major development projects are sold in one bulk sale or if the properties are sold differently than anticipated in the Plan, the actual results could be materially different from our undiscounted future net cash flow analysis.

The results of the impairment analysis are particularly dependent on the estimated future sales prices, method of disposition, and holding period for each property. The estimated holding period, as set forth in the Plan, is based on management’s current intent for the use and disposition of each property, and is subject to change in future periods if the intentions of the Company were to change.

In the event that projected undiscounted future net cash flows are not adequate to recover the carrying value of an asset, impairment is indicated and may require a write down to the asset’s fair value. Fair value is determined based on best available evidence including comparable sales, current appraised values, property tax assessed values, and discounted cash flow analysis. If fair value of the asset is less than its carrying value, its carrying value is reduced and an impairment charge is recorded in the current period. In 2014, 2013 and 2012, impairment analyses of estimated undiscounted future net cash flows were conducted and indicated that the cash flows were adequate to recover the carrying value of our land inventory. As a result, there was no impairment recorded for the years ended December 31, 2014, 2013, and 2012.

Derivatives. ALLETE is exposed to certain risks relating to its business operations that can be managed through the use of derivative instruments. ALLETE may enter into derivative instruments to manage those risks including interest rate risk related to certain variable-rate borrowings. (See Note 9. Derivatives.)

Accounting for Stock-Based Compensation. We apply the fair value recognition guidance for share-based payments. Under this guidance, we recognize stock-based compensation expense for all share-based payments granted, net of an estimated forfeiture rate. (See Note 18. Employee Stock and Incentive Plans.)
 
Prepayments and Other Current Assets
 
 
 
As of December 31
2014

 
2013

Millions
 
 
 
Deferred Fuel Adjustment Clause

$16.3

 

$23.0

Construction Costs for Development Project (a)
48.2

 

Restricted Cash (b)
2.7

 

Other
14.8

 
12.1

Total Prepayments and Other Current Assets

$82.0

 

$35.1

(a)
Construction Costs for Development Project acquired/incurred due to ALLETE Clean Energy’s acquisition on November 20, 2014 of a project to develop and construct a wind energy facility in 2015. (See Other Current Liabilities table and Note 7. Acquisitions.)
(b)
Restricted Cash related to ALLETE Clean Energy’s wind energy facilities operating expense and capital distribution reserve requirements.


ALLETE, Inc. 2014 Form 10-K
75


NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Other Non-Current Assets. As of December 31, 2014, included in Other Non-Current Assets on the Consolidated Balance Sheet was restricted cash of $5.3 million related to ALLETE Clean Energy’s wind energy facilities debt service and other requirements. As of December 31, 2013, the Company had restricted cash of $5.4 million related to cash held in escrow pending the closing of the wind energy facilities acquisition on January 30, 2014. (See Note 7. Acquisitions.)

Other Current Liabilities
 
 
 
As of December 31
2014

 
2013

Millions
 
 
 
Customer Deposits

$19.7

 

$26.0

Power Purchase Agreements (a)
19.4

 

Construction Deposits Received for Development Project (b)
54.3

 

Other
27.4

 
26.6

Total Other Current Liabilities

$120.8

 

$52.6

(a)
Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 7. Acquisitions.)
(b)
Construction Deposits Received for Development Project are due to ALLETE Clean Energy’s project to develop and construct a wind energy facility in 2015. (See Prepayment and Other Current Assets table and Note 7. Acquisitions.)

Other Non-Current Liabilities
 
 
 
As of December 31
2014

 
2013

Millions
 
 
 
Asset Retirement Obligation (a)

$109.2

 

$81.8

Power Purchase Agreements (b)
110.7

 

Other
45.1

 
45.4

Total Other Non-Current Liabilities

$265.0

 

$127.2

(a)
The increase in 2014 is primarily related to BNI Coal for coal mining expansion and ALLETE Clean Energy due to wind energy facilities acquisitions.
(b)
Power Purchase Agreements were acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions in 2014. (See Note 7. Acquisitions.)

Environmental Liabilities. We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated, based on current law and existing technologies. 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. (See Note 12. Commitments, Guarantees and Contingencies.)

Revenue Recognition. Regulated utility rates are under the jurisdiction of Minnesota, Wisconsin and federal regulatory authorities. Customers are billed on a cycle basis. Revenue is accrued for service provided but not yet billed. Regulated utility electric rates include adjustment clauses that: (1) bill or credit customers for fuel and purchased energy costs above or below the base levels in rate schedules; (2) bill retail customers for the recovery of conservation improvement program expenditures not collected in base rates; and (3) bill customers for the recovery of certain transmission, renewable energy and environmental expenditures. Fuel and purchased power expense is deferred to match the period in which the revenue for fuel and purchased power expense is collected from customers pursuant to the fuel adjustment clause. BNI Coal recognizes revenue when coal is delivered.

We account for revenue from our cost recovery riders (renewable resources, transmission and environmental improvement) in accordance with the accounting standards for alternative revenue programs. These standards allow for recognizing revenue under an alternative revenue program if the program is established by an order from the utility’s regulatory commission, the order allows automatic adjustment of future rates, the amount of the revenue recognized is objectively determinable and probable of recovery, and the revenue will be collected within 24 months following the end of the annual period in which it is recognized. Revenue recognized using the alternative revenue program guidance is included in Operating Revenue on our Consolidated Statement of Income and Regulatory Assets on our Consolidated Balance Sheet until it is subsequently collected from customers.

ALLETE, Inc. 2014 Form 10-K
76


NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Minnesota Power participates in MISO. MISO transactions are accounted for on a net hourly basis in each of the day-ahead and real-time markets. Minnesota Power records net sales in Operating Revenue and net purchases in Fuel and Purchased Power Expense on our Consolidated Statement of Income. The revenues and charges from MISO related to serving retail and municipal electric customers are recorded on a net basis as Fuel and Purchased Power Expense.

Amortization of Power Purchase Agreements. As part of the ALLETE Clean Energy wind energy facilities acquisitions in 2014, the Company assumed various PPAs that were at below-market prices and will amortize the liabilities to revenue over the life of the agreements for the difference between contract prices and estimated market prices. In 2014, we recognized $12.7 million of amortization relating to the PPA liabilities in Operating Revenue on the Consolidated Statement of Income.

Unamortized Discount and Premium on Debt. Discount and premium on debt are deferred and amortized over the terms of the related debt instruments using the straight-line method which approximates the effective interest method.

Income Taxes. ALLETE and its subsidiaries file a consolidated federal income tax return as well as combined and separate state income tax returns. We account for income taxes using the liability method in accordance with the accounting standards for income taxes. Under the liability method, deferred income tax assets and liabilities are established for all temporary differences in the book and tax basis of assets and liabilities, based upon enacted tax laws and rates applicable to the periods in which the taxes become payable.

Due to the effects of regulation on Minnesota Power and SWL&P, certain adjustments made to deferred income taxes are, in turn, recorded as regulatory assets or liabilities. Federal investment tax credits have been recorded as deferred credits and are being amortized to income tax expense over the service lives of the related property. In accordance with the accounting standards for uncertainty in income taxes, we are required to recognize in our financial statements the largest tax benefit of a tax position that is “more-likely-than-not” to be sustained on audit, based solely on the technical merits of the position as of the reporting date. The term “more-likely-than-not” means more than 50 percent likely. (See Note 15. Income Tax Expense.)

Excise Taxes. We collect excise taxes from our customers levied by government entities. These taxes are stated separately on the billing to the customer and recorded as a liability to be remitted to the government entity. We account for the collection and payment of these taxes on a net basis.

Purchase Accounting. In accordance with the authoritative accounting guidance, the purchase price of an acquired business is generally allocated to the assets acquired and liabilities assumed at their estimated fair values on the date of acquisition. Any unallocated purchase price amount is recognized as goodwill on the balance sheet if it exceeds the estimated fair value and as a bargain purchase gain on the income statement if it is below the estimated fair value. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, the utilization of independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. (See Note 7. Acquisitions.)

New Accounting Standards.

Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. In July 2013, the FASB issued an accounting standard update on the financial statement presentation of unrecognized tax benefits when an NOL carryforward, a similar tax loss, or a tax credit carryforward exists. An unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for an NOL carryforward, a similar tax loss, or a tax credit carryforward. To the extent an NOL carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes that would result from the disallowance of a tax position or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. This guidance was adopted in the first quarter of 2014, and did not have a material impact on our consolidated financial position, results of operations, or cash flows.





ALLETE, Inc. 2014 Form 10-K
77


NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. In April 2014, the FASB issued an accounting standard update modifying the criteria for determining which disposals should be presented as discontinued operations and modifying the related disclosure requirements. Additionally, the new guidance requires that a business which qualifies as held for sale upon acquisition should be reported as discontinued operations. The new guidance will be effective beginning in the first quarter of 2015, and will apply prospectively to new disposals and new classifications of disposal groups as held for sale. This guidance is not expected to have a material impact on our consolidated financial position, results of operations or cash flows.

Revenue from Contracts with Customers. In May 2014, the FASB issued amended revenue recognition guidance to clarify the principles for recognizing revenue from contracts with customers. The guidance requires an entity to recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. The guidance also requires expanded disclosures relating to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Additionally, qualitative and quantitative disclosures are required regarding customer contracts, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. This accounting guidance is effective for the Company beginning in the first quarter of 2017 using one of two prescribed retrospective methods. Early adoption is not permitted for public companies. The Company is evaluating the impact of the amended revenue recognition guidance on the Company’s consolidated financial statements.


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 regulated utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. Investments and Other is comprised primarily of our Energy Infrastructure and Related Services businesses; ALLETE Clean Energy, our business which acquired four wind energy facilities in 2014 and is developing a wind facility to be sold in 2015, and BNI Coal, our coal mining operations in North Dakota. Investments and Other also includes ALLETE Properties, our Florida real estate investment, and other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,000 acres of land in Minnesota, and earnings on cash and investments. For a description of our reportable business segments, see Item 1. Business.
 
Consolidated

Regulated
Operations

Investments
and Other

Millions
 
 
 
Year Ended December 31, 2014
 
 
 
Operating Revenue

$1,136.8


$1,003.5


$133.3

Fuel and Purchased Power Expense
356.1

356.1


Operating and Maintenance Expense
456.2

345.6

110.6

Depreciation Expense
135.7

118.0

17.7

Operating Income
188.8

183.8

5.0

Interest Expense
(54.8
)
(46.9
)
(7.9
)
Equity Earnings in ATC
19.6

19.6


Other Income
8.6

7.8

0.8

Income (Loss) Before Non-Controlling Interest and Income Taxes
162.2

164.3

(2.1
)
Income Tax Expense (Benefit)
36.7

39.9

(3.2
)
Net Income
125.5

124.4

1.1

Less: Non-Controlling Interest in Subsidiaries
0.7


0.7

Net Income Attributable to ALLETE

$124.8


$124.4


$0.4

 
 
 
 
As of December 31, 2014
 
 
 
Total Assets

$4,360.8


$3,709.6


$651.2

Capital Additions

$604.3


$583.5


$20.8



ALLETE, Inc. 2014 Form 10-K
78


NOTE 2. BUSINESS SEGMENTS (Continued)

 
Consolidated

Regulated
Operations

Investments
and Other

Millions
 
 
 
Year Ended December 31, 2013
 
 
 
Operating Revenue

$1,018.4


$925.5


$92.9

Fuel and Purchased Power Expense
334.8

334.8


Operating and Maintenance Expense
412.9

322.4

90.5

Depreciation Expense
116.6

110.2

6.4

Operating Income (Loss)
154.1

158.1

(4.0
)
Interest Expense
(50.3
)
(42.1
)
(8.2
)
Equity Earnings in ATC
20.3

20.3


Other Income
9.3

4.7

4.6

Income (Loss) Before Non-Controlling Interest and Income Taxes
133.4

141.0

(7.6
)
Income Tax Expense (Benefit)
28.7

36.1

(7.4
)
Net Income (Loss)
104.7

104.9

(0.2
)
Less: Non-Controlling Interest in Subsidiaries



Net Income (Loss) Attributable to ALLETE

$104.7


$104.9

$(0.2)
 
 
 
 
As of December 31, 2013
 
 
 
Total Assets

$3,476.8


$3,160.8


$316.0

Capital Additions

$339.5


$326.3


$13.2

 
Consolidated

Regulated
Operations

Investments
and Other

Millions
 
 
 
Year Ended December 31, 2012
 
 
 
Operating Revenue

$961.2


$874.4


$86.8

Fuel and Purchased Power Expense
308.7

308.7


Operating and Maintenance Expense
397.1

310.0

87.1

Depreciation Expense
100.2

93.9

6.3

Operating Income (Loss)
155.2

161.8

(6.6
)
Interest Expense
(45.5
)
(39.8
)
(5.7
)
Equity Earnings in ATC
19.4

19.4


Other Income
6.0

5.1

0.9

Income (Loss) Before Non-Controlling Interest and Income Taxes
135.1

146.5

(11.4
)
Income Tax Expense (Benefit)
38.0

50.4

(12.4
)
Net Income
97.1

96.1

1.0

Less: Non-Controlling Interest in Subsidiaries



Net Income Attributable to ALLETE

$97.1


$96.1

$1.0
 
 
 
 
As of December 31, 2012
 
 
 
Total Assets

$3,253.4


$2,962.4


$291.0

Capital Additions

$432.2


$418.2


$14.0




ALLETE, Inc. 2014 Form 10-K
79


NOTE 3. PROPERTY, PLANT AND EQUIPMENT

Property, Plant and Equipment
 
 
 
As of December 31
2014

 
2013

Millions
 
 
 
Regulated Utility

$3,903.3

 

$3,380.0

Construction Work in Progress
355.4

 
303.9

Accumulated Depreciation
(1,260.2
)
 
(1,181.7
)
Regulated Utility Plant - Net
2,998.5

 
2,502.2

Investments and Other Operations (a)
357.8

 
131.3

Construction Work in Progress
5.9

 
3.4

Accumulated Depreciation
(75.8
)
 
(60.4
)
Investments and Other Operations Plant - Net
287.9

 
74.3

Property, Plant and Equipment - Net

$3,286.4

 

$2,576.5

(a)
Includes primarily ALLETE Clean Energy, BNI Coal and a small amount of non-rate base generation.

Depreciation is computed using the straight-line method over the estimated useful lives of the various classes of assets.

Estimated Useful Lives of Property, Plant and Equipment
Generation
5 to 50 years
 
Distribution
18 to 65 years
Transmission
44 to 67 years
 
Investments and Other Operations
5 to 44 years

Asset Retirement Obligations. We recognize, at fair value, obligations associated with the retirement of certain tangible, long-lived assets that result from the acquisition, construction, development or normal operation of the asset. Asset retirement obligations (ARO) relate primarily to the decommissioning of our coal-fired and wind generating facilities and land reclamation at BNI Coal, and are included in Other Non-Current Liabilities on our Consolidated Balance Sheet. The associated retirement costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the asset. Removal costs associated with certain distribution and transmission assets have not been recognized, as these facilities have indeterminate useful lives.

Conditional asset retirement obligations have been identified for treated wood poles and remaining polychlorinated biphenyl and asbestos-containing assets; however, removal costs have not been recognized because they are considered immaterial to our consolidated financial statements.

Long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for future plant removal costs in depreciation rates. These plant removal cost recoveries are classified either as AROs or as a regulatory liability for non-ARO obligations. To the extent annual accruals for plant removal costs differ from accruals under approved depreciation rates, a regulatory asset has been established in accordance with the guidance for AROs. (See Note 5. Regulatory Matters.)

Asset Retirement Obligation
 
 
Millions
 
 
Obligation as of December 31, 2012
 

$77.9

Accretion
 
4.6

Revisions in estimated cash flows
 
(0.7
)
Obligation as of December 31, 2013
 
81.8

Accretion
 
5.5

Liabilities recognized (a)
 
23.0

Liabilities settled
 
(0.5
)
Revisions in estimated cash flows
 
(0.6
)
Obligation as of December 31, 2014
 

$109.2

(a)
The increase in 2014 is primarily related to BNI Coal for coal mining expansion and ALLETE Clean Energy due to wind energy facilities acquisitions.

ALLETE, Inc. 2014 Form 10-K
80


NOTE 4. JOINTLY-OWNED FACILITIES AND PROJECTS

We own 80 percent of the 585 MW Boswell Unit 4. While we operate the plant, certain decisions about the operations of Boswell Unit 4 are subject to the oversight of a committee on which we and WPPI Energy, the owner of the remaining 20 percent of Boswell Unit 4, have equal representation and voting rights. Each of us must provide our own financing and is obligated to pay our ownership share of operating costs. Our share of direct operating expenses of Boswell Unit 4 is included in operating expense on our Consolidated Statement of Income.

We are a participant in the CapX2020 initiative to ensure reliable electric transmission and distribution in the region surrounding our rate-regulated operations in Minnesota, along with other electric cooperatives, municipals, and investor-owned utilities. We are currently participating in one CapX2020 project and have completed two CapX2020 projects with varying ownership percentages.

Our investments in jointly-owned facilities and projects and the related ownership percentages are as follows:
 
Regulated Utility Plant As of December 31
Plant in Service
Accumulated Depreciation
Construction Work in Progress
% Ownership
 
 
Millions
 
 
 
 
 
2014
 
 
 
 
 
Boswell Unit 4

$419.1


$209.1


$168.1

80
 
CapX2020 Projects
55.5

1.7

44.0

9.3 - 14.7
 
Total

$474.6


$210.8


$212.1

 
 
2013
 
 
 
 
 
Boswell Unit 4

$416.1


$197.5


$71.5

80
 
CapX2020 Projects
22.8

1.0

57.7

9.3 - 14.7
 
Total

$438.9


$198.5


$129.2

 


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

FERC-Approved Wholesale Rates. Minnesota Power has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a customer of Minnesota Power. In April 2014, Minnesota Power amended its formula-based wholesale electric sales contract with the Nashwauk Public Utilities Commission, extending the term through June 30, 2026. The electric service agreements with the remaining 15 Minnesota municipal customers and SWL&P are effective through June 30, 2019. The rates included in these contracts are set each July 1 based on a cost-based formula methodology, 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 Nashwauk Public Utilities Commission agreement, no termination notice may be given prior to June 30, 2023. Under the agreements with the remaining 15 municipal customers and SWL&P, no termination notices may be given prior to June 30, 2016.

2012 Wisconsin Rate Case. SWL&P’s current retail rates are based on a 2012 PSCW retail rate order, effective January 1, 2013, that allows for a 10.9 percent return on common equity.

Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. In November 2013, the MPUC approved Minnesota Power’s updated billing factor which allows Minnesota Power to charge retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. We filed a petition on April 24, 2014, to include additional transmission investments and expenditures in customer billing rates, which was approved by the MPUC on January 29, 2015. (See Note 1. Operations and Significant Accounting Policies.)


ALLETE, Inc. 2014 Form 10-K
81


NOTE 5. REGULATORY MATTERS (Continued)

Renewable Cost Recovery Rider. Construction on the 205 MW Bison 4 wind facility in North Dakota was completed with project costs totaling approximately $333 million through December 31, 2014. With the completion of Bison 4, the Bison Wind Energy Center in North Dakota consists of 497 MW of nameplate capacity. On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. Customer billing rates for our Bison 1, 2, & 3 wind facilities were approved by the MPUC in a December 2013 order. On April 29, 2014 and November 10, 2014, we filed renewable resources factor filings which include updated costs associated with the Bison Wind Energy Center. Upon approval of the filings, we will be authorized to include updated billing rates on customer bills. (See Note 1. Operations and Significant Accounting Policies.)

On January 29, 2015, the MPUC approved our petition seeking cost recovery for investments and expenditures related to the restoration and repair of Thomson through a renewable resources rider. The total project investment for Thomson is estimated to be approximately $90 million, net of insurance. (See Note 12. Commitments, Guarantees and Contingencies.)

Integrated Resource Plan. In a November 2013 order, the MPUC approved Minnesota Power’s 2013 Integrated Resource Plan which details our “EnergyForward” strategic plan and includes an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. Significant elements of the “EnergyForward” plan include major wind investments in North Dakota which were completed in the fourth quarter of 2014, installation of emissions control technology at Boswell Unit 4, planning for the proposed GNTL, conversion of Laskin from coal to natural gas in the second quarter of 2015 and retiring Taconite Harbor Unit 3 in the second quarter of 2015. We are required to submit our 2015 Integrated Resource Plan with the MPUC no later than September 1, 2015.

Boswell Mercury Emissions Reduction Plan. Minnesota Power is implementing a mercury emissions reduction project for Boswell Unit 4 in order to comply with the Minnesota Mercury Emissions Reduction Act and the Federal MATS rule. In August 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA. The plan proposed that Minnesota Power install pollution controls by early 2016 to address both the Minnesota Mercury Emissions Reduction Act requirements and the Federal MATS rule. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are included in the estimated capital expenditures required for compliance with the MATS rule and are estimated to be approximately $250 million, of which $145 million was spent through December 31, 2014. In November 2013, the MPUC issued an order approving the Boswell Unit 4 mercury emissions reduction plan and cost recovery, establishing an environmental improvement rider. Also in November 2013, environmental intervenors filed a petition for reconsideration with the MPUC which was subsequently denied in an order dated January 17, 2014. The MPUC’s order was affirmed by the Minnesota Court of Appeals on November 3, 2014. In December 2013, Minnesota Power filed a petition with the MPUC to establish customer billing rates for the approved environmental improvement rider based on actual and estimated investments and expenditures, which was approved in an order dated July 2, 2014. On November 26, 2014, we filed an updated environmental improvement factor filing which included updated costs associated with Boswell Unit 4. Upon approval of this filing, we will be authorized to include updated billing rates on customer bills. (See Note 1. Operations and Significant Accounting Policies.)

Great Northern Transmission Line (GNTL). Minnesota Power and Manitoba Hydro have proposed construction of the GNTL, an approximately 220-mile 500 kV transmission line, between Manitoba and Minnesota’s Iron Range. The GNTL is subject to various federal and state regulatory approvals. In October 2013, a Certificate of Need application was filed with the MPUC with respect to the GNTL. In an order dated January 8, 2014, the MPUC determined the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. On April 15, 2014, Minnesota Power filed a route permit application with the MPUC and a request for a presidential permit to cross the U.S.-Canadian border with the U.S. Department of Energy. In an order dated July 2, 2014, the MPUC determined the route permit application to be complete. Manitoba Hydro must also obtain regulatory and governmental approvals related to a new transmission line in Canada. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. Upon receipt of all applicable permits and approvals, construction of the GNTL is anticipated to begin in 2016, and to be completed in 2020. (See Note 12. Commitments, Guarantees and Contingencies.)

Regulatory Assets and Liabilities. Our regulated utility operations are subject to the accounting guidance for the effect of certain types of regulation. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. No regulatory assets or liabilities are currently earning a return. The recovery, refund or credit to rates for these regulatory assets and liabilities will occur over the periods either specified by the applicable regulatory authority or over the corresponding period related to the asset or liability.

ALLETE, Inc. 2014 Form 10-K
82


NOTE 5. REGULATORY MATTERS (Continued)

Regulatory Assets and Liabilities
 
 
As of December 31
2014

2013

Millions
 
 
Current Regulatory Assets (a)
 
 
Deferred Fuel Adjustment Clause

$16.3


$23.0

   Total Current Regulatory Assets
16.3

23.0

Non-Current Regulatory Assets
 
 
Defined Benefit Pension and Other Postretirement Benefit Plans (b)
223.9

164.1

Cost Recovery Riders (c)
59.7

39.6

Income Taxes
46.6

35.3

Asset Retirement Obligations
17.8

16.0

PPACA Income Tax Deferral
5.0

5.0

Other
4.3

3.8

Total Non-Current Regulatory Assets
357.3

263.8

Total Regulatory Assets

$373.6


$286.8

 
 
 
Non-Current Regulatory Liabilities
 
 
Wholesale and Retail Contra AFUDC

$42.9


$19.7

Plant Removal Obligations
22.8

19.7

Income Taxes
13.4

17.0

Defined Benefit Pension and Other Postretirement Benefit Plans (b)
3.5

16.3

Other
11.6

8.3

Total Non-Current Regulatory Liabilities

$94.2


$81.0

(a)
Current regulatory assets are included in Prepayments and Other on the Consolidated Balance Sheet.
(b)
Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income, are recognized as regulatory assets or regulatory liabilities on the Consolidated Balance Sheet. (See Note 17. Pension and Other Postretirement Benefit Plans.)
(c)
The cost recovery rider regulatory assets are due to capital expenditures related to our Bison Wind Energy Center, investment in CapX2020 projects, and the Boswell Unit 4 environmental upgrade and are recognized in accordance with the accounting standards for alternative revenue programs.


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 based on a FERC-approved 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 December 31, 2014, our equity investment in ATC was $121.1 million ($114.6 million at December 31, 2013). On January 29, 2015, we invested an additional $0.4 million in ATC. In total, we expect to invest approximately $1.9 million throughout 2015.
ALLETE’s Investment in ATC
 
 
Year Ended December 31
2014

2013

Millions
 
 
Equity Investment Beginning Balance

$114.6


$107.3

Cash Investments
3.9

3.1

Equity in ATC Earnings
19.6

20.3

Distributed ATC Earnings
(17.0
)
(16.1
)
Equity Investment Ending Balance

$121.1


$114.6


ALLETE, Inc. 2014 Form 10-K
83


NOTE 6. INVESTMENT IN ATC (Continued)
ATC Summarized Financial Data
 
 
Balance Sheet Data
 
 
As of December 31
2014

2013

Millions
 
 
Current Assets

$66.4


$80.7

Non-Current Assets
3,728.7

3,509.5

Total Assets

$3,795.1


$3,590.2

Current Liabilities

$313.1


$381.4

Long-Term Debt
1,701.0

1,550.0

Other Non-Current Liabilities
163.8

126.2

Members’ Equity
1,617.2

1,532.6

Total Liabilities and Members’ Equity

$3,795.1


$3,590.2


Income Statement Data
 
 
 
Year Ended December 31
2014

2013

2012

Millions
 
 
 
Revenue

$635.0


$626.3


$603.2

Operating Expense
307.4

295.1

281.0

Other Expense
88.9

83.6

84.8

Net Income

$238.7


$247.6


$237.4

ALLETE’s Equity in Net Income

$19.6


$20.3


$19.4


In November 2013, several customer groups located within the MISO service area filed a complaint with the FERC requesting, among other things, a reduction in the base return on equity used by MISO transmission owners, including ATC, to 9.15 percent. ATC's current authorized return on equity is 12.2 percent. In the fourth quarter of 2014, FERC ordered formal hearing proceedings to begin and established a date for potential refunds from November 12, 2013. An initial decision in the complaint is expected by November 30, 2015. In the fourth quarter of 2014, ATC recorded approximately an $18 million refund liability as ATC believes that it is probable that a refund will be required upon ultimate resolution of this matter. The refund liability is subject to adjustment in future periods if assumptions in the estimate change. ATC’s refund liability negatively impacted our Equity Earnings in ATC by approximately $1 million after-tax in 2014. We own approximately 8 percent of ATC and estimate that for every 50 basis point reduction in ATC’s allowed return on equity our equity earnings in ATC would be impacted annually by approximately $0.5 million on an after-tax basis.


NOTE 7. ACQUISITIONS

The acquisitions below are consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services to complement its core regulated utility, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth.

ACE Wind Acquisition
On January 30, 2014, ALLETE Clean Energy acquired wind energy facilities located in Lake Benton, Minnesota (Lake Benton), Storm Lake, Iowa (Storm Lake II) and Condon, Oregon (Condon) from The AES Corporation (AES) for $26.9 million. ALLETE Clean Energy also has an option to acquire a fourth wind energy facility from AES in Armenia Mountain, Pennsylvania (Armenia Mountain), in June 2015.

Lake Benton, Storm Lake II and Condon have 104 MW, 77 MW and 50 MW of generating capability, respectively. Lake Benton and Storm Lake II began commercial operations in 1998, while Condon began operations in 2002. All three wind energy facilities have PPAs in place for their entire output, which expire in various years between 2019 and 2032. Pursuant to the acquisition agreement, ALLETE Clean Energy has an option to acquire the 101 MW Armenia Mountain wind energy facility in June 2015. Armenia Mountain began operations in 2009.

ALLETE, Inc. 2014 Form 10-K
84


NOTE 7. ACQUISITIONS (Continued)

ALLETE Clean Energy acquired a controlling interest in the limited liability company (LLC) which owns Lake Benton and Storm Lake II, and a controlling interest in the LLC that owns Condon. The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. In connection with finalizing purchase price accounting, the Company recorded minor adjustments to certain assets and liabilities, which are reflected in the table below. These adjustments had no impact on the results of operations. Fair value measurements were valued primarily using the discounted cash flow method.

Millions
 
Assets Acquired
 
Cash and Cash Equivalents

$3.8

Other Current Assets
14.3

Property, Plant and Equipment – Net
156.9

Other Non-Current Assets (a)
7.5

Total Assets Acquired

$182.5

Liabilities Assumed
 
Other Current Liabilities (b)

$15.2

Long-Term Debt Due Within One Year
2.2

Long-Term Debt
21.1

Power Purchase Agreements
99.4

Other Non-Current Liabilities
10.6

Non-Controlling Interest (c)
7.1

Total Liabilities and Non-Controlling Interest Assumed
$155.6
Net Identifiable Assets Acquired

$26.9

(a)
Included in Other Non-Current Assets was $0.3 million for the option to purchase Armenia Mountain in 2015, and goodwill of $2.9 million; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.
(b)
Other Current Liabilities included $12.4 million related to the current liabilities portion of the Power Purchase Agreements.
(c)
The purchase price accounting valued the non-controlling interest related to Lake Benton, Storm Lake II and Condon at fair value using the discounted cash flow method. The non-controlling interest related to Lake Benton and Storm Lake II was subsequently purchased by ALLETE Clean Energy.

ALLETE Clean Energy incurred $1.4 million after-tax of acquisition-related costs in 2014, which were expensed when incurred and were recorded in Other Expense on the Consolidated Statement of Income. The pro forma impact of this acquisition was not material to the results of the Company for the years ended December 31, 2014 and 2013.

On February 11, 2014, ALLETE Clean Energy purchased the non-controlling interest related to Lake Benton and Storm Lake II for $6.0 million. This was accounted for as an equity transaction, and no gain or loss was recognized in net income or other comprehensive income.

Montana-Dakota Utilities
On November 20, 2014, ALLETE Clean Energy acquired a business for $27.0 million which is developing a wind facility near Hettinger, North Dakota. ALLETE Clean Energy will develop and construct a 107 MW wind farm using 43 turbines which will then be sold to Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., for approximately $200 million. Construction is expected to be completed in December 2015, and the sale is subject to regulatory approvals.

The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition. Fair value measurements were valued primarily using the replacement cost method and determined that the assets acquired amounted to cash of approximately $3.6 million and construction in process of approximately $23.4 million. There were no liabilities assumed and no recognition of goodwill.

Acquisition-related costs were expensed as incurred and were not material for the year ended December 31, 2014. The pro forma impacts of this acquisition also were not material to the results of the Company for the years ended December 31, 2014 and 2013.

ALLETE, Inc. 2014 Form 10-K
85


NOTE 7. ACQUISITIONS (Continued)

As of December 31, 2014, $48.2 million of construction costs incurred (including the construction costs acquired) and $54.3 million of construction deposits received from Montana-Dakota Utilities Co. have been classified on the Consolidated Balance Sheet as Other Current Assets and Other Current Liabilities, respectively. Subject to regulatory approval, ALLETE expects revenue to be recognized under the percentage of completion method of accounting as progress toward completion of the project is achieved. Until regulatory approval is obtained, we expect no impact from the project on the Consolidated Statement of Income. Costs to construct the wind facility and deposits received from Montana-Dakota Utilities Co. are reported as Construction Costs for Development Project in investing activities and Construction Deposits Received for Development Project in financing activities on the Consolidated Statement of Cash Flows, respectively.

Storm Lake I Acquisition
On December 17, 2014, ALLETE Clean Energy acquired a wind generation facility in Storm Lake, Iowa (Storm Lake I) from NRG Energy, Inc. for $15.0 million, subject to a working capital adjustment.

Storm Lake I has 108 MW of generating capability and is located adjacent to Storm Lake II which ALLETE Clean Energy acquired in January 2014. The wind generation facility began commercial operations in 1999 and has a PPA in place for its entire output which expires in 2018.

The acquisition was accounted for as a business combination and the purchase price was allocated based on the preliminary estimated fair values of the assets acquired and liabilities assumed at the date of acquisition, as shown in the table below. The allocation of the purchase price is subject to judgment and the preliminary estimated fair value of the assets acquired and liabilities assumed may be adjusted when the valuation analysis is completed in subsequent periods. Preliminary estimates subject to adjustment in subsequent periods relating primarily to property, plant and equipment and the PPA; subsequent adjustments could impact the amount of goodwill recorded or result in a bargain purchase. Fair value measurements were valued primarily using the discounted cash flow method.

Millions

Assets Acquired

Cash and Cash Equivalents

$0.4

Other Current Assets
4.7

Property, Plant and Equipment – Net
47.3

Other Non-Current Assets (a)
11.4

Total Assets Acquired

$63.8

Liabilities Assumed

Other Current Liabilities (b)

$8.2

Power Purchase Agreements
23.5

Other Non-Current Liabilities
17.0

Total Liabilities Assumed
$48.7
Net Identifiable Assets Acquired

$15.1

(a)
Included in Other Non-Current Assets was $0.4 million of restricted cash and an immaterial amount of goodwill; for tax purposes, the purchase price allocation resulted in no allocation to goodwill.
(b)
Other Current Liabilities included $7.5 million related to the current liabilities portion of the Power Purchase Agreements.

Acquisition-related costs were expensed as incurred and were not material for the year ended December 31, 2014. The pro forma impacts of this acquisition also were not material to the results of the Company for the years ended December 31, 2014 and 2013.

ALLETE Clean Energy Purchase Agreement
On December 31, 2014, ALLETE Clean Energy signed a purchase agreement to acquire wind facilities in southern Minnesota for approximately $47.5 million, subject to a working capital adjustment.

The facilities have 97.5 MW of generating capability and are located near our Lake Benton facility acquired in January 2014. The wind facilities began commercial operations in 2003 and have PPAs in place for the entire output, which expire in 2018 and 2023. The acquisition is expected to close in the first quarter of 2015.


ALLETE, Inc. 2014 Form 10-K
86


NOTE 8. INVESTMENTS

Investments. At December 31, 2014, our investment portfolio included the real estate assets of ALLETE Properties, debt and equity securities consisting primarily of securities held in other postretirement plans to fund employee benefits, the cash equivalents within these plans, and other assets consisting primarily of land in Minnesota.

Other Investments
 
 
As of December 31
2014

2013

Millions
 
 
ALLETE Properties

$88.2


$89.9

Available-for-sale Securities (a)
18.9

17.7

Cash Equivalents (b)
2.9

34.2

Other
4.4

4.5

Total Other Investments

$114.4


$146.3

(a)
As of December 31, 2014, the aggregate amount of available-for-sale corporate debt securities maturing in one year or less was $0.6 million, in one year to less than three years was $1.7 million, in three years to less than five years was $2.6 million, and in five or more years was $5.9 million.
(b)
During 2014, cash included in Other Investments was transferred to Cash and Cash Equivalents.

ALLETE Properties
 
 
As of December 31
2014

2013

Millions
 
 
Land Inventory Beginning Balance

$85.4


$86.5

Cost of Sales
(2.2
)
(1.5
)
Other
0.6

0.4

Land Inventory Ending Balance
83.8

85.4

Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)
1.2

1.4

Other
3.2

3.1

Total Real Estate Assets

$88.2


$89.9


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 indicators of impairment on a quarterly basis and no impairments were recorded for the year ended December 31, 2014 (none for the years ended December 31, 2013 and 2012).

Long-Term Finance Receivables. As of December 31, 2014, long-term finance receivables were $1.2 million net of an allowance ($1.4 million net of an allowance as of December 31, 2013). 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 December 31, 2014, the allowance for doubtful accounts amounted to $0.6 million ($0.6 million as of December 31, 2013).

If a purchaser defaults on a sales contract, the legal remedy is usually limited to terminating the contract and retaining the purchaser’s deposit. The property is then available for resale. Contract purchasers may incur significant costs during due diligence, planning, designing and marketing the property before the contract closes, therefore they may have substantially more at risk than the deposit.

Available-for-Sale Investments. We account for our available-for-sale portfolio in accordance with the guidance for certain investments in debt and equity securities. Our available-for-sale securities portfolio consisted of securities held in other postretirement plans to fund employee benefits.


ALLETE, Inc. 2014 Form 10-K
87


NOTE 8. INVESTMENTS (Continued)

Available-For-Sale Securities
Millions
 
Gross Unrealized
 
As of December 31
Cost
Gain
Loss
Fair Value
2014
$19.6
$0.2
$0.9
$18.9
2013
$18.3
$0.6
$17.7
2012
$27.4
$0.5
$1.1
$26.8
 
 
Net
Gross Realized
Year Ended December 31
 
Proceeds
Gain
Loss
2014
 
$3.6
$0.2
2013
 
$16.1
$2.2
2012
 
$1.5


NOTE 9. DERIVATIVES

We have one 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 which represents approximately 5 percent of the Company’s outstanding long-term debt, including long-term debt due within one year, as of December 31, 2014. (See Note 11. Short-Term and Long-Term Debt.) The Swap has an effective date of August 26, 2014, and matures on August 25, 2015. The Swap involves the receipt of the one-month LIBOR in exchange for fixed interest payments over the life of the agreement at 0.75 percent without an exchange of the underlying notional amount. Cash flows from the Swap are expected to be highly effective. If it is determined that the Swap ceases to be effective, we will prospectively discontinue hedge accounting. When applicable, we use the shortcut method to assess hedge effectiveness. If the shortcut method is not applicable, we assess effectiveness using the “change-in-variable-cash-flows” method. Our assessment of hedge effectiveness resulted in no ineffectiveness recorded for the year ended December 31, 2014. As of December 31, 2014, the fair value of the Swap was a $0.3 million liability which was included in Other Current Liabilities on the Consolidated Balance Sheet. The fair value as of December 31, 2013, included an additional variable to fixed interest rate swap that expired on August 26, 2014, with an aggregate fair value at December 31, 2013 of $0.6 million of which $0.3 million was included in Other Non-Current Liabilities and $0.3 million was included in Other Current Liabilities on the Consolidated Balance Sheet. Changes in the fair value of the Swap were recorded in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheet. Cash flows from the Swap are presented in the same category as the hedged item on the Consolidated Statement of Cash Flows. Amounts recorded in Other Comprehensive Income related to the Swap will be recorded in earnings when the hedged transactions occurs or when it is probable it will not occur. Gains or losses on the interest rate hedging transaction are reflected as a component of Interest Expense on the Consolidated Statement of Income.


NOTE 10. 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). The three levels of the fair value hierarchy are as follows:

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


ALLETE, Inc. 2014 Form 10-K
88


NOTE 10. FAIR VALUE (Continued)

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

Level 3 — Significant inputs that are generally less observable from objective sources. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value.

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 December 31, 2014 and 2013. 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, which may affect the valuation of these 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 is excluded from the recurring fair value measures in the tables below.

 
Fair Value as of December 31, 2014
Recurring Fair Value Measures
Level 1

 
Level 2

 
Level 3

 
Total

Millions
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Investments (a)
 
 
 
 
 
 
 
Available-for-sale – Equity Securities

$8.1

 

 

 

$8.1

Available-for-sale – Corporate Debt Securities

 

$10.8

 

 
10.8

Cash Equivalents
2.9

 

 

 
2.9

Total Fair Value of Assets

$11.0

 

$10.8

 

 

$21.8

 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
Deferred Compensation (b)

 

$16.2

 

 

$16.2

Derivatives – Interest Rate Swap (c)

 
0.3

 

 
0.3

Total Fair Value of Liabilities

 

$16.5

 

 

$16.5

Total Net Fair Value of Assets (Liabilities)

$11.0

 
$(5.7)
 

 

$5.3

(a)
Included in Other Investments on the Consolidated Balance Sheet.
(b)
Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.
(c)
Included in Current Liabilities - Other on the Consolidated Balance Sheet.

ALLETE, Inc. 2014 Form 10-K
89


NOTE 10. FAIR VALUE (Continued)

 
Fair Value as of December 31, 2013
Recurring Fair Value Measures
Level 1

 
Level 2

 
Level 3

 
Total

Millions
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Investments (a)
 
 
 
 
 
 
 
Available-for-sale – Equity Securities

$7.9

 

 

 

$7.9

Available-for-sale – Corporate Debt Securities

 

$9.8

 

 
9.8

Cash Equivalents
34.2

 

 

 
34.2

Total Fair Value of Assets

$42.1

 

$9.8

 

 

$51.9

 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
Deferred Compensation (b)

 

$16.8

 

 

$16.8

Derivatives – Interest Rate Swap (c)

 
0.6

 

 
0.6

Total Fair Value of Liabilities

 

$17.4

 

 

$17.4

Total Net Fair Value of Assets (Liabilities)

$42.1

 
$(7.6)
 

 

$34.5

(a)
Included in Other Investments on the Consolidated Balance Sheet.
(b)
Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.
(c)
Included in Current Liabilities - Other and Other Non-Current Liabilities on the Consolidated Balance Sheet.

There was no activity in Level 3 during the years ended December 31, 2014 or 2013.

The Company’s policy is to recognize transfers in and transfers out as of the actual date of the event or change in circumstances that caused the transfer. For the years ended December 31, 2014 and 2013, there were no transfers in or out of Levels 1, 2 or 3.

Fair Value of Financial Instruments. With the exception of the item listed in the table below, the estimated fair value of all financial instruments approximates the carrying amount. The fair value for the item 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
 
 
 
December 31, 2014
$1,373.5
 
$1,484.5
December 31, 2013
$1,110.2
 
$1,131.7



ALLETE, Inc. 2014 Form 10-K
90


NOTE 11. SHORT-TERM AND LONG-TERM DEBT

Short-Term Debt. As of December 31, 2014, total short-term debt outstanding was $104.4 million ($27.2 million as of December 31, 2013) and consisted of long-term debt due within one year and notes payable.

As of December 31, 2014, we had bank lines of credit aggregating $408.4 million ($406.4 million as of December 31, 2013), the majority of which expire in November 2018. We had $47.5 million outstanding in standby letters of credit and $3.7 million outstanding in draws under our lines of credit as of December 31, 2014 ($5.4 million in standby letters of credit and no draws outstanding as of December 31, 2013).

Long-Term Debt. As of December 31, 2014, total long-term debt outstanding was $1,272.8 million ($1,083.0 million as of December 31, 2013). In conjunction with ALLETE Clean Energy’s January 30, 2014 wind energy facilities acquisition, ALLETE Clean Energy assumed $23.3 million of long-term debt, including $2.2 million due within one year. (See Note 7. Acquisitions.) The aggregate amount of long-term debt maturing in 2015 is $100.7 million ($24.9 million in 2016; $54.6 million in 2017; $54.8 million in 2018; $46.9 million in 2019; and $1,091.6 million thereafter). Substantially all of our regulated electric plant is subject to the lien of the mortgage collateralizing outstanding first mortgage bonds. The mortgages contain non-financial covenants customary in utility mortgages, including restrictions on our ability to incur liens, dispose of assets, and merge with other entities.

During 2014, we issued $375.0 million of ALLETE first mortgage bonds (Bonds) in the private placement market as shown below:

Issue Date
Maturity Date
Principal Amount
Interest Rate
March 4, 2014
March 15, 2024
$60 Million
3.69%
March 4, 2014
March 15, 2044
$40 Million
4.95%
June 26, 2014
July 15, 2022
$75 Million
3.40%
June 26, 2014
July 15, 2044
$40 Million
5.05%
September 16, 2014
September 15, 2021
$60 Million
3.02%
September 16, 2014
September 15, 2029
$50 Million
3.74%
September 16, 2014
September 15, 2044
$50 Million
4.39%

The Company has the option to prepay all or a portion of the Bonds at its discretion, subject to a make-whole provision; however, each series of bonds is redeemable at par, including, in each case, accrued and unpaid interest, six months prior to the maturity date. The Bonds are subject to additional terms and conditions which are customary for these types of transactions. The Company used the proceeds from the sale of the Bonds to refinance debt, 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 institutional accredited investors.





ALLETE, Inc. 2014 Form 10-K
91


NOTE 11. SHORT-TERM AND LONG-TERM DEBT (Continued)

Long-Term Debt
 
 
As of December 31
2014

2013

Millions
 
 
First Mortgage Bonds
 
 
6.94% Series Due 2014

$18.0
7.70% Series Due 2016
$20.0
20.0

1.83% Series Due 2018
50.0

50.0

8.17% Series Due 2019
42.0

42.0

5.28% Series Due 2020
35.0

35.0

4.85% Series Due 2021
15.0

15.0

3.02% Series Due 2021
60.0


3.40% Series Due 2022
75.0


4.95% Pollution Control Series F Due 2022

111.0

6.02% Series Due 2023
75.0

75.0

3.69% Series Due 2024
60.0


4.90% Series Due 2025
30.0

30.0

5.10% Series Due 2025
30.0

30.0

3.20% Series Due 2026
75.0

75.0

5.99% Series Due 2027
60.0

60.0

3.30% Series Due 2028
40.0

40.0

3.74% Series Due 2029
50.0


5.69% Series Due 2036
50.0

50.0

6.00% Series Due 2040
35.0

35.0

5.82% Series Due 2040
45.0

45.0

4.08% Series Due 2042
85.0

85.0

4.21% Series Due 2043
60.0

60.0

4.95% Series Due 2044
40.0


5.05% Series Due 2044
40.0


4.39% Series Due 2044
50.0


Unsecured Term Loan Variable Rate Due 2015
75.0

75.0

Senior Unsecured Notes 5.99% Due 2017
50.0

50.0

Variable Demand Revenue Refunding Bonds Series 1997 A Due 2015 – 2020
24.6

24.6

Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025
27.8

27.8

SWL&P First Mortgage Bonds 4.15% Series Due 2028
15.0

15.0

Other Long-Term Debt, 0.08% – 7.50% Due 2015 – 2037
59.1

41.8

Total Long-Term Debt
1,373.5

1,110.2

Less: Due Within One Year
100.7

27.2

Net Long-Term Debt

$1,272.8


$1,083.0


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 December 31, 2014, our ratio was approximately 0.47 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from the lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. As of December 31, 2014, ALLETE was in compliance with its financial covenants.


ALLETE, Inc. 2014 Form 10-K
92


NOTE 12. 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 Agreement, 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 December 31, 2014, Square Butte had total debt outstanding of $402.9 million. Annual debt service for Square Butte is expected to be approximately $45 million in each of the next five years, 2015 through 2019, 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.

Minnesota Power’s cost of power purchased from Square Butte during 2014 was $70.1 million ($71.1 million in 2013; $67.1 million in 2012). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $10.5 million in 2014 ($10.5 million in 2013; $11.1 million in 2012). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

Minnkota Power Sales Agreement. In December 2009, Minnesota Power entered into a power sales agreement with Minnkota Power, which commenced June 1, 2014. Under the power sales agreement, Minnesota Power is selling 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.

Minnkota Power PPA. In December 2012, Minnesota Power entered into a long-term PPA with Minnkota Power. Under this agreement, Minnesota Power will purchase 50 MW of capacity and the energy associated with that capacity from June 2016 through May 2020. The agreement includes a fixed capacity charge and energy pricing that escalates at a fixed rate annually over the term.

Oliver Wind I and II PPAs. 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 that expire in 2031 and 2032, respectively. Each agreement provides for the purchase of all output from the facilities at fixed energy prices. There are no fixed capacity charges, and we only pay for energy as it is delivered to us.

Manitoba Hydro PPAs. Minnesota Power has a long-term PPA with Manitoba Hydro that expires in May 2020. 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. In addition, Minnesota Power has a separate long-term PPA with Manitoba Hydro to purchase surplus energy through April 2022. This energy-only agreement 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.


ALLETE, Inc. 2014 Form 10-K
93


NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Power Purchase Agreements (Continued)

In May 2011, Minnesota Power and Manitoba Hydro signed an additional long-term PPA. The PPA provides for Minnesota Power to purchase 250 MW of capacity and energy from Manitoba Hydro for 15 years beginning in 2020. The agreement is subject to construction of additional transmission capacity between Manitoba and the U.S., along with construction of new hydroelectric generating capacity in Manitoba. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. The capacity price is adjusted annually until 2020 by the change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed price component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices.

In July 2014, Minnesota Power and Manitoba Hydro signed a long-term PPA that provides for Minnesota Power to purchase up to 133 MW of energy from Manitoba Hydro for 20 years beginning in 2020. The agreement was approved by the MPUC in an order dated January 30, 2015, and is subject to the construction of the GNTL.

Great River Energy PPAs. In August 2014 and January 2015, Minnesota Power and Great River Energy signed long-term PPAs that provide for Minnesota Power to purchase 50 MW of capacity and energy under the first PPA and 50 MW of capacity only under the second PPA. The PPAs commence in June 2016 and expire in May 2020. Both contracts have fixed capacity pricing. The energy price in the first PPA is based on a formula that includes an annual fixed price component adjusted for changes in a natural gas index as well as market prices. Both PPAs are subject to MPUC approval.

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.

Construction on the 205 MW Bison 4 wind facility in North Dakota was completed with project costs totaling approximately $333 million through December 31, 2014. With the completion of Bison 4, the Bison Wind Energy Center in North Dakota consists of 497 MW of nameplate capacity. On January 17, 2014, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to Bison 4. Customer billing rates for our Bison 1, 2, & 3 wind facilities were approved by the MPUC in a December 2013 order. On April 29, 2014 and November 10, 2014, we filed renewable resources factor filings which include updated costs associated with the Bison Wind Energy Center. Upon approval of the filings, we will be authorized to include updated billing rates on customer bills.

Hydro Operations. In June 2012, record rainfall and flooding occurred near Duluth, Minnesota, and surrounding areas. The flooding impacted Minnesota Power’s St. Louis River hydro system, particularly Thomson, which had damage to the forebay canal and flooding at the facility. The forebay rebuild is complete and Minnesota Power commenced filling the forebay canal on October 9, 2014. Thomson returned to partial generation in the fourth quarter of 2014 and work is ongoing towards returning to full generation early in 2015. Total project costs are estimated to be approximately $90 million, net of insurance. On January 29, 2015, the MPUC approved our petition seeking cost recovery of investments and expenditures related to the restoration and repair of Thomson through a renewable resources rider.

Coal, Rail and Shipping Contracts. We have coal supply agreements providing for the purchase of a significant portion of our coal requirements with expiration dates through December 2015. We also have coal transportation agreements in place for the delivery of a significant portion of our coal requirements with expiration dates through December 2015. Minnesota Power is currently in discussions regarding the extension of our coal supply and transportation contracts beyond 2015. Our minimum annual payment obligation under these supply and transportation agreements is $38.3 million for 2015. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.


ALLETE, Inc. 2014 Form 10-K
94


NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Coal, Rail and Shipping Contracts (Continued)

Rail congestion has negatively impacted customers throughout the Upper Midwest, affecting commerce by rail including, but not limited to, agriculture, commodity, intermodal and energy industries. We have experienced delays in coal deliveries resulting in lower coal inventory levels in 2013 and throughout much of 2014 at our generating stations in Northeastern Minnesota. Minnesota Power filed a notice of fuel supply emergency with the U.S. Department of Energy on September 22, 2014 in response to inadequate rail deliveries. Rail deliveries increased late in 2014, building inventories to normal levels by year end 2014. On December 30, 2014, the Surface Transportation Board ordered BNSF Railway to submit a detailed description of the contingency plans it would use to mitigate an acute coal inventory shortage at one or more generating stations in a region. Minnesota Power’s exposure to price risk for purchased power is significantly mitigated by the current ratemaking process and regulatory framework, which allows recovery of fuel costs in excess of those included in base rates.

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 $3.0 million termination fee. We also lease other properties and equipment under operating lease agreements with terms expiring through 2022. The aggregate amount of minimum lease payments for all operating leases is $13.4 million in 2015, $11.4 million in 2016, $10.6 million in 2017, $9.5 million in 2018, $8.3 million in 2019 and $27.3 million thereafter. Total lease expense was $14.8 million in 2014 ($13.8 million in 2013; $11.5 million in 2012).

Transmission. We continue to make investments in transmission opportunities that strengthen or enhance the transmission grid or take advantage of our geographical location between sources of renewable energy and end users. These include the GNTL and the CapX2020 initiative, as well as investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others), and our investment in ATC.

Transmission Investments. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. In November 2013, the MPUC approved Minnesota Power’s updated billing factor which allows Minnesota Power to charge retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. We filed a petition on April 24, 2014, to include additional transmission investments and expenditures in customer billing rates, which was approved by the MPUC on January 29, 2015.

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 and municipal 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.
Minnesota Power is currently participating in the construction of one CapX2020 transmission line project. Minnesota Power also participated in two CapX2020 projects which were previously completed and placed into service in 2011 and 2012. In June 2011, the MPUC approved the route permit for the Minnesota portion of the Fargo to St. Cloud project, of which the final phase is currently under construction and expected to be in service in the second quarter of 2015.

Based on projected costs of the three transmission line projects and the allocation agreements among participating utilities, in total Minnesota Power plans to invest approximately $105 million in the CapX2020 initiative through 2015, of which $99 million was spent through December 31, 2014. As future CapX2020 projects are identified, Minnesota Power may elect to participate on a project-by-project basis.

Great Northern Transmission Line (GNTL). As a condition of the long-term PPA signed in May 2011 with Manitoba Hydro, construction of additional transmission capacity is required. As a result, Minnesota Power and Manitoba Hydro proposed construction of the GNTL, an approximately 220-mile 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.

ALLETE, Inc. 2014 Form 10-K
95


NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Transmission (Continued)

The GNTL is subject to various federal and state regulatory approvals. In October 2013, a Certificate of Need application was filed with the MPUC with respect to the GNTL. In an order dated January 8, 2014, the MPUC determined the Certificate of Need application was complete and referred the docket to an administrative law judge for a contested case proceeding. On April 15, 2014, Minnesota Power filed a route permit application with the MPUC and a request for a presidential permit to cross the U.S.-Canadian border with the U.S. Department of Energy. In an order dated July 2, 2014, the MPUC determined the route permit application to be complete. Manitoba Hydro must also obtain regulatory and governmental approvals related to a new transmission line in Canada. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in the third quarter of 2014. Upon receipt of all applicable permits and approvals, construction of the GNTL is anticipated to begin in 2016, and to be completed in 2020. Total project cost in the U.S., including substation work, is estimated to be between $560 million and $710 million, depending on the final route of the line. Minnesota Power is expected to have majority ownership of the transmission line.

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 expected future restrictive environmental requirements imposed 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 project power supply trends and impacts on customers.

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 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. All of Minnesota Power’s coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, baghouses and low NOX technologies. Under currently applicable environmental regulations, these facilities are substantially compliant with applicable emission requirements.

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 asserted 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 Boswell Unit 4’s 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 reached a settlement with the EPA regarding these NOVs and entered into a Consent Decree which was approved by the U.S. District Court for the District of Minnesota (Court) on September 29, 2014. The Consent Decree covers Minnesota Power’s Boswell, Laskin, Taconite Harbor, and Rapids Energy Centers. The Consent Decree provides for more stringent emissions limits at all affected units, the option of refueling, retrofits or retirements at some units, and the addition of 200 MW of wind energy. Minnesota Power is required to spend $4.2 million on environmental mitigation projects over the next five years. Under the terms of the Consent Decree, Minnesota Power also paid a $1.4 million civil penalty which was recognized as an expense in 2013. In 2014, the Company recorded an expense associated with the environmental mitigation projects.


ALLETE, Inc. 2014 Form 10-K
96


NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

Since 2005, the Company has, and will, invest more than $600 million to reduce sulfur dioxide, nitrogen oxide, mercury and particulate matters emissions at its thermal generation facilities, and between 2010 and 2014 placed in service nearly 500 MW of renewable wind energy, which fulfills certain obligations under the Consent Decree. In addition, Minnesota Power’s EnergyForward plan addresses many of the requirements included in the Consent Decree. Under the EnergyForward plan, Minnesota Power intends to: 1) retire Taconite Harbor Unit 3, 2) convert Laskin from coal to natural gas, and 3) install emission controls at Boswell Unit 4.

The Consent Decree further requires that, by no later than December 31, 2018, Boswell Units 1 and 2 must be retired, refueled, repowered, or emissions rerouted to an existing Boswell scrubber. Minnesota Power estimates that if the units are not retired, capital expenditures could range between $20 million and $40 million. We are evaluating our options with regard to Boswell Units 1 and 2 to comply with the Consent Decree and future anticipated environmental regulations. We are required to notify the EPA no later than December 31, 2016, whether we will retire, refuel, repower or reroute Boswell Units 1 and 2. We believe that future capital expenditures or costs to retire would likely be eligible for recovery in rates over time subject to regulatory approval in a rate proceeding.

Cross-State Air Pollution Rule (CSAPR). On April 29, 2014, the U.S. Supreme Court issued an opinion reversing an August 2012 U.S. Court of Appeals for the D.C. Circuit decision that had vacated the CSAPR. The EPA filed a motion with the U.S. Court of Appeals for the D.C. Circuit on June 26, 2014, to have the stay of CSAPR lifted and the CSAPR compliance deadlines tolled by three years. On October 23, 2014, the U.S. Court of Appeals for the D.C. Circuit granted the EPA's motion, allowing the first compliance period, Phase I, to begin on January 1, 2015, with Phase II beginning in 2017.

CSAPR requires five states in the eastern half of the United States, including Minnesota, to significantly improve air quality by reducing power plant emissions that contribute to ozone or fine particulate pollution in other states. These states are required to make summertime NOx reductions under the CSAPR ozone season control program. CSAPR does not require installation of controls; rather it requires that facilities have sufficient allowances to cover their emissions on an annual basis. These allowances will be allocated to facilities from each state’s annual budget and can be bought and sold.

In December 2014, the EPA distributed the CSAPR allowances to CSAPR-subject units for the Phase I years (2015 and 2016). Phase II allowances (2017-2020) have not been distributed. Based on our initial accounting of the NOx and SO2 Phase I allowances already issued, and our review of the CSAPR Phase II allowances not yet issued, we currently expect projected generation levels and emission rates will be in compliance in both Phase I and Phase II.

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, built 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, 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.

Due to legal challenges at both the state and federal levels, there is currently no applicable compliance deadline for the Regional Haze Rule. As part of our 2013 Integrated Resource Plan, which was approved by the MPUC in November 2013, we plan to retire Taconite Harbor Unit 3 in the second quarter of 2015. We believe that the Taconite Harbor Unit 3 retirement will be accomplished before any compliance deadline takes effect.


ALLETE, Inc. 2014 Form 10-K
97


NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

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 in February 2012, addressing such emissions from coal-fired utility units greater than 25 MW. There are currently 187 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. Minnesota Power was notified by the MPCA that it has approved Minnesota Power’s request for an additional year extending the date of compliance for the Boswell Unit 4 environmental upgrade to April 1, 2016. Compliance at Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures of approximately $250 million through 2016, of which $145 million was spent through December 31, 2014. Boswell Unit 3 is also subject to the MATS rule; however, the emission reduction investments completed in 2009 at our Boswell Unit 3 generating unit substantially meet the requirements of the MATS rule. Our “EnergyForward” plan, which was approved as part of our 2013 Integrated Resource Plan by the MPUC in a November 2013 order, also includes the conversion of Laskin Units 1 and 2 to natural gas in 2015 to position the Company for MATS compliance. On January 9, 2014, the MPCA approved Minnesota Power’s application to extend the deadline for Taconite Harbor Unit 3 to comply with MATS to June 1, 2015, in order to align the Unit 3 retirement with MISO’s resource planning year.

Minnesota Mercury Emissions Reduction Act. In order to comply with the 2006 Minnesota Mercury Emissions Reduction Act, Minnesota Power must implement a mercury emissions reduction project for Boswell Unit 4 by December 31, 2018. The Boswell Unit 4 environmental upgrade discussed above, which is required to be completed by April 1, 2016 (see Mercury and Air Toxics Standards (MATS) Rule), will fulfill the requirements of the Minnesota Mercury Emissions Reduction Act.

EPA National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters. A final rule issued by the EPA for Industrial Boiler Maximum Achievable Control Technology (Industrial Boiler MACT) became effective in December 2012. Major existing sources have until January 31, 2016, to achieve compliance with the final rule. Minnesota Power’s Hibbard Renewable Energy Center and Rapids Energy Center are subject to this rule. We expect compliance to consist largely of adjustments to our operating practices; therefore costs for complying with the final rule are not expected to be material at this time.

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 NAAQS, the state is required to adopt plans describing how it will reduce emissions to attain the NAAQS. These state plans often include more stringent air emission limitations on sources of air pollutants than the NAAQS. Four NAAQS have either recently been revised or are currently proposed for revision, as described below.

Ozone NAAQS. The EPA has proposed to more stringently control emissions that result in ground level ozone. In January 2010, the EPA proposed to revise the 2008 eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. On November 25, 2014, the EPA proposed a 65 to 70 parts per billion (ppb) NAAQS for ground level ozone. The EPA is proposing to update both the primary ozone standard and the secondary standard. Both standards would be 8-hour standards set within a range of 65 to 70 ppb. The EPA is also seeking comment on levels for the primary standard as low as 60 ppb. The EPA has announced it will accept comments on all aspects of the proposal, including retaining the existing standard. A final rule is expected to be issued in the fourth quarter of 2015. The costs for complying with the final ozone NAAQS cannot be estimated at this time.

Particulate Matter NAAQS. The EPA finalized the Particulate Matter NAAQS in September 2006. Since then, the EPA has established more stringent 24-hour and annual average fine particulate matter (PM2.5) standards; the 24-hour coarse particulate matter standard has remained unchanged. In December 2012, the EPA issued a final rule implementing a more stringent annual PM2.5 standard, while retaining the current 24-hour PM2.5 standard. To implement the new annual PM2.5 standard, the EPA is also revising aspects of relevant monitoring, designation and permitting requirements. New projects and permits must comply with the new standard, which is generally demonstrated by modeling at the facility level.


ALLETE, Inc. 2014 Form 10-K
98


NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

Under the final rule, states will be responsible for additional PM2.5 monitoring, which will likely be accomplished by relocating or repurposing existing monitors. The EPA asked states to submit attainment designations by December 2013, based on already available monitoring data. The EPA issued designations of 2012 fine particulate attainment status on December 18, 2014. Minnesota retained attainment status; however, Minnesota sources may ultimately be required to reduce their emissions to assist with attainment in neighboring states. Accordingly, the costs for complying with the final Particulate Matter NAAQS cannot be estimated at this time.

SO2 and NO2 NAAQS. During 2010, the EPA finalized one-hour NAAQS for SO2 and NO2. Ambient monitoring data indicates that Minnesota will likely be in compliance with these new standards; however, the one-hour SO2 NAAQS also may require the EPA to evaluate modeling data to determine attainment. In April 2012, the MPCA notified Minnesota Power that modeling had been suspended as a result of the EPA’s announcement that the SIP submittals would not require modeling demonstrations for states, such as Minnesota, where ambient monitors indicate compliance with the new standard. The EPA notified states that their infrastructure SIPs for maintaining attainment of the standard were required to be submitted to the EPA for approval by June 2013. However, the State of Minnesota has delayed completing the documents pending EPA guidance to states for preparing the SIP submittal. The MPCA has indicated it will communicate with affected sources once it has more information on how the state will meet the EPA’s SIP requirements. Guidance was expected in 2013 but has been delayed. Currently, compliance with these new NAAQS is expected to be required as early as 2017. The costs for complying with the final standards cannot be estimated at this time.

In July 2014, the Fond du Lac Band of Lake Superior Chippewa (Band) announced that it had petitioned the EPA to redesignate its reservation air shed from Class II to Class I air quality pursuant to Section 164(c) of the Clean Air Act. The Band does not currently possess authority to directly regulate air quality. Federal Class I air shed status, if granted, would allow the Band to impose more stringent Clean Air Act protections within the boundaries of the Fond du Lac reservation, including the reservation air shed, near Cloquet, Minnesota. Five other reservations across the U.S. have applied for and received Class I status. A public hearing was held by the Band on October 2, 2014, and the public comment period on the petition expired on November 10, 2014. The Band is now preparing responses to the comments after which the Band will make a formal submittal request to the EPA. There is no deadline for the approval, denial, or modification of the request by the EPA. The Company has requested additional clarification from the Band and the MPCA on the final regulatory structure that may arise from a Class I redesignation. We are unable to determine the impact of potential Class I status on the Company’s operations at this time. 

Climate Change. The scientific community generally accepts that emissions of GHG are linked to global climate change which creates physical and financial risks. Physical risks could include, but are not limited to: increased or decreased precipitation and water levels in lakes and rivers; increased temperatures; and changes in the intensity and frequency of extreme weather events. These all have the potential to affect the Company’s business and operations. We are addressing climate change by taking the following steps that also ensure reliable and environmentally compliant generation resources to meet our customers’ requirements:

Expanding our renewable energy supply;
Providing energy conservation initiatives for our customers and engaging in other demand side efforts;
Improving efficiency of our energy generating facilities;
Supporting research of technologies to reduce carbon emissions from generation facilities and carbon sequestration efforts; and
Evaluating and developing less carbon intensive future generating assets such as efficient and flexible natural gas generating facilities.

President Obama’s Climate Action Plan. In June 2013, President Obama announced a Climate Action Plan (CAP) that calls for implementation of measures that reduce GHG emissions in the U.S., emphasizing means such as expanded deployment of renewable energy resources, energy and resource conservation, energy efficiency improvements and a shift to fuel sources that have lower emissions. Certain portions of the CAP directly address electric utility GHG emissions.

ALLETE, Inc. 2014 Form 10-K
99


NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

EPA Regulation of GHG Emissions. In May 2010, the EPA issued the Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). The Tailoring Rule establishes permitting thresholds required to address GHG emissions for new facilities, existing facilities that undergo major modifications and 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. However, GHG requirements are likely to be added to our existing Title V operating permits by the MPCA as these permits are renewed or amended.

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 Best Available Control Technology (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 that these control technologies could be determined to be BACT on a project-by-project basis.

In June 2014, the U.S. Supreme Court invalidated the aspect of the Tailoring Rule that established lower permitting thresholds for GHG than for other pollutants subject to PSD. However, the court also upheld the EPA’s power to require BACT for GHG from sources already subject to regulation under PSD. Minnesota Power’s coal-fired generating facilities are already subject to regulation under PSD, so we anticipate that ultimately PSD for GHG will apply to our facilities, but the timing of the promulgation of a replacement for the Tailoring Rule is uncertain. The PSD applies to existing facilities only when they undertake a major modification that increases emissions. At this time, we are unable to predict the compliance costs that we might incur.

In March 2012, the EPA announced a proposed rule to apply CO2 emission New Source Performance Standards (NSPS), under Section 111(b) of the Clean Air Act, to new fossil fuel-fired electric generating units. The proposed NSPS would have applied only to new or re-powered units. Based on the volume of comments received, the EPA announced its intent to re-propose the rule. In September 2013, the EPA retracted its March 2012 proposal and announced the release of a revised NSPS for new or re-powered utility CO2 emissions.

In June 2014, the EPA announced a proposed rule under Section 111(d) of the Clean Air Act for existing power plants entitled “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units” (CPP). The EPA is expected to finalize such rules by the summer of 2015. In the CPP, the EPA proposes to set state-specific goals for CO2 emissions from the power sector. The EPA maintains such goals are achievable if a state undertakes a combination of measures across its power sector that constitute the EPA’s guideline for a Best System of Emission Reductions (BSER).

The EPA proposed that BSER is comprised of four building blocks: 1) improved fossil fuel power plant efficiency, 2) increased reliance on low-emitting power sources by generating more electricity from existing natural gas combined cycle units, 3) building more or preserving existing zero- and low-emitting power sources, including renewable and nuclear energy, and 4) more efficient electricity use by consumers.

The EPA then established state goals, expressed as a carbon intensity target in CO2 tons per megawatt hour, by estimating the achievability of the building blocks in each state. Using 2012 emissions data, the EPA derived interim goals for states to be met over the years 2020-2029, as well as a final goal to be met in 2030 and thereafter. Under the CPP, each state would be required to develop a state implementation plan by June 30, 2016. Minnesota Power is currently evaluating the CPP as it relates to the State of Minnesota and its potential impact on the Company. We submitted comments on the CPP to the EPA.

Minnesota has already initiated several measures consistent with those called for under the CAP and CPP. Minnesota Power is implementing its “EnergyForward” strategic plan that provides for significant emission reductions and diversifying its electricity generation mix to include more renewable and natural gas energy. (See Note 5. Regulatory Matters.)

We are unable to predict the GHG emission compliance costs we might incur; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.



ALLETE, Inc. 2014 Form 10-K
100


NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

Minnesota’s Next Generation Energy Act of 2007. On April 14, 2014, a U.S. District Court for the District of Minnesota ruled that part of Minnesota’s Next Generation Energy Act of 2007 violated the Commerce Clause of the U.S. Constitution. The portions of the law which were ruled unconstitutional prohibited the importation of power from a new CO2-producing facility outside of Minnesota and prohibited the entry into new long-term power purchase agreements that would increase CO2 emissions in Minnesota. The State of Minnesota appealed the decision to the U.S. Court of Appeals for the Eighth Circuit on May 16, 2014.

Water. The Clean Water Act requires NPDES permits 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.

Clean Water Act - Aquatic Organisms. In April 2011, the EPA announced 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, and have a design intake flow of greater than 2 million gallons per day, to limit the number of aquatic organisms that are impacted by the facility’s intake structure or cooling system. The Section 316(b) rule was published in the Federal Register on August 15, 2014, with an effective date of October 14, 2014. The Section 316(b) standards will be implemented through NPDES permits issued to the covered facilities with compliance timing dependent on individual NPDES renewal schedules. No NPDEC permits have been re-issued containing 316(b) requirements since the final rule was published, so at this time we are unable to determine the final cost of compliance; however, our preliminary assessment suggests costs of compliance could be up to approximately $15 million. We would seek recovery of any additional costs through a general rate case.

Steam Electric Power Generating Effluent Guidelines. In April 2013, the EPA announced proposed revisions to the federal effluent guidelines for steam electric power generating stations under the Clean Water Act. The proposed revisions would set limits on the level of toxic materials in wastewater discharged from seven waste streams: flue gas desulfurization wastewater, fly ash transport water, bottom ash transport water, combustion residual leachate, non-chemical metal cleaning wastes, coal gasification wastewater, and wastewater from flue gas mercury control systems. As part of this proposed rulemaking, the EPA is considering imposing rules to address “legacy” wastewater currently residing in ponds as well as rules to impose stringent best management practices for discharges from active coal combustion residual surface impoundments. The EPA’s proposed rulemaking would base effluent limitations on what can be achieved by available technologies. The proposed rule was published in the Federal Register in June 2013, and public comments were due in September 2013. The EPA is expected to issue the final rule by September 30, 2015. Compliance with the final rule, as proposed, would be required no later than July 1, 2022. We are reviewing the proposed rule and evaluating its potential impacts on our operations. We are unable to predict the compliance costs we might incur related to these or other potential future water discharge regulations; however, the costs could be material, including costs associated with retrofits for bottom ash handling, pond dewatering, pond closure, and wastewater treatment and/or reuse. We would seek recovery of any additional costs through cost recovery riders or in a general rate case

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 coal-fired 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 (CCR) generated by the electric utility sector. The proposal sought comments on three general regulatory schemes for coal ash under Subtitle D of Resource Conservation and Recovery Act (RCRA) (non-hazardous) or Subtitle C of RCRA (hazardous).







ALLETE, Inc. 2014 Form 10-K
101


NOTE 12. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

The EPA issued the final CCR rule on December 19, 2014 under Subtitle D (non-hazardous) of RCRA. The rule includes additional requirements for new landfill and impoundment construction as well as closure activities related to certain existing impoundments. The final rule also includes provisions that could incentivize early closure of existing impoundments within a three-year window. Costs of compliance, primarily for Boswell and Laskin, could be up to approximately $130 million. The Company continues to work on minimizing costs on behalf of customers through evaluation of beneficial re-use and recycling of CCR and CCR-related waters. We would seek recovery of any additional costs through a general rate case.

Other Matters

ALLETE Clean Energy. In January 2014, ALLETE Clean Energy acquired three wind energy facilities–Lake Benton, Storm Lake II and Condon–from AES. All three wind energy facilities have PPAs in place for their entire output, which expire in various years between 2019 and 2032. On December 17, 2014, ALLETE Clean Energy acquired a wind facility, Storm Lake I, which has a PPA in place for its entire output which expires in 2018. On December 31, 2014, ALLETE Clean Energy signed a purchase agreement to acquire a wind facility in southern Minnesota and has PPAs in place for the entire output, which expire in 2018 and 2023. The acquisition is expected to close in the first quarter of 2015. (See Note 7. Acquisitions.)

BNI Coal. As of December 31, 2014, BNI Coal had surety bonds outstanding of $49.5 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although the coal supply agreements obligate the customers to provide for the closing costs, additional assurance is required by federal and state regulations. In addition to the surety bonds, BNI Coal has secured a letter of credit for an additional $0.6 million to provide for BNI Coal’s total reclamation liability, which is currently estimated at $49.3 million. BNI Coal does not believe it is likely that any of these outstanding surety bonds or the letter of credit will be drawn upon.

ALLETE Properties. As of December 31, 2014, ALLETE Properties, through its subsidiaries, had surety bonds outstanding and letters of credit to governmental entities totaling $10.2 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is approximately $7.4 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

Community Development District Obligations. In March 2005, the Town Center District issued $26.4 million of tax-exempt, 6 percent capital improvement revenue bonds 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 are secured by special assessments on the benefited 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 December 31, 2014, we owned 72 percent of the assessable land in the Town Center District (73 percent at December 31, 2013) and 93 percent of the assessable land in the Palm Coast Park District (93 percent at December 31, 2013). At these ownership levels, our annual assessments are approximately $1.4 million for Town Center and $2.1 million for Palm Coast Park. As we sell property, the obligation to pay special assessments will pass to the new landowners. In accordance with accounting guidance, these bonds are not reflected as debt on our Consolidated Balance Sheet.

Legal Proceedings.

Notice of Potential Clean Air Act Citizen Lawsuit. In July 2013, the Sierra Club submitted to Minnesota Power a notice of intent to file a citizen suit under the Clean Air Act, which it supplemented in March 2014. This notice of intent alleged violations of opacity and other permit requirements at our Boswell, Laskin, and Taconite Harbor energy centers. Minnesota Power intends to vigorously defend any lawsuit that may be filed by the Sierra Club. We are unable to predict the outcome of this matter. Accordingly, an accrual related to any damages that may result from the notice of intent has not been recorded as of December 31, 2014, because a potential loss is not currently probable or reasonably estimable.

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, and compliance with regulations, rate base and cost of service issues, among other things. We do not expect the outcome of these matters to have a material effect on our financial position, results of operations or cash flows.

ALLETE, Inc. 2014 Form 10-K
102


NOTE 13. COMMON STOCK AND EARNINGS PER SHARE

Summary of Common Stock
Shares

Equity

 
Thousands

Millions

Balance as of December 31, 2011
37,513


$705.6

Employee Stock Purchase Program
20

0.8

Invest Direct
474

19.2

Options and Stock Awards
95

6.0

Equity Issuance Program
1,275

53.1

Balance as of December 31, 2012
39,377

784.7

Employee Stock Purchase Program
16

0.7

Invest Direct
395

18.5

Options and Stock Awards
301

17.9

Equity Issuance Program
1,312

63.4

Balance as of December 31, 2013
41,401

885.2

Employee Stock Purchase Program
18

0.8

Invest Direct
378

18.9

Options and Stock Awards
78

8.0

Equity Issuance Program
1,851

90.0

Forward Sale Agreement and Issuance
1,807

85.2

Contributions to Pension
396

19.5

Balance as of December 31, 2014
45,929


$1,107.6


Equity Issuance Program. We entered into a distribution agreement with Lampert Capital Markets, Inc., in February 2008, as amended most recently in May 2014, with respect to the issuance and sale of up to an aggregate of 9.6 million shares of our common stock, without par value, of which 1.3 million shares remain available for issuance. For the year ended December 31, 2014, 1.9 million shares of common stock were issued under this agreement resulting in net proceeds of $90.0 million (1.3 million shares for net proceeds of $63.4 million for the year ended December 31, 2013). The shares sold in 2012 through August 1, 2013, were offered and sold pursuant to Registration Statement No. 333-170289. On August 2, 2013, we filed Registration Statement No. 333-190335, pursuant to which the remaining shares will continue to be offered for sale, from time to time.

Earnings Per Share. The difference between basic and diluted earnings per share, if any, arises from outstanding stock options, non-vested restricted stock units, performance share awards granted under our Executive Long-Term Incentive Compensation Plan and common shares under the forward sale agreement (described below). In 2014 and 2013, in accordance with accounting standards for earnings per share, no 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. In 2012, there were 0.2 million shares excluded because the option exercise prices were greater than the average market prices; therefore, their effect would have been anti-dilutive.

Forward Sale Agreement and Issuance of Common Stock. On February 26, 2014, ALLETE entered into a confirmation of forward sale agreement (Agreement) with a forward counterparty in connection with a public offering of 2.8 million shares of ALLETE common stock. The use of an equity forward transaction substantially eliminates future equity market price risk by fixing a common equity offering sales price under the then existing market conditions, while mitigating immediate share dilution resulting from the offering by postponing the actual issuance of common stock until funds are needed in accordance with our capital investment strategy.

Pursuant to the Agreement, the forward counterparty (or its affiliate) borrowed 2.8 million shares of ALLETE common stock (borrowed shares) from third parties and sold them to the underwriters. ALLETE had the right to elect physical, cash or net share settlement under the forward sales agreement, for all or a portion of its obligations under the Agreement. In the event that ALLETE elected physical settlement of the Agreement, it would deliver shares of its common stock in exchange for cash proceeds at the then-applicable forward sale price. The forward sale price was initially $48.01 per share, subject to adjustment as provided in the Agreement. On September 5, 2014, ALLETE physically settled a portion of its obligations under the Agreement by having delivered approximately 1.4 million shares of common stock in exchange for cash proceeds of $65.0 million. On February 4, 2015, ALLETE physically settled the remaining portion of its obligation under the Agreement by delivering approximately 1.4 million shares for cash proceeds of $65.4 million.

ALLETE, Inc. 2014 Form 10-K
103


NOTE 13. COMMON STOCK AND EARNINGS PER SHARE (Continued)

In connection with the public offering of the 2.8 million shares, ALLETE granted the underwriters an option to purchase up to an additional 0.4 million shares of ALLETE common stock (the option shares). The underwriters exercised the option in full and on March 4, 2014, the Company issued and sold the option shares to the underwriters at a price to ALLETE equal to the initial forward sale price for proceeds of $20.2 million.

The equity forward transaction was reflected in ALLETE’s diluted earnings per share using the treasury stock method, which resulted in no material dilutive impact to ALLETE’s diluted earnings per share for the year ended December 31, 2014. Prior to any settlement date, any dilutive effect of the Agreement on our earnings per share would only occur during periods when the average market price per share of our common stock is above the per share adjusted forward sales price described above.

The equity forward transaction is accounted for as an equity instrument in accordance with the accounting guidance for distinguishing liabilities from equity and the guidance for derivatives. Under the accounting guidance, the transaction qualifies for an exception from derivative accounting because the forward sale transaction is indexed to ALLETE’s stock.

Contributions to Pension. In 2014, we contributed approximately 0.4 million shares of ALLETE common stock to our pension plan, which had an aggregate value of $19.5 million when contributed. There were no contributions of ALLETE common stock to our pension plan in 2013 or 2012. These shares of ALLETE common stock were contributed in reliance upon an exemption available pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended.

Reconciliation of Basic and Diluted
 
 
 
Earnings Per Share
 

Dilutive

 

Year Ended December 31
Basic

Securities

Diluted

Millions Except Per Share Amounts
 
 
 
2014
 
 
 
Net Income Attributable to ALLETE

$124.8




$124.8

Average Common Shares
42.9

0.2

43.1

Earnings Per Share

$2.91




$2.90

2013
 
 
 
Net Income Attributable to ALLETE

$104.7




$104.7

Average Common Shares
39.7

0.1

39.8

Earnings Per Share

$2.64




$2.63

2012
 
 
 
Net Income Attributable to ALLETE

$97.1




$97.1

Average Common Shares
37.6


37.6

Earnings Per Share

$2.59




$2.58




NOTE 14. OTHER INCOME (EXPENSE)

Year Ended December 31
2014

2013

2012

Millions
 
 
 
AFUDC – Equity

$7.8


$4.6


$5.1

Gain on Sale of Available-for-sale Securities
0.2

2.2


Investments and Other Income
0.6

2.5

0.9

Total Other Income

$8.6


$9.3


$6.0




ALLETE, Inc. 2014 Form 10-K
104


NOTE 15. INCOME TAX EXPENSE

Income Tax Expense
 
 
 
Year Ended December 31
2014

2013

2012

Millions
 
 
 
Current Tax Expense
 
 
 
Federal (a)
$1.1


State (a)
2.9
$0.1
$0.5
Total Current Tax Expense
4.0

0.1

0.5

Deferred Tax Expense
 
 
 
Federal
25.3

22.9

37.0

State
8.2

6.5

1.4

Investment Tax Credit Amortization
(0.8
)
(0.8
)
(0.9
)
Total Deferred Tax Expense
32.7

28.6

37.5

Total Income Tax Expense

$36.7


$28.7


$38.0

(a)
For the years ended December 31, 2014, 2013, and 2012, the federal and state current tax expense was minimal due to NOLs which resulted from the bonus depreciation provisions of the Tax Increase Prevention Act of 2014 and the American Taxpayer Relief Act of 2012. The federal and state NOLs will be carried forward to offset future taxable income. The year ended 2014 includes the resolution of an IRS examination for the tax years 2005-2009 and the impacts of initiatives implemented on the 2013 federal and state tax returns to utilize tax carryforwards that may have expired.

Reconciliation of Taxes from Federal Statutory
 
 
 
Rate to Total Income Tax Expense
 
 
 
Year Ended December 31
2014

2013

2012

Millions
 
 
 
Income Before Non-Controlling Interest and Income Taxes

$162.2


$133.4


$135.1

Statutory Federal Income Tax Rate
35
%
35
%
35
%
Income Taxes Computed at 35 percent Statutory Federal Rate

$56.8


$46.7


$47.3

Increase (Decrease) in Tax Due to:
 
 
 
State Income Taxes – Net of Federal Income Tax Benefit
7.2

4.3

1.2

Regulatory Differences for Utility Plant
(3.5
)
(2.2
)
(2.2
)
Production Tax Credits
(23.7
)
(19.2
)
(7.6
)
Other
(0.1
)
(0.9
)
(0.7
)
Total Income Tax Expense

$36.7


$28.7


$38.0


The effective tax rate on income was 22.6 percent for 2014 (21.5 percent for 2013; 28.1 percent for 2012). The 2014, 2013, and 2012 effective rates were primarily impacted by production tax credits and by the deduction for AFUDC-Equity (included in Regulatory Differences for Utility Plant, above).

ALLETE, Inc. 2014 Form 10-K
105


NOTE 15. INCOME TAX EXPENSE (Continued)

Deferred Tax Assets and Liabilities
 
 
As of December 31
2014

2013

Millions
 
 
Deferred Tax Assets
 
 
Employee Benefits and Compensation

$102.2


$66.3

Property Related
102.7

82.2

NOL Carryforwards
156.5

112.8

Tax Credit Carryforwards
95.7

55.1

Power Purchase Agreements
51.8


Other
17.0

16.9

Gross Deferred Tax Assets
525.9

333.3

Deferred Tax Asset Valuation Allowance
(22.1
)
(8.0
)
Total Deferred Tax Assets

$503.8


$325.3

Deferred Tax Liabilities
 
 
Property Related

$848.8


$656.2

Regulatory Asset for Benefit Obligations
89.9

58.7

Unamortized Investment Tax Credits
10.3

11.1

Partnership Basis Differences
41.9

36.7

Other
16.1

22.7

Total Deferred Tax Liabilities

$1,007.0


$785.4

Net Deferred Income Taxes

$503.2


$460.1

Recorded as:
 
 
Net Current Deferred Tax Assets

$7.5

$19.0
Net Long-Term Deferred Tax Liabilities
510.7

479.1

Net Deferred Income Taxes

$503.2


$460.1


NOL and Tax Credit Carryforwards
 
 
As of December 31
2014
2013

Millions
 
 
Federal NOL Carryforwards (a)
$413.7

$279.8

Federal Tax Credit Carryforwards
$59.3
$35.5
State NOL Carryforwards (a)
$184.7
$156.3
State Tax Credit Carryforwards (b)
$14.7
$11.9
(a)
Pretax amounts.
(b)
Net of a $21.7 million valuation allowance as of December 31, 2014 ($7.7 million as of December 31, 2013).

The federal NOL and tax credit carryforward periods expire between 2030 and 2035. We expect to fully utilize the federal NOL and federal tax credit carryforwards; therefore no federal valuation allowance has been recognized as of December 31, 2014. The state NOL and tax credit carryforward periods expire between 2025 and 2035. We have established a valuation allowance against certain state NOL and tax credits that we do not expect to utilize before their expiration.


ALLETE, Inc. 2014 Form 10-K
106


NOTE 15. INCOME TAX EXPENSE (Continued)

Gross Unrecognized Income Tax Benefits
2014

2013

2012

Millions
 
 
 
Balance at January 1

$1.2


$2.7


$11.4

Additions for Tax Positions Related to the Current Year

0.1


Additions for Tax Positions Related to Prior Years
1.0

1.3


Reductions for Tax Positions Related to Prior Years


(8.7
)
Reductions for Settlements

(2.9
)

Lapse of Statute
(0.2
)


Balance as of December 31

$2.0


$1.2


$2.7


Unrecognized tax benefits are the differences between a tax position taken or expected to be taken in a tax return and the benefit recognized and measured pursuant to the “more-likely-than-not” criteria. The unrecognized tax benefit balance includes permanent tax positions which, if recognized would affect the annual effective income tax rate. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

The gross unrecognized tax benefits as of December 31, 2014, include $0.4 million of net unrecognized tax benefits which, if recognized, would affect the annual effective income tax rate. The decrease in the unrecognized tax benefit balance of $2.9 million in 2013 was due to the removal of our uncertain tax positions for positions effectively settled with the IRS for tax years 2005 through 2009. The decrease in the unrecognized tax benefit balance of $8.7 million in 2012 was due to the removal of our uncertain tax position for our tax accounting method change for deductible repairs. During 2012, the IRS issued a directive from its Large Business and International Division to its local examination teams that led to the removal of the repairs uncertain tax position in 2012.

As of December 31, 2014, we had no accrued interest ($0.5 million for 2013 and $0.5 million for 2012) related to unrecognized tax benefits included on our Consolidated Balance Sheet due to our NOL carryforwards. We classify interest related to unrecognized tax benefits as interest expense and tax-related penalties in operating expenses on our Consolidated Statement of Income. In 2014, we recognized a decrease in interest expense of $0.5 million related to unrecognized tax benefits on our Consolidated Statement of Income (zero for 2013 and decrease of $0.6 million for 2012). There were no penalties recognized in 2014, 2013 or 2012. The unrecognized tax benefit amounts have been presented as reductions to the tax benefits associated with NOL and tax credit carryforwards on our Consolidated Balance Sheet.

ALLETE and its subsidiaries file a consolidated federal income tax return as well as combined and separate state income tax returns in various jurisdictions. ALLETE has settled with the IRS for the audit of tax years 2005 through 2009. ALLETE is no longer subject to federal examination for years before 2011, or state examination for years before 2010.

During the next 12 months it is reasonably possible the amount of unrecognized tax benefits could be reduced by $0.1 million due to the expiration of the statute of limitations. This amount is primarily due to temporary tax positions.

In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. The regulations are generally effective for tax years beginning January 1, 2014. As ALLETE is adopting certain utility-specific guidance for deductible repairs previously issued by the IRS, the issuance will not have a material impact on our consolidated financial statements.



ALLETE, Inc. 2014 Form 10-K
107


NOTE 16. RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Changes in accumulated other comprehensive loss, net of tax, for the year ended December 31, 2014, were as follows:

 
Unrealized Gains
and Losses on
Available-for-sale
Securities
Defined Benefit
Pension, Other
Postretirement
Items
Gains and
Losses on
Cash Flow
Hedge
Total
Millions
 
 
 
 
For the Year Ended December 31, 2014
 
 
 
 
Beginning Accumulated Other Comprehensive Loss
$(0.1)
$(16.7)
$(0.3)
$(17.1)
Other Comprehensive Income (Loss) Before Reclassifications
(0.3
)
(5.2
)
0.2

(5.3
)
Amounts Reclassified From Accumulated Other Comprehensive Loss
0.1

1.2


1.3

Net Other Comprehensive Income (Loss)
(0.2
)
(4.0
)
0.2

(4.0
)
Ending Accumulated Other Comprehensive Loss
$(0.3)
$(20.7)
$(0.1)
$(21.1)

Reclassifications from accumulated other comprehensive loss for the year ended December 31, 2014, were as follows:

 
Year Ended
Amount Reclassified from Accumulated Other Comprehensive Loss
December 31,
 
2014
Millions
 
Unrealized Gains on Available-for-sale Securities (a)
$(0.2)
Income Taxes (b)
0.1

Total, Net of Income Taxes
$(0.1)
 
 
Amortization of Defined Benefit Pension and Other Postretirement Items
 
Prior Service Costs (c)
$0.3
Actuarial Gains and Losses (c)
(2.3
)
Total
(2.0
)
Income Taxes (b)
0.8

Total, Net of Income Taxes
$(1.2)
Total Reclassifications
$(1.3)
(a)
Included in Other Income (Expense) – Other on our Consolidated Statement of Income.
(b)
Included in Income Tax Expense on our Consolidated Statement of Income.
(c)
Defined benefit pension and other postretirement items excluded from our Regulated Operations are recognized in accumulated other comprehensive loss and are subsequently reclassified out of accumulated other comprehensive loss as components of net periodic pension and other postretirement benefit expense. (See Note 17. Pension and Other Postretirement Benefit Plans.)



ALLETE, Inc. 2014 Form 10-K
108


NOTE 16. RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Continued)

Changes in accumulated other comprehensive loss, net of tax, for the year ended December 31, 2013, were as follows:

 
Unrealized Gains
and Losses on
Available-for-sale
Securities
Defined Benefit
Pension, Other
Postretirement
Items
Gains and
Losses on
Cash Flow
Hedge
Total
Millions
 
 
 
 
For the Year Ended December 31, 2013
 
 
 
 
Beginning Accumulated Other Comprehensive Loss
$(0.1)
$(21.5)
$(0.4)
$(22.0)
Other Comprehensive Income Before Reclassifications
1.3

3.2

0.1

4.6

Amounts Reclassified From Accumulated Other Comprehensive Loss
(1.3
)
1.6


0.3

Net Other Comprehensive Income

4.8

0.1

4.9

Ending Accumulated Other Comprehensive Loss
$(0.1)
$(16.7)
$(0.3)
$(17.1)

Reclassifications from accumulated other comprehensive loss for the year ended December 31, 2013, were as follows:

 
Year Ended
Amount Reclassified from Accumulated Other Comprehensive Loss
December 31,
 
2013
Millions
 
Unrealized Gains on Available-for-sale Securities (a)
$2.2
Income Taxes (b)
(0.9
)
Total, Net of Income Taxes
$1.3
 
 
Amortization of Defined Benefit Pension and Other Postretirement Items
 
Prior Service Costs (c)
$0.8
Actuarial Gains and Losses (c)
(3.5
)
Total
(2.7
)
Income Taxes (b)
1.1

Total, Net of Income Taxes
$(1.6)
Total Reclassifications
$(0.3)
(a)
Included in Other Income (Expense) – Other on our Consolidated Statement of Income.
(b)
Included in Income Tax Expense on our Consolidated Statement of Income.
(c)
Defined benefit pension and other postretirement items excluded from our Regulated Operations are recognized in accumulated other comprehensive loss and are subsequently reclassified out of accumulated other comprehensive loss as components of net periodic pension and other postretirement benefit expense. (See Note 17. Pension and Other Postretirement Benefit Plans.)


NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

We have noncontributory union and non-union defined benefit pension plans covering eligible employees. The plans provide defined benefits based on years of service and final average pay. In 2014, we contributed $19.5 million to the plans, all of which was contributed in shares of ALLETE common stock (no contributions in 2013; $7.3 million in 2012). We also have a defined contribution RSOP covering substantially all employees. The 2014 plan year employer contributions, which are made through the employee stock ownership plan portion of the RSOP, totaled $9.1 million ($8.4 million for the 2013 plan year; $7.7 million for the 2012 plan year). (See Note 13. Common Stock and Earnings Per Share and Note 18. Employee Stock and Incentive Plans.)


ALLETE, Inc. 2014 Form 10-K
109


NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

In 2006, the non-union defined benefit pension plan was amended to suspend further crediting of service to the plan and to close the plan to new participants. In conjunction with those amendments, contributions were increased to the RSOP. In 2010, the Minnesota Power union defined benefit pension plan was amended to close the plan to new participants beginning February 1, 2011.

We have postretirement health care and life insurance plans covering eligible employees. In 2010, our postretirement health plan was amended to close the plan to employees hired after January 31, 2011. The full eligibility requirement was also amended in 2010, to require employees to be at least age 55 with 10 years of participation in the plan. In 2014, our postretirement life plan was amended to close the plan to non-union employees retiring after December 31, 2015. The postretirement health and life plans are contributory with participant contributions adjusted annually. Postretirement health and life benefits are funded through a combination of Voluntary Employee Benefit Association trusts (VEBAs), established under section 501(c)(9) of the Internal Revenue Code, and irrevocable grantor trusts. In 2014, no contributions were made to the VEBAs ($10.8 million in 2013; $1.5 million in 2012) and no contributions were made to the grantor trusts ($2.0 million in 2013; none in 2012).

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 pension plans. Contributions are based on estimates and assumptions which are subject to change. We do not expect to make any contributions to the defined benefit pension plan or the defined benefit postretirement health and life plan in 2015.

Accounting for defined benefit pension and postretirement benefit plans requires that employers recognize on a prospective basis the funded status of their defined benefit pension and other postretirement plans on their balance sheet and recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost.

The defined benefit pension and postretirement health and life benefit expense (credit) recognized annually by our regulated utilities are expected to be recovered (refunded) through rates filed with our regulatory jurisdictions. As a result, these amounts that are required to otherwise be recognized in accumulated other comprehensive income have been recognized as a long-term regulatory asset (regulatory liability) on our Consolidated Balance Sheet, in accordance with the accounting standards for Regulated Operations. The defined benefit pension and postretirement health and life benefit expense (credits) associated with our other non-rate base operations are recognized in accumulated other comprehensive income.

ALLETE, Inc. 2014 Form 10-K
110


NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Pension Obligation and Funded Status
At December 31
2014

2013

Millions
 
 
Accumulated Benefit Obligation

$661.4


$577.6

Change in Benefit Obligation
 

 

Obligation, Beginning of Year

$622.8


$652.1

Service Cost
8.3

9.9

Interest Cost
29.8

26.0

Actuarial (Gain) Loss
72.6

(49.2
)
Benefits Paid
(36.9
)
(33.5
)
Participant Contributions
17.9

17.5

Obligation, End of Year

$714.5


$622.8

Change in Plan Assets
 

 

Fair Value, Beginning of Year

$501.6


$460.1

Actual Return on Plan Assets
41.0

56.5

Employer Contribution (a)
38.5

18.5

Benefits Paid
(36.9
)
(33.5
)
Fair Value, End of Year

$544.2


$501.6

Funded Status, End of Year
$(170.3)
$(121.2)
 
 
 
Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
 

 

Current Liabilities
$(1.2)
$(1.1)
Non-Current Liabilities
$(169.1)
$(120.1)
(a)
Includes participant contributions noted above.

The pension costs that are reported as a component within our Consolidated Balance Sheet, reflected in long-term regulatory assets or liabilities and accumulated other comprehensive income, consist of the following:

Unrecognized Pension Costs
As of December 31
2014

2013

Millions
 
 
Net Loss

$250.4


$194.9

Prior Service Cost
0.2

0.4

Total Unrecognized Pension Costs

$250.6


$195.3


Components of Net Periodic Pension Expense
Year Ended December 31
2014

2013

2012

Millions
 
 
 
Service Cost

$8.3


$9.9


$9.1

Interest Cost
29.8

26.0

26.4

Expected Return on Plan Assets
(38.2
)
(35.2
)
(35.4
)
Amortization of Loss
14.2

21.5

17.5

Amortization of Prior Service Cost
0.3

0.3

0.3

Net Pension Expense

$14.4


$22.5


$17.9



ALLETE, Inc. 2014 Form 10-K
111


NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Other Changes in Pension Plan Assets and Benefit Obligations Recognized in
Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31
2014

2013

Millions
 
 
Net (Gain) Loss
$69.8
$(70.4)
Amortization of Prior Service Cost
(0.3
)
(0.3
)
Amortization of Loss
(14.2
)
(21.5
)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
$55.3
$(92.2)

Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
As of December 31
2014

2013

Millions
 
 
Projected Benefit Obligation

$714.5


$622.8

Accumulated Benefit Obligation

$661.4


$577.6

Fair Value of Plan Assets

$544.2


$501.6


Postretirement Health and Life Obligation and Funded Status
At December 31
2014

2013

Millions
 
 
Change in Benefit Obligation
 
 
Obligation, Beginning of Year

$151.9


$168.8

Service Cost
3.4

3.9

Interest Cost
7.3

6.8

Actuarial (Gain) Loss
18.1

(18.8
)
Benefits Paid
(8.9
)
(9.9
)
Participant Contributions
2.6

2.7

Plan Amendments
(2.9
)

Plan Curtailments
(0.6
)

Settlements (a)

(1.6
)
Obligation, End of Year

$170.9


$151.9

Change in Plan Assets
 
 
Fair Value, Beginning of Year

$157.0


$131.0

Actual Return on Plan Assets
11.6

21.4

Employer Contribution
1.1

11.7

Participant Contributions
2.6

2.7

Benefits Paid
(9.1
)
(9.8
)
Fair Value, End of Year

$163.2


$157.0

Funded Status, End of Year
$(7.7)
$5.1
 
 
 
Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
 
 
Non-Current Assets
$6.6
$19.4
Current Liabilities
$(0.9)
$(0.9)
Non-Current Liabilities
$(13.4)
$(13.4)
(a)
Result of the termination of a legacy benefit plan.

ALLETE, Inc. 2014 Form 10-K
112


NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

According to the accounting standards for retirement benefits, only assets in the VEBAs are treated as plan assets in the above table for the purpose of determining funded status. In addition to the postretirement health and life assets reported in the previous table, we had $17.9 million in irrevocable grantor trusts included in Other Investments on our Consolidated Balance Sheet at December 31, 2014 ($17.8 million at December 31, 2013).

The postretirement health and life costs that are reported as a component within our Consolidated Balance Sheet, reflected in regulatory long-term assets or liabilities and accumulated other comprehensive income, consist of the following:

Unrecognized Postretirement Health and Life Costs
As of December 31
2014

2013

Millions
 
 
Net (Gain) Loss
$6.9
$(9.0)
Prior Service Credit
(10.6
)
(10.1
)
Total Unrecognized Postretirement Health and Life Credit
$(3.7)
$(19.1)

Components of Net Periodic Postretirement Health and Life Expense
Year Ended December 31
2014

2013

2012

Millions
 
 
 
Service Cost

$3.4


$3.9


$4.2

Interest Cost
7.3

6.8

9.4

Expected Return on Plan Assets
(10.3
)
(9.7
)
(9.9
)
Amortization of Loss
0.5

1.6

7.5

Amortization of Prior Service Credit
(2.5
)
(2.5
)
(1.7
)
Amortization of Transition Obligation


0.1

Effect of Plan Settlement (a)

(1.6
)

Net Postretirement Health and Life Expense (Credit)
$(1.6)
$(1.5)

$9.6

(a)
Result of the termination of a legacy benefit plan.

Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations
Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
Year Ended December 31
2014

2013

Millions
 
 
Net (Gain) Loss
$16.4
$(30.2)
Prior Service Credit Arising During the Period
(3.0
)

Amortization of Prior Service Credit
2.5

2.5

Amortization of Loss
(0.5
)
(1.6
)
Amount Recognized due to Plan Settlement (a)

(0.2
)
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
$15.4
$(29.5)
(a)
Result of the termination of a legacy benefit plan.

ALLETE, Inc. 2014 Form 10-K
113


NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

Estimated Future Benefit Payments
    Pension
Postretirement Health and Life
Millions
 

 
2015

$36.5


$8.0

2016

$37.1


$8.5

2017

$38.2


$8.8

2018

$39.0


$9.0

2019

$39.9


$9.4

Years 2020 – 2024

$207.8


$49.4


The pension and postretirement health and life costs recorded in regulatory long-term assets or liabilities and accumulated other comprehensive income expected to be recognized as a component of net pension and postretirement benefit costs for the year ending December 31, 2015, are as follows:
 
      Pension
Postretirement
Health and Life
Millions
 
 
Net Loss

$17.9


$0.4

Prior Service Cost (Credit)
0.2

(3.0
)
Total Pension and Postretirement Health and Life Cost (Credit)

$18.1

$(2.6)

Assumptions Used to Determine Benefit Obligation
As of December 31
2014
2013
Discount Rate
 
 
Pension
4.30%
4.93%
Postretirement Health and Life
4.33%
4.96%
Rate of Compensation Increase
3.70 - 4.30%
3.70 - 4.30%
Health Care Trend Rates
 
 
Trend Rate
6.75%
7.25%
Ultimate Trend Rate
5.00%
5.00%
Year Ultimate Trend Rate Effective
2022
2020

Assumptions Used to Determine Net Periodic Benefit Costs
Year Ended December 31
2014
2013
2012
Discount Rate
4.93 - 4.96%
4.10 - 4.13%
4.54 - 4.56%
Expected Long-Term Return on Plan Assets
 
 
 
Pension
8.00%
8.25%
8.25%
Postretirement Health and Life
6.40 - 8.00%
6.60 - 8.25%
6.60 - 8.25%
Rate of Compensation Increase
3.70 - 4.30%
4.30 - 4.60%
4.30 - 4.60%

In establishing the expected long-term rate of return on plan assets, we determine the long-term historical performance of each asset class, adjust these for current economic conditions, and utilizing the target allocation of our plan assets, forecast the expected long-term rate of return.

ALLETE, Inc. 2014 Form 10-K
114


NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

The discount rate is computed using a yield curve adjusted for ALLETE’s projected cash flows to match our plan characteristics. The yield curve is determined using high-quality long-term corporate bond rates at the valuation date. We believe the adjusted discount curve used in this comparison does not materially differ in duration and cash flows from our pension obligation. The decrease in the discount rates used as of December 31, 2014 increased the pension and postretirement health and life benefit obligations by approximately $53 million and $14 million, respectively.

The Company utilizes actuarial assumptions about mortality to calculate the pension and postretirement health and life benefit obligations. In 2014, revised mortality tables were released, and the Company adopted updated mortality tables as of December 31, 2014. The adoption of updated mortality tables increased the pension and postretirement health and life benefit obligations as of December 31, 2014 by approximately $25 million and $8 million, respectively.

Sensitivity of a One-Percentage-Point Change in Health Care Trend Rates
 
One Percent
Increase
One Percent
Decrease
Millions
 
 
Effect on Total of Postretirement Health and Life Service and Interest Cost

$1.5

$(1.2)
Effect on Postretirement Health and Life Obligation

$21.6

$(17.7)

Actual Plan Asset Allocations
Pension
Postretirement
Health and Life (a)
 
2014
2013
2014
2013
Equity Securities
48
%
52
%
58
%
63
%
Debt Securities
39
%
34
%
34
%
29
%
Private Equity
8
%
9
%
8
%
8
%
Real Estate
5
%
5
%


 
100
%
100
%
100
%
100
%
(a)
Includes VEBAs and irrevocable grantor trusts.

There were no shares of ALLETE common stock included in pension plan equity securities as of December 31, 2014 (no shares as of December 31, 2013).

As of December 31, 2013, the defined benefit pension plan adopted a dynamic asset allocation strategy (glide path) that increases the invested allocation to fixed income assets as the funding level of the plan increases to better match the sensitivity of the plan’s assets and liabilities to changes in interest rates. This is expected to reduce the volatility of reported pension plan expenses. The postretirement health and life plans’ assets continue to be diversified to achieve strong returns within managed risk. Equity securities are diversified among domestic companies with large, mid and small market capitalizations, as well as investments in international companies. The majority of debt securities are made up of investment grade bonds. Below are the current targeted allocations as of December 31, 2014.

Plan Asset Target Allocations
    Pension
Postretirement
Health and Life (a)
Equity Securities
56
%
60
%
Debt Securities
35
%
37
%
Real Estate
9
%
3
%
 
100
%
100
%
(a)
Includes VEBAs and irrevocable grantor trusts.

ALLETE, Inc. 2014 Form 10-K
115


NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)

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). The three levels of the fair value hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. This category includes various U.S. equity securities, public mutual funds, and futures. These instruments are valued using the closing price from the applicable exchange or whose value is quoted and readily traded daily.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs. This category includes various bonds and non-public funds whose underlying investments may be level 1 or level 2 securities.

Level 3 — Significant inputs that are generally less observable from objective sources. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value. This category includes private equity funds and real estate valued through external appraisal processes. Valuation methodologies incorporate pricing models, discounted cash flow models, and similar techniques which utilize capitalization rates, discount rates, cash flows and other factors.

Pension Fair Value
 
Fair Value as of December 31, 2014
Recurring Fair Value Measures
Level 1
Level 2
Level 3
Total
Millions
 
 
 
 
Assets:
 
 
 
 
Equity Securities:
 
 
 
 
U.S. Large-cap (a)

$32.1


$56.4



$88.5

U.S. Mid-cap Growth (a)
13.6

23.9


37.5

U.S. Small-cap (a)
13.9

24.4


38.3

International
46.1

45.9


92.0

Debt Securities:
 

 

 

 

Mutual Funds
0.1



0.1

Fixed Income
2.7

201.0


203.7

Cash Equivalents
11.9



11.9

Other Types of Investments:
 

 

 

 

Private Equity Funds



$43.3

43.3

Real Estate


28.9

28.9

Total Fair Value of Assets

$120.4


$351.6


$72.2


$544.2

(a)
The underlying investments classified under U.S. Equity Securities consist of money market funds (Level 1) and actively-managed funds (Level 2), which are combined with futures, and settle daily, to achieve the returns of the U.S. Equity Securities Large-cap, Mid-cap Growth, and Small-cap funds. Our exposure with respect to these investments includes both the futures and the underlying investments. 

ALLETE, Inc. 2014 Form 10-K
116


NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
Fair Value (Continued)

Recurring Fair Value Measures
 
 
Activity in Level 3
Private Equity Funds
    Real Estate
Millions
 
 
Balance as of December 31, 2013

$46.8


$26.5

Actual Return on Plan Assets
1.2

2.8

Purchases, sales, and settlements, net
(4.7
)
(0.4
)
Balance as of December 31, 2014

$43.3


$28.9


 
Fair Value as of December 31, 2013
Recurring Fair Value Measures
Level 1
Level 2
Level 3
Total
Millions
 
 
 
 
Assets:
 
 
 
 
Equity Securities:
 
 
 
 
U.S. Large-cap (a)

$20.9


$59.3



$80.2

U.S. Mid-cap Growth (a)
9.4

26.7


36.1

U.S. Small-cap (a)
9.9

28.2


38.1

International
61.2

43.5


104.7

Debt Securities:
 

 

 

 

Mutual Funds
130.1



130.1

Fixed Income

36.4


36.4

Cash Equivalents
2.7



2.7

Other Types of Investments:
 

 

 

 

Private Equity Funds



$46.8

46.8

Real Estate


26.5

26.5

Total Fair Value of Assets

$234.2


$194.1


$73.3


$501.6

(a)
The underlying investments classified under U.S. Equity Securities consist of money market funds (Level 1) and actively-managed funds (Level 2), which are combined with futures, and settle daily, to achieve the returns of the U.S. Equity Securities Large-cap, Mid-cap Growth, and Small-cap funds. Our exposure with respect to these investments includes both the futures and the underlying investments. 

Recurring Fair Value Measures
 
 
 
Activity in Level 3
 
Private Equity Funds
   Real Estate
Millions
 
 
 
Balance as of December 31, 2012
 

$58.9


$24.9

Actual Return on Plan Assets
 
2.3

2.1

Purchases, sales, and settlements, net
 
(14.4
)
(0.5
)
Balance as of December 31, 2013
 

$46.8


$26.5




ALLETE, Inc. 2014 Form 10-K
117


NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
Fair Value (Continued)

Postretirement Health and Life Fair Value
 
Fair Value as of December 31, 2014
Recurring Fair Value Measures
Level 1
Level 2
Level 3
Total
Millions
 
 
 
 
Assets:
 
 
 
 
Equity Securities:
 
 
 
 
U.S. Large-cap (a)

$29.3




$29.3

U.S. Mid-cap Growth (a)
20.0



20.0

U.S. Small-cap (a)
12.6



12.6

International
30.6



30.6

Debt Securities:
 

 

 

 

Mutual Funds
44.5



44.5

Fixed Income


$9.9


9.9

Cash Equivalents
3.4



3.4

Other Types of Investments:
 

 

 

 

Private Equity Funds



$12.9

12.9

Total Fair Value of Assets

$140.4


$9.9


$12.9


$163.2

(a)
The underlying investments classified under U.S. Equity Securities consist of mutual funds (Level 1). 

Recurring Fair Value Measures
 
Activity in Level 3
Private Equity Funds
Millions
 
Balance as of December 31, 2013

$13.1

Actual Return on Plan Assets
1.4

Purchases, sales, and settlements, net
(1.6
)
Balance as of December 31, 2014

$12.9


 
Fair Value as of December 31, 2013
Recurring Fair Value Measures
Level 1
Level 2
Level 3
Total
Millions
 
 
 
 
Assets:
 
 
 
 
Equity Securities:
 
 
 
 
U.S. Large-cap (a)

$28.3




$28.3

U.S. Mid-cap Growth (a)
17.6



17.6

U.S. Small-cap (a)
18.2



18.2

International
33.4



33.4

Debt Securities:
 

 

 

 

Mutual Funds
30.8



30.8

Fixed Income


$15.5


15.5

Cash Equivalents
0.1



0.1

Other Types of Investments:
 

 

 

 

Private Equity Funds



$13.1

13.1

Total Fair Value of Assets

$128.4


$15.5


$13.1


$157.0

(a)
The underlying investments classified under U.S. Equity Securities consist of mutual funds (Level 1). 


ALLETE, Inc. 2014 Form 10-K
118


NOTE 17. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
Fair Value (Continued)

Recurring Fair Value Measures
 
Activity in Level 3
Private Equity Funds
Millions
 
Balance as of December 31, 2012

$13.5

Actual Return on Plan Assets
2.4

Purchases, sales, and settlements, net
(2.8
)
Balance as of December 31, 2013

$13.1


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 a fully insured postretirement health benefit, including a prescription drug benefit, which qualifies us for a federal subsidy under the Act. The federal subsidy is reflected in the premiums charged to us by the insurance company.


NOTE 18. EMPLOYEE STOCK AND INCENTIVE PLANS

Employee Stock Ownership Plan. We sponsor a leveraged ESOP within the RSOP. Eligible employees may contribute to the RSOP plan as of their date of hire. In 1990, the ESOP issued a $75.0 million note (term not to exceed 25 years at 10.25 percent) to use as consideration for 2.8 million shares (1.9 million shares adjusted for stock splits) of our newly issued common stock. The note was refinanced in 2006 at 6 percent. We make annual contributions to the ESOP equal to the ESOP’s debt service less available dividends received by the ESOP. The majority of dividends received by the ESOP are used to pay debt service, with the balance distributed to participants. The ESOP shares were initially pledged as collateral for the debt. As the debt is repaid, shares are released from collateral and allocated to participants based on the proportion of debt service paid in the year. As shares are released from collateral, we report compensation expense equal to the current market price of the shares less dividends on allocated shares. Dividends on allocated ESOP shares are recorded as a reduction of retained earnings; available dividends on unallocated ESOP shares are recorded as a reduction of debt and accrued interest. ESOP compensation expense was $9.1 million in 2014 ($8.4 million in 2013; $7.7 million in 2012).

According to the accounting standards for stock compensation, unallocated shares of ALLETE common stock currently held and purchased by the ESOP will be treated as unearned ESOP shares and not considered outstanding for earnings per share computations. ESOP shares are included in earnings per share computations after they are allocated to participants.

As of December 31
2014

2013

2012

Millions
 
 
 
ESOP Shares
 
 
 
Allocated
1.9

2.0

2.2

Unallocated
0.3

0.5

0.7

Total
2.2

2.5

2.9

Fair Value of Unallocated Shares

$13.2


$24.1


$28.7


Stock-Based Compensation. Stock Incentive Plan. Under our Executive Long-Term Incentive Compensation Plan (Executive Plan), share-based awards may be issued to key employees through a broad range of methods, including non-qualified and incentive stock options, performance shares, performance units, restricted stock, stock appreciation rights and other awards. There are 0.8 million shares of common stock reserved for issuance under the Executive Plan, with 0.6 million of these shares available for issuance as of December 31, 2014.



ALLETE, Inc. 2014 Form 10-K
119


NOTE 18. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

We currently have the following types of share-based awards outstanding:

Non-Qualified Stock Options. These options allow for the purchase of shares of common stock at a price equal to the market value of our common stock at the date of grant. Options become exercisable beginning one year after the grant date, with one-third vesting each year over three years. Options may be exercised up to ten years following the date of grant. In the case of qualified retirement, death or disability, options vest immediately and the period over which the options can be exercised is three years. Employees have up to three months to exercise vested options upon voluntary termination or involuntary termination without cause. All options are canceled upon termination for cause. All options vest immediately upon retirement, death, disability or a change of control, as defined in the award agreement. We determine the fair value of options using the Black-Scholes option-pricing model. The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on the straight-line basis over the options’ vesting periods, or the accelerated vesting period if the employee is retirement eligible. Stock options have not been granted under our Executive Plan since 2008.

The risk-free interest rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the grant date. Expected volatility is estimated based on the historic volatility of our stock and the stock of our peer group companies. We utilize historical option exercise and employee pre-vesting termination data to estimate the option life. The dividend growth rate is based upon historical growth rates in our dividends.

Performance Shares. Under the performance share awards plan, the number of shares earned is contingent upon attaining specific market goals over a three-year performance period. Market goals are measured by total shareholder return relative to a group of peer companies. In the case of qualified retirement, death or disability during a performance period, a pro rata portion of the award will be earned at the conclusion of the performance period based on the market goals achieved. In the case of termination of employment for any reason other than qualified retirement, death or disability, no award will be earned. If there is a change in control, a pro rata portion of the award will be paid based on the greater of actual performance up to the date of the change in control or target performance. The fair value of these awards is determined by the probability of meeting the total shareholder return goals. Compensation cost is recognized over the three-year performance period based on our estimate of the number of shares which will be earned by the award recipients.

Restricted Stock Units. Under the restricted stock units plan, shares for retirement eligible participants vest monthly over a three-year period. For non-retirement eligible participants, shares vest at the end of the three-year period. In the case of qualified retirement, death or disability, a pro rata portion of the award will be earned. In the case of termination of employment for any reason other than qualified retirement, death or disability, no award will be earned. If there is a change in control, a pro rata portion of the award will be earned. The fair value of these awards is equal to the grant date fair value. Compensation cost is recognized over the three-year vesting period based on our estimate of the number of shares which will be earned by the award recipients.

Employee Stock Purchase Plan (ESPP). Under our ESPP, eligible employees may purchase ALLETE common stock at a 5 percent discount from the market price. Because the discount is not greater than 5 percent, we are not required to apply fair value accounting to these awards.

RSOP. The RSOP is a contributory defined contribution plan subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended, and qualifies as an employee stock ownership plan and profit sharing plan. The RSOP provides eligible employees an opportunity to save for retirement.

The following share-based compensation expense amounts were recognized in our Consolidated Statement of Income for the periods presented.

Share-Based Compensation Expense
Year Ended December 31
2014

2013

2012

Millions
 
 
 
Performance Shares

$1.6


$1.7


$1.4

Restricted Stock Units
0.7

0.7

0.7

Total Share-Based Compensation Expense

$2.3


$2.4


$2.1

Income Tax Benefit

$1.0


$1.0


$0.9


ALLETE, Inc. 2014 Form 10-K
120


NOTE 18. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

There were no capitalized share-based compensation costs during the years ended December 31, 2014, 2013 or 2012.

As of December 31, 2014, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our Consolidated Statements of Income was $1.8 million and $0.7 million, respectively. These amounts are expected to be recognized over a weighted-average period of 1.6 years for performance share awards and 1.7 years for restricted stock units.

Non-Qualified Stock Options. The following table presents information regarding our outstanding stock options as of December 31, 2014, 2013 and 2012.

 
2014
2013
2012
 
Number of
Options
Weighted-Average
Exercise
Price
Number of
Options
Weighted-Average
Exercise
Price
Number of
Options
Weighted-Average
Exercise
Price
Outstanding as of January 1,
108,299


$44.10

395,678


$42.28

460,234


$41.68

Granted (a)






Exercised
(42,020
)

$43.65

(287,379
)

$41.60

(49,075
)

$35.84

Forfeited




(15,481
)

$44.86

Outstanding as of December 31,
66,279


$44.39

108,299


$44.10

395,678


$42.28

Exercisable as of December 31,
66,279


$44.39

108,299


$43.17

395,678


$41.71

(a)
Stock options have not been granted since 2008. The weighted-average grant-date intrinsic value of options granted in 2008 was $6.18.

Cash received from non-qualified stock options exercised was approximately $1.8 million in 2014. The intrinsic value of a stock award is the amount by which the fair value of the underlying stock exceeds the exercise price of the award. The total intrinsic value of options exercised was $0.4 million during 2014 ($2.2 million in 2013; $0.3 million in 2012).

 
Range of Exercise Price
As of December 31, 2014
$39.10 to $41.35
$44.15 to $48.65
Options Outstanding and Exercisable:
 
 
Number Outstanding and Exercisable
21,849

44,430

Weighted Average Remaining Contractual Life (Years)
2.9

1.7

Weighted Average Exercise Price

$39.27


$46.90

Aggregate Intrinsic Value (Millions)

$0.3


$0.4


Performance Shares. The following table presents information regarding our non-vested performance shares as of December 31, 2014, 2013 and 2012.

 
2014
2013
2012
 
Number of
Shares
Weighted-
Average
Grant Date
Fair Value
Number of
Shares
Weighted-
Average
Grant Date
Fair Value
Number of
Shares
Weighted-
Average
Grant Date
Fair Value
Non-vested as of January 1,
114,765


$47.02

107,899


$40.73

128,333


$36.54

Granted (a)
47,992


$46.47

45,830


$52.15

38,764


$44.70

Awarded
(36,515
)

$42.01

(18,605
)

$35.10

(41,009
)

$34.25

Unearned Grant Award


(18,606
)

$35.10

(17,575
)

$34.25

Forfeited
(6,607
)

$48.29

(1,753
)

$47.26

(614
)

$34.49

Non-vested as of December 31,
119,635


$48.26

114,765


$47.02

107,899


$40.73

(a)    Shares granted include accrued dividends.


ALLETE, Inc. 2014 Form 10-K
121


NOTE 18. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)

There were 43,081 and 38,344 performance shares granted in January 2014 and 2015, for the three-year performance periods ending in 2016 and 2017, respectively. The ultimate issuance is contingent upon the attainment of certain future market goals of ALLETE during the performance periods. The grant date fair value of the performance shares granted was $2.0 million and $2.3 million, respectively.

There were 36,515 performance shares awarded in February 2014 for the three-year performance period ending in 2013. There were no performance shares awarded in February 2015 for the three-year performance period ending in 2014. The grant date fair value of the shares awarded was $1.5 million and zero, respectively.

Restricted Stock Units. The following table presents information regarding our available restricted stock units as of December 31, 2014, 2013 and 2012.

 
2014
2013
2012
 
Number of
Shares
Weighted- Average
Grant Date
Fair Value
Number of
Shares
Weighted- Average
Grant Date
Fair Value
Number of
Shares
Weighted- Average
Grant Date
Fair Value
Available as of January 1,
55,982


$40.85

56,415


$36.61

63,464


$32.57

Granted (a)
19,645


$48.44

21,440


$43.41

18,162


$40.83

Awarded
(18,860
)

$37.64

(20,939
)

$32.03

(24,707
)

$29.43

Forfeited
(2,879
)

$45.92

(934
)

$41.02

(504
)

$31.80

Available as of December 31,
53,888


$44.47

55,982


$40.85

56,415


$36.61

(a)    Shares granted include accrued dividends.

There were 17,491 and 15,633 restricted stock units granted in January 2014 and 2015, for the vesting periods ending in 2016 and 2017, respectively. The grant date fair value of the restricted stock units granted was $0.9 million and $0.9 million, respectively.

There were 18,860 restricted stock units awarded in 2014. The grant date fair value of the shares awarded was $0.7 million.

There were 17,815 restricted stock units awarded in February 2015. The grant date fair value of the shares awarded was $0.7 million.


NOTE 19. QUARTERLY FINANCIAL DATA (UNAUDITED)

Information for any one quarterly period is not necessarily indicative of the results which may be expected for the year.

Quarter Ended
Mar. 31

Jun. 30

Sept. 30

Dec. 31

Millions Except Earnings Per Share
 
 
 
 
2014
 
 
 
 
Operating Revenue

$296.5


$260.7


$288.9


$290.7

Operating Income

$48.3


$28.2


$60.8


$51.5

Net Income Attributable to ALLETE

$33.5


$16.8


$41.6


$32.9

Earnings Per Share of Common Stock
 
 
 
 
Basic

$0.81


$0.40


$0.97


$0.73

Diluted

$0.80


$0.40


$0.97


$0.73

2013
 
 
 
 
Operating Revenue

$263.8


$235.6


$251.0


$268.0

Operating Income

$44.4


$24.4


$38.4


$46.9

Net Income Attributable to ALLETE

$32.5


$14.0


$25.2


$33.0

Earnings Per Share of Common Stock
 
 
 
 
Basic

$0.83


$0.36


$0.63


$0.82

Diluted

$0.83


$0.35


$0.63


$0.82


ALLETE, Inc. 2014 Form 10-K
122


Schedule II

ALLETE

Valuation and Qualifying Accounts and Reserves
 
Balance at
Beginning of
Period
Additions
Deductions
from
Reserves (a)
Balance at
End of
Period
 
Charged to
Income
Other
Charges
Millions
 
 
 
 
 
Reserve Deducted from Related Assets
 
 
 
 
 
Reserve For Uncollectible Accounts
 
 
 
 
 
2012 Trade Accounts Receivable

$0.9


$1.0



$0.9


$1.0

Finance Receivables – Long-Term

$0.6





$0.6

2013 Trade Accounts Receivable

$1.0


$1.3



$1.2


$1.1

Finance Receivables – Long-Term

$0.6





$0.6

2014 Trade Accounts Receivable

$1.1


$1.8



$1.8


$1.1

Finance Receivables – Long-Term

$0.6





$0.6

Deferred Asset Valuation Allowance
 
 
 
 
 
2012 Deferred Tax Assets

$0.4

$2.0



$2.4

2013 Deferred Tax Assets

$2.4

$5.6



$8.0

2014 Deferred Tax Assets

$8.0


$14.1




$22.1

(a)
Includes uncollectible accounts written off.






ALLETE, Inc. 2014 Form 10-K
123
Exhibit 10(e)6 12-31-2014
Exhibit 10(e)6

ALLETE Executive Annual Incentive Plan
Form of Award
Effective 2015
[Eligible Executive Employees]

Target Award Opportunity



Base Salary
$
 
 
Times
 
 
 
Award Opportunity (percent of base salary)
%
 
 
Equals
 
 
 
Target Award
$

Performance Levels and Award Amounts


Goal Performance Level
Payout as Percent of
Target Award
Award Amount
Superior
200%
$
Target
100%
$
Threshold
37.5%
$
Below Threshold
0%
$


Goals

 
 
 
 
 
 
 
Goal
 
 
 
 
 
 
 
Weighting
 
Financial Goals
 
 
 
 
 
 
 
Net Income
50%
 
 
Cash from Operating Activities
 
25%
 
 
 
 
 
 
 
 
 
Strategic & Operational Positioning Goals
 
 
 
  25% 
 
 
 
 
 
 
 
100%

Compensation Subject to Compensation Recovery Policy

Annual Incentive Plan Compensation is subject to recoupment as defined in the Compensation Recovery policy.



Exhibit 10(f)3 12-31-2014










ALLETE AND AFFILIATED COMPANIES
SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN II

Amended and Restated Effective January 1, 2015




TABLE OF CONTENTS
SECTION
 HEADING
PAGE

ARTICLE 1
Establishment and Purpose
2

 
1.1 Establishment
2

 
1.2 Compensation Recovery Policy
3

ARTICLE 2
Section 409A Plans and Organization
3

 
2.1 Section 409A Plans
3

 
2.2 Organization
3

 
2.3 Section 409A Compliance
3

ARTICLE 3
Administration
4

 
3.1 Administrator
4

 
3.2 Duties
4

 
3.3 Agents
4

 
3.4 Binding Effect of Decisions
4

 
3.5 Employer Information
4

ARTICLE 4
Participation
4

 
4.1 Eligibility and Commencement of Participation
4

 
4.2 Special Rule for Initial Participation
5

 
4.3 Termination of Participation
5

ARTICLE 5
Annual Make-Up Award
5

 
5.1 Eligibility
5

 
5.2 Amount of Annual Make-Up Award
5

 
5.3 Payment
6

 
5.4 Forfeiture of Annual Make-Up Award
6

ARTICLE 6
SERP II Account Balance Plan for Employees
7

 
6.1 Elective Deferrals
7

 
6.2 Non-Elective Deferrals
8

 
6.3 FICA and Other Taxes
8

 
6.4 Distributions
8

 
6.5 Additional Distribution Rules
10

 
6.6 Subsequent Changes in Time and Form of Distributions
11

ARTICLE 7
Accounts and Investments
12

 
7.1 Establishment of Accounts
12

 
7.2 Timing of Credits to Accounts
12





SECTION
 HEADING
PAGE

 
7.3 Vesting
12

 
7.4 Investments
12

 
7.5 Valuation Date
12

ARTICLE 8
SERP II Retirement Benefit
12

 
8.1 Eligibility
12

 
8.2 Vesting and Forfeiture
13

 
8.3 Retirement Benefit
13

 
8.4 Forfeiture of Vested Retirement Benefit for Misconduct
13

 
8.5 Time and Form of Distributions
14

 
8.6 Additional Distribution Rules
14

 
8.7 Subsequent Changes in Time and Form of Payment
16

 
8.8 FICA and Other Taxes
16

ARTICLE 9
Payment Acceleration and Delay
16

 
9.1 Permitted Accelerations of Payment
16

 
9.2 Permissible Payment Delays
17

 
9.3 Suspension Not Allowed
18

ARTICLE 10
Beneficiary
18

 
10.1 Beneficiary
18

 
10.2 No Beneficiary Designation
18

ARTICLE 11
Claims Procedures
18

 
11.1 Presentation of Claim
18

 
11.2 Notification of Decision
18

 
11.3 Review of a Denied Claim
19

 
11.4 Decision on Review
20

 
11.5 Other Remedies
20

ARTICLE 12
Amendment or Termination
21

ARTICLE 13
Miscellaneous Provisions
21

 
13.1 Unsecured General Creditor
21

 
13.2 Employer's Liability
21

 
13.3 Nonassignability
21

 
13.4 No Right to Employment
21

 
13.5 Incompetency
22

 
13.6 Tax Withholding
22

 
13.7 Furnishing Information
22




SECTION
 HEADING
PAGE

 
13.8 Notice
22

 
13.9 Gender and Number
22

 
13.10 Headings
22

 
13.11 Applicable Law and Construction
22

 
13.12 Invalid or Unenforceable Provisions
22

 
13.13 Successors
23

APPENDIX A
24






Exhibit 10(f)3




        
ALLETE AND AFFILIATED COMPANIES

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN II

Effective January 1, 2015
ARTICLE 1
Establishment, Purpose and Intent

1.1
Establishment. This document includes the terms of the ALLETE and Affiliated Companies Supplemental Executive Retirement Plan II. The purpose of SERP II is to provide eligible Employees (i) an opportunity to elect to defer compensation and (ii) a supplemental Retirement Benefit, the primary purpose of which is to compensate for annual compensation limits and maximum benefit limitations imposed by the Code on Retirement Plans maintained by the Company.
  
SERP II is a successor to the ALLETE and Affiliated Companies Supplemental Executive Retirement Plan (“SERP I”). On December 31, 2004, the Company froze SERP I with respect to all deferrals and vested accrued Retirement Benefits (if any). On January 1, 2005, the Company established SERP II to govern (a) amounts initially deferred after December 31, 2004 and investment earnings thereon; (b) Retirement Benefit accruals after December 31, 2004; and (c) accrued but unvested SERP I Retirement Benefits as of December 31, 2004. From January 1, 2005 to the effective date hereof, the Company operated and administered the Plan in all material respects in good faith compliance with the applicable requirements of Section 409A, the final and proposed Treasury Regulations, IRS Notice 2005-1, and all other IRS guidance. The Company amended and restated SERP II in its entirety, effective January 1, 2009, to comply with Section 409A. The Company intends that SERP II constitute an unfunded deferred compensation plan for a select group of management or highly compensated employees within the meaning of ERISA sections 201(2), 301(a)(3) and 401(a)(1). All provisions of SERP II shall be interpreted and administered to the extent possible in a manner consistent with the stated intentions.
Effective January 20, 2009, the Company amended SERP II to narrow the salary-grade eligibility requirements to receive an Annual Make-Up Award for employees who first became eligible to participate in SERP II after September 30, 2006.

Effective January 1, 2011, the Company amended SERP II to incorporate any compensation recovery policy adopted by the Company and to provide that certain benefits may be subject to forfeiture for Misconduct.

Effective January 1, 2015, the Company hereby amends SERP II to reflect the reduction to the Flexible Dollar Makeup in connection with amendments to the ALLETE and Affiliated Companies Flexible Compensation Plan that eliminate the life insurance percentage (age-rated) flexible dollars benefit commencing with the Plan Year that begins on January 1, 2015.

Capitalized terms, unless otherwise defined herein, shall have the meaning provided in Appendix A.




Exhibit 10(f)3


1.2
Compensation Recovery Policy. All amounts payable to Participants in accordance with this Plan are subject to, and the Company hereby incorporates into this SERP II, the terms of any compensation recovery policy or policies established and amended by the Company from time to time (“Compensation Recovery Policy”).

ARTICLE 2
Section 409A Plans and Organization

2.1
Section 409A Plans.
The provisions of SERP II include terms and conditions applicable to the following 409A Plans:
2.1.1
An elective account balance plan for Employees for purposes of Elective Deferrals;

2.1.2
A non-elective account balance plan for Employees for purposes of Non-Elective Deferrals; and

2.1.3
A non-account balance plan for Employees.

2.2
Organization.
Except as otherwise provided in this section or in a specific section, all provisions of the Plan apply to all amounts deferred under any Article of the Plan.
2.2.1
The provisions of Article 5 apply only for purposes of identifying employees eligible to receive an Annual Make-Up Award and the amount of the award, if any.

2.2.2
The provisions of Articles 6 and 7 apply only to the extent that SERP II provides for Employees’ Elective Deferrals, or Non-Elective Deferrals or both, which, for purposes of Section 409A, represent the elective and non-elective account balance plans identified in subsections 2.1.1 and 2.1.2, respectively.

2.2.3
The provisions of Article 8 apply only to the extent that SERP II provides for Retirement Benefits, which represent the non-account balance plan identified in subsection 2.1.3.

2.3
Section 409A Compliance.
To the extent that any provision of the Plan would cause a conflict with the requirements of Section 409A, or would cause the administration of the Plan to fail to satisfy Section 409A, such provision shall be deemed null and void to the extent permitted by applicable law. Nothing herein shall be construed as a guarantee of any particular tax treatment to a Participant.

ARTICLE 3
Administration

3.1
Administrator.
The Administrator shall administer the Plan or may delegate any of its duties to such other person or persons from time to time as it may designate. Members of the Employee Benefit Plans Committee may participate in SERP II; however, any individual serving on the Employee Benefit Plans Committee shall not vote or act on any matter relating solely to himself or herself.



Exhibit 10(f)3


3.2
Duties.
The Administrator has the authority to construe and interpret all provisions of the Plan and, to the extent permitted by Section 409A, the Administrator is authorized to remedy any errors, inconsistencies or omissions, to resolve any ambiguities, to adopt rules and practices concerning the administration of the Plan, and to make any determinations and calculations necessary or appropriate hereunder. The Company shall pay all expenses and liabilities incurred in connection with Plan administration.
3.3
Agents.
The Administrator may engage the services of accountants, attorneys, actuaries, investment consultants, and such other professional personnel as are deemed necessary or advisable to assist in fulfilling the Administrator’s responsibilities. The Administrator, the Company and the Board may rely upon the advice, opinions or valuations of any such persons.
3.4
Binding Effect of Decisions.
The decision or action of the Administrator with respect to any question arising out of or in connection with the administration, interpretation and application of the Plan and the rules and regulations promulgated hereunder shall be final, conclusive and binding upon all persons having any interest in the Plan. Neither the Administrator, its delegates, nor the Board shall be personally liable for any good faith action, determination or interpretation with respect to the Plan, and each shall be fully protected by the Company in respect of any such action, determination or interpretation.
3.5
Employer Information.
To enable the Administrator to perform its duties, each Employer shall supply full and timely information to the Administrator on all matters relating to the compensation of its Participants, the date and circumstances of the Participant’s death, Disability or Separation from Service, and other pertinent information as the Administrator may reasonably require.

ARTICLE 4
Participation

4.1
Eligibility and Commencement of Participation.
Eligible Employees may participate in the Plan, except to the extent provided in Section 8.1 regarding eligibility for Retirement Benefits. Each Plan Year, the Administrator shall notify Eligible Employees of their eligibility to participate in the Plan during the following Plan Year.  An Eligible Employee shall become a Participant either upon the initial submission of an election form on which the Eligible Employee has elected Elective Deferrals or upon first receiving an allocation of Non-Elective Deferrals.
4.2
Special Rule for Initial Participation.
Within 30 days after the date an individual first becomes an Eligible Employee, the individual may elect to commence participating with respect to compensation to be paid for services performed after the election is filed. This election relating to initial participation in the Plan is available only to Participants who do not participate in any Aggregated Plans. If an Employee whose participation in the Plan is terminated again becomes an Eligible Employee, he or she may elect to defer pursuant to this Section only if the Employee was ineligible to defer compensation in this Plan and all other Related Company elective account balance plans, within the meaning of Section 409A, for the 24 months preceding the date on which the Participant again became eligible to participate in this Plan.



Exhibit 10(f)3


4.3
Termination of Participation.
If the Administrator determines in good faith that a Participant is no longer an Eligible Employee, the Participant shall cease active participation in the Plan on the last day of the Plan Year during which the Participant ceased to be an Eligible Employee, and the terms of this Plan shall continue to govern Participant’s Account until the Participant’s Account is paid in full.

ARTICLE 5
Annual Make-Up Award

5.1
Eligibility.
An Employee who: (i) was a Participant as of September 30, 2006, (ii) has continuously remained an Employee in ALLETE management salary grade SA-SM, and (iii) has continuously participated in the ALLETE Executive Annual Incentive Plan or been eligible to receive a Bonus shall be eligible to receive an Annual Make-up Award. Any other Employee shall be eligible to receive an Annual Make-up Award if the Employee: (i) initially becomes, or again becomes, a Participant after September 30, 2006, (ii) is in ALLETE management salary grade SG-SM, and (iii) participates in the ALLETE Executive Annual Incentive Plan or is eligible to receive a Bonus.

5.2
Amount of Annual Make-Up Award.
The Annual Make-Up Award shall be the sum of the Flexible Dollar Makeup, the RSOP Allocation Makeup and the RSOP Match Allocation Makeup, each calculated as described in this section.
5.2.1
Flexible Dollar Makeup. The Flexible Dollar Makeup for a Plan Year commencing with the Plan Year that begins on January 1, 2015, shall equal the product of 2% and an amount equal to the sum of: (a) the total of the Participant’s Annual Incentive Award and other awards (to the extent included in calculations for the Retirement Plans) for such year, and (b) the Participant’s Salary (determined as of October 1 of the prior Plan Year) in excess of the Code section 401(a)(17) limitation in effect for that Plan Year. The Flexible Dollar Makeup for the Plan Year that commenced on January 1, 2014 shall also include the Participant’s life insurance percentage under the ALLETE and Affiliated Companies Flexible Compensation Plan for nonunion employees.

5.2.2
RSOP Allocation Makeup. For a Participant who was a Participant as of September 30, 2006, for so long as he remains continuously eligible as a Participant, the RSOP Allocation Makeup for a Plan Year shall equal the product of C and D, with C equal to the sum of (i) 1.5% and (ii) the percentage (if any) being allocated for that year as an excess amount pursuant to the RSOP, and D equal to the sum of (a) the total of the Participant’s Annual Incentive Award and other award (to the extent included in calculations for the Retirement Plans) for such year, and (b) the amount of the Participant’s Salary in excess of the Code section 401(a)(17) limitation in effect for that Plan Year.

For a Participant who becomes a Participant on or after October 1, 2006, the RSOP Allocation Makeup for a Plan Year shall equal the product of E and F, with E equal to the sum of: (i) 6% and (ii) the percentage, if any, being allocated as an excess amount pursuant to the RSOP; and F equal to the sum of (a) the total of the Participant’s Annual Incentive Award and other award (to the extent included in calculations for the Retirement Plans) for the year, and (b) the amount of the Participant’s Salary in excess of the Code section 401(a)(17) limitation in effect for that Plan Year.



Exhibit 10(f)3


If a Participant ceases to be an Eligible Employee during a Plan Year the RSOP Allocation Makeup for that Plan Year will be calculated by: (i) taking into account the full Annual Incentive Award and other award (to the extent included in calculations for the Retirement Plans) and, (ii) with respect to any Participant whose base salary exceeds the Code section 401(a)(17) limitation in effect for that Plan Year, prorating the Participant’s Salary to reflect the period during the Plan Year for which the Participant was an Eligible Employee.
5.2.3
RSOP Match Allocation Makeup. The RSOP Match Allocation Makeup for a Plan Year shall equal the excess of G over H, with G equal to the lesser of: (i) the sum of the Participant’s Elective Deferrals out of Salary and RSOP deferrals (including both pre-tax and Roth after-tax deferrals), and (ii) with respect to any Eligible Employee who was a Participant as of September 30, 2006, for so long as he remains continuously eligible as a Participant, 4% of the Participant’s Salary plus Bonus; or with respect to any Eligible Employee who becomes a Participant on or after October 1, 2006, 5% of the Participant’s Salary plus Bonus; and H equal to RSOP matching contributions for the Plan Year on behalf of the Participant.

5.3
Payment.
Except to the extent deferred in accordance with this Plan, the Annual Make-Up Award for any year shall be paid between January 1 and March 15 of the year following the year to which the award relates.
5.4
Forfeiture of Annual Make-Up Award. Notwithstanding any other term or provision of this Article 5, if a Participant engages in Misconduct, the Participant shall forfeit or repay, as necessary, any Annual Make-Up Award payable on account of the period during which the Misconduct occurred and any subsequent period.

ARTICLE 6
SERP II Account Balance Plan for Employees

6.1
Elective Deferrals.

6.1.1
Deferral Elections. For each Plan Year, a Participant may elect to defer some or all of Salary, Bonus, and, if eligible, an Annual Make-up Award, Severance Pay and Other Awards. Elections are effective on a calendar year basis and become irrevocable no later than the date specified by the Administrator, but in any event before the beginning of the Plan Year to which the elections relate. A Participant’s elections will become effective only if the forms required by the Administrator have been properly completed and signed by the Participant, timely delivered to the Administrator, and accepted by the Administrator. A Participant who fails to file elections before the required date will be treated as having elected not to defer any amounts for the following Plan Year. For any Plan Year the Administrator may, in its sole discretion, decide not to allow one or more Participants to defer certain types of compensation.

6.1.2
Special Rule for Performance-Based Compensation. The Administrator, in its complete and sole discretion, may allow a Participant to revise a deferral election with respect to a Bonus if the Administrator determines that the Bonus is performance-based compensation within the meaning of Section 409A and the election becomes irrevocable no later than the earlier of: (a) six months preceding the end of the performance period to which the Bonus relates; or (b) the date as of which the Bonus has become readily ascertainable, within the meaning of Section 409A.



Exhibit 10(f)3


6.1.3
Special Rule for Severance Pay. A Participant may elect to defer all or a portion of Severance Pay by filing with the Administrator an irrevocable deferral election no later than the date the Participant obtains a legally binding right to the Severance Pay.

6.1.4
Cancellation of Deferral Election due to Disability. If a Participant becomes disabled, the Administrator may, in its sole discretion, cancel the Participant’s deferral election, with respect to amounts to be deferred on or after the cancellation, by the end of the year during which the Participant becomes disabled, or, if later, the 15th day of the third month following the date on which the Participant becomes disabled. For purposes of this Section, a Participant shall be disabled if the Participant is suffering from any medically determinable physical or mental impairment resulting in the Participant’s inability to perform the duties of his position or any substantially similar position, if such impairment can be expected to result in death or can be expected to last for a continuous period of six months.

The Participant may elect to defer amounts for the Plan Year following his return to employment and for every Plan Year thereafter while an Eligible Employee, provided the Participant’s deferral election otherwise complies with all of the requirements of this Section.
6.1.5
Cancellation of Deferral Election due to Unforeseeable Emergency. If a Participant experiences an Unforeseeable Emergency during a Plan Year, the Participant may submit to the Administrator a written request to cancel Elective Deferrals for the Plan Year to satisfy the Unforeseeable Emergency. If the Administrator either approves the Participant’s request to cancel Elective Deferrals for the Plan Year, or approves a request for a distribution of in accordance with Section 6.4.6, then effective as of the date the request is approved the Administrator shall cancel the Participant’s deferral elections for the remainder of the Plan Year. A Participant whose Elective Deferrals are canceled during a Plan Year in accordance with this section may elect Elective Deferrals for the following Plan Year; provided, however, if required to comply with Treasury Regulations section 1.401(k)-1(d)(3), the Participant may not elect to defer any amounts attributable to periods less than six months from the date on which the Participant receives a distribution on account of an Unforeseeable Emergency.

6.1.6
Withholding of Deferrals. The Administrator will withhold Elective Deferrals not later than the end of the calendar year during which the Company would otherwise have paid the amounts to the Participant but for the Participant’s deferral election. The Administrator will not withhold Elective Deferrals from a Participant’s Salary during any period in which the Participant is on an unpaid leave of absence.

6.2
Non-Elective Deferrals.

6.2.1
Annual Make-Up Award. If the Administrator determines that a Participant’s Salary exceeds the Code section 401(a)(17) limit, the Administrator shall automatically credit the Participant’s Annual Make-up Award to the Participant’s Account.

6.2.2
162(m) Deferrals. The Administrator shall automatically credit a Participant’s 162(m) Deferrals to the Participant’s Account.




Exhibit 10(f)3


6.3
FICA and Other Taxes.
For each Plan Year during which a Participant has Deferrals, the Participant’s Employer(s) shall, in a manner determined by the Employer(s), withhold the Participant’s share of FICA and other required employment or state, local, and foreign taxes on Deferrals from that portion of the Participant’s Salary, Bonus, Annual Make-up Award, Severance Pay, Other Award and in the event of a 162(m) Deferral, the Participant’s compensation generally, that is not deferred. To the extent permitted by Section 409A, the Administrator may reduce a Participant’s Deferrals to the extent necessary to pay FICA and other employment, state, local and foreign taxes.
6.4
Distributions.
The Plan provides for distributions in a Specified Year, or upon a Separation from Service, death, Disability, or Unforeseeable Emergency. At the time of a Participant’s initial deferral election, a Participant may elect to receive a distribution: (i) with respect to Elective Deferrals, in a Specified Year; and (ii) with respect to all Deferrals, upon the earlier of Separation from Service, death or Disability. In each subsequent Plan year, a Participant may elect to have all or any portion of that year’s Elective Deferrals distributed either in a Specified Year, subject to the restrictions in Section 6.4.1, or in accordance with the Participant’s prior elections for distributions other than in a Specified Year. Except as otherwise provided in the Plan, a Participant’s distribution elections are irrevocable and will govern the Deferrals to which the election relates until the amounts covered by the election are paid in full or until subsequently changed in accordance with Section 6.6. Notwithstanding any elections by a Participant, all distributions are subject to the provisions of Sections 1.2 and 6.5.
6.4.1
Specified Year. A Participant may elect to receive a distribution of Elective Deferrals in a Specified Year, which may be no earlier than the third Plan Year beginning after the date on which the Participant initially elects to receive a distribution in a Specified Year. Except as otherwise provided in this subsection or in Section 6.6, once a Participant has elected to receive a distribution in a Specified Year, the Participant may not elect to receive a distribution in a different Specified Year. Beginning during the year preceding any Specified Year previously elected by the Participant, the Participant may elect to receive a distribution of Elective Deferrals in a later Specified Year, subject, however, to the restrictions of this subsection. All amounts distributed in a Specified Year will be paid in a single lump sum.

6.4.2
Separation from Service. A Participant may elect to receive a distribution commencing either upon a Separation from Service, or during any of the first five years following the year of the Separation from Service. A Participant may elect to receive a distribution in the form of a lump sum, monthly installments over a period of five (5), ten (10), or fifteen (15) years, or a combination of both a lump sum and installments.

6.4.3
Disability. A Participant may elect to receive a distribution on account of Disability. Distributions upon Disability will commence on the earlier of the Participant’s 65th birthday or the second anniversary of the Disability, unless changed in accordance with Section 6.6. A Participant may elect to receive the distribution in the form of a lump sum, monthly installments over a period of five (5), ten (10), or fifteen (15) years, or a combination of both a lump sum and installments. Notwithstanding any other election by a Participant relating to a distribution upon Disability, if a Participant dies after commencement of a Disability but before the year during which distributions would commence, the Participant’s Account shall be distributed in accordance with the Participant’s election regarding distributions upon death.




Exhibit 10(f)3


6.4.4
Death. A Participant may elect to receive a distribution commencing upon death or during any of the first five years following the year of death. A Participant may elect to receive a distribution in the form of a lump sum, monthly installments over a period of five (5), ten (10), or fifteen (15) years, or a combination of both a lump sum and installments.

6.4.5
Unforeseeable Emergency. A Participant may submit a written request for a distribution on account of an Unforeseeable Emergency. Upon approval by the Administrator of a Participant’s request, the Participant’s Account, or that portion of a Participant’s Account deemed necessary by the Administrator to satisfy the Unforeseeable Emergency (determined in a manner consistent with Section 409A) plus amounts necessary to pay taxes reasonably anticipated because of the distribution, will be distributed in a single lump sum.

6.5
Additional Distribution Rules.

6.5.1
Default Time and Form of Distribution. If a Participant fails timely to elect a time and form of distribution, the Participant’s Account will be distributed upon any Separation from Service, including death, in the form of a single lump sum payment.

6.5.2
Commencement of Distributions. Except as otherwise provided in this section, if a Participant has elected to receive a distribution commencing upon a Distribution Event, or if a distribution is required upon a Distribution Event, distribution will commence between the date of the Distribution Event and the end of the year in which the Distribution Event occurs. If a Participant has elected, or is required, to receive a distribution commencing upon a Distribution Event, and the Distribution Event occurs on or after October 1 of a Plan Year, the distribution may, to the extent permitted by Section 409A, commence after the Distribution Event and on or before the 15th day of the third calendar month following the Distribution Event, even if after the end of the year during which the Distribution Event occurs; provided, however, the Participant will not be permitted, directly or indirectly, to designate the taxable year of the distribution. If a Participant has elected to receive a distribution commencing during any of the first five years following the year of a Distribution Event, the distribution will commence during the year elected by the Participant. If a Participant has elected to receive a distribution in a Specified Year, the distribution will occur during the Specified Year. Any distribution that complies with this section shall be deemed for all purposes to comply with the Plan requirements regarding the time and form of distributions.

6.5.3
Installments. If a Participant elects to receive distributions in monthly installments, the Participant’s Account will be paid in substantially equal monthly installments in consecutive years over the period elected by the Participant. Each monthly installment will be paid during the Plan Year in which it is due, commencing as described in Section 6.5.2. During the Plan Year in which distributions commence, the Participant will receive one installment for each calendar month beginning after the date of the Distribution Event, or, if the Participant has elected to receive a distribution commencing during any of the first five years following the year of a Distribution Event, one monthly installment for each calendar month beginning after the anniversary date of the Distribution Event. During the distribution period, the Participant’s Account will be credited with interest compounded monthly at a rate of 7.5% per year. Any installment distribution that complies with this section shall be deemed for all purposes to comply with the Plan requirements regarding the time and form of distributions.



Exhibit 10(f)3


6.5.4
Death After Commencement of Distributions. Upon the death of a Participant after distributions of the Participant’s Account have commenced, the balance of the Participant’s Account will be distributed to the Participant’s Beneficiary at the same times and in the same forms that the Account would have been distributed to the Participant if the Participant had survived.

6.5.5
Distributions to Specified Employees. Notwithstanding anything to the contrary in this Plan, if a Participant becomes entitled to a distribution on account of a Separation from Service and is a Specified Employee on the date of the Separation from Service, distributions shall not commence until the earlier of: (i) the expiration of the six-month period beginning on the date of Participant’s Separation from Service, or (ii) the date of Participant’s death. Payments to which a Specified Employee would otherwise be entitled during this six-month period shall be accumulated and paid, together with earnings that have accrued during this six-month delay, during the seventh month following the date of the Participant’s Separation from Service, or, if earlier, the date of the Participant’s death.

6.5.6
Effect of Change in Control. Notwithstanding a Participant’s elections regarding distributions upon a Separation from Service and a distribution in a Specified Year, if (a) the Participant has a Separation from Service within two years following a Change in Control or (b) a Change in Control occurs within six months after the Participant has a Separation from Service, the Participant shall receive a distribution of the Participant’s entire Account in a single lump sum upon the later of the Separation from Service or the Change in Control, whether or not distributions have already commenced.

6.6
Subsequent Changes in Time and Form of Distributions.
A Participant may, in accordance with rules, procedures and forms specified from time to time by the Administrator, elect to change the time of commencement or change the form in which the Participant’s Account is distributed or both, provided that: (i) the Participant elects at least twelve (12) months prior to the date on which payments are otherwise scheduled to commence; (ii) the new election does not take effect for at least twelve (12) months; and (iii) with respect to changes applicable to distributions in a Specified Year or upon Separation from Service, the distributions must be deferred for at least five (5) years from the date the distributions would otherwise have been paid, or in the case of installment payments, five (5) years from the date the installments were scheduled to commence. For purposes of this section, distributions on account of a Specified Year are considered scheduled to commence on January 1 of the Specified Year and all other distributions are considered to commence on the date of the Distribution Event, or if the Participant has elected a later year for commencement, January 1 of the year elected by the Participant. Any election in accordance with this section to change the time or form or both shall be irrevocable on the date it is filed with the Administrator unless subsequently changed pursuant to this Section.




Exhibit 10(f)3


ARTICLE 7
Accounts and Investments

7.1
Establishment of Accounts.
The Company will establish notional accounts for each Participant as the Administrator deems necessary or advisable from time to time. The Company will establish a Participant’s Account at the earlier of the time a Participant first elects to defer any amounts into the Account or the time the Company first credits non-elective amounts to the Account. Each Account shall be credited as appropriate with deferrals and earnings with respect to deferrals and debited for distributions from the Account.
7.2
Timing of Credits to Accounts.
The Administrator shall credit a Participant’s Elective Deferrals to the Participant’s Account(s) not later than the end of the calendar year during which the Company would otherwise have paid the amounts to the Participant but for the Participant’s deferral election. The Administrator shall credit Non-Elective Deferrals at such times and in such amounts as the Administrator determines.
7.3
Vesting.
All Participant Accounts are fully vested at all times.
7.4
Investments.
The Administrator may select investment funds to use for measuring notional gains and losses credited or debited to Participant’s Accounts. The Administrator will establish, from time to time, rules and procedures for allowing each Participant who has not had a Distribution Event to designate which one or more of the selected investment funds will be used to determine the notional gains and losses credited or debited to the Participant’s Accounts prior to commencement of distributions.
7.5
Valuation Date.
As of each Valuation Date, each Account will be adjusted to reflect the effect of notional investment gains or losses, additions, distributions, transfers and all other transactions with respect to that Account since the previous Valuation Date.

ARTICLE 8
SERP II Retirement Benefit

8.1
Eligibility.
The provisions of Article 8 apply only to Eligible Employees who were eligible for Retirement Benefits on September 30, 2006. Effective October 1, 2006, the Company froze eligibility for Retirement Benefits and individuals who were not Participants on that date are not eligible for Retirement Benefits. Any Participant who was accruing Retirement Benefits on September 30, 2006 or who was eligible to accrue Retirement Benefits on that date because the Participant received an Annual Incentive Award or Other Award and was serving in management salary grades SA - SM, will remain eligible for Retirement Benefits in accordance with this section; provided the Participant remains an Employee of a Related Company.



Exhibit 10(f)3


8.2
Vesting; Forfeiture of Unvested Retirement Benefit.
Participants will fully vest in the Retirement Benefit upon: (i) Retirement; (ii) becoming Disabled after attaining both age 50 and 10 years of Vesting Service; or (iii) upon attaining age 50 and 10 years of Vesting Service after becoming Disabled. Participants will forfeit unvested Retirement Benefits and prior years of Vesting Service upon Separation from Service or death prior to full vesting.
8.3
Retirement Benefit.
The amount of the Retirement Benefit shall equal a single life annuity determined in the manner provided in the Retirement Plans, including any applicable early retirement factors and cost of living adjustments, but using a Participant’s Final Average Earnings and years of Credited Service as described in this section.
8.3.1
Final Average Earnings. Final Average Earnings include the sum of: (i) the Participant’s four highest consecutive Annual Incentive Awards and Other Awards within the “applicable 15-year period,” and (ii) the Participant’s highest Basic Compensation during any consecutive 48-month period within the “applicable 15-year period” to the extent that Basic Compensation exceeds the limitation on compensation imposed by Code section 401(a)(17). Compensation in excess of the limitation on compensation imposed by Code section 401(a)(17) shall be determined by using the limit in effect on the first day of the 48-month period described in (i) and the next three anniversaries of that date. With respect to a Participant who becomes entitled to a distribution upon Retirement, the “applicable 15-year period” shall be the fifteen (15) years preceding the date of Retirement. With respect to a Participant who becomes entitled to a distribution because of Disability, the “applicable 15-year period” shall be the 15-year period that: (i) ends no earlier than the Participant’s Disability and no later than the Participant’s sixty-fifth (65th) birthday; and (ii) would result in the greatest Retirement Benefit.

8.3.2
Years of Credited Service. A Participant will receive credit for years of Credited Service after September 30, 2006, only to the extent that: (i) the Participant has been continuously employed since that date by a Related Company in management salary grades SA - SM; and (ii) distributions of Retirement Benefits have not commenced.

8.4
Forfeiture of Vested Retirement Benefit for Misconduct. Notwithstanding any other term or condition in this Article 8, a Participant will forfeit any vested Retirement Benefit attributable to any year during which the Participant engaged in Misconduct and any subsequent period. For purposes of calculating the Retirement Benefit of any Participant who engaged in Misconduct, the Participant’s Final Average Earnings and Years of Credited Service will exclude the period during which the Participant engaged in Misconduct and any subsequent period.


8.5
Time and Form of Distributions. Subject to the provisions of Section 8.6, a Participant will become entitled to a distribution of vested Retirement Benefits, in the form determined by this section, upon the earlier of: (i) Retirement; (ii) Disability; or (iii) solely with respect to a Participant who vests after becoming Disabled, the earlier of death or attainment of age 65.



Exhibit 10(f)3


8.5.1
Election of Alternative Forms of Distribution. A Participant may elect to receive the Retirement Benefit in one of the following forms, each of which shall be actuarially equivalent: (i) monthly installments over a 15-year period, (ii) a monthly life annuity, (iii) a lump sum payment; or (iv) a combination of a lump sum and either (i) or (ii). Actuarially equivalence will be calculated using actuarial factors adopted by the Administrator from time to time. Effective as of December 31, 2008, Participant elections regarding the form of distribution are irrevocable and will remain in effect until the Retirement Benefits are paid in full unless a Participant elects to change the time and form of payment in accordance with Section 8.7.
8.5.2
Default Form of Payment. If a Participant fails to elect a form of payment with respect to the Participant’s Retirement Benefit before December 31, 2008, the Retirement Benefit will be paid in the form of monthly installments over a 15-year period unless the Participant elects to change the time and form of payment in accordance with Section 8.7.
8.6    Additional Distribution Rules.

8.6.1
Commencement of Distributions. Distributions on account of a Distribution Event other than Disability will commence between the date of the Distribution Event and the end of the year in which the Distribution Event occurs. If a Distribution Event other than Disability occurs on or after October 1 of a Plan Year, the distribution may, to the extent permitted by Section 409A, commence after the Distribution Event and on or before the 15th day of the third calendar month following the Distribution Event, even if after the end of the year during which the Distribution Event occurs; provided, however, the Participant will not be permitted, directly or indirectly, to designate the taxable year of the distribution. Any distribution that complies with this section shall be deemed for all purposes to comply with the Plan requirements regarding the time and form of distributions.
8.6.2
Distributions to Specified Employees. Notwithstanding anything to the contrary in this Plan, if a Participant becomes entitled to a distribution on account of a Retirement and is a Specified Employee on the date of the Retirement, distributions shall not commence until the earlier of: (i) the expiration of the six-month period beginning on the date of Participant’s Retirement, or (ii) the date of the Participant’s death. Payments to which a Specified Employee would otherwise be entitled during this six-month period shall be accumulated and paid, together with earnings (calculated using the interest rate adopted by the Administrator for determining actuarial equivalence) that have accrued during this six-month delay, during the seventh month following the date of the Participant’s Retirement, or, if earlier, the date of the Participant’s death.
8.6.3
Disability. Unless subsequently changed in accordance with the Plan, distributions on account of Disability will commence on the earlier of the Participant’s 65th birthday or the second anniversary of the Disability.



Exhibit 10(f)3


8.6.4
Annuity Payments and Installments. If a Participant elects to receive all or a portion of the distributions in monthly installments, that portion to be paid in installments will be paid in substantially equal monthly installments in consecutive months over a 15-year period. If a Participant elects to receive all or a portion of the distributions in the form of a life annuity, that portion to be paid as a life annuity will be paid in monthly installments in consecutive months for the remainder of the Participant’s life, in the case of a unmarried Participant, and in the case of a married Participant over the lives of the Participant and the Participant’s Eligible Surviving Spouse. Each monthly installment or life annuity payment will be paid during the Plan Year in which it is due, commencing as described in Section 8.6.1. During the Plan Year in which distributions commence, the Participant will receive one installment or life annuity payment for each calendar month beginning after the date of the Distribution Event. If the Participant has elected to be paid in installments, during the distribution period the portion of the Participant’s Account to be paid in installments will be credited with interest compounded monthly at the interest rate used by the Administrator to determine actuarial equivalence. Any distribution that complies with this section shall be deemed for all purposes to comply with the Plan requirements regarding the time and form of distributions.
8.6.5
Death After Commencement of Benefits. Upon the death of a Participant after distributions of the Participant’s Retirement Benefit have commenced, the remainder of the Participant’s Retirement Benefit will continue to be distributed to the Participant’s Beneficiary at the same time and in the same form as the benefit would have been distributed to the Participant had the Participant survived, except to the extent that the Participant had elected a life annuity: (i) if the Participant has an Eligible Surviving Spouse on the date of death, the surviving spouse will receive 60% of the Participant’s life annuity benefit for the remainder of the spouse’s life and (ii) if the Participant does not have an Eligible Surviving Spouse, the annuity will cease as of the first day of the month following the month during which the Participant died.
8.6.6
Effect of Change of Control. With respect to any Participant whose Retirement Benefit distributions have commenced, or would commence, upon a Separation from Service, if (a) the Participant’s Separation from Service occurs within two years following a Change in Control or (b) a Change in Control occurs within six months after the Participant’s Separation from Service, then notwithstanding the Participant’s elections regarding distributions upon a Separation from Service, the Participant shall receive a distribution of the Participant’s entire remaining vested Retirement Benefit in a single lump sum upon the later of the Separation from Service or the Change in Control, whether or not distributions have already commenced. Any Retirement Benefit that does not become payable in a lump sum in accordance with this section will vest, if at all, in accordance with Section 8.2, will become payable in accordance with Section 8.5, and will otherwise remain subject to the provisions of Article 8.




Exhibit 10(f)3


8.7    Subsequent Changes in Time and Form of Payment.
A Participant may, in accordance with rules, procedures and forms specified from time to time by the Administrator, elect to change the form in which the Participant’s Retirement Benefit is distributed, provided that: (i) the Participant elects at least twelve (12) months prior to the date on which payments are otherwise scheduled to commence; (ii) the new election does not take effect for at least twelve (12) months; and (iii) with respect to changes applicable to distributions upon Retirement or, solely with respect to a Participant who vests after becoming Disabled, distributions upon attaining age 65, distributions must be deferred for at least five years from the date the distributions would otherwise have been paid, or in the case of installment payments or life annuity payments, five years from the date the installments or life annuity payments were scheduled to commence. Any such election shall be irrevocable on the date it is filed with the Administrator unless subsequently changed pursuant to this section. For purposes of this section, distributions are considered to commence on the date of the Distribution Event.
8.8    FICA and Other Taxes.
At the time of a Participant’s Distribution Event, the Participant’s Employer(s) shall, in a manner determined by the Employer(s), calculate the FICA and other required employment or state, local, and foreign taxes due on the lump sum present value, calculated using the factors adopted by the Administrator for determining actuarial equivalence, of the Participant’s Retirement Benefit and shall reduce the Participant’s Retirement Benefit by the amount of any such taxes payable by the Participant. The amount of the Participant’s Retirement Benefit remaining after reduction for any taxes shall be payable in accordance with Sections 8.6 and 8.7.

ARTICLE 9
Payment Acceleration and Delay

9.1
Permitted Accelerations of Payment.
Except as otherwise provided herein or permitted by Section 409A, the Plan prohibits the acceleration of the time or schedule of any payment due under the Plan.
9.1.1
Distribution in the Event of Taxation. If, for any reason, all or any portion of any benefit provided by the Plan becomes taxable to a Participant because of a violation of Section 409A prior to receipt, the Participant may file a written request with the Administrator for a distribution of that portion of the Plan benefit that has become taxable. Upon the grant of such a request, which grant shall not be unreasonably withheld, the Participant shall receive a distribution equal to the taxable portion of the Plan benefit. If the request is granted, the tax liability distribution shall be paid between the date on which the Participant’s request is approved and the end of the Plan Year during which the approval occurred, or if later, the 15th day of the third calendar month following the date on which the Participant’s request is approved.

9.1.2
Compliance with Ethics Laws or Conflicts of Interests Laws. The Administrator is authorized, in its sole discretion, to accelerate the time or schedule of a payment to the extent necessary to avoid the violation of any applicable federal, state, local, or foreign ethics law or conflicts of interest law as provided in Section 409A.




Exhibit 10(f)3


9.1.3
Small Accounts. The Administrator may, in its sole discretion, distribute in a single lump sum the aggregate amounts of Deferrals or Elective Deferrals or both credited to the Participant’s Account, along with any related earnings, provided: (i) the distribution results in the payment of the Participant’s entire interest in the Account and all Aggregated Plans, and (ii) the total payment does not exceed the applicable dollar limit under Code section 402(g)(1)(B). The Administrator shall notify the Participant in writing if the Administrator exercises its discretion pursuant to this Section.

9.1.4
Settlement of a Bona Fide Dispute. The Administrator may, in its sole discretion, accelerate the time or schedule of a distribution as part of a settlement of a bona fide dispute between the Participant and the Employer over the Participant’s right to a distribution provided that the distribution relates only to the deferred compensation in dispute and the Employer is not experiencing a downturn in financial health.

9.1.5
Settlement of Debt. The Administrator may, in its sole discretion, accelerate the time or schedule of a payment to satisfy an ordinary debt owed by the Participant to the Employer at the time the debt becomes due as provided in Section 409A.

9.2
Permissible Payment Delays.
Notwithstanding anything in the Plan to the contrary, to the extent permitted by Section 409A, the Administrator may, in its sole discretion, delay a distribution to a Participant:
9.2.1
If the distribution would jeopardize the Employer’s ability to continue as a going concern, provided that the delayed amount is distributed in the first calendar year in which the payment would not have such effect.

9.2.2
If the Company reasonably anticipates that its deduction with respect to a distribution, if paid as scheduled, could be limited or barred by the application of Code section 162(m), provided the delayed amount is distributed in the first calendar year in which the Company reasonably anticipates that the deduction would not be limited or barred by the application of Code section 162(m).

9.2.3
If the distribution would violate Federal securities or other applicable laws, provided that the delayed amount is distributed at the earliest date at which the Administrator reasonably anticipates that the distribution will not cause such violation.

9.2.4
If calculation of the distribution is not administratively practicable due to events beyond the control of the Participant, provided that the delayed amount is distributed in the first calendar year in which the calculation of the distribution is administratively practicable.

9.3
Suspension Not Allowed.
If a Participant whose distributions have commenced becomes eligible again to defer compensation as a Participant in any plan subject to Section 409A maintained by a Related Company, distribution of the Participant’s Retirement Benefit or Account may not be suspended.




Exhibit 10(f)3


ARTICLE 10
Beneficiary Designation

10.1
Beneficiary.
Each Participant shall have the right, in accordance with procedures established from time to time by the Administrator, to designate a Beneficiary(ies) (both primary as well as contingent) to whom Plan benefits shall, if permitted by the Plan, be paid if a Participant dies prior to complete distribution of benefits. Each Beneficiary designation shall be in a written form prescribed by the Administrator, and will be effective only when filed with the Administrator during the Participant’s lifetime. Any Beneficiary designation may be changed by a Participant without the consent of the previously named Beneficiary by filing a new Beneficiary designation with the Administrator. The most recent Beneficiary designation received by the Administrator shall control the payment of all benefits under the Plan in the event of the Participant’s death.
10.2
No Beneficiary Designation.
In the absence of an effective Beneficiary designation, or if all designated Beneficiaries predecease the Participant or die prior to the complete distribution of the Participant’s benefits, benefits shall be paid in the following order of precedence: (a) the Participant’s surviving spouse; (b) the Participant’s children (including adopted children), per stirpes; or (c) the Participant’s estate.

ARTICLE 11
Claims Procedures

11.1
Presentation of Claim.
Any Participant or Beneficiary of a deceased Participant (such Participant or Beneficiary being referred to below as a “Claimant”) may file with the Administrator a written claim for a determination with respect to Plan benefits. The claim must state with particularity the determination desired by the Claimant.
11.2
Notification of Decision.
The Administrator shall consider a Claimant’s claim, and, except as provided below, within 90 days after the claim is received, shall notify the Claimant in writing:
11.2.1
That the claim has been allowed in full; or

11.2.2
That the claim has been denied, in whole or in part, and such notice must set forth in a manner calculated to be understood by the Claimant:

a.
The specific reason(s) for the denial of the claim, or any part of it;

b.
Specific reference(s) to pertinent provisions of the Plan upon which such denial was based;

c.
A description of any additional material or information necessary for the Claimant to perfect the claim, and an explanation of why such material or information is necessary; and



Exhibit 10(f)3


d.
An explanation of the claim review procedures and time limits, including a statement of the Claimant’s right to initiate a civil action pursuant to section 502(a) of ERISA following an adverse determination upon review.

11.2.3
If the Administrator determines that an extension of time for processing is required, written notice of the extension shall be furnished to the Claimant prior to termination of the original 90-day period. In no event shall such extension exceed 90 days from the end of such initial period.

11.2.4
In the case of a claim for disability benefits, the Administrator shall notify the Claimant, in accordance with subsection 11.2.2 above, within 45 days after the claim is received. The notification shall advise the Claimant whether the Administrator’s denial relied upon any specific rule, guideline, protocol or scientific or clinical judgment.

11.2.5
In the case of a claim for disability benefits, if the Administrator determines that an extension of time for processing is required due to matters beyond the control of the Plan, written notice of the extension shall be furnished to the Claimant prior to termination of the original 45-day period. Such extension shall not exceed 30 days from the end of the initial period. If, prior to the end of the first 30-day extension period, the Administrator determines that, due to matters beyond the control of the Plan, an additional extension of time for processing is required, written notice of a second 30-day extension shall be furnished to the Claimant prior to termination of the first 30-day extension.

11.3
Review of a Denied Claim.
Within 90 days after receiving a notice from the Administrator that a claim has been denied, in whole or in part, a Claimant (or the Claimant’s duly authorized representative) may file a written request for a review of the denial of the claim and of pertinent documents. The Claimant (or the Claimant’s duly authorized representative):
11.3.1
May request reasonable access to, and copies of, all documents, records, and other information relevant to the claim, which shall be provided to Claimant free of charge; and

11.3.2
May submit written comments or other documents.

11.4
Decision on Review.
The Administrator shall review all comments or other documents submitted by the Claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination. The Administrator shall render its decision on review promptly, and not later than 60 days after the filing of a written request for review of the denial (or, if other special circumstances require additional time and written notice of such extension and circumstances is given to the Claimant within the initial 60-day period). The Administrator shall notify the Claimant, in language calculated to be understood by the Claimant:
11.4.1
That the claim has been allowed in full; or

11.4.2
That the claim has been denied, in whole or in part, and such notice must set forth:

a.
Specific reasons for the decision;




Exhibit 10(f)3


b.
Specific reference(s) to the pertinent Plan provisions upon which the decision was based;

c.
A statement that Claimant is entitled to reasonable access to, and copies of, all documents, records or other information relevant to the claim upon request and free of charge;

d.
A statement regarding the Claimant’s right to initiate an action pursuant to section 502(a) of ERISA; and

e.
Such other matters as the Administrator deems relevant.

11.4.3
In the case of a claim for disability benefits, the notice shall set forth:

a.
Whether the Administrator’s denial relied upon any specific rule, guideline, protocol or scientific or clinical judgment; and

b.
The following statement: “You and your Plan may have other voluntary alternative dispute resolution options, such as mediation. One way to find out what may be available is to contact your local U.S. Department of Labor Office and your State insurance regulatory agency.”

11.5
Other Remedies.
A Claimant’s compliance with the foregoing procedures is a mandatory prerequisite to a Claimant’s right to pursue any other remedy with respect to any claim relating to this Plan.

ARTICLE 12
Amendment or Termination

The Company hereby reserves the right to amend, modify, or terminate any one or more of the 409A Plans, at any time by action of the Board, with or without prior notice. No amendment or termination shall reduce any Participant’s Account or Retirement Benefit without the written consent of the affected Participant. Notwithstanding anything herein to the contrary, to the extent consistent with Section 409A, the Board may terminate the Plan and distribute to each Participant the Participant’s Account and the Participant’s Retirement Benefit, if any, in a lump sum; provided that all distributions (i) commence no earlier than the date that is twelve (12) months following the termination date (or any earlier date that would comply with Section 409A) and (ii) are completed by the date that is twenty-four (24) months following the termination date (or any later date that would comply with Section 409A). In addition, payments may be accelerated upon termination of any 409A Plan only if, to the extent required under Section 409A, (i) the Company terminates all Aggregated Plans, and (ii) for three years following the date of termination of the 409A Plan, the Company does not adopt any new arrangement that would have been an Aggregated Plan of the terminated 409A Plan.

ARTICLE 13
Miscellaneous Provisions

13.1
Unsecured General Creditor.
Participants and their Beneficiaries, heirs, successors and assigns shall have no legal or equitable rights, interests or claims in any property or assets of an Employer. An Employer’s obligation under the Plan shall be merely that of an unfunded and unsecured promise to pay money in the future.



Exhibit 10(f)3


13.2
Employer’s Liability.
An Employer’s liability for benefits shall be defined only by the Plan. An Employer shall have no obligation to a Participant except as expressly provided in the Plan.
13.3
Nonassignability.
Neither a Participant nor any other person shall have any right to commute, sell, assign, transfer, pledge, anticipate, mortgage or otherwise encumber, transfer, hypothecate, alienate or convey in advance of actual receipt, the amounts, if any, payable hereunder, or any part thereof, which are, and all rights to which are expressly declared to be, unassignable and non-transferable. No part of the amounts payable shall, prior to actual payment, be subject to seizure, attachment, garnishment or sequestration for the payment of any debts, judgments, alimony or separate maintenance owed by a Participant or any other person, be transferable by operation of law in the event of a Participant’s or any other person’s bankruptcy or insolvency or be transferable to a spouse as a result of a property settlement or otherwise.
13.4
No Right to Employment.
Nothing contained in this Plan or any documents relating to the Plan shall: (a) confer on a Participant any right to continue in the employ of a Related Company, (b) constitute any contract or agreement of employment, (c) interfere with the right of a Related Company to terminate the Participant’s employment at any time, with or without cause.
13.5
Incompetency.
If the Administrator determines that a distribution under this Plan is to be paid to a minor, a person declared incompetent or to a person incapable of handling the disposition of that person’s property, the Administrator may direct such distribution to be paid to the guardian, legal representative or person having the care and custody of such minor, incompetent or incapable person. The Administrator may require proof of majority, competence, capacity, guardianship, or status as a legal representative as it may deem appropriate prior to distribution of a payment. Any distribution shall be a payment for the account of the Participant and the Participant’s Beneficiary, as the case may be, and shall be a complete discharge of any liability for such payment amount.
13.6
Tax Withholding.
To the extent required by the law in effect at the time of any distribution, the Participant’s Employer shall withhold from any payments to a Participant hereunder any taxes required to be withheld by the federal or any state or local government, in amounts and in a manner to be determined in the sole discretion of the Employer(s).
13.7
Furnishing Information.
A Participant or his Beneficiary will cooperate with the Administrator by furnishing any and all information requested by the Administrator and take such other actions as may be requested in order to facilitate the administration of the Plan and the distributions hereunder, including but not limited to taking such physical examinations as the Administrator may deem necessary.
13.8
Notice.
Any notice or filing required or permitted under the Plan shall be sufficient if in writing and if (i) hand-delivered or sent by telecopy, (ii) sent by registered or certified mail, or (iii) sent by nationally-recognized overnight courier. Such notice shall be deemed given as of (i) the date of delivery if hand-delivered or sent by telecopy, (ii) as of the date shown on the postmark on the receipt for registration or certification, if delivery is by mail, or (iii) on the first business day after dispatch, if sent by nationally-recognized overnight courier.



Exhibit 10(f)3


13.9
Gender and Number.
Except when otherwise indicated by context, words in the masculine gender shall include the feminine and neuter genders, the singular shall include the plural, and the plural shall include the singular.
13.10
Headings.
The headings contained in this Plan are for convenience only and will not control or affect the meaning or construction of any of the terms or provisions of this Plan.
13.11
Applicable Law and Construction.
The Plan shall be governed by, construed and administered in accordance with the applicable provisions of ERISA, and any other applicable Federal law, including Section 409A, and to the extent not preempted by Federal law, this Plan shall be governed by, construed and administered in accordance with the laws of the State of Minnesota, other than its laws respecting choice of law.
13.12
Invalid or Unenforceable Provisions.
If any provision of this Plan shall be held invalid or unenforceable, such invalidity or unenforceability shall not affect any other provisions hereof and the Administrator may elect in its sole discretion to construe such invalid or unenforceable provisions in a manner that conforms to applicable law or as if such provisions, to the extent invalid or unenforceable, had not been included.
13.13
Successors.
This Plan shall bind any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business or assets of the Company, in the same manner and to the same extent that the Company would be obligated under this Plan if no succession had taken place. In the case of any transaction in which a successor would not by the foregoing provision or by operation of law be bound by this Plan, the Company shall require such successor expressly and unconditionally to assume and agree to perform the obligations of the Company and each Employer under this Plan, in the same manner and to the same extent that the Company and each Employer would be required to perform if no such succession had taken place.










Exhibit 10(f)3


APPENDIX A
162(m) Deferrals” means the portion of a Participant’s Annual Incentive Award for a Plan Year that the Company reasonably anticipates is not deductible by the application of Code section 162(m).
409A Plan” means one of the separate non-qualified deferred compensation arrangements described in Section 2.1.
Account” means the Company’s bookkeeping entry representing a Participant’s Deferrals, and such other accounts or sub-accounts as the Administrator deems necessary or appropriate.
Administrator” means the Employee Benefit Plans Committee appointed by the Board or delegates of the Employee Benefit Plans Committee.
Aggregated Plans” means, with respect to any 409A Plan, that plan and all other non-qualified deferred compensation plans which must be aggregated with that plan in accordance with the plan aggregation rules of Section 409A.
Annual Incentive Award” means the annual award received by a Participant under the ALLETE Executive Annual Incentive Plan or any predecessor or successor plan.
Basic Compensation” shall have the meaning prescribed in Retirement Plan A, but shall be calculated without regard to the limitation on compensation imposed by Code section 401(a)(17).
Beneficiary” means one or more persons, trusts, estates or other entities, designated in accordance this Plan, that are entitled to receive Plan benefits upon the death of a Participant.
Board” means the Board of Directors of the Company.
Bonus” means any incentive compensation, including Annual Incentive Awards, that is payable to the Participant in addition to the Participant’s Salary.
Change in Control” means the earliest of:
i.
the date any one Person, or more than one Person acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)), acquires ownership of stock of the Company that, together with stock previously held by the acquirer, constitutes more than fifty (50%) percent of the total fair market value or total voting power of Company stock. If any one Person, or more than one Person acting as a group, is considered to own more than fifty (50%) percent of the total fair market value or total voting power of Company stock, the acquisition of additional stock by the same Person or Persons acting as a group does not cause a Change in Control. An increase in the percentage of stock owned by any one Person, or Persons acting as a group, as a result of a transaction in which Company acquires its stock in exchange for property, is treated as an acquisition of stock;




Exhibit 10(f)3


ii.
(b) the date any one Person, or more than one Person acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)), acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by that Person or Persons) ownership of Company stock possessing at least thirty (30%) percent of the total voting power of Company stock;

iii.
(c) the date a majority of the members of the Company’s board of directors is replaced during any twelve (12) month period by directors whose appointment or election is not endorsed by a majority of the members of the board of directors prior to the date of appointment or election; or

iv.
(d) the date any one Person, or more than one Person acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)), acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by that Person or Persons) assets from the Company that have a total gross fair market value equal to at least forty (40%) percent of the total gross fair market value of all the Company’s assets immediately prior to the acquisition or acquisitions. For this purpose, “gross fair market value” means the value of the corporation’s assets, or the value of the assets being disposed of, without regard to any liabilities associated with these assets.

In determining whether a Change in Control occurs, the attribution rules of Code section 318 apply to determine stock ownership. The stock underlying a vested option is treated as owned by the individual who holds the vested option, and the stock underlying an unvested option is not treated as owned by the individual who holds the unvested option. The term “Person” used in this definition means any individual, corporation (including any non-profit corporation), general, limited or limited liability partnership, limited liability company, joint venture, estate, trust, firm, association, organization or other entity or any governmental or quasi-governmental authority, organization, agency or body.
Claimant” shall have the meaning set forth in Section 11.1.
Code” means the Internal Revenue Code of 1986, as it may be amended from time to time.
Company” means ALLETE, Inc., a Minnesota Corporation, and any successor to all, or substantially all, of the Company’s assets or business.
Credited Service” shall have the meaning prescribed in the Retirement Plan A.
Deferrals” means Elective Deferrals and Non-Elective Deferrals.
Disability” or “Disabled” when used with an initial capital letter, means a physical or mental condition in which the Participant is:
i.
unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months;



Exhibit 10(f)3


ii.
by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, receiving income replacement benefits for a period of not less than three (3) months under the Employer’s accident and health plan;

iii.
determined to be totally disabled by the Social Security Administration; or

iv.
disabled pursuant to an Employer-sponsored disability insurance arrangement provided that the definition of disability applied under such disability insurance program complies with the foregoing definition of Disability.

When the term “disability” (without an initial capital letter) is used in the Plan, it shall have the meaning prescribed in the definition of “Separation from Service.”
Distribution Event” means, with respect to Article 6, a Specified Year, a Separation from Service, death, Disability or the Administrator’s determination regarding the occurrence of an Unforeseeable Emergency and, with respect to Article 8, Retirement, Disability or solely with respect to a Participant who vests after becoming Disabled, the earlier of death or attainment of age 65.
Elective Deferrals” means any portion of a Participant’s Salary, Bonus, Severance Pay, Annual Make-up Award or Other Award that a Participant irrevocably elects to defer.
Eligible Employee” means an Employee in management salary grades SA-SM, who has been notified in writing by the Administrator of eligibility to participate in the Plan.
Eligible Surviving Spouse” shall have the meaning prescribed in Retirement Plan A.
Employee” means a person who is a common-law employee of any Related Company.
Employer(s)” means the Company and any Related Company (now in existence or hereafter formed or acquired) that have been selected by the Administrator to participate in the Plan.
ERISA” means the Employee Retirement Income Security Act of 1974, as it may be amended from time to time.
IRS” means the Internal Revenue Service.
Misconduct” means the occurrence of either or both of the following, as determined in its sole discretion by either the Executive Compensation Committee of the Company’s Board of Directors with respect to Section 16 Officers of the Company, or the Administrator with respect to any other Participant:

(a)    an act or omission by the Participant involving dishonesty in connection with his or her responsibilities as an employee of the Company; or
(b)    the Participant’s conviction of, or entry of a plea of nolo contendere to, any felony or a misdemeanor involving moral turpitude, provided that a misdemeanor motor vehicle violation will not constitute a crime of moral turpitude unless it involves driving while impaired within the scope of employment or another serious driving offense committed within the scope of employment.



Exhibit 10(f)3


For purposes of clarifying the foregoing definition, Misconduct can occur regardless of whether the Company discovers the Misconduct before or after the Participant’s Separation from Service and regardless of whether the Participant has a Separation from Service on account of the Misconduct.
Non-Elective Deferrals” means 162(m) Deferrals and the Annual Make-up Award credited to the Account of any Participant whose Salary exceeds the Code section 401(a)(17) limit.
Other Award” means an award, other than an Annual Incentive Award or Severance Pay, that a Participant may defer at the Administrator’s discretion.
Participant” means any Eligible Employee (i) who has elected to defer amounts under the Plan, (ii) who is eligible to receive a Retirement Benefit or (iii) whose compensation, or a portion thereof, was deferred as a Non-Elective Deferral.
Plan” means SERP II.
Plan Year” means a period beginning on January 1 of each calendar year and continuing through December 31 of such calendar year.
Related Company” means the Company and all persons with whom the Company would be considered a single employer under Code section 414(b) (employees of controlled group of corporations), and all persons with whom such person would be considered a single employer under Code section 414(c) (employees of partnerships, proprietorships, etc., under common control); provided that in applying Code sections 1563(a)(1), (2), and (3) for purposes of determining a controlled group of corporations under Code section 414(b), the language “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Code sections 1563(a)(1), (2), and (3), and in applying Treasury Regulations section 1.414(c)-2 for purposes of determining trades or businesses (whether or not incorporated) that are under common control for purposes of Code section 414(c), “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Treasury Regulations section 1.414(c)-2.
Retirement” means Separation from Service, for reasons other than death, on or after attaining both 50 years of age and 10 years of Vesting Service.
Retirement Benefit” means the benefit payable pursuant to Article 8.
Retirement Plans” mean the Minnesota Power and Affiliated Companies Retirement Plan A and Minnesota Power and Affiliated Companies Retirement Plan B, as amended from time to time.
Retirement Savings and Stock Ownership Plan” or “RSOP” means the Minnesota Power and Affiliated Companies Retirement Savings and Stock Ownership Plan, as amended from time to time.
Salary” means the Participant’s earnings during a calendar year, before any reduction pursuant to Code sections 125, 132(f)(4), or 401(k) and this Plan. It does not include overtime compensation, if any, Bonuses, Annual Incentive Awards and Other Awards, expense reimbursements, allowances, commission payments, employer contributions or awards under this Plan or other employee benefit plans, imputed income (whether such imputed income is from vehicle use, life insurance premiums, or any other source) payments made pursuant to the Results Sharing Program, payment of stock options and performance shares under the Long Term Incentive Compensation Plan, and any other payments of a similar nature. In the case of a Participant who is employed jointly by the Company and an affiliated company (as defined in the RSOP), Salary as defined herein shall include amounts received from all such companies.



Exhibit 10(f)3


Section 409A” means both section 409A of the Code and Treasury Regulations section 1.409A-1 et seq., as they both may be amended from time to time, and other guidance issued by the Treasury Department and Internal Revenue Service thereunder.
Separation from Service” means that the Participant terminates employment within the meaning of Treasury Regulations section 1.409A-1(h) and other applicable guidance with all Related Companies. Whether a termination of employment has occurred is determined under the facts and circumstances, and a termination of employment shall occur if all Related Companies and the Participant reasonably anticipate that no further services shall be performed after a certain date or that the level of bona fide services the Participant shall perform after such date (as an employee or an independent contractor) shall permanently decrease to no more than 20 percent of the average level of bona fide services performed (whether as an employee or an independent contractor) over the immediately preceding 36-month period (or the full period of services to the Related Companies if the Participant has been providing services to the Related Companies less than 36 months). A Participant shall not be considered to separate from service during a bona fide leave of absence for less than six (6) months or longer if the Participant retains a right to reemployment with any Related Company by contract or statute. With respect to disability leave, a Participant shall not be considered to separate from service for 29 months unless the Participant otherwise terminates employment or is terminated by all Related Companies. For purposes of determining whether a Separation from Service has occurred on account of a disability, a Participant shall be disabled if the Participant is suffering from any medically determinable physical or mental impairment resulting in the Participant’s inability to perform the duties of his position or any substantially similar position, if such impairment can be expected to result in death or can be expected to last for a continuous period of 6 months.
SERP II” means the ALLETE and Affiliated Companies Supplemental Executive Retirement Plan II, as amended from time to time.
Severance Pay” means the cash payment(s) to a Participant payable in connection with his Separation from Service in accordance with the terms of a severance arrangement that is the subject of bona fide, arm’s length negotiations between a Related Company and the Participant at the time of the Separation from Service.
Specified Year” means a calendar year during which a Participant has elected to receive a distribution of Elective Deferrals.
Specified Employee” means an Employee who is subject to the six-month delay rule described in Code section 409A(2)(B)(i). The Board shall adopt guidelines for identifying Specified Employees in a manner consistent with Section 409A, and may amend the guidelines from time to time as permitted by Section 409A.
Unforeseeable Emergency” means an unanticipated emergency that is caused by an event beyond the control of the Participant that would result in severe financial hardship to the Participant resulting from (i) an illness or accident of the Participant or the Participant’s spouse, the Participant’s beneficiary, or the Participant’s dependent (as defined in Code section 152, without regard to Code sections 152(b)(1), (b)(2), and (d)(1)(B)), (ii) a loss of the Participant’s property due to casualty, or (iii) such other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant, all as determined in the sole discretion of the Administrator.
Valuation Date” means each day that the U.S. stock markets are open or such other dates as may be set by the Administrator from time to time.



Exhibit 10(f)3


Vesting Service” shall have the meaning prescribed in the Retirement Plan A. Participants will continue to receive credit for Vesting Service after October 1, 2006. A Disabled Participant will receive credit for Vesting Service on account of any period after the commencement of the Disability during which the Participant is characterized as an active employee on the Related Company’s employment records.



Exhibit 10(f)3


IN WITNESS WHEREOF, ALLETE, Inc. has caused these presents to be signed by its duly authorized officers, effective as of January 1, 2015.


ALLETE, Inc.
By:
/s/ Alan R. Hodnik
 
Alan R. Hodnik
Its:
Chairman, President and Chief Executive Officer
                    
ATTEST
By:
/s/ Deborah A. Amberg
 
Deborah A. Amberg
Its:
Senior Vice President, General Counsel and Secretary
                    




Exhibit 10(j)16 12-31-2014
Exhibit 10(j)16


ALLETE
EXECUTIVE LONG-TERM INCENTIVE COMPENSATION PLAN
PERFORMANCE SHARE GRANT
[Effective 2015]
[Eligible Executive Employees]

Name


In accordance with the terms of ALLETE’s Executive Long-Term Incentive Compensation Plan, as amended (the "Plan"), and as determined by and through the Executive Compensation Committee of ALLETE’s Board of Directors, ALLETE hereby grants to you (the "Participant") Performance Shares, as set forth below, subject to the terms and conditions set forth in this Grant, including Annex A and Annex B hereto and all documents incorporated herein by reference:


Number of Performance Shares Granted:
 
Date of Grant:
 
Performance Period:
 
Performance Goals:
See Annex B

This Grant is made in accordance with the Plan.

Further terms and conditions of the Grant are set forth in Annex A hereto and Performance Goals are set forth in Annex B hereto, both of which are integral parts of this Grant.

Any term, provision or condition applicable to the Performance Shares set forth in the Plan and not set forth herein is hereby incorporated by reference. To the extent any provision hereof is inconsistent with a Plan provision, the Plan provision will govern.

YOU SHOULD CAREFULLY READ AND REVIEW THE TERMS AND CONDITIONS SET FORTH IN THIS GRANT, INCLUDING ANNEX A HERETO, WHICH CONTAINS IMPORTANT INFORMATION, INCLUDING MANDATORY CLAIMS AND ARBITRATION PROCEDURES.

You will be deemed to have accepted this Grant on the Date of Grant and all its associated terms and conditions, including the mandatory claims and arbitration procedures set forth in Annex A, unless you notify the Company of your non-acceptance of the Grant by contacting the Director-Compensation and Benefits, in writing within sixty (60) days of the Date of Grant.

IN WITNESS WHEREOF, ALLETE has caused this Grant to be executed by its Chairman, President and Chief Executive Officer as of the date and year first above written.

ALLETE

By:
 
 
Chairman, President & CEO

Attachments:    Annex A and Annex B



ANNEX A
TO
ALLETE
EXECUTIVE LONG-TERM INCENTIVE COMPENSATION PLAN
PERFORMANCE SHARE GRANT
    
The Grant of Performance Shares evidenced by the Grant to which this is annexed is subject to the following additional terms and conditions:

1.    Dividend Equivalents. You will receive Dividend Equivalents with respect to Performance Shares that are earned and payable. Dividend Equivalents are calculated and credited to you after the Performance Period has ended. The Dividend Equivalents will be in the form of additional Performance Shares, which will be added to the number of Performance Shares earned, and will equal the number of Shares (including fractional Shares) that could have been purchased on applicable dividend payment dates, based on the closing ALLETE common stock price as reported in the consolidated transaction reporting system on that date, with cash dividends that would have been paid on underlying Performance Shares, if such Performance Shares were Shares. Dividend Equivalents will only become payable if and to the extent the underlying Performance Shares are earned and become payable.

2.    Satisfaction of Goals. Performance Shares remain unearned unless and until Performance Goals are achieved. After the Performance Period has ended, the Executive Compensation Committee (the “Committee”) will determine the extent to which the Performance Goals have been met. You will not earn any Performance Shares if the threshold performance level has not been met. Subject to the provisions of Section 4 below and to provisions in the Plan for change in control, Performance Shares will be earned as follows: If the threshold level has been met, you will have earned 50% of the Performance Shares (as increased by the Dividend Equivalents). If the target level has been met, you will have earned 100% of the Performance Shares (as increased by the Dividend Equivalents). If the superior level has been met, you will have earned 200% of the Performance Shares (as increased by the Dividend Equivalents). Straight line interpolation will be used to determine earned awards based on achievement of goals between the threshold, target and superior levels.

3.    Payment. Subject to the provisions of Section 4 below and to provisions in the Plan for Change in Control, Performance Shares (as increased by the Dividend Equivalents) shall be paid in full after the Committee has determined the extent to which Performance Goals have been met and within two and one half months after the end of the Performance Period. Payment shall be made, after withholding Performance Shares in an amount equal in value to the minimum amount of tax required to be withheld by law, by depositing ALLETE common stock into your Invest Direct account. Performance Share awards shall not vest until paid.


4.    Payment Upon Death, Retirement or Disability; Forfeiture of Unvested Performance Shares Upon Demotion, Unsatisfactory Job Performance, Default on Certain Agreements or Other Separation from Service.




4.1    If during a Performance Period you (i) Retire, (ii) die while employed by a Related Company, or (iii) become Disabled, you (or your beneficiary or estate) will receive a payment of any Performance Shares (as increased by the Dividend Equivalents) after the end of the Performance Period in accordance with Section 3 above. The payment shall be prorated based upon the number of whole calendar months within the Performance Period which had elapsed as of the date of death, Retirement or Disability in relation to the number of calendar months in the full Performance Period. A whole month is counted in the calculation if you were in the position as of the 15th of the month.

4.2     If after the end of a Performance Period, but before any or all Performance Shares have been paid, you Retire, die or become Disabled, you (or your beneficiary or estate) will be entitled to full payout of all earned Performance Shares (as increased by the Dividend Equivalents) in accordance with Section 3 above.

4.3    If, prior to payment of all Performance Shares, you are demoted, you default on any written agreement with a Related Company related to a restrictive employment covenant (such as confidentiality, non-disclosure, non-competition, non-solicitation, or the like) or ALLETE determines, in its sole discretion, that your job performance is unsatisfactory, ALLETE reserves the right to cancel or amend your grant relating to any unpaid Performance Shares, with the result that some portion or all of your unpaid Performance Shares (and related Dividend Equivalents) will be forfeited.

4.4    If you have a Separation from Service for any reason other than those specified in subsection 4.1 above, all Performance Shares (and related Dividend Equivalents), to the extent not yet paid, shall be forfeited on the date of such Separation from Service, except as otherwise provided by the Committee.

5.    Compensation Recovery Policy. The Grant is subject to the terms of any compensation recovery policy or policies established by ALLETE as may be amended from time to time (“Compensation Recovery Policy”). ALLETE hereby incorporates into the Grant the terms of the Compensation Recovery Policy.

6.    Section 409A Compliance. This Grant is intended to comply with Section 409A of the Code (“Section 409A”) or an exemption thereunder, and, accordingly, to the maximum extent permitted, the Plan and the Grant shall be interpreted and administered in compliance therewith. Notwithstanding any other provision of the Grant, payments provided pursuant to the Grant may only be made upon an event and in a manner that complies with Section 409A or an applicable exemption. Any payments pursuant to the Grant that may be excluded from Section 409A as a short-term deferral shall be excluded from Section 409A to the maximum extent possible. To the extent that any provision of the Grant would cause a conflict with the requirements of Section 409A or would cause the administration of the Grant to fail to satisfy Section 409A, such provision shall be deemed null and void to the extent permitted by applicable law. Nothing herein shall be construed as a guarantee of any particular tax treatment. ALLETE makes no representation that the Grant complies with Section 409A and in no event shall ALLETE be liable for the payment of any taxes and penalties that you may incur under Section 409A.

7.    Claims Procedure and Arbitration. The Grant is subject to the following claims procedures:


2


7.1    Mandatory Claims Procedures. If you or any person acting on your behalf (the “Claimant”) has any claim or dispute related in any way to the Grant or to the Plan, the Claimant must follow these claims procedures. All claims must be brought no later than one year following the date on which the claim first arose and any claim not submitted within such time limit will be waived.

7.2    Claim Submission. Any claim must be made in writing to the Claims Administrator. The Claims Administrator, or its delegate, shall notify the Claimant of the resolution of the claim within 90 days after receipt of the claim; provided, however, if the Claims Administrator determines that an extension is necessary, the 90-day period shall be extended to up to 180 days upon notice to that effect to the Claimant.

7.3    Notice of Denial. If a claim is wholly or partially denied, the denial notice shall contain (i) the reason or reasons for denial of the claim, and (ii) references to the pertinent Plan provisions upon which the denial is based. Unless the claim is submitted for arbitration as provided below and in the Plan, the Claims Administrator’s decision or action shall be final, conclusive and binding on all persons having any interest in the Plan.

7.4    Arbitration. If, after exhausting the procedures set forth above, a Claimant wishes to pursue legal action, any action by the Claimant with respect to a claim, must be resolved by arbitration in the manner described herein.

a)
Time Limits. A Claimant seeking arbitration of any determination by the Claims Administrator must, within six (6) months of the date of the Claims Administrator’s final decision, file a demand for arbitration with the American Arbitration Association submitting the claim to resolution by arbitration. A Claimant waives any claim not filed timely in accordance with this Section.

b)
Rules Applicable to Arbitration. The arbitration process shall be conducted in accordance with the Commercial Law Rules of the American Arbitration Association.

c)
Venue. The arbitration shall be conducted in Minneapolis, Minnesota.

d)
Binding Effect. The decision of the arbitrator with respect to the claim will be final and binding upon the Company and the Claimant. BY PARTICIPATING IN THE PLAN, AND ACCEPTING THE GRANT, YOU, ON BEHALF OF YOURSELF AND ANY PERSONWITH A CLAIM RELATING TO YOUR GRANT, AGREE TO WAIVE ANY RIGHT TO SUE IN COURT OR TO PURSUE ANY LEGAL RIGHT OR REMEDY THAT MIGHT OTHERWISE BE AVAILABLE IN CONNECTION WITH THE RESOLUTION OF THE CLAIM.

e)
Enforceability. Judgment upon any award entered by an arbitrator may be entered in any court having jurisdiction over the parties.


3


f)
Waiver of Class, Collective, and Representative Actions.  Any claim shall be heard without consolidation of such claims with any other person or entity.  To the fullest extent permitted by law, whether in court or in arbitration, by participating in the Plan, you waive any right to commence, be a party to in any way, or be an actual or putative class member of any class, collective, or representative action arising out of or relating to any claim, and you agree that any claim may only be initiated or maintained and decided on an individual basis. 

g)
Standard of Review. Any decision of an arbitrator on a claim shall be limited to determining whether the Claims Administrator’s decision or action was arbitrary or capricious or was unlawful. The arbitrator shall adhere to and apply the deferential standard of review set out in Conkright v. Frommert, 130 S. Ct. 1640 (2010), Metropolitan Life Insurance Co. v. Glenn, 554 U.S. 105 (2008), and Firestone Tire and Rubber Company v. Bruch, 489 U.S. 101 (1989), and shall accord due deference to the determinations, interpretations, and construction of the Plan document by the Claims Administrator.

h)
General Procedures.

i.
Arbitration Rules. The arbitration hearing will be conducted under the AAA Commercial Arbitration Rules (as amended or revised from time to time by AAA) (hereinafter the “AAA Rules”), before one AAA arbitrator who is from the Large, Complex Case Panel and who has experience with matters involving executive compensation and equity compensation plans. The AAA Rules and the terms and procedures set forth here may conflict on certain issues. To the extent that the procedures set forth here conflict with the AAA Rules, the procedures set forth here shall control and be applied by the arbitrator. Notwithstanding the amount of the claim, the Procedures for Large, Complex Commercial Disputes shall not apply.

ii.
Substantive Law. The arbitrator shall apply the substantive law (and the laws of remedies, if applicable), of Minnesota or federal law, or both, depending upon the claim. Except to the extent required by applicable law, the Claimant shall keep any arbitration decision or award strictly confidential and not disclose to anyone other than his or her spouse, attorney, or tax advisor.

iii.
Authority. The arbitrator shall have jurisdiction to hear and rule on prehearing disputes and is authorized to hold prehearing conferences by telephone or in person as the arbitrator deems necessary. The arbitrator will have the authority to hear a motion to dismiss and/or a motion for summary judgment by any party and in doing so shall apply the standards governing such motions under the Federal Rules of Civil Procedure.

iv.
Pre-Hearing Procedures. Each party may take the deposition of not more than one individual and the expert witness, if any, designated by another party. Each party will have the right to subpoena witnesses in accordance with the Federal Arbitration Act, Title 9 of the United States Code. Additional discovery may be had only if the arbitrator so orders, upon a showing of substantial need.

4


v.
Fees and Costs. Administrative arbitration fees and arbitrator compensation shall be borne equally by the parties, and each party shall be responsible for its own attorney’s fees, if any; provided, however, that the Committee will authorize payment by the Company of all administrative arbitration fees, arbitrator compensation and attorney’s fees if the Committee concludes that a Claimant has substantially prevailed on his or her claims. Unless prohibited by statute, the arbitrator shall assess attorney’s fees against a party upon a showing that such party’s claim, defense or position is frivolous, or unreasonable, or factually groundless. If either party pursues a claim by any means other than those set forth in this Article, the responding party shall be entitled to dismissal of such action, and the recovery of all costs and attorney’s fees and losses related to such action, unless prohibited by statute.

i)
Interstate Commerce and the Federal Arbitration Act. The Company is involved in transactions involving interstate commerce, and the employee’s employment with the Company involves such commerce. Therefore, the Federal Arbitration Act, Title 9 of the United States Code, will govern the interpretation, enforcement, and all judicial proceedings regarding the arbitration procedures in this Section.

8.    Ratification of Actions. By receiving the Grant or other benefit under the Plan, you and each person claiming under or through you shall be conclusively deemed to have indicated your acceptance and ratification of, and consent to, any action taken under the Plan or the Grant by ALLETE, the Board or the Committee.

9.    No Impact on Other Benefits. The Grant or payment on account thereof shall not be taken into account in determining any benefits under any severance, retirement, welfare, insurance or other benefit plan of ALLETE or any affiliate except to the extent otherwise expressly provided in writing in such other plan or an agreement thereunder.

10.    Notices. Any notice hereunder to ALLETE shall be addressed to ALLETE, 30 West Superior Street, Duluth, Minnesota 55802, Attention: Director - -Compensation and Benefits, Human Resources, and any notice hereunder to you shall be directed to your address as indicated by ALLETE’s records, subject to the right of either party to designate at any time hereafter in writing some other address.

11.    Governing Law and Severability. To the extent not preempted by the Federal law, the Grant will be governed by and construed in accordance with the laws of the State of Minnesota, without regard to its conflicts of law provisions. In the event any provision of the Grant shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of the Grant, and the Grant shall be construed and enforced as if the illegal or invalid provision had not been included.

12.    Definitions. Capitalized terms not otherwise defined herein shall have the meanings given them in the Plan. The following definitions apply to the Grant and this Annex A:

12.1    Claims Administrator” means ALLETE’s Chief Executive Officer, unless the claimant is (or is acting on behalf of) an ALLETE executive officer (within the meaning of Exchange Act Rule 3b-7), in which case the Claims Administrator is the Executive Compensation Committee of the Board of Directors.

5


12.2    Code” means the Internal Revenue Code of 1986, as it may be amended from time to time.
12.3    Disability” or “Disabled” means a physical or mental condition in which the Participant is:
(a)
unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months;

(b)
by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, receiving income replacement benefits for a period of not less than three (3) months under the Employer’s accident and health plan;

(c)
determined to be totally disabled by the Social Security Administration; or

(d)
disabled pursuant to an Employer-sponsored disability insurance arrangement provided that the definition of disability applied under such disability insurance program complies with the foregoing definition of Disability.

12.4    Related Company” means ALLETE, Inc. and all persons with whom the ALLETE, Inc. would be considered a single employer under Code section 414(b) (employees of controlled group of corporations), and all persons with whom such person would be considered a single employer under Code section 414(c) (employees of partnerships, proprietorships, etc., under common control); provided that in applying Code sections 1563(a)(1), (2), and (3) for purposes of determining a controlled group of corporations under Code section 414(b), the language “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Code sections 1563(a)(1), (2), and (3), and in applying Treasury Regulations section 1.414(c)-2 for purposes of determining trades or businesses (whether or not incorporated) that are under common control for purposes of Code section 414(c), “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Treasury Regulations section 1.414(c)-2.

12.5    Retirement” or “Retires” means Separation from Service, for reasons other than death or Disability, on or after attaining normal retirement age or early retirement age as defined in the most applicable qualified retirement plan sponsored by the Related Company that employed the Participant immediately preceding the Separation from Service, without regard to whether the Participant is a participant in such plan, or if the employer Related Company does not sponsor such retirement plan, on or after attaining Normal Retirement Age or Early Retirement Age as defined in the ALLETE and Affiliated Companies Retirement Plan A, without regard to whether the Participant is a participant under the ALLETE and Affiliated Companies Retirement Plan A.


6


12.6    Separation from Service” means that the Participant terminates employment within the meaning of Treasury Regulations section 1.409A-1(h) and other applicable guidance with all Related Companies. Whether a termination of employment has occurred is determined under the facts and circumstances, and a termination of employment shall occur if all Related Companies and the Participant reasonably anticipate that no further services shall be performed after a certain date or that the level of bona fide services the Participant shall perform after such date (as an employee or an independent contractor) shall permanently decrease to no more than 20 percent of the average level of bona fide services performed (whether as an employee or an independent contractor) over the immediately preceding 36-month period (or the full period of services to the Related Companies if the Participant has been providing services to the Related Companies less than 36 months). A Participant shall not be considered to separate from service during a bona fide leave of absence for less than six (6) months or longer if the Participant retains a right to reemployment with any Related Company by contract or statute. With respect to disability leave, a Participant shall not be considered to separate from service for 29 months unless the Participant otherwise terminates employment or is terminated by all Related Companies.



7


ANNEX B
TO
ALLETE
Executive Long Term Incentive Compensation Plan
Performance Share Grant
Effective 2015
[Eligible Executive Employees]

Financial Measure:
Total Shareholder Return (TSR) computed over the three-year period.

Performance Share Award:
If ALLETE’s TSR ranking is 4th or higher among a peer group of 27 companies (superior performance), 200% of the Performance Share Grant will be earned. If ALLETE’s TSR performance ranks 14th among the peer group (target performance), 100% of the Grant will be earned. If ALLETE’s TSR performance ranks 19th (threshold performance), 50% of the Grant will be earned. If TSR performance is below threshold, no Performance Shares will be earned. Straight-line interpolation will be used to determine earned awards based on the TSR ranking between threshold, target and superior.
TSR Rank
Perf. Level
Payout %
1
 
200%
2
 
200%
3
 
200%
4
Superior
200%
5
 
190%
6
 
180%
7
 
170%
8
 
160%
9
 
150%
10
 
140%
11
 
130%
12
 
120%
13
 
110%
14
Target
100%
15
 
90%
16
 
80%
17
 
70%
18
 
60%
19
Threshold
50%
20
 
0%
21
 
0%
22
 
0%
23
 
0%
24
 
0%
25
 
0%
26
 
0%
27
 
0%
28
 
0%







Exhibit 10(j)17 12-31-2014
Exhibit 14(j)17

ALLETE
EXECUTIVE LONG-TERM INCENTIVE COMPENSATION PLAN
RESTRICTED STOCK UNIT GRANT
[Effective 2015]
[Eligible Executive Employees]

Name
 

In accordance with the terms of ALLETE’s Executive Long-Term Incentive Compensation Plan, as amended (the "Plan"), and as determined by and through the Executive Compensation Committee of ALLETE’s Board of Directors, ALLETE hereby grants to you (the "Participant") Restricted Stock Units (“RSU’s”) as set forth below, payable in the form of ALLETE Common Stock, subject to the terms and conditions set forth in this Grant, including Annex A hereto, and all documents incorporated herein by reference:

Number of Restricted Stock Units:        
Date of Grant:                    
Vesting Period:                    
                
This Grant is made in accordance with the Plan.

Further terms and conditions of the Grant are set forth in Annex A hereto, which is an integral part of this Grant.

Any term, provision or condition applicable to the Restricted Stock Units set forth in the Plan and not set forth herein is hereby incorporated by reference. To the extent any provision hereof is inconsistent with a Plan provision, the Plan provision will govern.

YOU SHOULD CAREFULLY READ AND REVIEW THE TERMS AND CONDITIONS SET FORTH IN THIS GRANT, INCLUDING ANNEX A HERETO, WHICH CONTAINS IMPORTANT INFORMATION, INCLUDING MANDATORY CLAIMS AND ARBITRATION PROCEDURES.
    
You will be deemed to have accepted this Grant on the Date of Grant, and all its associated terms and conditions, including the mandatory claims and arbitration procedures set forth in Annex A, unless you notify the Company of your non-acceptance of the Grant by contacting the Director-Compensation and Benefits, in writing within sixty (60) days of the Date of Grant.


IN WITNESS WHEREOF, ALLETE has caused this Grant to be executed by its Chairman, President and Chief Executive Officer as of the date and year first above written.


ALLETE
                            
                            
By:
 
 
Chairman, President & CEO
    
Attachment: Annex A



ANNEX A
TO
ALLETE
EXECUTIVE LONG-TERM INCENTIVE COMPENSATION PLAN
RESTRICTED STOCK UNIT GRANT

The grant of restricted stock units (each, a “RSU”) under the ALLETE Executive Long-Term Incentive Compensation Plan (the “Plan”), evidenced by the Grant to which this is annexed, is subject to the following additional terms and conditions:

1.    Form and Timing of Payment. Subject to the provisions hereof, each RSU will be paid in the form of one share of ALLETE common stock (each, a “Share”), plus accrued Dividend Equivalents. Shares will be deposited into your ALLETE Invest Direct plan account. Except as otherwise provided in sections 3 and 4, below, payment will be made during the period ending sixty days after the end of the vesting period; provided, however, the Participant will not be permitted, directly or indirectly, to designate the taxable year of the distribution. Payment will be subject to withholding Shares equal in value to the minimum amount of tax required to be withheld by law.

2.    Dividend Equivalents. You will receive Dividend Equivalents in connection with the RSUs granted. Dividend Equivalents will be calculated and credited to you at the time the underlying RSUs are paid. Dividend Equivalents will be in the form of additional RSUs, which will be added to the number of RSUs subject to the grant, and will equal the number of Shares (including fractional Shares) that could have been purchased on applicable dividend payment dates, based on the closing ALLETE common stock price as reported in the consolidated transaction reporting system on that date, with cash dividends that would have been paid on the underlying RSUs, if such RSUs were Shares. Dividend Equivalents will only become payable if and to the extent the underlying RSUs vest and become payable.


3.    Payment Upon Retirement, Death or Disability; Forfeiture Upon Other Termination of Employment, Default on Certain Agreements or Unsatisfactory Job Performance.

3.1    Subject to Section 3.4 below, if during the vesting period you (i) Retire, (ii) die while employed by a Related Company, or (iii) become Disabled, a portion of the unvested RSUs subject to the Grant will vest and be paid to you (or your beneficiary or estate) during the period ending sixty days after such event; provided, however, you will not be permitted, directly or indirectly, to designate the taxable year of the distribution. Except as otherwise provided in Section 4, payment pursuant to this Section 3.1 will be prorated, after giving effect to accumulated Dividend Equivalents, based on the number of whole calendar months within the vesting period that had elapsed as of the date of Retirement, death or Disability in relation to the number of calendar months in the vesting period. For purposes of this calculation, you will be credited with a whole month if you were employed on the 15th of the month.

3.2     Except as otherwise provided in Section 4, if during the vesting period or prior to payment of all RSUs you have a Separation from Service for any reason other than those specified in Section 3.1 above, all unvested or unpaid RSUs subject to the Grant (and related Dividend Equivalents) will be forfeited on the date of such Separation from Service.




3.3    If during the vesting period or prior to payment of all RSUs you are demoted, you default on any written agreement with a Related Company related to a restrictive employment covenant (such as confidentiality, non-disclosure, non-competition, non-solicitation, or the like), or if ALLETE determines, in its sole discretion, that your job performance is unsatisfactory, ALLETE may cancel or amend your grant relating to any unpaid RSUs, resulting in the forfeiture of some portion or all of your unpaid RSUs (and related Dividend Equivalents).

3.4    Notwithstanding anything herein to the contrary, if you become entitled to a payment of the RSUs by reason of your Retirement and if you are a Specified Employee on the date of such Retirement, payment shall not be made until the earlier of: (i) the expiration of the six-month period beginning on the date of your Retirement, or (ii) the date of your death. The payment to which a Specified Employee would otherwise be entitled during this six-month period shall be paid, together with Dividend Equivalents that have accrued during this six-month delay, during the seventh month following the date of the Participant’s Retirement, or, if earlier, the date of the Participant’s death.

4.    Change in Control. Upon a Change in Control, unless the Committee provides otherwise prior to the Change in Control, outstanding unvested RSUs shall be prorated (as described below) and such prorated RSUs shall immediately vest and be payable to you during the period ending sixty days after the Change in Control. The RSUs will not be subject to proration and immediately vest, however, if and to the extent that the Grant is, in connection with the Change in Control, fully assumed by the successor corporation or parent thereof; in such case, the RSUs shall be prorated and immediately vest upon your termination of employment by the successor corporation for reasons other than cause within 18 months following the Change in Control and be payable to the Participant during the period ending sixty days after the termination of employment. Any payment on account of or in connection with a Change in Control will be prorated, after giving effect to the accumulation of Dividend Equivalents, based on the number of whole calendar months within the three-year vesting period that had elapsed as of the date of the Change in Control or termination of employment, as applicable, in relation to the number of calendar months in the three-year vesting period. For purposes of this calculation, you will be credited with a whole month if you were employed on the 15th of the month. In no event will you be permitted, directly or indirectly, to designate the taxable year of the distribution on account of or in connection with a Change in Control.

5.    Compensation Recovery Policy. The Grant is subject to the terms of any compensation recovery policy or policies established by ALLETE as may be amended from time to time (“Compensation Recovery Policy”). ALLETE hereby incorporates into the Grant the terms of the Compensation Recovery Policy.

2


6.     Section 409A Compliance. This Grant is intended to comply with Section 409A or an exemption thereunder, and, accordingly, to the maximum extent permitted, the Plan and the Grant shall be interpreted and administered in compliance therewith. Notwithstanding any other provision of the Grant, payments provided pursuant to the Grant may only be made upon an event and in a manner that complies with Section 409A or an applicable exemption. Any payments pursuant to the Grant that may be excluded from Section 409A as a short-term deferral shall be excluded from Section 409A to the maximum extent possible. To the extent that any provision of the Grant would cause a conflict with the requirements of Section 409A or would cause the administration of the Grant to fail to satisfy Section 409A, such provision shall be deemed null and void to the extent permitted by applicable law. Nothing herein shall be construed as a guarantee of any particular tax treatment. ALLETE makes no representation that the Grant complies with Section 409A and in no event shall ALLETE be liable for the payment of any taxes and penalties that you may incur under Section 409A.
7.     Claims Procedure and Arbitration. The Grant is subject to the following claims procedures:

7.1    Mandatory Claims Procedures. If you or any person acting on your behalf (the “Claimant”) has any claim or dispute related in any way to the Grant or to the Plan, the Claimant must follow these claims procedures. All claims must be brought no later than one year following the date on which the claim first arose and any claim not submitted within such time limit will be waived.

7.2    Claim Submission. Any claim must be made in writing to the Claims Administrator. The Claims Administrator, or its delegate, shall notify the Claimant of the resolution of the Claim within 90 days after receipt of the claim; provided, however, if the Claims Administrator determines that an extension is necessary, the 90-day period shall be extended to up to 180 days upon notice to that effect to the Claimant.

7.3    Notice of Denial. If a claim is wholly or partially denied, the denial notice shall contain (i) the reason or reasons for denial of the claim, and (ii) references to the pertinent Plan provisions upon which the denial is based. Unless the claim is submitted for arbitration as provided below and in the Plan, the Claims Administrator’s decision or action shall be final, conclusive and binding on all persons having any interest in the Plan.

7.4    Arbitration. If, after exhausting the procedures set forth above, a Claimant wishes to pursue legal action, any action by the Claimant with respect to a claim, must be resolved by arbitration in the manner described herein.

a)
Time Limits. A Claimant seeking arbitration of any determination by the Claims Administrator must, within six (6) months of the date of the Claims Administrator’s final decision, file a demand for arbitration with the American Arbitration Association submitting the Claim to resolution by arbitration. A Claimant waives any claim not filed timely in accordance with this Section.

b)
Rules Applicable to Arbitration. The arbitration process shall be conducted in accordance with the Commercial Law Rules of the American Arbitration Association.

c)
Venue. The arbitration shall be conducted in Minneapolis, Minnesota.


3


d)
Binding Effect. The decision of the arbitrator with respect to the claim will be final and binding upon the Company and the Claimant. BY PARTICIPATING IN THE PLAN, AND ACCEPTING THE GRANT, YOU, ON BEHALF OF YOURSELF AND ANY PERSON WITH A CLAIM RELATING TO YOUR GRANT, AGREE TO WAIVE ANY RIGHT TO SUE IN COURT OR TO PURSUE ANY OTHER LEGAL RIGHT OR REMEDY THAT MIGHT OTHERWISE BE AVAILABLE IN CONNECTION WITH THE RESOLUTION OF THE CLAIM.

e)
Enforceability. Judgment upon any award entered by an arbitrator may be entered in any court having jurisdiction over the parties.

f)
Waiver of Class, Collective, and Representative Actions.  Any claim shall be heard without consolidation of such claims with any other person or entity.  To the fullest extent permitted by law, whether in court or in arbitration, by participating in the Plan, you waive any right to commence, be a party to in any way, or be an actual or putative class member of any class, collective, or representative action arising out of or relating to any claim, and you agree that any claim may only be initiated or maintained and decided on an individual basis. 

g)
Standard of Review. Any decision of an arbitrator on a claim shall be limited to determining whether the Claims Administrator’s decision or action was arbitrary or capricious or was unlawful. The arbitrator shall adhere to and apply the deferential standard of review set out in Conkright v. Frommert, 130 S. Ct. 1640 (2010), Metropolitan Life Insurance Co. v. Glenn, 554 U.S. 105 (2008), and Firestone Tire and Rubber Company v. Bruch, 489 U.S. 101 (1989), and shall accord due deference to the determinations, interpretations, and construction of the Plan document by the Claim’s Administrator.

h)
General Procedures.


i.
Arbitration Rules. The arbitration hearing will be conducted under the AAA Commercial Arbitration Rules (as amended or revised from time to time by AAA) (hereinafter the “AAA Rules”), before one AAA arbitrator who is from the Large, Complex Case Panel and who has experience with matters involving executive compensation and equity compensation plans. The AAA Rules and the terms and procedures set forth here may conflict on certain issues. To the extent that the procedures set forth here conflict with the AAA Rules, the procedures set forth here shall control and be applied by the arbitrator. Notwithstanding the amount of the claim, the Procedures for Large, Complex Commercial Disputes shall not apply.

ii.
Substantive Law. The arbitrator shall apply the substantive law (and the laws of remedies, if applicable), of Minnesota or federal law, or both, depending upon the claim. Except to the extent required by applicable law, the Claimant shall keep any arbitration decision or award strictly confidential and not disclose to anyone other than his or her spouse, attorney, or tax advisor.


4


iii.
Authority. The arbitrator shall have jurisdiction to hear and rule on prehearing disputes and is authorized to hold prehearing conferences by telephone or in person as the arbitrator deems necessary. The arbitrator will have the authority to hear a motion to dismiss and/or a motion for summary judgment by any party and in doing so shall apply the standards governing such motions under the Federal Rules of Civil Procedure.

iv.
Pre-Hearing Procedures. Each party may take the deposition of not more than one individual and the expert witness, if any, designated by another party. Each party will have the right to subpoena witnesses in accordance with the Federal Arbitration Act, Title 9 of the United States Code. Additional discovery may be had only if the arbitrator so orders, upon a showing of substantial need.

v.
Fees and Costs. Administrative arbitration fees and arbitrator compensation shall be borne equally by the parties, and each party shall be responsible for its own attorney’s fees, if any; provided, however, that the Committee will authorize payment by the Company of all administrative arbitration fees, arbitrator compensation and attorney’s fees if the Committee concludes that a Claimant has substantially prevailed on his or her claims. Unless prohibited by statute, the arbitrator shall assess attorney’s fees against a party upon a showing that such party’s claim, defense or position is frivolous, or unreasonable, or factually groundless. If either party pursues a claim by any means other than those set forth in this Article, the responding party shall be entitled to dismissal of such action, and the recovery of all costs and attorney’s fees and losses related to such action, unless prohibited by statute.

i)
Interstate Commerce and the Federal Arbitration Act. The Company is involved in transactions involving interstate commerce, and the employee’s employment with the Company involves such commerce. Therefore, the Federal Arbitration Act, Title 9 of the United States Code, will govern the interpretation, enforcement, and all judicial proceedings regarding the arbitration procedures in this Section.


8.    Ratification of Actions. By receiving the Grant or other benefit under the Plan, you and each person claiming under or through you shall be conclusively deemed to have indicated your acceptance and ratification of, and consent to, any action taken under the Plan or the Grant by ALLETE, the Board, or the Committee.

9.     No Impact on Other Benefits. The Grant or payment on account thereof shall not be taken into account in determining any benefits under any severance, retirement, welfare, insurance or other benefit plan of ALLETE or any affiliate except to the extent otherwise expressly provided in writing in such other plan or an agreement thereunder.

10.    Notices. Any notice hereunder to ALLETE shall be addressed to ALLETE, 30 West Superior Street, Duluth, Minnesota 55802, Attention: Director - Compensation and Benefits, Human Resources, and any notice hereunder to you shall be directed to your address as indicated by ALLETE’s records, subject to the right of either party to designate at any time hereafter in writing some other address.


5


11.    Governing Law and Severability. To the extent not preempted by the Federal law, the Grant will be governed by and construed in accordance with the laws of the State of Minnesota, without regard to its conflicts of law provisions. In the event any provision of the Grant shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of the Grant, and the Grant shall be construed and enforced as if the illegal or invalid provision had not been included.

11.    Definitions. Capitalized terms not otherwise defined herein shall have the meanings given them in the Plan. The following definitions apply to the Grant and this Annex A:

11.1    Claims Administrator” means ALLETE’s Chief Executive Officer, unless the claimant is (or is acting on behalf of) an ALLETE executive officer (within the meaning of Exchange Act Rule 3b-7), in which case the Claims Administrator is the Executive Compensation Committee of the Board of Directors.    
11.2    Change in Control” means the earliest of:
(i)
the date any one Person, or more than one Person acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)), acquires ownership of stock of the Company that, together with stock previously held by the acquirer, constitutes more than fifty (50%) percent of the total fair market value or total voting power of Company stock. If any one Person, or more than one Person acting as a group, is considered to own more than fifty (50%) percent of the total fair market value or total voting power of Company stock, the acquisition of additional stock by the same Person or Persons acting as a group does not cause a Change in Control. An increase in the percentage of stock owned by any one Person, or Persons acting as a group, as a result of a transaction in which Company acquires its stock in exchange for property, is treated as an acquisition of stock;

(ii)
the date any one Person, or more than one Person acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)), acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by that Person or Persons) ownership of Company stock possessing at least thirty (30%) percent of the total voting power of Company stock;

(iii)
the date a majority of the members of the Company’s board of directors is replaced during any twelve (12) month period by directors whose appointment or election is not endorsed by a majority of the members of the board of directors prior to the date of appointment or election; or

(iv)
the date any one Person, or more than one Person acting as a group (as the term “group” is used in Treasury Regulations section 1.409A-3(i)(5)(v)(B)), acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by that Person or Persons) assets from the Company that have a total gross fair market value equal to at least forty (40%) percent of the total gross fair market value of all the Company’s assets immediately prior to the acquisition or acquisitions. For this purpose, “gross fair market value” means the value of the corporation’s assets, or the value of the assets being disposed of, without regard to any liabilities associated with these assets.


6


In determining whether a Change in Control occurs, the attribution rules of Code section 318 apply to determine stock ownership. The stock underlying a vested option is treated as owned by the individual who holds the vested option, and the stock underlying an unvested option is not treated as owned by the individual who holds the unvested option. The term “Person” used in this definition means any individual, corporation (including any non-profit corporation), general, limited or limited liability partnership, limited liability company, joint venture, estate, trust, firm, association, organization or other entity or any governmental or quasi-governmental authority, organization, agency or body.
11.3    Code” means the Internal Revenue Code of 1986, as it may be amended from time to time
11.4    Disability” or “Disabled” means a physical or mental condition in which the Participant is:
i.
unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months;

ii.
by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, receiving income replacement benefits for a period of not less than three (3) months under the Employer’s accident and health plan;

iii.
determined to be totally disabled by the Social Security Administration; or

iv.
disabled pursuant to an Employer-sponsored disability insurance arrangement provided that the definition of disability applied under such disability insurance program complies with the foregoing definition of Disability.

11.5    Related Company” means the ALLETE, Inc. and all persons with whom the ALLETE, Inc. would be considered a single employer under Code section 414(b) (employees of controlled group of corporations), and all persons with whom such person would be considered a single employer under Code section 414(c) (employees of partnerships, proprietorships, etc., under common control); provided that in applying Code sections 1563(a)(1), (2), and (3) for purposes of determining a controlled group of corporations under Code section 414(b), the language “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Code sections 1563(a)(1), (2), and (3), and in applying Treasury Regulations section 1.414(c)-2 for purposes of determining trades or businesses (whether or not incorporated) that are under common control for purposes of Code section 414(c), “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Treasury Regulations section 1.414(c)-2.

11.6    Retirement” or “Retires” means Separation from Service, for reasons other than death or Disability, on or after attaining normal retirement age or early retirement age as defined in the most applicable qualified retirement plan sponsored by the Related Company that employed the Participant immediately preceding the Separation from Service, without regard to whether the Participant is a participant in such plan, or if the employer Related Company does not sponsor such retirement plan, on or after attaining Normal Retirement Age or Early Retirement Age as defined in the ALLETE and Affiliated Companies Retirement Plan A, without regard to whether the Participant is a participant under the ALLETE and Affiliated Companies Retirement Plan A.

7


11.7    Section 409A means Section 409A of the Code and Treasury Regulations section 1.409A-1 et seq., as they both may be amended from time to time, or other guidance issued by the Treasury Department and Internal Revenue Service thereunder.

11.8    Separation from Service” means that the Participant terminates employment within the meaning of Treasury Regulations section 1.409A-1(h) and other applicable guidance with all Related Companies. Whether a termination of employment has occurred is determined under the facts and circumstances, and a termination of employment shall occur if all Related Companies and the Participant reasonably anticipate that no further services shall be performed after a certain date or that the level of bona fide services the Participant shall perform after such date (as an employee or an independent contractor) shall permanently decrease to no more than 20 percent of the average level of bona fide services performed (whether as an employee or an independent contractor) over the immediately preceding 36-month period (or the full period of services to the Related Companies if the Participant has been providing services to the Related Companies less than 36 months). A Participant shall not be considered to separate from service during a bona fide leave of absence for less than six (6) months or longer if the Participant retains a right to reemployment with any Related Company by contract or statute. With respect to disability leave, a Participant shall not be considered to separate from service for 29 months unless the Participant otherwise terminates employment or is terminated by all Related Companies.

11.9    Specified Employee” means an Participant who is subject to the six-month delay rule described in Code section 409A(2)(B)(i), determined in accordance with guidelines adopted by the Board from time to time as permitted by Section 409A of the Code and Treasury Regulations section 1.409A-1 et seq., as they both may be amended from time to time, and other guidance issued by the Treasury Department and Internal Revenue Service thereunder.



8
Exhibit 10(l)5 12-31-2014
Exhibit 10(l)5

ALLETE, INC.
Non-Employee Director Compensation
Effective January 1, 2015
    
             
Board Retainers (1) (2)
Stock
Cash

$73,000
$58,000
Committee Cash Retainers (1) (2)
Audit
Executive Compensation
Corporate Governance & Nominating

$9,000
$7,500
$7,500
Chair Cash Retainers (1) (2)
Audit
Executive Compensation
Corporate Governance & Nominating

$10,000
$7,500
$5,000

Lead Director (1) (2) (3)
Board Stock Retainer
Board Cash Retainer
Lead Director Cash Retainer

$73,000
$58,000
$25,000

Board Chairman (1) (2) (3)
Board Stock Retainer
Board Cash Retainer

$90,000
$85,000


(1) 
Cash and stock retainers may be deferred under the Director Compensation Deferral Plan II.
(2) 
Cash retainers may be elected to be received in ALLETE stock.
(3) 
Lead Director and Board Chairman are not eligible for other committee or chair retainers.



Exhibit 12 12-31-2014


Exhibit 12

ALLETE
Computation of Ratios of Earnings to Fixed Charges (Unaudited)

Year Ended December 31,
2014
2013
2012
2011
2010
Millions
 
 
 
 
 
Earnings are defined:
 
 
 
 
 
 
Pretax Income Before Non-Controlling Interest

$162.2


$133.3


$135.0


$129.2


$119.1

 
Add: Fixed Charges
62.5

56.7

51.2

47.6

43.4

 
Less: Non-Controlling Interest (a)
0.7





 
Undistributed Income from Less than 50 percent Owned Equity Investment
2.6

4.1

3.8

3.8

3.4

 
Earnings as defined:

$221.4


$185.9


$182.4


$173.0


$159.1

 
 
 
 
 
 
 
Fixed Charges:
 
 
 
 
 
 
Interest on Long-Term Debt

$55.6


$50.9


$47.0


$43.1


$39.7

 
Other Interest Charges
2.0

1.2

0.4

1.6

1.0

 
Interest Component of All Rentals (b)
4.9

4.6

3.8

2.9

2.7

 
Total Fixed Charges

$62.5


$56.7


$51.2


$47.6


$43.4

Ratio of Earnings to Fixed Charges
3.54

3.28

3.56

3.63

3.67

(a)
Pretax income of subsidiaries that have not incurred fixed charges.
(b)
Represents interest portion of rents estimated at 33 1/3 percent.


Exhibit 21 12-31-2014
Exhibit 21

SUBSIDIARIES OF THE REGISTRANT
(As of December 31, 2014)
(Reported Under Item 601 of Regulation S-K)
Name of Organization
State or Country
ALLETE, Inc. (d.b.a. ALLETE; Minnesota Power; Minnesota Power, Inc.;

Minnesota
Minnesota Power & Light Company; MPEX; MPEX A Division of Minnesota Power)

 
ALLETE Automotive Services, LLC

Minnesota
ALLETE Capital II

Delaware
ALLETE Capital III
Delaware
ALLETE Properties, LLC (d.b.a. ALLETE Properties)

Minnesota
ALLETE Commercial, LLC
Florida
Cape Coral Holdings, Inc.

Florida
Lake Swamp, LLC

Florida
Lehigh Acquisition, LLC

Delaware
Florida Landmark Communities, LLC
Florida
Lehigh Corporation

Florida
Mardem, LLC

Florida
Palm Coast Holdings, Inc.

Florida
Port Orange Holdings, LLC
Florida
Interlachen Lakes Estates, LLC
Florida
Palm Coast Land, LLC
Florida
Tomoka Holdings, LLC

Florida
ALLETE Water Services, Inc.

Minnesota
Florida Water Services Corporation

Florida
Energy Replacement Property, LLC

Minnesota
Energy Land, Incorporated
Wisconsin
Lakeview Financial Corporation I

Minnesota
Lakeview Financial Corporation II

Minnesota
ALLETE Enterprises, Inc.

Minnesota
ALLETE Clean Energy, Inc.
Minnesota
ACE Wind LLC
Delaware
ACE Mid-West Holdings, LLC
Delaware
MWW Holdings, LLC
Delaware
Lake Benton Power Associates LLC
Delaware
Lake Benton Holdings LLC
Delaware
Lake Benton Power Partners L.L.C.
Delaware
Storm Lake Power Partners I LLC
Delaware
Storm Lake Power Associates LLC
Delaware
Storm Lake II Holdings LLC
Delaware
Storm Lake Power Partners II LLC
Delaware
ACE West Holdings, LLC
Delaware
Condon Wind Power, LLC
Delaware
Thunder Spirit Wind, LLC
Delaware
ACE O&M, LLC
Delaware
ALLETE Renewable Resources, Inc.

North Dakota
BNI Coal, Ltd.

North Dakota
MP Affiliate Resources, Inc.

Minnesota
Rainy River Energy Corporation

Minnesota
Rainy River Energy Corporation - Wisconsin

Wisconsin
Upper Minnesota Properties, Inc.

Minnesota
Upper Minnesota Properties - Development, Inc.

Minnesota
MP Investments, Inc.

Delaware
RendField Land Company, Inc.

Minnesota
Superior Water, Light and Power Company

Wisconsin


Exhibit 23 12-31-2014
Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-188315, 333-190335) and Form S-8 (Nos. 333-91348, 333-183051, 333-162890, 333-190336) of ALLETE, Inc. of our report dated February 17, 2015, relating to the financial statements, financial statement schedule and the effectiveness of internal control over financial reporting, which appears in this Form 10‑K.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP
Minneapolis, Minnesota
February 17, 2015



Exhibit 31(a) 12-31-2014


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, certify that:

1.
I have reviewed this annual report on Form 10-K for the fiscal year ended December 31, 2014, of ALLETE, Inc.;

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:
February 17, 2015
/s/ Alan R. Hodnik
 
 
Alan R. Hodnik
 
 
President and Chief Executive Officer





Exhibit 31(b) 12-31-2014


Exhibit 31(b)


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, Steven Q. DeVinck, certify that:

1.
I have reviewed this annual report on Form 10-K for the fiscal year ended December 31, 2014, of ALLETE, Inc.;

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:
February 17, 2015
/s/ Steven Q. DeVinck
 
 
Steven Q. DeVinck
 
 
Senior Vice President and Chief Financial Officer



Exhibit 32 12-31-2014


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 Annual Report on Form 10-K of ALLETE for the fiscal year ended December 31, 2014, (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:
February 17, 2015
/s/ Alan R. Hodnik
 
 
Alan R. Hodnik
 
 
President and Chief Executive Officer

Date:
February 17, 2015
/s/ Steven Q. DeVinck
 
 
Steven Q. DeVinck
 
 
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.



Exhibit 95 12-31-2014


Exhibit 95

Mine Safety Disclosure

 
Mine or Operating Name/MSHA Identification Number
Section 104 S&S Citations (#)
Section 104(b) Orders (#)
Section 104(d) Citations and Orders (#)
Section 110(b)(2) Violations (#)
Section 107(a) Orders (#)
Total Dollar Value of MSHA Assessments Proposed ($)
Total Number of Mining- Related Fatalities (#)
Received Notice of Pattern of Violation Under Section 104(e) (yes/no)
Received Notice of Potential to Have Pattern Under Section 104(e) (yes/no)
Legal Actions Pending as of Last Day of Period (#)
Legal Actions Initiated During Period (#)
Legal Actions Resolved During Period (#)
 
 
 
Center Mine / 3200218
6
$11,849
No
No

For the year ended December 31, 2014, BNI Coal, owner of Center Mine, received six significant and substantial (S&S) citations under Section 104(a) of the Mine Safety Act. The total penalties assessed on BNI with respect to its citations were $2,174 and total penalties proposed were $9, 675. In 2013, BNI Coal had a S&S citation under Section 104(a) of the Mine and Safety Act for which the Mine Safety and Health Administration proposed a penalty of $52,500; a hearing case has been filed in relation to this penalty. For the year ended December 31, 2014, there were no citations, orders, violations or notices received under Sections 104(b), 104(d), 107(a), 104(e) or 110(b)(2) of the Mine Safety Act and there were no fatalities.



Exhibit 99 12-31-2014



 
Exhibit 99
For Release:
February 17, 2015
Investor Contact:
Tim Thorp
 
218-723-3953
 
tthorp@allete.com
 
 
 
NEWS
 
 
ALLETE earnings rise in 2014
Minnesota Power and ALLETE Clean Energy propel year-over-year earnings growth

Duluth, Minn. - ALLETE, Inc. (NYSE: ALE) today reported 2014 earnings of $2.90 per share on net income of $124.8 million versus $2.63 per share on net income of $104.7 million in 2013, an increase of ten percent. Included in 2014 results were $1.4 million, or three cents per share of costs related to an ALLETE Clean Energy acquisition, and a non-recurring $2.5 million, or six cents per share charge associated with an EPA settlement.
Operating revenue for the year grew by 12 percent to $1.14 billion, compared to $1.02 billion in 2013. Earnings for 2014 were diluted by 23 cents per share due to an increase in outstanding common stock.
“We’re happy to report another strong year of financial results,” said ALLETE Chairman, President and CEO Al Hodnik. “ALLETE’s net income grew by over 19 percent year-over-year and coincided with record capital expenditures for our company. With this positive earnings momentum and the growth initiatives we have in place, we begin 2015 very confident in ALLETE’s future.” Hodnik noted the company’s Board of Directors recently increased the dividend on its common stock.
Net income for the Regulated Operations segment, consisting of Minnesota Power, Superior Water, Light & Power and the company’s investment in the American Transmission Co., was $124.4 million during 2014 compared with $104.9 million a year ago. This year’s results were impacted by increased cost recovery revenue and production tax credits, as well as higher power marketing sales related to the commencement of the Square Butte resale agreement with Minnkota Power. Those increases were partially offset by higher operating and maintenance, depreciation, and interest expenses. Total regulated utility electricity sales rose by five percent in 2014 from 2013.
ALLETE’s Investments and Other segment recorded net income of $0.4 million in 2014 versus a $0.2 million net loss in 2013. Earnings from ALLETE Clean Energy were the primary contributor to the year-over-year increase. BNI Coal posted slightly higher earnings in 2014 and ALLETE Properties recorded a slightly smaller loss than in 2013. These increases were partially offset by increased corporate expenses. Last year’s results for this segment included gains on sales of investments.
ALLETE expects to earn between $3.00 and $3.20 per share in 2015 on net income of between $140 and $150 million, excluding costs associated with the recently announced acquisition of U.S. Water Services.
ALLETE will host a conference call and webcast at 10 a.m. Eastern Time this morning to discuss details of its quarterly financial performance. Interested parties may listen live by calling (877) 303-5852, or by accessing the webcast at www.allete.com. A replay of the call will be available through February 19, 2015 by calling (855) 859-2056, pass code 65605949.
ALLETE is predominantly a regulated utility through Minnesota Power, Superior Water, Light & Power and an investment in the American Transmission Company (ATC). Minnesota Power is well positioned for the future as it executes on its EnergyForward initiative and serves a potentially growing industrial customer base. ATC is poised for future growth both organically and through its partnership with Duke Energy. ALLETE's infrastructure and related services businesses include ALLETE Clean Energy, BNI Coal, and U.S. Water Services. ALLETE Clean Energy has a growing portfolio of wind generating facilities, and U.S. Water Services provides integrated water management to a growing base of industrial and commercial customers. More information about ALLETE is available at www.allete.com.
The statements contained in this release and statements that ALLETE may make orally in connection with this release that are not historical facts, are forward-looking statements. Actual results may differ materially from those projected in the forward-looking statements. These forward-looking statements involve risks and uncertainties and investors are directed to the risks discussed in documents filed by ALLETE with the Securities and Exchange Commission.





ALLETE's press releases and other communications may include certain non-Generally Accepted Accounting Principles (GAAP) financial measures. A "non-GAAP financial measure" is defined as a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP in the company's financial statements.

Non-GAAP financial measures utilized by the Company include presentations of earnings (loss) per share. ALLETE's management believes that these non-GAAP financial measures provide useful information to investors by removing the effect of variances in GAAP reported results of operations that are not indicative of changes in the fundamental earnings power of the Company's operations. Management believes that the presentation of the non-GAAP financial measures is appropriate and enables investors and analysts to more accurately compare the company's ongoing financial performance over the periods presented.






ALLETE, Inc.
Consolidated Statement of Income
For the Periods Ended December 31, 2014 and 2013
Millions Except Per Share Amounts
 
Quarter Ended
Year to Date
 
2014
2013
2014
2013
 
 
 
 
 
Operating Revenue
$290.7
$268.0
$1,136.8
$1,018.4
Operating Expenses
 
 
 
 
Fuel and Purchased Power
87.4
89.1
356.1
334.8
Operating and Maintenance
115.6
101.7
456.2
412.9
Depreciation
36.2
30.3
135.7
116.6
Total Operating Expenses
239.2
221.1
948.0
864.3
Operating Income
51.5
46.9
188.8
154.1
Other Income (Expense)
 
 
 
 
Interest Expense
(15.3)
(12.5)
(54.8)
(50.3)
Equity Earnings in ATC
4.0
5.2
19.6
20.3
Other
2.6
1.8
8.6
9.3
Total Other Expense
(8.7)
(5.5)
(26.6)
(20.7)
Income Before Income Taxes
42.8
41.4
162.2
133.4
Income Tax Expense
9.6
8.4
36.7
28.7
Net Income
33.2

33.0

125.5

104.7

Less: Non-Controlling Interest in Subsidiaries
0.3


0.7


Net Income Attributable to ALLETE

$32.9

$33.0
$124.8
$104.7
Average Shares of Common Stock
 
 
 
 
Basic
45.2

40.6

42.9

39.7

Diluted
45.4

40.7

43.1

39.8

Basic Earnings Per Share of Common Stock
$0.73
$0.82
$2.91
$2.64
Diluted Earnings Per Share of Common Stock
$0.73
$0.82
$2.90
$2.63
Dividends Per Share of Common Stock
$0.49
$0.475
$1.96
$1.90





Consolidated Balance Sheet
Millions
 
Dec. 31,
Dec. 31,
 
 
Dec. 31,
Dec. 31,
 
2014
2013
 
 
2014
2013
Assets
 
 
 
Liabilities and Shareholders' Equity
 
 
Cash and Cash Equivalents
$145.8
$97.3
 
Current Liabilities
$416.0
$230.2
Other Current Assets
273.0
209.7
 
Long-Term Debt
1,272.8
1,083.0
Property, Plant and Equipment - Net
3,286.4
2,576.5
 
Deferred Income Taxes
510.7
479.1
Regulatory Assets
357.3
263.8
 
Regulatory Liabilities
94.2
81.0
Investment in ATC
121.1
114.6
 
Defined Benefit Pension & Other Postretirement Benefit Plans
190.9
133.4
Other Investments
114.4
146.3
 
Other Non-Current Liabilities
265.0
127.2
Other Non-Current Assets
62.8
68.6
 
Shareholders' Equity
1,611.2
1,342.9
Total Assets
$4,360.8
$3,476.8
 
Total Liabilities and Shareholders' Equity
$4,360.8
$3,476.8





 
Quarter Ended
Year to Date
ALLETE, Inc.
December 31,
December 31,
Income (Loss)
2014
2013
2014
2013
Millions
 
 
 
 
Regulated Operations
$31.8
$31.9
$124.4
$104.9
Investments and Other
1.1
1.1
0.4
(0.2)
Net Income Attributable to ALLETE
$32.9
$33.0
$124.8
$104.7
Diluted Earnings Per Share
$0.73
$0.82
$2.90
$2.63

Statistical Data
 
 
 
 
Corporate
 
 
 
 
Common Stock
 
 
 
 
High
$57.97
$51.72
$57.97
$54.14
Low
$44.19
$47.48
$44.19
$41.39
Close
$55.14
$49.88
$55.14
$49.88
Book Value
$35.04
$32.43
$35.04
$32.43

Kilowatt-hours Sold
 
 
 
 
Millions
 
 
 
 
Regulated Utility
 
 
 
 
Retail and Municipals
 
 
 
 
Residential
313
313
1,204
1,177
Commercial
371
364
1,468
1,455
Municipals
221
258
864
999
Industrial
1,972
1,830
7,487
7,338
Total Retail and Municipal
2,877
2,765
11,023
10,969
Other Power Suppliers
822
530
2,904
2,278
Total Regulated Utility
3,699
3,295
13,927
13,247
Non-regulated Energy Operations
31
23
123
113
Total Kilowatt-hours Sold
3,730
3,318
14,050
13,360

Regulated Utility Revenue
 
 
 
 
Millions
 
 
 
 
Regulated Operations
 
 
 
 
Retail and Municipals
 
 
 
 
Residential

$32.2


$31.1


$124.6


$117.1

Commercial
33.9

32.2

134.8

128.1

Municipals
14.8

16.4

60.4

66.4

Industrial
118.1

108.0

455.7

425.9

Total Retail and Municipals
199.0

187.7

775.5

737.5

Other Power Suppliers
30.6

23.7

115.5

89.5

Other
24.3

30.5

112.5

98.5

Total Regulated Utility Revenue

$253.9


$241.9


$1,003.5


$925.5


This exhibit has been furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, except as shall be expressly set forth by specific reference in such filing.