ALLETE
ALLETE INC (Form: 10-K, Received: 02/17/2015 07:53:21)

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
CO 2
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
NO 2
Nitrogen Dioxide
NO X
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
SO 2
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 NO X 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 NO x 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 NO x and SO 2 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 (PM 2.5 ) 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 PM 2.5 standard, while retaining the current 24-hour PM 2.5 standard. To implement the new annual PM 2.5 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 PM 2.5 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.

SO 2 and NO 2 NAAQS. During 2010, the EPA finalized one-hour NAAQS for SO 2 and NO 2 . Ambient monitoring data indicates that Minnesota will likely be in compliance with these new standards; however, the one-hour SO 2 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 CO 2 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 CO 2 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 CO 2 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 CO 2 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 CO 2 -producing facility outside of Minnesota and prohibited the entry into new long-term power purchase agreements that would increase CO 2 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 CO 2 , 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 CO 2 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 Load Minnesota 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 SO 2 , 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