ALLETE
ALLETE INC (Form: 10-K, Received: 02/22/2016 17:14:07)

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, 2015
 
 
 
 
£
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, 2015 , was $2,256,186,129 .

As of February 1, 2016 , there were 49,111,849 shares of ALLETE Common Stock, without par value, outstanding.

Documents Incorporated By Reference
Portions of the Proxy Statement for the 2016 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.


ALLETE, Inc. 2015 Form 10-K
2


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


ALLETE, Inc. 2015 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
ALLETE Transmission Holdings
ALLETE Transmission Holdings (formerly Rainy River Energy Corporation - Wisconsin)
ArcelorMittal
ArcelorMittal USA, Inc.
ATC
American Transmission Company LLC
Basin
Basin Electric Power Cooperative
Bison
Bison Wind Energy Center
BNI Energy
BNI Coal, Ltd. d/b/a BNI Energy
Boswell
Boswell Energy Center
CO 2
Carbon Dioxide
Company
ALLETE, Inc. and its subsidiaries
CSAPR
Cross-State Air Pollution Rule
DC
Direct Current
EIS
Environmental Impact Statement
Enbridge
Enbridge, Inc.
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
IRP
Integrated Resource 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

ALLETE, Inc. 2015 Form 10-K
4


Definitions (continued)

Abbreviation or Acronym
Term
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.
Montana-Dakota Utilities
Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc.
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 and 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 Corp.
PPA
Power Purchase Agreement
PPACA
Patient Protection and Affordable Care Act of 2010
PSCW
Public Service Commission of 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
TransAlta
TransAlta Energy Marketing (U.S.) Inc.
U.S.
United States of America
U.S. Water Services
U.S. Water Services Holding Company and its subsidiaries
USS Corporation
United States Steel Corporation

ALLETE, Inc. 2015 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;
changes in and compliance with laws and regulations;
changes in tax rates or policies or in rates of inflation;
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;
changes in operating expenses and capital expenditures and our ability to raise revenues from our customers in regulated rates or sales price increases at our Energy Infrastructure and Related Services businesses;
the impacts of commodity prices on ALLETE and our customers;
our ability to attract 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;
population growth rates and demographic patterns;
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;
effects of competition, including competition for retail and wholesale customers;
effects of restructuring initiatives in the electric industry;
the impacts on our Regulated Operations segment of climate change and future regulation to restrict the emissions of greenhouse gases;
effects of increased deployment of distributed low-carbon electricity generation resources;
the impacts of laws and regulations related to renewable and distributed generation;
pricing, availability and transportation of fuel and other commodities and the ability to recover the costs of such commodities;
our current and potential industrial and municipal customers’ ability to execute announced expansion plans;
real estate market conditions where our legacy Florida real estate investment is located may not improve;
the success of efforts to realize value from, invest in, and develop new opportunities in, our Energy Infrastructure and Related Services businesses; and
factors affecting Energy Infrastructure and Related Services businesses, including fluctuations in the volume of customer orders, unanticipated cost increases, changes in legislation and regulations impacting the industries in which the customers served operate, the effects of weather, credit worthiness of customers, ability to obtain materials required to perform services, and changing market conditions.



ALLETE, Inc. 2015 Form 10-K
6


Forward Looking Statements (Continued)

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 25 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 it assess the impact of each of these factors on the businesses of ALLETE or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. Readers are urged to carefully review and consider the various disclosures made by ALLETE in this Form 10-K and in other reports filed with the SEC that attempt to identify the risks and uncertainties that may affect ALLETE’s business.



ALLETE, Inc. 2015 Form 10-K
7


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 145,000 retail customers. Minnesota Power also has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a wholesale customer of Minnesota Power. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 13,000 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 .

ALLETE Clean Energy was established in 2011, and focuses on developing, acquiring and operating clean and renewable energy projects. ALLETE Clean Energy currently owns and operates, in four states, approximately 535 MW of nameplate capacity wind energy generation that are under long-term power sales agreements. In addition, ALLETE Clean Energy constructed a 107 MW wind energy facility for sale to Montana-Dakota Utilities; construction and sale were completed in 2015.

U.S. Water Services is our integrated water management company which was acquired on February 10, 2015.

Corporate and Other is comprised of BNI Energy, our coal mining operations in North Dakota, ALLETE Properties, our legacy Florida real estate investment, 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 is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2015 , 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
2015

2014

2013

 
 
 
 
Consolidated Operating Revenue – Millions (a)

$1,486.4


$1,136.8


$1,018.4

 
 
 
 
Percentage of Consolidated Operating Revenue
 
 
 
Regulated Operations
67
%
88
%
91
%
ALLETE Clean Energy (a)(b)
18
%
3
%

U.S. Water Services (c)
8
%


Corporate and Other
7
%
9
%
9
%
 
100
%
100
%
100
%
(a)
Includes the construction and sale of a wind energy facility by ALLETE Clean Energy to Montana-Dakota Utilities for $197.7 million in 2015. (See Note 7. Acquisitions.)
(b)
Reflects operations acquired in conjunction with the ALLETE Clean Energy wind energy facilities acquisitions. (See Note 7. Acquisitions.)
(c)
U.S. Water Services was acquired on February 10, 2015. (See Note 7. Acquisitions.)

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.



ALLETE, Inc. 2015 Form 10-K
8


REGULATED OPERATIONS

Electric Sales / Customers
Regulated Utility Kilowatt-hours Sold
 
 
 
 
 
 
Year Ended December 31
2015

%
2014

%
2013

%
Millions
 
 
 
 
 
 
Retail and Municipal
 
 
 
 
 
 
Residential
1,113

8
1,204

9
1,177

9
Commercial
1,462

10
1,468

10
1,455

11
Industrial
6,635

46
7,487

54
7,338

55
Municipal
833

6
864

6
999

8
Total Retail and Municipal
10,043

70
11,023

79
10,969

83
Other Power Suppliers
4,310

30
2,904

21
2,278

17
Total Regulated Utility Kilowatt-hours Sold
14,353

100
13,927

100
13,247

100

Industrial Customers . In 2015 , industrial customers represented 46 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 Kilowatt-hours Sold
 
 
 
 
 
 
Year Ended December 31
2015

%
2014

%
2013

%
Millions
 
 
 
 
 
 
Taconite/Iron Concentrate
4,000

60
4,880

65
4,851

66
Paper, Pulp and Secondary Wood Products
1,456

22
1,499

20
1,505

21
Pipelines and Other Industrial
1,179

18
1,108

15
982

13
Total Industrial Customer Kilowatt-hours Sold
6,635

100
7,487

100
7,338

100

Eight 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 4,000 million kilowatt-hours, or 60 percent , of total industrial customer kilowatt-hour sales in 2015 . 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. Iron concentrate reclamation facilities also use large quantities of electricity to extract and process iron-bearing tailings left from previous mining operations to produce iron ore concentrate.

Minnesota Power provides electric service to five taconite customers capable of producing up to approximately 41 million tons of taconite pellets annually. Four of these customers are Large Power Customers (see Large Power Customer Contracts ). The fifth is Northshore Mining, owned and operated by Cliffs Natural Resources Inc., which self-generates a majority of its power, and is capable of producing approximately 6 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. Minnesota Power also provides electric service to three iron concentrate facilities capable of producing up to approximately 4 million 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 American Iron and Steel Institute (AISI), an association of North American steel producers, reported that U.S. raw steel production operated at approximately 71 percent of capacity in 2015 ( 77 percent in 2014 and in 2013 ). Many steel producers reduced production in 2015, citing higher levels of imports and lower prices. Some Minnesota taconite and iron concentrate producers reduced production in 2015 in response to declining U.S. steel production.

ALLETE, Inc. 2015 Form 10-K
9


REGULATED OPERATIONS (Continued)
Industrial Customers (Continued)

The following table reflects Minnesota Power’s taconite customers’ production levels for the past ten years.

Minnesota Power Taconite Customer Production
Year
 
Tons (Millions)
2015*
 
30
2014
 
39
2013
 
37
2012
 
39
2011
 
39
2010
 
35
2009
 
17
2008
 
39
2007
 
38
2006
 
39
Source: Minnesota Department of Revenue 2015 Mining Tax Guide for years 2006 - 2014.
* Preliminary data from the Minnesota Department of Revenue.


Minnesota Power’s 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 Minnesota Power’s taconite customers’ production would impact our annual earnings per share by approximately $0.03, net of expected power marketing sales at current 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 Minnesota Power to file a rate case to recover lost revenue.

In addition to serving the taconite industry, Minnesota Power serves a number of customers in the paper, pulp and secondary wood products industry, which represented 1,456 million kilowatt-hours, or 22 percent , of total industrial customer kilowatt-hour sales in 2015 . The four major paper and pulp mills we serve reported operating at, or near, full capacity in 2015. In September 2014, Boise, Inc. (Boise) provided the required one-year written notice of its intent to install additional generation at its International Falls, Minnesota, paper mill which was completed in 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 9 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), two concentrate reclamation facilities (both of which are owned by one company and are served under a single contract), 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.

ALLETE, Inc. 2015 Form 10-K
10


REGULATED OPERATIONS (Continued)
Large Power Customer Contracts (Continued)

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.

Contract Status for Minnesota Power Large Power Customers
As of February 1, 2016
Customer
Industry
Location
Ownership
Earliest
Termination Date
ArcelorMittal USA, Inc. – Minorca Mine (a)
Taconite
Virginia, MN
ArcelorMittal S.A.
December 31, 2025
Hibbing Taconite Co. (b)
Taconite
Hibbing, MN
62.3% ArcelorMittal S.A.
23.0% Cliffs Natural Resources Inc.
14.7% USS Corporation
January 31, 2020
United Taconite LLC (b)
Taconite
Eveleth, MN
Cliffs Natural Resources Inc.
January 31, 2020
USS Corporation
(USS – Minnesota Ore) (b)(c)
Taconite
Mt. Iron, MN and Keewatin, MN
USS Corporation
January 31, 2020
Boise, Inc.
Paper
International Falls, MN
Packaging Corporation of America
December 31, 2023
UPM, Blandin Paper Mill (b)
Paper
Grand Rapids, MN
UPM-Kymmene Corporation
January 31, 2020
NewPage Corporation  (d)
Paper and Pulp
Duluth, MN
Verso Corporation
December 31, 2022
Sappi Cloquet LLC (b)
Paper and Pulp
Cloquet, MN
Sappi Limited
January 31, 2020
Magnetation, LLC (e)
Iron Concentrate
Coleraine, MN and Bovey, MN
50.1% Magnetation, Inc.
49.9% AK Steel Corporation
December 31, 2025
(a)
In November 2015, Minnesota Power and ArcelorMittal USA, Inc. signed a new 10-year electric service agreement through December 31, 2025, which was approved by the MPUC in an order dated February 2, 2016.
(b)
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, 2020.
(c)
USS Corporation owns both the Minntac Plant in Mountain Iron, MN, and the Keewatin Taconite Plant in Keewatin, MN.
(d)
On January 7, 2015, Verso Corporation acquired NewPage Corporation. This acquisition does not impact Minnesota Power’s electric service agreement with NewPage Corporation. On January 26, 2016, Verso Corporation announced that it had filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code. (See Item 7. Management’s Discussion and Analysis – Outlook – Industrial Customers and Prospective Additional Load.)
(e)
On July 24, 2015, Minnesota Power filed a petition with the MPUC for approval of a new electric service agreement (Agreement) for service to both Magnetation’s Plant 2 and Plant 4 facilities, with a term through at least December 31, 2025. This Agreement was approved by the MPUC in an order dated February 2, 2016, and is subject to bankruptcy court approval. (See Item 7. Management’s Discussion and Analysis – Outlook – Industrial Customers and Prospective Additional Load.)

Residential and Commercial Customers. In 2015 , residential and commercial customers represented 18 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, 13,000 natural gas customers and 10,000 water customers.

ALLETE, Inc. 2015 Form 10-K
11


REGULATED OPERATIONS (Continued)

Municipal Customers. In 2015 , municipal customers represented 6 percent of total regulated utility kilowatt-hour sales. Minnesota Power has 16 non-affiliated municipal customers in Minnesota.

On April 21, 2015, Minnesota Power amended its formula-based wholesale electric sales contract with the Nashwauk Public Utilities Commission, extending the term through June 30, 2028. The electric service agreement with one other municipal customer is 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 Minnesota Power’s 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.

In September 2015, Minnesota Power amended its wholesale electric contracts with 14 municipal customers, extending the contract terms through December 31, 2024. These contracts include fixed capacity charges through 2018; beginning in 2019, the capacity charge will not increase by more than two percent or decrease by more than negative one percent from the previous year’s capacity charge and will be determined using a cost-based formula methodology. The base energy charge for each year of the contract term will be set each January 1, subject to monthly adjustment, and is also determined using a cost-based formula methodology.

All of the wholesale contracts include a termination clause requiring a three -year notice to terminate. In January 2016, one of Minnesota Power’s municipal customers provided notice of its intent to terminate its contract effective June 30, 2019. Minnesota Power currently provides approximately 29 MW of average monthly demand to this customer. Under the Nashwauk Public Utilities Commission agreement, no termination notice may be given prior to June 30, 2025. The remaining 14 municipal customers may not give termination notices prior to December 31, 2021.

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 Agreements. Minnesota Power has 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 the cost of fuel. The agreement allows Minnesota Power to recover a pro rata share of increased costs related to emissions that occur during the last five years of the contract. On July 9, 2015, Minnesota Power entered into an additional agreement to sell 100 MW of capacity only to Basin at fixed rates for a two-year period beginning in June 2016.

Minnkota Power Sales Agreement. Minnesota Power has 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 entitlement 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 . Of Minnesota Power’s 50 percent output entitlement, it sold to Minnkota Power approximately 28 percent in 2015 ( 23 percent in 2014). (See Note 12. Commitments, Guarantees and Contingencies.)

Seasonality

The operations of our industrial customers, which make up a large portion of our sales portfolio, are not typically subject to significant seasonal variations. (See Electric Sales / Customers. ) As a result, Minnesota Power is generally not subject to significant seasonal fluctuations in electric sales.

Power Supply

In order to meet its customers’ electric requirements, Minnesota Power utilizes a mix of its own generation and purchased power. At December 31, 2015 , Minnesota Power’s generation is primarily coal-fired, but also includes approximately 180 MW of natural gas-fired and biomass co-fired generation, 120 MW of hydroelectric generation, and 522 MW of nameplate capacity wind energy generation. Purchased power consists of long-term coal, wind and hydro PPAs as well as market purchases. The following table reflects Minnesota Power’s generating capabilities as of December 31, 2015 , and total electrical output for 2015 . Minnesota Power had an annual net peak load of 1,631  MW on January 4, 2015.


ALLETE, Inc. 2015 Form 10-K
12


REGULATED OPERATIONS (Continued)
Power Supply (Continued)
 
 
 
 
 
Year Ended
 
Unit
Year
Net
 
December 31, 2015
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
67

 
 
 
 
3
1973
364

 
 
 
 
4
1980
468

(a)
 
 
 
 
 
966

 
6,265,756

42.8
Laskin Energy Center in Hoyt Lakes, MN
1 & 2
1953

(b)
86,046

0.6
Taconite Harbor Energy Center
1
1957
77

 
 
 
in Schroeder, MN
2
1957
77

 
 
 
 
3
1967

(b)
 
 
 
 
 
154

 
1,051,950

7.2
Total Coal-Fired
 
 
1,120

 
7,403,752

50.6
Biomass/Coal/Natural Gas
 
 
 
 
 
 
Hibbard Renewable Energy Center in Duluth, MN
3 & 4
1949, 1951
63

 
973

Cloquet Energy Center in Cloquet, MN
5
2001
22

 
115,987

0.8
Laskin Energy Center in Hoyt Lakes, MN (b)
1 & 2
1953
95

 
3,282

Total Biomass/Coal/Natural Gas
 
 
180

 
120,242

0.8
Hydro (c)
 
 
 
 
 
 
Group consisting of ten stations in MN
Multiple
Multiple
120

 
424,119

2.9
Wind (d)
 
 
 
 
 
 
Taconite Ridge Energy Center in Mt. Iron, MN
Multiple
2008
25

 
67,415

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

 
1,539,600

10.5
Total Wind
 
 
522

 
1,607,015

11.0
Total Company Generation
 
 
1,942

 
9,555,128

65.3
 
 
 
 
 
 
 
Long-Term Purchased Power
 
 
 
 
 
 
Lignite Coal - Square Butte near Center, ND (e)
 
 
 
 
1,660,101

11.4
Wind - Oliver County, ND
 
 
 
 
334,836

2.3
Hydro - Manitoba Hydro in Manitoba, Canada
 
 
 
 
310,572

2.1
Total Long-Term Purchased Power
 
 


 
2,305,509

15.8
Other Purchased Power (f)
 
 
 
 
2,771,470

18.9
Total Purchased Power
 
 


 
5,076,979

34.7
Total
 
 
1,942

 
14,632,107

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)
Laskin Energy Center was converted from coal to natural gas in June 2015 and Taconite Harbor Unit 3 was retired in May 2015 as outlined in Minnesota Power’s 2013 IRP. Future plans for Taconite Harbor are included in Minnesota Power’s EnergyForward plan which includes the economic idling of Taconite Harbor Units 1 and 2 in the fall of 2016 and the ceasing of coal-fired operations at Taconite Harbor in 2020. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.)
(c)
Hydro consists of ten stations with 34 generating units and a total nameplate capacity of 120 MW. Thomson returned to full production in the fourth quarter of 2015.
(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.
(e)
Minnesota Power has 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 entitlement from Square Butte to Minnkota Power. (See Electric Sales / Customers.)
(f)
Includes short-term market purchases in the MISO market and from Other Power Suppliers.

ALLETE, Inc. 2015 Form 10-K
13


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 2015 for electric generation at Minnesota Power’s coal-fired generating stations was 4.4 million tons. As of December 31, 2015 , Minnesota Power had coal inventories of 1.6 million tons (1.0 million tons as of December 31, 2014 ). Minnesota Power’s coal supply agreements have expiration dates through 2016 for a significant portion of its coal requirements and 2019 for a portion of its coal requirements. In 2016 , 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 and believes that adequate supplies of low-sulfur, sub-bituminous coal will continue to be available.

On January 11, 2016, one of Minnesota Power’s coal suppliers, Arch Coal, Inc. (Arch Coal), announced that it had filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code and that it had reached an agreement with the majority of its senior lenders on the terms of a financial restructuring. The United States Bankruptcy Court for the Eastern District of Missouri authorized Arch Coal to enter into and perform under coal contracts in the ordinary course of business. 

Minnesota Power anticipates receiving its contracted fuel from Arch Coal in 2016 and beyond. In the event that circumstances would change, Minnesota Power purchases fuel for its power plants from four large coal producers and believes there are adequate supplies in the marketplace to procure fuel from alternative sources, should it be necessary. Additionally, Minnesota Power has approximately 1.6 million tons of coal inventories as of December 31, 2015 (4.4 million tons consumed in 2015).

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 2018. 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
2015

2014

2013

Average Price per Ton

$27.00


$26.52


$28.90

Average Price per MBtu

$1.49


$1.47


$1.60


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 Energy 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 2015 was approximately $1.55 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 energy 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 Minnesota Power only pays for energy as it is delivered.

Manitoba Hydro PPAs. Minnesota Power has five long-term PPAs with Manitoba Hydro. The first PPA 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. Under the second PPA, Minnesota Power is purchasing surplus energy through April 2022 . This energy-only agreement primarily consists of surplus hydro energy on Manitoba Hydro’s system that is delivered to Minnesota Power on a non-firm basis. The pricing is based on forward market prices. Under this agreement, Minnesota Power will purchase at least one million MWh of energy over the contract term.


ALLETE, Inc. 2015 Form 10-K
14


REGULATED OPERATIONS (Continued)
Long-Term Purchased Power (Continued)

In May 2011, Minnesota Power and Manitoba Hydro signed a third PPA. This 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. In September 2015, Manitoba Hydro submitted the final preferred route and EIS for the additional transmission capacity in Canada to the Manitoba Conservation and Water Stewardship for regulatory approval. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in 2014. (See Transmission and Distribution – Great Northern Transmission Line .) The capacity price is adjusted annually until 2020 by the change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed price component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices.

In July 2014, Minnesota Power and Manitoba Hydro signed a fourth PPA that provides for Minnesota Power to purchase up to 133  MW of energy from Manitoba Hydro for 20 years beginning in 2020. The pricing under this PPA is based on forward market prices. The PPA was approved by the MPUC in an order dated January 30, 2015, and is subject to the construction of the GNTL.

In October 2015, Minnesota Power and Manitoba Hydro signed a fifth PPA that provides for Minnesota Power to purchase 50  MW of capacity at fixed prices. The PPA begins in June 2017 and expires in May 2020.

Great River Energy PPAs. In August 2014, January 2015 and October 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, 50 MW of capacity only under the second PPA, and 50 MW of capacity only under the third PPA. The first and second PPAs begin in June 2016 and expire in May 2020, and the third PPA begins in June 2017 and expires in May 2020. All of these 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.

TransAlta PPAs. In September 2015, Minnesota Power and TransAlta signed PPAs that provide for Minnesota Power to purchase 50 MW of energy during off-peak hours and 100 MW of energy during on-peak hours beginning in January 2017 and expiring through December 2019. The energy prices are fixed throughout the terms of the PPAs.

Transmission and Distribution

We have electric transmission and distribution lines of 500 kV (8 miles), 345 kV (242 miles), 250 kV (465 miles), 230 kV (765 miles), 161 kV (43 miles), 138 kV (130 miles), 115 kV (1,268 miles) and less than 115 kV (6,295 miles). We own and operate 177 substations with a total capacity of 10,980 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.

On April 2, 2015, the CapX2020 transmission line project from Fargo, North Dakota, to St. Cloud, Minnesota, was completed and placed in service. Minnesota Power previously participated in two additional CapX2020 projects which were completed and placed in service in 2011 and 2012.

Minnesota Power invested approximately $100 million to complete the three transmission line projects. As future CapX2020 projects are identified, Minnesota Power may participate on a project-by-project basis.

Great Northern Transmission Line (GNTL). As a condition of the long-term PPA signed in May 2011 with Manitoba Hydro, construction of additional transmission capacity is required. As a result, Minnesota Power and Manitoba Hydro proposed construction of the GNTL, an approximately 220 -mile 500  kV transmission line between Manitoba and Minnesota’s Iron Range in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy.

ALLETE, Inc. 2015 Form 10-K
15


REGULATED OPERATIONS (Continued)
Transmission and Distribution (Continued)

The GNTL is subject to various federal and state regulatory approvals. In October 2013, a certificate of need application was filed with the MPUC which was approved in an order dated June 30, 2015. Based on this order, Minnesota Power’s portion of the investments and expenditures for the project are eligible for cost recovery under its existing transmission cost recovery rider and are anticipated to be included in future transmission factor filings. In an order dated December 17, 2015, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In April 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 a July 2014 order, the MPUC determined the route permit application to be complete. On October 30, 2015, the Minnesota Department of Commerce and the U.S. Department of Energy released the final EIS for the GNTL. On January 4, 2016, an administrative law judge recommended approval of the route permit for the GNTL. A final decision on the route permit by the MPUC is expected in the first quarter of 2016. Manitoba Hydro must also obtain regulatory and governmental approvals related to a new transmission line in Canada. In September 2015, Manitoba Hydro submitted the final preferred route and EIS for the transmission line in Canada to the Manitoba Conservation and Water Stewardship for regulatory approval. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in 2014. Upon receipt of all applicable permits and approvals, construction of the GNTL is expected to begin by 2017 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.

Investment in ATC

Our wholly-owned subsidiary, ALLETE Transmission Holdings, 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. We account for our investment in ATC under the equity method of accounting. As of December 31, 2015 , our equity investment in ATC was $124.5 million ( $121.1 million at December 31, 2014 ). (See Note 6. Investment in ATC.)

Our equity earnings in ATC for the year ended December 31, 2015 , were $16.3 million and reflected a $5.2 million reduction related to complaints filed with the FERC by several customer groups located within the MISO service area; of which $2.4 million was attributable to ATC’s change in estimate of a refund liability relating to prior years. The groups requested, 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 . On February 12, 2015, an additional complaint was filed with the FERC seeking an order to further reduce the base return on equity to 8.67 percent . On December 29, 2015, a federal administrative law judge ruled that the MISO transmission users have been charged an unreasonable base return on equity and proposed a reduction to 10.32 percent, subject to approval or adjustment by the FERC. A final decision from the FERC on the administrative law judge’s recommendation is currently expected in 2016. 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 ( $0.9 million pre-tax).

ATC’s 10-year transmission assessment, which covers the years 2015 through 2024, identifies a need for between $3.7 billion and $4.5 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.

ATC and Duke Energy Corporation are partners in a joint venture, Duke-American Transmission Co. (DATC) which builds, owns and operates electric transmission facilities in North America. DATC is subject to the rules and regulations of the FERC, various independent system operators and state regulatory authorities.

Properties

Our Regulated Operations businesses own office and service buildings, an energy control center, repair shops and storerooms in various localities. All of the electric plants are subject to mortgages, which collateralize the outstanding first mortgage bonds of Minnesota Power and SWL&P. Most of the generating plants and substations are located on real property owned by Minnesota Power or SWL&P, subject to the lien of a mortgage, whereas most of the 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.)


ALLETE, Inc. 2015 Form 10-K
16


REGULATED OPERATIONS (Continued)

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 Minnesota Power’s 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 our Regulated Operations’ 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.

Minnesota Public Utilities Commission.

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. Subsequent to this last order, and as authorized by the MPUC, Minnesota Power has increased revenue under cost recovery riders for environmental, renewable and transmission investments. (See Transmission Cost Recovery Rider, Renewable Cost Recovery Rider and Boswell Mercury Emissions Reduction Plan .) Revenue from cost recovery riders was $86.0 million in 2015 ( $69.9 million in 2014 and $40.5 million in 2013 ).

Energy-Intensive Trade-Exposed (EITE) Customer Rates. The Minnesota Legislature enacted EITE customer ratemaking legislation in June 2015. The legislation establishes that it is the energy policy of the state to have competitive rates for certain industries such as mining and forest products. On November 13, 2015, Minnesota Power filed a rate schedule for EITE customers and a corresponding rider for EITE cost recovery with the MPUC. The rate proposal is revenue, and cash flow, neutral. On February 11, 2016, the MPUC dismissed the petition without prejudice, offering Minnesota Power the option to refile the petition with additional information or initiate a new petition. Minnesota Power is evaluating the MPUC’s decision.

Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. In an order dated February 3, 2016, 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. As a result of the MPUC approval of the certificate of need for the GNTL on June 30, 2015, the project is eligible for cost recovery under the existing transmission cost recovery rider. Minnesota Power anticipates including its portion of the investments and expenditures for the GNTL in future transmission factor filings to include updated billing rates on customer bills. (See Transmission and Distribution – Great Northern Transmission Line. )

Renewable Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for investments and expenditures related to the 497 MW Bison Wind Energy Center in North Dakota. Customer billing rates for the Bison Wind Energy Center were approved by the MPUC in an order dated May 22, 2015. In November 2014, Minnesota Power filed a renewable resources factor filing which includes updated costs associated with Bison. Upon approval of the filing, Minnesota Power will be authorized to include updated billing rates on customer bills.

On February 13, 2015, Minnesota Power supplemented its November 2014 renewable resources factor filing to include costs associated with the restoration and repair of Thomson. In an order dated March 5, 2015, the MPUC approved Minnesota Power’s petition seeking cost recovery for investments and expenditures related to the restoration and repair of Thomson through a renewable resources rider.

Annual Automatic Adjustment (AAA) of Charges. Minnesota Power’s AAA filings made in 2012, 2013, 2014 and 2015 are pending MPUC approval, and represent approximately $700 million in retail fuel cost recovery collected but subject to refund. These filings have historically been approved, and Minnesota Power currently expects full recovery of amounts represented by each AAA filing, although we cannot predict the outcome of the filings at the MPUC.

ALLETE, Inc. 2015 Form 10-K
17


REGULATED OPERATIONS (Continued)
Regulatory Matters (Continued)

Integrated Resource Plan (IRP). In a November 2013 order, the MPUC approved Minnesota Power’s 2013 IRP which detailed its EnergyForward strategic plan, announced in January 2013. Significant elements of the EnergyForward plan include major wind investments in North Dakota which were completed in the fourth quarter of 2014, the installation of emissions control technology at Boswell Unit 4 completed in December 2015, planning for the proposed GNTL, the conversion of Laskin from coal to natural gas completed in June 2015 and the retirement of Taconite Harbor Unit 3 completed in May 2015. On September 1, 2015, Minnesota Power filed its 2015 IRP with the MPUC which contains the next steps in its 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. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.)

Boswell Mercury Emissions Reduction Plan. In August 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA in order to comply with the Minnesota Mercury Emissions Reduction Act and the Federal MATS rule. Construction on the project to implement the Boswell Unit 4 mercury emissions reduction plan was completed with project costs totaling approximately $220 million through December 31, 2015 . In a November 2013 order, the MPUC approved the Boswell Unit 4 mercury emissions reduction plan and cost recovery, establishing an environmental improvement rider. Customer billing rates for the environmental improvement rider were approved by the MPUC in an order dated August 24, 2015. On September 30, 2015, Minnesota Power filed an updated environmental improvement factor filing which included updated costs associated with Boswell Unit 4. Upon approval of the filing, Minnesota Power will be authorized to include updated billing rates on customer bills.

Boswell Remaining Life Petition. On November 17, 2015, Minnesota Power filed a petition with the MPUC for approval to extend Boswell’s remaining life to 2050 for all units and utilize the existing environmental improvement rider to credit a portion of the depreciation expense savings to customers. The extension request is based on the significant multi-emissions retrofit work done at Boswell Unit 3 and Boswell Unit 4.

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 Power refers to its conservation programs collectively 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 $7.1 million for 2015 ( $6.9 million for 2014; $6.0 million for 2013), with actual spending of $6.6 million in 2015 ( $7.2 million in 2014; $6.4 million in 2013). The investment goal for 2016 is $7.3 million .

Minnesota requires each utility to establish an annual energy-savings goal of 1.5 percent of annual retail energy sales. On April 1, 2015, Minnesota Power submitted its 2014 CIP filing that requested a CIP financial incentive of $6.2 million . The requested CIP financial incentive was approved by the MPUC in an order dated September 16, 2015, and was recorded as revenue and as a regulatory asset. The approved financial incentive will be recovered through customer billing rates in 2015 and 2016. In 2014 and 2013, the CIP financial incentive recognized was $8.7 million and $7.1 million , respectively. CIP financial incentives are recognized in the period in which the MPUC approves the filing. The MPUC implemented certain limitations on amounts recoverable for the utility performance incentive program for recovery years beginning in 2015.

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 Minnesota Power’s municipal and wholesale 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.


ALLETE, Inc. 2015 Form 10-K
18


REGULATED OPERATIONS (Continued)
Regulatory Matters (Continued)

MISO Return on Equity Complaints. In November 2013, several customer groups located within the MISO service area filed complaints with the FERC requesting, among other things, a reduction in the base return on equity used by MISO transmission owners, including ALLETE, to 9.15 percent . On February 12, 2015, an additional complaint was filed with the FERC seeking an order to further reduce the base return on equity to 8.67 percent . On December 29, 2015, a federal administrative law judge ruled that the MISO transmission users have been charged an unreasonable base return on equity and proposed a reduction to 10.32 percent, subject to approval or adjustment by the FERC. A final decision from the FERC on the administrative law judge’s recommendation is expected in 2016. As a result of these complaints filed with the FERC and the administrative law judge’s recommendation , Minnesota Power has recorded an estimated refund obligation for MISO revenue of $7.2 million and an estimated refund for MISO transmission expense of $4.5 million , resulting in a reserve of $2.7 million as of December 31, 2015 ; $1.5 million was attributable to prior years.

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 oversee the safe, cost-effective delivery of electric power across all or parts of 15 states and the Canadian province of Manitoba which includes nearly 175,000 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 electric utilities’ applicable 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’s 2015 IRP, which was filed with the MPUC on September 1, 2015, includes an update on its plans and progress in meeting the Minnesota renewable energy milestones through 2025. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.)

ALLETE, Inc. 2015 Form 10-K
19


REGULATED OPERATIONS (Continued)
Minnesota Legislation (Continued)

Minnesota Power continues to execute its renewable energy strategy through key renewable projects that will ensure it meets the identified state mandate at the lowest cost for customers. Minnesota Power has exceeded the interim milestone requirements to date with approximately 27 percent of its applicable retail and municipal energy sales 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 has two solar projects under development. On August 21, 2015, Minnesota Power filed for MPUC approval of a 10 MW utility scale solar project at Camp Ripley, a Minnesota Army National Guard base and training facility near Little Falls, Minnesota. At a hearing on January 28, 2016, the MPUC approved the Camp Ripley solar project as eligible to meet the solar energy standard and for current cost recovery, subject to certain compliance requirements. On September 10, 2015, Minnesota Power filed for MPUC approval of a 1 MW community solar garden project in Saint Louis County, Minnesota. If the community solar garden project is also approved, Minnesota Power believes these projects will meet approximately one-third of the overall mandate and approximately one-fourth of the mandate related to solar photovoltaic devices with a nameplate capacity of 20 kilowatts or less. Costs associated with these projects are expected to be recovered from customers.

Energy-Intensive Trade-Exposed (EITE) Customer Rates. The Minnesota Legislature enacted EITE customer ratemaking legislation in June 2015. The legislation establishes that it is the energy policy of the state to have competitive rates for certain industries such as mining and forest products. On November 13, 2015, Minnesota Power filed a rate schedule for EITE customers and a corresponding rider for EITE cost recovery with the MPUC. The rate proposal is revenue, and cash flow, neutral. On February 11, 2016, the MPUC dismissed the petition without prejudice, offering Minnesota Power the option to refile the petition with additional information or initiate a new petition. Minnesota Power is evaluating the MPUC’s decision.

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 are 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 sought 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, 2015 , 6 percent of our Regulated Operations’ electric energy sales were to municipal customers in Minnesota by contract. These customers have the right to seek an energy supply from any wholesale electric service provider upon contract expiration. In April 2015, Minnesota Power amended its formula-based wholesale electric sales contract with the Nashwauk Public Utilities Commission, extending the term through June 30, 2028. In September 2015, Minnesota Power amended its wholesale electric contracts with 14 of its municipal customers, extending the contract terms through December 31, 2024. In January 2016, one of Minnesota Power’s municipal customers provided notice of its intent to terminate its contract effective June 30, 2019. Minnesota Power currently provides approximately 29 MW of average monthly demand to this customer. (See Electric Sales / Customers. )

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 Minnesota Power do not require a franchise to operate. SWL&P serves customers under electric, natural gas and/or water franchises in 1 city and 14 villages or towns.


ALLETE, Inc. 2015 Form 10-K
20


ENERGY INFRASTRUCTURE AND RELATED SERVICES

ALLETE Clean Energy

ALLETE Clean Energy was established in 2011, and focuses on developing, acquiring and operating clean and renewable energy projects. ALLETE Clean Energy currently owns and operates approximately, in four states, 535 MW of nameplate capacity wind energy generation that are under long-term power sales agreements. In addition, ALLETE Clean Energy constructed a 107 MW wind energy facility for sale to Montana-Dakota Utilities; construction and sale were completed in 2015.
Wind Energy Facility
Location
Capacity MW
PPA MW
PPA Expiration
Armenia Mountain
Pennsylvania
100.5
100%
2024
Chanarambie/Viking
Minnesota
97.5
 
 
PPA 1
 
 
12%
2018
PPA 2
 
 
88%
2023
Condon
Oregon
50
100%
2022
Lake Benton
Minnesota
104
100%
2028
Storm Lake I
Iowa
108
100%
2019
Storm Lake II
Iowa
77
 
 
PPA 1
 
 
90%
2019
PPA 2
 
 
10%
2032

U.S. Water Services

On February 10, 2015, ALLETE acquired U.S. Water Services. Headquartered in St. Michael, Minnesota, U.S. Water Services provides integrated water management for industry by combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage and improve efficiency. U.S. Water Services is located in 49 states and Canada and has an established base of approximately 4,000 customers. U.S. Water Services differentiates itself from the competition by developing synergies between established solutions in engineering, equipment, and chemical water treatment and helping customers achieve efficient and sustainable use of their water and energy systems. U.S. Water Services is a leading provider to the biofuels industry, and also serves the food and beverage, industrial, power generation, and midstream oil and gas industries. U.S. Water Services principally relies upon recurring revenue from a diverse mix of industrial customers.

CORPORATE AND OTHER

Corporate and Other is comprised of BNI Energy, our coal mining operations in North Dakota, ALLETE Properties, our legacy Florida real estate investment, 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. (See Outlook.)

BNI Energy

BNI Energy is a supplier of lignite in North Dakota, producing approximately 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 Energy’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, 2015 , BNI Energy had a $22.1 million asset reclamation obligation ($20.3 million at December 31, 2014 ) 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, Inc. 2015 Form 10-K
21


CORPORATE AND OTHER (Continued)

ALLETE Properties

ALLETE Properties represents our legacy Florida real estate investment. Our strategy for ALLETE Properties has been to complete and maintain key entitlements and infrastructure improvements without requiring significant additional investment, and sell assets in the portfolio over time in order to optimize cash flows in support of future investment opportunities and growth initiatives.

In recent years, market conditions for real estate in Florida have required us to review our land inventories for impairment. In response to market conditions and recent transaction activity, during the fourth quarter of 2015 the Company reevaluated its strategy related to the real estate assets of ALLETE Properties. The revised strategy incorporates the possibility of a bulk sale of its entire portfolio which, if consummated, is likely to result in sales proceeds below the book value of the real estate assets. ALLETE also continues to pursue sales of individual parcels over time. Proceeds from such a sale would be strategically deployed to support growth in our energy infrastructure and related services businesses. ALLETE will continue to maintain key entitlements and infrastructure without making additional investments or acquisitions.

In connection with implementing the revised strategy in 2015, management evaluated its impairment analysis for its real estate assets using updated assumptions to determine estimated future net cash flows on an undiscounted basis. Future net cash flows were adjusted to consider the possibility of a bulk sale of its entire portfolio, in addition to sales over time under the existing divestiture plan. Estimated fair values were based upon current market data and pricing for individual parcels. Our impairment analysis incorporates a probability-weighted approach considering the alternative courses of sales noted above.

Based on the results of undiscounted cash flow analysis, the undiscounted future net cash flows were not adequate to recover the carrying value of the real estate assets totaling $83.3 million. Estimated fair value was derived from current market interest in the property for a bulk sale of its entire portfolio, and discounted cash flow analysis of estimated selling price for sales over time. As a result, a non-cash impairment charge of $36.3 million was recorded in 2015 to reduce the carrying value of the real estate to its estimated fair value at December 31, 2015.

If our real estate assets are sold differently than anticipated, the actual results could be materially different from our undiscounted future net cash flow analysis.

In 2014 and 2013, impairment analyses of estimated undiscounted future net cash flows were conducted based on the strategy existing at that time, and indicated that the cash flows were adequate to recover the carrying value of ALLETE Properties real estate assets. As a result, no impairment was recorded for the years ended December 31, 2014 and 2013.

ALLETE Properties’ major projects are Town Center, Palm Coast Park and Ormond Crossings. 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, 2015 , outstanding finance receivables were $1.6 million , net of reserves, with maturities through 2017 . 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. 2015 Form 10-K
22


CORPORATE AND OTHER (Continued)

Non-Rate Base Generation

As of December 31, 2015 , non-rate base generation   consists of 29 MW of generation at Rapids Energy Center. In 2015 , we sold 0.1 million MWh of non-rate base generation (0.1 million MWh in 2014 and in 2013 ).
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
27
Hydro
4 & 5
1917, 1948
2000
2
(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 or have already been promulgated by both the EPA and state authorities. Minnesota Power’s facilities are subject to additional regulation under many of these proposals. In preparation and response to these regulations, Minnesota Power is reshaping its generation portfolio over time to reduce its reliance on coal, has installed cost-effective emission control technology, and advocates for sound science and policy during rulemaking implementation.

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. We anticipate that although many of the state and federal environmental regulations have been finalized, or will be finalized in the near future, potential expenditures for future environmental matters may be material and may 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. (See Note 12. Commitments, Guarantees and Contingencies.)


EMPLOYEES

At December 31, 2015 , ALLETE had 1,945 employees, of which 1,923 were full-time.

Minnesota Power and SWL&P have an aggregate of 554 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 Energy has 173 employees, of which 127 are members of IBEW Local 1593. The current labor agreement with IBEW Local 1593 expires on March 31, 2019.



ALLETE, Inc. 2015 Form 10-K
23


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.


EXECUTIVE OFFICERS OF THE REGISTRANT

As of February 22, 2016 , these are the executive officers of ALLETE:
Executive Officers
Initial Effective Date
 
 
Alan R. Hodnik, Age 56
 
Chairman, President and Chief Executive Officer
May 10, 2011
President and Chief Executive Officer
May 1, 2010
 
 
Robert J. Adams, Age 53
 
Senior Vice President – Energy-Centric Businesses and Chief Risk Officer
November 14, 2015
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 50
 
Senior Vice President, General Counsel and Secretary
January 1, 2006
 
 
Patrick L. Cutshall, Age 51
 
Treasurer
January 1, 2016
 
 
Steven Q. DeVinck, Age 56
 
Senior Vice President and Chief Financial Officer
March 3, 2014
Controller and Vice President – Business Support
December 5, 2009
 
 
David J. McMillan, Age 54
 
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 54
 
Controller
March 3, 2014
 
 

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, the following executives held other positions with the Company during the past five years.

Mr. Morris was Director - Accounting.
Mr. Cutshall was Director - Investments and Tax; Director - Investments.

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 10, 2016.



ALLETE, Inc. 2015 Form 10-K
24


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.

Entity-wide Risks

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 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 adversely affected. Market disruptions or a downgrade of our credit ratings may increase the cost of borrowing or 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.

A deterioration in general economic conditions may have adverse impacts on our financial position, results of operations and cash flows.

If economic conditions deteriorate on a national or regional level, it may have a negative impact on the Company and our customers. This impact may include volatility and unpredictability in the demand for the products and services offered by our businesses, the loss of existing customers, tempered growth strategies, production cutbacks, or bankruptcies. It is also possible that an uncertain economy could affect expenses including pension costs, interest costs, and uncollectible accounts, or lead to reductions in the value of certain real estate and other investments.

We may be impacted by new state or federal legislation, or regulations, and compliance could have an adverse effect on our businesses.

We are subject to, and affected by, extensive state and federal legislation and regulation. We believe that our businesses comply with applicable laws and regulations. If it were determined that they failed to comply, we could become subject to fines or penalties or be required to implement additional compliance measures or actions, the cost of which could be material. Adoption of new laws, rules, regulations, principles, or practices by federal or state agencies, or changes to present laws, rules, regulations, principles, or practices and their interpretations, could have an adverse effect on our financial position, results of operations and cash flows.

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 an 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.

ALLETE, Inc. 2015 Form 10-K
25


Item 1A. Risk Factors (Continued)
Entity-wide Risks (Continued)

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 impacts 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 or through our cost-plus fixed fee coal supply agreements at BNI Energy. However, there is no certainty that regulators will continue to allow recovery of these rising costs in the future.

We are exposed to significant reputation risk.

The Company and its subsidiaries could suffer negative impacts to their reputations as a result of operational incidents, violations of corporate compliance policies, regulatory violations, or other events which may result in negative customer perception and increased regulatory oversight, each of which could have an adverse effect on our financial position, results of operations and cash flows.

Catastrophic events, such as acts of war and natural disasters, may adversely affect our operations.

Catastrophic events such as fires, earthquakes, explosions, floods, ice storms, tornadoes, or similar occurrences could adversely affect the Company’s facilities, operations, financial position, results of operations and cash flows. Although the Company has contingency plans and employs crisis management to respond and recover operations in the event of a severe disruption resulting from such events, these measures may not be successful. Furthermore, despite these measures, if such an occurrence were to occur, our financial position, results of operations and cash flows could be adversely affected.

We are vulnerable to acts of terrorism or cybersecurity attacks.

Our operations may be targets of terrorist activities, including cybersecurity attacks, which could disrupt our ability to produce or distribute some portion of our products. We could be subject to computer viruses, terrorism, theft and sabotage, which may also disrupt our operations and/or adversely impact our results of operations. Our businesses require 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 an adverse effect on our financial position, results of operations and cash flows.

Government challenges to our tax positions, as well as tax law changes and the inherent difficulty in quantifying potential tax effects of business decisions, could adversely affect our results of operations and liquidity.

We are required to make judgments in order to estimate tax obligations. These judgments include reserves for potential adverse outcomes for tax positions that may be challenged by tax authorities. The obligations, which include income taxes and taxes other than income taxes, involved complex matters that ultimately could be litigated. We also estimate our ability to use tax benefits, including those in the form of carryforwards and tax credits that are recorded as deferred tax assets on our Consolidated Balance Sheet. A disallowance of these tax benefits could have an adverse impact on our financial position, results of operations and cash flows.

We plan to utilize our carryforwards and tax credits in the future to reduce our income tax obligations. If we cannot generate enough taxable income in the future to utilize all of our carryforwards and tax credits before they expire, we may incur adverse charges to earnings. If the Internal Revenue Service disagrees with the deductions resulting from our tax planning strategies, our financial position, results of operations and cash flows may be adversely impacted.

ALLETE, Inc. 2015 Form 10-K
26


Item 1A. Risk Factors (Continued)

Regulated Operations Risks

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, experience decreased demand, or experience a decline in prices for their product.

Minnesota Power’s 9 Large Power Customers accounted for 22 percent of our 2015 consolidated operating revenue ( 31 percent in 2014 ; 31 percent in 2013 ), of which one of these customers accounted for 7.7 percent of consolidated revenue in 2015 (11.9 percent in 2014 ; 12.0 percent in 2013 ). 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. Additionally, 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, experience decreased demand or experience a decline in prices for their product, there could be 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 adoption of new regulations could have an 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 an 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. 2015 Form 10-K
27


Item 1A. Risk Factors (Continued)
Regulated Operations Risks (Continued)

Our operations pose certain environmental risks that could 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 expenditures, 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 energy 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 an 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.

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 an 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 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 an adverse 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 2014, the EPA announced a proposed rule under Section 111(d) of the Clean Air Act for existing power plants (CPP). In 2015, the EPA issued the CPP, together with a proposed federal implementation plan and a model rule for emissions trading. The CPP establishes uniform CO 2 emission performance rates for existing fossil fuel-fired and natural gas-fired combined cycle generating units, setting state-specific goals for CO 2 emissions from the power sector. State goals under the CPP include interim goals to be met over the years 2022 through 2029, as well as a final goal to be met in 2030 and thereafter. Under the CPP, each state is required to develop a state implementation plan by September 6, 2016, or by September 6, 2018, if granted an extension. The implementation of the CPP could have an adverse 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 2015, coal was the primary fuel source for 77 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 adversely affect our results of operations, particularly if implementation costs are not fully recoverable from customers.

ALLETE, Inc. 2015 Form 10-K
28


Item 1A. Risk Factors (Continued)
Regulated Operations Risks (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.

The operation and maintenance of our electric generation and transmission facilities are subject to operational risks that could 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, 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 expect to incur significant capital expenditures in making capital improvements to our existing electric generation facilities and in the development and/or construction of new 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 an 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, as well as 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 an adverse impact on our business, operations and results of operations.

Our results of operations could be impacted by declining wholesale power prices.

Wholesale prices for electricity have declined in recent years primarily due to low natural gas prices. If there are reductions in demand from customers or if we lose customers, we will market any available power to Other Power Suppliers in an effort to mitigate any earnings impact. Sales to Other Power Suppliers are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements in various durations. Due to the low wholesale prices for electricity, we can make no assurances that our power marketing efforts would fully offset any reduction in earnings resulting from the lower demand from existing customers or the loss of customers.

ALLETE, Inc. 2015 Form 10-K
29


Item 1A. Risk Factors (Continued)
Regulated Operations Risks (Continued)

The price of electricity and fuel may be volatile.

Volatility in market prices for electricity and fuel could 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.

Fluctuations in our fuel and purchased power costs related to our retail and municipal customers are passed on to customers through the fuel adjustment clause. Volatility in market prices for our fuel and purchase power costs primarily impacts our sales to Other Power Suppliers.

Demand for energy may decrease.

Our results of operations are impacted by the demand for energy in our service territories. There could be lower demand for energy due to a loss of customers as a result of economic conditions, customers constructing their own generation facilities, higher costs and rates charged to customers, or loss of service territory or franchises. Further, the energy conservation and technological advances that increase energy efficiency may temporarily or permanently reduce the demand for energy products. In addition, there are state and federal regulations requiring mandatory conservation measures, which would reduce the demand for energy. Continuing technology improvements and regulatory developments may make customer and third party-owned generation technologies such as rooftop solar systems, wind turbines, microturbines and battery storage systems more cost effective and feasible for more of our customers. If more customers utilize their own generation, demand for energy from us would decline. There may not be future economic growth opportunities that would enable us to replace the lost energy demand from these customers. Therefore a decrease in demand for energy could adversely impact our financial position, results of operations and cash flows.

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 territories. Currently, there are several companies in our service territories that are in the process of developing natural resource-based projects that represent long-term growth potential and load diversity for our Regulated Operations businesses. 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 or if these customers are unable to successfully implement expansion plans, our long-term strategy and thus our results of operations could be adversely impacted.


ALLETE, Inc. 2015 Form 10-K
30


Item 1A. Risk Factors (Continued)

Energy Infrastructure and Related Services Risks

The generation of electricity from ALLETE Clean Energy’s wind energy facilities depends heavily on suitable meteorological conditions.

ALLETE Clean Energy’s facilities are geographically diverse; however, if wind conditions are unfavorable, ALLETE Clean Energy's electricity generation and revenue from its wind energy facilities may be substantially below its expectations. The electricity produced and revenues generated by a wind energy facility are highly dependent on suitable wind conditions and associated weather conditions, which are beyond ALLETE Clean Energy’s control. Furthermore, components of its systems could be damaged by severe weather, such as hailstorms, lightning or tornadoes. In addition, replacement and spare parts for key components of ALLETE Clean Energy’s diverse turbine portfolio may be difficult or costly to acquire or may be unavailable. Unfavorable weather and atmospheric conditions could impair the effectiveness of ALLETE Clean Energy’s assets or reduce their output beneath their rated capacity or require shutdown of key equipment, impeding operation of its wind energy facilities.

As contracts with its counterparties expire, ALLETE Clean Energy may not be able to replace them with agreements on similar terms.

ALLETE Clean Energy is party to long-term PPAs which expire in various years between 2018 and 2032. These PPA expirations are prior to the end of the estimated useful lives of the respective wind energy facilities. If, for any reason, ALLETE Clean Energy is unable to enter into new agreements with existing or new counterparties on similar terms once the current agreements expire, or sell energy in the wholesale market resulting in similar revenue, our financial position, results of operations and cash flows could be adversely affected.

Counterparties to ALLETE Clean Energy’s offtake agreements may not fulfill their obligations.

ALLETE Clean Energy is party to long-term PPAs with a limited number of creditworthy counterparties. If, for any reason, any of the counterparties under these agreements are unable or unwilling to fulfill their related contractual obligations, and ALLETE Clean Energy is unable to remarket the energy resulting in similar revenue, our financial position, results of operations and cash flows could be adversely affected.

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

Our Energy Infrastructure and Related Services businesses consist of ALLETE Clean Energy and U.S. Water Services. The Company's strategy for these businesses includes growth through acquisitions, project development for others, and by adding customers, products, and new geographies. This strategy depends, in part, on the Company’s ability to successfully identify and evaluate acquisition opportunities and consummate acquisitions on acceptable terms. The Company may compete with other companies for these acquisition opportunities, which may increase the Company’s cost of making acquisitions and the Company may be unsuccessful in pursuing these acquisition opportunities. These companies may be able to pay more for acquisitions and may be able to identify, evaluate, bid for and purchase a greater number of assets than the Company’s financial or human resources permit. If the Company is unable to execute its strategy of growth through acquisitions, project development for others, and/or the addition of new customers, products and geographies, it may impede our long-term objectives of achieving average annual earnings per share growth of a minimum of 5 percent and providing a dividend payout competitive with our industry.

Acquisitions are subject to uncertainties. If we are unable to successfully integrate and manage future acquisitions or strategic investments, this could have an 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.

U.S. Water Services principally relies upon recurring revenues from a diverse mix of industrial customers. Some of these customers can be adversely affected by low commodity prices such as those for ethanol and oil which may cause these customers to purchase fewer of U.S. Water Services’ products and services. If U.S. Water Services is unable to retain its existing customers, add new customers, or if it experiences reduced demand for its products and services, adverse impacts on our results of operations could occur that would prevent us from achieving our future growth expectations.


ALLETE, Inc. 2015 Form 10-K
31


Item 1A. Risk Factors (Continued)
Energy Infrastructure and Related Services Risks (Continued)

ALLETE has a significant amount of goodwill and intangible assets. A determination that goodwill or intangible assets have been impaired could result in a significant non-cash charge to earnings.

We had approximately $215 million of goodwill and intangible assets recorded on our Consolidated Balance Sheet as of December 31, 2015 , primarily relating to our acquisition of U.S. Water Services on February 10, 2015. If we make changes in our business strategy or if market or other conditions adversely affect operations of our Energy Infrastructure and Related Services businesses, we may be required to record an impairment charge. Declines in projected operating cash flows at certain of our reported units may result in goodwill impairments. An impairment could have an adverse effect on our results of operations.

Corporate and Other Risks

BNI Energy may be adversely impacted by its exposure to customer concentration and environmental laws and regulations.

BNI Energy sells lignite to two electric generating cooperatives, Minnkota Power and Square Butte, and could be adversely impacted if these customers were unable or unwilling to fulfill their related contractual obligations. In addition, BNI Energy and its customers may be adversely impacted by environmental laws and regulations which could have an adverse effect on our financial position, results of operations and cash flows.

Real estate market conditions where our legacy Florida real estate investment is located may not improve.

During the fourth quarter of 2015, the Company reevaluated its strategy related to the real estate assets of ALLETE Properties. The revised strategy incorporates the possibility of a bulk sale of its entire portfolio, in addition to sales over time. However, continued adverse market conditions could impact the timing of land sales, which could result in little to no sales, while still incurring operating expenses such as community development district assessments and property taxes, resulting in continued annual net operating losses at ALLETE Properties. Furthermore, weak market conditions could put the properties at risk for further impairment which could adversely impact our results of operations.


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.

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.


ALLETE, Inc. 2015 Form 10-K
32


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 $0.52 per share on our common stock is payable on March 1, 2016, to the shareholders of record on February 16, 2016. 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:
 
 
2015
 
 
2014
 
 
Price Range
Dividends
Price Range
Dividends
Quarter
High
Low
Declared
High
Low
Declared
First
$59.73
$51.16

$0.505

$52.73
$47.96

$0.49

Second
$52.98
$46.27
0.505

$52.54
$47.51
0.49

Third
$52.49
$45.29
0.505

$51.56
$44.39
0.49

Fourth
$52.90
$47.93
0.505

$57.97
$44.19
0.49

Annual Total
 
 

$2.02

 
 

$1.96


At February 1, 2016, there were approximately 24,000 common stock shareholders of record.

ALLETE, Inc. 2015 Form 10-K
33


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

Performance Graph.

The following graph compares ALLETE’s cumulative Total Shareholder Return on its common stock with the cumulative return of the S&P 500 Index and the Philadelphia Utility Index. The S&P 500 Index is a capitalization-weighted index of 500 stocks designed to measure performance of the broad domestic economy through changes in the aggregate market value of 500 stocks representing all major industries. Because this composite index has a broad industry base, its performance may not closely track that of a composite index comprised solely of electric utilities. The Philadelphia Utility Index is a capitalization-weighted index of 20 utility companies involved in the production of electric energy.

The calculations assume a $100 investment on December 31, 2010, and reinvestment of dividends.
 
2010
2011
2012
2013
2014
2015
ALLETE
$100
$118
$120
$152
$175
$168
S&P 500 Index
$100
$102
$118
$157
$178
$181
Philadelphia Utility Index
$100
$119
$119
$132
$170
$180


ALLETE, Inc. 2015 Form 10-K
34


Item 6. Selected Financial Data

 
2015

2014

2013

2012

2011

Millions
 
 
 
 
 
Operating Revenue (a)

$1,486.4


$1,136.8


$1,018.4


$961.2


$928.2

Operating Expenses

$1,275.7


$948.0


$864.3


$806.0


$778.2

Net Income

$141.5


$125.5


$104.7


$97.1


$93.6

Less: Non-Controlling Interest in Subsidiaries  (b)
0.4

0.7



(0.2
)
Net Income Attributable to ALLETE

$141.1


$124.8


$104.7


$97.1


$93.8

Common Stock Dividends
97.9

83.8

75.2

69.1

62.1

Earnings Retained in Business

$43.2


$41.0


$29.5


$28.0


$31.7

Shares Outstanding – Millions
 
 
 
 
 
Year-End
49.1

45.9

41.4

39.4

37.5

Average (c)
 
 
 
 
 
Basic
48.3

42.9

39.7

37.6

35.3

Diluted
48.4

43.1

39.8

37.6

35.4

Diluted Earnings Per Share

$2.92


$2.90


$2.63


$2.58


$2.65

Total Assets

$4,907.1


$4,360.8


$3,476.8


$3,253.4


$2,876.0

Long-Term Debt

$1,568.7


$1,272.8


$1,083.0


$933.6


$857.9

Return on Common Equity
8.0
%
8.6
%
8.3
%
8.6
%
9.1
%
Common Equity Ratio
53
%
54
%
55
%
54
%
56
%
Dividends Declared per Common Share

$2.02


$1.96


$1.90


$1.84


$1.78

Dividend Payout Ratio
69
%
68
%
72
%
71
%
67
%
Book Value Per Share at Year-End

$37.18


$35.04


$32.43


$30.50


$28.77

Capital Expenditures by Segment
 
 
 
 
 
Regulated Operations

$224.4


$583.5


$326.3


$418.2


$228.0

ALLETE Clean Energy
8.6

4.2




U.S. Water Services
2.9





Corporate and Other
15.9

16.6

13.2

14.0

18.8

Total Capital Expenditures

$251.8


$604.3


$339.5


$432.2


$246.8

(a)
In 2015, operating revenue included the construction and sale of a wind energy facility from ALLETE Clean Energy to Montana-Dakota Utilities for $197.7 million. (See Note 7. Acquisitions.)
(b)
In 2014 and 2015, non-controlling interest related to the January 2014 acquisition made by ALLETE Clean Energy. (See Note 7. Acquisitions.) In 2011, non-controlling interest related to ALLETE Properties was purchased during that year.
(c)
Excludes unallocated ESOP shares in each of the years 2011 through 2014. (See Note 13. Common Stock and Earnings Per Share.)



ALLETE, Inc. 2015 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 Form 10-K 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 risks facing our Company. Additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations. Our business, financial condition or results of operations could suffer if the risks are realized.

Overview

Basis of Presentation. During 2015, management updated our reportable segment presentation to reflect the manner in which we operate, assess and allocate resources after our recent acquisitions. We now present three reportable segments, Regulated Operations, ALLETE Clean Energy and U.S. Water Services. Prior period amounts have been revised to conform with the current business segment presentation.

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 145,000 retail customers. Minnesota Power also has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a wholesale customer of Minnesota Power. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 13,000 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.)

ALLETE Clean Energy was established in 2011, and focuses on developing, acquiring and operating clean and renewable energy projects. ALLETE Clean Energy currently owns and operates, in four states, approximately 535 MW of nameplate capacity wind energy generation that are under long-term power sales agreements. In addition, ALLETE Clean Energy constructed a 107 MW wind energy facility for sale to Montana-Dakota Utilities; construction and sale were completed in 2015.

U.S. Water Services is our integrated water management company which was acquired on February 10, 2015.

Corporate and Other is comprised of BNI Energy, our coal mining operations in North Dakota, ALLETE Properties, our legacy Florida real estate investment, 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 is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2015 , 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.

2015 Financial Overview

The following net income discussion summarizes a comparison of the year ended December 31, 2015 , to the year ended December 31, 2014 .

Net income attributable to ALLETE for 2015 was $141.1 million , or $2.92 per diluted share, compared to $124.8 million , or $2.90 per diluted share, for 2014 . Net income for 2015 included a $22.3 million after-tax, or $0.46 per share, non-cash impairment charge relating to the real estate assets of ALLETE Properties, and $4.8 million of after-tax expense, or $0.10 per share, for acquisition costs related to U.S. Water Services and ALLETE Clean Energy’s wind energy facilities acquisitions in 2015. (See Note 7. Acquisitions.) Net income for 2014 included 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 and a $1.4 million after-tax expense, or $0.03 per share, of acquisition costs related to ALLETE Clean Energy’s wind energy facilities acquisition which closed in January 2014. (See Note 7. Acquisitions and Note 12. Commitments, Guarantees and Contingencies.) Net income for 2015 increased primarily due to higher net income at Minnesota Power and ALLETE Clean Energy. Earnings per share dilution was $0.36 due to additional shares of common stock outstanding as of December 31, 2015. (See Note 13. Common Stock and Earnings Per Share.)

ALLETE, Inc. 2015 Form 10-K
36


2015 Financial Overview (Continued)

Regulated Operations net income attributable to ALLETE was $131.6 million in 2015 , compared to $123.0 million in 2014 . Net income for 2015 increased primarily due to higher net income at Minnesota Power resulting from higher cost recovery rider revenue, production tax credits, power marketing sales as the Minnkota Power sales agreement commenced in June 2014, and lower operating and maintenance expenses. These increases were partially offset by lower industrial sales and higher depreciation, interest and property tax expense. In addition, Minnesota Power recorded a reserve for estimated refunds of $1.6 million after-tax due to the MISO return on equity complaints, of which $0.9 million after-tax was attributable to prior years. (See Note 5. Regulatory Matters.) Our equity earnings in ATC for 2015 also reflected a $3.0 million after-tax charge related to the MISO return on equity complaints, of which approximately $1.4 million after-tax was attributable to prior years. (See Note 6. Investment in ATC.) Net income for 2014 included 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.

ALLETE Clean Energy net income attributable to ALLETE was $29.9 million in 2015 , compared to net income of $3.3 million in 2014 . Net income for 2015 increased primarily due to the recognition of profit of $20.4 million after-tax, or $0.42 per share, on the construction of a wind energy facility which was sold to Montana-Dakota Utilities in 2015, and the income generated from the operations of wind energy facilities which were acquired in 2015 and December 2014. Net income for 2015 also included $1.8 million of after-tax expense, or $0.04 per share, for acquisition costs relating to the acquisitions of the Chanarambie/Viking and Armenia Mountain wind energy facilities. The net income for 2014 included a $1.4 million after-tax expense, or $0.03 per share, for acquisition costs related to ALLETE Clean Energy’s wind energy facilities acquisition in January 2014.

U.S. Water Services net income attributable to ALLETE was $0.9 million for the period from February 10, 2015, through December 31, 2015. Net income included $2.2 million of after-tax expense related to purchase accounting for inventories and sales backlog; the total impact of this purchase accounting adjustment was $2.5 million after-tax, and is expected to be recognized through the first quarter of 2016. (See Note 7. Acquisitions.)

Corporate and Other net loss attributable to ALLETE was $21.3 million in  2015 , compared to a net loss of $1.5 million in 2014 . The net loss for 2015 included a $22.3 million after-tax, or $0.46 per share, non-cash impairment charge relating to the real estate assets of ALLETE Properties, and a $3.0 million after-tax expense, or $0.06 per share, for acquisition costs related to the acquisition of U.S. Water Services. BNI Energy recorded net income of $6.7 million in 2015 ($6.1 million in 2014) as deliveries of coal increased in 2015. ALLETE Properties recorded a net loss of $23.3 million in 2015 (net loss of $2.3 million in 2014), which was primarily attributable to the aforementioned non-cash impairment charge.

2015 Compared to 2014

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

Regulated Operations
Year Ended December 31
2015

2014

Millions
 
 
Operating Revenue

$991.2


$1,003.5

Fuel and Purchased Power
328.1

356.1

Transmission Services
54.1

45.6

Cost of Sales
7.9

17.3

Operating and Maintenance
229.6

240.8

Depreciation and Amortization
135.1

118.0

Taxes Other than Income Taxes
46.2

41.9

Operating Income
190.2

183.8

Interest Expense
(53.9
)
(49.2
)
Equity Earnings in ATC
16.3

19.6

Other Income
3.4

7.8

Income Before Income Taxes
156.0

162.0

Income Tax Expense
24.4

39.0

Net Income Attributable to ALLETE
$131.6

$123.0



ALLETE, Inc. 2015 Form 10-K
37


2015 Compared to 2014 (Continued)
Regulated Operations (Continued)

Operating Revenue decreased $12.3 million , or 1 percent , from 2014 primarily due to lower fuel adjustment clause recoveries, gas sales, and financial incentives under the Minnesota Conservation Improvement Program, partially offset by higher cost recovery rider revenue, kWh sales, FERC formula based rates, and transmission revenue.

Fuel adjustment clause recoveries decreased $37.1 million due to lower fuel and purchased power costs attributable to our retail and municipal customers. (See Operating Expenses - Fuel and Purchased Power Expense. )

Gas sales at SWL&P decreased $11.0 million from 2014 primarily as a result of unseasonably cold weather during the first half of 2014 and a warmer than average 2015. (See Cost of Sales. )

Financial incentives under the Minnesota Conservation Improvement Program decreased $2.5 million from 2014 as a result of annual limits placed on recoveries beginning in 2015.

Cost recovery rider revenue increased $17.8 million primarily due to the completion of the Bison Wind Energy Center and CapX2020 projects as well as higher capital expenditures related to the Boswell Unit 4 environmental upgrade.

Revenue from Regulated Operations increased $14.7 million due to a 3.1 percent increase in kWh sales. 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 48.4 percent in 2015 compared to 2014 primarily due to the commencement of the Minnkota Power sales agreement in June 2014. (See Note 12. Commitments, Guarantees and Contingencies.) Sales to our residential and municipal customers were impacted by unseasonably cold temperatures in 2014 and warmer than average temperatures in 2015. Heating degree days in Duluth, Minnesota, were approximately 16 percent lower in 2015 compared to 2014. Sales to our industrial customers decreased 11.4 percent primarily due to reduced taconite production.
 
Kilowatt-hours Sold
2015

2014

Quantity
Variance
%
Variance
Millions
 
 
 
 
Regulated Utility
 
 
 
 
Retail and Municipal
 
 
 
 
Residential
1,113

1,204

(91
)
(7.6
)
Commercial
1,462

1,468

(6
)
(0.4
)
Industrial
6,635

7,487

(852
)
(11.4
)
Municipal
833

864

(31
)
(3.6
)
Total Retail and Municipal
10,043

11,023

(980
)
(8.9
)
Other Power Suppliers
4,310

2,904

1,406

48.4

Total Regulated Utility Kilowatt-hours Sold
14,353

13,927

426

3.1


Revenue from electric sales to taconite and iron concentrate customers accounted for 17 percent of consolidated operating revenue in 2015 (25 percent in 2014 ). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 6 percent of consolidated operating revenue in 2015 (8 percent in 2014 ). Revenue from electric sales to pipelines and other industrial customers accounted for 6 percent of consolidated operating revenue in 2015 (7 percent in 2014 ).

Revenue to our wholesale customers under our FERC formula based rates increased $6.9 million primarily due to additional renewable, environmental and other investments.

Transmission revenue increased $2.7 million primarily due to higher MISO-related revenue, which was partially offset by an estimated refund for MISO transmission revenue due to the MISO return on equity complaints. (See Operating Expenses - Transmission Services and Note 5. Regulatory Matters . )


ALLETE, Inc. 2015 Form 10-K
38


2015 Compared to 2014 (Continued)
Regulated Operations (Continued)

Operating Expenses decreased $18.7 million , or 2.3 percent , from 2014 .

Fuel and Purchased Power Expense decreased $28.0 million , or 8 percent , from 2014 primarily due to lower purchased power and fuel prices in 2015 compared to 2014, partially offset by higher kWh sales in 2015. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause. (See Operating Revenue. )

Transmission Services expense increased $8.5 million , or 19 percent , from 2014 primarily due to higher MISO-related expense, which was partially offset by an estimated refund for MISO transmission expense due to the MISO return on equity complaints. (See Operating Revenue and Note 5. Regulatory Matters.)

Cost of Sales decreased $9.4 million , or 54 percent , from 2014 due to lower purchased gas at SWL&P. (See Operating Revenue. )

Operating and Maintenance Expense decreased $11.2 million , or 5 percent , from 2014 , due to cost reduction efforts and the absence of a $4.2 million expense that was recorded in 2014 to reflect a liability associated with environmental mitigation projects required as part of an EPA NOV Consent Decree settlement. Cost reduction efforts resulted in lower wage, vehicle fleet and miscellaneous employee expenses. These reductions were partially offset by increased expense for the operation and maintenance of the 205 MW addition at our Bison Wind Energy Center that went into service in December 2014.

Depreciation and Amortization Expense increased $17.1 million , or 14 percent , from 2014 primarily due to additional property, plant and equipment in service.

Taxes Other than Income Taxes increased $4.3 million , or 10 percent , from 2014 primarily due to higher property tax expenses resulting from higher taxable plant and rates.

Interest Expense increased $4.7 million , or 10 percent , from 2014 primarily due to higher average long-term debt balances.

Equity Earnings in ATC decreased $3.3 million , or 17 percent , from 2014 primarily due to a $5.2 million expense related to the MISO return on equity complaints, of which $2.4 million was attributable to ATC’s change in estimate of a refund liability relating to prior years. (See Note 6. Investment in ATC.)

Other Income decreased $4.4 million , or 56 percent , from 2014 primarily due to lower AFUDC–Equity.

Income Tax Expense decreased $14.6 million , or 37 percent , from 2014 primarily due to increased production tax credits as a result of the 205 MW addition to the Bison Wind Energy Center in December 2014.

ALLETE Clean Energy
Year Ended December 31
2015

2014

Millions
 
 
Operating Revenue

$262.1


$33.2

Net Income Attributable to ALLETE
$29.9

$3.3


Operating Revenue increased $228.9 million from 2014 primarily due to the recognition of $197.7 million of revenue from the construction and sale of a wind energy facility to Montana-Dakota Utilities. (See Note 7. Acquisitions.) The acquisitions of Storm Lake I in December 2014, Chanarambie/Viking in April 2015 and Armenia Mountain in July 2015 also contributed to the increase in revenue in 2015 compared to 2014.


ALLETE, Inc. 2015 Form 10-K
39


2015 Compared to 2014 (Continued)
ALLETE Clean Energy (Continued)
 
Year Ended December 31,
 
2015
2014
Production and Operating Revenue
kWh
Revenue
kWh
Revenue
Millions
 
 
 
 
Wind Energy Facility
 
 
 
 
Lake Benton
265.1


$13.5

264.7


$13.4

Storm Lake II
186.4

11.7

169.4

11.1

Condon
84.1

7.8

91.5

8.2

Storm Lake I
230.7

12.1

9.0

0.5

Chanarambie/Viking
199.1

9.8



Armenia Mountain
111.6

9.5



Construction Profit

197.7



Total
1,077.0

$262.1
534.6


$33.2


Net Income Attributable to ALLETE increased $26.6 million from 2014 . Net income in 2015 included $20.4 million after-tax, or $0.46 per share, due to the profit from the construction and sale of a wind energy facility to Montana-Dakota Utilities, and $6.9 million related to income generated from the full year of operations of Storm Lake I and the additions of Chanarambie/Viking and Armenia Mountain. Net income in 2015 included $1.8 million of after-tax expense, or $0.04 per share, for acquisition costs related to the acquisitions of the Chanarambie/Viking and Armenia Mountain wind energy facilities. Net income in 2014 included a $1.4 million after-tax expense, or $0.03 per share, for acquisition costs related to the January 2014 acquisition.

U.S. Water Services
For the period February 10, 2015 through December 31
2015

Millions
 
Operating Revenue

$119.8

Net Income Attributable to ALLETE
$0.9

Operating Revenue was $119.8 million for the period February 10, 2015, through December 31, 2015. Revenue from chemical and related services, which includes recurring revenue contracts for the delivery and service of chemicals, amounted to $92.5 million for the period February 10, 2015, through December 31, 2015. Revenue from equipment and related services, which includes sales of water treatment equipment, amounted to $27.3 million for the period February 10, 2015, through December 31, 2015. U.S. Water Services strives to provide a full-service product offering to customers including equipment, chemicals, engineering and service.

Net Income Attributable to ALLETE was $0.9 million for the period February 10, 2015, through December 31, 2015. Net income included $2.2 million of after-tax expense related to purchase accounting for inventories and sales backlog; the total impact of this purchase accounting adjustment was $2.5 million after-tax, and is expected to be recognized through the first quarter of 2016.

Corporate and Other

Operating Revenue increased $13.2 million , or 13 percent , from 2014 primarily due to an increase in revenue at BNI Energy, which operates under cost-plus fixed fee contracts, as a result of higher expenses and increased coal delivered in 2015. Increased sales at ALLETE Properties also contributed to the increase.

Net Income Attributable to ALLETE decreased $19.8 million from 2014 primarily due to a $22.3 million after-tax, or $0.46 per share, non-cash impairment charge relating to the real estate assets of ALLETE Properties. (See Note 1. Operations and Significant Accounting Policies.) Also contributing to the decrease was a $3.0 million after-tax expense, or $0.06 per share, for acquisition costs related to the acquisition of U.S. Water Services. In 2015, results reflected slightly higher net income at BNI Energy.


ALLETE, Inc. 2015 Form 10-K
40


2015 Compared to 2014 (Continued)

Income Taxes – Consolidated

For the year ended December 31, 2015, the effective tax rate was 15.2 percent (22.6 percent for the year ended December 31, 2014). The decrease from the year ended December 31, 2014, was primarily due to increased production tax credits in 2015 related to additional wind energy generation. The effective tax rate deviated from the statutory rate of approximately 41 percent primarily due to production tax credits and the deduction for AFUDC–Equity. (See Note 15. Income Tax Expense.)


2014 Compared to 2013

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

Regulated Operations
Year ended December 31
2014

2013

Millions
 
 
Operating Revenue

$1,003.5


$925.5

Fuel and Purchased Power
356.1

334.8

Transmission Services
45.6

32.3

Cost of Sales
17.3

12.6

Operating and Maintenance
240.8

239.1

Depreciation and Amortization
118.0

110.2

Taxes Other than Income Taxes
41.9

38.4

Operating Income
183.8

158.1

Interest Expense
(49.2
)
(44.4
)
Equity Earnings in ATC
19.6

20.3

Other Income
7.8

4.7

Income Before Income Taxes
162.0

138.7

Income Tax Expense
39.0

35.1

Net Income Attributable to ALLETE
$123.0
$103.6

Operating Revenue increased $ 78 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 primarily due 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 in June 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


ALLETE, Inc. 2015 Form 10-K
41


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

Revenue from electric sales to taconite and iron concentrate customers accounted for 25 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 8 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 placed in service in March 2013 and higher MISO related revenue. (See Operating Expenses Transmission Services .)

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

Fuel adjustment clause recoveries increased $4.7 million due to higher fuel and purchased power costs attributable to our retail and municipal customers. (See Operating Expenses Fuel and Purchased Power Expense. )

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. )
 
Transmission Services expense increased $13.3 million , or 41 percent , from 2013 primarily due to higher MISO-related expense. (See Operating Revenue. )

Cost of Sales increased $4.7 million , or 37 percent , from 2013 due to higher gas sales in 2014; purchased gas expenses are recovered from our customers through a purchased gas adjustment clause. (See Operating Revenue .)

Operating and Maintenance Expense increased $1.7 million , or 1 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 which was partially offset by lower benefit expense. Employee benefit expense was lower due to higher discount rates in 2014 attributable to our defined benefit pension and other postretirement benefit plans.

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

Taxes Other than Income Taxes increased $3.5 million , or 9 percent , from 2013 primarily due to higher taxable plant and rates.

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

Equity Earnings in ATC decreased $0.7 million , or 3 percent , from 2013 primarily due to ATC recording an estimated refund liability for complaints filed with the FERC related to the allowed MISO return on equity for transmission owners.

Income Tax Expense increased $3.9 million , or 11 percent , from 2013 primarily due to higher pretax income in 2014, partially offset by higher federal production tax credits in 2014.

ALLETE, Inc. 2015 Form 10-K
42


2014 Compared to 2013 (Continued)

ALLETE Clean Energy
Year ended December 31,
2014

2013

Millions
 
 
Operating Revenue

$33.2


Net Income (Loss) Attributable to ALLETE
$3.3
$(3.4)

Operating Revenue increased $33.2 million from 2013 due to the acquisitions of Storm Lake II, Condon and Lake Benton in January 2014, and Storm Lake I in December 2014. Prior to these acquisitions, ALLETE Clean Energy had no revenue generating assets.
 
Year Ended
December 31, 2014
Production and Operating Revenue
kWh
Revenue
Millions
 
 
Wind Energy Facility
 
 
Lake Benton
264.7


$13.4

Storm Lake II
169.4

11.1

Condon
91.5

8.2

Storm Lake I
9.0

0.5

Total
534.6


$33.2


Net Income Attributable to ALLETE increased $6.7 million from 2013 . Net income for 2014 included a $1.4 million after-tax expense, or $0.03 per share, for acquisition costs related to ALLETE Clean Energy’s wind energy facilities acquisition in January 2014. Net income in 2014 increased primarily due to the acquisitions of the wind energy facilities in January 2014.

U.S. Water Services

U.S. Water Services was acquired on February 10, 2015.

Corporate and Other

Operating Revenue increased $7.2 million , or 8 percent , from 2013 primarily due to a $2.7 million increase in revenue at BNI Energy, which operates under cost-plus fixed fee contracts, resulting from increased coal deliveries and higher expenses in 2014. ALLETE Properties revenue increased $1.8 million primarily due to higher wetland mitigation bank credit sales.

Net Income Attributable to ALLETE decreased $6.0 million from 2013 primarily due to gains on sales of investments in 2013, and higher state income tax expense in 2014.

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 energy 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. 2015 Form 10-K
43


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. We believe the following policies 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.)

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, 2015 was approximately 47 percent equity securities, 39 percent debt, 8 percent private equity, and 6 percent real estate. Our postretirement health and life asset allocation at December 31, 2015 , was approximately 57 percent equity securities, 35 percent debt, and 8 percent private equity. Equity securities consist of a mix of market capitalization sizes with domestic and international securities. In 2015 , 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 $1.6 million , pretax.

The discount rate is computed using a bond matching study which utilizes a portfolio of high quality bonds that produce cash flows similar to the projected costs of our pension and other postretirement plans. In 2015 , we used discount rates of 4.30 percent and 4.33 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 $1.8 million , pretax.

The mortality assumptions used to calculate our pension and other postretirement benefit obligations as of December 31, 2015 considered a modified RP-2014 mortality table and an updated mortality projection scale. (See Note 17. Pension and Other Postretirement Benefit Plans.)


ALLETE, Inc. 2015 Form 10-K
44


Critical Accounting Policies (Continued)

Impairment of Long-Lived Assets. We review our long-lived assets, which include the legacy 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 include a bulk sale of its entire portfolio, the sale of each individual 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 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, may vary among each land parcel, and may change in the future. If the excess of undiscounted future net cash flows over the carrying amount of a property is small, there is a greater risk of future impairment in the event of such future changes and any resulting impairment charges could be material.

In recent years, market conditions for real estate in Florida have required us to review our land inventories for impairment. In response to market conditions and recent transaction activity, during the fourth quarter of 2015 the Company reevaluated its strategy related to the real estate assets of ALLETE Properties. The revised strategy incorporates the possibility of a bulk sale of its entire portfolio which, if consummated, is likely to result in sales proceeds below the book value of the real estate assets. ALLETE also continues to pursue sales of individual parcels over time. Proceeds from such a sale would be strategically deployed to support growth in our energy infrastructure and related services businesses. ALLETE will continue to maintain key entitlements and infrastructure without making additional investments or acquisitions.
In connection with implementing the revised strategy in 2015, management evaluated its impairment analysis for its real estate assets using updated assumptions to determine estimated future net cash flows on an undiscounted basis. Future net cash flows were adjusted to consider the possibility of a bulk sale of its entire portfolio, in addition to sales over time under the existing divestiture plan. Estimated fair values were based upon current market data and pricing for individual parcels. Our impairment analysis incorporates a probability-weighted approach considering the alternative courses of sales noted above.
Based on the results of undiscounted cash flow analysis, the undiscounted future net cash flows were not adequate to recover the carrying value of the real estate assets totaling $83.3 million. Estimated fair value was derived from current market interest in the property for a bulk sale of its entire portfolio, and discounted cash flow analysis of estimated selling price for sales over time. As a result, a non-cash impairment charge of $36.3 million was recorded in 2015 to reduce the carrying value of the real estate to its estimated fair value at December 31, 2015.
If our real estate assets are sold differently than anticipated, the actual results could be materially different from our undiscounted future net cash flow analysis.
In 2014 and 2013, impairment analyses of estimated undiscounted future net cash flows were conducted based on the strategy existing at that time, and indicated that the cash flows were adequate to recover the carrying value of ALLETE Properties real estate assets. As a result, no impairment was recorded for the years ended December 31, 2014 and 2013.
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. 2015 Form 10-K
45


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 the application of tax statutes and regulations, and projections of future federal taxable income, 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.

Valuation of Goodwill and Intangible Assets. When we acquire a business, the assets acquired and liabilities assumed are recorded at their respective fair values as of the acquisition date. Determining the fair value of intangible assets acquired as part of a business combination requires us to make significant estimates. These estimates include the amount and timing of projected future cash flows, the discount rate used to discount those cash flows to present value, the assessment of the asset’s life cycle, and the consideration of legal, technical, regulatory, economic, and competitive risks. The fair value assigned to intangible assets is determined by estimating the future cash flows of each project and discounting the net cash flows back to their present values. The discount rate used is determined at the time of measurement in accordance with accepted valuation standards.

Goodwill. Goodwill is the excess of the purchase price (consideration transferred) over the estimated fair value of net assets of acquired businesses. In accordance with GAAP, goodwill is not amortized. The Company assesses whether there has been an impairment of goodwill annually in the fourth quarter and whenever an event occurs or circumstances change that would indicate the carrying amount may be impaired. Impairment testing for goodwill is done at the reporting unit level. An impairment loss is recognized when the carrying amount of the reporting unit’s net assets exceeds the estimated fair value of the reporting unit. The test for impairment requires us to make several estimates about fair value, most of which are based on projected future cash flows. Our estimates associated with the goodwill impairment test are considered critical due to the amount of goodwill recorded on our Consolidated Balance Sheet and the judgment required in determining fair value, including projected future cash flows. The results of our annual impairment test are discussed in Note 10. Fair Value in this Form 10-K. Goodwill was $130.6 million and $2.9 million as of December 31, 2015 , and December 31, 2014 , respectively.

Intangible Assets. Intangible assets include customer relationships, patents, non-compete agreements and trademarks and trade names. Intangible assets with definite lives consist of customer relationships, patents, and non-compete agreements, which are amortized on a straight-line or accelerated basis with estimated useful lives ranging from approximately 3 years to approximately 22  years. We review definite-lived intangible assets for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Indefinite-lived intangible assets consist of trademarks and trade names, which are tested for impairment annually in the fourth quarter and whenever an event occurs or circumstances change that would indicate that the carrying amount may be impaired. Impairment is calculated as the excess of the asset’s carrying amount over its fair value. Our impairment reviews are based on an estimated future cash flow approach that requires significant judgment with respect to future revenue and expense growth rates, selection of an appropriate discount rate, and other assumptions and estimates. We use estimates that are consistent with our business plans and a market participant view of the assets being evaluated. The results of our annual impairment test are discussed in Note 10. Fair Value in this Form 10-K. Actual results may differ from our estimates due to a number of risk factors, including those which are discussed in Item 1A, "Risk Factors" in this Form 10-K. Intangible assets, net of accumulated amortization, were $84.6 million and $1.9 million as of December 31, 2015 , and December 31, 2014 , respectively.


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 average annual earnings per share growth of a minimum of 5 percent and providing a dividend payout competitive with our industry.

ALLETE is predominately a regulated utility through Minnesota Power, SWL&P and an investment in ATC. ALLETE’s strategy is to remain predominately a regulated utility while investing in its Energy Infrastructure and Related Services businesses to complement its regulated businesses, balance exposure to the utility’s industrial customers, and provide potential long-term earnings growth. ALLETE expects net income from Regulated Operations to be approximately 85 percent to 90 percent of total consolidated net income in 2016. Over the next several years, the contribution of the Energy Infrastructure and Related Services businesses to net income is expected to increase as ALLETE grows these operations. ALLETE expects its businesses to provide regulated, contracted or recurring revenues and to support sustained growth in net income and cash flow.


ALLETE, Inc. 2015 Form 10-K
46


Outlook (Continued)

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 energy 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 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 2016.

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. Approximately 46 percent of our regulated utility kWh sales in 2015 (54 percent in 2014 ) were made to our industrial customers in these industries.

Minnesota Power provides electric service to five taconite customers capable of producing up to approximately 41 million tons of taconite pellets annually. Four of these customers are Large Power Customers (see Large Power Customer Contracts ). The fifth is Northshore Mining, owned and operated by Cliffs Natural Resources Inc., which self-generates a majority of its power, and is capable of producing approximately 6 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. Minnesota Power also provides electric service to three iron concentrate customers capable of producing up to approximately 4 million 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 over 150 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 2016 will increase compared to 2015. The American Iron and Steel Institute (AISI), an association of North American steel producers, reported that U.S. raw steel production operated at approximately 71 percent of capacity in 2015 ( 77 percent in 2014 and in 2013 ). Many steel producers reduced production in 2015, citing higher levels of imports and lower prices. Some Minnesota taconite and iron concentrate producers reduced production in 2015 in response to declining U.S. steel production. While steel consumption is expected to increase in the U.S. in 2016, the high level of imports and lower prices may impact Minnesota taconite production in 2016.

ALLETE, Inc. 2015 Form 10-K
47


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

The following table reflects Minnesota Power’s taconite customers’ production levels for the past ten years.
Minnesota Power Taconite Customer Production
Year
 
Tons (Millions)
2015*
 
30
2014
 
39
2013
 
37
2012
 
39
2011
 
39
2010
 
35
2009
 
17
2008
 
39
2007
 
38
2006
 
39
Source: Minnesota Department of Revenue 2015 Mining Tax Guide for years 2006 - 2014.
* Preliminary data from the Minnesota Department of Revenue.

Minnesota Power’s 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 Minnesota Power’s taconite customers’ production would impact our annual earnings per share by approximately $0.03, net of expected power marketing sales at current 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 Minnesota Power to file a rate case to recover lost revenue.

Minnesota Power’s Large Power taconite customers, subject to demand nomination requirements, nominate demand levels for their energy needs each December, March, and August for the following four-month periods. Based on nominations received on December 1, 2015, Minnesota Power’s Large Power taconite customers nominated at approximately 80 percent of full demand levels for January through April 2016.

Minnesota Power proactively sells power that is temporarily not required by industrial customers in the wholesale power markets to optimize the value of its generating facilities. Minnesota Power has remarketed a significant portion of the power not expected to be taken by the idled taconite facilities and is well positioned to serve the power needs for those facilities in the event they resume production sooner than currently indicated.

In addition to serving the taconite industry, Minnesota Power serves a number of customers in the paper, pulp and secondary wood products industry. The four major paper and pulp mills we serve reported operating at, or near, full capacity in 2015, and similar levels are expected in 2016. In September 2014, Boise, Inc. (Boise) provided the required one-year written notice of its intent to install additional generation at its International Falls, Minnesota, paper mill which was completed in 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.

USS Corporation . In the second quarter of 2015, USS Corporation temporarily idled its Minnesota Ore Operations - Keetac plant in Keewatin, Minnesota, and a portion of its Minnesota Ore Operations - Minntac plant in Mountain Iron, Minnesota. These actions were due to high inventory levels and ongoing adjustment of its steel producing operations throughout North America. Global influences in the market, including a higher level of imports, unfairly traded products and reduced steel prices, were cited as having an impact. In the third quarter of 2015, USS Corporation returned its Minntac plant to full production. USS Corporation’s Keetac plant remains idled. Both facilities are Large Power Customers of Minnesota Power. USS Corporation has the capability to produce approximately 5 million tons and 15 million tons of taconite annually at its Keetac and Minntac plants, respectively.

ALLETE, Inc. 2015 Form 10-K
48


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

Magnetation . On May 5, 2015, Magnetation announced that it had reached an agreement with holders of more than 70 percent of its 11.0 percent senior secured notes due in 2018 to restructure its balance sheet and provide liquidity to support long-term operations. To implement this restructuring, Magnetation announced that it had filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the District of Minnesota, citing the significant decrease in global iron ore prices and its existing capital structure.

Magnetation stated that it intends to continue to pay suppliers and vendors in full under normal terms for goods and services provided after the bankruptcy filing date of May 5, 2015. Magnetation stated that it expects its mining and pelletizing operations and customer shipments to continue in the ordinary course throughout the reorganization. Minnesota Power’s pre-petition amounts due from Magnetation are less than $1 million.

Magnetation’s Plant 4 iron concentrate facility is a Large Power Customer of Minnesota Power. On July 24, 2015, Minnesota Power filed a petition with the MPUC for approval of a new electric service agreement (Agreement) for service to both Magnetation’s Plant 2 and Plant 4 facilities, with a term through at least December 31, 2025. This Agreement was approved by the MPUC in an order dated February 2, 2016, and is subject to bankruptcy court approval.

On January 6, 2016, Magnetation announced a temporary production curtailment at its Plant 2 iron concentrate facility in Bovey, Minnesota, effective January 18, 2016, in order to balance its production with its customers’ needs.

United Taconite . In August 2015, Cliffs Natural Resources Inc. (Cliffs) temporarily idled its United Taconite plant in Eveleth, Minnesota, citing high levels of inventories, lower demand from its customers, and the high rate of imported steel. Cliffs has said the plant will return to production as soon as demand from customers returns. Cliffs also stated that the idling offers a chance to start reworking the plant to produce a fully fluxed taconite pellet. That new product will replace a flux pellet now made at Cliffs’ Empire operation in Michigan which is scheduled to shut down at the end of 2016. United Taconite has the capability to produce approximately 5 million tons of taconite annually.

Steel Dynamics . On May 26, 2015, Steel Dynamics announced the decision to idle its Minnesota Operations for an initial 24-month period. Its Minnesota Operations include Mesabi Nugget and Mining Resources, both of which are Minnesota Power industrial customers. Steel Dynamics cited the significant decline in pig iron pricing as the reason behind its decision. Mesabi Nugget and Mining Resources account for a combined 30 MW of load for Minnesota Power when fully operational.

Verso Corporation . On January 26, 2016, Verso Corporation and its subsidiaries announced that they had filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware, citing a decline in demand for its products and a significant increase in foreign imports. NewPage Corporation is a subsidiary of Verso Corporation and a Large Power Customer of Minnesota Power. Verso Corporation stated it expects the reorganization process to have virtually no impact on its daily business and intends to pay suppliers in full for goods and services delivered after the bankruptcy filing date of January 26, 2016. Minnesota Power’s pre-petition amounts due from NewPage Corporation are $2.7 million.

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. We cannot predict the outcome of these projects.

Nashwauk Public Utilities Commission . On April 21, 2015, Minnesota Power 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, 2028. 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 up to approximately 110 MW of additional load for Minnesota Power. Essar announced the completion of project financing in October 2014 and has stated that it expects to achieve full production capability in 2016. We expect minimal electricity sales to the Nashwauk Public Utilities Commission for electric service to Essar Steel Minnesota’s taconite mine and processing facility in 2016.


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

PolyMet . Minnesota Power has 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. On November 6, 2015, PolyMet announced the completion of the final EIS by state and federal agencies, which was subsequently published in the Federal Register and Minnesota Environmental Quality Board Monitor. The final EIS requires an adequacy decision by the Minnesota Department of Natural Resources and Records of Decision by the federal agencies, which are expected in 2016, before final action can be taken on the required permits to construct and operate the mining operation. Minnesota Power could supply between 45 MW and 50 MW of load under a ten-year power supply contract that would begin upon start-up of the mining operations.

Enbridge . Minnesota Power has a long-term contract with Enbridge that extends through December 31, 2020. Enbridge owns and operates a crude oil and liquids transportation system in North America including in our service territories. Enbridge recently completed an expansion at two pumping stations located in Minnesota Power’s service territory in Deer River and Floodwood, Minnesota resulting in load growth of approximately 15 MW. Subject to the receipt of required permits, Enbridge plans to construct a pipeline connecting its Beaver Lodge Station, near Tioga, North Dakota, to an existing terminal in Superior, Wisconsin (Sandpiper). Enbridge is also planning a replacement of its Line 3 pipeline running from Canada, through Minnesota, and into its Superior terminal. Completion and full operation of the Sandpiper and Line 3 replacement projects, expected in 2019, would result in between 15 MW and 25 MW of additional load at SWL&P.

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. The Bison Wind Energy Center added 205 MW of capacity in the fourth quarter of 2014, bringing total capacity to 497 MW. (See Renewable Energy. )
The installation of emissions control technology at Boswell Unit 4 completed in December 2015 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 which was completed in June 2015.
Retirement of Taconite Harbor Unit 3, one of three coal-fired units at Taconite Harbor, which was retired in May 2015.

On July 9, 2015, Minnesota Power announced the next steps in its EnergyForward plan, which will reduce carbon emissions, increase the use of renewable resources and add natural gas to meet customer electric service needs in a balanced, reliable and cost-effective way. Significant additional elements of the plan include:

Economic idling of Taconite Harbor Units 1 and 2 in the fall of 2016 and the ceasing of coal-fired operations there in 2020.
Adding between 200 MW and 300 MW of cleaner and flexible natural gas-fired generation to Minnesota Power’s portfolio within the next decade.
Building both large and small scale solar generation.
Expanding the potential for additional energy efficiency savings.

Integrated Resource Plan (IRP). In a November 2013 order, the MPUC approved Minnesota Power’s 2013 IRP which detailed elements of its EnergyForward strategic plan, announced in January 2013. On September 1, 2015, Minnesota Power filed its 2015 IRP with the MPUC which contains the next steps in its 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.

Renewable Energy. In February 2007, Minnesota enacted a law requiring 25 percent of electric utilities’ applicable 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’s 2015 IRP, which was filed with the MPUC on September 1, 2015, includes an update on its plans and progress in meeting the Minnesota renewable energy milestones through 2025. (See EnergyForward .)


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Outlook (Continued)
EnergyForward (Continued)

Minnesota Power continues to execute its renewable energy strategy through key renewable projects that will ensure it meets the identified state mandate at the lowest cost for customers. Minnesota Power has exceeded the interim milestone requirements to date with approximately 27 percent of its applicable retail and municipal energy sales supplied by renewable energy sources in 2015. Minnesota Power expects 31 percent of its applicable retail and municipal energy sales will be supplied by renewable energy sources in 2016.

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 has two solar projects under development. On August 21, 2015, Minnesota Power filed for MPUC approval of a 10 MW utility scale solar project at Camp Ripley, a Minnesota Army National Guard base and training facility near Little Falls, Minnesota. At a hearing on January 28, 2016, the MPUC approved the Camp Ripley solar project as eligible to meet the solar energy standard and for current cost recovery, subject to certain compliance requirements. On September 10, 2015, Minnesota Power filed for MPUC approval of a 1 MW community solar garden project in Saint Louis County, Minnesota. If the community solar garden project is also approved, Minnesota Power believes these projects will meet approximately one-third of the overall mandate and approximately one-fourth of the mandate related to solar photovoltaic devices with a nameplate capacity of 20 kilowatts or less. Costs associated with these projects are expected to be recovered from customers.

Wind Energy . Minnesota Power’s 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 the 25 MW Taconite Ridge Energy Center located in northeastern Minnesota. Minnesota Power also has 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.

Customer billing rates for the Bison Wind Energy Center were approved by the MPUC in an order dated May 22, 2015. In November 2014, Minnesota Power filed a renewable resources factor filing which includes updated costs associated with Bison. Upon approval of the filing, Minnesota Power 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 its 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 five long-term PPAs with Manitoba Hydro. The first PPA 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. Under the second PPA, Minnesota Power is purchasing 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 a third PPA. This 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. In September 2015, Manitoba Hydro submitted the final preferred route and EIS for the additional transmission capacity in Canada to the Manitoba Conservation and Water Stewardship for regulatory approval. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in 2014. The capacity price is adjusted annually until 2020 by the change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed price component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices.

In July 2014, Minnesota Power and Manitoba Hydro signed a fourth PPA that provides for Minnesota Power to purchase up to 133  MW of energy from Manitoba Hydro for 20 years beginning in 2020. The pricing under this PPA is based on forward market prices. The PPA was approved by the MPUC in an order dated January 30, 2015, and is subject to the construction of the GNTL. (See Great Northern Transmission Line. )

In October 2015, Minnesota Power and Manitoba Hydro signed a fifth PPA that provides for Minnesota Power to purchase 50  MW of capacity at fixed prices. The PPA begins in June 2017 and expires in May 2020.

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Outlook (Continued)
EnergyForward (Continued)

Hydro Operations . On February 13, 2015, Minnesota Power supplemented its November 2014 renewable resources factor filing to include costs associated with the restoration and repair of Thomson. In an order dated March 5, 2015, the MPUC approved Minnesota Power’s petition seeking cost recovery of investments and expenditures related to the restoration and repair of Thomson through a renewable resources rider. Thomson returned to full production in the fourth quarter of 2015.

Boswell Mercury Emissions Reduction Plan. In August 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA in order to comply with the Minnesota Mercury Emissions Reduction Act and the Federal MATS rule. Construction on the project to implement the Boswell Unit 4 mercury emissions reduction plan was completed with project costs totaling approximately $220 million through December 31, 2015 . In a November 2013 order, the MPUC approved the Boswell Unit 4 mercury emissions reduction plan and cost recovery, establishing an environmental improvement rider. Customer billing rates for the environmental improvement rider were approved by the MPUC in an order dated August 24, 2015. On September 30, 2015, Minnesota Power filed an updated environmental improvement factor filing which included updated costs associated with Boswell Unit 4. Upon approval of the filing, Minnesota Power will be authorized to include updated billing rates on customer bills.

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

Energy Infrastructure and Related Services.

ALLETE Clean Energy.

ALLETE Clean Energy was established in 2011, and focuses on developing, acquiring and operating clean and renewable energy projects. ALLETE Clean Energy currently owns and operates, in four states, approximately 535 MW of nameplate capacity wind energy generation that are under long-term power sales agreements. In addition, ALLETE Clean Energy constructed a 107 MW wind energy facility for sale to Montana-Dakota Utilities; construction and sale were completed in 2015.

ALLETE Clean Energy believes the market for renewable energy in North America is robust, driven by several factors including environmental regulation, tax incentives, societal expectations and continual technology advances. The recent Clean Power Plan is an example of an environmental regulation that we believe will drive renewable energy development.

ALLETE Clean Energy’s strategy includes the safe, reliable, optimal and profitable operation of its existing facilities. This includes a strong safety culture, the continuous pursuit of operational efficiencies at existing facilities, and cost controls. While ALLETE Clean Energy generally acquires facilities in liquid power markets, ALLETE Clean Energy’s strategy also includes the exploration of power sales agreement extensions upon expiration of existing contracts.

ALLETE Clean Energy will pursue steady growth through acquisitions or project development for others. ALLETE Clean Energy is targeting acquisitions of existing facilities with a purchase price in the $50 million to $100 million range, and which have long-term power sales agreements in place for the facility’s output. At this time, ALLETE Clean Energy expects acquisitions will be primarily wind or solar facilities in North America.


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Outlook (Continued)
ALLETE Clean Energy (Continued)

ALLETE Clean Energy will manage risk by having a diverse portfolio of assets, which will include power sales contract expiration and geographic diversity. The current mix of power sales agreement expiration and geographic location is as follows:
Wind Energy Facility
Location
Capacity MW
PPA MW
PPA Expiration
Armenia Mountain
Pennsylvania
100.5
100%
2024
Chanarambie/Viking
Minnesota
97.5
 
 
PPA 1
 
 
12%
2018
PPA 2
 
 
88%
2023
Condon
Oregon
50
100%
2022