UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)
xQuarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the quarterly period ended June 30, 2016March 31, 2017

or
¨Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 For the transition period from ______________ to ______________

Commission File Number 1-3548

ALLETE, Inc.
(Exact name of registrant as specified in its charter)

Minnesota 41-0418150
(State or other jurisdiction of incorporation or organization) (IRS Employer Identification No.)

30 West Superior Street
Duluth, Minnesota 55802-2093
(Address of principal executive offices)
(Zip Code)

(218) 279-5000
(Registrant’s telephone number, including area code)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer x
Accelerated Filer ¨
 
Non-Accelerated Filer ¨
Smaller Reporting Company ¨
 
Emerging Growth Company ¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  ¨ Yes   x No

Common Stock, without par value,
49,379,94550,883,123 shares outstanding
as of June 30, 2016March 31, 2017




Index
   Page
    
Definitions
3
    
Forward-Looking Statements
5
    
Part I.
Financial Information
 
    
 
Item 1.
Consolidated Financial Statements
 
    
 
Consolidated Balance Sheet -
 
  June 30, 2016March 31, 2017, and December 31, 20152016
7
    
 
Consolidated Statement of Income -
 
  Quarter and SixThree Months Ended June 30,March 31, 2017 and 2016 and 2015
8
    
 
Consolidated Statement of Comprehensive Income -
 
  Quarter and SixThree Months Ended June 30,March 31, 2017 and 2016 and 2015
9
    
 
Consolidated Statement of Cash Flows -
 
  SixThree Months Ended June 30,March 31, 2017 and 2016 and 2015
10
    
 
Consolidated Statement of Shareholders’ Equity -
 
  SixThree Months Ended June 30, 2016March 31, 2017
11
    
 
Notes to Consolidated Financial Statements
12
    
 
Item 2.
Management’s Discussion and Analysis of Financial Condition
and Results of Operations
3736
    
 
Item 3.
Quantitative and Qualitative Disclosures about Market Risk
5551
    
 
Item 4.
Controls and Procedures
5652
    
Part II.
Other Information
 
    
 
Item 1.
Legal Proceedings
5652
    
 
Item 1A.
Risk Factors
5652
    
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
5652
    
 
Item 3.
Defaults Upon Senior Securities
5652
    
 
Item 4.
Mine Safety Disclosures
5652
    
 
Item 5.
Other Information
5652
    
 
Item 6.
Exhibits
5753
    
Signatures
5854


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 AcronymTerm
AFUDCAllowance for Funds Used During Construction – the cost of both debt and equity funds used to finance utility plant additions during construction periods
ALLETEALLETE, Inc.
ALLETE Clean EnergyALLETE Clean Energy, Inc. and its subsidiaries
ALLETE PropertiesALLETE Properties, LLC and its subsidiaries
ALLETE Transmission HoldingsALLETE Transmission Holdings, Inc.
ATCAmerican Transmission Company LLC
BasinBisonBasin Electric Power CooperativeBison Wind Energy Center
BNI EnergyBNI Coal, Ltd. d/b/a BNI Energy, Inc. and its subsidiary
BoswellBoswell Energy Center
CliffsCamp RipleyCliffs Natural Resources Inc.Camp Ripley Solar Array
CO2
Carbon Dioxide
CompanyALLETE, Inc. and its subsidiaries
CSAPRCross-State Air Pollution Rule
DCDirect Current
EISEnvironmental Impact Statement
EPAUnited States Environmental Protection Agency
ERP Iron OreERP Iron Ore, LLC
ESOPEmployee Stock Ownership Plan
EssarEssar Steel Minnesota LLC
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
Form 10-KALLETE Annual Report on Form 10-K
Form 10-QALLETE Quarterly Report on Form 10-Q
GAAPGenerally Accepted Accounting Principles in the United States of America
GHGGreenhouse Gases
GNTLGreat Northern Transmission Line
IBEWInternational Brotherhood of Electrical Workers
IRPIntegrated Resource Plan
Invest DirectALLETE’s Direct Stock Purchase and Dividend Reinvestment Plan
IRPIntegrated Resource Plan
Item ___Item ___ of this Form 10-Q
kVKilovolt(s)
kW / kWhKilowatt(s) / Kilowatt-hour(s)
LaskinLaskin Energy Center
MACTMaximum Achievable Control Technology
MagnetationMagnetation, LLC
Manitoba HydroManitoba Hydro-Electric Board
MATSMercury and Air Toxics Standards
Mesabi MetallicsMesabi Metallics Company, LLC (formerly Essar Steel Minnesota, LLC)
Minnesota PowerAn operating division of ALLETE, Inc.
Minnkota PowerMinnkota Power Cooperative, Inc.
MISOMidcontinent Independent System Operator, Inc.
Montana-Dakota UtilitiesMontana-Dakota Utilities Co., a division of MDU Resources Group, Inc.
MPCAMinnesota Pollution Control Agency


Abbreviation or AcronymTerm
MPUCMinnesota Public Utilities Commission
MW / MWhMegawatt(s) / Megawatt-hour(s)
NAAQSNational Ambient Air Quality Standards
NDPSCNorth Dakota Public Service Commission
NOLNet Operating Loss
NO2
Nitrogen Dioxide
NOX
Nitrogen Oxides
Northshore MiningNorthern States PowerNorthshore MiningNorthern States Power Company, a wholly-owned subsidiary of CliffsXcel Energy Inc.
Note ___Note ___ to the Consolidated Financial Statements in this Form 10-Q
NPDESNational Pollutant Discharge Elimination System
Oliver Wind IOliver Wind I Energy Center
Oliver Wind IIOliver Wind II Energy Center
Palm Coast Park DistrictPalm Coast Park Community Development District in Florida
PolyMetPolyMet Mining Corp.
PPAPPA/PSAPower Purchase Agreement / Power Sales Agreement
PPACAPatient Protection and Affordable Care Act of 2010
PSCWPublic Service Commission of Wisconsin
SECSecurities and Exchange Commission
Shell EnergyShell Energy North America (US), L.P.
Silver Bay PowerSilver Bay Power Company, a wholly-owned subsidiary of Cliffs Natural Resources Inc.
SIPState Implementation Plan
SO2
Sulfur Dioxide
Square ButteSquare Butte Electric Cooperative, a North Dakota cooperative corporation
SWL&PSuperior Water, Light and Power Company
Taconite HarborTaconite Harbor Energy Center
ThomsonThomson Energy Center
Town Center DistrictTown Center at Palm Coast Community Development District in Florida
United TaconiteUnited Taconite LLC, a wholly-owned subsidiary of Cliffs
U.S.United States of America
U.S. Water ServicesU.S. Water Services Holding Company and its subsidiaries
USS CorporationUnited States Steel Corporation




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-Q, in presentations, on our website, in response to questions or otherwise. These statements are qualified in their entirety by reference to, and are accompanied by, the following important factors, in addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements that could cause our actual results to differ materially from those indicated in the forward-looking statements:

our ability to successfully implement our strategic objectives;
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 our 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, creditworthiness of customers, ability to obtain materials required to perform services, and changing market conditions.




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 Part 1, Item 1A under the heading “Risk Factors” beginning on page 25 of our 2015ALLETE’s 2016 Form 10-K. Any forward-lookingforward‑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-Q and in other reports filed with the SEC that attempt to identify the risks and uncertainties that may affect ALLETE’s business.


PART I.  FINANCIAL INFORMATION

ITEM 1.  CONSOLIDATED FINANCIAL STATEMENTS

ALLETE
CONSOLIDATED BALANCE SHEET
Millions – Unaudited
June 30,
2016		 December 31,
2015		March 31,
2017		 December 31,
2016
   
Millions   
Assets      
Current Assets      
Cash and Cash Equivalents
$91.9
 
$97.0

$81.8
 
$27.5
Accounts Receivable (Less Allowance of $1.5 and $1.0)113.6
 121.2
Inventories110.4
 117.1
Accounts Receivable (Less Allowance of $2.4 and $3.1)122.8
 122.5
Inventories – Net110.5
 104.2
Prepayments and Other38.4
 35.7
45.5
 40.3
Total Current Assets354.3
 371.0
360.6
 294.5
Property, Plant and Equipment – Net3,631.3
 3,669.1
3,745.3
 3,741.2
Regulatory Assets359.1
 372.0
320.9
 330.1
Investment in ATC129.0
 124.5
140.2
 135.6
Other Investments72.3
 74.6
57.7
 55.6
Goodwill and Intangible Assets – Net212.7
 215.2
212.0
 213.4
Other Non-Current Assets98.9
 68.1
105.2
 106.5
Total Assets
$4,857.6
 
$4,894.5

$4,941.9
 
$4,876.9
Liabilities and Equity   
Liabilities and Shareholders’ Equity   
Liabilities      
Current Liabilities      
Accounts Payable
$64.8
 
$88.8

$59.2
 
$74.0
Accrued Taxes37.7
 44.0
56.1
 46.5
Accrued Interest17.8
 18.6
14.8
 17.6
Long-Term Debt Due Within One Year64.5
 35.7
162.6
 187.7
Notes Payable0.9
 1.6
1.3
 —
Other85.9
 86.1
70.6
 73.7
Total Current Liabilities271.6
 274.8
364.6
 399.5
Long-Term Debt1,498.9
 1,556.7
1,370.2
 1,370.4
Deferred Income Taxes595.1
 579.8
568.6
 554.6
Regulatory Liabilities94.6
 105.0
125.0
 125.8
Defined Benefit Pension and Other Postretirement Benefit Plans204.5
 206.8
195.1
 210.9
Other Non-Current Liabilities340.8
 349.0
316.9
 322.7
Total Liabilities3,005.5
 3,072.1
2,940.4
 2,983.9
Commitments, Guarantees and Contingencies (Note 13)
 

 
Equity   
ALLETE’s Equity   
Common Stock Without Par Value, 80.0 Shares Authorized, 49.4 and 49.1 Shares Outstanding1,283.5
 1,271.4
Shareholders’ Equity   
Common Stock Without Par Value, 80.0 Shares Authorized, 50.9 and 49.6 Shares Issued and Outstanding1,381.2
 1,295.3
Accumulated Other Comprehensive Loss(24.2) (24.5)(27.7) (28.2)
Retained Earnings592.8
 573.3
648.0
 625.9
Total ALLETE Equity1,852.1
 1,820.2
Non-Controlling Interest in Subsidiaries—
 2.2
Total Equity1,852.1
 1,822.4
Total Liabilities and Equity
$4,857.6
 
$4,894.5
Total Shareholders’ Equity2,001.5
 1,893.0
Total Liabilities and Shareholders’ Equity
$4,941.9
 
$4,876.9
The accompanying notes are an integral part of these statements.


ALLETE
CONSOLIDATED STATEMENT OF INCOME
Millions Except Per Share Amounts – Unaudited
Quarter Ended Six Months EndedThree Months Ended
June 30, June 30,March 31,
20162015 2016201520172016
   
Millions Except Per Share Amounts 
Operating Revenue
$314.8

$323.3
 
$648.6

$643.3

$365.6

$333.8
Operating Expenses    
Fuel and Purchased Power78.1
80.1
 155.0
166.1
93.0
76.9
Transmission Services16.1
11.3
 32.9
26.2
16.6
16.8
Cost of Sales33.4
52.3
 66.7
83.5
35.2
33.3
Operating and Maintenance82.0
85.4
 160.1
165.1
83.3
78.1
Depreciation and Amortization48.7
41.3
 96.8
80.3
50.5
48.1
Taxes Other than Income Taxes14.3
13.4
 28.1
26.2
14.4
13.8
Total Operating Expenses272.6
283.8
 539.6
547.4
293.0
267.0
Operating Income42.2
39.5
 109.0
95.9
72.6
66.8
Other Income (Expense)    
Interest Expense(17.4)(16.2) (34.3)(31.3)(17.2)(16.9)
Equity Earnings in ATC4.1
4.7
 8.9
8.6
6.1
4.8
Other0.6
0.7
 1.6
1.8
0.6
1.0
Total Other Expense(12.7)(10.8) (23.8)(20.9)(10.5)(11.1)
Income Before Non-Controlling Interest and Income Taxes29.5
28.7
 85.2
75.0
62.1
55.7
Income Tax Expense4.7
6.4
 14.0
12.6
13.1
9.3
Net Income24.8
22.3
 71.2
62.4
49.0
46.4
Less: Non-Controlling Interest in Subsidiaries—
(0.2) 0.5
—
—
0.5
Net Income Attributable to ALLETE$24.8
$22.5
 
$70.7

$62.4

$49.0

$45.9
Average Shares of Common Stock    
Basic49.3
48.6
 49.2
47.7
50.2
49.2
Diluted49.5
48.7
 49.3
47.8
50.4
49.2
Basic Earnings Per Share of Common Stock
$0.50

$0.46
 
$1.44

$1.31

$0.97

$0.93
Diluted Earnings Per Share of Common Stock
$0.50

$0.46
 
$1.43

$1.30

$0.97

$0.93
Dividends Per Share of Common Stock
$0.52

$0.505
 
$1.04

$1.01

$0.535

$0.52
The accompanying notes are an integral part of these statements.


ALLETE
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Millions – Unaudited
 Quarter Ended Six Months Ended
 June 30, June 30,
 2016 2015 2016 2015
        
Net Income$24.8 
$22.3
 
$71.2
 
$62.4
Other Comprehensive Income       
Unrealized Gain on Securities       
Net of Income Taxes of $0.3, $–, $–, and $0.10.4
 —
 —
 0.1
Unrealized Gain on Derivatives    

 

Net of Income Taxes of $–, $0.1, $–, and $0.1—
 —
 —
 0.1
Defined Benefit Pension and Other Postretirement Benefit Plans       
Net of Income Taxes of $0.1, $0.2, $0.2, and $0.40.1
 0.4
 0.3
 0.7
Total Other Comprehensive Income0.5
 0.4
 0.3
 0.9
Total Comprehensive Income25.3
 22.7
 71.5
 63.3
Less: Non-Controlling Interest in Subsidiaries—
 (0.2) 0.5
 —
Total Comprehensive Income Attributable to ALLETE
$25.3
 
$22.9
 
$71.0
 
$63.3
 Three Months Ended
 March 31,
 2017 2016
Millions   
Net Income
$49.0
 
$46.4
Other Comprehensive Income (Loss)   
Unrealized Gain (Loss) on Securities   
Net of Income Tax Expense (Benefit) of $0.3 and $(0.3)0.3
 (0.4)
Defined Benefit Pension and Other Postretirement Benefit Plans   
Net of Income Tax Expense of $0.1 and $0.10.2
 0.2
Total Other Comprehensive Income (Loss)0.5
 (0.2)
Total Comprehensive Income49.5
 46.2
Less: Non-Controlling Interest in Subsidiaries—
 0.5
Total Comprehensive Income Attributable to ALLETE
$49.5
 
$45.7
The accompanying notes are an integral part of these statements.



ALLETE
CONSOLIDATED STATEMENT OF CASH FLOWS
Millions – Unaudited
Six Months EndedThree Months Ended
June 30,March 31,
2016 20152017 2016
   
Millions   
Operating Activities      
Net Income
$71.2
 
$62.4

$49.0
 
$46.4
Allowance for Funds Used During Construction – Equity(1.2) (1.6)
AFUDC – Equity(0.2) (0.9)
Income from Equity Investments – Net of Dividends(2.9) (2.3)(1.5) (2.9)
Gain on Sales of Investments—
 (0.1)
Change in Fair Value of Contingent Consideration(0.4) —
Loss on Sales of Property, Plant and Equipment0.1
 —
Depreciation Expense94.2
 78.7
49.2
 46.8
Amortization of Power Purchase Agreements(11.1) (11.0)
Amortization of PSAs(5.9) (5.6)
Amortization of Other Intangible Assets and Other Assets5.0
 2.9
2.9
 2.3
Deferred Income Tax Expense13.8
 12.3
13.0
 9.2
Share-Based Compensation Expense1.3
 1.3
0.7
 0.6
ESOP Compensation Expense0.9
 4.9
1.1
 —
Defined Benefit Pension and Postretirement Benefit Expense2.6
 7.7
2.5
 1.3
Bad Debt Expense1.1
 0.3
Bad Debt Expense (Recoveries)(0.4) 0.6
Changes in Operating Assets and Liabilities      
Accounts Receivable6.5
 17.3
0.1
 (4.2)
Inventories6.7
 (13.4)(6.3) 1.1
Prepayments and Other(0.8) 4.2
1.8
 0.1
Accounts Payable1.3
 (25.6)(11.3) (4.2)
Other Current Liabilities(18.5) 47.4
(1.0) 0.9
Cash Contributions to Defined Benefit Pension Plans(1.7) —
Changes in Regulatory and Other Non-Current Assets(21.0) (9.6)9.6
 2.8
Changes in Regulatory and Other Non-Current Liabilities(2.9) 6.5
(2.6) (1.1)
Cash from Operating Activities146.2
 182.3
98.7
 93.2
Investing Activities      
Proceeds from Sale of Available-for-sale Securities1.4
 0.7
0.3
 1.1
Payments for Purchase of Available-for-sale Securities(1.2) (0.8)(0.5) (0.3)
Acquisitions of Subsidiaries – Net of Cash Acquired—
 (214.4)
Investment in ATC(1.6) (0.8)(3.1) (1.2)
Changes to Other Investments2.1
 (0.4)(1.2) 0.2
Additions to Property, Plant and Equipment(74.8) (140.5)(36.7) (42.4)
Cash in Escrow for Acquisition—
 (15.0)
Proceeds from Sale of Property, Plant and Equipment0.2
 —
0.1
 —
Cash for Investing Activities(73.9) (371.2)(41.1) (42.6)
Financing Activities      
Proceeds from Issuance of Common Stock15.2
 148.2
70.6
 9.0
Proceeds from Issuance of Long-Term Debt2.2
 15.0
Changes in Restricted Cash(2.0) (2.9)(6.9) (5.8)
Changes in Notes Payable(0.7) (3.7)1.3
 (0.9)
Repayments of Long-Term Debt(32.1) (3.4)(26.3) (26.6)
Acquisition of Non-Controlling Interest(8.0) —
Acquisition-Related Contingent Consideration Payments(0.7) —
(15.1) (0.6)
Debt Issuance Costs(0.1) —
Dividends on Common Stock(51.2) (49.5)(26.9) (25.7)
Cash from (for) Financing Activities(77.4) 103.7
Cash for Financing Activities(3.3) (50.6)
Change in Cash and Cash Equivalents(5.1) (85.2)54.3
 —
Cash and Cash Equivalents at Beginning of Period97.0
 145.8
27.5
 97.0
Cash and Cash Equivalents at End of Period
$91.9
 
$60.6

$81.8
 
$97.0
The accompanying notes are an integral part of these statements.


ALLETE
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
Millions – Unaudited
Total
Equity
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Common
Stock
Non-Controlling Interest in Subsidiaries
Total Shareholders’
Equity
Retained
Earnings
Accumulated
Other
Comprehensive
Loss
Common
Stock
   
Balance as of December 31, 2015
$1,822.4

$573.3
$(24.5)
$1,271.4

$2.2
Millions   
Balance as of December 31, 2016
$1,893.0

$625.9
$(28.2)
$1,295.3
Comprehensive Income       
Net Income71.2
70.7
  0.5
49.0
49.0
—
—
Other Comprehensive Income – Net of Tax        
Defined Benefit Pension and Other Postretirement Plans – Net of Tax0.3
 0.3
 
Unrealized Gain on Securities0.3
—
0.3
—
Defined Benefit Pension and Other Postretirement Plans0.2
—
0.2
—
Total Comprehensive Income71.5
   49.5
   
Common Stock Issued17.4
  17.4
 85.9
—
—
85.9
Dividends Declared(51.2)(51.2)  (26.9)(26.9)—
—
Acquisition of Non-Controlling Interest(8.0)  (5.3)(2.7)
Balance as of June 30, 2016
$1,852.1

$592.8
$(24.2)
$1,283.5
—
Balance as of March 31, 2017
$2,001.5

$648.0
$(27.7)
$1,381.2
The accompanying notes are an integral part of these statements.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – UNAUDITED

The accompanying unaudited Consolidated Financial Statements have been prepared in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X, and do not include all of the information and notes required by GAAP for complete financial statements. Similarly, the December 31, 20152016, Consolidated Balance Sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. In management’s opinion, these unaudited financial statements include all adjustments necessary for a fair statement of financial results. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Operating results for the sixthree months ended June 30, 2016,March 31, 2017, are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 20162017. For further information, refer to the Consolidated Financial Statements and notes included in our 20152016 Form 10-K.


NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

Inventories.Inventories – Net. Inventories are stated at the lower of cost or market.net realizable value. Inventories in our Regulated Operations and ALLETE Clean Energy segments are carried at an average cost or first-in, first-out basis. Inventories in our U.S. Water Services segment and Corporate and Other segmentsoperations are carried at an average cost, first-in, first-out or specific identification basis. Fuel for generation is carried at an average cost basis. Certain other inventories, including capital spares, are carried at specific cost.
InventoriesJune 30,
2016
 December 31,
2015
Inventories – NetMarch 31,
2017
 December 31,
2016
Millions      
Fuel (a)

$49.2
 
$58.1

$48.3
 
$43.9
Materials and Supplies49.8
 49.1
49.0
 48.7
Raw Materials2.8
 2.7
2.9
 2.9
Work in Progress0.6
 —
1.4
 1.0
Finished Goods8.3
 7.5
9.9
 8.6
Reserve for Obsolescence(0.3) (0.3)(1.0) (0.9)
Total Inventories
$110.4
 
$117.1
Total Inventories – Net
$110.5
 
$104.2
(a)Fuel consists primarily of coal inventory at Minnesota Power.
Prepayments and Other Current AssetsJune 30,
2016
 December 31,
2015
Millions   
Deferred Fuel Adjustment Clause
$14.5
 
$10.6
Restricted Cash (a)
7.5
 5.6
Other16.4
 19.5
Total Prepayments and Other Current Assets
$38.4
 
$35.7
(a)Restricted Cash includes collateral deposits required under ALLETE Clean Energy’s loan agreements and cash pledged as collateral for U.S. Water Services’ standby letters of credit.

Other Non-Current Assets. As of June 30, 2016, included in Other Non-Current Assets on the Consolidated Balance Sheet was restricted cash related to collateral deposits required under ALLETE Clean Energy’s loan agreements and PPAs of $8.2 million ($8.1 million as of December 31, 2015). Also included in Other Non-Current Assets on the Consolidated Balance Sheet as of June 30, 2016, was a $31 million contract payment made to Cliffs as part of a long-term power sales agreement between Minnesota Power and Silver Bay Power. (See Note 13. Commitments, Guarantees and Contingencies.) The contract payment will be amortized over the term of the sales agreement.
Prepayments and Other Current AssetsMarch 31,
2017
 December 31,
2016
Millions   
Deferred Fuel Adjustment Clause
$18.4
 
$18.6
Restricted Cash9.1
 2.2
Other18.0
 19.5
Total Prepayments and Other Current Assets
$45.5
 
$40.3
Other Current LiabilitiesJune 30,
2016
 December 31,
2015
Millions   
Customer Deposits
$13.4
 
$15.1
Power Purchase Agreements23.9
 23.3
Other48.6
 47.7
Total Other Current Liabilities
$85.9
 
$86.1
Other Non-Current AssetsMarch 31,
2017
 December 31,
2016
Millions   
Contract Payment
$28.9
 
$29.6
Finance Receivable11.5
 11.5
Restricted Cash8.6
 8.6
Other56.2
 56.8
Total Other Non-Current Assets
$105.2
 
$106.5



NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Other Non-Current LiabilitiesJune 30,
2016
 December 31,
2015
Millions   
Asset Retirement Obligation
$135.2
 
$131.4
Power Purchase Agreements125.9
 138.1
Contingent Consideration (a)
37.3
 36.6
Other42.4
 42.9
Total Other Non-Current Liabilities
$340.8
 
$349.0
Other Current LiabilitiesMarch 31,
2017
 December 31,
2016
Millions   
PSAs
$24.6
 
$24.6
Contingent Consideration (a)
4.6
 —
Other41.4
 49.1
Total Other Current Liabilities
$70.6
 
$73.7
(a)Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 3. Acquisitions and5. Fair Value.)
Other Non-Current LiabilitiesMarch 31,
2017
 December 31,
2016
Millions   
Asset Retirement Obligation
$157.2
 
$136.6
PSAs107.6
 113.8
Contingent Consideration (a)
5.4
 25.0
Other46.7
 47.3
Total Other Non-Current Liabilities
$316.9
 
$322.7
(a)Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 5. Fair Value.)

Supplemental Statement of Cash Flows Information.
Six Months Ended June 30,2016
 2015
Three Months Ended March 31,2017
 2016
Millions      
Cash Paid During the Period for Interest – Net of Amounts Capitalized
$32.9
 
$30.0

$18.9
 
$19.6
Cash Paid During the Period for Income Taxes
$0.4
 
$1.0
Noncash Investing and Financing Activities 
  
 
  
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment$(24.4) $(25.5)$(3.5) $(25.6)
Capitalized Asset Retirement Costs
$2.3
 
$7.8

$19.3
 
$3.5
AFUDC–Equity
$1.2
 
$1.6

$0.2
 
$0.9
Contingent Consideration—
 
$35.7
ALLETE Common Stock Contributed to the Pension Plan
$13.5
 —

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

New Accounting Standards.Pronouncements.

Recently Adopted Pronouncements

Amendments toSimplifying the Consolidation Analysis.Measurement of Inventory. In February 2015, the FASB issued revised guidancean accounting standard which changesrequires entities that measure inventory using the analysis that a reporting entity must performfirst-in, first-out or average cost methods to determine whether it should consolidate certain typesmeasure inventory at the lower of legal entities. The new standard affects (1) limited partnershipscost or net realizable value. Net realizable value is defined as estimated selling price in the ordinary course of business less reasonably predictable costs of completion, disposal and similar legal entities, (2) evaluating fees paid to a decision maker or a service provider as a variable interest, (3) the effect of fee arrangements on the primary beneficiary determination, (4) the effect of related parties on the primary beneficiary determination, and (5) certain investment funds.transportation. This accounting guidance was adopted in the first quarter of 20162017 and did not have a material impact on our Consolidated Financial Statements.

Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent).Improvements to Employee Share-Based Payment Accounting. In May 2015,March 2016, the FASB issued anguidance to simplify the accounting standard update which removesfor share-based payment transactions by requiring all excess tax benefits and deficiencies to be recognized in income tax expense or benefit in earnings, thus eliminating the requirement to categorize withinclassify the fair value hierarchy all investmentsexcess tax benefit and deficiencies as additional paid-in capital. Under the new guidance, an entity makes an accounting policy election to either estimate the expected forfeiture awards or account for which fair value is measured using the net asset value per share (or its equivalent) practical expedient. The guidance applies to investments for which there is not a readily determinable fair value (market quote) or the investment is in a mutual fund without a publicly available net asset value.forfeitures as they occur. This accounting guidance was adopted in the first quarter of 2016 and did not have2017. The adoption of this guidance is expected to result in a materialless than $1 million impact on our Consolidated Financial Statements.

Presentation of Debt Issuance Costs. In April 2015, the FASB issued revised guidance addressing the presentation requirements for debt issuance costs. Under the revised guidance, all costs incurred to issue debt are to be presented on the Consolidated Balance Sheet as a direct deduction from the carrying amount of that debt liability. This guidance was adopted in the first quarter of 2016 resulting in the reclassification of unamortized debt issuance costs from Other Non-Current Assets to Long-Term Debt on the Consolidated Balance Sheet. The effect of the adoption decreased Total Assets and Total Liabilities on ALLETE's Consolidated Balance Sheet by $12.6 million as of December 31, 2015.income tax expense (benefit) annually.



NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
New Accounting StandardsPronouncements (Continued)

Clarifying the Definition of a Business. In January 2017, the FASB issued clarifying guidance on the definition of a business and provided additional guidance to assist with evaluating whether transactions are to be accounted for as an acquisition or disposal of a group of assets or a business. The clarifying guidance will also impact other areas including the accounting for goodwill and consolidation. This accounting guidance was adopted in the first quarter of 2017 and did not have an impact on our Consolidated Financial Statements.

Recently Issued Pronouncements

Simplifying the Test for Goodwill Impairment. In January 2017, the FASB issued updated guidance which simplifies the measurement of goodwill impairment by removing step two of the goodwill impairment test that requires the determination of the fair value of individual assets and liabilities of a reporting unit. The updated guidance requires goodwill impairment to be measured as the amount by which a reporting unit’s carrying value exceeds its fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. This guidance is effective for the Company beginning in the first quarter of 2020, with early adoption permitted on a prospective basis.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. In March 2017, the FASB issued guidance to improve the presentation of net periodic pension and postretirement benefit costs. Under the new guidance, an entity shall present the service cost component of the net periodic benefit cost in the same income statement line as other employee compensation costs arising from services rendered during the period. The guidance also allows only the service cost component of the periodic expense to be eligible for capitalization. The other components of net periodic expense will be presented separately from the line item that includes the service cost and will be excluded from the operating income subtotal. This accounting guidance is effective for the Company beginning in the first quarter of 2018. The adoption of this guidance by the Company is expected to result in higher operating expense and lower operating income. This guidance is not expected to have an impact on net income. We will continue to evaluate the impact of this standard on our Consolidated Financial Statements.

Revenue from Contracts with Customers. In 2014, the FASB issued amended revenue recognition guidance to clarify the principles for recognizing revenue from contracts with customers. The guidance requires an entity to recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. The guidance also requires expanded disclosures relating to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Additionally, qualitative and quantitative disclosures are required regarding customer contracts, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. The Company is considering the impact of the new guidance on its ability to recognize revenue from certain contracts where collectibility is in question and bundled sales contracts and contracts with pricing provisions that may require it to recognize revenue at prices other than the contract price (e.g., straight line or estimated future market prices). The guidance is effective for the Company beginning in the first quarter of 2018 with early adoption permitted. The Company will adopt this guidance for our fiscal year beginning January 1, 2018.

Leases. In February 2016, the FASB issued an accounting standard update which revises the existing guidance for leases. Under the revised guidance, lessees will be required to recognize a “right-of-use” asset and a lease liability for all leases with a term greater than 12 months. The new standard also requires additional quantitative and qualitative disclosures by lessees and lessors to enable users of the financial statements to assess the amount, timing and uncertainty of cash flows arising from leases. The accounting for leases by lessors and the recognition, measurement and presentation of expenses and cash flows from leases are not expected to significantly change as a result of the updated guidance. The revised guidance is effective for the Company beginning in the first quarter of 2019 with early adoption permitted. The Company isWe are currently evaluating the impact of the amended lease guidance on the Company’sour Consolidated Financial Statements.

Revenue from Contracts with Customers.Financial Instruments. In May 2014,January 2016, the FASB issued amended revenue recognition guidancean accounting standard update which requires entities to clarify the principles for recognizing revenue from contracts with customers. The guidance requires an entity tomeasure their investments at fair value and recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. The guidance also requires expanded disclosures relating to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Additionally, qualitative and quantitative disclosures are required regarding customer contracts, significant judgments andany changes in judgments, and assets recognized fromfair value in net income unless the costs to obtain or fulfill a contract.investments qualify for the new practicability exception. The practicability exception will be available for equity investments that do not have readily determinable fair values. The updated guidance is effective for the Company beginning in the first quarter of 2018 with early adoption permitted. The Company is2018. We are currently evaluating the impact that the standard will have on our Consolidated Financial Statements.




NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
New Accounting Pronouncements (Continued)

Classification of Certain Cash Receipts and Cash Payments. In August 2016, the FASB issued an accounting standard update which addresses the following eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the amended revenue recognitionborrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies (including bank-owned life insurance policies); distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. This accounting guidance onis effective for the Company beginning in the first quarter of 2018. The guidance will result in changes to the Company’s Consolidated Financial Statements.Statement of Cash Flows relating to debt prepayments, contingent consideration payments, proceeds from insurance settlements, proceeds from corporate-owned life insurance policies and distributions received from equity method investees.

Statement of Cash Flows: Restricted Cash. In November 2016, the FASB issued an accounting standard update related to the presentation of restricted cash in the Company’s Consolidated Statement of Cash Flows. The update requires that the Consolidated Statement of Cash Flows explain the change during the period in cash, cash equivalents, and restricted cash. Restricted cash should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the Consolidated Statement of Cash Flows. This accounting guidance is effective for the Company beginning in the first quarter of 2018. The Company plans to adopt this guidance for our fiscal year beginning January 1, 2018, and the guidance will result in changes to the Company’s Consolidated Statement of Cash Flows such that restricted cash amounts will be included in the beginning-of-period and end-of-period cash and cash equivalents totals.

Revision of Prior Balance Sheet. During the first quarter of 2017, the Company identified an error related to the deferred income tax treatment associated with its Wholesale and Retail Contra AFUDC Regulatory Liability. The Company evaluated the materiality of the error and concluded it was not material to any previously issued historical financial statements. The Company has revised its historical Consolidated Balance Sheet as of December 31, 2016, by decreasing Regulatory Assets and Deferred Income Taxes by $29.5 million. The correction had no impact on our Consolidated Statement of Income.


NOTE 2. INVESTMENTS

Investments. As of June 30, 2016,March 31, 2017, the investment portfolio included the legacy real estate assets of ALLETE Properties, debt and equity securities consisting primarily of securities held in other postretirement plans to fund employee benefits, the cash equivalents within these plans and other assets consisting primarily of land in Minnesota.
Other InvestmentsJune 30,
2016
 December 31,
2015
March 31,
2017
 December 31,
2016
Millions      
ALLETE Properties
$47.8
 
$50.1

$31.6
 
$31.7
Available-for-sale Securities (a)
18.4
 18.5
19.6
 18.8
Cash Equivalents2.3
 2.0
2.6
 1.3
Other3.8
 4.0
3.9
 3.8
Total Other Investments
$72.3
 
$74.6

$57.7
 
$55.6
(a)As of June 30, 2016,March 31, 2017, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $0.2 million, in one year to less than three years was $2.5$3.0 million, in three years to less than five years was $5.0 million and in five or more years was $3.3$3.9 million.

Land Inventory. Land inventory is accounted for as held for use and is recorded at cost, unless the carrying value is determined not to be recoverable in accordance with the accounting standards for property, plant and equipment, in which case the land inventory is written down to estimated fair value. Land values are reviewed for indicators of impairment on a quarterly basis and no impairments wereimpairment was recorded for the quarter and sixthree months ended June 30,March 31, 2017, and 2016.

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

Gross realized and unrealized gains and losses on our available-for-sale investments were immaterial for the three months ended March 31, 2017, and 2016.


NOTE 3. ACQUISITIONS

The following acquisitions below are consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services businesses to complement its core regulated utility,businesses, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth. The pro forma impact of the following acquisitions was not significant, either individually or in the aggregate, to the results of the Company for the sixthree months ended June 30, 2016 and 2015.March 31, 2016.

2016 Activity.

Acquisition of Non-Controlling Interest. OnIn April 15, 2016, ALLETE Clean Energy acquired the non-controlling interest in the limited liability company that owns itsthe Condon wind energy facility for $8.0 million. This transaction was accounted for as an equity transaction, and no gain or loss was recognized in net income or other comprehensive income. As a result of the acquisition, the Condon wind energy facility is now a wholly-owned subsidiary of ALLETE Clean Energy.

2015 Activity.

WEST. In October 2016, U.S. Water Services. In February 2015, ALLETEServices acquired U.S.100 percent of Water Services.& Energy Systems Technology of Nevada, Inc. (WEST). Total consideration for the transaction was $202.3$6.5 million, which included paymentsubject to a working capital adjustment. Consideration of $166.6$5.9 million was paid in cash and an estimated fair value of earnings-based contingent consideration of $35.7 million, as estimated at the date of acquisition, to be paid through 2019. The contingent consideration is presented within Other Non-Current Liabilities on the Consolidated Balance Sheet. The Consolidated Statement of Income reflects 100 percent of the results of operations for U.S. Water Services since the acquisition date as the Company hasand a $0.6 million payment is due in April 2018. WEST is an integrated water management company and was acquired 100 percent ofto expand U.S. Water Services.Services’ regional footprint in the Southwestern United States.

The acquisition was accounted for as a business combination and the purchase price was allocated based on the preliminary estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalized in 2015, is reflectedacquisition, as shown in the following table. The allocation of the purchase price is subject to judgment and the preliminary estimated fair value of the assets acquired and the liabilities assumed may be adjusted when the valuation analysis is complete in subsequent periods. Preliminary estimates subject to adjustment in subsequent periods relate primarily to working capital; subsequent adjustments could impact the amount of goodwill recorded. Fair value measurements were valued primarily using the discounted cash flow method.method and replacement cost basis.
Millions 
Assets Acquired 
Cash and Cash Equivalents
$0.90.1
Accounts ReceivableOther Current Assets16.81.1
InventoriesCustomer Relationships (a)
13.4
Other Current Assets (b)
5.3
Property, Plant and Equipment10.6
Intangible Assets (c)
83.02.8
Goodwill (d)(a)(b)
122.93.9
Other Non-Current Assets0.20.1
Total Assets Acquired
$253.18.0
Liabilities Assumed 
Current Liabilities
$19.20.2
Non-Current Liabilities31.61.2
Total Liabilities Assumed
$50.81.4
Net Identifiable Assets Acquired
$202.36.6
(a)Included in Inventories was $2.7 million of fair value adjustments relating to work in progress and finished goods inventories which were recognized as Cost of SalesPresented within one year from the acquisition date.
(b)Included in Other Current Assets was $1.6 million relating to the fair value of sales backlog. Sales backlog was recognized as Cost of Sales within one year from the acquisition date. Also included in Other Current Assets was restricted cash of $2.1 million relating to cash pledged as collateral for standby letters of credit.
(c)Intangible Assets include customer relationships, patents, non-compete agreements, and trademarks and trade names. (See Note 4. Goodwill and Intangible Assets.)
(d)For tax purposes,Assets – Net on the purchase price allocation resulted in $2.9 million of deductible goodwill.

Acquisition-related costs of $3.0 million after-tax were expensed as incurred during the first quarter of 2015 and recorded in Operating and Maintenance on the Consolidated Statement of Income.


NOTE 3. ACQUISITIONS (Continued)
2015 Activity (Continued)

Chanarambie/Viking. In April 2015, ALLETE Clean Energy acquired 100 percent of wind energy facilities in southern Minnesota (Chanarambie/Viking) from EDF Renewable Energy, Inc. for $48.0 million.

The facilities have 97.5 MW of generating capability and are located near ALLETE Clean Energy’s Lake Benton facility. The wind energy facilities began commercial operations in 2003 and have PPAs in place for their entire output, which expire in 2018 (12 MW) and 2023 (85.5 MW).

The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalized in 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method.
Millions
Assets Acquired
Current Assets
$4.8
Property, Plant and Equipment103.0
Other Non-Current Assets (a)
1.0
Total Assets Acquired
$108.8
Liabilities Assumed
Current Liabilities (b)

$6.7
Power Purchase Agreements49.0
Non-Current Liabilities5.1
Total Liabilities Assumed
$60.8
Net Identifiable Assets Acquired
$48.0
(a)Included in Other Non-Current Assets was $0.3 million of goodwill. For tax purposes, the purchase price allocation resulted in no allocation to goodwill.
(b)Current Liabilities included $5.9 million related to the current portion of PPAs.

Acquisition-related costs of $0.2 million after-tax were expensed as incurred during the second quarter of 2015 and recorded in Operating and Maintenance on the Consolidated Statement of Income.

Armenia Mountain. In July 2015, ALLETE Clean Energy acquired 100 percent of a wind energy facility located near Troy, Pennsylvania (Armenia Mountain) from The AES Corporation (AES) and a minority shareholder for $111.1 million, plus the assumption of existing debt.

The facility has 100.5 MW of generating capability, began commercial operations in 2009, and has PPAs in place for its entire output, which expire in 2024.

The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalized in 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method.


NOTE 3. ACQUISITIONS (Continued)
2015 Activity (Continued)
Millions
Assets Acquired
Current Assets (a)
$9.0
Property, Plant and Equipment156.2
Other Non-Current Assets (b)
14.4
Total Assets Acquired
$179.6
Liabilities Assumed
Current Liabilities
$2.9
Long-Term Debt Due Within One Year5.9
Long-Term Debt55.0
Other Non-Current Liabilities4.7
Total Liabilities Assumed$68.5
Net Identifiable Assets Acquired
$111.1
(a)Included in Current Assets was $1.0 million related to the current portion of PPAs and $6.0 million of restricted cash related to collateral deposits required under its loan agreement.
(b)Included in Other Non-Current Assets was $8.2 million related to the non-current portion of PPAs, $6.1 million of restricted cash related to collateral deposits required under its loan agreements, and an immaterial amount of goodwill. For tax purposes, the purchase price allocation resulted in no allocation to goodwill.

Acquisition-related costs of $1.6 million after-tax were expensed as incurred throughout the second and third quarters of 2015, and recorded in Operating and Maintenance on the Consolidated Statement of Income.

A and W Technologies. In November 2015, U.S. Water Services acquired 100 percent of A and W Technologies, Inc. (AWT). Total consideration for the transaction was $9.3 million, which included payment of $8.3 million in cash and a $1.0 million payment due in April 2017. AWT, similar to U.S. Water Services, is an integrated water management company and was acquired to expand U.S. Water Services’ regional footprint in the Southeastern United States.

The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalized in 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method.
Millions
Assets Acquired
Current Assets$1.0
Property, Plant and Equipment0.1
Intangible Assets (a)
3.9
Goodwill (b)
4.4
Total Assets Acquired
$9.4
Liabilities Assumed
Current Liabilities
$0.1
Total Liabilities Assumed$0.1
Net Identifiable Assets Acquired
$9.3
(a)Intangible Assets include customer relationships and non-compete agreements.Consolidated Balance Sheet. (See Note 4. Goodwill and Intangible Assets.)
(b)For tax purposes, the purchase price allocation resulted in $4.4 million of deductibleno allocation to goodwill.

Acquisition-related costs were immaterial, expensed as incurred during the fourth quarter of 20152016 and recorded in Operating and Maintenance on the Consolidated Statement of Income.




NOTE 4. GOODWILL AND INTANGIBLE ASSETS

The aggregate carrying amount of goodwill was $130.6$131.2 million as of June 30, 2016,March 31, 2017, and December 31, 2015.2016. There have been no changes to goodwill by reportable segment for the sixthree months ended June 30, 2016.March 31, 2017.

Balances of intangible assets, net, excluding goodwill as of June 30, 2016,March 31, 2017, are as follows:
December 31,
2015
  Amortization June 30,
2016
December 31,
2016
 AmortizationMarch 31,
2017
Millions      
Intangible Assets      
Definite-Lived Intangible Assets      
Customer Relationships$60.8 $(2.1) 
$58.7
$59.3$(1.1)
$58.2
Developed Technology and Other (a)
7.2 (0.4) 6.8
6.3(0.3)6.0
Total Definite-Lived Intangible Assets68.0
 (2.5) 65.5
65.6
(1.4)64.2
Indefinite-Lived Intangible Assets      
Trademarks and Trade Names16.6
 n/a 16.6
16.6
n/a16.6
Total Intangible Assets
$84.6
 $(2.5) 
$82.1

$82.2
$(1.4)
$80.8
(a)Developed Technology and Other includes patents, non-compete agreements and land easements.

Customer relationships have a remaining useful life of approximately 2221 years, and developed technology and other have remaining useful lives ranging from approximately 32 years to approximately 1312 years (weighted average of approximately 8 years). The weighted average remaining useful life of all definite-lived intangible assets as of June 30, 2016,March 31, 2017, is approximately 20 years.

Amortization expense of intangible assets was $1.4 million for the sixthree months ended June 30, 2016, was $2.5 million.March 31, 2017 ($1.3 million for the three months ended March 31, 2016). Accumulated amortization was $6.6$10.7 million as of June 30, 2016March 31, 2017 ($4.19.3 million as of December 31, 2015)2016). The estimated amortization expense for definite-liveddefinite‑lived intangible assets for the remainder of 20162017 is $2.6$4.1 million. Estimated annual amortization expense for definite-liveddefinite‑lived intangible assets is $5.0 million in 2017, $4.7$5.1 million in 2018, $4.8 million in 2019, $4.5 million in 2020, $4.4 million in 2019, $4.2 million in 20202021 and $44.6$41.3 million thereafter.


NOTE 5. FAIR VALUE

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Descriptions of the three levels of the fair value hierarchy are discussed in Note 10.9. Fair Value to the Consolidated Financial Statements in our 20152016 Form 10-K.

The following tables set forth by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2016March 31, 2017, and December 31, 20152016. Each asset and liability is classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of these assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of Cash and Cash Equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore is excluded from the recurring fair value measures in the following tables.


NOTE 5. FAIR VALUE (Continued)
Fair Value as of June 30, 2016Fair Value as of March 31, 2017
Recurring Fair Value MeasuresLevel 1
 Level 2
 Level 3
 Total
Level 1
 Level 2
 Level 3
 Total
Millions              
Assets              
Investments (a)
              
Available-for-sale – Equity Securities
$7.4
 —
 —
 
$7.4

$7.5
 —
 —
 
$7.5
Available-for-sale – Corporate Debt Securities—
 
$11.0
 —
 11.0
Available-for-sale – Corporate and Governmental Debt Securities—
 
$12.1
 —
 12.1
Cash Equivalents2.3
 —
 —
 2.3
2.6
 —
 —
 2.6
Total Fair Value of Assets
$9.7
 
$11.0
 —
 
$20.7

$10.1
 
$12.1
 —
 
$22.2
              
Liabilities (b)
              
Deferred Compensation—
 
$15.9
 —
 
$15.9
—
 
$17.2
 —
 
$17.2
U.S. Water Services Contingent Consideration—
 —
 
$37.3
 37.3
—
 —
 
$10.0
 10.0
Total Fair Value of Liabilities—
 
$15.9
 
$37.3
 
$53.2
—
 
$17.2
 
$10.0
 
$27.2
Total Net Fair Value of Assets (Liabilities)
$9.7
 $(4.9) $(37.3) $(32.5)
$10.1
 $(5.1) $(10.0) $(5.0)
(a)Included in Other Investments on the Consolidated Balance Sheet.
(b)Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.Sheet with the exception of the current portion of the U.S. Water Services Contingent Consideration which is included in Other Current Liabilities. (See Note 1. Operations and Significant Accounting Policies.)
Fair Value as of December 31, 2015Fair Value as of December 31, 2016
Recurring Fair Value MeasuresLevel 1
 Level 2
 Level 3
 Total
Level 1
 Level 2
 Level 3
 Total
Millions              
Assets              
Investments (a)
              
Available-for-sale – Equity Securities
$7.6
 —
 —
 
$7.6

$7.1
 —
 —
 
$7.1
Available-for-sale – Corporate Debt Securities—
 
$10.9
 —
 10.9
Available-for-sale – Corporate and Governmental Debt Securities—
 
$11.7
 —
 11.7
Cash Equivalents2.0
 —
 —
 2.0
1.3
 —
 —
 1.3
Total Fair Value of Assets
$9.6
 
$10.9
 —
 
$20.5

$8.4
 
$11.7
 —
 
$20.1
              
Liabilities (b)
              
Deferred Compensation—
 
$16.1
 —
 
$16.1
—
 
$16.0
 —
 
$16.0
U.S. Water Services Contingent Consideration—
 —
 
$36.6
 36.6
—
 —
 
$25.0
 25.0
Total Fair Value of Liabilities—
 
$16.1
 
$36.6
 
$52.7
—
 
$16.0
 
$25.0
 
$41.0
Total Net Fair Value of Assets (Liabilities)
$9.6
 $(5.2) $(36.6) $(32.2)
$8.4
 $(4.3) $(25.0) $(20.9)
(a)Included in Other Investments on the Consolidated Balance Sheet.
(b)Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.

The Level 3 activityliability in the preceding tables is the result of the February 2015 acquisition of U.S. Water Services. Changes in the U.S. Water Services Contingent Consideration can result from changes in discount rates, timing of milestones that trigger payment, and the timing and amount of earnings estimates. The following table provides a reconciliation of the beginning and ending balances of the U.S. Water Services Contingent Consideration measured at fair value using Level 3 measurements as of March 31, 2017. Management analyzes the fair value of U.S. Water Services’ Contingent Consideration for the six months ended June 30, 2016, are primarily due to accretion expense.contingent liability on a quarterly basis and makes adjustments as appropriate.


NOTE 5. FAIR VALUE (Continued)
Recurring Fair Value Measures
Activity in Level 3
Millions
Balance as of December 31, 2016
$25.0
Accretion0.5
Payments (a)
(15.1)
Changes in Cash Flow Projections (b)
(0.4)
Balance as of March 31, 2017
$10.0
(a)Payments relate to retirement of U.S. Water Services former employees.
(b)Changes in cash flow projections reflect the impact of a modification to the shareholder agreement in the first quarter of 2017 which provided participants a one-time election to sell shares at a determined price. Participants representing approximately half of the outstanding contingent consideration shares made the election, which were paid in April 2017, resulting in $4.6 million of the U.S. Water Services Contingent Consideration liability being classified in Other Current Liabilities on the Consolidated Balance Sheet. The remaining liability will be paid through the first quarter of 2019.

For the sixthree months ended June 30, 2016,March 31, 2017, and the year ended December 31, 2015,2016, there were no transfers in or out of Levels 1, 2 or 3.

Fair Value of Financial Instruments. With the exception of the item listed in the following table, below, the estimated fair value of all financial instruments approximates the carrying amount. The fair value for the item listed belowin the following table was based on quoted market prices for the same or similar instruments (Level 2).
Financial InstrumentsCarrying Amount Fair Value
Millions   
Long-Term Debt, Including Long-Term Debt Due Within One Year   
June 30, 2016$1,575.2 $1,647.6
December 31, 2015$1,605.0 $1,676.0



NOTE 5. FAIR VALUE (Continued)
Financial InstrumentsCarrying Amount Fair Value
Millions   
Long-Term Debt, Including Long-Term Debt Due Within One Year   
March 31, 2017$1,543.4 $1,614.9
December 31, 2016$1,569.1 $1,653.8

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis. Non-financial assets such as equity method investments, goodwill, intangible assets, and property, plant and equipment are measured at fair value when there is an indicator of impairment and recorded at fair value only when an impairment is recognized. For the sixthree months ended June 30, 2016,March 31, 2017, and the year ended December 31, 2015,2016, there were no triggering events or indicators of impairment for these non-financial assets.


NOTE 6. REGULATORY MATTERS

Regulatory matters are summarized in Note 5.4. Regulatory Matters to our Consolidated Financial Statements in our 20152016 Form 10-K,10‑K, with additional disclosure provided in the following paragraphs.

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

2010 Minnesota General 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 order, and asAs authorized by the MPUC, Minnesota Power also recognizes revenue under cost recovery riders for environmental,transmission, renewable and transmission investments.environmental investments and expenditures. (See Transmission Cost Recovery Rider, Renewable Cost Recovery Rider and Boswell Mercury Emissions Reduction Plan Environmental Improvement Rider.) Revenue from cost recovery riders was $48.9$24.2 million for the sixthree months ended June 30, 2016March 31, 2017 ($44.925.4 million for the sixthree months ended June 30, 2015)March 31, 2016).



NOTE 6. REGULATORY MATTERS (Continued)
Electric Rates (Continued)

2016 Minnesota General Rate Case. In November 2016, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 9 percent for retail customers. The rate filing seeks a return on equity of 10.25 percent and a 53.8 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $55 million in additional revenue. In December 2016, Minnesota Power filed a request to modify its original interim rate proposal reducing its requested interim rate increase to $34.7 million from the original request of approximately $49 million due to a change in its electric sales forecast. In December 2016 orders, the MPUC accepted the November 2016 filing as complete and authorized an annual interim rate increase of $34.7 million beginning January 1, 2017.

On February 23, 2017, Minnesota Power filed an additional request to further reduce its requested interim rate increase. In an order dated April 13, 2017, the MPUC approved Minnesota Power’s updated retail rate request resulting in a reduction in the annual interim rate increase to $32.2 million beginning May 1, 2017. On February 28, 2017, Minnesota Power filed an update to its rate increase request, reducing its requested final retail rate increase from approximately $55 million to approximately $39 million on an annualized basis. As of March 31, 2017, Minnesota Power has not received any indication that a refund of interim rates will be necessary. Management will continue to evaluate the need for a reserve for interim rates as the 2016 general rate case proceeds.

As part of the 2016 Minnesota general rate request and through Minnesota Power’s 2017 remaining life depreciation petition filed on February 1, 2017, Minnesota Power is seeking an extension of the recovery period for Boswell to better reflect recent environmental investments at the facility and mitigate rate increases for our customers. If approved, annual depreciation expense will be reduced by approximately $25 million. If the requested recovery period extension is not approved, we would expect final rates to be increased by a similar amount, subject to regulatory approval. We cannot predict the level of final rates that may be authorized by the MPUC.

Energy-Intensive Trade-Exposed (EITE) Customer Rates. The state of Minnesota Legislature enacted an EITE customer ratemaking law in June 2015 which established that it is the energy policy of the state to have competitive rates for certain industries such as mining and forest products. In November 2015, Minnesota Power filed a rate schedule petition with the MPUC for EITE customers and a corresponding rider for EITE cost recovery with the MPUC. The rate proposal was revenue and cash flow neutral to Minnesota Power.recovery. In ana March 2016 order, dated March 23, 2016, the MPUC dismissed the petition without prejudice, providing Minnesota Power the option to refile the petition with additional information or file a new petition. OnIn June 30, 2016, Minnesota Power filed a revised EITE petition with the MPUC which includesincluded additional information on the net benefits analysis, limits on eligible customers and term lengths for the EITE discount. The MPUC approved a reduction in rates for EITE customers in a December 2016 order and subsequently approved cost recovery in an order dated April 20, 2017. The rate adjustments are revenue and cash flow neutral to Minnesota Power.

FERC-Approved Wholesale Rates. Minnesota Power has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a wholesale customer of Minnesota Power. All of the wholesale contracts include a termination clause requiring a three-year notice to terminate.

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. No termination notice may be given for this contract prior to June 30, 2025. The electric service agreements with SWL&P and one otheranother municipal customer are effective through January 31, 2020 and June 30, 2019.2019, respectively. Under the agreement with SWL&P, no termination notice may be given prior to April 30, 2017. The other municipal customer provided termination notice for its contract in June 2016. Minnesota Power currently provides approximately 29 MW of average monthly demand to this customer. The rates included in these three 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. No termination notices may be given prior to December 31, 2021. 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 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 will also be determined using a cost-based formula methodology.

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. Under the agreement with SWL&P, no termination notice may be given prior to July 31, 2016. The remaining 14 municipal customers may not give termination notices prior to December 31, 2021.



NOTE 6. REGULATORY MATTERS (Continued)

2016 Wisconsin Rate Case.SWL&P’s current retail rates are based on a 2012 PSCW retail rate order, effective January 1, 2013, that allows for a 10.9 percent return on common equity. On June 28, 2016, SWL&P filed a rate increase request with the PSCW requesting an average overall increase of 3.1 percent for retail customers (a 3.5 percent increase in electric rates, a 1.3 percent decrease in natural gas rates and a 7.8 percent increase in water rates). The rate filing seeks an overall return on equity of 10.9 percent, based on a capital structure consisting of approximately 55 percent equity and 45 percent debt. On an annualized basis, the requested rate increase would generate approximately $2.7 million in additional revenue. Hearings are expected to be scheduled in late 2016. The Company anticipates new rates will take effect during the first quarter of 2017. We cannot predict the level of rates that may be approved by the PSCW.Electric Rates (Continued)

Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. In ana February 2016 order, dated February 3, 2016, the MPUC approved Minnesota Power’s updated customer billing factorrates 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 in June 2015, the project is eligible for cost recovery under the existing transmission cost recovery rider. Minnesota Power is funding the construction of the GNTL with Manitoba Hydro (see Great Northern Transmission Line), and 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.cost recovery filings.

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 and the restoration and repair of Thomson. Updated customer billing rates for the renewable cost recovery rider were approved by the MPUC in ana December 2016 order, dated March 9, 2016, allowingwhich allows Minnesota Power to charge retail customers on a current basis for the costs of constructing certain renewable investments plus a return on the capital invested. While approvingThe approval is on a provisional basis pending the updated customer billing rates for the renewable cost recovery rider,outcome of Minnesota Power’s 2016 general rate case. (See 2016 Minnesota General Rate Case.)

In a November 2016 order, the MPUC also alloweddirected Minnesota Power additional time to submit support for its position on its utilization ofattribute all North Dakota investment tax credits.credits realized from Bison to Minnesota Power regulated retail customers. As a result of the adverse regulatory outcome, Minnesota Power recorded a regulatory liability and a reduction in operating revenue of $15.0 million in 2016. The North Dakota investment tax credits previously recognized as income tax credits in Corporate and Other were reversed in 2016 resulting in an $8.8 million charge to net income for the year ended December 31, 2016. In December 2016, Minnesota Power submitted a request for reconsideration with the MPUC. In an order dated February 14, 2017, the MPUC decided to reconsider its November 2016 order and requested comments by June 30, 2017.

Prior to the November 2016 MPUC order, Minnesota Power accountsaccounted for North Dakota investment tax credits based on long-standingthe long‑standing regulatory precedents of stand-alone allocation methodology of accounting for income taxes. The stand-alone method provides that income taxes (and credits) are calculated as if Minnesota Power was the only entity included in ALLETE’s consolidated federal and unitary state income tax returns. Minnesota Power hashad recorded a regulatory liability for North Dakota investment tax credits generated by its jurisdictional activity and expected to be realized in the future. North Dakota investment tax credits attributable to ALLETE’s apportionment and income of ALLETE’s other subsidiaries arewere included in the ALLETE consolidated group. The

Minnesota DepartmentPower also has approval for current cost recovery of Commerce (Department)investments and expenditures related to compliance with the Minnesota Solar Energy Standard. (See Minnesota Solar Energy Standard.) Currently, there is no approved customer billing rate for solar costs.

Environmental Improvement Rider. Minnesota Power has inquired about our usean approved environmental improvement rider in place for investments and expenditures related to the implementation of the North Dakota investment tax credits, takingBoswell Unit 4 mercury emissions reduction plan completed in 2015. Updated customer billing rates for the position that all North Dakota investment tax credits generated fromenvironmental improvement rider were approved by the Bison Wind Energy Center should be credited to Minnesota Power ratepayers. The MPUC did not come toin a decision on this issueDecember 2016 order; however, in itsan order dated March 9, 2016, but requested that22, 2017, the MPUC approved a request by Minnesota Power provide further support onto delay implementation of the updated rates until resolution of its position which was submitted on April 8, 2016. On April 22, 2016 the Department submitted additional comments restating its position that the tax credits should be credited to ratepayers.

The amount of North Dakota investment tax credits recognized by ALLETE as of June 30, general rate case. (See 2016 total approximately $8 million, which represents the amount of North Dakota investment tax credits that the Department believes should be refunded to ratepayers. Minnesota Power will appropriately consider all avenues of appeal should an adverse decision be issued by the MPUC.General Rate Case.)

Annual Automatic Adjustment (AAA)2016 Wisconsin General Rate Case.SWL&P’s current retail rates are based on a 2012 PSCW retail rate order that allows for a 10.9 percent return on common equity. In June 2016, SWL&P filed a rate increase request with the PSCW requesting an average increase of Charges. In3.1 percent for retail customers (3.5 percent increase in electric rates; 1.3 percent decrease in natural gas rates; and 7.8 percent increase in water rates). The filing seeks an order dated June 2, 2016,overall return on equity of 10.9 percent and a 55 percent equity ratio. On an annualized basis, the MPUC approved Minnesota Power’s AAA filings made in 2012 and 2013, and deferred action for 90 days on the AAA filing made in 2014 pending review and confirmation of coal transportation costs and terms of service. Minnesota Power’s AAA filings made in 2014 and 2015 are pending MPUC approval, and representrequested rate increase would generate approximately $350$2.7 million in retail fuel cost recovery collected, but subject to refund. Minnesota Power currently expects full recovery of amounts represented by each AAA filing, although weadditional revenue. The Company anticipates new rates will take effect in mid-2017. We cannot predict the outcomelevel of rates that may be approved by the MPUC’s review of our pending filings.PSCW.



NOTE 6.  REGULATORY MATTERS (Continued)

Integrated Resource Plan (IRP).Plan. 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 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. In September 2015, Minnesota Power filed its 2015 IRP with the MPUC which includesincluded an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. The 2015 IRP also containscontained the next steps in Minnesota Power’s EnergyForward plan including the economic idling of Taconite Harbor Units 1 and 2 which occurred in the fall ofSeptember 2016, the ceasing of coal-fired operations at Taconite Harbor in 2020, and the addition of between 200 MW and 300 MW of natural gas-fired generation in the next decade.



NOTE 6. REGULATORY MATTERS (Continued)
Integrated Resource Plan (Continued)

In ana July 2016 order, dated July 18, 2016, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The order accepts Minnesota Power’s plans for Taconite Harbor, directs Minnesota Power to retire Boswell Units 1 and 2 no later than 2022, requires an analysis of generation and demand response alternatives to be filed with a natural gas resource proposal, and requires Minnesota Power to conduct request for proposals for additional wind, solar and demand response resource additions subject to further MPUC approvals. In October 2016, Minnesota Power announced Boswell Units 1 and 2 will be retired in 2018 as the latest step in its EnergyForward strategic plan. Minnesota Power’s next IRP must be filed by February 1, 2018.

Boswell Mercury Emissions Reduction Plan. Minnesota Power has an approved environmental improvement rider in place for investments and expenditures related to the implementation of the Boswell Unit 4 mercury emissions reduction plan completed in 2015. Customer billing rates for the environmental improvement rider were approved by the MPUC in August 2015. In September 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. In November 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.

Great Northern Transmission Line (GNTL). Minnesota Power and Manitoba Hydro have proposed construction of the GNTL, an approximately 220-mile 500 kV500-kV transmission line between Manitoba and Minnesota’s Iron Range. The GNTL is subject to various federal and state regulatory approvals. In October 2013,2015, a certificate of need application was filed with the MPUC which was approved in a June 2015 order.by the MPUC. 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 factorcost recovery filings. (See Transmission Cost Recovery Rider.) In a December 2015, order, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In an 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 an2016 order, dated April 11, 2016, the MPUC approved the route permit for the GNTL which largely follows Minnesota Power’s preferred route, including the international border crossing. A final decision on the presidential permit bycrossing, and in November 2016, the U.S. Department of Energy issued a presidential permit to cross the U.S.-Canadian border, which was the final major regulatory approval needed before construction in the U.S. could begin. Site clearing and pre-construction activities commenced in the first quarter of 2017 with construction expected 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, of which Minnesota Power’s portion is expected to be between $300 million and $350 million; the difference will be recovered from a subsidiary of Manitoba Hydro as contributions in the third quarteraid of 2016. construction. Total project costs of $56.8 million have been incurred through March 31, 2017, of which $29.6 million has been recovered from a subsidiary of Manitoba Hydro.

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.

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.On June 1, 2016, Minnesota Power submitted its CIP triennial filing for 2017 through 2019 with the Minnesota Department of Commerce, which outlines Minnesota Power’s CIP spending and energy-saving goals for 2017 through 2019. A decision on the CIP triennial filing by the Minnesota Department of Commerce is expected in the fourth quarter of 2016.

On April 1, 2016, Minnesota Power submitted its 2015 CIP consolidated filing, which detailed Minnesota Power’s CIP program results and requested a CIP financial incentive of $7.5 million based upon MPUC procedures. In an order dated July 19, 2016, the MPUC approved Minnesota Power’s CIP consolidated filing, including the requested CIP financial incentive. CIP financial incentives are recognized in the period in which the MPUC approves the filing.



NOTE 6. 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 and ATC, to 9.15 percent. In December 2015, a federal administrative law judge ruled on the November 2013 complaint proposing a reduction in the base return on equity to 10.32 percent, subject to approval or adjustment by the FERC. A final decision from10.82 percent including an incentive adder for participation in a regional transmission organization. In September 2016, the FERC onissued an order affirming the administrative law judge’s recommendation is expected in 2016.recommendation.

In February 2015, an additional complaint was filed with the FERC seeking an order to further reduce the base return on equity to 8.67 percent. OnIn June 30, 2016, a federal administrative law judge ruled on the February 2015additional complaint proposing a further reduction in the base return on equity to 9.70 percent, or 10.20 percent including an incentive adder for participation in a regional transmission organization, subject to approval or adjustment by the FERC. A final decision from the FERC on the administrative law judge’s recommendation is expected in 2017. On January 6, 2015,The final decision from the FERC approved an incentive adder of upis not expected to 50 basis pointshave a material impact on the allowed base return on equity for our participation in a regional transmission organization, subject to the outcome of the return on equity complaints.Consolidated Financial Statements.

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 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 kW or less. Minnesota Power has two completed solar projects and another solar project is under development. In August 2015, Minnesota Power filed for MPUC approval of a 10 MW utility scale solar project at the Camp Ripley a Minnesota Army National Guard base and training facility near Little Falls, Minnesota. In ana February 2016 order, dated February 24, 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.which was subsequently finalized by the MPUC in a December 2016 order. Camp Ripley was completed in the fourth quarter of 2016. In September 2015, Minnesota Power filed for MPUC approval of a community solar garden project in Duluth,northeastern Minnesota, which is comprised of a 1 MW solar array to be owned and operated by a third party with the output purchased by Minnesota Power and a 40 kW solar array that will beis owned and operated by Minnesota Power. In ana July 2016 order, dated July 27, 2016, the MPUC approved the community solar garden project and cost recovery, subject to certain compliance requirements. Minnesota Power believes these projects will meet approximately one-third of the overall mandate. Additionally, on June 1, 2016,in an order dated February 10, 2017, the MPUC approved Minnesota Power filed aPower’s proposal with the MPUC to increase the amount of solar rebates available for customer-sited solar installations and recover costs of the program through Minnesota Power’s renewable cost recovery rider. If approved, Minnesota Power expects the projectsThis proposal to incentivize customer-sited solar installations is expected to meet parta portion of the required mandate related to solar photovoltaic devices with a nameplate capacity of 20 kW or less.


NOTE 6. REGULATORY MATTERS (Continued)

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


NOTE 6. REGULATORY MATTERS (Continued)
Regulatory Assets and LiabilitiesJune 30,
2016
 December 31,
2015
March 31,
2017
 December 31,
2016
Millions      
Current Regulatory Assets (a)
      
Deferred Fuel Adjustment Clause
$14.5
 
$10.6

$18.4
 
$18.6
Total Current Regulatory Assets14.5
 10.6
18.4
 18.6
Non-Current Regulatory Assets      
Defined Benefit Pension and Other Postretirement Benefit Plans (b)
215.0
 219.3
224.1
 226.1
Income Taxes (c)(a)
64.7
 64.2
34.6
 33.8
Cost Recovery Riders (d)
47.2
 58.0
Asset Retirement Obligations (e)
23.5
 21.6
Asset Retirement Obligations27.1
 26.0
Cost Recovery Riders20.1
 30.5
PPACA Income Tax Deferral5.0
 5.0
5.0
 5.0
Other3.7
 3.9
10.0
 8.7
Total Non-Current Regulatory Assets359.1
 372.0
320.9
 330.1
Total Regulatory Assets
$373.6
 
$382.6

$339.3
 
$348.7
      
Non-Current Regulatory Liabilities      
Wholesale and Retail Contra AFUDC (f)

$57.0
 
$58.0

$56.8
 
$56.8
North Dakota Investment Tax Credits27.4
 28.2
Income Taxes (c)
19.2
 19.1
Plant Removal Obligations14.4
 22.1
18.9
 19.1
Income Taxes (c)
5.4
 6.1
Defined Benefit Pension and Other Postretirement Benefit Plans (b)
—
 0.9
Other17.8
 17.9
2.7
 2.6
Total Non-Current Regulatory Liabilities
$94.6
 
$105.0

$125.0
 
$125.8
(a)Current regulatory assets are included in PrepaymentsSee Note 1. Operations and Other on the ConsolidatedSignificant Accounting Policies – Revision of Prior Balance Sheet.
(b)Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income as actuarial gains and losses as well as prior service costs and credits, are recognized as regulatory assets or regulatory liabilities on the Consolidated Balance Sheet. The asset or liability will decrease as the deferred items are amortized and recognized as components of net periodic benefit cost. (See Note 12. Pension and Other Postretirement Benefit Plans.)
(c)These assets and liabilities are offsets to deferred income taxes recognized on certain regulatory temporary differences, which will reverse over the remaining lives of those temporary differences.
(d)The cost recovery rider regulatory assets are revenues not yet collected from our customers primarily due to capital expenditures related to the Bison Wind Energy Center, investment in CapX2020 projects, and the Boswell Unit 4 environmental upgrade and are recognized in accordance with the accounting standards for alternative revenue programs. The cost recovery rider regulatory assets as of June 30, 2016, will be recovered over the next two years.
(e)Asset retirement obligations will accrete and be amortized over the lives of the related property with asset retirement obligations.
(f)Wholesale and Retail Contra AFUDC represents the regulatory offset to AFUDC Equity and Debt recorded during the construction period of our cost recovery rider projects prior to placing the projects in service. The regulatory liability will decrease over the remaining depreciable life of the related asset.


NOTE 7. 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 June 30, 2016March 31, 2017, our equity investment in ATC was $129.0$140.2 million ($124.5($135.6 million at December 31, 20152016). In the first sixthree months of 2016,2017, we invested $1.6$3.1 million in ATC, and on July 29, 2016,April 28, 2017, we invested an additional $1.9 million. We expect to make additional investments of approximately $2.7$5.9 million in 2016.2017.
ALLETE’s Investment in ATC 
Millions 
Equity Investment Balance as of December 31, 20152016
$124.5135.6
Cash Investments1.63.1
Equity in ATC Earnings8.96.1
Distributed ATC Earnings(6.04.6)
Equity Investment Balance as of June 30, 2016March 31, 2017
$129.0140.2




NOTE 7. INVESTMENT INIn September 2016, the FERC issued an order reducing ATC’s authorized return on equity to 10.32 percent, or 10.82 percent including an incentive adder for participation in a regional transmission organization. Prior to this order, ATC (Continued)

Ourhad been allowed a return on equity earnings in ATC continue to beof 12.2 percent which had been impacted by reductions for estimated refunds related to complaints filed with the FERC by several customer groupscustomers located within the MISO service area.


NOTE 7. INVESTMENT IN ATC (Continued)

In June 2016, a federal administrative law judge ruled on an additional complaint proposing a further reduction in the base return on equity to 9.70 percent, or 10.20 percent including an incentive adder for participation in a regional transmission organization, subject to approval or adjustment by the FERC. A final decision from the FERC on the administrative law judge’s recommendation is expected in 2017. (See Note 6. Regulatory Matters.) ATC's current authorized return on equity is 12.2 percent. 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 after-tax ($0.9 million pre-tax).after-tax.


NOTE 8. SHORT-TERM AND LONG-TERM DEBT

The following tables present ALLETE’s short-term and long-term debt as of June 30, 2016March 31, 2017 and December 31, 2015.2016:
June 30, 2016Principal
 Unamortized Debt Issuance Costs Total
March 31, 2017Principal
 Unamortized Debt Issuance Costs Total
Millions          
Short-Term Debt (a)

$66.0
 $(0.6) 
$65.4

$164.5
 $(0.6) 
$163.9
Long-Term Debt1,510.1
 (11.2) 1,498.9
1,380.2
 (10.0) 1,370.2
Total Debt
$1,576.1
 $(11.8) 
$1,564.3

$1,544.7
 $(10.6) 
$1,534.1
(a)Consists of long-term debt due within one year and notes payable.
December 31, 2016Principal
 Unamortized Debt Issuance Costs Total
Millions     
Short-Term Debt (a)

$188.3
 $(0.6) 
$187.7
Long-Term Debt1,380.8
 (10.4) 1,370.4
Total Debt
$1,569.1
 $(11.0) 
$1,558.1
(a)Consisted of long-term debt due within one year and notes payable.
December 31, 2015Principal
 Unamortized Debt Issuance Costs Total
Millions     
Short-Term Debt (a)

$37.9
 $(0.6) 
$37.3
Long-Term Debt1,568.7
 (12.0) 1,556.7
Total Debt
$1,606.6
 $(12.6) 
$1,594.0
(a)Consisted of long-term debt due within one year and notes payable.year.

No long-term debt was issued in the first sixthree months of 2016.2017.

In December 2016, ALLETE entered into an agreement to sell $80 million of the Company's senior unsecured notes (the Notes) to certain institutional buyers in the private placement market. The Notes will be sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to institutional accredited investors. The Notes will be issued on or about June 1, 2017, carry an interest rate of 3.11 percent and mature on June 1, 2027.

Interest on the Notes is payable semi-annually on June 1 and December 1 of each year, commencing on December 1, 2017. The Company has the option to prepay all or a portion of the Notes at its discretion, subject to a make-whole provision. The Notes are subject to additional terms and conditions which are customary for these types of transactions. Proceeds from the sale of the Notes will be used to redeem debt, fund corporate growth opportunities and/or for general corporate purposes.

Financial Covenants. Our long-term debt arrangements contain customary covenants. In addition, our lines of credit and letters of credit supporting certain long-term debt arrangements contain financial covenants. Our compliance with financial covenants is not dependent on debt ratings. The most restrictive financial covenant requires ALLETE to maintain a ratio of indebtedness to total capitalization (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to 0.65 to 1.00,, measured quarterly. As of June 30, 2016March 31, 2017, our ratio was approximately 0.460.43 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from the lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. As of June 30, 2016March 31, 2017, ALLETE was in compliance with its financial covenants.




NOTE 9. INCOME TAX EXPENSE
 Quarter Ended Six Months EndedThree Months Ended
 June 30, June 30,March 31,
 2016 2015 2016 20152017 2016
Millions           
Current Tax Expense (a)
           
Federal —
 —
 —
 —
—
 —
State 
$0.1
 $0.2 
$0.2
 $0.3
$0.1
 $0.1
Total Current Tax Expense 
$0.1
 $0.2 
$0.2
 $0.3
$0.1
 $0.1
Deferred Tax Expense           
Federal $2.1 
$3.9
 $6.7 
$8.7
$7.3 
$4.6
State 2.7
 2.5
 7.5
 4.0
5.9
 4.8
Investment Tax Credit Amortization (0.2) (0.2) (0.4) (0.4)(0.2) (0.2)
Total Deferred Tax Expense $4.6 
$6.2
 $13.8 
$12.3
$13.0 
$9.2
Total Income Tax Expense $4.7 
$6.4
 $14.0 
$12.6
$13.1 
$9.3
(a)For the sixthree months ended June 30,March 31, 2017, and 2016, and 2015, the federal and state current tax expense was minimal due to NOLs which resulted from the bonus depreciation provisions of the Protecting Americans from Tax Hikes Act of 2015, the Tax Increase Prevention Act of 2014 and the American Taxpayer Relief Act of 2012.

The Company's tax provision for interim periods is determined using an estimate of its annual effective tax rate, adjusted for discrete items arising in that quarter. In each quarter, the Company updates its estimate of the annual effective tax rate, and if the estimated annual effective tax rate changes, the Company would make a cumulative adjustment in that quarter.
Three Months Ended
Reconciliation of Taxes from Federal Statutory March 31,
Rate to Total Income Tax Expense 2017
 2016
Six Months Ended June 302016
2015
Millions    
Income Before Non-Controlling Interest and Income Taxes
$85.2

$75.0

$62.1
 
$55.7
Statutory Federal Income Tax Rate35%35%35% 35%
Income Taxes Computed at 35 percent Statutory Federal Rate
$29.8

$26.3

$21.7
 
$19.5
Increase (Decrease) in Tax Due to:    
State Income Taxes – Net of Federal Income Tax Benefit5.0
2.8
3.9
 3.2
Production Tax Credits(20.5)(20.8)(13.0) (13.9)
Regulatory Differences for Utility Plant(0.1)(0.4)0.1
 (0.1)
Other(0.2)4.7
0.4
 0.6
Total Income Tax Expense
$14.0

$12.6

$13.1
 
$9.3

For the sixthree months ended June 30, 2016,March 31, 2017, the effective tax rate was 16.421.1 percent (16.8(16.7 percent for the sixthree months ended June 30, 2015)March 31, 2016).

Uncertain Tax Positions. As of June 30, 2016,March 31, 2017, we had gross unrecognized tax benefits of $2.2$2.0 million ($2.42.0 million as of December 31, 2015)2016). Of the total gross unrecognized tax benefits, $0.5$0.7 million represents the amount of unrecognized tax benefits included on the Consolidated Balance Sheet that, if recognized, would favorably impact the effective income tax rate. The unrecognized tax benefit amounts have been presented as reductions to the tax benefits associated with NOL and tax credit carryforwards on the Consolidated Balance Sheet.

ALLETE and its subsidiaries file a consolidated federal income tax return as well as combined and separate state income tax returns in various jurisdictions. ALLETE has no open federal or state audits, and is no longer subject to federal examination for years before 2013, or state examination for years before 2012.




NOTE 10. RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)LOSS

Changes in Accumulated Other Comprehensive Loss. Comprehensive income (loss) is the change in shareholders’ equity during a period from transactions and events from non-owner sources, including net income. The amounts recorded to accumulated other comprehensive loss include unrealized gains and losses on available-for-sale securities, and defined benefit pension and other postretirement items, consisting of deferred actuarial gains or losses and prior service costs or credits, and gains and losses on derivatives accounted for as cash flow hedges.credits.

For the quarter and sixthree months ended June 30,March 31, 2017, and 2016, and 2015, reclassifications out of accumulated other comprehensive incomeloss for the Company were not material. Changes in accumulated other comprehensive loss for the sixthree months ended June 30, 2016,March 31, 2017, are presented on the Consolidated Statement of Shareholders’ Equity.


NOTE 11. EARNINGS PER SHARE AND COMMON STOCK

We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. The difference between basic and diluted earnings per share, if any, arises from outstanding stock options, non-vested restricted stock units and performance share awards granted under our Executive Long-Term Incentive Compensation Plan and common shares under the forward sale agreement entered into in February 2014.Plan. For the sixthree months ended June 30,March 31, 2017, and 2016, and 2015, no options to purchase shares of ALLETE common stock were excluded from the computation of diluted earnings per share.
  2016     2015    2017     2016  
Reconciliation of Basic and Diluted  Dilutive     Dilutive    Dilutive     Dilutive  
Earnings Per ShareBasic Securities Diluted Basic Securities DilutedBasic Securities Diluted Basic Securities Diluted
Millions Except Per Share Amounts                      
Quarter ended June 30,           
Three Months Ended March 31, 
    
      
Net Income Attributable to ALLETE
$24.8
   
$24.8
 
$22.5
   
$22.5

$49.0
   
$49.0
 
$45.9
   
$45.9
Average Common Shares49.3
 0.2
 49.5
 48.6
 0.1
 48.7
50.2
 0.2
 50.4
 49.2
 —
 49.2
Earnings Per Share
$0.50
   
$0.50
 
$0.46
   
$0.46

$0.97
   
$0.97
 
$0.93
   
$0.93
Six Months Ended June 30, 
    
      
Net Income Attributable to ALLETE
$70.7
   
$70.7
 
$62.4
   
$62.4
Average Common Shares49.2
 0.1
 49.3
 47.7
 0.1
 47.8
Earnings Per Share
$1.44
   
$1.43
 
$1.31
   
$1.30

Contributions to Pension. For the three months ended March 31, 2017, we contributed 0.2 million shares of ALLETE common stock to our defined benefit pension plan, which had an aggregate value of $13.5 million when contributed (no shares were contributed to the defined benefit pension plan for the three months ended March 31, 2016). These shares of ALLETE common stock were contributed in reliance upon an exemption available pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended.


NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
 Pension 
Other
Postretirement
Components of Net Periodic Benefit Expense (Income)2016 2015 2016 2015
Millions       
Quarter Ended June 30,       
Service Cost
$2.1
 
$2.5
 
$1.0
 
$1.1
Interest Cost8.1
 7.4
 1.8
 1.8
Expected Return on Plan Assets(10.7) (10.1) (2.8) (2.8)
Amortization of Prior Service Costs (Credits)—
 0.1
 (0.8) (0.7)
Amortization of Net Loss2.5
 4.5
 0.1
 0.1
Net Periodic Benefit Expense (Income)
$2.0
 
$4.4
 $(0.7) $(0.5)
        
Six Months Ended June 30,       
Service Cost
$4.1
 
$5.0
 
$2.0
 
$2.2
Interest Cost16.2
 14.9
 3.7
 3.6
Expected Return on Plan Assets(21.3) (20.3) (5.6) (5.5)
Amortization of Prior Service Costs (Credits)—
 0.1
 (1.5) (1.5)
Amortization of Net Loss4.9
 9.0
 0.1
 0.2
Net Periodic Benefit Expense (Income)
$3.9
 
$8.7
 $(1.3) $(1.0)


NOTE 12.  PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
 Pension 
Other
Postretirement
Components of Net Periodic Benefit Expense (Income)2017 2016 2017 2016
Millions       
Three Months Ended March 31,       
Service Cost
$2.5
 
$2.0
 
$1.1
 
$1.0
Interest Cost8.1
 8.1
 1.9
 1.9
Expected Return on Plan Assets(10.6) (10.6) (2.6) (2.8)
Amortization of Prior Service Credits—
 —
 (0.5) (0.7)
Amortization of Net Loss2.5
 2.4
 0.1
 —
Net Periodic Benefit Expense (Income)
$2.5
 
$1.9
 —
 $(0.6)

Employer Contributions. For the sixthree months ended June 30, 2016March 31, 2017, we contributed $1.7 million in cash and 2015, no contributions were made$13.5 million in ALLETE common stock to ourthe defined benefit pension plan;plan (none for the three months ended March 31, 2016); we do not expect to make $2.0 million inadditional contributions to our defined benefit pension plan in 2016.2017. For the sixthree months ended June 30,March 31, 2017, and 2016, and 2015, we made no contributions to our other postretirement benefit plan; we do not expect to make any contributions to our other postretirement benefit plan in 2016.2017.




NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES

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

Our PPAs are summarized in Note 12.11. Commitments, Guarantees and Contingencies to our Consolidated Financial Statements in our 20152016 Form 10-K, with additional disclosure provided in the following paragraphs.

Square Butte PPA. Minnesota Power has a PPA with Square Butte a North Dakota cooperative corporation, that extends through 2026 (Agreement). Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on its entitlement to the output of Square Butte’s 455 MW coal-fired generating unit. Minnesota Power’s output entitlement under the Agreement is 50 percent for the remainder of the Agreement, subject to the provisions of the Minnkota Power sales agreement described below.PSA. (See Minnkota Power PSA.) Square Butte’s costs consist primarily of debt service, operating and maintenance, depreciation and fuel expenses. As of June 30, 2016March 31, 2017, Square Butte had total debt outstanding of $361.9$313.7 million. Fuel expenses are recoverable through Minnesota Power’s fuel adjustment clause and include the cost of coal purchased from BNI Energy under a long-term contract.

Minnesota Power’s cost of power purchased from Square Butte during the sixthree months ended June 30, 2016,March 31, 2017, was $37.7$20.3 million ($39.5($18.5 million for the sixthree months ended June 30, 2015March 31, 2016). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $4.8$2.3 million during the six months ended June 30, 2016 ($5.0($2.4 million for the six months ended June 30, 2015)same period in 2016). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.

Minnkota Power Sales Agreement.PSA. Minnesota Power has a power sales agreementPSA with Minnkota Power, which commenced June 1,in 2014. Under the power sales agreement,PSA, 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 20162017 and in 2015.

Silver Bay Power Sales Agreement. On May 23, 2016, Minnesota Power and Silver Bay Power entered into a long-term power purchase agreement through 2031. Silver Bay Power supplies approximately 90 MW of load to Northshore Mining which has been served predominately through self-generation by Silver Bay Power. In the years 2016 through 2019, Minnesota Power will supply Silver Bay Power with at least 50 MW of energy and Silver Bay Power will have the option to purchase additional energy from Minnesota Power as it transitions away from self-generation. On December 31, 2019, Silver Bay Power will cease self-generation and Minnesota Power will supply the entire energy requirements for Silver Bay Power.

Shell Energy PPA. In June 2016, Minnesota Power and Shell Energy signed a PPA that provides for Minnesota Power to purchase 50 MW of energy at fixed prices. The PPA begins in January 2017 and expires in December 2019.2016.

Coal, Rail and Shipping Contracts. Minnesota Power has coal supply agreements providing for the purchase of a significant portion of its coal requirements through December 20162017 and a portion of its coal requirements through December 2021. Minnesota Power also has coal transportation agreements in place for the delivery of a significant portion of its coal requirements through December 2018.2019. The minimum annual payment obligation under these supply and transportation agreements is $17.7$20.7 million for the remainder of 2016, $27.9 million in 2017, $27.0 million in 2018, $1.8 million in 2019 and none thereafter. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.


NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

Leasing Agreements. BNI Energy is obligated to make lease payments for a dragline totaling $2.8 million annually forduring the lease term, which expires in 2027. BNI Energy has the option at the end of the lease term to renew the lease at fair market value, to purchase the dragline at fair market value, or to surrender the dragline and pay a $3.0 million termination fee. We also lease other properties and equipment under operating lease agreements with terms expiring through 2022.2023. The aggregate amount of minimum lease payments for all operating leases is $14.0$10.3 million in 2016, $12.6 million infor the remainder of 2017, $11.1$12.0 million in 2018, $9.9$10.7 million in 2019, $6.9$7.5 million in 2020, $5.9 million in 2021 and $23.2$18.3 million thereafter.

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, investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others), and our investment in ATC.
 
Our transmission investments are summarized in Note 12. Commitments, Guarantees and Contingencies to our Consolidated Financial Statements in our 2015 Form 10-K, with additional disclosure provided in the following paragraphs.

Great Northern Transmission Line (GNTL).Line. As a condition of the 250-MW long-term PPA signed in May 2011entered into 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 kV500-kV transmission line between Manitoba and Minnesota’s Iron Range in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy.

The GNTL is subject to various federal and state regulatory approvals.
NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Transmission (Continued)

In October 2013,2015, a certificate of need application was filed with the MPUC which was approved in a June 2015 order.by the MPUC. 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 factorcost recovery filings. (See Note 6. Regulatory Matters.) In a December 2015, order, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In an 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 an2016 order, dated April 11, 2016, the MPUC approved the route permit for the GNTL which largely follows Minnesota Power’s preferred route, including the international border crossing. A final decision on the presidential permit bycrossing, and in November 2016, the U.S. Department of Energy issued a presidential permit to cross the U.S.-Canadian border, which was the final major regulatory approval needed before construction in the U.S. could begin. Site clearing and pre-construction activities commenced in the first quarter of 2017 with construction expected 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, of which Minnesota Power’s portion is expected to be between $300 million and $350 million; the difference will be recovered from a subsidiary of Manitoba Hydro as contributions in the third quarteraid of 2016. construction. Total project costs of $56.8 million have been incurred through March 31, 2017, of which $29.6 million has been recovered from a subsidiary of Manitoba Hydro.

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. Minnesota Power is expected to have majority ownership of the transmission line.

Environmental Matters.

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. A number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements have recently been promulgated by both the EPA and state authorities. Minnesota Power’s facilities are subject to additional regulation under many of these regulations. In 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 with many state and federal environmental regulations finalized, or to 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 outcomes of 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 expenseexpensed unless recoverable in rates from customers.


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

Air. The electric utility industry is regulated both at the federal and state level to address air emissions. Minnesota Power’s generating facilities mainly burn low-sulfur western sub-bituminous coal. All of Minnesota Power’s coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, baghouses and low NOX technologies. Under currently applicable environmental regulations, these facilities are substantially compliant with emission requirements.



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

New Source Review (NSR). In August 2008, Minnesota Power received a Notice of Violation (NOV) from the EPA asserting violations of the NSR requirements of the Clean Air Act at Boswell and Laskin Unit 2 between the years of 1981 and 2001. Minnesota Power received an additional NOV in April 2011 alleging that two projects undertaken at Rapids Energy Center in 2004 and 2005 should have been reviewed under the NSR requirements and that the Rapids Energy Center’s Title V permit was violated. Minnesota Power reached a settlement with the EPA regarding these NOVs and entered into a Consent Decree which was approved by the U.S. District Court for the District of Minnesota (Court) in September 2014. The Consent Decree provided for, among other requirements, more stringent emissions limits at all affected units, the option of refueling, retrofits or retirements at certain small coal units, and the addition of 200 MW of wind energy. Provisions of the Consent Decree require that, by no later than December 31, 2018, Boswell Units 1 and 2 must be retired, refueled, repowered, or emissions rerouted through existing emission control technology at Boswell. In October 2016, Minnesota Power estimatesannounced that if the units are not retired, capital expenditures could range between $20 million and $40 million. Minnesota Power’s 2015 IRP filed with the MPUC on September 1, 2015, outlined Minnesota Power’s preferred option to reroute emissions from Boswell Units 1 and 2 through existing emission control technology at Boswell Unit 3. We are required to notifywill be retired in 2018 as the EPA no later than December 31, 2016, whether we will retire, refuel, repower or reroute Boswell Units 1 and 2.latest step in its EnergyForward strategic plan. We believe that future capital expenditures or costs to retire would likelywill be eligible for recovery in rates over time, subject to regulatory approval in a rate proceeding.

Cross-State Air Pollution Rule (CSAPR).The CSAPR requires a total of 28 states in the eastern half of the United States,U.S., including Minnesota, to reduce power plant emissions that contribute to ozone or fine particulate pollution in other states. The CSAPR does not require installation of controls; rather it requires that facilities have sufficient allowances to cover their emissions on an annual basis. These allowances are allocated to facilities from each state’s annual budget, and can be bought and sold.

In December 2014, the EPA distributed the CSAPR allowances to CSAPR-subject units for the Phase I years (2015Minnesota Power’s generation levels and 2016). Phase II allowances (2017emission rates in 2015 and beyond)2016 were below its allowances. Allowances for 2017 and 2018 were distributed onin June 29, 2016. Based on our review of the NOx and SO2 Phase I and Phase II allowances already issued and Phase II allowances not yet issued,pending issuance, we currently expect projected generation levels and emission rates will result in compliance in both Phase I and Phase II.with the CSAPR.

Mercury and Air Toxics Standards (MATS) Rule (formerly known as the Electric Generating Unit Maximum Achievable Control Technology (MACT) Rule). Under Section 112 of the Clean Air Act, the EPA is required to set emission standards for hazardous air pollutants (HAPs) for certain source categories. The EPA published the final MATS rule in the Federal Register in February 2012, addressing such emissions from coal-fired utility units greater than 25 MW. There are currently 187 listed HAPs that the EPA is required to evaluate for establishment of MACT standards. In the final MATS rule, the EPA established categories of HAPs, including mercury, trace metals other than mercury, acid gases, dioxin/furans and organics other than dioxin/furans. The EPA also established emission limits for the first three categories of HAPs and work practice standards for the remaining categories. Affected sources were required to be in compliance with the rule by April 2015. States had the authority to grant sources a one-year extension. The MPCA approved Minnesota Power’s request for an extension of the date of compliance for the Boswell Unit 4 environmental upgrade to April 1, 2016. Construction on the project to implement the Boswell Unit 4 mercury emissions reduction plan was completed in 2015. Boswell Unit 3 is also subject to the MATS rule; however, investments and compliance work completed at Boswell Unit 3, including the emission reduction investments completed in 2009, meet the requirements of the MATS rule. The conversion of Laskin Units 1 and 2 to natural gas in June 2015 positioned those units for MATS compliance.

In June 2015, the U.S. Supreme Court reversed and remanded an earlier U.S. Court of Appeals for the D.C. Circuit decision on the MATS rule. The U.S. Supreme Court ruled that it was unreasonable for the EPA to deem cost of compliance irrelevant in determining that regulation of emissions of hazardous air pollutants from power plants was “appropriate and necessary” under Section 112 of the Clean Air Act. The MATS rule remains in effect until the U.S. Court of Appeals for the D.C. Circuit acts on the remand. In December 2015, the U.S. Court of Appeals for the D.C. Circuit rejected a motion by utilities and states to vacate the MATS rule, instead ordering the rule to remain in effect while the EPA completes its review. OnIn April 15, 2016, the EPA announced its determination that the MATS rule is appropriate and necessary, even after considering cost of compliance. The outcome of these proceedings is not expected to have a material impact on Minnesota Power generation due to emission reduction obligations under the Minnesota Mercury Emissions Reduction Act and the Consent Decree. (See New Source Review.)



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

Minnesota Mercury Emissions Reduction Act/Rule. In order to comply with the 2006 Minnesota Mercury Emissions Reduction Act, which was incorporated into rules promulgated by the MPCA in September 2014, Minnesota Power was required to implement a mercury emissions reduction project for Boswell Unit 4 by December 31, 2018. The Boswell Unit 4 environmental upgrade discussed above (see Mercury and Air Toxics Standards (MATS) Rule) fulfills the requirements of the Minnesota Mercury Emissions Reduction Act.


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

EPA National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters. A final rule issued by the EPA for Industrial Boiler MACT became effective in December 2012. Major existing sources had until January 31, 2016, to achieve compliance with the final rule and July 29, 2016, to perform initial compliance demonstrations. Minnesota Power’s Hibbard Renewable Energy Center and Rapids Energy Center are subject to this rule.rule and are currently in compliance. Compliance consistsconsisted largely of adjustments to our operating practices; therefore, the costs for complying with the final rule arewere not expected to be material.

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

Ozone NAAQS. The EPA has proposed more stringent control related to emissions that result in ground level ozone. In January 2010, the EPA proposed to revise the 2008 eight-hour ozone standard of 75 parts per billion (ppb) and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. In October 2015, the EPA published the final rule in the Federal Register revising the eight-hour ozone standard to 70 ppb with a secondary standard also set at 70 ppb. All areas of Minnesota currently meet the new standard based on the most recent available ambient monitoring data. However,data; however, some areas in the metropolitan Twin Cities and southwest portion of the state are close to exceeding the standard, sostandard. As a result, voluntary efforts to reduce ozone continue in the state. No additional costs for compliance are anticipated at this time.

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

Under the final rule, states will be responsible for additional PM2.5 monitoring, which will likely be accomplished by relocating or repurposing existing monitors. The EPA asked states to submit attainment designations by December 2013, based on already available monitoring data, and issued designations of the 2012 revised primary annual fine particulate attainment status in December 2014. The EPA designated the entire state of Minnesota as unclassifiable/attainment; however, Minnesota sources may ultimately be required to reduce their emissions to assist with attainment in neighboring states. Accordingly,In September 2016, environmental groups filed a lawsuit against the EPA in the United States District Court for the Northern District of California alleging the EPA had failed to fully implement the PM2.5 standards in 24 states, including Minnesota, by not enforcing states’ submittals of required infrastructure SIPs for the 2012 PM2.5 NAAQS. The outcome of this litigation is uncertain, and as such, any costs for complying with the final Particulate Matter NAAQS cannot be estimated at this time.

SO2 and NO2 NAAQS. During 2010, the EPA finalized one-hour NAAQS for SO2 and NO2. Ambient monitoring data indicates that Minnesota is likely in compliance with these standards; however, the one-hour SO2 NAAQS also requires the EPA to evaluate additional modeling and monitoring considerations to determine attainment. In April 2012, the MPCA notified Minnesota Power that modeling had been suspended as a result of the EPA’s announcement that the SIP submittals would not require modeling demonstrations for states, such as Minnesota, where ambient monitors indicate compliance with the standard. The EPA notified states that their infrastructure SIPs for maintaining attainment of the standard were required to be submitted to the EPA for approval by June 2013. However,2013; however, the State of Minnesota delayed completing the documents pending EPA guidance to states for preparing the SIP submittal.



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

In September 2013, the EPA provided guidance to states regarding implementation of the one-hour NO2 NAAQS and in June 2014, as clarified in February 2015, the MPCA submitted a SIP revision to the EPA addressing the infrastructure requirements of Sections 110(a)(1) and 110(a)(2) of the Clean Air Act in regards to the one-hour NO2 and SO2 NAAQS, among other standards. The SIP stated that since the EPA determined in January 2012 that no area in the country is in violation of the one-hour NO2 NAAQS, there are no nonattainment areas in the country for this pollutant, and therefore Minnesota’s NO2 emissions cannot be significantly contributing to nonattainment in any other state. In October 2015, the EPA published in the Federal Register an approval and partial disapproval of the June 2014 SIP revision. According to the MPCA, the partial disapproval is regarding state delegation of a program unrelated to the one-hour NAAQS for SO2 and NO2,, and is not expected to require further action. As such, additional compliance costs for the one-hour NO2 NAAQS are not expected at this time.


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

In August 2015, the EPA finalized the SO2 data requirements rule (DRR) for the 2010 one-hour NAAQS to assist the states in implementing the standard. The rule sets emissions thresholds and exemptions for facilities that trigger modeling requirements. OnIn January 8, 2016, the MPCA informed the EPA of the Minnesota sources subject to the rule, confirming that Boswell and Taconite Harbor are the only Minnesota Power generating facilities subject to the DRR. The MPCA was required to notify the EPA as to how each source will evaluate air quality by July 1, 2016. Compliance options include ambient monitoring, modeling existing enforceable emission limits, or modeling actual emissions. The MPCA hasinitially informed Minnesota Power that compliant SO2 modeling recently completed at these facilities shouldwould satisfy the DRR obligations and no further modeling shouldwould be required.required; however, the DRR also requires facilities have federally-enforceable permit limits at which the one-hour SO2 NAAQS compliance was modeled by January 13, 2017. Taconite Harbor was issued an amended air permit in September 2016, containing the new modeling limits at that facility. The MPCA did not meet the January 13, 2017, deadline to amend the Boswell permit. The MPCA is in discussiondiscussions with the EPA on alternate compliance pathways to confirm its conclusion. The DRR also requires the MPCA to amend the operating permits for Boswell and Taconite Harbor by January 13, 2017, to include emissions limitsuse existing completed modeling at which one-hour SO2 NAAQS compliance was modeled. Minnesota Power is assisting the MPCA to ensure this deadline will be met.current limits. Compliance costs for the one-hour SO2 NAAQS are not expected to be material.

Class I Air Quality Petitions and Requests. In July 2014, the Fond du Lac Band of Lake Superior Chippewa (Fond du Lac Band) announced its intent to petition the EPA to redesignate its reservation air shed from Class II to Class I air quality pursuant to Section 164(c) of the Clean Air Act. The Fond du Lac Band does not currently possess authority to directly regulate air quality. Class I air shed status, if granted, would allow the Fond du Lac Band to impose more stringent Clean Air Act protections within the boundaries of the Fond du Lac reservation, including the reservation air shed, near Cloquet, Minnesota. Five other reservations across the U.S. have received Class I status. A public hearing was held by the Fond du Lac Band in October 2014, and the extended public comment period on the petition expired in November 2014. After the Fond du Lac Band prepares responses to the comments, it is anticipated to make a formal submittal request to the EPA. The Company has requested additional clarification from the Fond du Lac Band and the MPCA on the final regulatory structure that may arise from a Class I redesignation.

In May 2013, the Bad River Band of Lake Superior Chippewa (Bad River Band) announced its intent to petition the EPA to redesignate its reservation air shed which is located approximately 100 miles east of Duluth, Minnesota, from Class II to Class I air quality pursuant to Section 164(c) of the Clean Air Act. The Class I analysis report was issued by the Bad River Band in January 2015 whichand was followed by public hearings in March 2015 and a public comment period ending in May 2015. After the Bad River Band prepares responses to the comments, it is also anticipated to make a formal submittal request to the EPA.

There is no deadline for the approval, denial, or modification of these requests by the EPA. We are unable to determine the impact of potential Class I status on the Company’s operations at this time. 

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

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



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

President Obama’s Climate Action Plan. In June 2013, President Obama2015, the Federal government announced aan updated 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. On March 28, 2017, President Trump signed an Executive Order titled Promoting Energy Independence and Economic Growth that rescinds the Climate Action Plan.

EPA Regulation of GHG Emissions. In May 2010, the EPA issued the Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). The Tailoring Rule establishes permitting thresholds required to address GHG emissions for new facilities, existing facilities that undergo major modifications and other facilities characterized as major sources under the Clean Air Act’s Title V program. For our existing facilities, the rule does not require amending our existing Title V operating permits to include GHG requirements. However, GHG requirements are likely tomay be added to our existing Title V operating permits by the MPCA as these permits are renewed or amended.


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

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

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

In March 2012,October 2016, the EPA announcedpublished a proposed rule in the Federal Register to revise its PSD and Title V regulatory provisions concerning GHG emissions. In this proposed rule, the EPA proposes to amend its regulations to clarify that a source’s obligation to obtain a PSD or Title V permit is triggered only by non-GHG pollutants. If the PSD or Title V permitting requirements are triggered by non-GHG, NSR pollutants, then these programs will also apply CO2 emission New Source Performance Standards (NSPS), under Section 111(b) ofto the Clean Air Act, to new fossil fuel-fired electric generating units.source’s GHG emissions. The proposed NSPS wouldrule, as currently written, is not expected to have applied only to new or re-powered units. Baseda material impact on the volume of comments received,Title V permitting for current operations. It is uncertain as to how the EPA announced its intent to re-proposeTitle V permitting requirements will be affected by the rule. In September 2013, the EPA retracted its March 2012 proposal28, 2017, Executive Order titled Promoting Energy Independence and announced the release of a revised NSPS for new or re-powered utility CO2 emissions.Economic Growth.

In June 2014, the EPA announced a proposed rule under Section 111(d) of the Clean Air Act for existing power plants entitled “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units”, also referred to as the Clean Power Plan (CPP). The EPA issued the final CPP in August 2015, together with a proposed federal implementation plan and a model rule for emissions trading. Numerous petitionsPetitions for review of the rule have beenwere filed with the U.S. Court of Appeals for the District of Columbia Circuit. OnIn February 9, 2016, the U.S. Supreme Court issued an order staying the effectiveness of the rule until after the appellate court process is complete. In MaySeptember 2016, the U.S. Court of Appeals for the District of Columbia announced the petitions for review will be heard on September 27, 2016.oral arguments and is currently deliberating. The EPA is precluded from enforcing the CPP while the U.S. Supreme Court stay is in force; however, the MPCA has been holding a series of meetings on the CPP for educational and planning purposes in the interim. Minnesota Power has been actively involved in these MPCA meetings, and is closely monitoring the appeals process.

If upheld, the CPP would establish uniform CO2 emission performance rates for existing fossil fuel-fired and natural gas-fired combined cycle generating units, setting state-specific goals for CO2 emissions from the power sector. State goals were determined based on CPP source-specific performance emission rates and each state’s mix of power plants. The EPA maintains such goals are achievable if a state undertakes a combination of measures across its power sector that constituteconstitutes the EPA’s guideline for a Best System of Emission Reductions (BSER). BSER is comprised of three building blocks: 1) improved fossil fuel power plant efficiency, 2) increased reliance on low-emitting power sources by generating more electricity from existing natural gas combined cycle units, and 3) building more zero- and low-emitting power sources, including renewable energy. States may also choose to include avoided CO2 emissions from customer energy efficiency measures for credit towards meeting state goals. The regulatory review initiated by the March 28, 2017, Executive Order titled Promoting Energy Independence and Economic Growth is directed to include Section 111(b) and 111(d) CPP provisions. In addition, the EPA has filed a motion with the U.S. Court of Appeals for the District of Columbia Circuit to hold CPP-related litigation in abeyance while the EPA is reviewing the rule. Minnesota Power is monitoring developments with respect to the CPP rule and related matters.

State goals under the CPP are expressed as both mass-based and rate-based, goals, and 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 original schedule for the CPP, each state iswould have been required to develop a SIP by September 6, 2016, or by September 6, 2018, if granted an extension. Due to the U.S. Supreme Court order staying the effectiveness of the CPP, those SIP submittal dates are not currently in effect. If the CPP is upheld at the completion of the appellate court process, all of the CPP regulatory deadlines mayare expected to be reset based on the length of time that the appeals process takes.



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

In developing its plan, a state may choose to meet either the mass-based or the rate-based goals. Minnesota Power is currently evaluating the CPP as it relates to the State of Minnesota as well as its potential impact on the Company and is actively discussing potential compliance scenarios with regulatory agencies and in public stakeholder meetings. Minnesota has already initiated several measures consistent with those called for under the CAP and CPP. Minnesota Power is implementing its EnergyForward strategic plan that provides for significant emission reductions and diversifying its electricity generation mix to include more renewable and natural gas energy. (See Note 6. Regulatory Matters.)

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

Minnesota’s Next Generation Energy Act of 2007. In April 2014, the U.S. District Court for the District of Minnesota ruled that part of Minnesota’s Next Generation Energy Act of 2007 (NEGA) violated the Commerce Clause of the U.S. Constitution. The portions of the law which were ruled unconstitutional prohibited the importation of power from a new CO2-producing facility outside of Minnesota and prohibited the entry into new long-term PPAs that would increase CO2 emissions in Minnesota. The State of Minnesota appealed the decision to the U.S. Court of Appeals for the Eighth Circuit in May 2014. On June 15, 2016, the U.S. Court of Appeals for the Eighth Circuit upheld the federal district court’s decision that part of the NEGA violated the Commerce Clause of the U.S. Constitution.proceeding.

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

Clean Water Act - Aquatic Organisms. In April 2011, the EPA announced proposed regulations under Section 316(b) of the Clean Water Act that set standards applicable to cooling water intake structures for the protection of aquatic organisms. The proposed regulations would require existing large power plants and manufacturing facilities that withdraw greater than 25 percent of water from adjacent water bodies for cooling purposes, and have a design intake flow of greater than 2 million gallons per day, to limit the number of aquatic organisms that are impacted by the facility’s intake structure or cooling system. The Section 316(b) rule was effective in October 2014. The Section 316(b) standards will be implemented through NPDES permits issued to the covered facilities with compliance timing dependent on individual NPDES renewal schedules. No NPDES permits for Minnesota Power generating facilities have been re-issued containing Section 316(b) requirements since the final rule was published, so at this time we are unable to determine the final cost of compliance; however, ourcompliance. Should the MPCA require significant modifications to Minnesota Power’s intake structures, a preliminary assessment suggestsindicates costs of compliance could be up to approximately $15 million.million over the next 5 years. Minnesota Power would seek recovery of any additional costs through a general rate case.

Steam Electric Power Generating Effluent Guidelines. In April 2013,2015, the EPA announced proposed revisions to theissued revised federal effluent limit guidelines (ELG) for steam electric power generating stations under the Clean Water Act. The final ELG was issued in September 2015. It sets effluent limits and prescribes BACT for several wastewater streams, including flue gas desulphurization (FGD) water and coal combustion landfill leachate. The ELG rule also prohibits the discharge of bottom and fly ash contact waters. Compliance with the final rule is required between November 1, 2018, and December 31, 2023.

We are reviewing the final rule and evaluating its potential impact on Minnesota Power’s operations, primarily at Boswell. Boswell currently discharges bottom ash contact water through its NPDES permit, and also has a closed-loop FGD system that does not currently discharge, but may do so in the future. Under the final ELG rule, bottom ash discharge would not be allowed and bottom ash contact water would either need to be re-used in a closed-loop process, routed to a FGD scrubber, or the bottom ash handling system would need to be converted to a dry process. If the FGD wastewater is discharged in the future, it would require additional wastewater treatment. Efforts have been underway at Boswell for several years to reduce the amount of water discharged and evaluate potential re-use options in its plant processes. Additional efforts are underway to determine if land application of certain wastewater streams under a state disposal system may be feasible.

On April 12, 2017, the EPA announced that it would reconsider the final ELG rule and administratively stay the compliance dates set forth in the rule. The EPA has received seven petitions for review of the ELG rule, which were consolidated in the U.S. Court of Appeals for the Fifth Circuit in late 2015. The EPA has indicated they will also file a motion requesting that court to hold litigation challenging the ELG rule in abeyance while the EPA reconsiders the rule. All pending deadlines under the ELG rule will be stayed while the EPA re-examines it. Under the ELG rule schedule, required compliance activity deadlines could have been in place as soon as November 1, 2018. These deadlines could have included prescriptive wastewater treatment technology installation, as well as a ban on bottom ash contact water discharges. If the EPA’s reconsideration results in the rule being revised or rescinded, the authority to regulate bottom ash transport water and FGD wastewater would fall under existing Effluent Guidelines Limits and state resource agency purview.   



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

At this time, we cannot estimate what compliance costs we might incur related to these or other potential future water discharge regulations; however, the costs could be material, including costs associated with retrofits for bottom ash handling, pond dewatering, pond closure, and wastewater treatment and/or reuse. Minnesota Power would seek recovery of any additional costs through cost recovery riders or in a general rate case.proceeding.

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


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

Coal Ash Management Facilities. Minnesota Power generatesdisposes or disposesstores coal ash at four of its electric generating facilities. One facility storesfacilities by the following methods; storing ash in lined onsite impoundments (ash ponds) with engineered liners, disposing of dry ash in a lined dry ash landfill which has been idled and containment dikes. Another facility’shas a temporary landfill cover in place, applying ash is beneficially re-used. The other two facilities generate a combined wood and coal ash that is eitherto land applied as an approved beneficial use or truckedtrucking ash to state permitted landfills. In June 2010, the EPA proposed regulations for coal combustion residuals (CCR) generated by the electric utility sector. The proposal sought comments on three general regulatory schemes for coal ash under Subtitle D of Resource Conservation and Recovery Act (RCRA) (non-hazardous) or Subtitle C of RCRA (hazardous).

The EPA issued the final CCR rule in December 2014 under Subtitle D (non-hazardous) of RCRA and it was published in the Federal Register in April 2015. The rule includes additional requirements for new landfill and impoundment construction as well as closure activities related to certain existing impoundments. Costs of compliance for Boswell and Laskin are expected to occur primarily over the next 10 years and be between approximately $65 million and $100 million. Recently, the EPA has indicated to Minnesota Power that the Taconite Harbor landfill is a CCR unit, based on EPA’s interpretation of the CCR rule language. Minnesota Power has not disposed ash onsite atagreed to post the required CCR information for the Taconite Harbor since the effective date of the rule, and therefore,landfill on Minnesota Power’s website while the CCR ruleissue is not applicable to that generating facility.resolved. Minnesota Power continues to work on minimizing costs through evaluation of beneficial re-use and recycling of CCR and CCR-related waters. Compliance costs, if any for CCR at Taconite Harbor are not expected to be material. Minnesota Power would seek recovery of any additional costs through a general rate case.

Other Environmental Matters. In November 2016, U.S. Water Services received notice from the EPA regarding potential violations under the Federal Insecticide, Fungicide and Rodenticide Act for the sale of certain chemicals without registration or that were misbranded. The potential violations primarily related to sales in 2013 by a U.S. Water Services subsidiary which occurred prior to U.S. Water Services’ acquisition of that subsidiary. In the first quarter of 2017, U.S. Water Services reached a settlement with the EPA and entered into a consent agreement which provides for the payment of approximately $0.2 million to resolve this matter.

Other Matters.

ALLETE Clean Energy. ALLETE Clean Energy’s wind energy facilities have PPAsPSAs in place for their entire output and expire in various years between 2018 and 2032. As of June 30, 2016,March 31, 2017, ALLETE Clean Energy has $14.6 million outstanding in standby letters of credit.

U.S. Water Services. As of June 30, 2016,March 31, 2017, U.S. Water Services has $0.8 million outstanding in standby letters of credit.

BNI Energy. As of June 30, 2016,March 31, 2017, BNI Energy had surety bonds outstanding of $49.9 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although its coal supply agreements obligate the customers to provide for the closing costs, additional assurance is required by federal and state regulations. In addition to the surety bonds, BNI Energy has secured a letter of credit for an additional $0.6 million to provide for BNI Energy’s total reclamation liability, which is currently estimated at $47.5 million. BNI Energy does not believe it is likely that any of these outstanding surety bonds or the letter of credit will be drawn upon.

ALLETE Properties. As of June 30, 2016March 31, 2017, ALLETE Properties, through its subsidiaries, had surety bonds outstanding and letters of credit to governmental entities totaling $10.1$8.6 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is approximately $6.1$5.4 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.


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

Community Development District Obligations. At June 30, 2016March 31, 2017, we owned 7271 percent of the assessable land in the Town Center District (72 percent at December 31, 20152016) and 9289 percent of the assessable land in the Palm Coast Park District (92 percent at December 31, 20152016). At these ownership levels, our annual assessments related to capital improvement and special assessment bonds for the ALLETE Properties projects within these districts are approximately $1.4 million for Town Center at Palm Coast and $2.1 million for Palm Coast Park. As we sell property at these projects, the obligation to pay special assessments will pass to the new landowners. In accordance with accounting guidance, these bonds are not reflected as debt on our Consolidated Balance Sheet.

Legal Proceedings.

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.




NOTE 14. BUSINESS SEGMENTS

During the third quarter of 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,segments: Regulated Operations, ALLETE Clean Energy and U.S. Water Services. Prior period amounts have been revisedWe measure performance of our operations through budgeting and monitoring of contributions to conform with the currentconsolidated net income by each business segment presentation.segment.

Regulated Operations includes three operating segments which consist of 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.ATC. ALLETE Clean Energy is our business aimed atfocused on developing, acquiring or developing capital projects that createand operating clean and renewable energy solutions by way of wind, solar, biomass, hydro, natural gas, shale resources, clean coal technology and other emerging energy innovations.projects. U.S. Water Services is our integrated water management company which was acquired in February 2015.company. The ALLETE Clean Energy and U.S. Water Services reportable segments comprise our Energy Infrastructure and Related Services businesses. We also present Corporate and Other which includes two operating segments, BNI Energy, our coal mining operations in North Dakota, and ALLETE Properties, our legacy Florida real estate investment, along with 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.
Quarter Ended Six Months EndedThree Months Ended
June 30, June 30,March 31,
20162015 2016201520172016
Millions    
Operating Revenue    
Regulated Operations$234.9$230.0 $487.2$492.8$281.6$252.3
    
Energy Infrastructure and Related Services    
ALLETE Clean Energy18.8
34.0
 42.4
46.4
23.7
23.6
U.S. Water Services34.3
34.4
 66.7
49.9
32.1
32.4
    
Corporate and Other26.8
24.9
 52.3
54.2
28.2
25.5
Total Operating Revenue
$314.8

$323.3
 
$648.6

$643.3

$365.6

$333.8
Net Income (Loss) Attributable to ALLETE    
Regulated Operations (a)

$22.6

$23.3
 
$65.0

$64.3

$43.5

$42.4
    
Energy Infrastructure and Related Services    
ALLETE Clean Energy2.6
3.0
 8.7
5.5
6.7
6.1
U.S. Water Services1.0
0.6
 0.5
0.5
(0.3)(0.5)
    
Corporate and Other (a)
(1.4)(4.4) (3.5)(7.9)(0.9)(2.1)
Total Net Income Attributable to ALLETE
$24.8

$22.5
 
$70.7

$62.4

$49.0

$45.9
(a)In 2015, an intercompany loan agreement was entered into and interest expense was allocated to certain subsidiaries which is eliminated in consolidation. Prior period segment results have been revised to conform to the current presentation as if the intercompany loan existed as of January 1, 2015.
 June 30,
2016
December 31,
2015
Millions  
Assets  
Regulated Operations (a)
$3,823.4$3,853.1
   
Energy Infrastructure and Related Services  
ALLETE Clean Energy (a)
489.5
501.5
U.S. Water Services258.2
258.3
   
Corporate and Other286.5
281.6
Total Assets (a)

$4,857.6

$4,894.5
(a)As a result of revised accounting guidance adopted in the first quarter of 2016, we reclassified unamortized debt issuance costs from Other Non-Current Assets to Long-Term Debt on the Consolidated Balance Sheet. Prior period segment assets have been revised to conform to the current presentation. (See Note 1. Operations and Significant Accounting Policies.)


NOTE 14. BUSINESS SEGMENTS (Continued)
 March 31,
2017
December 31,
2016
Millions  
Assets  
Regulated Operations$3,828.2$3,823.9
   
Energy Infrastructure and Related Services  
ALLETE Clean Energy571.7
566.0
U.S. Water Services265.1
264.1
   
Corporate and Other276.9
222.9
Total Assets
$4,941.9

$4,876.9


ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

The following discussion should be read in conjunction with our Consolidated Financial Statements and notes to those statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations from the 20152016 Form 10-K, and the other financial information appearing elsewhere in this report. In addition to historical information, the following discussion and other parts of this Form 10-Q contain forward-looking information that involves risks and uncertainties. Readers are cautioned that forward-looking statements should be read in conjunction with our disclosures in this Form 10-Q and our 2016 Form 10-K under the headings: “Forward-Looking Statements” located on page 56 and “Risk Factors” located in Part I, Item 1A, beginning on page 25 of our 20152016 Form 10‑K.10-K. The risks and uncertainties described in this Form 10-Q and our 20152016 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.

Basis of Presentation. During the third quarter of 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 utility 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 Note 6. Regulatory Matters.)

ALLETE Clean Energy 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 areis from PSAs under long-term power sales agreements.various durations. In addition, ALLETE Clean Energy constructed and sold a 107 MW wind energy facility in 2015. On January 3, 2017, ALLETE Clean Energy announced that it will develop another wind energy facility of up to 50 MW after securing a 25-year PSA with Montana-Dakota Utilities. The PSA includes an option for saleMontana-Dakota Utilities to Montana-Dakota Utilities;purchase the facility upon completion; construction is expected to begin in 2018. On March 16, 2017, ALLETE Clean Energy announced it will build, own and sale were completedoperate a separate 100 MW wind energy facility pursuant to a 20-year PSA with Northern States Power; construction is expected to begin in the fourth quarter of 2015.late 2018 and is subject to regulatory approvals.

U.S. Water Services is ourprovides integrated water management company which was acquired in February 2015.for industry by combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage, and improve efficiency.

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.


ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (Continued)

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of June 30, 2016March 31, 2017, unless otherwise indicated. All subsidiaries are wholly-owned unless otherwise specifically indicated. References in this report to “we,” “us” and “our” are to ALLETE and its subsidiaries, collectively.

Financial Overview

The following net income discussion summarizes a comparison of the sixthree months ended June 30, 2016,March 31, 2017, to the sixthree months ended June 30, 2015.March 31, 2016.

Net income attributable to ALLETE for the sixthree months ended June 30, 2016,March 31, 2017, was $70.7$49.0 million, or $1.43$0.97 per diluted share, compared to $62.4$45.9 million, or $1.30$0.93 per diluted share, for the same period in 2015. Net income for 2015 included a $3.9 million after-tax expense, or $0.08 per share, for acquisition costs related to U.S. Water Services and ALLETE Clean Energy’s acquisitions. (See Note 3. Acquisitions.) In 2015, net income also included the recognition under percentage of completion accounting, of $1.5 million of after-tax estimated profit for the construction of a wind energy facility which was sold to Montana-Dakota Utilities in the fourth quarter of 2015. Net income for 2016 increased primarily due to higher net income at ALLETE Clean Energy.2016. Earnings per share dilution was $0.05$0.02 due to additional shares of common stock outstanding as of June 30, 2016.


ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (Continued)March 31, 2017.

Regulated Operations net income attributable to ALLETE was $65.0$43.5 million for the sixthree months ended June 30, 2016,March 31, 2017, compared to $64.3$42.4 million for the same period in 2015.2016. Net income for 2016 increased primarily due to slightly higher net income at Minnesota Power resulting from lower operating and maintenance expenses, higher FERC formula-basedthe implementation of interim retail rates on January 1, 2017, and higher cost recovery rider revenue.kWh sales primarily due to increased industrial sales. These increases were mostly offset by higher operating and maintenance, depreciation, and property tax, expenses, a decrease in kWh sales due to lower industrial sales and impacts of warmer temperatures in 2016.interest expenses. Our equity earnings in ATC and earnings at SWL&P, for the sixthree months ended June 30, 2016, were similarMarch 31, 2017, increased $0.7 million after-tax reflecting a higher investment balance and period over period changes in ATC’s estimate of a refund liability related to the same period in 2015.MISO return on equity complaints.

ALLETE Clean Energy net income attributable to ALLETE was $8.7$6.7 million for the sixthree months ended June 30, 2016,March 31, 2017, compared to $5.5$6.1 million for the same period in 2015.2016. Net income for 2015in 2016 included an allocation of earnings to a $0.9 million after-tax expense for acquisition costs related tonon-controlling interest in the Chanarambie/Viking wind energy facilities. In 2015, net income also includedlimited liability company that owns the recognition under percentage of completion accounting, of $1.5 million of after-tax estimated profit for the construction of aCondon wind energy facility, which was sold to Montana-Dakota Utilities in the fourth quarter of 2015. Net income for 2016 increased primarily due to income generated from the operations of wind energy facilitiessubsequently acquired by ALLETE Clean Energy in April and July 2015.2016. (See Note 3. Acquisitions.)

U.S. Water Services net incomeloss attributable to ALLETE was similar$0.3 million for the sixthree months ended June 30, 2016,March 31, 2017, compared to a net loss of $0.5 million for the same period fromin 2016. The net loss in 2017 includes an after-tax expense of $0.2 million for the datesettlement of acquisition, February 10, 2015, through June 30, 2015.an EPA investigation, and lower operating expenses. (See Note 13. Commitments, Guarantees and Contingencies.) The net loss in 2016 included $0.3 million of after-tax expense recognized as cost of sales related to purchase accounting for inventories and sales backlog. U.S. Water Services sells certain products which are seasonal in nature, with higher demand typically realized in warmer months; generally, lower sales occur in the first quarter of each year.

Corporate and Other net loss attributable to ALLETE was $3.5$0.9 million for the sixthree months ended June 30, 2016,March 31, 2017, compared to a net loss of $7.9$2.1 million for the same period in 2015. In 2015, the2016. The net loss included a $3.0 million after-taxin 2017 decreased primarily due to lower accretion expense for acquisition costs related to U.S. Water Services.resulting from the contingent consideration liability. (See Note 5. Fair Value.)




COMPARISON OF THE QUARTERSTHREE MONTHS ENDED JUNE 30,MARCH 31, 2017 AND 2016 AND 2015

(See Note 14. Business Segments for financial results by segment.)

Regulated Operations
Quarter Ended June 30,2016
2015
Three Months Ended March 31,2017
2016
Millions  
Operating Revenue
$234.9

$230.0

$281.6

$252.3
Fuel and Purchased Power78.1
80.1
93.0
76.9
Transmission Services16.1
11.3
16.6
16.8
Cost of Sales0.9
1.0
3.6
3.0
Operating and Maintenance53.5
57.8
55.0
50.6
Depreciation and Amortization38.3
33.7
39.7
38.3
Taxes Other than Income Taxes12.8
12.1
13.2
12.2
Operating Income35.2
34.0
60.5
54.5
Interest Expense(12.7)(13.9)(14.0)(13.1)
Equity Earnings in ATC4.1
4.7
6.1
4.8
Other Income0.3
0.7
0.2
0.9
Income Before Non-Controlling Interest and Income Taxes26.9
25.5
52.8
47.1
Income Tax Expense4.3
2.2
9.3
4.7
Net Income Attributable to ALLETE$22.6
$23.3
$43.5
$42.4

Operating Revenue increased $4.9$29.3 million, or 212 percent, from 20152016 primarily due to higher transmission revenue, kWh sales and FERC formula-based rates, partially offset by lower fuel adjustment clause recoveries, andinterim retail rates, kWh sales, conservation improvement program recoveries.

Transmission revenue increased $6.0 million primarily due to period over period changes in our estimate of a refund liability related to MISO return on equity complaintsrecoveries and higher MISO-relatedtransmission revenue. (See Operating Expenses - Transmission Services.)




COMPARISON OF THE QUARTERS ENDED JUNE 30, 2016 AND 2015 (Continued)
Regulated Operations (Continued)

Despite relatively flat overall kWh sales, revenue increased $3.8 million from 2015 due mostly to higher pricing on our wholesale power sales agreements compared to last year. Sales to our industrial customers decreased 3.9 percent due to reduced taconite production. In addition, demand revenue from our industrial customers was down in 2016 as a result of lower demand nominations during the quarter. Sales to our residential and commercial customers increased 4.4 percent and 2.4 percent, respectively. Sales to our residential and commercial customers were higher due to colder average temperatures this year as heating degree days in Duluth, Minnesota, were approximately 10 percent higher in the second quarter of 2016 compared to the same period in 2015.
Kilowatt-hours Sold    Quantity %
Quarter Ended June 30,2016
 2015
 Variance Variance
Millions       
Regulated Utility       
Retail and Municipal       
Residential237
 227
 10
 4.4 %
Commercial339
 331
 8
 2.4 %
Industrial1,513
 1,575
 (62) (3.9)%
Municipal187
 187
 —
 —
Total Retail and Municipal2,276
 2,320
 (44) (1.9)%
Other Power Suppliers1,185
 1,113
 72
 6.5 %
Total Regulated Utility Kilowatt-hours Sold3,461
 3,433
 28
 0.8 %

Revenue from electric sales to taconite/iron concentrate customers accounted for 17 percent of consolidated operating revenue in 2016 (19 percent in 2015). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 6 percent of consolidated operating revenue in 2016 (7 percent in 2015). Revenue from electric sales to pipelines and other industrial customers accounted for 8 percent of consolidated operating revenue in 2016 (6 percent in 2015).

Revenue from our wholesale customers under formula-based rates increased $1.1 million primarily due to environmental and other investments.

Fuel adjustment clause recoveries decreased $3.5increased $10.2 million due to lowerhigher fuel and purchased power costs attributable to our retail and municipal customers. (See Operating Expenses - Fuel and Purchased Power Expense.)

Interim retail rates for Minnesota Power, subject to refund, were approved by the MPUC in a December 2016 order and became effective January 1, 2017, resulting in revenue of $8.8 million in the first quarter of 2017. (See Note 6. Regulatory Matters.)

As a result of higher kWh sales, revenue increased $7.5 million from 2016 primarily due to higher sales to Industrial customers. Sales to Industrial customers increased 10.5 percent primarily due to increased taconite production and the commencement of a long-term PSA with Silver Bay Power in the second quarter of 2016. Sales to Residential and Municipal customers decreased 1.8 percent due to warmer temperatures in 2017. Heating degree days in Duluth, Minnesota, were approximately 3 percent lower in the first three months of 2017 compared to the same period in 2016. Sales to Commercial customers were consistent with 2016. Sales to Other Power Suppliers decreased 7.9 percent from 2016 as a result of increased sales to industrial customers. Sales to Other Power Suppliers are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements of various durations.
Kilowatt-hours Sold    Quantity %
Three Months Ended March 31,2017
 2016
 Variance Variance
Millions       
Regulated Utility       
Retail and Municipal       
Residential323
 329
 (6) (1.8)%
Commercial369
 368
 1
 0.3 %
Industrial1,762
 1,594
 168
 10.5 %
Municipal215
 219
 (4) (1.8)%
Total Retail and Municipal2,669
 2,510
 159
 6.3 %
Other Power Suppliers1,041
 1,130
 (89) (7.9)%
Total Regulated Utility Kilowatt-hours Sold3,710
 3,640
 70
 1.9 %


COMPARISON OF THE THREE MONTHS ENDED MARCH 31, 2017 AND 2016 (Continued)
Regulated Operations (Continued)

Revenue from electric sales to taconite/iron concentrate customers accounted for 21 percent of consolidated operating revenue in 2017 (16 percent in 2016). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 5 percent of consolidated operating revenue in 2017 (7 percent in 2016). Revenue from electric sales to pipelines and other industrial customers accounted for 7 percent of consolidated operating revenue in 2017 (7 percent in 2016).

Conservation improvement program recoveries decreased $1.7increased $1.6 million from 20152016 primarily due to a reductionan increase in related expenditures. (See Operating Expenses - Operating and Maintenance Expense.)

Transmission revenue increased $1.2 million primarily due to higher MISO-related revenue.

Operating Expenses increased $3.7$23.3 million, or 212 percent, from 2015.2016.

Fuel and Purchased Power expense decreased $2.0increased $16.1 million, or 221 percent, from 20152016 primarily due to lowerincreased kWh sales as well as higher purchased power prices compared to 2015, partially offset by higherand fuel costs in 2016.costs. 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 $4.8 million, or 42 percent, from 2015 primarily due to period over period changes in our estimate of a refund for MISO transmission expense related to MISO return on equity complaints and higher MISO-related expense. (See Operating Revenue and Note 6. Regulatory Matters.)

Operating and Maintenance expense decreased $4.3increased $4.4 million, or 79 percent, from 20152016 primarily due to lower benefit expenses. In addition,a $3.6 million sales tax refund received in 2016 and a $1.6 million increase in conservation improvement program expenses were $1.7 million less than 2015.in 2017. Conservation improvement program expenses are recovered from certain retail customers. (See Operating Revenue.)

Depreciation and Amortization expense increased $4.6$1.4 million, or 144 percent, from 20152016 primarily due to additional property, plant and equipment in service.

Taxes Other than Income Taxes increased $0.7 million, or 6 percent, from 2015 primarily due to higher property tax expenses resulting from higher taxable plant.



COMPARISON OF THE QUARTERS ENDED JUNE 30, 2016 AND 2015 (Continued)
Regulated Operations (Continued)

Interest Expense decreased $1.2 million, or 9 percent, from 2015 primarily due to lower average interest rates. We record interest expense for Regulated Operations based on Minnesota Power’s rate base and authorized capital structure, and allocate the balance to Corporate and Other.

Equity Earnings in ATC decreased $0.6 million, or 13 percent, from2015 due to period over period changes in ATC’s estimate of a refund liability related to MISO return on equity complaints. Accruals for refund liabilities for the second quarter of 2016 were approximately $1.1 million higher than the second quarter of 2015.

Income Tax Expense increased $2.1 million, or 95 percent, from 2015 primarily due to additional income tax expense recorded in 2016 as GAAP requires the recognition of quarterly income tax expense at the estimated annual effective tax rate. The estimated annual effective tax rate can differ from what a quarterly effective tax rate would otherwise be on a standalone basis, and this may cause quarter to quarter differences in the timing of income taxes.

ALLETE Clean Energy
Quarter Ended June 30,2016
2015
Millions  
Operating Revenue
$18.8

$34.0
Net Income Attributable to ALLETE$2.6
$3.0

Operating Revenue decreased $15.2 million from 2015. Operating revenue in 2015 included the recognition under percentage of completion accounting, of $20.5 million in revenue for the construction of a wind energy facility which was sold to Montana-Dakota Utilities in the fourth quarter of 2015. The decrease in operating revenue was partially offset by revenue generated from the operations of wind energy facilities acquired in April and July 2015.
 Quarter Ended June 30,
 20162015
Production and Operating RevenuekWhRevenuekWhRevenue
Millions    
Wind Energy Facility    
Lake Benton63.5

$3.1
66.4

$3.3
Storm Lake II39.1
2.6
41.1
2.7
Condon22.5
1.9
16.9
1.6
Storm Lake I56.3
2.9
55.8
3.0
Chanarambie/Viking64.5
3.2
57.6
2.9
Armenia Mountain48.8
5.1
—
—
Development Fee—
—
—
20.5
Total294.7
$18.8237.8

$34.0

Net Income Attributable to ALLETE decreased $0.4 million, or 13 percent, from 2015. Net income for 2015 included a $0.9 million after-tax expense for acquisition costs related to the Chanarambie/Viking wind energy facilities. In 2015, net income also included the recognition under percentage of completion accounting, of $1.5 million of after-tax estimated profit for the construction of a wind energy facility which was sold to Montana-Dakota Utilities in the fourth quarter of 2015.



COMPARISON OF THE QUARTERS ENDED JUNE 30, 2016 AND 2015 (Continued)

U.S. Water Services
Quarter Ended June 30,2016
2015
Millions  
Operating Revenue
$34.3

$34.4
Net Income Attributable to ALLETE$1.0$0.6

Operating Revenue for 2016 was consistent with the same period in 2015. Revenue from chemical sales and related services, which includes recurring revenue contracts for the delivery and service of chemicals, increased 5.0% to $27.2 million in 2016 compared to $25.9 million in 2015. Revenue from equipment and related services, which includes sales of water treatment equipment, was $7.0 million for 2016 compared to $8.5 million in 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 ALLETEincreased $0.4 million from 2015. Net income in 2015 included $0.6 million of after-tax expense related to purchase accounting fair value adjustments for inventories and sales backlog. 2016 also reflects increased investments in back office systems and support at U.S. Water Services as we create a platform for future growth.

Corporate and Other

Operating Revenue increased $1.9$1.0 million, or 8 percent, from 2015 primarily due to an increase in land sales at ALLETE Properties.

Net Loss Attributable to ALLETE decreased $3.0 million from 2015 primarily due to additional income tax expense recorded in 2015 as GAAP requires the recognition of quarterly income tax expense at the estimated annual effective tax rate. The estimated annual effective tax rate can differ from what a quarterly effective tax rate would otherwise be on a stand-alone basis, and this may cause quarter to quarter differences in the timing of income taxes. Slightly higher earnings at ALLETE Properties also contributed to the decrease in the net loss.

Income Taxes – Consolidated

For 2016 the effective tax rate was 15.9 percent (22.3 percent for the 2015). The effective tax rate deviated from the combined statutory rate of approximately 41 percent primarily due to production tax credits. (See Note 9. Income Tax Expense.) The estimated annual effective tax rate can differ from what a quarterly effective tax rate would otherwise be on a stand-alone basis, and this may cause quarter to quarter differences in the timing of income taxes.




COMPARISON OF THE SIX MONTHS ENDED JUNE 30, 2016 AND 2015

(See Note 14. Business Segments for financial results by segment.)

Regulated Operations
Six Months Ended June 30,2016
2015
Millions  
Operating Revenue
$487.2

$492.8
Fuel and Purchased Power155.0
166.1
Transmission Services32.9
26.2
Cost of Sales3.9
5.5
Operating and Maintenance104.1
116.5
Depreciation and Amortization76.6
65.8
Taxes Other than Income Taxes25.0
23.7
Operating Income89.7
89.0
Interest Expense(25.8)(27.5)
Equity Earnings in ATC8.9
8.6
Other Income1.2
1.6
Income Before Non-Controlling Interest and Income Taxes74.0
71.7
Income Tax Expense9.0
7.4
Net Income Attributable to ALLETE$65.0
$64.3

Operating Revenue decreased $5.6 million, or 1 percent, from 2015 primarily due to lower fuel adjustment clause recoveries, kWh sales, conservation improvement program recoveries and gas sales, partially offset by higher FERC formula-based rates, cost recovery rider revenue and transmission revenue.

Fuel adjustment clause recoveries decreased $9.9 million due to lower fuel and purchased power costs attributable to retail and municipal customers. (See Operating Expenses - Fuel and Purchased Power Expense.)

Revenue from Regulated Operations decreased $3.5 million due to a 2.0 percent decrease in kWh sales. Sales to our industrial customers decreased 11.9 percent primarily due to reduced taconite production. In addition, demand revenue from our industrial customers was down in 2016 as a result of lower demand nominations. Sales to our residential, commercial and municipal customers have been impacted by warmer temperatures in 2016 compared to the same period in 2015. Heating degree days in Duluth, Minnesota, were approximately 4 percent lower in the first six months of 2016 compared to the same period in 2015. 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 15.5 percent in 2016 compared to 2015. Revenue from Other Power Suppliers increased primarily as a result of more energy available for sale due to reduced demand from our taconite customers, and higher pricing on our wholesale power sales agreements compared to last year.
Kilowatt-hours Sold    Quantity %
Six Months Ended June 30,2016
 2015
 Variance Variance
Millions       
Regulated Utility       
Retail and Municipal       
Residential566
 583
 (17) (2.9)%
Commercial707
 715
 (8) (1.1)%
Industrial3,107
 3,525
 (418) (11.9)%
Municipal406
 420
 (14) (3.3)%
Total Retail and Municipal4,786
 5,243
 (457) (8.7)%
Other Power Suppliers2,315
 2,004
 311
 15.5 %
Total Regulated Utility Kilowatt-hours Sold7,101
 7,247
 (146) (2.0)%

Revenue from electric sales to taconite/iron concentrate customers accounted for 17 percent of consolidated operating revenue in 2016 (21 percent in 2015). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 6 percent of consolidated operating revenue in 2016 (7 percent in 2015). Revenue from electric sales to pipelines and other industrial customers accounted for 7 percent of consolidated operating revenue in 2016 (6 percent in 2015).


COMPARISON OF THE SIX MONTHS ENDED JUNE 30, 2016 AND 2015 (Continued)
Regulated Operations (Continued)

Conservation improvement program recoveries decreased $3.8 million from 2015 primarily due to a reduction in related expenditures. (See Operating Expenses - Operating and Maintenance Expense.)

Gas sales at SWL&P decreased $1.8 million from 2015 as a result of warmer temperatures in 2016 compared to the same period in 2015. (See Cost of Sales.)

Transmission revenue increased $5.3 million primarily due to period over period changes in our estimate of a refund liability related to MISO return on equity complaints. (See Operating Expenses - Transmission Services.)

Cost recovery rider revenue increased $4.0 million primarily due to the completion of the Boswell Unit 4 environmental upgrade in the fourth quarter of 2015.

Revenue from our wholesale customers under formula-based rates increased $2.9 million primarily due to additional environmental and other investments.

Operating Expenses decreased $6.3 million, or 2 percent, from 2015.

Fuel and Purchased Power expense decreased $11.1 million, or 7 percent, from 2015 primarily due to lower purchased power prices and kWh sales in 2016 compared to 2015, partially offset by higher fuel costs in 2016. 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 $6.7 million, or 26 percent, from 2015 primarily due to period over period changes in our estimate of a refund for MISO transmission expense related to MISO return on equity complaints and higher MISO-related expense. (See Operating Revenue and Note 6. Regulatory Matters.)

Cost of Sales decreased $1.6 million, or 29 percent, from 2015 due to lower purchased gas at SWL&P.(See Operating Revenue.)

Operating and Maintenance expensedecreased $12.4 million, or 11 percent, from 2015 primarily due to lower salary and benefit expenses, a $3.6 million sales tax refund received in the first quarter of 2016, and lower conservation improvement program expenses. Conservation improvement program expenses are recovered from certain retail customers. (See Operating Revenue.)

Depreciation and Amortization expense increased $10.8 million, or 16 percent, from 2015 primarily due to additional property, plant and equipment in service.

Taxes Other than Income Taxes increased $1.3 million, or 5 percent, from 2015 primarily due to higher property tax expenses resulting from higher taxable plant.

Interest Expense decreased $1.7increased $0.9 million, or 67 percent, from 20152016 primarily due to lowerhigher average interest rates. We record interest expense for Regulated Operations based on Minnesota Power’s rate base and authorized capital structure, and allocate the balance to Corporate and Other.

Equity Earnings in ATC increased $0.3$1.3 million, or 327 percent, from 20152016 primarily due to additional investmentinvestments in ATC partially offset byand period over period changes in ATC’s estimate of a refund liability related to MISO return on equity complaints. Accruals for refund liabilities for 2016 were approximately $0.4 million higher than 2015.(See Note 7. Investment in ATC.)

Income Tax Expense increased $1.6$4.6 million or 22 percent, from 2015 primarily2016 due to higher income before income taxespre-tax income. We expect our annual effective tax rate in 2016.2017 to be higher than 2016 due to higher pre-tax income.



COMPARISON OF THE SIXTHREE MONTHS ENDED JUNE 30,MARCH 31, 2017 AND 2016 AND 2015 (Continued)

ALLETE Clean Energy
Six Months Ended June 30,2016
2015
Three Months Ended March 31,2017
2016
Millions  
Operating Revenue
$42.4

$46.4

$23.7

$23.6
Net Income Attributable to ALLETE$8.7
$5.5
$6.7
$6.1

Operating Revenue decreased $4.0 million from 2015. Operating revenuewas similar in 2015 included2017 compared to the recognition under percentage of completion accounting, of $20.5 millionsame period in revenue for the construction of a wind energy facility which was sold to Montana-Dakota Utilities in the fourth quarter of 2015. The decrease in operating revenue was partially offset by revenue generated from the operations of wind energy facilities acquired in April and July 2015.2016.
Six Months Ended June 30,Three Months Ended March 31,
2016201520172016
Production and Operating RevenuekWhRevenuekWhRevenuekWhRevenuekWhRevenue
Millions        
Wind Energy Facility    
Wind Energy Facilities    
Lake Benton133.5

$6.5
148.4

$7.2
75.8

$3.5
70.0

$3.4
Storm Lake II91.6
5.6
98.1
6.0
48.2
2.9
52.5
3.0
Condon51.0
4.3
37.7
3.6
24.2
2.0
28.5
2.4
Storm Lake I120.3
6.0
124.9
6.2
69.7
3.4
64.0
3.1
Chanarambie/Viking145.1
6.8
57.6
2.9
80.9
3.9
80.6
3.6
Armenia Mountain140.8
13.2
—
—
87.7
8.0
92.0
8.1
Development Fee—
—
—
20.5
Total682.3
$42.4466.7

$46.4
Total Production and Operating Revenue386.5
$23.7387.6

$23.6

Net Income Attributable to ALLETE increased $3.2$0.6 million, or 10 percent, from 2015 primarily due to income generated from the operations of wind energy facilities acquired in April and July 2015.2016. Net income for 2015in 2016 included an allocation of earnings to a $0.9 million after-tax expense for acquisition costs related tonon-controlling interest in the Chanarambie/Viking wind energy facilities. In 2015, net income also includedlimited liability company that owns the recognition under percentage of completion accounting, of $1.5 million of after-tax estimated profit for the construction of aCondon wind energy facility which was sold to Montana-Dakota Utilitiessubsequently acquired by ALLETE Clean Energy in the fourth quarter of 2015.April 2016. (See Note 3. Acquisitions.)

U.S. Water Services
Six Months Ended
Period February 10, 2015
June 30, 2016
Through June 30, 2015
Three Months Ended March 31,2017
2016
Millions    
Operating Revenue
$66.7

$49.9

$32.1

$32.4
Net Income Attributable to ALLETE$0.5
Net Loss Attributable to ALLETE$(0.3)$(0.5)

Operating Revenue decreased $0.3 million from 2016 primarily due to fewer equipment sales, partially offset by increased $16.8sales of chemicals and related services. Revenue from chemical sales and related services, which includes recurring revenue contracts for the delivery and service of chemicals, was $27.2 million in 20162017 compared to the period$25.9 million in 2016. Revenue from February 10, 2015,equipment and related services, which includes sales of water treatment equipment, was $4.9 million for 2017 compared to June 30, 2015. The results for 2015 reflect operations$6.5 million in 2016; equipment sales can fluctuate from the date of acquisition, February 10, 2015, through June 30, 2016, and therefore, do not reflect a full six months.quarter to quarter.

Net IncomeLoss Attributable to ALLETE was similardecreased $0.2 million from 2016. The net loss in 2017 includes an after-tax expense of $0.2 million for the six months ended June 30,settlement of an EPA investigation, and lower operating expenses. (See Note 13. Commitments, Guarantees and Contingencies.) The net loss in 2016 comparedincluded $0.3 million of after-tax expense recognized as cost of sales related to the period from February 10, 2015, to June 30, 2015.purchase accounting for inventories and sales backlog. U.S. Water Services sells certain products which are seasonal in nature, with higher demand typically realized in warmer months. The results for 2015 reflect operations frommonths; generally, lower sales occur in the datefirst quarter of acquisition, February 10, 2015, through June 30, 2016, and therefore do not reflect a full six months. Net income for the six months ended June 30, 2016, included $0.3 million of after-tax expense related to purchase accounting fair value adjustments for inventories and sales backlog ($0.9 million from February 10, 2015, through June 30, 2015); these purchase accounting adjustments were fully recognized as of March 31, 2016. 2016 also reflects increased investments in back office systems and support at U.S. Water Services as we create a platform for future growth.each year.



COMPARISON OF THE SIXTHREE MONTHS ENDED JUNE 30,MARCH 31, 2017 AND 2016 AND 2015 (Continued)

Corporate and Other

Operating Revenue decreased $1.9increased $2.7 million, or 411 percent, from 20152016 primarily due to a decreasean increase in revenue at BNI Energy, which operates under cost-plus fixed fee contracts, as a result of lowerhigher expenses partially offset by higher revenue from more coal delivered at BNI Energy. In addition, ALLETE Properties had more land sales in 2016 than 2015.2017 compared to the same period in 2016.

Net Loss Attributable to ALLETE decreased $4.4$1.2 million from 20152016 primarily due to a $3.0 million after-taxlower accretion expense in 2015 for acquisition costs related to U.S. Water Services.resulting from the contingent consideration liability. Net income at BNI Energy increased to $3.7was $1.8 million in 20162017 compared to $3.2$2.0 million for the same period in 2015,2016, and the net loss at ALLETE Properties decreased to $1.6was $1.2 million in 20162017 compared to $2.0a net loss of $1.1 million for the same period in 2015.2016.

Income Taxes – Consolidated

For the sixthree months ended June 30, 2016,March 31, 2017, the effective tax rate was 16.421.1 percent (16.8(16.7 percent for the sixthree months ended June 30, 2015)March 31, 2016). The increase from the three months ended March 31, 2016, was primarily due to higher pre-tax income. We expect our annual effective tax rate in 2017 to be higher than 2016 due to higher pre-tax income. The effective rate deviated from the combined statutory rate of approximately 41 percent primarily due to production tax credits. (See Note 9. Income Tax Expense.)


CRITICAL ACCOUNTING POLICIES

Certain accounting measurements under GAAP involve management’s judgment about subjective factors and estimates, the effects of which are inherently uncertain. Accounting measurements that we believe are most critical to our reported results of operations and financial condition include: regulatory accounting, pension and postretirement health and life actuarial assumptions, impairment of long-lived assets, taxation and valuation of goodwill and intangible assets. These policies are reviewed with the Audit Committee of our Board of Directors on a regular basis and summarized in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 20152016 Form 10-K.

Valuation of Goodwill and Intangible Assets.

Goodwill. Our 2016 annual testing of U.S. Water Services’ goodwill for impairment indicated the calculated fair value of equity for the reporting unit exceeded carrying value by less than 10 percent. Significant assumptions utilized in the fair value calculation included a discount rate of 10.75 percent, cash flow forecasts through 2021, annual revenue growth rates ranging from 8 percent to 11 percent and a terminal growth rate of 5.0 percent. If U.S. Water Services fails to meet expected cash flow forecasts by a nominal margin or there is an increase in interest rates that has a negative impact on the discount rate used in the Company’s valuation under the income approach, the results of our future tests could result in an impairment of goodwill; our next annual impairment test will occur in the fourth quarter of 2017. Subsequent to our 2016 annual impairment test, there have been no triggering events or indicators of impairment of goodwill.


OUTLOOK

For additional information see our 20152016 Form 10-K.

ALLETE is an energy company committed to earning a financial return that rewards our shareholders, allows for reinvestment in our businesses and sustains growth. The Company has long-term objectives of achieving average annual earnings per share growth of a minimum of 5five 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 its Regulated Operations segment to be approximately 85 percent to 90 percent of total consolidated net income in 2016.2017. 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.



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 approvalapprovals for environmental,transmission, renewable and transmissionenvironmental 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. We are preparing for our next general rate case at Minnesota Power and expect to file in the fourth quarter of 2016.



OUTLOOK (Continued)

Regulatory Matters. Entities within our Regulated Operations segment are under the jurisdiction of the MPUC, the FERC, the PSCW or theand NDPSC. See Note 6. Regulatory Matters for discussion of regulatory matters within these jurisdictions.

2016 Minnesota General Rate Case. In November 2016, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 9 percent for retail customers. The rate filing seeks a return on equity of 10.25 percent and a 53.8 percent equity ratio. On an annualized basis, the requested final rate increase would have generated approximately $55 million in additional revenue. In December 2016, Minnesota Power filed a request to modify its original interim rate proposal reducing its requested interim rate increase to $34.7 million from the original request of approximately $49 million due to a change in its electric sales forecast. In December 2016 orders, the MPUC accepted the November 2016 filing as complete and authorized an annual interim rate increase of $34.7 million beginning January 1, 2017.

On February 23, 2017, Minnesota Power filed an additional request to further reduce its requested interim rate increase. In an order dated April 13, 2017, the MPUC approved Minnesota Power’s updated retail rate request resulting in a reduction in the annual interim rate increase to $32.2 million beginning May 1, 2017. On February 28, 2017, Minnesota Power filed an update to its rate increase request, reducing its requested final retail rate increase from approximately $55 million to approximately $39 million on an annualized basis. As of March 31, 2017, Minnesota Power has not received any indication that a refund of interim rates will be necessary. Management will continue to evaluate the need for a reserve for interim rates as the 2016 general rate case proceeds.
As part of the 2016 Minnesota general rate request and through Minnesota Power’s 2017 remaining life depreciation petition filed on February 1, 2017, Minnesota Power is seeking an extension of the recovery period for Boswell to better reflect recent environmental investments at the facility and mitigate rate increases for our Minnesota, FERC,customers. If approved, annual depreciation expense will be reduced by approximately $25 million. If the requested recovery period extension is not approved, we would expect final rates to be increased by a similar amount, subject to regulatory approval. We cannot predict the level of final rates that may be authorized by the MPUC.

2016 Wisconsin General Rate Case.SWL&P’s current retail rates are based on a 2012 PSCW retail rate order that allows for a 10.9 percent return on common equity. In June 2016, SWL&P filed a rate increase request with the PSCW requesting an average increase of 3.1 percent for retail customers (3.5 percent increase in electric rates; 1.3 percent decrease in natural gas rates; and North Dakota jurisdictions.7.8 percent increase in water rates). The filing seeks an overall return on equity of 10.9 percent and a 55 percent equity ratio. On an annualized basis, the requested rate increase would generate approximately $2.7 million in additional revenue. The Company anticipates new rates will take effect in mid-2017. We cannot predict the level of rates that may be approved by the PSCW.

Industrial Customers and Prospective Additional LoadLoad.

Industrial Customers. Electric power is one of several key inputs in the taconite mining, iron concentrate, paper, pulp and secondary wood products, pipeline and pipelineother industries. Approximately 4147 percent of our regulated utility kWh sales in the sixthree months ended June 30, 2016 (46 percent in the six months ended June 30, 2015)March 31, 2017, were made to our industrial customers (44 percent in these industries.the three months ended March 31, 2016).

Taconite and Iron Concentrate. Minnesota Power provides electric service to fivesix taconite customersfacilities capable of producing up to approximately 41 million tons of taconite pellets annually. Taconite pellets produced in Minnesota are primarily shipped to North American steel making facilities that are part of the integrated steel industry. Steel produced from these North American facilities is used primarily in the manufacture of automobiles, appliances, pipe and tube products for the gas and oil industry, and in the construction industry. Historically, less than five percent of Minnesota taconite production is exported outside of North America. Minnesota Power also provides electric service to three iron concentrate customersfacilities capable of producing up to approximately 4 million tons of iron concentrate per year. Iron concentrate is used in the production of taconite pellets. These iron concentrate facilities are owned in whole, or in part, by ERP Iron Ore and are not currently operating. (See ERP Iron Ore / Magnetation.)


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

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 7273 percent of capacity during the first sixthree months of 20162017 compared to 7370 percent in the first sixthree months of 2015. 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.2016. The World Steel Association, an association of over 150160 steel producers, national and regional steel industry associations, and steel research institutes representing approximately 85 percent of world steel production, projected U.S. steel consumption in 20162017 will increase compared to 2015. While steel consumption is expected to increase in the U.S. in 2016, there is a natural lag between U.S. steel consumption and Minnesota taconite production. The high level of imports and lower prices in 2015 continue to impact Minnesota taconite production in 2016. In 2015, petitions regarding unfairly traded cold-rolled, hot-rolled and corrosion-resistant steel products were filed by domestic steel producers with the U.S. Department of Commerce and U.S. International Trade Commission resulting in countervailing duty and antidumping investigations. The U.S. Department of Commerce has since made final affirmative determinations in the investigations for corrosion-resistant steel products and cold-rolled steel products as well as preliminary affirmative determinations in the investigations for hot-rolled steel products. The U.S. International Trade Commission has also made an affirmative ruling on corrosion-resistant steel products, concluding that investigation; final determinations for cold-rolled and hot-rolled steel products are expected in 2016. As a result of the affirmative determinations, cash deposits are collected on these products when imported from certain countries. According to the U.S. Census Bureau, May 2016 year-to-date imports for consumption of steel products are down approximately 303 percent compared to May 2015 year-to-date imports.2016.

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. Minnesota Power proactively sells power in the wholesale power markets that is temporarily not required by industrial customers to optimize the value of its generating facilities. Long-term reductions in taconite production or a permanent shut down of a taconite customer may lead Minnesota Power to file a general 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 four-month periods. Based on nominations received on July 29, 2016, Minnesota Power’s Large Power taconite customers nominated at approximately 90 percent of full demand levels for September through December of 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.



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

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.production in the third quarter of 2015, and in the first quarter of 2017, USS Corporation’sCorporation restarted its Keetac plant remains idled.plant. 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.

ERP Iron Ore / Magnetation. In May 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 StatesU.S. Bankruptcy Court for the District of Minnesota, citing the significant decrease in global iron ore prices and its existing capital structure.

In January 2016, Magnetation stated that it intends to continue to pay suppliers and vendorsidled its Plant 2 facility in full under normal terms for goods and services provided afterBovey, Minnesota. In October 2016, the bankruptcy filing date. Minnesota Power has received payment of all pre-petition amounts due from Magnetation.

court approved plans to idle Magnetation’s Plant 4 iron concentrate facility isnear Grand Rapids, Minnesota, and its pellet plant in Reynolds, Indiana, as well as terminate Magnetation’s pellet purchase agreement with AK Steel Corporation. The company subsequently idled the facilities and stated it was preserving the plants and their value for a Large Power Customerpotential buyer. On January 30, 2017, ERP Iron Ore purchased substantially all of Minnesota Power. In July 2015,Magnetation’s assets pursuant to an asset purchase agreement approved by the bankruptcy court. Although we cannot predict whether the facilities will be restarted, Minnesota Power filed a petition withwould serve the MPUC for approval of a new electric service agreement for service to both Magnetation’s Plant 2 and Plant 4 facilities with a term through at least December 31, 2025. ThisERP Iron Ore’s assumption of the existing electric service agreement was approved by the MPUC in an order dated February 2, 2016, and was subsequently approved by the bankruptcy court.

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 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. On June 9, 2016, Cliffs announced it will be restarting operations at its United Taconite plant in August 2016 following the announcements of Cliffs’ 10-year supply agreement with a major steel client and additional business contracted with another customer. United Taconite has the capability to produce approximately 5 million tons of taconite annually. On May 23, 2016, Minnesota Power extended its electric service agreements with Cliffs for 10 years at Cliffs' United Taconite and Babbitt facilities, subject to regulatory approval.agreement.

Silver Bay PowerPaper, Pulp and Secondary Wood Products. On May 23, 2016,In addition to serving the taconite industry, Minnesota Power entered into multiple agreements with Cliffsserves a number of customers in the paper, pulp and its subsidiaries. Under one of the agreements, Minnesota Power paid $31.0 millionsecondary wood products industry. The four major paper and pulp mills we serve reported operating at, or near, full capacity in cash as part of a long-term power sales agreement through 2031 between Minnesota Power2016, and Silver Bay Power. Silver Bay Power provides the majority of the electric service requirements for Northshore Mining, which has the capability to produce approximately 6 million tons of taconite annually. (See Note 13. Commitments, Guarantees and Contingencies.)similar levels are expected in 2017.

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 July 8,Mesabi Metallics, which changed its name from Essar Steel Minnesota LLC in December 2016, Minnesota Governor Dayton instructed the Minnesota Department of Natural Resources to terminate Essar’s mineral lease agreements with the state. Governor Dayton stated that Essar failed to pay full amounts owed to Minnesota contractors and show it has the ability to carry its current construction project through to completion, or provide reliable assurances that it will be able to do so in the foreseeable future.

Essar filed for bankruptcy protection on July 8, 2016, under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. In its filings Essar stated that it has arranged funding sources and intends to continue its project in Minnesota post-bankruptcy. Essar is a retail customer of the Nashwauk Public Utilities Commission, and Minnesota Power has a wholesale electric sales agreement with the Nashwauk Public Utilities Commission for electric service through at least June June��2028. Essar also makes ongoing payments to Minnesota PowerMesabi Metallics filed for electric transmission infrastructure costs. Essar’s pre-petition debt to Minnesota Power is not material.bankruptcy protection in July 2016, under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. The debtors initiated an auction process in Bankruptcy Court and at an April 26, 2017 hearing announced Chippewa Capital Partners (Chippewa) as the successful bidder. Chippewa now has the responsibility for finalizing a plan of reorganization, and upon approval by the debtors and the Bankruptcy Court could emerge from bankruptcy protection later this year.



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

Under the agreements for providing energy and capacity to Essar, Essar is obligated to increase “take or pay” payments on July 1, 2016. Minnesota Power, the Nashwauk Public Utilities Commission and Essar will propose to the bankruptcy court that the agreements will remain in place and payments under them will continue through at least December 2016. This agreement will require bankruptcy court approval, and we cannot predict the outcome of the bankruptcy court’s action.

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. In November 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 Minnesota Department of Natural Resources (DNR) issued its Record of Decision onin March 3, 2016, finding the final EIS adequate. The 30-day period allowed by law to challenge the Record of Decision passed without any legal challenges being filed. OnIn July 11, 2016, PolyMet submitted applications for water-related permits with the State of Minnesota, which are expectedand in August 2016, an application for an air quality permit was submitted to be followed by the submission ofMPCA. In November 2016, PolyMet submitted a state permit to mine application to the remaining permit applications in 2016.DNR detailing its operational plans for the mine. The final EIS also requires Records of Decision by the federal agencies, which are expected in 2016,2017, before final action can be taken on the required federal permits to construct and operate the mining operation. On January 9, 2017, the U.S. Forest Service signed the Final Record of Decision authorizing a land exchange with PolyMet, which upon completion of title transfer will result in PolyMet obtaining surface rights to land needed to develop its 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.

Louisiana-Pacific Corporation. Louisiana-Pacific Corporation recently announced that it is considering the construction of a wood siding plant at the Laskin Energy Park in Hoyt Lakes, Minnesota, at a total estimated cost of approximately $400 million. The plant would be located in Minnesota Power’s service territory, and employ about 250 people.

EnergyForward. In 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 SO2, particulates and mercury. (See Boswell Mercury Emission Reduction Plan.)
Planning for the proposed GNTL to deliver hydroelectric power from northern Manitoba by 2020. (See Transmission.)
The conversion of Laskin from coal to cleaner-burning natural gas 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.

In July 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 which occurred in the fall ofSeptember 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).Plan. 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. In September 2015, Minnesota Power filed its 2015 IRP with the MPUC which containscontained the next steps in its EnergyForward strategic plan, and includesincluded an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. In ana July 2016 order, dated July 18, 2016, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The order accepts Minnesota Power’s plans for Taconite Harbor, directs Minnesota Power to retire Boswell Units 1 and 2 no later than 2022, requires an analysis of generation and demand response alternatives to be filed with a natural gas resource proposal, and requires Minnesota Power to conduct request for proposals for additional wind, solar and demand response resource additions subject to further MPUC approvals. In October 2016, Minnesota Power announced that Boswell Units 1 and 2 will be retired in 2018 as the latest step in its EnergyForward strategic plan. Minnesota Power’s next IRP must be filed by February 1, 2018.



OUTLOOK (Continued)
EnergyForward (Continued)

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 in September 2015 and approved with modifications by the MPUC in an order dated July 18, 2016, includes an update on its plans and progress in meeting the Minnesota renewable energy milestones through 2025. (See EnergyForward.)

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 and expects approximately 3029 percent of its applicable retail and municipal energy sales will be supplied by renewable energy sources in 2016.2017.


OUTLOOK (Continued)
EnergyForward (Continued)

Minnesota Solar Energy Standard. In May 2013, legislation was enacted by the state of Minnesota requiring at least 1.5 percent of total retail electric sales, excluding sales to certain 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 kW or less. Minnesota Power has two completed solar projects and another solar project is under development. In August 2015, Minnesota Power filed for MPUC approval of a 10 MW utility scale solar project at the Camp Ripley a Minnesota Army National Guard base and training facility near Little Falls, Minnesota. In ana February 2016 order, dated February 24, 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.which was subsequently finalized by the MPUC in a December 2016 order. Camp Ripley was completed in the fourth quarter of 2016. In September 2015, Minnesota Power filed for MPUC approval of a community solar garden project in Duluth,northeastern Minnesota, which is comprised of a 1 MW solar array to be owned and operated by a third party with the output purchased by Minnesota Power and a 40 kW solar array that will beis owned and operated by Minnesota Power. In ana July 2016 order, dated July 27, 2016, the MPUC approved the community solar garden project and cost recovery, subject to certain compliance requirements. Minnesota Power believes these projects will meet approximately one-third of the overall mandate. Additionally, on June 1, 2016,in an order dated February 10, 2017, the MPUC approved Minnesota Power filed aPower’s proposal with the MPUC to increase the amount of solar rebates available for customer-sited solar installations and recover costs of the program through Minnesota Power’s renewable cost recovery rider. If approved, Minnesota Power expects the projectsThis proposal to incentivize customer-sited solar installations is expected to meet parta portion of the required mandate related to solar photovoltaic devices with a nameplate capacity of 20 kW or less.

Minnesota Power has approval for current cost recovery of investments and expenditures related to compliance with the Minnesota Solar Energy Standard. Currently, there is no approved customer billing rate for solar costs.

Wind Energy. Minnesota Power’s wind energy facilities consist of the 497 MW Bison Wind Energy Center(497 MW) located in North Dakota, and the 25 MW Taconite Ridge Energy Center(25 MW) 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.

Minnesota Power uses the 465-mile, 250 kV250-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.

Updated customer billing rates for the renewable cost recovery rider, which includes investments and expenditures related to the Bison, Wind Energy Center, were approved by the MPUC in ana December 2016 order, dated March 9, 2016, allowingwhich allows Minnesota Power to charge retail customers on a current basis for the costs of constructing certain renewable investments plus a return on the capital invested. While approvingThe approval is on a provisional basis pending the updated customer billing rates for the renewable cost recovery rider,outcome of Minnesota Power’s 2016 general rate case.

In a November 2016 order, the MPUC also alloweddirected Minnesota Power additional time to submit support for its position on its utilization ofattribute all North Dakota investment tax credits.credits realized from Bison to Minnesota Power regulated retail customers. As a result of the adverse regulatory outcome, Minnesota Power recorded a regulatory liability and a reduction in operating revenue of $15.0 million in 2016. The North Dakota investment tax credits previously recognized as income tax credits in Corporate and Other were reversed in 2016 resulting in an $8.8 million charge to net income for the year ended December 31, 2016. In December 2016, Minnesota Power submitted a request for reconsideration with the MPUC. In an order dated February 14, 2017, the MPUC decided to reconsider its November 2016 order and requested comments by June 30, 2017.



OUTLOOK (Continued)
EnergyForward (Continued)

Prior to the November 2016 MPUC order, Minnesota Power accountsaccounted for North Dakota investment tax credits based on long-standingthe long‑standing regulatory precedents of stand-alone allocation methodology of accounting for income taxes. The stand-alone method provides that income taxes (and credits) are calculated as if Minnesota Power was the only entity included in ALLETE’s consolidated federal and unitary state income tax returns. Minnesota Power hashad recorded a regulatory liability for North Dakota investment tax credits generated by its jurisdictional activity and expected to be realized in the future. North Dakota investment tax credits attributable to ALLETE’s apportionment and income of ALLETE’s other subsidiaries arewere included in the ALLETE consolidated group. The Minnesota Department of Commerce (Department) has inquired about our use of the North Dakota investment tax credits, taking the position that all North Dakota investment tax credits generated from the Bison Wind Energy Center should be credited to Minnesota Power ratepayers. The MPUC did not come to a decision on this issue in its order dated March 9, 2016, but requested that Minnesota Power provide further support on its position which was submitted on April 8, 2016. On April 22, 2016, the Department submitted additional comments restating its position that the tax credits should be credited to ratepayers.

The amount of North Dakota investment tax credits recognized by ALLETE as of June 30, 2016, total approximately $8 million, which represents the amount of North Dakota investment tax credits that the Department believes should be refunded to ratepayers. Minnesota Power will appropriately consider all avenues of appeal should an adverse decision be issued by the MPUC.

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.


OUTLOOK (Continued)
EnergyForward (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 Manitoba Conservation and Water Stewardship for regulatory approval. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in 2014.(See Transmission – 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. (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.

Boswell Mercury Emissions Reduction Plan. Minnesota Power has an approved environmental improvement rider in place for investments and expenditures related to the implementation of the Boswell Unit 4 mercury emissions reduction plan completed in 2015. Customer billing rates for the environmental improvement rider were approved by the MPUC in August 2015. In September 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, investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others), and our investment in ATC.

Great Northern Transmission Line (GNTL).Line. As a condition of the 250-MW long-term PPA signed in May 2011entered into 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 kV500-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.


OUTLOOK (Continued)
Transmission (Continued)

The GNTL is subject to various federal and state regulatory approvals. In October 2013,2015, a certificate of need application was filed with the MPUC which was approved in a June 2015 order.by the MPUC. 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 factorcost recovery filings. (See Note 6. Regulatory Matters.) In a December 2015, order, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In an 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 an2016 order, dated April 11, 2016, the MPUC approved the route permit for the GNTL which largely follows Minnesota Power’s preferred route, including the international border crossing. A final decision on the presidential permit bycrossing, and in November 2016, the U.S. Department of Energy issued a presidential permit to cross the U.S.-Canadian border, which was the final major regulatory approval needed before construction in the U.S. could begin. Site clearing and pre-construction activities commenced in the first quarter of 2017 with construction expected 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, of which Minnesota Power’s portion is expected to be between $300 million and $350 million; the difference will be recovered from a subsidiary of Manitoba Hydro as contributions in the third quarteraid of 2016. construction. Total project costs of $56.8 million have been incurred through March 31, 2017, of which $29.6 million has been recovered from a subsidiary of Manitoba Hydro.

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. 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. As of June 30, 2016,March 31, 2017, our equity investment in ATC was $129.0$140.2 million ($124.5135.6 million as of December 31, 2015)2016). In the first sixthree months of 2016,2017, we invested $1.6$3.1 million in ATC, and on July 29, 2016,April 28, 2017, we invested an additional $1.9 million. We expect to make additional investments of approximately $2.7$5.9 million in 2016.2017. (See Note 7. Investment in ATC.)

In November 2013, several customer groups located within the MISO service area filed complaints withSeptember 2016, the FERC requesting, among other things, a reduction in the base return on equity used by MISO transmission owners, including ATC, to 9.15 percent. In December 2015, a federal administrative law judge ruled on the November 2013 complaint proposing a reduction in the baseissued an order reducing ATC’s authorized return on equity to 10.32 percent, subjector 10.82 percent including an incentive adder for participation in a regional transmission organization. Prior to approval or adjustmentthis order, ATC had been allowed a return on equity of 12.2 percent which had been impacted by the FERC. A final decision from the FERC on the administrative law judge’s recommendation is expected in 2016.

In February 2015, an additional complaint wasreductions for estimated refunds related to complaints filed with the FERC seeking an order to further reduceby several customers located within the base return on equity to 8.67 percent. OnMISO service area.


OUTLOOK (Continued)
Transmission (Continued)

In June 30, 2016, a federal administrative law judge ruled on the February 2015an additional complaint proposing a further reduction in the base return on equity to 9.70 percent, or 10.20 percent including an incentive adder for participation in a regional transmission organization, subject to approval or adjustment by the FERC. A final decision from the FERC on the administrative law judge’s recommendation is expected in 2017. On January 6, 2015, the FERC approved an incentive adder of up to 50 basis points on the allowed base return on equity for our participation in a regional transmission organization, subject to the outcome of the return on equity complaints. Our equity earnings in ATC continue to be impacted by these reductions for estimated refunds and reflect these administrative law judge recommendations. ATC's current authorized return on equity is 12.2 percent.(See Note 6. Regulatory Matters.) 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 after-tax ($0.9 million pre-tax).after-tax.

ATC’s 10-year transmission assessment, which covers the years 2016 through 2025, identifies a need for between $3.6 billion and $4.4 billion in transmission system investments. These investments by ATC, if undertaken, 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.

Energy Infrastructure and Related Services.

ALLETE Clean Energy.

ALLETE Clean Energy 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.is from PSAs of various durations. In addition, ALLETE Clean Energy constructed and sold a 107 MW wind energy facility in 2015. On January 3, 2017, ALLETE Clean Energy announced that it will develop another wind energy facility of up to 50 MW after securing a 25-year PSA with Montana-Dakota Utilities. The PSA includes an option for saleMontana-Dakota Utilities to Montana-Dakota Utilities;purchase the facility upon completion; construction is expected to begin in 2018. On March 16, 2017, ALLETE Clean Energy announced it will build, own and sale were completedoperate a separate 100 MW wind energy facility pursuant to a 20-year PSA with Northern States Power; construction is expected to begin in the fourth quarter of 2015.late 2018 and is subject to regulatory approvals.

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 exampleState renewable portfolio standards, and state or federal regulations to limit GHG emissions are examples of an environmental regulation or public policy 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’sand its strategy also includes the exploration of power sales agreementPSA extensions upon expiration of existing contracts.



OUTLOOK (Continued)
ALLETE Clean Energy (Continued)

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 millionup to $100 million range, and200 MW each, which have long-term power sales agreementsPSAs in place for the facility’sfacilities’ output. At this time, ALLETE Clean Energy expects acquisitions will be primarily wind or solar facilities in North America. ALLETE Clean Energy is also targeting the development of new facilities up to 200 MW each, which will have long-term PSAs in place for the output or may be sold upon completion. Federal production tax credit qualification is important to development project economics, and ALLETE Clean Energy invested approximately $100 million in equipment in late 2016 to meet production tax credit safe harbor provisions.


OUTLOOK (Continued)
ALLETE Clean Energy (Continued)

ALLETE Clean Energy will managemanages risk by having a diverse portfolio of assets, which will include power sales contractincludes PSA expiration and geographic diversity. The current mix of power sales agreementPSA expiration and geographic location for existing facilities is as follows:
Wind Energy FacilityLocationCapacity MWPPA MW %PPA ExpirationLocationCapacity MWPSA MW %PSA Expiration
Armenia MountainPennsylvania100.5100%December 2024Pennsylvania100.5100%2024
Chanarambie/VikingMinnesota97.5 Minnesota97.5 
PPA 1 12%February 2018
PPA 2 88%February 2023
PSA 1 12%2018
PSA 2 88%2023
CondonOregon50100%October 2022Oregon50100%2022
Lake BentonMinnesota104100%December 2028Minnesota104100%2028
Storm Lake IIowa108100%December 2019Iowa108100%2019
Storm Lake IIIowa77 Iowa77 
PPA 1 90%April 2019
PPA 2 10%April 2032
PSA 1 90%2019
PSA 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 4,6004,800 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.industries, among others. U.S. Water Services principally relies upon recurring revenues from a diverse mix of industrial customers. U.S. Water Services’Services sells certain products which are seasonal in nature, with higher demand typically realized in warmer months. The results for 2015 reflect operations frommonths; generally, lower sales occur in the datefirst quarter of acquisition, February 10, 2015, through June 30, 2015, and therefore, do not reflect a full six months. each year.

Our strategy is to grow U.S. Water Services’ presence in North American presenceAmerica by adding customers, products and new geographies. We believe water scarcity and a growing emphasis on conservation will continue to drive significant growth in the industrial, commercial and governmental sectors leading to organic revenue growth for U.S. Water Services. U.S. Water Services also expects to pursue periodic strategic tuck-in acquisitions with a purchase price in the $10 million to $50 million range. Priority will be given to acquisitions which expand its geographic reach, add new technology, or deepen its capabilities to serve its expanding customer base.

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.

BNI Energy. BNI Energy anticipates selling 4.34.6 million tons of coal in 2016 (4.32017 (3.8 million tons were sold in 2015)2016) and has sold 2.31.2 million tons through June 30, 2016 (2.1for the three months ended March 31, 2017 (1.2 million tons were sold as of June 30, 2015)for the three months ended March 31, 2016). BNI Energy operates under cost-pluscost‑plus fixed fee agreements extending through December 31, 2037.

ALLETE Properties. ALLETE Properties represents our legacy Florida real estate investment. Market conditions can impact land sales and could result in our inability to cover our cost basis, operating expenses or fixed carrying costs such as community development district assessments and property taxes.


OUTLOOK (Continued)
Corporate and Other (Continued)

ALLETE Properties’ major projects in Florida are Town Center at Palm Coast and Palm Coast Park, and Ormond Crossings. Separately, the Lake Swamp wetland mitigation bank was permitted onwith approximately 4,100 acres combined of land that was previously part of Ormond Crossings.

available-for-sale. In addition to the threethese two projects, and the mitigation bank, ALLETE Properties has approximately 1,100 acres of other land available-for-sale.

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


OUTLOOK (Continued)

Income Taxes.

ALLETE’s aggregate federal and multi-state statutory tax rate is approximately 41 percent for 2016.2017. On an ongoing basis, ALLETE has tax credits and other tax adjustments that reduce the combined statutory rate to the effective tax rate. These tax credits and adjustments historically have included items such as investment tax credits, production tax credits, AFUDC–Equity,AFUDC-Equity, depletion, as well as other items. The annual effective rate can also be impacted by such items as changes in income before non-controlling interest and income taxes, state and federal tax law changes that become effective during the year, business combinations, tax planning initiatives and resolution of prior years’ tax matters. We expect our effective tax rate to be approximately 1620 percent for 20162017 primarily due to federal production tax credits as a result of wind energy generation. We also expect that our effective tax rate will be lower than the combined statutory rate over the next nineeight years due to production tax credits attributable to our wind energy generation.


LIQUIDITY AND CAPITAL RESOURCES

Liquidity Position. ALLETE is well-positioned to meet the Company’s liquidity needs. As of June 30, 2016March 31, 2017, we had cash and cash equivalents of $91.9$81.8 million, $395.2$396.1 million in available consolidated lines of credit and a debt-to-capital ratio of 4644 percent.

Capital Structure. ALLETE’s capital structure is as follows:
June 30,
2016
 % December 31,
2015
 %March 31,
2017
 % December 31,
2016
 %
Millions              
ALLETE Equity
$1,852.1
 54 
$1,820.2
 53
Non-Controlling Interest—
 — 2.2
 —
Shareholders’ Equity
$2,001.5
 56 
$1,893.0
 55
Long-Term Debt (Including Long-Term Debt Due Within One Year)1,575.2
 46 1,605.0
 471,543.4
 44 1,569.1
 45
Notes Payable0.9
 — 1.6
 —1.3
 — —
 —

$3,428.2
 100 
$3,429.0
 100
$3,546.2
 100 
$3,462.1
 100

Cash Flows. Selected information from ALLETE’sthe Consolidated Statement of Cash Flows is as follows:
For the Six Months Ended June 30,2016
 2015
For the Three Months Ended March 31,2017
 2016
Millions      
Cash and Cash Equivalents at Beginning of Period
$97.0
 
$145.8

$27.5
 
$97.0
Cash Flows from (used for)      
Operating Activities146.2
 182.3
98.7
 93.2
Investing Activities(73.9) (371.2)(41.1) (42.6)
Financing Activities(77.4) 103.7
(3.3) (50.6)
Change in Cash and Cash Equivalents(5.1) (85.2)54.3
 —
Cash and Cash Equivalents at End of Period
$91.9
 
$60.6

$81.8
 
$97.0

Operating Activities. Cash from operating activities was $146.2 million for the six months ended June 30, 2016 ($182.3 million for the six months ended June 30, 2015). Cash from operating activities was lowerhigher in 2017 compared to 2016 primarily due to contract billings in excesshigher recoveries of construction costsour cost recovery riders, net income and estimated earnings related to the wind facility developed by ALLETE Clean Energy for sale to Montana-Dakota Utilities in 2015,non-cash items (primarily depreciation expense and payment of $31.0 million made as part of a long-term power sales agreement between Minnesota Power and Silver Bay Power,deferred income tax expense), partially offset by higher recoveries under cost recovery riders, the timing of accounts payable payments and lower fuel inventory purchases.inventories.


LIQUIDITY AND CAPITAL RESOURCES (Continued)

Investing Activities. Cash used for investing activities was $73.9 million for the six months ended June 30,lower in 2017 compared to 2016 ($371.2 million for the six months ended June 30, 2015). The decrease in cash used for investing activities was primarily due to $214.4 million used in 2015, net of cash acquired, for the acquisition of U.S. Water Services in February 2015 and ALLETE Clean Energy’s April 2015 acquisition, as well as $65.7 million of lowerfewer capital expenditures in 2016.2017, partially offset by additional investment in ATC.

Financing Activities. Cash used for financing activities was $77.4 million for the six months ended June 30,lower in 2017 compared to 2016 ($103.7 million from financing activities for the six months ended June 30, 2015). The decrease in cash from financing activities was primarily due to $133.0 million in lowerhigher proceeds from the issuance of common stock, partially offset by higher contingent consideration payments. (See Securitiesand higher repayments of long-term debt of $28.7 million in 2016.Note 5. Fair Value.)


LIQUIDITY AND CAPITAL RESOURCES (Continued)

Working Capital. Additional working capital, if and when needed, generally is provided by consolidated bank lines of credit and the saleissuance of securities or commercial paper. As of June 30, 2016,March 31, 2017, we had consolidated bank lines of credit aggregating $408.4$409.0 million ($408.4409.0 million as of December 31, 2015)2016), the majority of which expire in November 2018.2019. We had $12.3$11.6 million outstanding in standby letters of credit and $0.9$1.3 million outstanding in draws under our lines of credit as of June 30, 2016March 31, 2017 ($12.411.1 million in standby letters of credit and $1.6 millionno outstanding in draws as of December 31, 2015)2016). In addition, as of June 30, 2016,March 31, 2017, we had 3.63.3 million original issue shares of our common stock available for issuance through Invest Direct, our direct stock purchase and dividend reinvestment plan, and 4.02.9 million original issue shares of common stock available for issuance through a distribution agreement with Lampert Capital Markets, Inc. (See Securities.) The amount and timing of future sales of our securities will depend upon market conditions and our specific needs.

Securities. We entered into a distribution agreement with Lampert Capital Markets, Inc., in 2008, as amended most recently in February 2015,August 2016, with respect to the issuance and sale of up to an aggregate of 13.6 million shares of our common stock, without par value, of which 4.02.9 million shares remain available for issuance. For the sixthree months ended June 30, 2016, noMarch 31, 2017, 1.0 million shares of common stock were issued under this agreement, (1.3 million shares were issued for the six months ended June 30, 2015, resulting in net proceeds of $69.9 million)$65.7 million (none for the three months ended March 31, 2016). The shares issued in 20152017 were offered and sold pursuant to Registration Statement No. 333-190335.333-212794, pursuant to which the remaining shares will continue to be offered for sale, from time to time.

During the sixthree months ended June 30, 2016,March 31, 2017, we issued 0.30.1 million shares of common stock through Invest Direct, the Employee Stock Purchase Plan, and the Retirement Savings and Stock Ownership Plan, resulting in net proceeds of $15.2$4.9 million (0.2 million shares were issued for the sixthree months ended June 30, 2015,March 31, 2016, resulting in net proceeds of $12.9$9.0 million). These shares of common stock were registered under Registration Statement Nos. 333-211075, 333-188315, 333-183051 and 333-162890.

Financial Covenants. See Note 8. Short-Term and Long-Term Debt for information regarding our financial covenants.

Pension and Other Postretirement Benefit Plans. Management considers various factors when making funding decisions, such as regulatory requirements, actuarially determined minimum contribution requirements and contributions required to avoid benefit restrictions for the defined benefit pension plans. In 2016,During the three months ended March 31, 2017, we contributed $1.7 million in cash and 0.2 million shares of ALLETE common stock, which had an aggregate value of $13.5 million when contributed, to the defined benefit pension plan. These shares of ALLETE common stock were contributed in reliance upon an exemption available pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended. We do not expect to make $2.0 million inadditional contributions to our defined benefit pension plan in 2017, and we do not expect to make any contributions to our other postretirement benefit plan.plan in 2017. (See Note 11. Earnings Per Share and Common Stock and Note 12. Pension and Other Postretirement Benefit Plans.)

Off-Balance Sheet Arrangements. Off-balance sheet arrangements are summarized in our 20152016 Form 10-K, with additional disclosure in Note 13. Commitments, Guarantees and Contingencies.

Capital Requirements. Our capital expenditures for 20162017 are expected to be approximately $195$295 million. For the sixthree months ended June 30, 2016,March 31, 2017, capital expenditures totaled $51.9$32.7 million ($117.918.4 million for the sixthree months ended June 30, 2015)March 31, 2016). The expenditures were primarily made in the Regulated Operations segment.


OTHER

Environmental Matters.

Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. We anticipate that althoughA number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements have recently been promulgated by both the EPA and state authorities. Minnesota Power’s facilities are subject to additional regulation under many of the statethese regulations. In 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 federal environmental regulations have been finalized, or will be finalized in the near future, potential expendituresadvocates for future environmental matters may be materialsound science and may require significant capital investments. We are unable to predict the outcome of the issues discussed inpolicy during rulemaking implementation. (See Note 13. Commitments, Guarantees and Contingencies.

)


OTHER (Continued)

Employees.

At June 30, 2016,As of March 31, 2017, ALLETE had 2,0081,975 employees, of which 1,9331,930 were full-time.

Minnesota Power and SWL&P have an aggregate of 557531 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 177183 employees, of which 131138 are members of IBEW Local 1593. The current labor agreement with IBEW Local 1593 expires on March 31, 2019.


NEW ACCOUNTING STANDARDSPRONOUNCEMENTS

New accounting standardspronouncements are discussed in Note 1. Operations and Significant Accounting Policies.


ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

SECURITIES INVESTMENTS

Available-for-Sale Securities. As of June 30, 2016March 31, 2017, our available-for-sale securities portfolio consisted primarily of securities held in other postretirement plans to fund employee benefits. (See Note 2. Investments.)

COMMODITY PRICE RISK

Our regulated utility operations incur costs for power and fuel (primarily coal and related transportation) in Minnesota and power and natural gas purchased for resale in our regulated service territory in Wisconsin. Our Minnesota regulated utility’sPower’s exposure to price risk for these commodities is significantly mitigated by the current ratemaking process and regulatory framework, which allows recovery of fuel costs in excess of those included in base rates. Conversely, costs below those in base rates result in a credit to our ratepayers. SWL&P’s exposure to price risk for natural gas is significantly mitigated by the current ratemaking process and regulatory framework, which allows the commodity cost to be passed through to customers. We seek to prudently manage our customers’ exposure to price risk by entering into contracts of various durations and terms for the purchase of power and coal and related transportation costs (Minnesota Power) and natural gas (SWL&P).

POWER MARKETING

Minnesota Power’s power marketing activities consist of: (1) purchasing energy in the wholesale market to serve its regulated service territory when energy requirements exceed generation output; and (2) selling excess available energy and purchased power. From time to time, Minnesota Power may have excess energy that is temporarily not required by retail and municipal customers in our regulated service territory. Minnesota Power actively sells any excess energy to the wholesale market to optimize the value of its generating facilities.

We are exposed to credit risk primarily through our power marketing activities. We use credit policies to manage credit risk, which includes utilizing an established credit approval process and monitoring counterparty limits.

INTEREST RATE RISK

We are exposed to risks resulting from changes in interest rates as a result of our issuance of variable rate debt. We manage our interest rate risk by varying the issuance and maturity dates of our fixed rate debt, limiting the amount of variable rate debt, and continually monitoring the effects of market changes in interest rates. We may also enter into derivative financial instruments, such as interest rate swaps, to mitigate interest rate exposure. Interest rates on variable rate long-term debt are reset on a periodic basis reflecting prevailing market conditions. Based on the variable rate debt outstanding at June 30, 2016March 31, 2017, an increase of 100 basis points in interest rates would impact the amount of pretaxpre-tax interest expense by $1.7$1.4 million. This amount was determined by considering the impact of a hypothetical 100 basis point increase to the average variable interest rate on the variable rate debt outstanding as of June 30, 2016March 31, 2017.




ITEM 4.  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures. As of June 30, 2016March 31, 2017, evaluations were performed, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, on the effectiveness of the design and operation of ALLETE’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)). Based upon those evaluations, our principal executive officer and principal financial officer have concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in ALLETE’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Controls. There has been no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.


PART II.  OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

For information regarding material legal and regulatory proceedings, see Note 5.4. Regulatory Matters and Note 12.11. Commitments, Guarantees and Contingencies to our Consolidated Financial Statements in our 20152016 Form 10-K and Note 6. Regulatory Matters and Note 13. Commitments, Guarantees and Contingencies herein. Such information is incorporated herein by reference.


ITEM 1A.  RISK FACTORS

There have been no material changes from the risk factors disclosed in Part I, Item 1A. Risk Factors of our 20152016 Form 10-K.


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

None.


ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

None.


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-Q.


ITEM 5.  OTHER INFORMATION

None.




ITEM 6.  EXHIBITS
Exhibit
Number
  
31(a) Rule 13a-14(a)/15d-14(a) Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b) Rule 13a-14(a)/15d-14(a) Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32 Section 1350 Certification of Periodic Report by the Chief Executive Officer and the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
95 Mine Safety
99 
ALLETE News Release dated August 3, 2016,May 4, 2017, announcing 2016 second2017 first quarter earnings. (This exhibit has been furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, except as shall be expressly set forth by specific reference in such filing.)
101.INS XBRL Instance
101.SCH XBRL Schema
101.CAL XBRL Calculation
101.DEF XBRL Definition
101.LAB XBRL Label
101.PRE XBRL Presentation



SIGNATURES


Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


  ALLETE, INC.
   
   
   
   
August 3, 2016May 4, 2017 /s/ Steven Q. DeVinckRobert J. Adams
  Steven Q. DeVinckRobert J. Adams
  Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
   
   
   
   
August 3, 2016May 4, 2017 /s/ Steven W. Morris
  Steven W. Morris
  Vice President, Controller and Chief Accounting Officer
(Principal Accounting Officer)


ALLETE, Inc. SecondFirst Quarter 20162017 Form 10-Q
5854