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 March 31,September 30, 2019
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, Minnesota55802-2093
(Address of principal executive offices)
(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading symbolName of each exchange on which registered
Common Stock, without par valueALENew York Stock Exchange
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 every Interactive Data File required to be submitted 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 such files).   x Yes   ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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,
51,624,42251,668,047 shares outstanding
as of March 31,September 30, 2019



Index
    
 
 
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
 
  
  
  
  
  
 
 
 
 
 
 
 
 
 
 



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 regulated 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
BisonBison Wind Energy Center
BlanchardBlanchard Solar Energy Facility
BNI EnergyBNI Energy, Inc. and its subsidiary
BoswellBoswell Energy Center
Camp RipleyCamp Ripley Solar Array
CO2
CIP
Carbon DioxideConservation Improvement Program
CliffsCleveland-Cliffs Inc.
CompanyALLETE, Inc. and its subsidiaries
CliffsCleveland-Cliffs Inc.
CSAPRCross-State Air Pollution Rule
DCDirect Current
EISEnvironmental Impact Statement
EITEEnergy-Intensive Trade-Exposed
EPAUnited States Environmental Protection Agency
ERP Iron OreERP Iron Ore, LLC
ESOPEmployee Stock Ownership Plan
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
HibbardHibbard Renewable Energy Center
Husky EnergyHusky Energy Inc.
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
Manitoba HydroManitoba Hydro-Electric Board
Minnesota PowerAn operating division of ALLETE, Inc.
Minnkota PowerMinnkota Power Cooperative, Inc.
MISOMidcontinent Independent System Operator, Inc.
MMTPManitoba-Minnesota Transmission Project


Abbreviation or AcronymTerm
Montana-Dakota UtilitiesMontana-Dakota Utilities Co., a divisionsubsidiary of MDU Resources Group, Inc.
Moody’sMoody’s Investors Service, 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
Nobles 2Nobles 2 Power Partners, LLC
NOLNet Operating Loss
NOX
NOX
Nitrogen Oxides
Northern States PowerNorthern States Power Company, a subsidiary of Xcel Energy Inc.
Northshore MiningNorthshore Mining Company, a wholly-owned subsidiary of Cleveland-Cliffs Inc.
Note ___Note ___ to the Consolidated Financial Statements in this Form 10-Q
NPDESNational Pollutant Discharge Elimination System
NTECNemadji Trail Energy Center
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.
PPA / PSAPower Purchase Agreement / Power Sales Agreement
PPACAPatient Protection and Affordable Care Act of 2010
PSCWPublic Service Commission of Wisconsin
SECSecurities and Exchange Commission
Silver Bay PowerSilver Bay Power Company, a wholly-owned subsidiary of Cleveland-Cliffs Inc.
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
TCJATax Cuts and Job Act of 2017 (Public Law 115-97)
Town Center DistrictTown Center at Palm Coast Community Development District in Florida
U.S.United States of America
U.S. Water ServicesU.S. Water Services Holding Company and its subsidiaries
WTGWind Turbine Generator





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 contract price increases at our Energy Infrastructure and Related Services and other 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 cybersecurity 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 GHG;
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 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 I, Item 1A. Risk Factors of ALLETE’s 2018 Form 10-K. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which that statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of these factors, nor can it assess the impact of each of these factors on the businesses of ALLETE or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. Readers are urged to carefully review and consider the various disclosures made by ALLETE in this Form 10-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
Unaudited
March 31,
2019

 December 31,
2018

September 30,
2019

 December 31,
2018

Millions      
Assets      
Current Assets      
Cash and Cash Equivalents
$353.3
 
$69.1

$100.3
 
$69.1
Accounts Receivable (Less Allowance of $1.0 and $1.7)98.9
 144.4
85.1
 144.4
Inventories – Net73.8
 86.7
84.6
 86.7
Prepayments and Other30.4
 34.1
26.1
 34.1
Total Current Assets556.4
 334.3
296.1
 334.3
Property, Plant and Equipment – Net3,940.5
 3,904.4
4,210.7
 3,904.4
Regulatory Assets385.1
 389.5
393.1
 389.5
Equity Investments154.8
 161.1
183.3
 161.1
Goodwill and Intangible Assets – Net1.1
 223.3
1.0
 223.3
Other Non-Current Assets180.9
 152.4
191.6
 152.4
Total Assets
$5,218.8
 
$5,165.0

$5,275.8
 
$5,165.0
Liabilities and Shareholders’ Equity      
Liabilities      
Current Liabilities      
Accounts Payable
$134.4
 
$149.8

$143.5
 
$149.8
Accrued Taxes60.3
 51.4
53.4
 51.4
Accrued Interest14.9
 17.9
15.0
 17.9
Long-Term Debt Due Within One Year14.3
 57.5
212.7
 57.5
Other98.5
 128.5
58.7
 128.5
Total Current Liabilities322.4
 405.1
483.3
 405.1
Long-Term Debt1,525.0
 1,428.5
1,404.9
 1,428.5
Deferred Income Taxes215.5
 223.6
213.9
 223.6
Regulatory Liabilities504.1
 512.1
510.4
 512.1
Defined Benefit Pension and Other Postretirement Benefit Plans165.2
 177.3
162.4
 177.3
Other Non-Current Liabilities287.9
 262.6
293.1
 262.6
Total Liabilities3,020.1
 3,009.2
3,068.0
 3,009.2
Commitments, Guarantees and Contingencies (Note 7)

 


 

Shareholders’ Equity      
Common Stock Without Par Value, 80.0 Shares Authorized, 51.6 and 51.5 Shares Issued and Outstanding1,431.1
 1,428.5
Common Stock Without Par Value, 80.0 Shares Authorized, 51.7 and 51.5 Shares Issued and Outstanding1,435.1
 1,428.5
Accumulated Other Comprehensive Loss(27.2) (27.3)(26.8) (27.3)
Retained Earnings794.8
 754.6
799.5
 754.6
Total Shareholders’ Equity2,198.7
 2,155.8
2,207.8
 2,155.8
Total Liabilities and Shareholders’ Equity
$5,218.8
 
$5,165.0

$5,275.8
 
$5,165.0
The accompanying notes are an integral part of these statements.



ALLETE
CONSOLIDATED STATEMENT OF INCOME
Unaudited
Three Months EndedQuarter Ended Nine Months Ended
March 31,September 30, September 30,
2019201820192018 20192018
Millions Except Per Share Amounts    
Operating Revenue    
Contracts with Customers – Utility
$282.2

$270.2

$254.1

$261.3
 
$786.1

$789.3
Contracts with Customers – Non-utility72.1
82.0
31.3
80.7
 141.1
243.1
Other – Non-utility2.9
6.0
2.9
6.0
 8.7
17.9
Total Operating Revenue357.2
358.2
288.3
348.0
 935.9
1,050.3
Operating Expenses    
Fuel, Purchased Power and Gas – Utility109.8
100.9
98.2
103.2
 295.9
300.6
Transmission Services – Utility18.3
18.4
18.3
17.9
 55.8
53.1
Cost of Sales – Non-utility30.6
32.9
14.7
38.7
 61.8
108.6
Operating and Maintenance76.2
86.5
58.1
80.3
 201.0
253.6
Depreciation and Amortization51.9
45.8
49.5
51.5
 151.6
153.4
Taxes Other than Income Taxes13.6
16.3
12.5
13.1
 39.8
43.8
Total Operating Expenses300.4
300.8
251.3
304.7
 805.9
913.1
Operating Income56.8
57.4
37.0
43.3
 130.0
137.2
Other Income (Expense)    
Interest Expense(16.5)(16.9)(16.1)(17.6) (48.9)(51.6)
Equity Earnings5.6
4.7
4.9
4.0
 15.3
13.0
Gain on Sale of U.S. Water Services20.1



 20.6

Other7.4
2.1
3.0
1.4
 14.6
5.7
Total Other Income (Expense)16.6
(10.1)(8.2)(12.2) 1.6
(32.9)
Income Before Income Taxes73.4
47.3
28.8
31.1
 131.6
104.3
Income Tax Expense (Benefit)2.9
(3.7)(2.4)0.4
 (4.3)(8.7)
Net Income
$70.5

$51.0

$31.2

$30.7
 
$135.9

$113.0
Average Shares of Common Stock    
Basic51.6
51.2
51.7
51.4
 51.6
51.3
Diluted51.7
51.4
51.8
51.6
 51.7
51.5
Basic Earnings Per Share of Common Stock
$1.37

$1.00

$0.60

$0.59
 
$2.63

$2.20
Diluted Earnings Per Share of Common Stock
$1.37

$0.99

$0.60

$0.59
 
$2.63

$2.19
The accompanying notes are an integral part of these statements.



ALLETE
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Unaudited
Three Months EndedQuarter Ended Nine Months Ended
March 31,September 30, September 30,
2019 20182019 2018 2019 2018
Millions          
Net Income
$70.5
 
$51.0

$31.2
 
$30.7
 
$135.9
 
$113.0
Other Comprehensive Income (Loss)          
Unrealized Gain (Loss) on Securities          
Net of Income Tax Expense of $– and $–0.1
 (0.1)
Net of Income Tax Expense of $–, $–, $0.1 and $–
 
 0.2
 (0.1)
Defined Benefit Pension and Other Postretirement Benefit Plans          
Net of Income Tax Expense of $0.1 and $0.1
 0.4
Net of Income Tax Expense of $0.1, $0.1, $0.2 and $0.30.1
 0.3
 0.3
 1.0
Total Other Comprehensive Income0.1
 0.3
0.1
 0.3
 0.5
 0.9
Total Comprehensive Income
$70.6
 
$51.3

$31.3
 
$31.0
 
$136.4
 
$113.9
The accompanying notes are an integral part of these statements.




ALLETE
CONSOLIDATED STATEMENT OF CASH FLOWS
Unaudited
Three Months EndedNine Months Ended
March 31,September 30,
2019 20182019 2018
Millions      
Operating Activities      
Net Income
$70.5
 
$51.0

$135.9
 
$113.0
AFUDC – Equity(0.6) (0.3)(1.9) (0.9)
Income from Equity Investments – Net of Dividends(1.2) (0.5)(3.2) (1.3)
Gain on Sales of Investments and Property, Plant and Equipment(1.7) (0.1)
Depreciation Expense50.7
 44.5
150.3
 149.3
Amortization of PSAs(2.9) (6.0)(8.7) (17.9)
Amortization of Other Intangible Assets and Other Assets1.9
 2.8
9.9
 7.8
Deferred Income Tax Expense (Benefit)2.6
 (4.4)
Deferred Income Tax Benefit(4.5) (9.1)
Share-Based and ESOP Compensation Expense1.8
 1.7
4.9
 5.1
Defined Benefit Pension and Postretirement Benefit Expense1.1
 2.2
1.8
 6.4
Provision for Interim Rate Refund0.6
 4.4
Payments / Provision for Interim Rate Refund(40.0) 13.0
Payments / Provision for Tax Reform Refund(10.2) 7.5
(10.4) 9.2
Bad Debt Expense0.4
 0.3
(0.3) 1.5
Gain on Sale of U.S. Water Services(20.1) 
(20.6) 
Changes in Operating Assets and Liabilities      
Accounts Receivable20.9
 6.3
34.1
 3.9
Inventories(5.1) (0.3)(15.9) (12.6)
Prepayments and Other2.9
 (1.2)7.3
 5.7
Accounts Payable(5.5) (0.1)(3.3) 9.9
Other Current Liabilities(9.9) 17.3
(15.8) 21.2
Cash Contributions to Defined Benefit Pension Plans(10.4) (15.0)(10.4) (15.0)
Changes in Regulatory and Other Non-Current Assets0.3
 3.8
(18.3) 7.2
Changes in Regulatory and Other Non-Current Liabilities(7.0) 7.4
(14.5) 1.7
Cash from Operating Activities79.1
 121.3
176.4
 298.1
Investing Activities      
Proceeds from Sale of Available-for-sale Securities2.7
 3.3
11.2
 9.3
Payments for Purchase of Available-for-sale Securities(2.6) (5.3)(11.1) (12.5)
Payments for Equity Investments(0.5) (1.6)(26.4) (5.0)
Return of Capital from Equity Investments8.3
 
8.3
 
Proceeds from Sale of U.S. Water Services – Net of Transaction Costs and Cash Retained264.7
 
266.1
 
Additions to Property, Plant and Equipment(89.3) (88.1)(421.3) (201.0)
Other Investing Activities1.8
 2.7
13.2
 1.4
Cash from (for) Investing Activities185.1
 (89.0)
Cash for Investing Activities(160.0) (207.8)
Financing Activities      
Proceeds from Issuance of Common Stock0.8
 4.3
1.7
 14.6
Proceeds from Issuance of Long-Term Debt100.0
 
200.0
 72.7
Repayments of Long-Term Debt(43.8) (1.9)(66.1) (59.5)
Acquisition-Related Contingent Consideration Payments(3.8) 
(3.8) 
Dividends on Common Stock(30.3) (28.7)(91.0) (86.2)
Other Financing Activities(0.9) (0.2)(1.0) (0.5)
Cash from (for) Financing Activities22.0
 (26.5)39.8
 (58.9)
Change in Cash, Cash Equivalents and Restricted Cash286.2
 5.8
56.2
 31.4
Cash, Cash Equivalents and Restricted Cash at Beginning of Period79.0
 110.1
79.0
 110.1
Cash, Cash Equivalents and Restricted Cash at End of Period
$365.2
 
$115.9

$135.2
 
$141.5
The accompanying notes are an integral part of these statements.



ALLETE
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
Unaudited
Three Months EndedQuarter Ended Nine Months Ended
March 31,September 30, September 30,
2019201820192018 20192018
Millions Except Per Share Amounts    
Common Stock    
Balance, Beginning of Period
$1,428.5

$1,401.4

$1,433.3

$1,415.4
 
$1,428.5

$1,401.4
Common Stock Issued2.6
6.0
1.8
5.7
 6.6
19.7
Balance, End of Period1,431.1
1,407.4
1,435.1
1,421.1
 1,435.1
1,421.1
    
Accumulated Other Comprehensive Loss    
Balance, Beginning of Period(27.3)(28.2)(26.9)(27.6) (27.3)(28.2)
Other Comprehensive Income - Net of Income Taxes    
Unrealized Gain (Loss) on Debt Securities0.1
(0.1)

 0.2
(0.1)
Defined Benefit Pension and Other Postretirement Plans
0.4
0.1
0.3
 0.3
1.0
Balance, End of Period(27.2)(27.9)(26.8)(27.3) (26.8)(27.3)
    
Retained Earnings    
Balance, Beginning of Period754.6
695.5
798.6
720.4
 754.6
695.5
Net Income70.5
51.0
31.2
30.7
 135.9
113.0
Common Stock Dividends(30.3)(28.7)(30.3)(28.8) (91.0)(86.2)
Balance, End of Period794.8
717.8
799.5
722.3
 799.5
722.3
    
Total Shareholders’ Equity
$2,198.7

$2,097.3

$2,207.8

$2,116.1
 
$2,207.8

$2,116.1
    
Dividends Per Share of Common Stock
$0.5875

$0.56

$0.5875

$0.56
 
$1.7625

$1.68

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, 2018, 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 threenine months ended March 31,September 30, 2019, are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2019. For further information, refer to the Consolidated Financial Statements and notes included in our 2018 Form 10-K.

NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

Cash, Cash Equivalents and Restricted Cash. We consider all investments purchased with original maturities of three months or less to be cash equivalents. As of March 31,September 30, 2019, restricted cash amounts included in Prepayments and Other on the Consolidated Balance Sheet include collateral deposits required under an ALLETE Clean Energy loan agreement. In prior periods presented, the amounts also include U.S. Water Service’sServices' standby letters of credit. The restricted cash amounts included in Other Non-Current Assets represent collateral deposits required under an ALLETE Clean Energy loan agreement, and PSAs and construction projects. In prior periods presented, the amounts also include deposits from a SWL&P customer in aid of future capital expenditures. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheet that aggregate to the amounts presented in the Consolidated Statement of Cash Flows.
Cash, Cash Equivalents and Restricted CashMarch 31,
2019

 December 31,
2018

 March 31,
2018

 December 31,
2017

September 30,
2019

 December 31,
2018

 September 30,
2018

 December 31,
2017

Millions              
Cash and Cash Equivalents
$353.3
 
$69.1
 
$98.5
 
$98.9

$100.3
 
$69.1
 
$128.0
 
$98.9
Restricted Cash included in Prepayments and Other7.2
 1.3
 8.8
 2.6
3.4
 1.3
 4.8
 2.6
Restricted Cash included in Other Non-Current Assets4.7
 8.6
 8.6
 8.6
31.5
 8.6
 8.7
 8.6
Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows
$365.2
 
$79.0
 
$115.9
 
$110.1

$135.2
 
$79.0
 
$141.5
 
$110.1


Inventories – Net. Inventories are stated at the lower of cost or net realizable value. Inventories in our Regulated Operations segment are carried at an average cost or first-in, first-out basis. Inventories in our ALLETE Clean Energy segment and Corporate and Other businesses are carried at an average cost, first-in, first-out or specific identification basis.
Inventories – NetMarch 31,
2019

 December 31,
2018

September 30,
2019

 December 31,
2018

Millions      
Fuel (a)

$29.4
 
$26.0

$37.8
 
$26.0
Materials and Supplies44.4
 44.2
46.8
 44.2
Raw Materials (b)

 2.8

 2.8
Work in Progress (b)

 6.1

 6.1
Finished Goods (b)

 8.4

 8.4
Reserve for Obsolescence (b)

 (0.8)
 (0.8)
Total Inventories – Net
$73.8
 
$86.7

$84.6
 
$86.7

(a)Fuel consists primarily of coal inventory at Minnesota Power.
(b)On March 26, 2019, ALLETE completed the sale of U.S. Water Services which resulted in the removal of the related inventory items from the Consolidated Balance Sheet.



NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Other Non-Current AssetsMarch 31,
2019

 December 31,
2018

September 30,
2019

 December 31,
2018

Millions      
Contract Assets (a)

$29.8
 
$30.7

$28.6
 
$30.7
Finance Receivable(b)10.4
 10.4

 10.4
Operating Lease Right-of-use Assets (b)(c)
34.0
 
30.4
 
ALLETE Properties24.0
 24.4
22.4
 24.4
Other82.7
 86.9
110.2
 86.9
Total Other Non-Current Assets
$180.9
 
$152.4

$191.6
 
$152.4

(a)Contract Assets includeconsist of payments made to customers as an incentive to execute or extend service agreements. The contract payments are being amortized over the term of the respective agreements as a reduction to revenue.
(b)Finance Receivable related to the 2016 sale of Ormond Crossings and Lake Swamp, which was collected in the second quarter of 2019.     
(c)See Leases.
Other Current LiabilitiesMarch 31,
2019

 December 31,
2018

September 30,
2019

 December 31,
2018

Millions      
Provision for Interim Rate Refund (a)

$40.6
 
$40.0

 
$40.0
PSAs12.4
 12.6

$12.3
 12.6
Contract Liabilities (b)
0.4
 7.6

 7.6
Provision for Tax Reform Refund (c)
0.5
 10.7
0.3
 10.7
Contingent Consideration (d)

 3.8

 3.8
Operating Lease Liabilities (e)
8.4
 
7.1
 
Other36.2
 53.8
39.0
 53.8
Total Other Current Liabilities
$98.5
 
$128.5

$58.7
 
$128.5

(a)Provision for Interim Rate Refund is expected to bewas refunded to Minnesota Power’s regulated retail customers in the second quarter of 2019.
(b)Contract Liabilities includeconsisted of deposits received as a result of entering into contracts with our customers prior to completing our performance obligations.
(c)Provision for Tax Reform Refund related to the income tax benefits of the TCJA in 2018 was refunded to Minnesota Power customers in the first quarter of 2019 and will be refunded to SWL&P customers in 2019 and 2020.
(d)Contingent Consideration related to the earnings-based payment resulting from the U.S. Water Services acquisition was paid in the first quarter of 2019.
(e)See Leases.
Other Non-Current LiabilitiesMarch 31,
2019

 December 31,
2018

September 30,
2019

 December 31,
2018

Millions      
Asset Retirement Obligation
$142.0
 
$138.6

$157.4
 
$138.6
PSAs73.9
 76.9
67.7
 76.9
Operating Lease Liabilities (a)
25.6
 
23.3
 
Other46.4
 47.1
44.7
 47.1
Total Other Non-Current Liabilities
$287.9
 
$262.6

$293.1
 
$262.6

(a)See Leases.



NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)

Supplemental Statement of Cash Flows Information.
Three Months Ended March 31,2019
 2018
Nine Months Ended September 30,2019
 2018
Millions      
Cash Paid for Interest – Net of Amounts Capitalized
$19.7
 
$19.3

$53.5
 
$52.9
Recognition of Right-of-use Assets and Lease Liabilities (a)
$30.4 
Noncash Investing and Financing Activities 
  
 
  
Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment$(1.1) $(48.1)
Reclassification of Property, Plant and Equipment to Inventory (a)

 
$46.9
Recognition of Right-of-use Assets and Lease Liabilities (b)
$34.0 
Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment$6.3 $(14.4)
Reclassification of Property, Plant and Equipment to Inventory (b)

 
$46.3
Capitalized Asset Retirement Costs
$1.6
 
$0.8

$16.6
 
$15.4
AFUDC–Equity
$0.6
 
$0.3

$1.9
 
$0.9

(a)See Leases.
(b)In February 2018, Montana-Dakota Utilities exercised its option to purchase the Thunder Spirit II wind energy facility upon completion, resulting in a reclassification from Property, Plant and Equipment – Net to Inventories – Net for project costs incurred in the prior year.
(b)See Leases.

New Accounting Pronouncements.

Recently Adopted Pronouncements

Disclosure Update and Simplification. In November 2018, the SEC adopted amendments to certain disclosure requirements. The amendments adopted include requirements that interim financial statements should include comparative statements for the same period in the prior financial year, except that the requirement for comparative balance sheet information may be satisfied by presenting the year-end balance sheet. It further includes a requirement analyzing the changes in each caption of shareholders’ equity either separately in a note or on the face of the financial statement. These amendments were effective for ALLETE in the first quarter of 2019. We have included the presentation of our Statement of Shareholders’ Equity to meet these requirements.

Leases. In 2016, the FASB issued an accounting standard update which revised the existing guidance for leases. Under the revised guidance, lessees will beare required to recognize right-of-use assets and lease liabilities on the Consolidated Balance Sheet for leases with terms greater than 12 months. The new standard also requires additional qualitative and quantitative 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 is not expected to significantly change as a result of the new guidance. The Company adopted this guidance in the first quarter of 2019 using the optional transition method and the package of practical expedients, which allowed for the adoption of the standard as of January 1, 2019, without restating previously disclosed information. Management elected the optional transition method of adoption due to the overall immateriality of the balance sheet gross up in the period of adoption. The package of practical expedients allowed management to not reassess the lease classification for leases, including those that had expired during the periods presented or that still existed at the time of adoption. We have included additional disclosures in the notes to the consolidated financial statements including additional information about the Company’s leases.statements. (See Leases.)

Leases. We determine if a contract is, or contains, a lease at inception and recognize a right-of-use asset and lease liability for all leases with a term greater than 12 months. Our right-of-use assets and lease liabilities for operating leases are included in Other Non-Current Assets, Other Current Liabilities and Other Non-Current Liabilities, respectively, in our Consolidated Balance Sheet. We currently do not have any finance leases.

Right-of-use assets represent our right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Operating lease right-of-use assets and lease liabilities are recognized at the commencement date based on the estimated present value of lease payments over the lease term. As our leases do not provide an explicit rate, we determine the present value of future lease payments based on our estimated incremental borrowing rate using information available at the lease commencement date. The operating lease right-of-use asset includes lease payments to be made during the lease term and any lease incentives, as applicable.


NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Leases (Continued)

Our leases may include options to extend or buy out the lease at certain points throughout the term, and if it is reasonably certain that we will exercise that option at lease commencement, we include those rental payments in our calculation of the right-of-use asset and lease liability. Lease and rent expense is recognized on a straight-line basis over the lease term. Leases with a term of 12 months or less are not recordedrecognized on the Consolidated Balance Sheet.

The majority of our operating leases are for heavy equipment, vehicles and land with fixed monthly payments which we group into two categories: Vehicles and Equipment; and Land and Other. Our largest operating lease is for the dragline at BNI Energy which includes a termination payment at the end of the lease term if we do not exercise our purchase option. The amount of this payment is $3 million and is included in our calculation of the right-of-use assetassets and lease liabilityliabilities recorded. None of our other leases contain residual value guarantees.

TheAdditional information on the components of lease cost and presentation of cash flows were as follows:
 Quarter Ended Nine Months Ended
 September 30, September 30,
 2019 2019
Millions   
Operating Lease Cost
$2.0
 
$6.7
    
Other Information:   
Operating Cash Flows From Operating Leases
$2.0
 
$6.7

Additional information related to leases was as follows:
Three Months Ended March 31, 2019
Millions
Operating Lease Cost
$2.9September 30,
 
Other Information:
Operating Cash Flows From Operating Leases
$2.92019
Millions 
Balance Sheet Information Related to Leases: 
Other Non-Current Assets
$34.030.4
Total Operating Lease Right-of-use Assets
$34.030.4
  
Other Current Liabilities
$8.47.1
Other Non-Current Liabilities25.623.3
Total Operating Lease Liabilities
$34.030.4
  
Weighted Average Remaining Lease Term (Years): 
Operating Leases - Vehicles and Equipment4
Operating Leases - Land and Other2928
  
Weighted Average Discount Rate: 
Operating Leases - Vehicles and Equipment3.63.7%
Operating Leases - Land and Other4.54.1%



NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Leases (Continued)

Maturities of lease liabilities were as follows:
March 31, 2019September 30, 2019
Millions  
2019
$9.9

$2.2
20207.9
7.9
20216.1
6.1
20224.9
4.9
20233.1
3.1
Thereafter9.4
9.4
Total Lease Payments Due41.3
33.6
Less: Imputed Interest7.3
3.2
Total Lease Obligations34.0
30.4
Less: Current Lease Obligations8.4
7.1
Long-term Lease Obligations
$25.6

$23.3


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

Sale of U.S. Water Services. On February 8, 2019, the Company entered into a stock purchase agreement providing for the sale of U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. for a cash purchase price of $270 million. On March 26, 2019, ALLETE completed the sale and received approximately $265 million in cash at closing, net of transaction costs and cash retained. This amount is subject to adjustment for finalization of such items as estimated working capital. The Company recognized a gain on the sale of U.S. Water Services of approximately $10$11.1 million after-tax duringin 2019.

ALLETE Clean Energy Asset Acquisition. On May 3, 2019, ALLETE Clean Energy acquired the three months ended March 31, 2019.Diamond Spring wind project in Oklahoma from Apex Clean Energy. ALLETE Clean Energy will build, own and operate the approximately 300 MW wind energy facility. The Diamond Spring wind project is fully contracted to sell wind power to Walmart Inc., Smithfield Foods, Inc. and Starbucks Corporation under long-term power sales agreements. Construction is expected to begin in late 2019 and be completed in late 2020.

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


NOTE 2. REGULATORY MATTERS

Regulatory matters are summarized in Note 4. Regulatory Matters to the Consolidated Financial Statements in our 2018 Form 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, PSCW or FERC. As authorized by the MPUC, Minnesota Power also recognizes revenue under cost recovery riders for transmission, renewable, and environmental investments and expenditures. Revenue from cost recovery riders was $7.4$24.3 million for the threenine months ended March 31,September 30, 2019 ($24.181.2 million for threenine months ended March 31,September 30, 2018). With the implementation of final rates in Minnesota Power’s general rate case, certain revenue previously recognized under cost recovery riders was incorporated into base rates. (See 2016 Minnesota General Rate Case.)


NOTE 2. REGULATORY MATTERS (Continued)
Electric Rates (Continued)

2016 Minnesota General Rate Case. The MPUC issued an order dated March 12, 2018, in Minnesota Power’s general rate case approving a return on common equity of 9.25 percent and a 53.81 percent equity ratio. Final rates went into effect on December 1, 2018, which is expected to result in additional revenue of approximately $13 million on an annualized basis. Interim rates were collected from January 1, 2017, through November 30, 2018, which were fully offset by the recognition of a corresponding reserve. Minnesota Power has recorded a reserve for an interim rate refund, net of discounts provided to EITE customers, of $40.6 million as of March 31, 2019 ($40.0$40.0 million as of December 31, 2018),2018, which is expected to bewas refunded in the second quarter of 2019.

2020 Minnesota General Rate Review. On November 1, 2019, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 10.6 percent for retail customers. The rate filing seeks a return on equity of 10.05 percent and a 53.81 percent equity ratio. On an annualized basis, the requested final rate increase would generate approximately $66 million in additional revenue. Once the filing is accepted as complete, an annual interim rate increase of approximately $48 million is expected to be implemented within 60 days, subject to MPUC adjustment and authorization. We cannot predict the level of interim or final rates that may be authorized by the MPUC.

2018 Wisconsin General Rate Case. In an order dated December 20, 2018, the PSCW approved a rate increase for SWL&P including a return on equity of 10.4 percent and a 55.0 percent equity ratio. Final rates went into effect January 1, 2019, which is expected to result in additional revenue of approximately $1.3 million on an annualized basis.


Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. In a 2016 order, the MPUC approved Minnesota Power’s updated customer billing rates allowing 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. On July 9, 2019, Minnesota Power filed a petition seeking MPUC approval to update the customer billing factor to include investments made for the GNTL.

NOTE 2. REGULATORY MATTERS (Continued)Renewable Cost Recovery Rider. Minnesota Power has an approved cost recovery rider for certain renewable investments and expenditures. The cost recovery rider allows Minnesota Power to charge retail customers on a current basis for the costs of certain renewable investments plus a return on the capital invested. Current customer billing rates for the renewable cost recovery rider were approved by the MPUC in a November 2018 order. On August 15, 2019, Minnesota Power filed a petition seeking MPUC approval to update the customer billing factor.

Fuel Adjustment Clause Reform. In a December 2017 order, the MPUC adopted a program to implement certain procedural reforms to Minnesota utilities’ automatic fuel adjustment clause (FAC) for fuel and purchased power. With this order, the method of accounting for all Minnesota electric utilities changed to a monthly budgeted, forward-looking FAC with annual prudence review and true-up to actual allowed costs. On May 1, 2019, Minnesota Power filed its fuel adjustment forecast for 2020 with the MPUC.

Integrated Resource Plan. In a 2016 order, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The order accepted Minnesota Power’s plans for the economic idling of Taconite Harbor Units 1 and 2 and the ceasing of coal-fired operations at Taconite Harbor in 2020, directed Minnesota Power to retire Boswell Units 1 and 2 no later than 2022, required an analysis of generation and demand response alternatives to be filed with a natural gas resource proposal, and required Minnesota Power to conduct requestrequests for proposalsproposal for additional wind, solar and demand response resource additions subject to further MPUC approvals.additions. Minnesota Power retired Boswell Units 1 and 2 in the fourth quarter of 2018. Minnesota Power’s next IRP filing is due by October 1, 2020.

In 2017, Minnesota Power submitted a resource package to the MPUC requesting approval of PPAs for the output of a 250 MW wind energy facility and a 10 MW solar energy facility as well as approval of a 250 MW natural gas capacity dedication agreement. These agreements wereThe natural gas capacity dedication agreement was subject to MPUC approval of the construction of NTEC, a 525 MW to 550 MW combined-cycle natural gas‑firedgas-fired generating facility which will be jointly owned by Dairyland Power Cooperative and a subsidiary of ALLETE. Minnesota Power would purchase approximately 50 percent of the facility's output starting in 2025. In an order dated January 24, 2019, the MPUC approved Minnesota Power’s request for approval of the NTEC natural gas capacity dedication agreement. Separately, the MPUC required a baseload retirement evaluation in Minnesota Power’s next IRP filing analyzing its existing fleet, including potential early retirement scenarios of Boswell Units 3 and 4, as well as a securitization plan. On January 8, 2019, an application for a certificate of public convenience and necessity for NTEC was submitted to the PSCW. A decision on the application is expected in 2020.



NOTE 2. REGULATORY MATTERS (Continued)

Conservation Improvement Program. On April 1, 2019, Minnesota Power submitted its 2018 consolidated filing, which detailed Minnesota Power’s CIP program results and requested a CIP financial incentive of $2.8 million based upon MPUC procedures, which was approved by the MPUC in an order dated July 19, 2019. In 2018, the CIP financial incentive of $3.0 million was recognized in the third quarter upon approval by the MPUC of Minnesota Power’s 2017 CIP consolidated filing. CIP financial incentives are recognized in the period in which the MPUC approves the filing.

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 for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. With the exception of the regulatory asset for Boswell Units 1 and 2 net plant and equipment, no other regulatory assets 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 2. REGULATORY MATTERS (Continued)
Regulatory Assets and LiabilitiesMarch 31,
2019

 December 31,
2018

September 30,
2019

 December 31,
2018

Millions      
Non-Current Regulatory Assets      
Defined Benefit Pension and Other Postretirement Benefit Plans
$218.0
 
$218.5

$215.0
 
$218.5
Income Taxes103.2
 105.5
100.9
 105.5
Asset Retirement Obligations32.4
 32.6
32.1
 32.6
Cost Recovery Riders16.8
 
Boswell 1 and 2 Net Plant and Equipment14.8
 16.3
12.1
 16.3
Manufactured Gas Plant
8.1
 8.0
8.1
 8.0
PPACA Income Tax Deferral4.9
 5.0
4.8
 5.0
Other3.7
 3.6
3.3
 3.6
Total Non-Current Regulatory Assets
$385.1
 
$389.5

$393.1
 
$389.5
      
Current Regulatory Liabilities (a)
      
Provision for Interim Rate Refund (b)

$40.6
 
$40.0

 
$40.0
Transmission Formula Rates Refund3.3
 4.4

$2.4
 4.4
Provision for Tax Reform Refund (c)
0.5
 10.7
0.3
 10.7
Total Current Regulatory Liabilities44.4
 55.1
2.7
 55.1
Non-Current Regulatory Liabilities      
Income Taxes389.4
 396.4
382.4
 396.4
Wholesale and Retail Contra AFUDC67.3
 64.4
74.7
 64.4
Plant Removal Obligations26.8
 25.1
32.6
 25.1
North Dakota Investment Tax Credits12.3
 14.7
12.3
 14.7
Conservation Improvement Program5.2
 1.5
5.9
 1.5
Transmission Formula Rates Refund1.6
 1.6
0.4
 1.6
Cost Recovery Riders

 6.9

 6.9
Other1.5
 1.5
2.1
 1.5
Total Non-Current Regulatory Liabilities504.1
 512.1
510.4
 512.1
Total Regulatory Liabilities
$548.5
 
$567.2

$513.1
 
$567.2

(a)Current regulatory liabilities are presented within Other Current Liabilities on the Consolidated Balance Sheet.
(b)This amount is expected to bewas refunded to Minnesota Power’s regulated retail customers in the second quarter of 2019.
(c)Provision for Tax Reform Refund related to the income tax benefits of the TCJA in 2018 was refunded to Minnesota Power customers in the first quarter of 2019 and will be refunded to SWL&P customers in 2019 and 2020.





NOTE 3. EQUITY INVESTMENTS

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 portions of Wisconsin, Michigan, Minnesota and Illinois. We account for our investmentinvestment in ATC under the equity method of accounting. In the threenine months ended March 31, 2019, we invested $0.4 million in ATC, and on AprilSeptember 30, 2019, we invested $4.7 million in ATC, and on October 31, 2019, we invested an additional $2.3$1.9 million. We do not expect to make $5.8 million inany additional investments in 2019.
ALLETE’s Investment in ATC 
Millions 
Equity Investment Balance as of December 31, 2018
$128.1
Cash Investments0.44.7
Equity in ATC Earnings5.615.3
Distributed ATC Earnings(4.412.1)
Amortization of the Remeasurement of Deferred Income Taxes0.30.9
Equity Investment Balance as of March 31,September 30, 2019
$130.0136.9


ATC’s authorized return on equity is 10.32 percent, or 10.82 percent including an incentive adder for participation in a regional transmission organization.


NOTE 3. EQUITY INVESTMENTS (Continued)
Investment in ATC (Continued)

In 2016, a federal administrative law judge ruled on a complaint proposing a 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 pending.

Investment in Nobles 2. Our wholly-owned subsidiary, ALLETE South Wind, owns 49 percent of Nobles 2, the entity that will own and operate a 250 MW wind energy facility in southwestern Minnesota pursuant to a 20-year PPA with Minnesota Power. We account for our investment in Nobles 2 under the equity method of accounting. As of March 31,September 30, 2019, our equity investment in Nobles 2 was $24.8$46.4 million ($33.0 million at December 31, 2018). In the first quarter of 2019, Nobles 2 returned capital of $8.3 million based on its cash needs. We expect to make approximately $12 million in additional investments in 2019.


NOTE 4. GOODWILL AND INTANGIBLE ASSETS

As a result of completing the sale of U.S. Water Services on March 26, 2019, there was no0 goodwill recorded as of March 31,September 30, 2019 ($148.5 million at December 31, 2018).

The balance of intangible assets, net, as of March 31,September 30, 2019, is as follows:
December 31,
2018

  Amortization 
Other (b)
 March 31,
2019

December 31,
2018

  Amortization 
Other (b)
 September 30,
2019

Millions      
Intangible Assets      
Definite-Lived Intangible Assets      
Customer Relationships
$50.7
 $(1.1) $(49.6) 

$50.7
 $(1.1) $(49.6) 
Developed Technology and Other (a)
7.5
 (0.3) (6.1) 
$1.1
7.5
 (0.4) (6.1) 
$1.0
Total Definite-Lived Intangible Assets58.2
 (1.4) (55.7) 1.1
58.2
 (1.5) (55.7) 1.0
Indefinite-Lived Intangible Assets      
Trademarks and Trade Names16.6
 n/a (16.6) 
16.6
 
 (16.6) 
Total Intangible Assets
$74.8
 $(1.4) $(72.3) 
$1.1

$74.8
 $(1.5) $(72.3) 
$1.0

(a)Developed Technology and Other includes patents, non-compete agreements, land easements and trade names with finite lives.
(b)On March 26, 2019, ALLETE completed the sale of U.S. Water Services which resulted in the removal of the related intangible assets from the Consolidated Balance Sheet.

Amortization expense for intangible assets was $1.4$1.5 million for the threenine months ended March 31,September 30, 2019 and 2018.($4.1 million for the nine months ended September 30, 2018). The remaining definite-lived intangible assets will continue to be amortized ratably through 2028.



NOTE 5. FAIR VALUE

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Descriptions of the three levels of the fair value hierarchy are discussed in Note 9. Fair Value to the Consolidated Financial Statements in our 2018 Form 10-K.


NOTE 5. FAIR VALUE (Continued)

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 March 31,September 30, 2019, and December 31, 2018. 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.
Fair Value as of March 31, 2019Fair Value as of September 30, 2019
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
$12.3
 
 
 
$12.3

$10.6
 
 
 
$10.6
Available-for-sale – Corporate and Governmental Debt Securities (b)

 
$8.3
 
 8.3

 
$9.6
 
 9.6
Cash Equivalents1.0
 
 
 1.0
1.2
 
 
 1.2
Total Fair Value of Assets
$13.3
 
$8.3
 
 
$21.6

$11.8
 
$9.6
 
 
$21.4
              
Liabilities              
Deferred Compensation (c)

 
$21.6
 
 
$21.6

 
$21.6
 
 
$21.6
Total Fair Value of Liabilities
 
$21.6
 
 
$21.6

 
$21.6
 
 
$21.6
Total Net Fair Value of Assets (Liabilities)
$13.3
 $(13.3) 
 

$11.8
 $(12.0) 
 $(0.2)
              
              
Fair Value as of December 31, 2018Fair Value as of December 31, 2018
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
$12.2
 
 
 
$12.2

$12.2
 
 
 
$12.2
Available-for-sale – Corporate and Governmental Debt Securities
 
$8.0
 
 8.0

 
$8.0
 
 8.0
Cash Equivalents1.0
 
 
 1.0
1.0
 
 
 1.0
Total Fair Value of Assets
$13.2
 
$8.0
 
 
$21.2

$13.2
 
$8.0
 
 
$21.2
              
Liabilities              
Deferred Compensation (c)

 
$19.8
 
 
$19.8

 
$19.8
 
 
$19.8
U.S. Water Services Contingent Consideration (d)

 
 
$3.8
 3.8

 
 
$3.8
 3.8
Total Fair Value of Liabilities
 
$19.8
 
$3.8
 
$23.6

 
$19.8
 
$3.8
 
$23.6
Total Net Fair Value of Assets (Liabilities)
$13.2
 $(11.8) $(3.8) $(2.4)
$13.2
 $(11.8) $(3.8) $(2.4)
(a)Included in Other InvestmentsNon-Current Assets on the Consolidated Balance Sheet.
(b)As of March 31,September 30, 2019, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $1.7$2.4 million, in one year to less than three years was $4.0$6.1 million, in three years to less than five years was $1.8$0.7 million and in five or more years was $0.8$0.4 million.
(c)Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.
(d)Included in Other Current Liabilities on the Consolidated Balance Sheet.


NOTE 5. FAIR VALUE (Continued)

The Level 3 liability in the preceding table is related to the contingent consideration liability that resulted from the 2015 acquisition of U.S. Water Services. Based on the terms and conditions of the acquisition agreement, a final payout of $3.8 million was made in the first quarter of 2019 for the remaining outstanding shares.


NOTE 5. FAIR VALUE (Continued)

Fair Value of Financial Instruments. With the exception of the item listed in the following table, the estimated fair value of all financial instruments approximates the carrying amount. The fair value for the item listed in the following table was based on quoted market prices for the same or similar instruments (Level 2).
Financial InstrumentsCarrying Amount Fair ValueCarrying Amount Fair Value
Millions      
Long-Term Debt, Including Long-Term Debt Due Within One Year      
March 31, 2019$1,549.0 $1,639.5
September 30, 2019$1,626.7 $1,814.1
December 31, 2018$1,495.2 $1,534.6$1,495.2 $1,534.6


Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis. Non-financial assets such as equity method investments, land inventory, 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 threequarter and nine months ended March 31,September 30, 2019, and the year ended December 31, 2018, there were no triggering events or indicators of impairment for these non-financial assets.


NOTE 6. SHORT-TERM AND LONG-TERM DEBT

The following tables present the Company’s short-term and long-term debt as of March 31,September 30, 2019, and December 31, 2018:
March 31, 2019Principal
 Unamortized Debt Issuance Costs Total
September 30, 2019Principal
 Unamortized Debt Issuance Costs Total
Millions          
Short-Term Debt
$14.7
 $(0.4) 
$14.3

$213.1
 $(0.4) 
$212.7
Long-Term Debt1,534.3
 (9.3) 1,525.0
1,413.6
 (8.7) 1,404.9
Total Debt
$1,549.0
 $(9.7) 
$1,539.3

$1,626.7
 $(9.1) 
$1,617.6

December 31, 2018Principal
 Unamortized Debt Issuance Costs Total
Millions     
Short-Term Debt
$57.9
 $(0.4) 
$57.5
Long-Term Debt1,437.3
 (8.8) 1,428.5
Total Debt
$1,495.2
 $(9.2) 
$1,486.0


On January 10, 2019, ALLETE entered into an amended and restated $400 million credit agreement, as amended (Credit Agreement). The Credit Agreement is unsecured, has a variable interest rate and will expire in January 2024. At ALLETE’s request and subject to certain conditions, the Credit Agreement may be increased by up to $150 million and ALLETE may make two requests to extend the maturity date, each for a one-year extension. Advances may be used by ALLETE for general corporate purposes, to provide liquidity in support of ALLETE’s commercial paper program and to issue up to $60$100 million in letters of credit.

We had $60.1 million outstanding in standby letters of credit and 0 outstanding draws under our lines of credit as of September 30, 2019 ($18.4 million in standby letters of credit and 0 outstanding draws as of December 31, 2018).

On March 1, 2019, ALLETE issued and sold the following First Mortgage Bonds (the Bonds):
Maturity DatePrincipal AmountInterest Rate
March 1, 2029$70 Million4.08%
March 1, 2049$30 Million4.47%



NOTE 6. SHORT-TERM AND LONG-TERM DEBT (Continued)

ALLETE has the option to prepay all or a portion of the Bonds at its discretion, subject to a make-whole provision. The Bonds are subject to additional terms and conditions which are customary for these types of transactions. ALLETE intends to useused the proceeds from the sale of the Bonds to fund utility capital investment and for general corporate purposes. The Bonds were sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to institutional accredited investors.



NOTE 6. SHORT-TERM AND LONG-TERM DEBT (Continued)On August 14, 2019, ALLETE entered into an amended and restated $110.0 million term loan agreement (Term Loan). The Term Loan is unsecured and due on August 25, 2020, and may be prepaid at any time, subject to a make-whole provision. Interest on the Term Loan is payable quarterly at a rate per annum equal to LIBOR plus 1.025 percent. Proceeds from the Term Loan were used for construction related expenditures.

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 March 31,September 30, 2019, our ratio was approximately 0.410.43 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. ALLETE has no significant restrictions on its ability to pay dividends from retained earnings or net income. As of March 31,September 30, 2019, ALLETE was in compliance with its financial covenants.


NOTE 7. 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 11. Commitments, Guarantees and Contingencies to the Consolidated Financial Statements in our 2018 Form 10-K, with additional disclosure provided in the following paragraphs.

Square Butte PPA. As of March 31,September 30, 2019, Square Butte had total debt outstanding of $302.6$295.9 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 threenine months ended March 31,September 30, 2019, was $20.5$61.3 million ($17.357.9 million for the three months ended March 31, 2018)same period in 2018). 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 $2.1$6.3 million ($2.36.9 million for the same period in 2018). 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 PSA. Minnesota Power has a PSA with Minnkota Power, which commenced in 2014. Under the 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 2019 and in 2018.

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 2019 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 2021. The estimated minimum payments under these supply and transportation agreements is $5.7 million for the remainder of 2019, $9.0 million in 2020, $7.5 million in 2021 and none thereafter. The costs of fuel and related transportation costs for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.




NOTE 7. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

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. As a condition of the 250-MW long-term PPA entered into with Manitoba Hydro, construction of additional transmission capacity is required. As a result, Minnesota Power is constructing the GNTL, an approximately 220‑mile 500-kV transmission line between Manitoba and Minnesota’s Iron Range that was proposed by Minnesota Power and Manitoba Hydro in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy.


NOTE 7. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Transmission (Continued)

In a 2016 order, the MPUC approved the route permit for the GNTL, and in 2016, the U.S. Department of Energy issued a presidential permit to cross the U.S.‑CanadianU.S.-Canadian border, which was the final major regulatory approval needed before construction in the U.S. could begin. Site clearing and pre‑constructionConstruction activities commenced in the first quarter of 2017, with construction expectedand Minnesota Power expects the GNTL to be completed in 2020. To date, most of the right-of-way has been cleared while foundation installationcomplete and transmission tower construction have commenced.in-service by mid-2020. The total project cost in the U.S., including substation work, is estimated to be between $560 million and $710approximately $700 million, of which Minnesota Power’s portion is expected to be between $300 million and $350approximately $325 million; the difference will be recovered from a subsidiary of Manitoba Hydro as non-shareholder contributions to capital. Total project costs of $458.2$581.6 million have been incurred through March 31,September 30, 2019, of which $245.0$310.4 million has been recovered from a subsidiary of Manitoba Hydro.

Manitoba Hydro must obtain regulatory and governmental approvals related to the MMTP, a new transmission line in Canada that will connect with the GNTL. In 2015, Manitoba Hydro submitted the final preferred route and EIS for the MMTP to the Manitoba Conservation and Water Stewardship for siting and environmental approval, which was received on April 4, 2019. In 2016, Manitoba Hydro filed an application with the Canadian National Energy Board (NEB) requesting authorization to construct and operate the MMTP, which was recommended for approval on November 15, 2018. ApprovalOn June 14, 2019, Manitoba Hydro announced Canada’s federal government approved the MMTP project and on August 22, 2019, the NEB granted final pre-construction approvals. Construction on the MMTP commenced in the third quarter of the Canadian federal cabinet is also required.2019.

The MMTP is subject to legal and regulatory challenges which Minnesota Power is actively monitoring. Manitoba Hydro has informed Minnesota Power that it continues to work towards completing the MMTP on schedule. In order to meet the transmission in‑service requirements in PPAs with Minnesota Power, Manitoba Hydro has indicated that it would need to start construction of the MMTP by September 2019. We are unable to predict the outcome of the Canadian regulatory review process, including the timing thereof or whether any onerous conditions may be imposed, or the timing of the completion of the MMTP, including the impact of any delays that may result in construction schedule adjustments. Any significant delays inIn the event the MMTP construction schedule may result inis delayed and not in-service by June 1, 2020, Minnesota Power adjusting the GNTLhas construction schedule and impact the timing of capital expendituresrelated agreements in place with Manitoba Hydro and associated cost recovery under our transmission cost recovery rider.a Manitoba Hydro subsidiary that will protect Minnesota Power and its customers.

Construction of Manitoba Hydro’s Keeyask hydroelectric generation facility, which will provide the power to be sold under PPAs with Minnesota Power and transmitted on the MMTP and the GNTL, commenced in 2014 and is anticipated to be in service by early 2021.

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 been promulgated by both the EPA and state authorities over the past several years. Minnesota Power’s facilities are subject to additional requirements under many of 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 have been obtained. We anticipate that with many state and federal environmental regulations and requirements finalized, or to be finalized in the near future, potential expenditures for future environmental matters may be material and 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.



NOTE 7. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

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 expensed unless recoverable in rates from customers.


NOTE 7. 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.

Cross-State Air Pollution Rule (CSAPR). The CSAPR requires certain states in the eastern half of the 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 but does require 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. Based on our review of the NOx and SO2 allowances issued and pending issuance, we currently expect generation levels and emission rates will result in continued compliance with the CSAPR.

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. None of the compliance costs for proposed or current NAAQS revisions are expected to be material.

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 renewable power supply for both our operations and the operations of others;
Providing energy conservation initiatives for our customers and engaging in other demand side management efforts;
Improving efficiency of our generating facilities;
Supporting research of technologies to reduce carbon emissions from generating facilities and carbon sequestration efforts;
Evaluating and developing less carbon intensive future generating assets such as efficient and flexible natural gas-fired generating facilities;
Managing vegetation on right-of-way corridors to reduce potential wildfire or storm damage risks; and
Practicing sound forestry management in our service territories to create landscapes more resilient to disruption from climate-related changes, including planting and managing long-lived conifer species.

EPA Regulation of GHG Emissions. In 2014,On June 19, 2019, the EPA finalized several separate rulemakings regarding regulating carbon emissions from electric utility generating units.

The EPA repealed the Clean Power Plan (CPP), following a determination by the EPA that the CPP exceeded the EPA’s statutory authority under the Clean Air Act (CAA). The primary reason for this was that the CPP attempted to regulate electric generating unit’s carbon emissions through measures outside of the affected unit’s direct control. The CPP was first announced as 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.

With the Clean Power Plan (CPP). The EPA issued the final CPP in 2015, together with a proposed federal implementation plan and a model rule for emissions trading. In 2016, the U.S. Supreme Court issued an order staying the effectiveness of the rule until after the appellate court process is complete. In 2016, the U.S. Court of Appeals for the District of Columbia Circuit heard oral arguments and is currently deliberating. If the CPP is upheld at the completion of the appellate process, allrepeal of the CPP, regulatory deadlines are expected to be reset based on the length of time that the appeals process takes. The EPA is precluded from enforcing the CPP while the U.S. Supreme Court stay is in force.

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 filed a motion with the U.S. Court of Appeals for the District of Columbia Circuit to hold CPP-related litigation in suspension while the EPA is reviewing the rule. In 2017, an Advanced Notice of Proposed Rulemaking for a CPP replacement rule was published in the Federal Register.

In August 2018, the EPA published the proposed Affordable Clean Energy Rule inwas finalized. The rule establishes emissions guidelines for states to use when developing plans to limit carbon dioxide at coal-fired power plants. The rule identifies heat rate improvements made at individual units as the Federal Register, which is intended to replace the CPP with revisedbest system of emission guidelines that inform the development, submittal, and implementation of State Implementation Plans (SIP) to reduce GHG emissionsreduction. Affected facilities for existing steam generating units. If a state does not submit a SIP or submits a plan that is unacceptable to the EPA, the EPA would develop a Federal Implementation Plan (FIP). Minnesota Power generating facilities affected by this proposal include Boswell Laskin, Taconite HarborUnits 3 and Hibbard.

4. Based on our initial review of the rule, many of the candidate heat rate improvements are already installed on Boswell Units 3 and 4.


NOTE 7. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

The proposedAdditionally, the EPA finalized new regulations for the state implementation of the Affordable Clean Energy Rule seeks to reduce carbon intensity at existing steam generation units by prescribing Best System of Emission Reduction (BSER), primarily through Heat Rate Improvement (HRI) technologies. Under the proposal, statesand any future emission guidelines issued under CAA Section 111(d). States will have up to three years to submit State Implementation Plans (SIP), and the EPA has 12 months to review and approve those plans. Since the Affordable Clean Energy Rule allows states considerable flexibility in how to best implement its requirements, Minnesota Power plans to work closely with the MPCA and the Minnesota Department of Commerce, who are currently co-reviewing the rule as the state develops its SIP. If a state does not submit a SIP or submits a SIP that is unacceptable to the EPA, the EPA will develop a Federal Implementation Plan. We currently anticipate that the MPCA will develop a SIP which is subject to EPA approval. While many offor the HRIs proposed by the EPA in the proposed rule have already been installed in Minnesota Power’s largest coal-fired generating units, compliance specifics would be detailed in either Minnesota’s SIP or a FIP.Affordable Clean Energy Rule.

Minnesota hashad already initiated several measures consistent with those called for under the now repealed CPP and proposedfinalized Affordable Clean Energy Rule. Minnesota Power iscontinues 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 2. Regulatory Matters.) We are unable to predict the GHG emission compliance costs we might incur;incur as a result of the Affordable Clean Energy Rule and the resulting SIP; however, the costs could be material. Minnesota Power would seek recovery of additional costs through a rate 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.

Steam Electric Power Generating Effluent Limitations Guidelines. In 2015, the EPA issued revised federal effluent limitation guidelines (ELG) for steam electric power generating stations under the Clean Water Act. It set effluent limits and prescribed BACT for several wastewater streams, including flue gas desulphurization (FGD) water, bottom ash transport water and coal combustion landfill leachate. In 2017, the EPA announced a two-year postponement of the ELG compliance date of November 1, 2018, to November 1, 2020, while the agency reconsiders the bottom ash transport water and FGD wastewater provisions. On April 12, 2019, the U.S. Court of Appeals for the Fifth Circuit vacated and remanded back to the EPA portions of the ELG that allowed for continued discharge of legacy wastewater and leachate.

The final ELG rule’sELG's potential impact on Minnesota Power operations is 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 discharge to surface waters, but may do so in the future. Under the existing ELG rule, bottom ash transport water discharge to surface waters must cease no later than December 31, 2023. Bottom ash contact water will either need to be re-used in a closed-loop process, routed to a FGD scrubber, or the bottom ash handling system will need to be converted to a dry process. If FGD wastewater is discharged in the future, it will require additional wastewater treatment. The ELG rule provision regarding these two waste-streams are being reconsidered and may change prior to November 1, 2020. Efforts have been underway at Boswell to reduce the amount of water discharged and evaluate potential re‑usere-use options in its plant processes. The EPA’s additional reconsideration of legacy wastewater discharge requirements have the potential to reduce time lines for dewatering Boswell’s existing bottom ash pond. The timing of a draft rule addressing legacy wastewater and leachate is currently unknown.

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 re-use. Minnesota Power would seek recovery of additional costs through a rate 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 reports to the EPA.

Coal Ash Management Facilities. Minnesota Power stores or disposes coal ash at four of its electric generating facilities by the following methods: storing ash in linedclay-lined onsite impoundments (ash ponds), disposing of dry ash in a lined dry ash landfill, applying ash to land as an approved beneficial use and trucking ash to state permitted landfills.


NOTE 7. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

Coal Combustion Residuals from Electric Utilities (CCR). In 2015, the EPA published the final rule regulating CCR as nonhazardous waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) in the Federal Register. 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 15 years and be between approximately $65 million and $120 million. The EPA has indicated to Minnesota Power that the landfill at Taconite Harbor, which has been idled and has a temporary landfill cover in place, is a CCR unit based on the EPA’s interpretation of the CCR rule language. rule.

Minnesota Power has agreed to post the required CCR information for the Taconite Harbor landfill on Minnesota Power’s website while the CCR issue is resolved. Compliance costs for CCR at Taconite Harbor are not expected to be material. Minnesota Power would seek recovery of additional costs through a rate proceeding.



NOTE 7. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)

Minnesota Power continues to work on minimizing costs through evaluation of beneficial re-use and recycling of CCR and CCR‑related waters. In 2017, the EPA announced its intention to formally reconsider the CCR rule under Subtitle D of the RCRA and in March 2018, published the first phase of the proposed rule revisions in the Federal Register. In July 2018, the EPA finalized revisions to elements of the CCR rule, including extending certain deadlines by two years, the establishment of alternative groundwater protection standards for certain constituents and the potential for risk‑basedrisk-based management options at facilities based on site characteristics. In August 2018, a U.S. District Court for the District of Columbia decision vacated specific provisions of the CCR rule. The court decision changes the status of three existing impoundments at Boswell that must now be considered unlined. Compliance costs at Boswell due to the court decision are unknown at this time. Minnesota Power would seek recovery of additional costs through a rate proceeding.

Other Environmental Matters

Manufactured Gas Plant Site. We are reviewing and addressing environmental conditions at a former manufactured gas plant site located in Superior, Wisconsin, and formerly operated by SWL&P.Wisconsin. SWL&P has been working with the Wisconsin Department of Natural Resources (WDNR) in determining the extent and location of contamination at the site and surrounding properties. In December 2017, the WDNR authorized SWL&P to transition from site investigation into the remedial design process. As of March 31,September 30, 2019, we have recorded a liability of approximately $7 million for remediation costs at this site (approximately $7 million as of December 31, 2018), and. SWL&P has also recorded an associated regulatory asset as we expect recovery of these remediation costs to be allowed by the PSCW. We expectRemediation costs are expected to incur some or all of these costs over the next four years.be incurred through 2023.

Other Matters.

ALLETE Clean Energy. ALLETE Clean Energy’s wind energy facilities have PSAs in place for their entire output and expire in various years between 20192020 and 2032. As of March 31,September 30, 2019, ALLETE Clean Energy has $21.6$60.8 million outstanding in standby letters of credit.

BNI Energy. As of March 31,September 30, 2019, BNI Energy had surety bonds outstanding of $49.9 million and a letter of credit for an additional $0.6$67.7 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. BNI Energy’s total reclamation liability is currently estimated at $47.5$67.3 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 March 31,September 30, 2019,, ALLETE Properties had surety bonds outstanding and letters of credit to governmental entities totaling $8.6$4.8 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is $6.1$2.3 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.

Community Development District Obligations. As of March 31,September 30, 2019, we owned 6866 percent of the assessable land in the Town Center District (68(68 percent as of December 31, 2018)2018) and 12 percent of the assessable land in the Palm Coast Park District (19 percent as of December 31, 2018). As of March 31,September 30, 2019, 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 $0.6 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.



NOTE 7. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)

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 8. 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 non-vested restricted stock units and performance share awards granted under our Executive Long-Term Incentive Compensation Plan.
  2019     2018    2019     2018  
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                      
Three Months Ended March 31, 
    
      
Quarter ended September 30,           
Net Income
$70.5
   
$70.5
 
$51.0
   
$51.0

$31.2
   
$31.2
 
$30.7
   
$30.7
Average Common Shares51.6
 0.1
 51.7
 51.2
 0.2
 51.4
51.7
 0.1
 51.8
 51.4
 0.2
 51.6
Earnings Per Share
$1.37
   
$1.37
 
$1.00
   
$0.99
$0.60
   $0.60
 
$0.59
   
$0.59
Nine Months Ended September 30, 
    
      
Net Income
$135.9
   
$135.9
 
$113.0
   
$113.0
Average Common Shares51.6
 0.1
 51.7
 51.3
 0.2
 51.5
Earnings Per Share$2.63
   $2.63
 
$2.20
   
$2.19



NOTE 9. INCOME TAX EXPENSE
Three Months Ended Quarter Ended Nine Months Ended
March 31, September 30, September 30,
2019 2018 2019 2018 2019 2018
Millions           
Current Income Tax Expense (a)
           
Federal
 
 
 
 
 
State
$0.3
 
$0.7
 
 
 
$0.2
 
$0.4
Total Current Income Tax Expense
$0.3
 
$0.7
 
 
 
$0.2
 
$0.4
Deferred Income Tax Expense (Benefit)           
Federal (b)
$(9.7) $(6.8) $(5.0) $(2.2) $(21.8) $(16.4)
State (c)
12.5
 2.6
 2.7
 2.8
 17.7
 7.8
Investment Tax Credit Amortization(0.2) (0.2) (0.1) (0.2) (0.4) (0.5)
Total Deferred Income Tax Expense (Benefit)$2.6 $(4.4) $(2.4) $0.4 $(4.5) $(9.1)
Total Income Tax Expense (Benefit)$2.9 $(3.7) $(2.4) $0.4 $(4.3) $(8.7)

(a)For each of the threenine months ended March 31,September 30, 2019, and 2018, 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. Federal and state NOLs are being carried forward to offset current and future taxable income.
(b)For each of the threenine months ended March 31,September 30, 2019, and 2018, the federal income tax benefit is primarily due to production tax credits.
(c)
For the threenine months ended March 31,September 30, 2019, the state income tax expense is primarily due to the sale of U.S. Water Services.

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.


NOTE 9. INCOME TAX EXPENSE (Continued)
Three Months EndedQuarter EndedNine Months Ended
Reconciliation of Taxes from Federal StatutoryMarch 31,September 30,
Rate to Total Income Tax Expense2019 20182019 20182019 2018
Millions         
Income Before Income Taxes
$73.4
 
$47.3

$28.8
 
$31.1

$131.6
 
$104.3
Statutory Federal Income Tax Rate21% 21%21% 21%21% 21%
Income Taxes Computed at Statutory Federal Rate
$15.4
 
$9.9

$6.0
 
$6.5

$27.6
 
$21.9
Increase (Decrease) in Income Tax Due to:        
State Income Taxes – Net of Federal Income Tax Benefit10.1
 2.6
2.1
 2.2
14.1
 6.4
Production Tax Credits(16.3) (14.4)(9.6) (9.4)(35.7) (35.0)
Regulatory Differences – Excess Deferred Tax(3.2) (2.2)(1.7) (1.1)(6.5) (5.5)
U.S. Water Services Sale of Stock Basis Difference2.4
 

 
1.7
 
Share-Based Compensation(0.9) (0.5)
 
(0.9) (0.5)
Other(4.6) 0.9
0.8
 2.2
(4.6) 4.0
Total Income Tax Expense (Benefit)$2.9 $(3.7)$(2.4) $0.4$(4.3) $(8.7)


For the threenine months ended March 31,September 30, 2019, the effective tax rate was an expensea benefit of 4.03.3 percent (benefit of 7.88.3 percent for the threenine months ended March 31,September 30, 2018). The effective tax rate includedfor 2019 was a lower benefit primarily due to a higher tax rate on, and higher pre-tax income tax expense of $10.2 millionresulting from the gain on, the sale of U.S. Water Services.

Uncertain Tax Positions. As of March 31,September 30, 2019, we had gross unrecognized tax benefits of $1.3 million ($1.6 million as of December 31, 2018). Of the total gross unrecognized tax benefits, $0.6 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 2015,2016, or state examination for years before 2014.2015.





NOTE 10. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
Pension 
Other
Postretirement
Pension 
Other
Postretirement
Components of Net Periodic Benefit Cost2019 2018 2019 2018
Components of Net Periodic Benefit Cost (Credit)2019 2018 2019 2018
Millions              
Three Months Ended March 31,       
Quarter Ended September 30,       
Service Cost
$2.3
 
$2.7
 
$1.0
 
$1.2

$2.3
 
$2.7
 
$1.0
 
$1.2
Non-Service Cost Components (a)
              
Interest Cost8.0
 7.4
 1.9
 1.8
7.9
 7.4
 1.9
 1.8
Expected Return on Plan Assets(11.0) (11.0) (2.6) (2.7)(11.0) (11.1) (2.6) (2.7)
Amortization of Prior Service Credits
 
 (0.4) (0.4)
 
 (0.4) (0.4)
Amortization of Net Loss1.8
 3.0
 0.1
 0.2
1.9
 3.0
 0.1
 0.2
Net Periodic Benefit Cost
$1.1
 
$2.1
 
 
$0.1

$1.1
 
$2.0
 
 
$0.1
       
Nine Months Ended September 30,       
Service Cost
$7.0
 
$8.2
 
$2.8
 
$3.7
Non-Service Cost Components (a)
       
Interest Cost23.9
 22.2
 5.7
 5.4
Expected Return on Plan Assets(33.3) (33.2) (7.9) (8.2)
Amortization of Prior Service Credits(0.2) 
 (1.5) (1.3)
Amortization of Net Loss5.1
 9.0
 0.2
 0.6
Net Periodic Benefit Cost (Credit)
$2.5
 
$6.2
 $(0.7) 
$0.2

(a)These components of net periodic benefit cost (credit) are included in the line item “Other” under Other Income (Expense) on the Consolidated Statement of Income.

Employer Contributions. For the threenine months ended March 31,September 30, 2019, we contributed $10.4 million in cash to the defined benefit pension plans ($15.0 million for the threenine months ended March 31,September 30, 2018); we do not0t expect to make additional contributions to our defined benefit pension plans in 2019. For the threenine months ended March 31,September 30, 2019, and 2018, we made no0 contributions to our other postretirement benefit plans; we do not0t expect to make any contributions to our other postretirement benefit plans in 2019.





NOTE 11. BUSINESS SEGMENTS

We present three reportable segments: Regulated Operations, ALLETE Clean Energy and U.S. Water Services. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.

Regulated Operations includes three3 operating segments which consist of our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC. ALLETE Clean Energy is our business focused on developing, acquiring and operating clean and renewable energy projects. U.S. Water Services was our integrated water management company, which reflects operating results until the closing date of its sale on March 26, 2019. 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 two2 operating segments, BNI Energy, our coal mining operations in North Dakota, and ALLETE Properties, our legacy Florida real estate investment, along with our investment in Nobles 2, other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 4,000 acres of land in Minnesota, and earnings on cash and investments.

 Three Months Ended
 March 31,
 20192018
Millions  
Operating Revenue  
Regulated Operations  
Residential
$45.2

$40.7
Commercial38.9
36.6
Municipal15.4
14.0
Industrial121.6
114.9
Other Power Suppliers39.4
43.7
Other21.7
20.3
Total Regulated Operations282.2
270.2
   
Energy Infrastructure and Related Services  
   
ALLETE Clean Energy  
Long-term PSA14.6
18.6
Other2.9
6.0
Total ALLETE Clean Energy17.5
24.6
   
U.S. Water Services (a)
  
Point-in-Time19.0
22.3
Contract9.2
9.5
Capital Project5.2
6.4
Total U.S. Water Services33.4
38.2
   
Corporate and Other  
Long-term Contract20.2
20.0
Other3.9
5.2
Total Corporate and Other24.1
25.2
Total Operating Revenue
$357.2

$358.2
Net Income (Loss)  
Regulated Operations
$51.5

$43.9
   
Energy Infrastructure and Related Services  
ALLETE Clean Energy5.8
8.1
U.S. Water Services (a)
(1.1)(1.4)
   
Corporate and Other (a)
14.3
0.4
Total Net Income
$70.5

$51.0

NOTE 11. BUSINESS SEGMENTS (Continued)
 Quarter Ended Nine Months Ended
 September 30, September 30,
 20192018 20192018
Millions     
Operating Revenue     
Regulated Operations     
Residential
$29.8

$30.8
 
$104.2

$102.2
Commercial36.8
38.1
 110.6
110.9
Municipal11.8
14.2
 39.4
41.9
Industrial115.6
117.3
 357.5
347.5
Other Power Suppliers37.3
40.9
 111.9
127.3
CIP Financial Incentive (a)
2.8
3.0
 2.8
3.0
Other20.0
17.0
 59.7
56.5
Total Regulated Operations254.1
261.3
 786.1
789.3
      
Energy Infrastructure and Related Services     
      
ALLETE Clean Energy     
Long-term PSA7.5
9.0
 34.6
40.0
Other2.9
6.0
 8.7
17.9
Total ALLETE Clean Energy10.4
15.0
 43.3
57.9
      
U.S. Water Services (b)
     
Point-in-Time
29.0
 19.0
77.0
Contract
9.7
 9.2
28.7
Capital Project
6.3
 5.2
19.0
Total U.S. Water Services
45.0
 33.4
124.7
      
Corporate and Other



   
Long-term Contract20.5
21.2
 61.9
63.9
Other3.3
5.5
 11.2
14.5
Total Corporate and Other23.8
26.7
 73.1
78.4
Total Operating Revenue
$288.3

$348.0
 
$935.9

$1,050.3
Net Income (Loss)     
Regulated Operations
$32.4

$29.8
 
$114.2

$99.7
      
Energy Infrastructure and Related Services     
ALLETE Clean Energy(1.2)1.0
 6.5
15.9
U.S. Water Services (b)

1.7
 (1.1)0.5
      
Corporate and Other (b)

(1.8) 16.3
(3.1)
Total Net Income
$31.2

$30.7
 
$135.9

$113.0

(a)See Note 2. Regulatory Matters.
(b)On March 26, 2019, ALLETE completed the sale of U.S. Water Services. The Company recognized a gain on the sale of approximately $10$11.1 million after-tax reflected in Corporate and Other in 2019. (See Note 1. Operations and Significant Accounting Policies.)


NOTE 11. BUSINESS SEGMENTS (Continued)
March 31,
2019

December 31,
2018

September 30,
2019

December 31,
2018

Millions  
Assets  
Regulated Operations
$3,962.7

$3,952.5

$4,045.2

$3,952.5
  
Energy Infrastructure and Related Services  
ALLETE Clean Energy643.8
606.6
839.8
606.6
U.S. Water Services (a)

295.8

295.8
  
Corporate and Other612.3
310.1
390.8
310.1
Total Assets
$5,218.8

$5,165.0

$5,275.8

$5,165.0

(a)On March 26, 2019, ALLETE completed the sale of U.S. Water Services. (See Note 1. Operations and Significant Accounting Policies.)


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 our 2018 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 2018 Form 10-K under the headings: “Forward-Looking Statements” located on page 6 and “Risk Factors” located in Part I, Item 1A, beginning on page 23 of our 2018 Form 10-K. The risks and uncertainties described in this Form 10-Q and our 2018 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.

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 portions 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 1615 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 2. 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 555 MW of nameplate capacity wind energy generation that is contracted under PSAs of various durations. In addition, ALLETE Clean Energy currently has approximately 480 MW of wind energy facilities under construction that it will own and operate with long-term PSAs in place. ALLETE Clean Energy also engages in the development of wind energy facilities to operate under long-term PSAs or for sale to others upon completion.

U.S. Water Services provided integrated water management for industry by combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage, and improve efficiency. On February 8, 2019, the Company entered into a stock purchase agreement providing for the sale of U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. for a cash purchase price of $270 million. On March 26, 2019, ALLETE completed the sale and received approximately $265 million in cash at closing, net of transaction costs and cash retained. This amount is subject to adjustment for finalization of such items as estimated working capital.

Corporate and Other is comprised of BNI Energy, our coal mining operations in North Dakota, ALLETE Properties, our legacy Florida real estate investment, our investment in Nobles 2, other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 4,000 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 March 31,September 30, 2019, 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 threenine months ended March 31,September 30, 2019, to the threenine months ended March 31,September 30, 2018.

Net income for the threenine months ended March 31,September 30, 2019, was $70.5$135.9 million, or $1.37$2.63 per diluted share, compared to $51.0$113.0 million, or $0.99$2.19 per diluted share, for the same period in 2018. Net income in 2019 included the gain on sale of U.S. Water Services of approximately $10$11.1 million after-tax, or $0.19$0.22 per share. Earnings per share dilution was $0.01 due to additional shares of common stock outstanding as of September 30, 2019.

Regulated Operations net income was $51.5$114.2 million for the threenine months ended March 31,September 30, 2019, compared to $43.9$99.7 million for the same period in 2018. Net income at Minnesota Power was higher than in 2018 primarily due to lower operating and maintenance and property tax expenses, increased cost recovery rider revenue lower property tax expense, and higher sales to residential customers resulting from cooler weather conditions in 2019.the timing of fuel adjustment clause recoveries. These increases were partially offset by lower industrial sales and the timing of fuel adjustment clause recoveries.kWh sales. Net income at SWL&P was higher than 2018 primarily due to higher rates effective January 1, 2019, and lower operating and maintenance expenses.rates. Our after-tax equity earnings in ATC were higher than in 2018 primarily due to additional investments in ATC.investments.

ALLETE Clean Energy net income was $5.8$6.5 million for the threenine months ended March 31,September 30, 2019, compared to $8.1$15.9 million for the same period in 2018. Net income in 2018 included $2.7 million of production tax credits that resulted from the retrospective qualification of additional wind turbine generators in 2016 and 2017. Net income in 2019 included lower revenue resulting from lower wind resources and availability due to weather as well as lower non-cash amortization related to the renewalexpiration of PSAs at lower prices.power sales agreements, and higher depreciation expense. These decreases were partially offset by $1.8$3.2 million of additional production tax credits generated in 2019 compared to production tax credits generated in 2018 as ALLETE Clean Energy continues to execute its refurbishment strategy.

U.S. Water Services net loss was $1.1 million for the threenine months ended March 31,September 30, 2019, compared to a net lossincome of $1.4$0.5 million for the same period in 2018. ALLETE completed the sale of U.S. Water Services in the first quarter of 2019.

Corporate and Other net income was $14.3$16.3 million for the threenine months ended March 31,September 30, 2019, compared to a net incomeloss of $0.4$3.1 million for the same period in 2018. Net income in 2019 included the gain on sale of U.S. Water Services of approximately $10$11.1 million after-tax. Net income in 2019 also included additional income tax benefit recorded in 2019 as GAAP requires the recognition of income tax expense at the estimated annual effective tax rate.rate, and higher earnings on cash and short-term investments.





COMPARISON OF THE THREE MONTHSQUARTERS ENDED MARCH 31,SEPTEMBER 30, 2019 AND 2018

(See Note 11. Business Segments for financial results by segment.)

Regulated Operations
Three Months Ended March 31,2019
2018
Quarter Ended September 30,2019
2018
Millions  
Operating Revenue – Utility
$282.2

$270.2

$254.1

$261.3
Fuel, Purchased Power and Gas – Utility109.8
100.9
98.2
103.2
Transmission Services – Utility18.3
18.4
18.3
17.9
Operating and Maintenance47.7
55.5
47.5
50.3
Depreciation and Amortization39.8
34.3
39.4
39.5
Taxes Other than Income Taxes12.3
15.1
11.4
11.8
Operating Income54.3
46.0
39.3
38.6
Interest Expense(15.5)(14.9)(14.4)(15.5)
Equity Earnings in ATC5.6
4.7
Equity Earnings4.9
4.0
Other Income4.3
1.6
2.1
1.4
Income Before Income Taxes48.7
37.4
31.9
28.5
Income Tax Benefit(2.8)(6.5)(0.5)(1.3)
Net Income
$51.5

$43.9

$32.4

$29.8

Operating Revenue Utility increased $12.0decreased $7.2 million, or 43 percent, from 2018 reflecting increased cost recovery rider revenue, higher fuel adjustment clause recoveries, and the timingas a result of the provision for tax reform refund in 2018 related to income tax changes resulting from the TCJA, partially offset by lower revenue from kWh sales.

Cost recovery rider revenue contributed an incremental $7.3 million over current base rates compared to 2018 primarily due tosales and conservation improvement program recoveries, partially offset by higher expenditures related to the construction of the GNTL and fewer production tax credits recognized by Minnesota Power. (See Note 2. Regulatory Matters.) If production tax credits are recognized at a level below those assumed in Minnesota Power’s base rates, an increase in cost recovery rider revenue is recognized to offset the impact of lower production tax credits on income tax expense.

Fuel adjustment clause recoveries increased $6.8 million due to higher fuel and purchased power costs attributable to retail and municipal customers.

Revenue was $4.7 million higher than 2018 reflecting the timing of Minnesota Power’s provision for tax reform refund in 2018. In the first quarter of 2018, Minnesota Power reserved for income tax benefits resulting from the reduction of the federal income tax rate enacted as part of the TCJA. In the second quarter of 2018, the MPUC allowed Minnesota Power to retain these income tax benefits to mostly offset an increase in depreciation expense resulting from the reconsideration of its decision in Minnesota Power’s general rate case to reduce the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2035. (See Operating Expenses - Depreciation and Amortization.)transmission revenue.

Revenue from kWh sales decreased $7.3$10.2 million from 2018 reflecting lower sales to Other Power Suppliers, Industrialresidential, commercial and municipal customers and Municipal customers. These decreases were partially offset by higheras well as lower sales to Residential customers.other power suppliers. Sales to Residentialresidential and commercial customers increased in 2019decreased from 2018 primarily due to coolermilder weather conditions in 2019 compared to the same period in 2018. Sales to Industrial customers decreased from 2018 reflecting in part lower sales to Husky Energy due to an April 2018 fire at its refinery in Superior, Wisconsin. Sales to Municipalmunicipal customers decreased in 2019 as a result of additional customer self-generation in 2019 and the expiration of a contract with a municipal customer on June 30, 2019. Sales to Other Power Suppliersother power suppliers decreased from 2018in 2019 primarily due to fewer market sales and sales under PSAs as a result of less generation available for sale, partially offset by the commencement of Minnesota Power’s PSA with Oconto Electric Cooperative in January 2019. Sales to Other Power Suppliersother power suppliers are sold at market-based prices into the MISO market on a daily basis or through PSAs of various durations.


COMPARISON OF THE THREE MONTHS ENDED MARCH 31, 2019 AND 2018 (Continued)
Regulated Operations (Continued)
Kilowatt-hours Sold    Quantity %    Quantity %
Three Months Ended March 31,2019
 2018
 Variance Variance
Quarter Ended September 30,2019
 2018
 Variance Variance
Millions              
Regulated Utility              
Retail and Municipal              
Residential349
 342
 7
 2.0 %248
 251
 (3) (1.2)%
Commercial366
 367
 (1) (0.3)%361
 369
 (8) (2.2)%
Industrial1,814
 1,843
 (29) (1.6)%1,802
 1,794
 8
 0.4 %
Municipal203
 219
 (16) (7.3)%146
 196
 (50) (25.5)%
Total Retail and Municipal2,732
 2,771
 (39) (1.4)%2,557
 2,610
 (53) (2.0)%
Other Power Suppliers822
 1,003
 (181) (18.0)%758
 968
 (210) (21.7)%
Total Regulated Utility Kilowatt-hours Sold3,554
 3,774
 (220) (5.8)%3,315
 3,578
 (263) (7.4)%

Revenue from electric sales to taconite and iron concentrate customers accounted for 2227 percent of consolidated operating revenue in 2019 (21(22 percent in 2018). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 56 percent of consolidated operating revenue in 2019 (4(5 percent in 2018). Revenue from electric sales to pipelines and other industrial customers accounted for 7 percent of consolidated operating revenue in 2019 (7(6 percent in 2018).

Conservation improvement program recoveries decreased $2.0 million from 2018 primarily due to a decrease in related expenditures.

Transmission revenue increased $4.3 million from 2018. Revenue in 2018 reflected a $4.4 million out-of-period adjustment for an estimated true-up of MISO rates that were billed in 2017 and are being credited to customers in 2019.



COMPARISON OF THE QUARTERS ENDED SEPTEMBER 30, 2019 AND 2018 (Continued)
Regulated Operations (Continued)

Operating Expenses increased $3.7decreased $7.9 million, or 24 percent, from 2018.

Fuel, Purchased Power and Gas – Utility expense increased $8.9decreased $5.0 million, or 95 percent, from 2018 primarily due to less generation and more purchased power, partially offset by lower kWh sales. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause.

Operating and Maintenance expense decreased $7.8$2.8 million, or 146 percent, from 2018 primarily due to lower salary and benefit expenses, and lower materials purchased for generation facilities.maintenance contract expenses.

Depreciation and Amortization Interest Expenseexpense increased $5.5 decreased $1.1 million, or 16 percent, from 2018 primarily due to the timing of modifications of the depreciable lives for Boswell as part of Minnesota Power’s general rate case. As part of its decision in Minnesota Power’s general rate case in 2018, the MPUC extended the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2050, and shortened the depreciable lives of Boswell Unit 1 and Unit 2 to 2022, resulting in a net decrease to depreciation expense in the first quarter of 2018. In the second quarter of 2018, as part of the reconsideration of its decision in Minnesota Power’s general rate case, the MPUC reduced the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2035, resulting in higher depreciation expense beginning in the second quarter of 2018. (See Operating Revenue.)

Taxes Other than Income Taxes decreased $2.8 million, or 197 percent, from 2018 primarily due to lower property tax expenses resulting frominterest on Minnesota Power’s reserve for interim rate refunds and lower estimated taxable market values.average interest rates, partially offset by higher average long-term debt balances. We record interest expense for Regulated Operations primarily based on rate base and authorized capital structure, and allocate the balance to Corporate and Other.

Equity Earnings in ATC increased $0.9 million, or 1923 percent, from 2018 primarily due to additional investments in ATC.

Other Income increased $2.7 million from2018 due to various individually immaterial items.

Income Tax Benefitdecreased $3.7$0.8 million from 2018 primarily due to higher pre-tax income. We expect our annual effective tax rate in 2019 to be a lower income tax benefit than in 2018 primarily due to higher pre-tax income.

ALLETE Clean Energy
Three Months Ended March 31,2019
2018
Quarter Ended September 30,2019
2018
Millions   
Operating Revenue
$17.5

$24.6
$10.4
$15.0
Net Income
$5.8

$8.1
Operating and Maintenance7.3
7.4
Depreciation and Amortization6.7
6.4
Taxes and Other0.5
0.6
Operating Income (Loss)(4.1)0.6
Interest Expense(0.7)(0.8)
Other Income0.3
0.1
Loss Before Income Taxes(4.5)(0.1)
Income Tax Benefit(3.3)(1.1)
Net Income (Loss) Attributable to ALLETE$(1.2)
$1.0

Operating Revenuedecreased $7.1$4.6 million, or 2931 percent, from 2018 primarily due to lower non-cash amortization related to the expiration of power sales agreements of $3.1 million as well as lower kWh sales resulting from lower wind resources and availabilityavailability.
 Quarter Ended September 30,
 20192018
Production and Operating RevenuekWhRevenuekWhRevenue
Millions    
Wind Energy Regions    
East28.6

$2.5
38.6

$3.5
Midwest145.0
6.7
139.7
10.1
West15.3
1.2
17.0
1.4
Total Production and Operating Revenue188.9

$10.4
195.3

$15.0

Income Tax Benefit increased $2.2 million from 2018 primarily due to weather,additional production tax credits generated in 2019 and the renewallower pre-tax income. The income tax benefit reflected production tax credits generated of PSAs at lower prices.$2.1 million in 2019 and $0.9 million in 2018.





COMPARISON OF THE THREE MONTHSQUARTERS ENDED MARCH 31,SEPTEMBER 30, 2019 AND 2018 (Continued)
ALLETE Clean Energy (Continued)
U.S. Water Services
 Three Months Ended March 31,
 20192018
Production and Operating RevenuekWhRevenuekWhRevenue
Millions    
Wind Energy Facilities    
Armenia Mountain80.4

$7.4
91.5

$8.3
Chanarambie/Viking65.2
3.2
78.7
3.9
Condon13.4
1.1
34.3
2.8
Lake Benton52.6
2.9
70.4
3.4
Storm Lake I53.4
1.1
62.5
3.3
Storm Lake II34.8
1.6
47.9
2.9
Other6.9
0.2


Total Production and Operating Revenue306.7

$17.5
385.3

$24.6
Quarter Ended September 30,2019
2018
Millions  
Operating Revenue

$45.0
Net Income

$1.7

Operating Revenue decreased $45.0 million from 2018. ALLETE completed the sale of U.S. Water Services in the first quarter of 2019. (See Note 1. Operations and Significant Accounting Policies.)

Net Income decreased $2.3 million, or 28 percent, from 2018. Net income in 2019 included lower revenue resulting from lower wind resources and availability due to weather as well as the renewal of PSAs at lower prices. These decreases were partially offset by $1.8 million of additional production tax credits generated as ALLETE Clean Energy continues to execute on its refurbishment strategy.

U.S. Water Services
Three Months Ended March 31,2019
2018
Millions  
Operating Revenue
$33.4

$38.2
Net Loss$(1.1)$(1.4)

Operating Revenue decreased $4.8 million, or 13 percent, from 2018. Revenue from chemical sales and related services was $28.2 million in 2019 compared to $31.8 million in 2018. Revenue from capital projects was $5.2 million for 2019 compared to $6.4 million in 2018.

Net Loss decreased $0.3$1.7 million from 2018. The net lossALLETE completed the sale of U.S. Water Services in 2019 was similar to 2018.the first quarter of 2019.

Corporate and Other

Operating Revenue decreased $1.1$2.9 million, or 411 percent, from 2018 primarily due to various individually insignificant items.lower revenue at BNI Energy, which operates under cost-plus fixed fee contracts, as a result of lower expenses and fewer tons sold in 2019 compared to 2018, lower revenue from non-rate base generation, and a decrease in land sales at ALLETE Properties.

Net Income was $14.3increased $1.8 million infrom 2018 comparedprimarily due to net income of $0.4 million in 2018. Net income in 2019 included the gain on sale of U.S. Water Services of approximately $10 million after-tax. Net income in 2019 also included additional income tax benefit as GAAP requires the recognition of income tax expense at the estimated annual effective tax rate.rate and lower expenses, partially offset by fewer land sales at ALLETE Properties. Net income at BNI Energy was $1.9$1.7 million in 2019 compared to net income of $1.8 millionand in 2018. The net loss at ALLETE Properties was $0.6$1.0 million in 2019 compared to a net loss of $0.5$0.4 million in 2018.

Income Taxes – Consolidated

For the three monthsquarter ended March 31,September 30, 2019, the effective tax rate was a benefit of 8.3 percent (expense of 1.3 percent for the quarter ended September 30, 2018). The 2019 increase in tax benefit was primarily due to additional production tax credits and additional income tax benefit 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.


COMPARISON OF THE NINE MONTHS ENDED SEPTEMBER 30, 2019 AND 2018

(See Note 11. Business Segments for financial results by segment.)

Regulated Operations
Nine Months Ended September 30,2019
2018
Millions  
Operating Revenue – Utility
$786.1

$789.3
Fuel, Purchased Power and Gas – Utility295.9
300.6
Transmission Services – Utility55.8
53.1
Operating and Maintenance149.4
160.7
Depreciation and Amortization119.4
118.3
Taxes Other than Income Taxes36.2
39.9
Operating Income129.4
116.7
Interest Expense(44.3)(45.5)
Equity Earnings15.3
13.0
Other Income9.2
4.0
Income Before Income Taxes109.6
88.2
Income Tax Benefit(4.6)(11.5)
Net Income
$114.2

$99.7



COMPARISON OF THE NINE MONTHS ENDED SEPTEMBER 30, 2019 AND 2018 (Continued)
Regulated Operations (Continued)

Operating Revenue Utility decreased $3.2 million from 2018 primarily due to lower revenue from kWh sales, mostly offset by higher fuel adjustment clause recoveries, increased cost recovery rider revenue, higher FERC formula-based rates and higher transmission revenue.

Revenue from kWh sales decreased $32.5 million from 2018 reflecting lower sales to residential, commercial, industrial and municipal customers as well as lower sales to other power suppliers. Sales to residential and commercial customers decreased from 2018 primarily due to milder weather in the second and third quarters of 2019. Sales to industrial customers decreased in 2019 reflecting in part lower sales to Husky Energy due to an April 2018 fire at its refinery in Superior, Wisconsin. Sales to municipal customers decreased from 2018 as a result of additional customer self-generation in 2019 and the expiration of a contract with a municipal customer on June 30, 2019. Sales to other power suppliers decreased in 2019 primarily due to fewer market sales and sales under PSAs as a result of less generation available for sale, partially offset by the commencement of Minnesota Power’s PSA with Oconto Electric Cooperative in January 2019. Sales to other power suppliers are sold at market-based prices into the MISO market on a daily basis or through PSAs of various durations.
Kilowatt-hours Sold    Quantity %
Nine Months Ended September 30,2019
 2018
 Variance Variance
Millions       
Regulated Utility       
Retail and Municipal       
Residential829
 836
 (7) (0.8)%
Commercial1,043
 1,075
 (32) (3.0)%
Industrial5,389
 5,418
 (29) (0.5)%
Municipal519
 603
 (84) (13.9)%
Total Retail and Municipal7,780
 7,932
 (152) (1.9)%
Other Power Suppliers2,294
 2,976
 (682) (22.9)%
Total Regulated Utility Kilowatt-hours Sold10,074
 10,908
 (834) (7.6)%

Revenue from electric sales to taconite customers accounted for 25 percent of consolidated operating revenue in 2019 (22 percent in 2018). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 6 percent of consolidated operating revenue in 2019 (5 percent in 2018). Revenue from electric sales to pipelines and other industrial customers accounted for 7 percent of consolidated operating revenue in 2019 (6 percent in 2018).

Fuel adjustment clause revenue increased $12.9 million due to period over period timing of recoveries for fuel and purchased power costs attributable to retail and municipal customers.

Cost recovery rider revenue contributed an incremental $12.0 million over current base rates compared to 2018 (see Note 2. Regulatory Matters) primarily due to higher expenditures related to the construction of the GNTL and lower transmission margins related to our portion of CapX2020 transmission lines. Transmission margins for CapX2020 transmission lines recognized below those assumed in Minnesota Power base rates result in increased cost recovery rider revenue to offset the impact of the lower margins.

Revenue from wholesale customers under FERC formula-based rates increased $3.4 million from 2018 primarily due to higher rates.

Transmission revenue increased $3.3 million from 2018. Revenue in 2018 reflected a $4.4 million out-of-period adjustment for an estimated true-up of MISO rates that were billed in 2017 and are being credited to customers in 2019.

Operating Expenses decreased $15.9 million, or 2 percent, from 2018.

Fuel, Purchased Power and Gas – Utility expense decreased $4.7 million, or 2 percent, from 2018 primarily due to lower kWh sales. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause.

Transmission Services – Utility expense increased $2.7 million, or 5 percent, from 2018 primarily due to higher MISO‑related expense.


COMPARISON OF THE NINE MONTHS ENDED SEPTEMBER 30, 2019 AND 2018 (Continued)
Regulated Operations (Continued)

Operating and Maintenance expensedecreased $11.3 million, or 7 percent, from 2018 primarily due to lower salary and benefit expenses, maintenance contract expenses and materials purchased for generation facilities.

Taxes Other than Income Taxes decreased $3.7 million, or 9 percent, from 2018 primarily due to lower property tax expenses resulting from lower estimated taxable market values.

Equity Earnings increased $2.3 million, or 18 percent, from2018 primarily due to additional investments in ATC.

Other Income increased $5.2 million from2018 reflecting various individually immaterial items.

Income Tax Benefit decreased $6.9 million from 2018 primarily due to higher pre-tax income. We expect our annual effective tax rate in 2019 to be a lower income tax benefit than in 2018 primarily due to higher pre-tax income.

ALLETE Clean Energy
Nine Months Ended September 30,2019
2018
Millions  
Operating Revenue
$43.3

$57.9
Operating and Maintenance22.7
22.6
Depreciation and Amortization19.8
18.2
Taxes and Other1.6
1.7
Operating Income (Loss)(0.8)15.4
Interest Expense(2.3)(2.8)
Other Income2.1
0.2
Income (Loss) Before Income Taxes(1.0)12.8
Income Tax Benefit(7.5)(3.1)
Net Income Attributable to ALLETE
$6.5

$15.9

Operating Revenue decreased $14.6 million, or 25 percent, from 2018 primarily due to lower non-cash amortization related to the expiration of 4.0power sales agreements of $9.2 million as well as lower kWh sales resulting from lower wind resources and availability.
 Nine Months Ended September 30,
 20192018
Production and Operating RevenuekWhRevenuekWhRevenue
Millions    
Wind Energy Regions    
East173.0

$15.7
185.6

$16.9
Midwest549.4
23.5
580.6
34.9
West51.4
4.1
75.3
6.1
Total Production and Operating Revenue773.8

$43.3
841.5

$57.9

Depreciation and Amortizationexpense increased $1.6 million, or 9 percent, from 2018 primarily due to additional property, plant and equipment in service.

Other Incomeincreased $1.9 million from 2018 reflecting various individually immaterial items.

Income Tax Benefit increased $4.4 million from 2018 primarily due to additional production tax credits generated in 2019 and lower pre-tax income. The income tax benefit reflected production tax credits generated of $6.3 million in 2019 and $3.1 million in 2018. The income tax benefit in 2018 also reflected $2.7 million of production tax credits that resulted from the retrospective qualification of additional wind turbine generators in 2016 and 2017.




COMPARISON OF THE NINE MONTHS ENDED SEPTEMBER 30, 2019 AND 2018 (Continued)

U.S. Water Services
Nine Months Ended September 30,20192018
Millions  
Operating Revenue$33.4$124.7
Net Income (Loss)$(1.1)$0.5

Operating Revenue decreased $91.3 million, or 73 percent, from 2018. ALLETE completed the sale of U.S. Water Services in the first quarter of 2019. (See Note 1. Operations and Significant Accounting Policies.)

Net Loss increased $1.6 million from 2018. ALLETE completed the sale of U.S. Water Services in the first quarter of 2019.

Corporate and Other

Operating Revenue decreased $5.3 million, or 7 percent, from 2018 primarily due to lower revenue at BNI Energy, which operates under cost-plus fixed fee contracts, as a result of lower expenses and fewer tons sold in 2019 compared to 2018, and lower revenue from non-rate base generation.

Net Income was $16.3 million in 2019 compared to a net loss of $3.1 million in 2018. Net income in 2019 included the gain on sale of U.S. Water Services of $11.1 million after-tax. Net income in 2019 also included additional income tax benefit recorded in 2019 as GAAP requires the recognition of income tax expense at the estimated annual effective tax rate, and higher earnings on cash and short-term investments. Net income at BNI Energy was $5.3 million in 2019 and in 2018. The net loss at ALLETE Properties was $2.1 million in 2019 compared to a net loss of $1.5 million in 2018.

Income Taxes – Consolidated

For the nine months ended September 30, 2019, the effective tax rate was a benefit of 3.3 percent (benefit of 7.88.3 percent for the threenine months ended March 31,September 30, 2018). The effective tax rate for 2019 includedwas a lower benefit primarily due to a higher tax rate on and higher pre-tax income tax expense of $10.2 millionresulting from the gain on the sale of U.S. Water Services.

We expect our annual effective tax rate in 2019 to be similara lower benefit as compared to 2018 reflecting the sale of U.S. Water Services, andpartially offset by higher production tax credits generated by ALLETE Clean Energy. The effective rate deviated from the combined statutory rate of approximately 28 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, and taxation. 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 2018 Form 10-K.





OUTLOOK

For additional information see our 2018 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 5 percent to 7 percent, and providing a dividend payout competitive with our industry. Regulated Operations is projected to have average annual earnings growth of 4 percent to 5 percent and our Energy Infrastructure and Related Services businesses are projected to have average annual earnings growth of at least 15 percent over the long-term.

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 and other businesses to complement its regulated businesses, balance exposure to the utility’s industrial customers and provide potential long-term earnings growth. ALLETE expects net income from Regulated Operations to be approximately 80 percent of total consolidated net income in 2019. Over the next several years, the contribution of the Energy Infrastructure and Related Services and other 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.

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 approvals for transmission, renewable and environmental investments, as well as work with regulators to earn a fair rate of return. Minnesota Power anticipates filing a rate case in the fourth quarter of 2019 with a 2020 test year.

Regulatory Matters. Entities within our Regulated Operations segment are under the jurisdiction of the MPUC, FERC, PSCW and NDPSC. See Note 2. Regulatory Matters for discussion of regulatory matters within these jurisdictions.

2016 Minnesota General Rate Case. The MPUC issued an order dated March 12, 2018, in Minnesota Power’s general rate case approving a return on common equity of 9.25 percent and a 53.81 percent equity ratio. Final rates went into effect on December 1, 2018, which is expected to result in additional revenue of approximately $13 million on an annualized basis. Interim rates were collected from January 1, 2017, through November 30, 2018, which were fully offset by the recognition of a corresponding reserve. Minnesota Power has recorded a reserve for an interim rate refund, net of discounts provided to EITE customers, of $40.6 million as of March 31, 2019 ($40.0$40.0 million as of December 31, 2018),2018, which is expected to bewas refunded in the second quarter of 2019.

2020 Minnesota General Rate Review. On November 1, 2019, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 10.6 percent for retail customers. The rate filing seeks a return on equity of 10.05 percent and a 53.81 percent equity ratio. On an annualized basis, the requested final rate increase would generate approximately $66 million in additional revenue. Once the filing is accepted as complete, an annual interim rate increase of approximately $48 million is expected to be implemented within 60 days, subject to MPUC adjustment and authorization. We cannot predict the level of interim or final rates that may be authorized by the MPUC.

2018 Wisconsin General Rate Case. In an order dated December 20, 2018, the PSCW approved a rate increase for SWL&P including a return on equity of 10.4 percent and a 55.0 percent equity ratio. Final rates went into effect January 1, 2019, which is expected to result in additional revenue of approximately $1.3 million on an annualized basis.




OUTLOOK (Continued)

Industrial Customers and Prospective Additional Load.

Industrial Customers. Electric power is one of several key inputs in the taconite mining, iron concentrate, paper, pulp and secondary wood products, pipeline and other industries. Approximately 5153 percent of our regulated utility kWh sales in the threenine months ended March 31,September 30, 2019, were made to our industrial customers (49(50 percent in the threenine months ended March 31,September 30, 2018).

Taconite and Iron Concentrate. Minnesota Power’s taconite customers are 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 10 percent of Minnesota taconite production has been exported outside of North America. Minnesota Power also has provided electric service to three iron concentrate facilities capable of producing up to approximately 4 million tons of iron concentrate per year. Iron concentrate is used in the production of taconite pellets. These facilities have been idled since at least 2016. In July 2018, ERP Iron Ore announced it would no longer seek to restart its operations.

There has been a general historical correlation between U.S. steel production and Minnesota taconite production. The American Iron and Steel Institute, an association of North American steel producers, reported that U.S. raw steel production operated at approximately 8281 percent of capacity during the first threenine months of 2019 compared to 7578 percent in the first threenine months of 2018. The World Steel Association, an association of over 160 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 2019 will increase by approximately one percent compared to 2018.

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 $0.04, 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.

USS Corporation. On October 17, 2019, USS Corporation announced that it had idled one of its pellet production lines at its Minnesota Ore Operations - Minntac plant in Mountain Iron, Minnesota, citing changing market conditions and the need to adjust its raw materials accordingly. USS Corporation also noted it plans to perform additional maintenance during this time in preparation for improved market conditions and does not anticipate any employment impacts. We cannot predict when production may resume on the idled pellet production line, however, we do not expect a material impact to results of operations for 2019.

Northshore Mining. Cliffs has announced that it is investing furtherhas made an approximately $90 million investment in its Minnesota ore operations specifically it plans to invest approximately $90 million through 2020 to expand capacity for producing direct reduced-grade pellets at Northshore Mining. The additional direct reduced-grade pellets could be sold commercially or used to supply Cliff’s plannedCliffs is currently constructing a hot briquetted iron production plant in Toledo, Ohio. CliffsOhio, and has announced plans to beginbegun shipping direct reduced-grade pellets to the Toledo plant later in 2019 in anticipation of the planned start of operations in 2020.mid-2020. Minnesota Power has a PSA through 2031 with Silver Bay Power, which provides the majority of the electric service requirements for Northshore Mining. (See Silver Bay Power.)

Silver Bay Power. In 2016, Minnesota Power and Silver Bay Power entered into a PSA through 2031. Silver Bay Power supplies approximately 90 MW of load to Northshore Mining, an affiliate of Silver Bay Power, which hashad been served predominately through self-generation by Silver Bay Power. Through 2019, Minnesota Power will supplysupplied Silver Bay Power with at least 50 MW of energy and Silver Bay Power hashad the option to purchase additional energy from Minnesota Power as it transitionstransitioned away from self-generation. By December 31,In the third quarter of 2019, Silver Bay Power is expected to ceaseceased self-generation and Minnesota Power is expected to supplybegan supplying the full energy requirements for Silver Bay Power.

Paper, Pulp and Secondary Wood Products. We expect operating levels in 2019 at the four major paper and pulp mills we serve to be similar to 2018.

Pipeline and Other Industries.

Husky Energy. In April 2018, a fire at Husky Energy’s refinery in Superior, Wisconsin, disrupted operations at the facility. Under normal operating conditions, SWL&P provides approximately 14 MW of average monthly demand to Husky Energy in addition to water service. On September 30, 2019, Husky Energy announced that it had received the required permit approvals to begin reconstruction. The facility remains at minimal operations, and the refinery is not expected to resume normal operations until 2020. 2021.



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

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.


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

PolyMet. PolyMet is planning to start a new copper-nickel and precious metal (non-ferrous) mining operation in northeastern Minnesota. In 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) and the U.S. Army Corps of Engineers have both issued final Records of Decision, finding the final EIS adequate.

In 2016, PolyMet submitted applications for water-related permits with the DNR and MPCA, an air quality permit with the MPCA, and a state permit to mine application with the DNR detailing its operational plans for the mine. In June 2018, the U.S. Forest Service and PolyMet closed on a land exchange, which resulted in PolyMet obtaining surface rights to land needed to develop its mining operation. In November 2018, the DNR issued PolyMet’s permit to mine and certain water-related permits. In December 2018, the MPCA issued PolyMet’s final state water and air quality permits. On March 21, 2019, the U.S. Army Corps of Engineers issued PolyMet’s final federal permit. PolyMet now holdshas received all necessary permits to construct and operate its mining operation. In June 2018, the U.S. Forest Service and PolyMet closed on a land exchange, which resulted in PolyMet obtaining surface rights to land needed to develop itsnew mining operation. Minnesota Power could supply between 45 MW and 50 MW of load under a 10‑year power supply contract with PolyMet that would begin upon start-up of operations.


EnergyForward. Minnesota Power is executing EnergyForward, a strategic plan for assuring reliability, protecting affordability and further improving environmental performance. The plan includes completed and planned investments in wind, solar, natural gas and hydroelectric power, construction of additional transmission capacity, the installation of emissions control technology and the idling of certain coal-fired generating facilities.

In 2017, Minnesota Power submitted a resource package to the MPUC requesting approval of PPAs for the output of a 250 MW wind energy facility (see Nobles 2 PPA) and a 10 MW solar energy facility (see Solar Energy) as well as approval of a 250 MW natural gas capacity dedication agreement. These agreements wereThe natural gas capacity dedication agreement was subject to MPUC approval of the construction of NTEC, a 525 MW to 550 MW combined-cycle natural gas‑fired generating facility which will be jointly owned by Dairyland Power Cooperative and a subsidiary of ALLETE. Minnesota Power would purchase approximately 50 percent of the facility's output starting in 2025. In an order dated January 24, 2019, the MPUC approved Minnesota Power’s request for approval of the NTEC natural gas capacity dedication agreement. Separately, the MPUC required a baseload retirement evaluation in Minnesota Power’s next IRP filing analyzing its existing fleet including potential early retirement scenarios of Boswell Units 3 and 4, as well as a securitization plan. On January 8, 2019, an application for a certificate of public convenience and necessity for NTEC was submitted to the PSCW. A decision on the application is expected in 2020.

Integrated Resource Plan. In a 2016 order, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The order accepted Minnesota Power’s plans for the economic idling of Taconite Harbor Units 1 and 2 and the ceasing of coal-fired operations at Taconite Harbor in 2020, directed Minnesota Power to retire Boswell Units 1 and 2 no later than 2022, required an analysis of generation and demand response alternatives to be filed with a natural gas resource proposal, and required Minnesota Power to conduct requestrequests for proposalsproposal for additional wind, solar and demand response resource additions subject to further MPUC approvals.additions. Minnesota Power retired Boswell Units 1 and 2 in the fourth quarter of 2018. Minnesota Power’s next IRP filing is due October 1, 2020. (See Note 2. Regulatory Matters.)

Renewable Energy. Minnesota Power’s 2015 IRP includes an update on its plans and progress in meeting the Minnesota renewable energy milestones through 2025. Minnesota Power continues to execute its renewable energy strategy through 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 between 25 percent and 30approximately 50 percent of its applicable retail and municipal energy sales will be supplied by renewable energy sources in 2019.by 2021.

Solar Energy. Minnesota Power’s solar energy supply consists of Camp Ripley, a 10 MW solar energy facility at the Camp Ripley Minnesota Army National Guard base and training facility near Little Falls, Minnesota, and a community solar garden project in northeastern Minnesota, which is comprised of a 1 MW solar array owned and operated by a third party with the output purchased by Minnesota Power and a 40 kW solar array that is owned and operated by Minnesota Power. In an October 2018 order, the MPUC approved a PPA for the output of the 10 MW Blanchard solar energy facility to be located in central Minnesota.

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.



OUTLOOK (Continued)
EnergyForward (Continued)

Wind Energy. Minnesota Power’s wind energy facilities consist of Bison (497 MW) located in North Dakota, and Taconite Ridge (25 MW) located in northeastern Minnesota. Minnesota Power also has two long-term wind energy 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-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. TheMinnesota Power is currently pursuing a modernization and capacity upgrade of its DC transmission line capacity can be increased if renewable energy or transmission needs justify investmentssystem to upgrade the line.continue providing reliable operations and additional system capabilities.

Minnesota Power has an approved cost recovery rider for certain renewable investments and expenditures. The cost recovery rider allows Minnesota Power to charge retail customers on a current basis for the costs of certain renewable investments plus a return on the capital invested. Updated customer billing rates for the renewable cost recovery rider were provisionally approved by the MPUC in a November 2018 order.

Nobles 2 PPA. In the third quarter of 2018, Minnesota Power and Nobles 2 signed an amended long-term PPA that provides for Minnesota Power to purchase the energy and associated capacity from a 250 MW wind energy facility in southwestern Minnesota for a 20-year period beginning in 2020. The agreement provides for the purchase of output from the facility at fixed energy prices. There are no fixed capacity charges, and Minnesota Power will only pay for energy as it is delivered. This agreement is subject to construction of the wind energy facility. (See Note 3. Equity Investments.)

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.

The third PPA provides for Minnesota Power to purchase 250 MW of capacity and energy from Manitoba Hydro for 15 years beginning in 2020. The PPA is subject to the construction of the GNTL and MMTP. (See Note 7. Commitments, Guarantees and Contingencies.) 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.

The fourth PPA 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 is subject to the construction of the GNTL and MMTP. (See Note 7. Commitments, Guarantees and Contingencies.)

The fifth PPA provides for Minnesota Power to purchase 50 MW of capacity from Manitoba Hydro at fixed prices. The PPA began in June 2017 and expires in May 2020.


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. As a condition of the 250-MW long-term PPA entered into with Manitoba Hydro, construction of additional transmission capacity is required. As a result, Minnesota Power is constructing the GNTL, an approximately 220‑mile 500-kV transmission line between Manitoba and Minnesota’s Iron Range that was proposed by Minnesota Power and Manitoba Hydro in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy.



OUTLOOK (Continued)
Transmission (Continued)

In a 2016 order, the MPUC approved the route permit for the GNTL, and in 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‑constructionConstruction activities commenced in the first quarter of 2017, with construction expectedand Minnesota Power expects the GNTL to be completed in 2020. To date, most of the right-of-way has been cleared while foundation installationcomplete and transmission tower construction have commenced.in-service by mid-2020. The total project cost in the U.S., including substation work, is estimated to be between $560 million and $710approximately $700 million, of which Minnesota Power’s portion is expected to be between $300 million and $350approximately $325 million; the difference will be recovered from a subsidiary of Manitoba Hydro as non-shareholder contributions to capital. Total project costs of $458.2$581.6 million have been incurred through March 31,September 30, 2019, of which $245.0$310.4 million has been recovered from a subsidiary of Manitoba Hydro.

Manitoba Hydro must obtain regulatory and governmental approvals related to the MMTP, a new transmission line in Canada that will connect with the GNTL. (See Note 7. Commitments, Guarantees and Contingencies.)

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 portions of Wisconsin, Michigan, Minnesota and Illinois. As of March 31,September 30, 2019, our equity investment in ATC was $130.0$136.9 million ($128.1 million as of December 31, 2018). In the first threenine months of 2019, we invested $0.4$4.7 million in ATC, and on April 30,October 31, 2019, we invested an additional $2.3$1.9 million. We do not expect to make $5.8 million ofany additional investments in 2019. (See Note 3. Equity Investments.)

ATC’s authorized return on equity is 10.32 percent, or 10.82 percent including an incentive adder for participation in a regional transmission organization. In 2016, a federal administrative law judge ruled on a complaint proposing a 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 pending.

ATC’s 10-year transmission assessment, which covers the years 20182019 through 2027,2028, identifies a need for between $2.8$2.9 billion and $3.4$3.6 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 555 MW of nameplate capacity wind energy generation that is contracted under PSAs of various durations. In addition, ALLETE Clean Energy currently has approximately 480 MW of wind energy facilities under construction that it will own and operate with long-term PSAs in place. ALLETE Clean Energy also engages in the development of wind energy facilities to operate under long-term PSAs or for sale to others upon completion.

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. State renewable portfolio standards and state or federal regulations to limit GHG emissions are examples of 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. ALLETE Clean Energy generally acquires facilities in liquid power markets and its strategy includes the exploration of PSA extensions upon expiration of existing contracts and production tax credit requalification of existing facilities.

ALLETE Clean Energy will pursue growth through acquisitions or project development. ALLETE Clean Energy is targeting acquisitions of existing facilities up to 200 MW each, which have long-term PSAs in place for the facilities’ output. At this time, ALLETE Clean Energy expects acquisitions or development of new facilities 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.



OUTLOOK (Continued)
ALLETE Clean Energy (Continued)

Federal production tax credit qualification is important to the economics of project development, and in 2016, 2017 and 2018 ALLETE Clean Energy invested in equipment to meet production tax credit safe harbor provisions which provides an opportunity to seek development of up to approximately 1,500 MW of production tax credit qualified wind projects through 2022. ALLETE Clean Energy will also invest approximately $80 million through 2020 for production tax credit requalification of up to 468 WTGs at its Storm Lake I, Storm Lake II, Lake Benton and Condon wind energy facilities. We anticipate annual production tax credits relating to these projects of approximately $14$12 million in 2019, $17 million to $22 million annually in 2020 through 2027 and decreasing thereafter through 2030.

In March 2017, ALLETE Clean Energy announced it will build, own and operate a 100 MW wind energy facility pursuant to a 20-year PSA with Northern States Power; construction is expected to be completed in late 2019. In March 2018, ALLETE Clean Energy announced that it will build, own and operate an 80 MW wind energy facility pursuant to a 15-year PSA with NorthWestern Corporation; construction is expected to be completed in late 2019.

On May 3, 2019, ALLETE Clean Energy acquired the Diamond Spring wind project in Oklahoma from Apex Clean Energy. ALLETE Clean Energy will build, own and operate the approximately 300 MW wind energy facility. The Diamond Spring wind project is fully contracted to sell wind power to Walmart Inc., Smithfield Foods, Inc. and Starbucks Corporation under long-term power sales agreements. Construction is expected to begin in late 2019 and be completed in late 2020.

ALLETE Clean Energy manages risk by having a diverse portfolio of assets, which includes PSA expiration, technology and geographic diversity. The current portfolio of approximately 555 MW is subject to typical variations in seasonal wind with higher wind resources typically available in the winter months. The majority of its planned maintenance leverages this seasonality and is performed during lower wind periods. The current mix of PSA expiration and geographic location for existing facilities is as follows:
Wind Energy FacilityLocationCapacity MWPSA MW %PSA ExpirationRegionCapacity MWPSA MW %PSA Expiration
Armenia MountainPennsylvania101100%2024East101100%2024
Chanarambie/VikingMinnesota98 Midwest98 
PSA 1 (a)
 12%2023 12%2023
PSA 2 88%2023 88%2023
CondonOregon50100%2022West50100%2022
Lake BentonMinnesota104100%2028Midwest104100%2028
Storm Lake IIowa108100%2019Midwest108100%2027
Storm Lake IIIowa77 Midwest77 
PSA 1 90%2020 90%2020
PSA 2 10%2032 10%2032
OtherMinnesota17100%2028Midwest17100%2028
(a)The PSA expiration assumes the exercise of four one-year renewal options that ALLETE Clean Energy has the sole right to exercise.

U.S. Water Services.

On February 8, 2019, the Company entered into a stock purchase agreement providing for the sale of U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. for a cash purchase price of $270 million. On March 26, 2019, ALLETE completed the sale and received approximately $265 million in cash at closing, net of transaction costs and cash retained. This amount is subject to adjustment for finalization of such items as estimated working capital. ALLETE plans to use the proceeds from the sale primarily to reinvest in growth initiatives at our Regulated Operations and ALLETE Clean Energy.




OUTLOOK (Continued)
Corporate and Other.

BNI Energy. BNI Energy anticipates selling 4.44.3 million tons of lignite coal in 2019 (4.3 million tons were sold in 2018) and has sold 1.13.2 million tons for the threenine months ended March 31,September 30, 2019 (1.2(3.4 million tons were sold for the threenine months ended March 31,September 30, 2018). BNI Energy operates under cost-plus fixed fee agreements extending through December 31, 2037.

Investment in Nobles 2. Our wholly-owned subsidiary, ALLETE South Wind, owns 49 percent of Nobles 2, the entity that will own and operate a 250 MW wind energy facility in southwestern Minnesota pursuant to a 20-year PPA with Minnesota Power. The wind energy facility will be built in Nobles County, Minnesota and is expected to be completed in late 2020, with an estimated total project cost of approximately $350 million to $400 million, of which our portion is expected to be approximately $170 million to $200 million. We expect to utilize tax equity to finance a portion of our project costs. We account for our investment in Nobles 2 under the equity method of accounting. As of March 31,September 30, 2019, our equity investment in Nobles 2 was $24.8$46.4 million ($33.0 million at December 31, 2018). In the first quarter of 2019, Nobles 2 returned capital of $8.3 million based on its cash needs. We expect to make approximately $12 million in additional investments in 2019.


OUTLOOK (Continued)
Corporate and Other (Continued)

ALLETE Properties. ALLETE Properties represents our legacy Florida real estate investment. ALLETE Properties’ major projects in Florida are Town Center at Palm Coast and Palm Coast Park, with approximately 1,500 acres combined of land available for sale. In addition to these two projects, ALLETE Properties has approximately 600 acres of other land available for sale. Market conditions can impact land sales and could result in our inability to cover our cost basis and operating expenses including fixed carrying costs such as community development district assessments and property taxes.

Our strategy incorporates the possibility of a bulk sale of the entire ALLETE Properties portfolio. Proceeds from a bulk sale would be strategically deployed to support growth initiatives at our Regulated Operations and ALLETE Clean Energy. ALLETE Properties also continues to pursue sales of individual parcels over time and will continue to maintain key entitlements and infrastructure.

Income Taxes.

ALLETE’s aggregate federal and multi-state statutory tax rate is approximately 28 percent for 2019. ALLETE also 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, depletion, as well as other items. The annual effective rate can also be impacted by such items as changes in income before 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 a benefit of approximately 105 percent for 2019 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 10 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 March 31,September 30, 2019, we had cash and cash equivalents of $353.3$100.3 million, $387.0$346.9 million in available consolidated lines of credit and a debt-to-capital ratio of 4142 percent.

Capital Structure. ALLETE’s capital structure is as follows:
March 31,
2019

 % December 31,
2018

 %September 30,
2019

 % December 31,
2018

 %
Millions              
Shareholders’ Equity
$2,198.7
 59 
$2,155.8
 59
$2,207.8
 58 
$2,155.8
 59
Long-Term Debt (Including Long-Term Debt Due Within One Year)1,549.0
 41 1,495.2
 411,626.7
 42 1,495.2
 41

$3,747.7
 100 
$3,651.0
 100
$3,834.5
 100 
$3,651.0
 100



LIQUIDITY AND CAPITAL RESOURCES (Continued)

Cash Flows. Selected information from the Consolidated Statement of Cash Flows is as follows:
For the Three Months Ended March 31,2019
 2018
Millions   
Cash, Cash Equivalents and Restricted Cash at Beginning of Period
$79.0
 
$110.1
Cash Flows from (used for)   
Operating Activities79.1
 121.3
Investing Activities185.1
 (89.0)
Financing Activities22.0
 (26.5)
Change in Cash, Cash Equivalents and Restricted Cash286.2
 5.8
Cash, Cash Equivalents and Restricted Cash at End of Period
$365.2
 
$115.9



LIQUIDITY AND CAPITAL RESOURCES (Continued)
For the Nine Months Ended September 30,2019
 2018
Millions   
Cash, Cash Equivalents and Restricted Cash at Beginning of Period
$79.0
 
$110.1
Cash Flows from (used for)   
Operating Activities176.4
 298.1
Investing Activities(160.0) (207.8)
Financing Activities39.8
 (58.9)
Change in Cash, Cash Equivalents and Restricted Cash56.2
 31.4
Cash, Cash Equivalents and Restricted Cash at End of Period
$135.2
 
$141.5

Operating Activities. Cash from operating activities was lower in 2019 compared to 2018 primarily due to the refund of Minnesota Power’s provisionprovisions for tax reform and interim rates to customers, fewer customer deposits received and lower recoveries from customers under cost recovery riders in 2019. These decreases were partially offset by the timing of collections of accounts receivable.

Investing Activities. Cash fromused for investing activities was higherlower in 2019 compared to 2018 primarily due to proceeds received from the sale of U.S. Water Services.Services, partially offset by higher additions to property, plant and equipment.

Financing Activities. Cash from financing activities was higher in 2019 primarily due to higher proceeds from the issuance of long-term debt. This increase was partially offset by higher repayments of long-term debt.

Working Capital. Additional working capital, if and when needed, generally is provided by consolidated bank lines of credit and the issuance of securities, including long-term debt, common stock and commercial paper. As of March 31,September 30, 2019, we had consolidated bank lines of credit aggregating $407.0 million ($407.0 million as of December 31, 2018), the majority of which expire in January 2024. We had $20.0$60.1 million outstanding in standby letters of credit and no outstanding draws under our lines of credit as of March 31,September 30, 2019 ($18.4 million in standby letters of credit and no outstanding draws as of December 31, 2018). In addition, as of March 31,September 30, 2019, we had 2.83.7 million original issue shares of our common stock available for issuance through Invest Direct, our direct stock purchase and dividend reinvestment plan, and 2.9 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. On July 31, 2019, we filed Registration Statement No. 333-232905, pursuant to which the remaining shares will continue to be offered for sale, from time to time.

Securities. During the threenine months ended March 31,September 30, 2019, we issued 0.10.2 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 $0.8$1.7 million (0.2(0.3 million shares were issued for the threenine months ended March 31,September 30, 2018, resulting in net proceeds of $4.3$14.6 million). These shares of common stock were registered under Registration Statement Nos. 333-231030, 333-211075, 333-183051 and 333-162890.

On January 10, 2019, ALLETE entered into an amended and restated $400 million credit agreement, as amended (Credit Agreement). The Credit Agreement is unsecured, has a variable interest rate and will expire in January 2024. At ALLETE’s request and subject to certain conditions, the Credit Agreement may be increased by up to $150 million and ALLETE may make two requests to extend the maturity date, each for a one-year extension. Advances may be used by ALLETE for general corporate purposes, to provide liquidity in support of ALLETE’s commercial paper program and to issue up to $60$100 million in letters of credit. (See Note 6. Short-Term and Long-Term Debt.)

Financial Covenants. See Note 6. 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. (See Note 10. Pension and Other Postretirement Benefit Plans.)

Off-Balance Sheet Arrangements. Off-balance sheet arrangements are summarized in our 2018 Form 10-K, with additional disclosure in Note 7. Commitments, Guarantees and Contingencies.


LIQUIDITY AND CAPITAL RESOURCES (Continued)

Credit Ratings. Access to reasonably priced capital markets is dependent in part on credit and ratings. Our securities have been rated by S&P Global Ratings and by Moody’s. Rating agencies use both quantitative and qualitative measures in determining a company’s credit rating. These measures include business risk, liquidity risk, competitive position, capital mix, financial condition, predictability of cash flows, management strength and future direction. Some of the quantitative measures can be analyzed through a few key financial ratios, while the qualitative ones are more subjective. Our current credit ratings are listed in the following table:
Credit RatingsS&P Global RatingsMoody’s
Issuer Credit RatingBBB+Baa1
Commercial PaperA-2P-2
First Mortgage Bonds(a)A2
(a)Not rated by S&P Global Ratings.


LIQUIDITY AND CAPITAL RESOURCES (Continued)

On March 26, 2019, Moody’s downgraded the long-term ratings of ALLETE, including its issuer rating to Baa1 from A3, and changed its credit rating outlook to stable from negative. Moody’s noted the combined impact of the 2018 adverse general rate case outcome at Minnesota Power as well as its debt coverage ratios going forward as its rationale for the downgrade.

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

Capital Requirements. Our capital expenditures for 2019 and 2020 are now expected to be approximately $530 million.$695 million and $495 million, respectively. The increases from the 2019 and 2020 capital expenditures projected in our 2018 Form 10-K are primarily due to the Diamond Spring wind energy facility that ALLETE Clean Energy will build, own and operate pursuant to long-term PSAs with Walmart Inc., Smithfield Foods, Inc. and Starbucks Corporation. (See Outlook – ALLETE Clean Energy.) For the threenine months ended March 31,September 30, 2019, capital expenditures totaled $85.1$421.6 million ($52.6215.5 million for the threenine months ended March 31,September 30, 2018). The expenditures were primarily made in the Regulated Operations and ALLETE Clean Energy segments.


OTHER

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 been promulgated by both the EPA and state authorities over the past several years. Minnesota Power’s facilities are subject to additional requirements under many of 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. (See Note 7. Commitments, Guarantees and Contingencies.)

Employees.

As of March 31,September 30, 2019, ALLETE had 1,3541,349 employees, of which 1,3361,314 were full-time.

Minnesota Power and SWL&P have an aggregate of 449473 employees who are members of International Brotherhood of Electrical Workers (IBEW) Local 31. The current labor agreements with IBEW Local 31 expire on April 30, 2020, for Minnesota Power and February 1, 2021, for SWL&P.

BNI Energy has 182 employees, of which 136135 are subject to a labor agreement with IBEW Local 1593. The current labor agreement with IBEW Local 1593 expiredexpires on March 31, 2019. Negotiations are proceeding and we believe a ratified agreement will be agreed upon with no disruption to operations.2023.




OTHER (Continued)

NEW ACCOUNTING PRONOUNCEMENTS

New accounting pronouncements 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 March 31,September 30, 2019, our available-for-sale securities portfolio consisted primarily of securities held in other postretirement plans to fund employee benefits.


ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (Continued)

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. Minnesota Power’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 or distribution of savings in fuel costs to 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 as of March 31,September 30, 2019, an increase of 100 basis points in interest rates would impact the amount of pre-tax interest expense by $0.5$1.5 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 March 31,September 30, 2019.





ITEM 4.  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures. As of March 31,September 30, 2019, 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 4. Regulatory Matters and Note 11. Commitments, Guarantees and Contingencies to the Consolidated Financial Statements in our 2018 Form 10-K and Note 2. Regulatory Matters and Note 7. 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 2018 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
 
 
 
 
 
 
101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH XBRL Schema
101.CAL XBRL Calculation
101.DEF XBRL Definition
101.LAB XBRL Label
101.PRE XBRL Presentation
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
*Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. ALLETE will furnish the omitted schedules to the SEC upon request.




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.
   
   
   
   
May 2,November 6, 2019 /s/ Robert J. Adams
  Robert J. Adams
  Senior Vice President and Chief Financial Officer
  (Principal Financial Officer)
   
   
   
   
May 2,November 6, 2019 /s/ Steven W. Morris
  Steven W. Morris
  Vice President, Controller and Chief Accounting Officer
  (Principal Accounting Officer)


ALLETE, Inc. FirstThird Quarter 2019 Form 10-Q
4751