Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

QUARTERLY REPORT PURSUANT TO SECTIONQuarterly Report pursuant to Section 13 ORor 15(d) OF THE SECURITIES

           EXCHANGE ACT OFof the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2021 or
Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Commission File Number 0-53713
OTTER TAIL CORPORATION
(Exact name of registrant as specified in its charter) 

For the quarterly period ended

September 30, 2020

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

           0-53713

OTTER TAIL CORPORATION

(Exact name of registrant as specified in its charter)

Minnesota

27-0383995

(State or other jurisdiction of

(I.R.S. Employer

incorporation or organization)

27-0383995
(I.R.S. Employer Identification No.)

215 South Cascade Street, Box 496, Fergus Falls,Minnesota

56538-0496

(Address of principal executive offices)

56538-0496
(Zip Code)

866-410-8780

(Registrant's telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

Registrant's telephone number, including area code: 866-410-8780
Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:

Act: 

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Shares, par value $5.00 per share

OTTR

The Nasdaq Stock Market LLC

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. YesNo 

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 (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). YesNo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or 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. (Check one):

Large accelerated filer ☑Accelerated filer ☐
Large Accelerated Filer
Accelerated Filer
Non-accelerated filer ☐
Non-Accelerated Filer
Smaller reporting company Reporting Company
Emerging growth company Growth Company

If an emerging growth company, indicate by checkmarkcheck 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 byin Rule 12b-2 of the Exchange Act).

YesNo

Indicate the number of shares outstanding of each of the issuer'sregistrant's classes of Common Stock,common stock, as of the latest practicable date:

October 31,202041,064,051

41,539,984CommonShares ($5 par value)

asof October 29, 2021. 



OTTER TAIL CORPORATION

INDEX

Part I. Financial Information

Page No.

TABLE OF CONTENTS

Item 1.

Financial Statements

Description
Page

ITEM 1.

2 &

7

8-33

ITEM 2.

Item 2.

34-52

ITEM 3.

Item 3.

52

ITEM 4.

Item 4.

52

Part II. Other InformationITEM 1.

Item 1.

53

ITEM 1A.

Item 1A.

Risk Factors 

53

ITEM 6.

Item 6.

Exhibits

54

Signatures

54


1


PART I. FINANCIAL INFORMATION

DEFINITIONS
The following abbreviations or acronyms are used in the text.

Item 1. Financial StatementsAFUDC

Allowance for Funds Used During ConstructionMPUCMinnesota Public Utilities Commission

ARP

Alternative Revenue ProgramNDPSCNorth Dakota Public Service Commission
BTDBTD Manufacturing, Inc.Northern PipeNorthern Pipe Products, Inc.
CIPConservation Improvement ProgramOTCOtter Tail Corporation

Consolidated Balance Sheets

ECR
Environmental Cost Recovery RiderOTPOtter Tail Power Company

(not audited)

EEP
Energy Efficiency PlanPACEPartnership in Assisting Community Expansion

(in thousands)

 

September 30,

2020

  

December 31,

2019

 
         

Assets

        
         

Current Assets

        

Cash and Cash Equivalents

 $44,904  $21,199 

Accounts Receivable:

        

Trade—Net

  100,423   77,947 

Other

  6,322   8,773 

Inventories

  81,871   97,851 

Unbilled Receivables

  16,409   20,911 

Income Taxes Receivable

  0   1,487 

Regulatory Assets

  17,435   21,650 

Other

  7,552   5,042 

Total Current Assets

  274,916   254,860 
         

Investments

  10,791   9,894 

Other Assets

  42,316   40,196 

Goodwill

  37,572   37,572 

Other IntangiblesNet

  10,419   11,290 

Regulatory Assets

  145,977   144,138 
         

Right of Use Assets - Operating Leases

  19,713   21,851 
         

Plant

        

Electric Plant in Service

  2,221,785   2,212,884 

Nonelectric Operations

  256,480   247,356 

Construction Work in Progress

  454,128   185,238 

Total Gross Plant

  2,932,393   2,645,478 

Less Accumulated Depreciation and Amortization

  939,590   891,684 

Net Plant

  1,992,803   1,753,794 
         

Total Assets

 $2,534,507  $2,273,595 

See accompanying condensed notes to consolidated financial statements.

EPA
Environmental Protection AgencyPIRPhase-In Rider
ESSRPExecutive Survivor and Supplemental Retirement PlanPTCsProduction tax credits
EUICElectric Utility Infrastructure Cost Recovery RiderPVCPolyvinyl chloride
FCAFuel Clause AdjustmentRHRRegional Haze Rule
FERCFederal Energy Regulatory CommissionROEReturn on equity
GCRGeneration Cost Recovery RiderRRRRenewable Resource Rider
ISOIndependent System OperatorSDPUCSouth Dakota Public Utilities Commission
IRPIntegrated Resource PlanSECSecurities and Exchange Commission
kWkiloWattT.O. PlasticsT.O. Plastics, Inc.
kwhkilowatt-hourTCRTransmission Cost Recovery Rider
MerricourtMerricourt Wind Energy CenterVinyltechVinyltech Corporation
MISOMidcontinent Independent System Operator, Inc.

FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 (the Act). When used in this Form 10-Q and in future filings by the Company with the SEC, in the Company’s press releases and in oral statements, words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “outlook,” “plan,” “possible,” “potential,” “should,” “will,” “would” or similar expressions are intended to identify forward-looking statements within the meaning of the Act. Such statements are based on current expectations and assumptions and entail various risks and uncertainties that could cause actual results to differ materially from those expressed in such forward-looking statements. The Company’s risks and uncertainties include, among other things, uncertainty of the impact and duration of the COVID-19 pandemic, uncertainty of future investments and capital expenditures, rate base levels and rate base growth, long-term investment risk, seasonal weather patterns and extreme weather events, counterparty credit risk, future business volumes with key customers, reductions in our credit ratings, our ability to access capital markets on favorable terms, assumptions and costs relating to funding our employee benefit plans, our subsidiaries’ ability to make dividend payments, cyber security threats or data breaches, the impact of government legislation and regulation, including foreign trade policy and environmental laws and regulations, the impact of climate change, including compliance with legislative and regulatory changes to address climate change, operational and economic risks associated with our electric generating and manufacturing facilities, risks associated with energy markets, the availability and pricing of resource materials, attracting and maintaining a qualified and stable workforce, expectations regarding regulatory proceedings, and changing macroeconomic and industry conditions. These and other risks and uncertainties are more fully described in our filings with the Securities and Exchange Commission, including our most recently filed Annual Report on Form 10-K. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information.
PART I. FINANCIAL INFORMATION
ITEM 1.FINANCIAL STATEMENTS

2


OTTER TAIL CORPORATION
CONSOLIDATED BALANCE SHEETS (unaudited)
(in thousands, except share data)September 30,
2021
December 31,
2020
Assets  
Current Assets  
Cash and Cash Equivalents$1,272 $1,163 
Receivables, net of allowance for credit losses178,759 113,959 
Inventories114,615 92,165 
Regulatory Assets22,517 21,900 
Other Current Assets17,804 5,645 
Total Current Assets334,967 234,832 
Noncurrent Assets
Investments55,456 51,856 
Property, Plant and Equipment, net of accumulated depreciation2,083,223 2,049,273 
Regulatory Assets158,515 168,395 
Intangible Assets, net of accumulated amortization9,319 10,144 
Goodwill37,572 37,572 
Other Noncurrent Assets34,096 26,282 
Total Noncurrent Assets2,378,181 2,343,522 
Total Assets$2,713,148 $2,578,354 
Liabilities and Shareholders' Equity
Current Liabilities
Short-Term Debt$97,857 $80,997 
Current Maturities of Long-Term Debt169,962 140,087 
Accounts Payable135,437 130,805 
Accrued Salaries and Wages28,455 26,908 
Accrued Taxes17,972 18,831 
Regulatory Liabilities25,323 16,663 
Other Current Liabilities35,081 22,495 
Total Current Liabilities510,087 436,786 
Noncurrent Liabilities and Deferred Credits
Pensions Benefit Liability101,446 114,055 
Other Postretirement Benefits Liability68,090 67,359 
Regulatory Liabilities230,733 233,973 
Deferred Income Taxes176,502 153,376 
Deferred Tax Credits16,847 17,405 
Other Noncurrent Liabilities62,342 60,002 
Total Noncurrent Liabilities and Deferred Credits655,960 646,170 
Commitments and Contingencies (Note 9)
00
Capitalization
Long-Term Debt, net of current maturities594,619 624,432 
Shareholders' Equity
Common Shares: 50,000,000 shares authorized of $5 par value; 41,539,984 and 41,469,879 outstanding
at September 30, 2021 and December 31, 2020
207,700 207,349 
Additional Paid-In Capital418,568 414,246 
Retained Earnings334,385 257,878 
Accumulated Other Comprehensive Loss(8,171)(8,507)
Total Shareholders' Equity952,482 870,966 
Total Capitalization1,547,101 1,495,398 
Total Liabilities and Shareholders' Equity$2,713,148 $2,578,354 

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

(in thousands, except share data)

 

September 30,

2020

  

December 31,

2019

 
         

Liabilities and Equity

        
         

Current Liabilities

        

Short-Term Debt

 $48,600  $6,000 

Current Maturities of Long-Term Debt

  215   183 

Accounts Payable

  189,327   120,775 

Accrued Salaries and Wages

  20,933   22,730 

Accrued Taxes

  14,283   17,525 

Regulatory Liabilities

  12,870   7,480 

Current Operating Lease Liabilities

  4,581   4,136 

Other Accrued Liabilities

  8,927   10,912 

Total Current Liabilities

  299,736   189,741 
         

Pensions Benefit Liability

  86,101   98,970 

Other Postretirement Benefits Liability

  72,508   71,437 

Long-Term Operating Lease Liabilities

  15,778   18,193 

Other Noncurrent Liabilities

  35,146   30,833 
         

Commitments and Contingencies (note 9)

          
         

Deferred Credits

        

Deferred Income Taxes

  152,448   131,941 

Deferred Tax Credits

  17,640   18,626 

Regulatory Liabilities

  236,892   239,906 

Other

  1,914   2,885 

Total Deferred Credits

  408,894   393,358 
         

Capitalization

        

Long-Term Debt—Net

  764,274   689,581 
         

Cumulative Preferred Shares – Authorized 1,500,000 Shares Without Par Value; Outstanding – None

  0   0 
         

Cumulative Preference Shares – Authorized 1,000,000 Shares Without Par Value; Outstanding – None

  0   0 
         

Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares; Outstanding, 2020—41,052,165 Shares; 2019—40,157,591 Shares

  205,261   200,788 

Premium on Common Shares

  398,301   364,790 

Retained Earnings

  254,468   222,341 

Accumulated Other Comprehensive Loss

  (5,960)  (6,437)

Total Common Equity

  852,070   781,482 

Total Capitalization

  1,616,344   1,471,063 

Total Liabilities and Equity

 $2,534,507  $2,273,595 
See accompanying notes to consolidated financial statements.

See accompanying condensed notes to consolidated financial statements.

3


OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (unaudited)
Three Months Ended September 30,Nine Months Ended September 30,
(in thousands, except per-share amounts)2021202020212020
Operating Revenues  
Electric$118,775 $115,213 $348,629 $333,213 
Product Sales197,519 120,542 514,983 330,045 
Total Operating Revenues316,294 235,755 863,612 663,258 
Operating Expenses
Electric Production Fuel17,698 11,554 44,576 34,077 
Electric Purchased Power9,878 13,428 40,273 45,940 
Electric Operating and Maintenance Expenses36,465 32,845 114,615 106,639 
Cost of Products Sold (excluding depreciation)134,212 86,856 358,767 246,567 
Other Nonelectric Expenses16,224 13,615 45,587 36,277 
Depreciation and Amortization22,815 20,395 68,109 61,230 
Electric Property Taxes4,474 4,333 13,136 12,601 
Total Operating Expenses241,766 183,026 685,063 543,331 
Operating Income74,528 52,729 178,549 119,927 
Other Income and Expense
Interest Charges9,648 8,568 28,601 25,353 
Nonservice Cost Components of Postretirement Benefits505 842 1,511 2,581 
Other Income (Expense), net203 1,712 2,095 3,733 
Income Before Income Taxes64,578 45,031 150,532 95,726 
Income Tax Expense11,824 9,097 25,380 18,543 
Net Income$52,754 $35,934 $125,152 $77,183 
Weighted-Average Common Shares Outstanding:
Basic41,504 40,914 41,487 40,548 
Diluted41,869 41,078 41,795 40,733 
Earnings Per Share:
Basic$1.27 $0.88 $3.02 $1.90 
Diluted$1.26 $0.87 $2.99 $1.89 

See accompanying notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Statements of Income

(not audited)

  

Three Months Ended

September 30,

  

Nine Months Ended

September 30,

 

(in thousands, except share and per-share amounts)

 

2020

  

2019

  

2020

  

2019

 

Operating Revenues

                

Electric:

                

Revenues from Contracts with Customers

 $112,435  $115,285  $330,313  $346,291 

Changes in Accrued Revenues under Alternative Revenue Programs

  2,778   (921)  2,900   (1,601)

Total Electric Revenues

  115,213   114,364   333,213   344,690 

Product Sales from Contracts with Customers

  120,542   114,288   330,045   359,137 

Total Operating Revenues

  235,755   228,652   663,258   703,827 

Operating Expenses

                

Production Fuel – Electric

  11,554   18,331   34,077   45,547 

Purchased Power – Electric System Use

  13,428   13,163   45,940   54,748 

Electric Operation and Maintenance Expenses

  32,845   35,869   106,639   114,107 

Cost of Products Sold (depreciation included below)

  86,856   88,747   246,567   277,325 

Other Nonelectric Expenses

  13,615   11,665   36,277   38,404 

Depreciation and Amortization

  20,395   19,657   61,230   58,229 

Property Taxes – Electric

  4,333   3,965   12,601   11,824 

Total Operating Expenses

  183,026   191,397   543,331   600,184 

Operating Income

  52,729   37,255   119,927   103,643 

Interest Charges

  8,568   7,539   25,353   23,190 

Nonservice Cost Components of Postretirement Benefits

  842   1,055   2,581   3,165 

Other Income

  1,712   1,020   3,733   3,114 

Income Before Income Taxes

  45,031   29,681   95,726   80,402 

Income Tax Expense

  9,097   4,936   18,543   13,907 

Net Income

  35,934  $24,745   77,183  $66,495 
                 

Average Number of Common Shares Outstanding – Basic

  40,913,972   39,714,672   40,548,133   39,694,677 

Average Number of Common Shares Outstanding – Diluted

  41,077,689   39,946,739   40,732,928   39,922,580 
                 

Basic Earnings Per Common Share

 $0.88  $0.62  $1.90  $1.68 
                 

Diluted Earnings Per Common Share

 $0.87  $0.62  $1.89  $1.67 

See accompanying condensed notes to consolidated financial statements.

4


OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)
Three Months Ended September 30,Nine Months Ended September 30,
(in thousands)2021202020212020
Net Income$52,754 $35,934 $125,152 $77,183 
Other Comprehensive Income (Loss):
Unrealized Gain (Loss) on Available-for-Sale Securities:
Reversal of Previously Recognized Losses (Gains) Realized on Sale of Investments and Included in Other Income (Expense) (21)(43)13 
Unrealized Gains (Losses)(33)(13)(85)205 
Income Tax (Expense) Benefit7 27 (46)
Available-for-Sale Securities, net of tax(26)(27)(101)172 
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs197 138 591 413 
Income Tax Expense(51)(36)(154)(108)
Pension and Postretirement Benefit Plan, net of tax146 102 437 305 
Total Other Comprehensive Income
120 75 336 477 
Total Comprehensive Income$52,874 $36,009 $125,488 $77,660 

See accompanying notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Statements of Comprehensive Income

(not audited)

  

Three Months Ended

September 30,

  

Nine Months Ended

September 30,

 

(in thousands)

 

2020

  

2019

  

2020

  

2019

 

Net Income

 $35,934  $24,745  $77,183  $66,495 

Other Comprehensive Income:

                

Unrealized Gains on Available-for-Sale Securities:

                

Reversal of Previously Recognized (Gains) Losses Realized on Sale of Investments and Included in Other Income During Period

  (21)  (1)  13   (5)

Unrealized (Losses) Gains Arising During Period

  (13)  30   205   187 

Income Tax Savings (Expense)

  7   (6)  (46)  (38)

Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax

  (27)  23   172   144 

Pension and Postretirement Benefit Plans:

                

Amortization of Unrecognized Postretirement Benefit Lossesand Costs (note 11)

  138   130   413   389 

Income Tax Expense

  (36)  (34)  (108)  (101)

Pension and Postretirement Benefit Plans – net-of-tax

  102   96   305   288 

Total Other Comprehensive Income

  75   119   477   432 

Total Comprehensive Income

 $36,009  $24,864  $77,660  $66,927 

See accompanying condensed notes to consolidated financial statements.

5


OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (unaudited)
(in thousands, except common shares outstanding)Common
Shares
Outstanding
Par Value,
Common
Shares
Additional Paid-In CapitalRetained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)1
Total Shareholders' Equity
Balance, June 30, 202141,538,709 $207,694 $417,870 $297,850 $(8,291)$915,123 
Common Stock Issuances, Net of Expenses1,275 (6)— — — 
Common Stock Retirements and Forfeitures— — (126)— — (126)
Net Income— — — 52,754 — 52,754 
Other Comprehensive Income— — — — 120 120 
Stock Compensation Expense— — 830 — — 830 
Common Dividends ($0.39 per share)— — — (16,219)— (16,219)
Balance, September 30, 202141,539,984 $207,700 $418,568 $334,385 $(8,171)$952,482 
Balance, June 30, 202040,848,828 $204,244 $390,141 $233,705 $(6,035)$822,055 
Common Stock Issuances, Net of Expenses203,337 1,017 6,885 — — 7,902 
Net Income— — — 35,934 — 35,934 
Other Comprehensive Income— — — — 75 75 
Stock Compensation Expense— — 1,275 — — 1,275 
Common Dividends ($0.37 per share)— — — (15,171)— (15,171)
Balance, September 30, 202041,052,165 $205,261 $398,301 $254,468 $(5,960)$852,070 
Balance, December 31, 202041,469,879 $207,349 $414,246 $257,878 $(8,507)$870,966 
Common Stock Issuances, Net of Expenses105,806 530 (578)— — (48)
Common Stock Retirements and Forfeitures(35,701)(179)(1,454)— — (1,633)
Net Income— — — 125,152 — 125,152 
Other Comprehensive Income— — — — 336 336 
Stock Compensation Expense— — 6,354 — — 6,354 
Common Dividends ($1.17 per share)— — — (48,645)— (48,645)
Balance, September 30, 202141,539,984 $207,700 $418,568 $334,385 $(8,171)$952,482 
Balance, December 31, 201940,157,591 $200,788 $364,790 $222,341 $(6,437)$781,482 
Common Stock Issuances, Net of Expenses932,791 4,664 30,107 — — 34,771 
Common Stock Retirements and Forfeitures(38,217)(191)(1,878)— — (2,069)
Net Income— — — 77,183 — 77,183 
Other Comprehensive Income— — — — 477 477 
Stock Compensation Expense— — 5,282 — — 5,282 
Common Dividends ($1.11 per share)— — — (45,056)— (45,056)
Balance, September 30, 202041,052,165 $205,261 $398,301 $254,468 $(5,960)$852,070 

Otter Tail Corporation

Consolidated Statements of Common Shareholders’ Equity

For the Three- and Nine-Month Periods Ended September 30, 2020 and 2019

(not audited)

(in thousands, except common shares outstanding)

 

Common

Shares

Outstanding

  

Par Value,

Common

Shares

  

Premium

on

Common

Shares

  

Retained

Earnings

  

Accumulated

Other Comprehensive Income/(Loss)

  

Total

Common

Equity

 

Balance, June 30, 2020

  40,848,828  $204,244  $390,141  $233,705  $(6,035) $822,055 

Common Stock Issuances, Net of Expenses

  203,337   1,017   6,885           7,902 

Net Income

              35,934       35,934 

Other Comprehensive Income

                  75   75 

Employee Stock Incentive Plan Expense

          1,275           1,275 

Common Dividends ($0.37 per share)

              (15,171)      (15,171)

Balance, September 30, 2020

  41,052,165  $205,261  $398,301  $254,468  $(5,960) $852,070 
                         

Balance, June 30, 2019

  39,754,902  $198,775  $345,030  $205,115  $(4,615) $744,305 

Common Stock Issuances, Net of Expenses

  375   1   (37)          (36)

Net Income

              24,745       24,745 

Other Comprehensive Income

                  119   119 

Employee Stock Incentive Plan Expense

          1,301           1,301 

Common Dividends ($0.35 per share)

              (13,929)      (13,929)

Balance, September 30, 2019

  39,755,277  $198,776  $346,294  $215,931  $(4,496) $756,505 
                         

Balance, December 31, 2019

  40,157,591  $200,788  $364,790  $222,341  $(6,437) $781,482 

Common Stock Issuances, Net of Expenses

  932,791   4,664   30,107           34,771 

Common Stock Retirements

  (38,217)  (191)  (1,878)          (2,069)

Net Income

              77,183       77,183 

Other Comprehensive Income

                  477   477 

Employee Stock Incentive Plan Expense

          5,282           5,282 

Common Dividends ($1.11 per share)

              (45,056)      (45,056)

Balance, September 30, 2020

  41,052,165  $205,261  $398,301  $254,468  $(5,960) $852,070 
                         

Balance, December 31, 2018

  39,664,884  $198,324  $344,250  $190,433  $(4,144) $728,863 

Common Stock Issuances, Net of Expenses

  145,617   728   (747)          (19)

Common Stock Retirements

  (55,224)  (276)  (2,454)          (2,730)

Net Income

              66,495       66,495 

Other Comprehensive Income

                  432   432 

ASU 2018-02 2017 TCJA Stranded Tax Transfer

              784   (784)  - 

Employee Stock Incentive Plan Expense

          5,245           5,245 

Common Dividends ($1.05 per share)

              (41,781)      (41,781)

Balance, September 30, 2019

  39,755,277  $198,776  $346,294  $215,931  $(4,496) $756,505 

6


1Accumulated Other Comprehensive Income (Loss) as of September 30, 2021 and December 31, 2020 is comprised of the following:
(in thousands)September 30,
2021
December 31,
2020
Unrealized Gain on Available-for-Sale Debt Securities:  
Before Tax$137 $265 
Tax Effect(29)(56)
Unrealized Gain on Available-for-Sale Debt, net of tax108 209 
Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits:
Before Tax(11,202)(11,793)
Tax Effect2,923 3,077 
Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits, net of tax(8,279)(8,716)
Accumulated Other Comprehensive Loss:
Before Tax(11,065)(11,528)
Tax Effect2,894 3,021 
Net Accumulated Other Comprehensive Loss$(8,171)$(8,507)
See accompanying notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Statements of Cash Flows

(not audited)

  

Nine Months Ended

September 30,

 

(in thousands)

 

2020

  

2019

 

Operating Activities

        

Net Income

 $77,183  $66,495 

Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:

        

Depreciation and Amortization

  61,230   58,229 

Deferred Tax Credits

  (986)  (1,011)

Deferred Income Taxes

  20,353   3,487 

Change in Deferred Debits and Other Assets

  3,439   7,142 

Discretionary Contribution to Pension Plan

  (11,200)  (22,500)

Change in Noncurrent Liabilities and Deferred Credits

  3,237   10,344 

Allowance for Equity/Other Funds Used During Construction

  (3,104)  (1,602)

Stock Compensation Expense

  5,282   5,245 

Other—Net

  (176)  312 

Cash (Used for) Provided by Current Assets and Current Liabilities:

        

Change in Receivables

  (20,025)  (16,213)

Change in Inventories

  15,980   9,218 

Change in Other Current Assets

  2,023   2,974 

Change in Payables and Other Current Liabilities

  (12,063)  (20,744)

Change in Interest and Income Taxes Receivable/Payable

  103   3,773 

Net Cash Provided by Operating Activities

  141,276   105,149 

Investing Activities

        

Capital Expenditures

  (220,630)  (149,695)

Proceeds from Disposal of Noncurrent Assets

  4,617   4,111 

Cash Used for Investments and Other Assets

  (6,372)  (5,546)

Net Cash Used in Investing Activities

  (222,385)  (151,130)

Financing Activities

        

Change in Checks Written in Excess of Cash

  90   383 

Net Short-Term Borrowings

  42,600   90,398 

Proceeds from Issuance of Common Stock

  35,219   0 

Common Stock Issuance Expenses

  (465)  (35)

Payments for Shares Withheld for Employee Tax Obligations

  (2,069)  (2,730)

Proceeds from Issuance of Long-Term Debt

  75,000   0 

Short-Term and Long-Term Debt Issuance Expenses

  (369)  (66)

Payments for Retirement of Long-Term Debt

  (136)  (128)

Dividends Paid

  (45,056)  (41,781)

Net Cash Provided by Financing Activities

  104,814   46,041 

Net Change in Cash and Cash Equivalents

  23,705   60 

Cash and Cash Equivalents at Beginning of Period

  21,199   861 

Cash and Cash Equivalents at End of Period

 $44,904  $921 

See accompanying condensed notes to consolidated financial statements.

7


OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
Nine Months Ended September 30,
(in thousands)20212020
Operating Activities  
Net Income$125,152 $77,183 
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation and Amortization68,109 61,230 
Deferred Tax Credits(558)(986)
Deferred Income Taxes18,835 20,353 
Change in Deferred Debits and Other Assets6,166 3,439 
Discretionary Contribution to Pension Plan(10,000)(11,200)
Change in Noncurrent Liabilities and Deferred Credits2,662 3,237 
Allowance for Equity Funds Used During Construction(427)(3,104)
Stock Compensation Expense6,354 5,282 
Other, Net(3,480)(176)
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables(64,800)(20,025)
Change in Inventories(22,450)15,980 
Change in Other Current Assets(12,159)2,023 
Change in Payables and Other Current Liabilities40,574 (12,063)
Change in Interest Payable and Income Taxes Receivable/Payable774 103 
Net Cash Provided by Operating Activities154,752 141,276 
Investing Activities
Capital Expenditures(117,312)(220,630)
Proceeds from Disposal of Noncurrent Assets5,819 4,617 
Cash Used for Investments and Other Assets(5,591)(6,372)
Net Cash Used in Investing Activities(117,084)(222,385)
Financing Activities
Change in Checks Written in Excess of Cash(3,133)90 
Net Short-Term Borrowings16,860 42,600 
Proceeds from Issuance of Common Stock 35,219 
Common Stock Issuance Expenses(67)(465)
Payments for Shares Withheld for Employee Tax Obligations(1,633)(2,069)
Proceeds from Issuance of Long-Term Debt 75,000 
Debt Issuance Expenses(772)(369)
Payments for Retirement of Long-Term Debt(169)(136)
Dividends Paid(48,645)(45,056)
Net Cash (Used in) Provided by Financing Activities
(37,559)104,814 
Net Change in Cash and Cash Equivalents109 23,705 
Cash and Cash Equivalents at Beginning of Period1,163 21,199 
Cash and Cash Equivalents at End of Period$1,272 $44,904 
Supplemental Disclosure of Noncash Investing Activities
Accrued Property, Plant, and Equipment Additions$14,358 $112,314 
See accompanying notes to consolidated financial statements
8


OTTER TAIL CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(
(unaudited)
1. Summary of Significant Accounting Policies
Overview
Otter Tail Corporation and its subsidiaries (collectively, the "Company", "us", "our" or "we") form a diverse, multi-platform business consisting of a vertically integrated, regulated utility with generation, transmission and distribution facilities complemented by manufacturing businesses providing metal fabrication for custom machine parts and metal components, manufacturing of extruded and thermoformed plastic products, and manufacturing of PVC pipe products. We classify our business into 3 segments: Electric, Manufacturing and Plastics.
Basis of Presentation
The unaudited consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the SEC for interim reporting. Accordingly, they do not audited)

include all the information and footnotes required by generally accepted accounting principles. In the opinion of management, Otter Tail Corporation (the Company) haswe have included all adjustments, (includingincluding normal recurring accruals)accruals, necessary for a fair presentation of the consolidated financial statements for the periods presented. The consolidated financial statements and condensed notes thereto should be read in conjunction with the consolidated financial statements and notes included in the Company'sour Annual Report on Form 10-K for the fiscal year ended December 31, 2019. 2020.

Because of the coronavirus (COVID-19) pandemic, the seasonality of our businesses and other factors, the earnings for the three and nine months ended September 30, 20202021 should not be taken as an indication of earnings for all or any part of the balance of the year.

1. Summarycurrent year or as an indication of Significant Accounting Policies

Revenue Recognition

Due to the diverse business operationsearnings for future years.

Use of the Company, recognition of revenue from contracts with customers depends on the product produced and sold or service performed. The Company recognizes revenue from contracts with customers at prices that are fixed or determinable as evidenced by an agreement with the customer, when the Company has met its performance obligation under the contract and it is probable that the Company will collect the amount to which it is entitled in exchange for the goods or services transferred or to be transferred to the customer. Depending on the product produced and sold or service performed and the terms of the agreement with the customer, the Company recognizes revenue either over time, in the case of delivery or transmission of electricity or related services or the production and storage of certain custom-made products, or at a point in time for the delivery of standardized products and other products made to the customer’s specifications where the terms of the contract require transfer of the completed product. Provisions for sales returns, early payment terms discounts, volume-based variable pricing incentives and warranty costs are recorded as reductions to revenue at the time revenue is recognized based on customer history, historical information and current trends.

In addition to recognizing revenue from contracts with customers under Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 606,Revenue from Contracts with Customers (ASC 606), the Company also records adjustments to Electric segment revenues for amounts subject to future collection under alternative revenue programs (ARPs) as defined in ASC Topic 980,Regulated Operations (ASC 980). The ARP revenue adjustments are recorded on the basis of recoverable costs incurred and returns earned under rate riders on a separate line on the face of the Company’s consolidated statements of income as they do not meet the criteria to be classified as revenue from contracts with customers.

Electric Segment Revenues—In the Electric segment, the Company recognizes revenue in two categories: (1) revenues from contracts with customers and (2) adjustments to revenues for amounts collectible under ARPs.

Most Electric segment revenues are earned from the generation, transmission and sale of electricity to retail customers at rates approved by regulatory commissions in the states where Otter Tail Power Company (OTP) provides service. OTP also earns revenue from the transmission of electricity for others over the transmission assets it owns separately, or jointly with other transmission service providers, under rate tariffs established by the independent transmission system operator and approved by the Federal Energy Regulatory Commission (FERC). A third source of revenue for OTP comes from the generation and sale of electricity to wholesale customers at contract or market rates. Revenues from all these sources meet the criteria to be classified as revenue from contracts with customers and are recognized over time as energy is delivered or transmitted. Revenue is recognizedEstimates

We use estimates based on the metered quantity of electricity deliveredbest information available in recording transactions and balances resulting from business operations. As better information becomes available, or transmitted atactual amounts are known, the applicable rates. For electricity delivered and consumed after a meter is read but prior to the end of the reporting period, OTP records revenue and an unbilled receivable based onrecorded estimates of the kilowatt-hours (kwh) of energy delivered to the customer.

ARPs provide for adjustments to rates outside of a general rate case proceeding, usually as a surcharge applied to future billings typically through the use of rate riders subject to periodic adjustments, to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. ARP riders generally provide for the recovery of specified costs and investments and include an incentive component to provide the regulated utility with a return on amounts invested.

OTP has recovered costs and earned incentives or returns on investments subject to recovery under several ARP rate riders, including:

In Minnesota: Transmission Cost Recovery (TCR), Environmental Cost Recovery (ECR), Renewable Resource Adjustment (RRA), Energy Intensive Trade Exposed and Conservation Improvement Program (CIP) riders.

In North Dakota: TCR, ECR, Renewable Resource Cost Recovery and Generation Cost Recovery (GCR) riders.

In South Dakota: TCR, ECR, Phase-In Rate Plan and Energy Efficiency Plan (conservation) riders.

8

OTP accrues ARP revenue based on costs incurred, investments made and returns on those investments that qualify for recovery through established riders. Amounts billed under riders in effect at the time of the billing are included in revenues from contracts with customers net of amounts billed that are subject to refund through future rider adjustments. Amounts accrued and subject to recovery through future rider rate updates and adjustments are reported as changes in accrued revenues under ARPs on a separate line in the revenue section of the Company’s consolidated statement of income. See table in note 3 for total revenues billed and accrued under ARP riders for the three- and nine-month periods ended September 30, 2020 and 2019.

Manufacturing Segment Revenues—Companies in the Manufacturing segment, BTD Manufacturing, Inc. (BTD) and T.O. Plastics, Inc. (T.O. Plastics), earn revenue predominantly from the production and delivery of custom-made or standardized parts to customers across several industries. BTD also earns revenue from the production and sale of tools and dies to other manufacturers. For the production and delivery of standardized products and other products made to customer specifications where the terms of the contract require transfer of the completed product, therevised. Consequently, operating company has met its performance obligation and recognizes revenue at the point in time when the product is shipped. For revenue recognized on products when shipped, the operating companies have no further obligation to provide services related to such products. The shipping terms used in these instances are FOB shipping point.

Plastics Segment Revenues—Companies in our Plastics segment earn revenue predominantly from the sale and delivery of standardized polyvinyl chloride (PVC) pipe products produced at their manufacturing facilities. Revenue from the sale of these products is recognized at the point in time when the product is shipped based on prices agreed to in a purchase order. For revenue recognized on shipped products, there is no further obligation to provide services related to such products. The shipping terms used in these instances are FOB shipping point. The Plastics segment has one customer for which it produces and stores a product made to the customer’s specifications and design under a build and hold agreement. For sales to this customer, the operating company recognizes revenue as the custom-made product is produced, adjusting the amount of revenue for volume rebate variable pricing considerations the operating company expects the customer will earn and applicable early payment discounts the company expects the customer will take. Ownership of the pipe transfers to the customer prior to delivery and the operating company is paid a negotiated fee for storage of the pipe.

See operating revenue table in note 2 for a disaggregation of the Company’s revenues by business segment for the three- and nine-month periods ended September 30, 2020 and 2019.

Agreements Subject to Legally Enforceable Netting Arrangements

OTP has certain derivative contracts that are designated as normal purchases. Individual counterparty exposures for these contractsresults can be offset accordingaffected by revisions to legally enforceable netting arrangements. The Company does not offset assetsprior accounting estimates.

2. Segment Information
We classify our business into 3 segments, Electric, Manufacturing and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet. 

Fair Value Measurements

The Company follows ASC Topic 820,Fair Value Measurements and Disclosures (ASC 820), for recurring fair value measurements. ASC 820 provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the hierarchy and examples of each level are as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange.

Level 2 – Pricing inputs are other than quoted prices in active markets but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts.

9

The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2020 and December 31, 2019:

September 30, 2020 (in thousands)

 

Level 1

  

Level 2

 

Level 3

Assets:

         

Investments:

         

Equity Funds – Held by Captive Insurance Company

 $1,665      

Corporate Debt Securities – Held by Captive Insurance Company

     $2,887  

Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company

      6,131  

Other Assets:

         

Money Market and Mutual Funds –Retirement Plans

  1,582      

Total Assets

 $3,247  $9,018  

December 31, 2019 (in thousands)

 

Level 1

  

Level 2

 

Level 3

Assets:

         

Investments:

         

Equity Funds – Held by Captive Insurance Company

 $1,586      

Corporate Debt Securities – Held by Captive Insurance Company

     $2,124  

Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company

      6,060  

Other Assets:

         

Money Market and Mutual Funds –Retirement Plans

  2,363      

Total Assets

 $3,949  $8,184  

The level 2 fair values for Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes.

Coyote Station Lignite Supply Agreement – Variable Interest Entity

In October 2012 the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of lignite coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton paid by the Coyote Station owners under the LSA reflects the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are required to buy certain assets of CCMC at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC because the Coyote Station owners are required to buy the membership interests of CCMC at the end of the contract term at equity value. No single owner of Coyote Station owns a majority interest in Coyote Station or has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE and the Company is not required to include CCMC in its consolidated financial statements.

If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and the Coyote Station owners purchase all of the outstanding membership interests of CCMC, the owners will satisfy (or if permitted by CCMC’s applicable lender assume) all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. In the event the contract is terminated prior to the end of the term due to certain events, OTP’s maximum exposure to additional costs, as a result of its involvement with CCMC, and potential impairment loss if recovery of those costs is denied by regulatory authorities, could be as high as approximately $50 million, OTP’s 35% share of CCMC’s unrecovered costs as of September 30, 2020.

10

Inventories

Inventories, valued at the lower of cost or net realizable value, consist of the following:

  

September 30,

  

December 31,

 

(in thousands)

 

2020

  

2019

 

Finished Goods

 $18,901  $31,863 

Work in Process

  14,480   16,508 

Raw Material, Fuel and Supplies

  48,490   49,480 

Total Inventories

 $81,871  $97,851 

Intangible Assets

Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360-10-35,Property, Plant, and Equipment—Overall—Subsequent Measurement.

The following table summarizes the components of the Company’s intangible assets at September 30, 2020 and December 31,2019:

September 30, 2020 (in thousands)

 

Gross Carrying

Amount

  

Accumulated

Amortization

  

Net Carrying

Amount

  

Remaining

Amortization

Periods (months)

 

Amortizable Intangible Assets:

               

Customer Relationships

 $22,491  $12,095  $10,396  79-179 

Other

  26   3   23  216 

Total

 $22,517  $12,098  $10,419    

December 31, 2019 (in thousands)

 

Gross Carrying

Amount

  

Accumulated

Amortization

  

Net Carrying

Amount

  

Remaining

Amortization

Periods (months)

 

Amortizable Intangible Assets:

               

Customer Relationships

 $22,491  $11,259  $11,232  88-188 

Other

  179   121   58  8-45 

Total

 $22,670  $11,380  $11,290    

The amortization expense for these intangible assets was:

  

Three Months Ended

  

Nine Months Ended

 
  

September 30,

  

September 30,

 

(in thousands)

 

2020

  

2019

  

2020

  

2019

 

Amortization Expense – Intangible Assets

 $284  $296  $871  $888 

The estimated annual amortization expense for these intangible assets for the next 51 months is:

(in thousands)

 

2020

  

2021

  

2022

  

2023

  

2024

 

Estimated Amortization Expense – Intangible Assets

 $275  $1,100  $1,100  $1,100  $1,100 

Supplemental Disclosures of Cash Flow Information

  

As of September 30,

 

(in thousands)

 

2020

  

2019

 

Noncash Investing Activities:

        

Transactions Related to Capital Additions not Settled in Cash

 $112,314  $15,893 

11

New Accounting Standards Adopted

ASU 2016-13—In June 2016 the FASB issued Accounting Standards Update (ASU) No.2016-13,Financial Instruments—Credit Losses (Topic 326) (ASC 326), which changes how entities account for credit losses on receivables and certain other assets effective for interim and annual periods beginning on or after December 31, 2019. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards. The Company adopted ASC 326 in the first quarter of 2020. Adoption of the new standard did not have a material impact on the Company’s consolidated financial statements, and the Company did not record a cumulative effect adjustment to retained earnings on adoption.

Accounting Policy

Trade account and unbilled receivables reflected in the Company’s consolidated balance sheets represent the net amounts expected to be collected. An allowance for credit losses is established based on expected losses. Expected losses are estimated by reviewing individual accounts, considering aging, financial condition of the debtor for certain accounts, recent payment history, current and forecasted economic conditions and other relevant factors.

Allowance for Credit Losses

Following is a summary of activity in allowances for credit losses on trade and unbilled accounts receivable across the Company:

  

Three Months Ended

  

Nine Months Ended

 
  

September 30,

  

September 30,

 

(in thousands)

 

2020

  

2019

  

2020

  

2019

 

Beginning Balance

 $2,100  $1,691  $1,339  $1,407 

Additions Charged to Expense (net of recoveries)

  474   86   1,845   549 

Reductions for Amounts Written Off

  (313)  (225)  (923)  (404)

Ending Balance

 $2,261  $1,552  $2,261  $1,552 

ASU 2018-15—In August 2018 the FASB issued ASU No.2018-15,Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40), which amends ASC 350-40, Internal-Use Software, to address a customer's accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. The amendments in ASU 2018-15 align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). Accordingly, the amendments in ASU 2018-15 require an entity (customer) in a hosting arrangement that is a service contract to follow the guidance in ASC 350-40 to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The amendments in ASU 2018-15 also require the entity to present the expense related to the capitalized implementation costs in the same line item in the statement of income as the fees associated with the hosting element (service) of the arrangement and classify payments for capitalized implementation costs in the statement of cash flows in the same manner as payments made for fees associated with the hosting element. The entity is also required to present the capitalized implementation costs in the statement of financial position in the same line item that a prepayment for the fees of the associated hosting arrangement would be presented. The amendments in ASU 2018-15 were effective for interim and annual periods beginning on or after December 15, 2019 with early adoption permitted in any interim period. The Company adopted the amendments in ASU 2018-15 in the first quarter of 2020. There was no impact to its consolidated financial statements on adoption, but the Company will begin capitalizing implementation costs incurred in cloud computing arrangements post-adoption.

12

2.Segment Information

The accounting policies of the segments are described under note 1 – Summary of Significant Accounting Policies. The Company's businesses have been classified into three segments to bePlastics, consistent with itsour business strategy, organizational structure and theour internal reporting and review processprocesses used by the Company’sour chief operating decision maker. These businesses sell productsmaker to make decisions regarding allocation of resources, to assess operating performance and provide services to customers primarily in the United States. The Company’s business structure currently includes the following 3 segments: Electric, Manufacturingmake strategic decisions.

Certain assets and Plastics. The chart below indicates the companies included in each segment.

graph.jpg

Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is a participant in the Midcontinent Independent System Operator, Inc. (MISO) markets. OTP’s operations have been the Company’s primary business since 1907.

Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping, fabrication and painting, and production of plastic thermoformed horticultural containers, life science and industrial packaging, and material handling components. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States.

Plastics consists of businesses producing PVC pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the United States, west of the Mississippi River.

OTP is a wholly owned subsidiary of the Company. All of the Company’s other businessescosts are owned by its wholly owned subsidiary, Varistar Corporation. The Company’snot allocated to our operating segments. Corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’sour captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not an operating segment. Rather,segment, rather it is added to operating segment totals to reconcile to totalsconsolidated amounts.

Information for each segment and our unallocated corporate costs for the three and nine months ended September 30, 2021 and 2020 are as follows:
Three Months Ended September 30,Nine Months Ended September 30,
(in thousands)2021202020212020
Operating Revenue1
Electric$118,775 $115,213 $348,629 $333,213 
Manufacturing89,977 59,849 250,085 174,276 
Plastics107,542 60,693 264,898 155,769 
Total$316,294 $235,755 $863,612 $663,258 
Net Income (Loss)
Electric$22,528 $24,737 $55,547 $54,225 
Manufacturing4,200 3,311 15,290 8,476 
Plastics28,410 10,343 60,102 20,922 
Corporate(2,384)(2,457)(5,787)(6,440)
Total$52,754 $35,934 $125,152 $77,183 
1Amounts reflect operating revenues to external customers. Intersegment operating revenues are not material for any period presented.
9

The following provides the identifiable assets by segment and corporate assets as of September 30, 2021 and December 31, 2020:
(in thousands)September 30,
2021
December 31,
2020
Identifiable Assets
Electric$2,271,636 $2,233,399 
Manufacturing242,414 191,005 
Plastics143,615 99,767 
Corporate55,483 54,183 
Total$2,713,148 $2,578,354 
3. Revenue
We present our operating revenues to external customers, in total and by amounts arising from contracts with customers and alternative revenue program (ARP) arrangements, disaggregated by revenue source and segment for the three and nine months ended September 30, 2021 and 2020:
Three Months Ended September 30,Nine Months Ended September 30,
(in thousands)2021202020212020
Operating Revenues
Electric Segment
Retail: Residential$33,902 $32,734 $100,067 $96,440 
Retail: Commercial and Industrial60,557 64,918 185,376 189,771 
Retail: Other1,979 1,953 5,687 5,550 
  Total Retail96,438 99,605 291,130 291,761 
Transmission13,300 12,288 37,085 32,802 
Wholesale6,944 1,500 14,711 3,141 
Other2,093 1,820 5,703 5,509 
Total Electric Segment118,775 115,213 348,629 333,213 
Manufacturing Segment
Metal Parts and Tooling76,455 50,957 210,141 145,435 
Plastic Products and Tooling10,198 7,600 30,624 25,323 
Scrap Metal Sales3,324 1,292 9,320 3,518 
Total Manufacturing Segment89,977 59,849 250,085 174,276 
Plastics Segment
PVC Pipe107,542 60,693 264,898 155,769 
Total Operating Revenue316,294 235,755 863,612 663,258 
Less: Non-contract Revenues Included Above
Electric Segment - ARP Revenues(33)2,778 (2,790)2,900 
Total Operating Revenues from Contracts with Customers$316,327 $232,977 $866,402 $660,358 
4. Select Balance Sheet Information
Receivables and Allowance for Credit Losses
Receivables as of September 30, 2021 and December 31, 2020 are as follows:
(in thousands)September 30,
2021
December 31,
2020
Receivables
Trade$152,906 $87,048 
Other11,182 8,939 
Unbilled Receivables17,003 21,187 
Total Receivables181,091 117,174 
Less: Allowance for Credit Losses2,332 3,215 
Receivables, net of allowance for credit losses$178,759 $113,959 
10

The following is a summary of activity in the allowance for credit losses for the nine months ended September 30, 2021 and 2020:
(in thousands)20212020
Beginning Balance, January 1$3,215 $1,339 
Additions Charged to Expense177 1,845 
Reductions for Amounts Written Off, Net of Recoveries(1,060)(923)
Ending Balance, September 30$2,332 $2,261 
Inventories
Inventories consist of the following as of September 30, 2021 and December 31, 2020:
(in thousands)September 30,
2021
December 31,
2020
Finished Goods$25,727 $22,046 
Work in Process29,932 16,210 
Raw Material, Fuel and Supplies58,956 53,909 
Total Inventories$114,615 $92,165 
Investments
The following is a summary of our investments as of September 30, 2021 and December 31, 2020:
(in thousands)September 30,
2021
December 31,
2020
Corporate-Owned Life Insurance Policies$40,096 $36,825 
Debt Securities9,208 9,260 
Money Market Funds953 4,075 
Mutual Funds5,170 1,662 
Other Investments29 34 
Total Investments$55,456 $51,856 
The amount of unrealized gains and losses on debt securities as of September 30, 2021 and December 31, 2020 are not material and no unrealized losses were deemed to be other-than-temporary. In addition, the amount of unrealized gains and losses on marketable equity securities still held as of September 30, 2021 and December 31, 2020 are not material.
Property, Plant and Equipment
Major classes of property, plant and equipment as of September 30, 2021 and December 31, 2020 include:
(in thousands)September 30,
2021
December 31,
2020
Electric Plant in Service  
Electric Plant in Service$2,705,778 $2,531,352 
Construction Work in Progress100,495 203,078 
Total Gross Electric Plant2,806,273 2,734,430 
Less Accumulated Depreciation and Amortization822,441 778,988 
Net Electric Plant1,983,832 1,955,442 
Nonelectric Property, Plant and Equipment
Nonelectric Property, Plant and Equipment in Service263,880 258,730 
Construction Work in Progress15,564 9,290 
Total Gross Nonelectric Property, Plant and Equipment279,444 268,020 
Less Accumulated Depreciation and Amortization180,053 174,189 
Net Nonelectric Property, Plant and Equipment99,391 93,831 
Net Property, Plant and Equipment$2,083,223 $2,049,273 
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5. Regulatory Matters
Regulatory Assets and Liabilities
The following presents our current and long-term regulatory assets and liabilities as of September 30, 2021 and December 31, 2020 and the period we expect to recover or refund such amounts:
Period ofSeptember 30, 2021December 31, 2020
(in thousands)Recovery/RefundCurrentLong-TermCurrentLong Term
Regulatory Assets
Pension and Other Postretirement Benefit Plans1
Various$11,037 $139,467 $11,037 $146,071 
Alternative Revenue Program Riders2
Up to 3 years7,229 8,225 8,871 9,373 
Asset Retirement Obligations1
Asset lives— 7,065 — 8,462 
ISO Cost Recovery Trackers1
Up to 2 years270 1,027 1,079 867 
Unrecovered Project Costs1
Up to 3 years3,227 1,456 361 2,989 
Deferred Rate Case Expenses1
Various637 936 360 230 
Debt Reacquisition Premiums1
Up to 12 years117 262 192 341 
Other1
Various 77 — 62 
Total Regulatory Assets$22,517 $158,515 $21,900 $168,395 
Regulatory Liabilities
Deferred Income TaxesAsset lives$ $130,555 $— $134,719 
Plant Removal ObligationsAsset lives5,893 96,734 — 98,707 
Fuel Clause AdjustmentsUp to 1 year5,692  10,947 — 
Alternative Revenue Program RidersVarious5,265 2,507 3,581 470 
Pension and Other Postretirement Benefit PlansUp to 1 year1,959  1,959 — 
Derivative InstrumentsVarious6,136 787 — — 
OtherVarious378 150 176 77 
Total Regulatory Liabilities$25,323 $230,733 $16,663 $233,973 
1Costs subject to recovery without a rate of return.
2Amount eligible for recovery includes an incentive or rate of return.
6. Short-Term and Long-Term Borrowings
The following is a summary of our outstanding short and long-term borrowings by borrower, Otter Tail Corporation (OTC) or Otter Tail Power Company (OTP), as of September 30, 2021 and December 31, 2020:
Short-Term Debt
The following is a summary of our lines of credit as of September 30, 2021 and December 31, 2020:
September 30, 2021December 31,
2020
(in thousands)Line LimitAmount OutstandingLetters
of Credit
Amount AvailableAmount Available
OTC Credit Agreement$170,000 $36,624 $— $133,376 $104,834 
OTP Credit Agreement170,000 61,233 13,159 95,608 140,068 
Total$340,000 $97,857 $13,159 $228,984 $244,902 
On September 30, 2021, OTC entered into a Fourth Amended and Restated Credit Agreement (the OTC Credit Agreement) and OTP entered into a Third Amended and Restated Credit Agreement (the OTP Credit Agreement) amending and restating the previously existing credit agreements to extend the maturity date of each agreement to September 30, 2026. The agreements both provide for $170 million revolving lines of credit to support operations, and borrowings which may be used for working capital needs and other capital requirements, to refinance certain indebtedness and for the issuance of letters of credit in an aggregate not to exceed $40 million for the OTC Credit Agreement and $50 million for the OTP Credit Agreement. Each credit facility includes an accordion provision allowing the borrower to increase the available borrowing capacity, subject to certain terms and conditions. The borrowing capacity of the OTC Credit Agreement can be increased to $290 million and the OTP Credit Agreement can be increased to $250 million. Borrowings under each credit facility are subject to a variable rate of interest on outstanding balances and a commitment fee is applied based on the Company’s consolidatedaverage unused amount available to be drawn under the respective facility. The variable rate of interest to be charged is based on either LIBOR or a Base Rate, as defined in the agreement, selected by the borrower at the time of an advance, subject to the conditions of each agreement, plus an applicable credit spread. The credit spread ranges from 0.125% to 2.00% for the OTC Credit Agreement and from zero to 1.75% for the OTP Credit Agreement, depending on the benchmark interest rate selected and is subject to adjustment
12

based on the credit ratings of the borrower. As of September 30, 2021, the weighted-average LIBOR Rate based interest rate was 1.59% and 1.33% under the OTC Credit Agreement and OTP Credit Agreement, respectively.
Each credit facility contains a number of restrictions on the borrower, including restrictions on their ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party and engage in transactions with related parties. The agreements also contain certain financial statements.

While 0 single customer accountedand non-financial covenants and defined events of default, and include provisions for over 10%the replacement of consolidatedthe LIBOR benchmark rate in the event that LIBOR is no longer available.

Long-Term Debt
The following is a summary of outstanding long-term debt by borrower as of September 30, 2021 and December 31, 2020: 
(in thousands)
EntityDebt InstrumentRateMaturitySeptember 30,
2021
December 31,
2020
OTCGuaranteed Senior Notes3.55%12/15/26$80,000 $80,000 
OTPSeries 2011A Senior Unsecured Notes4.63%12/01/21140,000 140,000 
OTPSeries 2007B Senior Unsecured Notes6.15%08/20/2230,000 30,000 
OTPSeries 2007C Senior Unsecured Notes6.37%08/02/2742,000 42,000 
OTPSeries 2013A Senior Unsecured Notes4.68%02/27/2960,000 60,000 
OTPSeries 2019A Senior Unsecured Notes3.07%10/10/2910,000 10,000 
OTPSeries 2020A Senior Unsecured Notes3.22%02/25/3010,000 10,000 
OTPSeries 2020B Senior Unsecured Notes3.22%08/20/3040,000 40,000 
OTPSeries 2007D Senior Unsecured Notes6.47%08/20/3750,000 50,000 
OTPSeries 2019B Senior Unsecured Notes3.52%10/10/3926,000 26,000 
OTPSeries 2020C Senior Unsecured Notes3.62%02/25/4010,000 10,000 
OTPSeries 2013B Senior Unsecured Notes5.47%02/27/4490,000 90,000 
OTPSeries 2018A Senior Unsecured Notes4.07%02/07/48100,000 100,000 
OTPSeries 2019C Senior Unsecured Notes3.82%10/10/4964,000 64,000 
OTPSeries 2020D Senior Unsecured Notes3.92%02/25/5015,000 15,000 
OTCPACE Note2.54%03/18/21 169 
Total$767,000 $767,169 
Less:Current Maturities Net of Unamortized Debt Issuance Costs169,962 140,087 
Unamortized Long-Term Debt Issuance Costs2,419 2,650 
Total Long-Term Debt Net of Unamortized Debt Issuance Costs$594,619 $624,432 
On June 10, 2021, OTP entered into a Note Purchase Agreement pursuant to which OTP agreed to issue, in a private placement transaction, $230 million aggregate principal amount of senior unsecured notes consisting of (a) $40 million of 2.74% Series 2021A Senior Unsecured Notes due November 29, 2031, (b) $100 million of 3.69% Series 2021B Senior Unsecured Notes due November 29, 2051 and (c) $90 million of 3.77% Series 2022A Senior Unsecured Notes due May 20, 2052. As of September 30, 2021, there were no amounts outstanding. The funding of the notes will occur in 2 issuances, $140 million in November 2021 and $90 million in May 2022. The issuance of the notes is subject to the satisfaction of certain customary conditions to closing.
Financial Covenants
Certain of OTC's and OTP's short-term and long-term debt agreements require the borrower, whether OTC or OTP, to maintain certain financial covenants, including a maximum debt to total capitalization ratio of 0.60 to 1.00, a minimum interest and dividend coverage ratio of 1.50 to 1.00, and a maximum level of priority indebtedness. As of September 30, 2021, OTC and OTP were in compliance with these financial covenants.
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7. Pension Plan and Other Postretirement Benefits
Pension Plan
Components of net periodic pension benefit cost for the three and nine months ended September 30, 2021 and 2020 are as follows:
Three Months Ended September 30,Nine Months Ended September 30,
(in thousands)2021202020212020
Service Cost–Benefit Earned During the Period$1,866 $1,655 $5,597 $4,966 
Interest Cost on Projected Benefit Obligation2,915 3,264 8,745 9,790 
Expected Return on Assets(5,590)(5,506)(16,769)(16,516)
Amortization of Net Actuarial Loss:
From Regulatory Asset2,660 2,231 7,981 6,693 
From Other Comprehensive Income68 55 204 165 
Net Periodic Pension Cost$1,919 $1,699 $5,758 $5,098 
Wehad no minimum funding requirement as of December 31, 2020 but made a discretionary plan contribution of $10.0 million in January 2021.
Executive Survivor and Supplemental Retirement Plan (ESSRP)
Components of net periodic pension benefit cost for the three and nine months ended September 30, 2021 and 2020 are as follows:
Three Months Ended September 30,Nine Months Ended September 30,
(in thousands)2021202020212020
Service Cost–Benefit Earned During the Period$47 $45 $140 $134 
Interest Cost on Projected Benefit Obligation307 362 921 1,086 
Amortization of Net Actuarial Loss:
From Regulatory Asset30 24 92 71 
From Other Comprehensive Income124 85 373 256 
Net Periodic Pension Cost$508 $516 $1,526 $1,547 
Other Postretirement Benefits
Components of net periodic postretirement benefit cost for the three and nine months ended September 30, 2021 and 2020 are as follows: 
Three Months Ended September 30,Nine Months Ended September 30,
(in thousands)2021202020212020
Service Cost–Benefit Earned During the Period$430 $461 $1,291 $1,385 
Interest Cost on Projected Benefit Obligation472 598 1,418 1,795 
Amortization of Prior Service Cost
From Regulatory Asset(1,397)(1,169)(4,192)(3,508)
From Other Comprehensive Income(35)(28)(107)(86)
Amortization of Net Actuarial Loss
From Regulatory Asset919 1,051 2,759 3,154 
From Other Comprehensive Income24 26 71 78 
Net Periodic Postretirement Benefit Cost$413 $939 $1,240 $2,818 
14

8. Income Taxes
The reconciliation of the statutory federal income tax rate to our effective tax rate for each of the three and nine months ended September 30, 2021 and 2020 is as follows:
Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020
Federal Statutory Rate21.0 %21.0 %21.0 %21.0 %
Increases (Decreases) in Tax from:
State Taxes on Income, Net of Federal Tax5.0 5.0 5.0 5.0 
Production Tax Credits (PTCs)(5.0)— (6.0)— 
Amortization of Excess Deferred Income Taxes(1.6)(2.9)(2.0)(3.4)
North Dakota Wind Tax Credit Amortization, Net of Federal Tax(0.2)(0.6)(0.3)(0.8)
Excess Tax Deduction on Stock Awards 0.3  (0.4)
Allowance for Equity Funds Used During Construction(0.1)(0.7)(0.1)(0.8)
Other, Net(0.8)(1.9)(0.7)(1.2)
Effective Tax Rate18.3 %20.2 %16.9 %19.4 %
We began generating PTCs from our Merricourt wind farm placed in service in the fourth quarter of 2020. No PTCs were generated during the nine months ended September 30, 2020. Income tax benefits arising from PTCs are offset by corresponding operating revenue in 2019, certain customers providedreductions.
9. Commitments and Contingencies
Commitments
Construction and Other Purchase Commitments. OTP has commitments under contracts, including its share of construction program and other commitments associated with its jointly-owned facilities, extending into 2046.
Electric Utility Capacity and Energy Requirements and Coal Purchase and Delivery Contracts. OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2044. OTP also has contracts providing for the purchase and delivery of a significant portion of each business segment’s 2019 revenue. The Electric segment has 1 customer that provided 11.9% of 2019 segment revenues. The Manufacturing segment has 1 customer that manufactures and sells recreational vehicles that provided 23.8% of 2019 segment revenues and 1 customer that manufactures and sells lawn and garden equipment that provided 11.1% of 2019 segment revenues. The Manufacturing segment’s top 5 revenue-generating customers provided over 54% of 2019 segment revenues. The Plastics segment has 2 customers that individually provided 25.3% and 20.4% of 2019 segment revenues. The loss of any one of these customers would have a significant negative impact onits current coal requirements, with expiration dates ranging from 2022 through 2040. Certain contracts do not include minimum purchase requirements but do require all coal necessary for the financial position and results of operationsoperation of the respective business segment andplant to be purchased from the Company.

All of the Company’s long-lived assets are within the United States and sales within the United States accounted for 98.9% and 98.5% of operating revenues for the respective three-month periods ended September 30, 2020 and 2019, and 99.0% and 98.7% of operating revenues for the respective nine-month periods ended September 30, 2020 and 2019.

counterparty.
13

The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three- and nine-month periods ended September 30, 2019 and 2020 and total assets by business segment as of September 30, 2020 and December 31,2019 are presented in the following tables:

Operating RevenueLand Easements.

  

Three Months Ended

  

Nine Months Ended

 
  

September 30,

  

September 30,

 

(in thousands)

 

2020

  

2019

  

2020

  

2019

 

Electric Segment:

                

Retail Sales Revenue from Contracts with Customers

 $96,827  $100,345  $288,861  $303,276 

Changes in Accrued ARP Revenues

  2,778   (921)  2,900   (1,601)

Total Retail Sales Revenue

  99,605   99,424   291,761   301,675 

Transmission Services Revenue

  12,288   11,692   32,802   34,023 

Wholesale Revenues – Company Generation

  1,500   1,631   3,141   4,099 

Other Revenues

  1,830   1,626   5,548   4,929 

Total Electric Segment Revenues

  115,223   114,373   333,252   344,726 

Manufacturing Segment:

                

Metal Parts and Tooling

  50,957   56,255   145,435   185,520 

Plastic Products and Tooling

  7,600   8,088   25,323   26,486 

Other

  1,292   1,379   3,518   5,034 

Total Manufacturing Segment Revenues

  59,849   65,722   174,276   217,040 

Plastics Segment – Sale of PVC Pipe Products

  60,693   48,566   155,769   142,100 

Intersegment Eliminations

  (10)  (9)  (39)  (39)

Total

 $235,755  $228,652  $663,258  $703,827 

Interest Charges

  

Three Months Ended

  

Nine Months Ended

 
  

September 30,

  

September 30,

 

(in thousands)

 

2020

  

2019

  

2020

  

2019

 

Electric

 $7,334  $6,300  $22,066  $19,566 

Manufacturing

  553   561   1,661   1,791 

Plastics

  163   197   497   561 

Corporate and Intersegment Eliminations

  518   481   1,129   1,272 

Total

 $8,568  $7,539  $25,353  $23,190 

Income Taxes

  

Three Months Ended

  

Nine Months Ended

 
  

September 30,

  

September 30,

 

(in thousands)

 

2020

  

2019

  

2020

  

2019

 

Electric

 $6,048  $4,066  $12,247  $9,874 

Manufacturing

  891   285   2,163   2,888 

Plastics

  3,638   1,914   7,373   5,287 

Corporate

  (1,480)  (1,329)  (3,240)  (4,142)

Total

 $9,097  $4,936  $18,543  $13,907 

Net Income (Loss)

  

Three Months Ended

  

Nine Months Ended

 
  

September 30,

  

September 30,

 

(in thousands)

 

2020

  

2019

  

2020

  

2019

 

Electric

 $24,737  $17,682  $54,225  $43,884 

Manufacturing

  3,311   3,155   8,476   11,987 

Plastics

  10,343   5,397   20,922   14,918 

Corporate

  (2,457)  (1,489)  (6,440)  (4,294)

Total

 $35,934  $24,745  $77,183  $66,495 

14

Identifiable Assets

  

September 30,

  

December 31,

 

(in thousands)

 

2020

  

2019

 

Electric

 $2,191,215  $1,931,525 

Manufacturing

  189,525   195,742 

Plastics

  104,661   92,049 

Corporate

  49,106   54,279 

Total

 $2,534,507  $2,273,595 

3. Rate and Regulatory Matters

Below are descriptions of OTP’s major capital expenditure projects that are expected to have a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the FERC, impacting OTP’s revenues in 2020 and 2019.

Major Capital Expenditure Projects

Merricourt Wind Energy Center (Merricourt)—On November 16, 2016 OTP entered into an Asset Purchase Agreement (the Purchase Agreement) with EDF Renewable Development, Inc. and certain of its affiliated companies (collectively, EDF) to purchase the development assets and assume certain specified liabilities associated with Merricourt, a 150-megawatt (MW) wind farm in southeastern North Dakota, for a purchase price of approximately $34.7 million, subject to adjustments for interconnection costs. Also on November 16, 2016, OTP entered into a Turnkey Engineering, Procurement and Construction Services Agreement (the TEPC Agreement) with EDF-RE US Development, LLC (EDF-USD) pursuant to which EDF-USD will develop, design, procure, construct, interconnect, test and commission the wind farm with a targeted completion date in 2020 for consideration of approximately $200.5 million, subject to certain adjustments, payable following the closing of the Purchase Agreement in installments in connection with certain project construction milestones. In connection with action by the FERC, OTP and EDF-US agreed, in the First Amendment to the Purchase Agreement and the TEPC Agreement dated June 11,2019, to change the purchase price to $37.7 million andhas commitments to make a related reallocation of responsibility for interconnection costs and liabilities. On July 16, 2019 OTP closed on the purchase of substantially all of the development assets and assumed certain specified liabilities from EDF related to Merricourt pursuant to the Purchase Agreement, as amended, for a purchase price of approximately $37.7 million, subject to certain adjustments, and issued the notice to EDF-USD to begin construction in August 2019. The agreements contain customary representations, warranties, covenants and indemnities for this type of transaction. The Merricourt generator interconnection agreement with MISO was approved by the future payments under land easements extending into 2050.

Contingencies
FERC in April 2019.

OTP is earning a return in all three states served by OTP on amounts invested in Merricourt while the project is under construction. Returns are recovered in Minnesota and North Dakota through RRA riders and in South Dakota through the Phase-In Rate Plan Rider. As of September 30, 2020, OTP had capitalized approximately $231.1 million in project costs and allowance for funds used during construction (AFUDC) associated with Merricourt. While work on the project continues and commissioning of the wind turbines is in process, OTP has received Notices of Force Majeure from EDF-USD claiming rights to an extension of guaranteed project completion dates and adjustments to the consideration agreed upon in the TEPC Agreement due to COVID-19 impacts. While details regarding these claims and the related impacts to the project remain uncertain, OTP currently anticipates Merricourt will be in commercial operation by the end of December 2020.

ROE.Astoria Station—OTP is constructing this 245 MW simple-cycle natural gas-fired combustion turbine generation facility near Astoria, South Dakota as part of its plan to reliably meet customers’ electric needs, replace expiring capacity purchase agreements and prepare for the planned retirement of its Hoot Lake Plant in 2021. A final order granting an Advanced Determination of Prudence for Astoria Station was issued by the NDPSC on November 3, 2017, subject to certain qualifications and compliance obligations. On August 3, 2018 the SDPUC issued an order granting a site permit for Astoria Station. In a September 26, 2018 hearing the NDPSC established a GCR Rider for future recovery of costs incurred for Astoria Station. On March 6, 2019 the SDPUC issued an order approving a settlement that allows a phase-in rider which includes recovery of Astoria Station costs. The interconnection agreement for Astoria Station was executed by MISO in December 2018 and accepted by the FERC in January 2019. Site preparation and excavation began in May 2019, and construction is occurring on the site. As of September 30, 2020, OTP had capitalized approximately $131.6 million in project costs and AFUDC associated with Astoria Station. OTP currently expects this project to begin commercial operation in the first quarter of 2021.

15

General Rates

Minnesota—The MPUC rendered its final decision in OTP’s 2016 general rate case in March 2017 and issued its written order on May 1, 2017. Pursuant to the order, OTP’s allowed rate of return on rate base is 7.5056% and its allowed rate of return on equity (ROE) is 9.41%.

The MPUC’s order also included: (1) the determination that all costs (including FERC allocated costs and revenues) of the Big Stone South–Brookings and Big Stone South–Ellendale Multi-Value Projects (MVPs) will be included in the Minnesota TCR Rider and jurisdictionally allocated to OTP’s Minnesota customers (see discussion under Minnesota Transmission Cost Recovery Rider below), and (2) approval of OTP’s proposal to transition rate base, expenses and revenues from ECR and TCR Riders to base rate recovery, which occurred when final rates were implemented on November 1, 2017. Certain MISO expenses and revenues remain in the TCR Rider to allow for the ongoing refund or recovery of these variable revenues and costs.

On November 2, 2020 OTP filed a request with the MPUC for an increase in revenue recoverable under general rates in Minnesota. In its filing, OTP requested a net increase in annual revenue of approximately $14.5 million, or 6.77%, based on an allowed rate of return on rate base of 7.59% and an allowed rate of return on equity of 10.20% on an equity ratio of 52.5% of total capital. Through this rate case proceeding, OTP is proposing to recover, at the start of interim rates, revenue currently subject to recovery under Minnesota RRA and TCR riders. OTP is also proposing to move the cost of energy from base rates to full recovery under the Energy Adjustment Rider per a prior MPUC order. OTP is also proposing to move recovery of all CIP expenditures out of base rates to the CIP Rider with the implementation of final rates. An interim rate increase is expected to go into effect in January 2021.

North Dakota—On March 23, 2018 OTP made a supplemental filing to its initial request for a rate review, reducing its request for an annual revenue increase from $13.1 million to $7.1 million, a 4.8% annual increase. The $6.0 million decrease included $4.8 million related to tax reform and $1.2 million related to other updates.

In a September 26, 2018 hearing the NDPSC approved an overall annual revenue increase of $4.6 million (3.1%) and a ROE of 9.77% on a 52.5% equity capital structure. The NDPSC’s approval established a GCR Rider for future recovery of costs incurred for Astoria Station. The net revenue increase reflected a reduction in income tax recovery requirements related to the 2017 Tax Cuts and Jobs Act (TCJA) and decreases in rider revenue recovery requirements. Final rates were effective February 1,2019, with refunds of excess revenues collected under interim rates applied to customers’ April 2019 bills, including $0.8 million for amounts collected reflecting the higher tax rates under interim rates in effect in January and February 2018.

South Dakota—On April 20, 2018 OTP filed a request with the SDPUC to increase non-fuel rates in South Dakota by approximately $3.3 million annually, or 10.1%, as the first step in a two-step request. Interim rates were effective October 18,2018. The second step in the request was an additional 1.7% revenue increase to recover costs for Merricourt when the wind generation facility goes into service. The SDPUC approved a partial settlement on March 1, 2019 on all issues of the rate case except ROE. The partial settlement included approval of a phase-in plan to provide for a return on amounts invested in Astoria Station and Merricourt, which addressed the second step of the request for increased rates in South Dakota. The partial settlement also included a moratorium on filing another general rate case in South Dakota until the new generation projects have been in service for a year. The partial settlement also allowed OTP to retain the impact of lower tax rates related to the TCJA from January 1, 2018 through October 17,2018 resulting in the reversal of an accrued refund liability and recognition of $1.0 million in revenue in the first quarter of 2019. The SDPUC approved the ROE portion of the rate case on May 14, 2019 and pursuant to the SDPUC’s May 30, 2019 order, OTP’s allowed ROE was set at 8.75%, resulting in an annual revenue increase of approximately $2.2 million. Final rates went into effect August 1, 2019. An interim rate refund for the lower ROE going back to October 18, 2018 was applied to South Dakota customers’ October 2019 bills.

On July 9, 2019 the SDPUC approved a stipulation agreement entered into by OTP with SDPUC staff. The revenue requirement stated in the SDPUC’s final order dated May 30, 2019 understated the amount of OTP's South Dakota share of electric transmission plant in service, resulting in an annual revenue requirement shortfall of approximately $341,000. To address the shortfall, the parties agreed that OTP would file an update to its South Dakota TCR Rider. OTP was authorized full recovery of the transmission rate base correction reflected in the TCR Rider tracker beginning as of the first date of interim rates, October 18, 2018, with the TCR Rider rate update going into effect on October 1, 2019.

To ensure rates are appropriately set under the stipulation, the parties agreed to establish an earnings sharing mechanism to share with customers any weather-normalized earnings above the authorized ROE of 8.75%. OTP's annual weather-normalized earnings are reported each year by June 1 in its jurisdictional annual report, which will be used to determine the earnings level for purposes of calculating any refund. The earnings sharing mechanism requires that OTP will refund to customers 50% of

16

any weather-normalized revenue that corresponds to the earnings in excess of its authorized ROE, up to a maximum of 9.50% ROE for a particular year. OTP will refund 100% of any earnings above 9.50% each year. In the event a refund is due under this provision, OTP will notify the SDPUC of the refund amount and plan for crediting customers within 30 days of filing its South Dakota jurisdictional annual report.

Rate Riders

In addition to general rates, OTP has several rate riders in place in each of its state jurisdictional service areas. These rate riders are designed to recover expenses, costs and returns on rate base investments not currently being recovered in base, or general, rates. In addition to fuel cost recovery riders in each state, OTP has recovered costs and earned incentives or returns on investments subject to recovery under several rate riders, including:

In Minnesota: Transmission Cost Recovery (TCR), Environmental Cost Recovery (ECR), Renewable Resource Adjustment (RRA), Energy Intensive Trade Exposed and Conservation Improvement Program riders.

In North Dakota: TCR, ECR, Renewable Resource Cost Recovery and Generation Cost Recovery (GCR) riders.

In South Dakota: TCR, ECR, Phase-In Rate Plan and Energy Efficiency Plan (conservation) riders.

Following is a brief summary of recent proceedings of riders in place in each state served by OTP, followed by tables showing revenues recorded under rate riders for the three- and nine-month periods ended September 30, 2020 and September 30, 2019 and a listing of rate rider updates impacting revenues in 2020 and 2019. Additional information and background on these rate riders is provided in the Company’s Annual Report on Form 10-K for the year ended December 31, 2019.

Minnesota

Minnesota Conservation Improvement Programs (MNCIP)—On May 1, 2020 OTP filed a request for approval of its 2019 energy savings, recovery of $2.7 million in accrued financial incentives and recovery of 2019 program costs not included in base rates. OTP’s request was approved by order of the MPUC on August 18, 2020.

Transmission Cost Recovery Rider—In OTP’s 2016 general rate case order issued on May 1, 2017, the MPUC ordered OTP to include, in the TCR Rider retail rate base, Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVPs and all revenues received from other utilities under MISO’s tariffed rates as a credit in its TCR revenue requirement calculations. In doing so, the MPUC’s order diverted interstate wholesale revenues that have been approved by the FERC to offset FERC-approved expenses, effectively reducing OTP’s recovery of those FERC-approved expense levels. The MPUC-ordered treatment resulted in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC’s revenue requirements and authorized returns vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision can vary over time and be dependent on the differences between the revenue requirements and returns in the two jurisdictions at any given time. On August 18, 2017 OTP filed an appeal of the MPUC general rate case order with the Minnesota Court of Appeals to contest the portion of the order requiring OTP to jurisdictionally allocate costs of the FERC MVP transmission projects in the TCR Rider.

On June 11, 2018 the Minnesota Court of Appeals reversed the MPUC’s order related to the inclusion of Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVPs and all revenues received from other utilities under MISO’s tariffed rates as a credit in OTP’s Minnesota TCR revenue requirement calculations. On July 11, 2018 the MPUC filed a petition for review of the MVP decision to the Minnesota Supreme Court, which granted review of the Minnesota Court of Appeals decision. The Minnesota Supreme Court issued its opinion on April 22,2020, concluding the MPUC lacked authority to amend an existing transmission cost-recovery rider approved under Minnesota state law to include the costs and revenues associated with the Big Stone South–Brookings and Big Stone South–Ellendale MVPs and affirming the decision of the Minnesota Court of Appeals.

On October 22, 2020 the MPUC approved OTP’s request for a Minnesota TCR Rider update with exclusion of the Big Stone South–Brookings and Big Stone South–Ellendale projects and inclusion of three projects previously requested in the Minnesota TCR Rider eligibility petition. Updated rates go into effect in January 2021. With the decision, one-half of OTP’s Minnesota TCR December 2020 projected tracker balance of $13.4 million will be included in the 2021 TCR annual revenue requirement with the remainder included in the next annual update. The annual updates provide for recovery of approximately $2.6 million in excess MISO revenues credited to Minnesota customers through the TCR Rider prior to September 30, 2020. As a result, OTP recognized additional rider revenue of $2.6 million in the three-month period ended September 30, 2020.

17

Renewable Resource Adjustment—On June 21, 2019 OTP filed its annual update to the Minnesota RRA requesting approval for recovery of the difference in PTCs in base rates and the actual PTCs generated, as well as recovery of Merricourt. On December 19, 2019 the MPUC approved a revised request which included changes related to Merricourt capitalized costs.

Fuel and Purchased Power Costs Recovery—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 cost recovery. 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 October 31, 2019 the MPUC approved the forecasted monthly fuel cost rates submitted by OTP for 2020 and the rates became effective on January 1, 2020. This mechanism could result in reductions in Electric segment operating income margins, increase variability in consolidated net income in future periods if costs per kwh vary from forecasted costs per kwh, and cause an increase in working capital and short-term borrowings in the event recovery of all or a portion of excess costs is delayed or denied by the MPUC.

North Dakota

Renewable Resource Adjustment—On December 31, 2019 OTP filed its annual update to the North Dakota RRA requesting approval for recovery of the difference in PTCs in base rates and the actual PTCs generated, as well as a return on Merricourt costs incurred while under construction. This update also included a credit for the remaining unrefunded credit balance in the North Dakota ECR Rider tracker on November 30, 2019. On February 25, 2020 OTP filed a revised request which was approved by the NDPSC on March 18, 2020. Part of the NDPSC’s approval included adopting a levelized utilization of PTCs from the Merricourt project over the expected 25-year life of the project for rate-making purposes. PTCs on prior projects were passed back to customers through lower rates as they were generated over 10 years.

Generation Cost Recovery Rider—On May 15, 2019 the NDPSC approved OTP’s request to establish an initial GCR Rider rate for recovery of OTP’s North Dakota jurisdictional share of the revenue requirements on its investment in Astoria Station, effective on bills rendered after July 1, 2019. On June 10, 2020 the NDPSC approved the 2020 annual update request with an effective date of July 1, 2020.

South Dakota

Phase-In Rate Plan Rider—On May 31, 2019 OTP petitioned the SDPUC for approval of its initial rate for the Phase-In Rate Plan Rider as described in OTP’s most recent South Dakota general rate case settlement stipulation and was approved by the SDPUC’s order in that rate case. The petition was OTP’s initial filing for the rider to recover OTP’s South Dakota share of actual and forecasted costs for Astoria Station and Merricourt, and to refund forecasted net benefits associated with additional load growth in the Lake Norden area. On August 6, 2020 the SDPUC approved OTP’s request for an updated Phase-In Rider Factor effective September 1, 2020.

Revenues Recorded under Rate Riders

The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota, and South Dakota.

  

Three Months Ended September 30,

  

Nine Months Ended September 30,

 

Rate Rider (in thousands)

 

2020

  

2019

  

2020

  

2019

 

Minnesota

                

Renewable Resource Recovery

 $3,318  $1,316  $9,660  $3,949 

Conservation Improvement Program Costs and Incentives

  2,096   1,518   4,703   4,246 

Transmission Cost Recovery

  2,001   (284)  2,402   301 

Environmental Cost Recovery

  0   0   0   (1)

North Dakota

                
Renewable Resource Adjustment  1,256   (20)  3,455   616 

Transmission Cost Recovery

  809   908   3,131   3,554 

Generation Cost Recovery

  1,187   137   3,035   607 

Environmental Cost Recovery

  0   (7)  0   556 

South Dakota

                

Transmission Cost Recovery

  450   743   1,383   1,587 

Conservation Improvement Program Costs and Incentives

  194   100   748   440 

Environmental Cost Recovery

  0   (2)  0   (29)

Phase-In Rate Plan

  (53)  (10)  (77)  (10)

Total

 $11,258  $4,399  $28,440  $15,816 

18

Rate Rider Updates

The following table provides summary information on the status of updates since January 1, 2018 for the rate riders described above:

Rate Rider

 

R - Request Date

A - Approval Date

Effective Date

Requested or

Approved

 

Annual

Revenue

($000s)

 

Rate

Minnesota

          

Conservation Improvement Program

          

2019 Incentive and Cost Recovery

 A –

August 18, 2020

October 1, 2020

 $8,247 $0.00485

/kwh

2018 Incentive and Cost Recovery

 A –

December 27, 2019

January 1, 2020

 $11,926 $0.00710

/kwh

2017 Incentive and Cost Recovery

 A –

October 4, 2018

November 1, 2018

 $10,283 $0.00600

/kwh

Transmission Cost Recovery

          

2018 Annual Update–Updated Request

 A –

October 22, 2020

January 1, 2021

 $10,260 

Various

2017 Rate Reset

 A –

October 30, 2017

November 1, 2017

 $(3,311)

Various

Environmental Cost Recovery

          

2018 Annual Update

 A –

November 29, 2018

December 1, 2018

 $0 0%

of base

Renewable Resource Adjustment

          

2019 Annual Update – Revised

 A –

December 19, 2019

January 1, 2020

 $12,506 $0.00467

/kwh

2018 Annual Update

 A –

August 29, 2018

November 1, 2018

 $5,886 $0.00219

/kwh

North Dakota

          

Renewable Resource Adjustment

          

2020 Annual Update

 A –

March 18, 2020

April 1, 2020

 $5,762 5.637%

of base

2019 Annual Update

 A –

May 1, 2019

June 1, 2019

 $(235)-0.224%

of base

2018 Rate Reset for effect of TCJA

 A –

February 27, 2018

March 1, 2018

 $9,650 7.493%

of base

Transmission Cost Recovery

          

2020 Annual Update

 R –

August 31, 2020

January 1, 2021

 $5,570 

Various

2019 Annual Update

 A –

December 18, 2019

January 1, 2020

 $5,739 

Various

2018 Supplemental Update

 A –

December 6, 2018

February 1, 2019

 $4,801 

Various

2018 Rate Reset for effect of TCJA

 A –

February 27, 2018

March 1, 2018

 $7,469 

Various

Environmental Cost Recovery

          

2019 Update

 A –

October 22, 2019

November 1, 2019

 $0 0%

of base

2018 Update

 A –

December 19, 2018

February 1, 2019

 $(378)-0.310%

of base

2018 Rate Reset for effect of TCJA

 A –

February 27, 2018

March 1, 2018

 $7,718 5.593%

of base

Generation Cost Recovery

          

2020 Annual Update

 A –

June 10, 2020

July 1, 2020

 $6,184 6.041%

of base

2019 Initial Request

 A –

May 15, 2019

July 1, 2019

 $2,720 2.547%

of base

South Dakota

          

Transmission Cost Recovery

          

2020 Annual Update

 A –

February 19, 2020

March 1, 2020

 $2,327 

Various

2019 Rate Reset

 A –

September 17, 2019

October 1, 2019

 $2,046 

Various

2019 Annual Update

 A –

February 20, 2019

March 1, 2019

 $1,638 

Various

2018 Interim Rate Reset

 A –

October 18, 2018

October 18, 2018

 $1,171 

Various

Environmental Cost Recovery

          

2018 Interim Rate Reset

 A –

October 18, 2018

October 18, 2018

 $(189)-$0.00075

/kwh

Phase-In Rate Plan Recovery

          

2020 Annual Update

 A –

August 6, 2020

September 1, 2020

 $1,625 6.521%

of base

2019 Initial Request

 A –

August 21, 2019

September 1, 2019

 $864 3.345%

of base

FERC

Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935 (Federal Power Act). The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a suspension period, subject to ultimate approval by the FERC.

MVPs—MVPs are designed to enable the MISO region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit from the MVP.

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ROE—In November 2013 and February 2015, customers filed complaints with FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO tariff. OTP hastariff rate. FERC's most recent order, issued on November 19, 2020, adopted a revised ROE methodology and set the base ROE at 10.02% (10.52% with an adder) effective for the fifteen-month period from November 2013 to February 2015 and on a prospective basis beginning in September 2016. The order also dismissed any complaints covering the period from February 2015 to May 2016. The November 2020 opinion is subject to judicial review. We have deferred recognition and recorded a refund liability of $2.8$3.0 million as of September 30, 2020 as a result2021. This refund liability reflects our best estimate of the disputed ROE awaiting FERC action. The provision includes:

a $0.1 million refund for the first complaint period of November 2013 to February 2015 resulting from the potential reduction of the base ROE from 10.32%.

a $1.4 million refund related to the second complaint period of February 2015 to May 2016 resulting from a potential reduction in base ROE from 12.38%.

a $1.3 million refund for the period from September 2016 through September 2020 resulting from a potential reduction in base ROE from 10.82%.

Various FERC orders have been made that remain under appeal. All or some of the current liability will be refundedrequired refunds to customers once all regulatory and judicial proceedings are completed.

Regional Haze Rule (RHR). The RHR was adopted in an effort to improve visibility in national parks and wilderness areas. The RHR requires states, in coordination with the EPA and other governmental agencies, to develop and implement plans to achieve natural visibility conditions. The second RHR implementation period covers the years 2018-2028. States are required to submit a state implementation plan to assess reasonable progress with the RHR and determine what additional emission reductions are appropriate, if any.
Coyote Station, OTP's jointly owned coal-fired power plant in North Dakota, is subject to assessment in the second implementation period under the North Dakota state implementation plan. In September 2021, the North Dakota Department of Environmental Quality (NDDEQ) made public a draft of its state implementation plan. The plan concluded it is not reasonable to require additional emission controls during this planning period. Following a consultation and public comment period, and any subsequent modifications to the plan, the NDDEQ will submit its state implementation plan to the EPA for approval.
We cannot predict with certainty the impact the state implementation plan may have on our business until the state implementation plan has been approved or reversedotherwise acted on by the EPA. However, significant emission control investments could be required and recognized as revenue dependingthe recovery of such costs from customers would require regulatory approval. Alternatively, investments in emission control equipment may prove to be uneconomic and result in an early retirement of, or the sale of our interest in, Coyote Station, subject to regulatory approval. We cannot estimate the financial effects such a retirement or sale may have on various factors including MISO’s determinationour consolidated operating results, financial position or cash flows, but such amounts could be material and the recovery of refund amounts and FERC’s final determination of the reasonableness of base ROE over various periods.

such costs from customers would be subject to regulatory approval.
2015

4. Regulatory AssetsWestmoreland Coal Company (Westmoreland) Arbitration. In December 2018, insurers for Westmoreland, Westmoreland and Liabilities

Asits affiliated companies filed an arbitration demand against the co-owners of Coyote Station, including OTP, a regulated entity, OTP accounts for the financial effects of regulation35% co-owner. The claimant insurers are pursuing recovery in accordance with ASC 980. This accounting standard allows for the recording of a regulatory asset or liability for costs that will be collected or refunded in the future as required under regulation. Additionally, ASC 980-605-25 provides for the recognition of revenues authorized for recovery outside of a general rate case under alternative revenue programs which provide for recovery of costs and incentives or returns on investment in such items as transmission infrastructure, renewable energy resources or conservation initiatives. The following tables indicate the amount of regulatory assets$5.5 million, plus prejudgment interest to recover business interruption insurance proceeds paid to Westmoreland or its affiliates arising from a boiler feed pump explosion in December 2014 at the facility. The explosion and liabilities recorded on the Company’s consolidated balance sheets:

  

September 30, 2020

  

Remaining

Recovery/

 

(in thousands)

 

Current

  

Long-Term

  

Total

   Refund Period (months)  

Regulatory Assets:

                

Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1

 $9,018  $122,765  $131,783  

see below

 

Minnesota Transmission Cost Recovery Rider Accrued Revenues2

  3,676   6,126   9,802   27 

Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment1

  0   8,481   8,481  

asset lives

 

Conservation Improvement Program Costs and Incentives2

  1,040   2,094   3,134   24 

Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery1

  0   2,149   2,149  

asset lives

 

MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups1

  1,234   559   1,793   27 

Unrecovered Project Costs – Minnesota1

  401   1,092   1,493   21 

Minnesota Renewable Resource Rider Accrued Revenues2

  1,203   0   1,203   12 

Unrecovered Project Costs – North Dakota1

  0   856   856   21 

Minnesota SPP Transmission Cost Recovery Tracker1

  0   759   759  

see below

 

Debt Reacquisition Premiums1

  204   379   583   144 

Unrecovered Project Costs – South Dakota1

  144   357   501   24 

South Dakota Deferred Rate Case Expenses Subject to Recovery1

  137   143   280   25 

North Dakota Deferred Rate Case Expenses Subject to Recovery1

  122   152   274   27 

Deferred Marked-to-Market Losses1

  186   -   186   3 

North Dakota Generation Cost Recovery Rider Accrued Revenue2

  66   0   66   9 

Deferred Lease Expenses1

  0   65   65   56 

Minnesota Environmental Cost Recovery Rider Accrued Revenues2

  4   0   4   12 

Total Regulatory Assets

 $17,435  $145,977  $163,412     

Regulatory Liabilities:

                

Deferred Income Taxes

 $0  $136,630  $136,630  

asset lives

 

Accumulated Reserve for Estimated Removal Costs – Net of Salvage

  0   99,617   99,617  

asset lives

 

Refundable Fuel Clause Adjustment Revenues

  9,208   0   9,208   12 

North Dakota Transmission Cost Recovery Rider Accrued Refund

  1,233   0   1,233   3 

South Dakota Phase-In Rate Plan Rider Accrued Refund

  1,090   0   1,090   11 

Revenue for Rate Case Expenses Subject to Refund – Minnesota

  0   577   577  

see below

 

Prior Service Costs and Actuarial Gains on Postretirement Benefits

  471   0   471   12 

North Dakota Renewable Resource Recovery Rider Accrued Refund

  444   0   444   6 

South Dakota Transmission Cost Recovery Rider Accrued Refund

  232   0   232   5 

Minnesota Energy Intensive Trade Exposed Rider Accrued Refund

  186   0   186   12 

Other

  6   68   74   159 

Total Regulatory Liabilities

 $12,870  $236,892  $249,762     

Net Regulatory Asset/(Liability) Position

 $4,565  $(90,915) $(86,350)    

1Costs subject to recovery without a rate of return.

2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

21

 
  

December 31, 2019

  

Remaining

Recovery/

 

(in thousands)

 

Current

  

Long-Term

  

Total

  

Refund Period

(months)

 

Regulatory Assets:

                

Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1

 $9,090  $129,102  $138,192  

see below

 

Minnesota Transmission Cost Recovery Rider Accrued Revenues2

  4,208   0   4,208   12 

Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment1

  0   7,772   7,772  

asset lives

 

Conservation Improvement Program Costs and Incentives2

  4,024   2,844   6,868   21 

Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery1

  0   1,681   1,681  

asset lives

 

MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups1

  2,033   968   3,001   24 

Unrecovered Project Costs – Minnesota1

  715   225   940   16 

Minnesota Renewable Resource Rider Accrued Revenues2

  131   0   131   12 

Minnesota SPP Transmission Cost Recovery Tracker1

  0   202   202  

see below

 

Debt Reacquisition Premiums1

  201   548   749   153 

Unrecovered Project Costs – South Dakota1

  144   253   397   33 

South Dakota Deferred Rate Case Expenses Subject to Recovery1

  138   245   383   34 

North Dakota Deferred Rate Case Expenses Subject to Recovery1

  122   244   366   36 

Deferred Marked-to-Market Losses1

  743   -   743   12 

Deferred Lease Expenses1

  0   54   54   39 

Minnesota Environmental Cost Recovery Rider Accrued Revenues2

  4   0   4   12 

South Dakota Transmission Cost Recovery Rider Accrued Revenues2

  97   0   97   2 

Total Regulatory Assets

 $21,650  $144,138  $165,788     

Regulatory Liabilities:

                

Deferred Income Taxes

 $0  $141,707  $141,707  

asset lives

 

Accumulated Reserve for Estimated Removal Costs – Net of Salvage

  0   97,726   97,726  

asset lives

 

Refundable Fuel Clause Adjustment Revenues

  3,982   0   3,982   12 

North Dakota Transmission Cost Recovery Rider Accrued Refund

  700   0   700   12 

South Dakota Phase-In Rate Plan Rider Accrued Refund

  355   0   355   9 

Revenue for Rate Case Expenses Subject to Refund – Minnesota

  0   401   401  

see below

 

Prior Service Costs and Actuarial Gains on Postretirement Benefits

  471   0   471   12 

North Dakota Renewable Resource Recovery Rider Accrued Refund

  1,515   0   1,515   12 

Minnesota Energy Intensive Trade Exposed Rider Accrued Refund

  164   0   164   12 

North Dakota Generation Cost Recovery Rider Accrued Refund

  287   0   287   6 

Other

  6   72   78   168 

Total Regulatory Liabilities

 $7,480  $239,906  $247,386     

Net Regulatory Asset/(Liability) Position

 $14,170  $(95,768) $(81,598)    

1Costs subject to recovery without a rate of return.

2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

The regulatory asset and liability related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses and gains subject to recovery or refund through rates as they are expensed. These unrecognized benefit costs and actuarial losses and gains are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic 715,Compensation—Retirement Benefits, but are eligible for treatment as regulatory assets or liabilities based on their probable inclusion in future retail electric rates.

The Minnesota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that were recoverable from Minnesota customers as of the balance sheet date.

The Accumulated ARO Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations.

Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates.

22

The Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery are employee benefit-related costs that are required to be capitalized for ratemaking purposes and are recovered over the depreciable lives of the assets to which the related labor costs were applied.

MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups relate to the over/under collection of revenue based on comparison of the expected versus actual construction on eligible projects in the period. The true-ups also include the state jurisdictional portion of MISO Schedule 26/26A for regional transmission cost recovery that was included in the calculation of the state transmission riders and subsequently adjusted to reflect actual billing amounts in the schedule.

Unrecovered Project Costs – Minnesota are the Minnesota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project and excess unrecovered depreciation expense for Hoot Lake Plant and OTP’s hydroelectric plants related to acceleration of their remaining depreciable lives.

The Minnesota Renewable Resource Recovery Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that were recoverable from Minnesota customers as of the balance sheet date.

Unrecovered Project Costs – North Dakota are the North Dakota share of excess unrecovered depreciation expense for Hoot Lake Plant and OTP’s hydroelectric plants related to acceleration of their remaining depreciable lives.

The Minnesota SPP Transmission Cost Recovery Tracker regulatory asset relates to costs incurred to serve Minnesota customers that are subject to recovery but that had not been billed to Minnesota customers as of the balance sheet date.

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 147 months.

Unrecovered Project Costs – South Dakota are the South Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project and excess unrecovered depreciation expense for Hoot Lake Plant and OTP’s hydroelectric plants related to acceleration of their remaining depreciable lives.

South Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s most recent rate case in South Dakota and are currently being recovered beginning with the establishment of interim rates in October 2018.

North Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s most recent rate case in North Dakota currently being recovered beginning with the establishment of interim rates in January 2018.

All Deferred Marked-to-Market Losses recorded as of the balance sheet date relate to forward purchases of energy scheduled for delivery through December 2020.

The North Dakota Generation Cost Recovery Rider Accrued Revenues relate to revenues earned under the rider on recoverable costs incurred for the North Dakota share of OTP’s investment in Astoria Station, a natural gas-fired combustion turbine generation facility under construction near Astoria, South Dakota. The balance represents amounts subject to recovery from North Dakota customers that had not been billed to North Dakota customers as of the balance sheet date.

Deferred Lease Expenses: Under ASC 842 accounting rules for leases with scheduled escalating payments, rent expense is required to be recognized on a straight-line basis over the life of the lease based on the sum of those payments. Rate-regulated entities are generally only allowed to recoverensuing repairs reduced the amount of actual cash payments on leases and FERC accounting rules require that rent expense be recognized oncoal purchased from a Westmoreland affiliate under an existing coal purchase agreement. The Westmoreland insurers claim the basis of cash payments. The balanceco-owners breached the minimum purchase obligations in the deferred lease expense regulatory asset account represents operating lease rightcoal purchase agreement. As of use asset cumulative amortization and interest costs in excess of cumulative lease payments that are subjectSeptember 30, 2021, we have recorded an estimated liability for losses to recovery in future periods under regulatory accounting treatment as cash payments are rendered.

The Minnesota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS project that were recoverable from Minnesota customers as of the balance sheet date.

The South Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities and operating costsbe incurred to serve South Dakota customers that were recoverable from South Dakota customers as of the balance sheet date.

The regulatory liability related to Deferred Income Taxes results from changes in statutory tax rates accounted for in accordance with ASC Topic 740,Income Taxes.

23

The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred.

The North Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that were refundable to North Dakota customers as ofthis matter based upon the balance sheet date.

The South Dakota Phase-In Rate Plan Rider Accrued Refund relates to amounts collected for actual and forecasted costs for Astoria Station, Merricourt, and additional load growth that were refundable to South Dakota customers as of the balance sheet date.

Revenue for Rate Case Expenses Subject to Refund – Minnesota relates to revenues collected under general rates to recover costs related to prior rate case proceedingsmost recent information available, however, ultimate losses could be in excess of the actual costs incurred.

amount recorded. Any losses incurred from this matter could be eligible for recovery through typical cost recovery processes of our electric utility business. The North Dakota Renewable Resource Recovery Rider Accrued Refund relatespotential cost recovery would be subject to amounts collectedregulatory approval.

Other Contingencies. We are party to litigation and regulatory matters arising in the normal course of business. We regularly analyze relevant information and, as necessary, estimate and record accrued liabilities for qualifying renewable resource costs incurred to serve North Dakota customers that were refundable to North Dakota customerslegal, regulatory enforcement and other matters in which a loss is probable of occurring and can be reasonably estimated. We believe the effect on our consolidated operating results, financial position and cash flows, if any, for the disposition of all matters pending as of the balance sheet date.

The South Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that were refundable to South Dakota customers as of the balance sheet date.

The Minnesota Energy Intensive Trade Exposed Rider Accrued Refund relates to over-collected amounts from Minnesota retail customers for fuel and purchased power costs reductions provided to customers in energy intensive trade exposed industries that were subject to refund to Minnesota customers as of the balance sheet date.

The North Dakota Generation Cost Recovery Rider Accrued Refund relates to revenues collected under the rider in excess of returns allowed on recoverable costs incurred for the North Dakota share of OTP’s investment in Astoria Station, a natural gas-fired combustion turbine generation facility under construction near Astoria, South Dakota. The balance represents amounts subject to refund to North Dakota customers that had been billed to North Dakota customers as of the balance sheet date.

If for any reason OTP ceases to meet the criteria for application of guidance under ASC 980 for all or part of its operations, the regulatory assets and liabilities that no longer meet such criteria wouldSeptember 30, 2021, other than those discussed above, will not be removed from the consolidated balance sheet and included in the consolidated statement of income as an expense or income item in the period in which the application of guidance under ASC 980 ceases.

material.

5. Common Shares and Earnings Per Share

Shelf

10. Stockholders' Equity
Registration

Statements

On May 3, 2018 the Company2021 we filed a shelf registration statement with the Securities and Exchange Commission (SEC) under which the Company we may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement. The registration statement which expires on in May 2024.
On May 3, 2021.

On November 8, 2019, 2021, we filed a second registration statement with the Company entered into a Distribution Agreement with KeyBanc Capital Markets Inc. (KeyBanc Capital Markets). Pursuant to the terms of the Distribution Agreement, the Company may offer and sell its common shares from time to time through KeyBanc, as the Company’s distribution agentSEC for the offer and sale of the shares, up to an aggregate sales price of $75,000,000.

Under the Distribution Agreement, the Company will designate the minimum price and maximum number of common shares to be sold through KeyBanc on any given trading day or over a specified period of trading days, and KeyBanc will use commercially reasonable efforts to sell such shares on such days, subject to certain conditions. Sales of the shares, if any, will be made by means of ordinary brokers’ transactions on the Nasdaq Global Select Market at market prices or as otherwise agreed with KeyBanc. The Company may also agree to sell shares to KeyBanc, as principal for its own account, on terms agreed to by the Company and KeyBanc in a separate agreement at the time of sale. KeyBanc will receive from the Company a commissionissuance of up to 2%1,500,000 common shares under an Automatic Dividend Reinvestment and Share Purchase Plan, which provides shareholders, retail customers of the gross sales price per share for anyOTP and other interested investors a method of purchasing our common shares sold through it as the Company’s distribution agentby reinvesting their dividends and/or making optional cash investments. Shares purchased under the Distribution Agreement. The Company is not obligated to sell and KeyBanc is not obligated to buy or sell any of the shares under the Distribution Agreement. The shares, if issued, willplan may be issued pursuant to the Company’s existing shelf registration statement.

24

2020 Common Stock Activity

Following is a reconciliation of the Company’snew issue common shares outstanding from December 31, 2019 through September 30, 2020:

Common Shares Outstanding, December 31, 2019

40,157,591

Issuances:

At-the-Market Offering

588,084

Automatic Dividend Reinvestment and Share Purchase Plan:

Dividends Reinvested

102,042

Cash Invested

88,636

Executive Stock Performance Awards (2017 awards earned)

62,497

Vesting of Restricted Stock Units

35,720

Employee Stock Purchase Plan:

Cash Invested

29,894

Dividends Reinvested

7,906

Restricted Stock Issued to Directors

17,400

Directors Deferred Compensation

612

Retirements:

Shares Withheld for Individual Income Tax Requirements

(38,217)

Common Shares Outstanding, September 30, 2020

41,052,165

Earnings Per Share

The numerator used in the calculation of both basic and diluted earnings per common share is net income with no adjustments for the three- and nine-month periods ended September 30, 2020 and 2019. The denominator used in the calculation of basic earnings per common share is the weighted average number ofor common shares outstanding during the period excluding nonvested restricted shares granted to the Company’s directors, which are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share. The denominator used in the calculation of diluted earnings per common share is derived by adjusting basic shares outstanding for the items listed in the following reconciliation for the three- and nine-month periods ended September 30:

  

Three Months ended

September 30

  

Nine Months ended

September 30

 
  

2020

  

2019

  

2020

  

2019

 

Weighted Average Common Shares Outstanding – Basic

  40,913,972   39,714,672   40,548,133   39,694,677 

Plus Outstanding Share Awards net of Share Reductions for Unrecognized Stock-Based Compensation Expense and Excess Tax Benefits:

                

Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance

  98,012   149,023   107,017   147,106 

Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees

  48,682   68,138   53,303   63,902 

Shares Expected to be Issued Under the Employee Stock Purchase Plan

  13,182   0   14,997   0 

Nonvested Restricted Shares

  2,603   13,107   8,033   14,896 

Shares Expected to be Issued Under the Deferred Compensation Program for Directors

  1,238   1,799   1,445   1,999 

Total Dilutive Shares

  163,717   232,067   184,795   227,903 

Weighted Average Common Shares Outstanding – Diluted

  41,077,689   39,946,739   40,732,928   39,922,580 

25

6. Share-Based Payments

Stock Incentive Awards

The following stock incentive awards were granted under the 2014 Stock Incentive Plan during the nine months ended September 30, 2020.

Award

Grant Date

 

Shares/

Units

Granted

  

Weighted

Average

Grant-Date

Fair Value

per Award

 

Vesting

Restricted Stock Units Granted:

          

With Dividend Equivalent:

          

To Key Management Employees

February 3, 2020

  3,000  $54.0450 

25% per year through February 6, 2024

To Executive Officers

February 12, 2020

  15,300  $54.0607 

25% per year through February 6, 2024

Without Dividend Equivalent:

          

To Nonexecutive Employees

April 20, 2020

  14,975  $40.18 

100% April 8, 2024

Stock Performance Awards Granted:

          

Under Executive Agreement

February 12, 2020

  47,600  $47.10 

December 31, 2022

Under Legacy Agreement

February 12, 2020

  7,400  $52.20 

December 31, 2022

Restricted Stock Granted to Nonemployee Directors

April 20, 2020

  17,400  $44.85 

33% per year through April 8, 2023

The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration in certain cases, and subject to forfeiture under the terms of the restricted stock unit award agreements. Certain restricted stock units granted to executive officers and certain key employees are eligible to receive dividend equivalent payments on all unvested awards over the awards respective vesting periods. The grant-date fair value of each restricted stock unit paying a dividend equivalent was the average of the high and low market price per sharepurchased on the date of grant.open market. The grant-date fair value of each restricted stock unit that does not pay a dividend equivalent was the average of the high and low market price per share on the date of grant, discounted for the value of the dividend exclusion on those restricted stock units over the unit’s vesting period.

Under the performance share awards the aggregate award for performance at target is 55,000 shares. For target performance the participants would earn an aggregate of 27,500 common shares for achieving the target set for the Company’s 3-year average adjusted ROE. The participants would also earn an aggregate of 27,500 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the Edison Electric Institute Index over the performance measurement period of January 1, 2020 through December 31, 2022, with the beginning and ending share values based on the average closing price of a share of the Company’s common stock for the 20 trading days immediately following January 1, 2020 and the average closing price for the 20 trading days immediately preceding January 1, 2023. Actual payment may range from zero to 150% of the target amount, or up to 82,500 common shares. There are no voting or dividend rights related to these shares until the shares, if any, are issued at the end of the performance measurement period. The terms of these awards are such that the entire award will be classified and accounted for as equity, as required under ASC 718,Compensation – Stock Compensation, and will be measured over the performance period based on the grant-date fair value of the award. The grant-date fair value of each performance share award was determined using a Monte Carlo fair valuation simulation model.

Under the 2020 Performance Award Agreements, payment and the amount of paymentregistration statement expires in the event of retirement, resignation for good reason or involuntary termination without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that the payment of performance awards granted to an officer who is party to an Executive Employment Agreement with the Company is to be made at target at the date of any such event. The vesting of these awards is accelerated and paid at target in the event of a change in control.

The restricted shares granted to the Company’s nonemployee directors are eligible for full dividend and voting rights. Restricted shares not vested and dividends on those restricted shares are subject to forfeiture under the terms of the restricted stock award agreements. The grant-date fair value of each restricted share was the average of the high and low market price per share on the date of grant.

The end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the earlier of the indicated vesting period for the respective awards or the date the grantee becomes eligible for retirement as defined in their award agreement.

May 2024.
26

As of September 30, 2020, the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $3.9 million (before income taxes) which will be amortized over a weighted-average period of 1.9 years.

Amounts of compensation expense recognized under the Company’s stock-based payment programs for the three- and nine-month periods ended September 30, 2020 and 2019 are presented in the table below:

  

Three months ended

  

Nine months ended

 
  

September 30,

  

September 30,

 

(in thousands)

 

2020

  

2019

  

2020

  

2019

 

Stock Performance Awards Granted to Executive Officers

 $758  $743  $3,170  $3,274 

Restricted Stock Dividend Equivalent Units Granted to Executive Officers and Key Employees

  106   189   891   999 

Restricted Stock Granted to Nonemployee Directors

  237   203   677   572 

Restricted Stock Units Granted to Nonexecutive Employees

  133   112   408   346 

ESPP (15% discount)

  41   54   136   54 

Totals

 $1,275  $1,301  $5,282  $5,245 

7. Retained Earnings and Dividend Restriction

The CompanyRestrictions

Otter Tail Corporation is a holding company with no significant operations of its own. The primary source of funds for payments of dividends to the Company’sour shareholders is from dividends paid or distributions made by the Company’sour subsidiaries. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by the Company’sour subsidiaries.

Both the CompanyOTC Credit Agreement and OTP credit agreementsCredit Agreement contain restrictions on the payment of cash dividends upon a default or event of default. An event of default, would be consideredincluding failure to have occurred if the Company did not meetmaintain certain financial covenants. As of September 30, 2020, the Company was2021, we were in compliance with these financial covenants.

Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. What constitutes “funds properly included in a capital account” is undefined in the Federal Power Act or the related regulations; however, the FERC has consistently interpreted the provision to allow dividends to be paid as long as (1)i) the source of the dividends is clearly disclosed, (2)ii) the dividend is not excessive and (3)iii) there is no self-dealing on the part of corporate officials.

The MPUC indirectly limits the amount of dividends OTP can pay to the Company by requiring an equity-to-total-capitalization ratio between 47.5% and 58.1% based on OTP’s 2020 capital structure petition effective by order of the MPUC on July 15, 2020. As of September 30, 2020, 2021, OTP’s equity-to-total-capitalization ratio including short-term debt was 52.8%52.6% and its net assets restricted from distribution totaled approximately $619$674.9 million. Under the 2020 capital structure petition, OTP’s total capitalization for OTP cannot exceed $1,704,607,000.

$1.7 billion.

8. Leases

No update required

11. Share-Based Payments
Stock Compensation Expense
Stock-based compensation expense arising from our employee stock purchase plan and share-based compensation plans, recognized within operating expenses in the consolidated statements of income, amounted to $0.8 million and $1.3 million for interim reporting periods.

9. Commitments and Contingencies

Construction and Other Purchase Commitments

At the three months ended September 30, 2021 and 2020, OTP had commitments under contracts,respectively, and $6.4 million and $5.3 million for the nine months ended September 30, 2021 and 2020, respectively.

Stock Awards. We grant restricted stock awards to members of our Board of Directors and restricted stock units to our employees. The awards vest, depending on award type and recipient, either ratably over periods of three and four years or cliff vest after four years. Vesting is accelerated in certain circumstances, including its shareon retirement. Restricted stock awards granted to members of construction program commitmentsthe Board of Directors are issued and other commitments, extending into 2022outstanding on grant and carry the same voting and dividend rights of approximately $58 million. At December 31, 2019 OTP had commitments under contracts, including its share of construction program commitmentsunrestricted outstanding common stock. Restricted stock units are not issued or outstanding on grant and other nonlease commitments, extending into 2021 of approximately $317 million.

On October 1, 2019 T.O. Plastics entered into a six-year resin supply agreement that commenced on January 1, 2020. Underdo not provide for voting or dividend rights. Certain restricted stock unit award recipients are eligible to receive dividend equivalent payments during the resin supply agreement, there are no minimum purchase requirements, but T.O. Plastics is requiredvesting period, subject to purchase all of a specified class of regrind resin delivered by the supplier at a set price per pound. Based on current forecasted production levels, T.O. Plastics anticipates the quantity of resin deliveredforfeiture under the supply agreement will not exceed its requirements over the six-year termterms of the supply agreement or exceedagreement.

The grant date fair value of each stock award is determined based on the market costprice of alternative sourcesour common stock on the date of grant adjusted to exclude the resin. T.O. Plastics estimates it will payvalue of dividends for those awards that do not receive dividend or dividend equivalent payments during the supplier approximately $1.9 million annually under this agreement.

vesting period.
2716

Electric Utility Capacity and Energy Requirements and Coal Purchase and Delivery Contracts

OTP has commitmentsThe following is a summary of stock award activity for the purchasenine months ended September 30, 2021:
SharesWeighted Average
Grant-Date
Fair Value
Nonvested, January 1, 2021128,664 $44.30 
Granted57,650 43.10 
Vested(47,646)42.98 
Forfeited(2,075)40.95 
Nonvested, September 30, 2021136,593 $44.30 

The fair value of capacityvested awards was $2.1 million and energy requirements under agreements extending into 2043. OTP also has contracts providing for$2.8 million during the purchasenine months ended September 30, 2021 and delivery of a significant portion of its current coal requirements. OTP’s current coal purchase agreements for Coyote Station expire2020.
Stock Performance Awards. Stock performance awards are granted to executive officers and certain other key employees. The awards vest at the end of a three-year performance period. The number of common shares awarded, if any, at the end of the performance period ranges from zero to 150% of the target amount based on two performance measures: i) total shareholder return relative to a peer group and ii) return on equity. The awards have no voting or dividend rights during the vesting period. Vesting of the awards is accelerated in certain circumstances, including on retirement. The amount of common shares awarded on an accelerated vesting is based either on actual performance at the end of the performance period or the amount of common shares earned at target.
The grant date fair value of stock performance awards granted during the nine months ended September 30, 2021 and 2020 was determined using a Monte Carlo fair value simulation model incorporating the following assumptions:
20212020
Risk-free interest rate0.18 %1.42 %
Expected term (in years)3.003.00
Expected volatility32.00 %19.00 %
Dividend yield3.60 %2.80 %
The risk-free interest rate was derived from yields on U.S. government bonds of a similar term. The expected term of the award is equal to the three-year performance period. Expected volatility was estimated based on actual historical volatility of our common stock. Dividend yield was estimated based on historic and future yield estimates.
2040. OTP has agreements with Peabody COALSALES, LLC (Peabody)The following is a summary of stock performance award activity for the purchasenine months ended September 30, 2021 (share amounts reflect awards at target):
 SharesWeighted Average
Grant-Date
Fair Value
Nonvested, January 1, 2021164,600 $42.32 
Granted79,000 38.34 
Vested(54,000)35.73 
Forfeited— — 
Nonvested, September 30, 2021189,600 $42.54 
The fair value of subbituminous coal for Big Stone Plant’s coal requirements through December 31, 2022. There are no fixed minimum purchase requirements under these agreements but allvested awards was $2.5 million and $3.4 million during the nine months ended September 30, 2021 and 2020.
12. Earnings Per Share
The numerator used in the calculation of Big Stone Plant’s coal requirementsboth basic and diluted earnings per common share is net income. The denominator used in the calculation of basic earnings per common share is the weighted average number of common shares outstanding during the period. The denominator used in the calculation of diluted earnings per common share is derived by adjusting basic shares outstanding for the period covered must be purchased exclusively from Peabody. OTP has an all-requirements agreement with Navajo Transitional Energy Co.dilutive effect of potential common shares outstanding, which consist of time and performance based stock awards and employee stock purchase plan shares.
17

The following includes the computation of the denominator for basic and diluted weighted-average shares outstanding for the purchasethree and nine months ended September 30, 2021 and 2020:
Three Months Ended September 30,Nine Months Ended September 30,
(in thousands)2021202020212020
Weighted Average Common Shares Outstanding – Basic41,504 40,914 41,487 40,548 
Effect of Dilutive Securities:
Stock Performance Awards262 98 209 107 
Stock Awards88 49 82 53 
Employee Stock Purchase Plan Shares and Other15 17 17 25 
Dilutive Effect of Potential Common Shares365 164 308 185 
Weighted Average Common Shares Outstanding – Diluted41,869 41,078 41,795 40,733 
The amount of subbituminous coalshares excluded from diluted weighted-average common shares outstanding because such shares were anti-dilutive was not material for Hoot Lake Plant through December 31, 2023, the three and nine months ended September 30, 2021 and 2020.
13. Derivative Instruments
OTP enters into derivative instruments to manage its exposure to future price variability and reduce volatility in prices for our retail customers. These derivative instruments are not designated as qualifying hedging transactions but provide for an economic hedge against future price variability. The instruments are recorded at fair value on the consolidated balance sheets, with no fixed minimum purchase requirement. OTP plans to discontinue generation at Hoot Lake Plantchanges in May 2021.

OTP Land Easements

OTP has commitments to make future payments for land easements not classified as leases, extending into 2034fair value recorded in the consolidated statements of approximately $9.7 million.

Transmission Obligation

In September 2020, in connection with Merricourt andincome. However, in accordance with rate-making and cost recovery processes, we recognize a regulatory asset or liability to defer losses or gains from derivative activity until settlement of the Merricourt amended and restated generator interconnection agreement,associated derivative instrument.

As of September 30, 2021, OTP entered into a 20-year Facilities Service Agreement (FSA)had outstanding pay-fixed, receive-variable swap agreements with an owneraggregate notional amount of adjacent transmission assets to pay for upgrades and additions to the owner’s transmission facilities required to accommodate the transmission356,200 megawatt-hours of electricity, generated by Merricourt’s wind turbines. OTP estimates itwhich will pay approximately $675,000 annuallybe settled periodically through October 2040 under2022. As of September 30, 2021, the FSA. The annual payment requirements are subject to adjustments for changesaggregate fair value of these contracts was $6.9 million, of which $6.1 million is included in income tax rates, rates of return onother current assets and other variable factors$0.8 million is included in other noncurrent assets on the MISO tariff.

consolidated balance sheets.

14. Fair Value Measurements
Contingencies

OTP hadThe following tables present our assets measured at fair value on a $2.8 million refund liability on its balance sheetrecurring basis as of September 30, 2020. This represents its best estimate2021 and December 31, 2020 classified by the input method used to measure fair value:
Level 1Level 2Level 3
September 30, 2021
Investments:
Money Market Funds$953 $ $ 
Mutual Funds5,170   
Corporate Debt Securities 2,377  
Government-Backed and Government-Sponsored Enterprises’ Debt Securities 6,831  
Derivative Instruments 6,923  
Total Assets$6,123 $16,131 $ 
December 31, 2020
Investments:
Money Market Funds$4,075 $— $— 
Mutual Funds1,662 — — 
Corporate Debt Securities— 2,627 — 
Government-Backed and Government-Sponsored Enterprises’ Debt Securities— 6,633 — 
Total Assets$5,737 $9,260 $— 

The level 2 fair value measurements for government-backed and government-sponsored enterprises and corporate debt securities are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes.
The level 2 fair value measurements for derivative instruments are determined by using inputs such as forward electric commodity prices, adjusted for location differences. These inputs are observable in the marketplace throughout the full term of the refund obligations that would arise netinstrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace.
18

In addition to the potential ROE refund described above, the most significant contingenciesassets recorded at fair value on a recurring basis, we also hold financial instruments that could impact the Company’s consolidated financial statements are those related to environmental remediation, risks associated with warranty claims relating to divested businesses that could exceed established reserve amounts, risks associated with adverse regulatory decisions that could impact the recovery of fixed asset costs in future rates and litigation matters.

On July 30, 2020 the MPUC ordered a reductionnot recorded at fair value in the remaining depreciable lives of OTP’s Hoot Lake Plant and seven hydroelectric plants. The MPUC stipulated recoverabilityconsolidated balance sheets but for which disclosure of the resulting increase in depreciation expense, which we estimate will be approximately $1.4 million on an annual basis, would be determined in OTP’s next rate case. Based onfair value of these financial instruments is provided. The following reflects the relevant factscarrying value and circumstances, OTP has concluded the additional depreciation expense is probableestimated fair value of recoverythese assets and has recognized a regulatory asset for the amountliabilities as of incremental expense recognized in 2020.

State implementation of pollution control plans to improve visibilitySeptember 30, 2021 and air quality at national parks under the EPA’s Regional Haze Rule (RHR) could require OTP to incur significant new costs, which could, dependent on determinations by state regulatory commissions on approval to recover such costs from customers, negatively impact OTP’s and the Company’s net income, financial position and cash flows. The North Dakota Department of Environmental Quality (NDDEQ) must submit a state implementation plan to the EPA by July 2021. While this process is still in the early stages, if the NDDEQ and/or the EPA requires sources subject to RHR Round 2 reasonable progress determinations, including Coyote Station, to undertake emissions control measures that are reasonably consistent with those required of sources during Round 1, OTP anticipates that significant emissions controls would be required at Coyote Station by December 31, 2028. In light of the costs for emissions control equipment, there are scenarios where it may not be economically feasible to invest in such equipment and an early retirement of the Coyote Station would therefore be necessary. The costs related to an early retirement of Coyote Station would be material to OTP and the Company and would be subject to state commission approval for recovery from customers.

In October 2020, during testing and commissioning of Merricourt, a defect in a turbine blade was identified. The Company is investigating the defect along with additional blades to determine if other blades have similar defects. Depending on the extent of the defect and repair and replacement alternatives, the date of commercial operation of the project, or a portion thereof, may be delayed beyond December 2020. The cost of the project could also be impacted, but the risk of loss on assets of the project only transfers to Otter Tail Power Company at commercial operation. Considering this along with the commercial and contractual provisions in place, the Company does not anticipate this issue will have a material financial impact on the Company.

2020:
 September 30, 2021December 31, 2020
(in thousands)Carrying
Amount
Fair ValueCarrying
Amount
Fair Value
Assets:
Cash and Cash Equivalents$1,272 $1,272 $1,163 $1,163 
Total1,272 1,272 1,163 1,163 
Liabilities:
Short-Term Debt97,857 97,857 80,997 80,997 
Long-Term Debt764,581 873,632 764,519 858,455 
Total$862,438 $971,489 $845,516 $939,452 
28

Other

The Company is a party to litigation and regulatory enforcement matters arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of September 30, 2020, other than those relating to the RHR, will not be material.

10. Short-Term and Long-Term Borrowings

The following table presents the status of the Company’s lines of credit as of September 30, 2020 and December 31, 2019:

(in thousands)

 

Line Limit

  

In Use on

September 30,

2020

  

Restricted due to Outstanding

Letters of Credit

  

Available on

September 30,

2020

  

Available on

December 31,

2019

 

Otter Tail Corporation Credit Agreement

 $170,000  $48,600  $0  $121,400  $164,000 

OTP Credit Agreement

  170,000   0   7,670   162,330   154,524 

Total

 $340,000  $48,600  $7,670  $283,730  $318,524 

Long-Term Debt Issuances

2019 Note Purchase Agreement

On September 12, 2019, OTP entered into a Note Purchase Agreement (the 2019 Note Purchase Agreement) with the purchasers named therein (the Purchasers), pursuant to which OTP agreed to issue to the Purchasers, in a private placement transaction, $175 million aggregate principal amount of OTP’s senior unsecured notes consisting of (a) $10,000,000 aggregate principal amount of its 3.07% Series 2019A Senior Unsecured Notes due October 10, 2029 (the Series 2019A Notes), (b) $26,000,000 aggregate principal amount of its 3.52% Series 2019B Senior Unsecured Notes due October 10, 2039 (the Series 2019B Notes), (c) $64,000,000 aggregate principal amount of its 3.82% Series 2019C Senior Unsecured Notes due October 10, 2049 (the Series 2019C Notes), (d) $10,000,000 aggregate principal amount of its 3.22% Series 2020A Senior Unsecured Notes due February 25, 2030 (the Series 2020A Notes), (e) $40,000,000 aggregate principal amount of its 3.22% Series 2020B Senior Unsecured Notes due August 20, 2030 (the Series 2020B Notes), (f) $10,000,000 aggregate principal amount of its 3.62% Series 2020C Senior Unsecured Notes due February 25, 2040 (the Series 2020C Notes) and (g) $15,000,000 aggregate principal amount of its 3.92% Series 2020D Senior Unsecured Notes due February 25, 2050 (the Series 2020D Notes; and together with the Series 2019A Notes, the Series 2019B Notes, the Series 2019C Notes, the Series 2020A Notes, the Series 2020B Notes and the Series 2020C Notes, the Notes).

On February 25, 2020, OTP issued the Series 2020A Notes, the Series 2020C Notes and the Series 2020D Notes pursuant to the 2019 Note Purchase Agreement. On August 20, 2020, OTP issued the Series 2020B Notes pursuant to the 2019 Note Purchase Agreement. OTP used the $75 million proceeds from the issuances to pay for capital expenditures and for other corporate purposes. The Series 2019A Notes, Series 2019B Notes and Series 2019C Notes were issued by the Company on October 10, 2019.

OTP may prepay all or any part of the Notes (in an amount not less than 10% of the aggregate principal amount of the Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount so prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the 2019 Note Purchase Agreement, any prepayment made by OTP of all of the (a) Series 2020A Notes then outstanding on or after August 25,2029, (b) Series 2020C Notes then outstanding on or after August 25, 2039 or (c) Series 2020D Notes then outstanding on or after August 25, 2049 will be made without any make-whole amount. The 2019 Note Purchase Agreement also requires OTP to offer to prepay all outstanding Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2019 Note Purchase Agreement) of OTP.

The 2019 Note Purchase Agreement contains a number of restrictions on the business of OTP. These include restrictions on OTP’s abilities to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The 2019 Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants. Specifically, OTP may not permit its Interest-bearing Debt (as defined in the 2019 Note Purchase Agreement) to exceed 60% of Total Capitalization (as defined in the 2019 Note Purchase Agreement), determined as of the end of each fiscal quarter. OTP is also restricted from allowing its Priority Indebtedness (as defined in the Note Purchase Agreement) to exceed 20% of Total Capitalization, determined as of the end of each fiscal quarter. The 2019 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. The 2019 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event OTP’s existing credit agreement or any renewal, extension or replacement thereof, at any time contains any financial covenant or other provision providing for limitations on interest

29

expense and such a covenant is not contained in the 2019 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the Notes than any analogous provision contained in the 2019 Note Purchase Agreement (an Additional Covenant), then unless waived by the Required Holders (as defined in the 2019 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2019 Note Purchase Agreement. The 2019 Note Purchase Agreement also provides for the amendment, modification or deletion of an Additional Covenant if such Additional Covenant is amended or modified under or deleted from the credit agreement, provided that no default or event of default has occurred and is continuing.

The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of September 30, 2020 and December 31, 2019:

September 30, 2020 (in thousands)

 

OTP

  

Otter Tail

Corporation

  

Consolidated

 

Short-Term Debt

 $-  $48,600  $48,600 

Long-Term Debt:

            

3.55% Guaranteed Senior Notes, due December 15, 2026

     $80,000  $80,000 

Senior Unsecured Notes 4.63%, Series 2011A, due December 1, 2021

 $140,000       140,000 

Senior Unsecured Notes 6.15%, Series 2007B, due August 20, 2022

  30,000       30,000 

Senior Unsecured Notes 6.37%, Series 2007C, due August 20, 2027

  42,000       42,000 

Senior Unsecured Notes 4.68%, Series 2013A, due February 27, 2029

  60,000       60,000 

Senior Unsecured Notes 3.07%, Series 2019A, due October 10, 20291

  10,000       10,000 

Senior Unsecured Notes 3.22%, Series 2020A, due February 25, 2030

  10,000       10,000 

Senior Unsecured Notes 3.22%, Series 2020B, due August 20, 20301

  40,000       40,000 

Senior Unsecured Notes 6.47%, Series 2007D, due August 20, 2037

  50,000       50,000 

Senior Unsecured Notes 3.52%, Series 2019B, due October 10, 2039

  26,000       26,000 

Senior Unsecured Notes 3.62%. Series 2020C, due February 25, 2040

  10,000       10,000 

Senior Unsecured Notes 5.47%, Series 2013B, due February 27, 2044

  90,000       90,000 

Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048

  100,000       100,000 

Senior Unsecured Notes 3.82%, Series 2019C, due October 10, 2049

  64,000       64,000 

Senior Unsecured Notes 3.92%, Series 2020D, due February 25, 2050

  15,000       15,000 

PACE Note, 2.54%, due March 18, 2021

      215   215 

Total

 $687,000  $80,215  $767,215 

Less: Current Maturities net of Unamortized Debt Issuance Costs

  -   215   215 

Unamortized Long-Term Debt Issuance Costs

  2,408   318   2,726 

Total Long-Term Debt net of Unamortized Debt Issuance Costs

 $684,592  $79,682  $764,274 

Total Short-Term and Long-Term Debt (with current maturities)

 $684,592  $128,497  $813,089 

December 31, 2019 (in thousands)

 

Short-Term Debt

 $-  $6,000  $6,000 

Long-Term Debt:

            

3.55% Guaranteed Senior Notes, due December 15, 2026

     $80,000  $80,000 

Senior Unsecured Notes 4.63%, Series 2011A, due December 1, 2021

 $140,000       140,000 

Senior Unsecured Notes 6.15%, Series 2007B, due August 20, 2022

  30,000       30,000 

Senior Unsecured Notes 6.37%, Series 2007C, due August 20, 2027

  42,000       42,000 

Senior Unsecured Notes 4.68%, Series 2013A, due February 27, 2029

  60,000       60,000 

Senior Unsecured Notes 3.07%, Series 2019A, due October 10, 20291

  10,000       10,000 

Senior Unsecured Notes 6.47%, Series 2007D, due August 20, 2037

  50,000       50,000 

Senior Unsecured Notes 3.52%, Series 2019B, due October 10, 2039

  26,000       26,000 

Senior Unsecured Notes 5.47%, Series 2013B, due February 27, 2044

  90,000       90,000 

Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048

  100,000       100,000 

Senior Unsecured Notes 3.82%, Series 2019C, due October 10, 2049

  64,000       64,000 

PACE Note, 2.54%, due March 18, 2021

      351   351 

Total

 $612,000  $80,351  $692,351 

Less: Current Maturities net of Unamortized Debt Issuance Costs

  -   183   183 

Unamortized Long-Term Debt Issuance Costs

  2,231   356   2,587 

Total Long-Term Debt net of Unamortized Debt Issuance Costs

 $609,769  $79,812  $689,581 

Total Short-Term and Long-Term Debt (with current maturities)

 $609,769  $85,995  $

695,764

 

1Holder is COBANK, a cooperative lender. Interest payments are subject to cash credits which may result in a lower effective interest rate.

30

11. Pension Plan and Other Postretirement Benefits

Pension Plan—Components of net periodic pension benefit cost of the Company's noncontributory funded pension plan are as follows:

  

Three Months Ended

September 30,

  

Nine Months Ended

September 30,

 

(in thousands)

 

2020

  

2019

  

2020

  

2019

 

Service Cost—Benefit Earned During the Period

 $1,655  $1,373  $4,966  $4,119 

Interest Cost on Projected Benefit Obligation

  3,264   3,603   9,790   10,809 

Expected Return on Assets

  (5,506)  (5,324)  (16,516)  (15,973)

Amortization of Prior-Service Cost:

                

From Regulatory Asset

  0   1   0   4 

From Other Comprehensive Income1

  0   2   0   6 

Amortization of Net Actuarial Loss:

                

From Regulatory Asset

  2,231   1,163   6,693   3,488 

From Other Comprehensive Income1

  55   26   165   79 

Net Periodic Pension Cost2

 $1,699  $844  $5,098  $2,532 

1Corporate cost included in nonservice cost components of postretirement benefits.

                

2Allocation of costs:

                

Service costs included in OTP capital expenditures

 $516  $333  $1,371  $1,059 

Service costs included in electric operation and maintenance expenses

  1,099   1,007   3,476   2,961 

Service costs included in other nonelectric expenses

  40   33   119   99 

Nonservice costs capitalized as regulatory assets

  13   (128)  36   (408)

Nonservice costs included in nonservice cost components of postretirement benefits

  31   (401)  96   (1,179)

Cash flows—The Company had no minimum funding requirement as of December 31, 2019 but made a discretionary plan contribution of $11.2 million in January 2020.

Executive Survivor and Supplemental Retirement Plan—Components of net periodic pension benefit cost of the Company’s unfunded, nonqualified benefit plan for executive officers and certain key management employees are as follows:

  

Three Months Ended

September 30,

  

Nine Months Ended

September 30,

 

(in thousands)

 

2020

  

2019

  

2020

  

2019

 

Service Cost—Benefit Earned During the Period

 $45  $104  $134  $313 

Interest Cost on Projected Benefit Obligation

  362   433   1,086   1,301 

Amortization of Prior Service Cost:

                

From Regulatory Asset

  0   2   0   4 

From Other Comprehensive Income1

  0   4   0   12 

Amortization of Net Actuarial Loss:

                

From Regulatory Asset

  24   31   71   93 

From Other Comprehensive Income1

  85   87   256   262 

Net Periodic Pension Cost2

 $516  $661  $1,547  $1,985 

1Amortization of prior service costs and net actuarial losses from other comprehensive income are included in nonservice cost components of postretirement benefits.

                

2Allocation of Costs:

                

Service costs included in electric operation and maintenance expenses

 $0  $26  $0  $78 

Service costs included in other nonelectric expenses

  45   78   134   235 

Nonservice costs included in nonservice cost components of postretirement benefits

  471   557   1,413   1,672 

31

Other Postretirement Benefits—Components of net periodic postretirement benefit cost for health insurance benefits for retired OTP and corporate employees, net of the effect of Medicare Part D Subsidy:

  

Three Months Ended

September 30,

  

Nine Months Ended

September 30,

 

(in thousands)

 

2020

  

2019

  

2020

  

2019

 

Service Cost—Benefit Earned During the Period

 $461  $321  $1,385  $964 

Interest Cost on Projected Benefit Obligation

  598   770   1,795   2,312 

Amortization of Prior-Service Cost:

                

From Regulatory Asset

  (1,169)  0   (3,508)  0 

From Other Comprehensive Income1

  (28)  0   (86)  0 

Amortization of Net Actuarial Loss:

                

From Regulatory Asset

  1,051   393   3,154   1,178 

From Other Comprehensive Income1

  26   10   78   29 

Net Periodic Postretirement Benefit Cost2

 $939  $1,494  $2,818  $4,483 

Effect of Medicare Part D Subsidy

 $281  $(45) $842  $(134)

1Corporate cost included in nonservice cost components of postretirement benefits.

                

2Allocation of Costs:

                

Service costs included in OTP capital expenditures

 $144  $78  $382  $248 

Service costs included in electric operation and maintenance expenses

  306   235   970   693 

Service costs included in other nonelectric expenses

  11   8   33   23 

Nonservice costs capitalized as regulatory assets

  150   284   396   905 

Nonservice costs included in nonservice cost components of postretirement benefits

  328   889   1,037   2,614 

12. Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Cash EquivalentsEquivalents: The carrying amount approximates fair value because of the short-term maturity of those instruments.

Short-Term DebtDebt: The carrying amount approximates fair value because the debt obligations are short-term and the balances outstanding as of September 30, 2020 and December 31, 2019 related to the Otter Tail Corporation Credit Agreement wereare subject to variable interest rates of LIBOR plus 1.50%,interest which approximate market rates.

reset frequently, a Level 2 fair value input.

Long-Term Debt including Current MaturitiesDebt: The fair value of the Company's and OTP’s long-term debt is estimated based on the current market indications for borrowings of rates available tosimilar maturities, a Level 2 fair value input.
19

ITEM 2.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the Companyfollowing discussion and analysis of our financial condition and results of operations together with our interim financial statements and the related notes appearing under Item 1 of this Quarterly Report on Form 10-Q, and our annual financial statements and the related notes along with the discussion and analysis of our financial condition and results of operations contained in our Annual Report on Form 10-K for the issuance of debt. The fair value measurements of the Company’s long-term debt issues fall into level 2 of the fair value hierarchy set forth in ASC 820.

  

September 30, 2020

  

December 31, 2019

 

(in thousands)

 

Carrying

Amount

  

Fair Value

  

Carrying

Amount

  

Fair Value

 

Cash and Cash Equivalents

 $44,904  $44,904  $21,199  $21,199 

Short-Term Debt

  (48,600)  (48,600)  (6,000)  (6,000)

Long-Term Debt including Current Maturities

  (764,489)  (867,972)  (689,764)  (742,279)

13. Property, Plant and Equipment

No update required for interim reporting period.

32

14. Income Tax Expense

The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income before income taxes and income tax expense reported on the Company’s consolidated statements of income for the three- and nine-month periodsyear ended September 30, 2020 and 2019:

  

Three Months Ended

September 30,

  

Nine Months Ended

September 30,

 

(in thousands)

 

2020

  

2019

  

2020

  

2019

 

Income Before Income Taxes

 $45,031  $29,681  $95,726  $80,402 

Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%)

 $11,708  $7,717  $24,889  $20,905 

(Decreases) Increases in Tax from:

                

Differences Reversing in Excess of Federal Rates

  (1,678)  (933)  (3,450)  (2,690)

Allowance for Funds Used During Construction – Equity

  (388)  (239)  (948)  (419)

North Dakota Wind Tax Credit Amortization – Net of Federal Taxes

  (259)  (258)  (775)  (774)

Research and Development and Other Tax Credits

  (263)  (612)  (649)  (987)

Excess Tax Deduction – Equity Method Stock Awards

  0   0   (535)  (827)

Corporate Owned Life Insurance

  (155)  (50)  (141)  (609)

Reconciliation and Prior Period Adjustments

  172   (688)  172   (722)

Other Items – Net

  (40)  (1)  (20)  30 

Income Tax Expense

 $9,097  $4,936  $18,543  $13,907 

Effective Income Tax Rate

  20.2%  16.6%  19.4%  17.3%

The following table summarizes the activity related to the Company’s unrecognized tax benefits:

(in thousands)

 

2020

  

2019

 

Balance on January 1

 $1,488  $1,282 

(Decreases) Increases Related to Tax Positions for Prior Years

  (27)  37 

Increases Related to Tax Positions for Current Year

  123   153 

Uncertain Positions Resolved During Year

  (586)  0 

Decrease from the Expiration of Statute of Limitations

  (139)  (170)

Balance on September 30

 $859  $1,302 

The balance of unrecognized tax benefits as of September 30, 2020 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of September 30, 2020 could be reduced by as much as $139,000 within the next 12 months due to expected settlement. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes in its consolidated statement of income.

The CompanyDecember 31, 2020.

Otter Tail Corporation and its subsidiaries fileform a consolidated U.S. federal income tax returndiverse group of businesses with operations classified into three segments: Electric, Manufacturing and various state income tax returns. As of November 1, 2020, Plastics. Our Electric business is a vertically integrated, regulated utility with limited exceptions, the Company is no longer subjectgeneration, transmission and distribution facilities to examinations by taxing authorities for tax years prior to 2017 for federal andserve our customers in western Minnesota, eastern North Dakota income taxes and prior to 2016northeastern South Dakota. Our Manufacturing segment provides metal fabrication for Minnesota income taxes.

33

Item 2.      Management's Discussioncustom machine parts and Analysis of Financial Conditionmetal components and Results of Operations

COVID-19

Otter Tail Corporation (the Company, we, usmanufactures extruded and our) continuesthermoformed plastic products. Our Plastics segment manufactures PVC pipe for use in, among other applications, municipal and rural water, wastewater, and water reclamation projects.

COVID-19
We continue to monitor the progression of the novel coronavirus disease 2019 (COVID-19) and its impact on our businesses, employees, customers, construction contractors and vendors. As this pandemic continues, we are following the directives and advice of government leaders and medical professionals and have adopted practices to help curtail the spread of the virus and mitigate its impact on our communities, employees, construction contractors, customers and business operations. Our Electric segment business provides a critical service to our customers and our manufacturing platform businesses provide products and support to critical infrastructure industries. All of our operating companies have been deemed critical infrastructure businesses. Accordingly, we continue to operate our businesses
Beginning in a manner that is safe for our employees and our customers.

March 2020, COVID-19 and the resulting economic conditions have had a material negative impact on thenegatively impacted operating results of operations in our Manufacturing segment as customer demand declined significantly in the second quarter of 2020. Sales volumes strengthened in the third and fourth quarters of 2020 due to a lesser extent, also impacted the results of operations of ourstrong recreational vehicle and lawn and garden end-market demand. Our Electric and Plastics segments but have not had a material impact on our consolidated financial position or liquidity. We saw a reductionoperating results were also impacted in customer demand in our Manufacturing segment in late March 2020 and experienced significantly lower levels of customer demand in our Manufacturing segment through the end of June 2020 but began to see some recovery in demand in the third quarter of 2020. A moderate level of reduced demand may continue in our Manufacturing segment over the near term. Within our Electric segment, we have experienced reduced demand from commercial and industrial customers.customers and increased costs for bad debts. In our Plastics segment, we experienced lower sales volumes in the second quarter of 2020 as distributors of our products reduced inventory levels given the uncertainty of the potential impact of COVID-19. Sales volumes recovered and gross profit margins increased in the third and fourth quarters of 2020, and have continued to increase in 2021, due to uncertainty over theincreased demand and supply disruptions.

The impact of COVID-19 but experiencedand the resulting macroeconomic conditions on our business and financial results began to ease in the first quarter of 2021 and continued to do so through the third quarter of 2021. However, uncertainty remains regarding the magnitude and duration of the pandemic and resulting financial effects. Increased infection rates and any future responses to mitigate the spread of the virus, including any potential vaccination mandates that would apply to our employees, could impact our business and our financial results in future periods.
Recently, the Department of Labor’s Occupational Safety and Health Administration (“OSHA”) drafted an emergency temporary standard requiring all employers with at least 100 employees to ensure their employees are fully vaccinated or require weekly testing for unvaccinated employees. On October 12, 2021, OSHA sent a recoverydraft of the standard to the White House regulatory office for approval and it is anticipated to be acted upon soon. Additionally, President Biden issued an executive order on September 9, 2021, which requires employees of certain federal contractors and covered subcontractors to be vaccinated, with no weekly testing option, unless they have an approved disability or religious exemption. We expect one, or both, of these new regulations will apply to at least some, and possibly all, of our businesses. The exact impact the new regulations could have on our companies is uncertain at this time. However, it could result in salesemployee attrition, difficulty fulfilling future labor needs, additional costs related to compliance and may have an adverse effect on our future operating results.
We continue to monitor developments involving our workforce, customers, construction contractors, suppliers and vendors and the financial effects on our business. However, due to the unprecedented and evolving nature of this pandemic, we cannot predict the full extent of the impact COVID-19 will have on our operating results, financial condition and liquidity.
RESOURCE MATERIAL AVAILABILITY AND PRICING
Supply shortages of steel and resin, two key material inputs to our Manufacturing and Plastics segments, respectively, have impacted our operating results in 2021.
Steel supply shortages arose primarily due to steel mill capacity reductions in 2020 in response to lower steel demand due to COVID-19. Production and availability of steel have begun to improve as steel mill facilities have increased marginsproduction capacities in response to strong market demand for steel products. The combination of steel supply shortages and strong demand has led to significantly increased steel prices. The increase in steel prices has led to increased sale prices for our products at BTD, our metal fabrication business within our Manufacturing segment, as we pass along material cost increases to our customers. In addition, limited steel availability has led to increased complexity in managing our business, including our production schedules, and other increased costs. We anticipate increased steel prices will continue throughout the remainder of 2021 and into 2022.
Resin shortages initially arose as a result of production plant shutdowns due to abnormally low temperatures and ice storms in the Gulf Coast region of the United States in the first quarter of 2021 and have been exacerbated by hurricane activity in the third quarter of the year. These supply constraints, along with robust domestic and global demand for PVC resin, have led to significantly increased resin prices. The increase in the price of resin, the primary material input into the PVC pipe manufactured by our Plastics segment businesses, along with strong customer demand for PVC pipe and low pipe inventories, due to higherthe resin supply constraints, have led to rapidly increased sales prices for PVC pipepipe. The increase in sale prices relativehas outpaced the increase in resin costs, leading to lower-cost inventory.

Beginning in April 2020, in response to the actualexpanding gross profit margins and anticipated impact of COVID-19 on our business operations, we implemented a variety of policies, including furloughs, shift and pay reductions, wage and hiring freezes, suspension of certain employee benefits, a workforce reduction and other cost reduction efforts to mitigate the negative impact to our financial results. We continue to monitor the impacts of the pandemic on our businesses and will adjust our response as circumstances evolve.

Financial And OTHER metrics USED IN THE FOLLOWING DISCUSSION

Heating Degree Days (HDDs) is a measure of how much (in degrees), and for how long (in days), the outside air temperature was below a certain normalized level. This measure is commonly used in calculations relating to the energy consumption required to heat buildings.

Cooling Degree Days (CDDs) is a measure of how much (in degrees), and for how long (in days), the outside air temperature was above a certain normalized level. This measure is commonly used in calculations relating to the energy consumption required to cool buildings.

Otter Tail Power Company (OTP) generally bases its forecasted kilowatt-hour (kwh) sales and rates on expected consumption under a normal level of HDDs and CDDs over a given period of time in its service territory. Increased or decreased levels of consumption for certain customer classifications are attributed to deviation from the norms and are a significant factor influencing consumptionincrease in net earnings in our Plastics segment. We anticipate these market dynamics will persist through the remainder of electricity across our service territory.2021 and continue during the first half of 2022. We present HDDs and CDDscurrently expect these conditions to provide an indication of the impact of weather on kwh sales, revenues and earnings relative to forecast and on period-to-period results.

Backlog, expressed in dollars, is the level of sales orders received but not yet completed by a company or operating segment. The Company discloses these figures for its Manufacturing segment as an indication of future business volume within the segment.

Utility Rate Base is the value of property on which a public utility is permitted to earn a specified rate of return in accordance with rules set by a regulatory agency. In general, the rate base consists of the value of property used by the utility in providing service. Rate base can include: cash, working capital, materials and supplies, deductions for accumulated provisions for depreciation, contributions in aid of construction, customer advances for construction, accumulated deferred income taxes, and accumulated deferred investment tax credits, dependent on the method that is usedsubside beginning in the calculation,second half of 2022.

The marketplace dynamics impacting both our Manufacturing and Plastics segments are fluid and subject to change which can vary from jurisdiction to jurisdiction. The Company presents actual and forecasted levels of utility rate base in its outlook to provide an indication of expected investments on which the Company expects to earn future returns.

may impact our operating results prospectively.
3420


RESULTS OF OPERATIONS – QUARTER TO DATE

Results

Provided below is a summary and discussion of Operations

Following is an analysis of the Company’sour operating results by business segment for the three and nine months ended September 30, 2020 and 2019on a consolidated basis followed by a discussion of changes inthe operating results of each of our segments: Electric, Manufacturing and Plastics. In addition to the segment results, we provide an overview of our Corporate costs. Our Corporate costs do not constitute a reportable segment but rather consist of unallocated general corporate expenses, such as corporate staff and overhead costs, the results of our captive insurance company and other items excluded from the measurement of segment performance. Corporate costs are added to operating segment totals to reconcile to totals on our consolidated financial position during the nine months ended September 30,statements of income.

Intersegment transactions were not material in 2021 or 2020 and our business outlook for the remainderamounted to less than $0.1 million of 2020.

Comparison of the Three Months Ended September 30, 2020 and 2019

Consolidated operating revenues were $235.8 millionand operating expenses for each period.

CONSOLIDATED RESULTS    
The following table summarizes consolidated operating results for the three months ended September 30, 2021 and 2020:
(in thousands)20212020$ change% change
Operating Revenues$316,294 $235,755 $80,539 34.2 %
Operating Expenses241,766 183,026 58,740 32.1 
Operating Income74,528 52,729 21,799 41.3 
Interest Charges9,648 8,568 1,080 12.6 
Nonservice Cost Components of Postretirement Benefits505 842 (337)(40.0)
Other Income203 1,712 (1,509)(88.1)
Income Before Income Taxes64,578 45,031 19,547 43.4 
Income Tax Expense11,824 9,097 2,727 30.0 
Net Income$52,754 $35,934 $16,820 46.8 %
Operating Revenues increased $80.5 million primarily due to rising PVC pipe prices and increased sales volumes within our Plastics segment and increased volumes and material cost, leading to increased sales prices, in our Manufacturing segment. Increased transmission services and wholesale revenues, partially offset by decreased retail revenues, within our Electric segment also contributed to higher operating revenues in the third quarter of 2021 compared to the same period last year. See our segment disclosures below for additional discussion of items impacting operating revenues.
Operating Expenses increased $58.7 million primarily due to increased costs of products sold in our Manufacturing and Plastics segments due to increased raw material costs and higher sales volumes, as well as increased labor costs. Operating expenses in our Electric segment increased primarily due to higher depreciation and amortization expense arising from our recent rate base investments and higher operating and maintenance expenses. See our segment disclosures below for additional discussion of items impacting operating expenses.
Interest Charges increased $1.1 million due to interest expense from our $40.0 million long-term debt issuance in August 2020, a higher level of short-term borrowings outstanding in 2021 compared with $228.7to 2020 and a decrease in capitalized interest in 2021 following the completion and placement in service of Astoria Station in the first quarter of 2021.
Other Income decreased $1.5 million primarily due to lower earned equity AFUDC due to the completion and placement in-service of Astoria Station in the first quarter of 2021. During the construction of Astoria Station we earned AFUDC in our Minnesota jurisdiction.
Income Tax Expense increased $2.7 million primarily due to increased income before income taxes. Our effective tax rate was 18.3% in the third quarter of 2021 and 20.2% in the third quarter of 2020. The decrease in our effective tax rate was driven by PTCs earned in the third quarter of 2021 from our Merricourt wind farm, which was placed in service in the fourth quarter of 2020, partially offset by other permanent differences. See Note 8 to our consolidated financial statements included in this Quarterly Report on Form 10-Q for additional information regarding factors impacting our effective tax rate in 2021 and 2020.
21

ELECTRIC SEGMENT RESULTS
The following table summarizes Electric segment operating results for the three months ended September 30, 2019. Operating income was $52.7 million2021 and 2020:
(in thousands)20212020$ change% change
Retail Revenues$96,438 $99,605 $(3,167)(3.2)%
Transmission Services Revenues13,300 12,288 1,012 8.2 
Wholesale Revenues6,944 1,500 5,444 362.9 
Other Electric Revenues2,093 1,830 263 14.4 
Total Operating Revenues118,775 115,223 3,552 3.1 
Production Fuel17,698 11,554 6,144 53.2 
Purchased Power9,878 13,428 (3,550)(26.4)
Operating and Maintenance Expenses36,465 32,845 3,620 11.0 
Depreciation and Amortization17,874 15,647 2,227 14.2 
Property Taxes4,474 4,333 141 3.3 
Operating Income$32,386 $37,416 $(5,030)(13.4)%
20212020change% change
Electric kilowatt-hour (kwh) Sales (in thousands)
  
Retail kwh Sales1,076,580 1,075,336 1,244 0.1 %
Wholesale kwh Sales – Company Generation174,187 75,884 98,303 129.5 
Heating Degree Days3 61 (58)(95.1)
Cooling Degree Days463 363 100 27.5 
The operating results of our Electric segment are impacted by fluctuations in weather conditions and the resulting demand for the three months ended September 30, 2020 compared with $37.3 millionelectricity for the three months ended September 30, 2019. The Company recorded diluted earnings per share of $0.87 for the three months ended September 30, 2020 compared with $0.62 for the three months ended September 30, 2019.

Amounts presented in the segment tables that follow for operating revenues, cost of products soldheating and other nonelectric operating expenses for the three-month periods ended September 30, 2020 and 2019 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:

Intersegment Eliminations (in thousands)

 

September 30, 2020

  

September 30, 2019

 

Operating Revenues:

        

Electric

 $10  $9 

Nonelectric

  --   -- 

Costs of Products Sold

  3   5 

Other Nonelectric Expenses

  7   4 

Electric

  

Three Months Ended

         
  

September 30,

      

%

 

(in thousands)

 

2020

  

2019

  

Change

  

Change

 

Retail Sales Revenues from Contracts with Customers

 $96,827  $100,345  $(3,518)  (3.5)

Changes in Accrued Revenues under Alternative Revenue Programs

  2,778   (921)  3,699   401.6 

Total Retail Sales Revenue

 $99,605  $99,424  $181   0.2 

Transmission Services Revenue

  12,288   11,692   596   5.1 

Wholesale Revenues – Company Generation

  1,500   1,631   (131)  (8.0)

Other Revenues

  1,830   1,626   204   12.5 

Total Operating Revenues

 $115,223  $114,373  $850   0.7 

Production Fuel

  11,554   18,331   (6,777)  (37.0)

Purchased Power – System Use

  13,428   13,163   265   2.0 

Electric Operation and Maintenance Expenses

  32,845   35,869   (3,024)  (8.4)

Depreciation and Amortization

  15,647   15,198   449   3.0 

Property Taxes

  4,333   3,965   368   9.3 

Operating Income

 $37,416  $27,847   9,569   34.4 

Electric Megawatt-hour (mwh) Sales

                

Retail mwh Sales

  1,075,336   1,091,427   (16,091)  (1.5)

Wholesale mwh Sales – Company Generation

  75,884   71,506   4,378   6.1 

HDDs

  61   42   19   45.2 

CDDs

  363   288   75   26.0 

cooling. The following table shows heating and cooling degree days as a percent of normal:

  

Three Months ended September 30,

 
  

2020

  

2019

 

HDDs

  115.1%  76.4%

CDDs

  104.6%  83.0%

normal for the three months ended September 30, 2021 and 2020.
 20212020
Heating Degree Days5.8 %115.1 %
Cooling Degree Days132.7 %104.6 %
35

The following table summarizes the estimated effect on diluted earnings per share of the difference in retail kwh sales under actual weather conditions and expected retail kwh sales under normal weather conditions in 2021 and 2020, and between years.

 
2021 vs
Normal
2021 vs
2020
2020 vs
Normal
Effect on Diluted Earnings Per Share$0.03 $0.02 $0.01 
Retail Revenues decreased $3.2 million primarily due to the following:
The recognition of $2.6 million of Minnesota transmission rider revenue in the third quartersquarter of 2020 resulting from a favorable judicial decision regarding the state jurisdictional treatment of federally approved transmission projects.
A $1.2 million decrease in fuel recovery revenues largely due to lower purchased power costs and 2019credits provided to retail customers from increased margins on wholesale sales, but partially offset by increased recovery of higher production fuel costs.
A decrease in revenue from the combination of reduced demand from residential and between quarters:

  

2020 vs Normal

  

2019 vs Normal

  

2020 vs 2019

 

Effect on Diluted Earnings Per Share

 $0.01  $(0.02) $0.03 

The $0.2commercial and industrial customers, exclusive of the impact of weather, net of the effect of a change in customer usage mix.

These decreases in revenue were partially offset by a $1.2 million increase in retailconsumption from the favorable impact of weather in the third quarter of 2021 compared to the same period last year.
Transmission Services Revenues increased $1.0 million primarily due to increased generator interconnection revenues.
Wholesale Revenues increased $5.4 million as a result of a 129.5% increase in wholesale sales revenue includes:

A $3.3 millionvolumes and a 101.7% increase in Minnesota and North Dakota Renewable Resource Adjustment (RRA) Rider revenues related to earning a return on funds invested in the Merricourt Wind Energy Center (Merricourt) while the project is under construction.

A $2.1 million increase in Transmission Cost Recovery (TCR) revenues, mainly due to the recognition of Minnesota TCR Rider revenues resulting from a favorable decision regarding the state jurisdictional treatment of federally approved transmission rate incentives.

A $1.5 million increase in retail revenues mainly related to increased residential kwh consumption due to favorable weather impacts in the third quarter of 2020 compared to the third quarter of 2019.

A $1.1 million increase in revenues from the North Dakota Generation Cost Recovery (GCR) Rider which went into effect in July 2019 to provide a return on funds invested in Astoria Station while the generation project is under construction.

These increases in revenue were mostly offset by:

A $6.6 million decrease in retail revenue related to the recovery of decreased fuel and purchased power costs to serve retail customers. Fuel costs decreased as a result of a 24.0% decrease in kwhs generated at OTP's fuel-burning power plants, but also as a result of a 37.9% decrease in the cost of fuel per kwh generated at Coyote Station related to higher-cost coal burned in the third quarter of 2019 due to the absorption of mine operating costs in inventory during Coyote Station's second quarter 2019 maintenance shutdown.

A $1.2 million decrease in revenue due to decreased kwh sales to commercial and industrial customers, mainly due to COVID-19-related impacts in the third quarter of 2020.

Transmission services revenuewholesale prices driven by increased $0.6fuel costs and market demand for wholesale energy.

Production Fuel costsincreased $6.1 million mainly due to anas a result of a 41.4% increase in facility service agreement revenues related to transmission upgrades made to accommodate independent generator access to the transmission grid.

Production fuel costs decreased $6.8 million due to a 24.0% decrease in kwhs generated from our fuel-burning plants due to higher demand and a 21.7% decreasefavorable prices for energy in wholesale markets. In addition, increased fuel cost per kwh of generation, weighted heavily byalso contributed to higher production fuel costs per kwh of generation at Coyote Station in the third quarter of 2019. Coyote Station was down for maintenance2021.

Purchased Power costs to serve retail customers decreased $3.6 million primarily due to a 48.9% decrease in the second quartervolume of 2019purchased power as our recent capacity additions provide additional generation resources to serve customer demand and minemarket conditions led to operating costs incurred duringour
22

existing facilities at higher capacity factors in lieu of purchasing power at higher market prices, but partially offset by an increase in the second quarter and absorbed in inventory were expensed as fuel costs when Coyote Station resumed operationscost of purchased power per kwh in the third quarter of 2019.

The cost2021.

Operating and MaintenanceExpense increased $3.6 million mainly due to:
$1.4 million of purchased power to serve retail customers increased $0.3Merricourt and Astoria Station operating and maintenance expenses incurred in the third quarter of 2021 as these facilities are now commercially operational.
$2.1 million as a result of maintenance costs arising from our planned outage at Big Stone plant, which began in the third quarter of 2021 and we expect will be completed in the fourth quarter of the year.
Other additional expenses include an 18.7% increase in kwh purchases, mostlytransmission tariff expense from higher transmission volumes and increased travel costs as business travel recovers from the impact of COVID-19.
These expense increases were partially offset by, a 14.1% decreaseamong other items, lower operating costs following the closure of Hoot Lake Plant in May 2021 and lower bad debt expense due to improving customer collections as the economic impact of COVID-19 has eased.
Depreciation and Amortization expense increased $2.2 million primarily due to Merricourt and Astoria Station being placed in service in the cost per kwh purchased.fourth quarter of 2020 and the first quarter of 2021, respectively.
MANUFACTURING SEGMENT RESULTS
The following table summarizes Manufacturing segment operating results for the three months ended September 30, 2021 and 2020:
(in thousands)20212020$ change% change
Operating Revenues$89,977 $59,849 $30,128 50.3 %
Cost of Products Sold (excluding depreciation)70,148 44,444 25,704 57.8 
Other Operating Expenses10,161 6,901 3,260 47.2 
Depreciation and Amortization3,794 3,759 35 0.9 
Operating Income$5,874 $4,745 $1,129 23.8 %
Operating Revenues increased $30.1 million primarily due to a 41.3% increase in material costs at BTD, which is passed through to customers, as steel prices increased significantly from the previous year. Steel prices have increased as steel mill production has not matched customer demand as mill capacity recovers from shutdowns in 2020 resulting from the COVID-19 pandemic. A 4.0% increase in sales volumes and an increase in scrap revenues, primarily due to higher scrap metal prices, also contributed to the increase in operating revenues. We anticipate steel prices will remain elevated for the remainder of 2021 and into 2022. Increased horticultural product sales volumes at T.O. Plastics in 2021, driven by increasing customer demand, as well as increased sales prices also contributed to increased operating revenues in 2021 as compared to 2020.
Cost of Products Sold increased $25.7 million primarily due to increased volumes and higher material, labor and freight costs at BTD. The increase in purchased power volumematerial cost is largely driven by increased steel prices as mentioned above. The increases in labor and freight costs and lower productivity resulted in lower gross profit margins compared to the same period in 2020. Lower productivity during the period was a functionprimarily the result of reduced generation at Big Stone Plant, which went offline for scheduled maintenancerecent increases in September 2020,headcount and the availability of low-priced energy intime required for new employee to achieve peak productivity. Increased sales volumes and production activity at T.O. Plastics also contributed to the wholesale market. The decrease in purchased power prices was driven mainly by low prices for natural gas-fired generation.

Electric operating and maintenance expense decreased $3.0 million, including:

A $1.0 million decrease in labor and benefit costs due to an increase in capitalized labor related to an increase in construction activity and decreases in corporate overhead and performance incentive costs.

A $0.9 million decrease in transmission tariff expenses related to decreased rates.

A $0.6 million decrease in Hoot Lake Plant external services costs related to Unit 2 turbine maintenance repairs completed in the third quarter of 2019.

A $0.5 million decrease in tree-trimming and vegetation maintenance expenses.

A $0.5 million decrease in travel-related expenses related to Covid-19 travel restrictions.

These decreases in expense were partially offset by:

A $0.4 million increase in customer bad debt expense provisions, mainly due to adoption of Covid-19-related service suspension and debt collection policies.

Property tax expense increased $0.4 million due to property additions and increased jurisdictional valuations.

Depreciation expense increased $0.4 million mainly due to 2019 capital additions for generation and transmission plant.

Manufacturing

  

Three Months Ended

         
  

September 30,

      

%

 

(in thousands)

 

2020

  

2019

  

Change

  

Change

 

Operating Revenues

 $59,849  $65,722  $(5,873)  (8.9)

Cost of Products Sold

  44,444   51,399   (6,955)  (13.5)

Operating Expenses

  6,901   6,846   55   0.8 

Depreciation and Amortization

  3,759   3,505   254   7.2 

Operating Income

 $4,745  $3,972  $773   19.5 

The $5.9 million decrease in revenues in our Manufacturing segment includes the following:

Revenues at BTD Manufacturing, Inc. (BTD) decreased $5.4 million between quarters, driven by a $4.1 million decline in prices of materials passed through to customers and $1.3 million in decreased sales volumes. The decrease in sales volumes primarily resulted from lower parts sales to construction and industrial equipment manufacturers, partially offset by increased parts sales to recreational vehicle, agricultural and lawn and garden equipment manufacturers. Increases in parts revenue related to favorable product pricing were offset by lower tooling and scrap revenues.

Revenues at T.O. Plastics, Inc. (T.O. Plastics), our manufacturer of thermoformed plastic and horticultural products, decreased $0.5 million, mainly due to market softness generated by the uncertainty of how COVID-19 was going to impact these end markets.

The $7.0 million decrease in cost of products sold in our Manufacturing segment includes the following:

Cost of products sold at BTD decreased $6.62021.

Other Operating Expenses increased $3.3 million mainly as a result of the $4.1 million in lower material costs passed through to customers but also due to improved productivity and the decrease in sales volume.

Cost of products sold at T.O. Plastics decreased $0.3 million related to the decrease in sales volume.

Plastics

  

Three Months Ended

         
  

September 30,

      

%

 

(in thousands)

 

2020

  

2019

  

Change

  

Change

 

Operating Revenues

 $60,693  $48,566  $12,127   25.0 

Cost of Products Sold

  42,415   37,353   5,062   13.6 

Operating Expenses

  3,250   2,872   378   13.2 

Depreciation and Amortization

  905   865   40   4.6 

Operating Income

 $14,123  $7,476  $6,647   88.9 

Plastics segment revenues and operating income increased $12.1 million and $6.6 million, respectively, primarily due to a 21.2% increase in pounds of polyvinyl chloride (PVC) pipe sold driven by distributors rebuilding inventory in the third quarter of 2020 after reducing inventory levels2021 compared to 2020. In the third quarter of 2021 other operating expenses were impacted by increased incentive based compensation and other costs necessary to support higher business volumes.

PLASTICS SEGMENT RESULTS
The following table summarizes Plastics segment operating results for the three months ended September 30, 2021 and 2020:
(in thousands)20212020$ change% change
Operating Revenues$107,542 $60,693 $46,849 77.2 %
Cost of Products Sold (excluding depreciation)64,064 42,415 21,649 51.0 
Other Operating Expenses3,832 3,250 582 17.9 
Depreciation and Amortization1,099 905 194 21.4 
Operating Income$38,547 $14,123 $24,424 172.9 %
Operating Revenues increased $46.8 million, primarily due to a 103.6% increase in the second quarter of 2020 due to uncertainty over the impact of COVID-19 on sales. Cost of products sold increased $5.1 million due to the increase in sales volume, partially offset by a 6.3% decrease in the costprice per pound of PVC pipe sold. The decreaseincrease in sale prices was largely due to the combination of PVC resin supply constraints, which has led to limited PVC pipe inventory, and strong demand for PVC pipe products. Resin supply in the cost per poundthird quarter of PVC2021 was negatively impacted by disruptions caused by Hurricane Ida in the Gulf Coast region, which compounded supply constraints that began in the first quarter of 2021 as a result of plant shutdowns caused by extreme winter weather. Pounds of pipe sold isin the third quarter of 2021 decreased 13.0% from the same period last year. We anticipate sales prices will remain elevated throughout the remainder of 2021 and into 2022, as resin suppliers work to fulfill purchase allotments and pipe manufacturers continue to replenish depleted inventories while customer demand remains strong.
Cost of Products Sold increased $21.6 million primarily due to lowerincreased PVC resin and other input material input costs. The $0.4 millioncosts per pound, which increased 91.7% compared to the same period in the previous year. Increases in labor and freight costs in 2021 also contributed to the increase in segment operating expenses is mainly due to increased employee benefit costs.

cost of products sold.

CorporateOther Operating Expenses

Corporate includes items such increased $0.6 million as corporate staff and overhead costs, the resultsa result of our captive insurance company and other items excluded from the measurement of operating segment performance. Corporate is not an operating segment. Rather it is added to operating segment totals to reconcile to totals on our consolidated statements of income.

  

Three Months Ended

         
  

September 30,

      

%

 

(in thousands)

 

2020

  

2019

  

Change

  

Change

 

Operating Expenses

 $3,471  $1,951  $1,520   77.9 

Depreciation and Amortization

  84   89   (5)  (5.6)

The $1.5 million increase in corporate operating expenses is mainly due to an increase in performance incentive accruals driven by improved quarter-over-quarter results.

Interest Charges

Interest chargesvariable costs associated with the increased to $8.6 millionfinancial results in 2021.

CORPORATE COSTS
The following table summarizes Corporate operating results for the three months ended September 30, 2020 from $7.52021 and 2020:
(in thousands)20212020$ change% change
Other Operating Expenses$2,231 $3,471 $(1,240)(35.7)%
Depreciation and Amortization48 84 (36)(42.9)
Operating Loss$2,279 $3,555 $(1,276)(35.9)%
Other Operating Expenses decreased $1.2 million in the three months ended September 30, 2019. The $1.1 million increase in interest charges is primarily due to an increasedecreased stock and incentive based compensation cost as a result of the timing of expense recognition, which can fluctuate due to changes in interest expense at OTP relatedestimates of annual financial performance relative to debt issuances of $100 milliontargeted amounts.
RESULTS OF OPERATIONS – YEAR TO DATE
Intersegment transactions were not material in October of 2019, $35 million in February of2021 or 2020 and $40amounted to less than $0.1 million in August 2020 under OTP’s 2019 Note Purchase Agreement.

Other Income

Other income increased to $1.7 million in the three months ended September 30, 2020 from $1.0 million in the three months ended September 30, 2019. The $0.7 million increase in other income includes:

A $0.3 million increase in allowance for equity funds used during construction at OTP mostly related to the Minnesota share of construction work in progress on OTP’s Astoria Station project.

A $0.2 million increase in the cash surrender value of corporate-owned life insurance policies held by the Company.

A $0.1 million decrease in unrealized losses on equity investments held by our captive insurance company, Otter Tail Assurance Limited, in the third quarter of 2020.

Income Tax Expense

Income tax expense increased $4.2 million in the three months ended September 30, 2020 compared with the three months ended September 30, 2019, mainly due to the tax effect of a $15.3 million increase in income before income taxes. operating revenues and operating expenses for each period.

CONSOLIDATED RESULTS
The following table provides a reconciliation of income tax expense calculated at our net composite federal and state statutory rate on income before income taxes on oursummarizes consolidated statements of income.

  

Three Months Ended

September 30,

 

(in thousands)

 

2020

  

2019

 

Income Before Income Taxes

 $45,031  $29,681 

Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%)

 $11,708  $7,717 

(Decreases) Increases in Tax from:

        

Differences Reversing in Excess of Federal Rates

  (1,678)  (933)

Allowance for Funds Used During Construction – Equity

  (388)  (239)

Research and Development and Other Tax Credits

  (263)  (612)

North Dakota Wind Tax Credit Amortization – Net of Federal Taxes

  (259)  (258)

Corporate Owned Life Insurance

  (155)  (50)

Reconciliation and Prior Period Adjustments

  172   (688)

Other Items – Net

  (40)  (1)

Income Tax Expense

 $9,097  $4,936 

Effective Income Tax Rate

  20.2%  16.6%

Comparison of the Nine Months Ended September 30, 2020 and 2019

Consolidated operating revenues were $663.3 millionresults for the nine months ended September 30, 2021 and 2020:
(in thousands)20212020$ change% change
Operating Revenues$863,612 $663,258 $200,354 30.2 %
Operating Expenses685,063 543,331 141,732 26.1 
Operating Income178,549 119,927 58,622 48.9 
Interest Charges28,601 25,353 3,248 12.8 
Nonservice Cost Components of Postretirement Benefits1,511 2,581 (1,070)(41.5)
Other Income2,095 3,733 (1,638)(43.9)
Income Before Income Taxes150,532 95,726 54,806 57.3 
Income Tax Expense25,380 18,543 6,837 36.9 
Net Income$125,152 $77,183 $47,969 62.1 %

Operating Revenues increased $200.4 million primarily due to higher PVC pipe prices within our Plastics segment and increased volumes and material costs, leading to higher sales prices, in our Manufacturing segment. Increased transmission services and wholesale revenues within our Electric segment also contributed to the higher operating revenues in 2021. See our segment disclosures below for additional discussion of items impacting operating revenues.
Operating Expenses increased $141.7 million in 2021 primarily due to increased costs of products sold in our Plastics and Manufacturing segments due to higher raw material costs and sales volumes. Operating expenses in our Electric segment increased primarily from higher operating and maintenance and depreciation and amortization expenses, in each case largely the result of our recent rate base investments and the associated operating costs of such investments. See our segment disclosures below for additional discussion of items impacting operating expenses.
Interest Charges increased $3.2 million in 2021 due to a debt issuance in our Electric segment in the third quarter of 2020, increased outstanding borrowings under our short-term debt arrangements, both of which were largely used to finance rate base investments in our Electric segment, and a decrease in capitalized interest in 2021 due to the completion and placement in service of Astoria Station in the first quarter of 2021.
Nonservice Cost Components of Postretirement Benefits decreased $1.1 million in 2021 due to a change in how prescription drug coverage is provided to retirees and the impact of nonservice costs from a decrease in the discount rate from 2020 to 2021.
Other Income decreased $1.6 million in 2021 due to a $2.7 million decrease in earned equity AFUDC due primarily to the completion and placement in service of Astoria Station in the first quarter of 2021, but partially offset by increases in the values of corporate-owned life insurance policies and other investments in 2021 compared to 2020.
Income Tax Expense increased $6.8 million in 2021 primarily due to increased income before income taxes. Our effective tax rate was 16.9% in 2021 and 19.4% in 2020 with $703.8 millionthe decrease primarily driven by PTCs earned in 2021 from our Merricourt wind farm, which was placed in service in the fourth quarter of 2020. See Note 8 to our consolidated financial statements included in the report on Form 10-Q for additional information regarding factors impacting our effective tax rate.
24

ELECTRIC SEGMENT RESULTS
The following table summarizes Electric segment operating results for the nine months ended September 30, 2019. Operating income was $119.9 million2021 and 2020:
(in thousands)20212020$ change% change
Retail Revenues$291,130 $291,761 $(631)(0.2)%
Transmission Services Revenues37,085 32,802 4,283 13.1 
Wholesale Revenues14,711 3,141 11,570 368.4 
Other Electric Revenues5,703 5,548 155 2.8 
Total Operating Revenues348,629 333,252 15,377 4.6 
Production Fuel44,576 34,077 10,499 30.8 
Purchased Power40,273 45,940 (5,667)(12.3)
Operating and Maintenance Expenses114,615 106,639 7,976 7.5 
Depreciation and Amortization53,335 47,063 6,272 13.3 
Property Taxes13,136 12,601 535 4.2 
Operating Income$82,694 $86,932 $(4,238)(4.9)%
Electric kilowatt-hour (kwh) Sales (in thousands)
  
Retail kwh Sales3,511,730 3,538,299 (26,569)(0.8)%
Wholesale kwh Sales – Company Generation358,761 156,948 201,813 128.6 
Heating Degree Days3,614 3,968 (354)(8.9)
Cooling Degree Days700 533 167 31.3 
The operating results of our Electric segment are impacted by fluctuations in weather conditions and the resulting demand for the nine months ended September 30, 2020 compared with $103.6 millionelectricity for the nine months ended September 30, 2019. The Company recorded diluted earnings per share of $1.89 for the nine months ended September 30, 2020 compared with $1.67 for the nine months ended September 30, 2019.

Amounts presented in the segment tables that follow for operating revenues, cost of products soldheating and other nonelectric operating expenses for the nine-month periods ended September 30, 2020 and 2019 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:

Intersegment Eliminations (in thousands)

 

September 30, 2020

  

September 30, 2019

 

Operating Revenues:

        

Electric

 $39  $36 

Nonelectric

  --   3 

Costs of Products Sold

  10   25 

Other Nonelectric Expenses

  29   14 

Electric

  

Nine Months Ended

         
  

September 30,

      

%

 

(in thousands)

 

2020

  

2019

  

Change

  

Change

 

Retail Sales Revenues from Contracts with Customers

 $288,861  $303,276  $(14,415)  (4.8)

Changes in Accrued Revenues under Alternative Revenue Programs

  2,900   (1,601)  4,501   281.1 

Total Retail Sales Revenue

 $291,761  $301,675  $(9,914)  (3.3)

Transmission Services Revenue

  32,802   34,023   (1,221)  (3.6)

Wholesale Revenues – Company Generation

  3,141   4,099   (958)  (23.4)

Other Revenues

  5,548   4,929   619   12.6 

Total Operating Revenues

 $333,252  $344,726  $(11,474)  (3.3)

Production Fuel

  34,077   45,547   (11,470)  (25.2)

Purchased Power – System Use

  45,940   54,748   (8,808)  (16.1)

Other Operation and Maintenance Expenses

  106,639   114,107   (7,468)  (6.5)

Depreciation and Amortization

  47,063   44,765   2,298   5.1 

Property Taxes

  12,601   11,824   777   6.6 

Operating Income

 $86,932  $73,735  $13,197   17.9 

Electric mwh Sales

                

Retail mwh Sales

  3,538,299   3,657,618   (119,319)  (3.3)

Wholesale mwh Sales – Company Generation

  156,948   153,645   3,303   2.1 

HDDs

  3,968   4,692   (724)  (15.4)

CDDs

  533   392   141   36.0 

cooling. The following table shows heating and cooling degree days as a percent of normal:

  

Nine Months ended September 30,

 
  

2020

  

2019

 

HDDs

  99.3%  118.0%

CDDs

  116.9%  86.0%

normal for the nine months ended September 30, 2021 and 2020.

 20212020
Heating Degree Days89.9 %99.3 %
Cooling Degree Days150.9 %116.9 %
The following table summarizes the estimated effect on diluted earnings per share of the difference in retail kwh sales under actual weather conditions and expected retail kwh sales under normal weather conditions in the first nine months of2021 and 2020, and 2019 and between years.
 
2021 vs
Normal
2021 vs
2020
2020 vs
Normal
Effect on Diluted Earnings Per Share$0.02 $0.01 $0.01 
Retail Revenues decreased $0.6 million primarily due to the periods:

  

2020 vs Normal

  

2019 vs Normal

  

2020 vs 2019

 

Effect on Diluted Earnings Per Share

 $0.02  $0.06  $(0.04)

following:

The $9.9A $4.7 million decrease in fuel recovery revenues largely due to lower purchased power costs and credits provided to retail customers from increased margins on wholesale sales, but partially offset by increased recovery of higher production fuel costs.

The recognition of $2.6 million of Minnesota transmission rider revenue includes:

An $18.6 million decrease in retail revenue related to the recovery of decreased fuel and purchased power costs to serve retail customers. Decreased demand caused by the milder winter weather contributed to a 21.2% decrease in kwhs generated for system use and a $10.9 million decrease in fuel costs. Also, the cost of fuel burned per kwh of generation was higher in the first nine months of 2019 as a result of the absorption of fixed coal extraction costs in inventory during Coyote Station's second quarter 2019 maintenance shutdown. Purchased power costs decreased by $8.8 million, despite an 8.8% increase in kwhs purchased, due to a 22.8% decrease in purchased power prices resulting from a decrease in market demand between periods.

A $2.4 million decrease in revenues related to decreased consumption due to milder winter weather in 2020 compared with 2019, reflected in the 15.4% decrease in HDDs in the nine months ended September 30, 2020 compared with the nine months ended September 30, 2019. The decrease in consumption due to the decrease in HDDS was only partially offset by an increase in consumption related to warmer summer weather in 2020 compared with 2019.

A $1.6 million decrease in revenue due to decreased kwh sales to commercial and industrial customers mainly due to COVID-19 related impacts in the second and third quarters of 2020.

A $1.0 million decrease in retail revenue in South Dakota related to the first quarter 2019 reversal of a tax refund provision accrued in 2018 in connection with OTP's 2018 South Dakota rate case settlement agreement.

in the third quarter of 2020 resulting from a favorable judicial decision regarding the state jurisdictional treatment of federally approved transmission projects.

A $1.6 million decrease in revenue from the combination of reduced demand from residential and commercial and industrial customers, exclusive of the impact of weather, net of the effect of a change in customer usage mix.
These decreases in revenue were partially offset by:

An $8.5 million increase in Minnesota and North Dakota RRA Rider revenues related to earning a return on funds invested in Merricourt while the project is under construction.

A $2.4 million increase in revenues from the North Dakota Generation Rider which went into effect in July 2019 to provide a return on funds invested in Astoria Station while the generation project is under construction.

A $2.1 million increase in Minnesota TCR Rider revenues, mainly due to the recognition of revenues resulting from a favorable decision regarding state jurisdictional treatment of federally approved transmission rate incentives.

A $0.6 million increase in conservation improvement program (CIP) cost recovery and incentive revenues mainly related to the recovery of increased program spending in Minnesota and South Dakota.

Transmission services revenue decreased $1.2 million mainly due to a $2.1 million reduction in transmission tariff revenues related to decreased transmission volume resulting from lower electrical demand partly attributable toby the impact of COVID-19, partially offset by a $0.8following:

A $3.6 million increase in facility service agreementrider revenues primarily related to transmission upgrades made to accommodate independent generator access to the transmission grid.

Wholesale electric revenues decreased $1.0recovery of Merricourt and Astoria Station project costs and operating expenses.

A $3.0 million despite a 2.1% increase in wholesale kwh sales,new revenue from an interim rate increase in Minnesota, net of estimated refunds, effective January 1, 2021 in connection with our rate case filed in November 2020.
A $2.1 million increase in revenue from transmission rider recovery, due to a 25% decrease in revenue per kwh sold. The lower wholesale prices per kwh resulted in a $0.4increased transmission investments, and increased conservation improvement program spending.
Transmission Services Revenues increased $4.3 million decrease in margins on wholesale energy sales from OTP’s generating units in the first nine months of 2020 compared with the first nine months of 2019.

Production fuel costs decreased $11.5 millionprimarily due to a 23.5% decrease in kwhs generated at OTP’s fuel-burning generation plantsincreased recovery of higher transmission costs and a 2.2% decrease in fuel costs per kwh generated. Decreases in generationincreased transmission investment as well as increased generator interconnection revenues.

25

Wholesale Revenues increased $11.6 million as a result of a 22.8% decrease128.6% increase in purchased powerwholesale sales volumes and a 104.9% increase in wholesale electric prices, partially offsetprimarily driven by an 8.8%increased fuel costs and high market demand for wholesale energy, which serves to drive up spot market prices for electricity.
Production Fuel costsincreased $10.5 million primarily as a result of a 30.8% increase in kwhs purchased. The increase in kwhs purchased was mainlygenerated from our fuel-burning plants due to the decrease in markethigher demand and favorable prices for electricity driven by low prices for natural gas-fired generationenergy in combination with lower demand in the second quarter of 2020 duewholesale markets.
Purchased Power costs to COVID-19-related declines in electricity use by commercial and industrial consumers.

Electric operating and maintenance expenseserve retail customers decreased $7.5 million, including:

A $3.5 million decrease in contracted services and materials and supplies expenses at Coyote Station, mainly related to the plant's second quarter 2019 extended maintenance outage.

A $2.4 million decrease in transmission tariff expenses related to decreased rates.

A $1.1 million decrease in materials and supplies and contracted services expenses at Hoot Lake Plant related to second quarter 2019 turbine repairs.

A $0.9 million decrease in travel-related expenses due to COVID-19 travel restrictions.

A $0.7 million decrease in tree-trimming and vegetation maintenance expenses.

A $0.6 million decrease in pollution control reagent costs due to a 24.0% decrease in kwhs generated at OTP's coal burning plants.

These items were partially offset by:

A $1.1 million increase in customer bad debt expense provisions, mainly due to adoption of COVID-19-related service suspension and debt collection policies.

A $0.5 million in CIP expenditures.

Depreciation expense increased $2.3$5.7 million mainly due to 2019 capitala 26.7% decrease in the volume of purchased power as our recent capacity additions forprovide additional generation resources to serve customer demand and transmissionmarket conditions led to operating our existing facilities at higher capacity factors in lieu of purchasing power at higher market prices.

Operating and Maintenance Expense increased $8.0 million, which was primarily the result of:
$4.0 million of Merricourt and Astoria Station operating and maintenance expenses incurred in 2021 as these facilities are now commercially operational.
$2.1 million of maintenance costs arising from our planned outage at Big Stone plant, which began in the new customer information system that went into service during the firstthird quarter of 20192021 and new service vehicles.

Property tax we expect will be completed in the fourth quarter of the year.

Other additional costs including a $1.6 million increase in transmission tariff expenses, a $1.0 million increase in vegetative maintenance cost, and an increase in conservation program expenditures.
These expense increases were partially offset by, among other items, $1.7 million of lower bad debt expense due to improving customer collections as the economic impact of COVID-19 has eased and lower operating costs following the closure of Hoot Lake Plant in May 2021.
Depreciation and Amortization expense increased $0.8$6.3 million primarily due to property additionsMerricourt and Astoria Station being placed in service in the fourth quarter of 2020 and in February 2021, respectively.
MANUFACTURING SEGMENT RESULTS
The following table summarizes Manufacturing segment operating results for the nine months ended September 30, 2021 and 2020:
(in thousands)20212020$ change% change
Operating Revenues$250,085 $174,276 $75,809 43.5 %
Cost of Products Sold (excluding depreciation)189,183 131,145 58,038 44.3 
Other Operating Expenses28,109 19,678 8,431 42.8 
Depreciation and Amortization11,395 11,244 151 1.3 
Operating Income$21,398 $12,209 $9,189 75.3 %
Operating Revenuesincreased jurisdictional valuations.

Manufacturing

  

Nine Months Ended

         
  

September 30,

      

%

 

(in thousands)

 

2020

  

2019

  

Change

  

Change

 

Operating Revenues

 $174,276  $217,040  $(42,764)  (19.7)

Cost of Products Sold

  131,145   167,002   (35,857)  (21.5)

Operating Expenses

  19,678   22,880   (3,202)  (14.0)

Depreciation and Amortization

  11,244   10,606   638   6.0 

Operating Income

 $12,209  $16,552  $(4,343)  (26.2)

$75.8 million primarily due to higher revenues at BTD, which was largely driven by a 15.6% increase in sales volumes and a 25.5% increase in material costs, which are passed through to customers through increased sales prices. The $42.8 million decreaseincrease in material costs is largely the result of historically high steel prices due to supply shortages as steel mill capacity rebounds from capacity reductions in 2020. Sales volumes in 2020 were negatively impacted by COVID-19 as customers implemented temporary plant shutdowns due to the pandemic. Sales volumes in 2021 have rebounded as customer demand across most end markets has been robust. An increase in horticultural product sales volumes at T.O. Plastics in 2021, driven by increasing customer demand, as well as increased sales prices, also contributed to increased operating revenues in our Manufacturing segment includes2021.

Cost of Products Sold increased $58.0 million primarily due to increased volumes and higher material, labor and freight costs at BTD. The increase in material cost is largely the following:

Revenues at BTD decreased $41.6 million. Parts revenue was down $41.4 million, mainly due to decreased sales volumes to all end market customer categories served by BTD, in order of magnitude: construction, lawn and garden, industrial and energy equipment, recreational vehicle and agricultural end markets. The decreased sales mainly resulted from customers implementing temporary plant shutdowns due to the COVID-19 pandemic. Lower prices related to the pass through of lower material costs accounted for a $17.1 million decrease in parts revenue, partially offset by $1.2 million in price increases exclusive of the pass through of material cost reductions.

Revenues at T.O. Plastics decreased $1.2 million primarily as a result of lower product demand from customers due to COVID-19-related impacts on customer’s sales and service activities.

The $35.9 million decreaseresult of high steel prices as mentioned above. Year to date gross profit margins are consistent with the prior year as increases in labor and freight costs and lower productivity in the third quarter of 2021 have been offset by higher sales volumes, as higher volumes have resulted in greater leveraging of fixed production costs. Increased sales volumes and production activity at T.O. Plastics has also contributed to the increase in cost of products sold in our Manufacturing segment includes2021. Year to date gross profit margins at T.O. Plastics increased compared to the following:

Cost of products sold at BTD decreased $35.7 million as a result of both the decreased sales volume and the $17.1 million in lower material costs passed through to customers.

Cost of products sold at T.O. Plastics decreased $0.2 million due to a $1.4 million decrease in material costs related to the decrease in sales volume, mostly offset by increases in other indirect costs and an increase in rental costs for more warehouse space.

The $3.2same period in 2020, as higher production activities have resulted in greater leveraging of fixed production costs and sales prices have increased, resulting from input material cost inflation.

Other Operating Expenses increased $8.4 million decrease in 2021 compared to 2020. Other operating expenses in our Manufacturing segment includes a $2.3 million decrease in operating expenses at BTD related to2020 were reduced by initiatives taken at BTDto reduce costs in an effort to mitigate the negative impacts onimpact of declining sales related to COVID-19, mainly reductionsvolumes from the effects of COVID-19. Other operating expenses in travel and outside services expenditures. Operating expenses at T.O. Plastics decreased $0.9 million, including $0.4 million as a result of the receipt of insurance settlement proceeds in the first quarter of 2020 and a $0.3 million write off of the value of destroyed property in 2019 related to the March 2019 partial roof collapse. T.O, Plastics travel and other selling expenses decreased2021 were impacted by $0.2 million due to restrictions on activity in response to COVID-19-related safety initiatives.

BTD incurred $1.0 million in termination costs in the second quarter of 2020, with $0.9 million charged to cost of products sold and $0.1 million charged to operating expense, related to headcount reductions across all its sites in response to the ongoing reduction in sales volume.

We estimate COVID-19 issues at BTD negatively impacted our earnings by approximately $0.08 per share in the first nine months of 2020. This relates to reduced sales as customers initiated or continued temporary plant shutdowns which caused lost labor productivity, and costs related to personal protective equipment. BTD also continued to pay health care costs for furloughed employees.

Plastics

  

Nine Months Ended

         
  

September 30,

      

%

 

(in thousands)

 

2020

  

2019

  

Change

  

Change

 

Operating Revenues

 $155,769  $142,100  $13,669   9.6 

Cost of Products Sold

  115,432   110,348   5,084   4.6 

Operating Expenses

  8,990   8,486   504   5.9 

Depreciation and Amortization

  2,667   2,617   50   1.9 

Operating Income

 $28,680  $20,649  $8,031   38.9 

Plastics segment revenues and operating income increased $13.7 million and $8.0 million, respectively, due to a 10.2%an increase in pounds of PVC pipe soldincentive based compensation arising from the improvement in combination with a decreasefinancial results, and an increase in cost per pound of pipe sold. The sales volume increase resulted from a combination of factors including improved market conditions during the third quarter of 2020 duecosts necessary to limited effects of COVID-19 and concerns over raw material supply and product availability due to two resin suppliers invoking force majeure, anticipated impacts from hurricanes, significant global demand for PVC resin and limited pipe inventory across the country. Cost of products sold increased $5.1 million due tosupport the increase in sales volume, partially offset by a 5.0% decrease in the cost per poundbusiness volumes.

26

PLASTICS SEGMENT RESULTS
The $0.5 million increase infollowing table summarizes Plastics segment operating expenses is due to increases in salary and benefit expenses, contracted service costs and corporate management fees.

Corporate

Corporate includes items such as corporate staff and overhead costs, the results of our captive insurance company and other items excluded from the measurement of operating segment performance. Corporate is not an operating segment. Rather it is added to operating segment totals to reconcile to totals on our consolidated statements of income.

  

Nine Months Ended

         
  

September 30,

      

%

 

(in thousands)

 

2020

  

2019

  

Change

  

Change

 

Operating Expenses

 $7,638  $7,052  $586   8.3 

Depreciation and Amortization

  256   241   15   6.2 

Corporate operating expenses increased $0.6 million mainly as a result of a $0.4 million decrease in corporate costs charged to subsidiaries, a $0.4 million increase in labor costs and a $0.2 million increase in insurance costs, partially offset by a $0.3 million decrease in contracted service expenditures.

Interest Charges

Interest charges increased to $25.4 million infor the nine months ended September 30, 2020 from $23.22021 and 2020:

(in thousands)20212020$ change% change
Operating Revenues$264,898 $155,769 $109,129 70.1 %
Cost of Products Sold (excluding depreciation)169,584 115,432 54,152 46.9 
Other Operating Expenses10,450 8,990 1,460 16.2 
Depreciation and Amortization3,200 2,667 533 20.0 
Operating Income$81,664 $28,680 $52,984 184.7 %
Operating Revenues increased $109.1 million, primarily due to a 71.1% increase in the price per pound of PVC pipe sold. As discussed above, sale prices have rapidly increased in 2021 due to the combination of PVC resin supply constraints, which has led to limited PVC pipe inventory, and strong demand for PVC pipe products. Resin supply constraints has impacted our production and sales volumes were down slightly compared to the previous year.
Cost of Products Sold increased $54.2 million primarily due to increased PVC resin and other input costs, which increased 60.3% compared to the same period in the previous year. Increases in labor and freight costs in 2021 also contributed to the increase in cost of products sold.
Other Operating Expenses increased $1.5 million as a result of an increase in variable costs associated with increased financial results in 2021.
CORPORATE COSTS
The following table summarizes Corporate operating results for the nine months ended September 30, 2019. 2021 and 2020:
(in thousands)20212020$ change% change
Other Operating Expenses$7,028 $7,638 $(610)(8.0)%
Depreciation and Amortization179 256 (77)(30.1)
Operating Loss$7,207 $7,894 $(687)(8.7)%
Other Operating Expenses decreased $0.6 million due to net decreases in corporate overhead and operating costs.
REGULATORY RATE MATTERS
The $2.2 millionfollowing provides a summary of general rate case filings, rate rider filings and other regulatory filings that have or are expected to have a material impact on our operating results, financial position or cash flows.
GENERAL RATES
Minnesota Rate Case: On November 2, 2020, OTP filed a request with the MPUC for an increase in interest charges isrevenue recoverable through base rates in Minnesota. In its filing, OTP requested a net increase in annual revenue of approximately $14.5 million, or 6.77%, based on an allowed rate of return on rate base of 7.59% and an allowed rate of return on equity of 10.20% on an equity ratio of 52.5% of total capital. Through this proceeding, OTP has proposed changes to the mechanism of cost recovery, with some costs moving from riders into base rates and fuel, purchased power, and conservation program costs moving out of base rates and into riders. The filing also included a revenue decoupling mechanism proposal. Such mechanisms are designed to separate a utility's revenue from changes in energy sales. The decoupling mechanism uses a tracker balance through which authorized customer margins are subject to a true-up mechanism to maintain or cap a given level of revenues.
On December 3, 2020, the MPUC approved an interim annual rate increase of $6.9 million, or 3.2%, effective January 1, 2021. This approval was provided after an alternative recovery proposal was submitted by OTP, which, among other changes, requested the extension of depreciable lives of certain wind-related assets and deferred certain cost recovery decisions to the final rate determination. In the aggregate, this alternative recovery proposal reduced operating costs and delayed recovery of certain other costs by approximately $7.0 million to lessen the interim rate impact on customers.
In a filing submitted to the MPUC on April 30, 2021, OTP lowered its requested net annual revenue increase from its initial request of $14.5 million to $8.2 million, primarily due to a reduction in operating costs from amounts included in its November 2020 filing. The cost reductions include, among other items, lower depreciation expense on our wind generation assets due to the extension of depreciable lives from 25 to 35 years and a reduction in postretirement benefit costs.
On September 20, 2021, the Administrative Law Judge assigned to our rate case issued his recommendations to the MPUC, and the MPUC is expected to hold deliberations in early November with a written order expected to be issued by the end of January 2022. We anticipate final rates will be implemented by mid-2022.
27

RATE RIDERS
The following table includes a summary of pending and recently concluded rate rider proceedings:
RecoveryFilingAmountEffective
MechanismJurisdictionStatusDate(in millions)DateNotes
RRR2019MNApproved06/21/19$12.5 01/01/20Includes return on Merricourt construction costs.
TCR2018MNApproved05/07/2010.3 01/21/20See below for additional details.
EUIC2021MNRequested06/07/211.3 01/01/22Includes recovery of new infrastructure costs, including advanced metering, outage management and demand response systems.
RRR2021NDApproved03/07/2111.804/01/21Includes return on Merricourt construction costs.
GCR2020NDApproved06/10/206.2 07/01/20Includes return on Astoria Station construction costs.
TCR2022NDRequested09/15/216.1 01/01/22Includes recovery of three new transmission projects/programs.
RRR2020NDApproved03/18/205.8 04/01/20Includes return on Merricourt construction costs.
TCR2020NDApproved08/31/205.6 01/21/20Includes recovery of new transmission assets.
TCR2021NDApproved11/18/205.601/01/21Includes recovery of eight new transmission projects.
GCR2021NDApproved03/01/215.207/01/21Includes recovery of Astoria Station, net of anticipated savings associated with the retirement of Hoot Lake Plant.
TCR2020SDApproved01/29/202.303/02/20Annual update to transmission cost recovery rider.
TCR2021SDApproved02/19/212.203/01/21Includes recovery of two new transmission projects.
PIR2020SDApproved05/31/201.609/01/20Includes return on Merricourt and Astoria Station construction costs.
Minnesota TCR. On May 1, 2017, the MPUC ordered OTP to include in the TCR rider retail rate base the Minnesota jurisdictional share of OTP's investments in certain transmission assets and all revenues received from other utilities under MISO's tariffed rates as a credit in its TCR revenue requirement calculations. The order had the effect of diverting interstate wholesale revenues that have been approved by the FERC to offset the FERC-approved expenses, effectively reducing OTP's recovery of FERC-approved expense levels.
On August 18, 2017, OTP filed an increaseappeal of the MPUC order with the Minnesota Court of Appeals to contest the portion of the order requiring OTP to jurisdictionally allocate costs of the FERC transmission projects in interest expensethe TCR rider. On June 11, 2018, the Minnesota Court of Appeals reversed the MPUC's order. On July 11, 2018, the MPUC filed a petition for review of the decision to the Minnesota Supreme Court, which granted review of the appellate court decision. The Minnesota Supreme Court issued its opinion on April 22, 2020, concluding the MPUC lacked authority to amend an existing TCR rider approved under Minnesota state law to include the costs and revenues associated with these transmission projects and affirming the decision of the Minnesota Court of Appeals.
On October 22, 2020, the MPUC approved OTP's request for a Minnesota TCR rider update with the exclusion of these transmission projects. In addition, the MPUC approved the inclusion of three new projects previously requested in the Minnesota TCR rider eligibility petition. Updated rates went into effect in January 2021. With this decision, one-half of the projected TCR rider tracker balance at OTP related to debt issuancesDecember 2020 of $100$13.4 million will be included in the 2021 TCR rider annual revenue requirement, with the remainder included in the next annual update. The annual updates provide for recovery of approximately $2.6 million in OctoberMISO revenues credits to Minnesota customers through the TCR rider prior to September 30, 2020. As a result, OTP recognized additional rider revenue of 2019, $35$2.6 million in Februaryduring the third quarter of 20202020.
INTEGRATED RESOURCE PLAN
Minnesota law requires utilities to submit to the MPUC for approval a 15-year advance IRP. A resource plan is a set of resource options a utility could use to meet the service needs of its customers over a forecast period, including an explanation of the utility’s supply and $40 million in August 2020 under OTP’s 2019 Note Purchase Agreement.

Other Income

Other income increaseddemand circumstances, and the extent to $3.7 millionwhich each resource option would be used to meet those service needs. Typically, the filings are submitted every two years.

On September 1, 2021, OTP filed its 2022 IRP concurrently with regulators in the nine months ended September 30, 2020three states where OTP operates, Minnesota, North Dakota and South Dakota. The 2022 IRP includes OTP’s preferred plan for meeting customers’ anticipated capacity and energy needs while maintaining system reliability and low electric service rates.
The components of OTP's preferred plan include:
the addition of dual fuel capability at our Astoria Station natural gas plant, allowing for the plant to burn fuel oil in addition to natural gas;
the addition of 150 megawatts of solar generation in 2025;
the addition of 100 megawatts of wind generation in 2027;
the commencement of the process of withdrawing from $3.1 millionour 35 percent ownership interest in Coyote Station, a jointly owned, coal-fired generation plant, by December 31, 2028; and
the nine months ended September 30, 2019. addition of 50 megawatts of solar generation in 2033.
The $0.6 million increase2022 IRP requests approval for certain activities planned to commence within the next five years, which include the addition of dual fuel capacity at our Astoria Station natural gas plant, the addition of 150 megawatts of solar generation, and the withdrawal from our ownership interest in other income includesCoyote Station.
28

The preferred plan proposes to, subject to regulatory approval, create a $1.5 million increase in allowance for equity funds used during construction (AFUDC) at OTP, mostlyregulatory asset as a vehicle to recover costs related to the Minnesota share of construction work in progress on OTP’s Astoriafuture withdrawal from Coyote Station, project, partially offset by a $0.8 million decrease inincluding the cash surrendernet book value of corporate-owned life insurance policies held by the Company.

Income Tax Expense

Income tax expense increased $4.6 million in the nine months ended September 30, 2020 compared withexisting lignite sales agreement under which Coyote Station acquires all of its lignite coal fuel from a nearby mine is necessary. For its economic analysis, OTP developed an estimate of the nine months ended September 30, 2019, mainlyreasonably foreseeable costs of withdrawing from Coyote Station at the end of 2028 of $68.5 million. These costs may differ from actual results due to the tax effectuncertainty and timing of future events associated with the terms and conditions of a $15.3 million increase in income before income taxes. The following table provides a reconciliation of income tax expense calculated at our net composite federal and state statutory rate on income before income taxes on our consolidated statements of income.

  

Nine Months Ended September 30,

 

(in thousands)

 

2020

  

2019

 

Income Before Income Taxes

 $95,726  $80,402 

Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%)

 $24,889  $20,905 

(Decreases) Increases in Tax from:

        

Differences Reversing in Excess of Federal Rates

  (3,450)  (2,690)

Allowance for Funds Used During Construction – Equity

  (948)  (419)

North Dakota Wind Tax Credit Amortization – Net of Federal Taxes

  (775)  (774)

Research and Development Tax Credits

  (649)  (987)

Excess Tax Deduction – Equity Method Stock Awards

  (535)  (827)

Corporate Owned Life Insurance

  (141)  (609)

Reconciliation and Prior Period Adjustments

  172   (722)

Other Items – Net

  (20)  30 

Income Tax Expense

 $18,543  $13,907 

Effective Income Tax Rate

  19.4%  17.3%

Liquidity

withdrawal.

LIQUIDITY
LIQUIDITY OVERVIEW
We believe our financial condition is strong and our cash, other liquid assets, operating cash flows, existing lines of credit, access to capital markets, and borrowing ability because of investment-grade credit ratings, when taken together, provide us ample liquidity to conduct our business operations and fund our capital expenditures related to expansion of existing businesses and development of new projects.expenditure plans. Our liquidity, including our operating cash flows and access to capital markets, can be impacted by macroeconomic factors outside of our control, such as those which may be caused by COVID-19. In addition, our liquidity could be impacted by non-compliance with covenants under our various debt instruments. As of September 30, 2020,2021, we were in compliance with all debt covenants (see the Financial CovenantCovenants section under Capital Resources below).

As of September 30, 2020, COVID-19 and the resulting deteriorating economic conditions had not had a material impact on our liquidity. We continue to have sufficient liquidity under our credit facilities to support our operating companies based on the current economic environment. We are closely monitoring our liquidity and capital market conditions given the uncertainty surrounding the impact of COVID-19, which could have an adverse effect on the availability and terms of future debt and equity financing.

The following table presents the status of our lines of credit as of September 30, 20202021 and December 31, 2019:

(in thousands)

 

Line Limit

  

In Use on

September 30,

2020

  

Restricted due to Outstanding

Letters of Credit

  

Available on

September 30,

2020

  

Available on

December 31,

2019

 

Otter Tail Corporation Credit Agreement

 $170,000  $48,600  $--  $121,400  $164,000 

OTP Credit Agreement

  170,000   --   7,670   162,330   154,524 

Total

 $340,000  $48,600  $7,670  $283,730  $318,524 

2020:

20212020
(in thousands)Line LimitAmount OutstandingLetters
of Credit
Amount AvailableAmount Available
OTC Credit Agreement$170,000 $36,624 $— $133,376 $104,834 
OTP Credit Agreement170,000 61,233 13,159 95,608 140,068 
Total$340,000 $97,857 $13,159 $228,984 $244,902 
We have adopted an internal risk tolerance metric to maintain a minimum of $50 million of liquidity under the Otter Tail CorporationOTC Credit Agreement. Should additional liquidity be needed, this agreement includes an accordion feature allowing us to increase the amount available to $290 million, subject to certain terms and conditions. The OTP Credit Agreement also includes an accordion feature allowing OTP to increase that facility to $250 million, subject to certain terms and conditions.

CASH FLOWS
The following is a discussion of our cash flows for the nine months ended September 30, 2021 and 2020:
(in thousands)20212020
Net Cash Provided by Operating Activities$154,752 $141,276 
Net Cash Provided by Operating Activities increased $13.5 million for the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020. The increase in cash provided by operating activities was the result of increased earnings during the year, which was partially offset by increased working capital needs. Our At-the-Market equity offering program, which allows uslevel of working capital increased year over year, and was impacted by increased accounts receivables within our Manufacturing and Plastics segments, due to sell common shares upstrong sales volumes and significantly increased sales prices in 2021, and higher inventory levels within our Manufacturing segment due to an aggregate sales pricehigher production volumes and increased material costs in 2021, but partially offset by increased accounts payable due to higher production volumes and increased costs in our Manufacturing and Plastics segments in 2021. We made a discretionary contribution to our pension plan of $75$10.0 million remains in effect. We issued $35.0the nine months ended September 30, 2021 compared to a contribution of $11.2 million in 2020.
(in thousands)20212020
Net Cash Used in Investing Activities$117,084 $222,385 
Net Cash Used in Investing Activities decreased $105.3 million for the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020. The decrease is primarily the result of lower capital investment within our Electric segment as capital spending on our large generation assets, Merricourt and Astoria Station, occurred throughout 2020 and was largely completed by the fourth quarter of 2020.
29

(in thousands)20212020
Net Cash (Used in) Provided by Financing Activities$(37,559)$104,814 
Net Cash (Used in) Provided by Financing Activities decreased $142.4 million for the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020, primarily as a result of a decrease in financing needs given the lower level of capital spending in our Electric segment in 2021 compared to 2020. Financing activities in the nine months ended September 30, 2021 included a net borrowing increase of $16.9 million under our line of credit facilities and dividend payments of $48.6 million ($1.17 per share).
Financing activities in the nine months ended September 30, 2020 included proceeds of $75.0 million from the issuance of long-term debt, a net borrowing increase of $42.6 million under our line of credit facilities and $34.8 million in proceeds raised from the issuance of common equitystock, net of issuance costs. We paid dividends of $45.1 million ($1.11 per share) in the nine months ended September 30, 2020.
CAPITAL REQUIREMENTS
CAPITAL EXPENDITURES
We have a capital expenditure program for expanding, upgrading and improving our plants and operating equipment. Typical uses of cash for capital expenditures are investments in electric generation facilities and environmental upgrades, transmission and distribution lines, manufacturing facilities and upgrades, equipment used in the manufacturing process, and computer hardware and information systems. Our capital expenditure program is subject to review and regulatory approval and is revised in light of changes in demands for energy, technology, environmental laws, regulatory changes, business expansion opportunities, the costs of labor, materials and equipment and our financial condition.
Our 2022 IRP, filed with the MPUC on September 1, 2021, outlined our preferred plan for meeting our electric customers’ anticipated energy needs while maintaining system reliability, which included significant planned additions and enhancements to our electric fleet of assets. The following provides a summary of the actual capital expenditures for the year ended December 31, 2020, and the anticipated capital expenditures for the period 2021 through 2026, for our Electric segment, inclusive of the additions outlined in our 2022 IRP, and our non-electric businesses:
(in millions)2020
2021(1)
20222023202420252026Total
2022 - 2026
Electric Segment:
Renewables and Natural Gas Generation23 30 80 92 92 160 454 
Technology and Infrastructure26 30 18 — — 74 
Distribution Plant Replacements31 37 35 35 35 33 175 
Transmission (includes replacements)27 26 28 24 20 27 125 
Other34 30 29 32 36 23 150 
Total Electric Segment$357 $117 $149 $202 $201 $183 $243 $978 
Manufacturing and Plastics Segments15 36 33 46 31 21 22 153 
Total Capital Expenditures$372 $153 $182 $248 $232 $204 $265 $1,131 
Total Electric Utility Average Rate Base$1,385 $1,570 $1,630 $1,750 $1,860 $1,980 $2,100 
Annual Rate Base Growth13.4 %3.8 %7.4 %6.3 %6.5 %6.1 %
(1) Includes actual results for the nine months ended September 30, 2021, and anticipated capital expenditures for the fourth quarter of 2021.
CONTRACTUAL OBLIGATIONS
Our contractual obligations primarily include principal and interest payments due under our At-the-Market offering program, Dividend Reinvestmentoutstanding debt obligations, commitments to acquire coal, energy and Employee Stock Purchase planscapacity commitments, payments to meet our postretirement benefit obligations, and payment obligations under land easement and leasing arrangements. Our contractual obligations as of December 31, 2020 are included in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, of our Annual Report on Form 10-K for the year ended December 31, 2020. There were no material changes in our contractual obligations outside of the ordinary course of our business during the nine months ended September 30, 2021.
COMMON STOCK DIVIDENDS
We paid dividends to our common stockholders totaling $48.6 million, or $1.17 per share, in the first nine months of 2020. We expect to issue up to an additional $20 million in common equity under these programs into 2021 depending on conditions in the equity capital markets caused by the COVID-19 pandemic or other factors.

Equity and debt financing will be required in the period 2020 through 2024 given the expansion plans related to our Electric segment to fund construction of new rate base investments. Also, such financing will be required should we decide to reduce borrowings under our lines of credit or refund or retire early any of our presently outstanding debt, to complete acquisitions or for other corporate purposes. The terms and conditions and the timing of our equity and debt financing activities could be impacted by the economic effects of COVID-19 and the resulting market volatility. In addition, our borrowing costs can be impacted by changing interest rates on short-term and long-term debt and ratings assigned to us by independent rating agencies, which in part are based on certain credit measures such as interest coverage and leverage ratios.

2021. The determination of the amount of future cash dividends to be declared and paid will depend on, among other things, our financial condition, improvement in earnings per share, cash flows from operations, the level of our capital expenditures and our future business prospects. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by our subsidiaries. See note 7Note 10 to our consolidated financial statements included in this Quarterly Report on Form 10-Q for additional information. The decision to declare a dividend is reviewed quarterly by the boardour Board of directors. On February 4, 2020 our boardDirectors.

30

CAPITAL RESOURCES
Financial flexibility is provided by operating activities was $141.3 million for the nine months ended September 30, 2020 compared with cash providedflows, unused lines of credit, and access to capital markets, which is aided by operating activities of $105.1 million for the nine months ended September 30, 2019. The primary reasons for the $36.2 million increase in cash provided by operations between the periods were an $11.3 million decrease in discretionary pension fund contributions, a $10.7 million increase in net income, a $7.0 million reduction in cash used for working capital itemsstrong financial coverages and a $3.0 million increaseinvestment grade credit ratings. Equity or debt financing will be required in the non-cash depreciation expense between the periods. The reduction in cash used for workingperiod 2021 through 2025 to support our capital items was mainly dueinvestments, primarily within our Electric segment to an $8.1 million decrease in cash used for trade accounts payable at BTD mostly related to lower material purchases resulting from a reduction in business activity in 2020 related to COVID-19.

Net cash used in investing activities was $222.4 million for the nine months ended September 30, 2020 compared with $151.1 million for the nine months ended September 30, 2019. The $71.3 million increase is mainly due to a $77.1 million increase in cash used for construction expenditures at OTP, partially offset by a $6.2 million net decrease in capital expenditures in our nonutility businesses. OTP’s cash used for capital expenditures totaled $210.0 million in the first nine months of 2020 compared with $132.9 million in the first nine months of 2019. The majority of the 2020 expenditures at OTP related to thefund construction of Astoria Stationnew rate base and Merricourt.

Net cash provided bytransmission investments. In addition, we may issue equity or debt financing activities was $104.8 million for the nine months ended September 30, 2020 compared with net cash provided by financing activitiesto opportunistically reduce borrowings under our lines of $46.0 million for the nine months ended September 30, 2019. Financing activities in the first nine months of 2020 included $75.0 million in proceeds from the issuance ofcredit, to satisfy or early retire our outstanding long-term debt, at OTP under its 2019 Note Purchase Agreementor to fund its current construction program expenditures. Further information on the debt issuance is provided below under “Capital Resources.” We also borrowed $42.6 million under the Otter Tail Corporation Credit Agreement and raised net proceeds of $32.7 million from the issuance of common stock. The proceeds from the line borrowings and stock issuances provided the majority of fundsfinance potential acquisition opportunities or for $105 million in equity contributions to OTP to fund its construction program expenditures. Financing activities in the first nine months of 2020 also included $45.1 million in common dividend payments.

Financing activities in the first nine months of 2019 included proceeds of $90.4 million from borrowings under the OTP and Otter Tail Corporation credit agreements which were used, together with cash flows from operations, to fund OTPs capital expenditures. The Company also paid $41.8 million in common dividends in the first nine months of 2019.

CAPITAL REQUIREMENTS

2019-2024 Capital Expenditures

In June 2020, we updated our 2020-2024 anticipated capital expenditures, shifting the timing of expenditures between years and projects as a result of more definitive plans with no material impact on the $1.0 billion five-year expenditure total. The following table shows our 2019 capital expenditures and June 30, 2020 revised 2020 through 2024 anticipated capital expenditures and electric utility average rate base:

(in millions)

 

2019

  

2020

  

2021

  

2022

  

2023

  

2024

  

Total

 

Capital Expenditures:

                            

Electric Segment:

                            

Renewables and Natural Gas Generation

     $258  $65  $53  $--  $--  $376 

Technology and Infrastructure

      --   11   28   32   28   99 

Distribution Plant Replacements

      20   25   28   31   30   134 

Transmission (includes replacements)

      62   14   30   30   30   166 

Other

      26   23   25   25   24   123 

Total Electric Segment

 $187  $366  $138  $164  $118  $112  $898 

Manufacturing and Plastics Segments

  20   14   17   17   19   17   84 

Total Capital Expenditures

 $207  $380  $155  $181  $137  $129  $982 

Total Electric Utility Average Rate Base

 $1,170  $1,415  $1,587  $1,664  $1,726  $1,765     

Rate Base Growth

      20.9%  12.2%  4.9%  3.7%  2.3%    

Execution on the anticipated electric utility capital expenditure plan is expected to grow rate base 8.6% and be a key driver in increasing utility earnings over the 2020 through 2024 timeframe.

As of September 30, 2020, OTP had capitalized approximately $231.1 million in project costs and AFUDC associated with Merricourt. OTP estimates its direct generation and transmission capital costs for the Merricourt project will be approximately $260 million. Additional transmission system upgrades for the project amounting to approximately $6.4 million will be made by a neighboring MISO transmission owner. OTP has received Notices of Force Majeure from EDF-RE US Development, LLC claiming rights to an extension of guaranteed project completion dates and adjustments to the consideration agreed upon in the TEPC Agreement due to COVID-19 impacts. While details regarding these claims and impact to the project remain uncertain, OTP currently anticipates Merricourt will be in commercial operation before the end of December 2020. These and other potential impacts of COVID-19-related disruptions continue to present risks for the costs and timing of payments related to the project.

As of September 30, 2020, OTP had capitalized approximately $131.6 million in project costs and AFUDC associated with Astoria Station. OTP estimates its direct generation and transmission capital costs for the Astoria Station project will be approximately $152.5 million and anticipates the plant will begin commercial operation in the first quarter of 2021, prior to the planned retirement of Hoot Lake Plant in May 2021.

In September 2020, OTP announced plans for the construction of the $60 million Hoot Lake Solar project. This is a 49-megawatt project OTP expects to build on land around Hoot Lake Plant in Fergus Falls, Minnesota. The project is expected to include up to 170,000 solar panels and to generate enough energy to power approximately 10,000 homes each year. The project is targeted for completion in 2022.

Contractual Obligations

In the first nine months of 2020, OTP paid down a portion of its $317 million in obligations for commitments under contracts in place as of December 31, 2019, reducing its obligations for commitments under contracts to $58 million as of September 30, 2020. This includes commitments related to the construction of Astoria Station and Merricourt of $39 million for the remainder of 2020 and $6 million for 2021. In the first nine months of 2020, OTP increased its debt obligations by $75 million in the years beyond 2024. In September 2020, OTP entered into a 20-year Facilities Service Agreement with an owner of adjacent transmission assets to pay for upgrades and additions to the owner’s transmission facilities required to accommodate the transmission of electricity generated by Merricourt’s wind turbines, increasing its other purchase obligations by $1.4 million in each of the two-year periods 2021-2022 and 2023-2024, and $10.8 million beyond 2024.

corporate purposes.
REGISTRATION STATEMENTS
45

CAPITAL RESOURCES

On May 3, 20182021, we filed two registration statements with the SEC. The first statement, a shelf registration, statement with the Securities and Exchange Commission (SEC) under which we mayallows us to offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelfregistration statement. The second registration statement which expires on May 3, 2021. On May 3, 2018 we also filed a shelf registration statement with the SECallows for the issuance of up to 1,500,000 common shares under our Automatic Dividend Reinvestment and Share Purchase Plan, (the Plan), which permitsprovides our common shareholders, retail customers of OTP and other interested investors a method of purchasing our common shares by reinvesting their dividends and/or making optional cash investments. Shares purchased by participants inunder the Plan toplan may be either new issue common shares or common shares purchased inon the open market. The shelfBoth registration for the Plan expires onstatements expire in May 3, 2021. On November 8, 2019 the Company entered into a Distribution Agreement with KeyBanc under which we may offer and sell our common shares from time to time through KeyBanc, as our distribution agent, up to an aggregate sales price of $75 million through an At-the-Market offering program. In the third quarter of 2020, we received proceeds of $3,523,311, net of $44,599 in commissions, from the issuance of 87,400 common shares under this program.

Debt

Brief descriptions of the short-term and long-term credit and debt agreements currently in place at 2024.

SHORT-TERM DEBT
Otter Tail Corporation and Otter Tail Power Company are each party to a credit agreement (the OTC Credit Agreement and OTP are presented below. See note 10 to our consolidated financial statements included in our Annual Report on Form 10-KCredit Agreement, respectively) which each provide for the year ended December 31, 2019 for additional information on the terms, provisions, restrictionsunsecured revolving lines of credit. On September 30, 2021, Otter Tail Corporation entered into a Fourth Amended and covenants under these agreements.

Short-Term Debt

On October 29, 2012 weRestated Credit Agreement and Otter Tail Power Company entered into a Third Amended and Restated Credit Agreement, (the OTC Credit Agreement), which provided for an unsecured $130 million revolvingamending and restating the previously existing credit facility that could be increased subject to certain terms and conditions. On October 31, 2019 the OTC Credit Agreement was amendedagreements to extend its expirationthe maturity date by one year from October 31, 2023of each agreement to October 31, 2024,September 30, 2026. The borrowing capacity and to increase the amountother significant terms of the revolvingagreements remained unchanged from the previous credit facility to $170 million.agreements. The amendment also provides this facility can be increased to $290 million subject to certain termsfollowing is a summary of key provisions and conditions. Borrowings under the OTC Credit Agreement bear interest at LIBOR plus 1.50%, subject to adjustment based on our senior unsecured credit ratings or the issuer rating if a rating is not providedborrowing information as of, and for the seniornine months ended, September 30, 2021:

(in thousands, except interest rates)OTC Credit AgreementOTP Credit Agreement
Borrowing Limit$170,000 $170,000 
Borrowing Limit if Accordion Exercised1
290,000 250,000 
Amount Restricted Due to Outstanding Letters of Credit as of September 30, 2021— 13,159 
Amount Outstanding as of September 30, 202136,624 61,233 
Average Amount Outstanding During the Nine Months Ended September 30, 202158,703 51,911 
Maximum Amount Outstanding During the Nine Months Ended September 30, 202179,718 72,471 
Interest Rate as of September 30, 20211.59 %1.33 %
Maturity DateSeptember 30, 2026September 30, 2026
1Each facility includes an accordion featuring allowing the borrower to increase the borrowing limit if certain terms and conditions are met.
LONG-TERM DEBT
At September 30, 2021, we had $767.0 million of principal outstanding under long-term debt arrangements. These instruments generally provide for unsecured credit.

borrowings at fixed rates of interest with maturities ranging from 2021 to 2050.

On October 29, 2012 OTP entered into a Second Amended and Restated Credit Agreement (the OTP Credit Agreement), providing for an unsecured $170 million revolving credit facility that may be increased to $250 million subject to certain terms and conditions. On October 31, 2019 the OTP Credit Agreement was amended to extend its expiration date by one year from October 31, 2023 to October 31, 2024. OTP can draw on this credit facility to support the working capital needs and other capital requirements of its operations, including letters of credit in an aggregate amount not to exceed $50 million outstanding at any time. Borrowings under this line of credit bear interest at LIBOR plus 1.25%, subject to adjustment based on the ratings of OTP’s senior unsecured debt or the issuer rating if a rating is not provided for the senior unsecured debt.

Long-Term Debt

On September 12, 2019,June 10, 2021, OTP entered into a Note Purchase Agreement (the 2019 Note Purchase Agreement) with the purchasers named therein, pursuant to which OTP agreed to issue, to the purchasers, in a private placement transaction, $175$230 million aggregate principal amount of OTP’s senior unsecured notes. The funding of the notes consistingwill occur in two issuances, $140 million in November 2021 and $90 million in May 2022. The issuance of (a) $10,000,000 aggregate principal amount of its 3.07% Series 2019A Senior Unsecured Notes due October 10, 2029 (the Series 2019A Notes), (b) $26,000,000 aggregate principal amount of its 3.52% Series 2019B Senior Unsecured Notes due October 10, 2039 (the Series 2019B Notes), (c) $64,000,000 aggregate principal amount of its 3.82% Series 2019C Senior Unsecured Notes due October 10, 2049 (the Series 2019C Notes), (d) $10,000,000 aggregate principal amount of its 3.22% Series 2020A Senior Unsecured Notes due February 25, 2030 (the Series 2020A Notes), (e) $40,000,000 aggregate principal amount of its 3.22% Series 2020B Senior Unsecured Notes due August 20, 2030 (the Series 2020B Notes), (f) $10,000,000 aggregate principal amount of its 3.62% Series 2020C Senior Unsecured Notes due February 25, 2040 (the Series 2020C Notes) and (g) $15,000,000 aggregate principal amount of its 3.92% Series 2020D Senior Unsecured Notes due February 25, 2050 (the Series 2020D Notes).

On February 25, 2020, OTP issued the Series 2020A Notes, the Series 2020C Notes and the Series 2020D Notes pursuantnotes is subject to the 2019 Note Purchase Agreement. Onsatisfaction of certain customary conditions to closing. We intend to use the proceeds of the notes to refinance existing long-term indebtedness, including long-term debt instruments with outstanding principal balances of $140 million and $30 million, which mature in December 2021 and August 20, 2020, OTP issued the Series 2020B Notes pursuant to the 2019 Note Purchase Agreement. OTP used the $75 million proceeds from the issuances to pay for capital expenditures2022, respectively, and for othergeneral corporate purposes. The Series 2019A Notes, Series 2019B Notes

Note 6 to our consolidated financial statements included in this Quarterly Report on Form 10-Q includes additional information regarding these short-term and Series 2019C Notes were issued by OTP on October 10, 2019.

On February 27, 2018 OTP issued $100 million aggregate principal amountlong-term debt instruments.

Financial Covenants
Certain of its 4.07% Series 2018A Senior Unsecured Notes due February 7, 2048 pursuant to a Note Purchase Agreement dated as of November 14, 2017 (the 2018 Note Purchase Agreement).

On December 13, 2016our short- and long-debt agreements require Otter Tail Corporation issued $80 million aggregate principal amount of its 3.55% Guaranteed Senior Notes due December 15, 2026 (the 2026 Notes) pursuantand OTP to a Note Purchase Agreement dated asmaintain certain financial covenants. As of September 23, 2016 (the 2016 Note Purchase Agreement). Our obligations under the 2016 Note Purchase Agreement and the 2026 Notes are guaranteed by our Material Subsidiaries (as defined in the 2016 Note Purchase Agreement, but specifically excluding OTP).

On February 27, 2014 OTP issued $60 million aggregate principal amount of its 4.68% Series A Senior Unsecured Notes due February 27, 2029 and $90 million aggregate principal amount of its 5.47% Series B Senior Unsecured Notes due February 27, 2044 pursuant to a Note Purchase Agreement dated as of August 14, 2013 (the 2013 Note Purchase Agreement).

On December 1, 2011 OTP issued $140 million aggregate principal amount of its 4.63% Senior Unsecured Notes due December 1,30, 2021, pursuant to a Note Purchase Agreement dated as of July 29, 2011 (the 2011 Note Purchase Agreement).

OTP also has outstanding its $122 million senior unsecured notes issued in three series consisting of $30 million aggregate principal amount of 6.15% Senior Unsecured Notes, Series B, due 2022; $42 million aggregate principal amount of 6.37% Senior Unsecured Notes, Series C, due 2027; and $50 million aggregate principal amount of 6.47% Senior Unsecured Notes, Series D, due 2037 (collectively, the 2007 Notes). The 2007 Notes were issued pursuant to a Note Purchase Agreement dated as of August 20, 2007 (the 2007 Note Purchase Agreement). 

Financial Covenants

Wewe were in compliance with thethese financial covenants inas further described below:

Otter Tail Corporation under its financial covenants, may not permit its ratio of interest-bearing debt to total capitalization to exceed 0.60 to 1.00, may not permit its interest and dividend coverage ratio to be less than 1.50 to 1.00, and may not permit its priority indebtedness to exceed 10% of our debt agreements as of September 30, 2020.

No Credit Agreement or Note Purchase Agreement contains any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies.

Our borrowing agreements are subject to certain financial covenants. Specifically:

Under the OTC Credit Agreement and the 2016 Note Purchase Agreement, we may not permit the ratio of our Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit our Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis). As of September 30, 2020, our Interest and Dividend Coverage Ratio calculated under the requirements of the OTC Credit Agreement and the 2016 Note Purchase Agreement was 4.74 to 1.00.

Under the 2016 Note Purchase Agreement, we may not permit our Priority Indebtedness to exceed 10% of our Total Capitalization.

Under the OTP Credit Agreement, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00.

Under the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, OTP may not permit the ratio of its Consolidated Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, in each case as provided in the related borrowing agreement, and OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement. As of September 30, 2020, OTP’s Interest and Dividend Coverage Ratio and Interest Charges Coverage Ratio, calculated under the requirements of the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, was 3.91 to 1.00.

Under the 2013 Note Purchase Agreement, the 2018 Note Purchase Agreement, and the 2019 Note Purchase Agreement, OTP may not permit its Interest-bearing Debt to exceed 60% of Total Capitalization and may not permit its Priority Indebtedness to exceed 20% of its Total Capitalization, in each case as provided in the related agreement.

total capitalization. As of September 30, 2020,2021, our ratio of Interest-bearing Debtinterest-bearing debt to Total Capitalizationtotal capitalization was 0.49 to 1.00 on a consolidated basis and 0.47 to 1.00, for OTP. Neither Otter Tail Corporation nor OTPour interest and dividend coverage ratio was 5.73 to 1.00, and we had any Priority Indebtedness outstanding asno priority indebtedness outstanding.

OTP under its financial covenants, may not permit its ratio of debt to total capitalization to exceed 0.60 to 1.00, may not permit its interest and dividend coverage ratio to be less than 1.50 to 1.00, and may not permit its priority debt to exceed 20% of its total capitalization. As of September 30, 2020.

OFF-BALANCE-SHEET ARRANGEMENTS

We2021, OTP's interest-bearing debt to total capitalization was 0.47 to 1.00, its interest and our subsidiary companiesdividend coverage ratio was 3.16 to 1.00, and OTP had no priority indebtedness outstanding.

31

OFF-BALANCE-SHEET ARRANGEMENTS
As of September 30, 2021 we have outstanding letters of credit totaling $12.1$16.9 million, buta portion of which reduces our lineborrowing capacity under our lines of credit borrowing limits are only restricted by $7.7 million incredit. No outstanding letters of credit.credit are reflected in outstanding short-term debt on our consolidated balance sheets. We do not have any other off-balance-sheet arrangements or any relationships with unconsolidated entities or financial partnerships. These entities are often referred to as structured finance special purpose entities or variable interest entities, which are established for the purpose of facilitating off-balance-sheet arrangements or for other contractually narrow or limited purposes. We are not exposed to any financing, liquidity, market or credit risk that could arise if we had such relationships.

47

2020 BUSINESS OUTLOOK

We are raising and narrowing our 2020 diluted earnings per share guidance range based on our financial results through the first nine months of 2020 and updated view of current business conditions in our Plastics and Manufacturing segments. We now expect our 2020 diluted earnings per share to be in the range of $2.26 to $2.36 instead of $2.10 to $2.30. This revision in guidance is primarily driven by strong performance in our Plastics segment along with continued favorable business conditions in this segment expected through the rest of 2020. Also, the impact of COVID-19 on our Electric segment has been less than previously expected. Our 2020 diluted earnings per share guidance includes $0.04 of dilution associated with actual and planned issuances of common shares under our At-the-Market Offering Program and Dividend Reinvestment and Employee Stock Purchase Plans to help fund construction projects at OTP.

We currently expect capital additions to be $380 million in 2020, with our Electric segment accounting for 96% of those additions, largely driven by the Merricourt and Astoria Station rate base projects. A five-year anticipated capital expenditures table is provided above on page 45.

Segment components of our revised 2020 diluted earnings per share guidance range compared with 2019 actual earnings and with our previously issued guidance are as follows.

 

 

2019

EPS by

  

2020 Guidance

February 20, 2020

  

2020 Guidance

May 5, 2020

  

2020 Guidance

August 3, 2020

  

2020 Guidance

November 2, 2020

 
Diluted Earnings Per Share  Segment   

Low

  

High

  

Low

  

High

  

Low

  

High

  

Low

  

High

 

Electric

 $1.48  $1.67  $1.70  $1.65  $1.70  $1.67  $1.70  $1.67  $1.69 

Manufacturing

 $0.32  $0.31  $0.35  $0.14  $0.23  $0.15  $0.23  $0.23  $0.25 

Plastics

 $0.51  $0.43  $0.47  $0.43  $0.47  $0.50  $0.54  $0.64  $0.66 

Corporate

 $(0.14) $(0.19) $(0.15) $(0.22) $(0.15) $(0.22) $(0.17) $(0.28) $(0.24)

Total

 $2.17  $2.22  $2.37  $2.00  $2.25  $2.10  $2.30  $2.26  $2.36 

Return on Equity

  11.6%  11.0%  11.7%  9.9%  11.1%  10.4%  11.4%  11.2%  11.7%

The estimates and assumptions underlying our latest 2020 guidance (issued on November 2, 2020) as compared to earlier guidance (issued on August 3, 2020) are summarized below.

Our 2020 guidance for our Electric segment includes:

CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES

o

Capital spending on the Merricourt and Astoria Station rate base projects of $177 million and $81 million, respectively, in 2020. The Merricourt project has rider recovery mechanisms in place in all three state jurisdictions. The Astoria Station project has rider recovery mechanisms in place in South Dakota and North Dakota. This project earns allowance for funds used during construction in Minnesota, has already been approved in our integrated resource plan and is expected to be recovered through a general rate increase in Minnesota requested on November 2, 2020. The Astoria Station capital project is currently on budget, with commercial operation expected to begin in the first quarter of 2021. The Merricourt project continues to be on budget and is expected to be in commercial operation before the end of December 2020.

o

Increased revenues related to $25 million in anticipated capital spending for self-funded generator interconnection agreements.

o

No major planned generation plant maintenance outages for 2020. Plant outage costs totaled $3.1 million in 2019.

o

The April 2020 Minnesota Supreme Court decision in OTP’s favor related to the higher return earned on Federal Energy Regulatory Commission jurisdiction transmission lines. The estimated impact of this decision is an increase to 2020 earnings of $0.05 per share. This was reflected in our third quarter financial results. On a go-forward basis the positive impact of this decision on an annual basis is $0.01 per share. We have updated our Minnesota Transmission Cost Recovery rider filing with new rates incorporating the results of the decision to reflect the effect of this ruling.

o

A favorable impact of weather on 2020 earnings compared to the forecasted earnings under normal weather conditions of $0.02 per share through September 30, 2020.

The above items are offset by:

o

Reductions in commercial and industrial demand related to the negative impacts of COVID-19 as some customers in our jurisdictions have either completely shut down operations or curtailed operations given reduced demands for their products and services. We also expect to incur increased costs for bad debts, personal 

48

protective equipment and the loss of late fee revenue. The total estimated earnings impact of these items ranges from $0.06 per share to $0.08 per share. OTP continues to work on obtaining regulatory relief to mitigate the impact of COVID-19 on its operating results. Potential COVID-19-related items include items such as lost commercial and industrial revenues, lost late fees and added expenses for increased bad debts, personal protective equipment and other increased operating and maintenance expenses. Our current electric segment guidance does not assume recovery of any of these items in 2020.

o

Increased expenses caused in large part by a decrease in the discount rate used for the pension plan and a lower rate used for our long-term rate of return. The discount rate for 2020 is 3.47% compared with 4.50% for 2019. For each 25-basis-point decline in the discount rate, pension expense increases approximately $1.0 million. The assumed long-term rate of return for 2020 is 6.88% compared with 7.25% in 2019. Each 25-basis-point decline in this rate equates to approximately $0.7 million in increased pension expense.

o

A planned contribution to the Otter Tail Power Company Foundation of $0.02 per share.

o

Higher depreciation and property tax expense due to large capital projects being put into service.

o

Increased interest costs associated with a full year’s interest expense on $100 million of senior unsecured notes issued in October 2019 and interest on the $35 million and $40 million of senior unsecured notes issued in February and August of 2020, respectively.

We are raising and narrowing our guidance range for our Manufacturing segment:

o

We now estimate an increase of $0.05 per share from the mid-point of our August 3, 2020 guidance. The upward revision is driven by a stronger than expected recovery in the second half of 2020 as compared to our previous assumptions.

o

Backlog for the Manufacturing segment is approximately $63 million for 2020 compared with $56 million one year ago.

We are raising and narrowing our earnings guidance range for our Plastics segment. Sales volumes in 2020 are now forecasted to be approximately 5% higher than 2019 given strong results in the first nine months of 2020 and current market conditions. Market conditions continued to improve during the third quarter due to limited effects of COVID-19, two resin suppliers invoking force majeure which positively impacted PVC pipe sale prices, concerns over hurricanes creating limited availability of PVC resin supplies, significant global demand for PVC resin and limited PVC pipe inventory across the country. All of these factors contributed to increasing sales and raw material prices which have favorably impacted our financial results in the Plastics segment. Also included in this updated guidance is a planned contribution to Otter Tail Corporation’s Foundation of $0.03 per share.

Corporate costs, net of tax, are expected to be higher than 2019 and our previous 2020 guidance due to increases in employee benefit costs resulting from the significant increase in 2020 earnings and a planned contribution to Otter Tail Corporation’s Foundation of $0.03 per share.

Critical Accounting Policies Involving Significant Estimates

The discussion and analysis of the financial statements andour results of operations are based on our consolidated financial statements which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparationCertain of these consolidated financial statements requiresour accounting policies require management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities.

liabilities in the preparation of our consolidated financial statements. We use estimates based on the best information availablehave disclosed in recording transactions and balances resulting from business operations. Estimates are used for such items as depreciable lives, asset impairment evaluations, tax provisions, collectability of trade accounts receivable, self-insurance programs, unbilled electric revenues, interim rate refunds, warranty reserves and actuarially determined benefits costs and liabilities. As better information becomes available or actual amounts are known, estimates are revised. Operating results can be affected by revised estimates. Actual results may differ from these estimates under different assumptions or conditions. Management has discussed the application of these critical accounting policies and the development of these estimates with the Audit Committee of the board of directors. A discussion of critical accounting policies is included under the caption “Critical Accounting Policies Involving Significant Estimates” on pages 57 through 59 of our Annual Report on Form 10-K for the year ended December 31, 2019. Aside2020 the critical accounting policies that affect our most significant estimates and assumptions used in preparing our consolidated financial statements. There have been no material changes to our critical accounting policies and estimates from an interim test of goodwill impairment performed for our BTD reporting unit, which was performed duringthose disclosed in the quarter ended March 31, 2020 and is further described below, theremost recent Annual Report on Form 10-K.

ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
There have been no material changes in critical accounting policies or estimates.

Goodwill is required to be tested annually for impairment and more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Examples of such events or circumstances may include, among others, a significant adverse change in business climate, weakness in an industry in which a reporting unit operates or recent significant cash or operating losses with expectations that those losses will continue. Goodwill is tested for impairment at the reporting unit level. A reporting unit is defined as an operating segment or one level below an operating segment (referred to as a component). A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and segment management regularly reviews the operating results of that component.

During the quarter ended March 31, 2020, the Company concluded an interim impairment test of goodwill of its BTD reporting unit, which carries a goodwill balance of $18.1 million, was warranted. This conclusion was reached based on the deteriorating economic conditions resulting from COVID-19 that led to lower product demand across all end markets beginning in the last half of March 2020 and the anticipation of subsequent further reduced demand resulting from temporary plant shutdowns of our original equipment manufacturer customers. In response to this reduced demand, BTD has reduced its operating levels and implemented certain cost reduction efforts, including temporary furloughs of production employees.

We estimated the fair value of the BTD reporting unit primarily using an income approach, which includes a discounted cash flow methodology to arrive at a fair value estimate by determining the present value of projected future cash flows over a specified period plus a terminal value related to cash flows beyond the projection period. The discount rate applied to the estimated future cash flows reflects our estimate of the weighted-average cost of capital of comparable companies. To supplement our income approach, we reference various market indications of fair value, where available. Our market approach includes fair value estimates using multiples derived from comparable enterprise values to EBITDA and revenue multiples, comparable price earnings ratios and, if available, comparable sales transactions for comparative peer companies.

The impairment assessment indicated no impairment was present as the estimated fair value of the reporting unit exceeded the carrying value by approximately 20%. The most significant assumption impacting our fair value estimate under the income approach is the anticipated duration and severity of reduced demand and the resulting impact on revenue levels given the uncertainty of economic conditions in light of COVID-19. Our assumptions included significantly reduced demand in the second quarter of 2020 followed by recovering levels of demand in the third and fourth quarters of 2020. Other significant assumptions included operating expense levels and our ability to manage costs during the anticipated period of reduced demand, the terminal growth rate which impacts estimated cash flow generation beyond our discrete projection period, and the discount rate applied to our estimated future cash flows.

Our estimates and assumptions inherently include a degree of uncertainty, and these estimates and assumptions could be significantly impacted by factors such as the duration and severity of reduced economic activity and industry conditions within the recreational vehicle, lawn and garden, construction, agricultural, and industrial and energy equipment end markets. A significant change in our estimates and assumptions could result in an impairment charge in a future period which could materially impact our results of operations and financial position.

Forward Looking Information - Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995

In connection with the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995 (the Act), we have filed cautionary statements identifying important factors that could cause our actual results to differ materiallyrisk from those discusseddisclosed in forward-looking statements made by or on behalf of the Company. When used in this Form 10-QItem 7A, Quantitative and Qualitative Disclosures About Market Risk, in future filings by the Company with the Securities and Exchange Commission, in our press releases and in oral statements, words such as "may", "will", "expect", "anticipate", "continue", "estimate", "project", "believes" or similar expressions are intended to identify forward-looking statements within the meaning of the Act and are included, along with this statement, for purposes of complying with the safe harbor provision of the Act. These forward-looking statements involve risks and uncertainties. Actual results may differ materially from those contemplated by the forward-looking statements due to, among other factors, the risks and uncertainties described in the section entitled “Risk Factors” in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2019, and in Part II, Item 1A2020.

ITEM 4.CONTROLS AND PROCEDURES
Evaluation of our Quarterly Report on Form 10-Q for the quarters ended June 30, 2020 and September 30, 2020, as well as the various factors described below:

The economic effects of the COVID-19 pandemic and measures taken to arrest its spread, as well as any emergency measures we are forced to take in response, could continue to adversely impact our business, including our results of operations, financial condition and liquidity.

Federal and state environmental regulation could require us to incur substantial capital expenditures and increased operating costs.

Weather impacts, including normal seasonal fluctuation of weather, as well as extreme weather events that could be associated with climate change, could adversely affect our results of operations.

Volatile financial markets and changes in our debt ratings could restrict our ability to access capital and increase borrowing costs and pension plan and postretirement health care expenses.

Any significant impairment of our goodwill would cause a decrease in our asset values and a reduction in our net operating income.

The inability of our subsidiaries to provide sufficient earnings and cash flows to allow us to meet our financial obligations and debt covenants and pay dividends to our shareholders could have an adverse effect on the Company.

We rely on our information systems to conduct our business, and failure to protect these systems against security breaches or cyber-attacks could adversely affect our business and results of operations. Additionally, if these systems fail or become unavailable for any significant period, our business could be harmed.

Economic conditions could negatively impact our businesses.

If we are unable to achieve the organic growth we expect, our financial performance may be adversely affected.

Our plans to grow our businesses through capital projects, including infrastructure and new technology additions, or to grow or realign our businesses through acquisitions or dispositions may not be successful, which could result in poor financial performance.

We may, from time to time, sell assets to provide capital to fund investments in our electric utility business or for other corporate purposes, which could result in the recognition of a loss on the sale of any assets sold and other potential liabilities. The sale of any of our businesses also exposes us to additional risks associated with indemnification obligations under the applicable sales agreements and any related disputes.

Significant warranty claims and remediation costs in excess of amounts normally reserved for such items could adversely affect our results of operations and financial condition.

We are subject to risks associated with energy markets.

Changes in tax laws, as well as judgments and estimates used in the determination of tax-related asset and liability amounts, could materially adversely affect our business, financial condition, results of operations and prospects.

Four of our operating companies have single customers that provide a significant portion of the individual operating company’s and the business segment’s revenue. The loss of, or significant reduction in revenue from, any one of these customers would have a significant negative financial impact on the operating company and its business segment and could have a significant negative financial impact on the Company.

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

We may experience fluctuations in revenues and expenses related to our electric operations, which may cause our financial results to fluctuate and could impair our ability to make distributions to shareholders or scheduled payments on our debt obligations, or to meet covenants under our borrowing agreements.

Actions by the regulators of our electric operations could result in rate reductions, lower revenues and earnings or delays in recovering capital expenditures.

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

OTP’s electric transmission and generation facilities could be vulnerable to cyber and physical attack that could impair our ability to provide electrical service to our customers or disrupt the U.S. bulk power system.

OTP’s electric generating facilities are subject to operational risks that could result in early closure, unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.

Regulation of generating plant emissions could affect our operating costs and the costs of supplying electricity to our customers and the economic viability of continued operation of certain of OTP’s steam-powered electric plants.

The long-range planning required for transmission and generation projects creates risks of increased costs and lower returns on investment when the project is finally completed.

Competition from foreign and domestic manufacturers, the price and availability of raw materials, trade policy and tariffs affecting prices and markets for raw material and manufactured products, prices and supply of scrap or recyclable material and general economic conditions could affect the revenues and earnings of our manufacturing businesses.

Economic conditions in the industries in which our customers operate can have an adverse impact on our results of operations and cash flows.

Our business and operating results may be adversely affected if we are not able to maintain our manufacturing, engineering and technological expertise.

Our manufacturing, painting and coating operations are subject to environmental, health and safety laws and regulations that could result in liabilities to us.

Our plastics operations are highly dependent on a limited number of vendors for PVC resin and a limited supply of PVC resin. The loss of a key vendor, or any interruption or delay in the supply of PVC resin, could result in reduced sales or increased costs for our plastics business.

We compete against many other manufacturers of PVC pipe and manufacturers of alternative products. Customers may not distinguish our products from those of our competitors.

Changes in PVC resin prices can negatively affect our plastics business.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

At September 30, 2020 we had exposure to market risk associated with interest rates because we had $48.6 million in short-term debt outstanding subject to variable interest rates indexed to LIBOR plus 1.50% under the OTC Credit Agreement.

All of our remaining consolidated long-term debt outstanding on September 30, 2020 has fixed interest rates. We manage our interest rate risk through the issuance of fixed-rate debt with varying maturities, through economic refunding of debt through optional refundings, limiting the amount of variable interest rate debt, and the utilization of short-term borrowings to allow flexibility in the timing and placement of long-term debt.

We have not used interest rate swaps to manage net exposure to interest rate changes related to our portfolio of borrowings. We maintain a ratio of fixed-rate debt to total debt within a certain range. It is our policy to enter into interest rate transactions and other financial instruments only to the extent considered necessary to meet our stated objectives. We do not enter into interest rate transactions for speculative or trading purposes.

The companies in our Manufacturing segment are exposed to market risk related to changes in commodity prices for steel, aluminum, and polystyrene and other plastics resins. The price and availability of these raw materials could affect the revenues and earnings of our Manufacturing segment.

The PVC pipe companies are exposed to market risk related to changes in commodity prices for PVC resins, the raw material used to manufacture PVC pipe. The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices are rising or stable, sales volume has been higher and when resin prices are falling, sales volume has been lower. Operating income may decline when the supply of PVC pipe increases faster than demand. Due to the commodity nature of PVC resin and the dynamic supply and demand factors worldwide, it is very difficult to predict gross margin percentages or to assume that historical trends will continue.

Item 4. Controls and Procedures

.Under the supervision and with the participation of companythe Company’s management, including ourthe Chief Executive Officer and the Chief Financial Officer, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 as amended (the Exchange Act)) as of September 30, 2020,2021, the end of the period covered by this report. Based on that evaluation, ourthe Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2020.

During the fiscal quarter ended September 30, 2020, there2021.

Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting (as defined in RuleRules 13a-15(f) under the Exchange Act) during the quarter ended September 30, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1.

ITEM 1.LEGAL PROCEEDINGS
Legal Proceedings

We are the subject of various legal and regulatory proceedings in the ordinary course of our business. Such matters are subject to many uncertainties and to outcomes that are not predictable with assurance. We record a liability in our consolidated financial statements for costs related to claims, including future legal costs, settlements and judgments, where we have assessed that a loss is probable, and an amount can be reasonably estimated. Material proceedings are described under note 3, “RateNote 9, Commitments and Regulatory Matters” and note 9, "Commitments and Contingencies"Contingencies, to the consolidated financial statements.

Item 1A. Risk Factors

Aside from the additional risk factor described belowstatements, and in Part II, Item 1AManagement's Discussion and Analysis of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, there hasFinancial Condition and Results of Operations, Regulatory Rate Matters.

ITEM 1A.RISK FACTORS
There have been no material change inchanges from the risk factors set forth under Part I,disclosed in Item 1A, “Risk Factors” on pages 29 through 39Risk Factors, of our Annual Report on Form 10-K for the year ended December 31, 2019.

2020.

32

ITEM 6.EXHIBITS
The economic effectsfollowing Exhibits are filed as part of, the COVID-19 pandemic and measures taken to arrest its spread,as well as any emergency measures we take in response, could continue to adversely impact our business, including our results of operations, financial condition and liquidity.

The outbreak and global spread of COVID-19, which has been declared a pandemicor incorporated by the World Health Organization, has adversely impacted economic activity and conditions worldwide and is currently impacting our business operations. The extent to which COVID-19 will continue to impact our business is highly uncertain and will depend on future developments and the extent of federal, state and local government responses affecting the economy. In particular, the COVID-19 pandemic could, among other things:

reference into, this report.

further reduce customer demand in our Manufacturing segment, where we have experienced a significant decline in orders

 No.Description
10.1

further reduce customer demand in our Electric segment, including demand from commercial and industrial customers;

result in lower PVC pipe sales due to potential delays or cancellation of public water and wastewater infrastructure projects caused by funding shortfalls;

lead to disruptions of our workforce;

force us to temporarily close certain plants or construction sites if precautions to prevent the spread of the virus at those locations are not effective;

increase our bad debt expenses, particularly in our Electric segment;

increase our future pension benefit cost and funding requirements;

increase health insurance premiums;

disrupt the supply chains, delivery systems or construction workforce related to our Electric segment maintenance requirements and capital expenditure plans, including our Merricourt and Astoria Station projects, resulting in further delays and increased costs;

disrupt global financial markets, reducing our ability to access capital necessary to finance such expenditures, and which could in the future negatively affect our liquidity; and

result in a recession or market correction that could materially affect our businessbetween Otter Tail Corporation, as Borrower, and the valuebanks named therein, with U.S. Bank National Association, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Form 8-Kfiled by Otter Tail Corporation on October 4, 2021)

10.2

We continue to monitor developments involving our workforce, customers, construction contractors, suppliers and vendors and take steps to mitigate against additional impacts, but given the unprecedented and dynamic nature of these circumstances, we cannot predict the full extent of the impact that COVID-19 will have on our results of operations, financial condition and liquidity. The situation continues to change, and the magnitude of the impact will depend, in part, on the length and severity of the pandemic. However, the effects could have a material impact on our results of operations, financial condition and liquidity and heighten many of the known risks described under Part I, Item 1A, “Risk Factors” on pages 29 through 39 of our Annual Report on Form 10-K for the year ended December 31, 2019.

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Item 6.      Exhibits

31.1

31.1

31.2

31.2

32.1

32.1

32.2

32.2

101.SCH

101.SCH

Inline XBRL Taxonomy Extension Schema Document.

Document

101.CAL

101.CAL

Inline XBRL Taxonomy Extension Calculation Linkbase Document.

Document

101.LAB

101.LAB

Inline XBRL Taxonomy Extension Label Linkbase Document.

Document

101.PRE

101.PRE

Inline XBRL Taxonomy Extension Presentation Linkbase Document.

Document

101.DEF

101.DEF

Inline XBRL Taxonomy Extension Definition Linkbase Document.

Document

104

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).


33

Table of Contents
SIGNATURES

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

OTTER TAIL CORPORATION

By:    /s/ Kevin G. Moug            

Kevin G. Moug
      Chief Financial Officer and Senior Vice President
   (Chief Financial Officer/Authorized Officer)

Dated: November 6, 2020

OTTER TAIL CORPORATION
By:/s/ Kevin G. Moug
Kevin G. Moug
Chief Financial Officer and Senior Vice President
(duly authorized officer and principal financial officer)
Dated: November 3, 2021
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