SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

☒~~QUARTERLY REPORT PURSUANT TO SECTIO~~NQuarterly Report pursuant to Section 13 ORor 15(d) ~~OF THE SECURITIES~~

~~EXCHANGE ACT OF~~of the Securities Exchange Act of 1934

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T ~~(§ 232.405 of this chapter)~~ during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes☑No☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting ~~company, 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 ~~checkmark~~check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act☐

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

~~July~~ 31,~~2020~~– ~~40,872,064~~

41,538,084CommonShares ($5 par value)

asof April 30, 2021.

~~OTTER TAIL CORPORATION~~

~~INDEX~~

~~Part I. Financial Information~~	~~Page No.~~
TABLE OF CONTENTS


DEFINITIONS

The following abbreviations or acronyms are used in the text.

AFUDC

Allowance for Funds Used During Construction

MPUC

Minnesota Public Utilities Commission

ARP

Alternative Revenue Program

NDPSC

North Dakota Public Service Commission

BTD

BTD Manufacturing, Inc.

Northern Pipe

Northern Pipe Products, Inc.

CIP

Conservation Improvement Program

OTC

Otter Tail Corporation

ECR

Environmental Cost Recovery

OTP

Otter Tail Power Company

ECR

Environmental Cost Recovery Rider

PACE

Partnership in Assisting Community Expansion

EEP

Energy Efficiency Plan

PIR

Phase-In Rider

EPA

Environmental Protection Agency

PTCs

Production tax credits

ESSRP

Executive Survivor and Supplemental Retirement Plan

PVC

Polyvinyl chloride

FCA

Fuel Clause Adjustment

RHR

Regional Haze Rule

FERC

Federal Energy Regulatory Commission

ROE

Return on equity

GCR

Generation Cost Recovery

RRR

Renewable Resource Rider

ISO

Independent System Operator

SDPUC

South Dakota Public Utilities Commission

kiloWatt

SEC

Securities and Exchange Commission

kwh

kilowatt-hour

T.O. Plastics

T.O. Plastics, Inc.

Merricourt

Merricourt Wind Energy Center

TCR

Transmission Cost Recovery

MISO

Midcontinent Independent System Operator, Inc.

Vinyltech

Vinyltech Corporation


FORWARD-LOOKING INFORMATION

This 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, 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, 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

Table of I~~tem~~ 1. Contents

OTTER TAIL CORPORATION

fCONSOLIDATED BALANCE SHEETS~~inancial~~ s~~tatements~~

~~Otter Tail Corporation~~

~~Consolidated Balance Sheets~~

~~(not audited)~~


(in thousands, except share data)	March 31, 2021		December 31, 2020

Assets
Current Assets
Cash and Cash Equivalents	$	1,212	$	1,163
Receivables, net of allowance for credit losses	134,390		113,959
Inventories	92,426		92,165
Regulatory Assets	21,419		21,900
Other Current Assets	9,516		5,645
Total Current Assets	258,963		234,832
Noncurrent Assets
Investments	54,446		51,856
Property, Plant and Equipment, net of accumulated depreciation	2,060,792		2,049,273
Regulatory Assets	167,556		168,395
Intangible Assets, net of accumulated amortization	9,869		10,144
Goodwill	37,572		37,572
Other Noncurrent Assets	29,342		26,282
Total Noncurrent Assets	2,359,577		2,343,522
Total Assets	$	2,618,540	$	2,578,354

Liabilities and Shareholders' Equity
Current Liabilities
Short-Term Debt	$	134,851	$	80,997
Current Maturities of Long-Term Debt	139,941		140,087
Accounts Payable	113,073		130,805
Accrued Salaries and Wages	17,635		26,908
Accrued Taxes	19,437		18,831
Regulatory Liabilities	12,517		16,663
Other Current Liabilities	21,975		22,495
Total Current Liabilities	459,429		436,786
Noncurrent Liabilities and Deferred Credits
Pensions Benefit Liability	103,193		114,055
Other Postretirement Benefits Liability	67,255		67,359
Regulatory Liabilities	234,986		233,973
Deferred Income Taxes	160,529		153,376
Deferred Tax Credits	17,219		17,405
Other Noncurrent Liabilities	63,577		60,002
Total Noncurrent Liabilities and Deferred Credits	646,759		646,170
Commitments and Contingencies (Note 9)	0		0
Capitalization
Long-Term Debt, net of current maturities	624,485		624,432
Shareholders' Equity
Common Shares: 50,000,000 share authorized of $5 par value; 41,510,455 and 41,469,879 outstanding at March 31, 2021 and December 31, 2020	207,552		207,349
Additional Paid-In Capital	416,708		414,246
Retained Earnings	271,999		257,878
Accumulated Other Comprehensive Loss	(8,392)		(8,507)
Total Shareholders' Equity	887,867		870,966
Total Capitalization	1,512,352		1,495,398
Total Liabilities and Shareholders' Equity	$	2,618,540	$	2,578,354

(in thousands)

June 30,
2020

December 31,
2019

Assets

Current Assets

Cash and Cash Equivalents
$ 39,512 $ 21,199
Accounts Receivable:

Trade—Net
84,197 77,947
Other
6,452 8,773
Inventories
89,754 97,851
Unbilled Receivables
19,019 20,911
Income Taxes Receivable
- 1,487
Regulatory Assets
19,958 21,650
Other
8,031 5,042
Total Current Assets
266,923 254,860

Investments
10,581 9,894
Other Assets
40,138 40,196
Goodwill
37,572 37,572
Other Intangibles—Net
10,703 11,290
Regulatory Assets
141,063 144,138

Right of Use Assets - Operating Leases
20,571 21,851

Plant

Electric Plant in Service
2,211,082 2,212,884
Nonelectric Operations
252,933 247,356
Construction Work in Progress
321,621 185,238
Total Gross Plant
2,785,636 2,645,478
Less Accumulated Depreciation and Amortization
923,948 891,684
Net Plant
1,861,688 1,753,794

Total Assets
$ 2,389,239 $ 2,273,595

Table of Contents

OTTER TAIL CORPORATION

CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended March 31,
(in thousands, except per-share amounts)	2021		2020

Operating Revenues
Electric	$	123,699	$	119,870
Product Sales	138,011		114,877
Total Operating Revenues	261,710		234,747
Operating Expenses
Electric Production Fuel	14,714		13,735
Electric Purchased Power	19,260		18,830
Electric Operating and Maintenance Expenses	41,421		40,615
Cost of Products Sold (excluding depreciation)	101,977		85,879
Other Nonelectric Expenses	13,693		11,900
Depreciation and Amortization	22,126		20,399
Electric Property Taxes	4,320		4,100
Total Operating Expenses	217,511		195,458
Operating Income	44,199		39,289
Other Income and Expense
Interest Charges	9,398		8,123
Nonservice Cost Components of Postretirement Benefits	383		871
Other Income (Expense)	1,160		(389)
Income Before Income Taxes	35,578		29,906
Income Tax Expense	5,249		5,638
Net Income	$	30,329	$	24,268

Weighted-Average Common Shares Outstanding:
Basic	41,455		40,217
Diluted	41,700		40,444
Earnings Per Share:
Basic	$	0.73	$	0.60
Diluted	$	0.73	$	0.60

~~Otter Tail Corporation~~

~~Consolidated Balance Sheets~~

~~(not audited)~~

(in thousands, except share data)

June 30,
2020

December 31,
2019

Liabilities and Equity

Current Liabilities

Short-Term Debt
$ 41,239 $ 6,000
Current Maturities of Long-Term Debt
261 183
Accounts Payable
133,967 120,775
Accrued Salaries and Wages
16,891 22,730
Accrued Taxes
12,193 17,525
Regulatory Liabilities
13,023 7,480
Current Operating Lease Liabilities
4,543 4,136
Other Accrued Liabilities
10,806 10,912
Total Current Liabilities
232,923 189,741

Pensions Benefit Liability
86,657 98,970
Other Postretirement Benefits Liability
71,845 71,437
Long-Term Operating Lease Liabilities
16,584 18,193
Other Noncurrent Liabilities
34,647 30,833

Commitments and Contingencies (note 9)

Deferred Credits

Deferred Income Taxes
141,538 131,941
Deferred Tax Credits
17,969 18,626
Regulatory Liabilities
238,160 239,906
Other
2,472 2,885
Total Deferred Credits
400,139 393,358

Capitalization

Long-Term Debt—Net
724,389 689,581

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

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

Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares; Outstanding, 2020—40,848,828 Shares; 2019—40,157,591 Shares
204,244 200,788
Premium on Common Shares
390,141 364,790
Retained Earnings
233,705 222,341
Accumulated Other Comprehensive Loss
(6,035 ) (6,437 )
Total Common Equity
822,055 781,482
Total Capitalization
1,546,444 1,471,063
Total Liabilities and Equity
$ 2,389,239 $ 2,273,595

See accompanying ~~condensed~~ notes to consolidated financial statements.

Table of Contents

OTTER TAIL CORPORATION

~~Otter Tail Corporation~~

~~Consolidated Statements of Income~~

~~(not audited)~~

Three Months Ended
June 30,

Six Months Ended
June 30,

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

2020

2019

2020

2019

Operating Revenues

Electric:

Revenues from Contracts with Customers
$ 97,921 $ 101,861 $ 217,878 $ 231,006
Changes in Accrued Revenues under Alternative Revenue Programs
209 369 122 (680 )
Total Electric Revenues
98,130 102,230 218,000 230,326
Product Sales from Contracts with Customers
94,626 126,973 209,503 244,849
Total Operating Revenues
192,756 229,203 427,503 475,175
Operating Expenses

Production Fuel – Electric
8,788 8,296 22,523 27,216
Purchased Power – Electric System Use
13,682 19,633 32,512 41,585
Electric Operation and Maintenance Expenses
33,179 39,856 73,794 78,238
Cost of Products Sold (depreciation included below)
73,832 97,996 159,711 188,578
Other Nonelectric Expenses
10,762 13,262 22,662 26,739
Depreciation and Amortization
20,436 19,441 40,835 38,572
Property Taxes – Electric
4,168 3,900 8,268 7,859
Total Operating Expenses
164,847 202,384 360,305 408,787
Operating Income
27,909 26,819 67,198 66,388
Interest Charges
8,662 7,825 16,785 15,651
Nonservice Cost Components of Postretirement Benefits
868 1,075 1,739 2,110
Other Income
2,410 850 2,021 2,094
Income Before Income Taxes
20,789 18,769 50,695 50,721
Income Tax Expense
3,808 3,343 9,446 8,971
Net Income
16,981 15,426 41,249 41,750

Average Number of Common Shares Outstanding – Basic
40,513,286 39,712,036 40,365,214 39,684,679
Average Number of Common Shares Outstanding – Diluted
40,676,761 39,917,831 40,560,549 39,910,499

Basic Earnings Per Common Share
$ 0.42 $ 0.39 $ 1.02 $ 1.05

Diluted Earnings Per Common Share
$ 0.42 $ 0.39 $ 1.02 $ 1.05
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three Months Ended March 31,
(in thousands)	2021		2020

Net Income	$	30,329	$	24,268
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) During Period	(5)		2
Unrealized Gains (Losses) Arising During Period	(40)		126
Income Tax (Expense) Benefit	10		(27)
Available-for-Sale Securities, net of tax	(35)		101
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs	203		138
Income Tax Expense	(53)		(36)
Pension and Postretirement Benefit Plan, net of tax	150		102
Total Other Comprehensive Income	115		203
Total Comprehensive Income	$	30,444	$	24,471

See accompanying ~~condensed~~ notes to consolidated financial statements.

Table of Contents

OTTER TAIL CORPORATION

~~Otter Tail Corporation~~

~~Consolidated Statements of Comprehensive Income~~

~~(not audited)~~

Three Months Ended
June 30,

Six Months Ended
June 30,

(in thousands)

2020

2019

2020

2019

Net Income
$ 16,981 $ 15,426 $ 41,249 $ 41,750
Other Comprehensive Income:

Unrealized Gains on Available-for-Sale Securities:

Reversal of Previously Recognized Losses (Gains) Realized on Sale of Investments and Included in Other Income During Period
32 (4 ) 34 (4 )
Unrealized Gains Arising During Period
92 66 218 157
Income Tax Expense
(26 ) (13 ) (53 ) (32 )
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax
98 49 199 121
Pension and Postretirement Benefit Plans:

Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11)
137 129 275 259
Income Tax Expense
(36 ) (33 ) (72 ) (67 )
Pension and Postretirement Benefit Plans – net-of-tax
101 96 203 192
Total Other Comprehensive Income
199 145 402 313
Total Comprehensive Income
$ 17,180 $ 15,571 $ 41,651 $ 42,063
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY


(in thousands, except common shares outstanding)	Common Shares Outstanding	Par Value, Common Shares		Additional Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)1		Total Shareholders' Equity

Balance, December 31, 2020	41,469,879	$	207,349	$	414,246	$	257,878	$	(8,507)	$	870,966
Common Stock Issuances, Net of Expenses	76,277	382		(407)						(25)
Common Stock Retirements and Forfeitures	(35,701)	(179)		(1,328)						(1,507)
Net Income						30,329				30,329
Other Comprehensive Income								115		115
Stock Compensation Expense				4,197						4,197
Common Dividends ($0.39 per share)						(16,208)				(16,208)
Balance, March 31, 2021	41,510,455	$	207,552	$	416,708	$	271,999	$	(8,392)	$	887,867

Balance, December 31, 2019	40,157,591	$	200,788	$	364,790	$	222,341	$	(6,437)	$	781,482
Common Stock Issuances, Net of Expenses	257,074	1,285		6,990						8,275
Common Stock Retirements and Forfeitures	(38,217)	(191)		(1,881)						(2,072)
Net Income						24,268				24,268
Other Comprehensive Income								203		203
Stock Compensation Expense				2,770						2,770
Common Dividends ($0.37 per share)						(14,907)				(14,907)
Balance, March 31, 2020	40,376,448	$	201,882	$	372,669	$	231,702	$	(6,234)	$	800,019

1Accumulated Other Comprehensive Income (Loss) as of March 31, 2021 and December 31, 2020 is comprised of the following:
(in thousands) March 31,
2021 December 31,
2020
Unrealized Gain (Loss) on Available-for-Sale Debt Securities:
Before Tax $ 220 $ 265
Tax Effect (46) (56)
Unrealized Gain (Loss) on Available-for-Sale Debt, net of tax 174 209
Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits:
Before Tax (11,590) (11,793)
Tax Effect 3,024 3,077
Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits, net of tax (8,566) (8,716)
Accumulated Other Comprehensive Loss:
Before Tax (11,370) (11,528)
Tax Effect 2,978 3,021
Net Accumulated Other Comprehensive Loss $ (8,392) $ (8,507)

See accompanying ~~condensed~~ notes to consolidated financial statements.

~~Table of Contents~~

~~Consolidated Statements of Common Shareholders’ Equity~~

~~For the~~ ~~Three- and Six~~~~-Month Periods Ended~~ ~~June 30~~~~, 20~~20 ~~and 201~~9

~~(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, March 31, 2020
40,376,448 $ 201,882 $ 372,669 $ 231,702 $ (6,234 ) $ 800,019
Common Stock Issuances, Net of Expenses
472,380 2,362 16,235 18,597
Net Income
16,981 16,981
Other Comprehensive Income
199 199
Employee Stock Incentive Plan Expense
1,237 1,237
Common Dividends ($0.37 per share)
(14,978 ) (14,978 )
Balance, June 30, 2020
40,848,828 $ 204,244 $ 390,141 $ 233,705 $ (6,035 ) $ 822,055

Balance, March 31, 2019
39,729,708 $ 198,649 $ 342,991 $ 203,619 $ (4,760 ) $ 740,499
Common Stock Issuances, Net of Expenses
25,194 126 (109 ) 17
Net Income
15,426 15,426
Other Comprehensive Income
145 145
Employee Stock Incentive Plan Expense
2,148 2,148
Common Dividends ($0.35 per share)
(13,930 ) (13,930 )
Balance, June 30, 2019
39,754,902 $ 198,775 $ 345,030 $ 205,115 $ (4,615 ) $ 744,305

Balance, December 31, 2019
40,157,591 $ 200,788 $ 364,790 $ 222,341 $ (6,437 ) $ 781,482
Common Stock Issuances, Net of Expenses
729,454 3,647 23,222 26,869
Common Stock Retirements
(38,217 ) (191 ) (1,878 ) (2,069 )
Net Income
41,249 41,249
Other Comprehensive Income
402 402
Employee Stock Incentive Plan Expense
4,007 4,007
Common Dividends ($0.74 per share)
(29,885 ) (29,885 )
Balance, June 30, 2020
40,848,828 $ 204,244 $ 390,141 $ 233,705 $ (6,035 ) $ 822,055

Balance, December 31, 2018
39,664,884 $ 198,324 $ 344,250 $ 190,433 $ (4,144 ) $ 728,863
Common Stock Issuances, Net of Expenses
145,242 727 (710 ) 17
Common Stock Retirements
(55,224 ) (276 ) (2,454 ) (2,730 )
Net Income
41,750 41,750
Other Comprehensive Income
313 313
ASU 2018-02 2017 TCJA Stranded Tax Transfer
784 (784 ) -
Employee Stock Incentive Plan Expense
3,944 3,944
Common Dividends ($0.70 per share)
(27,852 ) (27,852 )
Balance, June 30, 2019
39,754,902 $ 198,775 $ 345,030 $ 205,115 $ (4,615 ) $ 744,305

Table of Contents

OTTER TAIL CORPORATION

~~Otter Tail Corporation~~

~~Consolidated Statements of Cash Flows~~

~~(not audited)~~

Six Months Ended
June 30,

(in thousands)

2020

2019

Operating Activities

Net Income
$ 41,249 $ 41,750
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:

Depreciation and Amortization
40,835 38,572
Deferred Tax Credits
(657 ) (674 )
Deferred Income Taxes
9,472 960
Change in Deferred Debits and Other Assets
5,565 3,884
Discretionary Contribution to Pension Plan
(11,200 ) (10,000 )
Change in Noncurrent Liabilities and Deferred Credits
5,178 11,942
Allowance for Equity/Other Funds Used During Construction
(1,858 ) (688 )
Stock Compensation Expense
4,007 3,944
Other—Net
(147 ) 276
Cash (Used for) Provided by Current Assets and Current Liabilities:

Change in Receivables
(3,929 ) (30,478 )
Change in Inventories
8,097 410
Change in Other Current Assets
(1,066 ) 2,870
Change in Payables and Other Current Liabilities
(23,562 ) 222
Change in Interest and Income Taxes Receivable/Payable
1,917 6,297
Net Cash Provided by Operating Activities
73,901 69,287
Investing Activities

Capital Expenditures
(119,830 ) (54,012 )
Proceeds from Disposal of Noncurrent Assets
3,953 3,405
Cash Used for Investments and Other Assets
(5,128 ) (4,776 )
Net Cash Used in Investing Activities
(121,005 ) (55,383 )
Financing Activities

Change in Checks Written in Excess of Cash
550 (1,120 )
Net Short-Term Borrowings
35,239 18,003
Proceeds from Issuance of Common Stock
27,225 -
Common Stock Issuance Expenses
(374 ) -
Payments for Shares Withheld for Employee Tax Obligations
(2,069 ) (2,730 )
Proceeds from Issuance of Long-Term Debt
35,000 -
Short-Term and Long-Term Debt Issuance Expenses
(179 ) -
Payments for Retirement of Long-Term Debt
(90 ) (84 )
Dividends Paid
(29,885 ) (27,852 )
Net Cash Provided by (Used in) Financing Activities
65,417 (13,783 )
Net Change in Cash and Cash Equivalents
18,313 121
Cash and Cash Equivalents at Beginning of Period
21,199 861
Cash and Cash Equivalents at End of Period
$ 39,512 $ 982
CONSOLIDATED STATEMENTS OF CASH FLOWS


	Three Months Ended March 31,
(in thousands)	2021		2020

Operating Activities
Net Income	$	30,329	$	24,268
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation and Amortization	22,126		20,399
Deferred Tax Credits	(186)		(329)
Deferred Income Taxes	5,697		5,812
Change in Deferred Debits and Other Assets	543		5,087
Discretionary Contribution to Pension Plan	(10,000)		(11,200)
Change in Noncurrent Liabilities and Deferred Credits	(1,804)		860
Allowance for Equity/Other Funds Used During Construction	(45)		(791)
Stock Compensation Expense	4,197		2,770
Other—Net	(1,569)		46
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	(20,431)		(16,666)
Change in Inventories	(261)		(301)
Change in Other Current Assets	(3,871)		(447)
Change in Payables and Other Current Liabilities	(6,930)		(7,690)
Change in Interest Payable and Income Taxes Receivable/Payable	(2,525)		(41)
Net Cash Provided by Operating Activities	15,270		21,777
Investing Activities
Capital Expenditures	(50,076)		(75,059)
Proceeds from Disposal of Noncurrent Assets	3,244		2,487
Cash Used for Investments and Other Assets	(2,188)		(2,487)
Net Cash Used in Investing Activities	(49,020)		(75,059)
Financing Activities
Change in Checks Written in Excess of Cash	(2,144)		0
Net Short-Term Borrowings	53,854		13,893
Proceeds from Issuance of Common Stock	0		8,399
Common Stock Issuance Expenses	(25)		(124)
Payments for Shares Withheld for Employee Tax Obligations	(1,507)		(2,072)
Proceeds from Issuance of Long-Term Debt	0		35,000
Short-Term and Long-Term Debt Issuance Expenses	(2)		(177)
Payments for Retirement of Long-Term Debt	(169)		(45)
Dividends Paid	(16,208)		(14,907)
Net Cash Provided by Financing Activities	33,799		39,967
Net Change in Cash and Cash Equivalents	49		(13,315)
Cash and Cash Equivalents at Beginning of Period	1,163		21,199
Cash and Cash Equivalents at End of Period	$	1,212	$	7,884





Supplemental Disclosure of Noncash Investing Activities
Transactions Related to Capital Additions Not Settled in Cash	$	18,962	$	16,193

See accompanying ~~condensed~~ notes to consolidated financial ~~statements.~~

statements

Table of Contents

O~~TTER~~

OTTER TAIL CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(

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) has~~we have included all adjustments (including normal recurring 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's~~our 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 six~~ months ended ~~June 30, 2020~~March 31, 2021 should not be taken as an indication of earnings for all or any part of the balance of the year.

1. ~~Summary~~Use of ~~Significant Accounting Policies~~

~~Revenue Recognition~~

Due to the diverse business operations 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 delivered or transmitted at~~best information available in recording transactions and balances resulting from business operations. As better information becomes available (or actual 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 on~~recorded 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 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.~~

~~Table of Contents~~

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~~ ~~six~~~~-month periods ended~~ ~~June 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~~ ~~six~~~~-month periods ended~~ ~~June 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 contracts~~results can be ~~offset according~~affected by revisions to ~~legally enforceable netting arrangements. The Company does~~ ~~not~~ ~~offset assets~~prior 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.~~

~~Table of Contents~~

~~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~~ ~~June 30, 2020~~ ~~and~~ ~~December 31, 2019:~~

June 30, 2020 (in thousands)

Level 1

Level 2

Level 3
Assets:

Investments:

Equity Funds – Held by Captive Insurance Company
$ 1,450
Corporate Debt Securities – Held by Captive Insurance Company
$ 3,062
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company
5,960
Other Assets:

Money Market and Mutual Funds –Retirement Plans
1,560
Total Assets
$ 3,010 $ 9,022

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 $50.0 million, OTP’s 35% share of CCMC’s unrecovered costs as of ~~June 30, 2020.~~

~~Table of Contents~~

~~Inventories~~

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

June 30,

December 31,

(in thousands)

2020

2019

Finished Goods
$ 26,190 $ 31,863
Work in Process
14,418 16,508
Raw Material, Fuel and Supplies
49,146 49,480
Total Inventories
$ 89,754 $ 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~~ ~~June 30, 2020~~ ~~and~~ ~~December~~ ~~31,~~~~2019:~~

June 30, 2020 (in thousands)

Gross Carrying
Amount

Accumulated
Amortization

Net Carrying
Amount

Remaining
Amortization
Periods (months)

Amortizable Intangible Assets:

Customer Relationships
$ 22,491 $ 11,820 $ 10,671 82 - 182
Other
179 147 32 2 - 39
Total
$ 22,670 $ 11,967 $ 10,703

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

Six Months Ended

June 30,

June 30,

(in thousands)

2020

2019

2020

2019

Amortization Expense – Intangible Assets
$ 291 $ 296 $ 587 $ 592

~~The estimated annual amortization expense for these intangible assets for the next~~ ~~five~~ ~~years is:~~

(in thousands)

2020

2021

2022

2023

2024

Estimated Amortization Expense – Intangible Assets
$ 1,140 $ 1,105 $ 1,105 $ 1,104 $ 1,099

~~Supplemental Disclosures of Cash Flow Information~~

As of June 30,

(in thousands)

2020

2019

Noncash Investing Activities:

Transactions Related to Capital Additions not Settled in Cash
$ 61,925 $ 16,841

~~Table of Contents~~

~~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

Six Months Ended

June 30,

June 30,

(in thousands)

2020

2019

2020

2019

Beginning Balance
$ 1,681 $ 1,533 $ 1,339 $ 1,407
Additions Charged to Expense (net of recoveries)
736 216 1,371 463
Reductions for Amounts Written Off
(317 ) (58 ) (610 ) (179 )
Ending Balance
$ 2,100 $ 1,691 $ 2,100 $ 1,691

~~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.~~

~~Table of Contents~~

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 be~~Plastics, consistent with ~~its~~our business strategy, organizational structure and ~~the~~our internal reporting and review ~~process~~processes used by ~~the Company’s~~our chief operating decision ~~maker. These businesses sell products~~maker 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, Manufacturing~~make strategic decisions.

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

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 businesses~~costs are ~~owned by its wholly owned subsidiary, Varistar Corporation. The Company’s~~not allocated to our operating segments. Corporate operating costs include items such as corporate staff and overhead costs, the results of ~~the Company’s~~our 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 ~~totals~~consolidated amounts.

Information for each segment and our unallocated corporate costs for the three months ended March 31, 2021 and 2020 are as follows:



(in thousands)	2021		2020

Operating Revenue1
Electric	$	123,699	$	119,870
Manufacturing	75,825		68,479
Plastics	62,186		46,398
Total	$	261,710	$	234,747
Net Income (Loss)
Electric	$	17,587	$	16,182
Manufacturing	5,385		4,927
Plastics	9,147		5,449
Corporate	(1,790)		(2,290)
Total	$	30,329	$	24,268

1Amounts reflect operating revenues to external customers. Intersegment operating revenues are not material for any period presented.

Table of Contents

The following provides the identifiable assets by segment and corporate assets as of March 31, 2021 and December 31, 2020:


(in thousands)	March 31, 2021		December 31, 2020

Identifiable Assets
Electric	$	2,242,026	$	2,233,399
Manufacturing	209,477		191,005
Plastics	111,148		99,767
Corporate	55,889		54,183
Total	$	2,618,540	$	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 months ended March 31, 2021 and 2020:



(in thousands)	2021		2020

Operating Revenues
Electric Segment
Retail: Residential	$	37,485	$	35,839
Retail: Commercial and Industrial	66,403		68,942
Retail: Other	1,818		1,822
Total Retail	105,706		106,603
Transmission	11,944		10,841
Wholesale	4,507		876
Other	1,542		1,550
Total Electric Segment	123,699		119,870
Manufacturing Segment
Metal Parts and Tooling	62,673		57,211
Plastic Products and Tooling	10,295		9,883
Scrap Metal Sales	2,857		1,385
Total Manufacturing Segment	75,825		68,479
Plastics Segment
PVC Pipe	62,186		46,398
Total Operating Revenue	261,710		234,747
Less: Noncontract Revenues Included Above
Electric Segment - Alternative Revenue Program Revenues	(975)		(87)
Total Operating Revenues from Contracts with Customers	$	262,685	$	234,834

4. Select Balance Sheet Information

Receivables and Allowance for Credit Losses

Receivables as of March 31, 2021 and December 31, 2020 are as follows:


(in thousands)	March 31, 2021		December 31, 2020

Receivables
Trade	$	112,060	$	87,048
Other	6,982		8,939
Unbilled Receivables	18,331		21,187
Total Receivables	137,373		117,174
Less Allowance for Credit Losses	2,983		3,215
Receivables, net of allowance for credit losses	$	134,390	$	113,959

Table of Contents

The following is a summary of activity in the allowance for credit losses for the three months ended March 31, 2021 and 2020:


(in thousands)	2021		2020

Beginning Balance, January 1	$	3,215	$	1,339
Additions Charged to Expense	211		635
Reductions for Amounts Written-Off, Net of Recoveries	(443)		(293)
Ending Balance, March 31	$	2,983	$	1,681

Inventories

Inventories consist of the following as of March 31, 2021 and December 31, 2020:


(in thousands)	March 31, 2021		December 31, 2020

Finished Goods	$	20,567	$	22,046
Work in Process	19,324		16,210
Raw Material, Fuel and Supplies	52,535		53,909
Total Inventories	$	92,426	$	92,165

Investments

The following is a summary of our investments at March 31, 2021 and December 31, 2020:


(in thousands)	March 31, 2021		December 31, 2020

Corporate-Owned Life Insurance Policies	$	38,205	$	36,825
Debt Securities	9,209		9,260
Money Market Funds	1,862		4,075
Mutual Funds	5,141		1,662
Other Investments	29		34
Total Investments	$	54,446	$	51,856

The amount of unrealized gains and losses on debt securities as of March 31, 2021 and December 31, 2020 are not material and no unrealized losses were deemed to be other-than-temporary. In addition, the ~~Company’s consolidated~~amount of unrealized gains and losses on marketable equity securities still held as of March 31, 2021 and December 31, 2020 are not material.

Property, Plant and Equipment

Major classes of property, plant and equipment as of March 31, 2021 and December 31, 2020 include:


(in thousands)	March 31, 2021		December 31, 2020

Electric Plant in Service
Electric Plant in Service	2,682,884		2,531,352
Construction Work in Progress	77,676		203,078
Total Gross Electric Plant	2,760,560		2,734,430
Less Accumulated Depreciation and Amortization	796,161		778,988
Net Electric Plant	$	1,964,399	$	1,955,442
Nonelectric Property, Plant and Equipment
Nonelectric Property, Plant and Equipment in Service	259,975		258,730
Construction Work in Progress	12,086		9,290
Total Gross Nonelectric Property, Plant and Equipment	272,061		268,020
Less Accumulated Depreciation and Amortization	175,668		174,189
Net Nonelectric Property, Plant and Equipment	96,393		93,831
Net Property, Plant and Equipment	$	2,060,792	$	2,049,273

Table of Contents

5. Regulatory Matters

Regulatory Assets and Liabilities

The following presents our current and long-term regulatory assets and liabilities as of March 31, 2021 and December 31, 2020 and the period we expect to recover or refund such amounts:


	Period of	March 31, 2021				December 31, 2020
(in thousands)	Recovery/Refund	Current		Long-Term		Current		Long Term

Regulatory Assets
Pension and Other Postretirement Benefit Plans1	Various	$	11,037	$	143,996	$	11,037	$	146,071
Alternative Revenue Program Riders2	Up to 3 years	6,891		10,418		8,871		9,373
Asset Retirement Obligations1	Asset lives	0		8,539		0		8,462

ISO Cost Recovery Trackers1	Up to 2 years	809		703		1,079		867
Unrecovered Project Costs1	Up to 3 years	1,556		2,937		361		2,989
Deferred Rate Case Expenses1	Various	493		165		360		230
Debt Reacquisition Premiums1	Up to 12 years	180		302		192		341
Other1	Various	453		496		0		62
Total Regulatory Assets		$	21,419	$	167,556	$	21,900	$	168,395
Regulatory Liabilities
Deferred Income Taxes	Asset lives	$	0	$	133,306	$	0	$	134,719
Plant Removal Obligations	Asset lives	0		100,616		0		98,707
Fuel Clause Adjustments	Up to 1 year	7,072		0		10,947		0
Alternative Revenue Program Riders	Various	3,306		837		3,581		470
Pension and Other Postretirement Benefit Plans	Up to 1 year	1,959		0		1,959		0


Other	Various	180		227		176		77
Total Regulatory Liabilities		$	12,517	$	234,986	$	16,663	$	233,973

1Costs subject to recovery without a rate of return.
2Amount eligible for recovery includes an incentive or rate of return.

Table of Contents

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 March 31, 2021 and December 31, 2020:

Short-Term Debt

The following is a summary of our lines of credit as of March 31, 2021 and December 31, 2020:


			March 31, 2021						December 31, 2020
(in thousands)	Line Limit		Amount Outstanding		Letters of Credit		Amount Available		Amount Available

OTC Credit Agreement	$	170,000	$	78,206	$	0	$	91,794	$	104,834
OTP Credit Agreement	170,000		56,645		12,671		100,684		140,068
Total	$	340,000	$	134,851	$	12,671	$	192,478	$	244,902

Long-Term Debt

The following is a summary of outstanding long-term debt by borrower as of March 31, 2021 and December 31, 2020:


					(in thousands)
Entity		Debt Instrument	Rate	Maturity	March 31, 2021		December 31, 2020

OTC		Guaranteed Senior Notes	3.55%	12/15/26	$	80,000	$	80,000
OTP		Series 2011A Senior Unsecured Notes	4.63%	12/01/21	140,000		140,000
OTP		Series 2007B Senior Unsecured Notes	6.15%	08/20/22	30,000		30,000
OTP		Series 2007C Senior Unsecured Notes	6.37%	08/02/27	42,000		42,000
OTP		Series 2013A Senior Unsecured Notes	4.68%	02/27/29	60,000		60,000
OTP		Series 2019A Senior Unsecured Notes	3.07%	10/10/29	10,000		10,000
OTP		Series 2020A Senior Unsecured Notes	3.22%	02/25/30	10,000		10,000
OTP		Series 2020B Senior Unsecured Notes	3.22%	08/20/30	40,000		40,000
OTP		Series 2007D Senior Unsecured Notes	6.47%	08/20/37	50,000		50,000
OTP		Series 2019B Senior Unsecured Notes	3.52%	10/10/39	26,000		26,000
OTP		Series 2020C Senior Unsecured Notes	3.62%	02/25/40	10,000		10,000
OTP		Series 2013B Senior Unsecured Notes	5.47%	02/27/44	90,000		90,000
OTP		Series 2018A Senior Unsecured Notes	4.07%	02/07/48	100,000		100,000
OTP		Series 2019C Senior Unsecured Notes	3.82%	10/10/49	64,000		64,000
OTP		Series 2020D Senior Unsecured Notes	3.92%	02/25/50	15,000		15,000
OTC		PACE Note	2.54%	03/18/21	0		169
Total					$	767,000	$	767,169
Less:	Current Maturities Net of Unamortized Debt Issuance Costs				139,941		140,087
	Unamortized Long-Term Debt Issuance Costs				2,574		2,650
Total Long-Term Debt Net of Unamortized Debt Issuance Costs					$	624,485	$	624,432

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 ~~statements.~~

~~While 0 single~~covenants, including a maximum debt to total capitalization 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 March 31, 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 months ended March 31, 2021 and 2020 are as follows:



(in thousands)	2021		2020

Service Cost–Benefit Earned During the Period	$	1,866	$	1,655
Interest Cost on Projected Benefit Obligation	2,915		3,263
Expected Return on Assets	(5,590)		(5,505)



Amortization of Net Actuarial Loss:
From Regulatory Asset	2,660		2,231
From Other Comprehensive Income	68		55
Net Periodic Pension Cost	$	1,919	$	1,699

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 months ended March 31, 2021 and 2020 are as follows:



(in thousands)	2021		2020

Service Cost–Benefit Earned During the Period	$	47	$	45
Interest Cost on Projected Benefit Obligation	307		362



Amortization of Net Actuarial Loss:
From Regulatory Asset	31		23
From Other Comprehensive Income	124		86
Net Periodic Pension Cost	$	509	$	516

Other Postretirement Benefits

Components of net periodic postretirement benefit cost for the three months ended March 31, 2021 and 2020 are as follows:



(in thousands)	2021		2020

Service Cost–Benefit Earned During the Period	$	430	$	462
Interest Cost on Projected Benefit Obligation	473		598
Amortization of Prior Service Cost
From Regulatory Asset	(1,397)		(1,169)
From Other Comprehensive Income	(36)		(29)
Amortization of Net Actuarial Loss
From Regulatory Asset	920		1,051
From Other Comprehensive Income	23		26
Net Periodic Postretirement Benefit Cost	$	413	$	939

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8. Income Taxes

The reconciliation of the statutory federal income tax rate to our effective tax rate for each of the three months ended March 31, 2021 and 2020 is as follows:



	2021		2020

Federal Statutory Rate	21.0	%	21.0	%
Increases (Decreases) in Tax from:
State Taxes on Income, Net of Federal Tax	5.0		5.0
Production Tax Credits (PTCs)	(7.6)		0
Amortization of Excess Deferred Income Taxes	(2.9)		(4.1)
Corporate-Owned Life Insurance	(0.5)		0.7
North Dakota Wind Tax Credit Amortization, Net of Federal Tax	(0.4)		(0.9)
Excess Tax Deduction on Stock Awards	(0.1)		(1.3)
Allowance for Equity Funds Used During Construction	0		(1.0)
Other, Net	0.3		(0.5)
Effective Tax Rate	14.8	%	18.9	%

We began generating PTCs from our Merricourt wind farm placed in service in the fourth quarter of 2020. No PTCs were generated during the three months ended March 31, 2020. Income tax benefits arising from PTCs are offset by corresponding operating revenue reductions as PTC amounts generated reduce Electric segment customer ~~accounted~~billings.

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. T.O. Plastics is party to a resin supply agreement under which it must purchase all of a specified class of regrind resin delivered by the supplier at a periodically negotiated price per pound. The agreement expires in 2026.

Electric Utility Capacity and Energy Requirements and Coal Purchase and Delivery Contracts. OTP has commitments for ~~over~~ ~~10%~~the purchase of ~~consolidated revenue in~~ ~~2019,~~ ~~certain customers provided~~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 on~~its current coal requirements, with expiration dates ranging from 2022 through 2040. These contracts do not include minimum purchase requirements but do require all coal necessary for the ~~financial position and results of operations~~operation of the respective ~~business segment and~~plant 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~~ ~~June 30, 2020~~ ~~and~~ ~~2019,~~ ~~and 99.0% and 98.8% of operating revenues for the respective~~ ~~six~~~~-month periods ended~~ ~~June 30, 2020~~ ~~and~~ ~~2019.~~

counterparty.

~~Table of Contents~~

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~~ ~~six~~~~-month periods ended~~ ~~June 30, 2019~~ ~~and~~ ~~2020~~ ~~and total assets by business segment as of~~ ~~June 30, 2020~~ ~~and~~ ~~December~~ ~~31,~~~~2019~~ ~~are presented in the following tables:~~

~~Operating Revenue~~Land Easements.

Three Months Ended

Six Months Ended

June 30,

June 30,

(in thousands)

2020

2019

2020

2019

Electric Segment:

Retail Sales Revenue from Contracts with Customers
$ 85,344 $ 87,976 $ 192,034 $ 202,931
Changes in Accrued ARP Revenues
209 369 122 (680 )
Total Retail Sales Revenue
85,553 88,345 192,156 202,251
Transmission Services Revenue
9,673 11,469 20,514 22,331
Wholesale Revenues – Company Generation
765 941 1,641 2,468
Other Revenues
2,162 1,489 3,718 3,303
Total Electric Segment Revenues
98,153 102,244 218,029 230,353
Manufacturing Segment:

Metal Parts and Tooling
37,267 62,541 94,478 129,265
Plastic Products and Tooling
7,840 9,353 17,723 18,398
Other
841 1,602 2,226 3,655
Total Manufacturing Segment Revenues
45,948 73,496 114,427 151,318
Plastics Segment – Sale of PVC Pipe Products
48,679 53,476 95,076 93,534
Intersegment Eliminations
(24 ) (13 ) (29 ) (30 )
Total
$ 192,756 $ 229,203 $ 427,503 $ 475,175

~~Interest Charges~~

Three Months Ended

Six Months Ended

June 30,

June 30,

(in thousands)

2020

2019

2020

2019

Electric
$ 7,348 $ 6,625 $ 14,732 $ 13,266
Manufacturing
554 646 1,108 1,230
Plastics
186 215 334 364
Corporate and Intersegment Eliminations
574 339 611 791
Total
$ 8,662 $ 7,825 $ 16,785 $ 15,651

~~Income Taxes~~

Three Months Ended

Six Months Ended

June 30,

June 30,

(in thousands)

2020

2019

2020

2019

Electric
$ 2,579 $ 1,037 $ 6,199 $ 5,808
Manufacturing
(189 ) 1,149 1,272 2,603
Plastics
1,818 2,044 3,735 3,373
Corporate
(400 ) (887 ) (1,760 ) (2,813 )
Total
$ 3,808 $ 3,343 $ 9,446 $ 8,971

~~Net Income (Loss)~~

Three Months Ended

Six Months Ended

June 30,

June 30,

(in thousands)

2020

2019

2020

2019

Electric
$ 13,306 $ 7,502 $ 29,488 $ 26,202
Manufacturing
238 3,990 5,165 8,832
Plastics
5,130 5,792 10,579 9,521
Corporate
(1,693 ) (1,858 ) (3,983 ) (2,805 )
Total
$ 16,981 $ 15,426 $ 41,249 $ 41,750

~~Table of Contents~~

~~Identifiable Assets~~

June 30,

December 31,

(in thousands)

2020

2019

Electric
$ 2,054,523 $ 1,931,525
Manufacturing
184,462 195,742
Plastics
102,285 92,049
Corporate
47,969 54,279
Total
$ 2,389,239 $ 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 and~~has 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.

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 ~~June 30, 2020,~~ OTP had capitalized approximately $131.7 million in project costs and allowance for funds used during construction (AFUDC) associated with Merricourt. While construction on site continues, 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 expects Merricourt to be completed before~~ ~~December 31, 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~~ ~~June 30, 2020,~~ ~~OTP had capitalized approximately $108.0 million in project costs and AFUDC associated with Astoria Station. OTP currently expects this project will be completed in late~~ ~~2020~~ ~~or early~~ ~~2021.~~

~~Table of Contents~~

~~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 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.~~

~~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 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.~~

~~Table of Contents~~

~~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~~ ~~six~~~~-month periods ended~~ ~~June 30, 2020~~ ~~and~~ ~~June 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.~~

~~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 Multi-Value Projects (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 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.~~

On ~~November 30, 2018~~ ~~OTP filed its annual update and supplemental filing to the Minnesota TCR rider. In this filing~~ ~~two~~ scenarios were submitted based on whether the Minnesota Supreme Court affirmed the original decision by the Minnesota Court of Appeals to exclude the MVP projects from the TCR rider or overturned the Minnesota Court of Appeals decision and includes the ~~two~~ ~~MVP projects in the TCR rider. In addition, on~~ ~~April 1, 2019,~~ ~~the MNDOC filed comments in OTP’s TCR rider docket, opposing OTP’s proposal for TCR rider recovery of these costs. The Minnesota Supreme Court issued its opinion on~~ ~~April~~ ~~22,~~~~2020,~~ concluding that 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.

~~Table of Contents~~

On ~~May 7, 2020~~ ~~OTP filed reply comments in the docket within~~ 15 ~~days of the Minnesota Supreme Court ruling as required by the MPUC. OTP filed updated revenue requirements excluding the Brookings and Big Stone–Ellendale projects and including~~ ~~three~~ ~~projects previously requested in the Minnesota TCR rider eligibility petition. OTP requested new rates be implemented~~ ~~January 1, 2021~~ ~~with the~~ ~~three~~ ~~new projects deemed eligible for TCR rider recovery effective~~ ~~January 1, 2020.~~ ~~OTP also requested~~ ~~one~~~~-half of the~~ ~~December 2020~~ ~~tracker balance of $13.4 million be included in the~~ ~~January 1, 2021~~ ~~revenue requirement with the remainder included in the next annual update. OTP also requested a carrying charge be included as of~~ ~~January 1, 2021.~~ On ~~June 4, 2020~~ ~~the MPUC filed a Notice of Combined and Extended Comment Period for both the Minnesota TCR rider and TCR rider eligibility filing with the comment period closing on~~ ~~July 6, 2020~~ ~~and the reply comment period closing on~~ ~~July 21, 2020.~~ ~~In the MNDOC's comments regarding eligibility for recovery of investments in the~~ ~~three~~ ~~new projects through the Minnesota TCR rider, the MNDOC recommended the MPUC reject OTP’s petition for inclusion of the~~ ~~three~~ ~~projects. In the matter of OTP’s petition for approval of a TCR annual adjustment, at the request of the MNDOC the MPUC extended the deadlines for filing initial and reply comments to~~ ~~August~~ ~~14,~~~~2020~~ ~~and~~ ~~August 24, 2020,~~ ~~respectively. The estimated amount of higher MISO ROE revenues credited to Minnesota customers through the TCR rider through~~ ~~June 30, 2020,~~ ~~which OTP is now seeking recovery of through its Minnesota TCR rider update request, is approximately $2.6 million.~~

~~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 21, 2019~~ ~~the SDPUC approved OTP’s supplemental filing for its South Dakota Phase-In Rate Plan Rider effective~~ ~~September 1, 2019.~~ On ~~June 1, 2020~~ ~~OTP filed its~~ ~~first~~ ~~annual update request to the rider with a proposed effective date of~~ ~~September 1, 2020.~~

~~Table of Contents~~

~~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
R –
May 1, 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
R –
May 7, 2020
January 1, 2021
$ 10,264
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%
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

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%
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
R –
June 1, 2020
September 1, 2020
$ 1,931 7.753%
of base
2019 Initial Request
A –
August 21, 2019
September 1, 2019
$ 864 3.345%
of base

~~Table of Contents~~

~~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 June 30,

Six Months Ended June 30,

Rate Rider (in thousands)

2020

2019

2020

2019

Minnesota

Renewable Resource Recovery
$ 3,088 $ 1,317 $ 6,342 $ 2,633
Conservation Improvement Program Costs and Incentives
1,521 1,841 2,607 2,728
Transmission Cost Recovery
(314 ) (56 ) 401 585
Environmental Cost Recovery
- - - (1 )
North Dakota

Transmission Cost Recovery
840 874 2,322 2,646
Renewable Resource Adjustment
1,070 (93 ) 2,199 636
Generation Cost Recovery
900 222 1,848 470
Environmental Cost Recovery
- (12 ) - 563
South Dakota

Transmission Cost Recovery
371 371 933 844
Conservation Improvement Program Costs and Incentives
210 96 554 340
Environmental Cost Recovery
- (23 ) - (27 )
Phase-In Rate Plan
(670 ) - (24 ) -
Total
$ 7,016 $ 4,537 $ 17,182 $ 11,417

~~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.

~~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 has~~tariff 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 ~~$2.9~~$3.7 million as of ~~June 30, 2020~~ ~~as a result~~March 31, 2021. 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 $1.5 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~~ ~~June 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 refunded~~required refunds to customers once all regulatory and judicial proceedings are finalized.

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, with state implementation plans targeted for submission to the EPA by July 31, 2021. States are required 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. We cannot predict with certainty the impact the state implementation plan may have on our business until the plan is finalized and adopted. However, significant emission control investments could be required, and the recovery of such costs from customers would require regulatory approval. Alternatively, investments in emission control equipment may prove to be uneconomic and result in a required early retirement of, or ~~reversed and recognized as revenue depending on various factors including MISO’s determination~~the sale of ~~refund amounts and FERC’s final determination of the reasonableness of base ROE over various periods.~~

~~Table of Contents~~

4. ~~Regulatory Assets and Liabilities~~

~~As a regulated entity, OTP accounts for~~our interest in, Coyote Station. We cannot estimate the financial effects such a retirement or sale may have on our consolidated operating results, financial position or cash flows, but such amounts could be material and the recovery of ~~regulation~~such costs from customers would be subject to regulatory approval.

Other Contingencies. We are party to litigation and regulatory enforcement matters arising in ~~accordance with ASC~~ ~~980.~~ ~~This accounting standard allows~~the normal course of business. We regularly analyze relevant information and, as necessary, estimate and record accrued liabilities for legal, 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 ~~recording~~disposition of ~~a regulatory asset or liability for costs that~~all matters pending as of March 31, 2021, other than those relating to the RHR, will not 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 and liabilities recorded on the Company’s consolidated balance sheets:

June 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 $ 124,901 $ 133,919
see below

Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment¹
- 8,243 8,243
asset lives

Minnesota Transmission Cost Recovery Rider Accrued Revenues²
6,563 - 6,563 12
Conservation Improvement Program Costs and Incentives²
276 3,553 3,829 27
MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups¹
1,500 963 2,463 30
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery¹
- 1,974 1,974
asset lives

Minnesota Renewable Resource Rider Accrued Revenues²
722 - 722 12
Debt Reacquisition Premiums¹
204 430 634 147
Big Stone II Unrecovered Project Costs – Minnesota¹
583 - 583 10
Minnesota SPP Transmission Cost Recovery Tracker¹
- 401 401
see below

Deferred Marked-to-Market Losses¹
372 - 372 6
Big Stone II Unrecovered Project Costs – South Dakota¹
144 180 324 27
South Dakota Deferred Rate Case Expenses Subject to Recovery¹
138 177 315 28
North Dakota Generation Cost Recovery Rider Accrued Revenue²
312 - 312 12
North Dakota Deferred Rate Case Expenses Subject to Recovery¹
122 183 305 30
Deferred Lease Expenses¹
- 58 58 33
Minnesota Environmental Cost Recovery Rider Accrued Revenues²
4 - 4 12
Total Regulatory Assets
$ 19,958 $ 141,063 $ 161,021
Regulatory Liabilities:

Deferred Income Taxes
$ - $ 138,517 $ 138,517
asset lives

Accumulated Reserve for Estimated Removal Costs – Net of Salvage
- 99,055 99,055
asset lives

Refundable Fuel Clause Adjustment Revenues
10,241 - 10,241 12
North Dakota Transmission Cost Recovery Rider Accrued Refund
1,010 - 1,010 6
South Dakota Phase-In Rate Plan Rider Accrued Refund
783 - 783 2
Revenue for Rate Case Expenses Subject to Refund – Minnesota
- 518 518
see below

Prior Service Costs and Actuarial Gains on Postretirement Benefits
471 - 471 12
Minnesota Energy Intensive Trade Exposed Rider Accrued Refund
198 - 198 3
South Dakota Transmission Cost Recovery Rider Accrued Refund
159 - 159 8
North Dakota Renewable Resource Recovery Rider Accrued Refund
156 - 156 9
Other
5 70 75 162
Total Regulatory Liabilities
$ 13,023 $ 238,160 $ 251,183
Net Regulatory Asset/(Liability) Position
$ 6,935 $ (97,097 ) $ (90,162 )

¹~~Costs subject to recovery without a rate of return.~~

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

material.

Table of Contents

10. Stockholders' Equity

December 31, 2019

(in thousands)

Current

Long-Term

Total

Remaining
Recovery/
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

Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment¹
- 7,772 7,772
asset lives

Minnesota Transmission Cost Recovery Rider Accrued Revenues²
4,208 - 4,208 12
Conservation Improvement Program Costs and Incentives²
4,024 2,844 6,868 21
MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups¹
2,033 968 3,001 24
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery¹
- 1,681 1,681
asset lives

Minnesota Renewable Resource Rider Accrued Revenues²
131 - 131 12
Debt Reacquisition Premiums¹
201 548 749 153
Big Stone II Unrecovered Project Costs – Minnesota¹
715 225 940 16
Minnesota SPP Transmission Cost Recovery Tracker¹
- 202 202
see below

Deferred Marked-to-Market Losses¹
743 - 743 12
Big Stone II 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 Lease Expenses¹
- 54 54 39
Minnesota Environmental Cost Recovery Rider Accrued Revenues²
4 - 4 12
South Dakota Transmission Cost Recovery Rider Accrued Revenues²
97 - 97 2
Total Regulatory Assets
$ 21,650 $ 144,138 $ 165,788
Regulatory Liabilities:

Deferred Income Taxes
$ - $ 141,707 $ 141,707
asset lives

Accumulated Reserve for Estimated Removal Costs – Net of Salvage
- 97,726 97,726
asset lives

Refundable Fuel Clause Adjustment Revenues
3,982 - 3,982 12
North Dakota Transmission Cost Recovery Rider Accrued Refund
700 - 700 12
South Dakota Phase-In Rate Plan Rider Accrued Refund
355 - 355 9
Revenue for Rate Case Expenses Subject to Refund – Minnesota
- 401 401
see below

Prior Service Costs and Actuarial Gains on Postretirement Benefits
471 - 471 12
Minnesota Energy Intensive Trade Exposed Rider Accrued Refund
164 - 164 12
North Dakota Renewable Resource Recovery Rider Accrued Refund
1,515 - 1,515 12
North Dakota Generation Cost Recovery Rider Accrued Refund
287 - 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 )

¹~~Costs subject to recovery without a rate of return.~~

²~~Amount 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 Accumulated ARO Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations.~~

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.

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

Registration Statements

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 agent~~SEC 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 any~~OTP and other interested investors a method of purchasing our common shares ~~sold through it as the Company’s distribution agent~~by 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, will~~plan may be ~~issued pursuant to the Company’s existing shelf registration statement.~~

~~Table of Contents~~

~~2020~~ ~~Common Stock Activity~~

~~Following is a reconciliation of the Company’s~~new issue common shares ~~outstanding from~~ ~~December 31, 2019~~ ~~through~~ ~~June 30, 2020:~~

~~Common Shares Outstanding, December 31, 2019~~	~~40,157,591~~
~~Issuances:~~
~~At-the-Market Offering~~	~~500,684~~
~~Automatic Dividend Reinvestment and Share Purchase Plan:~~
~~Dividends Reinvested~~	~~63,929~~
~~Cash Invested~~	~~30,345~~
~~Executive Stock Performance Awards (2017 awards earned)~~	~~62,497~~
~~Vesting of Restricted Stock Units~~	~~35,720~~
~~Employee Stock Purchase Plan:~~
~~Cash Invested~~	~~13,432~~
~~Dividends Reinvested~~	~~4,835~~
~~Restricted Stock Issued to Directors~~	~~17,400~~
~~Directors Deferred Compensation~~	~~612~~
~~Retirements:~~
~~Shares Withheld for Individual Income Tax Requirements~~	~~(38,217~~	)
~~Common Shares Outstanding, June 30, 2020~~	~~40,848,828~~

~~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~~ ~~six~~~~-month periods ended~~ ~~June 30, 2020~~ ~~and~~ ~~2019.~~ ~~The denominator used in the calculation of basic earnings per common share is the weighted average number of~~or 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~~ ~~six~~~~-month periods ended~~ ~~June 30:~~

Three Months ended
June 30

Six Months ended
June 30

2020

2019

2020

2019

Weighted Average Common Shares Outstanding – Basic
40,513,286 39,712,036 40,365,214 39,684,679
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
97,401 134,137 111,519 146,148
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees
47,331 60,168 55,614 61,783
Shares Expected to be Issued Under the Employee Stock Purchase Plan
15,833 - 15,905 -
Nonvested Restricted Shares
1,637 9,657 10,749 15,790
Shares Expected to be Issued Under the Deferred Compensation Program for Directors
1,273 1,833 1,548 2,099
Total Dilutive Shares
163,475 205,795 195,335 225,820
Weighted Average Common Shares Outstanding – Diluted
40,676,761 39,917,831 40,560,549 39,910,499

~~Table of Contents~~

6. ~~Share-Based Payments~~

~~Stock Incentive Awards~~

~~The following stock incentive awards were granted under the~~ ~~2014~~ ~~Stock Incentive Plan during the~~ ~~six~~ ~~months ended~~ ~~June 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 payment~~registration 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.

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’s~~our shareholders is from dividends paid or distributions made by ~~the Company’s~~our 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’s~~our subsidiaries.

Both the ~~Company~~OTC Credit Agreement and OTP ~~credit agreements~~Credit Agreement contain restrictions on the payment of cash dividends upon a default or event of ~~default. An event of~~ default, ~~would be considered~~including failure to ~~have occurred if the Company did~~ ~~not~~ ~~meet~~maintain certain financial covenants. As of ~~June 30, 2020,~~ ~~the Company was~~March 31, 2021, 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 ~~June 30, 2020,~~ March 31, 2021, OTP’s equity-to-total-capitalization ratio including short-term debt was ~~52.9%~~52.4% and its net assets restricted from distribution totaled approximately ~~$549~~$671.0 million. Under the 2020 capital structure petition, ~~OTP’s~~ total capitalization for OTP cannot exceed ~~$1,704,607,000.~~

$1.7 billion.

11. Share-Based Payments

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 $4.2 million and $2.8 million for ~~interim reporting periods.~~

9. ~~Commitments~~the three months ended March 31, 2021 and ~~Contingencies~~

2020.

Stock Awards. We grant restricted stock awards to members of our Board of Directors and ~~Other Purchase Commitments~~restricted stock units to our employees. The awards vest, depending on award type and recipient, either ratably over periods of three

At ~~June 30, 2020~~ ~~OTP had commitments under contracts,~~ and four years or cliff vest after four years. Vesting is accelerated in certain circumstances, including ~~its share~~upon retirement. Restricted stock awards granted to members of ~~construction program commitments~~the Board of Directors are issued and ~~other commitments, extending into 2022~~outstanding upon grant and carry the same voting and dividend rights of ~~approximately $185 million. At~~ ~~December 31, 2019~~ ~~OTP had commitments under contracts, including its share of construction program commitments~~unrestricted outstanding common stock. Restricted stock units are not issued or outstanding upon grant and ~~other nonlease commitments, extending into 2021 of approximately $317 million.~~

On ~~October 1, 2019~~ ~~T.O. Plastics entered into a new~~ ~~six-year resin supply agreement that commenced on~~ ~~January 1, 2020.~~ ~~Under~~do not provide for voting or dividend rights. Certain restricted stock unit award recipients are eligible to receive dividend equivalent payments during the ~~new resin supply agreement, there are~~ no ~~minimum purchase requirements, but T.O. Plastics is required~~vesting 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 term~~terms of the ~~supply agreement or exceed~~agreement.

The grant date fair value of each stock award is determined based on the market ~~cost~~price of ~~alternative sources~~our common stock on the date of grant adjusted to exclude the ~~resin. T.O. Plastics estimates it will pay~~value 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.

The fair value of ~~capacity~~vested awards was $0.7 million and ~~energy requirements under agreements extending into~~ ~~2043.~~ ~~OTP also has contracts providing for~~$1.3 million during the ~~purchase~~three months ended March 31, 2021 and ~~delivery of a significant portion of its current coal requirements. OTP’s current coal purchase agreements for Coyote Station expire~~2020.

Stock Performance Awards. Stock performance awards are granted to executive officers and certain other key employees. The awards vest at the end of ~~2040.~~ ~~OTP has agreements with Peabody COALSALES, LLC (Peabody) for~~a three-year performance period. The number of common shares awarded, if any, at the ~~purchase 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 all of Big Stone Plant’s coal requirements for the period covered must be purchased exclusively from Peabody. OTP has an all-requirements agreement with Navajo Transitional Energy Co. for the purchase of subbituminous coal for Hoot Lake Plant through ~~December 31, 2023,~~ ~~with~~ no ~~fixed minimum purchase requirement.~~

~~OTP Land Easements~~

~~OTP has commitments to make future payments for land easements~~ ~~not~~ ~~classified as leases, extending into~~ ~~2034~~ ~~of approximately $9.9 million.~~

~~Contingencies~~

~~OTP had a $2.9 million refund liability on its balance sheet as of~~ ~~June 30, 2020.~~ ~~This represents its best estimate~~end of the ~~refund obligations that would arise net~~performance period ranges from 0 to 150% of ~~amounts that would be subject~~the target amount based on two performance measures: i) total shareholder return relative to ~~recovery under state jurisdictional TCR riders. This~~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 ~~outcome~~end of the ~~appeals of the FERC ruling reducing the ROE component of the MISO Tariff and ordering MISO to refund amounts charged in excess of the lower rate. As discussed in note~~ 3 in greater detail, OTP believes its estimated accrued refund liability is appropriate based on the current facts and circumstances and is awaiting results of the appeal before determining if a change in this estimate will be needed.

Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimatingperformance period or the amount of common shares earned at target.

The grant date fair value of stock performance awards granted during the three months ended March 31, 2021 and 2020 was determined using a Monte Carlo fair value simulation model incorporating the following assumptions:


	2021		2020

Risk-free interest rate	0.18	%	1.42	%
Expected term (in years)	3.00		3.00
Expected volatility	32.00	%	19.00	%
Dividend yield	3.60	%	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.

The following is a summary of stock performance award activity for the three months ended March 31, 2021 (share amounts reflect awards at target):


	Shares	Weighted Average Grant-Date Fair Value

Nonvested, January 1, 2021	164,600	$	42.32
Granted	79,000	38.34
Vested	(54,000)	35.73
Forfeited	0	0
Nonvested, March 31, 2021	189,600	$	42.54

The fair value of vested awards was $2.5 million and $3.4 million during the three months ended March 31, 2021 and 2020.

12. Earnings Per Share

The numerator used in the calculation of both 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 dilutive effect of potential ~~loss.~~ common shares outstanding, which consist of time and performance based stock awards and employee stock purchase plan shares.

The following includes the computation of the denominator for basic and diluted weighted-average shares outstanding for the three months ended March 31, 2021 and 2020:



(in thousands)	2021	2020

Weighted Average Common Shares Outstanding – Basic	41,455	40,217
Effect of Dilutive Securities:
Stock Performance Awards	143	126
Stock Awards	85	83
Employee Stock Purchase Plan Shares and Other	17	18
Dilutive Effect of Potential Common Shares	245	227
Weighted Average Common Shares Outstanding – Diluted	41,700	40,444

The amount of shares excluded from diluted weighted-average common shares outstanding because such shares were anti-dilutive was not material for the three months ended March 31, 2021 and 2020.

13. Fair Value Measurements

The following tables present our assets measured at fair value on a recurring basis as of March 31, 2021 and December 31, 2020 classified by the input method used to measure fair value:


	Level 1		Level 2		Level 3

March 31, 2021
Investments:
Money Market Funds	$	1,862	$	—	$	—
Mutual Funds	5,141		—		—
Corporate Debt Securities	—		2,401		—
Government-Backed and Government-Sponsored Enterprises’ Debt Securities	—		6,808		—
Total Assets	$	7,003	$	9,209	$	—
December 31, 2020
Investments:
Money Market Funds	$	4,075	$	—	$	—
Mutual Funds	1,662		—		—
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.

In addition to ~~the potential ROE refund described above, the most significant contingencies~~assets 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 reduction~~not recorded at fair value in the ~~remaining depreciable lives of OTP’s Hoot Lake Plant and~~ ~~seven~~ ~~hydroelectric plants. The MPUC stipulated recoverability~~consolidated 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 on~~fair value of these financial instruments is provided. The following reflects the ~~relevant facts~~carrying value and ~~circumstances, OTP has concluded the additional depreciation expense is probable~~estimated fair value of ~~recovery~~these assets and ~~will recognize a regulatory asset for the amount~~(liabilities) as of ~~incremental expense recognized in~~ ~~2020.~~

~~State implementation of pollution control plans to improve visibility~~March 31, 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.

~~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 ~~June 30, 2020,~~ ~~other than those relating to the RHR, will~~ ~~not~~ ~~be material.~~

2020:


	March 31, 2021				December 31, 2020
(in thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Cash and Cash Equivalents	$	1,212	$	1,212	$	1,163	$	1,163
Short-Term Debt	(134,851)		(134,851)		(80,997)		(80,997)
Long-Term Debt	(764,426)		(839,942)		(764,519)		(858,455)

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

Short-Term ~~Debt~~Debt: —The carrying amount approximates fair value because the debt obligations are short-term and the balances outstanding ~~as of~~ ~~June 30, 2020~~ ~~and~~ ~~December 31, 2019~~ ~~related to the Otter Tail Corporation Credit Agreement were~~are 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 Maturities~~Debt: —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 to~~similar maturities, a Level 2 fair value input.


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

You should read the ~~Company~~following 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 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.~~

June 30, 2020

December 31, 2019

(in thousands)

Carrying
Amount

Fair Value

Carrying
Amount

Fair Value

Cash and Cash Equivalents
$ 39,512 $ 39,512 $ 21,199 $ 21,199
Short-Term Debt
(41,239 ) (41,239 ) (6,000 ) (6,000 )
Long-Term Debt including Current Maturities
(724,650 ) (795,995 ) (689,764 ) (742,279 )

~~13.~~ ~~Property, Plant and Equipment~~

No ~~update required for interim reporting period.~~

~~Table of Contents~~

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~~ ~~six~~~~-month periods~~year ended ~~June 30, 2020~~ ~~and~~ ~~2019:~~

Three Months Ended June 30,

Six Months Ended June 30,

(in thousands)

2020

2019

2020

2019

Income Before Income Taxes
$ 20,789 $ 18,769 $ 50,695 $ 50,721
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%)
$ 5,405 $ 4,879 $ 13,181 $ 13,187
(Decreases) Increases in Tax from:

Differences Reversing in Excess of Federal Rates
(543 ) (774 ) (1,772 ) (1,757 )
Allowance for Funds Used During Construction – Equity
(248 ) (94 ) (560 ) (180 )
Excess Tax Deduction – Equity Method Stock Awards
- - (535 ) (827 )
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes
(258 ) (258 ) (516 ) (516 )
Research and Development and Other Tax Credits
(333 ) (187 ) (387 ) (375 )
Corporate Owned Life Insurance
(193 ) (150 ) 14 (559 )
Other Items – Net
(22 ) (73 ) 21 (2 )
Income Tax Expense
$ 3,808 $ 3,343 $ 9,446 $ 8,971
Effective Income Tax Rate
18.3 % 17.8 % 18.6 % 17.7 %

~~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 Related to Tax Positions for Prior Years
(42 ) -
Increases Related to Tax Positions for Current Year
81 75
Uncertain Positions Resolved During Year
- (42 )
Balance on June 30
$ 1,527 $ 1,315

~~The balance of unrecognized tax benefits as of~~ ~~June 30, 2020~~ ~~would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of~~ ~~June 30, 2020~~ ~~could be reduced by as much as $725,000 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 Company~~December 31, 2020.

Otter Tail Corporation and its subsidiaries ~~file~~form a ~~consolidated U.S. federal income tax return~~diverse group of businesses with operations classified into three segments: Electric, Manufacturing and ~~various state income tax returns. As of~~ ~~August 1, 2020,~~ Plastics. Our Electric business is a vertically integrated, regulated utility with ~~limited exceptions, the Company is~~ no ~~longer subject~~generation, transmission and distribution facilities to ~~examinations by taxing authorities for tax years prior to~~ ~~2016~~ ~~for federal,~~serve our customers in western Minnesota, ~~and~~eastern North Dakota ~~income taxes.~~

~~Table of Contents~~

~~Item 2.~~ ~~Management's Discussion~~ and ~~Analysis of Financial Condition~~northeastern South Dakota. Our Manufacturing segment provides metal fabrication for custom machine parts and ~~Results of Operations~~

~~COVID-19~~

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

We continue to monitor the progression of the novel coronavirus (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~~We continue to operate our businesses in a manner that is safe for our employees and our customers.

Beginning in March 2020, COVID-19 and the resulting economic conditions ~~have had a material negative impact on the~~negatively 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 our~~strong 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 began to see a reduction~~operating results were also impacted in ~~customer demand in our Manufacturing segment in late March 2020 and have experienced significantly lower levels of customer demand in this segment through the end of June~~ 2020. ~~We anticipate this reduced demand will continue over the near term.~~ Within our Electric segment, we ~~have~~ experienced reduced demand from commercial and industrial customers and the risk of disruptions for our capital projects, including Merricourt and Astoria Station, also continues. With over 250 individuals working on the Astoria Station site at times during various stages of construction, 26 have tested positive for COVID-19. Continued or additional incidence of infection at the Astoria Station or Merricourt sites, may result in delayed completion schedules and increased costs for ~~these projects.~~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 ~~due to~~given the uncertainty ~~over~~of the potential impact of COVID-19.

~~Beginning~~ Sales volumes recovered and gross profit margins increased in ~~April~~the third and fourth quarters of 2020 ~~in response~~due to ~~the actual~~increase demand and ~~anticipated~~concerns of supply disruptions.

The impact of COVID-19 and the resulting macroeconomic conditions on our business ~~operations, we~~and financial results have ~~implemented a variety~~begun to ease. However, uncertainty remains regarding the magnitude and duration of ~~policies, including furloughs, shift~~the pandemic and ~~pay reductions, wage~~resulting financial effects. We expect demand from commercial and ~~hiring freezes, suspension of certain employee benefits, a workforce reduction~~industrial customers and ~~other cost reduction efforts~~bad debt expense levels within our Electric segment to ~~mitigate~~be impacted during 2021, and customer demand within our Manufacturing and Plastics segments could be disrupted as the ~~negative impact to our financial results.~~ pandemic evolves.

We continue to monitor developments involving our workforce, customers, construction contractors, suppliers and vendors and the ~~impacts of the pandemic~~financial effects 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 level. This measure is commonly used in calculations relating~~business. However, due to the ~~energy consumption required to heat buildings.~~

~~Cooling Degree Days~~ ~~(CDDs) is a measure~~unprecedented and evolving nature of ~~how much (in degrees), and for how long (in days),~~this pandemic, we cannot predict the ~~outside air temperature was above a certain 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 consumption of electricity across our service territory. We present HDDs and CDDs to provide an indicationfull extent of the impact ~~of weather~~COVID-19 will have 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 used in the calculation, 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.

~~Table of Contents~~

~~Results of Operations~~

~~Following is an analysis of the Company’s~~our operating results, ~~by business segment for the three~~financial condition and ~~six months ended June 30, 2020~~liquidity.


RESULTS OF OPERATIONS

Provided below is a summary and ~~2019~~discussion of our operating results on a consolidated basis followed by a discussion of ~~changes~~the operating results of each of our segments, Electric, Manufacturing and Plastics. Intersegment transactions were not material in 2021 or 2020. 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 six months ended June 30, 2020 and~~statements of income.

CONSOLIDATED RESULTS

The following table summarizes our ~~business outlook for the remainder~~consolidated results of ~~2020.~~

~~Comparison of the Three Months Ended June 30, 2020 and 2019~~

~~Consolidated operating revenues were $192.8 million~~operations for the three months ended ~~June 30,~~March 31, 2021 and 2020:
(in thousands) 2021 2020 $ change % change
Operating Revenues $ 261,710 $ 234,747 $ 26,963 11.5 %
Operating Expenses 217,511 195,458 22,053 11.3
Operating Income 44,199 39,289 4,910 12.5
Interest Charges 9,398 8,123 1,275 15.7
Nonservice Cost Components of Postretirement Benefits 383 871 (488) (56.0)
Other Income 1,160 (389) 1,549 (398.2)
Income Before Income Taxes 35,578 29,906 5,672 19.0
Income Tax Expense 5,249 5,638 (389) (6.9)
Net Income $ 30,329 $ 24,268 $ 6,061 25.0 %

Operating Revenues increased $27.0 million primarily due to rising pipe prices within our Plastics segment and increased material cost leading to increased sales prices in our Manufacturing segment. Operating revenues within our Electric segment also increased, primarily as a result of increased transmission and wholesale electric revenues. See our segment disclosures below for additional discussion of items impacting operating revenues.

Operating Expenses increased $22.1 million primarily due to increased costs of products sold in our Plastics and Manufacturing segments due to increased raw material costs in each segment. Operating expenses in our Electric segment increased primarily due to higher depreciation and amortization expense arising from our recent rate base investments. See our segment disclosures below for additional discussion of items impacting operating expenses.

Interest Charges increased $1.3 million mostly due to:

•A $0.5 million increase in interest expense related to OTP long-term debt issuances of $35 million in February 2020 and $40 million in August 2020.

•A $0.3 million reduction in capitalized interest at OTP related to the completion and start up of Astoria Station in the first quarter of 2021.

•A $0.4 million increase in corporate interest expense due to a higher level of short-term borrowings between the quarters as well as an increase in the cost of borrowing.

Nonservice Cost Components of Postretirement Benefits decreased $0.5 million due to a change in how prescription drug coverage is provided to retirees and due to the impact on nonservice costs of a 70 basis point drop in the discount rate from 2020 to 2021.

Other Income increased $1.5 million primarily due to increases in the cash values of corporate-owned life insurance policies and captive insurance company investments in the first quarter of 2021 compared ~~with $229.2~~to losses in value in the first quarter of 2020.

Income Tax Expense decreased $0.4 million despite a $5.7 million increase in income before income taxes primarily due to PTCs earned in the first quarter of 2021 from our Merricourt wind farm, which was placed in service in the fourth quarter of 2020. Our effective tax rate was 14.8% in the first quarter of 2021 and 18.9% in the first quarter of 2020. See Note 8 to our consolidated financial statements included in this report on Form 10-Q for additional information regarding factors impacting our effective tax rate in 2021 and 2020.

ELECTRIC SEGMENT RESULTS

The following table summarizes the results of operations for our Electric segment for the three months ended ~~June 30, 2019. Operating income was $27.9 million~~March 31, 2021 and 2020:


(in thousands)	2021		2020		$ change		% change

Retail Sales Revenue	$	105,706	$	106,603	$	(897)	(0.8)	%
Transmission Services Revenues	11,944		10,841		1,103		10.2
Wholesale Revenues	4,507		876		3,631		414.5
Other Electric Revenues	1,542		1,556		(14)		(0.9)
Total Operating Revenue	123,699		119,876		3,823		3.2
Production Fuel	14,714		13,735		979		7.1
Purchased Power	19,260		18,830		430		2.3
Operation and Maintenance Expenses	41,421		40,615		806		2.0
Depreciation and Amortization	17,308		15,676		1,632		10.4
Property Taxes	4,320		4,100		220		5.4
Operating Income	$	26,676	$	26,920	$	(244)	(0.9)	%

Electric kilowatt-hour (kwh) Sales (in thousands)
Retail kwh Sales	1,348,519		1,429,910		(81,391)		(5.7)	%
Wholesale kwh Sales – Company Generation	80,423		38,924		41,499		106.6
Heating Degree Days	3,078		3,272		(194)		(5.9)
Cooling Degree Days	—		—		—		—

Results of operations for the ~~three months ended June 30, 2020 compared with $26.8 million~~Electric segment are impacted by fluctuations in weather conditions and the resulting demand for ~~the three months ended June 30, 2019. The Company recorded diluted earnings per share of $0.42~~electricity for ~~the three months ended June 30, 2020 compared with $0.39 for the three months ended June 30, 2019.~~

~~Amounts presented in the segment tables that follow for operating revenues, cost of products sold~~heating and other nonelectric operating expenses for the three-month periods ended June 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)

June 30, 2020

June 30, 2019

Operating Revenues:

Electric
$ 23 $ 14
Nonelectric
1 (1 )
Costs of Products Sold
2 3
Other Nonelectric Expenses
22 10

~~Electric~~

Three Months Ended

June 30,

%

(in thousands)

2020

2019

Change

Change

Retail Sales Revenues from Contracts with Customers
$ 85,344 $ 87,976 $ (2,632 ) (3.0 )
Changes in Accrued Revenues under Alternative Revenue Programs
209 369 (160 ) (43.4 )
Total Retail Sales Revenue
$ 85,553 $ 88,345 $ (2,792 ) (3.2 )
Transmission Services Revenue
9,673 11,469 (1,796 ) (15.7 )
Wholesale Revenues – Company Generation
765 941 (176 ) (18.7 )
Other Revenues
2,162 1,489 673 45.2
Total Operating Revenues
$ 98,153 $ 102,244 $ (4,091 ) (4.0 )
Production Fuel
8,788 8,296 492 5.9
Purchased Power – System Use
13,682 19,633 (5,951 ) (30.3 )
Electric Operation and Maintenance Expenses
33,179 39,856 (6,677 ) (16.8 )
Depreciation and Amortization
15,740 15,082 658 4.4
Property Taxes
4,168 3,900 268 6.9
Operating Income
$ 22,596 $ 15,477 7,119 46.0
Electric Megawatt-hour (mwh) Sales

Retail mwh Sales
1,033,053 1,088,052 (54,999 ) (5.1 )
Wholesale mwh Sales – Company Generation
42,140 42,805 (665 ) (1.6 )
HDDs
635 580 55 9.5
CDDs
170 104 66 63.5

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

Three Months ended June 30,

2020

2019

HDDs
122.1 % 112.6 %
CDDs
156.0 % 95.4 %

normal.


	2021		2020

Heating Degree Days	89.5	%	95.6	%


	2021 vs Normal		2021 vs 2020		2020 vs Normal

Effect on Diluted Earnings Per Share	$	(0.04)	$	(0.02)	$	(0.02)

Retail Sales Revenue decreased $0.9 million driven by:

•A $2.8 million decrease in retail revenue mainly due to decreased kwh sales to commercial and industrial customers, exclusive of the impact of milder weather on sales, due to ongoing impacts of COVID-19 on first quarter 2021 kwh sales. COVID-19 did not impact electric revenues in the first quarter of 2020.

•A $1.5 million decrease in fuel recovery revenue ~~includes:~~

●

A $4.2 million decrease in retail revenue related to the recovery of decreased fuel and purchased power costs incurred to serve retail customers. Decreased commercial and industrial demand related to COVID-19 contributed to the 5.1% decrease in retail kwh sales and a $5.2 million decrease in fuel and purchased power costs to serve retail customers.

●

A $2.7 million decrease in revenue due to decreased kwh sales to commercial and industrial customers, exclusive of the decrease in fuel cost recovery revenues, mainly due to COVID-19-related impacts in the second quarter of 2020.

●

~~A $1.0 million combined decrease in South Dakota Phase-In Rider revenues and Minnesota Conservation Improvement Program Rider revenues.~~

mainly due to credits provided to customers from increased margins on wholesale kwh sales and a 5.7% reduction in retail kwh sales between the quarters.

•A $0.9 million decrease in retail revenues related to decreased consumption due to milder weather in the first quarter of 2021 compared with the first quarter of 2020, evidenced by a 5.9% decrease in heating-degree days between the quarters.

These decreases in revenue were partially offset by:

●

A $2.9 million increase in Minnesota and North Dakota renewable rider revenues related to earning a return on funds invested in the Merricourt Wind Energy Center (Merricourt) while the project is under construction.

●

~~A $1.3 million increase in revenues related to increased consumption due to favorable quarter over quarter weather impacts.~~

●

A $0.7 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 $0.2 million increase in revenue related to volume sales increases of electricity to residential customers exclusive of the impact of weather on sales.~~

~~Transmission services revenue decreased $1.8~~

•A $2.3 million ~~mainly due~~increase in new retail revenues, net of an estimated refund, related to ~~lower tariffs and decreased transmission volume resulting from lower electrical demand partially attributable to the impact of COVID-19.~~

~~The~~an interim rate increase in Minnesota effective January 1, 2021 in connection with OTP's current Minnesota rate case filed in November 2020.

•A $0.7 million increase in ~~other revenue includes $1.0~~conservation rider revenues related to the recovery of increased conservation improvement program spending in Minnesota and South Dakota.

•A $0.5 million ~~from a commercial customer~~increase in renewable rider revenues in North Dakota related to recovery of Merricourt operating expenses and returns on increased investment in the ~~second~~project, which was placed in service in the fourth quarter of 2020.

•A $0.5 million increase in retail revenue due to a positive price variance resulting from varying kwh sales to customers under different tariffs.

•A $0.3 million net increase in North Dakota and South Dakota generation, transmission and phase-in rider revenues related to the recovery of Astoria Station and transmission project costs.

Transmission Services Revenues increased $1.1 million due to increases of $0.7 million in generator interconnection revenues under two new agreements which began billing after the first quarter of 2020 ~~partially offset~~and $0.4 million in Midcontinent Independent System Operator. Inc. (MISO) transmission services tariff revenues.

Wholesale Electric Revenue increased $3.6 million as a result of a 106.6% increase in wholesale kwh sales and a 149% increase in wholesale electric prices driven by ~~a $0.3 million decrease in revenue from steam sales to an ethanol producer due to Big Stone Plant being on economic dispatch~~high market demand and ~~not producing steam at certain times~~availability constraints during the ~~second quarter~~February 2021 cold weather, which drove up spot market prices for electricity.

Production Fuel costsincreased $1.0 million mainly as a result of ~~2020.~~

~~Production fuel costs increased $0.5 million despite an 11.7% decrease~~a 16.2% increase in kwhs generated from our fuel-burning plants ~~mainly as a result of a 20.0% increase~~due to higher demand and favorable prices for energy in ~~fuel-cost per kwh of generation, weighted heavily by higher fuel~~wholesale markets. Fuel costs per kwh of generation decreased 7.8% at ~~Coyote Station~~our fuel-burning plants as a result of increased efficiencies at higher and longer-sustained levels of generation. Fuel costs per kwh of generation including renewable generation decreased 15.4% as a result of Merricourt being added to our generation mix in ~~the second quarter of~~December 2020. ~~Coyote Station was down for maintenance in the second quarter of 2019.~~

~~The cost of purchased power~~

Purchased Power costs to serve retail customers ~~decreased $6.0~~increased $0.4 million as a result of a 26.2% decrease in purchased power prices, driven mainly by low prices for natural gas-fired generation, and a 5.6% decrease in kwhs purchased. The decrease in purchased power volume is due, in part, to COVID-19-related declines in electricity use by commercial and industrial customers.

~~Electric operating and maintenance expense decreased $6.7 million, including:~~

●

~~A $3.0 million decrease in contracted services and materials and supplies expenses at Coyote Station related to the plant's second quarter 2019 extended maintenance outage.~~

●

~~A $1.1 million decrease in labor and benefit expenses.~~

●

~~A $1.0 million decrease in transmission tariff expenses related to decreased kwh purchases and decreased transmission tariff rates.~~

●

~~A $0.9 million decrease in vegetation maintenance expenses and conservation improvement program expenditures.~~

●

~~A $0.6 million decrease in materials and supplies and contracted services expenses at Hoot Lake Plant related to second quarter 2019 turbine repairs.~~

~~A $0.4 million decrease in travel-related expenses related to COVID-19 travel restrictions was offset by a $0.4 million~~26.6% increase ~~in customer bad debt expense provisions due to adoption of COVID-19-related service suspension and debt collection policies.~~

~~Depreciation expense increased $0.7 million mainly due to 2019 capital additions for generation and transmission plant.~~

~~Table of Contents~~

~~Manufacturing~~

Three Months Ended

June 30,

%

(in thousands)

2020

2019

Change

Change

Operating Revenues
$ 45,948 $ 73,496 $ (27,548 ) (37.5 )
Cost of Products Sold
36,087 56,364 (20,277 ) (36.0 )
Operating Expenses
5,499 7,954 (2,455 ) (30.9 )
Depreciation and Amortization
3,739 3,419 320 9.4
Operating Income
$ 623 $ 5,759 $ (5,136 ) (89.2 )

~~The $27.5 million decrease in revenues in our Manufacturing segment includes the following:~~

●

Revenues at BTD Manufacturing, Inc. (BTD) decreased $26.0 million. Parts revenue was down $19.8 million related to decreased sales volumes to all end market customer categories served by BTD, in order of magnitude: recreational vehicle, construction, lawn and garden, agricultural, industrial and energy equipment end markets, as customers implemented temporary plant shutdowns due to the COVID-19 pandemic. Lower prices related to the pass through of lower material costs accounted for a $5.9 million decrease in parts revenue, partially offset by $0.5 million in price increases exclusive of the pass through of material cost reductions. Scrap revenue decreased $0.8 million due to a 46.8% decrease in scrap volume and a 5.1% decrease in scrap metal prices.

●

Revenues at T.O. Plastics, Inc. (T.O. Plastics), our manufacturer of thermoformed plastic and horticultural products, decreased $1.5 million primarily due to decreases of $0.9 million in sales of horticultural containers, $0.3 million in industrial sales and $0.2 million in life sciences product sales. The decreased sales level was mainly due to market softness generated by the uncertainty of how COVID-19 was going to impact these end markets.

~~The $20.3 million decrease in cost of products sold in our Manufacturing segment includes the following:~~

●

~~Cost of products sold at BTD decreased $19.5 million as a result of both the decreased sales volume and the $5.9 million in lower material costs passed through to customers.~~

●

~~Cost of products sold at T.O. Plastics decreased $0.8 million related to the decrease in sales volume.~~

The $2.5 million decrease in operating expenses in our Manufacturing segment includes a $2.3 million decrease in operating expenses at BTD related to initiatives taken at BTD to mitigate the negative impacts on sales related to COVID-19, mainly reductions in salaries, incentives and benefits, travel and outside services expenditures. Operating expenses at T.O. Plastics decreased $0.2 million, mainly due to decreases in salaries and incentives.

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 second quarter earnings by approximately $0.08 per share. 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~~

Three Months Ended

June 30,

%

(in thousands)

2020

2019

Change

Change

Operating Revenues
$ 48,679 $ 53,476 $ (4,797 ) (9.0 )
Cost of Products Sold
37,747 41,635 (3,888 ) (9.3 )
Operating Expenses
2,970 2,949 21 0.7
Depreciation and Amortization
872 861 11 1.3
Operating Income
$ 7,090 $ 8,031 $ (941 ) (11.7 )

Plastics segment revenues and operating income decreased $4.8 million and $0.9 million, respectively, due to a 5.8% decrease in pounds of polyvinyl chloride (PVC) pipe sold in combination with a 3.3% decrease in PVC pipe prices. The decrease in

~~Table of Contents~~

sales volume is attributed to a drop in sales to distributors who reduced inventory levels due to uncertainty over the impact of COVID-19 on sales and expectations of PVC pipe prices decreasing in light of declining resin prices in the second quarter of 2020. Cost of products sold decreased $3.9 million due to the decrease in sales volume and a 3.7% decrease in the cost per pound of PVC pipe sold mainly due to a decrease in resin costs. The decrease in pipe prices partially offset by a decrease in resin prices resulted in a 2.0% decrease in gross margin per pound of PVC pipe sold.

~~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.

Three Months Ended

June 30,

%

(in thousands)

2020

2019

Change

Change

Operating Expenses
$ 2,315 $ 2,369 $ (54 ) (2.3 )
Depreciation and Amortization
85 79 6 7.6

~~Interest Charges~~

Interest charges increased to $8.7 million in the three months ended June 30, 2020 from $7.8 million in the three months ended June 30, 2019. The $0.9 million increase in interest charges is primarily due to an increase in interest expense at OTP related to debt issuances of $100 million in October of 2019 and $35 million in February of 2020 under OTP’s 2019 Note Purchase Agreement.

~~Other Income~~

~~Other income increased to $2.4 million in the three months ended June 30, 2020 from $0.8 million in the three months ended June 30, 2019. The $1.6 million increase in other income includes:~~

●

~~A $0.7 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 $0.6 million increase in the cash surrender value of corporate-owned life insurance policies held by the Company.~~

●

~~A $0.2 million increase in unrealized gains earned on equity investments held by our captive insurance company, Otter Tail Assurance Limited.~~

~~Income Tax Expense~~

Income tax expense increased $0.5 million in the three months ended June 30, 2020 compared with the three months ended June 30, 2019 mainly due to the tax effect of a $2.0 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.

Three Months Ended June 30,

(in thousands)

2020

2019

Income Before Income Taxes
$ 20,789 $ 18,769
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%)
$ 5,405 $ 4,879
(Decreases) Increases in Tax from:

Differences Reversing in Excess of Federal Rates
(543 ) (774 )
Research and Development and Other Tax Credits
(333 ) (187 )
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes
(258 ) (258 )
Allowance for Funds Used During Construction – Equity
(248 ) (94 )
Corporate Owned Life Insurance
(193 ) (150 )
Other Items – Net
(22 ) (73 )
Income Tax Expense
$ 3,808 $ 3,343
Effective Income Tax Rate
18.3 % 17.8 %

~~Table of Contents~~

~~Comparison of the Six Months Ended June 30, 2020 and 2019~~

Consolidated operating revenues were $427.5 million for the six months ended June 30, 2020 compared with $475.2 million for the six months ended June 30, 2019. Operating income was $67.2 million for the six months ended June 30, 2020 compared with $66.4 million for the six months ended June 30, 2019. The Company recorded diluted earnings per share of $1.02 for the six months ended June 30, 2020 compared with $1.05 for the six months ended June 30, 2019.

Amounts presented in the segment tables that follow for operating revenues, cost of products sold and other nonelectric operating expenses for the six-month periods ended June 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)

June 30, 2020

June 30, 2019

Operating Revenues:

Electric
$ 29 $ 27
Nonelectric
-- 3
Costs of Products Sold
7 20
Other Nonelectric Expenses
22 10

~~Electric~~

Six Months Ended

June 30,

%

(in thousands)

2020

2019

Change

Change

Retail Sales Revenues from Contracts with Customers
$ 192,034 $ 202,931 $ (10,897 ) (5.4 )
Changes in Accrued Revenues under Alternative Revenue Programs
122 (680 ) 802 117.9
Total Retail Sales Revenue
$ 192,156 $ 202,251 $ (10,095 ) (5.0 )
Transmission Services Revenue
20,514 22,331 (1,817 ) (8.1 )
Wholesale Revenues – Company Generation
1,641 2,468 (827 ) (33.5 )
Other Revenues
3,718 3,303 415 12.6
Total Operating Revenues
$ 218,029 $ 230,353 $ (12,324 ) (5.4 )
Production Fuel
22,523 27,216 (4,693 ) (17.2 )
Purchased Power – System Use
32,512 41,585 (9,073 ) (21.8 )
Other Operation and Maintenance Expenses
73,794 78,238 (4,444 ) (5.7 )
Depreciation and Amortization
31,416 29,567 1,849 6.3
Property Taxes
8,268 7,859 409 5.2
Operating Income
$ 49,516 $ 45,888 $ 3,628 7.9
Electric mwh Sales

Retail mwh Sales
2,462,963 2,566,191 (103,228 ) (4.0 )
Wholesale mwh Sales – Company Generation
81,064 82,139 (1,075 ) (1.3 )
HDDs
3,907 4,650 (743 ) (16.0 )
CDDs
170 104 66 63.5

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

Six Months ended June 30,

2020

2019

HDDs
99.1 % 118.6 %
CDDs
156.0 % 95.4 %

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 six months of 2020 and 2019 and between the periods:

2020 vs Normal

2019 vs Normal

2020 vs 2019

Effect on Diluted Earnings Per Share
$ 0.01 $ 0.08 $ (0.07 )

~~Table of Contents~~

~~The $10.1 million decrease in retail sales revenue includes:~~

●

A $12.0 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 and the impacts of COVID-19 contributed to a 20.1% decrease in kwhs generated for system use and a $4.1 million decrease in fuel costs. Purchased power costs decreased by $9.1 million despite a 5.1% increase in kwhs purchased due to a 25.6% decrease in purchased power prices.

●

A $3.9 million decrease in revenues related to decreased consumption due to milder weather in the first six months of 2020 compared with the first six months of 2019, evidenced by a 16.0% decrease in heating-degree days between the periods.

●

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.

●

A $0.4 million decrease in revenue due to decreased kwh sales to commercial and industrial customers resulting from a $2.2 million reduction in commercial and industrial sales due to COVID-19-related impacts on sales in the second quarter of 2020, mostly offset by increased sales resulting from a large commercial customer expanding its production capacity and increasing demand.

●

~~A $0.2 million decrease in transmission rider revenues.~~

~~These decreases in revenue were partially offset by:~~

●

~~A $5.3 million increase in Minnesota and North Dakota renewable rider revenues related to earning a return on funds invested in Merricourt while the project is under construction.~~

●

$1.4 million 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 $0.6 million increase in revenue related to volume sales increases of electricity to residential and commercial customers exclusive of the impact of weather on sales.~~

Transmission services revenue decreased $1.8 million mainly due to a reduction in transmission tariff revenues related to decreased transmission volume resulting from lower electrical demand partially attributable to the impact of COVID-19.

Wholesale electric revenues decreased $0.8 million due to lower wholesale electric prices and a 1.3% decrease in wholesale kwh sales. The lower wholesale prices per kwh resulted in a $0.2 million decrease in margins on wholesale energy sales from OTP’s generating units in the first six months of 2020 compared with the first six months of 2019.

Production fuel costs decreased $4.7 million due to a 23.2% decrease in kwhs generated at OTP’s fuel-burning generation plants, partially offset by a 7.8% increase in fuel costs per kwh generated. A 69.7% increase in generation at Coyote Station, which was offline for maintenance during the entire second quarter of 2019, was more than offset by decreases in generation at both Big Stone Plant and Hoot Lake Plant, which were curtailed due to economic dispatch as reduced demand and lower prices for alternative fuels and generation sources drove market prices for electricity down in the second quarter of 2020.

~~The cost of purchased power to serve retail customers decreased $9.1 million as a result of a 25.6% decrease~~ in purchased power prices, partially offset by a ~~5.1% increase~~19.2% decrease in kwhs purchased. The ~~decrease~~increase in ~~market~~kwh prices ~~for electricity~~mainly was driven by ~~low prices~~high market demand for ~~natural gas-fired generation~~electricity and availability constraints caused by the February 2021 cold weather.

Operating and MaintenanceExpense increased $0.8 million mainly due to:

•$1.2 million in ~~combination with lower demand in the second quarter of 2020 due to COVID-19-related declines in electricity use by commercial and industrial consumers.~~

~~Electric~~Merricourt operating and maintenance ~~expense decreased $4.4 million, including:~~

●

~~A $3.4 million decrease in contracted services and materials and supplies expenses at Coyote Station, mainly related to the plant's second~~expenses incurred in the first quarter ~~2019 extended maintenance outage.~~

●

~~A $1.5 million decrease in transmission tariff expenses related to decreased rates.~~

●

~~A $0.5 million decrease in materials and supplies and contracted services expenses at Hoot Lake Plant related to second quarter 2019 turbine repairs.~~

●

~~A $0.5 million decrease in pollution control reagent costs due to a 23.9% decrease in kwhs generated at OTP’s coal burning plants between periods.~~

~~These items were partially offset by:~~

●

~~A $1.6 million net increase in labor and benefit costs.~~

~~Table~~ of ~~Contents~~2021 as the wind farm is now commercially operational.

•A ~~$0.7 million decrease in travel and employee education expenses related to COVID-19 travel restrictions and social distancing requirements was offset by a~~ $0.7 million increase in ~~customer~~conservation improvement program expenditures, which are being recovered through retail rate riders in Minnesota and South Dakota.

These increases in expense were partially offset by:

•A $0.6 million decrease in steam generation plant maintenance and operating expenses.

•A $0.5 million decrease in bad debt expense ~~provisions~~ due to ~~adoption of COVID-19-related service suspension and debt collection policies.~~

~~Depreciation expense increased $1.8 million mainly due to 2019 capital additions for generation and transmission plant, the new~~improved customer ~~information system that went into service during~~collections in the first quarter of ~~2019~~2021.

Depreciation and ~~new service vehicles.~~

~~Property tax~~ Amortization expense increased ~~$0.4~~$1.6 million primarily due to Merricourt going into service in December of 2020.

Property Taxes increased $0.2 million due to property additions and increased ~~jurisdictional valuations.~~

valuations on existing property.

~~Manufacturing~~

Six Months Ended

June 30,

%

(in thousands)

2020

2019

Change

Change

Operating Revenues
$ 114,427 $ 151,318 $ (36,891 ) (24.4 )
Cost of Products Sold
86,701 115,603 (28,902 ) (25.0 )
Operating Expenses
12,777 16,034 (3,257 ) (20.3 )
Depreciation and Amortization
7,485 7,101 384 5.4
Operating Income
$ 7,464 $ 12,580 $ (5,116 ) (40.7 )

Table of Contents

MANUFACTURING SEGMENT RESULTS

The ~~$36.9 million decrease in revenues in~~following table summarizes the results of operations for our Manufacturing segment ~~includes~~for the three months ended March 31, 2021 and 2020:


(in thousands)	2021		2020		$ change		% change

Operating Revenues	$	75,825	$	68,479	$	7,346	10.7	%
Cost of Products Sold	56,311		50,614		5,697		11.3
Other Operating Expenses	8,212		7,278		934		12.8
Depreciation and Amortization	3,757		3,746		11		0.3
Operating Income	$	7,545	$	6,841	$	704	10.3	%

Operating Revenues increased $7.3 million primarily due to the following:

●

Revenues at BTD decreased $36.2 million. Parts revenue was down $22.5 million related to decreased sales volumes to all end market customer categories served by BTD, in order of magnitude: recreational vehicle, construction, lawn and garden, agricultural, energy equipment and industrial end markets, as customers implemented temporary plant shutdowns due to the COVID-19 pandemic. Lower prices related to the pass through of lower material costs accounted for a $13.0 million decrease in parts revenue, partially offset by $0.6 million in price increases exclusive of the pass through of material cost reductions. In addition to the decrease in parts revenue, scrap revenue decreased $1.4 million due to a 30.1% decrease in scrap volume and a 13.0% decrease in scrap metal prices.

●

Revenues at T.O. Plastics decreased $0.7 million primarily due to a $0.6 million decrease in industrial sales and a $0.3 million decrease in sales of life sciences products and scrap material, partially offset by a $0.2 million increase in sales of horticultural containers. The $0.9 million in decreased sales of industrial and life sciences products is associated with lower demand from customers due to COVID-19-related impacts on customer’s production and sales activity.

•At BTD, revenues increased $6.2 million, consisting of $4.4 million in material cost increases passed through to customers and $1.8 million in volume and price increases. The ~~$28.9~~volume increase was driven by stronger sales in the recreational vehicle, agricultural, lawn and garden and construction end markets offset, in part, by a decline in sales primarily in the energy end market. Scrap revenues increased $1.5 million ~~decrease~~mostly due to increases in ~~cost~~scrap metal prices, but also due to increases in scrap volumes from increased sales and production activity. These increases in revenue were, partially offset by lower tooling and other revenues.

•At T.O. Plastics, revenues increased $0.4 million. A $1.0 million increase in horticultural product sales was partially offset by decreases in industrial, life sciences and other product sales totaling $0.6 million.

Cost of Products Sold increased $5.7 million due to the following:

•Cost of products sold at BTD increased $5.9 million as a result of higher material prices and sales-volume-driven increases in ~~our Manufacturing segment includes~~material and labor costs.

•Cost of products sold at T.O. Plastics decreased $0.2 million due to lower material costs resulting from a higher mix of product sales utilizing reclaimed material and the ~~following:~~

●

~~Cost of products sold at BTD decreased $29.1 million as a result of both the decreased sales volume and the $13.0 million in lower material costs passed through to customers.~~

●

Cost of products sold at T.O. Plastics increased $0.2 million due to an increases in rental costs for more warehouse space and increases in other indirect costs, despite a $0.5 million decrease in material costs related to the decrease in sales volume.

~~The $3.3 million decrease~~reduction in ~~operating expenses~~industrial and life sciences product sales, which more than offset increases in ~~our Manufacturing segment includes a $2.5 million decrease in operating~~material costs on increased horticultural product sales.

Other Operating Expenses increased $0.9 million. Operating expenses at BTD ~~related~~increased $0.5 million mainly due to ~~initiatives taken at BTD to mitigate the negative impacts on sales related to COVID-19, mainly reductions~~increases in ~~salaries, incentives and benefits, travel and outside services expenditures.~~operating expenses. Operating expenses at T.O. Plastics ~~decreased $0.8~~increased $0.4 million, ~~including $0.4~~mainly due to recognition of an expense reduction of $0.6 million related to insurance settlement proceeds received in the first quarter of 2020.

PLASTICS SEGMENT RESULTS

The following table summarizes the results of operations for our Plastics segment for the three months ended March 31, 2021 and 2020:


(in thousands)	2021		2020		$ change		% change

Operating Revenues	$	62,186	$	46,397	$	15,789	34.0	%
Cost of Products Sold	45,666		35,270		10,396		29.5
Other Operating Expenses	2,944		2,770		174		6.3
Depreciation and Amortization	990		890		100		11.2
Operating Income	$	12,586	$	7,467	$	5,119	68.6	%

Operating Revenues increased $15.8 million due to a 34% increase in the price per pound of PVC pipe sold and a 1.1% increase in pounds of PVC pipe sold. The price increase was driven, in part, by PVC resin supply constraints due to resin production plant shutdowns and feedstock shortages related to abnormally low temperatures and snowstorms in the Gulf Coast region of the United States in February 2021 and significant global demand for PVC resin and limited pipe inventory across the country. Cost of products sold increased $10.4 million primarily due to increased PVC resin and other material cost increases.

Cost of Products Sold increased $10.4 million primarily due to increased PVC resin and other material cost increases.

Other Operating Expenses increased $0.2 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~~increased incentive benefits directly related to ~~the March 2019 partial roof collapse. T.O, Plastics travel and other selling expenses decreased by $0.1 million due to restrictions on activity in response to COVID-19-related safety initiatives.~~

We estimate COVID-19 issues at BTD negatively impacted our earnings by approximately $0.09 per share in the first six 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.

~~Table of Contents~~

~~Plastics~~

Six Months Ended

June 30,

%

(in thousands)

2020

2019

Change

Change

Operating Revenues
$ 95,076 $ 93,534 $ 1,542 1.6
Cost of Products Sold
73,017 72,995 22 --
Operating Expenses
5,740 5,614 126 2.2
Depreciation and Amortization
1,762 1,752 10 0.6
Operating Income
$ 14,557 $ 13,173 $ 1,384 10.5

~~Plastics segment revenues and operating income~~ increased ~~$1.5 million and $1.4 million, respectively, due to a 4.4% increase in pounds of pipe sold, partially offset by a 2.6% decrease in PVC pipe prices.~~ profitability.

CORPORATE COSTS

The sales volume increase resulted mainly from weather conditions that negatively impacted sales across our sales territory in the first quarter of 2019. Cost of products sold remained unchanged despite the increase in sales volume due to a 4.2% decrease in the cost per pound of pipe sold, mainly due to decreased resin costs. These items resulted in a 2.9% increase in gross margin per pound of PVC pipe sold.

following table summarizes Corporate

~~Corporate includes items such as corporate staff and overhead costs, the~~ results of ~~our captive insurance company~~operations for the three months ended March 31, 2021 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.

Six Months Ended

June 30,

%

(in thousands)

2020

2019

Change

Change

Operating Expenses
$ 4,167 $ 5,101 $ (934 ) (18.3 )
Depreciation and Amortization
172 152 20 13.2

~~Corporate operating expenses decreased $0.9~~2020:


(in thousands)	2021		2020		$ change		% change

Other Operating Expenses	$	2,537	$	1,852	$	685	37.0	%
Depreciation and Amortization	71		87		(16)		(18.4)
Operating Loss	$	2,608	$	1,939	$	669	34.5	%

Other Operating Expenses increased $0.7 million mainly as a result of increased stock incentive compensation expenses related to improved performance of the Company's stock quarter over quarter and in its projected returns on equity.

Table of Contents


REGULATORY RATE MATTERS

The following provides a summary of general rate case filings and rate rider 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 revenue recoverable under general rates in Minnesota. In its filing, OTP requested a net ~~decrease in incentive and benefit costs of $0.5 million and a $0.3 million decrease in contracted service expenditures.~~

~~Interest Charges~~

~~Interest charges increased to $16.8 million in the six months ended June 30, 2020 from $15.7 million in the six months ended June 30, 2019. The $1.1 million~~ increase in ~~interest charges is~~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 in 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 ~~an increase~~a reduction in ~~interest~~operating costs from amounts included in its November 2020 filing. The cost reductions include, among other items, lower depreciation expense ~~at OTP related~~on our wind generation assets due to ~~debt issuances~~the extension of ~~$100 million~~depreciable lives from 25 to 35 years and a reduction in ~~October of 2019 and $35 million in February of 2020 under OTP’s 2019 Note Purchase Agreement.~~

postretirement benefit costs.

RATE RIDERS

~~Table of Contents~~

Recovery

Filing

Amount

Effective

Mechanism

Jurisdiction

Status

Date

(in millions)

Date

Notes

RRR - 2019

Approved

06/21/19

12.5

01/01/20

Includes return on Merricourt construction costs.

TCR - 2018

Approved

05/07/20

10.3

01/21/20

See below for additional details.

TCR - 2020

Approved

08/31/20

5.6

01/21/20

Includes recovery of new transmission assets.

RRR - 2020

Approved

03/18/20

5.8

04/01/20

Includes return on Merricourt construction costs.

GCR - 2020

Approved

06/10/20

6.2

07/01/20

Includes return on Astoria Station construction costs.

TCR - 2021

Approved

11/18/20

5.6

01/01/21

Includes recovery of eight new transmission projects.

TCR - 2020

Approved

01/29/20

2.3

03/02/20

Annual update to transmission cost recovery rider.

PIR - 2020

Approved

05/31/20

1.6

09/01/20

Includes return on Merricourt and Astoria Station construction costs.

TCR - 2021

Approved

02/19/21

2.2

03/01/21

Includes recovery of two new transmission projects.

RRR - 2021

Approved

03/07/21

11.8

04/01/21

Includes return on Merricourt construction costs.

GCG - 2021

Requested

03/01/21

5.2

—

Includes recovery of Astoria Station, net of anticipated savings associated with the retirement of Hoot Lake Plant.

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 ~~calculated~~levels.

On August 18, 2017, OTP filed an appeal 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 the 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 ~~our net composite federal and state statutory rate on income before income taxes on our consolidated statements~~December 2020 of ~~income.~~

Six Months Ended June 30,

(in thousands)

2020

2019

Income Before Income Taxes
$ 50,695 $ 50,721
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%)
$ 13,181 $ 13,187
(Decreases) Increases in Tax from:

Differences Reversing in Excess of Federal Rates
(1,772 ) (1,757 )
Allowance for Funds Used During Construction – Equity
(560 ) (180 )
Excess Tax Deduction – Equity Method Stock Awards
(535 ) (827 )
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes
(516 ) (516 )
Research and Development and Other Tax Credits
(387 ) (375 )
Corporate Owned Life Insurance
14 (559 )
Other Items – Net
21 (2 )
Income Tax Expense
$ 9,446 $ 8,971
Effective Income Tax Rate
18.6 % 17.7 %

$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 MISO revenues credits to Minnesota customers through the TCR rider prior to September 30, 2020. As a result, OTP recognized additional rider revenue of $2.6 million during the third quarter of 2020.

~~Liquidity~~Table of Contents

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 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 ~~June 30, 2020,~~March 31, 2021, we were in compliance with all debt covenants (see the Financial ~~Covenant~~Covenants section under Capital Resources below).

~~As of June 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~~business 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 ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019:~~

(in thousands)

Line Limit

In Use on
June 30,
2020

Restricted due to Outstanding Letters of Credit

Available on
June 30,
2020

Available on
December 31,
2019

Otter Tail Corporation Credit Agreement
$ 170,000 $ 41,239 $ -- $ 128,761 $ 164,000
OTP Credit Agreement
170,000 -- 7,670 162,330 154,524
Total
$ 340,000 $ 41,239 $ 7,670 $ 291,091 $ 318,524

2020:


			2021						2020
(in thousands)	Line Limit		Amount Outstanding		Letters of Credit		Amount Available		Amount Available

Otter Tail Corporation Credit Agreement	$	170,000	$	78,206	$	—	$	91,794	$	104,834
OTP Credit Agreement	170,000		56,645		12,671		100,684		140,068
Total	$	340,000	$	134,851	$	12,671	$	192,478	$	244,902

We have ~~adopted~~ an internal risk tolerance metric to maintain a minimum of $50 million of liquidity under the Otter Tail Corporation 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.

The following is a discussion of our cash flows for the three months ended March 31, 2021 and 2020:


(in thousands)	2021		2020

Net Cash Provided by Operating Activities	$	15,270	$	21,777

Net Cash Provided by Operating Activities decreased $6.5 million for the three months ended March 31, 2021 compared to the three months ended March 31, 2020. An increase in net income in 2021 was more than offset by an increase in working capital requirements, which was primarily the result of increased accounts receivables within our Manufacturing and Plastics segments due to strong sales volumes and increased sales prices during the three months ended March 31, 2021. We ~~expect~~made a discretionary contribution to ~~issue~~ our ~~Series 2020B Notes~~pension plan of $10.0 million during the three months ended March 31, 2021 compared to a contribution of $11.2 million in 2020. We do not anticipate making any further discretionary contributions to the pension plan in 2021.


(in thousands)	2021		2020

Net Cash Used in Investing Activities	$	49,020	$	75,059

Net Cash Used in Investing Activities decreased $26.0 million for the three months ended March 31, 2021 compared to the three months ended March 31, 2020. The decrease is primarily the result of lower capital investment within our Electric segment as capital spending on ~~August 20,~~our large generation assets, Merricourt and Astoria Station, were largely completed in the fourth quarter of 2020.


(in thousands)	2021		2020

Net Cash Provided by Financing Activities	$	33,799	$	39,967

Net Cash Provided by Financing Activities decreased $6.2 million for the three months ended March 31, 2021 compared to the three months ended March 31, 2020, ~~to provide an additional $40.0~~primarily as a result of a decrease in financing needs given the lower level of capital spending in our Electric segment in 2021. Financing activities in the three months ended March 31, 2021 included a net borrowing increase of $53.9 million under our line of ~~liquidity. Our At-the-Market equity offering program, which allows us to sell common shares up to an aggregate sales price~~credit facilities and a dividend payment of ~~$75~~$16.2 million ~~remains~~($0.39 per share).

Financing activities in ~~effect. We issued $27.0~~the three months ended March 31, 2020 included proceeds of $35.0 million from the issuance of long-term debt, a net borrowing increase of $13.9 million under our line of credit facilities and $6.2 million in proceeds raised from the issuance of common ~~equity~~stock, net of issuance costs. We paid a dividend of $14.9 million ($0.37 per share) in the three months ended March 31, 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 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. Refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, of our Form 10-K for the year ended December 31, 2020 for our capital expenditure plan for the five year period from 2021 through 2025.

CONTRACTUAL OBLIGATIONS

Our contractual obligations primarily include principal and interest payments due under our ~~At-the-Market offering program, Dividend Reinvestment~~outstanding debt obligations, commitments to acquire coal, energy and ~~Employee Stock Purchase plans~~capacity 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 Form 10-K for the year ended December 31, 2020. There were no material in our contractual obligations outside of the ordinary course of our business during the three months ended March 31, 2021.

COMMON STOCK DIVIDENDS

We paid dividends to our common stockholders totaling $16.2 million, or $0.39 per share, in the first ~~six~~three months of 2020. We expect to issue up to an additional $28 million in common equity under these programs barring any further deteriorations of the capital markets from the COVID-19 pandemic or other factors. If weakened economic conditions persist for a prolonged period of time, we are prepared to add additional liquidity as necessary, including exercising the accordion features under our lines of credit to increase our available borrowing capacity under the lines by a combined $200 million.

~~Table of Contents~~

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 7~~Note 10 to our consolidated financial statements included in this report on Form 10-Q for additional information. The decision to declare a dividend is reviewed quarterly by ~~the board~~our Board of ~~directors. On February 4, 2020 our board of directors increased the quarterly dividend from $0.35 to $0.37 per common share.~~

~~2020 Cash Flows Compared with 2019 Cash Flows~~

~~Cash~~Directors.

Financial flexibility is provided by operating ~~activities was $73.9 million for the six months ended June 30, 2020 compared with~~ cash ~~provided~~flows, unused lines of credit, and access to capital markets, which is aided by operating activities of $69.3 million for the six months ended June 30, 2019. The primary reasons for the $4.6 million increase in cash provided by operations between the quarters were a $2.3 million increasestrong financial coverages and investment grade credit ratings. Equity or debt financing will be required in the ~~non-cash depreciation expense and a $2.1 million decrease in cash used for working~~period 2021 through 2025 to support our capital ~~items between the quarters.~~

Net cash used in investing activities was $121.0 million for the six months ended June 30, 2020 compared with $55.4 million for the six months ended June 30, 2019. The $65.6 million increase is mainly dueinvestments, primarily within our Electric segment to a $70.3 million increase in cash used for construction expenditures at OTP, partially offset by a $4.5 million net decrease in capital expenditures in our nonutility businesses. OTP’s cash used for capital expenditures totaled $113.9 million in the first six months of 2020 compared with $43.6 million in the first six months of 2019. The majority of the 2020 expenditures at OTP related to thefund construction of ~~Astoria Station~~new rate base and ~~Merricourt.~~

~~Net cash provided by~~transmission investments. In addition, we may issue equity or debt financing ~~activities was $65.4 million for the six months ended June 30, 2020 compared with net cash used in financing activities~~to opportunistically reduce borrowings under our lines of ~~$13.8 million for the six months ended June 30, 2019. Financing activities in the first six months of 2020 included $35.0 million in proceed from the issuance of~~credit, to satisfy or early retire our outstanding long-term debt, ~~at OTP under its 2019 Note Purchase Agreement~~or to fund its current construction program expenditures. Further information on the debt issuance is provided below under “Capital Resources.” We also borrowed $35.2 million under the Otter Tail Corporation Credit Agreement and raised net proceeds of $24.8 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 ~~$78 million in equity contributions to OTP to fund its construction program expenditures. Financing activities in the six months of 2020 also included $29.9 million in common dividend payments.~~

Financing activities in the first six months of 2019 included proceeds of $13.4 million from borrowings under the OTP credit agreement to fund OTP capital expenditures and $4.6 million under the Otter Tail Corporation Credit Agreement to provide working capital for our manufacturing companies. The line of credit borrowings were more than offset by $27.9 million in common dividend payments.

~~Table of Contents~~

~~CAPITAL REQUIREMENTS~~

~~201~~9~~-20~~24 ~~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 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 June 30, 2020, OTP had capitalized approximately $131.7 million in project costs and allowances for funds used during construction (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 $6.5 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 expects Merricourt to be completed before December 31, 2020. These and other ~~potential impacts of COVID-19-related disruptions continue to present risks for the schedule, costs and timing of payments related to the project.~~

As of June 30, 2020, OTP had capitalized approximately $108.0 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 $154 million and anticipates the plant will be online in late 2020 or early 2021, prior to the planned retirement of Hoot Lake Plant in May 2021. OTP has not altered the construction schedule for Astoria Station due to COVID-19. However, COVID-19-related disruptions have increased risks for the project workforce given, among other factors, that it involves more than 250 construction workers on site and 26 have tested positive for COVID-19. Circumstances continue to evolve which could result in a delay in completion and increased costs for the project.

As of June 30, 2020, our capital expenditure activities had not been materially impacted by COVID-19. However, future supply chain, workforce, contractor or other disruptions could result in added costs and lead to delayed completion of certain of our capital expenditure projects. We are actively monitoring our supply chains and working with our contractors to ensure the continued safety of all parties.

~~Contractual Obligations~~

In the first six 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 $185 million as of June 30, 2020. This includes commitments related to the construction of Astoria Station and Merricourt of $163 million for the remainder of 2020 and $6 million for 2021. In the first quarter of 2020, OTP increased its debt obligations by $35 million in the years beyond 2024.

corporate purposes.

REGISTRATION STATEMENTS

Otter Tail Corporation and ~~OTP. See note 10~~Otter Tail Power Company are each party to a credit agreement (the OTC Credit Agreement and OTP Credit Agreement, respectively) which provide for unsecured revolving lines of credit. The following is a summary of key provisions and borrowing information as of and for the three months ended March 31, 2021:


(in thousands, except interest rates)	OTC Credit Agreement			OTP 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 March 31, 2021	—			12,671
Amount Outstanding as of March 31, 2021	78,206			56,645
Average Amount Outstanding During the Three Months Ended March 31, 2021	68,737			38,007
Maximum Amount Outstanding During the Three Months Ended March 31, 2021	79,718			69,674
Interest Rate as of March 31, 2021	1.6		%	1.4		%
Maturity Date	October 31, 2024			October 31, 2024


1Each facility includes an accordion featuring allowing the borrower to increase the borrowing limit if certain terms and conditions are met.

At March 31, 2021, we had $767.0 million of principal outstanding under long-term debt arrangements. These instruments generally provide for unsecured borrowings at fixed rates of interest with maturities ranging from 2021 to 2050. Note 6 to our consolidated financial statements included in ~~our Annual Report~~this report on Form ~~10-K for the year ended December 31, 2019 for~~10-Q includes additional information ~~on the terms, provisions, restrictions and covenants under~~regarding these ~~agreements.~~

~~Short-Term Debt~~

~~On October 29, 2012 we entered into~~instruments. One OTP debt instrument with a ~~Third Amended and Restated Credit Agreement (the OTC Credit Agreement), which provided for an unsecured $130~~principal balance of $140.0 million revolving credit facility that could be increased subject to certain terms and conditions. On October 31, 2019 the OTC Credit Agreement was amended to extend its expiration date by one year from October 31, 2023 to October 31, 2024, and to increase the amount of the revolving credit facility to $170 million. The amendment also provides this facility can be increased to $290 million subject to certain terms 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 provided for the senior unsecured credit.

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 creditmatures 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 unsecuredDecember 2021. We anticipate issuing long-term debt ~~or the issuer rating if a rating is not provided for the senior unsecured debt.~~

~~Long-Term Debt~~

~~On September 12, 2019,OTP entered into a Note Purchase Agreement (the 2019 Note Purchase Agreement)~~in 2021 with the ~~purchasers named therein, pursuant~~proceeds used to ~~which OTP agreed to issue to the purchasers, in a private placement transaction, $175 million aggregate principal amount~~satisfy this maturing instrument.

Certain 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)our short- 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 pursuant to the 2019 Note Purchase Agreement. OTP used the $35 million proceeds from the issuance to pay for capital expenditures and for other corporate purposes. The Series 2019A Notes, Series 2019B Notes and Series 2019C Notes were issued by OTP on October 10, 2019. The remaining notes to be issued under the 2019 Note Purchase Agreement, Series 2020B Notes, are expected to be issued on August 20, 2020, subject to the satisfaction of certain customary conditions to closing.

On February 27, 2018 OTP issued $100 million aggregate principal amount 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).

~~Table of Contents~~

~~On December 13, 2016~~long-debt agreements require Otter Tail Corporation ~~issued $80 million aggregate principal amount~~and OTP to maintain certain financial covenants. As of its 3.55% Guaranteed Senior Notes due December 15, 2026 (the 2026 Notes) pursuant to a Note Purchase Agreement dated 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,~~March 31, 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 ~~the~~these 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 Total Capitalization. As of March 31, 2021, our Interest-Bearing Debt to Total Capitalization was 0.50 to 1.00, our Interest and Dividend Coverage Ratio was 4.62 to 1.00 and we had no 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 March 31, 2021, OTP's Interest-Bearing Debt to Total Capitalization was 0.47 to 1.00, its Interest and Dividend Coverage Ratio was 3.55 to 1.00 and it had no Priority Indebtedness outstanding.

None of our debt agreements ~~as of June 30, 2020.~~

~~No Credit Agreement or Note Purchase Agreement contains~~include 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 June 30, 2020, our Interest and Dividend Coverage Ratio calculated under the requirements of the OTC Credit Agreement and the 2016 Note Purchase Agreement was 4.39 to 1.00.

OFF-BALANCE-SHEET ARRANGEMENTS

●

~~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 June 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 3.70 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.

As of June 30, 2020, our ratio of Interest-bearing Debt to Total Capitalization was 0.48 to 1.00 on a consolidated basis and 0.47 to 1.00 for OTP. Neither Otter Tail Corporation nor OTP had any Priority Indebtedness outstanding as of June 30, 2020.

~~OFF-BALANCE-SHEET ARRANGEMENTS~~

~~We and our subsidiary companies~~March 31, 2021 we have outstanding letters of credit totaling ~~$12.1~~$16.4 million, ~~but~~a portion of which reduces our ~~line~~borrowing capacity under our lines of ~~credit borrowing limits are only restricted by $7.7 million in~~credit. 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.


ITEM 3.			QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes in ~~critical accounting policies or estimates during the quarter ended June 30, 2020.~~

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.

~~Table of Contents~~

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 ~~discussed~~disclosed in ~~forward-looking statements made by or on behalf of the Company. When used in this Form 10-Q~~Item 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, in Part II, Item 1A~~2020.


ITEM 4.			CONTROLS AND PROCEDURES

Evaluation of ~~our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, and in Part II, Item 1A of this report on Form 10-Q, as well as the various factors described below:~~

●

The economic effects of the COVID-19 outbreak and measures taken to arrest its spread 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.

~~Table of Contents~~

●

~~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.~~

~~Table of Contents~~

~~Item 3.~~ ~~Quantitative and Qualitative~~ Disclosures ~~about Market Risk~~

At June 30, 2020 we had exposure to market risk associated with interest rates because we had $41.2 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 June 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 ~~company~~the Company’s management, including ~~our~~the 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 ~~June 30, 2020,~~March 31, 2021, the end of the period covered by this report. Based on that evaluation, ~~our~~the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of ~~June 30, 2020.~~

~~During the fiscal quarter ended June 30, 2020, there~~March 31, 2021.

Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting (as defined in ~~Rule~~Rules 13a-15(f) under the Exchange Act) during the quarter ended March 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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, “Rate~~Note 9 , Commitments and ~~Regulatory Matters” and note 9, "Commitments and Contingencies"~~Contingencies, to the consolidated financial statements.

~~Item 1A.~~

ITEM 1A.

RISK FACTORS

~~Risk Factors~~

~~Aside from the additional risk factor described below and in Part II, Item 1A of our Quarterly Report on Form 10 Q for the quarter ended March 31, 2020, there has~~There have been no material ~~change in~~changes from the risk factors ~~set forth under Part I,~~disclosed in Item 1A, ~~“Risk Factors” on pages 29 through 39~~Risk Factors, of our Annual Report on Form 10-K for the year ended December 31, ~~2019.~~

2020.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

We do not have a publicly announced stock repurchase program. The ~~economic effects~~following tables presents common shares of the ~~COVID-19 outbreak and measures taken~~Company that were surrendered to ~~arrest its spread could continue~~us by employees to~~adversely impact~~ pay taxes in connection with shares issued for incentive awards in February 2021 under our ~~business, including our results~~2014 Stock Incentive Plan:
Calendar Month Total Number
of Shares Purchased Average Price Paid per Share
January 2021 — $ —
February 2021 35,701 42.21
March 2021 — —
Total 35,701 $ 42.21

The following Exhibits are filed as part of, ~~operations, financial condition and liquidity.~~

~~The outbreak and global spread of COVID-19, which has been declared a pandemic~~or 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 economic recovery. 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 as many of our customers are in businesses impacted by the pandemic and have temporarily closed their plants, and where we have already taken steps to reduce our operations, including furloughing of employees and eliminating positions;

●

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

No.

●

~~reduce customer demand in our Plastics segment;~~

Description

31.1

●

~~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 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 business and the value of our common stock.~~

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.

~~Table of Contents~~

~~Item 6.~~

—~~Exhibits~~

~~31.1~~

Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

~~31.2~~

—Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

~~32.1~~

—Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

~~32.2~~

—Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.SCH

~~101.SCH~~

—Inline XBRL Taxonomy Extension Schema Document.

101.CAL

~~101.CAL~~

—Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.LAB

~~101.LAB~~

—Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE

~~101.PRE~~

—Inline XBRL Taxonomy Extension Presentation Linkbase Document.

101.DEF

~~101.DEF~~

—Inline XBRL Taxonomy Extension Definition Linkbase Document.

104			~~104~~						—Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the ~~Registrant~~registrant 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:~~ ~~August 7, 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: May 7, 2021

5527

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)


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


~~Item 1.~~			~~Financial Statements~~ Description	Page

			Definitions	2
			Forward Looking Information	2
PART I
ITEM 1.			Financial Statements:
			Consolidated Balance Sheets ~~– June 30, 2020 and December 31, 2019 (not audited)~~	~~2 &~~ 3

	Consolidated Statements of Income ~~– Three and Six Months Ended June 30, 2020 and 2019 (not audited)~~	4

	Consolidated Statements of Comprehensive Income ~~– Three and Six Months Ended June 30, 2020 and 2019 (not audited)~~	5

	Consolidated Statements of ~~Common~~ Shareholders’ Equity ~~– Three and Six Months Ended June 30, 2020 and 2019 (not audited)~~	6

	Consolidated Statements of Cash Flows ~~– Six Months Ended June 30, 2020 and 2019 (not audited)~~	7

	Condensed Notes to Consolidated Financial Statements ~~(not audited)~~	~~8-33~~ 8
ITEM 2.
~~Item 2.~~	~~Management's~~Management’s Discussion and Analysis of Financial Condition and Results of Operations	~~34-52~~ 17
ITEM 3.
~~Item 3.~~	Quantitative and Qualitative Disclosures About Market Risk	53 25
ITEM 4.
~~Item 4.~~	Controls and Procedures	53 25
PART II
~~Part II. Other Information~~ITEM 1.

~~Item 1.~~	Legal Proceedings	54 26
ITEM 1A.			Risk Factors	26
~~Item 1A.~~ ITEM 2.			~~Risk Factors~~ Unregistered Sales of Equity Securities and Use of Proceeds	54 26
ITEM 6.			Exhibits	26
~~Item 6.~~ Signatures			~~Exhibits~~	55 27

~~Signatures~~		55

~~OTTER TAIL CORPORATION~~
~~(Exact name of registrant as specified in its charter)~~

(in thousands)	June 30, 2020		December 31, 2019

Assets

Current Assets
Cash and Cash Equivalents	$	39,512	$	21,199
Accounts Receivable:
Trade—Net		84,197		77,947
Other		6,452		8,773
Inventories		89,754		97,851
Unbilled Receivables		19,019		20,911
Income Taxes Receivable		-		1,487
Regulatory Assets		19,958		21,650
Other		8,031		5,042
Total Current Assets		266,923		254,860

Investments		10,581		9,894
Other Assets		40,138		40,196
Goodwill		37,572		37,572
Other Intangibles—Net		10,703		11,290
Regulatory Assets		141,063		144,138

Right of Use Assets - Operating Leases		20,571		21,851

Plant
Electric Plant in Service		2,211,082		2,212,884
Nonelectric Operations		252,933		247,356
Construction Work in Progress		321,621		185,238
Total Gross Plant		2,785,636		2,645,478
Less Accumulated Depreciation and Amortization		923,948		891,684
Net Plant		1,861,688		1,753,794

Total Assets	$	2,389,239	$	2,273,595

(in thousands, except share data)	June 30, 2020			December 31, 2019

Liabilities and Equity

Current Liabilities
Short-Term Debt	$	41,239		$	6,000
Current Maturities of Long-Term Debt		261			183
Accounts Payable		133,967			120,775
Accrued Salaries and Wages		16,891			22,730
Accrued Taxes		12,193			17,525
Regulatory Liabilities		13,023			7,480
Current Operating Lease Liabilities		4,543			4,136
Other Accrued Liabilities		10,806			10,912
Total Current Liabilities		232,923			189,741

Pensions Benefit Liability		86,657			98,970
Other Postretirement Benefits Liability		71,845			71,437
Long-Term Operating Lease Liabilities		16,584			18,193
Other Noncurrent Liabilities		34,647			30,833

Commitments and Contingencies (note 9)

Deferred Credits
Deferred Income Taxes		141,538			131,941
Deferred Tax Credits		17,969			18,626
Regulatory Liabilities		238,160			239,906
Other		2,472			2,885
Total Deferred Credits		400,139			393,358

Capitalization
Long-Term Debt—Net		724,389			689,581

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

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

Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares; Outstanding, 2020—40,848,828 Shares; 2019—40,157,591 Shares		204,244			200,788
Premium on Common Shares		390,141			364,790
Retained Earnings		233,705			222,341
Accumulated Other Comprehensive Loss		(6,035	)		(6,437	)
Total Common Equity		822,055			781,482
Total Capitalization		1,546,444			1,471,063
Total Liabilities and Equity	$	2,389,239		$	2,273,595

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands, except share and per-share amounts)	2020		2019		2020		2019
Operating Revenues
Electric:
Revenues from Contracts with Customers	$	97,921	$	101,861	$	217,878	$	231,006
Changes in Accrued Revenues under Alternative Revenue Programs		209		369		122		(680	)
Total Electric Revenues		98,130		102,230		218,000		230,326
Product Sales from Contracts with Customers		94,626		126,973		209,503		244,849
Total Operating Revenues		192,756		229,203		427,503		475,175
Operating Expenses
Production Fuel – Electric		8,788		8,296		22,523		27,216
Purchased Power – Electric System Use		13,682		19,633		32,512		41,585
Electric Operation and Maintenance Expenses		33,179		39,856		73,794		78,238
Cost of Products Sold (depreciation included below)		73,832		97,996		159,711		188,578
Other Nonelectric Expenses		10,762		13,262		22,662		26,739
Depreciation and Amortization		20,436		19,441		40,835		38,572
Property Taxes – Electric		4,168		3,900		8,268		7,859
Total Operating Expenses		164,847		202,384		360,305		408,787
Operating Income		27,909		26,819		67,198		66,388
Interest Charges		8,662		7,825		16,785		15,651
Nonservice Cost Components of Postretirement Benefits		868		1,075		1,739		2,110
Other Income		2,410		850		2,021		2,094
Income Before Income Taxes		20,789		18,769		50,695		50,721
Income Tax Expense		3,808		3,343		9,446		8,971
Net Income		16,981		15,426		41,249		41,750

Average Number of Common Shares Outstanding – Basic		40,513,286		39,712,036		40,365,214		39,684,679
Average Number of Common Shares Outstanding – Diluted		40,676,761		39,917,831		40,560,549		39,910,499

Basic Earnings Per Common Share	$	0.42	$	0.39	$	1.02	$	1.05

Diluted Earnings Per Common Share	$	0.42	$	0.39	$	1.02	$	1.05

	Six Months Ended June 30,
(in thousands)	2020			2019
Operating Activities
Net Income	$	41,249		$	41,750
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation and Amortization		40,835			38,572
Deferred Tax Credits		(657	)		(674	)
Deferred Income Taxes		9,472			960
Change in Deferred Debits and Other Assets		5,565			3,884
Discretionary Contribution to Pension Plan		(11,200	)		(10,000	)
Change in Noncurrent Liabilities and Deferred Credits		5,178			11,942
Allowance for Equity/Other Funds Used During Construction		(1,858	)		(688	)
Stock Compensation Expense		4,007			3,944
Other—Net		(147	)		276
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables		(3,929	)		(30,478	)
Change in Inventories		8,097			410
Change in Other Current Assets		(1,066	)		2,870
Change in Payables and Other Current Liabilities		(23,562	)		222
Change in Interest and Income Taxes Receivable/Payable		1,917			6,297
Net Cash Provided by Operating Activities		73,901			69,287
Investing Activities
Capital Expenditures		(119,830	)		(54,012	)
Proceeds from Disposal of Noncurrent Assets		3,953			3,405
Cash Used for Investments and Other Assets		(5,128	)		(4,776	)
Net Cash Used in Investing Activities		(121,005	)		(55,383	)
Financing Activities
Change in Checks Written in Excess of Cash		550			(1,120	)
Net Short-Term Borrowings		35,239			18,003
Proceeds from Issuance of Common Stock		27,225			-
Common Stock Issuance Expenses		(374	)		-
Payments for Shares Withheld for Employee Tax Obligations		(2,069	)		(2,730	)
Proceeds from Issuance of Long-Term Debt		35,000			-
Short-Term and Long-Term Debt Issuance Expenses		(179	)		-
Payments for Retirement of Long-Term Debt		(90	)		(84	)
Dividends Paid		(29,885	)		(27,852	)
Net Cash Provided by (Used in) Financing Activities		65,417			(13,783	)
Net Change in Cash and Cash Equivalents		18,313			121
Cash and Cash Equivalents at Beginning of Period		21,199			861
Cash and Cash Equivalents at End of Period	$	39,512		$	982

June 30, 2020 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,450
Corporate Debt Securities – Held by Captive Insurance Company			$	3,062
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				5,960
Other Assets:
Money Market and Mutual Funds –Retirement Plans		1,560
Total Assets	$	3,010	$	9,022

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

	June 30,		December 31,
(in thousands)	2020		2019
Finished Goods	$	26,190	$	31,863
Work in Process		14,418		16,508
Raw Material, Fuel and Supplies		49,146		49,480
Total Inventories	$	89,754	$	97,851

June 30, 2020 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	11,820	$	10,671	82	-	182
Other		179		147		32	2	-	39
Total	$	22,670	$	11,967	$	10,703

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2020		2019		2020		2019
Amortization Expense – Intangible Assets	$	291	$	296	$	587	$	592

	As of June 30,
(in thousands)	2020		2019
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	61,925	$	16,841

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	R –	May 1, 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	R –	May 7, 2020	January 1, 2021	$	10,264		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%	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
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%	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	R –	June 1, 2020	September 1, 2020	$	1,931		7.753%	of base
2019 Initial Request	A –	August 21, 2019	September 1, 2019	$	864		3.345%	of base

	Three Months Ended June 30,						Six Months Ended June 30,
Rate Rider (in thousands)	2020			2019			2020			2019
Minnesota
Renewable Resource Recovery	$	3,088		$	1,317		$	6,342		$	2,633
Conservation Improvement Program Costs and Incentives		1,521			1,841			2,607			2,728
Transmission Cost Recovery		(314	)		(56	)		401			585
Environmental Cost Recovery		-			-			-			(1	)
North Dakota
Transmission Cost Recovery		840			874			2,322			2,646
Renewable Resource Adjustment		1,070			(93	)		2,199			636
Generation Cost Recovery		900			222			1,848			470
Environmental Cost Recovery		-			(12	)		-			563
South Dakota
Transmission Cost Recovery		371			371			933			844
Conservation Improvement Program Costs and Incentives		210			96			554			340
Environmental Cost Recovery		-			(23	)		-			(27	)
Phase-In Rate Plan		(670	)		-			(24	)		-
Total	$	7,016		$	4,537		$	17,182		$	11,417

	June 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	$	124,901		$	133,919		see below
Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment¹		-		8,243			8,243		asset lives
Minnesota Transmission Cost Recovery Rider Accrued Revenues²		6,563		-			6,563		12
Conservation Improvement Program Costs and Incentives²		276		3,553			3,829		27
MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups¹		1,500		963			2,463		30
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery¹		-		1,974			1,974		asset lives
Minnesota Renewable Resource Rider Accrued Revenues²		722		-			722		12
Debt Reacquisition Premiums¹		204		430			634		147
Big Stone II Unrecovered Project Costs – Minnesota¹		583		-			583		10
Minnesota SPP Transmission Cost Recovery Tracker¹		-		401			401		see below
Deferred Marked-to-Market Losses¹		372		-			372		6
Big Stone II Unrecovered Project Costs – South Dakota¹		144		180			324		27
South Dakota Deferred Rate Case Expenses Subject to Recovery¹		138		177			315		28
North Dakota Generation Cost Recovery Rider Accrued Revenue²		312		-			312		12
North Dakota Deferred Rate Case Expenses Subject to Recovery¹		122		183			305		30
Deferred Lease Expenses¹		-		58			58		33
Minnesota Environmental Cost Recovery Rider Accrued Revenues²		4		-			4		12
Total Regulatory Assets	$	19,958	$	141,063		$	161,021
Regulatory Liabilities:
Deferred Income Taxes	$	-	$	138,517		$	138,517		asset lives
Accumulated Reserve for Estimated Removal Costs – Net of Salvage		-		99,055			99,055		asset lives
Refundable Fuel Clause Adjustment Revenues		10,241		-			10,241		12
North Dakota Transmission Cost Recovery Rider Accrued Refund		1,010		-			1,010		6
South Dakota Phase-In Rate Plan Rider Accrued Refund		783		-			783		2
Revenue for Rate Case Expenses Subject to Refund – Minnesota		-		518			518		see below
Prior Service Costs and Actuarial Gains on Postretirement Benefits		471		-			471		12
Minnesota Energy Intensive Trade Exposed Rider Accrued Refund		198		-			198		3
South Dakota Transmission Cost Recovery Rider Accrued Refund		159		-			159		8
North Dakota Renewable Resource Recovery Rider Accrued Refund		156		-			156		9
Other		5		70			75		162
Total Regulatory Liabilities	$	13,023	$	238,160		$	251,183
Net Regulatory Asset/(Liability) Position	$	6,935	$	(97,097	)	$	(90,162	)

	December 31, 2019
(in thousands)	Current		Long-Term			Total			Remaining Recovery/ 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
Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment¹		-		7,772			7,772		asset lives
Minnesota Transmission Cost Recovery Rider Accrued Revenues²		4,208		-			4,208		12
Conservation Improvement Program Costs and Incentives²		4,024		2,844			6,868		21
MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups¹		2,033		968			3,001		24
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery¹		-		1,681			1,681		asset lives
Minnesota Renewable Resource Rider Accrued Revenues²		131		-			131		12
Debt Reacquisition Premiums¹		201		548			749		153
Big Stone II Unrecovered Project Costs – Minnesota¹		715		225			940		16
Minnesota SPP Transmission Cost Recovery Tracker¹		-		202			202		see below
Deferred Marked-to-Market Losses¹		743		-			743		12
Big Stone II 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 Lease Expenses¹		-		54			54		39
Minnesota Environmental Cost Recovery Rider Accrued Revenues²		4		-			4		12
South Dakota Transmission Cost Recovery Rider Accrued Revenues²		97		-			97		2
Total Regulatory Assets	$	21,650	$	144,138		$	165,788
Regulatory Liabilities:
Deferred Income Taxes	$	-	$	141,707		$	141,707		asset lives
Accumulated Reserve for Estimated Removal Costs – Net of Salvage		-		97,726			97,726		asset lives
Refundable Fuel Clause Adjustment Revenues		3,982		-			3,982		12
North Dakota Transmission Cost Recovery Rider Accrued Refund		700		-			700		12
South Dakota Phase-In Rate Plan Rider Accrued Refund		355		-			355		9
Revenue for Rate Case Expenses Subject to Refund – Minnesota		-		401			401		see below
Prior Service Costs and Actuarial Gains on Postretirement Benefits		471		-			471		12
Minnesota Energy Intensive Trade Exposed Rider Accrued Refund		164		-			164		12
North Dakota Renewable Resource Recovery Rider Accrued Refund		1,515		-			1,515		12
North Dakota Generation Cost Recovery Rider Accrued Refund		287		-			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	)

	Three Months ended June 30				Six Months ended June 30
	2020		2019		2020		2019
Weighted Average Common Shares Outstanding – Basic		40,513,286		39,712,036		40,365,214		39,684,679
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		97,401		134,137		111,519		146,148
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		47,331		60,168		55,614		61,783
Shares Expected to be Issued Under the Employee Stock Purchase Plan		15,833		-		15,905		-
Nonvested Restricted Shares		1,637		9,657		10,749		15,790
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		1,273		1,833		1,548		2,099
Total Dilutive Shares		163,475		205,795		195,335		225,820
Weighted Average Common Shares Outstanding – Diluted		40,676,761		39,917,831		40,560,549		39,910,499

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

(in thousands)	Line Limit		In Use on June 30, 2020		Restricted due to Outstanding Letters of Credit		Available on June 30, 2020		Available on December 31, 2019
Otter Tail Corporation Credit Agreement	$	170,000	$	41,239	$	-	$	128,761	$	164,000
OTP Credit Agreement		170,000		-		7,670		162,330		154,524
Total	$	340,000	$	41,239	$	7,670	$	291,091	$	318,524

June 30, 2020 (in thousands)	OTP		Otter Tail Corporation		Consolidated
Short-Term Debt	$	-	$	41,239	$	41,239
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 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				261		261
Total	$	647,000	$	80,261	$	727,261
Less: Current Maturities net of Unamortized Debt Issuance Costs		-		261		261
Unamortized Long-Term Debt Issuance Costs		2,281		330		2,611
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	644,719	$	79,670	$	724,389
Total Short-Term and Long-Term Debt (with current maturities)	$	644,719	$	121,170	$	765,889
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

Intersegment Eliminations (in thousands)	June 30, 2020		June 30, 2019
Operating Revenues:
Electric	$	23	$	14
Nonelectric		1		(1	)
Costs of Products Sold		2		3
Other Nonelectric Expenses		22		10

		2020 vs Normal				2019 vs Normal				2020 vs 2019
Effect on Diluted Earnings Per Share		$	0.03			$	0.01			$	0.02

(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	%

		2019 EPS by		2020 Guidance February 20, 2020						2020 Guidance May 5, 2020						2020 Guidance August 3, 2020
Diluted Earnings Per Share		Segment		Low			High			Low			High			Low			High
Electric	$	1.48		$	1.67		$	1.70		$	1.65		$	1.70		$	1.67		$	1.70
Manufacturing	$	0.32		$	0.31		$	0.35		$	0.14		$	0.23		$	0.15		$	0.23
Plastics	$	0.51		$	0.43		$	0.47		$	0.43		$	0.47		$	0.50		$	0.54
Corporate	$	(0.14	)	$	(0.19	)	$	(0.15	)	$	(0.22	)	$	(0.15	)	$	(0.22	)	$	(0.17	)
Total	$	2.17		$	2.22		$	2.37		$	2.00		$	2.25		$	2.10		$	2.30
Return on Equity		11.6	%		11.0	%		11.7	%		9.9	%		11.1	%		10.4	%		11.4	%


Calendar Month	Total Number of Shares Purchased	Average Price Paid per Share

January 2021	—	$	—
February 2021	35,701	42.21
March 2021	—	—
Total	35,701	$	42.21