| (in thousands, except share data) | September 30, 2021 | December 31, 2020 | |||||||||
| Assets | |||||||||||
| Current Assets | |||||||||||
| Cash and Cash Equivalents | $ | 1,272 | $ | 1,163 | |||||||
| Receivables, net of allowance for credit losses | 178,759 | 113,959 | |||||||||
| Inventories | 114,615 | 92,165 | |||||||||
| Regulatory Assets | 22,517 | 21,900 | |||||||||
| Other Current Assets | 17,804 | 5,645 | |||||||||
| Total Current Assets | 334,967 | 234,832 | |||||||||
| Noncurrent Assets | |||||||||||
| Investments | 55,456 | 51,856 | |||||||||
| Property, Plant and Equipment, net of accumulated depreciation | 2,083,223 | 2,049,273 | |||||||||
| Regulatory Assets | 158,515 | 168,395 | |||||||||
| Intangible Assets, net of accumulated amortization | 9,319 | 10,144 | |||||||||
| Goodwill | 37,572 | 37,572 | |||||||||
| Other Noncurrent Assets | 34,096 | 26,282 | |||||||||
| Total Noncurrent Assets | 2,378,181 | 2,343,522 | |||||||||
| Total Assets | $ | 2,713,148 | $ | 2,578,354 | |||||||
| Liabilities and Shareholders' Equity | |||||||||||
| Current Liabilities | |||||||||||
| Short-Term Debt | $ | 97,857 | $ | 80,997 | |||||||
| Current Maturities of Long-Term Debt | 169,962 | 140,087 | |||||||||
| Accounts Payable | 135,437 | 130,805 | |||||||||
| Accrued Salaries and Wages | 28,455 | 26,908 | |||||||||
| Accrued Taxes | 17,972 | 18,831 | |||||||||
| Regulatory Liabilities | 25,323 | 16,663 | |||||||||
| Other Current Liabilities | 35,081 | 22,495 | |||||||||
| Total Current Liabilities | 510,087 | 436,786 | |||||||||
| Noncurrent Liabilities and Deferred Credits | |||||||||||
| Pensions Benefit Liability | 101,446 | 114,055 | |||||||||
| Other Postretirement Benefits Liability | 68,090 | 67,359 | |||||||||
| Regulatory Liabilities | 230,733 | 233,973 | |||||||||
| Deferred Income Taxes | 176,502 | 153,376 | |||||||||
| Deferred Tax Credits | 16,847 | 17,405 | |||||||||
| Other Noncurrent Liabilities | 62,342 | 60,002 | |||||||||
| Total Noncurrent Liabilities and Deferred Credits | 655,960 | 646,170 | |||||||||
| 0 | 0 | ||||||||||
| Capitalization | |||||||||||
| Long-Term Debt, net of current maturities | 594,619 | 624,432 | |||||||||
| Shareholders' Equity | |||||||||||
Common Shares: 50,000,000 shares authorized of $5 par value; 41,539,984 and 41,469,879 outstanding at September 30, 2021 and December 31, 2020 | 207,700 | 207,349 | |||||||||
| Additional Paid-In Capital | 418,568 | 414,246 | |||||||||
| Retained Earnings | 334,385 | 257,878 | |||||||||
| Accumulated Other Comprehensive Loss | (8,171) | (8,507) | |||||||||
| Total Shareholders' Equity | 952,482 | 870,966 | |||||||||
| Total Capitalization | 1,547,101 | 1,495,398 | |||||||||
| Total Liabilities and Shareholders' Equity | $ | 2,713,148 | $ | 2,578,354 | |||||||
| ||
| ||
|
(in thousands, except share data) | September 30, 2020 | December 31, 2019 | ||||||
Liabilities and Equity | ||||||||
Current Liabilities | ||||||||
Short-Term Debt | $ | 48,600 | $ | 6,000 | ||||
Current Maturities of Long-Term Debt | 215 | 183 | ||||||
Accounts Payable | 189,327 | 120,775 | ||||||
Accrued Salaries and Wages | 20,933 | 22,730 | ||||||
Accrued Taxes | 14,283 | 17,525 | ||||||
Regulatory Liabilities | 12,870 | 7,480 | ||||||
Current Operating Lease Liabilities | 4,581 | 4,136 | ||||||
Other Accrued Liabilities | 8,927 | 10,912 | ||||||
Total Current Liabilities | 299,736 | 189,741 | ||||||
Pensions Benefit Liability | 86,101 | 98,970 | ||||||
Other Postretirement Benefits Liability | 72,508 | 71,437 | ||||||
Long-Term Operating Lease Liabilities | 15,778 | 18,193 | ||||||
Other Noncurrent Liabilities | 35,146 | 30,833 | ||||||
Commitments and Contingencies (note 9) | ||||||||
Deferred Credits | ||||||||
Deferred Income Taxes | 152,448 | 131,941 | ||||||
Deferred Tax Credits | 17,640 | 18,626 | ||||||
Regulatory Liabilities | 236,892 | 239,906 | ||||||
Other | 1,914 | 2,885 | ||||||
Total Deferred Credits | 408,894 | 393,358 | ||||||
Capitalization | ||||||||
Long-Term Debt—Net | 764,274 | 689,581 | ||||||
Cumulative Preferred Shares – Authorized 1,500,000 Shares Without Par Value; Outstanding – None | 0 | 0 | ||||||
Cumulative Preference Shares – Authorized 1,000,000 Shares Without Par Value; Outstanding – None | 0 | 0 | ||||||
Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares; Outstanding, 2020—41,052,165 Shares; 2019—40,157,591 Shares | 205,261 | 200,788 | ||||||
Premium on Common Shares | 398,301 | 364,790 | ||||||
Retained Earnings | 254,468 | 222,341 | ||||||
Accumulated Other Comprehensive Loss | (5,960 | ) | (6,437 | ) | ||||
Total Common Equity | 852,070 | 781,482 | ||||||
Total Capitalization | 1,616,344 | 1,471,063 | ||||||
Total Liabilities and Equity | $ | 2,534,507 | $ | 2,273,595 | ||||
|
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (in thousands, except per-share amounts) | 2021 | 2020 | 2021 | 2020 | |||||||||||||||||||
| Operating Revenues | |||||||||||||||||||||||
| Electric | $ | 118,775 | $ | 115,213 | $ | 348,629 | $ | 333,213 | |||||||||||||||
| Product Sales | 197,519 | 120,542 | 514,983 | 330,045 | |||||||||||||||||||
| Total Operating Revenues | 316,294 | 235,755 | 863,612 | 663,258 | |||||||||||||||||||
| Operating Expenses | |||||||||||||||||||||||
| Electric Production Fuel | 17,698 | 11,554 | 44,576 | 34,077 | |||||||||||||||||||
| Electric Purchased Power | 9,878 | 13,428 | 40,273 | 45,940 | |||||||||||||||||||
| Electric Operating and Maintenance Expenses | 36,465 | 32,845 | 114,615 | 106,639 | |||||||||||||||||||
| Cost of Products Sold (excluding depreciation) | 134,212 | 86,856 | 358,767 | 246,567 | |||||||||||||||||||
| Other Nonelectric Expenses | 16,224 | 13,615 | 45,587 | 36,277 | |||||||||||||||||||
| Depreciation and Amortization | 22,815 | 20,395 | 68,109 | 61,230 | |||||||||||||||||||
| Electric Property Taxes | 4,474 | 4,333 | 13,136 | 12,601 | |||||||||||||||||||
| Total Operating Expenses | 241,766 | 183,026 | 685,063 | 543,331 | |||||||||||||||||||
| Operating Income | 74,528 | 52,729 | 178,549 | 119,927 | |||||||||||||||||||
| Other Income and Expense | |||||||||||||||||||||||
| Interest Charges | 9,648 | 8,568 | 28,601 | 25,353 | |||||||||||||||||||
| Nonservice Cost Components of Postretirement Benefits | 505 | 842 | 1,511 | 2,581 | |||||||||||||||||||
| Other Income (Expense), net | 203 | 1,712 | 2,095 | 3,733 | |||||||||||||||||||
| Income Before Income Taxes | 64,578 | 45,031 | 150,532 | 95,726 | |||||||||||||||||||
| Income Tax Expense | 11,824 | 9,097 | 25,380 | 18,543 | |||||||||||||||||||
| Net Income | $ | 52,754 | $ | 35,934 | $ | 125,152 | $ | 77,183 | |||||||||||||||
| Weighted-Average Common Shares Outstanding: | |||||||||||||||||||||||
| Basic | 41,504 | 40,914 | 41,487 | 40,548 | |||||||||||||||||||
| Diluted | 41,869 | 41,078 | 41,795 | 40,733 | |||||||||||||||||||
| Earnings Per Share: | |||||||||||||||||||||||
| Basic | $ | 1.27 | $ | 0.88 | $ | 3.02 | $ | 1.90 | |||||||||||||||
| Diluted | $ | 1.26 | $ | 0.87 | $ | 2.99 | $ | 1.89 | |||||||||||||||
| ||||
|
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
(in thousands, except share and per-share amounts) | 2020 | 2019 | 2020 | 2019 | ||||||||||||
Operating Revenues | ||||||||||||||||
Electric: | ||||||||||||||||
Revenues from Contracts with Customers | $ | 112,435 | $ | 115,285 | $ | 330,313 | $ | 346,291 | ||||||||
Changes in Accrued Revenues under Alternative Revenue Programs | 2,778 | (921 | ) | 2,900 | (1,601 | ) | ||||||||||
Total Electric Revenues | 115,213 | 114,364 | 333,213 | 344,690 | ||||||||||||
Product Sales from Contracts with Customers | 120,542 | 114,288 | 330,045 | 359,137 | ||||||||||||
Total Operating Revenues | 235,755 | 228,652 | 663,258 | 703,827 | ||||||||||||
Operating Expenses | ||||||||||||||||
Production Fuel – Electric | 11,554 | 18,331 | 34,077 | 45,547 | ||||||||||||
Purchased Power – Electric System Use | 13,428 | 13,163 | 45,940 | 54,748 | ||||||||||||
Electric Operation and Maintenance Expenses | 32,845 | 35,869 | 106,639 | 114,107 | ||||||||||||
Cost of Products Sold (depreciation included below) | 86,856 | 88,747 | 246,567 | 277,325 | ||||||||||||
Other Nonelectric Expenses | 13,615 | 11,665 | 36,277 | 38,404 | ||||||||||||
Depreciation and Amortization | 20,395 | 19,657 | 61,230 | 58,229 | ||||||||||||
Property Taxes – Electric | 4,333 | 3,965 | 12,601 | 11,824 | ||||||||||||
Total Operating Expenses | 183,026 | 191,397 | 543,331 | 600,184 | ||||||||||||
Operating Income | 52,729 | 37,255 | 119,927 | 103,643 | ||||||||||||
Interest Charges | 8,568 | 7,539 | 25,353 | 23,190 | ||||||||||||
Nonservice Cost Components of Postretirement Benefits | 842 | 1,055 | 2,581 | 3,165 | ||||||||||||
Other Income | 1,712 | 1,020 | 3,733 | 3,114 | ||||||||||||
Income Before Income Taxes | 45,031 | 29,681 | 95,726 | 80,402 | ||||||||||||
Income Tax Expense | 9,097 | 4,936 | 18,543 | 13,907 | ||||||||||||
Net Income | 35,934 | $ | 24,745 | 77,183 | $ | 66,495 | ||||||||||
Average Number of Common Shares Outstanding – Basic | 40,913,972 | 39,714,672 | 40,548,133 | 39,694,677 | ||||||||||||
Average Number of Common Shares Outstanding – Diluted | 41,077,689 | 39,946,739 | 40,732,928 | 39,922,580 | ||||||||||||
Basic Earnings Per Common Share | $ | 0.88 | $ | 0.62 | $ | 1.90 | $ | 1.68 | ||||||||
Diluted Earnings Per Common Share | $ | 0.87 | $ | 0.62 | $ | 1.89 | $ | 1.67 | ||||||||
|
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (in thousands) | 2021 | 2020 | 2021 | 2020 | |||||||||||||||||||
| Net Income | $ | 52,754 | $ | 35,934 | $ | 125,152 | $ | 77,183 | |||||||||||||||
| Other Comprehensive Income (Loss): | |||||||||||||||||||||||
| Unrealized Gain (Loss) on Available-for-Sale Securities: | |||||||||||||||||||||||
| Reversal of Previously Recognized Losses (Gains) Realized on Sale of Investments and Included in Other Income (Expense) | — | (21) | (43) | 13 | |||||||||||||||||||
| Unrealized Gains (Losses) | (33) | (13) | (85) | 205 | |||||||||||||||||||
| Income Tax (Expense) Benefit | 7 | 7 | 27 | (46) | |||||||||||||||||||
| Available-for-Sale Securities, net of tax | (26) | (27) | (101) | 172 | |||||||||||||||||||
| Pension and Postretirement Benefit Plans: | |||||||||||||||||||||||
| Amortization of Unrecognized Postretirement Benefit Losses and Costs | 197 | 138 | 591 | 413 | |||||||||||||||||||
| Income Tax Expense | (51) | (36) | (154) | (108) | |||||||||||||||||||
| Pension and Postretirement Benefit Plan, net of tax | 146 | 102 | 437 | 305 | |||||||||||||||||||
Total Other Comprehensive Income | 120 | 75 | 336 | 477 | |||||||||||||||||||
| Total Comprehensive Income | $ | 52,874 | $ | 36,009 | $ | 125,488 | $ | 77,660 | |||||||||||||||
| ||||
|
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
(in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||
Net Income | $ | 35,934 | $ | 24,745 | $ | 77,183 | $ | 66,495 | ||||||||
Other Comprehensive Income: | ||||||||||||||||
Unrealized Gains on Available-for-Sale Securities: | ||||||||||||||||
Reversal of Previously Recognized (Gains) Losses Realized on Sale of Investments and Included in Other Income During Period | (21 | ) | (1 | ) | 13 | (5 | ) | |||||||||
Unrealized (Losses) Gains Arising During Period | (13 | ) | 30 | 205 | 187 | |||||||||||
Income Tax Savings (Expense) | 7 | (6 | ) | (46 | ) | (38 | ) | |||||||||
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax | (27 | ) | 23 | 172 | 144 | |||||||||||
Pension and Postretirement Benefit Plans: | ||||||||||||||||
Amortization of Unrecognized Postretirement Benefit Lossesand Costs (note 11) | 138 | 130 | 413 | 389 | ||||||||||||
Income Tax Expense | (36 | ) | (34 | ) | (108 | ) | (101 | ) | ||||||||
Pension and Postretirement Benefit Plans – net-of-tax | 102 | 96 | 305 | 288 | ||||||||||||
Total Other Comprehensive Income | 75 | 119 | 477 | 432 | ||||||||||||
Total Comprehensive Income | $ | 36,009 | $ | 24,864 | $ | 77,660 | $ | 66,927 | ||||||||
|
| (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, June 30, 2021 | 41,538,709 | $ | 207,694 | $ | 417,870 | $ | 297,850 | $ | (8,291) | $ | 915,123 | ||||||||||||||||||||||||
| Common Stock Issuances, Net of Expenses | 1,275 | 6 | (6) | — | — | — | |||||||||||||||||||||||||||||
| Common Stock Retirements and Forfeitures | — | — | (126) | — | — | (126) | |||||||||||||||||||||||||||||
| Net Income | — | — | — | 52,754 | — | 52,754 | |||||||||||||||||||||||||||||
| Other Comprehensive Income | — | — | — | — | 120 | 120 | |||||||||||||||||||||||||||||
| Stock Compensation Expense | — | — | 830 | — | — | 830 | |||||||||||||||||||||||||||||
| Common Dividends ($0.39 per share) | — | — | — | (16,219) | — | (16,219) | |||||||||||||||||||||||||||||
| Balance, September 30, 2021 | 41,539,984 | $ | 207,700 | $ | 418,568 | $ | 334,385 | $ | (8,171) | $ | 952,482 | ||||||||||||||||||||||||
| Balance, June 30, 2020 | 40,848,828 | $ | 204,244 | $ | 390,141 | $ | 233,705 | $ | (6,035) | $ | 822,055 | ||||||||||||||||||||||||
| Common Stock Issuances, Net of Expenses | 203,337 | 1,017 | 6,885 | — | — | 7,902 | |||||||||||||||||||||||||||||
| Net Income | — | — | — | 35,934 | — | 35,934 | |||||||||||||||||||||||||||||
| Other Comprehensive Income | — | — | — | — | 75 | 75 | |||||||||||||||||||||||||||||
| Stock Compensation Expense | — | — | 1,275 | — | — | 1,275 | |||||||||||||||||||||||||||||
| Common Dividends ($0.37 per share) | — | — | — | (15,171) | — | (15,171) | |||||||||||||||||||||||||||||
| Balance, September 30, 2020 | 41,052,165 | $ | 205,261 | $ | 398,301 | $ | 254,468 | $ | (5,960) | $ | 852,070 | ||||||||||||||||||||||||
| Balance, December 31, 2020 | 41,469,879 | $ | 207,349 | $ | 414,246 | $ | 257,878 | $ | (8,507) | $ | 870,966 | ||||||||||||||||||||||||
| Common Stock Issuances, Net of Expenses | 105,806 | 530 | (578) | — | — | (48) | |||||||||||||||||||||||||||||
| Common Stock Retirements and Forfeitures | (35,701) | (179) | (1,454) | — | — | (1,633) | |||||||||||||||||||||||||||||
| Net Income | — | — | — | 125,152 | — | 125,152 | |||||||||||||||||||||||||||||
| Other Comprehensive Income | — | — | — | — | 336 | 336 | |||||||||||||||||||||||||||||
| Stock Compensation Expense | — | — | 6,354 | — | — | 6,354 | |||||||||||||||||||||||||||||
| Common Dividends ($1.17 per share) | — | — | — | (48,645) | — | (48,645) | |||||||||||||||||||||||||||||
| Balance, September 30, 2021 | 41,539,984 | $ | 207,700 | $ | 418,568 | $ | 334,385 | $ | (8,171) | $ | 952,482 | ||||||||||||||||||||||||
| Balance, December 31, 2019 | 40,157,591 | $ | 200,788 | $ | 364,790 | $ | 222,341 | $ | (6,437) | $ | 781,482 | ||||||||||||||||||||||||
| Common Stock Issuances, Net of Expenses | 932,791 | 4,664 | 30,107 | — | — | 34,771 | |||||||||||||||||||||||||||||
| Common Stock Retirements and Forfeitures | (38,217) | (191) | (1,878) | — | — | (2,069) | |||||||||||||||||||||||||||||
| Net Income | — | — | — | 77,183 | — | 77,183 | |||||||||||||||||||||||||||||
| Other Comprehensive Income | — | — | — | — | 477 | 477 | |||||||||||||||||||||||||||||
| Stock Compensation Expense | — | — | 5,282 | — | — | 5,282 | |||||||||||||||||||||||||||||
| Common Dividends ($1.11 per share) | — | — | — | (45,056) | — | (45,056) | |||||||||||||||||||||||||||||
| Balance, September 30, 2020 | 41,052,165 | $ | 205,261 | $ | 398,301 | $ | 254,468 | $ | (5,960) | $ | 852,070 | ||||||||||||||||||||||||
|
|
|
(in thousands, except common shares outstanding) | Common Shares Outstanding | Par Value, Common Shares | Premium on Common Shares | Retained Earnings | Accumulated Other Comprehensive Income/(Loss) | Total Common Equity | ||||||||||||||||||
Balance, June 30, 2020 | 40,848,828 | $ | 204,244 | $ | 390,141 | $ | 233,705 | $ | (6,035 | ) | $ | 822,055 | ||||||||||||
Common Stock Issuances, Net of Expenses | 203,337 | 1,017 | 6,885 | 7,902 | ||||||||||||||||||||
Net Income | 35,934 | 35,934 | ||||||||||||||||||||||
Other Comprehensive Income | 75 | 75 | ||||||||||||||||||||||
Employee Stock Incentive Plan Expense | 1,275 | 1,275 | ||||||||||||||||||||||
Common Dividends ($0.37 per share) | (15,171 | ) | (15,171 | ) | ||||||||||||||||||||
Balance, September 30, 2020 | 41,052,165 | $ | 205,261 | $ | 398,301 | $ | 254,468 | $ | (5,960 | ) | $ | 852,070 | ||||||||||||
Balance, June 30, 2019 | 39,754,902 | $ | 198,775 | $ | 345,030 | $ | 205,115 | $ | (4,615 | ) | $ | 744,305 | ||||||||||||
Common Stock Issuances, Net of Expenses | 375 | 1 | (37 | ) | (36 | ) | ||||||||||||||||||
Net Income | 24,745 | 24,745 | ||||||||||||||||||||||
Other Comprehensive Income | 119 | 119 | ||||||||||||||||||||||
Employee Stock Incentive Plan Expense | 1,301 | 1,301 | ||||||||||||||||||||||
Common Dividends ($0.35 per share) | (13,929 | ) | (13,929 | ) | ||||||||||||||||||||
Balance, September 30, 2019 | 39,755,277 | $ | 198,776 | $ | 346,294 | $ | 215,931 | $ | (4,496 | ) | $ | 756,505 | ||||||||||||
Balance, December 31, 2019 | 40,157,591 | $ | 200,788 | $ | 364,790 | $ | 222,341 | $ | (6,437 | ) | $ | 781,482 | ||||||||||||
Common Stock Issuances, Net of Expenses | 932,791 | 4,664 | 30,107 | 34,771 | ||||||||||||||||||||
Common Stock Retirements | (38,217 | ) | (191 | ) | (1,878 | ) | (2,069 | ) | ||||||||||||||||
Net Income | 77,183 | 77,183 | ||||||||||||||||||||||
Other Comprehensive Income | 477 | 477 | ||||||||||||||||||||||
Employee Stock Incentive Plan Expense | 5,282 | 5,282 | ||||||||||||||||||||||
Common Dividends ($1.11 per share) | (45,056 | ) | (45,056 | ) | ||||||||||||||||||||
Balance, September 30, 2020 | 41,052,165 | $ | 205,261 | $ | 398,301 | $ | 254,468 | $ | (5,960 | ) | $ | 852,070 | ||||||||||||
Balance, December 31, 2018 | 39,664,884 | $ | 198,324 | $ | 344,250 | $ | 190,433 | $ | (4,144 | ) | $ | 728,863 | ||||||||||||
Common Stock Issuances, Net of Expenses | 145,617 | 728 | (747 | ) | (19 | ) | ||||||||||||||||||
Common Stock Retirements | (55,224 | ) | (276 | ) | (2,454 | ) | (2,730 | ) | ||||||||||||||||
Net Income | 66,495 | 66,495 | ||||||||||||||||||||||
Other Comprehensive Income | 432 | 432 | ||||||||||||||||||||||
ASU 2018-02 2017 TCJA Stranded Tax Transfer | 784 | (784 | ) | - | ||||||||||||||||||||
Employee Stock Incentive Plan Expense | 5,245 | 5,245 | ||||||||||||||||||||||
Common Dividends ($1.05 per share) | (41,781 | ) | (41,781 | ) | ||||||||||||||||||||
Balance, September 30, 2019 | 39,755,277 | $ | 198,776 | $ | 346,294 | $ | 215,931 | $ | (4,496 | ) | $ | 756,505 | ||||||||||||
1Accumulated Other Comprehensive Income (Loss) as of September 30, 2021 and December 31, 2020 is comprised of the following: | |||||||||||
| (in thousands) | September 30, 2021 | December 31, 2020 | |||||||||
| Unrealized Gain on Available-for-Sale Debt Securities: | |||||||||||
| Before Tax | $ | 137 | $ | 265 | |||||||
| Tax Effect | (29) | (56) | |||||||||
| Unrealized Gain on Available-for-Sale Debt, net of tax | 108 | 209 | |||||||||
| Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits: | |||||||||||
| Before Tax | (11,202) | (11,793) | |||||||||
| Tax Effect | 2,923 | 3,077 | |||||||||
| Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits, net of tax | (8,279) | (8,716) | |||||||||
| Accumulated Other Comprehensive Loss: | |||||||||||
| Before Tax | (11,065) | (11,528) | |||||||||
| Tax Effect | 2,894 | 3,021 | |||||||||
| Net Accumulated Other Comprehensive Loss | $ | (8,171) | $ | (8,507) | |||||||
| ||
|
Nine Months Ended September 30, | ||||||||
(in thousands) | 2020 | 2019 | ||||||
Operating Activities | ||||||||
Net Income | $ | 77,183 | $ | 66,495 | ||||
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: | ||||||||
Depreciation and Amortization | 61,230 | 58,229 | ||||||
Deferred Tax Credits | (986 | ) | (1,011 | ) | ||||
Deferred Income Taxes | 20,353 | 3,487 | ||||||
Change in Deferred Debits and Other Assets | 3,439 | 7,142 | ||||||
Discretionary Contribution to Pension Plan | (11,200 | ) | (22,500 | ) | ||||
Change in Noncurrent Liabilities and Deferred Credits | 3,237 | 10,344 | ||||||
Allowance for Equity/Other Funds Used During Construction | (3,104 | ) | (1,602 | ) | ||||
Stock Compensation Expense | 5,282 | 5,245 | ||||||
Other—Net | (176 | ) | 312 | |||||
Cash (Used for) Provided by Current Assets and Current Liabilities: | ||||||||
Change in Receivables | (20,025 | ) | (16,213 | ) | ||||
Change in Inventories | 15,980 | 9,218 | ||||||
Change in Other Current Assets | 2,023 | 2,974 | ||||||
Change in Payables and Other Current Liabilities | (12,063 | ) | (20,744 | ) | ||||
Change in Interest and Income Taxes Receivable/Payable | 103 | 3,773 | ||||||
Net Cash Provided by Operating Activities | 141,276 | 105,149 | ||||||
Investing Activities | ||||||||
Capital Expenditures | (220,630 | ) | (149,695 | ) | ||||
Proceeds from Disposal of Noncurrent Assets | 4,617 | 4,111 | ||||||
Cash Used for Investments and Other Assets | (6,372 | ) | (5,546 | ) | ||||
Net Cash Used in Investing Activities | (222,385 | ) | (151,130 | ) | ||||
Financing Activities | ||||||||
Change in Checks Written in Excess of Cash | 90 | 383 | ||||||
Net Short-Term Borrowings | 42,600 | 90,398 | ||||||
Proceeds from Issuance of Common Stock | 35,219 | 0 | ||||||
Common Stock Issuance Expenses | (465 | ) | (35 | ) | ||||
Payments for Shares Withheld for Employee Tax Obligations | (2,069 | ) | (2,730 | ) | ||||
Proceeds from Issuance of Long-Term Debt | 75,000 | 0 | ||||||
Short-Term and Long-Term Debt Issuance Expenses | (369 | ) | (66 | ) | ||||
Payments for Retirement of Long-Term Debt | (136 | ) | (128 | ) | ||||
Dividends Paid | (45,056 | ) | (41,781 | ) | ||||
Net Cash Provided by Financing Activities | 104,814 | 46,041 | ||||||
Net Change in Cash and Cash Equivalents | 23,705 | 60 | ||||||
Cash and Cash Equivalents at Beginning of Period | 21,199 | 861 | ||||||
Cash and Cash Equivalents at End of Period | $ | 44,904 | $ | 921 | ||||
|
| Nine Months Ended September 30, | |||||||||||
| (in thousands) | 2021 | 2020 | |||||||||
| Operating Activities | |||||||||||
| Net Income | $ | 125,152 | $ | 77,183 | |||||||
| Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: | |||||||||||
| Depreciation and Amortization | 68,109 | 61,230 | |||||||||
| Deferred Tax Credits | (558) | (986) | |||||||||
| Deferred Income Taxes | 18,835 | 20,353 | |||||||||
| Change in Deferred Debits and Other Assets | 6,166 | 3,439 | |||||||||
| Discretionary Contribution to Pension Plan | (10,000) | (11,200) | |||||||||
| Change in Noncurrent Liabilities and Deferred Credits | 2,662 | 3,237 | |||||||||
| Allowance for Equity Funds Used During Construction | (427) | (3,104) | |||||||||
| Stock Compensation Expense | 6,354 | 5,282 | |||||||||
| Other, Net | (3,480) | (176) | |||||||||
| Cash (Used for) Provided by Current Assets and Current Liabilities: | |||||||||||
| Change in Receivables | (64,800) | (20,025) | |||||||||
| Change in Inventories | (22,450) | 15,980 | |||||||||
| Change in Other Current Assets | (12,159) | 2,023 | |||||||||
| Change in Payables and Other Current Liabilities | 40,574 | (12,063) | |||||||||
| Change in Interest Payable and Income Taxes Receivable/Payable | 774 | 103 | |||||||||
| Net Cash Provided by Operating Activities | 154,752 | 141,276 | |||||||||
| Investing Activities | |||||||||||
| Capital Expenditures | (117,312) | (220,630) | |||||||||
| Proceeds from Disposal of Noncurrent Assets | 5,819 | 4,617 | |||||||||
| Cash Used for Investments and Other Assets | (5,591) | (6,372) | |||||||||
| Net Cash Used in Investing Activities | (117,084) | (222,385) | |||||||||
| Financing Activities | |||||||||||
| Change in Checks Written in Excess of Cash | (3,133) | 90 | |||||||||
| Net Short-Term Borrowings | 16,860 | 42,600 | |||||||||
| Proceeds from Issuance of Common Stock | — | 35,219 | |||||||||
| Common Stock Issuance Expenses | (67) | (465) | |||||||||
| Payments for Shares Withheld for Employee Tax Obligations | (1,633) | (2,069) | |||||||||
| Proceeds from Issuance of Long-Term Debt | — | 75,000 | |||||||||
| Debt Issuance Expenses | (772) | (369) | |||||||||
| Payments for Retirement of Long-Term Debt | (169) | (136) | |||||||||
| Dividends Paid | (48,645) | (45,056) | |||||||||
Net Cash (Used in) Provided by Financing Activities | (37,559) | 104,814 | |||||||||
| Net Change in Cash and Cash Equivalents | 109 | 23,705 | |||||||||
| Cash and Cash Equivalents at Beginning of Period | 1,163 | 21,199 | |||||||||
| Cash and Cash Equivalents at End of Period | $ | 1,272 | $ | 44,904 | |||||||
| Supplemental Disclosure of Noncash Investing Activities | |||||||||||
| Accrued Property, Plant, and Equipment Additions | $ | 14,358 | $ | 112,314 | |||||||
include all the information and footnotes required by generally accepted accounting principles. In the opinion of management, September 30, 2020 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company Corporate Debt Securities – Held by Captive Insurance Company Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company Other Assets: Money Market and Mutual Funds –Retirement Plans Total Assets December 31, 2019 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company Corporate Debt Securities – Held by Captive Insurance Company Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company Other Assets: Money Market and Mutual Funds –Retirement Plans Total Assets September 30, December 31, (in thousands) 2020 2019 Finished Goods Work in Process Raw Material, Fuel and Supplies Total Inventories September 30, 2020 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships Other Total December 31, 2019 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships Other Total Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2020 2019 2020 2019 Amortization Expense – Intangible Assets (in thousands) 2020 2021 2022 2023 2024 Estimated Amortization Expense – Intangible Assets As of September 30, (in thousands) 2020 2019 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2020 2019 2020 2019 Beginning Balance Additions Charged to Expense (net of recoveries) Reductions for Amounts Written Off Ending Balance
(audited)Otter Tail Corporation (the Company) haswe have included all adjustments, (includingincluding normal recurring accruals)accruals, necessary for a fair presentation of the consolidated financial statements for the periods presented. The consolidated financial statements and condensed notes thereto should be read in conjunction with the consolidated financial statements and notes included in the Company'sour Annual Report on 2019. 2020.20202021 should not be taken as an indication of earnings for all or any part of the balance of the year.1. Summarycurrent year or as an indication of Significant Accounting PoliciesRevenue RecognitionDue to the diverse business operationsearnings for future years.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 recognizedEstimatesmetered quantity of electricity deliveredbest information available in recording transactions and balances resulting from business operations. As better information becomes available, or transmitted atactual amounts are known, the applicable rates. For electricity delivered and consumed after a meter is read but prior to the end of the reporting period, OTP records revenue and an unbilled receivable based onrecorded estimates of the kilowatt-hours (kwh) of energy delivered to the customer.ARPs provide for adjustments to rates outside of a general rate case proceeding, usually as a surcharge applied to future billings typically through the use of rate riders subject to periodic adjustments, to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. ARP riders generally provide for the recovery of specified costs and investments and include an incentive component to provide the regulated utility with a return on amounts invested.OTP has recovered costs and earned incentives or returns on investments subject to recovery under several ARP rate riders, including:●In Minnesota: Transmission Cost Recovery (TCR), Environmental Cost Recovery (ECR), Renewable Resource Adjustment (RRA), Energy Intensive Trade Exposed and Conservation Improvement Program (CIP) riders.●In North Dakota: TCR, ECR, Renewable Resource Cost Recovery and Generation Cost Recovery (GCR) riders.●In South Dakota: TCR, ECR, Phase-In Rate Plan and Energy Efficiency Plan (conservation) riders.8OTP accrues ARP revenue based on costs incurred, investments made and returns on those investments that qualify for recovery through established riders. Amounts billed under riders in effect at the time of the billing are included in revenues from contracts with customers net of amounts billed that are subject to refund through future rider adjustments. Amounts accrued and subject to recovery through future rider rate updates and adjustments are reported as changes in accrued revenues under ARPs on a separate line in the revenue section of the Company’s consolidated statement of income. See table in note 3 for total revenues billed and accrued under ARP riders for the three- and nine-month periods ended September 30, 2020 and 2019.Manufacturing Segment Revenues—Companies in the Manufacturing segment, BTD Manufacturing, Inc. (BTD) and T.O. Plastics, Inc. (T.O. Plastics), earn revenue predominantly from the production and delivery of custom-made or standardized parts to customers across several industries. BTD also earns revenue from the production and sale of tools and dies to other manufacturers. For the production and delivery of standardized products and other products made to customer specifications where the terms of the contract require transfer of the completed product, therevised. Consequently, operating company has met its performance obligation and recognizes revenue at the point in time when the product is shipped. For revenue recognized on products when shipped, the operating companies have no further obligation to provide services related to such products. The shipping terms used in these instances are FOB shipping point.Plastics Segment Revenues—Companies in our Plastics segment earn revenue predominantly from the sale and delivery of standardized polyvinyl chloride (PVC) pipe products produced at their manufacturing facilities. Revenue from the sale of these products is recognized at the point in time when the product is shipped based on prices agreed to in a purchase order. For revenue recognized on shipped products, there is no further obligation to provide services related to such products. The shipping terms used in these instances are FOB shipping point. The Plastics segment has one customer for which it produces and stores a product made to the customer’s specifications and design under a build and hold agreement. For sales to this customer, the operating company recognizes revenue as the custom-made product is produced, adjusting the amount of revenue for volume rebate variable pricing considerations the operating company expects the customer will earn and applicable early payment discounts the company expects the customer will take. Ownership of the pipe transfers to the customer prior to delivery and the operating company is paid a negotiated fee for storage of the pipe.See operating revenue table in note 2 for a disaggregation of the Company’s revenues by business segment for the three- and nine-month periods ended September 30, 2020 and 2019.Agreements Subject to Legally Enforceable Netting ArrangementsOTP has certain derivative contracts that are designated as normal purchases. Individual counterparty exposures for these contractsresults can be offset accordingaffected by revisions to legally enforceable netting arrangements. The Company does not offset assetsprior accounting estimates.liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet. Fair Value MeasurementsThe 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.9The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2020 and December 31, 2019: $ 1,665 $ 2,887 6,131 1,582 $ 3,247 $ 9,018 $ 1,586 $ 2,124 6,060 2,363 $ 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 EntityIn October 2012 the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of lignite coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton paid by the Coyote Station owners under the LSA reflects the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are required to buy certain assets of CCMC at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC because the Coyote Station owners are required to buy the membership interests of CCMC at the end of the contract term at equity value. No single owner of Coyote Station owns a majority interest in Coyote Station or has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE and the Company is not required to include CCMC in its consolidated financial statements.If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and the Coyote Station owners purchase all of the outstanding membership interests of CCMC, the owners will satisfy (or if permitted by CCMC’s applicable lender assume) all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. In the event the contract is terminated prior to the end of the term due to certain events, OTP’s maximum exposure to additional costs, as a result of its involvement with CCMC, and potential impairment loss if recovery of those costs is denied by regulatory authorities, could be as high as approximately $50 million, OTP’s 35% share of CCMC’s unrecovered costs as of September 30, 2020.10InventoriesInventories, valued at the lower of cost or net realizable value, consist of the following: $ 18,901 $ 31,863 14,480 16,508 48,490 49,480 $ 81,871 $ 97,851 Intangible AssetsIntangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360-10-35,Property, Plant, and Equipment—Overall—Subsequent Measurement.The following table summarizes the components of the Company’s intangible assets at September 30, 2020 and December 31,2019: $ 22,491 $ 12,095 $ 10,396 79-179 26 3 23 216 $ 22,517 $ 12,098 $ 10,419 $ 22,491 $ 11,259 $ 11,232 88-188 179 121 58 8-45 $ 22,670 $ 11,380 $ 11,290 The amortization expense for these intangible assets was: $ 284 $ 296 $ 871 $ 888 The estimated annual amortization expense for these intangible assets for the next 51 months is: $ 275 $ 1,100 $ 1,100 $ 1,100 $ 1,100 Supplemental Disclosures of Cash Flow Information $ 112,314 $ 15,893 11New Accounting Standards AdoptedASU 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 PolicyTrade 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 LossesFollowing is a summary of activity in allowances for credit losses on trade and unbilled accounts receivable across the Company: $ 2,100 $ 1,691 $ 1,339 $ 1,407 474 86 1,845 549 (313 ) (225 ) (923 ) (404 ) $ 2,261 $ 1,552 $ 2,261 $ 1,552 ASU 2018-15—In August 2018 the FASB issued ASU No.2018-15,Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40), which amends ASC 350-40, Internal-Use Software, to address a customer's accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. The amendments in ASU 2018-15 align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). Accordingly, the amendments in ASU 2018-15 require an entity (customer) in a hosting arrangement that is a service contract to follow the guidance in ASC 350-40 to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The amendments in ASU 2018-15 also require the entity to present the expense related to the capitalized implementation costs in the same line item in the statement of income as the fees associated with the hosting element (service) of the arrangement and classify payments for capitalized implementation costs in the statement of cash flows in the same manner as payments made for fees associated with the hosting element. The entity is also required to present the capitalized implementation costs in the statement of financial position in the same line item that a prepayment for the fees of the associated hosting arrangement would be presented. The amendments in ASU 2018-15 were effective for interim and annual periods beginning on or after December 15, 2019 with early adoption permitted in any interim period. The Company adopted the amendments in ASU 2018-15 in the first quarter of 2020. There was no impact to its consolidated financial statements on adoption, but the Company will begin capitalizing implementation costs incurred in cloud computing arrangements post-adoption.122.Segment InformationThe accounting policies of the segments are described under note 1 – Summary of Significant Accounting Policies. The Company's businesses have been classified into three segments to bePlastics, consistent with itsour business strategy, organizational structure and theour internal reporting and review processprocesses used by the Company’sour chief operating decision maker. These businesses sell productsmaker to make decisions regarding allocation of resources, to assess operating performance and provide services to customers primarily in the United States. The Company’s business structure currently includes the following 3 segments: Electric, Manufacturingmake strategic decisions.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 businessescosts are owned by its wholly owned subsidiary, Varistar Corporation. The Company’snot allocated to our operating segments. Corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’sour captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not an operating segment. Rather,segment, rather it is added to operating segment totals to reconcile to totalsconsolidated amounts.Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2021 2020 2021 2020 Electric $ 118,775 $ 115,213 $ 348,629 $ 333,213 Manufacturing 89,977 59,849 250,085 174,276 Plastics 107,542 60,693 264,898 155,769 Total $ 316,294 $ 235,755 $ 863,612 $ 663,258 Net Income (Loss) Electric $ 22,528 $ 24,737 $ 55,547 $ 54,225 Manufacturing 4,200 3,311 15,290 8,476 Plastics 28,410 10,343 60,102 20,922 Corporate (2,384) (2,457) (5,787) (6,440) Total $ 52,754 $ 35,934 $ 125,152 $ 77,183 (in thousands) September 30,
2021December 31,
2020Identifiable Assets Electric $ 2,271,636 $ 2,233,399 Manufacturing 242,414 191,005 Plastics 143,615 99,767 Corporate 55,483 54,183 Total $ 2,713,148 $ 2,578,354 Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2021 2020 2021 2020 Operating Revenues Electric Segment Retail: Residential $ 33,902 $ 32,734 $ 100,067 $ 96,440 Retail: Commercial and Industrial 60,557 64,918 185,376 189,771 Retail: Other 1,979 1,953 5,687 5,550 Total Retail 96,438 99,605 291,130 291,761 Transmission 13,300 12,288 37,085 32,802 Wholesale 6,944 1,500 14,711 3,141 Other 2,093 1,820 5,703 5,509 Total Electric Segment 118,775 115,213 348,629 333,213 Manufacturing Segment Metal Parts and Tooling 76,455 50,957 210,141 145,435 Plastic Products and Tooling 10,198 7,600 30,624 25,323 Scrap Metal Sales 3,324 1,292 9,320 3,518 Total Manufacturing Segment 89,977 59,849 250,085 174,276 Plastics Segment PVC Pipe 107,542 60,693 264,898 155,769 Total Operating Revenue 316,294 235,755 863,612 663,258 Less: Non-contract Revenues Included Above Electric Segment - ARP Revenues (33) 2,778 (2,790) 2,900 Total Operating Revenues from Contracts with Customers $ 316,327 $ 232,977 $ 866,402 $ 660,358 (in thousands) September 30,
2021December 31,
2020Receivables Trade $ 152,906 $ 87,048 Other 11,182 8,939 Unbilled Receivables 17,003 21,187 Total Receivables 181,091 117,174 Less: Allowance for Credit Losses 2,332 3,215 Receivables, net of allowance for credit losses $ 178,759 $ 113,959 (in thousands) 2021 2020 Beginning Balance, January 1 $ 3,215 $ 1,339 Additions Charged to Expense 177 1,845 Reductions for Amounts Written Off, Net of Recoveries (1,060) (923) Ending Balance, September 30 $ 2,332 $ 2,261 (in thousands) September 30,
2021December 31,
2020Finished Goods $ 25,727 $ 22,046 Work in Process 29,932 16,210 Raw Material, Fuel and Supplies 58,956 53,909 Total Inventories $ 114,615 $ 92,165 (in thousands) September 30,
2021December 31,
2020Corporate-Owned Life Insurance Policies $ 40,096 $ 36,825 Debt Securities 9,208 9,260 Money Market Funds 953 4,075 Mutual Funds 5,170 1,662 Other Investments 29 34 Total Investments $ 55,456 $ 51,856 (in thousands) September 30,
2021December 31,
2020Electric Plant in Service Electric Plant in Service $ 2,705,778 $ 2,531,352 Construction Work in Progress 100,495 203,078 Total Gross Electric Plant 2,806,273 2,734,430 Less Accumulated Depreciation and Amortization 822,441 778,988 Net Electric Plant 1,983,832 1,955,442 Nonelectric Property, Plant and Equipment Nonelectric Property, Plant and Equipment in Service 263,880 258,730 Construction Work in Progress 15,564 9,290 Total Gross Nonelectric Property, Plant and Equipment 279,444 268,020 Less Accumulated Depreciation and Amortization 180,053 174,189 Net Nonelectric Property, Plant and Equipment 99,391 93,831 Net Property, Plant and Equipment $ 2,083,223 $ 2,049,273 Period of September 30, 2021 December 31, 2020 (in thousands) Recovery/Refund Current Long-Term Current Long Term Regulatory Assets Various $ 11,037 $ 139,467 $ 11,037 $ 146,071 Up to 3 years 7,229 8,225 8,871 9,373 Asset lives — 7,065 — 8,462 Up to 2 years 270 1,027 1,079 867 Up to 3 years 3,227 1,456 361 2,989 Various 637 936 360 230 Up to 12 years 117 262 192 341 Various — 77 — 62 Total Regulatory Assets $ 22,517 $ 158,515 $ 21,900 $ 168,395 Regulatory Liabilities Deferred Income Taxes Asset lives $ — $ 130,555 $ — $ 134,719 Plant Removal Obligations Asset lives 5,893 96,734 — 98,707 Fuel Clause Adjustments Up to 1 year 5,692 — 10,947 — Alternative Revenue Program Riders Various 5,265 2,507 3,581 470 Pension and Other Postretirement Benefit Plans Up to 1 year 1,959 — 1,959 — Derivative Instruments Various 6,136 787 — — Other Various 378 150 176 77 Total Regulatory Liabilities $ 25,323 $ 230,733 $ 16,663 $ 233,973 September 30, 2021 December 31,
2020(in thousands) Line Limit Amount Outstanding Letters
of CreditAmount Available Amount Available OTC Credit Agreement $ 170,000 $ 36,624 $ — $ 133,376 $ 104,834 OTP Credit Agreement 170,000 61,233 13,159 95,608 140,068 Total $ 340,000 $ 97,857 $ 13,159 $ 228,984 $ 244,902 Company’s consolidatedaverage unused amount available to be drawn under the respective facility. The variable rate of interest to be charged is based on either LIBOR or a Base Rate, as defined in the agreement, selected by the borrower at the time of an advance, subject to the conditions of each agreement, plus an applicable credit spread. The credit spread ranges from 0.125% to 2.00% for the OTC Credit Agreement and from zero to 1.75% for the OTP Credit Agreement, depending on the benchmark interest rate selected and is subject to adjustmentstatements.While 0 single customer accountedand non-financial covenants and defined events of default, and include provisions for over 10%the replacement of consolidatedthe LIBOR benchmark rate in the event that LIBOR is no longer available.(in thousands) Entity Debt Instrument Rate Maturity September 30,
2021December 31,
2020OTC 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 — 169 Total $ 767,000 $ 767,169 Less: Current Maturities Net of Unamortized Debt Issuance Costs 169,962 140,087 Unamortized Long-Term Debt Issuance Costs 2,419 2,650 Total Long-Term Debt Net of Unamortized Debt Issuance Costs $ 594,619 $ 624,432 Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2021 2020 2021 2020 Service Cost–Benefit Earned During the Period $ 1,866 $ 1,655 $ 5,597 $ 4,966 Interest Cost on Projected Benefit Obligation 2,915 3,264 8,745 9,790 Expected Return on Assets (5,590) (5,506) (16,769) (16,516) Amortization of Net Actuarial Loss: From Regulatory Asset 2,660 2,231 7,981 6,693 From Other Comprehensive Income 68 55 204 165 Net Periodic Pension Cost $ 1,919 $ 1,699 $ 5,758 $ 5,098 Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2021 2020 2021 2020 Service Cost–Benefit Earned During the Period $ 47 $ 45 $ 140 $ 134 Interest Cost on Projected Benefit Obligation 307 362 921 1,086 Amortization of Net Actuarial Loss: From Regulatory Asset 30 24 92 71 From Other Comprehensive Income 124 85 373 256 Net Periodic Pension Cost $ 508 $ 516 $ 1,526 $ 1,547 Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2021 2020 2021 2020 Service Cost–Benefit Earned During the Period $ 430 $ 461 $ 1,291 $ 1,385 Interest Cost on Projected Benefit Obligation 472 598 1,418 1,795 Amortization of Prior Service Cost From Regulatory Asset (1,397) (1,169) (4,192) (3,508) From Other Comprehensive Income (35) (28) (107) (86) Amortization of Net Actuarial Loss From Regulatory Asset 919 1,051 2,759 3,154 From Other Comprehensive Income 24 26 71 78 Net Periodic Postretirement Benefit Cost $ 413 $ 939 $ 1,240 $ 2,818 Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 Federal Statutory Rate 21.0 % 21.0 % 21.0 % 21.0 % Increases (Decreases) in Tax from: State Taxes on Income, Net of Federal Tax 5.0 5.0 5.0 5.0 Production Tax Credits (PTCs) (5.0) — (6.0) — Amortization of Excess Deferred Income Taxes (1.6) (2.9) (2.0) (3.4) North Dakota Wind Tax Credit Amortization, Net of Federal Tax (0.2) (0.6) (0.3) (0.8) Excess Tax Deduction on Stock Awards — 0.3 — (0.4) Allowance for Equity Funds Used During Construction (0.1) (0.7) (0.1) (0.8) Other, Net (0.8) (1.9) (0.7) (1.2) Effective Tax Rate 18.3 % 20.2 % 16.9 % 19.4 % in 2019, certain customers providedreductions.each business segment’s 2019 revenue. The Electric segment has 1 customer that provided 11.9% of 2019 segment revenues. The Manufacturing segment has 1 customer that manufactures and sells recreational vehicles that provided 23.8% of 2019 segment revenues and 1 customer that manufactures and sells lawn and garden equipment that provided 11.1% of 2019 segment revenues. The Manufacturing segment’s top 5 revenue-generating customers provided over 54% of 2019 segment revenues. The Plastics segment has 2 customers that individually provided 25.3% and 20.4% of 2019 segment revenues. The loss of any one of these customers would have a significant negative impact onits current coal requirements, with expiration dates ranging from 2022 through 2040. Certain contracts do not include minimum purchase requirements but do require all coal necessary for the financial position and results of operationsoperation of the respective business segment andplant to be purchased from the Company.All of the Company’s long-lived assets are within the United States and sales within the United States accounted for 98.9% and 98.5% of operating revenues for the respective three-month periods ended September 30, 2020 and 2019, and 99.0% and 98.7% of operating revenues for the respective nine-month periods ended September 30, 2020 and 2019.13
The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three- and nine-month periods ended September 30, 2019 and 2020 and total assets by business segment as of September 30, 2020 and December 31,2019 are presented in the following tables:
Operating RevenueLand Easements.
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
(in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||
Electric Segment: | ||||||||||||||||
Retail Sales Revenue from Contracts with Customers | $ | 96,827 | $ | 100,345 | $ | 288,861 | $ | 303,276 | ||||||||
Changes in Accrued ARP Revenues | 2,778 | (921 | ) | 2,900 | (1,601 | ) | ||||||||||
Total Retail Sales Revenue | 99,605 | 99,424 | 291,761 | 301,675 | ||||||||||||
Transmission Services Revenue | 12,288 | 11,692 | 32,802 | 34,023 | ||||||||||||
Wholesale Revenues – Company Generation | 1,500 | 1,631 | 3,141 | 4,099 | ||||||||||||
Other Revenues | 1,830 | 1,626 | 5,548 | 4,929 | ||||||||||||
Total Electric Segment Revenues | 115,223 | 114,373 | 333,252 | 344,726 | ||||||||||||
Manufacturing Segment: | ||||||||||||||||
Metal Parts and Tooling | 50,957 | 56,255 | 145,435 | 185,520 | ||||||||||||
Plastic Products and Tooling | 7,600 | 8,088 | 25,323 | 26,486 | ||||||||||||
Other | 1,292 | 1,379 | 3,518 | 5,034 | ||||||||||||
Total Manufacturing Segment Revenues | 59,849 | 65,722 | 174,276 | 217,040 | ||||||||||||
Plastics Segment – Sale of PVC Pipe Products | 60,693 | 48,566 | 155,769 | 142,100 | ||||||||||||
Intersegment Eliminations | (10 | ) | (9 | ) | (39 | ) | (39 | ) | ||||||||
Total | $ | 235,755 | $ | 228,652 | $ | 663,258 | $ | 703,827 | ||||||||
Interest Charges
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
(in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||
Electric | $ | 7,334 | $ | 6,300 | $ | 22,066 | $ | 19,566 | ||||||||
Manufacturing | 553 | 561 | 1,661 | 1,791 | ||||||||||||
Plastics | 163 | 197 | 497 | 561 | ||||||||||||
Corporate and Intersegment Eliminations | 518 | 481 | 1,129 | 1,272 | ||||||||||||
Total | $ | 8,568 | $ | 7,539 | $ | 25,353 | $ | 23,190 | ||||||||
Income Taxes
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
(in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||
Electric | $ | 6,048 | $ | 4,066 | $ | 12,247 | $ | 9,874 | ||||||||
Manufacturing | 891 | 285 | 2,163 | 2,888 | ||||||||||||
Plastics | 3,638 | 1,914 | 7,373 | 5,287 | ||||||||||||
Corporate | (1,480 | ) | (1,329 | ) | (3,240 | ) | (4,142 | ) | ||||||||
Total | $ | 9,097 | $ | 4,936 | $ | 18,543 | $ | 13,907 | ||||||||
Net Income (Loss)
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
(in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||
Electric | $ | 24,737 | $ | 17,682 | $ | 54,225 | $ | 43,884 | ||||||||
Manufacturing | 3,311 | 3,155 | 8,476 | 11,987 | ||||||||||||
Plastics | 10,343 | 5,397 | 20,922 | 14,918 | ||||||||||||
Corporate | (2,457 | ) | (1,489 | ) | (6,440 | ) | (4,294 | ) | ||||||||
Total | $ | 35,934 | $ | 24,745 | $ | 77,183 | $ | 66,495 | ||||||||
Identifiable Assets
September 30, | December 31, | |||||||
(in thousands) | 2020 | 2019 | ||||||
Electric | $ | 2,191,215 | $ | 1,931,525 | ||||
Manufacturing | 189,525 | 195,742 | ||||||
Plastics | 104,661 | 92,049 | ||||||
Corporate | 49,106 | 54,279 | ||||||
Total | $ | 2,534,507 | $ | 2,273,595 | ||||
3. Rate and Regulatory Matters
Below are descriptions of OTP’s major capital expenditure projects that are expected to have a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the FERC, impacting OTP’s revenues in 2020 and 2019.
Major Capital Expenditure Projects
Merricourt Wind Energy Center (Merricourt)—On November 16, 2016 OTP entered into an Asset Purchase Agreement (the Purchase Agreement) with EDF Renewable Development, Inc. and certain of its affiliated companies (collectively, EDF) to purchase the development assets and assume certain specified liabilities associated with Merricourt, a 150-megawatt (MW) wind farm in southeastern North Dakota, for a purchase price of approximately $34.7 million, subject to adjustments for interconnection costs. Also on November 16, 2016, OTP entered into a Turnkey Engineering, Procurement and Construction Services Agreement (the TEPC Agreement) with EDF-RE US Development, LLC (EDF-USD) pursuant to which EDF-USD will develop, design, procure, construct, interconnect, test and commission the wind farm with a targeted completion date in 2020 for consideration of approximately $200.5 million, subject to certain adjustments, payable following the closing of the Purchase Agreement in installments in connection with certain project construction milestones. In connection with action by the FERC, OTP and EDF-US agreed, in the First Amendment to the Purchase Agreement and the TEPC Agreement dated June 11,2019, to change the purchase price to $37.7 million andhas commitments to make a related reallocation of responsibility for interconnection costs and liabilities. On July 16, 2019 OTP closed on the purchase of substantially all of the development assets and assumed certain specified liabilities from EDF related to Merricourt pursuant to the Purchase Agreement, as amended, for a purchase price of approximately $37.7 million, subject to certain adjustments, and issued the notice to EDF-USD to begin construction in August 2019. The agreements contain customary representations, warranties, covenants and indemnities for this type of transaction. The Merricourt generator interconnection agreement with MISO was approved by the future payments under land easements extending into 2050.
OTP is earning a return in all three states served by OTP on amounts invested in Merricourt while the project is under construction. Returns are recovered in Minnesota and North Dakota through RRA riders and in South Dakota through the Phase-In Rate Plan Rider. As of September 30, 2020, OTP had capitalized approximately $231.1 million in project costs and allowance for funds used during construction (AFUDC) associated with Merricourt. While work on the project continues and commissioning of the wind turbines is in process, OTP has received Notices of Force Majeure from EDF-USD claiming rights to an extension of guaranteed project completion dates and adjustments to the consideration agreed upon in the TEPC Agreement due to COVID-19 impacts. While details regarding these claims and the related impacts to the project remain uncertain, OTP currently anticipates Merricourt will be in commercial operation by the end of December 2020.
ROE.
General Rates
Minnesota—The MPUC rendered its final decision in OTP’s 2016 general rate case in March 2017 and issued its written order on May 1, 2017. Pursuant to the order, OTP’s allowed rate of return on rate base is 7.5056% and its allowed rate of return on equity (ROE) is 9.41%.
The MPUC’s order also included: (1) the determination that all costs (including FERC allocated costs and revenues) of the Big Stone South–Brookings and Big Stone South–Ellendale Multi-Value Projects (MVPs) will be included in the Minnesota TCR Rider and jurisdictionally allocated to OTP’s Minnesota customers (see discussion under Minnesota Transmission Cost Recovery Rider below), and (2) approval of OTP’s proposal to transition rate base, expenses and revenues from ECR and TCR Riders to base rate recovery, which occurred when final rates were implemented on November 1, 2017. Certain MISO expenses and revenues remain in the TCR Rider to allow for the ongoing refund or recovery of these variable revenues and costs.
On November 2, 2020 OTP filed a request with the MPUC for an increase in revenue recoverable under general rates in Minnesota. In its filing, OTP requested a net increase in annual revenue of approximately $14.5 million, or 6.77%, based on an allowed rate of return on rate base of 7.59% and an allowed rate of return on equity of 10.20% on an equity ratio of 52.5% of total capital. Through this rate case proceeding, OTP is proposing to recover, at the start of interim rates, revenue currently subject to recovery under Minnesota RRA and TCR riders. OTP is also proposing to move the cost of energy from base rates to full recovery under the Energy Adjustment Rider per a prior MPUC order. OTP is also proposing to move recovery of all CIP expenditures out of base rates to the CIP Rider with the implementation of final rates. An interim rate increase is expected to go into effect in January 2021.
North Dakota—On March 23, 2018 OTP made a supplemental filing to its initial request for a rate review, reducing its request for an annual revenue increase from $13.1 million to $7.1 million, a 4.8% annual increase. The $6.0 million decrease included $4.8 million related to tax reform and $1.2 million related to other updates.
In a September 26, 2018 hearing the NDPSC approved an overall annual revenue increase of $4.6 million (3.1%) and a ROE of 9.77% on a 52.5% equity capital structure. The NDPSC’s approval established a GCR Rider for future recovery of costs incurred for Astoria Station. The net revenue increase reflected a reduction in income tax recovery requirements related to the 2017 Tax Cuts and Jobs Act (TCJA) and decreases in rider revenue recovery requirements. Final rates were effective February 1,2019, with refunds of excess revenues collected under interim rates applied to customers’ April 2019 bills, including $0.8 million for amounts collected reflecting the higher tax rates under interim rates in effect in January and February 2018.
South Dakota—On April 20, 2018 OTP filed a request with the SDPUC to increase non-fuel rates in South Dakota by approximately $3.3 million annually, or 10.1%, as the first step in a two-step request. Interim rates were effective October 18,2018. The second step in the request was an additional 1.7% revenue increase to recover costs for Merricourt when the wind generation facility goes into service. The SDPUC approved a partial settlement on March 1, 2019 on all issues of the rate case except ROE. The partial settlement included approval of a phase-in plan to provide for a return on amounts invested in Astoria Station and Merricourt, which addressed the second step of the request for increased rates in South Dakota. The partial settlement also included a moratorium on filing another general rate case in South Dakota until the new generation projects have been in service for a year. The partial settlement also allowed OTP to retain the impact of lower tax rates related to the TCJA from January 1, 2018 through October 17,2018 resulting in the reversal of an accrued refund liability and recognition of $1.0 million in revenue in the first quarter of 2019. The SDPUC approved the ROE portion of the rate case on May 14, 2019 and pursuant to the SDPUC’s May 30, 2019 order, OTP’s allowed ROE was set at 8.75%, resulting in an annual revenue increase of approximately $2.2 million. Final rates went into effect August 1, 2019. An interim rate refund for the lower ROE going back to October 18, 2018 was applied to South Dakota customers’ October 2019 bills.
On July 9, 2019 the SDPUC approved a stipulation agreement entered into by OTP with SDPUC staff. The revenue requirement stated in the SDPUC’s final order dated May 30, 2019 understated the amount of OTP's South Dakota share of electric transmission plant in service, resulting in an annual revenue requirement shortfall of approximately $341,000. To address the shortfall, the parties agreed that OTP would file an update to its South Dakota TCR Rider. OTP was authorized full recovery of the transmission rate base correction reflected in the TCR Rider tracker beginning as of the first date of interim rates, October 18, 2018, with the TCR Rider rate update going into effect on October 1, 2019.
To ensure rates are appropriately set under the stipulation, the parties agreed to establish an earnings sharing mechanism to share with customers any weather-normalized earnings above the authorized ROE of 8.75%. OTP's annual weather-normalized earnings are reported each year by June 1 in its jurisdictional annual report, which will be used to determine the earnings level for purposes of calculating any refund. The earnings sharing mechanism requires that OTP will refund to customers 50% of
any weather-normalized revenue that corresponds to the earnings in excess of its authorized ROE, up to a maximum of 9.50% ROE for a particular year. OTP will refund 100% of any earnings above 9.50% each year. In the event a refund is due under this provision, OTP will notify the SDPUC of the refund amount and plan for crediting customers within 30 days of filing its South Dakota jurisdictional annual report.
Rate Riders
In addition to general rates, OTP has several rate riders in place in each of its state jurisdictional service areas. These rate riders are designed to recover expenses, costs and returns on rate base investments not currently being recovered in base, or general, rates. In addition to fuel cost recovery riders in each state, OTP has recovered costs and earned incentives or returns on investments subject to recovery under several rate riders, including:
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Following is a brief summary of recent proceedings of riders in place in each state served by OTP, followed by tables showing revenues recorded under rate riders for the three- and nine-month periods ended September 30, 2020 and September 30, 2019 and a listing of rate rider updates impacting revenues in 2020 and 2019. Additional information and background on these rate riders is provided in the Company’s Annual Report on Form 10-K for the year ended December 31, 2019.
Minnesota
Minnesota Conservation Improvement Programs (MNCIP)—On May 1, 2020 OTP filed a request for approval of its 2019 energy savings, recovery of $2.7 million in accrued financial incentives and recovery of 2019 program costs not included in base rates. OTP’s request was approved by order of the MPUC on August 18, 2020.
Transmission Cost Recovery Rider—In OTP’s 2016 general rate case order issued on May 1, 2017, the MPUC ordered OTP to include, in the TCR Rider retail rate base, Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVPs and all revenues received from other utilities under MISO’s tariffed rates as a credit in its TCR revenue requirement calculations. In doing so, the MPUC’s order diverted interstate wholesale revenues that have been approved by the FERC to offset FERC-approved expenses, effectively reducing OTP’s recovery of those FERC-approved expense levels. The MPUC-ordered treatment resulted in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC’s revenue requirements and authorized returns vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision can vary over time and be dependent on the differences between the revenue requirements and returns in the two jurisdictions at any given time. On August 18, 2017 OTP filed an appeal of the MPUC general rate case order with the Minnesota Court of Appeals to contest the portion of the order requiring OTP to jurisdictionally allocate costs of the FERC MVP transmission projects in the TCR Rider.
On June 11, 2018 the Minnesota Court of Appeals reversed the MPUC’s order related to the inclusion of Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVPs and all revenues received from other utilities under MISO’s tariffed rates as a credit in OTP’s Minnesota TCR revenue requirement calculations. On July 11, 2018 the MPUC filed a petition for review of the MVP decision to the Minnesota Supreme Court, which granted review of the Minnesota Court of Appeals decision. The Minnesota Supreme Court issued its opinion on April 22,2020, concluding the MPUC lacked authority to amend an existing transmission cost-recovery rider approved under Minnesota state law to include the costs and revenues associated with the Big Stone South–Brookings and Big Stone South–Ellendale MVPs and affirming the decision of the Minnesota Court of Appeals.
On October 22, 2020 the MPUC approved OTP’s request for a Minnesota TCR Rider update with exclusion of the Big Stone South–Brookings and Big Stone South–Ellendale projects and inclusion of three projects previously requested in the Minnesota TCR Rider eligibility petition. Updated rates go into effect in January 2021. With the decision, one-half of OTP’s Minnesota TCR December 2020 projected tracker balance of $13.4 million will be included in the 2021 TCR annual revenue requirement with the remainder included in the next annual update. The annual updates provide for recovery of approximately $2.6 million in excess MISO revenues credited to Minnesota customers through the TCR Rider prior to September 30, 2020. As a result, OTP recognized additional rider revenue of $2.6 million in the three-month period ended September 30, 2020.
Renewable Resource Adjustment—On June 21, 2019 OTP filed its annual update to the Minnesota RRA requesting approval for recovery of the difference in PTCs in base rates and the actual PTCs generated, as well as recovery of Merricourt. On December 19, 2019 the MPUC approved a revised request which included changes related to Merricourt capitalized costs.
Fuel and Purchased Power Costs Recovery—In a December 2017 order, the MPUC adopted a program to implement certain procedural reforms to Minnesota utilities’ automatic fuel adjustment clause (FAC) for fuel and purchased power cost recovery. With this order, the method of accounting for all Minnesota electric utilities changed to a monthly budgeted, forward-looking FAC with annual prudence review and true-up to actual allowed costs. On October 31, 2019 the MPUC approved the forecasted monthly fuel cost rates submitted by OTP for 2020 and the rates became effective on January 1, 2020. This mechanism could result in reductions in Electric segment operating income margins, increase variability in consolidated net income in future periods if costs per kwh vary from forecasted costs per kwh, and cause an increase in working capital and short-term borrowings in the event recovery of all or a portion of excess costs is delayed or denied by the MPUC.
North Dakota
Renewable Resource Adjustment—On December 31, 2019 OTP filed its annual update to the North Dakota RRA requesting approval for recovery of the difference in PTCs in base rates and the actual PTCs generated, as well as a return on Merricourt costs incurred while under construction. This update also included a credit for the remaining unrefunded credit balance in the North Dakota ECR Rider tracker on November 30, 2019. On February 25, 2020 OTP filed a revised request which was approved by the NDPSC on March 18, 2020. Part of the NDPSC’s approval included adopting a levelized utilization of PTCs from the Merricourt project over the expected 25-year life of the project for rate-making purposes. PTCs on prior projects were passed back to customers through lower rates as they were generated over 10 years.
Generation Cost Recovery Rider—On May 15, 2019 the NDPSC approved OTP’s request to establish an initial GCR Rider rate for recovery of OTP’s North Dakota jurisdictional share of the revenue requirements on its investment in Astoria Station, effective on bills rendered after July 1, 2019. On June 10, 2020 the NDPSC approved the 2020 annual update request with an effective date of July 1, 2020.
South Dakota
Phase-In Rate Plan Rider—On May 31, 2019 OTP petitioned the SDPUC for approval of its initial rate for the Phase-In Rate Plan Rider as described in OTP’s most recent South Dakota general rate case settlement stipulation and was approved by the SDPUC’s order in that rate case. The petition was OTP’s initial filing for the rider to recover OTP’s South Dakota share of actual and forecasted costs for Astoria Station and Merricourt, and to refund forecasted net benefits associated with additional load growth in the Lake Norden area. On August 6, 2020 the SDPUC approved OTP’s request for an updated Phase-In Rider Factor effective September 1, 2020.
Revenues Recorded under Rate Riders
The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota, and South Dakota.
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
Rate Rider (in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||
Minnesota | ||||||||||||||||
Renewable Resource Recovery | $ | 3,318 | $ | 1,316 | $ | 9,660 | $ | 3,949 | ||||||||
Conservation Improvement Program Costs and Incentives | 2,096 | 1,518 | 4,703 | 4,246 | ||||||||||||
Transmission Cost Recovery | 2,001 | (284 | ) | 2,402 | 301 | |||||||||||
Environmental Cost Recovery | 0 | 0 | 0 | (1 | ) | |||||||||||
North Dakota | ||||||||||||||||
| Renewable Resource Adjustment | 1,256 | (20 | ) | 3,455 | 616 | |||||||||||
Transmission Cost Recovery | 809 | 908 | 3,131 | 3,554 | ||||||||||||
Generation Cost Recovery | 1,187 | 137 | 3,035 | 607 | ||||||||||||
Environmental Cost Recovery | 0 | (7 | ) | 0 | 556 | |||||||||||
South Dakota | ||||||||||||||||
Transmission Cost Recovery | 450 | 743 | 1,383 | 1,587 | ||||||||||||
Conservation Improvement Program Costs and Incentives | 194 | 100 | 748 | 440 | ||||||||||||
Environmental Cost Recovery | 0 | (2 | ) | 0 | (29 | ) | ||||||||||
Phase-In Rate Plan | (53 | ) | (10 | ) | (77 | ) | (10 | ) | ||||||||
Total | $ | 11,258 | $ | 4,399 | $ | 28,440 | $ | 15,816 | ||||||||
Rate Rider Updates
The following table provides summary information on the status of updates since January 1, 2018 for the rate riders described above:
Rate Rider | R - Request Date A - Approval Date | Effective Date Requested or Approved | Annual Revenue ($000s) | Rate | ||||||
Minnesota | ||||||||||
Conservation Improvement Program | ||||||||||
2019 Incentive and Cost Recovery | A – | August 18, 2020 | October 1, 2020 | $ | 8,247 | $0.00485 | /kwh | |||
2018 Incentive and Cost Recovery | A – | December 27, 2019 | January 1, 2020 | $ | 11,926 | $0.00710 | /kwh | |||
2017 Incentive and Cost Recovery | A – | October 4, 2018 | November 1, 2018 | $ | 10,283 | $0.00600 | /kwh | |||
Transmission Cost Recovery | ||||||||||
2018 Annual Update–Updated Request | A – | October 22, 2020 | January 1, 2021 | $ | 10,260 | Various | ||||
2017 Rate Reset | A – | October 30, 2017 | November 1, 2017 | $ | (3,311 | ) | Various | |||
Environmental Cost Recovery | ||||||||||
2018 Annual Update | A – | November 29, 2018 | December 1, 2018 | $ | 0 | 0% | of base | |||
Renewable Resource Adjustment | ||||||||||
2019 Annual Update – Revised | A – | December 19, 2019 | January 1, 2020 | $ | 12,506 | $0.00467 | /kwh | |||
2018 Annual Update | A – | August 29, 2018 | November 1, 2018 | $ | 5,886 | $0.00219 | /kwh | |||
North Dakota | ||||||||||
Renewable Resource Adjustment | ||||||||||
2020 Annual Update | A – | March 18, 2020 | April 1, 2020 | $ | 5,762 | 5.637% | of base | |||
2019 Annual Update | A – | May 1, 2019 | June 1, 2019 | $ | (235 | ) | -0.224% | of base | ||
2018 Rate Reset for effect of TCJA | A – | February 27, 2018 | March 1, 2018 | $ | 9,650 | 7.493% | of base | |||
Transmission Cost Recovery | ||||||||||
2020 Annual Update | R – | August 31, 2020 | January 1, 2021 | $ | 5,570 | Various | ||||
2019 Annual Update | A – | December 18, 2019 | January 1, 2020 | $ | 5,739 | Various | ||||
2018 Supplemental Update | A – | December 6, 2018 | February 1, 2019 | $ | 4,801 | Various | ||||
2018 Rate Reset for effect of TCJA | A – | February 27, 2018 | March 1, 2018 | $ | 7,469 | Various | ||||
Environmental Cost Recovery | ||||||||||
2019 Update | A – | October 22, 2019 | November 1, 2019 | $ | 0 | 0% | of base | |||
2018 Update | A – | December 19, 2018 | February 1, 2019 | $ | (378 | ) | -0.310% | of base | ||
2018 Rate Reset for effect of TCJA | A – | February 27, 2018 | March 1, 2018 | $ | 7,718 | 5.593% | of base | |||
Generation Cost Recovery | ||||||||||
2020 Annual Update | A – | June 10, 2020 | July 1, 2020 | $ | 6,184 | 6.041% | of base | |||
2019 Initial Request | A – | May 15, 2019 | July 1, 2019 | $ | 2,720 | 2.547% | of base | |||
South Dakota | ||||||||||
Transmission Cost Recovery | ||||||||||
2020 Annual Update | A – | February 19, 2020 | March 1, 2020 | $ | 2,327 | Various | ||||
2019 Rate Reset | A – | September 17, 2019 | October 1, 2019 | $ | 2,046 | Various | ||||
2019 Annual Update | A – | February 20, 2019 | March 1, 2019 | $ | 1,638 | Various | ||||
2018 Interim Rate Reset | A – | October 18, 2018 | October 18, 2018 | $ | 1,171 | Various | ||||
Environmental Cost Recovery | ||||||||||
2018 Interim Rate Reset | A – | October 18, 2018 | October 18, 2018 | $ | (189 | ) | -$0.00075 | /kwh | ||
Phase-In Rate Plan Recovery | ||||||||||
2020 Annual Update | A – | August 6, 2020 | September 1, 2020 | $ | 1,625 | 6.521% | of base | |||
2019 Initial Request | A – | August 21, 2019 | September 1, 2019 | $ | 864 | 3.345% | of base | |||
FERC
Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935 (Federal Power Act). The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a suspension period, subject to ultimate approval by the FERC.
MVPs—MVPs are designed to enable the MISO region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit from the MVP.
ROE—In November 2013 and February 2015, customers filed complaints with FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO tariff. OTP hastariff rate. FERC's most recent order, issued on November 19, 2020, adopted a revised ROE methodology and set the base ROE at 10.02% (10.52% with an adder) effective for the fifteen-month period from November 2013 to February 2015 and on a prospective basis beginning in September 2016. The order also dismissed any complaints covering the period from February 2015 to May 2016. The November 2020 opinion is subject to judicial review. We have deferred recognition and recorded a refund liability of $2.8$3.0 million as of September 30, 2020 as a result2021. This refund liability reflects our best estimate of the disputed ROE awaiting FERC action. The provision includes:
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Various FERC orders have been made that remain under appeal. All or some of the current liability will be refundedrequired refunds to customers once all regulatory and judicial proceedings are completed.
4. Regulatory AssetsWestmoreland Coal Company (Westmoreland) Arbitration. In December 2018, insurers for Westmoreland, Westmoreland and Liabilities
Asits affiliated companies filed an arbitration demand against the co-owners of Coyote Station, including OTP, a regulated entity, OTP accounts for the financial effects of regulation35% co-owner. The claimant insurers are pursuing recovery in accordance with ASC 980. This accounting standard allows for the recording of a regulatory asset or liability for costs that will be collected or refunded in the future as required under regulation. Additionally, ASC 980-605-25 provides for the recognition of revenues authorized for recovery outside of a general rate case under alternative revenue programs which provide for recovery of costs and incentives or returns on investment in such items as transmission infrastructure, renewable energy resources or conservation initiatives. The following tables indicate the amount of regulatory assets$5.5 million, plus prejudgment interest to recover business interruption insurance proceeds paid to Westmoreland or its affiliates arising from a boiler feed pump explosion in December 2014 at the facility. The explosion and liabilities recorded on the Company’s consolidated balance sheets:
September 30, 2020 | Remaining Recovery/ | |||||||||||||||
(in thousands) | Current | Long-Term | Total | Refund Period (months) | ||||||||||||
Regulatory Assets: | ||||||||||||||||
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1 | $ | 9,018 | $ | 122,765 | $ | 131,783 | see below | |||||||||
Minnesota Transmission Cost Recovery Rider Accrued Revenues2 | 3,676 | 6,126 | 9,802 | 27 | ||||||||||||
Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment1 | 0 | 8,481 | 8,481 | asset lives | ||||||||||||
Conservation Improvement Program Costs and Incentives2 | 1,040 | 2,094 | 3,134 | 24 | ||||||||||||
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery1 | 0 | 2,149 | 2,149 | asset lives | ||||||||||||
MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups1 | 1,234 | 559 | 1,793 | 27 | ||||||||||||
Unrecovered Project Costs – Minnesota1 | 401 | 1,092 | 1,493 | 21 | ||||||||||||
Minnesota Renewable Resource Rider Accrued Revenues2 | 1,203 | 0 | 1,203 | 12 | ||||||||||||
Unrecovered Project Costs – North Dakota1 | 0 | 856 | 856 | 21 | ||||||||||||
Minnesota SPP Transmission Cost Recovery Tracker1 | 0 | 759 | 759 | see below | ||||||||||||
Debt Reacquisition Premiums1 | 204 | 379 | 583 | 144 | ||||||||||||
Unrecovered Project Costs – South Dakota1 | 144 | 357 | 501 | 24 | ||||||||||||
South Dakota Deferred Rate Case Expenses Subject to Recovery1 | 137 | 143 | 280 | 25 | ||||||||||||
North Dakota Deferred Rate Case Expenses Subject to Recovery1 | 122 | 152 | 274 | 27 | ||||||||||||
Deferred Marked-to-Market Losses1 | 186 | - | 186 | 3 | ||||||||||||
North Dakota Generation Cost Recovery Rider Accrued Revenue2 | 66 | 0 | 66 | 9 | ||||||||||||
Deferred Lease Expenses1 | 0 | 65 | 65 | 56 | ||||||||||||
Minnesota Environmental Cost Recovery Rider Accrued Revenues2 | 4 | 0 | 4 | 12 | ||||||||||||
Total Regulatory Assets | $ | 17,435 | $ | 145,977 | $ | 163,412 | ||||||||||
Regulatory Liabilities: | ||||||||||||||||
Deferred Income Taxes | $ | 0 | $ | 136,630 | $ | 136,630 | asset lives | |||||||||
Accumulated Reserve for Estimated Removal Costs – Net of Salvage | 0 | 99,617 | 99,617 | asset lives | ||||||||||||
Refundable Fuel Clause Adjustment Revenues | 9,208 | 0 | 9,208 | 12 | ||||||||||||
North Dakota Transmission Cost Recovery Rider Accrued Refund | 1,233 | 0 | 1,233 | 3 | ||||||||||||
South Dakota Phase-In Rate Plan Rider Accrued Refund | 1,090 | 0 | 1,090 | 11 | ||||||||||||
Revenue for Rate Case Expenses Subject to Refund – Minnesota | 0 | 577 | 577 | see below | ||||||||||||
Prior Service Costs and Actuarial Gains on Postretirement Benefits | 471 | 0 | 471 | 12 | ||||||||||||
North Dakota Renewable Resource Recovery Rider Accrued Refund | 444 | 0 | 444 | 6 | ||||||||||||
South Dakota Transmission Cost Recovery Rider Accrued Refund | 232 | 0 | 232 | 5 | ||||||||||||
Minnesota Energy Intensive Trade Exposed Rider Accrued Refund | 186 | 0 | 186 | 12 | ||||||||||||
Other | 6 | 68 | 74 | 159 | ||||||||||||
Total Regulatory Liabilities | $ | 12,870 | $ | 236,892 | $ | 249,762 | ||||||||||
Net Regulatory Asset/(Liability) Position | $ | 4,565 | $ | (90,915 | ) | $ | (86,350 | ) | ||||||||
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December 31, 2019 | Remaining Recovery/ | |||||||||||||||
(in thousands) | Current | Long-Term | Total | Refund Period (months) | ||||||||||||
Regulatory Assets: | ||||||||||||||||
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1 | $ | 9,090 | $ | 129,102 | $ | 138,192 | see below | |||||||||
Minnesota Transmission Cost Recovery Rider Accrued Revenues2 | 4,208 | 0 | 4,208 | 12 | ||||||||||||
Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment1 | 0 | 7,772 | 7,772 | asset lives | ||||||||||||
Conservation Improvement Program Costs and Incentives2 | 4,024 | 2,844 | 6,868 | 21 | ||||||||||||
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery1 | 0 | 1,681 | 1,681 | asset lives | ||||||||||||
MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups1 | 2,033 | 968 | 3,001 | 24 | ||||||||||||
Unrecovered Project Costs – Minnesota1 | 715 | 225 | 940 | 16 | ||||||||||||
Minnesota Renewable Resource Rider Accrued Revenues2 | 131 | 0 | 131 | 12 | ||||||||||||
Minnesota SPP Transmission Cost Recovery Tracker1 | 0 | 202 | 202 | see below | ||||||||||||
Debt Reacquisition Premiums1 | 201 | 548 | 749 | 153 | ||||||||||||
Unrecovered Project Costs – South Dakota1 | 144 | 253 | 397 | 33 | ||||||||||||
South Dakota Deferred Rate Case Expenses Subject to Recovery1 | 138 | 245 | 383 | 34 | ||||||||||||
North Dakota Deferred Rate Case Expenses Subject to Recovery1 | 122 | 244 | 366 | 36 | ||||||||||||
Deferred Marked-to-Market Losses1 | 743 | - | 743 | 12 | ||||||||||||
Deferred Lease Expenses1 | 0 | 54 | 54 | 39 | ||||||||||||
Minnesota Environmental Cost Recovery Rider Accrued Revenues2 | 4 | 0 | 4 | 12 | ||||||||||||
South Dakota Transmission Cost Recovery Rider Accrued Revenues2 | 97 | 0 | 97 | 2 | ||||||||||||
Total Regulatory Assets | $ | 21,650 | $ | 144,138 | $ | 165,788 | ||||||||||
Regulatory Liabilities: | ||||||||||||||||
Deferred Income Taxes | $ | 0 | $ | 141,707 | $ | 141,707 | asset lives | |||||||||
Accumulated Reserve for Estimated Removal Costs – Net of Salvage | 0 | 97,726 | 97,726 | asset lives | ||||||||||||
Refundable Fuel Clause Adjustment Revenues | 3,982 | 0 | 3,982 | 12 | ||||||||||||
North Dakota Transmission Cost Recovery Rider Accrued Refund | 700 | 0 | 700 | 12 | ||||||||||||
South Dakota Phase-In Rate Plan Rider Accrued Refund | 355 | 0 | 355 | 9 | ||||||||||||
Revenue for Rate Case Expenses Subject to Refund – Minnesota | 0 | 401 | 401 | see below | ||||||||||||
Prior Service Costs and Actuarial Gains on Postretirement Benefits | 471 | 0 | 471 | 12 | ||||||||||||
North Dakota Renewable Resource Recovery Rider Accrued Refund | 1,515 | 0 | 1,515 | 12 | ||||||||||||
Minnesota Energy Intensive Trade Exposed Rider Accrued Refund | 164 | 0 | 164 | 12 | ||||||||||||
North Dakota Generation Cost Recovery Rider Accrued Refund | 287 | 0 | 287 | 6 | ||||||||||||
Other | 6 | 72 | 78 | 168 | ||||||||||||
Total Regulatory Liabilities | $ | 7,480 | $ | 239,906 | $ | 247,386 | ||||||||||
Net Regulatory Asset/(Liability) Position | $ | 14,170 | $ | (95,768 | ) | $ | (81,598 | ) | ||||||||
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The regulatory asset and liability related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses and gains subject to recovery or refund through rates as they are expensed. These unrecognized benefit costs and actuarial losses and gains are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic 715,Compensation—Retirement Benefits, but are eligible for treatment as regulatory assets or liabilities based on their probable inclusion in future retail electric rates.
The Minnesota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that were recoverable from Minnesota customers as of the balance sheet date.
The Accumulated ARO Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations.
Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates.
The Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery are employee benefit-related costs that are required to be capitalized for ratemaking purposes and are recovered over the depreciable lives of the assets to which the related labor costs were applied.
MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups relate to the over/under collection of revenue based on comparison of the expected versus actual construction on eligible projects in the period. The true-ups also include the state jurisdictional portion of MISO Schedule 26/26A for regional transmission cost recovery that was included in the calculation of the state transmission riders and subsequently adjusted to reflect actual billing amounts in the schedule.
Unrecovered Project Costs – Minnesota are the Minnesota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project and excess unrecovered depreciation expense for Hoot Lake Plant and OTP’s hydroelectric plants related to acceleration of their remaining depreciable lives.
The Minnesota Renewable Resource Recovery Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that were recoverable from Minnesota customers as of the balance sheet date.
Unrecovered Project Costs – North Dakota are the North Dakota share of excess unrecovered depreciation expense for Hoot Lake Plant and OTP’s hydroelectric plants related to acceleration of their remaining depreciable lives.
The Minnesota SPP Transmission Cost Recovery Tracker regulatory asset relates to costs incurred to serve Minnesota customers that are subject to recovery but that had not been billed to Minnesota customers as of the balance sheet date.
Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 147 months.
Unrecovered Project Costs – South Dakota are the South Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project and excess unrecovered depreciation expense for Hoot Lake Plant and OTP’s hydroelectric plants related to acceleration of their remaining depreciable lives.
South Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s most recent rate case in South Dakota and are currently being recovered beginning with the establishment of interim rates in October 2018.
North Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s most recent rate case in North Dakota currently being recovered beginning with the establishment of interim rates in January 2018.
All Deferred Marked-to-Market Losses recorded as of the balance sheet date relate to forward purchases of energy scheduled for delivery through December 2020.
The North Dakota Generation Cost Recovery Rider Accrued Revenues relate to revenues earned under the rider on recoverable costs incurred for the North Dakota share of OTP’s investment in Astoria Station, a natural gas-fired combustion turbine generation facility under construction near Astoria, South Dakota. The balance represents amounts subject to recovery from North Dakota customers that had not been billed to North Dakota customers as of the balance sheet date.
Deferred Lease Expenses: Under ASC 842 accounting rules for leases with scheduled escalating payments, rent expense is required to be recognized on a straight-line basis over the life of the lease based on the sum of those payments. Rate-regulated entities are generally only allowed to recoverensuing repairs reduced the amount of actual cash payments on leases and FERC accounting rules require that rent expense be recognized oncoal purchased from a Westmoreland affiliate under an existing coal purchase agreement. The Westmoreland insurers claim the basis of cash payments. The balanceco-owners breached the minimum purchase obligations in the deferred lease expense regulatory asset account represents operating lease rightcoal purchase agreement. As of use asset cumulative amortization and interest costs in excess of cumulative lease payments that are subjectSeptember 30, 2021, we have recorded an estimated liability for losses to recovery in future periods under regulatory accounting treatment as cash payments are rendered.
The Minnesota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS project that were recoverable from Minnesota customers as of the balance sheet date.
The South Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities and operating costsbe incurred to serve South Dakota customers that were recoverable from South Dakota customers as of the balance sheet date.
The regulatory liability related to Deferred Income Taxes results from changes in statutory tax rates accounted for in accordance with ASC Topic 740,Income Taxes.
The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred.
The North Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that were refundable to North Dakota customers as ofthis matter based upon the balance sheet date.
The South Dakota Phase-In Rate Plan Rider Accrued Refund relates to amounts collected for actual and forecasted costs for Astoria Station, Merricourt, and additional load growth that were refundable to South Dakota customers as of the balance sheet date.
Revenue for Rate Case Expenses Subject to Refund – Minnesota relates to revenues collected under general rates to recover costs related to prior rate case proceedingsmost recent information available, however, ultimate losses could be in excess of the actual costs incurred.
amount recorded. Any losses incurred from this matter could be eligible for recovery through typical cost recovery processes of our electric utility business. The North Dakota Renewable Resource Recovery Rider Accrued Refund relatespotential cost recovery would be subject to amounts collectedregulatory approval.
The South Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that were refundable to South Dakota customers as of the balance sheet date.
The Minnesota Energy Intensive Trade Exposed Rider Accrued Refund relates to over-collected amounts from Minnesota retail customers for fuel and purchased power costs reductions provided to customers in energy intensive trade exposed industries that were subject to refund to Minnesota customers as of the balance sheet date.
The North Dakota Generation Cost Recovery Rider Accrued Refund relates to revenues collected under the rider in excess of returns allowed on recoverable costs incurred for the North Dakota share of OTP’s investment in Astoria Station, a natural gas-fired combustion turbine generation facility under construction near Astoria, South Dakota. The balance represents amounts subject to refund to North Dakota customers that had been billed to North Dakota customers as of the balance sheet date.
If for any reason OTP ceases to meet the criteria for application of guidance under ASC 980 for all or part of its operations, the regulatory assets and liabilities that no longer meet such criteria wouldSeptember 30, 2021, other than those discussed above, will not be removed from the consolidated balance sheet and included in the consolidated statement of income as an expense or income item in the period in which the application of guidance under ASC 980 ceases.
5. Common Shares and Earnings Per Share
Statements Three Months ended September 30 Nine Months ended September 30 2020 2019 2020 2019 Weighted Average Common Shares Outstanding – Basic 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 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees Shares Expected to be Issued Under the Employee Stock Purchase Plan Nonvested Restricted Shares Shares Expected to be Issued Under the Deferred Compensation Program for Directors Total Dilutive Shares Weighted Average Common Shares Outstanding – Diluted 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 25% per year through February 6, 2024 To Executive Officers February 12, 2020 25% per year through February 6, 2024 Without Dividend Equivalent: To Nonexecutive Employees April 20, 2020 100% April 8, 2024 Stock Performance Awards Granted: Under Executive Agreement February 12, 2020 December 31, 2022 Under Legacy Agreement February 12, 2020 December 31, 2022 Restricted Stock Granted to Nonemployee Directors April 20, 2020 33% per year through April 8, 2023 Three months ended Nine months ended September 30, September 30, (in thousands) 2020 2019 2020 2019 Stock Performance Awards Granted to Executive Officers Restricted Stock Dividend Equivalent Units Granted to Executive Officers and Key Employees Restricted Stock Granted to Nonemployee Directors Restricted Stock Units Granted to Nonexecutive Employees ESPP (15% discount) TotalsShelf 2018 the Company2021 we filed a shelf registration statement with the Securities and Exchange Commission (SEC) under which the Company we may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement. The registration statement which expires on in May 2024.2021.On November 8, 2019, 2021, we filed a second registration statement with the Company entered into a Distribution Agreement with KeyBanc Capital Markets Inc. (KeyBanc Capital Markets). Pursuant to the terms of the Distribution Agreement, the Company may offer and sell its common shares from time to time through KeyBanc, as the Company’s distribution agentSEC for the offer and sale of the shares, up to an aggregate sales price of $75,000,000.Under the Distribution Agreement, the Company will designate the minimum price and maximum number of common shares to be sold through KeyBanc on any given trading day or over a specified period of trading days, and KeyBanc will use commercially reasonable efforts to sell such shares on such days, subject to certain conditions. Sales of the shares, if any, will be made by means of ordinary brokers’ transactions on the Nasdaq Global Select Market at market prices or as otherwise agreed with KeyBanc. The Company may also agree to sell shares to KeyBanc, as principal for its own account, on terms agreed to by the Company and KeyBanc in a separate agreement at the time of sale. KeyBanc will receive from the Company a commissionissuance of up to 2%1,500,000 common shares under an Automatic Dividend Reinvestment and Share Purchase Plan, which provides shareholders, retail customers of the gross sales price per share for anyOTP and other interested investors a method of purchasing our common shares sold through it as the Company’s distribution agentby reinvesting their dividends and/or making optional cash investments. Shares purchased under the Distribution Agreement. The Company is not obligated to sell and KeyBanc is not obligated to buy or sell any of the shares under the Distribution Agreement. The shares, if issued, willplan may be issued pursuant to the Company’s existing shelf registration statement.242020 Common Stock ActivityFollowing is a reconciliation of the Company’snew issue common shares outstanding from December 31, 2019 through September 30, 2020:Common Shares Outstanding, December 31, 201940,157,591Issuances:At-the-Market Offering588,084Automatic Dividend Reinvestment and Share Purchase Plan:Dividends Reinvested102,042Cash Invested88,636Executive Stock Performance Awards (2017 awards earned)62,497Vesting of Restricted Stock Units35,720Employee Stock Purchase Plan:Cash Invested29,894Dividends Reinvested7,906Restricted Stock Issued to Directors17,400Directors Deferred Compensation612Retirements:Shares Withheld for Individual Income Tax Requirements(38,217)Common Shares Outstanding, September 30, 202041,052,165Earnings Per ShareThe numerator used in the calculation of both basic and diluted earnings per common share is net income with no adjustments for the three- and nine-month periods ended September 30, 2020 and 2019. The denominator used in the calculation of basic earnings per common share is the weighted average number ofor common shares outstanding during the period excluding nonvested restricted shares granted to the Company’s directors, which are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share. The denominator used in the calculation of diluted earnings per common share is derived by adjusting basic shares outstanding for the items listed in the following reconciliation for the three- and nine-month periods ended September 30: 40,913,972 39,714,672 40,548,133 39,694,677 98,012 149,023 107,017 147,106 48,682 68,138 53,303 63,902 13,182 0 14,997 0 2,603 13,107 8,033 14,896 1,238 1,799 1,445 1,999 163,717 232,067 184,795 227,903 41,077,689 39,946,739 40,732,928 39,922,580 256. Share-Based PaymentsStock Incentive AwardsThe following stock incentive awards were granted under the 2014 Stock Incentive Plan during the nine months ended September 30, 2020. 3,000 $ 54.0450 15,300 $ 54.0607 14,975 $ 40.18 47,600 $ 47.10 7,400 $ 52.20 17,400 $ 44.85 The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration in certain cases, and subject to forfeiture under the terms of the restricted stock unit award agreements. Certain restricted stock units granted to executive officers and certain key employees are eligible to receive dividend equivalent payments on all unvested awards over the awards respective vesting periods. The grant-date fair value of each restricted stock unit paying a dividend equivalent was the average of the high and low market price per sharepurchased on the date of grant.open market. The grant-date fair value of each restricted stock unit that does not pay a dividend equivalent was the average of the high and low market price per share on the date of grant, discounted for the value of the dividend exclusion on those restricted stock units over the unit’s vesting period.Under the performance share awards the aggregate award for performance at target is 55,000 shares. For target performance the participants would earn an aggregate of 27,500 common shares for achieving the target set for the Company’s 3-year average adjusted ROE. The participants would also earn an aggregate of 27,500 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the Edison Electric Institute Index over the performance measurement period of January 1, 2020 through December 31, 2022, with the beginning and ending share values based on the average closing price of a share of the Company’s common stock for the 20 trading days immediately following January 1, 2020 and the average closing price for the 20 trading days immediately preceding January 1, 2023. Actual payment may range from zero to 150% of the target amount, or up to 82,500 common shares. There are no voting or dividend rights related to these shares until the shares, if any, are issued at the end of the performance measurement period. The terms of these awards are such that the entire award will be classified and accounted for as equity, as required under ASC 718,Compensation – Stock Compensation, and will be measured over the performance period based on the grant-date fair value of the award. The grant-date fair value of each performance share award was determined using a Monte Carlo fair valuation simulation model.Under the 2020 Performance Award Agreements, payment and the amount of paymentregistration statement expires in the event of retirement, resignation for good reason or involuntary termination without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that the payment of performance awards granted to an officer who is party to an Executive Employment Agreement with the Company is to be made at target at the date of any such event. The vesting of these awards is accelerated and paid at target in the event of a change in control.The restricted shares granted to the Company’s nonemployee directors are eligible for full dividend and voting rights. Restricted shares not vested and dividends on those restricted shares are subject to forfeiture under the terms of the restricted stock award agreements. The grant-date fair value of each restricted share was the average of the high and low market price per share on the date of grant.The end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the earlier of the indicated vesting period for the respective awards or the date the grantee becomes eligible for retirement as defined in their award agreement.26As of September 30, 2020, the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $3.9 million (before income taxes) which will be amortized over a weighted-average period of 1.9 years.Amounts of compensation expense recognized under the Company’s stock-based payment programs for the three- and nine-month periods ended September 30, 2020 and 2019 are presented in the table below: $ 758 $ 743 $ 3,170 $ 3,274 106 189 891 999 237 203 677 572 133 112 408 346 41 54 136 54 $ 1,275 $ 1,301 $ 5,282 $ 5,245 7. Retained Earnings and Dividend RestrictionThe CompanyRestrictions
Both the CompanyOTC Credit Agreement and OTP credit agreementsCredit Agreement contain restrictions on the payment of cash dividends upon a default or event of default. An event of default, would be consideredincluding failure to have occurred if the Company did not meetmaintain certain financial covenants. As of September 30, 2020, the Company was2021, we were in compliance with these financial covenants.
8. Leases
No update required
9. Commitments and Contingencies
Construction and Other Purchase Commitments
At the three months ended September 30, 2021 and 2020, OTP had commitments under contracts,respectively, and $6.4 million and $5.3 million for the nine months ended September 30, 2021 and 2020, respectively.
On October 1, 2019 T.O. Plastics entered into a six-year resin supply agreement that commenced on January 1, 2020. Underdo not provide for voting or dividend rights. Certain restricted stock unit award recipients are eligible to receive dividend equivalent payments during the resin supply agreement, there are no minimum purchase requirements, but T.O. Plastics is requiredvesting period, subject to purchase all of a specified class of regrind resin delivered by the supplier at a set price per pound. Based on current forecasted production levels, T.O. Plastics anticipates the quantity of resin deliveredforfeiture under the supply agreement will not exceed its requirements over the six-year termterms of the supply agreement or exceedagreement.
OTP has commitmentsThe following is a summary of stock award activity for the purchasenine months ended September 30, 2021:Shares Weighted Average
Grant-Date
Fair ValueNonvested, January 1, 2021 128,664 $ 44.30 Granted 57,650 43.10 Vested (47,646) 42.98 Forfeited (2,075) 40.95 Nonvested, September 30, 2021 136,593 $ 44.30
| 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 | % | |||||||
| 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 | — | — | |||||||||
| Nonvested, September 30, 2021 | 189,600 | $ | 42.54 | ||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (in thousands) | 2021 | 2020 | 2021 | 2020 | |||||||||||||||||||
| Weighted Average Common Shares Outstanding – Basic | 41,504 | 40,914 | 41,487 | 40,548 | |||||||||||||||||||
| Effect of Dilutive Securities: | |||||||||||||||||||||||
| Stock Performance Awards | 262 | 98 | 209 | 107 | |||||||||||||||||||
| Stock Awards | 88 | 49 | 82 | 53 | |||||||||||||||||||
| Employee Stock Purchase Plan Shares and Other | 15 | 17 | 17 | 25 | |||||||||||||||||||
| Dilutive Effect of Potential Common Shares | 365 | 164 | 308 | 185 | |||||||||||||||||||
| Weighted Average Common Shares Outstanding – Diluted | 41,869 | 41,078 | 41,795 | 40,733 | |||||||||||||||||||
OTP Land Easements
OTP has commitments to make future payments for land easements not classified as leases, extending into 2034fair value recorded in the consolidated statements of approximately $9.7 million.
Transmission Obligation
In September 2020, in connection with Merricourt andincome. However, in accordance with rate-making and cost recovery processes, we recognize a regulatory asset or liability to defer losses or gains from derivative activity until settlement of the Merricourt amended and restated generator interconnection agreement,associated derivative instrument.
consolidated balance sheets.
OTP hadThe following tables present our assets measured at fair value on a $2.8 million refund liability on its balance sheetrecurring basis as of September 30, 2020. This represents its best estimate2021 and December 31, 2020 classified by the input method used to measure fair value:Level 1 Level 2 Level 3 September 30, 2021 Investments: Money Market Funds $ 953 $ — $ — Mutual Funds 5,170 — — Corporate Debt Securities — 2,377 — Government-Backed and Government-Sponsored Enterprises’ Debt Securities — 6,831 — Derivative Instruments — 6,923 — Total Assets $ 6,123 $ 16,131 $ — December 31, 2020 Investments: Money Market Funds $ 4,075 $ — $ — Mutual Funds 1,662 — — Corporate Debt Securities — 2,627 — Government-Backed and Government-Sponsored Enterprises’ Debt Securities — 6,633 — Total Assets $ 5,737 $ 9,260 $ —
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 estimating the amount of potential loss.
On July 30, 2020 the MPUC ordered a reductionnot recorded at fair value in the remaining depreciable lives of OTP’s Hoot Lake Plant and seven hydroelectric plants. The MPUC stipulated recoverabilityconsolidated balance sheets but for which disclosure of the resulting increase in depreciation expense, which we estimate will be approximately $1.4 million on an annual basis, would be determined in OTP’s next rate case. Based onfair value of these financial instruments is provided. The following reflects the relevant factscarrying value and circumstances, OTP has concluded the additional depreciation expense is probableestimated fair value of recoverythese assets and has recognized a regulatory asset for the amountliabilities as of incremental expense recognized in 2020.
State implementation of pollution control plans to improve visibilitySeptember 30, 2021 and air quality at national parks under the EPA’s Regional Haze Rule (RHR) could require OTP to incur significant new costs, which could, dependent on determinations by state regulatory commissions on approval to recover such costs from customers, negatively impact OTP’s and the Company’s net income, financial position and cash flows. The North Dakota Department of Environmental Quality (NDDEQ) must submit a state implementation plan to the EPA by July 2021. While this process is still in the early stages, if the NDDEQ and/or the EPA requires sources subject to RHR Round 2 reasonable progress determinations, including Coyote Station, to undertake emissions control measures that are reasonably consistent with those required of sources during Round 1, OTP anticipates that significant emissions controls would be required at Coyote Station by December 31, 2028. In light of the costs for emissions control equipment, there are scenarios where it may not be economically feasible to invest in such equipment and an early retirement of the Coyote Station would therefore be necessary. The costs related to an early retirement of Coyote Station would be material to OTP and the Company and would be subject to state commission approval for recovery from customers.
In October 2020, during testing and commissioning of Merricourt, a defect in a turbine blade was identified. The Company is investigating the defect along with additional blades to determine if other blades have similar defects. Depending on the extent of the defect and repair and replacement alternatives, the date of commercial operation of the project, or a portion thereof, may be delayed beyond December 2020. The cost of the project could also be impacted, but the risk of loss on assets of the project only transfers to Otter Tail Power Company at commercial operation. Considering this along with the commercial and contractual provisions in place, the Company does not anticipate this issue will have a material financial impact on the Company.
| September 30, 2021 | December 31, 2020 | ||||||||||||||||||||||
| (in thousands) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Cash and Cash Equivalents | $ | 1,272 | $ | 1,272 | $ | 1,163 | $ | 1,163 | |||||||||||||||
| Total | 1,272 | 1,272 | 1,163 | 1,163 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||
| Short-Term Debt | 97,857 | 97,857 | 80,997 | 80,997 | |||||||||||||||||||
| Long-Term Debt | 764,581 | 873,632 | 764,519 | 858,455 | |||||||||||||||||||
| Total | $ | 862,438 | $ | 971,489 | $ | 845,516 | $ | 939,452 | |||||||||||||||
Other
The Company is a party to litigation and regulatory enforcement matters arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of September 30, 2020, other than those relating to the RHR, will not be material.
10. Short-Term and Long-Term Borrowings
The following table presents the status of the Company’s lines of credit as of September 30, 2020 and December 31, 2019:
(in thousands) | Line Limit | In Use on September 30, 2020 | Restricted due to Outstanding Letters of Credit | Available on September 30, 2020 | Available on December 31, 2019 | |||||||||||||||
Otter Tail Corporation Credit Agreement | $ | 170,000 | $ | 48,600 | $ | 0 | $ | 121,400 | $ | 164,000 | ||||||||||
OTP Credit Agreement | 170,000 | 0 | 7,670 | 162,330 | 154,524 | |||||||||||||||
Total | $ | 340,000 | $ | 48,600 | $ | 7,670 | $ | 283,730 | $ | 318,524 | ||||||||||
Long-Term Debt Issuances
2019 Note Purchase Agreement
On September 12, 2019, OTP entered into a Note Purchase Agreement (the 2019 Note Purchase Agreement) with the purchasers named therein (the Purchasers), pursuant to which OTP agreed to issue to the Purchasers, in a private placement transaction, $175 million aggregate principal amount of OTP’s senior unsecured notes consisting of (a) $10,000,000 aggregate principal amount of its 3.07% Series 2019A Senior Unsecured Notes due October 10, 2029 (the Series 2019A Notes), (b) $26,000,000 aggregate principal amount of its 3.52% Series 2019B Senior Unsecured Notes due October 10, 2039 (the Series 2019B Notes), (c) $64,000,000 aggregate principal amount of its 3.82% Series 2019C Senior Unsecured Notes due October 10, 2049 (the Series 2019C Notes), (d) $10,000,000 aggregate principal amount of its 3.22% Series 2020A Senior Unsecured Notes due February 25, 2030 (the Series 2020A Notes), (e) $40,000,000 aggregate principal amount of its 3.22% Series 2020B Senior Unsecured Notes due August 20, 2030 (the Series 2020B Notes), (f) $10,000,000 aggregate principal amount of its 3.62% Series 2020C Senior Unsecured Notes due February 25, 2040 (the Series 2020C Notes) and (g) $15,000,000 aggregate principal amount of its 3.92% Series 2020D Senior Unsecured Notes due February 25, 2050 (the Series 2020D Notes; and together with the Series 2019A Notes, the Series 2019B Notes, the Series 2019C Notes, the Series 2020A Notes, the Series 2020B Notes and the Series 2020C Notes, the Notes).
On February 25, 2020, OTP issued the Series 2020A Notes, the Series 2020C Notes and the Series 2020D Notes pursuant to the 2019 Note Purchase Agreement. On August 20, 2020, OTP issued the Series 2020B Notes pursuant to the 2019 Note Purchase Agreement. OTP used the $75 million proceeds from the issuances to pay for capital expenditures and for other corporate purposes. The Series 2019A Notes, Series 2019B Notes and Series 2019C Notes were issued by the Company on October 10, 2019.
OTP may prepay all or any part of the Notes (in an amount not less than 10% of the aggregate principal amount of the Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount so prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the 2019 Note Purchase Agreement, any prepayment made by OTP of all of the (a) Series 2020A Notes then outstanding on or after August 25,2029, (b) Series 2020C Notes then outstanding on or after August 25, 2039 or (c) Series 2020D Notes then outstanding on or after August 25, 2049 will be made without any make-whole amount. The 2019 Note Purchase Agreement also requires OTP to offer to prepay all outstanding Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2019 Note Purchase Agreement) of OTP.
The 2019 Note Purchase Agreement contains a number of restrictions on the business of OTP. These include restrictions on OTP’s abilities to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The 2019 Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants. Specifically, OTP may not permit its Interest-bearing Debt (as defined in the 2019 Note Purchase Agreement) to exceed 60% of Total Capitalization (as defined in the 2019 Note Purchase Agreement), determined as of the end of each fiscal quarter. OTP is also restricted from allowing its Priority Indebtedness (as defined in the Note Purchase Agreement) to exceed 20% of Total Capitalization, determined as of the end of each fiscal quarter. The 2019 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. The 2019 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event OTP’s existing credit agreement or any renewal, extension or replacement thereof, at any time contains any financial covenant or other provision providing for limitations on interest
expense and such a covenant is not contained in the 2019 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the Notes than any analogous provision contained in the 2019 Note Purchase Agreement (an Additional Covenant), then unless waived by the Required Holders (as defined in the 2019 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2019 Note Purchase Agreement. The 2019 Note Purchase Agreement also provides for the amendment, modification or deletion of an Additional Covenant if such Additional Covenant is amended or modified under or deleted from the credit agreement, provided that no default or event of default has occurred and is continuing.
The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of September 30, 2020 and December 31, 2019:
September 30, 2020 (in thousands) | OTP | Otter Tail Corporation | Consolidated | |||||||||
Short-Term Debt | $ | - | $ | 48,600 | $ | 48,600 | ||||||
Long-Term Debt: | ||||||||||||
3.55% Guaranteed Senior Notes, due December 15, 2026 | $ | 80,000 | $ | 80,000 | ||||||||
Senior Unsecured Notes 4.63%, Series 2011A, due December 1, 2021 | $ | 140,000 | 140,000 | |||||||||
Senior Unsecured Notes 6.15%, Series 2007B, due August 20, 2022 | 30,000 | 30,000 | ||||||||||
Senior Unsecured Notes 6.37%, Series 2007C, due August 20, 2027 | 42,000 | 42,000 | ||||||||||
Senior Unsecured Notes 4.68%, Series 2013A, due February 27, 2029 | 60,000 | 60,000 | ||||||||||
Senior Unsecured Notes 3.07%, Series 2019A, due October 10, 20291 | 10,000 | 10,000 | ||||||||||
Senior Unsecured Notes 3.22%, Series 2020A, due February 25, 2030 | 10,000 | 10,000 | ||||||||||
Senior Unsecured Notes 3.22%, Series 2020B, due August 20, 20301 | 40,000 | 40,000 | ||||||||||
Senior Unsecured Notes 6.47%, Series 2007D, due August 20, 2037 | 50,000 | 50,000 | ||||||||||
Senior Unsecured Notes 3.52%, Series 2019B, due October 10, 2039 | 26,000 | 26,000 | ||||||||||
Senior Unsecured Notes 3.62%. Series 2020C, due February 25, 2040 | 10,000 | 10,000 | ||||||||||
Senior Unsecured Notes 5.47%, Series 2013B, due February 27, 2044 | 90,000 | 90,000 | ||||||||||
Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 | 100,000 | 100,000 | ||||||||||
Senior Unsecured Notes 3.82%, Series 2019C, due October 10, 2049 | 64,000 | 64,000 | ||||||||||
Senior Unsecured Notes 3.92%, Series 2020D, due February 25, 2050 | 15,000 | 15,000 | ||||||||||
PACE Note, 2.54%, due March 18, 2021 | 215 | 215 | ||||||||||
Total | $ | 687,000 | $ | 80,215 | $ | 767,215 | ||||||
Less: Current Maturities net of Unamortized Debt Issuance Costs | - | 215 | 215 | |||||||||
Unamortized Long-Term Debt Issuance Costs | 2,408 | 318 | 2,726 | |||||||||
Total Long-Term Debt net of Unamortized Debt Issuance Costs | $ | 684,592 | $ | 79,682 | $ | 764,274 | ||||||
Total Short-Term and Long-Term Debt (with current maturities) | $ | 684,592 | $ | 128,497 | $ | 813,089 | ||||||
December 31, 2019 (in thousands) | ||||||||||||
Short-Term Debt | $ | - | $ | 6,000 | $ | 6,000 | ||||||
Long-Term Debt: | ||||||||||||
3.55% Guaranteed Senior Notes, due December 15, 2026 | $ | 80,000 | $ | 80,000 | ||||||||
Senior Unsecured Notes 4.63%, Series 2011A, due December 1, 2021 | $ | 140,000 | 140,000 | |||||||||
Senior Unsecured Notes 6.15%, Series 2007B, due August 20, 2022 | 30,000 | 30,000 | ||||||||||
Senior Unsecured Notes 6.37%, Series 2007C, due August 20, 2027 | 42,000 | 42,000 | ||||||||||
Senior Unsecured Notes 4.68%, Series 2013A, due February 27, 2029 | 60,000 | 60,000 | ||||||||||
Senior Unsecured Notes 3.07%, Series 2019A, due October 10, 20291 | 10,000 | 10,000 | ||||||||||
Senior Unsecured Notes 6.47%, Series 2007D, due August 20, 2037 | 50,000 | 50,000 | ||||||||||
Senior Unsecured Notes 3.52%, Series 2019B, due October 10, 2039 | 26,000 | 26,000 | ||||||||||
Senior Unsecured Notes 5.47%, Series 2013B, due February 27, 2044 | 90,000 | 90,000 | ||||||||||
Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 | 100,000 | 100,000 | ||||||||||
Senior Unsecured Notes 3.82%, Series 2019C, due October 10, 2049 | 64,000 | 64,000 | ||||||||||
PACE Note, 2.54%, due March 18, 2021 | 351 | 351 | ||||||||||
Total | $ | 612,000 | $ | 80,351 | $ | 692,351 | ||||||
Less: Current Maturities net of Unamortized Debt Issuance Costs | - | 183 | 183 | |||||||||
Unamortized Long-Term Debt Issuance Costs | 2,231 | 356 | 2,587 | |||||||||
Total Long-Term Debt net of Unamortized Debt Issuance Costs | $ | 609,769 | $ | 79,812 | $ | 689,581 | ||||||
Total Short-Term and Long-Term Debt (with current maturities) | $ | 609,769 | $ | 85,995 | $ | 695,764 |
| |||||
|
11. Pension Plan and Other Postretirement Benefits
Pension Plan—Components of net periodic pension benefit cost of the Company's noncontributory funded pension plan are as follows:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
(in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||
Service Cost—Benefit Earned During the Period | $ | 1,655 | $ | 1,373 | $ | 4,966 | $ | 4,119 | ||||||||
Interest Cost on Projected Benefit Obligation | 3,264 | 3,603 | 9,790 | 10,809 | ||||||||||||
Expected Return on Assets | (5,506 | ) | (5,324 | ) | (16,516 | ) | (15,973 | ) | ||||||||
Amortization of Prior-Service Cost: | ||||||||||||||||
From Regulatory Asset | 0 | 1 | 0 | 4 | ||||||||||||
From Other Comprehensive Income1 | 0 | 2 | 0 | 6 | ||||||||||||
Amortization of Net Actuarial Loss: | ||||||||||||||||
From Regulatory Asset | 2,231 | 1,163 | 6,693 | 3,488 | ||||||||||||
From Other Comprehensive Income1 | 55 | 26 | 165 | 79 | ||||||||||||
Net Periodic Pension Cost2 | $ | 1,699 | $ | 844 | $ | 5,098 | $ | 2,532 | ||||||||
1Corporate cost included in nonservice cost components of postretirement benefits. | ||||||||||||||||
2Allocation of costs: | ||||||||||||||||
Service costs included in OTP capital expenditures | $ | 516 | $ | 333 | $ | 1,371 | $ | 1,059 | ||||||||
Service costs included in electric operation and maintenance expenses | 1,099 | 1,007 | 3,476 | 2,961 | ||||||||||||
Service costs included in other nonelectric expenses | 40 | 33 | 119 | 99 | ||||||||||||
Nonservice costs capitalized as regulatory assets | 13 | (128 | ) | 36 | (408 | ) | ||||||||||
Nonservice costs included in nonservice cost components of postretirement benefits | 31 | (401 | ) | 96 | (1,179 | ) | ||||||||||
Cash flows—The Company had no minimum funding requirement as of December 31, 2019 but made a discretionary plan contribution of $11.2 million in January 2020.
Executive Survivor and Supplemental Retirement Plan—Components of net periodic pension benefit cost of the Company’s unfunded, nonqualified benefit plan for executive officers and certain key management employees are as follows:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
(in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||
Service Cost—Benefit Earned During the Period | $ | 45 | $ | 104 | $ | 134 | $ | 313 | ||||||||
Interest Cost on Projected Benefit Obligation | 362 | 433 | 1,086 | 1,301 | ||||||||||||
Amortization of Prior Service Cost: | ||||||||||||||||
From Regulatory Asset | 0 | 2 | 0 | 4 | ||||||||||||
From Other Comprehensive Income1 | 0 | 4 | 0 | 12 | ||||||||||||
Amortization of Net Actuarial Loss: | ||||||||||||||||
From Regulatory Asset | 24 | 31 | 71 | 93 | ||||||||||||
From Other Comprehensive Income1 | 85 | 87 | 256 | 262 | ||||||||||||
Net Periodic Pension Cost2 | $ | 516 | $ | 661 | $ | 1,547 | $ | 1,985 | ||||||||
1Amortization of prior service costs and net actuarial losses from other comprehensive income are included in nonservice cost components of postretirement benefits. | ||||||||||||||||
2Allocation of Costs: | ||||||||||||||||
Service costs included in electric operation and maintenance expenses | $ | 0 | $ | 26 | $ | 0 | $ | 78 | ||||||||
Service costs included in other nonelectric expenses | 45 | 78 | 134 | 235 | ||||||||||||
Nonservice costs included in nonservice cost components of postretirement benefits | 471 | 557 | 1,413 | 1,672 | ||||||||||||
Other Postretirement Benefits—Components of net periodic postretirement benefit cost for health insurance benefits for retired OTP and corporate employees, net of the effect of Medicare Part D Subsidy:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
(in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||
Service Cost—Benefit Earned During the Period | $ | 461 | $ | 321 | $ | 1,385 | $ | 964 | ||||||||
Interest Cost on Projected Benefit Obligation | 598 | 770 | 1,795 | 2,312 | ||||||||||||
Amortization of Prior-Service Cost: | ||||||||||||||||
From Regulatory Asset | (1,169 | ) | 0 | (3,508 | ) | 0 | ||||||||||
From Other Comprehensive Income1 | (28 | ) | 0 | (86 | ) | 0 | ||||||||||
Amortization of Net Actuarial Loss: | ||||||||||||||||
From Regulatory Asset | 1,051 | 393 | 3,154 | 1,178 | ||||||||||||
From Other Comprehensive Income1 | 26 | 10 | 78 | 29 | ||||||||||||
Net Periodic Postretirement Benefit Cost2 | $ | 939 | $ | 1,494 | $ | 2,818 | $ | 4,483 | ||||||||
Effect of Medicare Part D Subsidy | $ | 281 | $ | (45 | ) | $ | 842 | $ | (134 | ) | ||||||
1Corporate cost included in nonservice cost components of postretirement benefits. | ||||||||||||||||
2Allocation of Costs: | ||||||||||||||||
Service costs included in OTP capital expenditures | $ | 144 | $ | 78 | $ | 382 | $ | 248 | ||||||||
Service costs included in electric operation and maintenance expenses | 306 | 235 | 970 | 693 | ||||||||||||
Service costs included in other nonelectric expenses | 11 | 8 | 33 | 23 | ||||||||||||
Nonservice costs capitalized as regulatory assets | 150 | 284 | 396 | 905 | ||||||||||||
Nonservice costs included in nonservice cost components of postretirement benefits | 328 | 889 | 1,037 | 2,614 | ||||||||||||
12. Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
reset frequently, a Level 2 fair value input.
| ITEM 2. | MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | ||||
September 30, 2020 | December 31, 2019 | |||||||||||||||
(in thousands) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Cash and Cash Equivalents | $ | 44,904 | $ | 44,904 | $ | 21,199 | $ | 21,199 | ||||||||
Short-Term Debt | (48,600 | ) | (48,600 | ) | (6,000 | ) | (6,000 | ) | ||||||||
Long-Term Debt including Current Maturities | (764,489 | ) | (867,972 | ) | (689,764 | ) | (742,279 | ) | ||||||||
13. Property, Plant and Equipment
No update required for interim reporting period.
14. Income Tax Expense
The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income before income taxes and income tax expense reported on the Company’s consolidated statements of income for the three- and nine-month periodsyear ended September 30, 2020 and 2019:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
(in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||
Income Before Income Taxes | $ | 45,031 | $ | 29,681 | $ | 95,726 | $ | 80,402 | ||||||||
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) | $ | 11,708 | $ | 7,717 | $ | 24,889 | $ | 20,905 | ||||||||
(Decreases) Increases in Tax from: | ||||||||||||||||
Differences Reversing in Excess of Federal Rates | (1,678 | ) | (933 | ) | (3,450 | ) | (2,690 | ) | ||||||||
Allowance for Funds Used During Construction – Equity | (388 | ) | (239 | ) | (948 | ) | (419 | ) | ||||||||
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes | (259 | ) | (258 | ) | (775 | ) | (774 | ) | ||||||||
Research and Development and Other Tax Credits | (263 | ) | (612 | ) | (649 | ) | (987 | ) | ||||||||
Excess Tax Deduction – Equity Method Stock Awards | 0 | 0 | (535 | ) | (827 | ) | ||||||||||
Corporate Owned Life Insurance | (155 | ) | (50 | ) | (141 | ) | (609 | ) | ||||||||
Reconciliation and Prior Period Adjustments | 172 | (688 | ) | 172 | (722 | ) | ||||||||||
Other Items – Net | (40 | ) | (1 | ) | (20 | ) | 30 | |||||||||
Income Tax Expense | $ | 9,097 | $ | 4,936 | $ | 18,543 | $ | 13,907 | ||||||||
Effective Income Tax Rate | 20.2 | % | 16.6 | % | 19.4 | % | 17.3 | % | ||||||||
The following table summarizes the activity related to the Company’s unrecognized tax benefits:
(in thousands) | 2020 | 2019 | ||||||
Balance on January 1 | $ | 1,488 | $ | 1,282 | ||||
(Decreases) Increases Related to Tax Positions for Prior Years | (27 | ) | 37 | |||||
Increases Related to Tax Positions for Current Year | 123 | 153 | ||||||
Uncertain Positions Resolved During Year | (586 | ) | 0 | |||||
Decrease from the Expiration of Statute of Limitations | (139 | ) | (170 | ) | ||||
Balance on September 30 | $ | 859 | $ | 1,302 | ||||
The balance of unrecognized tax benefits as of September 30, 2020 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of September 30, 2020 could be reduced by as much as $139,000 within the next 12 months due to expected settlement. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes in its consolidated statement of income.
The CompanyDecember 31, 2020.
Item 2. Management's Discussioncustom machine parts and Analysis of Financial Conditionmetal components and Results of Operations
COVID-19
Otter Tail Corporation (the Company, we, usmanufactures extruded and our) continuesthermoformed plastic products. Our Plastics segment manufactures PVC pipe for use in, among other applications, municipal and rural water, wastewater, and water reclamation projects.
March 2020, COVID-19 and the resulting economic conditions have had a material negative impact on thenegatively impacted operating results of operations in our Manufacturing segment as customer demand declined significantly in the second quarter of 2020. Sales volumes strengthened in the third and fourth quarters of 2020 due to a lesser extent, also impacted the results of operations of ourstrong recreational vehicle and lawn and garden end-market demand. Our Electric and Plastics segments but have not had a material impact on our consolidated financial position or liquidity. We saw a reductionoperating results were also impacted in customer demand in our Manufacturing segment in late March 2020 and experienced significantly lower levels of customer demand in our Manufacturing segment through the end of June 2020 but began to see some recovery in demand in the third quarter of 2020. A moderate level of reduced demand may continue in our Manufacturing segment over the near term. Within our Electric segment, we have experienced reduced demand from commercial and industrial customers.customers and increased costs for bad debts. In our Plastics segment, we experienced lower sales volumes in the second quarter of 2020 as distributors of our products reduced inventory levels given the uncertainty of the potential impact of COVID-19. Sales volumes recovered and gross profit margins increased in the third and fourth quarters of 2020, and have continued to increase in 2021, due to uncertainty over theincreased demand and supply disruptions.
Beginning in April 2020, in response to the actualexpanding gross profit margins and anticipated impact of COVID-19 on our business operations, we implemented a variety of policies, including furloughs, shift and pay reductions, wage and hiring freezes, suspension of certain employee benefits, a workforce reduction and other cost reduction efforts to mitigate the negative impact to our financial results. We continue to monitor the impacts of the pandemic on our businesses and will adjust our response as circumstances evolve.
Financial And OTHER metrics USED IN THE FOLLOWING DISCUSSION
Heating Degree Days (HDDs) is a measure of how much (in degrees), and for how long (in days), the outside air temperature was below a certain normalized level. This measure is commonly used in calculations relating to the energy consumption required to heat buildings.
Cooling Degree Days (CDDs) is a measure of how much (in degrees), and for how long (in days), the outside air temperature was above a certain normalized level. This measure is commonly used in calculations relating to the energy consumption required to cool buildings.
Otter Tail Power Company (OTP) generally bases its forecasted kilowatt-hour (kwh) sales and rates on expected consumption under a normal level of HDDs and CDDs over a given period of time in its service territory. Increased or decreased levels of consumption for certain customer classifications are attributed to deviation from the norms and are a significant factor influencing consumptionincrease in net earnings in our Plastics segment. We anticipate these market dynamics will persist through the remainder of electricity across our service territory.2021 and continue during the first half of 2022. We present HDDs and CDDscurrently expect these conditions to provide an indication of the impact of weather on kwh sales, revenues and earnings relative to forecast and on period-to-period results.
Backlog, expressed in dollars, is the level of sales orders received but not yet completed by a company or operating segment. The Company discloses these figures for its Manufacturing segment as an indication of future business volume within the segment.
Utility Rate Base is the value of property on which a public utility is permitted to earn a specified rate of return in accordance with rules set by a regulatory agency. In general, the rate base consists of the value of property used by the utility in providing service. Rate base can include: cash, working capital, materials and supplies, deductions for accumulated provisions for depreciation, contributions in aid of construction, customer advances for construction, accumulated deferred income taxes, and accumulated deferred investment tax credits, dependent on the method that is usedsubside beginning in the calculation,second half of 2022.
Intersegment Eliminations (in thousands) September 30, 2020 September 30, 2019 Operating Revenues: Electric Nonelectric Costs of Products Sold Other Nonelectric Expenses Three Months Ended September 30, % (in thousands) 2020 2019 Change Change Retail Sales Revenues from Contracts with Customers Changes in Accrued Revenues under Alternative Revenue Programs Total Retail Sales Revenue Transmission Services Revenue Wholesale Revenues – Company Generation Other Revenues Total Operating Revenues Production Fuel Purchased Power – System Use Electric Operation and Maintenance Expenses Depreciation and Amortization Property Taxes Operating Income Electric Megawatt-hour (mwh) Sales Retail mwh Sales Wholesale mwh Sales – Company Generation HDDs CDDs cooling. The following table shows heating and cooling degree days as a percent of Three Months ended September 30, 2020 2019 HDDs CDDsResultsOperationsFollowing is an analysis of the Company’sour operating results by business segment for the three and nine months ended September 30, 2020 and 2019on a consolidated basis followed by a discussion of changes inthe operating results of each of our segments: Electric, Manufacturing and Plastics. In addition to the segment results, we provide an overview of our Corporate costs. Our Corporate costs do not constitute a reportable segment but rather consist of unallocated general corporate expenses, such as corporate staff and overhead costs, the results of our captive insurance company and other items excluded from the measurement of segment performance. Corporate costs are added to operating segment totals to reconcile to totals on our consolidated financial position during the nine months ended September 30,statements of income.our business outlook for the remainderamounted to less than $0.1 million of 2020.Comparison of the Three Months Ended September 30, 2020 and 2019Consolidated operating revenues were $235.8 millionand operating expenses for each period.(in thousands) 2021 2020 $ change % change Operating Revenues $ 316,294 $ 235,755 $ 80,539 34.2 % Operating Expenses 241,766 183,026 58,740 32.1 Operating Income 74,528 52,729 21,799 41.3 Interest Charges 9,648 8,568 1,080 12.6 Nonservice Cost Components of Postretirement Benefits 505 842 (337) (40.0) Other Income 203 1,712 (1,509) (88.1) Income Before Income Taxes 64,578 45,031 19,547 43.4 Income Tax Expense 11,824 9,097 2,727 30.0 Net Income $ 52,754 $ 35,934 $ 16,820 46.8 % with $228.7to 2020 and a decrease in capitalized interest in 2021 following the completion and placement in service of Astoria Station in the first quarter of 2021.2019. Operating income was $52.7 million2021 and 2020:(in thousands) 2021 2020 $ change % change Retail Revenues $ 96,438 $ 99,605 $ (3,167) (3.2) % Transmission Services Revenues 13,300 12,288 1,012 8.2 Wholesale Revenues 6,944 1,500 5,444 362.9 Other Electric Revenues 2,093 1,830 263 14.4 Total Operating Revenues 118,775 115,223 3,552 3.1 Production Fuel 17,698 11,554 6,144 53.2 Purchased Power 9,878 13,428 (3,550) (26.4) Operating and Maintenance Expenses 36,465 32,845 3,620 11.0 Depreciation and Amortization 17,874 15,647 2,227 14.2 Property Taxes 4,474 4,333 141 3.3 Operating Income $ 32,386 $ 37,416 $ (5,030) (13.4) % 2021 2020 change % change Retail kwh Sales 1,076,580 1,075,336 1,244 0.1 % Wholesale kwh Sales – Company Generation 174,187 75,884 98,303 129.5 Heating Degree Days 3 61 (58) (95.1) Cooling Degree Days 463 363 100 27.5 the three months ended September 30, 2020 compared with $37.3 millionelectricity for the three months ended September 30, 2019. The Company recorded diluted earnings per share of $0.87 for the three months ended September 30, 2020 compared with $0.62 for the three months ended September 30, 2019.Amounts presented in the segment tables that follow for operating revenues, cost of products soldheating and other nonelectric operating expenses for the three-month periods ended September 30, 2020 and 2019 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below: $ 10 $ 9 -- -- 3 5 7 4 Electric $ 96,827 $ 100,345 $ (3,518 ) (3.5 ) 2,778 (921 ) 3,699 401.6 $ 99,605 $ 99,424 $ 181 0.2 12,288 11,692 596 5.1 1,500 1,631 (131 ) (8.0 ) 1,830 1,626 204 12.5 $ 115,223 $ 114,373 $ 850 0.7 11,554 18,331 (6,777 ) (37.0 ) 13,428 13,163 265 2.0 32,845 35,869 (3,024 ) (8.4 ) 15,647 15,198 449 3.0 4,333 3,965 368 9.3 $ 37,416 $ 27,847 9,569 34.4 1,075,336 1,091,427 (16,091 ) (1.5 ) 75,884 71,506 4,378 6.1 61 42 19 45.2 363 288 75 26.0 normal: 115.1 % 76.4 % 104.6 % 83.0 % 2021 2020 Heating Degree Days 5.8 % 115.1 % Cooling Degree Days 132.7 % 104.6 % 35
The following table summarizes the estimated effect on diluted earnings per share of the difference in retail kwh sales under actual weather conditions and expected retail kwh sales under normal weather conditions in 2021 and 2020, and between years.
2021 vs Normal | 2021 vs 2020 | 2020 vs Normal | |||||||||||||||
| Effect on Diluted Earnings Per Share | $ | 0.03 | $ | 0.02 | $ | 0.01 | |||||||||||
2020 vs Normal | 2019 vs Normal | 2020 vs 2019 | ||||||||||
Effect on Diluted Earnings Per Share | $ | 0.01 | $ | (0.02 | ) | $ | 0.03 | |||||
The $0.2commercial and industrial customers, exclusive of the impact of weather, net of the effect of a change in customer usage mix.
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These increases in revenue were mostly offset by:
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Transmission services revenuewholesale prices driven by increased $0.6fuel costs and market demand for wholesale energy.
Production fuel costs decreased $6.8 million due to a 24.0% decrease in kwhs generated from our fuel-burning plants due to higher demand and a 21.7% decreasefavorable prices for energy in wholesale markets. In addition, increased fuel cost per kwh of generation, weighted heavily byalso contributed to higher production fuel costs per kwh of generation at Coyote Station in the third quarter of 2019. Coyote Station was down for maintenance2021.
The cost2021.
| (in thousands) | 2021 | 2020 | $ change | % change | |||||||||||||||||||
| Operating Revenues | $ | 89,977 | $ | 59,849 | $ | 30,128 | 50.3 | % | |||||||||||||||
| Cost of Products Sold (excluding depreciation) | 70,148 | 44,444 | 25,704 | 57.8 | |||||||||||||||||||
| Other Operating Expenses | 10,161 | 6,901 | 3,260 | 47.2 | |||||||||||||||||||
| Depreciation and Amortization | 3,794 | 3,759 | 35 | 0.9 | |||||||||||||||||||
| Operating Income | $ | 5,874 | $ | 4,745 | $ | 1,129 | 23.8 | % | |||||||||||||||
Electric operating and maintenance expense decreased $3.0 million, including:
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These decreases in expense were partially offset by:
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Property tax expense increased $0.4 million due to property additions and increased jurisdictional valuations.
Depreciation expense increased $0.4 million mainly due to 2019 capital additions for generation and transmission plant.
Manufacturing
Three Months Ended | ||||||||||||||||
September 30, | % | |||||||||||||||
(in thousands) | 2020 | 2019 | Change | Change | ||||||||||||
Operating Revenues | $ | 59,849 | $ | 65,722 | $ | (5,873 | ) | (8.9 | ) | |||||||
Cost of Products Sold | 44,444 | 51,399 | (6,955 | ) | (13.5 | ) | ||||||||||
Operating Expenses | 6,901 | 6,846 | 55 | 0.8 | ||||||||||||
Depreciation and Amortization | 3,759 | 3,505 | 254 | 7.2 | ||||||||||||
Operating Income | $ | 4,745 | $ | 3,972 | $ | 773 | 19.5 | |||||||||
The $5.9 million decrease in revenues in our Manufacturing segment includes the following:
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The $7.0 million decrease in cost of products sold in our Manufacturing segment includes the following:
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Other Operating Expenses increased $3.3 million |
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Plastics
Three Months Ended | ||||||||||||||||
September 30, | % | |||||||||||||||
(in thousands) | 2020 | 2019 | Change | Change | ||||||||||||
Operating Revenues | $ | 60,693 | $ | 48,566 | $ | 12,127 | 25.0 | |||||||||
Cost of Products Sold | 42,415 | 37,353 | 5,062 | 13.6 | ||||||||||||
Operating Expenses | 3,250 | 2,872 | 378 | 13.2 | ||||||||||||
Depreciation and Amortization | 905 | 865 | 40 | 4.6 | ||||||||||||
Operating Income | $ | 14,123 | $ | 7,476 | $ | 6,647 | 88.9 | |||||||||
Plastics segment revenues and operating income increased $12.1 million and $6.6 million, respectively, primarily due to a 21.2% increase in pounds of polyvinyl chloride (PVC) pipe sold driven by distributors rebuilding inventory in the third quarter of 2020 after reducing inventory levels2021 compared to 2020. In the third quarter of 2021 other operating expenses were impacted by increased incentive based compensation and other costs necessary to support higher business volumes.
| (in thousands) | 2021 | 2020 | $ change | % change | |||||||||||||||||||
| Operating Revenues | $ | 107,542 | $ | 60,693 | $ | 46,849 | 77.2 | % | |||||||||||||||
| Cost of Products Sold (excluding depreciation) | 64,064 | 42,415 | 21,649 | 51.0 | |||||||||||||||||||
| Other Operating Expenses | 3,832 | 3,250 | 582 | 17.9 | |||||||||||||||||||
| Depreciation and Amortization | 1,099 | 905 | 194 | 21.4 | |||||||||||||||||||
| Operating Income | $ | 38,547 | $ | 14,123 | $ | 24,424 | 172.9 | % | |||||||||||||||
Corporate includes items such increased $0.6 million as corporate staff and overhead costs, the resultsa result of our captive insurance company and other items excluded from the measurement of operating segment performance. Corporate is not an operating segment. Rather it is added to operating segment totals to reconcile to totals on our consolidated statements of income.
Three Months Ended | ||||||||||||||||
September 30, | % | |||||||||||||||
(in thousands) | 2020 | 2019 | Change | Change | ||||||||||||
Operating Expenses | $ | 3,471 | $ | 1,951 | $ | 1,520 | 77.9 | |||||||||
Depreciation and Amortization | 84 | 89 | (5 | ) | (5.6 | ) | ||||||||||
The $1.5 million increase in corporate operating expenses is mainly due to an increase in performance incentive accruals driven by improved quarter-over-quarter results.
Interest Charges
Interest chargesvariable costs associated with the increased to $8.6 millionfinancial results in 2021.
| (in thousands) | 2021 | 2020 | $ change | % change | |||||||||||||||||||
| Other Operating Expenses | $ | 2,231 | $ | 3,471 | $ | (1,240) | (35.7) | % | |||||||||||||||
| Depreciation and Amortization | 48 | 84 | (36) | (42.9) | |||||||||||||||||||
| Operating Loss | $ | 2,279 | $ | 3,555 | $ | (1,276) | (35.9) | % | |||||||||||||||
| RESULTS OF OPERATIONS – YEAR TO DATE | |||||
Other Income
Other income increased to $1.7 million in the three months ended September 30, 2020 from $1.0 million in the three months ended September 30, 2019. The $0.7 million increase in other income includes:
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Income Tax Expense
Income tax expense increased $4.2 million in the three months ended September 30, 2020 compared with the three months ended September 30, 2019, mainly due to the tax effect of a $15.3 million increase in income before income taxes. operating revenues and operating expenses for each period.
Three Months Ended September 30, | ||||||||
(in thousands) | 2020 | 2019 | ||||||
Income Before Income Taxes | $ | 45,031 | $ | 29,681 | ||||
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) | $ | 11,708 | $ | 7,717 | ||||
(Decreases) Increases in Tax from: | ||||||||
Differences Reversing in Excess of Federal Rates | (1,678 | ) | (933 | ) | ||||
Allowance for Funds Used During Construction – Equity | (388 | ) | (239 | ) | ||||
Research and Development and Other Tax Credits | (263 | ) | (612 | ) | ||||
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes | (259 | ) | (258 | ) | ||||
Corporate Owned Life Insurance | (155 | ) | (50 | ) | ||||
Reconciliation and Prior Period Adjustments | 172 | (688 | ) | |||||
Other Items – Net | (40 | ) | (1 | ) | ||||
Income Tax Expense | $ | 9,097 | $ | 4,936 | ||||
Effective Income Tax Rate | 20.2 | % | 16.6 | % | ||||
Comparison of the Nine Months Ended September 30, 2020 and 2019
Consolidated operating revenues were $663.3 millionresults for the nine months ended September 30, 2021 and 2020:
| (in thousands) | 2021 | 2020 | $ change | % change | |||||||||||||||||||
| Operating Revenues | $ | 863,612 | $ | 663,258 | $ | 200,354 | 30.2 | % | |||||||||||||||
| Operating Expenses | 685,063 | 543,331 | 141,732 | 26.1 | |||||||||||||||||||
| Operating Income | 178,549 | 119,927 | 58,622 | 48.9 | |||||||||||||||||||
| Interest Charges | 28,601 | 25,353 | 3,248 | 12.8 | |||||||||||||||||||
| Nonservice Cost Components of Postretirement Benefits | 1,511 | 2,581 | (1,070) | (41.5) | |||||||||||||||||||
| Other Income | 2,095 | 3,733 | (1,638) | (43.9) | |||||||||||||||||||
| Income Before Income Taxes | 150,532 | 95,726 | 54,806 | 57.3 | |||||||||||||||||||
| Income Tax Expense | 25,380 | 18,543 | 6,837 | 36.9 | |||||||||||||||||||
| Net Income | $ | 125,152 | $ | 77,183 | $ | 47,969 | 62.1 | % | |||||||||||||||
| (in thousands) | 2021 | 2020 | $ change | % change | |||||||||||||||||||
| Retail Revenues | $ | 291,130 | $ | 291,761 | $ | (631) | (0.2) | % | |||||||||||||||
| Transmission Services Revenues | 37,085 | 32,802 | 4,283 | 13.1 | |||||||||||||||||||
| Wholesale Revenues | 14,711 | 3,141 | 11,570 | 368.4 | |||||||||||||||||||
| Other Electric Revenues | 5,703 | 5,548 | 155 | 2.8 | |||||||||||||||||||
| Total Operating Revenues | 348,629 | 333,252 | 15,377 | 4.6 | |||||||||||||||||||
| Production Fuel | 44,576 | 34,077 | 10,499 | 30.8 | |||||||||||||||||||
| Purchased Power | 40,273 | 45,940 | (5,667) | (12.3) | |||||||||||||||||||
| Operating and Maintenance Expenses | 114,615 | 106,639 | 7,976 | 7.5 | |||||||||||||||||||
| Depreciation and Amortization | 53,335 | 47,063 | 6,272 | 13.3 | |||||||||||||||||||
| Property Taxes | 13,136 | 12,601 | 535 | 4.2 | |||||||||||||||||||
| Operating Income | $ | 82,694 | $ | 86,932 | $ | (4,238) | (4.9) | % | |||||||||||||||
Electric kilowatt-hour (kwh) Sales (in thousands) | |||||||||||||||||||||||
| Retail kwh Sales | 3,511,730 | 3,538,299 | (26,569) | (0.8) | % | ||||||||||||||||||
| Wholesale kwh Sales – Company Generation | 358,761 | 156,948 | 201,813 | 128.6 | |||||||||||||||||||
| Heating Degree Days | 3,614 | 3,968 | (354) | (8.9) | |||||||||||||||||||
| Cooling Degree Days | 700 | 533 | 167 | 31.3 | |||||||||||||||||||
Amounts presented in the segment tables that follow for operating revenues, cost of products soldheating and other nonelectric operating expenses for the nine-month periods ended September 30, 2020 and 2019 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:
Intersegment Eliminations (in thousands) | September 30, 2020 | September 30, 2019 | ||||||
Operating Revenues: | ||||||||
Electric | $ | 39 | $ | 36 | ||||
Nonelectric | -- | 3 | ||||||
Costs of Products Sold | 10 | 25 | ||||||
Other Nonelectric Expenses | 29 | 14 | ||||||
Electric
Nine Months Ended | ||||||||||||||||
September 30, | % | |||||||||||||||
(in thousands) | 2020 | 2019 | Change | Change | ||||||||||||
Retail Sales Revenues from Contracts with Customers | $ | 288,861 | $ | 303,276 | $ | (14,415 | ) | (4.8 | ) | |||||||
Changes in Accrued Revenues under Alternative Revenue Programs | 2,900 | (1,601 | ) | 4,501 | 281.1 | |||||||||||
Total Retail Sales Revenue | $ | 291,761 | $ | 301,675 | $ | (9,914 | ) | (3.3 | ) | |||||||
Transmission Services Revenue | 32,802 | 34,023 | (1,221 | ) | (3.6 | ) | ||||||||||
Wholesale Revenues – Company Generation | 3,141 | 4,099 | (958 | ) | (23.4 | ) | ||||||||||
Other Revenues | 5,548 | 4,929 | 619 | 12.6 | ||||||||||||
Total Operating Revenues | $ | 333,252 | $ | 344,726 | $ | (11,474 | ) | (3.3 | ) | |||||||
Production Fuel | 34,077 | 45,547 | (11,470 | ) | (25.2 | ) | ||||||||||
Purchased Power – System Use | 45,940 | 54,748 | (8,808 | ) | (16.1 | ) | ||||||||||
Other Operation and Maintenance Expenses | 106,639 | 114,107 | (7,468 | ) | (6.5 | ) | ||||||||||
Depreciation and Amortization | 47,063 | 44,765 | 2,298 | 5.1 | ||||||||||||
Property Taxes | 12,601 | 11,824 | 777 | 6.6 | ||||||||||||
Operating Income | $ | 86,932 | $ | 73,735 | $ | 13,197 | 17.9 | |||||||||
Electric mwh Sales | ||||||||||||||||
Retail mwh Sales | 3,538,299 | 3,657,618 | (119,319 | ) | (3.3 | ) | ||||||||||
Wholesale mwh Sales – Company Generation | 156,948 | 153,645 | 3,303 | 2.1 | ||||||||||||
HDDs | 3,968 | 4,692 | (724 | ) | (15.4 | ) | ||||||||||
CDDs | 533 | 392 | 141 | 36.0 | ||||||||||||
cooling. The following table shows heating and cooling degree days as a percent of normal:
Nine Months ended September 30, | ||||||||
2020 | 2019 | |||||||
HDDs | 99.3 | % | 118.0 | % | ||||
CDDs | 116.9 | % | 86.0 | % | ||||
normal for the nine months ended September 30, 2021 and 2020.
| 2021 | 2020 | ||||||||||
| Heating Degree Days | 89.9 | % | 99.3 | % | |||||||
| Cooling Degree Days | 150.9 | % | 116.9 | % | |||||||
2021 vs Normal | 2021 vs 2020 | 2020 vs Normal | |||||||||||||||
| Effect on Diluted Earnings Per Share | $ | 0.02 | $ | 0.01 | $ | 0.01 | |||||||||||
2020 vs Normal | 2019 vs Normal | 2020 vs 2019 | ||||||||||
Effect on Diluted Earnings Per Share | $ | 0.02 | $ | 0.06 | $ | (0.04 | ) | |||||
The $9.9•A $4.7 million decrease in fuel recovery revenues largely due to lower purchased power costs and credits provided to retail customers from increased margins on wholesale sales, but partially offset by increased recovery of higher production fuel costs.
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in the third quarter of 2020 resulting from a favorable judicial decision regarding the state jurisdictional treatment of federally approved transmission projects.
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Transmission services revenue decreased $1.2 million mainly due to a $2.1 million reduction in transmission tariff revenues related to decreased transmission volume resulting from lower electrical demand partly attributable toby the impact of COVID-19, partially offset by a $0.8following:
Wholesale electric revenues decreased $1.0recovery of Merricourt and Astoria Station project costs and operating expenses.
Production fuel costs decreased $11.5 millionprimarily due to a 23.5% decrease in kwhs generated at OTP’s fuel-burning generation plantsincreased recovery of higher transmission costs and a 2.2% decrease in fuel costs per kwh generated. Decreases in generationincreased transmission investment as well as increased generator interconnection revenues.
The cost of purchased power to serve retail customers decreased $8.8
Electric operating and maintenance expenseserve retail customers decreased $7.5 million, including:
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These items were partially offset by:
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Depreciation expense increased $2.3$5.7 million mainly due to 2019 capitala 26.7% decrease in the volume of purchased power as our recent capacity additions forprovide additional generation resources to serve customer demand and transmissionmarket conditions led to operating our existing facilities at higher capacity factors in lieu of purchasing power at higher market prices.
Property tax we expect will be completed in the fourth quarter of the year.
| (in thousands) | 2021 | 2020 | $ change | % change | |||||||||||||||||||
| Operating Revenues | $ | 250,085 | $ | 174,276 | $ | 75,809 | 43.5 | % | |||||||||||||||
| Cost of Products Sold (excluding depreciation) | 189,183 | 131,145 | 58,038 | 44.3 | |||||||||||||||||||
| Other Operating Expenses | 28,109 | 19,678 | 8,431 | 42.8 | |||||||||||||||||||
| Depreciation and Amortization | 11,395 | 11,244 | 151 | 1.3 | |||||||||||||||||||
| Operating Income | $ | 21,398 | $ | 12,209 | $ | 9,189 | 75.3 | % | |||||||||||||||
Manufacturing
Nine Months Ended | ||||||||||||||||
September 30, | % | |||||||||||||||
(in thousands) | 2020 | 2019 | Change | Change | ||||||||||||
Operating Revenues | $ | 174,276 | $ | 217,040 | $ | (42,764 | ) | (19.7 | ) | |||||||
Cost of Products Sold | 131,145 | 167,002 | (35,857 | ) | (21.5 | ) | ||||||||||
Operating Expenses | 19,678 | 22,880 | (3,202 | ) | (14.0 | ) | ||||||||||
Depreciation and Amortization | 11,244 | 10,606 | 638 | 6.0 | ||||||||||||
Operating Income | $ | 12,209 | $ | 16,552 | $ | (4,343 | ) | (26.2 | ) | |||||||
$75.8 million primarily due to higher revenues at BTD, which was largely driven by a 15.6% increase in sales volumes and a 25.5% increase in material costs, which are passed through to customers through increased sales prices. The $42.8 million decreaseincrease in material costs is largely the result of historically high steel prices due to supply shortages as steel mill capacity rebounds from capacity reductions in 2020. Sales volumes in 2020 were negatively impacted by COVID-19 as customers implemented temporary plant shutdowns due to the pandemic. Sales volumes in 2021 have rebounded as customer demand across most end markets has been robust. An increase in horticultural product sales volumes at T.O. Plastics in 2021, driven by increasing customer demand, as well as increased sales prices, also contributed to increased operating revenues in our Manufacturing segment includes2021.
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The $35.9 million decreaseresult of high steel prices as mentioned above. Year to date gross profit margins are consistent with the prior year as increases in labor and freight costs and lower productivity in the third quarter of 2021 have been offset by higher sales volumes, as higher volumes have resulted in greater leveraging of fixed production costs. Increased sales volumes and production activity at T.O. Plastics has also contributed to the increase in cost of products sold in our Manufacturing segment includes2021. Year to date gross profit margins at T.O. Plastics increased compared to the following:
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The $3.2same period in 2020, as higher production activities have resulted in greater leveraging of fixed production costs and sales prices have increased, resulting from input material cost inflation.
BTD incurred $1.0 million in termination costs in the second quarter of 2020, with $0.9 million charged to cost of products sold and $0.1 million charged to operating expense, related to headcount reductions across all its sites in response to the ongoing reduction in sales volume.
We estimate COVID-19 issues at BTD negatively impacted our earnings by approximately $0.08 per share in the first nine months of 2020. This relates to reduced sales as customers initiated or continued temporary plant shutdowns which caused lost labor productivity, and costs related to personal protective equipment. BTD also continued to pay health care costs for furloughed employees.
Plastics
Nine Months Ended | ||||||||||||||||
September 30, | % | |||||||||||||||
(in thousands) | 2020 | 2019 | Change | Change | ||||||||||||
Operating Revenues | $ | 155,769 | $ | 142,100 | $ | 13,669 | 9.6 | |||||||||
Cost of Products Sold | 115,432 | 110,348 | 5,084 | 4.6 | ||||||||||||
Operating Expenses | 8,990 | 8,486 | 504 | 5.9 | ||||||||||||
Depreciation and Amortization | 2,667 | 2,617 | 50 | 1.9 | ||||||||||||
Operating Income | $ | 28,680 | $ | 20,649 | $ | 8,031 | 38.9 | |||||||||
Plastics segment revenues and operating income increased $13.7 million and $8.0 million, respectively, due to a 10.2%an increase in pounds of PVC pipe soldincentive based compensation arising from the improvement in combination with a decreasefinancial results, and an increase in cost per pound of pipe sold. The sales volume increase resulted from a combination of factors including improved market conditions during the third quarter of 2020 duecosts necessary to limited effects of COVID-19 and concerns over raw material supply and product availability due to two resin suppliers invoking force majeure, anticipated impacts from hurricanes, significant global demand for PVC resin and limited pipe inventory across the country. Cost of products sold increased $5.1 million due tosupport the increase in sales volume, partially offset by a 5.0% decrease in the cost per poundbusiness volumes.
Corporate
Corporate includes items such as corporate staff and overhead costs, the results of our captive insurance company and other items excluded from the measurement of operating segment performance. Corporate is not an operating segment. Rather it is added to operating segment totals to reconcile to totals on our consolidated statements of income.
Nine Months Ended | ||||||||||||||||
September 30, | % | |||||||||||||||
(in thousands) | 2020 | 2019 | Change | Change | ||||||||||||
Operating Expenses | $ | 7,638 | $ | 7,052 | $ | 586 | 8.3 | |||||||||
Depreciation and Amortization | 256 | 241 | 15 | 6.2 | ||||||||||||
Corporate operating expenses increased $0.6 million mainly as a result of a $0.4 million decrease in corporate costs charged to subsidiaries, a $0.4 million increase in labor costs and a $0.2 million increase in insurance costs, partially offset by a $0.3 million decrease in contracted service expenditures.
Interest Charges
Interest charges increased to $25.4 million infor the nine months ended September 30, 2020 from $23.22021 and 2020:
| (in thousands) | 2021 | 2020 | $ change | % change | |||||||||||||||||||
| Operating Revenues | $ | 264,898 | $ | 155,769 | $ | 109,129 | 70.1 | % | |||||||||||||||
| Cost of Products Sold (excluding depreciation) | 169,584 | 115,432 | 54,152 | 46.9 | |||||||||||||||||||
| Other Operating Expenses | 10,450 | 8,990 | 1,460 | 16.2 | |||||||||||||||||||
| Depreciation and Amortization | 3,200 | 2,667 | 533 | 20.0 | |||||||||||||||||||
| Operating Income | $ | 81,664 | $ | 28,680 | $ | 52,984 | 184.7 | % | |||||||||||||||
| (in thousands) | 2021 | 2020 | $ change | % change | |||||||||||||||||||
| Other Operating Expenses | $ | 7,028 | $ | 7,638 | $ | (610) | (8.0) | % | |||||||||||||||
| Depreciation and Amortization | 179 | 256 | (77) | (30.1) | |||||||||||||||||||
| Operating Loss | $ | 7,207 | $ | 7,894 | $ | (687) | (8.7) | % | |||||||||||||||
| REGULATORY RATE MATTERS | |||||
| Recovery | Filing | Amount | Effective | ||||||||||||||||||||||||||||||||||||||
| Mechanism | Jurisdiction | Status | Date | (in millions) | Date | Notes | |||||||||||||||||||||||||||||||||||
| RRR | 2019 | MN | Approved | 06/21/19 | $ | 12.5 | 01/01/20 | Includes return on Merricourt construction costs. | |||||||||||||||||||||||||||||||||
| TCR | 2018 | MN | Approved | 05/07/20 | 10.3 | 01/21/20 | See below for additional details. | ||||||||||||||||||||||||||||||||||
| EUIC | 2021 | MN | Requested | 06/07/21 | 1.3 | 01/01/22 | Includes recovery of new infrastructure costs, including advanced metering, outage management and demand response systems. | ||||||||||||||||||||||||||||||||||
| RRR | 2021 | ND | Approved | 03/07/21 | 11.8 | 04/01/21 | Includes return on Merricourt construction costs. | ||||||||||||||||||||||||||||||||||
| GCR | 2020 | ND | Approved | 06/10/20 | 6.2 | 07/01/20 | Includes return on Astoria Station construction costs. | ||||||||||||||||||||||||||||||||||
| TCR | 2022 | ND | Requested | 09/15/21 | 6.1 | 01/01/22 | Includes recovery of three new transmission projects/programs. | ||||||||||||||||||||||||||||||||||
| RRR | 2020 | ND | Approved | 03/18/20 | 5.8 | 04/01/20 | Includes return on Merricourt construction costs. | ||||||||||||||||||||||||||||||||||
| TCR | 2020 | ND | Approved | 08/31/20 | 5.6 | 01/21/20 | Includes recovery of new transmission assets. | ||||||||||||||||||||||||||||||||||
| TCR | 2021 | ND | Approved | 11/18/20 | 5.6 | 01/01/21 | Includes recovery of eight new transmission projects. | ||||||||||||||||||||||||||||||||||
| GCR | 2021 | ND | Approved | 03/01/21 | 5.2 | 07/01/21 | Includes recovery of Astoria Station, net of anticipated savings associated with the retirement of Hoot Lake Plant. | ||||||||||||||||||||||||||||||||||
| TCR | 2020 | SD | Approved | 01/29/20 | 2.3 | 03/02/20 | Annual update to transmission cost recovery rider. | ||||||||||||||||||||||||||||||||||
| TCR | 2021 | SD | Approved | 02/19/21 | 2.2 | 03/01/21 | Includes recovery of two new transmission projects. | ||||||||||||||||||||||||||||||||||
| PIR | 2020 | SD | Approved | 05/31/20 | 1.6 | 09/01/20 | Includes return on Merricourt and Astoria Station construction costs. | ||||||||||||||||||||||||||||||||||
Other Income
Other income increaseddemand circumstances, and the extent to $3.7 millionwhich each resource option would be used to meet those service needs. Typically, the filings are submitted every two years.
Income Tax Expense
Income tax expense increased $4.6 million in the nine months ended September 30, 2020 compared withexisting lignite sales agreement under which Coyote Station acquires all of its lignite coal fuel from a nearby mine is necessary. For its economic analysis, OTP developed an estimate of the nine months ended September 30, 2019, mainlyreasonably foreseeable costs of withdrawing from Coyote Station at the end of 2028 of $68.5 million. These costs may differ from actual results due to the tax effectuncertainty and timing of future events associated with the terms and conditions of a $15.3 million increase in income before income taxes. The following table provides a reconciliation of income tax expense calculated at our net composite federal and state statutory rate on income before income taxes on our consolidated statements of income.
Nine Months Ended September 30, | ||||||||
(in thousands) | 2020 | 2019 | ||||||
Income Before Income Taxes | $ | 95,726 | $ | 80,402 | ||||
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) | $ | 24,889 | $ | 20,905 | ||||
(Decreases) Increases in Tax from: | ||||||||
Differences Reversing in Excess of Federal Rates | (3,450 | ) | (2,690 | ) | ||||
Allowance for Funds Used During Construction – Equity | (948 | ) | (419 | ) | ||||
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes | (775 | ) | (774 | ) | ||||
Research and Development Tax Credits | (649 | ) | (987 | ) | ||||
Excess Tax Deduction – Equity Method Stock Awards | (535 | ) | (827 | ) | ||||
Corporate Owned Life Insurance | (141 | ) | (609 | ) | ||||
Reconciliation and Prior Period Adjustments | 172 | (722 | ) | |||||
Other Items – Net | (20 | ) | 30 | |||||
Income Tax Expense | $ | 18,543 | $ | 13,907 | ||||
Effective Income Tax Rate | 19.4 | % | 17.3 | % | ||||
Liquidity
withdrawal.
| LIQUIDITY | |||||
As of September 30, 2020, COVID-19 and the resulting deteriorating economic conditions had not had a material impact on our liquidity. We continue to have sufficient liquidity under our credit facilities to support our operating companies based on the current economic environment. We are closely monitoring our liquidity and capital market conditions given the uncertainty surrounding the impact of COVID-19, which could have an adverse effect on the availability and terms of future debt and equity financing.
(in thousands) | Line Limit | In Use on September 30, 2020 | Restricted due to Outstanding Letters of Credit | Available on September 30, 2020 | Available on December 31, 2019 | |||||||||||||||
Otter Tail Corporation Credit Agreement | $ | 170,000 | $ | 48,600 | $ | -- | $ | 121,400 | $ | 164,000 | ||||||||||
OTP Credit Agreement | 170,000 | -- | 7,670 | 162,330 | 154,524 | |||||||||||||||
Total | $ | 340,000 | $ | 48,600 | $ | 7,670 | $ | 283,730 | $ | 318,524 | ||||||||||
2020:
| 2021 | 2020 | ||||||||||||||||||||||||||||
| (in thousands) | Line Limit | Amount Outstanding | Letters of Credit | Amount Available | Amount Available | ||||||||||||||||||||||||
| OTC Credit Agreement | $ | 170,000 | $ | 36,624 | $ | — | $ | 133,376 | $ | 104,834 | |||||||||||||||||||
| OTP Credit Agreement | 170,000 | 61,233 | 13,159 | 95,608 | 140,068 | ||||||||||||||||||||||||
| Total | $ | 340,000 | $ | 97,857 | $ | 13,159 | $ | 228,984 | $ | 244,902 | |||||||||||||||||||
| (in thousands) | 2021 | 2020 | |||||||||
| Net Cash Provided by Operating Activities | $ | 154,752 | $ | 141,276 | |||||||
| (in thousands) | 2021 | 2020 | |||||||||
| Net Cash Used in Investing Activities | $ | 117,084 | $ | 222,385 | |||||||
| (in thousands) | 2021 | 2020 | |||||||||
| Net Cash (Used in) Provided by Financing Activities | $ | (37,559) | $ | 104,814 | |||||||
| CAPITAL REQUIREMENTS | |||||
| (in millions) | 2020 | 2021(1) | 2022 | 2023 | 2024 | 2025 | 2026 | Total 2022 - 2026 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Electric Segment: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Renewables and Natural Gas Generation | 23 | 30 | 80 | 92 | 92 | 160 | 454 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Technology and Infrastructure | 2 | 26 | 30 | 18 | — | — | 74 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Distribution Plant Replacements | 31 | 37 | 35 | 35 | 35 | 33 | 175 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Transmission (includes replacements) | 27 | 26 | 28 | 24 | 20 | 27 | 125 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | 34 | 30 | 29 | 32 | 36 | 23 | 150 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total Electric Segment | $ | 357 | $ | 117 | $ | 149 | $ | 202 | $ | 201 | $ | 183 | $ | 243 | $ | 978 | |||||||||||||||||||||||||||||||||||||||||||
| Manufacturing and Plastics Segments | 15 | 36 | 33 | 46 | 31 | 21 | 22 | 153 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Total Capital Expenditures | $ | 372 | $ | 153 | $ | 182 | $ | 248 | $ | 232 | $ | 204 | $ | 265 | $ | 1,131 | |||||||||||||||||||||||||||||||||||||||||||
| Total Electric Utility Average Rate Base | $ | 1,385 | $ | 1,570 | $ | 1,630 | $ | 1,750 | $ | 1,860 | $ | 1,980 | $ | 2,100 | |||||||||||||||||||||||||||||||||||||||||||||
| Annual Rate Base Growth | 13.4 | % | 3.8 | % | 7.4 | % | 6.3 | % | 6.5 | % | 6.1 | % | |||||||||||||||||||||||||||||||||||||||||||||||
(1) Includes actual results for the nine months ended September 30, 2021, and anticipated capital expenditures for the fourth quarter of 2021. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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
| CAPITAL RESOURCES | |||||
Net cash used in investing activities was $222.4 million for the nine months ended September 30, 2020 compared with $151.1 million for the nine months ended September 30, 2019. The $71.3 million increase is mainly due to a $77.1 million increase in cash used for construction expenditures at OTP, partially offset by a $6.2 million net decrease in capital expenditures in our nonutility businesses. OTP’s cash used for capital expenditures totaled $210.0 million in the first nine months of 2020 compared with $132.9 million in the first nine months of 2019. The majority of the 2020 expenditures at OTP related to thefund construction of Astoria Stationnew rate base and Merricourt.
Net cash provided bytransmission investments. In addition, we may issue equity or debt financing activities was $104.8 million for the nine months ended September 30, 2020 compared with net cash provided by financing activitiesto opportunistically reduce borrowings under our lines of $46.0 million for the nine months ended September 30, 2019. Financing activities in the first nine months of 2020 included $75.0 million in proceeds from the issuance ofcredit, to satisfy or early retire our outstanding long-term debt, at OTP under its 2019 Note Purchase Agreementor to fund its current construction program expenditures. Further information on the debt issuance is provided below under “Capital Resources.” We also borrowed $42.6 million under the Otter Tail Corporation Credit Agreement and raised net proceeds of $32.7 million from the issuance of common stock. The proceeds from the line borrowings and stock issuances provided the majority of fundsfinance potential acquisition opportunities or for $105 million in equity contributions to OTP to fund its construction program expenditures. Financing activities in the first nine months of 2020 also included $45.1 million in common dividend payments.
Financing activities in the first nine months of 2019 included proceeds of $90.4 million from borrowings under the OTP and Otter Tail Corporation credit agreements which were used, together with cash flows from operations, to fund OTPs capital expenditures. The Company also paid $41.8 million in common dividends in the first nine months of 2019.
CAPITAL REQUIREMENTS
2019-2024 Capital Expenditures
In June 2020, we updated our 2020-2024 anticipated capital expenditures, shifting the timing of expenditures between years and projects as a result of more definitive plans with no material impact on the $1.0 billion five-year expenditure total. The following table shows our 2019 capital expenditures and June 30, 2020 revised 2020 through 2024 anticipated capital expenditures and electric utility average rate base:
(in millions) | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | Total | |||||||||||||||||||||
Capital Expenditures: | ||||||||||||||||||||||||||||
Electric Segment: | ||||||||||||||||||||||||||||
Renewables and Natural Gas Generation | $ | 258 | $ | 65 | $ | 53 | $ | -- | $ | -- | $ | 376 | ||||||||||||||||
Technology and Infrastructure | -- | 11 | 28 | 32 | 28 | 99 | ||||||||||||||||||||||
Distribution Plant Replacements | 20 | 25 | 28 | 31 | 30 | 134 | ||||||||||||||||||||||
Transmission (includes replacements) | 62 | 14 | 30 | 30 | 30 | 166 | ||||||||||||||||||||||
Other | 26 | 23 | 25 | 25 | 24 | 123 | ||||||||||||||||||||||
Total Electric Segment | $ | 187 | $ | 366 | $ | 138 | $ | 164 | $ | 118 | $ | 112 | $ | 898 | ||||||||||||||
Manufacturing and Plastics Segments | 20 | 14 | 17 | 17 | 19 | 17 | 84 | |||||||||||||||||||||
Total Capital Expenditures | $ | 207 | $ | 380 | $ | 155 | $ | 181 | $ | 137 | $ | 129 | $ | 982 | ||||||||||||||
Total Electric Utility Average Rate Base | $ | 1,170 | $ | 1,415 | $ | 1,587 | $ | 1,664 | $ | 1,726 | $ | 1,765 | ||||||||||||||||
Rate Base Growth | 20.9 | % | 12.2 | % | 4.9 | % | 3.7 | % | 2.3 | % | ||||||||||||||||||
Execution on the anticipated electric utility capital expenditure plan is expected to grow rate base 8.6% and be a key driver in increasing utility earnings over the 2020 through 2024 timeframe.
As of September 30, 2020, OTP had capitalized approximately $231.1 million in project costs and AFUDC associated with Merricourt. OTP estimates its direct generation and transmission capital costs for the Merricourt project will be approximately $260 million. Additional transmission system upgrades for the project amounting to approximately $6.4 million will be made by a neighboring MISO transmission owner. OTP has received Notices of Force Majeure from EDF-RE US Development, LLC claiming rights to an extension of guaranteed project completion dates and adjustments to the consideration agreed upon in the TEPC Agreement due to COVID-19 impacts. While details regarding these claims and impact to the project remain uncertain, OTP currently anticipates Merricourt will be in commercial operation before the end of December 2020. These and other potential impacts of COVID-19-related disruptions continue to present risks for the costs and timing of payments related to the project.
As of September 30, 2020, OTP had capitalized approximately $131.6 million in project costs and AFUDC associated with Astoria Station. OTP estimates its direct generation and transmission capital costs for the Astoria Station project will be approximately $152.5 million and anticipates the plant will begin commercial operation in the first quarter of 2021, prior to the planned retirement of Hoot Lake Plant in May 2021.
In September 2020, OTP announced plans for the construction of the $60 million Hoot Lake Solar project. This is a 49-megawatt project OTP expects to build on land around Hoot Lake Plant in Fergus Falls, Minnesota. The project is expected to include up to 170,000 solar panels and to generate enough energy to power approximately 10,000 homes each year. The project is targeted for completion in 2022.
Contractual Obligations
In the first nine months of 2020, OTP paid down a portion of its $317 million in obligations for commitments under contracts in place as of December 31, 2019, reducing its obligations for commitments under contracts to $58 million as of September 30, 2020. This includes commitments related to the construction of Astoria Station and Merricourt of $39 million for the remainder of 2020 and $6 million for 2021. In the first nine months of 2020, OTP increased its debt obligations by $75 million in the years beyond 2024. In September 2020, OTP entered into a 20-year Facilities Service Agreement with an owner of adjacent transmission assets to pay for upgrades and additions to the owner’s transmission facilities required to accommodate the transmission of electricity generated by Merricourt’s wind turbines, increasing its other purchase obligations by $1.4 million in each of the two-year periods 2021-2022 and 2023-2024, and $10.8 million beyond 2024.
CAPITAL RESOURCES
On May 3, 20182021, we filed two registration statements with the SEC. The first statement, a shelf registration, statement with the Securities and Exchange Commission (SEC) under which we mayallows us to offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelfregistration statement. The second registration statement which expires on May 3, 2021. On May 3, 2018 we also filed a shelf registration statement with the SECallows for the issuance of up to 1,500,000 common shares under our Automatic Dividend Reinvestment and Share Purchase Plan, (the Plan), which permitsprovides our common shareholders, retail customers of OTP and other interested investors a method of purchasing our common shares by reinvesting their dividends and/or making optional cash investments. Shares purchased by participants inunder the Plan toplan may be either new issue common shares or common shares purchased inon the open market. The shelfBoth registration for the Plan expires onstatements expire in May 3, 2021. On November 8, 2019 the Company entered into a Distribution Agreement with KeyBanc under which we may offer and sell our common shares from time to time through KeyBanc, as our distribution agent, up to an aggregate sales price of $75 million through an At-the-Market offering program. In the third quarter of 2020, we received proceeds of $3,523,311, net of $44,599 in commissions, from the issuance of 87,400 common shares under this program.
Debt
Brief descriptions of the short-term and long-term credit and debt agreements currently in place at 2024.
Short-Term Debt
On October 29, 2012 weRestated Credit Agreement and Otter Tail Power Company entered into a Third Amended and Restated Credit Agreement, (the OTC Credit Agreement), which provided for an unsecured $130 million revolvingamending and restating the previously existing credit facility that could be increased subject to certain terms and conditions. On October 31, 2019 the OTC Credit Agreement was amendedagreements to extend its expirationthe maturity date by one year from October 31, 2023of each agreement to October 31, 2024,September 30, 2026. The borrowing capacity and to increase the amountother significant terms of the revolvingagreements remained unchanged from the previous credit facility to $170 million.agreements. The amendment also provides this facility can be increased to $290 million subject to certain termsfollowing is a summary of key provisions and conditions. Borrowings under the OTC Credit Agreement bear interest at LIBOR plus 1.50%, subject to adjustment based on our senior unsecured credit ratings or the issuer rating if a rating is not providedborrowing information as of, and for the seniornine months ended, September 30, 2021:
| (in thousands, except interest rates) | OTC Credit 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 September 30, 2021 | — | 13,159 | |||||||||
| Amount Outstanding as of September 30, 2021 | 36,624 | 61,233 | |||||||||
| Average Amount Outstanding During the Nine Months Ended September 30, 2021 | 58,703 | 51,911 | |||||||||
| Maximum Amount Outstanding During the Nine Months Ended September 30, 2021 | 79,718 | 72,471 | |||||||||
| Interest Rate as of September 30, 2021 | 1.59 | % | 1.33 | % | |||||||
| Maturity Date | September 30, 2026 | September 30, 2026 | |||||||||
1Each facility includes an accordion featuring allowing the borrower to increase the borrowing limit if certain terms and conditions are met. | |||||||||||
borrowings at fixed rates of interest with maturities ranging from 2021 to 2050.
Long-Term Debt
On September 12, 2019,June 10, 2021, OTP entered into a Note Purchase Agreement (the 2019 Note Purchase Agreement) with the purchasers named therein, pursuant to which OTP agreed to issue, to the purchasers, in a private placement transaction, $175$230 million aggregate principal amount of OTP’s senior unsecured notes. The funding of the notes consistingwill occur in two issuances, $140 million in November 2021 and $90 million in May 2022. The issuance of (a) $10,000,000 aggregate principal amount of its 3.07% Series 2019A Senior Unsecured Notes due October 10, 2029 (the Series 2019A Notes), (b) $26,000,000 aggregate principal amount of its 3.52% Series 2019B Senior Unsecured Notes due October 10, 2039 (the Series 2019B Notes), (c) $64,000,000 aggregate principal amount of its 3.82% Series 2019C Senior Unsecured Notes due October 10, 2049 (the Series 2019C Notes), (d) $10,000,000 aggregate principal amount of its 3.22% Series 2020A Senior Unsecured Notes due February 25, 2030 (the Series 2020A Notes), (e) $40,000,000 aggregate principal amount of its 3.22% Series 2020B Senior Unsecured Notes due August 20, 2030 (the Series 2020B Notes), (f) $10,000,000 aggregate principal amount of its 3.62% Series 2020C Senior Unsecured Notes due February 25, 2040 (the Series 2020C Notes) and (g) $15,000,000 aggregate principal amount of its 3.92% Series 2020D Senior Unsecured Notes due February 25, 2050 (the Series 2020D Notes).
On February 25, 2020, OTP issued the Series 2020A Notes, the Series 2020C Notes and the Series 2020D Notes pursuantnotes is subject to the 2019 Note Purchase Agreement. Onsatisfaction of certain customary conditions to closing. We intend to use the proceeds of the notes to refinance existing long-term indebtedness, including long-term debt instruments with outstanding principal balances of $140 million and $30 million, which mature in December 2021 and August 20, 2020, OTP issued the Series 2020B Notes pursuant to the 2019 Note Purchase Agreement. OTP used the $75 million proceeds from the issuances to pay for capital expenditures2022, respectively, and for othergeneral corporate purposes. The Series 2019A Notes, Series 2019B Notes
On February 27, 2018 OTP issued $100 million aggregate principal amountlong-term debt instruments.
On December 13, 2016our short- and long-debt agreements require Otter Tail Corporation issued $80 million aggregate principal amount of its 3.55% Guaranteed Senior Notes due December 15, 2026 (the 2026 Notes) pursuantand OTP to a Note Purchase Agreement dated asmaintain certain financial covenants. As of September 23, 2016 (the 2016 Note Purchase Agreement). Our obligations under the 2016 Note Purchase Agreement and the 2026 Notes are guaranteed by our Material Subsidiaries (as defined in the 2016 Note Purchase Agreement, but specifically excluding OTP).
On February 27, 2014 OTP issued $60 million aggregate principal amount of its 4.68% Series A Senior Unsecured Notes due February 27, 2029 and $90 million aggregate principal amount of its 5.47% Series B Senior Unsecured Notes due February 27, 2044 pursuant to a Note Purchase Agreement dated as of August 14, 2013 (the 2013 Note Purchase Agreement).
On December 1, 2011 OTP issued $140 million aggregate principal amount of its 4.63% Senior Unsecured Notes due December 1,30, 2021, pursuant to a Note Purchase Agreement dated as of July 29, 2011 (the 2011 Note Purchase Agreement).
OTP also has outstanding its $122 million senior unsecured notes issued in three series consisting of $30 million aggregate principal amount of 6.15% Senior Unsecured Notes, Series B, due 2022; $42 million aggregate principal amount of 6.37% Senior Unsecured Notes, Series C, due 2027; and $50 million aggregate principal amount of 6.47% Senior Unsecured Notes, Series D, due 2037 (collectively, the 2007 Notes). The 2007 Notes were issued pursuant to a Note Purchase Agreement dated as of August 20, 2007 (the 2007 Note Purchase Agreement).
Financial Covenants
Wewe were in compliance with thethese financial covenants inas further described below:
No Credit Agreement or Note Purchase Agreement contains any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies.
Our borrowing agreements are subject to certain financial covenants. Specifically:
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total capitalization. As of September 30, 2020,2021, our ratio of Interest-bearing Debtinterest-bearing debt to Total Capitalizationtotal capitalization was 0.49 to 1.00 on a consolidated basis and 0.47 to 1.00, for OTP. Neither Otter Tail Corporation nor OTPour interest and dividend coverage ratio was 5.73 to 1.00, and we had any Priority Indebtedness outstanding asno priority indebtedness outstanding.
OFF-BALANCE-SHEET ARRANGEMENTS
We2021, OTP's interest-bearing debt to total capitalization was 0.47 to 1.00, its interest and our subsidiary companiesdividend coverage ratio was 3.16 to 1.00, and OTP had no priority indebtedness outstanding.
| OFF-BALANCE-SHEET ARRANGEMENTS | |||||
2020 BUSINESS OUTLOOK
We are raising and narrowing our 2020 diluted earnings per share guidance range based on our financial results through the first nine months of 2020 and updated view of current business conditions in our Plastics and Manufacturing segments. We now expect our 2020 diluted earnings per share to be in the range of $2.26 to $2.36 instead of $2.10 to $2.30. This revision in guidance is primarily driven by strong performance in our Plastics segment along with continued favorable business conditions in this segment expected through the rest of 2020. Also, the impact of COVID-19 on our Electric segment has been less than previously expected. Our 2020 diluted earnings per share guidance includes $0.04 of dilution associated with actual and planned issuances of common shares under our At-the-Market Offering Program and Dividend Reinvestment and Employee Stock Purchase Plans to help fund construction projects at OTP.
We currently expect capital additions to be $380 million in 2020, with our Electric segment accounting for 96% of those additions, largely driven by the Merricourt and Astoria Station rate base projects. A five-year anticipated capital expenditures table is provided above on page 45.
Segment components of our revised 2020 diluted earnings per share guidance range compared with 2019 actual earnings and with our previously issued guidance are as follows.
| 2019 EPS by | 2020 Guidance February 20, 2020 | 2020 Guidance May 5, 2020 | 2020 Guidance August 3, 2020 | 2020 Guidance November 2, 2020 | |||||||||||||||||||||||||||||||
| Diluted Earnings Per Share | Segment | Low | High | Low | High | Low | High | Low | High | |||||||||||||||||||||||||||
Electric | $ | 1.48 | $ | 1.67 | $ | 1.70 | $ | 1.65 | $ | 1.70 | $ | 1.67 | $ | 1.70 | $ | 1.67 | $ | 1.69 | ||||||||||||||||||
Manufacturing | $ | 0.32 | $ | 0.31 | $ | 0.35 | $ | 0.14 | $ | 0.23 | $ | 0.15 | $ | 0.23 | $ | 0.23 | $ | 0.25 | ||||||||||||||||||
Plastics | $ | 0.51 | $ | 0.43 | $ | 0.47 | $ | 0.43 | $ | 0.47 | $ | 0.50 | $ | 0.54 | $ | 0.64 | $ | 0.66 | ||||||||||||||||||
Corporate | $ | (0.14 | ) | $ | (0.19 | ) | $ | (0.15 | ) | $ | (0.22 | ) | $ | (0.15 | ) | $ | (0.22 | ) | $ | (0.17 | ) | $ | (0.28 | ) | $ | (0.24 | ) | |||||||||
Total | $ | 2.17 | $ | 2.22 | $ | 2.37 | $ | 2.00 | $ | 2.25 | $ | 2.10 | $ | 2.30 | $ | 2.26 | $ | 2.36 | ||||||||||||||||||
Return on Equity | 11.6 | % | 11.0 | % | 11.7 | % | 9.9 | % | 11.1 | % | 10.4 | % | 11.4 | % | 11.2 | % | 11.7 | % | ||||||||||||||||||
The estimates and assumptions underlying our latest 2020 guidance (issued on November 2, 2020) as compared to earlier guidance (issued on August 3, 2020) are summarized below.
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| CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES |
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The above items are offset by:
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