UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[ X]☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended | June 30, |
OR
[ ]☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from | to |
Commission file number | 0-53713 |
OTTER TAIL CORPORATION |
(Exact name of registrant as specified in its charter) |
Minnesota | 27-0383995 |
(State or other jurisdiction of | (I.R.S. Employer |
incorporation or organization) | Identification No.) |
215 South Cascade Street, Box 496, Fergus Falls, Minnesota | 56538-0496 |
(Address of principal executive offices) | (Zip Code) |
866-410-8780 |
(Registrant's telephone number, including area code) |
(Former name, former address and former fiscal year, if changed since last report) |
Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:
Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
Common Shares, par value $5.00 per share | OTTR | The Nasdaq Stock Market LLC |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.:
| Large accelerated filer ☑ | Accelerated filer ☐ | |
| Non-accelerated filer ☐ | Smaller reporting company | Emerging growth company ☐ |
If an emerging growth company, indicate by checkmark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act ☐
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).
Yes ☐ No ☑
Indicate the number of shares outstanding of each of the issuer's classes of Common Stock, as of the latest practicable date:
July 31 31, 20192020 –39,755,27740,872,064 Common Shares ($5 par value)
INDEX
Page No. | ||
Item 1. | ||
Consolidated Balance Sheets – June 30, | 2 & 3 | |
4 | ||
5 | ||
6 | ||
7 | ||
Condensed Notes to Consolidated Financial Statements (not audited) |
| |
Item 2. | Management's Discussion and Analysis of Financial Condition and Results of Operations |
|
Item 3. |
| |
Item 4. |
| |
Item 1. | 54 | |
Item 1A. | 54 | |
Item 6. | 55 | |
55 | ||
Otter Tail Corporation | ||
| ||
(not audited) |
(in thousands) | June 30, 2019 | December 31, 2018 | June 30, 2020 | December 31, 2019 | ||||||||||||
Assets | ||||||||||||||||
Current Assets | ||||||||||||||||
Cash and Cash Equivalents | $ | 982 | $ | 861 | $ | 39,512 | $ | 21,199 | ||||||||
Accounts Receivable: | ||||||||||||||||
Trade—Net | 105,407 | 75,144 | 84,197 | 77,947 | ||||||||||||
Other | 9,956 | 9,741 | 6,452 | 8,773 | ||||||||||||
Inventories | 105,860 | 106,270 | 89,754 | 97,851 | ||||||||||||
Unbilled Receivables | 18,349 | 23,626 | 19,019 | 20,911 | ||||||||||||
Income Taxes Receivable | - | 2,439 | - | 1,487 | ||||||||||||
Regulatory Assets | 14,501 | 17,225 | 19,958 | 21,650 | ||||||||||||
Other | 8,511 | 6,114 | 8,031 | 5,042 | ||||||||||||
Total Current Assets | 263,566 | 241,420 | 266,923 | 254,860 | ||||||||||||
Investments | 9,683 | 8,961 | 10,581 | 9,894 | ||||||||||||
Other Assets | 39,002 | 35,759 | 40,138 | 40,196 | ||||||||||||
Goodwill | 37,572 | 37,572 | 37,572 | 37,572 | ||||||||||||
Other Intangibles—Net | 11,858 | 12,450 | 10,703 | 11,290 | ||||||||||||
Regulatory Assets | 131,692 | 135,257 | 141,063 | 144,138 | ||||||||||||
Right of Use Assets - Operating Leases | 19,473 | - | ||||||||||||||
Right of Use Assets - Operating Leases | 20,571 | 21,851 | ||||||||||||||
Plant | ||||||||||||||||
Electric Plant in Service | 2,170,259 | 2,019,721 | 2,211,082 | 2,212,884 | ||||||||||||
Nonelectric Operations | 234,245 | 228,120 | 252,933 | 247,356 | ||||||||||||
Construction Work in Progress | 73,069 | 181,626 | 321,621 | 185,238 | ||||||||||||
Total Gross Plant | 2,477,573 | 2,429,467 | 2,785,636 | 2,645,478 | ||||||||||||
Less Accumulated Depreciation and Amortization | 875,475 | 848,369 | 923,948 | 891,684 | ||||||||||||
Net Plant | 1,602,098 | 1,581,098 | 1,861,688 | 1,753,794 | ||||||||||||
Total Assets | $ | 2,114,944 | $ | 2,052,517 | $ | 2,389,239 | $ | 2,273,595 | ||||||||
See accompanying condensed notes to consolidated financial statements. |
Otter Tail Corporation | ||
Consolidated Balance Sheets | ||
(not audited) |
(in thousands, except share data) | June 30, 2019 | December 31, 2018 | June 30, 2020 | December 31, 2019 | ||||||||||||
Liabilities and Equity | ||||||||||||||||
Current Liabilities | ||||||||||||||||
Short-Term Debt | $ | 36,602 | $ | 18,599 | $ | 41,239 | $ | 6,000 | ||||||||
Current Maturities of Long-Term Debt | 177 | 172 | 261 | 183 | ||||||||||||
Accounts Payable | 111,848 | 96,291 | 133,967 | 120,775 | ||||||||||||
Accrued Salaries and Wages | 18,034 | 24,857 | 16,891 | 22,730 | ||||||||||||
Accrued Federal and State Income Taxes | 3,732 | - | ||||||||||||||
Other Accrued Taxes | 11,753 | 17,287 | ||||||||||||||
Accrued Taxes | 12,193 | 17,525 | ||||||||||||||
Regulatory Liabilities | 8,959 | 738 | 13,023 | 7,480 | ||||||||||||
Current Operating Lease Liabilities | 3,784 | - | 4,543 | 4,136 | ||||||||||||
Other Accrued Liabilities | 11,260 | 12,149 | 10,806 | 10,912 | ||||||||||||
Total Current Liabilities | 206,149 | 170,093 | 232,923 | 189,741 | ||||||||||||
Pensions Benefit Liability | 88,030 | 98,358 | 86,657 | 98,970 | ||||||||||||
Other Postretirement Benefits Liability | 73,080 | 71,561 | 71,845 | 71,437 | ||||||||||||
Long-Term Operating Lease Liabilities | 16,084 | - | 16,584 | 18,193 | ||||||||||||
Other Noncurrent Liabilities | 28,859 | 24,326 | 34,647 | 30,833 | ||||||||||||
Commitments and Contingencies (note 9) | ||||||||||||||||
Deferred Credits | ||||||||||||||||
Deferred Income Taxes | 122,035 | 120,976 | 141,538 | 131,941 | ||||||||||||
Deferred Tax Credits | 19,300 | 19,974 | 17,969 | 18,626 | ||||||||||||
Regulatory Liabilities | 224,655 | 226,469 | 238,160 | 239,906 | ||||||||||||
Other | 2,384 | 1,895 | 2,472 | 2,885 | ||||||||||||
Total Deferred Credits | 368,374 | 369,314 | 400,139 | 393,358 | ||||||||||||
Capitalization | ||||||||||||||||
Long-Term Debt—Net | 590,063 | 590,002 | 724,389 | 689,581 | ||||||||||||
Cumulative Preferred Shares – Authorized 1,500,000 Shares Without Par Value; Outstanding – None | - | - | - | - | ||||||||||||
Cumulative Preference Shares – Authorized 1,000,000 Shares Without Par Value; Outstanding – None | - | - | - | - | ||||||||||||
Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares; Outstanding, 2019—39,754,902 Shares; 2018—39,664,884 Shares | 198,775 | 198,324 | ||||||||||||||
Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares; Outstanding, 2020—40,848,828 Shares; 2019—40,157,591 Shares | 204,244 | 200,788 | ||||||||||||||
Premium on Common Shares | 345,030 | 344,250 | 390,141 | 364,790 | ||||||||||||
Retained Earnings | 205,115 | 190,433 | 233,705 | 222,341 | ||||||||||||
Accumulated Other Comprehensive Loss | (4,615 | ) | (4,144 | ) | (6,035 | ) | (6,437 | ) | ||||||||
Total Common Equity | 744,305 | 728,863 | 822,055 | 781,482 | ||||||||||||
Total Capitalization | 1,334,368 | 1,318,865 | 1,546,444 | 1,471,063 | ||||||||||||
Total Liabilities and Equity | $ | 2,114,944 | $ | 2,052,517 | $ | 2,389,239 | $ | 2,273,595 | ||||||||
See accompanying condensed notes to consolidated financial statements. |
Otter Tail Corporation
Consolidated Statements of Income
(not audited)
| ||||
|
Three Months Ended June 30, | Six Months Ended June 30, | Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||||||
(in thousands, except share and per-share amounts) | 2019 | 2018 | 2019 | 2018 | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||||
Operating Revenues | ||||||||||||||||||||||||||||||||
Electric: | ||||||||||||||||||||||||||||||||
Revenues from Contracts with Customers | $ | 101,861 | $ | 105,284 | $ | 231,006 | $ | 229,109 | $ | 97,921 | $ | 101,861 | $ | 217,878 | $ | 231,006 | ||||||||||||||||
Changes in Accrued Revenues under Alternative Revenue Programs | 369 | (1,565 | ) | (680 | ) | (2,440 | ) | 209 | 369 | 122 | (680 | ) | ||||||||||||||||||||
Total Electric Revenues | 102,230 | 103,719 | 230,326 | 226,669 | 98,130 | 102,230 | 218,000 | 230,326 | ||||||||||||||||||||||||
Product Sales under Contracts with Customers | 126,973 | 122,629 | 244,849 | 240,945 | ||||||||||||||||||||||||||||
Product Sales from Contracts with Customers | 94,626 | 126,973 | 209,503 | 244,849 | ||||||||||||||||||||||||||||
Total Operating Revenues | 229,203 | 226,348 | 475,175 | 467,614 | 192,756 | 229,203 | 427,503 | 475,175 | ||||||||||||||||||||||||
Operating Expenses | ||||||||||||||||||||||||||||||||
Production Fuel – Electric | 8,296 | 15,888 | 27,216 | 34,594 | 8,788 | 8,296 | 22,523 | 27,216 | ||||||||||||||||||||||||
Purchased Power – Electric System Use | 19,633 | 14,402 | 41,585 | 35,995 | 13,682 | 19,633 | 32,512 | 41,585 | ||||||||||||||||||||||||
Electric Operation and Maintenance Expenses | 39,856 | 37,741 | 78,238 | 77,216 | 33,179 | 39,856 | 73,794 | 78,238 | ||||||||||||||||||||||||
Cost of Products Sold (depreciation included below) | 97,996 | 93,545 | 188,578 | 182,330 | 73,832 | 97,996 | 159,711 | 188,578 | ||||||||||||||||||||||||
Other Nonelectric Expenses | 13,262 | 12,649 | 26,739 | 25,143 | 10,762 | 13,262 | 22,662 | 26,739 | ||||||||||||||||||||||||
Depreciation and Amortization | 19,441 | 18,745 | 38,572 | 37,508 | 20,436 | 19,441 | 40,835 | 38,572 | ||||||||||||||||||||||||
Property Taxes – Electric | 3,900 | 3,273 | 7,859 | 7,108 | 4,168 | 3,900 | 8,268 | 7,859 | ||||||||||||||||||||||||
Total Operating Expenses | 202,384 | 196,243 | 408,787 | 399,894 | 164,847 | 202,384 | 360,305 | 408,787 | ||||||||||||||||||||||||
Operating Income | 26,819 | 30,105 | 66,388 | 67,720 | 27,909 | 26,819 | 67,198 | 66,388 | ||||||||||||||||||||||||
Interest Charges | 7,825 | 7,676 | 15,651 | 15,048 | 8,662 | 7,825 | 16,785 | 15,651 | ||||||||||||||||||||||||
Nonservice Cost Components of Postretirement Benefits | 1,075 | 1,386 | 2,110 | 2,803 | 868 | 1,075 | 1,739 | 2,110 | ||||||||||||||||||||||||
Other Income | 850 | 707 | 2,094 | 1,890 | 2,410 | 850 | 2,021 | 2,094 | ||||||||||||||||||||||||
Income Before Income Taxes | 18,769 | 21,750 | 50,721 | 51,759 | 20,789 | 18,769 | 50,695 | 50,721 | ||||||||||||||||||||||||
Income Tax Expense | 3,343 | 3,054 | 8,971 | 6,848 | 3,808 | 3,343 | 9,446 | 8,971 | ||||||||||||||||||||||||
Net Income | 15,426 | 18,696 | 41,750 | 44,911 | 16,981 | 15,426 | 41,249 | 41,750 | ||||||||||||||||||||||||
Average Number of Common Shares Outstanding – Basic | 39,712,036 | 39,605,717 | 39,684,679 | 39,578,296 | 40,513,286 | 39,712,036 | 40,365,214 | 39,684,679 | ||||||||||||||||||||||||
Average Number of Common Shares Outstanding – Diluted | 39,917,831 | 39,879,069 | 39,910,499 | 39,871,376 | 40,676,761 | 39,917,831 | 40,560,549 | 39,910,499 | ||||||||||||||||||||||||
Basic Earnings Per Common Share | $ | 0.39 | $ | 0.47 | $ | 1.05 | $ | 1.13 | $ | 0.42 | $ | 0.39 | $ | 1.02 | $ | 1.05 | ||||||||||||||||
Diluted Earnings Per Common Share | $ | 0.39 | $ | 0.47 | $ | 1.05 | $ | 1.13 | $ | 0.42 | $ | 0.39 | $ | 1.02 | $ | 1.05 | ||||||||||||||||
See accompanying condensed notes to consolidated financial statements. |
Otter Tail Corporation
Consolidated Statements of Comprehensive Income
(not audited)
| ||||
|
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
(in thousands) | 2019 | 2018 | 2019 | 2018 | ||||||||||||
Net Income | $ | 15,426 | $ | 18,696 | $ | 41,750 | $ | 44,911 | ||||||||
Other Comprehensive Income (Loss): | ||||||||||||||||
Unrealized Gain (Loss) on Available-for-Sale Securities: | ||||||||||||||||
Reversal of Previously Recognized Gains Realized on Sale of Investments and Included in Other Income During Period | (4 | ) | - | (4 | ) | (110 | ) | |||||||||
Unrealized Gains (Losses) Arising During Period | 66 | (13 | ) | 157 | (79 | ) | ||||||||||
Income Tax (Expense) Benefit | (13 | ) | 3 | (32 | ) | 40 | ||||||||||
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax | 49 | (10 | ) | 121 | (149 | ) | ||||||||||
Pension and Postretirement Benefit Plans: | ||||||||||||||||
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11) | 129 | 233 | 259 | 460 | ||||||||||||
Income Tax Expense | (33 | ) | (61 | ) | (67 | ) | (120 | ) | ||||||||
Adjustment to Income Tax Expense Related to 2017 Tax Cuts and Jobs Act | - | - | - | (531 | ) | |||||||||||
Pension and Postretirement Benefit Plans – net-of-tax | 96 | 172 | 192 | (191 | ) | |||||||||||
Total Other Comprehensive Income (Loss) | 145 | 162 | 313 | (340 | ) | |||||||||||
Total Comprehensive Income | $ | 15,571 | $ | 18,858 | $ | 42,063 | $ | 44,571 | ||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
(in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||
Net Income | $ | 16,981 | $ | 15,426 | $ | 41,249 | $ | 41,750 | ||||||||
Other Comprehensive Income: | ||||||||||||||||
Unrealized Gains on Available-for-Sale Securities: | ||||||||||||||||
Reversal of Previously Recognized Losses (Gains) Realized on Sale of Investments and Included in Other Income During Period | 32 | (4 | ) | 34 | (4 | ) | ||||||||||
Unrealized Gains Arising During Period | 92 | 66 | 218 | 157 | ||||||||||||
Income Tax Expense | (26 | ) | (13 | ) | (53 | ) | (32 | ) | ||||||||
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax | 98 | 49 | 199 | 121 | ||||||||||||
Pension and Postretirement Benefit Plans: | ||||||||||||||||
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11) | 137 | 129 | 275 | 259 | ||||||||||||
Income Tax Expense | (36 | ) | (33 | ) | (72 | ) | (67 | ) | ||||||||
Pension and Postretirement Benefit Plans – net-of-tax | 101 | 96 | 203 | 192 | ||||||||||||
Total Other Comprehensive Income | 199 | 145 | 402 | 313 | ||||||||||||
Total Comprehensive Income | $ | 17,180 | $ | 15,571 | $ | 41,651 | $ | 42,063 | ||||||||
See accompanying condensed notes to consolidated financial statements. |
Consolidated Statements of Common Shareholders’ Equity
For the Three- and Six-Month Periods Ended June 30, 2020 and 2019
(not audited)
| ||||||
| ||||||
|
(in thousands, except common shares outstanding) | Common Shares Outstanding | Par Value, Common Shares | Premium on Common Shares | Retained Earnings | Accumulated Other Comprehensive Income/(Loss) | Total Common Equity | Common | Par Value, | Premium | Retained | Accumulated | Total | ||||||||||||||||||||||||||||||||||||
Balance, March 31, 2020 | 40,376,448 | $ | 201,882 | $ | 372,669 | $ | 231,702 | $ | (6,234 | ) | $ | 800,019 | ||||||||||||||||||||||||||||||||||||
Common Stock Issuances, Net of Expenses | 472,380 | 2,362 | 16,235 | 18,597 | ||||||||||||||||||||||||||||||||||||||||||||
Net Income | 16,981 | 16,981 | ||||||||||||||||||||||||||||||||||||||||||||||
Other Comprehensive Income | 199 | 199 | ||||||||||||||||||||||||||||||||||||||||||||||
Employee Stock Incentive Plan Expense | 1,237 | 1,237 | ||||||||||||||||||||||||||||||||||||||||||||||
Common Dividends ($0.37 per share) | (14,978 | ) | (14,978 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Balance, June 30, 2020 | 40,848,828 | $ | 204,244 | $ | 390,141 | $ | 233,705 | $ | (6,035 | ) | $ | 822,055 | ||||||||||||||||||||||||||||||||||||
Balance, March 31, 2019 | 39,729,708 | $ | 198,649 | $ | 342,991 | $ | 203,619 | $ | (4,760 | ) | $ | 740,499 | 39,729,708 | $ | 198,649 | $ | 342,991 | $ | 203,619 | $ | (4,760 | ) | $ | 740,499 | ||||||||||||||||||||||||
Common Stock Issuances, Net of Expenses | 25,194 | 126 | (109 | ) | 17 | 25,194 | 126 | (109 | ) | 17 | ||||||||||||||||||||||||||||||||||||||
Net Income | 15,426 | 15,426 | 15,426 | 15,426 | ||||||||||||||||||||||||||||||||||||||||||||
Other Comprehensive Income | 145 | 145 | 145 | 145 | ||||||||||||||||||||||||||||||||||||||||||||
Employee Stock Incentive Plan Expense | 2,148 | 2,148 | 2,148 | 2,148 | ||||||||||||||||||||||||||||||||||||||||||||
Common Dividends ($0.35 per share) | (13,930 | ) | (13,930 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Common Dividends ($0.35 per share) | (13,930 | ) | (13,930 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Balance, June 30, 2019 | 39,754,902 | $ | 198,775 | $ | 345,030 | $ | 205,115 | $ | (4,615 | ) | $ | 744,305 | 39,754,902 | $ | 198,775 | $ | 345,030 | $ | 205,115 | $ | (4,615 | ) | $ | 744,305 | ||||||||||||||||||||||||
Balance, March 31, 2018 | 39,626,594 | $ | 198,133 | $ | 341,841 | $ | 174,209 | $ | (6,133 | ) | $ | 708,050 | ||||||||||||||||||||||||||||||||||||
Balance, December 31, 2019 | 40,157,591 | $ | 200,788 | $ | 364,790 | $ | 222,341 | $ | (6,437 | ) | $ | 781,482 | ||||||||||||||||||||||||||||||||||||
Common Stock Issuances, Net of Expenses | 25,778 | 129 | (222 | ) | (93 | ) | 729,454 | 3,647 | 23,222 | 26,869 | ||||||||||||||||||||||||||||||||||||||
Common Stock Retirements | (936 | ) | (5 | ) | (36 | ) | (41 | ) | (38,217 | ) | (191 | ) | (1,878 | ) | (2,069 | ) | ||||||||||||||||||||||||||||||||
Net Income | 18,696 | 18,696 | 41,249 | 41,249 | ||||||||||||||||||||||||||||||||||||||||||||
Other Comprehensive Loss | 162 | 162 | ||||||||||||||||||||||||||||||||||||||||||||||
Other Comprehensive Income | 402 | 402 | ||||||||||||||||||||||||||||||||||||||||||||||
Employee Stock Incentive Plan Expense | 1,107 | 1,107 | 4,007 | 4,007 | ||||||||||||||||||||||||||||||||||||||||||||
Common Dividends ($0.335 per share) | (13,300 | ) | (13,300 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Balance, June 30, 2018 | 39,651,436 | $ | 198,257 | $ | 342,690 | $ | 179,605 | $ | (5,971 | ) | $ | 714,581 | ||||||||||||||||||||||||||||||||||||
Common Dividends ($0.74 per share) | (29,885 | ) | (29,885 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Balance, June 30, 2020 | 40,848,828 | $ | 204,244 | $ | 390,141 | $ | 233,705 | $ | (6,035 | ) | $ | 822,055 | ||||||||||||||||||||||||||||||||||||
Balance, December 31, 2018 | 39,664,884 | $ | 198,324 | $ | 344,250 | $ | 190,433 | $ | (4,144 | ) | $ | 728,863 | ||||||||||||||||||||||||||||||||||||
Balance, December 31, 2018 | 39,664,884 | $ | 198,324 | $ | 344,250 | $ | 190,433 | $ | (4,144 | ) | $ | 728,863 | ||||||||||||||||||||||||||||||||||||
Common Stock Issuances, Net of Expenses | 145,242 | 727 | (710 | ) | 17 | 145,242 | 727 | (710 | ) | 17 | ||||||||||||||||||||||||||||||||||||||
Common Stock Retirements | (55,224 | ) | (276 | ) | (2,454 | ) | (2,730 | ) | (55,224 | ) | (276 | ) | (2,454 | ) | (2,730 | ) | ||||||||||||||||||||||||||||||||
Net Income | 41,750 | 41,750 | 41,750 | 41,750 | ||||||||||||||||||||||||||||||||||||||||||||
Other Comprehensive Income | 313 | 313 | 313 | 313 | ||||||||||||||||||||||||||||||||||||||||||||
ASU 2018-02 2017 TCJA Stranded Tax Transfer | 784 | (784 | ) | - | 784 | (784 | ) | - | ||||||||||||||||||||||||||||||||||||||||
Employee Stock Incentive Plan Expense | 3,944 | 3,944 | 3,944 | 3,944 | ||||||||||||||||||||||||||||||||||||||||||||
Common Dividends ($0.70 per share) | (27,852 | ) | (27,852 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Common Dividends ($0.70 per share) | (27,852 | ) | (27,852 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Balance, June 30, 2019 | 39,754,902 | $ | 198,775 | $ | 345,030 | $ | 205,115 | $ | (4,615 | ) | $ | 744,305 | 39,754,902 | $ | 198,775 | $ | 345,030 | $ | 205,115 | $ | (4,615 | ) | $ | 744,305 | ||||||||||||||||||||||||
Balance, December 31, 2017 | 39,557,491 | $ | 197,787 | $ | 343,450 | $ | 161,286 | $ | (5,631 | ) | $ | 696,892 | ||||||||||||||||||||||||||||||||||||
Common Stock Issuances, Net of Expenses | 153,376 | 767 | (860 | ) | (93 | ) | ||||||||||||||||||||||||||||||||||||||||||
Common Stock Retirements | (59,431 | ) | (297 | ) | (2,153 | ) | (2,450 | ) | ||||||||||||||||||||||||||||||||||||||||
Net Income | 44,911 | 44,911 | ||||||||||||||||||||||||||||||||||||||||||||||
Other Comprehensive Loss | (340 | ) | (340 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Employee Stock Incentive Plan Expense | 2,253 | 2,253 | ||||||||||||||||||||||||||||||||||||||||||||||
Common Dividends ($0.67 per share) | (26,592 | ) | (26,592 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Balance, June 30, 2018 | 39,651,436 | $ | 198,257 | $ | 342,690 | $ | 179,605 | $ | (5,971 | ) | $ | 714,581 | ||||||||||||||||||||||||||||||||||||
Otter Tail Corporation
Consolidated Statements of Cash Flows
(not audited)
| ||
|
Six Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
(in thousands) | 2019 | 2018 | 2020 | 2019 | ||||||||||||
Cash Flows from Operating Activities | ||||||||||||||||
Operating Activities | ||||||||||||||||
Net Income | $ | 41,750 | $ | 44,911 | $ | 41,249 | $ | 41,750 | ||||||||
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: | ||||||||||||||||
Depreciation and Amortization | 38,572 | 37,508 | 40,835 | 38,572 | ||||||||||||
Deferred Tax Credits | (674 | ) | (703 | ) | (657 | ) | (674 | ) | ||||||||
Deferred Income Taxes | 960 | 2,076 | 9,472 | 960 | ||||||||||||
Change in Deferred Debits and Other Assets | 3,884 | 10,309 | 5,565 | 3,884 | ||||||||||||
Discretionary Contribution to Pension Plan | (10,000 | ) | (20,000 | ) | (11,200 | ) | (10,000 | ) | ||||||||
Change in Noncurrent Liabilities and Deferred Credits | 11,942 | (759 | ) | 5,178 | 11,942 | |||||||||||
Allowance for Equity/Other Funds Used During Construction | (688 | ) | (1,060 | ) | (1,858 | ) | (688 | ) | ||||||||
Stock Compensation Expense—Equity Awards | 3,944 | 2,253 | ||||||||||||||
Stock Compensation Expense | 4,007 | 3,944 | ||||||||||||||
Other—Net | 276 | (193 | ) | (147 | ) | 276 | ||||||||||
Cash (Used for) Provided by Current Assets and Current Liabilities: | ||||||||||||||||
Change in Receivables | (30,478 | ) | (25,677 | ) | (3,929 | ) | (30,478 | ) | ||||||||
Change in Inventories | 410 | (2,401 | ) | 8,097 | 410 | |||||||||||
Change in Other Current Assets | 2,870 | 2,428 | (1,066 | ) | 2,870 | |||||||||||
Change in Payables and Other Current Liabilities | 222 | 1,233 | (23,562 | ) | 222 | |||||||||||
Change in Interest and Income Taxes Receivable/Payable | 6,297 | 3,470 | 1,917 | 6,297 | ||||||||||||
Net Cash Provided by Operating Activities | 69,287 | 53,395 | 73,901 | 69,287 | ||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||
Investing Activities | ||||||||||||||||
Capital Expenditures | (54,012 | ) | (49,094 | ) | (119,830 | ) | (54,012 | ) | ||||||||
Net Proceeds from Disposal of Noncurrent Assets | 3,405 | 1,477 | ||||||||||||||
Proceeds from Disposal of Noncurrent Assets | 3,953 | 3,405 | ||||||||||||||
Cash Used for Investments and Other Assets | (4,776 | ) | (2,102 | ) | (5,128 | ) | (4,776 | ) | ||||||||
Net Cash Used in Investing Activities | (55,383 | ) | (49,719 | ) | (121,005 | ) | (55,383 | ) | ||||||||
Cash Flows from Financing Activities | ||||||||||||||||
Financing Activities | ||||||||||||||||
Change in Checks Written in Excess of Cash | (1,120 | ) | 2,236 | 550 | (1,120 | ) | ||||||||||
Net Short-Term Borrowings (Repayments) | 18,003 | (91,394 | ) | |||||||||||||
Net Short-Term Borrowings | 35,239 | 18,003 | ||||||||||||||
Proceeds from Issuance of Common Stock | 27,225 | - | ||||||||||||||
Common Stock Issuance Expenses | - | (108 | ) | (374 | ) | - | ||||||||||
Payments for Retirement of Capital Stock | (2,730 | ) | (2,450 | ) | ||||||||||||
Payments for Shares Withheld for Employee Tax Obligations | (2,069 | ) | (2,730 | ) | ||||||||||||
Proceeds from Issuance of Long-Term Debt | - | 100,000 | 35,000 | - | ||||||||||||
Short-Term and Long-Term Debt Issuance Expenses | - | (441 | ) | (179 | ) | - | ||||||||||
Payments for Retirement of Long-Term Debt | (84 | ) | (107 | ) | (90 | ) | (84 | ) | ||||||||
Dividends Paid | (27,852 | ) | (26,592 | ) | (29,885 | ) | (27,852 | ) | ||||||||
Net Cash Used in Financing Activities | (13,783 | ) | (18,856 | ) | ||||||||||||
Net Cash Provided by (Used in) Financing Activities | 65,417 | (13,783 | ) | |||||||||||||
Net Change in Cash and Cash Equivalents | 121 | (15,180 | ) | 18,313 | 121 | |||||||||||
Cash and Cash Equivalents at Beginning of Period | 861 | 16,216 | 21,199 | 861 | ||||||||||||
Cash and Cash Equivalents at End of Period | $ | 982 | $ | 1,036 | $ | 39,512 | $ | 982 | ||||||||
See accompanying condensed notes to consolidated financial statements. |
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(not audited)
In the opinion of management, Otter Tail Corporation (the Company) has included all adjustments (including normal recurring accruals) necessary for a fair presentation of the consolidated financial statements for the periods presented. The consolidated financial statements and condensed notes thereto should be read in conjunction with the consolidated financial statements and notes included in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2018.2019. Because of seasonalthe coronavirus (COVID-19) pandemic, the seasonality of our businesses and other factors, the earnings for the three-three and six-monthssix months ended June 30, 20192020 should not be taken as an indication of earnings for all or any part of the balance of the year.
The following condensed notes are numbered to correspond to numbers of the notes included in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2018.
1. Summary of Significant Accounting Policies
Revenue Recognition
Due to the diverse business operations of the Company, recognition of revenue from contracts with customers depends on the product produced and sold or service performed. The Company recognizes revenue from contracts with customers at prices that are fixed or determinable as evidenced by an agreement with the customer, when the Company has met its performance obligation under the contract and it is probable that the Company will collect the amount to which it is entitled in exchange for the goods or services transferred or to be transferred to the customer. Depending on the product produced and sold or service performed and the terms of the agreement with the customer, the Company recognizes revenue either over time, in the case of delivery or transmission of electricity or related services or the production and storage of certain custom-made products, or at a point in time for the delivery of standardized products and other products made to the customer’s specifications where the terms of the contract require transfer of the completed product. Provisions for sales returns, early payment terms discounts, volume-based variable pricing incentives and warranty costs are recorded as reductions to revenue at the time revenue is recognized based on customer history, historical information and current trends.
In addition to recognizing revenue from contracts with customers under Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Accounting Standards Update (ASU) Topic 606,No.2014-09,Revenue from Contracts with Customers(Topic (ASC 606) (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,RegRegulated Operationsulated 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 recognized based on the metered quantity of electricity delivered or transmitted at the applicable rates. For electricity delivered and consumed after a meter is read but prior to the end of the reporting period, OTP records revenue and an unbilled receivable based on estimates of the kilowatt-hours (kwh) of energy delivered to the customer.
ARPs provide for adjustments to rates outside of a general rate case proceeding, usually as a surcharge applied to future billings typically through the use of rate riders subject to periodic adjustments, to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. ARP riders generally provide for the recovery of specified costs and investments and include an incentive component to provide the regulated utility with a return on amounts invested.
OTP has recovered costs and earned incentives or returns on investments subject to recovery under several ARP rate riders, including:
● | In Minnesota: Transmission Cost Recovery (TCR), Environmental Cost Recovery (ECR), Renewable Resource Adjustment (RRA), Energy Intensive Trade Exposed and Conservation Improvement Program riders. |
● | In North Dakota: TCR, ECR, |
● | In South Dakota: TCR, ECR, Phase-In Rate Plan and Energy Efficiency Plan (conservation) riders. |
OTP accrues ARP revenue based on the basis of costs incurred, investments made and returns on those investments that qualify for recovery through established riders. Amounts billed under riders in effect at the time of the billing are included in revenues from contracts with customers net of amounts billed that are subject to refund through future rider adjustments. Amounts accrued and subject to recovery through future rider rate updates and adjustments are reported as changes in accrued revenues under ARPs on a separate line in the revenue section of the Company’s consolidated statement of income. See table in note 3 for total revenues billed and accrued under ARP riders for the three- and six-month periods ended June 30, 20192020 and 2018.2019.
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, the 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 product.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. Revenue for storage of the pipe is also recognized over time as the pipe is stored.
See operating revenue table in note 2 for a disaggregation of the Company’s revenues by business segment for the three- and six-month periods ended June 30, 20192020 and 2018.2019.
Agreements Subject to Legally Enforceable Netting Arrangements
OTP has certain derivative contracts that are designated as normal purchases. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The Company does not offset assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet.
Fair Value Measurements
The Company follows ASC Topic 820,Fair Value Measurements and Disclosures (ASC 820), for recurring fair value measurements. ASC 820 provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the hierarchy and examples of each level are as follows:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange.
Level 2 – Pricing inputs are other than quoted prices in active markets but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.
Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts.
The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 20192020 and December 31, 2018:2019:
June 30, 2019 (in thousands) | Level 1 | Level 2 | Level 3 | ||||||||||||||||||
June 30, 2020 (in thousands) | Level 1 | Level 2 | Level 3 | ||||||||||||||||||
Assets: | |||||||||||||||||||||
Investments: | |||||||||||||||||||||
Equity Funds – Held by Captive Insurance Company | $ | 1,483 | $ | 1,450 | |||||||||||||||||
Corporate Debt Securities – Held by Captive Insurance Company | $ | 3,368 | $ | 3,062 | |||||||||||||||||
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company | 4,701 | 5,960 | |||||||||||||||||||
Other Assets: | |||||||||||||||||||||
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan | 1,311 | ||||||||||||||||||||
Money Market and Mutual Funds –Retirement Plans | 1,560 | ||||||||||||||||||||
Total Assets | $ | 2,794 | $ | 8,069 | $ | 3,010 | $ | 9,022 | |||||||||||||
December 31, 2018 (in thousands) | Level 1 | Level 2 | Level 3 | ||||||||||||||||||
December 31, 2019 (in thousands) | Level 1 | Level 2 | Level 3 | ||||||||||||||||||
Assets: | |||||||||||||||||||||
Investments: | |||||||||||||||||||||
Equity Funds – Held by Captive Insurance Company | $ | 1,294 | $ | 1,586 | |||||||||||||||||
Corporate Debt Securities – Held by Captive Insurance Company | $ | 5,898 | $ | 2,124 | |||||||||||||||||
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company | 1,586 | 6,060 | |||||||||||||||||||
Other Assets: | |||||||||||||||||||||
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan | 838 | ||||||||||||||||||||
Money Market and Mutual Funds –Retirement Plans | 2,363 | ||||||||||||||||||||
Total Assets | $ | 2,132 | $ | 7,484 | $ | 3,949 | $ | 8,184 | |||||||||||||
The level 2 fair values for Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes.
Coyote Station Lignite Supply Agreement – Variable Interest Entity
In October 2012 the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of lignite coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton paid by the Coyote Station owners under the LSA reflects the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be 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 in that theybecause the Coyote Station owners are required to buy the entitymembership interests of CCMC at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually,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, as required by the LSA, the owners will satisfy or (if(or if permitted by CCMC’s applicable lender) assume,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 because regulations or legislation renderprior to the burningend of coal cost prohibitive and the assets worthless,term due to certain events, OTP’s maximum exposure to lossadditional costs, as a result of its involvement with CCMC, asand potential impairment loss if recovery of June 30, 2019 those costs is denied by regulatory authorities, could be as high as $52.2approximately $50.0 million, OTP’s 35% share of CCMC’s unrecovered costs.costs as of June 30, 2020.
Inventories
Inventories, valued at the lower of cost or net realizable value, consist of the following:
June 30, | December 31, | June 30, | December 31, | |||||||||||||
(in thousands) | 2019 | 2018 | 2020 | 2019 | ||||||||||||
Finished Goods | $ | 32,699 | $ | 37,130 | $ | 26,190 | $ | 31,863 | ||||||||
Work in Process | 19,414 | 20,393 | 14,418 | 16,508 | ||||||||||||
Raw Material, Fuel and Supplies | 53,747 | 48,747 | 49,146 | 49,480 | ||||||||||||
Total Inventories | $ | 105,860 | $ | 106,270 | $ | 89,754 | $ | 97,851 | ||||||||
Goodwill and Other Intangible Assets
An assessment of the carrying amounts of goodwill of the Company’s operating units as of December 31, 2018 indicated the fair values are substantially in excess of their respective book values and not impaired.
The following table indicates there were no changes to goodwill by business segment during the firstsix months of 2019:
(in thousands) | Gross Balance December 31, 2018 | Accumulated Impairments | Balance (net of impairments) December 31, 2018 | Adjustments to Goodwill in 2019 | Balance (net of impairments) June 30, 2019 | |||||||||||||||
Manufacturing | $ | 18,270 | $ | - | $ | 18,270 | $ | - | $ | 18,270 | ||||||||||
Plastics | 19,302 | - | 19,302 | - | 19,302 | |||||||||||||||
Total | $ | 37,572 | $ | - | $ | 37,572 | $ | - | $ | 37,572 | ||||||||||
Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360-10-35,Property, Plant, and Equipment—Overall—Subsequent Measurement.
The following table summarizes the components of the Company’s intangible assets at June 30, 20192020 and December 31,2018:2019:
June 30, 2019 (in thousands) | Gross Carrying Amount | Accumulated Amortization | Net Carrying Amount | Remaining Amortization Periods (months) | ||||||||||||||||||||||||||||||
June 30, 2020 (in thousands) | Gross Carrying | Accumulated | Net Carrying Amount | Remaining | ||||||||||||||||||||||||||||||
Amortizable Intangible Assets: | ||||||||||||||||||||||||||||||||||
Customer Relationships | $ | 22,491 | $ | 10,693 | $ | 11,798 | 6 | - | 194 | $ | 22,491 | $ | 11,820 | $ | 10,671 | 82 | - | 182 | ||||||||||||||||
Other | 154 | 94 | 60 | 14 | 179 | 147 | 32 | 2 | - | 39 | ||||||||||||||||||||||||
Total | $ | 22,645 | $ | 10,787 | $ | 11,858 | $ | 22,670 | $ | 11,967 | $ | 10,703 | ||||||||||||||||||||||
December 31, 2018 (in thousands) | Gross Carrying Amount | Accumulated Amortization | Net Carrying Amount | Remaining Amortization Periods (months) | ||||||||||||||||||||||||||||||
December 31, 2019 (in thousands) | Gross Carrying Amount | Accumulated Amortization | Net Carrying Amount | Remaining Amortization Periods (months) | ||||||||||||||||||||||||||||||
Amortizable Intangible Assets: | ||||||||||||||||||||||||||||||||||
Customer Relationships | $ | 22,491 | $ | 10,127 | $ | 12,364 | 12 | - | 200 | $ | 22,491 | $ | 11,259 | $ | 11,232 | 88 | - | 188 | ||||||||||||||||
Other | 154 | 68 | 86 | 20 | 179 | 121 | 58 | 8 | - | 45 | ||||||||||||||||||||||||
Total | $ | 22,645 | $ | 10,195 | $ | 12,450 | $ | 22,670 | $ | 11,380 | $ | 11,290 | ||||||||||||||||||||||
The amortization expense for these intangible assets was:
Three Months Ended | Six Months Ended | Three Months Ended | Six Months Ended | |||||||||||||||||||||||||||||
June 30, | June 30, | June 30, | June 30, | |||||||||||||||||||||||||||||
(in thousands) | 2019 | 2018 | 2019 | 2018 | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||||
Amortization Expense – Intangible Assets | $ | 296 | $ | 345 | $ | 592 | $ | 690 | $ | 291 | $ | 296 | $ | 587 | $ | 592 | ||||||||||||||||
The estimated annual amortization expense for these intangible assets for the next five years is:
(in thousands) | 2019 | 2020 | 2021 | 2022 | 2023 | |||||||||||||||
Estimated Amortization Expense – Intangible Assets | $ | 1,184 | $ | 1,133 | $ | 1,099 | $ | 1,099 | $ | 1,099 | ||||||||||
(in thousands) | 2020 | 2021 | 2022 | 2023 | 2024 | |||||||||||||||
Estimated Amortization Expense – Intangible Assets | $ | 1,140 | $ | 1,105 | $ | 1,105 | $ | 1,104 | $ | 1,099 | ||||||||||
Supplemental Disclosures of Cash Flow Information
As of June 30, | ||||||||
(in thousands) | 2020 | 2019 | ||||||
Noncash Investing Activities: | ||||||||
Transactions Related to Capital Additions not Settled in Cash | $ | 61,925 | $ | 16,841 | ||||
As of June 30, | ||||||||
(in thousands) | 2019 | 2018 | ||||||
Noncash Investing Activities: | ||||||||
Transactions Related to Capital Additions not Settled in Cash | $ | 16,841 | $ | 11,564 | ||||
New Accounting Standards Adopted
ASU 2016--0213—In FebruaryJune 2016 the FASB issued ASU No.2016-02,Leases (Topic 842) (ASU 2016-02). ASU 2016-02 is a comprehensive amendment of the ASC, creating Topic 842, which supersedes the requirements under ASC Topic 840 on leases and requires the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. The amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The main difference between previous Generally Accepted Accounting Principles in the United States (GAAP) and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. The Company adopted the amendments in ASU 2016-02 to its consolidated financial statements effective January 1, 2019. See note 8 for further information on leases and the Company’s elections for applying the new standard.
ASU 2018-02—In February 2018 the FASB issued ASU No.2018-02,Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (ASU 2018-02). The amendments in ASU 2018-02, which are narrow in scope, allow a reclassification from accumulated other comprehensive income/(loss) (AOCI/(L)) to retained earnings for the stranded tax effects resulting from the Tax Cuts and Jobs Act (TCJA). Consequently, the amendments eliminate the stranded tax effects resulting from the TCJA and will improve the usefulness of information reported to financial statement users. The amendments in ASU 2018-02 also require certain disclosures about stranded tax effects and are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The amendments in ASU 2018-02 can be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the TCJA is recognized.
The Company adopted the updates in ASU 2018-02 effective January 1, 2019, applying them in the period of adoption and not retrospectively. On adoption, the Company reclassified $784,000 of income tax effects of the TCJA on the gross deferred tax amounts reflected in AOCI/(L) at the date of enactment of the TCJA from AOCI/(L) to retained earnings so the remaining gross deferred tax amounts related to items in AOCI/(L) will reflect current effective tax rates.
Support for the determination of the stranded tax effects resulting from the enactment of the TCJA in AOCI/(L) is provided in the table below.
(in thousands) | Unrealized Gains on Available-for- Sale Securities | Unamortized Actuarial Losses and Prior Service Costs on Pension and Other Postretirement Benefits | AOCI/(L) | |||||||||
Balance on December 22, 2017 – Pre-tax | $ | 71 | $ | (5,672 | ) | $ | (5,601 | ) | ||||
Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts | $ | 10 | $ | (794 | ) | $ | (784 | ) | ||||
ASU 2017-04—In January 2017 the FASB issued ASU No.2017-04,Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04), which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. In computing the implied fair value of goodwill under Step 2, an entity must perform procedures to determine the fair value at the impairment testing date of its assets and liabilities (including unrecognized assets and liabilities) following the procedure that would be required in determining the fair value of assets acquired and liabilities assumed in a business combination. Under the amendments in ASU 2017-04, an entity will perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized will not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity will consider income tax effects from any tax-deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable.
The amendments in ASU 2017-04 modify the concept of impairment from the condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of a reporting unit exceeds its fair value. An entity no longer will determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Because these amendments eliminate Step 2 from the goodwill impairment test, they should reduce the cost and complexity of evaluating goodwill for impairment. The amendments in ASU 2017-04 are effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. The Company early adopted the amendments in ASU 2017-04 in the first quarter of 2019. The Company had no indication that any of its goodwill was impaired, therefore, the adoption of the updated standard had no impact on the Company’s consolidated financial statements.
New Accounting Standards Update (ASU) No.Pending Adoption
ASU 2016-13,—In June 2016 the FASB issued ASU No.2016-13,Financial Instruments—Credit Losses(Topic (Topic 326)(ASC Topic 326), which changes how entities account for credit losses on receivables and certain other assets. 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 Topic 326 in the first quarter of 2020. Adoption of the new standard did not have a material impact on the Company’s consolidated financial statements, and the Company did not record a cumulative effect adjustment to retained earnings on adoption.
Accounting Policy
Trade account and unbilled receivables reflected in the Company’s consolidated balance sheets represent the net amounts expected to be collected. An allowance for credit losses is established based on expected losses. Expected losses are estimated by reviewing individual accounts, considering aging, financial condition of the debtor for certain accounts, recent payment history, current and forecasted economic conditions and other relevant factors.
Allowance for Credit Losses
Following is a summary of activity in allowances for credit losses on trade and unbilled accounts receivable across the Company:
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
(in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||
Beginning Balance | $ | 1,681 | $ | 1,533 | $ | 1,339 | $ | 1,407 | ||||||||
Additions Charged to Expense (net of recoveries) | 736 | 216 | 1,371 | 463 | ||||||||||||
Reductions for Amounts Written Off | (317 | ) | (58 | ) | (610 | ) | (179 | ) | ||||||||
Ending Balance | $ | 2,100 | $ | 1,691 | $ | 2,100 | $ | 1,691 | ||||||||
ASU 2018-15—In August 2018 the FASB issued ASU No.2018-15,Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40), which amends ASC 350-40, Internal-Use Software, to address a customer's accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. The amendments in ASU 2018-15 align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). Accordingly, the amendments in ASU 2018-15 require an entity (customer) in a hosting arrangement that is a service contract to follow the guidance in ASC 350-40 to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The amendments in ASU 2018-15 also require the entity to present the expense related to the capitalized implementation costs in the same line item in the statement of income as the fees associated with the hosting element (service) of the arrangement and classify payments for capitalized implementation costs in the statement of cash flows in the same manner as payments made for fees associated with the hosting element. The entity is also required to present the capitalized implementation costs in the statement of financial position in the same line item that a prepayment for the fees of the associated hosting arrangement would be presented. The amendments in ASU 2018-15 were effective for interim and annual periods beginning on or after December 15, 2019.2019 with early adoption permitted in any interim period. The Company is currently evaluating whatadopted the amendments in ASU 2018-15 in the first quarter of 2020. There was no impact adoption of the new standard may have onto its consolidated financial statements.statements on adoption, but the Company will begin capitalizing implementation costs incurred in cloud computing arrangements post-adoption.
2. Segment Information
The accounting policies of the segments are described under note 1 – Summary of Significant Accounting Policies. The Company's businesses have been classified into three segments to be consistent with its business strategy and the reporting and review process used by the Company’s chief operating decision maker. These businesses sell products and provide services to customers primarily in the United States. The Company’s business structure currently includes the following three3 segments: Electric, Manufacturing and Plastics. The chart below indicates the companies included in each segment.
Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is a participant in the Midcontinent Independent System Operator, Inc. (MISO) markets. OTP’s operations have been the Company’s primary business since 1907.
Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping, fabrication and painting, and production of plastic thermoformed horticultural containers, life science and industrial packaging, and material handling components and extruded raw material stock.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 upper Midwest and Southwest regionsUnited States, west of the United States.Mississippi River.
OTP is a wholly owned subsidiary of the Company. All of the Company’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation. The Company’s Corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’s 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, it is added to operating segment totals to reconcile to totals on the Company’s consolidated financial statements.
While no0 single customer accounted for over 10% of the Company’s consolidated revenue in 2018,2019, certain customers provided a significant portion of each business segment’s 20182019 revenue. The Electric segment has one1 customer that provided 11.2%11.9% of 20182019 segment revenues. The Manufacturing segment has one1 customer that manufactures and sells recreational vehicles that provided 22.2%23.8% of 20182019 segment revenues and one1 customer that manufactures and sells lawn and garden equipment that
provided 11.2% of 20182019 segment revenues. The Manufacturing segment’s top five5 revenue-generating customers provided over 52%54% of 20182019 segment revenues. The Plastics segment has two2 customers that togetherindividually provided 39.1%25.3% and 20.4% of 20182019 segment revenues. The loss of any one of these customers would have a significant negative impact on the financial position and results of operations of the respective business segment and the Company.
All of the Company’s long-lived assets are within the United States and sales within the United States accounted for 98.5%98.9% and 98.2%98.5% of operating revenues for the respective three-month periods ended June 30, 20192020 and 2018,2019, and 98.8%99.0% and 98.3%98.8% of operating revenues for the respective six-month periods ended June 30, 20192020 and 2018.2019.
The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three- and six-month periods ended June 30, 2019 and 20182020 and total assets by business segment as of June 30, 20192020 and December 31, 20182019 are presented in the following tables:
Operating Revenue
Three Months Ended | Six Months Ended | Three Months Ended | Six Months Ended | |||||||||||||||||||||||||||||
June 30, | June 30, | June 30, | June 30, | |||||||||||||||||||||||||||||
(in thousands) | 2019 | 2018 | 2019 | 2018 | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||||
Electric Segment: | ||||||||||||||||||||||||||||||||
Retail Sales Revenue from Contracts with Customers | $ | 87,976 | $ | 89,400 | $ | 202,931 | $ | 198,580 | $ | 85,344 | $ | 87,976 | $ | 192,034 | $ | 202,931 | ||||||||||||||||
Changes in Accrued ARP Revenues | 369 | (1,565 | ) | (680 | ) | (2,440 | ) | 209 | 369 | 122 | (680 | ) | ||||||||||||||||||||
Total Retail Sales Revenue | 88,345 | 87,835 | 202,251 | 196,140 | 85,553 | 88,345 | 192,156 | 202,251 | ||||||||||||||||||||||||
Transmission Services Revenue | 11,469 | 11,313 | 22,331 | 23,216 | 9,673 | 11,469 | 20,514 | 22,331 | ||||||||||||||||||||||||
Wholesale Revenues – Company Generation | 941 | 2,539 | 2,468 | 3,554 | 765 | 941 | 1,641 | 2,468 | ||||||||||||||||||||||||
Other Revenues | 1,489 | 2,038 | 3,303 | 3,780 | 2,162 | 1,489 | 3,718 | 3,303 | ||||||||||||||||||||||||
Total Electric Segment Revenues | 102,244 | 103,725 | 230,353 | 226,690 | 98,153 | 102,244 | 218,029 | 230,353 | ||||||||||||||||||||||||
Manufacturing Segment: | ||||||||||||||||||||||||||||||||
Metal Parts and Tooling | 62,541 | 57,388 | 129,265 | 114,315 | 37,267 | 62,541 | 94,478 | 129,265 | ||||||||||||||||||||||||
Plastic Products and Tooling | 9,353 | 7,961 | 18,398 | 18,196 | 7,840 | 9,353 | 17,723 | 18,398 | ||||||||||||||||||||||||
Other | 1,602 | 2,805 | 3,655 | 4,305 | 841 | 1,602 | 2,226 | 3,655 | ||||||||||||||||||||||||
Total Manufacturing Segment Revenues | 73,496 | 68,154 | 151,318 | 136,816 | 45,948 | 73,496 | 114,427 | 151,318 | ||||||||||||||||||||||||
Plastics Segment – Sale of PVC Pipe Products | 53,476 | 54,476 | 93,534 | 104,129 | 48,679 | 53,476 | 95,076 | 93,534 | ||||||||||||||||||||||||
Intersegment Eliminations | (13 | ) | (7 | ) | (30 | ) | (21 | ) | (24 | ) | (13 | ) | (29 | ) | (30 | ) | ||||||||||||||||
Total | $ | 229,203 | $ | 226,348 | $ | 475,175 | $ | 467,614 | $ | 192,756 | $ | 229,203 | $ | 427,503 | $ | 475,175 | ||||||||||||||||
Interest Charges
Three Months Ended | Six Months Ended | Three Months Ended | Six Months Ended | |||||||||||||||||||||||||||||
June 30, | June 30, | June 30, | June 30, | |||||||||||||||||||||||||||||
(in thousands) | 2019 | 2018 | 2019 | 2018 | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||||
Electric | $ | 6,625 | $ | 6,687 | $ | 13,266 | $ | 13,077 | $ | 7,348 | $ | 6,625 | $ | 14,732 | $ | 13,266 | ||||||||||||||||
Manufacturing | 646 | 555 | 1,230 | 1,109 | 554 | 646 | 1,108 | 1,230 | ||||||||||||||||||||||||
Plastics | 215 | 160 | 364 | 310 | 186 | 215 | 334 | 364 | ||||||||||||||||||||||||
Corporate and Intersegment Eliminations | 339 | 274 | 791 | 552 | 574 | 339 | 611 | 791 | ||||||||||||||||||||||||
Total | $ | 7,825 | $ | 7,676 | $ | 15,651 | $ | 15,048 | $ | 8,662 | $ | 7,825 | $ | 16,785 | $ | 15,651 | ||||||||||||||||
Income Taxes
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
(in thousands) | 2019 | 2018 | 2019 | 2018 | ||||||||||||
Electric | $ | 1,037 | $ | 611 | $ | 5,808 | $ | 2,709 | ||||||||
Manufacturing | 1,149 | 1,018 | 2,603 | 2,241 | ||||||||||||
Plastics | 2,044 | 2,207 | 3,373 | 4,621 | ||||||||||||
Corporate | (887 | ) | (782 | ) | (2,813 | ) | (2,723 | ) | ||||||||
Total | $ | 3,343 | $ | 3,054 | $ | 8,971 | $ | 6,848 | ||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
(in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||
Electric | $ | 2,579 | $ | 1,037 | $ | 6,199 | $ | 5,808 | ||||||||
Manufacturing | (189 | ) | 1,149 | 1,272 | 2,603 | |||||||||||
Plastics | 1,818 | 2,044 | 3,735 | 3,373 | ||||||||||||
Corporate | (400 | ) | (887 | ) | (1,760 | ) | (2,813 | ) | ||||||||
Total | $ | 3,808 | $ | 3,343 | $ | 9,446 | $ | 8,971 | ||||||||
Net Income (Loss)
Three Months Ended | Six Months Ended | Three Months Ended | Six Months Ended | |||||||||||||||||||||||||||||
June 30, | June 30, | June 30, | June 30, | |||||||||||||||||||||||||||||
(in thousands) | 2019 | 2018 | 2019 | 2018 | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||||
Electric | $ | 7,502 | $ | 10,600 | $ | 26,202 | $ | 27,268 | $ | 13,306 | $ | 7,502 | $ | 29,488 | $ | 26,202 | ||||||||||||||||
Manufacturing | 3,990 | 3,583 | 8,832 | 7,747 | 238 | 3,990 | 5,165 | 8,832 | ||||||||||||||||||||||||
Plastics | 5,792 | 6,229 | 9,521 | 13,073 | 5,130 | 5,792 | 10,579 | 9,521 | ||||||||||||||||||||||||
Corporate | (1,858 | ) | (1,716 | ) | (2,805 | ) | (3,177 | ) | (1,693 | ) | (1,858 | ) | (3,983 | ) | (2,805 | ) | ||||||||||||||||
Total | $ | 15,426 | $ | 18,696 | $ | 41,750 | $ | 44,911 | $ | 16,981 | $ | 15,426 | $ | 41,249 | $ | 41,750 | ||||||||||||||||
Identifiable Assets
June 30, | December 31, | June 30, | December 31, | |||||||||||||
(in thousands) | 2019 | 2018 | 2020 | 2019 | ||||||||||||
Electric | $ | 1,752,432 | $ | 1,728,534 | $ | 2,054,523 | $ | 1,931,525 | ||||||||
Manufacturing | 211,374 | 187,556 | 184,462 | 195,742 | ||||||||||||
Plastics | 104,762 | 91,630 | 102,285 | 92,049 | ||||||||||||
Corporate | 46,376 | 44,797 | 47,969 | 54,279 | ||||||||||||
Total | $ | 2,114,944 | $ | 2,052,517 | $ | 2,389,239 | $ | 2,273,595 | ||||||||
3. Rate and Regulatory Matters
Below are descriptions of OTP’s major capital expenditure projects that have had, or 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 20192020 and 2018.2019.
Major Capital Expenditure Projects
Merricourt Wind Energy Center (Merricourt)—On November 16, 2016 OTP entered into an Asset Purchase Agreement (the Purchase Agreement) with EDF Renewable Development, Inc. and certain of its affiliated companies (collectively, EDF) to purchase the development assets and assume certain specified liabilities associated with Merricourt, a 150-megawatt (MW) wind farm in southeastern North Dakota, for a purchase price of approximately $34.7 million, subject to adjustments for interconnection costs. Also on November 16, 2016, OTP entered into a Turnkey Engineering, Procurement and Construction Services Agreement (the TEPC Agreement) with EDF-RE US Development, LLC (EDF-USD) pursuant to which EDF-USD will develop, design, procure, construct, interconnect, test and commission the wind farm with a targeted completion date in 2020 for consideration of approximately $200.5 million, subject to certain adjustments, payable following the closing of the Purchase Agreement in installments in connection with certain project construction milestones. In connection with action by the FERC, OTP and EDF-US agreed, in the First Amendment to the Purchase Agreement and the TEPC Agreement dated June 11,2019, to change the purchase price to $37.7 million and 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 FERC in April 2019.
OTP is earning a return in all three states served by OTP on amounts invested in Merricourt while the project is under construction. Returns are recovered in Minnesota and North Dakota through RRA riders and in South Dakota through the Phase-In Rate Plan rider. As of June 30, 2020, OTP had capitalized approximately $131.7 million in project costs and allowance for funds used during construction (AFUDC) associated with Merricourt. While construction on site continues, OTP has received Notices of Force Majeure from EDF-USD claiming rights to an extension of guaranteed project completion dates and adjustments to the consideration agreed upon in the TEPC Agreement due to COVID-19 impacts. While details regarding these claims and the related impacts to the project remain uncertain, OTP currently expects Merricourt to be completed before December 31, 2020.
Astoria Station—OTP is constructing this 245-megawatt (MW)245 MW simple-cycle natural gas-fired combustion turbine generation facility near Astoria, South Dakota as part of its plan to reliably meet customers’ electric needs, replace expiring capacity purchase agreements and prepare for the planned retirement of its Hoot Lake Plant in 2021. A final order granting an AdvanceAdvanced Determination of Prudence (ADP) for Astoria Station was issued by the NDPSC on November 3, 2017, subject to certain qualifications and compliance obligations. On August 3, 2018 the SDPUC issued an order granting a site permit for Astoria Station. In a September 26, 2018 hearing the NDPSC established a GCR rider for future recovery of costs incurred for Astoria Station. On March 6, 2019 the SDPUC issued an order approving a settlement that allows a phase-in rider which includes recovery of Astoria Station costs. The interconnection agreement for Astoria Station was executed by MISO in December 2018 and accepted by the FERC in January 2019. Site preparation and excavatingexcavation began in May 2019.2019, and construction is occurring on the site. As of June 30, 2019,2020, OTP had capitalized approximately $19.6$108.0 million in project costs and allowance for funds used during construction (AFUDC)AFUDC associated with Astoria Station. OTP currently expects thethis project will cost approximately $158 million.
Merricourt Wind Energy Center (Merricourt)—Onbe completed in late 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 and assume the development assets and certain specified liabilities associated with Merricourt, a 150-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 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. The agreements contain customary representations, warranties, covenants and indemnities for this type of transaction. On October 26,2020 or early 2017 the MPUC approved the facility under the Renewable Energy Standard making Merricourt eligible for cost recovery under the Minnesota Renewable Resource Recovery rider, subject to qualifications and reporting obligations. The MPUC’s final written order was issued on January 10, 2018. A final order for an ADP, subject to qualifications and compliance obligations, and a Certificate of Public Convenience and Necessity were issued by the NDPSC on November 3, 2017. The phase-in rider approved by order of the SDPUC on March 6, 2019 includes recovery of Merricourt costs. The Merricourt generator interconnection agreement with MISO was approved by the FERC in April 2019.2021.
In connection with action by the FERC, OTP and EDF agreed, in the First Amendment to the Purchase Agreement and the TEPC Agreement dated June 11, 2019, to change the purchase price to $37.7 million and 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. As of June 30, 2019, OTP had capitalized approximately $5.6 million in development costs and AFUDC associated with Merricourt. OTP expects the project will cost approximately $270 million.
Big Stone South–Ellendale Multi-Value Transmission Project (MVP)General Rates—This 345-kilovolt transmission line, energized on February 6, 2019, extends 163 miles between a substation near Big Stone City, South Dakota and a substation near Ellendale, North Dakota. OTP jointly developed this project with Montana-Dakota Utilities Co., and the parties have equal ownership interest in the transmission line portion of the project. The MISO approved this project as an MVP under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff) in December 2011. MVPs are designed to enable the MISO region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation is designed to ensure the costs of transmission projects with regional benefits are properly assigned to those who benefit. OTP’s capitalized costs on this project as of June 30, 2019 were approximately $106 million, which includes assets that are 100% owned by OTP.
Recovery of OTP’s major transmission investments is through the MISO Tariff and Minnesota, North Dakota and South Dakota base rates and TCR riders.
Minnesota
General Rates—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 8.61%7.5056% and its allowed rate of return on equity (ROE) is 10.74%9.41%.
The MPUC’s order also included: (1) the determination that all costs (including FERC allocated costs and revenues) of the Big Stone South–Brookings and Big Stone South–Ellendale MVPs will be included in the Minnesota TCR rider and jurisdictionally allocated to OTP’s Minnesota customers (see discussion under Minnesota Transmission Cost Recovery Rider below), and (2) approval of OTP’s proposal to transition rate base, expenses and revenues from ECR and TCR riders to base rate recovery, which occurred when final rates were implemented on November 1, 2017. Certain MISO expenses and revenues remain in the TCR rider to allow for the ongoing refund or recovery of these variable revenues and costs.
North Dakota—On March 23, 2018 OTP made a supplemental filing to its initial request for a rate review, reducing its request for an annual revenue increase from $13.1 million to $7.1 million, a 4.8% annual increase. The $6.0 million decrease included $4.8 million related to tax reform and $1.2 million related to other updates.
In a September 26, 2018 hearing the NDPSC approved an overall annual revenue increase of $4.6 million (3.1%) and a ROE of 9.77% on a 52.5% equity capital structure. The NDPSC’s approval established a GCR rider for future recovery of costs incurred for Astoria Station. The net revenue increase reflected a reduction in income tax recovery requirements related to the 2017 Tax Cuts and Jobs Act (TCJA) and decreases in rider revenue recovery requirements. Final rates were effective February 1,2019, with refunds of excess revenues collected under interim rates applied to customers’ April 2019 bills, including $0.8 million for amounts collected reflecting the higher tax rates under interim rates in effect in January and February 2018.
South Dakota—On April 20, 2018 OTP filed a request with the SDPUC to increase non-fuel rates in South Dakota by approximately $3.3 million annually, or 10.1%, as the first step in a two-step request. Interim rates were effective October 18,2018. The second step in the request was an additional 1.7% revenue increase to recover costs for Merricourt when the wind generation facility goes into service. The SDPUC approved a partial settlement on March 1, 2019 on all issues of the rate case except ROE. The partial settlement included approval of a phase-in plan to provide for a return on amounts invested in Astoria Station and Merricourt, which addressed the second step of the request for increased rates in South Dakota. The partial settlement also included a moratorium on filing another general rate case in South Dakota until the new generation projects have been in service for a year. The partial settlement also allowed OTP to retain the impact of lower tax rates related to the TCJA from January 1, 2018 through October 17,2018 resulting in the reversal of an accrued refund liability and recognition of $1.0 million in revenue in the first quarter of 2019. The SDPUC approved the ROE portion of the rate case on May 14, 2019 and pursuant to the SDPUC’s May 30, 2019 order, OTP’s allowed ROE was set at 8.75%, resulting in an annual revenue increase of approximately $2.2 million. Final rates went into effect August 1, 2019. An interim rate refund for the lower ROE going back to October 18, 2018 was applied to South Dakota customers’ October 2019 bills.
On July 9, 2019 the SDPUC approved a stipulation agreement entered into by OTP with SDPUC staff. The revenue requirement stated in the SDPUC’s final order dated May 30, 2019 understated the amount of OTP's South Dakota share of electric transmission plant in service, resulting in an annual revenue requirement shortfall of approximately $341,000. To address the shortfall, the parties agreed that OTP would file an update to its South Dakota TCR rider. OTP was authorized full recovery of the transmission rate base correction reflected in the TCR rider tracker beginning as of the first date of interim rates, October 18, 2018, with the TCR rider rate update going into effect on October 1, 2019.
To ensure rates are appropriately set under the stipulation, the parties agreed to establish an earnings sharing mechanism to share with customers any weather-normalized earnings above the authorized ROE of 8.75%. OTP's annual weather-normalized earnings are reported each year by June 1 in its jurisdictional annual report, which will be used to determine the earnings level for purposes of calculating any refund. The earnings sharing mechanism requires that OTP will refund to customers 50% of any weather-normalized revenue that corresponds to the earnings in excess of its authorized ROE, up to a maximum of 9.50% ROE for a particular year. OTP will refund 100% of any earnings above 9.50% each year. In the event a refund is due under this provision, OTP will notify the SDPUC of the refund amount and plan for crediting customers within 30 days of filing its South Dakota jurisdictional annual report.
Rate Riders
In addition to general rates, OTP has several rate riders in place in each of its state jurisdictional service areas. These rate riders are designed to recover expenses, costs and returns on rate base investments not currently being recovered in base, or general, rates. In addition to fuel cost recovery riders in each state, OTP has recovered costs and earned incentives or returns on investments subject to recovery under several rate riders, including:
● | In Minnesota: Transmission Cost Recovery (TCR), Environmental Cost Recovery (ECR), Renewable Resource Adjustment (RRA), Energy Intensive Trade Exposed and Conservation Improvement Program riders. |
● | In North Dakota: TCR, ECR, Renewable Resource Cost Recovery and Generation Cost Recovery (GCR) riders. |
● | In South Dakota: TCR, ECR, Phase-In Rate Plan and Energy Efficiency Plan (conservation) riders. |
Following is a brief summary of recent proceedings of riders in place in each state served by OTP, followed by tables showing revenues recorded under rate riders for the three- and six-month periods ended June 30, 2020 and June 30, 2019 and a listing of rate rider updates impacting revenues in 2020 and 2019. Additional information and background on these rate riders is provided in the Company’s Annual Report on Form 10-K for the year ended December 31, 2019.
Minnesota
Minnesota Conservation Improvement Programs (MNCIP)—OTP recovers conservation related costs not included in base rates under the MNCIP through the use of an annual recovery mechanism approved by the MPUC. On May 25, 2016 the MPUC adopted changes to the MNCIP financial incentive. The model included incentives for utilities of 13.5% of 2017 net benefits, 12% of 2018 net benefits and 10% of 2019 net benefits, assuming the utility achieves 1.7% savings compared to retail sales. The financial incentive was also limited to 40% of 2017 MNCIP spending and 35% of 2018 spending and will be limited to 30% of 2019 spending. The new model reduces the MNCIP financial incentive by approximately 50% compared to the previous incentive mechanism. The Minnesota Department of Commerce (MNDOC) issued a decision on May 20, 2019 to extend all utilities 2017-2019 CIP plans one year, through 2020.
On April 1, 20192020 OTP filed a request for approval of its 20182019 energy savings, recovery of $3.0$2.7 million in accrued financial incentives and recovery of 20182019 program costs not included in base rates. On May 31, 2019 the MNDOC staff filed its comments with the MPUC on OTP’s 2018 petition to update its MNCIP rider, recommending the MPUC approve OTP’s petition with modifications. On June 24, 2019 OTP filed reply comments to the MNDOC staff recommendation reaffirming the $3.0 million request and offered an alternative $4.0 million financial incentive for the MPUC to consider.
Transmission Cost Recovery Rider—The Minnesota Public Utilities Act provides a mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that meet certain criteria, plus a return on investment at the level approved in a utility’s last general rate case. Additionally, following approval of the rate schedule, the MPUC may approve annual rate adjustments filed pursuant to the rate schedule.
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 MVPsMulti-Value Projects (MVPs) and all revenues received from other utilities under MISO’s tariffed rates as a credit in its TCR revenue requirement calculations. In doing so, the MPUC’s order diverted interstate wholesale revenues that have been approved by the FERC to offset FERC-approved expenses, effectively reducing OTP’s recovery of those FERC-approved expense levels. The
MPUC-ordered treatment resulted in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC’s revenue requirements and authorized returns vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision wouldcan 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 18,2017OTP filed an appeal of the MPUC general rate case order with the Minnesota Court of Appeals to contest the portion of the order requiring OTP to jurisdictionally allocate costs of the FERC MVP transmission projects in the TCR rider.
On June 11, 2018 the Minnesota Court of Appeals reversed the MPUC’s order related to the inclusion of Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVPs and all revenues received from other utilities under MISO’s tariffed rates as a credit in OTP Minnesota TCR revenue requirement calculations. On July 11, 2018 the MPUC filed a petition for review of the MVP decision to the Minnesota Supreme Court, which granted review of the Minnesota Court of Appeals decision. Oral arguments were heard by the Minnesota Supreme Court on March 11, 2019.
On November 30, 2018 OTP filed its annual update and supplemental filing to the Minnesota TCR rider. In this filing two scenarios were submitted based on whether the Minnesota Supreme Court affirmsaffirmed the original decision by the Minnesota Court of Appeals to exclude the MVP projects from the TCR rider or overturnsoverturned the Minnesota Court of Appeals decision and includes the two MVP projects in the TCR rider. Action by the Minnesota Supreme Court is expected later in 2019. In addition, on April 1, 2019, the MNDOC filed comments in OTP’s TCR rider docket, opposing OTP’s proposal for TCR rider recovery of these costs. The Minnesota Supreme Court issued its opinion on April 22,2020, concluding that the MPUC is 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 May 7, 2020 OTP filed reply comments in the docket within 15 expected to act on the TCR rider until afterdays of the Minnesota Supreme Court has actedruling as required by the MPUC. OTP filed updated revenue requirements excluding the Brookings and additional briefing has occurredBig Stone–Ellendale projects and including three projects previously requested in the docket.Minnesota TCR rider eligibility petition. OTP requested new rates be implemented January 1, 2021 with the three new projects deemed eligible for TCR rider recovery effective January 1, 2020. OTP also requested one-half of the December 2020 tracker balance of $13.4 million be included in the January 1, 2021 revenue requirement with the remainder included in the next annual update. OTP also requested a carrying charge be included as of January 1, 2021. On June 4, 2020 the MPUC filed a Notice of Combined and Extended Comment Period for both the Minnesota TCR rider and TCR rider eligibility filing with the comment period closing on July 6, 2020 and the reply comment period closing on July 21, 2020. In the MNDOC's comments regarding eligibility for recovery of investments in the three new projects through the Minnesota TCR rider, the MNDOC recommended the MPUC reject OTP’s petition for inclusion of the three projects. In the matter of OTP’s petition for approval of a TCR annual adjustment, at the request of the MNDOC the MPUC extended the deadlines for filing initial and reply comments to August 14,2020 and August 24, 2020, respectively. The estimated amount of higher MISO ROE revenues credited to Minnesota customers through the TCR rider through June 30, 20192020, which OTP is now seeking recovery of through its Minnesota TCR rider update request, is approximately $2.9$2.6 million.
Environmental Cost Recovery Rider—OTP had an ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant Air Quality Control System (AQCS). The ECR rider provided for a return on the project’s construction work in progress (CWIP) balance at the level approved in OTP’s 2010 general rate case. In its 2016 general rate case order, the MPUC approved OTP’s proposal to transition eligible rate base and expense recovery from the ECR rider to base rate recovery effective with implementation of final rates in November 2017. Accordingly, in its 2018 annual update filing OTP requested, and the MPUC approved, setting the Minnesota ECR rider rate to zero effective December 1, 2018. The remaining under-recovered balance was charged on customer billings in March and April 2019.
Renewable Resource Adjustment—Effective November 1, 2017, with the implementation of final rates in Minnesota, new rates were put into effect for the Minnesota RRA rider to address recovery of federal Production Tax Credits (PTCs) expiring on OTP’s wind farms in 2017 and 2018.On June 21, 2019 OTP filed a request for approval of its annual update to the Minnesota RRA. This update requestsRRA 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
General RatesRenewable 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 2, 201730, 2019. On February 25, 2020 OTP filed a revised request withwhich was approved by the NDPSC for a rate review and an effective increase in annual revenues from non-fuel base rateson March 18, 2020. Part of $13.1 million or 8.72%. The requested $13.1 million increase was net of reductions in North Dakota RRA, TCR and ECR rider revenues that would have resulted from a lower allowed rate of ROE and changes in allocation factors in the general rate case. In the request, OTP proposed an allowed return on rate base of 7.97% and an allowed rate of ROE of 10.3%. On December 20, 2017 the NDPSC approved OTP’s request for interim rates to increase annual revenue collections by $12.8 million, effective January 1, 2018. In response to the reduction in the federal corporate tax rate under the TCJA, the NDPSC issued an order on February 27, 2018 reducing OTP’s annual revenue requirement for interim rates by $4.5 million to $8.3 million, effective March 1, 2018.
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. This compares with OTP’s March 2018 adjusted annual revenue increase request of $7.1 million (4.8%) and a requested ROE of 10.3%. The NDPSC’s approval doesincluded adopting a levelized utilization of PTCs from the Merricourt project over the expected not25 require any rate base adjustments from OTP’s original request and establishes a GCR rider-year life of the project for future recovery of costs incurred for Astoria Station. The net revenue increase reflects a reduction in income tax recovery requirements relatedrate-making purposes. PTCs on prior projects were passed back to the TCJA and decreases in rider revenue recovery requirements. Finalcustomers through lower rates were effective February 1, 2019, with refunds of excess revenues collected under interim rates applied to customers’ April 2019 bills.
Renewable Resource Adjustment—OTP has a North Dakota RRA which enables OTP to recover its North Dakota jurisdictional share of investments in renewable energy facilities. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed, along with a return on investment.
Effective inwere generated over February 2019 with the implementation of general rates based on the results of OTP’s 201710 general rate case, recovery of renewable resource costs previously being recovered through the North Dakota RRA rider transitioned to recovery in base rates.
Transmission Cost Recovery Rider—North Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. For qualifying projects, the law authorizes a current return on CWIP and a return on investment at the level approved in the utility's most recent general rate case. Based on the order in the 2017 general rate case, only certain costs will remain subject to refund or recovery through this rider: Southwest Power Pool (SPP) costs and MISO Schedule 26 and 26A revenues and expenses and costs related to rider projects still under construction in the test year used in the 2017 general rate case. This rider will continue to be updated annually for new or modified electric transmission facilities and associated operating costs.
Environmental Cost Recovery Rider—OTP has an ECR rider in North Dakota. The ECR rider has provided for a return on investment at the level approved in OTP’s preceding general rate case and for recovery of OTP’s North Dakota share of environmental investments and costs approved for recovery under the rider. Prior to its 2017 general rate case reaching a final settlement and final rates going into effect on February 1, 2019, OTP’s North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects were being recovered through the ECR rider. Effective February 1, 2019 these rate base investments are being recovered under general rates and the rider was zeroed out except for an overcollection balance that will be refunded to ratepayers.years.
Generation Cost Recovery Rider—On March 1,May 15, 2019 OTP filed a request with 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 ofon its investment in Astoria Station. This request was approved by the NDPSC on May 15, 2019. The new rate of 2.547% will beStation, 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
General Rates—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 went into effect 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 settlement includes approval of a phase-in plan to provide for a return on amounts invested in Astoria Station and Merricourt, which addresses the second step of the request for increased rates in South Dakota. The partial settlement also includes a moratorium on filing another general rate case in South Dakota until the new generation projects have been in service for a year. The settlement also allows 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. Pursuant to the May 30, 2019 order, OTP’s allowed ROE was set at 8.75%, resulting in an annual revenue increase of approximately $2.2 million prior to the approval of a June 28, 2019 stipulation agreement discussed below. Final rates went into effect August 1, 2019. An interim rate refund for the lower ROE going back to October 18, 2018 will be applied to South Dakota customers’ October 2019 bills.
On June 28, 2019 OTP entered into a stipulation agreement with SDPUC staff for the purpose of correcting a mistake in OTP’s rate base in its 2018 general rate case docket. The revenue requirement stated in the SDPUC’s final order dated May 30, 2019 understated the correct amount of OTP's electric transmission plant in service by approximately $44 million. For South Dakota ratemaking purposes, the understatement results 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 will be 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 to go into effect on October 1, 2019, all subject to SDPUC approval. The stipulation agreement had the effect of increasing the non-fuel annual revenue increase in the general rate case to approximately $2.6 million or 7.7%, which is 69% of the adjusted requested annual revenue increase of approximately $3.7 million or 11.1%,
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 in the event OTP’s annual weather-normalized earnings exceed the SDPUC’s authorized ROE during any year until the ROE is reset in OTP's next general rate case, 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.
Transmission Cost RecoveryPhase-In Rate Plan Rider—South Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. OTP has a TCR rider in South Dakota. A supplemental filing to update the rider was made on January 29, 2018 to reflect updated costs and collections and incorporate the impact of the reduction in the federal corporate income tax rate under the TCJA. Effective October 18, 2018, with the implementation of interim rates under South Dakota general rate case proceedings, the TCR rate was decreased as a result of recovery of certain costs being shifted to recovery in interim rates and proposed for ongoing recoveries in final base rates at the end of the 2018 general rate case.
OTP made a supplemental filing for the South Dakota TCR rider on February 1, 2019. On February 20, 2019 the SDPUC approved the supplemental filing and rates effective March 1, 2019. Two new projects were approved for recovery under the rider: The Lake Norden area transmission upgrade project with a recovery date effective January 1, 2019 and The Big Stone South – Ellendale project with a recovery date effective January 2020.
Environmental Cost Recovery Rider—OTP has an ECR rider in South Dakota. The ECR rider provides for a return on investment at the level approved in OTP’s most recent general rate case and for recovery of OTP’s South Dakota share of environmental investments and costs approved for recovery under the rider. Prior to interim rates going into effect on October 18, 2018 pending a final decision on OTP’s South Dakota general rate increase request, OTP’s South Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant Mercury and Air Toxics Standards projects were being recovered through the ECR rider. With the initiation of interim rates, recovery of the costs previously being recovered under the ECR rider was transitioned to recovery under interim rates and the South Dakota ECR rider rate was reset to provide a refund to customers while interim rates are in effect.
Phase-In Rider
On May 31, 2019 OTP petitioned the SDPUC for approval of its initial rate for the Phase-In Rate Plan Rider under the SDPUC’s authority granted in South Dakota. This rider filing isas described in theOTP’s most recent South Dakota general rate case settlement stipulation and was approved by the SDPUC’s order in that rate case. The petition iswas 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 inarea. On August 21, 2019 the SDPUC approved OTP’s supplemental filing for its South Dakota jurisdiction.Phase-In Rate Plan Rider effective September 1, 2019. On June 1, 2020 OTP filed its first annual update request to the rider with a proposed effective date of September 1, 2020.
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 | Annual ($000s) | Rate | ||||||
Minnesota | ||||||||||
Conservation Improvement Program | ||||||||||
2019 Incentive and Cost Recovery | R – | May 1, 2020 | October 1, 2020 | $ | 8,247 | $0.00485 | /kwh | |||
2018 Incentive and Cost Recovery | A – | December 27, 2019 | January 1, 2020 | $ | 11,926 | $0.00710 | /kwh | |||
2017 Incentive and Cost Recovery | A – | October 4, 2018 | November 1, 2018 | $ | 10,283 | $0.00600 | /kwh | |||
Transmission Cost Recovery | ||||||||||
2018 Annual Update–Updated Request | R – | May 7, 2020 | January 1, 2021 | $ | 10,264 | Various | ||||
2017 Rate Reset | A – | October 30, 2017 | November 1, 2017 | $ | (3,311 | ) | Various | |||
Environmental Cost Recovery | ||||||||||
2018 Annual Update | A – | November 29, 2018 | December 1, 2018 | $ | - | 0% | of base | |||
Renewable Resource Adjustment | ||||||||||
2019 Annual Update – Revised | A – | December 19, 2019 | January 1, 2020 | $ | 12,506 | $0.00467 | /kwh | |||
2018 Annual Update | A – | August 29, 2018 | November 1, 2018 | $ | 5,886 | $0.00219 | /kwh | |||
North Dakota | ||||||||||
Renewable Resource Adjustment | ||||||||||
2020 Annual Update | A – | March 18, 2020 | April 1, 2020 | $ | 5,762 | 5.637% | of base | |||
2019 Annual Update | A – | May 1, 2019 | June 1, 2019 | $ | (235 | ) | -0.224% | of base | ||
2018 Rate Reset for effect of TCJA | A – | February 27, 2018 | March 1, 2018 | $ | 9,650 | 7.493% | of base | |||
Transmission Cost Recovery | ||||||||||
2019 Annual Update | A – | December 18, 2019 | January 1, 2020 | $ | 5,739 | Various | ||||
2018 Supplemental Update | A – | December 6, 2018 | February 1, 2019 | $ | 4,801 | Various | ||||
2018 Rate Reset for effect of TCJA | A – | February 27, 2018 | March 1, 2018 | $ | 7,469 | Various | ||||
Environmental Cost Recovery | ||||||||||
2019 Update | A – | October 22, 2019 | November 1, 2019 | $ | - | 0% | of base | |||
2018 Update | A – | December 19, 2018 | February 1, 2019 | $ | (378 | ) | -0.310% | of base | ||
2018 Rate Reset for effect of TCJA | A – | February 27, 2018 | March 1, 2018 | $ | 7,718 | 5.593% | of base | |||
Generation Cost Recovery | ||||||||||
2020 Annual Update | A – | June 10, 2020 | July 1, 2020 | $ | 6,184 | 6.041% | of base | |||
2019 Initial Request | A – | May 15, 2019 | July 1, 2019 | $ | 2,720 | 2.547% | of base | |||
South Dakota | ||||||||||
Transmission Cost Recovery | ||||||||||
2020 Annual Update | A – | February 19, 2020 | March 1, 2020 | $ | 2,327 | Various | ||||
2019 Rate Reset | A – | September 17, 2019 | October 1, 2019 | $ | 2,046 | Various | ||||
2019 Annual Update | A – | February 20, 2019 | March 1, 2019 | $ | 1,638 | Various | ||||
2018 Interim Rate Reset | A – | October 18, 2018 | October 18, 2018 | $ | 1,171 | Various | ||||
Environmental Cost Recovery | ||||||||||
2018 Interim Rate Reset | A – | October 18, 2018 | October 18, 2018 | $ | (189 | ) | -$0.00075 | /kwh | ||
Phase-In Rate Plan Recovery | ||||||||||
2020 Annual Update | R – | June 1, 2020 | September 1, 2020 | $ | 1,931 | 7.753% | of base | |||
2019 Initial Request | A – | August 21, 2019 | September 1, 2019 | $ | 864 | 3.345% | of base | |||
Revenues Recorded under Rate Riders
The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota and South Dakota.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
Rate Rider (in thousands) | 2019 | 2018 | 2019 | 2018 | ||||||||||||
Minnesota | ||||||||||||||||
Conservation Improvement Program Costs and Incentives1 | $ | 2,618 | $ | 2,368 | $ | 4,770 | $ | 4,884 | ||||||||
Renewable Resource Recovery | 1,317 | 659 | 2,633 | 1,184 | ||||||||||||
Transmission Cost Recovery | (56 | ) | (458 | ) | 585 | (487 | ) | |||||||||
Environmental Cost Recovery | - | (18 | ) | (1 | ) | (49 | ) | |||||||||
North Dakota | ||||||||||||||||
Transmission Cost Recovery | 874 | 1,165 | 2,646 | 3,227 | ||||||||||||
Renewable Resource Adjustment | (93 | ) | 2,079 | 636 | 4,046 | |||||||||||
Environmental Cost Recovery | (12 | ) | 1,830 | 563 | 3,651 | |||||||||||
Generation Cost Recovery | 222 | - | 470 | - | ||||||||||||
South Dakota | ||||||||||||||||
Transmission Cost Recovery | 371 | 250 | 844 | 786 | ||||||||||||
Conservation Improvement Program Costs and Incentives | 96 | 122 | 340 | 351 | ||||||||||||
Environmental Cost Recovery | (23 | ) | 515 | (27 | ) | 1,035 | ||||||||||
Total | $ | 5,314 | $ | 8,512 | $ | 13,459 | $ | 18,628 | ||||||||
|
Rate Rider Updates
The following table provides summary information on the status of updates since January 1, 2017 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 | |||||||||
2018 Incentive and Cost Recovery | R – | April 1, 2019 | October 1, 2019 | $ | 11,926 | $0.00710 | /kwh | ||
2017 Incentive and Cost Recovery | A – | October 4, 2018 | November 1, 2018 | $ | 10,283 | $0.00600 | /kwh | ||
2016 Incentive and Cost Recovery | A – | September 15, 2017 | October 1, 2017 | $ | 9,868 | $0.00536 | /kwh | ||
Transmission Cost Recovery | |||||||||
2018 Annual Update–Scenario A | R – | November 30, 2018 | June 1, 2019 | $ | 6,475 | Various | |||
–Scenario B | $ | 2,708 | Various | ||||||
2017 Rate Reset | A – | October 30, 2017 | November 1, 2017 | $ | (3,311 | ) | Various | ||
Environmental Cost Recovery | |||||||||
2018 Annual Update | A – | November 29, 2018 | December 1, 2018 | $ | - | 0% | of base | ||
2017 Rate Reset | A – | October 30, 2017 | November 1, 2017 | $ | (1,943 | ) | -0.935% | of base | |
Renewable Resource Adjustment | |||||||||
2019 Annual Update | R – | June 21, 2019 | November 1, 2019 | $ | 12,571 | $0.00469 | /kwh | ||
2018 Annual Update | A – | August 29, 2018 | November 1, 2018 | $ | 5,886 | $0.00219 | /kwh | ||
2017 Rate Reset | A – | October 30, 2017 | November 1, 2017 | $ | 1,279 | $0.00049 | /kwh | ||
North Dakota | |||||||||
Renewable Resource Adjustment | |||||||||
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 | ||
2017 Rate Reset | A – | December 20, 2017 | January 1, 2018 | $ | 9,989 | 7.756% | of base | ||
Transmission Cost Recovery | |||||||||
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 | |||
2017 Annual Update | A – | November 29, 2017 | January 1, 2018 | $ | 7,959 | Various | |||
Environmental Cost Recovery | |||||||||
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 | ||
2017 Rate Reset | A – | December 20, 2017 | January 1, 2018 | $ | 8,537 | 6.629% | of base | ||
Generation Cost Recovery | |||||||||
2019 Initial Request | A – | May 15, 2019 | July 1, 2019 | $ | 2,720 | 2.547% | of base | ||
South Dakota | |||||||||
Transmission Cost Recovery | |||||||||
2019 Rate Reset | R – | July 31, 2019 | October 1, 2019 | $ | 2,050 | 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 | |||
2017 Annual Update | A – | February 28, 2018 | March 1, 2018 | $ | 1,779 | Various | |||
2016 Annual Update | A – | February 17, 2017 | March 1, 2017 | $ | 2,053 | Various | |||
Environmental Cost Recovery | |||||||||
2018 Interim Rate Reset | A – | October 18, 2018 | October 18, 2018 | $ | (189 | ) | -$0.00075 | /kwh | |
2017 Annual Update | A – | October 13, 2017 | November 1, 2017 | $ | 2,082 | $0.00483 | /kwh | ||
Phase-In Rate Plan | |||||||||
2019 Initial Request | R – | May 31, 2019 | September 1, 2019 | $ | 1,027 | 3.942% | of base | ||
TCJA
The TCJA, passed in December 2017, reduced the federal corporate income tax rate from 35% to 21%, effective January 1, 2018. At the time of passage, OTP’s electric rates had been developed using a 35% tax rate. The MPUC, the NDPSC, the SDPUC and the FERC each initiated dockets or proceedings to begin working with utilities to assess the impact of the lower rates on electric rates, and to develop regulatory strategies to incorporate the tax reduction into future electric rates, if warranted.
The MPUC required regulated utilities providing service in Minnesota to make filings by February 15, 2018. On August 9, 2018 the MPUC determined the impacts of the TCJA as calculated, including amortization of excess accumulated deferred income taxes, should be refunded and rates should be adjusted going forward to account for the impacts of the TCJA. On December 5, 2018 the MPUC issued its final order related to the TCJA docket directing OTP to return to ratepayers, in a one-time refund, the TCJA-related savings accrued prior to the refund effective date. OTP must amortize its protected excess accumulated deferred income taxes (ADIT) as early as U.S. Internal Revenue Service provisions allow and amortize its unprotected excess ADIT over ten years. OTP was instructed to use its 2017 year-end ADIT balance to calculate its excess ADIT balance. The order also directs OTP to use these savings to reduce customers’ base rates prospectively—allocating the savings to customers in proportion to the size of each customer’s bill, or to each customer class in proportion to the class’s size. New rates reflecting the reduction in revenue requirements related to the TCJA tax rate reduction went into effect June 1, 2019. As of June 30, 2019, the accrued refund liability related to the tax rate reduction was $11.5 million for Minnesota customers. A one-time refund to Minnesota customers of $11.5 million in excess amounts billed from January 2018 through May 2019 will occur in August 2019.
As described above, OTP’s recent general rate cases in North Dakota and South Dakota reflected the impact of the TCJA in interim rates. OTP accrued refund liabilities for the time periods during which revenues were collected under rates set to recover higher levels of federal income taxes than OTP incurred under the lower federal tax rates in the TCJA. The North Dakota liability of $0.8 million as of March 31, 2019 for amounts collected reflecting the higher tax rates under interim rates in effect in January and February 2018 was refunded with the interim rate refund in April 2019.
As of June 30, 2019, accrued refund liabilities related to the tax rate reduction were $0.2 million for FERC jurisdictional rates. As of March 15, 2018, the FERC granted the request for waiver from a group of MISO transmission operators (including OTP) to revise inputs to their projected net revenue requirements for the 2018 rate year to reflect recent tax law changes.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
Rate Rider (in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||
Minnesota | ||||||||||||||||
Renewable Resource Recovery | $ | 3,088 | $ | 1,317 | $ | 6,342 | $ | 2,633 | ||||||||
Conservation Improvement Program Costs and Incentives | 1,521 | 1,841 | 2,607 | 2,728 | ||||||||||||
Transmission Cost Recovery | (314 | ) | (56 | ) | 401 | 585 | ||||||||||
Environmental Cost Recovery | - | - | - | (1 | ) | |||||||||||
North Dakota | ||||||||||||||||
Transmission Cost Recovery | 840 | 874 | 2,322 | 2,646 | ||||||||||||
Renewable Resource Adjustment | 1,070 | (93 | ) | 2,199 | 636 | |||||||||||
Generation Cost Recovery | 900 | 222 | 1,848 | 470 | ||||||||||||
Environmental Cost Recovery | - | (12 | ) | - | 563 | |||||||||||
South Dakota | ||||||||||||||||
Transmission Cost Recovery | 371 | 371 | 933 | 844 | ||||||||||||
Conservation Improvement Program Costs and Incentives | 210 | 96 | 554 | 340 | ||||||||||||
Environmental Cost Recovery | - | (23 | ) | - | (27 | ) | ||||||||||
Phase-In Rate Plan | (670 | ) | - | (24 | ) | - | ||||||||||
Total | $ | 7,016 | $ | 4,537 | $ | 17,182 | $ | 11,417 | ||||||||
FERC
Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935 (Federal Power Act). The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a suspension period, subject to ultimate approval by the FERC.
MVPs—MVPs are designed to enable the MISO region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit.benefit from the MVP.
OnROE—In November 12, 2013 a group of industrial and February 2015, customers and other stakeholders filed a complaintcomplaints with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff. The complainants sought to reduce the 12.38% ROE used in MISO’s transmission rates totariff. OTP has deferred recognition and recorded a proposed 9.15%. The complaint established a 15-month refund period from November 12, 2013 to February 11, 2015. A non-binding decision by the presiding Administrative Law Judge (ALJ) was issued on December 22, 2015 finding that the MISO transmission owners’ ROE should be 10.32%, and the FERC issued an order on September 28, 2016 setting the base ROE at 10.32%. Several parties requested rehearingliability of the September 2016 order and the requests are pending FERC action.
On November 6, 2014 a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional 50 basis points for Regional Transmission Organization participation (RTO Adder). On January 5, 2015 the FERC granted the request, deferring collection of the RTO Adder until the FERC issued its order in the ROE complaint proceeding. Based on the FERC adjustment to the MISO Tariff ROE resulting from the November 12, 2013 complaint and OTP’s incentive rate filing, OTP’s ROE went to 10.82% (a 10.32% base ROE plus the 0.5% RTO Adder) effective September 28, 2016.
On February 12, 2015 another group of stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff from 12.38% to a proposed 8.67%. This second complaint established a second15-month refund period from February 12, 2015 to May 11, 2016. The FERC issued an order on June 18, 2015 setting the complaint for hearings before an ALJ, which were held the week of February 16, 2016. A non-binding decision by the presiding ALJ was issued on June 30, 2016 finding that the MISO transmission owners’ ROE should be 9.7%. OTP is currently waiting for the issuance of a FERC order on the second complaint.
Based on the probable reduction by the FERC in the ROE component of the MISO Tariff, OTP had a $2.7 million liability on its balance sheet as of December 31, 2016, representing OTP’s best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a reduced ROE. MISO processed the refund for the FERC-ordered reduction in the MISO Tariff allowed ROE for the first15-month refund period in its February and June 2017 billings. The refund, in combination with a decision in the 2016 Minnesota general rate case that affected the Minnesota TCR rider, resulted in a reduction in OTP’s accrued MISO Tariff ROE refund liability from $2.7 million on December 31, 2016 to $1.6$2.9 million as of June 30, 2019.2020 as a result of the disputed ROE awaiting FERC action. The provision includes:
● | a $0.1 million refund for the first complaint period of November 2013 to February 2015 resulting from the potential reduction of the base ROE from 10.32%. |
● | a $1.5 million refund related to the second complaint period of February 2015 to May 2016 resulting from a potential reduction in base ROE from 12.38%. |
● | a $1.3 million refund for the period from September 2016 through June 2020 resulting from a potential reduction in base ROE from 10.82%. |
Various FERC orders have been made that remain under appeal. All or some of the current liability will be refunded to customers or reversed and recognized as revenue depending on various factors including MISO’s determination of refund amounts and FERC’s final determination of the reasonableness of base ROE over various periods.
In June 2014, the FERC adopted a two-step ROE methodology for electric utilities in an order issued in a complaint proceeding involving New England Transmission Owners (NETOs). The issue of how to apply the FERC ROE methodology has been contested in various complaint proceedings, including the two ROE complaints involving MISO transmission owners discussed above. In April 2017 the U.S. Court of Appeals for the District of Columbia (D.C. Circuit) vacated and remanded the FERC’s June 2014 ROE order in the NETOs’ complaint. The D.C. Circuit found that the FERC had not properly determined that the ROE authorized for NETOs prior to June 2014 was unjust and unreasonable. The D.C. Circuit also found that the FERC failed to justify the new ROE methodology. OTP will await the FERC response to the April 2017 action of the D.C. Circuit before determining if an adjustment to its accrued refund liability is required. On September 29, 2017 the MISO transmission owners filed a motion to dismiss the second complaint based on the D.C. Circuit decision in the NETOs complaint. The motion is currently pending before the FERC.
On October 16, 2018 the FERC issued an order proposing a methodology for addressing the issues that were remanded to the FERC by the D.C. Circuit in April 2017. The FERC order established a paper hearing on how the methodology should apply to the proceedings pending before the FERC involving NETOs’ ROE. In the order, the FERC selected a preliminary just and reasonable ROE for NETOs of 10.41%, exclusive of incentives, with a proposed cap on any pre-existing incentive-based total ROE at 13.08% and directed participants to submit supplemental briefs and additional written evidence regarding the proposed approaches to the Federal Power Act Section 206 inquiry and how to apply them to the NETO ROE complaints. On November 15, 2018, FERC issued an order establishing a paper hearing on whether and how a two-step ROE methodology developed for NETOs should apply to the ROE for MISO transmission owners. Initial briefs were due February 13, 2019 and reply briefs were due April 10, 2019. FERC is under no statutory timeline to act; however, the Company expects FERC to issue an order in the third or fourth quarter of 2019.
OTP believes its estimated accrued MISO Tariff ROE refund liability of $1.6 million as of June 30, 2019 related to the second MISO tariff ROE complaint is appropriate.
4. Regulatory Assets and Liabilities
As a regulated entity, OTP accounts for the financial effects of regulation 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 and liabilities recorded on the Company’s consolidated balance sheets:
June 30, 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 | $ | 6,355 | $ | 115,246 | $ | 121,601 | see below | |||||||||
Accumulated ARO Accretion/Depreciation Adjustment1 | - | 7,436 | 7,436 | asset lives | ||||||||||||
Conservation Improvement Program Costs and Incentives2 | 1,861 | 4,659 | 6,520 | 27 | ||||||||||||
Minnesota Transmission Cost Recovery Rider Accrued Revenues2 | 2,637 | - | 2,637 | 12 | ||||||||||||
Deferred Marked-to-Market Losses1 | 1,202 | 372 | 1,574 | 18 | ||||||||||||
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery1 | - | 1,359 | 1,359 | asset lives | ||||||||||||
Big Stone II Unrecovered Project Costs – Minnesota1 | 698 | 590 | 1,288 | 22 | ||||||||||||
Debt Reacquisition Premiums1 | 203 | 649 | 852 | 159 | ||||||||||||
Deferred Income Taxes1 | - | 701 | 701 | asset lives | ||||||||||||
North Dakota Generation Cost Recovery Rider Accrued Revenues2 | 470 | - | 470 | 12 | ||||||||||||
South Dakota Deferred Rate Case Expenses Subject to Recovery1 | 455 | - | 455 | 12 | ||||||||||||
Big Stone II Unrecovered Project Costs – South Dakota1 | 116 | 263 | 379 | 39 | ||||||||||||
North Dakota Deferred Rate Case Expenses Subject to Recovery1 | 377 | - | 377 | 12 | ||||||||||||
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1 | 120 | 222 | 342 | 30 | ||||||||||||
Minnesota SPP Transmission Cost Recovery Tracker1 | - | 148 | 148 | see below | ||||||||||||
Deferred Lease Expenses1 | - | 47 | 47 | 45 | ||||||||||||
Minnesota Environmental Cost Recovery Rider Accrued Revenues2 | 4 | - | 4 | 12 | ||||||||||||
Minnesota Renewable Resource Recovery Rider Accrued Revenues2 | 3 | - | 3 | 12 | ||||||||||||
Total Regulatory Assets | $ | 14,501 | $ | 131,692 | $ | 146,193 | ||||||||||
Regulatory Liabilities: | ||||||||||||||||
Deferred Income Taxes | $ | - | $ | 140,226 | $ | 140,226 | asset lives | |||||||||
Accumulated Reserve for Estimated Removal Costs – Net of Salvage | - | 83,977 | 83,977 | asset lives | ||||||||||||
Refundable Fuel Clause Adjustment Revenues – Minnesota | 5,087 | - | 5,087 | 12 | ||||||||||||
Refundable Fuel Clause Adjustment Revenues – North Dakota | 1,676 | - | 1,676 | 12 | ||||||||||||
North Dakota Renewable Resource Recovery Rider Accrued Refund | 725 | - | 725 | 12 | ||||||||||||
North Dakota Environmental Cost Recovery Rider Accrued Refund | 614 | - | 614 | 12 | ||||||||||||
North Dakota Transmission Cost Recovery Rider Accrued Refund | 391 | - | 391 | 12 | ||||||||||||
Revenue for Rate Case Expenses Subject to Refund – Minnesota | - | 284 | 284 | see below | ||||||||||||
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up | 94 | 93 | 187 | 18 | ||||||||||||
South Dakota Transmission Cost Recovery Rider Accrued Refund | 146 | - | 146 | 12 | ||||||||||||
Refundable Fuel Clause Adjustment Revenues – South Dakota | 130 | - | 130 | 12 | ||||||||||||
South Dakota Environmental Cost Recovery Rider Accrued Refund | 45 | - | 45 | 12 | ||||||||||||
Minnesota Energy Intensive Trade Exposed Rider Accrued Refund | 45 | - | 45 | 4 | ||||||||||||
Other | 6 | 75 | 81 | 174 | ||||||||||||
Total Regulatory Liabilities | $ | 8,959 | $ | 224,655 | $ | 233,614 | ||||||||||
Net Regulatory Asset/(Liability) Position | $ | 5,542 | $ | (92,963 | ) | $ | (87,421 | ) | ||||||||
1Costs subject to recovery without a rate of return. 2
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December 31, 2018 | 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 | $ | 6,346 | $ | 118,433 | $ | 124,779 | see below | |||||||||
Accumulated ARO Accretion/Depreciation Adjustment1 | - | 7,169 | 7,169 | asset lives | ||||||||||||
Conservation Improvement Program Costs and Incentives2 | 5,995 | 3,285 | 9,280 | 21 | ||||||||||||
Minnesota Transmission Cost Recovery Rider Accrued Revenues2 | 444 | - | 444 | 12 | ||||||||||||
Deferred Marked-to-Market Losses1 | 1,661 | 743 | 2,404 | 24 | ||||||||||||
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery1 | - | 986 | 986 | asset lives | ||||||||||||
Big Stone II Unrecovered Project Costs – Minnesota1 | 681 | 947 | 1,628 | 28 | ||||||||||||
Debt Reacquisition Premiums1 | 207 | 753 | 960 | 165 | ||||||||||||
Deferred Income Taxes1 | - | 2,423 | 2,423 | asset lives | ||||||||||||
South Dakota Deferred Rate Case Expenses Subject to Recovery1 | 178 | - | 178 | 12 | ||||||||||||
Big Stone II Unrecovered Project Costs – South Dakota1 | 100 | 342 | 442 | 53 | ||||||||||||
North Dakota Deferred Rate Case Expenses Subject to Recovery1 | 455 | - | 455 | 12 | ||||||||||||
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1 | 240 | - | 240 | 12 | ||||||||||||
Minnesota SPP Transmission Cost Recovery Tracker1 | - | 176 | 176 | see below | ||||||||||||
Minnesota Environmental Cost Recovery Rider Accrued Revenues2 | 121 | - | 121 | 12 | ||||||||||||
Minnesota Renewable Resource Recovery Rider Accrued Revenues2 | 452 | - | 452 | 12 | ||||||||||||
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues1 | 328 | - | 328 | 4 | ||||||||||||
North Dakota Environmental Cost Recovery Rider Accrued Revenues2 | 17 | - | 17 | 12 | ||||||||||||
Total Regulatory Assets | $ | 17,225 | $ | 135,257 | $ | 152,482 | ||||||||||
Regulatory Liabilities: | ||||||||||||||||
Deferred Income Taxes | $ | - | $ | 142,779 | $ | 142,779 | asset lives | |||||||||
Accumulated Reserve for Estimated Removal Costs – Net of Salvage | - | 83,229 | 83,229 | asset lives | ||||||||||||
North Dakota Renewable Resource Recovery Rider Accrued Refund | 177 | - | 177 | 12 | ||||||||||||
North Dakota Transmission Cost Recovery Rider Accrued Refund | 60 | - | 60 | 12 | ||||||||||||
Revenue for Rate Case Expenses Subject to Refund – Minnesota | - | 166 | 166 | see below | ||||||||||||
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up | - | 187 | 187 | 24 | ||||||||||||
South Dakota Transmission Cost Recovery Rider Accrued Refund | 168 | - | 168 | 12 | ||||||||||||
South Dakota Environmental Cost Recovery Rider Accrued Refund | 207 | - | 207 | 12 | ||||||||||||
Refundable Fuel Clause Adjustment Revenues | 121 | - | 121 | 12 | ||||||||||||
Other | 5 | 108 | 113 | 180 | ||||||||||||
Total Regulatory Liabilities | $ | 738 | $ | 226,469 | $ | 227,207 | ||||||||||
Net Regulatory Asset/(Liability) Position | $ | 16,487 | $ | (91,212 | ) | $ | (74,725 | ) | ||||||||
1Costs subject to recovery without a rate of return. 2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The regulatory asset and liability related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses and gains subject to recovery or refund through rates as they are expensed over the remaining service lives of active employees included in the plans.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 recoveryinclusion in future retail electric rates.
The Accumulated Asset Retirement Obligation (ARO)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 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 arewere recoverable from Minnesota customers as of June 30, 2019.the balance sheet date.
Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates.
All Deferred Marked-to-Market Losses recorded as ofMISO Schedule June 30, 2019 26/26A Transmission Cost Recovery Rider True-ups relate to forward purchasesthe over/under collection of energy scheduledrevenue 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 delivery through December 2020.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.
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.
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.
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.
Big Stone II 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.
Debt Reacquisition PremiumsThe 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.
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.
Big Stone II 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.
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.
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 OTPNorth Dakota customers that had not been billed to North Dakota customers as of the balance sheet date.
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.
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 remaining original liveslife of the reacquired debt issues,lease based on the longestsum of which is 159 months.those payments. Rate-regulated entities are generally only allowed to recover the amount of actual cash payments on leases and FERC accounting rules require that rent expense be recognized on the basis of cash payments. The balance in the deferred lease expense regulatory asset account represents operating lease right of use asset cumulative amortization and interest costs in excess of cumulative lease payments that are subject 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 costs incurred to serve South Dakota customers that were recoverable from South Dakota customers as of the balance sheet date.
The regulatory asset and liability related to Deferred Income Taxes results from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes.
North Dakota Generation Cost Recovery (NDGCR) Rider Accrued Revenues relate to revenues earned on 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 June 30, 2019 balance represents amounts subject to recovery from North Dakota customers that have not been billed to North Dakota customers.
South Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s current rate case in South Dakota and are currently being recovered beginning with the establishment of interim rates in October 2018.
Big Stone II 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.
North Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s current rate case in North Dakota currently being recovered beginning with the establishment of interim rates in January 2018.
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.
The Minnesota SPP Transmission Cost Recovery Tracker regulatory asset relates to costs incurred to serve Minnesota customers that are subject to recovery but that have not been billed to Minnesota customers as of June 30, 2019.
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 recover the amount of actual cash payments on leases and FERC accounting rules require that rent expense be recognized on the basis of cash payments. The balance in the deferred lease expense regulatory asset account on June 30, 2019 represents operating lease right of use asset cumulative amortization and interest costs in excess of cumulative lease payments that are subject 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 are recoverable from Minnesota customers as of June 30, 2019.
The Minnesota Renewable Resource Recovery Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that are recoverable from Minnesota customers as of June 30, 2019. Currently, the rider is only being used to recover the amount of federal PTCs generated by OTP’s wind farms that were transferred from inclusion in the rider and applied as a reduction in revenue requirements to Minnesota base rates. Subsequent to applying the PTCs to base rates the PTCs expired. The Minnesota RRA rider is now being used to recover the shortfall in base rates related to the expiration of the PTCs. Recovery will continue through the rider until interim or revised base rates are established in connection with OTP’s next Minnesota rate case.
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues relate to revenues recorded for fuel and purchased power costs reductions provided to customers in energy intensive trade exposed industries that are subject to recovery from other Minnesota customers.
North Dakota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects and for reagent and emission allowances costs that were recoverable from North Dakota customers as of December 31, 2018.
The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred.
North Dakota Renewable Resource Recovery Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that are refundable to North Dakota customers as
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 arewere refundable to North Dakota customers as of June 30, 2019.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 proceedings in excess of the actual costs incurred.
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 are refundable to South Dakota customers as of June 30, 2019.
The South Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the South Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to South Dakota customers as of June 30, 2019.
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 arewere subject to refund to Minnesota customers.customers as of the balance sheet date.
The South Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that were refundable to South Dakota customers as of the balance sheet date.
The North Dakota Renewable Resource Recovery Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that were refundable to North Dakota 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 would 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
Shelf Registration
On May 3, 2018 the Company filed a shelf registration statement with the Securities and Exchange Commission (SEC) under which the Company 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, which expires on May 3, 2021.
On November 8, 2019, the Company entered into a Distribution Agreement with KeyBanc Capital Markets Inc. (KeyBanc Capital Markets). Pursuant to the terms of the Distribution Agreement, the Company may offer and sell its common shares from time to time through KeyBanc, as the Company’s distribution agent 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 commission of up to 2% of the gross sales price per share for any shares sold through it as the Company’s distribution agent under the Distribution Agreement. The Company is not obligated to sell and KeyBanc is not obligated to buy or sell any of the shares under the Distribution Agreement. The shares, if issued, will be issued pursuant to the Company’s existing shelf registration statement.
2020Common SharesStock Activity
Following is a reconciliation of the Company’s common shares outstanding from December 31, 20182019 through June 30, 2019:2020:
Common Shares Outstanding, December 31, | ||||
Issuances: | ||||
At-the-Market Offering | 500,684 | |||
Automatic Dividend Reinvestment and Share Purchase Plan: | ||||
Dividends Reinvested | 63,929 | |||
Cash Invested | 30,345 | |||
Executive Stock Performance Awards | ||||
Vesting of Restricted Stock Units | ||||
Employee Stock Purchase Plan: | ||||
Cash Invested | 13,432 | |||
Dividends Reinvested | 4,835 | |||
Restricted Stock Issued to Directors | ||||
Directors Deferred Compensation | ||||
Retirements: | ||||
Shares Withheld for Individual Income Tax Requirements | ( | ) | ||
Common Shares Outstanding, June 30, |
Earnings Per Share
The numerator used in the calculation of both basic and diluted earnings per common share is net income with no adjustments for the three- and six-month periods ended June 30, 20192020 and 2018.2019. The denominator used in the calculation of basic earnings per common share is the weighted average number of 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 reconciliations.
Three Months ended June 30 | Six Months ended June 30 | |||||||||||||||
2019 | 2018 | 2019 | 2018 | |||||||||||||
Weighted Average Common Shares Outstanding – Basic | 39,712,036 | 39,605,717 | 39,684,679 | 39,578,296 | ||||||||||||
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 | 134,137 | 202,643 | 146,148 | 212,902 | ||||||||||||
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees | 60,168 | 57,616 | 61,783 | 58,373 | ||||||||||||
Nonvested Restricted Shares | 9,657 | 10,733 | 15,790 | 19,188 | ||||||||||||
Shares Expected to be Issued Under the Deferred Compensation Program for Directors | 1,833 | 2,360 | 2,099 | 2,617 | ||||||||||||
Total Dilutive Shares | 205,795 | 273,352 | 225,820 | 293,080 | ||||||||||||
Weighted Average Common Shares Outstanding – Diluted | 39,917,831 | 39,879,069 | 39,910,499 | 39,871,376 | ||||||||||||
The effect of dilutive shares on earnings per sharereconciliation for the three- and six-month periods ended June 30, 2019 30:and 2018, resulted in no differences greater than $0.01 between basic and diluted earnings per share in any period.
Three Months ended June 30 | Six Months ended June 30 | |||||||||||||||
2020 | 2019 | 2020 | 2019 | |||||||||||||
Weighted Average Common Shares Outstanding – Basic | 40,513,286 | 39,712,036 | 40,365,214 | 39,684,679 | ||||||||||||
Plus Outstanding Share Awards net of Share Reductions for Unrecognized Stock-Based Compensation Expense and Excess Tax Benefits: | ||||||||||||||||
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance | 97,401 | 134,137 | 111,519 | 146,148 | ||||||||||||
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees | 47,331 | 60,168 | 55,614 | 61,783 | ||||||||||||
Shares Expected to be Issued Under the Employee Stock Purchase Plan | 15,833 | - | 15,905 | - | ||||||||||||
Nonvested Restricted Shares | 1,637 | 9,657 | 10,749 | 15,790 | ||||||||||||
Shares Expected to be Issued Under the Deferred Compensation Program for Directors | 1,273 | 1,833 | 1,548 | 2,099 | ||||||||||||
Total Dilutive Shares | 163,475 | 205,795 | 195,335 | 225,820 | ||||||||||||
Weighted Average Common Shares Outstanding – Diluted | 40,676,761 | 39,917,831 | 40,560,549 | 39,910,499 | ||||||||||||
6. Share-Based Payments
Stock Incentive Awards
The following stock incentive awards were granted under the 2014 Stock Incentive Plan during the six-month period months ended June 30, 2019:2020.
Award | Grant-Date | Shares/Units Granted | Weighted Average Grant-Date Fair Value per Award | Vesting | Grant Date | Shares/ Units Granted | Weighted Average Grant-Date Fair Value per Award | Vesting | ||||||||||||
Restricted Stock Units Granted: | ||||||||||||||||||||
With Dividend Equivalent: | ||||||||||||||||||||
To Key Management Employees | February 3, 2020 | 3,000 | $ | 54.0450 | 25% per year through February 6, 2024 | |||||||||||||||
To Executive Officers | February 12, 2020 | 15,300 | $ | 54.0607 | 25% per year through February 6, 2024 | |||||||||||||||
Without Dividend Equivalent: | ||||||||||||||||||||
To Nonexecutive Employees | April 20, 2020 | 14,975 | $ | 40.18 | 100% April 8, 2024 | |||||||||||||||
Stock Performance Awards Granted: | ||||||||||||||||||||
Under Executive and Select Employee Agreements | February 13, 2019 | 47,800 | $ | 42.875 | December 31, 2021 | |||||||||||||||
Under Executive Agreement | February 12, 2020 | 47,600 | $ | 47.10 | December 31, 2022 | |||||||||||||||
Under Legacy Agreement | February 13, 2019 | 7,800 | $ | 45.885 | December 31, 2021 | February 12, 2020 | 7,400 | $ | 52.20 | December 31, 2022 | ||||||||||
Restricted Stock Units Granted to Executive Officers | February 13, 2019 | 15,600 | $ | 49.6225 | 25% per year through February 6, 2023 | |||||||||||||||
Restricted Stock Units Granted to Key Employees | April 8, 2019 | 13,270 | $ | 44.45 | 100% on April 8, 2023 | |||||||||||||||
Restricted Stock Granted to Nonemployee Directors | April 8, 2019 | 15,700 | $ | 49.73 | 33% per year through April 8, 2022 | April 20, 2020 | 17,400 | $ | 44.85 | 33% per year through April 8, 2023 | ||||||||||
The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration on retirement in certain cases. Allcases, 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, subject to forfeiture under the terms of the restricted stock unit award agreements.periods. The grant-date fair value of each restricted stock unit granted to an executive officerpaying a dividend equivalent was the average of the high and low market price per share on the date of grant. The grant-date fair value of each restricted stock unit granted to a key employee that isdoes not an executive officerpay 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 respectiveunit’s vesting periods.period.
Under the performance share awards the aggregate award for performance at target is 55,60055,000 shares. For target performance the participants would earn an aggregate of 27,80027,500 common shares for achieving the target set for the Company’s 3-year average adjusted ROE. The participants would also earn an aggregate of 27,80027,500 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, 20192020 through December 31, 2021,2022, 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, 20192020 and the average closing price for the 20 trading days immediately preceding January 1, 2022.2023. Actual payment may range from zero to 150% of the target amount, or up to 83,40082,500 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 Topic 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 20192020 Performance Award Agreements, payment and the amount of payment 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.
As of June 30, 2019,2020, the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $5.5$4.8 million (before income taxes) which will be amortized over a weighted-average period of 2.3 years.
Amounts of compensation expense recognized under the Company’s stock-based payment programs for the three- and six-month periods ended June 30, 20192020 and 20182019 are presented in the table below:
Three months ended | Six months ended | |||||||||||||||||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | June 30, | June 30, | |||||||||||||||||||||||||||||
(in thousands) | 2019 | 2018 | 2019 | 2018 | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||||
Stock Performance Awards Granted to Executive Officers | $ | 1,418 | $ | 668 | $ | 2,531 | $ | 1,319 | $ | 712 | $ | 1,418 | $ | 2,412 | $ | 2,531 | ||||||||||||||||
Restricted Stock Units Granted to Executive Officers | 383 | 173 | 810 | 422 | ||||||||||||||||||||||||||||
Restricted Stock Granted to Executive Officers | - | - | - | 16 | ||||||||||||||||||||||||||||
Restricted Stock Dividend Equivalent Units Granted to Executive Officers and Key Employees | 106 | 383 | 785 | 810 | ||||||||||||||||||||||||||||
Restricted Stock Granted to Nonemployee Directors | 204 | 165 | 369 | 331 | 236 | 204 | 440 | 369 | ||||||||||||||||||||||||
Restricted Stock Units Granted to Key Employees | 143 | 101 | 234 | 165 | ||||||||||||||||||||||||||||
Restricted Stock Units Granted to Nonexecutive Employees | 141 | 143 | 275 | 234 | ||||||||||||||||||||||||||||
ESPP (15% discount) | 42 | - | 95 | - | ||||||||||||||||||||||||||||
Totals | $ | 2,148 | $ | 1,107 | $ | 3,944 | $ | 2,253 | $ | 1,237 | $ | 2,148 | $ | 4,007 | $ | 3,944 | ||||||||||||||||
In July 2019 the Company reinstituted a 15% employee discount under its employee stock purchase plan. The Company estimates the discount will not have a material impact on annual stock-based payment expenses.
7. Retained Earnings and Dividend Restriction
The Company is a holding company with no significant operations of its own. The primary source of funds for payments of dividends to the Company’s shareholders is from dividends paid or distributions made by the Company’s subsidiaries. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by the Company’s subsidiaries.
Both the Company and OTP credit agreements contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be considered to have occurred if the Company did not meet certain financial covenants. As of June 30, 2019,2020, the Company was in compliance with these financial covenants.
Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. What constitutes “funds properly included in a capital account” is undefined in the Federal Power Act or the related regulations; however, the FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials.
The MPUC indirectly limits the amount of dividends OTP can pay to the Company by requiring an equity-to-total-capitalization ratio between 47.9%47.5% and 58.5%58.1% based on OTP’s 20182020 capital structure petition effective by order of the MPUC on October 18, 2018.July 15, 2020. As of June 30, 2019,2020, OTP’s equity-to-total-capitalization ratio including short-term debt was 52.8%52.9% and its net assets restricted from distribution totaled approximately $490$549 million.
On Under the May 1, 2019 OTP filed a petition for approval of an equity-to-total capitalization ratio between 46.0% and 56.2% with total capitalization not to exceed $1,331,302,000 in its 2019 capital structure filing. OTP’s 20192020 capital structure petition, was approved and effective by order of the MPUC on July 19, 2019.OTP’s total capitalization cannot exceed $1,704,607,000.
8. Leases
The Company adopted ASU 2016-02No and related updates (ASC Topic 842), which replaced previous lease accounting guidance, on January 1, 2019, using the modified retrospective method of adoption. As a result, prior periods have not been restated. ASC Topic 842 requires lessees to record assets and liabilities on the balance sheetupdate required for all leases with terms longer than 12 months. Adoption of the standard resulted in the recognition of net lease assets and lease liabilities of$20 million on January 1, 2019. The adoption of the new standard did not have a material effect on the Company’s consolidated statements of income or cash flows. In addition, the adoption did not have a material impact on the Company’s liquidity or the Company’s covenant compliance under its current debt agreements.
The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allows for the carry forward of lease classifications determined under the requirements of ASC Topic 840. The Company also elected the practical expedient related to land easements, allowing for the continuation of historical accounting treatment for land easements on existing agreements at OTP. In addition, the Company has elected the hindsight practical expedient to determine the reasonably certain lease term for leases in place at the time of adoption. The Company has elected the practical expedient to not separate nonlease components from lease components on real estate leases for the purpose of determining the classification and the value of lease assets and lease liabilities at the inception of a lease.
The Company enters into leases for coal rail cars, warehouse and office space, land and certain office, manufacturing and material handling equipment under varying terms and conditions. The lengths of the leases vary from less than 1 year to approximately 10 years. If a lease contains an option to extend and there is reasonable certainty the option will be exercised, the option is considered in the lease term at inception. None of these leases met the criteria to be classified as financing leases. Of the operating leases in place on January 1, 2019, 50 were capitalized as right-of-use assets and the remainder were month-to-month leases with no long-term obligations.
The right-of-use asset operating leases in place at the time of adoption were capitalized on the basis of their remaining payment obligation balances, discounted to present value based on the Company’s incremental borrowing rates (IBRs) appropriate to the leased asset and lease terms. The remaining payments for operating lease right-of-use assets are being charged to expense on a straight-line basis over the life of the lease.
For the Company’s current lease obligations, no explicit interest rates were stated in the lease agreements and no implicit rates could be determined based on the terms of the agreements. Therefore, in all cases, the Company has applied a formula-based IBR appropriate to the individual company, type of lease and lease term.
The breakdown of right-of-use assets and lease liabilities as of June 30, 2019 by business segment is provided in the following table.
(in thousands) | Electric | Manufacturing | Plastics | Corporate | Total | |||||||||||||||
Right of Use Assets – Operating Leases: | ||||||||||||||||||||
Gross | $ | 3,586 | $ | 16,630 | $ | 666 | $ | 769 | $ | 21,651 | ||||||||||
Accumulated Amortization | (526 | ) | (1,393 | ) | (195 | ) | (64 | ) | (2,178 | ) | ||||||||||
Net of Accumulated Amortization | $ | 3,060 | $ | 15,237 | $ | 471 | $ | 705 | $ | 19,473 | ||||||||||
Obligations: | ||||||||||||||||||||
Current Operating Lease Liabilities | $ | 975 | $ | 2,303 | $ | 353 | $ | 153 | $ | 3,784 | ||||||||||
Long-Term Operating Lease Liabilities | 2,336 | 13,019 | 118 | 611 | 16,084 | |||||||||||||||
Total Lease Liabilities | $ | 3,311 | $ | 15,322 | $ | 471 | $ | 764 | $ | 19,868 | ||||||||||
The amounts of the Company’s right-of-use operating lease obligations for each of the five years in the period 2019 through 2023 and in aggregate for the years beyond 2023 are presented in the following table, including obligations under lease agreements that had not commenced as of June 30, 2019.
| Right-of-Use Operating Leases | |||||||||||
| (in thousands) | OTP | Nonelectric | Total | |||||||||
2019 | $ | 570 | $ | 2,055 | $ | 2,625 | ||||||
2020 | 1,115 | 3,872 | 4,987 | |||||||||
2021 | 1,100 | 3,600 | 4,700 | |||||||||
2022 | 207 | 3,465 | 3,672 | |||||||||
2023 | 196 | 3,174 | 3,370 | |||||||||
Beyond 2023 | 447 | 8,022 | 8,469 | |||||||||
Total Minimum Obligations | $ | 3,635 | $ | 24,188 | $ | 27,823 | ||||||
Interest Component of Obligations | (314 | ) | (4,115 | ) | (4,429 | ) | ||||||
Present Value of Leases Commencing after June 30, 2019 | (10 | ) | (3,516 | ) | (3,526 | ) | ||||||
Present Value of Minimum Obligations, June 30, 2019 | $ | 3,311 | $ | 16,557 | $ | 19,868 | ||||||
The Company’s total minimum lease obligations reported in the table above includes obligations for a 10-year lease of a warehouse by T.O. Plastics entered into in 2018 and commencing in July 2019 and a 15-year lease for land on which OTP plans to construct a small solar-electric project with a one-time payment to be made at commencement of the lease in July 2019.
The weighted-average remaining lease term for the Company’s outstanding lease liabilities is 5.8 years and the weighted-average discount rate is 5.0%.
A reconciliation of the Company’s operating lease obligations on adoption of ASC Topic 842 on January 1, 2019 and its operating lease obligations on June 30, 2019 is provided in the table below.
(in thousands) | OTP | Nonelectric | Total | |||||||||
Operating Lease Obligations, January 1, 2019 | $ | 3,609 | $ | 16,760 | $ | 20,369 | ||||||
Non-cash Acquisition of Right-of-Use Assets | 167 | 1,725 | 1,892 | |||||||||
Lease Modifications | - | (1,366 | ) | (1,366 | ) | |||||||
Lease Obligation Payments | (551 | ) | (992 | ) | (1,543 | ) | ||||||
Interest Component of Lease Obligation Payment | 86 | 430 | 516 | |||||||||
Operating Lease Obligations, June 30, 2019 | $ | 3,311 | $ | 16,557 | $ | 19,868 | ||||||
The lease modifications in the above table relate to reductions in future minimum lease obligations on several units of leased equipment at BTD.
OTP has obligations to make future operating lease payments primarily related to coal rail-car leases. OTP’s rail-car lease payments are charged to fuel inventory and then expensed to production fuel – electric as a component of fuel cost when fuel is burned. OTP also leases office and operating equipment with lease payments charged to rent expense and reported in electric operation and maintenance expenses on the Company’s consolidated statements of income. From time to time, OTP will lease construction equipment or land for lay-down yards for materials used on capital projects. These leases are generally short term in nature with the lease payments being charged to the related construction project and included in CWIP or plant in service after the project is completed and placed in service.
The Company’s nonelectric companies have obligations to make future operating lease payments primarily related to leases of buildings and manufacturing equipment. These payments are charged to rent expense accounts and reported in costs of goods sold or other nonelectric expenses, as appropriate, on the Company’s consolidated statements of income.
The allocation of right-of-use asset and variable lease costs, including non-cash costs related to straight-line amortization of escalating lease payments, for the three- and six-month periods ending June 30, 2019 is presented in the following table.
Three Months Ended June 30, 2019 | Six Months Ended June 30, 2019 | |||||||||||||||||||||||
Operating Lease Cost | Variable Lease Cost | Total Lease Cost | Operating Lease Cost | Variable Lease Cost | Total Lease Cost | |||||||||||||||||||
Plant in Service or CWIP | $ | 11 | $ | - | $ | 11 | $ | 20 | $ | - | $ | 20 | ||||||||||||
Inventory | 238 | - | 238 | 463 | - | 463 | ||||||||||||||||||
Cost of Products Sold | 943 | 45 | 988 | 1,979 | 72 | 2,051 | ||||||||||||||||||
Electric Operation and Maintenance Expenses | 64 | - | 64 | 130 | - | 130 | ||||||||||||||||||
Other Nonelectric Expenses | 51 | 1 | 52 | 105 | 1 | 106 | ||||||||||||||||||
Total | 1,307 | $ | 46 | $ | 1,353 | $ | 2,697 | $ | 73 | $ | 2,770 | |||||||||||||
interim reporting periods.
9. Commitments and Contingencies
Construction and Other Purchase Commitments
At June 30, 20192020 OTP had commitments under contracts, including its share of construction program commitments and other nonlease commitments, extending into 20212022 of approximately $77.3$185 million. At December 31, 20182019 OTP had commitments under contracts, including its share of construction program commitments and other nonlease commitments, extending into 2021 of approximately $64.5$317 million. At
On June 30,October 1, 2019 T.O. Plastics had commitments forentered into a new six-year resin supply agreement that commenced on January 1, 2020. Under the new resin supply agreement, there are no minimum purchase requirements, but T.O. Plastics is required 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 throughdelivered under the supply agreement will December 31,not exceed its requirements over the 2021six-year term of approximately $4.1 million. At December 31, 2018 the supply agreement or exceed the market cost of alternative sources of the resin. T.O. Plastics had commitments forestimates it will pay the purchase of resin through December 31, 2021 ofsupplier approximately $5.0 million.$1.9 million annually under this agreement.
Electric Utility Capacity and Energy Requirements and Coal Purchase and Delivery Contracts
OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2042.2043. OTP also has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. OTP’s current coal purchase agreements for Coyote Station expire at the end of 2040. OTP’s current coal purchase agreements for Big Stone Plant expire at the end of 2020. OTP has an agreementagreements with Peabody COALSALES, LLC (Peabody) for the purchase of subbituminous coal for Big Stone Plant’s coal requirements through December 31, 2020.2022. There isare no fixed minimum purchase requirementrequirements under this agreementthese agreements but all of Big Stone Plant’s coal requirements for the period covered must be purchased under this agreement, except for a portion contracted to be purchased in 2019 under a prior existing agreement with Contura Coal Sales, LLC.exclusively from Peabody. OTP has an all-requirements agreement with Cloud PeakNavajo Transitional Energy Resources LLCCo. for the purchase of subbituminous coal for Hoot Lake Plant through December 31, 2023.2023, There arewith no fixed minimum purchase requirements under this agreement.requirement.
OTP Land Easements
OTP has commitments to make future payments for land easements not classified as leases, extending into 2034 of approximately $10.5$9.9 million.
Contingencies
OTP had a $1.6$2.9 million refund liability on its balance sheet as of June 30, 20192020. representingThis represents its best estimate of the refund obligations that would arise net of amounts that would be subject to recovery under state jurisdictional TCR riders,riders. This is based on the likelihoodoutcome of the appeals of the FERC ruling reducing the ROE component of the MISO Tariff and ordering MISO to refund amounts charged in excess of the lower rate. As discussed in note 3 in greater detail, OTP believes its estimated accrued refund liability is appropriate based on the current facts and circumstances and is awaiting further action byresults of the FERCappeal before determining if a change in this estimate will be needed.
Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. In addition to the potential ROE refund described above, the most significant contingencies that could impact the Company’s consolidated financial statements are those related to environmental remediation, risks associated with warranty claims relating to divested businesses that could exceed established reserve amounts, risks associated with adverse regulatory decisions that could impact the recovery of fixed asset costs in future rates and litigation matters. The Company currently is not aware of any items that would result in charges in excess of established reserve amounts.
In 2015 the Environmental Protection Agency (EPA), acting under Section 111(d) of the Clean Air Act, issued the Clean Power Plan which required states to submit plans to limit carbon dioxide emissions from certain fossil fuel-fired power plants. The rule is not currently in effect as a result of a stay by the Supreme Court in 2016. In 2017, the EPA issued a Notice of Proposed Rulemaking to repeal the Clean Power Plan; comments were due in April 2018.
On August 21, 2018July 30, 2020 the EPA proposedMPUC ordered a replacementreduction in the remaining depreciable lives of OTP’s Hoot Lake Plant and seven hydroelectric plants. The MPUC stipulated recoverability of the resulting increase in depreciation expense, which we estimate will be approximately $1.4 million on an annual basis, would be determined in OTP’s next rate case. Based on the relevant facts and circumstances, OTP has concluded the additional depreciation expense is probable of recovery and will recognize a regulatory asset for the Clean Power Plan --amount of incremental expense recognized in 2020.
State implementation of pollution control plans to improve visibility and air quality at national parks under the Affordable Clean Energy (ACE) Rule. Among other things,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 proposed ACE Rule identifiesCompany’s net income, financial position and cash flows. The North Dakota Department of Environmental Quality (NDDEQ) must submit a liststate 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 “candidate technologies”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 improving a plant’s heat rate and proposes that physical or operational changes to a power plant would emissions control equipment, there are scenarios where it may not be a “major modification” triggering extensive New Source Review, if the change does increase hourly emissions. On June 19, 2019 the EPA released the final versioneconomically feasible to invest in such equipment and an early retirement of the ACE Rule, which willCoyote Station would therefore be effective on September 6, 2019. necessary. The final ACE Rule establishes guidelines for statescosts related to use in developing plansan early retirement of Coyote Station would be material to address greenhouse gas emissions from existing coal-fired power plantsOTP and was finalized in conjunction with two related but separatethe Company and distinct rulemakings, which include repealing the Clean Power Plan and providing revisionswould be subject to state implementation plan guidance. The ACE Rule establishes heat rate improvements, or efficiency improvements, as the best system of emissions reductioncommission approval for carbon dioxiderecovery from existing coal-fired generation units. Heat rate is a measure of the amount of energy required to generate a unit of electricity. States will establish unit-specific standards of performance that reflect the emission limitation achievable through certain candidate heat-rate improvement technologies. The final ACE Rule did not include any final action regarding New Source Review. The EPA intends to address the proposed New Source Rule reforms in a separate final action.customers.
Other
The Company is a party to litigation and regulatory enforcement matters arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of June 30, 20192020, 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 June 30, 20192020 and December 31, 2018:2019:
(in thousands) | Line Limit | In Use on June 30, 2019 | Restricted due to Outstanding Letters of Credit | Available on June 30, 2019 | Available on December 31, 2018 | Line Limit | In Use on June 30, | Restricted due to | Available on June 30, | Available on | ||||||||||||||||||||||||||||||
Otter Tail Corporation Credit Agreement | $ | 130,000 | $ | 13,801 | $ | - | $ | 116,199 | $ | 120,785 | $ | 170,000 | $ | 41,239 | $ | - | $ | 128,761 | $ | 164,000 | ||||||||||||||||||||
OTP Credit Agreement | 170,000 | 22,801 | 8,766 | 138,433 | 160,316 | 170,000 | - | 7,670 | 162,330 | 154,524 | ||||||||||||||||||||||||||||||
Total | $ | 300,000 | $ | 36,602 | $ | 8,766 | $ | 254,632 | $ | 281,101 | $ | 340,000 | $ | 41,239 | $ | 7,670 | $ | 291,091 | $ | 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. OTP used the $35 million proceeds from the issuance to pay for capital expenditures and for other corporate purposes. The Series 2019A Notes, Series 2019B Notes and Series 2019C Notes were issued by the Company on October 10, 2019. The remaining unissued notes of the Note Purchase Agreement, Series 2020B, are expected to be issued on August 20, 2020, subject to the satisfaction of certain customary conditions to closing.
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 June 30, 20192020 and December 31, 2018:2019:
June 30, 2019 (in thousands) | OTP | Otter Tail Corporation | Otter Tail Corporation Consolidated | |||||||||||||||||||||
June 30, 2020 (in thousands) | OTP | Otter Tail | Consolidated | |||||||||||||||||||||
Short-Term Debt | $ | 22,801 | $ | 13,801 | $ | 36,602 | $ | - | $ | 41,239 | $ | 41,239 | ||||||||||||
Long-Term Debt: | ||||||||||||||||||||||||
3.55% Guaranteed Senior Notes, due December 15, 2026 | $ | 80,000 | $ | 80,000 | $ | 80,000 | $ | 80,000 | ||||||||||||||||
Senior Unsecured Notes 4.63%, due December 1, 2021 | $ | 140,000 | 140,000 | |||||||||||||||||||||
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 | 30,000 | 30,000 | ||||||||||||||||||||||
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 | 42,000 | 42,000 | ||||||||||||||||||||||
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 | 60,000 | 60,000 | ||||||||||||||||||||||
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 | 50,000 | 50,000 | ||||||||||||||||||||||
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 | 90,000 | 90,000 | ||||||||||||||||||||||
Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 | 100,000 | 100,000 | ||||||||||||||||||||||
PACE Note, 2.54%, due March 18, 2021 | 438 | 438 | ||||||||||||||||||||||
Senior Unsecured Notes 4.63%, Series 2011A, due December 1, 2021 | $ | 140,000 | 140,000 | |||||||||||||||||||||
Senior Unsecured Notes 6.15%, Series 2007B, due August 20, 2022 | 30,000 | 30,000 | ||||||||||||||||||||||
Senior Unsecured Notes 6.37%, Series 2007C, due August 20, 2027 | 42,000 | 42,000 | ||||||||||||||||||||||
Senior Unsecured Notes 4.68%, Series 2013A, due February 27, 2029 | 60,000 | 60,000 | ||||||||||||||||||||||
Senior Unsecured Notes 3.07%, Series 2019A, due October 10, 20291 | 10,000 | 10,000 | ||||||||||||||||||||||
Senior Unsecured Notes 3.22%, Series 2020A, due February 25, 2030 | 10,000 | 10,000 | ||||||||||||||||||||||
Senior Unsecured Notes 6.47%, Series 2007D, due August 20, 2037 | 50,000 | 50,000 | ||||||||||||||||||||||
Senior Unsecured Notes 3.52%, Series 2019B, due October 10, 2039 | 26,000 | 26,000 | ||||||||||||||||||||||
Senior Unsecured Notes 3.62%. Series 2020C, due February 25, 2040 | 10,000 | 10,000 | ||||||||||||||||||||||
Senior Unsecured Notes 5.47%, Series 2013B, due February 27, 2044 | 90,000 | 90,000 | ||||||||||||||||||||||
Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 | 100,000 | 100,000 | ||||||||||||||||||||||
Senior Unsecured Notes 3.82%, Series 2019C, due October 10, 2049 | 64,000 | 64,000 | ||||||||||||||||||||||
Senior Unsecured Notes 3.92%, Series 2020D, due February 25, 2050 | 15,000 | 15,000 | ||||||||||||||||||||||
PACE Note, 2.54%, due March 18, 2021 | 261 | 261 | ||||||||||||||||||||||
Total | $ | 512,000 | $ | 80,438 | $ | 592,438 | $ | 647,000 | $ | 80,261 | $ | 727,261 | ||||||||||||
Less: Current Maturities net of Unamortized Debt Issuance Costs | - | 177 | 177 | - | 261 | 261 | ||||||||||||||||||
Unamortized Long-Term Debt Issuance Costs | 1,816 | 382 | 2,198 | 2,281 | 330 | 2,611 | ||||||||||||||||||
Total Long-Term Debt net of Unamortized Debt Issuance Costs | $ | 510,184 | $ | 79,879 | $ | 590,063 | $ | 644,719 | $ | 79,670 | $ | 724,389 | ||||||||||||
Total Short-Term and Long-Term Debt (with current maturities) | $ | 532,985 | $ | 93,857 | $ | 626,842 | $ | 644,719 | $ | 121,170 | $ | 765,889 | ||||||||||||
December 31, 2019 (in thousands) | December 31, 2019 (in thousands) | |||||||||||||||||||||||
Short-Term Debt | $ | - | $ | 6,000 | $ | 6,000 | ||||||||||||||||||
Long-Term Debt: | ||||||||||||||||||||||||
3.55% Guaranteed Senior Notes, due December 15, 2026 | $ | 80,000 | $ | 80,000 | ||||||||||||||||||||
Senior Unsecured Notes 4.63%, Series 2011A, due December 1, 2021 | $ | 140,000 | 140,000 | |||||||||||||||||||||
Senior Unsecured Notes 6.15%, Series 2007B, due August 20, 2022 | 30,000 | 30,000 | ||||||||||||||||||||||
Senior Unsecured Notes 6.37%, Series 2007C, due August 20, 2027 | 42,000 | 42,000 | ||||||||||||||||||||||
Senior Unsecured Notes 4.68%, Series 2013A, due February 27, 2029 | 60,000 | 60,000 | ||||||||||||||||||||||
Senior Unsecured Notes 3.07%, Series 2019A, due October 10, 20291 | 10,000 | 10,000 | ||||||||||||||||||||||
Senior Unsecured Notes 6.47%, Series 2007D, due August 20, 2037 | 50,000 | 50,000 | ||||||||||||||||||||||
Senior Unsecured Notes 3.52%, Series 2019B, due October 10, 2039 | 26,000 | 26,000 | ||||||||||||||||||||||
Senior Unsecured Notes 5.47%, Series 2013B, due February 27, 2044 | 90,000 | 90,000 | ||||||||||||||||||||||
Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 | 100,000 | 100,000 | ||||||||||||||||||||||
Senior Unsecured Notes 3.82%, Series 2019C, due October 10, 2049 | 64,000 | 64,000 | ||||||||||||||||||||||
PACE Note, 2.54%, due March 18, 2021 | 351 | 351 | ||||||||||||||||||||||
Total | $ | 612,000 | $ | 80,351 | $ | 692,351 | ||||||||||||||||||
Less: Current Maturities net of Unamortized Debt Issuance Costs | - | 183 | 183 | |||||||||||||||||||||
Unamortized Long-Term Debt Issuance Costs | 2,231 | 356 | 2,587 | |||||||||||||||||||||
Total Long-Term Debt net of Unamortized Debt Issuance Costs | $ | 609,769 | $ | 79,812 | $ | 689,581 | ||||||||||||||||||
Total Short-Term and Long-Term Debt (with current maturities) | $ | 609,769 | $ | 85,995 | $ | 695,764 | ||||||||||||||||||
1Holder is COBANK, a cooperative lender. Interest payments are subject to cash credits which may result in a lower effective interest rate.
December 31, 2018 (in thousands) | OTP | Otter Tail Corporation | Otter Tail Corporation Consolidated | |||||||||
Short-Term Debt | $ | 9,384 | $ | 9,215 | $ | 18,599 | ||||||
Long-Term Debt: | ||||||||||||
3.55% Guaranteed Senior Notes, due December 15, 2026 | $ | 80,000 | $ | 80,000 | ||||||||
Senior Unsecured Notes 4.63%, due December 1, 2021 | $ | 140,000 | 140,000 | |||||||||
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 | 30,000 | 30,000 | ||||||||||
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 | 42,000 | 42,000 | ||||||||||
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 | 60,000 | 60,000 | ||||||||||
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 | 50,000 | 50,000 | ||||||||||
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 | 90,000 | 90,000 | ||||||||||
Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 | 100,000 | 100,000 | ||||||||||
PACE Note, 2.54%, due March 18, 2021 | 523 | 523 | ||||||||||
Total | $ | 512,000 | $ | 80,523 | $ | 592,523 | ||||||
Less: Current Maturities net of Unamortized Debt Issuance Costs | - | 172 | 172 | |||||||||
Unamortized Long-Term Debt Issuance Costs | 1,942 | 407 | 2,349 | |||||||||
Total Long-Term Debt net of Unamortized Debt Issuance Costs | $ | 510,058 | $ | 79,944 | $ | 590,002 | ||||||
Total Short-Term and Long-Term Debt (with current maturities) | $ | 519,442 | $ | 89,331 | $ | 608,773 | ||||||
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 June 30, | Six Months Ended June 30, | Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||||||
(in thousands) | 2019 | 2018 | 2019 | 2018 | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||||
Service Cost—Benefit Earned During the Period | $ | 1,373 | $ | 1,615 | 2,746 | $ | 3,230 | $ | 1,656 | $ | 1,373 | $ | 3,311 | $ | 2,746 | |||||||||||||||||
Interest Cost on Projected Benefit Obligation | 3,603 | 3,363 | 7,206 | 6,726 | 3,263 | 3,603 | 6,526 | 7,206 | ||||||||||||||||||||||||
Expected Return on Assets | (5,324 | ) | (5,299 | ) | (10,649 | ) | (10,599 | ) | (5,505 | ) | (5,324 | ) | (11,010 | ) | (10,649 | ) | ||||||||||||||||
Amortization of Prior-Service Cost: | ||||||||||||||||||||||||||||||||
From Regulatory Asset | 2 | 4 | 3 | 8 | - | 2 | - | 3 | ||||||||||||||||||||||||
From Other Comprehensive Income1 | 2 | - | 4 | - | - | 2 | - | 4 | ||||||||||||||||||||||||
Amortization of Net Actuarial Loss: | ||||||||||||||||||||||||||||||||
From Regulatory Asset | 1,162 | 1,783 | 2,325 | 3,567 | 2,231 | 1,162 | 4,462 | 2,325 | ||||||||||||||||||||||||
From Other Comprehensive Income1 | 26 | 47 | 53 | 91 | 55 | 26 | 110 | 53 | ||||||||||||||||||||||||
Net Periodic Pension Cost2 | $ | 844 | $ | 1,513 | $ | 1,688 | $ | 3,023 | $ | 1700 | $ | 844 | $ | 3,399 | $ | 1,688 | ||||||||||||||||
1Corporate cost included in nonservice cost components of postretirement benefits. | ||||||||||||||||||||||||||||||||
2Allocation of Costs: | ||||||||||||||||||||||||||||||||
Costs included in OTP capital expenditures | $ | 336 | $ | 379 | $ | 726 | $ | 707 | ||||||||||||||||||||||||
2Allocation of costs: | ||||||||||||||||||||||||||||||||
Service costs included in OTP capital expenditures | $ | 432 | $ | 336 | $ | 855 | $ | 726 | ||||||||||||||||||||||||
Service costs included in electric operation and maintenance expenses | 1,004 | 1,195 | 1,954 | 2,442 | 1,185 | 1,004 | 2,377 | 1,954 | ||||||||||||||||||||||||
Service costs included in other nonelectric expenses | 33 | 40 | 66 | 80 | 39 | 33 | 79 | 66 | ||||||||||||||||||||||||
Nonservice costs capitalized as regulatory assets | (130 | ) | (24 | ) | (280 | ) | (45 | ) | 12 | (130 | ) | 23 | (280 | ) | ||||||||||||||||||
Nonservice costs included in nonservice cost components of postretirement benefits | (399 | ) | (77 | ) | (778 | ) | (161 | ) | 32 | (399 | ) | 65 | (778 | ) | ||||||||||||||||||
Cash flows—The Company had no minimum funding requirement as of December 31, 20182019 but made a discretionary plan contribution of $10$11.2 million in January 2019.2020.
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 June 30, | Six Months Ended June 30, | Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||||||
(in thousands) | 2019 | 2018 | 2019 | 2018 | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||||
Service Cost—Benefit Earned During the Period | $ | 104 | $ | 100 | $ | 209 | $ | 200 | $ | 44 | $ | 104 | $ | 89 | $ | 209 | ||||||||||||||||
Interest Cost on Projected Benefit Obligation | 434 | 399 | 868 | 798 | 362 | 434 | 724 | 868 | ||||||||||||||||||||||||
Amortization of Prior-Service Cost: | ||||||||||||||||||||||||||||||||
Amortization of Prior Service Cost: | ||||||||||||||||||||||||||||||||
From Regulatory Asset | 1 | 4 | 2 | 8 | - | 1 | - | 2 | ||||||||||||||||||||||||
From Other Comprehensive Income1 | 4 | 9 | 8 | 19 | - | 4 | - | 8 | ||||||||||||||||||||||||
Amortization of Net Actuarial Loss: | ||||||||||||||||||||||||||||||||
From Regulatory Asset | 31 | 67 | 62 | 134 | 24 | 31 | 47 | 62 | ||||||||||||||||||||||||
From Other Comprehensive Income1 | 88 | 165 | 175 | 330 | 85 | 88 | 171 | 175 | ||||||||||||||||||||||||
Net Periodic Pension Cost2 | $ | 662 | $ | 744 | $ | 1,324 | $ | 1,489 | $ | 515 | $ | 662 | $ | 1,031 | $ | 1,324 | ||||||||||||||||
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 | $ | 26 | $ | 25 | $ | 52 | $ | 50 | $ | - | $ | 26 | $ | - | $ | 52 | ||||||||||||||||
Service costs included in other nonelectric expenses | 78 | 75 | 157 | 150 | 44 | 78 | 89 | 157 | ||||||||||||||||||||||||
Nonservice costs included in nonservice cost components of postretirement benefits | 558 | 644 | 1,115 | 1,289 | 471 | 558 | 942 | 1,115 | ||||||||||||||||||||||||
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 June 30, | Six Months Ended June 30, | Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||||||
(in thousands) | 2019 | 2018 | 2019 | 2018 | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||||
Service Cost—Benefit Earned During the Period | $ | 322 | $ | 381 | $ | 643 | $ | 763 | $ | 462 | $ | 322 | $ | 924 | $ | 643 | ||||||||||||||||
Interest Cost on Projected Benefit Obligation | 772 | 646 | 1,542 | 1,291 | 599 | 772 | 1,197 | 1,542 | ||||||||||||||||||||||||
Amortization of Prior-Service Cost: | ||||||||||||||||||||||||||||||||
From Regulatory Asset | (1,170 | ) | - | (2,339 | ) | - | ||||||||||||||||||||||||||
From Other Comprehensive Income1 | (29 | ) | - | (58 | ) | - | ||||||||||||||||||||||||||
Amortization of Net Actuarial Loss: | ||||||||||||||||||||||||||||||||
From Regulatory Asset | 392 | 412 | 785 | 824 | 1,052 | 392 | 2,103 | 785 | ||||||||||||||||||||||||
From Other Comprehensive Income1 | 9 | 11 | 19 | 21 | 26 | 9 | 52 | 19 | ||||||||||||||||||||||||
Net Periodic Postretirement Benefit Cost2 | $ | 1,495 | $ | 1,450 | $ | 2,989 | $ | 2,899 | $ | 940 | $ | 1,495 | $ | 1,879 | $ | 2,989 | ||||||||||||||||
Effect of Medicare Part D Subsidy | $ | (44 | ) | $ | (36 | ) | $ | (89 | ) | $ | (73 | ) | $ | 280 | $ | (44 | ) | $ | 561 | $ | (89 | ) | ||||||||||
1Corporate cost included in nonservice cost components of postretirement benefits. | ||||||||||||||||||||||||||||||||
2Allocation of Costs: | ||||||||||||||||||||||||||||||||
Costs included in OTP capital expenditures | $ | 79 | $ | 89 | $ | 170 | $ | 167 | ||||||||||||||||||||||||
Service costs included in OTP capital expenditures | $ | 120 | $ | 79 | $ | 238 | $ | 170 | ||||||||||||||||||||||||
Service costs included in electric operation and maintenance expenses | 235 | 283 | 458 | 577 | 331 | 235 | 664 | 458 | ||||||||||||||||||||||||
Service costs included in other nonelectric expenses | 8 | 9 | 15 | 19 | 11 | 8 | 22 | 15 | ||||||||||||||||||||||||
Nonservice costs capitalized as regulatory assets | 288 | 251 | 621 | 468 | 124 | 288 | 246 | 621 | ||||||||||||||||||||||||
Nonservice costs included in nonservice cost components of postretirement benefits | 885 | 818 | 1,725 | �� | 1,668 | 354 | 885 | 709 | 1,725 | |||||||||||||||||||||||
12. Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
Cash Equivalents—The carrying amount approximates fair value because of the short-term maturity of those instruments.
Short-Term Debt—The carrying amount approximates fair value because the debt obligations are short-term and the balances outstanding as of June 30, 20192020 and December 31, 20182019 related to the Otter Tail Corporation Credit Agreement and the OTP Credit Agreement were subject to variable interest rates of LIBOR plus 1.50% and LIBOR plus 1.25%, respectively, which approximate market rates.
Long-Term Debt including Current Maturities—The fair value of the Company's and OTP’s long-term debt is estimated based on the current market indications of rates available to the Company for the issuance of debt. The fair value measurements of the Company’s long-term debt issues fall into level 2 of the fair value hierarchy set forth in ASC 820.
June 30, 2019 | December 31, 2018 | |||||||||||||||
(in thousands) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Cash and Cash Equivalents | $ | 982 | $ | 982 | $ | 861 | $ | 861 | ||||||||
Short-Term Debt | (36,602 | ) | (36,602 | ) | (18,599 | ) | (18,599 | ) | ||||||||
Long-Term Debt including Current Maturities | (590,240 | ) | (631,747 | ) | (590,174 | ) | (601,513 | ) | ||||||||
June 30, 2020 | December 31, 2019 | |||||||||||||||
(in thousands) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Cash and Cash Equivalents | $ | 39,512 | $ | 39,512 | $ | 21,199 | $ | 21,199 | ||||||||
Short-Term Debt | (41,239 | ) | (41,239 | ) | (6,000 | ) | (6,000 | ) | ||||||||
Long-Term Debt including Current Maturities | (724,650 | ) | (795,995 | ) | (689,764 | ) | (742,279 | ) | ||||||||
13. Property, Plant and Equipment
No update required for interim reporting period.
14. Income Tax Expense
The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income before income taxes and income tax expense reported on the Company’s consolidated statements of income for the three- and six-month periods ended June 30, 20192020 and 2018:2019:
Three Months Ended June 30, | Six Months Ended June 30, | Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||||||
(in thousands) | 2019 | 2018 | 2019 | 2018 | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||||
Income Before Income Taxes | $ | 18,769 | $ | 21,750 | $ | 50,721 | $ | 51,759 | $ | 20,789 | $ | 18,769 | $ | 50,695 | $ | 50,721 | ||||||||||||||||
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) | $ | 4,879 | $ | 5,655 | $ | 13,187 | $ | 13,457 | ||||||||||||||||||||||||
Decreases in Tax from: | ||||||||||||||||||||||||||||||||
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) | $ | 5,405 | $ | 4,879 | $ | 13,181 | $ | 13,187 | ||||||||||||||||||||||||
(Decreases) Increases in Tax from: | ||||||||||||||||||||||||||||||||
Differences Reversing in Excess of Federal Rates | (774 | ) | (1,025 | ) | (1,757 | ) | (2,098 | ) | (543 | ) | (774 | ) | (1,772 | ) | (1,757 | ) | ||||||||||||||||
Allowance for Funds Used During Construction – Equity | (248 | ) | (94 | ) | (560 | ) | (180 | ) | ||||||||||||||||||||||||
Excess Tax Deduction – Equity Method Stock Awards | - | - | (827 | ) | (624 | ) | - | - | (535 | ) | (827 | ) | ||||||||||||||||||||
Corporate Owned Life Insurance | (150 | ) | (17 | ) | (559 | ) | (25 | ) | ||||||||||||||||||||||||
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes | (258 | ) | (258 | ) | (516 | ) | (516 | ) | (258 | ) | (258 | ) | (516 | ) | (516 | ) | ||||||||||||||||
Research and Development and Other Tax Credits | (187 | ) | (180 | ) | (375 | ) | (360 | ) | (333 | ) | (187 | ) | (387 | ) | (375 | ) | ||||||||||||||||
Allowance for Funds Used During Construction – Equity | (94 | ) | (111 | ) | (180 | ) | (278 | ) | ||||||||||||||||||||||||
Federal Production Tax Credits | - | (930 | ) | - | (2,050 | ) | ||||||||||||||||||||||||||
Other Comprehensive Income Deferred Tax Rate Adjustment | - | - | - | (531 | ) | |||||||||||||||||||||||||||
Corporate Owned Life Insurance | (193 | ) | (150 | ) | 14 | (559 | ) | |||||||||||||||||||||||||
Other Items – Net | (73 | ) | (80 | ) | (2 | ) | (127 | ) | (22 | ) | (73 | ) | 21 | (2 | ) | |||||||||||||||||
Income Tax Expense | $ | 3,343 | $ | 3,054 | $ | 8,971 | $ | 6,848 | $ | 3,808 | $ | 3,343 | $ | 9,446 | $ | 8,971 | ||||||||||||||||
Effective Income Tax Rate | 17.8 | % | 14.0 | % | 17.7 | % | 13.2 | % | 18.3 | % | 17.8 | % | 18.6 | % | 17.7 | % | ||||||||||||||||
The following table summarizes the activity related to the Company’s unrecognized tax benefits:
(in thousands) | 2019 | 2018 | 2020 | 2019 | ||||||||||||
Balance on January 1 | $ | 1,282 | $ | 684 | $ | 1,488 | $ | 1,282 | ||||||||
Decreases Related to Tax Positions for Prior Years | - | - | (42 | ) | - | |||||||||||
Increases Related to Tax Positions for Current Year | 75 | 72 | 81 | 75 | ||||||||||||
Uncertain Positions Resolved During Year | (42 | ) | (44 | ) | - | (42 | ) | |||||||||
Balance on June 30 | $ | 1,315 | $ | 712 | $ | 1,527 | $ | 1,315 | ||||||||
The balance of unrecognized tax benefits as of June 30, 20192020 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of June 30, 20192020 is not expected to change significantlycould be reduced by as much as $725,000 within the next 12 months. 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. There was no amount accrued for interest on tax uncertainties as of June 30, 2019.
The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of August 1, 2019,2020, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 20152016 for federal, Minnesota and North Dakota income taxes.
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
COVID-19
Otter Tail Corporation (the Company, we, us and our) continues to monitor the progression of the novel coronavirus (COVID-19) and its impact on our businesses, employees, customers, construction contractors and vendors. As this pandemic continues, we are following the directives and advice of government leaders and medical professionals and have adopted practices to help curtail the spread of the virus and mitigate its impact on our communities, employees, construction contractors, customers and business operations. Our Electric segment business provides a critical service to our customers and our manufacturing platform businesses provide products and support to critical infrastructure industries. All of our operating companies have been deemed critical infrastructure businesses. Accordingly, we continue to operate our businesses in a manner that is safe for our employees and our customers.
COVID-19 and the resulting economic conditions have had a material negative impact on the results of operations in our Manufacturing segment, and, to a lesser extent, also impacted the results of operations of our Electric and Plastics segments, but have not had a material impact on our consolidated financial position or liquidity. We began to see a reduction in customer demand in our Manufacturing segment in late March 2020 and have experienced significantly lower levels of customer demand in this segment through the end of June 2020. We anticipate this reduced demand will continue over the near term. Within our Electric segment, we have experienced reduced demand from commercial and industrial customers, and the risk of disruptions for our capital projects, including Merricourt and Astoria Station, also continues. With over 250 individuals working on the Astoria Station site at times during various stages of construction, 26 have tested positive for COVID-19. Continued or additional incidence of infection at the Astoria Station or Merricourt sites, may result in delayed completion schedules and increased costs for these projects. In our Plastics segment, we experienced lower sales in the second quarter as distributors reduced inventory levels due to uncertainty over the impact of COVID-19.
Beginning in April 2020, in response to the actual and anticipated impact of COVID-19 on our business operations, we have 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 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 level. This measure is commonly used in calculations relating to the energy consumption required to cool buildings.
Otter Tail Power Company (OTP) generally bases its forecasted kilowatt-hour (kwh) sales and rates on expected consumption under a normal level of HDDs and CDDs over a given period of time in its service territory. Increased or decreased levels of consumption for certain customer classifications are attributed to deviation from the norms and are a significant factor influencing consumption of electricity across our service territory. We present HDDs and CDDs to provide an 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 used in the calculation, which can vary from jurisdiction to jurisdiction. The Company presents actual and forecasted levels of utility rate base in its outlook to provide an indication of expected investments on which the Company expects to earn future returns.
Results of Operations
Following is an analysis of the Company’s operating results of Otter Tail Corporation (the Company, we, us and our) by business segment for the three and six months ended June 30, 20192020 and 20182019 followed by a discussion of changes in our consolidated financial position during the six months ended June 30, 20192020 and our business outlook for the remainder of 2019.2020.
Comparison of the Three Months Ended June 30, 20192020 and 20182019
Consolidated operating revenues were $192.8 million for the three months ended June 30, 2020 compared with $229.2 million for the three months ended June 30, 2019 compared with2019. Operating income was $27.9 million for the three months ended June 30,
$226.32018. Operating income was2020 compared with $26.8 million for the three months ended June 30, 2019 compared with $30.1 million for the three months ended June 30, 2018.2019. The Company recorded diluted earnings per share of $0.42 for the three months ended June 30, 2020 compared with $0.39 for the three months ended June 30, 2019 compared with $0.47 for the three months ended June 30, 2018.2019.
Amounts presented in the segment tables that follow for operating revenues, cost of products sold and other nonelectric operating expenses for the three-month periods ended June 30, 20192020 and 20182019 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:
Intersegment Eliminations (in thousands) | June 30, 2019 | June 30, 2018 | June 30, 2020 | June 30, 2019 | ||||||||||||
Operating Revenues: | ||||||||||||||||
Electric | $ | 14 | $ | 6 | $ | 23 | $ | 14 | ||||||||
Nonelectric | (1 | ) | 1 | 1 | (1 | ) | ||||||||||
Costs of Products Sold | 3 | 2 | 2 | 3 | ||||||||||||
Other Nonelectric Expenses | 10 | 5 | 22 | 10 | ||||||||||||
Electric
Three Months Ended | ||||||||||||||||
June 30, | % | |||||||||||||||
(in thousands) | 2019 | 2018 | Change | Change | ||||||||||||
Retail Sales Revenues from Contracts with Customers | $ | 87,976 | $ | 89,400 | $ | (1,424 | ) | (1.6 | ) | |||||||
Changes in Accrued Revenues under Alternative Revenue Programs | 369 | (1,565 | ) | 1,934 | 123.6 | |||||||||||
Total Retail Sales Revenue | $ | 88,345 | $ | 87,835 | $ | 510 | 0.6 | |||||||||
Transmission Services Revenue | 11,469 | 11,313 | 156 | 1.4 | ||||||||||||
Wholesale Revenues – Company Generation | 941 | 2,539 | (1,598 | ) | (62.9 | ) | ||||||||||
Other Revenues | 1,489 | 2,038 | (549 | ) | (26.9 | ) | ||||||||||
Total Operating Revenues | $ | 102,244 | $ | 103,725 | $ | (1,481 | ) | (1.4 | ) | |||||||
Production Fuel | 8,296 | 15,888 | (7,592 | ) | (47.8 | ) | ||||||||||
Purchased Power – System Use | 19,633 | 14,402 | 5,231 | 36.3 | ||||||||||||
Electric Operation and Maintenance Expenses | 39,856 | 37,741 | 2,115 | 5.6 | ||||||||||||
Depreciation and Amortization | 15,082 | 13,979 | 1,103 | 7.9 | ||||||||||||
Property Taxes | 3,900 | 3,273 | 627 | 19.2 | ||||||||||||
Operating Income | $ | 15,477 | $ | 18,442 | $ | (2,965 | ) | (16.1 | ) | |||||||
Electric Megawatt-hour (mwh) Sales | ||||||||||||||||
Retail mwh Sales | 1,088,052 | 1,136,326 | (48,274 | ) | (4.2 | ) | ||||||||||
Wholesale mwh Sales – Company Generation | 42,805 | 95,475 | (52,670 | ) | (55.2 | ) | ||||||||||
Heating Degree Days | 580 | 675 | (95 | ) | (14.1 | ) | ||||||||||
Cooling Degree Days | 104 | 228 | (124 | ) | (54.4 | ) | ||||||||||
Three Months Ended | ||||||||||||||||
June 30, | % | |||||||||||||||
(in thousands) | 2020 | 2019 | Change | Change | ||||||||||||
Retail Sales Revenues from Contracts with Customers | $ | 85,344 | $ | 87,976 | $ | (2,632 | ) | (3.0 | ) | |||||||
Changes in Accrued Revenues under Alternative Revenue Programs | 209 | 369 | (160 | ) | (43.4 | ) | ||||||||||
Total Retail Sales Revenue | $ | 85,553 | $ | 88,345 | $ | (2,792 | ) | (3.2 | ) | |||||||
Transmission Services Revenue | 9,673 | 11,469 | (1,796 | ) | (15.7 | ) | ||||||||||
Wholesale Revenues – Company Generation | 765 | 941 | (176 | ) | (18.7 | ) | ||||||||||
Other Revenues | 2,162 | 1,489 | 673 | 45.2 | ||||||||||||
Total Operating Revenues | $ | 98,153 | $ | 102,244 | $ | (4,091 | ) | (4.0 | ) | |||||||
Production Fuel | 8,788 | 8,296 | 492 | 5.9 | ||||||||||||
Purchased Power – System Use | 13,682 | 19,633 | (5,951 | ) | (30.3 | ) | ||||||||||
Electric Operation and Maintenance Expenses | 33,179 | 39,856 | (6,677 | ) | (16.8 | ) | ||||||||||
Depreciation and Amortization | 15,740 | 15,082 | 658 | 4.4 | ||||||||||||
Property Taxes | 4,168 | 3,900 | 268 | 6.9 | ||||||||||||
Operating Income | $ | 22,596 | $ | 15,477 | 7,119 | 46.0 | ||||||||||
Electric Megawatt-hour (mwh) Sales | ||||||||||||||||
Retail mwh Sales | 1,033,053 | 1,088,052 | (54,999 | ) | (5.1 | ) | ||||||||||
Wholesale mwh Sales – Company Generation | 42,140 | 42,805 | (665 | ) | (1.6 | ) | ||||||||||
HDDs | 635 | 580 | 55 | 9.5 | ||||||||||||
CDDs | 170 | 104 | 66 | 63.5 | ||||||||||||
The following table shows heating and cooling degree days as a percent of normal:
Three Months ended June 30, | ||||||||
2019 | 2018 | |||||||
Heating Degree Days | 112.6 | % | 133.7 | % | ||||
Cooling Degree Days | 95.4 | % | 221.4 | % | ||||
Three Months ended June 30, | ||||||||
2020 | 2019 | |||||||
HDDs | 122.1 | % | 112.6 | % | ||||
CDDs | 156.0 | % | 95.4 | % | ||||
The following table summarizes the estimated effect on diluted earnings per share of the difference in retail kilowatt-hour (kwh)kwh sales under actual weather conditions and expected retail kwh sales under normal weather conditions in the second quarters of 20192020 and 20182019 and between quarters:
2019 vs Normal | 2018 vs Normal | 2019 vs 2018 | ||||||||||
Effect on Diluted Earnings Per Share | $ | 0.01 | $ | 0.04 | $ | (0.03 | ) | |||||
2020 vs Normal | 2019 vs Normal | 2020 vs 2019 | ||||||||||
Effect on Diluted Earnings Per Share | $ | 0.03 | $ | 0.01 | $ | 0.02 | ||||||
The $0.5$2.8 million increasedecrease in retail sales revenue includes:
● | A |
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partially offset by:
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● | A $2.7 million decrease in revenue due to decreased kwh sales to commercial and industrial customers, exclusive of the decrease in fuel cost recovery revenues, mainly due to COVID-19-related impacts in the second quarter of 2020. |
● | A $1.0 million combined decrease in South Dakota Phase-In Rider revenues and Minnesota Conservation Improvement Program Rider revenues. |
These decreases in revenue were partially offset by:
● | A $2.9 million increase in Minnesota and North Dakota renewable rider revenues related to earning a return on funds invested in the Merricourt Wind Energy Center (Merricourt) while the project is under construction. |
● | A $1.3 million increase in revenues related to increased consumption due to favorable quarter over quarter weather impacts. |
● | A $0.7 million increase in revenues from the North Dakota Generation Rider which went into effect in July 2019 to provide a return on funds invested in Astoria Station while the generation project is under construction. |
● | A $0.2 million increase in revenue related to volume sales increases of electricity to residential customers exclusive of the impact of weather on sales. |
Wholesale electric revenuesTransmission services revenue decreased $1.6$1.8 million mainly due to fewer opportunities for wholesale sales as OTP’s Coyote Station was offline duringlower tariffs and decreased transmission volume resulting from lower electrical demand partially attributable to the entireimpact of COVID-19.
The $0.7 million increase in other revenue includes $1.0 million from a commercial customer in the second quarter of 20192020, partially offset by a $0.3 million decrease in revenue from steam sales to an ethanol producer due to an extended maintenance outage. Also, wholesale demand was down due to a milder spring in 2019, which also resulted in lower wholesale electricity prices.Big Stone Plant being on economic dispatch and not producing steam at certain times during the second quarter of 2020.
Production fuel costs decreased $7.6increased $0.5 million despite an 11.7% decrease in kwhs generated from our fuel-burning plants, mainly as a result of a 47.1% decrease20.0% increase in kwhs generated from ourfuel-cost per kwh of generation, weighted heavily by higher fuel burning plants due to the maintenance outagecosts per kwh of generation at Coyote Station and a 43.3% reduction in generation at Hoot Lake Plant due tothe second quarter of 2020. Coyote Station was down for maintenance issues and reduced opportunities for economic dispatch resulting from lower wholesale demand and lower wholesale energy prices due to milder spring weather in the second quarter of 2019.
The cost of purchased power to serve retail customers increased $5.2decreased $6.0 million (36.3%) due to a 66.4% increase in kwhs purchased as a result of needing to purchase replacementa 26.2% decrease in purchased power during Coyote Station’s maintenance outageprices, driven mainly by low prices for natural gas-fired generation, and reduced availability of Hoot Lake Plant due to maintenance issues. The increased costs due to the increasea 5.6% decrease in kwhs purchased was partially mitigated by an 18.1%purchased. The decrease in the cost per kwh purchased resulting from lower wholesale energy pricespower volume is due, in part, to the market factors addressed above.COVID-19-related declines in electricity use by commercial and industrial customers.
Electric operating and maintenance expense increased $2.1decreased $6.7 million, including:
● | A |
● | A $1.1 million decrease in labor and benefit expenses. |
● | A $1.0 million decrease in transmission tariff expenses related to decreased kwh purchases and decreased transmission tariff rates. |
● | A $0.9 million decrease in vegetation maintenance expenses and conservation improvement program expenditures. |
● | A $0.6 million |
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partiallyA $0.4 million decrease in travel-related expenses related to COVID-19 travel restrictions was offset by:
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Property taxby a $0.4 million increase in customer bad debt expense increased $0.6 millionprovisions due to capital additions, mainly transmission assets, in South Dakotaadoption of COVID-19-related service suspension and Minnesota.debt collection policies.
Depreciation and amortization expense increased $1.1$0.7 million mainly due to 20182019 capital additions for generation and transmission plant.
Manufacturing
Three Months Ended | Three Months Ended | |||||||||||||||||||||||||||||||
June 30, | % | June 30, | % | |||||||||||||||||||||||||||||
(in thousands) | 2019 | 2018 | Change | Change | 2020 | 2019 | Change | Change | ||||||||||||||||||||||||
Operating Revenues | $ | 73,496 | $ | 68,154 | $ | 5,342 | 7.8 | $ | 45,948 | $ | 73,496 | $ | (27,548 | ) | (37.5 | ) | ||||||||||||||||
Cost of Products Sold | 56,364 | 51,844 | 4,520 | 8.7 | 36,087 | 56,364 | (20,277 | ) | (36.0 | ) | ||||||||||||||||||||||
Operating Expenses | 7,954 | 7,439 | 515 | 6.9 | 5,499 | 7,954 | (2,455 | ) | (30.9 | ) | ||||||||||||||||||||||
Depreciation and Amortization | 3,419 | 3,760 | (341 | ) | (9.1 | ) | 3,739 | 3,419 | 320 | 9.4 | ||||||||||||||||||||||
Operating Income | $ | 5,759 | $ | 5,111 | $ | 648 | 12.7 | $ | 623 | $ | 5,759 | $ | (5,136 | ) | (89.2 | ) | ||||||||||||||||
The $5.3$27.5 million increasedecrease in revenues in our Manufacturing segment includes the following:
● | Revenues at BTD Manufacturing, Inc. (BTD) |
● | Revenues at T.O. Plastics, Inc. (T.O. Plastics), our manufacturer of thermoformed plastic and horticultural products, |
The $4.5$20.3 million increasedecrease in cost of products sold in our Manufacturing segment includes the following:
● | Cost of products sold at BTD |
● | Cost of products sold at T.O. Plastics |
The $0.5$2.5 million increasedecrease in operating expenses in our Manufacturing segment includes a $0.4$2.3 million increasedecrease in operating expenses at BTD related to initiatives taken at BTD to mitigate the negative impacts on sales related to COVID-19, mainly from increasesreductions in labor-related costs due to additional employees.salaries, incentives and benefits, travel and outside services expenditures. Operating expenses at T.O. Plastics increaseddecreased $0.2 million, mainly due to decreases in salaries and incentives.
BTD incurred $1.0 million in termination costs in the second quarter of 2020, with $0.9 million charged to cost of products sold and $0.1 million duecharged to an increaseoperating expense, related to headcount reductions across all its sites in response to the ongoing reduction in sales and marketing costs. Depreciation and amortization expensevolume.
We estimate COVID-19 issues at BTD decreased $0.3 millionnegatively impacted our second quarter earnings by approximately $0.08 per share. This relates to reduced sales, as a result of certain assets reaching the ends of their depreciable lives.customers initiated or continued temporary plant shutdowns which caused lost labor productivity, and costs related to personal protective equipment. BTD also continued to pay health care costs for furloughed employees.
Plastics
Three Months Ended | Three Months Ended | |||||||||||||||||||||||||||||||
June 30, | % | June 30, | % | |||||||||||||||||||||||||||||
(in thousands) | 2019 | 2018 | Change | Change | 2020 | 2019 | Change | Change | ||||||||||||||||||||||||
Operating Revenues | $ | 53,476 | $ | 54,476 | $ | (1,000 | ) | (1.8 | ) | $ | 48,679 | $ | 53,476 | $ | (4,797 | ) | (9.0 | ) | ||||||||||||||
Cost of Products Sold | 41,635 | 41,703 | (68 | ) | (0.2 | ) | 37,747 | 41,635 | (3,888 | ) | (9.3 | ) | ||||||||||||||||||||
Operating Expenses | 2,949 | 3,262 | (313 | ) | (9.6 | ) | 2,970 | 2,949 | 21 | 0.7 | ||||||||||||||||||||||
Depreciation and Amortization | 861 | 954 | (93 | ) | (9.7 | ) | 872 | 861 | 11 | 1.3 | ||||||||||||||||||||||
Operating Income | $ | 8,031 | $ | 8,557 | $ | (526 | ) | (6.1 | ) | $ | 7,090 | $ | 8,031 | $ | (941 | ) | (11.7 | ) | ||||||||||||||
Plastics segment revenues and operating income decreased $1.0$4.8 million and $0.5$0.9 million, respectively, due to a 3.6%5.8% decrease in pounds of polyvinyl chloride (PVC) pipe prices partially offset bysold in combination with a 1.9% increase3.3% decrease in poundsPVC pipe prices. The decrease in
sales volume increase wasis attributed to a drop in sales to distributors who reduced inventory levels due to stronger demand for productuncertainty over the impact of COVID-19 on sales and expectations of PVC pipe prices decreasing in southcentral and southwestern regionslight of the United States, offset by lower volumes with certain customersdeclining resin prices in the northern regionsecond quarter of our sales territory.2020. Cost of products sold decreased $0.1$3.9 million despitedue to the increasedecrease in sales volume due to 2.0%and a 3.7% decrease in the cost per pound of PVC pipe sold.sold mainly due to a decrease in resin costs. The decrease in pipe prices in excess of thepartially offset by a decrease in costs per pound of pipe soldresin prices resulted in a 9.0%2.0% decrease in gross margin per pound of PVC pipe sold. Plastics segment operating expenses decreased $0.3 million between the quarters mainly due to lower incentive compensation resulting from a decrease in operating income.
Corporate
Corporate includes items such as corporate staff and overhead costs, the results of our captive insurance company and other items excluded from the measurement of operating segment performance. Corporate is not an operating segment. Rather it is added to operating segment totals to reconcile to totals on our consolidated statements of income.
Three Months Ended | Three Months Ended | |||||||||||||||||||||||||||||||
June 30, | % | June 30, | % | |||||||||||||||||||||||||||||
(in thousands) | 2019 | 2018 | Change | Change | 2020 | 2019 | Change | Change | ||||||||||||||||||||||||
Operating Expenses | $ | 2,369 | $ | 1,953 | $ | 416 | 21.3 | $ | 2,315 | $ | 2,369 | $ | (54 | ) | (2.3 | ) | ||||||||||||||||
Depreciation and Amortization | 79 | 52 | 27 | 51.9 | 85 | 79 | 6 | 7.6 | ||||||||||||||||||||||||
Corporate operating expensesInterest Charges
Interest charges increased $0.4to $8.7 million mainlyin the three months ended June 30, 2020 from $7.8 million in the three months ended June 30, 2019. The $0.9 million increase in interest charges is primarily due to an increase in certain employee benefit costs.interest expense at OTP related to debt issuances of $100 million in October of 2019 and $35 million in February of 2020 under OTP’s 2019 Note Purchase Agreement.
Other Income
Other income increased to $2.4 million in the three months ended June 30, 2020 from $0.8 million in the three months ended June 30, 2019. The $1.6 million increase in other income includes:
● | A $0.7 million increase in allowance for equity funds used during construction at OTP mostly related to the Minnesota share of construction work in progress on OTP’s Astoria Station project. |
● | A $0.6 million increase in the cash surrender value of corporate-owned life insurance policies held by the Company. |
● | A $0.2 million increase in unrealized gains earned on equity investments held by our captive insurance company, Otter Tail Assurance Limited. |
Income Tax Expense
Income tax expense increased $0.3$0.5 million in the three months ended June 30, 20192020 compared with the three months ended June 30, 20182019 mainly due to a $0.9 million decrease in federal PTCs resulting from the expiration of PTCs on OTP’s Ashtabula wind farm in November 2018, partially offset by the tax effect of a $3.0$2.0 million decreaseincrease in income before income taxes. The following table provides a reconciliation of income tax expense calculated at our net composite federal and state statutory rate on income before income taxes on our consolidated statements of income.
Three Months Ended June 30, | Three Months Ended June 30, | |||||||||||||||
(in thousands) | 2019 | 2018 | 2020 | 2019 | ||||||||||||
Income Before Income Taxes | $ | 18,769 | $ | 21,750 | $ | 20,789 | $ | 18,769 | ||||||||
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) | $ | 4,879 | $ | 5,655 | $ | 5,405 | $ | 4,879 | ||||||||
Decreases in Tax from: | ||||||||||||||||
(Decreases) Increases in Tax from: | ||||||||||||||||
Differences Reversing in Excess of Federal Rates | (774 | ) | (1,025 | ) | (543 | ) | (774 | ) | ||||||||
Research and Development and Other Tax Credits | (333 | ) | (187 | ) | ||||||||||||
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes | (258 | ) | (258 | ) | ||||||||||||
Allowance for Funds Used During Construction – Equity | (248 | ) | (94 | ) | ||||||||||||
Corporate Owned Life Insurance | (150 | ) | (17 | ) | (193 | ) | (150 | ) | ||||||||
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes | (258 | ) | (258 | ) | ||||||||||||
Research and Development and Other Tax Credits | (187 | ) | (180 | ) | ||||||||||||
Allowance for Funds Used During Construction – Equity | (94 | ) | (111 | ) | ||||||||||||
Federal Production Tax Credits | - | (930 | ) | |||||||||||||
Other Items – Net | (73 | ) | (80 | ) | (22 | ) | (73 | ) | ||||||||
Income Tax Expense | $ | 3,343 | $ | 3,054 | $ | 3,808 | $ | 3,343 | ||||||||
Effective Income Tax Rate | 17.8 | % | 14.0 | % | 18.3 | % | 17.8 | % | ||||||||
ComparisonComparison of the Six Months Ended JuneSix Months Ended June 30, 20192020 and 20182019
Consolidated operating revenues were $427.5 million for the six months ended June 30, 2020 compared with $475.2 million for the six months ended June 30, 2019 compared with $467.62019. Operating income was $67.2 million for the six months ended June 30, 2018. Operating income was2020 compared with $66.4 million for the six months ended June 30, 2019 compared with $67.7 million for the six months ended June 30, 2018.2019. The Company recorded diluted earnings per share of $1.02 for the six months ended June 30, 2020 compared with $1.05 for the six months ended June 30, 2019 compared with $1.13 for the six months ended June 30, 2018.2019.
Amounts presented in the segment tables that follow for operating revenues, cost of products sold and other nonelectric operating expenses for the six-month periods ended June 30, 20192020 and 20182019 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:
Intersegment Eliminations (in thousands) | June 30, 2019 | June 30, 2018 | June 30, 2020 | June 30, 2019 | ||||||||||||
Operating Revenues: | ||||||||||||||||
Electric | $ | 27 | $ | 21 | $ | 29 | $ | 27 | ||||||||
Nonelectric | 3 | - | -- | 3 | ||||||||||||
Costs of Products Sold | 20 | 7 | 7 | 20 | ||||||||||||
Other Nonelectric Expenses | 10 | 14 | 22 | 10 | ||||||||||||
Electric
Six Months Ended | Six Months Ended | |||||||||||||||||||||||||||||||
June 30, | % | June 30, | % | |||||||||||||||||||||||||||||
(in thousands) | 2019 | 2018 | Change | Change | 2020 | 2019 | Change | Change | ||||||||||||||||||||||||
Retail Sales Revenues from Contracts with Customers | $ | 202,931 | $ | 198,580 | $ | 4,351 | 2.2 | $ | 192,034 | $ | 202,931 | $ | (10,897 | ) | (5.4 | ) | ||||||||||||||||
Changes in Accrued Revenues under Alternative Revenue Programs | (680 | ) | (2,440 | ) | 1,760 | (72.1 | ) | 122 | (680 | ) | 802 | 117.9 | ||||||||||||||||||||
Total Retail Sales Revenue | $ | 202,251 | $ | 196,140 | $ | 6,111 | 3.1 | $ | 192,156 | $ | 202,251 | $ | (10,095 | ) | (5.0 | ) | ||||||||||||||||
Transmission Services Revenue | 22,331 | 23,216 | (885 | ) | (3.8 | ) | 20,514 | 22,331 | (1,817 | ) | (8.1 | ) | ||||||||||||||||||||
Wholesale Revenues – Company Generation | 2,468 | 3,554 | (1,086 | ) | (30.6 | ) | 1,641 | 2,468 | (827 | ) | (33.5 | ) | ||||||||||||||||||||
Other Revenues | 3,303 | 3,780 | (477 | ) | (12.6 | ) | 3,718 | 3,303 | 415 | 12.6 | ||||||||||||||||||||||
Total Operating Revenues | $ | 230,353 | $ | 226,690 | $ | 3,663 | 1.6 | $ | 218,029 | $ | 230,353 | $ | (12,324 | ) | (5.4 | ) | ||||||||||||||||
Production Fuel | 27,216 | 34,594 | (7,378 | ) | (21.3 | ) | 22,523 | 27,216 | (4,693 | ) | (17.2 | ) | ||||||||||||||||||||
Purchased Power – System Use | 41,585 | 35,995 | 5,590 | 15.5 | 32,512 | 41,585 | (9,073 | ) | (21.8 | ) | ||||||||||||||||||||||
Other Operation and Maintenance Expenses | 78,238 | 77,216 | 1,022 | 1.3 | 73,794 | 78,238 | (4,444 | ) | (5.7 | ) | ||||||||||||||||||||||
Depreciation and Amortization | 29,567 | 27,901 | 1,666 | 6.0 | 31,416 | 29,567 | 1,849 | 6.3 | ||||||||||||||||||||||||
Property Taxes | 7,859 | 7,108 | 751 | 10.6 | 8,268 | 7,859 | 409 | 5.2 | ||||||||||||||||||||||||
Operating Income | $ | 45,888 | $ | 43,876 | $ | 2,012 | 4.6 | $ | 49,516 | $ | 45,888 | $ | 3,628 | 7.9 | ||||||||||||||||||
Electric mwh Sales | ||||||||||||||||||||||||||||||||
Retail mwh Sales | 2,566,191 | 2,590,219 | (24,028 | ) | (0.9 | ) | 2,462,963 | 2,566,191 | (103,228 | ) | (4.0 | ) | ||||||||||||||||||||
Wholesale mwh Sales – Company Generation | 82,139 | 134,879 | (52,740 | ) | (39.1 | ) | 81,064 | 82,139 | (1,075 | ) | (1.3 | ) | ||||||||||||||||||||
Heating Degree Days | 4,650 | 4,266 | 384 | 9.0 | ||||||||||||||||||||||||||||
Cooling Degree Days | 104 | 228 | (124 | ) | (54.4 | ) | ||||||||||||||||||||||||||
HDDs | 3,907 | 4,650 | (743 | ) | (16.0 | ) | ||||||||||||||||||||||||||
CDDs | 170 | 104 | 66 | 63.5 | ||||||||||||||||||||||||||||
The following table shows heating and cooling degree days as a percent of normal:
Six Months ended June 30, | ||||||||
2019 | 2018 | |||||||
Heating Degree Days | 118.6 | % | 110.1 | % | ||||
Cooling Degree Days | 95.4 | % | 221.4 | % | ||||
Six Months ended June 30, | ||||||||
2020 | 2019 | |||||||
HDDs | 99.1 | % | 118.6 | % | ||||
CDDs | 156.0 | % | 95.4 | % | ||||
The following table summarizes the estimated effect on diluted earnings per share of the difference in retail kwh sales under actual weather conditions and expected retail kwh sales under normal weather conditions in the first six months of 20192020 and 20182019 and between the periods:
2019 vs Normal | 2018 vs Normal | 2019 vs 2018 | ||||||||||
Effect on Diluted Earnings Per Share | $ | 0.08 | $ | 0.06 | $ | 0.02 | ||||||
2020 vs Normal | 2019 vs Normal | 2020 vs 2019 | ||||||||||
Effect on Diluted Earnings Per Share | $ | 0.01 | $ | 0.08 | $ | (0.07 | ) | |||||
The $6.1$10.1 million increasedecrease in retail sales revenue includes:
● | A |
● | A |
● | A $1.0 million decrease in retail revenue in South Dakota |
● | A |
● | A |
|
|
|
|
|
|
These decreases in revenue were partially offset by:
● | A |
● | $1.4 million in revenues from the North Dakota Generation Rider which went into effect in July 2019 to provide a return on funds invested in Astoria Station while the generation project is under construction. |
● | A |
Transmission services revenue decreased $0.9$1.8 million mainly due to a decreasereduction in MISOtransmission tariff revenuerevenues related to decreases in levelsdecreased transmission volume resulting from lower electrical demand partially attributable to the impact of recoverable transmission costs incurred.COVID-19.
Wholesale electric revenues decreased $1.1$0.8 million resulting fromdue to lower wholesale electric prices and a 39.1%1.3% decrease in wholesaleswholesale kwh sales. The lower wholesale prices per kwh resulted in a $0.2 million decrease in margins on wholesale energy sales from OTP’s generating units in the first six months of 2020 compared with the first six months of 2019.
Production fuel costs decreased $4.7 million due to fewer opportunities for wholesale sales asa 23.2% decrease in kwhs generated at OTP’s fuel-burning generation plants, partially offset by a 7.8% increase in fuel costs per kwh generated. A 69.7% increase in generation at Coyote Station, which was offline for maintenance during the entire second quarter of 2019, was more than offset by decreases in generation at both Big Stone Plant and Hoot Lake Plant, which were curtailed due to an extended maintenance outage.
Production fuel costs decreased $7.4 million mainlyeconomic dispatch as a result of a 21.3% decrease in kwhs generated from our fuel burning plants due to the maintenance outage at Coyote Stationreduced demand and lower prices for alternative fuels and generation sources drove market prices for electricity down in the second quarter of 2019 and a 7.6% reduction in generation at Hoot Lake Plant due to maintenance issues in the second quarter of 2019.2020.
The cost of purchased power to serve retail customers increased $5.6decreased $9.1 million (15.5%) due to a 22.9% increase in kwhs purchased as a result of needing to purchase replacementa 25.6% decrease in purchased power during Coyote Station’s maintenance outage and reduced availability of Hoot Lake Plant due to maintenance issues. The increased costs due to theprices, partially offset by a 5.1% increase in kwhs purchased was partially mitigated by a 6.0%purchased. The decrease in market prices for electricity was driven by low prices for natural gas-fired generation in combination with lower demand in the cost per kwh purchased resulting from lower wholesale energy prices.second quarter of 2020 due to COVID-19-related declines in electricity use by commercial and industrial consumers.
Electric operating and maintenance expense increased $1.0decreased $4.4 million, including:
● | A |
● | A |
partially offset by:
|
|
|
|
● | A $0.5 million decrease in materials and supplies and contracted services expenses at Hoot Lake Plant related to |
● | A |
These items were partially offset by:
● | A $1.6 million net increase in |
A $0.7 million decrease in travel and employee education expenses related to COVID-19 travel restrictions and social distancing requirements was offset by a $0.7 million increase in customer bad debt expense provisions due to adoption of COVID-19-related service suspension and debt collection policies.
Depreciation expense increased $1.8 million mainly due to 2019 capital additions for generation and transmission plant, the new customer information system that went into service during the first quarter of 2019 and new service vehicles.
Property tax expense increased $0.8$0.4 million due to capitalproperty additions in South Dakota and Minnesota.
Depreciation expense increased $1.7 million due to recent capital additions including the Big Stone South–Ellendale 345kV transmission line energized in February 2019, the new customer information system put in service in 2019 and other recent transmission plant upgrades.jurisdictional valuations.
Manufacturing
Six Months Ended | Six Months Ended | |||||||||||||||||||||||||||||||
June 30, | % | June 30, | % | |||||||||||||||||||||||||||||
(in thousands) | 2019 | 2018 | Change | Change | 2020 | 2019 | Change | Change | ||||||||||||||||||||||||
Operating Revenues | $ | 151,318 | $ | 136,816 | $ | 14,502 | 10.6 | $ | 114,427 | $ | 151,318 | $ | (36,891 | ) | (24.4 | ) | ||||||||||||||||
Cost of Products Sold | 115,603 | 103,885 | 11,718 | 11.3 | 86,701 | 115,603 | (28,902 | ) | (25.0 | ) | ||||||||||||||||||||||
Operating Expenses | 16,034 | 14,312 | 1,722 | 12.0 | 12,777 | 16,034 | (3,257 | ) | (20.3 | ) | ||||||||||||||||||||||
Depreciation and Amortization | 7,101 | 7,614 | (513 | ) | (6.7 | ) | 7,485 | 7,101 | 384 | 5.4 | ||||||||||||||||||||||
Operating Income | $ | 12,580 | $ | 11,005 | $ | 1,575 | 14.3 | $ | 7,464 | $ | 12,580 | $ | (5,116 | ) | (40.7 | ) | ||||||||||||||||
The $14.5$36.9 million increasedecrease in revenues in our Manufacturing segment includes the following:
● | Revenues at BTD |
● | Revenues at T.O. Plastics |
The $11.7$28.9 million increasedecrease in cost of products sold in our Manufacturing segment includes the following:
● | Cost of products sold at BTD |
● | Cost of products sold at T.O. Plastics increased |
The $1.7$3.3 million increasedecrease in operating expenses in our Manufacturing segment includes a $1.4$2.5 million increasedecrease in operating expenses at BTD related to initiatives taken at BTD to mitigate the negative impacts on sales related to COVID-19, mainly from increasesreductions in labor-related costs due to additional employees.salaries, incentives and benefits, travel and outside services expenditures. Operating expenses at T.O. Plastics increased $0.3decreased $0.8 million, due toincluding $0.4 million as a loss associated withresult of the partial collapsereceipt of a warehouse roofinsurance settlement proceeds in the first quarter of 2020 and a $0.3 million write off of the value of destroyed property in 2019 related to the March 2019 partial roof collapse. T.O, Plastics travel and increasedother selling expenses decreased by $0.1 million due to restrictions on activity in response to COVID-19-related safety initiatives.
BTD incurred $1.0 million in termination costs in the second quarter of 2020, with $0.9 million charged to cost of products sold and $0.1 million charged to operating expense, related to headcount reductions across all its sites in response to the ongoing reduction in sales volume.
We estimate COVID-19 issues at BTD negatively impacted our earnings by approximately $0.09 per share in the first six months of 2020. This relates to reduced sales as customers initiated or continued temporary plant shutdowns which caused lost labor productivity, and marketing expenditures.costs related to personal protective equipment. BTD also continued to pay health care costs for furloughed employees.
Plastics
Six Months Ended | Six Months Ended | |||||||||||||||||||||||||||||||
June 30, | % | June 30, | % | |||||||||||||||||||||||||||||
(in thousands) | 2019 | 2018 | Change | Change | 2020 | 2019 | Change | Change | ||||||||||||||||||||||||
Operating Revenues | $ | 93,534 | $ | 104,129 | $ | (10,595 | ) | (10.2 | ) | $ | 95,076 | $ | 93,534 | $ | 1,542 | 1.6 | ||||||||||||||||
Cost of Products Sold | 72,995 | 78,452 | (5,457 | ) | (7.0 | ) | 73,017 | 72,995 | 22 | -- | ||||||||||||||||||||||
Operating Expenses | 5,614 | 5,876 | (262 | ) | (4.5 | ) | 5,740 | 5,614 | 126 | 2.2 | ||||||||||||||||||||||
Depreciation and Amortization | 1,752 | 1,905 | (153 | ) | (8.0 | ) | 1,762 | 1,752 | 10 | 0.6 | ||||||||||||||||||||||
Operating Income | $ | 13,173 | $ | 17,896 | $ | (4,723 | ) | (26.4 | ) | $ | 14,557 | $ | 13,173 | $ | 1,384 | 10.5 | ||||||||||||||||
Plastics segment revenues decreased $10.6and operating income increased $1.5 million and $1.4 million, respectively, due to a 7.1% decrease4.4% increase in pounds of PVC pipe sold, andpartially offset by a 3.3%2.6% decrease in PVC pipe prices. Because of record first quarterThe sales volume in 2018, the overall decrease in year-over-yearincrease resulted mainly from weather conditions that negatively impacted sales volume was expected. Weather conditions across our sales territory also negatively impactedin the first quarter 2019 sales.of 2019. Cost of products sold decreased $5.5 million due toremained unchanged despite the decreaseincrease in sales volume with no changedue to a 4.2% decrease in the cost per pound of pipe sold, between periods. The decrease in pipe pricesmainly due to decreased resin costs. These items resulted in a 13.9% decrease2.9% increase in gross margin per pound of PVC pipe sold. Plastics segment operating expenses decreased $0.3 million between periods mainly due to a decrease in incentive compensation related to the decrease in operating income.
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.
Six Months Ended | Six Months Ended | |||||||||||||||||||||||||||||||
June 30, | % | June 30, | % | |||||||||||||||||||||||||||||
(in thousands) | 2019 | 2018 | Change | Change | 2020 | 2019 | Change | Change | ||||||||||||||||||||||||
Operating Expenses | $ | 5,101 | $ | 4,969 | $ | 132 | 2.7 | $ | 4,167 | $ | 5,101 | $ | (934 | ) | (18.3 | ) | ||||||||||||||||
Depreciation and Amortization | 152 | 88 | 64 | 72.7 | 172 | 152 | 20 | 13.2 | ||||||||||||||||||||||||
Corporate operating expenses decreased $0.9 million mainly as a result of a net decrease in incentive and benefit costs of $0.5 million and a $0.3 million decrease in contracted service expenditures.
Interest Charges
The $0.6Interest charges increased to $16.8 million increase in interest charges for the six months ended June 30, 2020 from $15.7 million in the six months ended June 30, 2019. The $1.1 million increase in interest charges is primarily due to an increase in interest expense at OTP related to debt issuances of $100 million in October of 2019 and $35 million in February of 2020 under OTP’s 2019 Note Purchase Agreement.
Income Tax Expense
Income tax expense increased $0.5 million in the six months ended June 30, 2020 compared with the six months ended June 30, 2018 is due to a $10.6 million increase in average debt outstanding between the periods, the replacement of $100 million of short-term debt bearing interest at 2.88% with long-term debt bearing interest at 4.07% in February 2018 and an increase in average short-term debt interest rates of approximately 1.1% between periods. A $0.1 million decrease in capitalized interest at OTP also contributed to the increase in interest charges between the quarters.
Nonservice Cost Components of Postretirement Benefits
The $0.7 million decrease in nonservice cost components of postretirement benefits in the six months ended June 30, 2019 compared with the six months ended June 30, 2018, is mostly due to a decrease in nonservice costs of the Company’s pension plans, mainly actuarial loss amortization expenses.
Income Taxes
Income tax expense increased $2.1 million in the six months ended June 30, 2019 compared with the six months ended June 30, 2018 mainly due to a $2.0 million decrease in federal PTCs resulting from the expiration of PTCs on OTP’s Ashtabula wind farm in November 2018.2019. 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 for the three-month periods ended June 30, 2019 and 2018:income.
Six Months Ended June 30, | ||||||||
(in thousands) | 2019 | 2018 | ||||||
Income Before Income Taxes | $ | 50,721 | $ | 51,759 | ||||
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) | $ | 13,187 | $ | 13,457 | ||||
Decreases in Tax from: | ||||||||
Differences Reversing in Excess of Federal Rates | (1,757 | ) | (2,098 | ) | ||||
Excess Tax Deduction – Equity Method Stock Awards | (827 | ) | (624 | ) | ||||
Corporate Owned Life Insurance | (559 | ) | (25 | ) | ||||
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes | (516 | ) | (516 | ) | ||||
Research and Development and Other Tax Credits | (375 | ) | (360 | ) | ||||
Allowance for Funds Used During Construction – Equity | (180 | ) | (278 | ) | ||||
Federal Production Tax Credits | - | (2,050 | ) | |||||
Other Comprehensive Income Deferred Tax Rate Adjustment | - | (531 | ) | |||||
Other Items – Net | (2 | ) | (127 | ) | ||||
Income Tax Expense | $ | 8,971 | $ | 6,848 | ||||
Effective Income Tax Rate | 17.7 | % | 13.2 | % | ||||
Six Months Ended June 30, | ||||||||
(in thousands) | 2020 | 2019 | ||||||
Income Before Income Taxes | $ | 50,695 | $ | 50,721 | ||||
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) | $ | 13,181 | $ | 13,187 | ||||
(Decreases) Increases in Tax from: | ||||||||
Differences Reversing in Excess of Federal Rates | (1,772 | ) | (1,757 | ) | ||||
Allowance for Funds Used During Construction – Equity | (560 | ) | (180 | ) | ||||
Excess Tax Deduction – Equity Method Stock Awards | (535 | ) | (827 | ) | ||||
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes | (516 | ) | (516 | ) | ||||
Research and Development and Other Tax Credits | (387 | ) | (375 | ) | ||||
Corporate Owned Life Insurance | 14 | (559 | ) | |||||
Other Items – Net | 21 | (2 | ) | |||||
Income Tax Expense | $ | 9,446 | $ | 8,971 | ||||
Effective Income Tax Rate | 18.6 | % | 17.7 | % | ||||
Financial PositionLiquidity
The following table presents the status of our lines of credit as of June 30, 2019 and December 31, 2018:
(in thousands) | Line Limit | In Use on June 30, 2019 | Restricted due to Outstanding Letters of Credit | Available on June 30, 2019 | Available on December 31, 2018 | |||||||||||||||
Otter Tail Corporation Credit Agreement | $ | 130,000 | $ | 13,801 | $ | - | $ | 116,199 | $ | 120,785 | ||||||||||
OTP Credit Agreement | 170,000 | 22,801 | 8,766 | 138,433 | 160,316 | |||||||||||||||
Total | $ | 300,000 | $ | 36,602 | $ | 8,766 | $ | 254,632 | $ | 281,101 | ||||||||||
We believe we have the necessary liquidity to effectively conduct business operations for an extended period if needed. Our balance sheet is strong and we are in compliance with our debt covenants. Financial flexibility is provided by operating cash flows, unused lines of credit, strong financial coverages, investment grade credit ratings and alternative financing arrangements such as leasing.
We believe our financial condition is strong and our cash, other liquid assets, operating cash flows, existing lines of credit, access to capital markets, and borrowing ability because of investment-grade credit ratings, when taken together, provide adequate resourcesus ample liquidity to fund ongoing operating requirementsconduct business operations and futurefund capital expenditures related to expansion of existing businesses and development of new projects. On May 3, 2018Our liquidity, including our operating cash flows and access to capital markets, can be impacted by macroeconomic factors outside of our control, such as those which may be caused by COVID-19. In addition, our liquidity could be impacted by non-compliance with covenants under our various debt instruments. As of June 30, 2020, we filedwere in compliance with all debt covenants (see the Financial Covenant section under Capital Resources below).
As of June 30, 2020, COVID-19 and the resulting deteriorating economic conditions had not had a shelf registration statement withmaterial impact on our liquidity. We continue to have sufficient liquidity under our credit facilities to support our operating companies based on the SECcurrent economic environment. We are closely monitoring our liquidity and capital market conditions given the uncertainty surrounding the impact of COVID-19, which could have an adverse effect on the availability and terms of future debt and equity financing.
The following table presents the status of our lines of credit as of June 30, 2020 and December 31, 2019:
(in thousands) | Line Limit | In Use on June 30, 2020 | Restricted due to Outstanding Letters of Credit | Available on June 30, 2020 | Available on December 31, 2019 | |||||||||||||||
Otter Tail Corporation Credit Agreement | $ | 170,000 | $ | 41,239 | $ | -- | $ | 128,761 | $ | 164,000 | ||||||||||
OTP Credit Agreement | 170,000 | -- | 7,670 | 162,330 | 154,524 | |||||||||||||||
Total | $ | 340,000 | $ | 41,239 | $ | 7,670 | $ | 291,091 | $ | 318,524 | ||||||||||
We have adopted an internal risk tolerance metric to maintain a minimum of $50 million of liquidity under the Otter Tail Corporation Credit Agreement. Should additional liquidity be needed, this agreement includes an accordion feature allowing us to increase the amount available to $290 million, subject to certain terms and conditions. The OTP Credit Agreement also includes an accordion feature allowing OTP to increase that facility to $250 million, subject to certain terms and conditions.
We expect to issue our Series 2020B Notes on August 20, 2020 to provide an additional $40.0 million of liquidity. Our At-the-Market equity offering program, which we may offer for sale, from timeallows us to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, which expires on May 3, 2021. On May 3, 2018, we also filed a shelf registration statement with the SEC for the issuance ofsell common shares up to 1,500,000an aggregate sales price of $75 million, remains in effect. We issued $27.0 million of common shares until May 3, 2021,equity under the Company's Automaticour At-the-Market offering program, Dividend Reinvestment and ShareEmployee Stock Purchase Plan (the Plan), which permits shares purchased by participantsplans in the Planfirst six months of 2020. We expect to be either new issue up to an additional $28 million in common sharesequity under these programs barring any further deteriorations of the capital markets from the COVID-19 pandemic or common shares purchased inother factors. If weakened economic conditions persist for a prolonged period of time, we are prepared to add additional liquidity as necessary, including exercising the open market.accordion features under our lines of credit to increase our available borrowing capacity under the lines by a combined $200 million.
Equity orand debt financing will be required in the period 20192020 through 20232024 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. Our operating cash flowsThe terms and access to capital markets canconditions and the timing of our equity and debt financing activities could be impacted by macroeconomic factors outside our control.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.
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 to consolidated financial statements for moreadditional information. The decision to declare a dividend is reviewed quarterly by the board of directors. On February 5, 20194, 2020 our board of directors increased the quarterly dividend from $0.335$0.35 to $0.35$0.37 per common share.
2020 Cash Flows Compared with 2019 Cash Flows
Cash provided by operating activities was $73.9 million for the six months ended June 30, 2020 compared with cash provided by operating activities of $69.3 million for the six months ended June 30, 2019 compared with $53.4 million for the six months ended June 30, 2018.2019. The primary reasons for the $15.9$4.6 million increase in cash provided by operations between the quarters waswere a $10.0$2.3 million decreaseincrease in discretionary contributions to the corporation’s funded pension plannon-cash depreciation expense and a $12.7 million net increase in cash provided by changes in noncurrent liabilities and deferred credits, partially offset by a $6.4$2.1 million decrease in cash from changes in deferred debits and other assetsused for working capital items between the periods.quarters.
Net cash used in investing activities was $121.0 million for the six months ended June 30, 2020 compared with $55.4 million for the six months ended June 30, 20192019. The $65.6 million increase is mainly due to a $70.3 million increase in cash used for construction expenditures at OTP, partially offset by a $4.5 million net decrease in capital expenditures in our nonutility businesses. OTP’s cash used for capital expenditures totaled $113.9 million in the first six months of 2020 compared with $49.7$43.6 million in the first six months of 2019. The majority of the 2020 expenditures at OTP related to the construction of Astoria Station and Merricourt.
Net cash provided by financing activities was $65.4 million for the six months ended June 30, 2018. The $5.7 million increase in cash used for investing activities includes a $3.7 million increase in capital expenditures at OTP and a $1.7 million increase in capital expenditures at BTD.
Net2020 compared with net cash used in financing activities wasof $13.8 million for the six months ended June 30, 2019. Financing activities in the first six months of 2020 included $35.0 million in proceed from the issuance of long-term debt at OTP under its 2019 compared with $18.9Note Purchase Agreement to fund its current construction program expenditures. Further information on the debt issuance is provided below under “Capital Resources.” We also borrowed $35.2 million under the Otter Tail Corporation Credit Agreement and raised net proceeds of $24.8 million from the issuance of common stock. The proceeds from the line borrowings and stock issuances provided the majority of funds for $78 million in equity contributions to OTP to fund its construction program expenditures. Financing activities in the six months ended June 30, 2018. of 2020 also included $29.9 million in common dividend payments.
Financing activities in the first six months of 2019 included proceeds of $13.4 million from borrowings under the OTP credit agreement to fund OTP capital expenditures and $4.6 million under the Otter Tail Corporation Credit Agreement to provide working capital for our manufacturing companies. The line of credit borrowings were more than offset by $27.9 million in common dividend payments.
Financing activities in the first six months
CAPITAL REQUIREMENTS
2019-20234 Capital Expenditures
Our consolidatedIn 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 plan for the 2019-2023 time period has been revised from $1.07 billion to $1.11 billion. The increase is primarily driven by the need for additional wind and technology-related investments and transmission investments. Given the increased capital expenditure plan, our compounded annual growth rate in rate base is projected to be 8.6% over the 2018 to 2023 timeframe.
total. The following table shows our 20182019 capital expenditures and our currentlyrevised 2020 through 2024 anticipated 2019 through 2023 capital expenditures and electric utility average rate base.base:
(in millions) | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | Total | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | Total | ||||||||||||||||||||||||||||||||||||||||||
Capital Expenditures: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric Segment: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Renewables and Natural Gas Generation | $ | 125 | $ | 264 | $ | 15 | $ | 82 | $ | - | $ | 486 | $ | 258 | $ | 65 | $ | 53 | $ | -- | $ | -- | $ | 376 | ||||||||||||||||||||||||||||||||
Transformative Technology and Infrastructure | 2 | 7 | 18 | 47 | 54 | 128 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Transmission (includes replacements) | 43 | 42 | 21 | 19 | 17 | 142 | ||||||||||||||||||||||||||||||||||||||||||||||||||
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 | 43 | 45 | 58 | 49 | 55 | 250 | 26 | 23 | 25 | 25 | 24 | 123 | ||||||||||||||||||||||||||||||||||||||||||||
Total Electric Segment | $ | 87 | $ | 213 | $ | 358 | $ | 112 | $ | 197 | $ | 126 | $ | 1,006 | $ | 187 | $ | 366 | $ | 138 | $ | 164 | $ | 118 | $ | 112 | $ | 898 | ||||||||||||||||||||||||||||
Manufacturing and Plastics Segments | 18 | 20 | 18 | 19 | 23 | 19 | 99 | 20 | 14 | 17 | 17 | 19 | 17 | 84 | ||||||||||||||||||||||||||||||||||||||||||
Total Capital Expenditures | $ | 105 | $ | 233 | $ | 376 | $ | 131 | $ | 220 | $ | 145 | $ | 1,105 | $ | 207 | $ | 380 | $ | 155 | $ | 181 | $ | 137 | $ | 129 | $ | 982 | ||||||||||||||||||||||||||||
Total Electric Utility Rate Base | $ | 1,100 | $ | 1,176 | $ | 1,394 | $ | 1,531 | $ | 1,581 | $ | 1,665 | ||||||||||||||||||||||||||||||||||||||||||||
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 currently 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 20192020 through 20232024 timeframe.
As of June 30, 2019,2020, OTP had capitalized approximately $19.6$131.7 million in project costs and allowanceallowances for funds used during construction (AFUDC) associated with Merricourt. OTP estimates its direct generation and transmission capital costs for the Merricourt project will be approximately $260 million. Additional transmission system upgrades for the project amounting to approximately $6.5 million will be made by a neighboring MISO transmission owner. OTP has received Notices of Force Majeure from EDF-RE US Development, LLC claiming rights to an extension of guaranteed project completion dates and adjustments to the consideration agreed upon in the TEPC Agreement due to COVID-19 impacts. While details regarding these claims and impact to the project remain uncertain, OTP currently expects Merricourt to be completed before December 31, 2020. These and other potential impacts of COVID-19-related disruptions continue to present risks for the schedule, costs and timing of payments related to the project.
As of June 30, 2020, OTP had capitalized approximately $108.0 million in project costs and AFUDC associated with Astoria Station. OTP expectsestimates its direct generation and transmission capital costs for the Astoria Station project will costbe approximately $158$154 million and anticipates the plant will be completedonline in late 2020 or early 2021, prior to the planned retirement of Hoot Lake Plant in May 2021. OTP has not altered the construction schedule for Astoria Station due to COVID-19. However, COVID-19-related disruptions have increased risks for the project workforce given, among other factors, that it involves more than 250 construction workers on site and 26 have tested positive for COVID-19. Circumstances continue to evolve which could result in a delay in completion and increased costs for the project.
As of June 30, 2019, OTP2020, our capital expenditure activities had capitalized approximately $5.6 millionnot been materially impacted by COVID-19. However, future supply chain, workforce, contractor or other disruptions could result in developmentadded costs and AFUDC associatedlead to delayed completion of certain of our capital expenditure projects. We are actively monitoring our supply chains and working with our contractors to ensure the Merricourt Wind Energy Center (Merricourt). OTP expects Merricourt will cost approximately $270 million and be completed in October 2020. For further details on these two projects see disclosures in Note 3 to our consolidated financial statements.continued safety of all parties.
Contractual Obligations
In the first six months of 2019,2020, OTP paid down approximately $13.5 milliona portion of its $64.5$317 million in obligations for commitments under contracts including its share of construction program commitments and other nonlease commitments in place onas of December 31, 20182019, reducing its obligations for commitments under contracts to $185 million as of June 30, 2020. This includes commitments related to the construction of Astoria Station and Merricourt of $163 million for the remainder of 2020 and $6 million for 2021. In the first quarter of 2020, OTP increased its commitments for the last six months of 2019debt obligations by $26.3 million. Also,$35 million in the second quarter of 2019 OTP’s lease payment obligations reported in Note 8 to the consolidated financial statements increased by $0.2 million as a result of OTP entering into a 27-month agreement for the lease of 20 additional coal rail cars to transport coal to Hoot Lake Plant from May 2019 through August 2021.years beyond 2024.
CAPITAL RESOURCES
On May 3, 2018 we filed a shelf registration statement with the SECSecurities and Exchange Commission (SEC) under which 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, which expires on May 3, 2021. On May 3, 2018 we also filed a shelf registration statement with the SEC for the issuance of up to 1,500,000 common shares under our Automatic Dividend Reinvestment and Share Purchase Plan (the Plan), which permits shares purchased by participants in the Plan to be either new issue common shares or common shares purchased in the open market. The shelf registration for the Plan expires on 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 second quarter of 2020, we received proceeds of $16,331,139, net of $206,723 in commissions, from the issuance of 388,304 common shares under this program.
Debt
Following are brief descriptions of the short-term and long-term credit and debt agreements currently in place at Otter Tail Corporation and OTP. See note 10 to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2019 for additional information on the terms, provisions, restrictions and covenants under these agreements.
Short-Term Debt
The following table presents the status of our lines of credit as of June 30, 2019 and December 31, 2018:
(in thousands) | Line Limit | In Use on June 30, 2019 | Restricted due to Outstanding Letters of Credit | Available on June 30, 2019 | Available on December 31, 2018 | |||||||||||||||
Otter Tail Corporation Credit Agreement | $ | 130,000 | $ | 13,801 | $ | - | $ | 116,199 | $ | 120,785 | ||||||||||
OTP Credit Agreement | 170,000 | 22,801 | 8,766 | 138,433 | 160,316 | |||||||||||||||
Total | $ | 300,000 | $ | 36,602 | $ | 8,766 | $ | 254,632 | $ | 281,101 | ||||||||||
On October 29, 2012 we entered into a Third Amended and Restated Credit Agreement (the OTC Credit Agreement), which isprovided for an unsecured $130 million revolving credit facility that maycould be increased subject to $250 million on thecertain terms and subject to the conditions described in the OTC Credit Agreement.conditions. On October 31, 20182019 the OTC Credit Agreement was amended to extend its expiration date by one year from October 31, 20222023 to October 31, 2023. We can draw on this2024, and to increase the amount of the revolving credit facility to refinance$170 million. The amendment also provides this facility can be increased to $290 million subject to certain indebtednessterms and support our operations and the operations of certain of our subsidiaries.conditions. Borrowings under the OTC Credit Agreement bear interest at LIBOR plus 1.50%, subject to adjustment based on our senior unsecured credit ratings or the issuer rating if a rating is not provided for the senior unsecured credit. We are required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The OTC Credit Agreement contains a number of restrictions on us and the businesses of our wholly owned subsidiary, Varistar Corporation and its subsidiaries, including restrictions on our and their ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of certain other parties and engage in transactions with related parties. The OTC Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The OTC Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in our credit ratings. Our obligations under the OTC Credit Agreement are guaranteed by certain of our subsidiaries. Outstanding letters of credit issued by us under the OTC Credit Agreement can reduce the amount available for borrowing under the line by up to $40 million.
On October 29, 2012 OTP entered into a Second Amended and Restated Credit Agreement (the OTP Credit Agreement), providing for an unsecured $170 million revolving credit facility that may be increased to $250 million on thesubject to certain terms and subject to the conditions described in the OTP Credit Agreement.conditions. On October 31, 20182019 the OTP Credit Agreement was amended to extend its expiration date by one year from October 31, 20222023 to October 31, 2023.2024. OTP can draw on this credit facility to support the working capital needs and other capital requirements of its operations, including letters of credit in an aggregate amount not to exceed $50 million outstanding at any time. Borrowings under this line of credit bear interest at LIBOR plus 1.25%, subject to adjustment based on the ratings of OTP’s senior unsecured debt or the issuer rating if a rating is not provided for the senior unsecured debt. OTP is required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The OTP Credit Agreement contains a number of restrictions on the business of OTP, including restrictions on its ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The OTP Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The OTP Credit 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. OTP’s obligations under the OTP Credit Agreement are not guaranteed by any other party.
Both the OTC Credit Agreement and the OTP Credit Agreement currently expire on October 31, 2023. Borrowings under these agreements currently use LIBOR as the base to determine the applicable interest rate. LIBOR is currently expected to be eliminated by January 1, 2022. Both agreements contain a provision to determine how interest rates will be established in the event a replacement for LIBOR has not been identified before the agreement expires. The process calls for the parties to jointly agree on an alternate rate of interest to LIBOR, such as the Secured Overnight Financing Rate, that gives due consideration to prevailing market convention for determining a rate of interest for syndicated loans in the United States at such time. The parties will enter into amendments to these agreements to reflect any alternate rate of interest and other related changes to the agreements as may be applicable. If for any reason an agreement cannot be reached on an alternate rate of interest, then any borrowings under the agreements will be determined using the Prime Rate plus a margin based on the Company’s and OTP’s long-term debt ratings at the time of the borrowings. If the alternate rate of interest agreed to by the parties is less than zero, such rate shall be deemed to be zero for the purposes of the credit agreement.
Long-Term Debt
2018 Note Purchase Agreement
On November 14, 2017, September 12, 2019,OTP entered into a Note Purchase Agreement (the 20182019 Note Purchase Agreement) with the purchasers named therein, 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).
On February 25, 2020, OTP issued the Series 2020A Notes, the Series 2020C Notes and the Series 2020D Notes pursuant to the 2019 Note Purchase Agreement. OTP used the $35 million proceeds from the issuance to pay for capital expenditures and for other corporate purposes. The Series 2019A Notes, Series 2019B Notes and Series 2019C Notes were issued by OTP on October 10, 2019. The remaining notes to be issued under the 2019 Note Purchase Agreement, Series 2020B Notes, are expected to be issued on August 20, 2020, subject to the satisfaction of certain customary conditions to closing.
On February 27, 2018 OTP issued $100 million aggregate principal amount of OTP’sits 4.07% Series 2018A Senior Unsecured Notes due February 7, 2048 (the 2018 Notes). The 2018 Notes were issued on February 7, 2018. Proceeds from the 2018 Notes were usedpursuant to repay outstanding borrowings under the OTP Credit Agreement.
OTP may prepay all or any parta Note Purchase Agreement dated as of the 2018 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 theNovember 14, 2017 (the 2018 Note Purchase Agreement, any prepayment made by OTP of all of the 2018 Notes then outstanding on or after August 7, 2047 will be made without any make-whole amount. The 2018 Note Purchase Agreement also requires OTP to offer to prepay all outstanding 2018 Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2018 Note Purchase Agreement) of OTP.
The 2018 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 2018 Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2018 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 2018 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event the OTP 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 2018 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the 2018 Notes than any analogous provision contained in the 2018 Note Purchase Agreement (an Additional Covenant), then unless waived by the Required Holders (as defined in the 2018 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2018 Note Purchase Agreement. The 2018 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 OTP Credit Agreement, provided that no default or event of default has occurred and is continuing..
On December 13, 2016 Note Purchase Agreement
On September 23, 2016 we entered into a Note Purchase Agreement (the 2016 Note Purchase Agreement) with the purchasers named therein, pursuant to which we agreed to issue to the purchasers, in a private placement transaction,Otter Tail Corporation issued $80 million aggregate principal amount of ourits 3.55% Guaranteed Senior Notes due December 15, 2026 (the 2026 Notes) pursuant to a Note Purchase Agreement dated as of September 23, 2016 (the 2016 Note Purchase Agreement). The 2026 Notes were issued on December 13, 2016. 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). The proceeds from the issuance of the 2026 Notes were used to repay the remaining $52,330,000 of our 9.000% Senior Notes due December 15, 2016, and to pay down a portion of the $50 million in funds borrowed in February 2016 under a Term Loan Agreement.
We may prepay all or any part of the 2026 Notes (in an amount not less than 10% of the aggregate principal amount of the 2026 Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the 2016 Note Purchase Agreement, any optional prepayment made by us of all of the 2026 Notes on or after September 15, 2026 will be made without any make-whole amount. We are required to offer to prepay all of the outstanding 2026 Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2016 Note Purchase Agreement) of the Company. In addition, if we and our Material Subsidiaries sell a “substantial part” of our or their assets and use the proceeds to prepay or retire senior Interest-bearing Debt (as defined in the 2016 Note Purchase Agreement) of the Company and/or a Material Subsidiary in accordance with the terms of the 2016 Note Purchase Agreement, we are required to offer to prepay a Ratable Portion (as defined in the 2016 Note Purchase Agreement) of the 2026 Notes held by each holder of the 2026 Notes.
The 2016 Note Purchase Agreement contains a number of restrictions on the business of the Company and our Material Subsidiaries. These include restrictions on our and our Material Subsidiaries’ abilities to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, engage in transactions with related parties, redeem or pay dividends on our and our Material Subsidiaries’ shares of capital stock, and make investments. The 2016 Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2016 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 our or our Material Subsidiaries’ credit ratings.
2013 Note Purchase Agreement
On August 14, 2013February 27, 2014 OTP entered into a Note Purchase Agreement (the 2013 Note Purchase Agreement) with the purchasers named therein, pursuant to which OTP agreed to issue to the purchasers, in a private placement transaction,issued $60 million aggregate principal amount of OTP’sits 4.68% Series A Senior Unsecured Notes due February 27, 2029 (the Series A Notes) and $90 million aggregate principal amount of OTP’sits 5.47% Series B Senior Unsecured Notes due February 27, 2044 pursuant to a Note Purchase Agreement dated as of August 14, 2013 (the Series B Notes and, together with the Series A Notes, the Notes). The notes were issued on February 27, 2014.
The 2013 Note Purchase Agreement states that 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 prepaid, together with accrued interest and a make-whole amount, provided that if no default or event of default under the 2013 Note Purchase Agreement exists, any optional prepayment made by OTP of (i) all of the Series A Notes then outstanding on or after November 27, 2028 or (ii) all of the Series B Notes then outstanding on or after November 27, 2043, will be made at 100% of the principal prepaid but without any make-whole amount. In addition, the 2013 Note Purchase Agreement states OTP must offer to prepay all of the 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 2013 Note Purchase Agreement) of OTP..
The 2013 Note Purchase Agreement contains a number of restrictions on the business of OTP, including restrictions on OTP’s ability 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 2013 Note Purchase Agreement also contains affirmative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2013 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 2013 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event the OTP 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 2013 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 2013 Note Purchase Agreement (an Additional Covenant), then unless waived by the Required Holders (as defined in the 2013 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2013 Note Purchase Agreement. The 2013 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 OTP Credit Agreement, provided that no default or event of default has occurred and is continuing.
2007 and 2011 Note Purchase Agreements
On December 1, 2011 OTP issued $140 million aggregate principal amount of its 4.63% Senior Unsecured Notes due December 1, 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). On August 21, 2017 OTP used borrowings under the OTP Credit Agreement to retire its $33 million aggregate principal amount of 5.95% Senior Unsecured Notes, Series A, which had been issued under the 2007 Note Purchase Agreement and matured on August 20, 2017.
The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each states that OTP may prepay all or any part of the notes issued thereunder (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 prepaid, together with accrued interest and a make-whole amount. The 2011 Note Purchase Agreement states in the event of a transfer of utility assets put event, the noteholders thereunder have the right to require OTP to repurchase the notes held by them in full, together with accrued interest and a make-whole amount, on the terms and conditions specified in the 2011 Note Purchase Agreement. The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each also states that OTP must offer to prepay all of the outstanding notes issued thereunder at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of OTP. The note purchase agreements contain a number of restrictions on OTP, including restrictions on OTP’s ability 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 note purchase agreements also include affirmative covenants and events of default, and certain financial covenants as described below under the heading “Financial Covenants.”
Financial Covenants
We were in compliance with the financial covenants in our debt agreements as of June 30, 2019.2020.
No Credit Agreement or Note Purchase Agreement contains any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies.
Our borrowing agreements are subject to certain financial covenants. Specifically:
● | Under the OTC Credit Agreement and the 2016 Note Purchase Agreement, we may not permit the ratio of our Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit our Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis). As of June 30, |
● | Under the 2016 Note Purchase Agreement, we may not permit our Priority Indebtedness to exceed 10% of our Total Capitalization. |
● | Under the OTP Credit Agreement, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00. |
● | Under the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, OTP may not permit the ratio of its Consolidated Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, in each case as provided in the related borrowing agreement, and OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement. As of June 30, |
● | Under the 2013 Note Purchase Agreement, the 2018 Note Purchase Agreement, and the |
As of June 30, 2019,2020, our ratio of Interest-bearing Debt to Total Capitalization was 0.460.48 to 1.00 on a consolidated basis and 0.47 to 1.00 for OTP. Neither Otter Tail Corporation nor OTP had any Priority Indebtedness outstanding as of June 30, 2019.2020.
OFF-BALANCE-SHEET ARRANGEMENTS
We and our subsidiary companies have outstanding letters of credit totaling $11.5$12.1 million, but our line of credit borrowing limits are only restricted by $8.8$7.7 million in outstanding letters of credit. We do not have any other off-balance-sheet arrangements or any relationships with unconsolidated entities or financial partnerships. These entities are often referred to as structured finance special purpose entities or variable interest entities, which are established for the purpose of facilitating off-balance-sheet arrangements or for other contractually narrow or limited purposes. We are not exposed to any financing, liquidity, market or credit risk that could arise if we had such relationships.
20192020 BUSINESS OUTLOOK
We anticipate 2019are raising our 2020 overall diluted earnings per share guidance range based on our first half financial results and updated view of the anticipated effects of the COVID-19 pandemic on our operating companies. We now expect our 2020 diluted earnings per share to be in the range of $2.10 to $2.25. $2.30. This improvement is driven by strong first half 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 also have taken into consideration strategies for improving future operating results, the cyclical nature of some of our businesses, and current regulatory factors facing our Electric segment. We currently expect capital expenditures for 20192020 to be $233$380 million compared with actual cash used for capital expenditures of $105$207 million in 2018.2019. Our Electric segment accounts for 96% of our 2020 planned capital expenditures. The increase in our planned expenditures for 2019 include $79 million for2020 is largely driven by the Merricourt and $46 millionAstoria Station rate base projects. 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. A revised five-year anticipated capital expenditures table is provided above on page 45.
Our current assumptions for Astoria Station.our updated Business Outlook assume our Electric and Plastics segments are in a gradual recovery as reflected in our updated guidance ranges. Our Manufacturing segment is under a slow recovery. BTD’s customers reduced production levels in the second quarter in response to COVID-19, causing a sharp decline in orders and revenue. We are planning for our Manufacturing segment plants to run at higher levels of capacity in the third and fourth quarters as customer forecasts are indicating increased demand as production plants are being brought back online. We continue to believe our assumptions are reasonable based on current business and economic conditions. We recognize these assumptions may prove to be inaccurate given the recent flare-up in COVID cases, which could result in a further slowing of the broader economic recovery. If our assumptions are not correct and we experience a prolonged negative economic impact from COVID-19, our outlook will be revised accordingly.
Segment components of our 2019revised 2020 diluted earnings per share guidance range compared with 20182019 actual earnings and with our previously issued guidance are as follows:follows.
| 2018 EPS by | 2019 Guidance February 18, 2019 | 2019 Guidance May 6, 2019 | 2019 Guidance August 5, 2019 |
| 2019 EPS by | 2020 Guidance February 20, 2020 | 2020 Guidance May 5, 2020 | 2020 Guidance August 3, 2020 | |||||||||||||||||||||||||||||||||||||||||||||||
| Diluted Earnings Per Share | Segment | Low | High | Low | High | Low | High | Segment | Low | High | Low | High | Low | High | ||||||||||||||||||||||||||||||||||||||||||
Electric | $ | 1.36 | $ | 1.46 | $ | 1.49 | $ | 1.48 | $ | 1.51 | $ | 1.48 | $ | 1.51 | $ | 1.48 | $ | 1.67 | $ | 1.70 | $ | 1.65 | $ | 1.70 | $ | 1.67 | $ | 1.70 | ||||||||||||||||||||||||||||
Manufacturing | $ | 0.32 | $ | 0.37 | $ | 0.41 | $ | 0.35 | $ | 0.39 | $ | 0.33 | $ | 0.37 | $ | 0.32 | $ | 0.31 | $ | 0.35 | $ | 0.14 | $ | 0.23 | $ | 0.15 | $ | 0.23 | ||||||||||||||||||||||||||||
Plastics | $ | 0.60 | $ | 0.44 | $ | 0.48 | $ | 0.44 | $ | 0.48 | $ | 0.46 | $ | 0.50 | $ | 0.51 | $ | 0.43 | $ | 0.47 | $ | 0.43 | $ | 0.47 | $ | 0.50 | $ | 0.54 | ||||||||||||||||||||||||||||
Corporate | $ | (0.22 | ) | $ | (0.17 | ) | $ | (0.13 | ) | $ | (0.17 | ) | $ | (0.13 | ) | $ | (0.17 | ) | $ | (0.13 | ) | $ | (0.14 | ) | $ | (0.19 | ) | $ | (0.15 | ) | $ | (0.22 | ) | $ | (0.15 | ) | $ | (0.22 | ) | $ | (0.17 | ) | ||||||||||||||
Total | $ | 2.06 | $ | 2.10 | $ | 2.25 | $ | 2.10 | $ | 2.25 | $ | 2.10 | $ | 2.25 | $ | 2.17 | $ | 2.22 | $ | 2.37 | $ | 2.00 | $ | 2.25 | $ | 2.10 | $ | 2.30 | ||||||||||||||||||||||||||||
Return on Equity | 11.5 | % | 11.5 | % | 12.3 | % | 11.5 | % | 12.3 | % | 11.5 | % | 12.3 | % | 11.6 | % | 11.0 | % | 11.7 | % | 9.9 | % | 11.1 | % | 10.4 | % | 11.4 | % | ||||||||||||||||||||||||||||
The following items contributeOur latest 2020 guidance issued on August 3, 2020, as compared to our earningsearlier guidance for 2019.issued on May 5, 2020, is summarized below.
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o | Capital spending on the Merricourt and Astoria Station rate base projects of $177 million and $81 million, respectively, in 2020. The |
o | Increased revenues related to $25 million in anticipated capital spending for self-funded generator interconnection agreements. |
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The above items are offset by:
o | The impact of unfavorable weather during the first quarter of 2020 and |
o |
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partially offset by:
o | Increased expenses caused in large part by a decrease in the discount rate used for the pension plan and a lower rate used for our long-term rate of return. The discount rate for 2020 is 3.47% compared with 4.50% for 2019. For each 25-basis-point decline in the discount rate, pension expense increases approximately $1.0 million. The assumed long-term rate of return for 2020 is 6.88% compared with 7.25% in 2019. Each 25-basis-point decline in this rate equates to approximately $0.7 million in increased pension expense. |
o | Higher depreciation and property tax expense due to large capital projects being put into service. |
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o | T.O. Plastics’ 2020 earnings are also expected to decline from our original guidance given lower demand and uncertainty across the end markets it serves related to the COVID-19 pandemic. T.O. Plastics |
o | Backlog for the |
● | We are raising our guidance range in 2020 net income for our Plastics segment and now expect 2020 earnings to be in line with 2019. Sales volumes in 2020 are now forecasted to be approximately 2% higher than 2019 given the strong 2020 first half results and current market conditions. Raw material prices did decrease in the second quarter but are now expected to trend up in the third quarter. This increase is related to suppliers’ plants being busy, tightening of demand and the resin export market strengthening. |
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Critical Accounting Policies Involving Significant Estimates
The discussion and analysis of the financial statements and results of operations are based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities.
We use estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used for such items as depreciable lives, asset impairment evaluations, tax provisions, collectability of trade accounts receivable, self-insurance programs, unbilled electric revenues, interim rate refunds, warranty reserves and actuarially determined benefits costs and liabilities. As better information becomes available or actual amounts are known, estimates are revised. Operating results can be affected by revised estimates. Actual results may differ from these estimates under different assumptions or conditions. Management has discussed the application of these critical accounting policies and the development of these estimates with the Audit Committee of the board of directors. A discussion of critical accounting policies is included under the caption “Critical Accounting Policies Involving Significant Estimates” on pages 57 through 59 of our Annual Report on Form 10-K for the year ended December 31, 2018. There2019. Aside from an interim test of goodwill impairment performed for our BTD reporting unit, which is further described below, there were no material changes in critical accounting policies or estimates during the six monthsquarter ended June 30, 2019.2020.
Goodwill is required to be tested annually for impairment and more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Examples of such events or circumstances may include, among others, a significant adverse change in business climate, weakness in an industry in which a reporting unit operates or recent significant cash or operating losses with expectations that those losses will continue. Goodwill is tested for impairment at the reporting unit level. A reporting unit is defined as an operating segment or one level below an operating segment (referred to as a component). A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and segment management regularly reviews the operating results of that component.
During the quarter ended March 31, 2020, the Company concluded an interim impairment test of goodwill of its BTD reporting unit, which carries a goodwill balance of $18.1 million, was warranted. This conclusion was reached based on the deteriorating economic conditions resulting from COVID-19 that led to lower product demand across all end markets beginning in the last half of March 2020 and the anticipation of subsequent further reduced demand resulting from temporary plant shutdowns of our original equipment manufacturer customers. In response to this reduced demand, BTD has reduced its operating levels and implemented certain cost reduction efforts, including temporary furloughs of production employees.
We estimated the fair value of the BTD reporting unit primarily using an income approach, which includes a discounted cash flow methodology to arrive at a fair value estimate by determining the present value of projected future cash flows over a specified period plus a terminal value related to cash flows beyond the projection period. The discount rate applied to the estimated future cash flows reflects our estimate of the weighted-average cost of capital of comparable companies. To supplement our income approach, we reference various market indications of fair value, where available. Our market approach includes fair value estimates using multiples derived from comparable enterprise values to EBITDA and revenue multiples, comparable price earnings ratios and, if available, comparable sales transactions for comparative peer companies.
The impairment assessment indicated no impairment was present as the estimated fair value of the reporting unit exceeded the carrying value by approximately 20%. The most significant assumption impacting our fair value estimate under the income approach is the anticipated duration and severity of reduced demand and the resulting impact on revenue levels given the uncertainty of economic conditions in light of COVID-19. Our assumptions included significantly reduced demand in the second quarter of 2020 followed by recovering levels of demand in the third and fourth quarters of 2020. Other significant assumptions included operating expense levels and our ability to manage costs during the anticipated period of reduced demand, the terminal growth rate which impacts estimated cash flow generation beyond our discrete projection period, and the discount rate applied to our estimated future cash flows.
Our estimates and assumptions inherently include a degree of uncertainty, and these estimates and assumptions could be significantly impacted by factors such as the duration and severity of reduced economic activity and industry conditions within the recreational vehicle, lawn and garden, construction, agricultural, and industrial and energy equipment end markets. A significant change in our estimates and assumptions could result in an impairment charge in a future period which could materially impact our results of operations and financial position.
Forward Looking Information - Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995
In connection with the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995 (the Act), we have filed cautionary statements identifying important factors that could cause our actual results to differ materially from those discussed in forward-looking statements made by or on behalf of the Company. When used in this Form 10-Q and in future filings by the Company with the Securities and Exchange Commission, in our press releases and in oral statements, words such as "may", "will", "expect", "anticipate", "continue", "estimate", "project", "believes" or similar expressions are intended to identify forward-looking statements within the meaning of the Act and are included, along with this statement, for purposes of complying with the safe harbor provision of the Act. These forward-looking statements involve risks and uncertainties. Actual results may differ materially from those contemplated by the forward-looking statements due to, among other factors, the risks and uncertainties described in the section entitled “Risk Factors” in Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2018,2019, in Part II, Item 1A of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, and in Part II, Item 1A of this report on Form 10-Q, as well as the various factors described below:
● | The economic effects of the COVID-19 outbreak and measures taken to arrest its spread could continue to adversely impact our business, including our results of operations, financial condition and liquidity. |
● | Federal and state environmental regulation could require us to incur substantial capital expenditures and increased operating costs. |
● | Weather impacts, including normal seasonal fluctuation of weather, as well as extreme weather events that could be associated with climate change, could adversely affect our results of operations. |
● | Volatile financial markets and changes in our debt ratings could restrict our ability to access capital and increase borrowing costs and pension plan and postretirement health care expenses. |
● | Any significant impairment of our goodwill would cause a decrease in our asset values and a reduction in our net operating income. |
● | The inability of our subsidiaries to provide sufficient earnings and cash flows to allow us to meet our financial obligations and debt covenants and pay dividends to our shareholders could have an adverse effect on |
● | We rely on our information systems to conduct our business, and failure to protect these systems against security breaches or cyber-attacks could adversely affect our business and results of operations. Additionally, if these systems fail or become unavailable for any significant period, our business could be harmed. |
● | Economic conditions could negatively impact our businesses. |
● | If we are unable to achieve the organic growth we expect, our financial performance may be adversely affected. |
● | Our plans to grow our businesses through capital projects, including infrastructure and new technology additions, or to grow or realign our businesses through acquisitions or dispositions may not be successful, which could result in poor financial performance. |
● | We may, from time to time, sell assets to provide capital to fund investments in our electric utility business or for other corporate purposes, which could result in the recognition of a loss on the sale of any assets sold and other potential liabilities. The sale of any of our businesses |
● | Significant warranty claims and remediation costs in excess of amounts normally reserved for such items could adversely affect our results of operations and financial condition. |
● | We are subject to risks associated with energy markets. |
● | Changes in tax laws, as well as judgments and estimates used in the determination of tax-related asset and liability amounts, could materially adversely affect our business, financial condition, results of operations and prospects. |
● | Four of our operating companies have single customers that provide a significant portion of the individual operating company’s and the business segment’s revenue. The loss of, or significant reduction in revenue from, any one of these customers would have a significant negative financial impact on the operating company and its business segment and could have a significant negative financial impact on |
● | The inability to attract and retain a qualified workforce including, but not limited to, executive officers, key employees and employees with specialized skills could have an adverse effect on our operations. |
● | We may experience fluctuations in revenues and expenses related to our electric operations, which may cause our financial results to fluctuate and could impair our ability to make distributions to shareholders or scheduled payments on our debt obligations, or to meet covenants under our borrowing agreements. |
● | Actions by the regulators of our electric operations could result in rate reductions, lower revenues and earnings or delays in recovering capital expenditures. |
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● | The long-range planning required for transmission and generation projects creates risks of increased costs and lower returns on investment when the project is finally completed. |
● | Competition from foreign and domestic manufacturers, the price and availability of raw materials, trade policy and tariffs affecting prices and markets for raw material and manufactured products, prices and supply of scrap or recyclable material and general economic conditions could affect the revenues and earnings of our manufacturing businesses. |
● | Economic conditions in the industries in which our customers operate can have an adverse impact on our results of operations and cash flows. |
● | Our business and operating results may be adversely affected if we are not able to maintain our manufacturing, engineering and technological expertise. |
● | Our manufacturing, painting and coating operations are subject to environmental, health and safety laws and regulations that could result in liabilities to us. |
● | Our plastics operations are highly dependent on a limited number of vendors for PVC resin and a limited supply of PVC resin. The loss of a key vendor, or any interruption or delay in the supply of PVC resin, could result in reduced sales or increased costs for our plastics business. |
● | We compete against many other manufacturers of PVC pipe and manufacturers of alternative products. Customers may not distinguish |
● | Changes in PVC resin prices can negatively affect our plastics business. |
Item 3. Quantitative and Qualitative Disclosures about Market Risk
At June 30, 20192020 we had exposure to market risk associated with interest rates because we had $13.8$41.2 million in short-term debt outstanding subject to variable interest rates indexed to LIBOR plus 1.50% under the OTC Credit Agreement and OTP had $22.8 million in short-term debt outstanding on June 30, 2019 subject to variable interest rates indexed to LIBOR plus 1.25% under the OTP Credit Agreement.
All of our remaining consolidated long-term debt outstanding on June 30, 20192020 has fixed interest rates. We manage our interest rate risk through the issuance of fixed-rate debt with varying maturities, through economic refunding of debt through optional refundings, limiting the amount of variable interest rate debt, and the utilization of short-term borrowings to allow flexibility in the timing and placement of long-term debt.
We have not used interest rate swaps to manage net exposure to interest rate changes related to our portfolio of borrowings. We maintain a ratio of fixed-rate debt to total debt within a certain range. It is our policy to enter into interest rate transactions and other financial instruments only to the extent considered necessary to meet our stated objectives. We do not enter into interest rate transactions for speculative or trading purposes.
The companies in our Manufacturing segment are exposed to market risk related to changes in commodity prices for steel, aluminum, and polystyrene and other plastics resins. The price and availability of these raw materials could affect the revenues and earnings of our Manufacturing segment.
The plasticsPVC pipe companies are exposed to market risk related to changes in commodity prices for PVC resins, the raw material used to manufacture PVC pipe. The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices are rising or stable, sales volume has been higher and when resin prices are falling, sales volume has been lower. Operating income may decline when the supply of PVC pipe increases faster than demand. Due to the commodity nature of PVC resin and the dynamic supply and demand factors worldwide, it is very difficult to predict gross margin percentages or to assume that historical trends will continue.
Item 4. Controls and Procedures
Under the supervision and with the participation of company management, including our Chief Executive Officer and Chief Financial Officer, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of June 30, 2019,2020, the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2019.2020.
During the fiscal quarter ended June 30, 2019,2020, there were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
We are the subject of various pending or threatened legal actions and regulatory proceedings in the ordinary course of our business. Such matters are subject to many uncertainties and to outcomes that are not predictable with assurance. We record a liability in our consolidated financial statements for costs related to claims, including future legal costs, settlements and judgments, where we have assessed that a loss is probable, and an amount can be reasonably estimated. We believeMaterial proceedings are described under note 3, “Rate and Regulatory Matters” and note 9, "Commitments and Contingencies" to the final resolution of currently pending or threatened legal actions and proceedings, either individually or in the aggregate, will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.
statements.
ThereAside from the additional risk factor described below and in Part II, Item 1A of our Quarterly Report on Form 10 Q for the quarter ended March 31, 2020, there has been no material change in the risk factors set forth under Part I, Item 1A, “Risk Factors” on pages 2829 through 3539 of our Annual Report on Form 10-K for the year ended December 31, 2018.2019.
The economic effects of the COVID-19 outbreak and measures taken to arrest its spread could continue toadversely impact our business, including our results of operations, financial condition and liquidity.
The outbreak and global spread of COVID-19, which has been declared a pandemic by the World Health Organization, has adversely impacted economic activity and conditions worldwide and is currently impacting our business operations. The extent to which COVID-19 will continue to impact our business is highly uncertain and will depend on future developments and the extent of federal, state and local government responses affecting economic recovery. In particular, the COVID-19 pandemic could, among other things:
● | further reduce customer demand in our Manufacturing segment, where we have experienced a significant decline in orders as many of our customers are in businesses impacted by the pandemic and have temporarily closed their plants, and where we have already taken steps to reduce our operations, including furloughing of employees and eliminating positions; |
● | reduce customer demand in our Electric segment, including demand from commercial and industrial customers; |
● | reduce customer demand in our Plastics segment; |
● | result in lower PVC pipe sales due to potential delays or cancellation of public water and wastewater infrastructure projects caused by funding shortfalls; |
● | lead to disruptions of our workforce; |
● | force us to temporarily close certain plants or construction sites if precautions to prevent the spread of the virus at those locations are not effective; |
● | increase our bad debt expenses, particularly in our Electric segment; |
● | increase our future pension benefit cost and funding requirements; |
● | increase health insurance premiums; |
● | disrupt the supply chains, delivery systems or construction workforce related to our Electric segment capital expenditure plans, including our Merricourt and Astoria Station projects, resulting in further delays and increased costs; |
● | disrupt global financial markets, reducing our ability to access capital necessary to finance such expenditures, and which could in the future negatively affect our liquidity; and |
● | result in a recession or market correction that could materially affect our business and the value of our common stock. |
We continue to monitor developments involving our workforce, customers, construction contractors, suppliers and vendors and take steps to mitigate against additional impacts, but given the unprecedented and dynamic nature of these circumstances, we cannot predict the full extent of the impact that COVID-19 will have on our results of operations, financial condition and liquidity. The situation continues to change, and the magnitude of the impact will depend, in part, on the length and severity of the pandemic. However, the effects could have a material impact on our results of operations, financial condition and liquidity and heighten many of the known risks described under Part I, Item 1A, “Risk Factors” on pages 29 through 39 of our Annual Report on Form 10-K for the year ended December 31, 2019.
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31.1 | Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31.2 | Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32.1 | Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
32.2 | Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
101.SCH | Inline XBRL Taxonomy Extension Schema Document. |
101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document. |
101.LAB | Inline XBRL Taxonomy Extension Label Linkbase Document. |
101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document. |
101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document. |
* Certain information has been omitted from this exhibit pursuant to Item 601(b)(2)(ii) of Regulation S-K.
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). |
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
OTTER TAIL CORPORATION
By: /s/ Kevin G. Moug
Kevin G. Moug
Chief Financial Officer and Senior Vice President(Chief (Chief Financial Officer/Authorized Officer)
Dated: August9, 2019August 7, 2020