Table of Contents

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

☒    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the quarterly period ended

SeptemberJune 30, 20192020

 

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:

 

OctoberJuly 3131, 20192020 39,759,05440,872,064 Common Shares ($5 par value)

 

 

 

 

OTTER TAIL CORPORATION

 

INDEX

 

Part I. Financial Information

Page No.

  

Item 1.

Financial Statements (not audited)

 
   
 

Consolidated Balance Sheets – SeptemberJune 30, 20192020 and December 31, 2018 2019 (not audited)

2 & 3

   
 

Consolidated Statements of Income – Three and NineSix Months Ended SeptemberJune 30, 2020 and 2019 and 2018(not audited)

4

   
 

Consolidated Statements of Comprehensive Income – Three and NineSix Months Ended SeptemberJune 30, 2020 and 2019 and 2018(not audited)

5

   
 

Consolidated Statements of Common Shareholders’ Equity – Three and NineSix Months Ended SeptemberJune 30, 2020 and 2019 and 2018(not audited)

6

   
 

Consolidated Statements of Cash Flows – NineSix Months Ended SeptemberJune 30, 2020 and 2019 and 2018(not audited)

7

   
 

Condensed Notes to Consolidated Financial Statements (not audited)

8-388-33

   

Item 2.

Management's Discussion and Analysis of Financial Condition and Results of Operations

39-5734-52

   

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

5753

   

Item 4.

Controls and Procedures

5753

   

Part II. Other Information

 
   

Item 1.

Legal Proceedings

5854

   

Item 1A.

Risk Factors 

5854

   

Item 6.

Exhibits

5855

   

Signatures

5955

 

1

 

 

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

 

Item 1. financial statements

Otter Tail Corporation

Consolidated Balance Sheets

Consolidated Balance Sheets

(not audited)

 

(in thousands)

 

September 30,

2019

 

December 31,

2018

  

June 30,

2020

 

December 31,

2019

 
  

Assets

            
  

Current Assets

            

Cash and Cash Equivalents

 $921  $861  $39,512  $21,199 

Accounts Receivable:

      

Trade—Net

 92,189  75,144  84,197  77,947 

Other

 8,884  9,741  6,452  8,773 

Inventories

 97,052  106,270  89,754  97,851 

Unbilled Receivables

 19,020  23,626  19,019  20,911 

Income Taxes Receivable

 -  2,439  -  1,487 

Regulatory Assets

 12,667  17,225  19,958  21,650 

Other

 6,926  6,114  8,031  5,042 

Total Current Assets

 237,659  241,420  266,923  254,860 
  

Investments

 9,743  8,961  10,581  9,894 

Other Assets

 38,996  35,759  40,138  40,196 

Goodwill

 37,572  37,572  37,572  37,572 

Other IntangiblesNet

 11,562  12,450  10,703  11,290 

Regulatory Assets

 130,551  135,257  141,063  144,138 
  

Right of Use Assets - Operating Leases

 21,953  - 

Right of Use Assets - Operating Leases

 20,571  21,851 
  

Plant

            

Electric Plant in Service

 2,189,732  2,019,721  2,211,082  2,212,884 

Nonelectric Operations

 238,542  228,120  252,933  247,356 

Construction Work in Progress

 141,839  181,626  321,621  185,238 

Total Gross Plant

 2,570,113  2,429,467  2,785,636  2,645,478 

Less Accumulated Depreciation and Amortization

 877,958  848,369  923,948  891,684 

Net Plant

 1,692,155  1,581,098  1,861,688  1,753,794 
  

Total Assets

 $2,180,191  $2,052,517  $2,389,239  $2,273,595 

See accompanying condensed notes to consolidated financial statements.

 

2

 

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

 

(in thousands, except share data)

 

September 30,

2019

 

December 31,

2018

  

June 30,

2020

 

December 31,

2019

 
  

Liabilities and Equity

                
  

Current Liabilities

                

Short-Term Debt

 $108,997  $18,599  $41,239  $6,000 

Current Maturities of Long-Term Debt

 180  172  261  183 

Accounts Payable

 89,360  96,291  133,967  120,775 

Accrued Salaries and Wages

 19,151  24,857  16,891  22,730 

Accrued Federal and State Income Taxes

 3,945  - 

Other Accrued Taxes

 13,828  17,287 

Accrued Taxes

 12,193  17,525 

Regulatory Liabilities

 6,311  738  13,023  7,480 

Current Operating Lease Liabilities

 4,006  -  4,543  4,136 

Other Accrued Liabilities

 7,409  12,149  10,806  10,912 

Total Current Liabilities

 253,187  170,093  232,923  189,741 
  

Pensions Benefit Liability

 75,363  98,358  86,657  98,970 

Other Postretirement Benefits Liability

 73,668  71,561  71,845  71,437 

Long-Term Operating Lease Liabilities

 18,384  -  16,584  18,193 

Other Noncurrent Liabilities

 28,130  24,326  34,647  30,833 
  

Commitments and Contingencies (note 9)

                
  

Deferred Credits

                

Deferred Income Taxes

 124,602  120,976  141,538  131,941 

Deferred Tax Credits

 18,963  19,974  17,969  18,626 

Regulatory Liabilities

 238,781  226,469  238,160  239,906 

Other

 2,593  1,895  2,472  2,885 

Total Deferred Credits

 384,939  369,314  400,139  393,358 
  

Capitalization

                

Long-Term Debt—Net

 590,015  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—39,755,277 Shares; 2018—39,664,884 Shares

 198,776  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

 346,294  344,250  390,141  364,790 

Retained Earnings

 215,931  190,433  233,705  222,341 

Accumulated Other Comprehensive Loss

 (4,496) (4,144) (6,035) (6,437)

Total Common Equity

 756,505  728,863  822,055  781,482 

Total Capitalization

 1,346,520  1,318,865  1,546,444  1,471,063 

Total Liabilities and Equity

 $2,180,191  $2,052,517  $2,389,239  $2,273,595 

 

See accompanying condensed notes to consolidated financial statements.

 

3

Otter Tail Corporation

Consolidated Statements of Income

(not audited)

 

Otter Tail Corporation

Consolidated Statements of Income

(not audited)

 

Three Months Ended

September 30,

 

Nine Months Ended

September 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

 $115,285  $105,749  $346,291  $334,858  $97,921  $101,861  $217,878  $231,006 

Changes in Accrued Revenues under Alternative Revenue Programs

 (921) (317) (1,601) (2,757) 209  369  122  (680)

Total Electric Revenues

 114,364  105,432  344,690  332,101  98,130  102,230  218,000  230,326 

Product Sales under Contracts with Customers

 114,288  122,230  359,137  363,175 

Product Sales from Contracts with Customers

 94,626  126,973  209,503  244,849 

Total Operating Revenues

 228,652  227,662  703,827  695,276  192,756  229,203  427,503  475,175 

Operating Expenses

                                

Production Fuel – Electric

 18,331  17,129  45,547  51,723  8,788  8,296  22,523  27,216 

Purchased Power – Electric System Use

 13,163  9,664  54,748  45,659  13,682  19,633  32,512  41,585 

Electric Operation and Maintenance Expenses

 35,869  33,897  114,107  111,113  33,179  39,856  73,794  78,238 

Cost of Products Sold (depreciation included below)

 88,747  93,361  277,325  275,691  73,832  97,996  159,711  188,578 

Other Nonelectric Expenses

 11,665  12,547  38,404  37,690  10,762  13,262  22,662  26,739 

Depreciation and Amortization

 19,657  18,708  58,229  56,216  20,436  19,441  40,835  38,572 

Property Taxes – Electric

 3,965  4,094  11,824  11,202  4,168  3,900  8,268  7,859 

Total Operating Expenses

 191,397  189,400  600,184  589,294  164,847  202,384  360,305  408,787 

Operating Income

 37,255  38,262  103,643  105,982  27,909  26,819  67,198  66,388 

Interest Charges

 7,539  7,549  23,190  22,597  8,662  7,825  16,785  15,651 

Nonservice Cost Components of Postretirement Benefits

 1,055  1,326  3,165  4,129  868  1,075  1,739  2,110 

Other Income

 1,020  1,245  3,114  3,135  2,410  850  2,021  2,094 

Income Before Income Taxes

 29,681  30,632  80,402  82,391  20,789  18,769  50,695  50,721 

Income Tax Expense

 4,936  7,359  13,907  14,207  3,808  3,343  9,446  8,971 

Net Income

 $24,745  $23,273  $66,495  $68,184  16,981  15,426  41,249  41,750 
 

Average Number of Common Shares OutstandingBasic

 39,714,672  39,621,524  39,694,677  39,592,705  40,513,286  39,712,036  40,365,214  39,684,679 

Average Number of Common Shares OutstandingDiluted

 39,946,739  39,903,565  39,922,580  39,882,105  40,676,761  39,917,831  40,560,549  39,910,499 
 

Basic Earnings Per Common Share

 $0.62  $0.59  $1.68  $1.72  $0.42  $0.39  $1.02  $1.05 
 

Diluted Earnings Per Common Share

 $0.62  $0.58  $1.67  $1.71  $0.42  $0.39  $1.02  $1.05 

 

See accompanying condensed notes to consolidated financial statements.

 

4

Otter Tail Corporation

Consolidated Statements of Comprehensive Income

(not audited)

 

Otter Tail Corporation

Consolidated Statements of Comprehensive Income

(not audited)

  

Three Months Ended

September 30,

  

Nine Months Ended

September 30,

 

(in thousands)

 

2019

  

2018

  

2019

  

2018

 

Net Income

 $24,745  $23,273  $66,495  $68,184 

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

  (1)  4   (5)  (106)

Unrealized Gains (Losses) Arising During Period

  30   (14)  187   (93)

Income Tax (Expense) Benefit

  (6)  2   (38)  42 

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

  23   (8)  144   (157)

Pension and Postretirement Benefit Plans:

                

Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11)

  130   232   389   692 

Income Tax Expense

  (34)  (60)  (101)  (180)

Adjustment to Income Tax Expense Related to 2017 Tax Cuts and Jobs Act

  -   -   -   (531)

Pension and Postretirement Benefit Plans – net-of-tax

  96   172   288   (19)

Total Other Comprehensive Income (Loss)

  119   164   432   (176)

Total Comprehensive Income

 $24,864  $23,437  $66,927  $68,008 
  

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.

 

5

 Consolidated Statements of Common Shareholders’ Equity

For the Three- and Six-Month Periods Ended June 30, 2020 and 2019

(not audited)

 

Otter Tail Corporation

Consolidated Statements of Common Shareholders’ Equity

For the Three- and Nine-Month Periods Ended September 30, 2019 and 2018

(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
Shares
Outstanding

 

Par Value,
Common
Shares

 

Premium
on
Common
Shares

 

Retained
Earnings

 

Accumulated
Other
Comprehensive
Income/(Loss)

 

Total
Common
Equity

 

Balance, June 30, 2019

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

Balance, March 31, 2020

  40,376,448  $201,882  $372,669  $231,702  $(6,234) $800,019 

Common Stock Issuances, Net of Expenses

 375  1  (37)      (36) 472,380  2,362  16,235       18,597 

Net Income

        24,745     24,745         16,981     16,981 

Other Comprehensive Income

          119  119           199  199 

Employee Stock Incentive Plan Expense

      1,301       1,301       1,237       1,237 

Common Dividends ($0.35 per share)

        (13,929)    (13,929)

Balance, September 30, 2019

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

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, June 30, 2018

  39,651,436  $198,257  $342,690  $179,605  $(5,971) $714,581 

Balance, March 31, 2019

  39,729,708  $198,649  $342,991  $203,619  $(4,760) $740,499 

Common Stock Issuances, Net of Expenses

 25,194  126  (109)      17 

Net Income

        15,426     15,426 

Other Comprehensive Income

          145  145 

Employee Stock Incentive Plan Expense

      2,148       2,148 

Common Dividends ($0.35 per share)

        (13,930)    (13,930)

Balance, June 30, 2019

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

Balance, December 31, 2019

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

Common Stock Issuances, Net of Expenses

 25,225  126  (126)      -  729,454  3,647  23,222       26,869 

Common Stock Retirements

 (11,777) (59) (503)      (562) (38,217) (191) (1,878)      (2,069)

Net Income

        23,273     23,273         41,249     41,249 

Other Comprehensive Loss

          164  164 

Other Comprehensive Income

          402  402 

Employee Stock Incentive Plan Expense

      1,149       1,149       4,007       4,007 

Common Dividends ($0.335 per share)

        (13,303)    (13,303)

Balance, September 30, 2018

  39,664,884  $198,324  $343,210  $189,575  $(5,807) $725,302 

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

 145,617  728  (747)      (19) 145,242  727  (710)      17 

Common Stock Retirements

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

Net Income

        66,495     66,495         41,750     41,750 

Other Comprehensive Income

          432  432           313  313 

ASU 2018-02 2017 TCJA Stranded Tax Transfer

        784  (784) -         784  (784) - 

Employee Stock Incentive Plan Expense

      5,245       5,245       3,944       3,944 

Common Dividends ($1.05 per share)

        (41,781)    (41,781)

Balance, September 30, 2019

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

Balance, December 31, 2017

  39,557,491  $197,787  $343,450  $161,286  $(5,631) $696,892 

Common Stock Issuances, Net of Expenses

 178,601  893  (986)      (93)

Common Stock Retirements

 (71,208) (356) (2,656)      (3,012)

Net Income

        68,184     68,184 

Other Comprehensive Loss

          (176) (176)

Employee Stock Incentive Plan Expense

      3,402       3,402 

Common Dividends ($1.005 per share)

        (39,895)    (39,895)

Balance, September 30, 2018

  39,664,884  $198,324  $343,210  $189,575  $(5,807) $725,302 

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 

 

6

 Otter Tail Corporation 

Consolidated Statements of Cash Flows

(not audited)

 

Otter Tail Corporation

Consolidated Statements of Cash Flows

(not audited)

 

Nine Months Ended

September 30,

  

Six Months Ended

June 30,

 

(in thousands)

 

2019

 

2018

  

2020

 

2019

 

Cash Flows from Operating Activities

    

Operating Activities

        

Net Income

 $66,495  $68,184  $41,249  $41,750 

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

        

Depreciation and Amortization

 58,229  56,216   40,835   38,572 

Deferred Tax Credits

 (1,011) (1,054)  (657)  (674)

Deferred Income Taxes

 3,487  7,529   9,472   960 

Change in Deferred Debits and Other Assets

 7,142  10,641   5,565   3,884 

Discretionary Contribution to Pension Plan

 (22,500) (20,000)  (11,200)  (10,000)

Change in Noncurrent Liabilities and Deferred Credits

 10,344  (191)  5,178   11,942 

Allowance for Equity/Other Funds Used During Construction

 (1,602) (1,586)  (1,858)  (688)

Stock Compensation Expense—Equity Awards

 5,245  3,402 

Stock Compensation Expense

  4,007   3,944 

Other—Net

 312  (201)  (147)  276 

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

        

Change in Receivables

 (16,213) (27,804)  (3,929)  (30,478)

Change in Inventories

 9,218  (6,581)  8,097   410 

Change in Other Current Assets

 2,974  3,827   (1,066)  2,870 

Change in Payables and Other Current Liabilities

 (20,744) 5,546   (23,562)  222 

Change in Interest and Income Taxes Receivable/Payable

 3,773  2,932   1,917   6,297 

Net Cash Provided by Operating Activities

 105,149  100,860   73,901   69,287 

Cash Flows from Investing Activities

    

Investing Activities

        

Capital Expenditures

 (149,695) (74,489)  (119,830)  (54,012)

Net Proceeds from Disposal of Noncurrent Assets

 4,111  1,879 

Proceeds from Disposal of Noncurrent Assets

  3,953   3,405 

Cash Used for Investments and Other Assets

 (5,546) (3,324)  (5,128)  (4,776)

Net Cash Used in Investing Activities

 (151,130) (75,934)  (121,005)  (55,383)

Cash Flows from Financing Activities

    

Financing Activities

        

Change in Checks Written in Excess of Cash

 383  (7)  550   (1,120)

Net Short-Term Borrowings (Repayments)

 90,398  (96,882)

Payments for Retirement of Capital Stock and Common Stock Issuance Expenses

 (2,765) (3,120)

Net Short-Term Borrowings

  35,239   18,003 

Proceeds from Issuance of Common Stock

  27,225   - 

Common Stock Issuance Expenses

  (374)  - 

Payments for Shares Withheld for Employee Tax Obligations

  (2,069)  (2,730)

Proceeds from Issuance of Long-Term Debt

 -  100,000   35,000   - 

Short-Term and Long-Term Debt Issuance Expenses

 (66) (441)  (179)  - 

Payments for Retirement of Long-Term Debt

 (128) (148)  (90)  (84)

Dividends Paid

 (41,781) (39,895)  (29,885)  (27,852)

Net Cash Provided by (Used in) Financing Activities

 46,041  (40,493)

Net Cash Provided by (Used in) Financing Activities

  65,417   (13,783)

Net Change in Cash and Cash Equivalents

 60  (15,567)  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

 $921  $649  $39,512  $982 

 

See accompanying condensed notes to consolidated financial statements.

 

7

 

OTTER TAIL CORPORATION

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 nine-monthssix months ended SeptemberJune 30, 20192020 should not be taken as an indication of earnings for all or any part of the balance of the year.

 

 

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 No.606, 2014-09,Revenue from Contracts with Customers(Topic 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, RegulatedRegulated 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.

 

8

Table of Contents

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, RRARenewable Resource Cost Recovery and Generation Cost Recovery (GCR) riders.

 

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

 

8

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 ninesix-month periods ended SeptemberJune 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 ninesix-month periods ended SeptemberJune 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.

 

9

Table of Contents

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

 

9

The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of SeptemberJune 30, 20192020 and December 31, 2018:2019:

 

September 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

 $1,462      $1,450     

Corporate Debt Securities – Held by Captive Insurance Company

    $3,378      $3,062  

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

    4,772      5,960  

Other Assets:

            

Money Market and Mutual Funds – Retirement Plans

 2,661     

Money Market and Mutual Funds –Retirement Plans

 1,560     

Total Assets

 $4,123  $8,150   $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 September 30, 2019 those costs is denied by regulatory authorities, could be as high as $51.3approximately $50.0 million, OTP’s 35% share of CCMC’s unrecovered costs.

costs as of June 30, 2020.

 

10

Inventories

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

 

 

September 30,

 

December 31,

  

June 30,

 

December 31,

 

(in thousands)

 

2019

 

2018

  

2020

 

2019

 

Finished Goods

 $29,601  $37,130  $26,190  $31,863 

Work in Process

 18,884  20,393  14,418  16,508 

Raw Material, Fuel and Supplies

 48,567  48,747  49,146  49,480 

Total Inventories

 $97,052  $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 0 changes to goodwill by business segment during the firstnine 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)

September 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 SeptemberJune 30, 20192020 and December 31, 2018:2019:

 

September 30, 2019 (in thousands)

 

Gross Carrying

Amount

 

Accumulated

Amortization

 

Net Carrying

Amount

 

Remaining

Amortization

Periods (months)

 

June 30, 2020 (in thousands)

 

Gross Carrying
Amount

 

Accumulated
Amortization

 

Net Carrying

Amount

 

Remaining
Amortization
Periods (months)

 

Amortizable Intangible Assets:

                    

Customer Relationships

 $22,491  $10,976  $11,515  3-191  $22,491  $11,820  $10,671  82-182 

Other

 154  107  47  11  179  147  32  2-39 

Total

 $22,645  $11,083  $11,562     $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

 

Nine Months Ended

  

Three Months Ended

 

Six Months Ended

 
 

September 30,

 

September 30,

  

June 30,

 

June 30,

 

(in thousands)

 

2019

 

2018

 

2019

 

2018

  

2020

 

2019

 

2020

 

2019

 

Amortization Expense – Intangible Assets

 $296  $329  $888  $1,019  $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

  

2020

 

2021

 

2022

 

2023

 

2024

 

Estimated Amortization Expense – Intangible Assets

 $1,184  $1,133  $1,099  $1,099  $1,099  $1,140  $1,105  $1,105  $1,104  $1,099 

 

11

Table of Contents

Supplemental Disclosures of Cash Flow Information

 

 

As of September 30,

  

As of June 30,

 

(in thousands)

 

2019

 

2018

  

2020

 

2019

 

Noncash Investing Activities:

          

Transactions Related to Capital Additions not Settled in Cash

 $15,893  $12,059  $61,925  $16,841 

 

11

New Accounting Standards Adopted

ASU 2016-02—In February 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.

12

Table of Contents

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 Pending Adoption

 

ASU 2016-13—In June 2016 the FASB issued ASUAccounting Standards Update (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 is effective for interim and annual periods beginning on or afterin the December 15, 2019. The Company does notfirst expect adoptionquarter of 2020. Adoption of the new standard todid not have a material impact on itsthe Company’s consolidated financial statements.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 20120188-1515—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 arewere effective for interim and annual periods beginning on or after December 15, 2019 with early adoption permitted in any interim period. The Company will adoptadopted the amendments in ASU 2018-15 in the first quarter of 20202020. and expects there will beThere was no impact to its consolidated financial statements on adoption, but does expect tothe Company will begin capitalizing implementation costs incurred in cloud computing arrangements post-adoption.

12

 

 

2. Segment Information

 

The accounting policies of the segments are described under note 1 – Summary of Significant Accounting Policies. The Company's businesses have been classified into three segments to 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 3 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.

 

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Table of Contents

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 0 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 1 customer that provided 11.2%11.9% of 20182019 segment revenues. The Manufacturing segment has 1 customer that manufactures and sells recreational vehicles that provided 22.2%23.8% of 20182019 segment revenues and 1 customer that manufactures and sells lawn and garden equipment that provided 11.2%11.1% of 20182019 segment revenues. The Manufacturing segment’s top 5 revenue-generating customers provided over 52%54% of 20182019 segment revenues. The Plastics segment has 2 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 98.1%98.5% of operating revenues for the respective three-month periods ended SeptemberJune 30, 20192020 and 2018,2019, and 98.7%99.0% and 98.2%98.8% of operating revenues for the respective ninesix-month periods ended SeptemberJune 30, 20192020 and 2018.2019.

 

13

The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three- and ninesix-month periods ended SeptemberJune 30, 2019 and 20182020 and total assets by business segment as of SeptemberJune 30, 20192020 and December 31, 20182019 are presented in the following tables:

 

Operating Revenue

 

  

Three Months Ended

  

Nine Months Ended

 
  

September 30,

  

September 30,

 

(in thousands)

 

2019

  

2018

  

2019

  

2018

 

Electric Segment:

                

Retail Sales Revenue from Contracts with Customers

 $100,345  $88,750  $303,276  $287,330 

Changes in Accrued ARP Revenues

  (921)  (317)  (1,601)  (2,757)

Total Retail Sales Revenue

  99,424   88,433   301,675   284,573 

Transmission Services Revenue

  11,692   12,569   34,023   35,785 

Wholesale Revenues – Company Generation

  1,631   2,826   4,099   6,380 

Other Revenues

  1,626   1,614   4,929   5,394 

Total Electric Segment Revenues

  114,373   105,442   344,726   332,132 

Manufacturing Segment:

                

Metal Parts and Tooling

  56,255   55,864   185,520   170,179 

Plastic Products and Tooling

  8,088   8,790   26,486   26,986 

Other

  1,379   2,373   5,034   6,678 

Total Manufacturing Segment Revenues

  65,722   67,027   217,040   203,843 

Plastics Segment – Sale of PVC Pipe Products

  48,566   55,203   142,100   159,332 

Intersegment Eliminations

  (9)  (10)  (39)  (31)

Total

 $228,652  $227,662  $703,827  $695,276 

14

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Three Months Ended

  

Six Months Ended

 
  

June 30,

  

June 30,

 

(in thousands)

 

2020

  

2019

  

2020

  

2019

 

Electric Segment:

                

Retail Sales Revenue from Contracts with Customers

 $85,344  $87,976  $192,034  $202,931 

Changes in Accrued ARP Revenues

  209   369   122   (680)

Total Retail Sales Revenue

  85,553   88,345   192,156   202,251 

Transmission Services Revenue

  9,673   11,469   20,514   22,331 

Wholesale Revenues – Company Generation

  765   941   1,641   2,468 

Other Revenues

  2,162   1,489   3,718   3,303 

Total Electric Segment Revenues

  98,153   102,244   218,029   230,353 

Manufacturing Segment:

                

Metal Parts and Tooling

  37,267   62,541   94,478   129,265 

Plastic Products and Tooling

  7,840   9,353   17,723   18,398 

Other

  841   1,602   2,226   3,655 

Total Manufacturing Segment Revenues

  45,948   73,496   114,427   151,318 

Plastics Segment – Sale of PVC Pipe Products

  48,679   53,476   95,076   93,534 

Intersegment Eliminations

  (24)  (13)  (29)  (30)

Total

 $192,756  $229,203  $427,503  $475,175 

 

Interest Charges

 

 

Three Months Ended

 

Nine Months Ended

  

Three Months Ended

 

Six Months Ended

 
 

September 30,

 

September 30,

  

June 30,

 

June 30,

 

(in thousands)

 

2019

 

2018

 

2019

 

2018

  

2020

 

2019

 

2020

 

2019

 

Electric

 $6,300  $6,509  $19,566  $19,586  $7,348  $6,625  $14,732  $13,266 

Manufacturing

 561  555  1,791  1,664  554  646  1,108  1,230 

Plastics

 197  150  561  460  186  215  334  364 

Corporate and Intersegment Eliminations

 481  335  1,272  887  574  339  611  791 

Total

 $7,539  $7,549  $23,190  $22,597  $8,662  $7,825  $16,785  $15,651 

 

Income Taxes

 

 

Three Months Ended

 

Nine Months Ended

  

Three Months Ended

 

Six Months Ended

 
 

September 30,

 

September 30,

  

June 30,

 

June 30,

 

(in thousands)

 

2019

 

2018

 

2019

 

2018

  

2020

 

2019

 

2020

 

2019

 

Electric

 $4,066  $5,172  $9,874  $7,881  $2,579  $1,037  $6,199  $5,808 

Manufacturing

 285  799  2,888  3,040  (189) 1,149  1,272  2,603 

Plastics

 1,914  2,276  5,287  6,897  1,818  2,044  3,735  3,373 

Corporate

 (1,329) (888) (4,142) (3,611) (400) (887) (1,760) (2,813)

Total

 $4,936  $7,359  $13,907  $14,207  $3,808  $3,343  $9,446  $8,971 

 

Net Income (Loss)

 

 

Three Months Ended

 

Nine Months Ended

  

Three Months Ended

 

Six Months Ended

 
 

September 30,

 

September 30,

  

June 30,

 

June 30,

 

(in thousands)

 

2019

 

2018

 

2019

 

2018

  

2020

 

2019

 

2020

 

2019

 

Electric

 $17,682  $14,567  $43,884  $41,835  $13,306  $7,502  $29,488  $26,202 

Manufacturing

 3,155  3,022  11,987  10,769  238  3,990  5,165  8,832 

Plastics

 5,397  6,432  14,918  19,505  5,130  5,792  10,579  9,521 

Corporate

 (1,489) (748) (4,294) (3,925) (1,693) (1,858) (3,983) (2,805)

Total

 $24,745  $23,273  $66,495  $68,184  $16,981  $15,426  $41,249  $41,750 

 

14

Identifiable Assets

 

  

September 30,

  

December 31,

 

(in thousands)

 

2019

  

2018

 

Electric

 $1,829,271  $1,728,534 

Manufacturing

  206,835   187,556 

Plastics

  97,459   91,630 

Corporate

  46,626   44,797 

Total

 $2,180,191  $2,052,517 

  

June 30,

  

December 31,

 

(in thousands)

 

2020

  

2019

 

Electric

 $2,054,523  $1,931,525 

Manufacturing

  184,462   195,742 

Plastics

  102,285   92,049 

Corporate

  47,969   54,279 

Total

 $2,389,239  $2,273,595 

 

 

3. Rate and Regulatory Matters

 

Below are descriptions of OTP’s major capital expenditure projects that 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

Astoria Station—OTP is constructing this 245-megawatt (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 Advance 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

15

Table of Contents

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 excavating began in May 2019. As of September 30, 2019, OTP had capitalized approximately $36.8 million in project costs and allowance for funds used during construction (AFUDC) associated with Astoria Station. OTP expects the project will cost approximately $158 million.

 

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 and assume the development assets and assume certain specified liabilities associated with Merricourt, a 150-MW150-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 2020for 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 26,2017 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.

In connection with action by the FERC, OTP and EDFEDF-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 SeptemberJune 30, 2019,2020, OTP had capitalized approximately $54.8$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 MW simple-cycle natural gas-fired combustion turbine generation facility near Astoria, South Dakota as part of its plan to reliably meet customers’ electric needs, replace expiring capacity purchase agreements and prepare for the planned retirement of its Hoot Lake Plant in 2021. A final order granting an Advanced Determination of Prudence for Astoria Station was issued by the NDPSC on November 3, 2017, subject to certain qualifications and compliance obligations. On August 3, 2018 the SDPUC issued an order granting a site permit for Astoria Station. In a September 26, 2018 hearing the NDPSC established a GCR rider for future recovery of costs incurred for Astoria Station. On March 6, 2019 the SDPUC issued an order approving a settlement that allows a phase-in rider which includes recovery of Astoria Station costs. The interconnection agreement for Astoria Station was executed by MISO in December 2018 and accepted by the FERC in January 2019. Site preparation and excavation began in May 2019, and construction is occurring on the site. As of June 30, 2020, OTP had capitalized approximately $108.0 million in project costs and AFUDC associated with Merricourt.Astoria Station. OTP currently expects thethis project will cost approximately $258 million.be completed in late 2020 or early 2021.

 

15

Big Stone South–Ellendale Multi-Value Transmission Project (MVP)General Rates—This 345-kilovolt transmission line, energized on February 6, 2019, extends 162 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 from the MVP. OTP capitalized costs of approximately $106 million on this project, including 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 7.5056% and its allowed rate of return on equity (ROE) is 9.41%.

 

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

 

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

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

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

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

To ensure rates are appropriately set under the stipulation, the parties agreed to establish an earnings sharing mechanism to share with customers any weather-normalized earnings above the authorized ROE of 8.75%. OTP's annual weather-normalized earnings are reported each year by June 1 in its jurisdictional annual report, which will be used to determine the earnings level for purposes of calculating any refund. The earnings sharing mechanism requires that OTP will refund to customers 50% of any weather-normalized revenue that corresponds to the earnings in excess of its authorized ROE, up to a maximum of 9.50% ROE for a particular year. OTP will refund 100% of any earnings above 9.50% each year. In the event a refund is due under this provision, OTP will notify the SDPUC of the refund amount and plan for crediting customers within 30 days of filing its South Dakota jurisdictional annual report.

16

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. On October 24, 2019 the MPUC approved a $3.0 million financial incentive for 2018.

 

Transmission Cost Recovery RiderThe 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 in late 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.

not17

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 SeptemberJune 30, 20192020, which OTP is now seeking recovery of through its Minnesota TCR rider update request, is approximately $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.

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Table of Contents

Renewable Resource AdjustmentEffective 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 September 30,December 19, 2019 OTP filedthe 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 JulyOctober 31, 2019 OTP submittedthe MPUC approved the forecasted monthly fuel cost rates tosubmitted by OTP for 2020 and the MPUC for the twelve-month period beginningrates became effective on January 1, 2020.

On implementation of the new mechanism, OTP will be required to accrue a liability and likely refund amounts of fuel and purchased power and related costs per kwh collected in excess of forecasted amounts per kwh submitted to the MPUC for setting rates for the upcoming year. OTP will continue to accrue revenue and a regulatory asset for fuel and purchased power costs incurred in excess of amounts recovered, that it expects to recover under the adjustment mechanism, unless and until recovery of those excess amounts are deemed not prudent and recovery is not granted through the true-up mechanism in a subsequent order by the MPUC. This mechanism could result in reductions in Electric segment operating income margins, and could 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 Rates—On November 2, 2017 OTP filed a request with the NDPSC for a rate review and an effective increase in annual revenues from non-fuel base rates 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 does not require any rate base adjustments from OTP’s original request and establishes a GCR rider for future recovery of costs incurred for Astoria Station. The net revenue increase reflects a reduction in income tax recovery requirements related to the 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.

Renewable Resource AdjustmentOTP 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 inOn FebruaryDecember 31, 2019 with the implementation of general rates based on the results of OTP’s 2017 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 remained 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.

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Table of Contents

OTP filed its annual update to the North Dakota TCR rider on August 30, 2019 seekingRRA requesting approval for recovery of approximately $5.7 million with a proposed effective date of January 1, 2020. The filing included 7 new projects, updated costs associated with existing projects, details about the pending MISO ROE complaint,difference in PTCs in base rates and details about SPP related expenses.

Environmental Cost Recovery Rider—OTP has an ECR rider in North Dakota. The ECR rider has provided forthe actual PTCs generated, as well as a return on investment atMerricourt costs incurred while under construction. This update also included a credit for the level approvedremaining unrefunded credit balance in OTP’s preceding general rate case and for recovery of OTP’sthe North Dakota share of environmental investments and costsECR rider tracker on November 30, 2019. On February 25, 2020 OTP filed a revised request which was approved for recovery underby the rider. Prior to its 2017 general rate case reaching a final settlement and final rates going into effectNDPSC on February 1, 2019,March 18, 2020. OTP’s North Dakota jurisdictional sharePart of the revenue requirements associated with its investment inNDPSC’s approval included adopting a levelized utilization of PTCs from the Big Stone Plant AQCS and Hoot Lake Plant Mercury and Air Toxic Standards (MATS)Merricourt project over the expected 25-year life of the project for rate-making purposes. PTCs on prior projects were being recoveredpassed back to customers through the ECR rider. Effectivelower rates as they were generated over February 1, 2019 10these 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. On October 22, 2019 the NDPSC approved OTP’s request to decrease the ECR rate to zero effective November 1, 2019 and include the final tracker balance in OTP’s next annual update to its RRA, which is expected to be filed on December 31, 2019. 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 GCR rider went into effectStation, 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 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 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 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. 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 was applied to South Dakota customers’ October 2019 bills.

On July 9, 2019 the SDPUC approved a stipulation agreement OTP entered into 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 resulted 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. 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.

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Table of Contents

Transmission Cost Recovery 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.

OTP made a supplemental filing for the South Dakota TCR rider on September 5, 2019 to address the transmission rate base correction disclosed in the 2018 general rate case docket. On September 17, 2019 the SDPUC approved the supplemental filing and rates were effective October 1, 2019.

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 MATS 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. The ending balance of the South Dakota ECR rider at the conclusion of interim rates was refunded to South Dakota customers along with their October 2019 interim rate refunds.

 

Phase-In Rate Plan Rider—On May 31, 2019 OTP petitioned the SDPUC for approval of its initial rate for the Phase-In Rate Plan Rider 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 in OTP’s South Dakota jurisdiction,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.

OTP made a supplemental filing for the South Dakota Phase-In Rate Plan Rider on August 2, 2019. On August 21, 2019 the SDPUC approved theOTP’s supplemental filing andfor its South Dakota Phase-In Rate Plan Rider effective September 1, 2019. On June 1, 2020 OTP filed its first annual update request to the new rates wererider with a proposed effective asdate of September 1, 2019.2020.

 

18

Rate Rider Updates

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

Rate Rider

 

R - Request Date

A - Approval Date

Effective Date

Requested or
Approved

 

Annual
Revenue

($000s)

 

Rate

Minnesota

          

Conservation Improvement Program

          

2019 Incentive and Cost Recovery

 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

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Revenues Recorded under Rate Riders

 

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

 

  

Three Months Ended

September 30,

  

Nine Months Ended

September 30,

 

Rate Rider (in thousands)

 

2019

  

2018

  

2019

  

2018

 

Minnesota

                

Conservation Improvement Program Costs and Incentives

 $1,518  $1,488  $4,246  $4,300 

Renewable Resource Recovery

  1,316   817   3,949   2,001 

Transmission Cost Recovery

  (284)  (1,196)  301   (1,683)

Environmental Cost Recovery

  -   24   (1)  (25)

North Dakota

                

Transmission Cost Recovery

  908   1,922   3,554   5,149 

Renewable Resource Adjustment

  (20)  2,220   616   6,266 

Generation Cost Recovery

  137   -   607   - 

Environmental Cost Recovery

  (7)  1,823   556   5,474 

South Dakota

                

Transmission Cost Recovery

  743   496   1,587   1,282 

Conservation Improvement Program Costs and Incentives

  100   238   440   589 

Phase-In Rate Plan Recovery

  (10)  -   (10)  - 

Environmental Cost Recovery

  (2)  545   (29)  1,580 

Total

 $4,399  $8,377  $15,816  $24,933 

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Table of Contents

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

A –

October 24, 2019

December 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 – Revised

R –

September 30, 2019

November 1, 2019

 $12,506 $0.00467

/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

         

2019 Annual Update

R –

August 30, 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

2017 Annual Update

A –

November 29, 2017

January 1, 2018

 $7,959 

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

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

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

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 Recovery

         

2019 Initial Request

A –

August 21, 2019

September 1, 2019

 $864 3.345%

 of base

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Table of Contents

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. A one-time refund to Minnesota customers of $11.5 million in excess of amounts billed from January 2018 through May 2019 occurred in August and September 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 September 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 from the MVP.

 

ROEOnIn 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.tariff. OTP has deferred recognition and recorded a liability of $2.9 million as of June 30, 2020 as a result of the disputed ROE awaiting FERC action. The complainants soughtprovision 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 reducecustomers or reversed and recognized as revenue depending on various factors including MISO’s determination of refund amounts and FERC’s final determination of the 12.38% ROE used in MISO’s transmission rates to 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 thereasonableness of base ROE at 10.32%. Several parties requested rehearing of the September 2016 order and the requests are pending FERC action.over various periods.

 

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.

 

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20

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 million as of September 30, 2019.

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. OTP believes its estimated accrued MISO Tariff ROE refund liability of $1.6 million as of September 30, 2019 related to the second MISO Tariff ROE complaint is appropriate.

On March 1, 2019 the FERC issued a Notice of Inquiry (NOI) seeking comment on whether, and if so how, it should modify its policies concerning the determination of the ROE used in designing jurisdictional rates charged by public utilities. For years, the FERC has utilized a particular two-step, analysis to establish ROEs for utilities and natural gas interstate pipelines. The NOI sought comments on whether it should develop ROEs using a different financial model. The NOI also sought comments, among other things, on the continued use of RTO Adders. Based on initial and reply comments to the NOI, which were filed during the summer of 2019, the FERC could issue a Notice of Proposed Rulemaking outlining a proposed change.

23

 

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:

 

 

September 30, 2019

 

Remaining

Recovery/

  

June 30, 2020

 Remaining
Recovery/
 

(in thousands)

 

Current

 

Long-Term

 

Total

 

Refund Period

(months)

  

Current

 

Long-Term

 

Total

 

Refund Period
(months)

 

Regulatory Assets:

                  

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

 $6,355  $113,657  $120,012  

see below

  $9,018  $124,901  $133,919  

see below

 

Accumulated ARO Accretion/Depreciation Adjustment1

 -  7,571  7,571  

asset lives

 

Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment1

 -  8,243  8,243  

asset lives

 

Minnesota Transmission Cost Recovery Rider Accrued Revenues2

 6,563  -  6,563  12 

Conservation Improvement Program Costs and Incentives2

 243  5,339  5,582  24  276  3,553  3,829  27 

Minnesota Transmission Cost Recovery Rider Accrued Revenues2

 2,856  -  2,856  12 

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

 1,500  963  2,463  30 

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

 -  1,525  1,525  

asset lives

  -  1,974  1,974  

asset lives

 

Minnesota Renewable Resource Rider Accrued Revenues2

 722  -  722  12 

Debt Reacquisition Premiums1

 204  430  634  147 

Big Stone II Unrecovered Project Costs – Minnesota1

 583  -  583  10 

Minnesota SPP Transmission Cost Recovery Tracker1

 -  401  401  

see below

 

Deferred Marked-to-Market Losses1

 972  186  1,158  15  372  -  372  6 

Big Stone II Unrecovered Project Costs – Minnesota1

 706  409  1,115  19 

Debt Reacquisition Premiums1

 203  598  801  156 

MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1

 60  711  771  27 

Big Stone II Unrecovered Project Costs – South Dakota1

 144  180  324  27 

South Dakota Deferred Rate Case Expenses Subject to Recovery1

 418  -  418  12  138  177  315  28 

Big Stone II Unrecovered Project Costs – South Dakota1

 116  234  350  36 

North Dakota Generation Cost Recovery Rider Accrued Revenue2

 312  -  312  12 

North Dakota Deferred Rate Case Expenses Subject to Recovery1

 339  -  339  12  122  183  305  30 

Minnesota SPP Transmission Cost Recovery Tracker1

 -  270  270  

see below

 

South Dakota Transmission Cost Recovery Rider Accrued Revenues2

 193  -  193  5 

Recoverable Fuel and Purchased Power Costs – South Dakota1

 124  -  124  12 

North Dakota Generation Cost Recovery Rider Accrued Revenues2

 78  -  78  9 

Deferred Lease Expenses1

 -  51  51  42  -  58  58  33 

Minnesota Environmental Cost Recovery Rider Accrued Revenues2

 4  -  4  3  4  -  4  12 

Total Regulatory Assets

 $12,667  $130,551  $143,218     $19,958  $141,063  $161,021    

Regulatory Liabilities:

                  

Deferred Income Taxes

 $-  $141,337  $141,337  

asset lives

  $-  $138,517  $138,517  

asset lives

 

Accumulated Reserve for Estimated Removal Costs – Net of Salvage

 -  96,981  96,981  

asset lives

  -  99,055  99,055  

asset lives

 

Refundable Fuel Clause Adjustment Revenues – Minnesota

 3,836  -  3,836  3 

Refundable Fuel Clause Adjustment Revenues

 10,241  -  10,241  12 

North Dakota Transmission Cost Recovery Rider Accrued Refund

 1,010  -  1,010  6 

South Dakota Phase-In Rate Plan Rider Accrued Refund

 783  -  783  2 

Revenue for Rate Case Expenses Subject to Refund – Minnesota

 -  518  518  

see below

 

Prior Service Costs and Actuarial Gains on Postretirement Benefits

 471  -  471  12 

Minnesota Energy Intensive Trade Exposed Rider Accrued Refund

 198  -  198  3 

South Dakota Transmission Cost Recovery Rider Accrued Refund

 159  -  159  8 

North Dakota Renewable Resource Recovery Rider Accrued Refund

 684  -  684  8  156  -  156  9 

North Dakota Transmission Cost Recovery Rider Accrued Refund

 601  -  601  2 

North Dakota Environmental Cost Recovery Rider Accrued Refund

 537  -  537  2 

Revenue for Rate Case Expenses Subject to Refund – Minnesota

 -  342  342  

see below

 

Refundable Fuel Clause Adjustment Revenues – North Dakota

 305  -  305  12 

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

 140  47  187  15 

Minnesota Energy Intensive Trade Exposed Rider Accrued Refund

 151  -  151  12 

South Dakota Phase-In Rate Plan Rider Accrued Refund

 39  -  39  12 

Minnesota Renewable Resource Recovery Rider Accrued Refund

 12  -  12  12 

Other

 6  74  80  171  5  70  75  162 

Total Regulatory Liabilities

 $6,311  $238,781  $245,092     $13,023  $238,160  $251,183    

Net Regulatory Asset/(Liability) Position

 $6,356  $(108,230) $(101,874)    $6,935  $(97,097) $(90,162)   

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.

 

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21


  

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 

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

  -   986   986  

asset lives

 

Deferred Marked-to-Market Losses1

  1,661   743   2,404   24 

Big Stone II Unrecovered Project Costs – Minnesota1

  681   947   1,628   28 

Debt Reacquisition Premiums1

  207   753   960   165 

MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1

  240   -   240   12 

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 

Minnesota SPP Transmission Cost Recovery Tracker1

  -   176   176  

see below

 

Minnesota Environmental Cost Recovery Rider Accrued Revenues2

  121   -   121   12 

Deferred Income Taxes1

  -   2,423   2,423  

asset lives

 

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

 

Refundable Fuel Clause Adjustment Revenues

  121   -   121   12 

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 

Other

  5   108   113   180 

Total Regulatory Liabilities

 $738  $226,469  $227,207     

Net Regulatory Asset/(Liability) Position

 $16,487  $(91,212) $(74,725)    
 
  

December 31, 2019

    

(in thousands)

 

Current

  

Long-Term

  

Total

  

Remaining
Recovery/

Refund Period
(months)

 

Regulatory Assets:

               

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

 $9,090  $129,102  $138,192  

see below

 

Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment1

  -   7,772   7,772  

asset lives

 

Minnesota Transmission Cost Recovery Rider Accrued Revenues2

  4,208   -   4,208  12 

Conservation Improvement Program Costs and Incentives2

  4,024   2,844   6,868  21 

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

  2,033   968   3,001  24 

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

  -   1,681   1,681  

asset lives

 

Minnesota Renewable Resource Rider Accrued Revenues2

  131   -   131  12 

Debt Reacquisition Premiums1

  201   548   749  153 

Big Stone II Unrecovered Project Costs – Minnesota1

  715   225   940  16 

Minnesota SPP Transmission Cost Recovery Tracker1

  -   202   202  

see below

 

Deferred Marked-to-Market Losses1

  743   -   743  12 

Big Stone II Unrecovered Project Costs – South Dakota1

  144   253   397  33 

South Dakota Deferred Rate Case Expenses Subject to Recovery1

  138   245   383  34 

North Dakota Deferred Rate Case Expenses Subject to Recovery1

  122   244   366  36 

Deferred Lease Expenses1

  -   54   54  39 

Minnesota Environmental Cost Recovery Rider Accrued Revenues2

  4   -   4  12 

South Dakota Transmission Cost Recovery Rider Accrued Revenues2

  97   -   97  2 

Total Regulatory Assets

 $21,650  $144,138  $165,788    

Regulatory Liabilities:

               

Deferred Income Taxes

 $-  $141,707  $141,707  

asset lives

 

Accumulated Reserve for Estimated Removal Costs – Net of Salvage

  -   97,726   97,726  

asset lives

 

Refundable Fuel Clause Adjustment Revenues

  3,982   -   3,982  12 

North Dakota Transmission Cost Recovery Rider Accrued Refund

  700   -   700  12 

South Dakota Phase-In Rate Plan Rider Accrued Refund

  355   -   355  9 

Revenue for Rate Case Expenses Subject to Refund – Minnesota

  -   401   401  

see below

 

Prior Service Costs and Actuarial Gains on Postretirement Benefits

  471   -   471  12 

Minnesota Energy Intensive Trade Exposed Rider Accrued Refund

  164   -   164  12 

North Dakota Renewable Resource Recovery Rider Accrued Refund

  1,515   -   1,515  12 

North Dakota Generation Cost Recovery Rider Accrued Refund

  287   -   287  6 

Other

  6   72   78  168 

Total Regulatory Liabilities

 $7,480  $239,906  $247,386    

Net Regulatory Asset/(Liability) Position

 $14,170  $(95,768) $(81,598)   

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 were recoverable from Minnesota customers as of the balance sheet date.

 

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

25
22


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

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 – 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 Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 156 months.

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.

 

South Dakota Deferred Rate Case ExpensesThe 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 in conjunction with OTP’s most recent rate case in South Dakota andto serve Minnesota customers that were recoverable from Minnesota customers as of the balance sheet date.

Debt Reacquisition Premiums are currently being recovered beginning withfrom OTP customers over the establishmentremaining original lives of interim rates inthe reacquired debt issues, the longest of which is October 2018.147 months.

 

Big Stone II Unrecovered Project Costs – South DakotaMinnesota are the South DakotaMinnesota 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 most recent rate case in North Dakota currently being recovered beginning with the establishment of interim rates in January 2018.

 

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

 

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 customersAll Deferred Marked-to-Market Losses recorded as of the balance sheet date.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 North 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 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 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.

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.

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 were subject to recovery from other Minnesota customers as of the balance sheet date.

26

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 the balance sheet date.

 

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

 

The North Dakota 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

23

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

 

The NorthSouth Dakota Environmental Cost RecoveryPhase-In Rate Plan Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investments in the Big Stone Plant AQCSfor actual and Hoot Lake Plant MATS projectsforecasted costs for Astoria Station, Merricourt, and additional load growth that were refundable to NorthSouth Dakota customers as of the balance sheet date. 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 is being refunded to North Dakota ratepayers through the rider.

 

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

 

The 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.

The Minnesota Renewable Resource Recovery Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve Minnesota customers that were refundable to Minnesota 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 SouthNorth Dakota Environmental CostRenewable Resource Recovery Rider Accrued Refund relates to amounts collected on the Southfor qualifying renewable resource costs incurred to serve North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projectscustomers that were refundable to SouthNorth Dakota customers as of the balance sheet date.

 

27

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.

24

2020Common SharesStock Activity

Following is a reconciliation of the Company’s common shares outstanding from December 31, 20182019 through SeptemberJune 30, 2019:2020:

 

Common Shares Outstanding, December 31, 20182019

  39,664,88440,157,591 

Issuances:

    

At-the-Market Offering

500,684

Automatic Dividend Reinvestment and Share Purchase Plan:

Dividends Reinvested

63,929

Cash Invested

30,345

Executive Stock Performance Awards (2016 shares(2017 awards earned)

  102,19862,497 

Vesting of Restricted Stock Units

  27,12535,720

Employee Stock Purchase Plan:

Cash Invested

13,432

Dividends Reinvested

4,835 

Restricted Stock Issued to Directors

  15,70017,400 

Directors Deferred Compensation

  594612 

Retirements:

    

Shares Withheld for Individual Income Tax Requirements

  (55,22438,217)

Common Shares Outstanding, SeptemberJune 30, 20192020

  39,755,27740,848,828 

 

Earnings Per Share

The numerator used in the calculation of both basic and diluted earnings per common share is net income with no adjustments for the three- and ninesix-month periods ended SeptemberJune 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

September 30,

  

Nine Months ended

September 30,

 
  

2019

  

2018

  

2019

  

2018

 

Weighted Average Common Shares Outstanding – Basic

  39,714,672   39,621,524   39,694,677   39,592,705 

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

  149,023   206,268   147,106   210,691 

Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees

  68,138   58,680   63,902   58,475 

Nonvested Restricted Shares

  13,107   14,761   14,896   17,712 

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

  1,799   2,332   1,999   2,522 

Total Dilutive Shares

  232,067   282,041   227,903   289,400 

Weighted Average Common Shares Outstanding – Diluted

  39,946,739   39,903,565   39,922,580   39,882,105 

The effect of dilutive shares on earnings per sharereconciliation for the three- and ninesix-month periods ended September 30, 2019 June 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 

28
25


 

6. Share-Based Payments

 

Stock Incentive Awards

The following stock incentive awards were granted under the 2014 Stock Incentive Plan during the ninesix-month period months ended SeptemberJune 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.

 

29
26


Employee Stock Purchase Plan

In July 2019 the Company reinstituted a 15% employee discount under its Employee Stock Purchase Plan (ESPP). The ESPP allows employees, through payroll withholding, to purchase shares of the Company’s common stock at a 15% discount from the average market price on the last day of the six-month investment period. Under ASC Topic 718,Compensation–Stock Compensation (ASC 718), the Company is required to record compensation expense related to the 15% discount. The Company currently plans to issue common shares rather than purchase shares in the open market to meet the requirements of the ESPP.

As of SeptemberJune 30, 2019,2020, the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $4.3$4.8 million (before income taxes) which will be amortized over a weighted-average period of 2.12.3 years.

 

Amounts of compensation expense recognized under the Company’s stock-based payment programs for the three- and ninesix-month periods ended SeptemberJune 30, 20192020 and 20182019 are presented in the table below:

 

 

Three months ended

 

Six months ended

 
 

Three Months Ended

September 30,

 

Nine Months Ended

September 30,

  

June 30,

 

June 30,

 

(in thousands)

 

2019

 

2018

 

2019

 

2018

  

2020

 

2019

 

2020

 

2019

 

Stock Performance Awards Granted to Executive Officers

 $743  $718  $3,274  $2,037  $712  $1,418  $2,412  $2,531 

Restricted Stock Units Granted to Executive Officers

 189  174  999  596 

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

 203  165  572  496  236  204  440  369 

Restricted Stock Units Granted to Key Employees

 112  92  346  257 

Restricted Stock Units Granted to Nonexecutive Employees

 141  143  275  234 

ESPP (15% discount)

 54  -  54  -  42  -  95  - 

Totals

 $1,301  $1,149  $5,245  $3,402  $1,237  $2,148  $4,007  $3,944 

 

 

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 SeptemberJune 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 46.0%47.5% and 56.2%58.1% based on OTP’s 20192020 capital structure petition effective by order of the MPUC on July 19, 2019.15, 2020. As of SeptemberJune 30, 2019,2020, OTP’s equity-to-total-capitalization ratio including short-term debt was 52.2%52.9% and its net assets restricted from distribution totaled approximately $497$549 million. Under the 20192020 capital structure petition, OTP’s total capitalization for OTP cannot exceed $1,331,302,000.$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.interim reporting periods.

30

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 oneyear to approximately tenyears. 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 September 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

 $3,557  $19,967  $666  $769  $24,959 

Accumulated Amortization

  (778)  (1,836)  (294)  (98)  (3,006)

Net of Accumulated Amortization

 $2,779  $18,131  $372  $671  $21,953 

Obligations:

                    

Current Operating Lease Liabilities

 $985  $2,541  $326  $154  $4,006 

Long-Term Operating Lease Liabilities

  2,081   15,686   45   572   18,384 

Total Lease Liabilities

 $3,066  $18,227  $371  $726  $22,390 

The amounts of the Company’s right-of-use operating lease obligations as of September 30, 2019 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.

(in thousands)

 

Right-of-Use Operating Leases

 
  

OTP

  

Nonelectric

  

Total

 

2019

 $275  $1,029  $1,304 

2020

  1,115   3,883   4,998 

2021

  1,100   3,619   4,719 

2022

  206   3,491   3,697 

2023

  196   3,203   3,399 

Beyond 2023

  448   7,979   8,427 

Total Minimum Obligations

 $3,340  $23,204  $26,544 

Interest Component of Obligations

  (274)  (3,880)  (4,154)

Present Value of Minimum Obligations, September 30, 2019

 $3,066  $19,324  $22,390 

The weighted-average remaining lease term for the Company’s outstanding lease liabilities is 6.2 years and the weighted-average discount rate is 5.3%.

31

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 September 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

  177   5,115   5,292 

Lease Modifications

  -   (164)  (164)

Lease Obligation Payments

  (845)  (3,086)  (3,931)

Interest Component of Lease Obligation Payment

  125   699   824 

Operating Lease Obligations, September 30, 2019

 $3,066  $19,324  $22,390 

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 nine-month periods ending September 30, 2019 is presented in the following table.

  

Three Months Ended September 30, 2019

  

Nine Months Ended September 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

 $9  $-  $9  $29  $-  $29 

Inventory

  244   -   244   707   -   707 

Cost of Products Sold

  963   65   1,028   2,942   137   3,079 

Electric Operation and Maintenance Expenses

  64   -   64   194   -   194 

Other Nonelectric Expenses

  51   (1)  50   156   -   156 

Total

 $1,331  $64  $1,395  $4,028  $137  $4,165 

 

 

9. Commitments and Contingencies

 

Construction and Other Purchase Commitments

At SeptemberJune 30, 2020 OTP had commitments under contracts, including its share of construction program commitments and other commitments, extending into 2022 of approximately $185 million. At December 31, 2019 OTP had commitments under contracts, including its share of construction program commitments and other nonlease commitments, extending into 2021 of approximately $138.9$317 million. At December 31, 2018 OTP had commitments under contracts, including its share of construction program commitments and other nonlease commitments, extending into 2021 of approximately $64.5 million. The increase in commitments is mainly due to a $77.5 million increase in commitments and contractual obligations in 2019 associated with the construction of OTP’s Astoria Station natural gas-fired combustion turbine in eastern South Dakota. Spending commitments increased $70.3 million for 2020 and $9.7 million for 2021. Total 2019 unmet project commitments decreased $5.7 million in 2019 with initiation of construction activities.    

 

At December 31, 2018 T.O. Plastics had commitments for the purchase of resin through December 31, 2021 of approximately $5.0 million under a long-term supply agreement. On October 1, 2019 this resin supply agreement was replaced withT.O. Plastics entered into a new six-year resin supply agreement that commencescommenced 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 delivered under the supply agreement will not exceed its requirements over the six-year term of the supply agreement or exceed the market cost of alternative sources of the resin. T.O. Plastics estimates it will pay the supplier approximately $1.6$1.9 million annually under this agreement.

 

32
27

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.exclusively from Peabody. OTP has an all-requirements agreement with Navajo Transitional Energy Co. (NTEC) 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. In October 2019, NTEC purchased the assets of Cloud Peak Energy Resources LLC, including its Spring Creek Mine in southeast Montana, through bankruptcy court. For a two-day period in October, operations at the Spring Creek Mine were suspended due to a disagreement between the Montana Department of Environmental Quality and the NTEC. Subsequent to the suspension of operations, the two parties agreed to allow the mine to operate for an additional seventy-five days while they work to resolve differences regarding the NTEC’s waiver of sovereign immunity from the state’s environmental laws.requirement.

 

OTP Land Easements

OTP has commitments to make future payments for land easements not classified as leases, extending into 2034 of approximately $10.4$9.9 million.

 

Contingencies

OTP had a $1.6$2.9 million refund liability on its balance sheet as of SeptemberJune 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.

 

InOn 2015July 30, 2020 the MPUC ordered a reduction in the remaining depreciable lives of OTP’s Hoot Lake Plant and seven the Environmental Protection Agency (EPA), acting under Section 111(d)hydroelectric plants. The MPUC stipulated recoverability of the Clean Air Act, issuedresulting 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 Clean Power Plan which required states to submit plans to limit carbon dioxide emissions from certain fossil fuel-fired power plants. The rulerelevant facts and circumstances, OTP has concluded the additional depreciation expense is not currentlyprobable of recovery and will recognize a regulatory asset for the amount of incremental expense recognized 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. 2020.

 

On August 21, 2018 the EPA proposed a replacement for the Clean Power Plan -- the Affordable Clean Energy (ACE) Rule. The final versionState implementation of the ACE Rule, which went into effect on September 6, 2019, establishes guidelines for states to use in developingpollution control plans to address greenhouse gas emissionsimprove visibility and air quality at national parks under the EPA’s Regional Haze Rule (RHR) could require OTP to incur significant new costs, which could, dependent on determinations by state regulatory commissions on approval to recover such costs from existing coal-fired power plantscustomers, negatively impact OTP’s and was finalized in conjunction with two related but separatethe Company’s net income, financial position and distinct rulemakings, which include repealing the Clean Power Plan and providing revisions to state implementation plan guidance.cash flows. The ACE Rule establishes heat rate improvements, or efficiency improvements, as the best systemNorth Dakota Department of emissions reduction for carbon dioxide 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 does not include any final action regarding New Source Review. States have until mid-2022 toEnvironmental Quality (NDDEQ) must submit a state implementation plan to the EPA by July 2021. While this process is still in the early stages, if the NDDEQ and/or the EPA requires sources subject to RHR Round 2 reasonable progress determinations, including Coyote Station, to undertake emissions control measures that are reasonably consistent with those required of sources during Round 1, OTP anticipates that significant emissions controls would be required at Coyote Station by December 31, 2028. In light of the costs for approval.emissions control equipment, there are scenarios where it may not be economically feasible to invest in such equipment and an early retirement of the Coyote Station would therefore be necessary. The costs related to an early retirement of Coyote Station would be material to OTP and the Company and would be subject to state commission approval for recovery from customers.

 

Other

The Company is a party to litigation and regulatory enforcement matters arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of SeptemberJune 30, 2019,2020, includingother than those described above,relating to the RHR, will not be material.

 

33
28

 

10. Short-Term and Long-Term Borrowings

 

The following table presents the status of the Company’s lines of credit as of SeptemberJune 30, 20192020 and December 31, 2018:2019:

 

(in thousands)

 

Line Limit

 

In Use on

September 30,

2019

 

Restricted due to

Outstanding

Letters of Credit

 

Available on

September 30,

2019

 

Available on

December 31,

2018

  

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

 $130,000  $35,837  $-  $94,163  $120,785  $170,000  $41,239  $-  $128,761  $164,000 

OTP Credit Agreement

 170,000  73,160  16,561  80,279  160,316  170,000  -  7,670  162,330  154,524 

Total

 $300,000  $108,997  $16,561  $174,442  $281,101  $340,000  $41,239  $7,670  $291,091  $318,524 

 

On October 31, 2019 both credit agreements were amended to extend the expiration dates by one year from October 31, 2023 to October 31, 2024 and the line limit on the Otter Tail Corporation Credit Agreement was increased to $170 million. The amendments to the credit agreements are listed as Exhibits 4.2 and 4.3 to this report on Form 10-Q and are incorporated herein by reference.

The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of September 30, 2019 and December 31, 2018:

September 30, 2019 (in thousands)

 

OTP

  

Otter Tail

Corporation

  

Otter Tail

Corporation

Consolidated

 

Short-Term Debt

 $73,160  $35,837  $108,997 

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

      394   394 

Total

 $512,000  $80,394  $592,394 

Less: Current Maturities net of Unamortized Debt Issuance Costs

  -   180   180 

Unamortized Long-Term Debt Issuance Costs

  1,830   369   2,199 

Total Long-Term Debt net of Unamortized Debt Issuance Costs

 $510,170  $79,845  $590,015 

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

 $583,330  $115,862  $699,192 

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 

34

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);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, (thethe Notes).

 

On October 10, 2019,February 25, 2020, OTP issued the Series 2019A Notes, Series 2019B Notes and Series 2019C Notes (the 2019 Notes) pursuant to the 2019 Note Purchase Agreement. OTP used a portion of the $100 million proceeds from the issuance to repay $69.9 million of existing indebtedness under the OTP Credit Agreement, primarily incurred to fund OTP capital expenditures, and intends to use the remainder of the proceeds to pay for additional capital expenditures and for OTP’s general corporate purposes. The Series 2020A Notes, the Series 2020C Notes and the Series 2020D Notes are expectedpursuant to bethe 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 February 25, 2020,October 10, 2019. andThe remaining unissued notes of the 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.

 

OTP may prepay all or any part of the 2019Notes (in an amount not less than 10% of the aggregate principal amount of the2019 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 2019A2020A Notes then outstanding on or after April 10, August 25,2029, (b) (b) Series 2019B2020C Notes then outstanding on or after April 10,August 25, 2039 or (c) Series 2019C2020D Notes then outstanding on or after AprilAugust 25, 2049 10,2049will 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

201929 Note Purchase Agreement is listed as Exhibit 4.1 to this report on Form 10-Q and is incorporated herein by reference.


35

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, 2020 and December 31, 2019:

 

June 30, 2020 (in thousands)

 

OTP

  

Otter Tail
Corporation

  

Consolidated

 

Short-Term Debt

 $-  $41,239  $41,239 

Long-Term Debt:

            

3.55% Guaranteed Senior Notes, due December 15, 2026

     $80,000  $80,000 

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

 $140,000       140,000 

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

  30,000       30,000 

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

  42,000       42,000 

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

  60,000       60,000 

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

  10,000       10,000 

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

  10,000       10,000 

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

  50,000       50,000 

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

  26,000       26,000 

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

  10,000       10,000 

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

  90,000       90,000 

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

  100,000       100,000 

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

  64,000       64,000 

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

  15,000       15,000 

PACE Note, 2.54%, due March 18, 2021

      261   261 

Total

 $647,000  $80,261  $727,261 

Less: Current Maturities net of Unamortized Debt Issuance Costs

  -   261   261 

Unamortized Long-Term Debt Issuance Costs

  2,281   330   2,611 

Total Long-Term Debt net of Unamortized Debt Issuance Costs

 $644,719  $79,670  $724,389 

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

 $644,719  $121,170  $765,889 

December 31, 2019 (in thousands)

 

Short-Term Debt

 $-  $6,000  $6,000 

Long-Term Debt:

            

3.55% Guaranteed Senior Notes, due December 15, 2026

     $80,000  $80,000 

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

 $140,000       140,000 

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

  30,000       30,000 

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

  42,000       42,000 

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

  60,000       60,000 

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

  10,000       10,000 

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

  50,000       50,000 

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

  26,000       26,000 

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

  90,000       90,000 

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

  100,000       100,000 

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

  64,000       64,000 

PACE Note, 2.54%, due March 18, 2021

      351   351 

Total

 $612,000  $80,351  $692,351 

Less: Current Maturities net of Unamortized Debt Issuance Costs

  -   183   183 

Unamortized Long-Term Debt Issuance Costs

  2,231   356   2,587 

Total Long-Term Debt net of Unamortized Debt Issuance Costs

 $609,769  $79,812  $689,581 

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

 $609,769  $85,995  $695,764 

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


30

 

11. Pension Plan and Other Postretirement Benefits

 

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

 

 

Three Months Ended

September 30,

 

Nine Months Ended

September 30,

  

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  $4,119  $4,845  $1,656  $1,373  $3,311  $2,746 

Interest Cost on Projected Benefit Obligation

 3,603  3,363  10,809  10,089  3,263  3,603  6,526  7,206 

Expected Return on Assets

 (5,324) (5,300) (15,973) (15,899) (5,505) (5,324) (11,010) (10,649)

Amortization of Prior-Service Cost:

                  

From Regulatory Asset

 1  4  4  12  -  2  -  3 

From Other Comprehensive Income1

 2  -  6  -  -  2  -  4 

Amortization of Net Actuarial Loss:

                  

From Regulatory Asset

 1,163  1,784  3,488  5,351  2,231  1,162  4,462  2,325 

From Other Comprehensive Income1

 26  46  79  137  55  26  110  53 

Net Periodic Pension Cost2

 $844  $1,512  $2,532  $4,535  $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

 $333  $455  $1,059  $1,162 

2Allocation of costs:

                

Service costs included in OTP capital expenditures

 $432  $336  $855  $726 

Service costs included in electric operation and maintenance expenses

  1,007   1,119   2,961   3,561   1,185   1,004   2,377   1,954 

Service costs included in other nonelectric expenses

  33   41   99   121   39   33   79   66 

Nonservice costs capitalized as regulatory assets

  (128)  (29)  (408)  (74)  12   (130)  23   (280)

Nonservice costs included in nonservice cost components of postretirement benefits

  (401)  (74)  (1,179)  (235)  32   (399)  65   (778)

 

Cash flows—The Company had no minimum funding requirement as of December 31, 20182019 but made a discretionary plan contributionscontribution of $10$11.2 million in January 2019 and $12.5 million in September 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

September 30,

 

Nine Months Ended

September 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  $313  $300  $44  $104  $89  $209 

Interest Cost on Projected Benefit Obligation

 433  399  1,301  1,197  362  434  724  868 

Amortization of Prior-Service Cost:

         

Amortization of Prior Service Cost:

         

From Regulatory Asset

 2  4  4  12  -  1  -  2 

From Other Comprehensive Income1

 4  10  12  29  -  4  -  8 

Amortization of Net Actuarial Loss:

                  

From Regulatory Asset

 31  66  93  200  24  31  47  62 

From Other Comprehensive Income1

 87  166  262  496  85  88  171  175 

Net Periodic Pension Cost2

 $661  $745  $1,985  $2,234  $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  $24  $78  $74  $-  $26  $-  $52 

Service costs included in other nonelectric expenses

  78   76   235   226   44   78   89   157 

Nonservice costs included in nonservice cost components of postretirement benefits

  557   645   1,672   1,934   471   558   942   1,115 

 

36
31


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

 

  

Three Months Ended

September 30,

  

Nine Months Ended

September 30,

 

(in thousands)

 

2019

  

2018

  

2019

  

2018

 

Service Cost—Benefit Earned During the Period

 $321  $382  $964  $1,145 

Interest Cost on Projected Benefit Obligation

  770   646   2,312   1,937 

Amortization of Net Actuarial Loss:

                

From Regulatory Asset

  393   412   1,178   1,236 

From Other Comprehensive Income1

  10   11   29   32 

Net Periodic Postretirement Benefit Cost2

 $1,494  $1,451  $4,483  $4,350 

Effect of Medicare Part D Subsidy

 $(45) $(37) $(134) $(110)

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

                

2Allocation of Costs:

                

Costs included in OTP capital expenditures

 $78  $108  $248  $275 

Service costs included in electric operation and maintenance expenses

  235   264   693   841 

Service costs included in other nonelectric expenses

  8   10   23   29 

Nonservice costs capitalized as regulatory assets

  284   301   905   769 

Nonservice costs included in nonservice cost components of postretirement benefits

  889   768   2,614   2,436 

  

Three Months Ended June 30,

  

Six Months Ended June 30,

 

(in thousands)

 

2020

  

2019

  

2020

  

2019

 

Service Cost—Benefit Earned During the Period

 $462  $322  $924  $643 

Interest Cost on Projected Benefit Obligation

  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

  1,052   392   2,103   785 

From Other Comprehensive Income1

  26   9   52   19 

Net Periodic Postretirement Benefit Cost2

 $940  $1,495  $1,879  $2,989 

Effect of Medicare Part D Subsidy

 $280  $(44) $561  $(89)

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

                

2Allocation of Costs:

                

Service costs included in OTP capital expenditures

 $120  $79  $238  $170 

Service costs included in electric operation and maintenance expenses

  331   235   664   458 

Service costs included in other nonelectric expenses

  11   8   22   15 

Nonservice costs capitalized as regulatory assets

  124   288   246   621 

Nonservice costs included in nonservice cost components of postretirement benefits

  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 SeptemberJune 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.

 

  

September 30, 2019

  

December 31, 2018

 

(in thousands)

 

Carrying

Amount

  

Fair Value

  

Carrying

Amount

  

Fair Value

 

Cash and Cash Equivalents

 $921  $921  $861  $861 

Short-Term Debt

  (108,997)  (108,997)  (18,599)  (18,599)

Long-Term Debt including Current Maturities

  (590,195)  (663,761)  (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.

 

37
32


 

14. Income Tax Expense

 

The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income before income taxes and income tax expense reported on the Company’s consolidated statements of income for the three- and ninesix-month periods ended SeptemberJune 30, 20192020 and 2018:2019:

 

 

Three Months Ended

September 30,

 

Nine Months Ended

September 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

 $29,681  $30,632  $80,402  $82,391  $20,789  $18,769  $50,695  $50,721 

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

 $7,717  $7,964  $20,905  $21,422 

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

 (933) (838) (2,690) (2,932) (543) (774) (1,772) (1,757)

Research and Development Tax Credits

 (612) (202) (987) (562)

Allowance for Funds Used During Construction – Equity

 (248) (94) (560) (180)

Excess Tax Deduction – Equity Method Stock Awards

 -  (73) (827) (698) -  -  (535) (827)

North Dakota Wind Tax Credit Amortization – Net of Federal Taxes

 (258) (258) (774) (774) (258) (258) (516) (516)

Reconciliation and Prior Period Adjustments

 (688) 2,109  (722) 2,028 

Research and Development and Other Tax Credits

 (333) (187) (387) (375)

Corporate Owned Life Insurance

 (50) (332) (609) (360) (193) (150) 14  (559)

Allowance for Funds Used During Construction – Equity

 (239) (138) (419) (416)

Federal Production Tax Credits

 -  (707) -  (2,757)

Other Comprehensive Income Deferred Tax Rate Adjustment

 -  -  -  (531)

Other Items – Net

 (1) (166) 30  (213) (22) (73) 21  (2)

Income Tax Expense

 $4,936  $7,359  $13,907  $14,207  $3,808  $3,343  $9,446  $8,971 

Effective Income Tax Rate

 16.6% 24.0% 17.3% 17.2% 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 

Increases Related to Tax Positions for Prior Years

 37  6 

Decreases Related to Tax Positions for Prior Years

 (42) - 

Increases Related to Tax Positions for Current Year

 153  113  81  75 

Uncertain Positions Resolved During Year

 (170) (186) -  (42)

Balance on September 30

 $1,302  $617 

Balance on June 30

 $1,527  $1,315 

 

The balance of unrecognized tax benefits as of SeptemberJune 30, 20192020 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of SeptemberJune 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 0 amount accrued for interest on tax uncertainties as of September 30, 2019.

 

The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of September 30, 2019,August 1, 2020, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2016 for federal, Minnesota and North Dakota income taxes and prior to 2015 for Minnesota income taxes.

 

38
33

 

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.

34

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 ninesix months ended SeptemberJune 30, 20192020 and 20182019 followed by a discussion of changes in our consolidated financial position during the ninesix months ended SeptemberJune 30, 20192020 and our business outlook for the remainder of 2019.2020.

 

Comparison of the Three Months Ended SeptemberJune 30, 20192020 and 20182019

 

Consolidated operating revenues were $228.7$192.8 million for the three months ended SeptemberJune 30, 20192020 compared with
$227.7
$229.2 million for the three months ended SeptemberJune 30, 2018.2019. Operating income was $37.3$27.9 million for the three months ended SeptemberJune 30, 20192020 compared with $38.3$26.8 million for the three months ended SeptemberJune 30, 2018.2019. The Company recorded diluted earnings per share of $0.62$0.42 for the three months ended SeptemberJune 30, 20192020 compared with $0.58$0.39 for the three months ended SeptemberJune 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 SeptemberJune 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)

 

Three Months Ended

September 30, 2019

 

Three Months Ended

September 30, 2018

  

June 30, 2020

 

June 30, 2019

 

Operating Revenues:

          

Electric

 $9  $10  $23  $14 

Nonelectric

 1  (1)

Costs of Products Sold

 5  4  2  3 

Other Nonelectric Expenses

 4  6  22  10 

 

Electric

 

  

Three Months Ended

         
  

September 30,

      

%

 

(in thousands)

 

2019

  

2018

  

Change

  

Change

 

Retail Sales Revenues from Contracts with Customers

 $100,345  $88,750  $11,595   13.1 

Changes in Accrued Revenues under Alternative Revenue Programs

  (921)  (317)  (604)  (190.5)

Total Retail Sales Revenues

 $99,424  $88,433  $10,991   12.4 

Transmission Services Revenues

  11,692   12,569   (877)  (7.0)

Wholesale Revenues – Company Generation

  1,631   2,826   (1,195)  (42.3)

Other Revenues

  1,626   1,614   12   0.7 

Total Operating Revenues

 $114,373  $105,442  $8,931   8.5 

Production Fuel

  18,331   17,129   1,202   7.0 

Purchased Power – System Use

  13,163   9,664   3,499   36.2 

Electric Operation and Maintenance Expenses

  35,869   33,897   1,972   5.8 

Depreciation and Amortization

  15,198   14,023   1,175   8.4 

Property Taxes

  3,965   4,094   (129)  (3.2)

Operating Income

 $27,847  $26,635  $1,212   4.6 

Electric Megawatt-hour (mwh) Sales

                

Retail mwh Sales

  1,091,427   1,079,622   11,805   1.1 

Wholesale mwh Sales – Company Generation

  71,506   93,790   (22,284)  (23.8)

Heating Degree Days

  42   107   (65)  (60.7)

Cooling Degree Days

  288   339   (51)  (15.0)

39

  

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 September 30,

 
  

2019

  

2018

 

Heating Degree Days

  76.4%  209.8%

Cooling Degree Days

  83.0%  95.8%
  

Three Months ended June 30,

 
  

2020

  

2019

 

HDDs

  122.1%  112.6%

CDDs

  156.0%  95.4%

35

 

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 thirdsecond quarters of 20192020 and 20182019 and between quarters:

 

  

2019 vs Normal

  

2018 vs Normal

  

2019 vs 2018

 

Effect on Diluted Earnings Per Share

 $(0.02) $0.00  $(0.02)
  

2020 vs Normal

  

2019 vs Normal

  

2020 vs 2019

 

Effect on Diluted Earnings Per Share

 $0.03  $0.01  $0.02 

 

The $11.0$2.8 million increasedecrease in retail sales revenue includes:

 

 

A $5.8$4.2 million increasedecrease in retail revenue related to the recovery of increasesdecreased fuel and purchased power costs incurred to serve retail customers. Decreased commercial and industrial demand related to COVID-19 contributed to the 5.1% decrease in retail kwh sales and a $5.2 million decrease in fuel and purchased-powerpurchased power costs explained below.to serve retail customers.

 

 

A $2.8$2.7 million increasedecrease in average electric prices, mainly relatedrevenue due to interim and final rate increases in South Dakota and to increaseddecreased kwh sales to commercial and industrial customers, exclusive of the decrease in higher rate classifications.fuel cost recovery revenues, mainly due to COVID-19-related impacts in the second quarter of 2020.

 

 

A $1.7$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 transmission cost recoveryMinnesota and North Dakota renewable rider revenues duerelated to recent investmentsearning a return on funds invested in transmission infrastructure and transmission costs not currently recovered in base rates.the Merricourt Wind Energy Center (Merricourt) while the project is under construction.

 

 

A $1.2$1.3 million increase in retail revenuerevenues related to increased consumption due to increased kwh sales, primarily to commercial customers, exclusive of the weather-related decrease in retail kwh sales.favorable quarter over quarter weather impacts.

 

 

A $0.5$0.7 million increase in Minnesota Renewable Rider revenues due to increased cost recovery requirements resulting from the expirationNorth 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 federal Production Tax Credits (PTCs) in November 2018electricity to residential customers exclusive of the impact of weather on a company-owned wind farm.sales.

 

Transmission services revenue decreased $1.8 million mainly due to lower tariffs and decreased transmission volume resulting from lower electrical demand partially attributable to the impact of COVID-19.

The $0.7 million increase in other revenue includes $1.0 million from a commercial customer in the second quarter of 2020, partially offset by:by a $0.3 million decrease in revenue from steam sales to an ethanol producer due to Big Stone Plant being on economic dispatch and not producing steam at certain times during the second quarter of 2020.

Production fuel costs increased $0.5 million despite an 11.7% decrease in kwhs generated from our fuel-burning plants, mainly as a result of a 20.0% increase in fuel-cost per kwh of generation, weighted heavily by higher fuel costs per kwh of generation at Coyote Station in the second quarter of 2020. Coyote Station was down for maintenance in the second quarter of 2019.

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

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

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

A $1.1 million decrease in labor and benefit expenses.

 

 

A $1.0 million decrease in retail revenuestransmission tariff expenses related to decreased consumption due to cooler weather in the third quarter of 2019 compared with the third quarter of 2018 reflected in a 15.0% decrease in cooling degree days between quarters.kwh purchases and decreased transmission tariff rates.

Transmission services revenues decreased $0.9 million due to a decrease in Midcontinent Independent System Operator, Inc. (MISO) tariff revenues associated with offsets received from independent generators to pay for transmission system upgrades made by Otter Tail Power Company (OTP) to facilitate the generators’ access to the electric grid.

Wholesale electric revenues decreased $1.2 million as cooler summer weather in the region resulted in decreased demand and lower prices for wholesale electricity. Wholesale prices per kwh sold were down 24.3%, making it uneconomical to generate and sell electricity from OTP’s Hoot Lake Plant when the incremental cost of generation exceeded wholesale prices.

Production fuel costs increased $1.2 million as a result of a 29.4% increase in the cost per kwh generated from our fuel-burning plants. The increased cost per kwh generated is mostly due to the absorption of Coyote Creek Mining Company’s (CCMC’s) fixed coal mining costs in Coyote Station’s fuel inventory while no coal was being delivered to Coyote Station during its spring 2019 maintenance outage. The increased cost per kwh generated was partially offset by a 17.3% reduction in kwhs generated at all of OTP’s fuel-burning plants.

The cost of purchased power to serve retail customers increased $3.5 million (36.2%) due to a 105% increase in kwhs purchased as a result of reduced generation at both Hoot Lake Plant and Coyote Station. Hoot Lake Plant Unit 2 was offline for maintenance and repairs in July 2019. Hoot Lake Plant was also curtailed in August and September 2019 due to economic dispatch as market prices for electricity had declined below Hoot Lake Plant’s incremental generating cost. Coyote Station generated fewer kwhs in July 2019 compared with July 2018 as it came back online in July 2019 after its extended maintenance outage. The price per kwh of purchased power decreased 33.5% in the third quarter of 2019 compared with the third quarter of 2018 due to a decrease in regional market prices for electricity driven by decreased demand due to cooler summer weather resulting in decreased air conditioning load in the Northern Plains region of the United States.

40

Electric operating and maintenance expense increased $2.0 million including:

 

 

A $2.7$0.9 million increasedecrease in expense related to the establishment of a $2.7 million regulatory assetvegetation maintenance expenses and credit to operating expense for deferred recovery of an income tax adjustment in the third quarter of 2018 related to 2017 Tax Cuts and Jobs Act (TCJA) guidance issued in that quarter. There was no similar expense reduction recorded in the third quarter of 2019. The income tax adjustment resulted from the August 2018 Internal Revenue Service (IRS) guidance clarifying changes related to the treatment of bonus depreciation rules for 2017, which affected 2017 deductions and corresponding reversals of excess deferred taxes in 2018. The adjustments related to the guidance resulted in a $2.7 million increase in income tax expense in the third quarter of 2018, which is subject to recovery through future rate adjustments.conservation improvement program expenditures.

 

 

A $0.6 million increasedecrease in materials and supplies and contracted services expenses at Hoot Lake Plant external services costs related to Unit 2second quarter 2019 turbine repairs in the third quarter of 2019.

A $0.4 million increase in line clearance costs.repairs.

 

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

A $1.0 million decrease in external services costs at Big Stone Plant mainly related to costs incurred during the plant’s 2018 maintenance outage.

A $0.7 million decrease in labor-related benefit expenses.

 

Depreciation and amortization expense increased $1.2$0.7 million mainly due to 20182019 capital additions for generation and transmission plant.

36

 

Manufacturing

 

 

Three Months Ended

      

Three Months Ended

     
 

September 30,

   

%

  

June 30,

   

%

 

(in thousands)

 

2019

 

2018

 

Change

 

Change

  

2020

 

2019

 

Change

 

Change

 

Operating Revenues

 $65,722  $67,027  $(1,305) (1.9) $45,948  $73,496  $(27,548) (37.5)

Cost of Products Sold

 51,399  51,143  256  0.5  36,087  56,364  (20,277) (36.0)

Operating Expenses

 6,846  7,842  (996) (12.7) 5,499  7,954  (2,455) (30.9)

Depreciation and Amortization

 3,505  3,716  (211) (5.7) 3,739  3,419  320  9.4 

Operating Income

 $3,972  $4,326  $(354) (8.2) $623  $5,759  $(5,136) (89.2)

 

The $1.3$27.5 million decrease in revenues in our Manufacturing segment includes the following:

 

 

Revenues at BTD Manufacturing, Inc. (BTD) decreased $0.6$26.0 million. Parts revenue was down $19.8 million related to decreased sales volumes to all end market customer categories served by BTD, in order of magnitude: recreational vehicle, construction, lawn and garden, agricultural, industrial and energy equipment end markets, as customers implemented temporary plant shutdowns due to:

o

A $3.7to the COVID-19 pandemic. Lower prices related to the pass through of lower material costs accounted for a $5.9 million increase in revenue from an increasedecrease in parts sales volume, including increased sales to manufacturers of recreational vehiclesrevenue, partially offset by $0.5 million in price increases exclusive of the pass through of material cost reductions. Scrap revenue decreased sales in energy and agricultural end markets.

o

A $0.7$0.8 million increase in tooling revenues.

more than offset by:

o

A $3.8 million decrease in revenue primarily from lower material price changes passed through to customers.

o

A $1.0 million reduction in revenues from scrap metal sales due to a 33.5%46.8% decrease in scrap volume and a 5.1% decrease in scrap metal prices and a 12.6% decrease in scrap volume.

o

A $0.2 million decrease in other revenues.prices.

 

 

Revenues at T.O. Plastics, Inc. (T.O. Plastics), our manufacturer of thermoformed plastic and horticultural products, decreased $0.7$1.5 million primarily due to a $0.6decreases of $0.9 million decrease in sales of horticultural products, mostlycontainers, $0.3 million in industrial sales and $0.2 million in life sciences product sales. The decreased sales level was mainly due to a $0.4 million shift inmarket softness generated by the timinguncertainty of saleshow COVID-19 was going to the second quarter of 2019 that historically have occurred in the third quarter.impact these end markets.

 

The $0.3$20.3 million increasedecrease in cost of products sold in our Manufacturing segment includes the following:

 

 

Cost of products sold at BTD increased $0.5decreased $19.5 million mainly as a result of increasedboth the decreased sales volume and the $5.9 million in lower material costs on higher sales volume.passed through to customers.

 

 

Cost of products sold at T.O. Plastics decreased $0.2$0.8 million duerelated to the decrease in sales volume.

 

41

The $1.0$2.5 million decrease in operating expenses in our Manufacturing segment is mainly due toincludes a $1.4$2.3 million reductiondecrease in accrued short-term incentive costs between quarters at BTD, partially offset by increases of $0.3 million in other operating expenses at BTD.BTD related to initiatives taken at BTD to mitigate the negative impacts on sales related to COVID-19, mainly reductions in salaries, incentives and benefits, travel and outside services expenditures. Operating expenses at T.O. Plastics increased $0.1 million between the quarters.

Depreciation and amortization expense at BTD decreased $0.2 million, mainly due to decreases in salaries and incentives.

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

We estimate COVID-19 issues at BTD negatively impacted our second quarter earnings by approximately $0.08 per share. This relates to reduced sales, as 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

     
 

September 30,

   

%

  

June 30,

   

%

 

(in thousands)

 

2019

 

2018

 

Change

 

Change

  

2020

 

2019

 

Change

 

Change

 

Operating Revenues

 $48,566  $55,203  $(6,637) (12.0) $48,679  $53,476  $(4,797) (9.0)

Cost of Products Sold

 37,353  42,222  (4,869) (11.5) 37,747  41,635  (3,888) (9.3)

Operating Expenses

 2,872  3,260  (388) (11.9) 2,970  2,949  21  0.7 

Depreciation and Amortization

 865  907  (42) (4.6) 872  861  11  1.3 

Operating Income

 $7,476  $8,814  $(1,338) (15.2) $7,090  $8,031  $(941) (11.7)

 

Plastics segment revenues and operating income decreased $6.6$4.8 million and $1.3$0.9 million, respectively, due to an 8.9%a 5.8% decrease in pounds of polyvinyl chloride (PVC) pipe sold andin combination with a 3.5%3.3% decrease in PVC pipe prices. The quarter-over-quarter decrease in

37

sales volume decrease relatesis attributed to lower demand for producta drop in sales to distributors who reduced inventory levels due to uncertainty over the impact of COVID-19 on sales and expectations of PVC pipe prices decreasing in light of declining resin prices in the Midwest and West Coast states.second quarter of 2020. Cost of products sold decreased $4.9$3.9 million due to the reduceddecrease in sales volume and a 2.9%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 5.2%2.0% decrease in gross margin per pound of PVC pipe sold. Plastics segment operating expenses decreased $0.4 million between the quarters mainly due to lower sales commissions and incentive compensation resulting from decreases in sales volume and 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

     
 

September 30,

   

%

  

June 30,

   

%

 

(in thousands)

 

2019

 

2018

 

Change

 

Change

  

2020

 

2019

 

Change

 

Change

 

Operating Expenses

 $1,951  $1,451  $500  34.5  $2,315  $2,369  $(54) (2.3)

Depreciation and Amortization

 89  62  27  43.5  85  79  6  7.6 

 

Corporate operating expensesInterest Charges

Interest charges increased $0.5to $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.

 

42

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

The $2.4 million decrease in income

Income tax expense increased $0.5 million in the three months ended SeptemberJune 30, 20192020 compared with the three months ended SeptemberJune 30, 2018 reflects2019 mainly due to the tax effect of a $2.0 million adjustment to income tax expense at OTP in the third quarter of 2018 for the reversal of excess deferred taxes related to IRS guidance that clarified changes to bonus depreciation under the TCJA applicable to 2017 income taxes, a $0.7 million reduction in tax expense due to 2019 reconciliations and prior periods adjustments and a $0.4 million increase in research and development tax credits at BTD. These decreases were partially offset by a $0.7 million decrease in federal PTCs resulting from the expiration of PTCs on OTP’s Ashtabula wind farm in November 2018.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 to income tax expense on our consolidated statements of income.

 

 

Three Months Ended

September 30,

  

Three Months Ended June 30,

 

(in thousands)

 

2019

 

2018

  

2020

 

2019

 

Income Before Income Taxes

 $29,681  $30,632  $20,789  $18,769 

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

 $7,717  $7,964  $5,405  $4,879 

Decreases in Tax from:

     

(Decreases) Increases in Tax from:

     

Differences Reversing in Excess of Federal Rates

 (933) (838) (543) (774)

Reconciliation and Prior Period Adjustments

 (688) 2,109 

Research and Development Tax Credits

 (612) (202)

Excess Tax Deduction – Equity Method Stock Awards

 --  (73)

Research and Development and Other Tax Credits

 (333) (187)

North Dakota Wind Tax Credit Amortization – Net of Federal Taxes

 (258) (258) (258) (258)

Allowance for Funds Used During Construction – Equity

 (239) (138) (248) (94)

Corporate Owned Life Insurance

 (50) (332) (193) (150)

Federal Production Tax Credits

 --  (707)

Other Items – Net

 (1) (166) (22) (73)

Income Tax Expense

 $4,936  $7,359  $3,808  $3,343 

Effective Income Tax Rate

 16.6% 24.0% 18.3% 17.8%

 

38

 

Comparison of the NineSix Months Ended SeptemberJune 30, 20192020 and 20182019

 

Consolidated operating revenues were $703.8$427.5 million for the ninesix months ended SeptemberJune 30, 20192020 compared with $695.3$475.2 million for the ninesix months ended SeptemberJune 30, 2018.2019. Operating income was $103.6$67.2 million for the ninesix months ended SeptemberJune 30, 20192020 compared with $106.0$66.4 million for the ninesix months ended SeptemberJune 30, 2018.2019. The Company recorded diluted earnings per share of $1.67$1.02 for the ninesix months ended SeptemberJune 30, 20192020 compared with $1.71$1.05 for the ninesix months ended SeptemberJune 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 nine-monthsix-month periods ended SeptemberJune 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)

 

Nine Months Ended

September 30, 2019

  

Nine Months Ended

September 30, 2018

 

Operating Revenues:

        

Electric

 $36  $31 

Nonelectric

  3   -- 

Costs of Products Sold

  25   11 

Other Nonelectric Expenses

  14   20 

43

Intersegment Eliminations (in thousands)

 

June 30, 2020

  

June 30, 2019

 

Operating Revenues:

        

Electric

 $29  $27 

Nonelectric

  --   3 

Costs of Products Sold

  7   20 

Other Nonelectric Expenses

  22   10 

 

Electric

 

 

Nine Months Ended

      

Six Months Ended

     
 

September 30,

   

%

  

June 30,

   

%

 

(in thousands)

 

2019

 

2018

 

Change

 

Change

  

2020

 

2019

 

Change

 

Change

 

Retail Sales Revenues from Contracts with Customers

 $303,276  $287,330  $15,946  5.5  $192,034  $202,931  $(10,897) (5.4)

Changes in Accrued Revenues under Alternative Revenue Programs

 (1,601) (2,757) 1,156  (41.9)  122  (680) 802  117.9 

Total Retail Sales Revenues

 $301,675  $284,573  $17,102  6.0 

Transmission Services Revenues

 34,023  35,785  (1,762) (4.9)

Total Retail Sales Revenue

 $192,156  $202,251  $(10,095) (5.0)

Transmission Services Revenue

  20,514  22,331  (1,817) (8.1)

Wholesale Revenues – Company Generation

 4,099  6,380  (2,281) (35.8)  1,641  2,468  (827) (33.5)

Other Revenues

 4,929  5,394  (465) (8.6)  3,718  3,303  415  12.6 

Total Operating Revenues

 $344,726  $332,132  $12,594  3.8  $218,029  $230,353  $(12,324) (5.4)

Production Fuel

 45,547  51,723  (6,176) (11.9)  22,523  27,216  (4,693) (17.2)

Purchased Power – System Use

 54,748  45,659  9,089  19.9   32,512  41,585  (9,073) (21.8)

Other Operation and Maintenance Expenses

 114,107  111,113  2,994  2.7   73,794  78,238  (4,444) (5.7)

Depreciation and Amortization

 44,765  41,924  2,841  6.8   31,416  29,567  1,849  6.3 

Property Taxes

 11,824  11,202  622  5.6   8,268  7,859  409  5.2 

Operating Income

 $73,735  $70,511  $3,224  4.6  $49,516  $45,888  $3,628  7.9 

Electric mwh Sales

                                

Retail mwh Sales

 3,657,618  3,669,841  (12,223) (0.3)  2,462,963  2,566,191  (103,228) (4.0)

Wholesale mwh Sales – Company Generation

 153,645  228,669  (75,024) (32.8)  81,064  82,139  (1,075) (1.3)

Heating Degree Days

 4,692  4,373  319  7.3 

Cooling Degree Days

 392  567  (175) (30.9)

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:

 

  

Nine Months ended September 30,

 
  

2019

  

2018

 

Heating Degree Days

  118.0%  111.4%

Cooling Degree Days

  86.0%  124.1%
  

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 ninesix months of 20192020 and 20182019 and between the periods:

 

  

2019 vs Normal

  

2018 vs Normal

  

2019 vs 2018

 

Effect on Diluted Earnings Per Share

 $0.06  $0.06  $0.00 
  

2020 vs Normal

  

2019 vs Normal

  

2020 vs 2019

 

Effect on Diluted Earnings Per Share

 $0.01  $0.08  $(0.07)

39

 

The $17.1$10.1 million increasedecrease in retail sales revenue includes:

 

 

A $5.7$12.0 million decrease in retail revenue related to the recovery of decreased fuel and purchased power costs to serve retail customers. Decreased demand caused by the milder winter weather and the impacts of COVID-19 contributed to a 20.1% decrease in kwhs generated for system use and a $4.1 million decrease in fuel costs. Purchased power costs decreased by $9.1 million despite a 5.1% increase in transmission cost recovery rider revenueskwhs purchased due to recent investmentsa 25.6% decrease in transmission infrastructure and transmission costs not currently recovered in base rates.purchased power prices.

 

 

A $5.5$3.9 million increasedecrease in retail revenuerevenues related to decreased consumption due to milder weather in the recoveryfirst six months of increases2020 compared with the first six months of 2019, evidenced by a 16.0% decrease in fuel and purchased power costs explained below.heating-degree days between the periods.

 

 

A $2.8$1.0 million increase in average electric prices, mainly related to interim and final rate increases in South Dakota.

A $2.0 million increasedecrease in retail revenue in South Dakota duerelated to the first quarter 2019 reversal of a tax refund provision accrued in 2018 in connection with OTP's 2018 South Dakota rate case settlement agreement.

 

 

A $1.9$0.4 million decrease in revenue due to decreased kwh sales to commercial and industrial customers resulting from a $2.2 million reduction in commercial and industrial sales due to COVID-19-related impacts on sales in the second quarter of 2020, mostly offset by increased sales resulting from a large commercial customer expanding its production capacity and increasing demand.

A $0.2 million decrease in transmission rider revenues.

These decreases in revenue were partially offset by:

A $5.3 million increase in Minnesota Renewable Riderand North Dakota renewable rider revenues duerelated to increased cost recovery requirements resultingearning a return on funds invested in Merricourt while the project is under construction.

$1.4 million in revenues from the expiration of federal PTCsNorth Dakota Generation Rider which went into effect in November 2018July 2019 to provide a return on a company-owned wind farm.funds invested in Astoria Station while the generation project is under construction.

 

 

A $0.6 million increase in revenue related to volume sales increases of electricity to residential and commercial customers exclusive of the establishmentimpact of a generation cost recovery rider in North Dakota in 2019 to provide for a returnweather on funds invested in building Astoria Station during its construction phase.sales.

 

partially offset by:

A $1.2 million decrease in retail revenue due to decreases in kwh sales to residential and industrial customers.

44

Transmission services revenuesrevenue decreased $1.8 million mainly due to a decreasereduction in MISOtransmission tariff revenue associated with offsets receivedrevenues related to decreased transmission volume resulting from independent generators to pay for transmission system upgrades made by OTP to facilitate the generators’ accesslower electrical demand partially attributable to the electric grid.impact of COVID-19.

 

Wholesale electric revenues decreased $2.3$0.8 million resulting fromdue to lower wholesale electric prices and a 32.8%1.3% decrease in wholesaleswholesale kwh sales due to fewer opportunities for wholesale sales as Coyote Station was offline during the second quarter of 2019 due to an extended maintenance outage and Hoot Lake Plant Unit 2 was offline for maintenance and repairs in June and July 2019. The decrease in revenues also resulted from decreased regional market demand in the third quarter of 2019 due to cooler summer weather, which also drove down wholesale electricity prices.sales. The lower wholesale prices made it uneconomical to generate and sell electricity from OTP’s Hoot Lake Plant when its incremental cost of generation exceeded wholesale prices.

Other electric revenues decreased $0.5 million mainly due toper kwh resulted in a $0.2 million reductiondecrease in revenuemargins on wholesale energy sales from salesOTP’s generating units in the first six months of Renewable Energy Credits and a $0.2 million reduction in late fees due to2020 compared with the suspensionfirst six months of late fee charges during the implementation of OTP’s new customer information and billing system.2019.

 

Production fuel costs decreased $6.2$4.7 million mainly asdue to a result of a 20.0%23.2% decrease in kwhs generated from ourat 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 the maintenance outage at Coyote Stationeconomic dispatch as reduced demand and lower prices for alternative fuels and generation sources drove market prices for electricity down in the second quarter of 2019 and due to maintenance and repairs at Hoot Lake Plant in June and July of 2019. The decrease in fuel costs related to the decrease in generation was partially offset by a 10.1% increase in the cost of fuel per kwh generated at OTP’s fuel-burning plants. The increased cost per kwh generated is mostly due to the absorption of CCMC’s fixed coal mining costs in Coyote Station’s fuel inventory while no coal was being delivered to Coyote Station during its spring 2019 maintenance outage.2020.

 

The cost of purchased power to serve retail customers increaseddecreased $9.1 million (19.9%) due to a 37.6% 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 12.9%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 $3.0decreased $4.4 million, including:

 

 

A $2.7$3.4 million increasedecrease in expense related to the establishment of a regulatory assetcontracted services and credit to operating expense for deferred recovery of an income tax adjustment in the third quarter of 2018 related to TCJA guidance issued in the quarter. There was no similar expense reduction recorded in the third quarter of 2019. The income tax adjustment is the result of August 2018 IRS guidance that clarified changes related to the treatment of bonus depreciation rules for 2017 that affected 2017 deductions and corresponding reversals of excess deferred taxes in 2018. The adjustments related to the guidance resulted in a $2.7 million increase in income tax expense, which is subject to recovery through future rate adjustments.

A $2.7 million increase in external service and materialmaterials and supplies expenses at Coyote Station, related to its extended maintenance shutdown in the second quarter of 2019.

A $1.4 million increase in transmission services expenses mainly related to cost reductions and billing adjustments recorded in 2018.

A $0.9 million increase in external services and material and supplies expenses at Hoot Lake Plant related to maintenance and repairs performed during its shutdown in June and July of 2019.

partially offset by:

A $1.3 million decrease in external services expenses related to Big Stone Plant maintenance and repair costs incurred in September 2018 during the first month of a scheduled eight-weekplant's second quarter 2019 extended maintenance outage.

 

 

A $1.1$1.5 million decrease in labor costs and labor-related benefit expenses.

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

 

 

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

 

 

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

These items were partially offset by:

 

 

A $0.4$1.6 million decreasenet increase in pollution control costs related to Coyote Stationlabor and Hoot Lake plant being off-line for extended periods of time in 2019 for scheduled and unplanned maintenance and repairs.benefit costs.

40

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 $2.8$1.8 million mainly due to recent2019 capital additions including the Big Stone South–Ellendale 345kVfor generation and transmission line energized in February 2019,plant, the new customer information system put inthat went into service induring the first quarter of 2019 and other recent transmission plant upgrades. new service vehicles.

Property tax expense increased $0.6$0.4 million due to capitalproperty additions in South Dakota and Minnesota.increased jurisdictional valuations.

45

 

Manufacturing

 

 

Nine Months Ended

      

Six Months Ended

     
 

September 30,

   

%

  

June 30,

   

%

 

(in thousands)

 

2019

 

2018

 

Change

 

Change

  

2020

 

2019

 

Change

 

Change

 

Operating Revenues

 $217,040  $203,843  $13,197  6.5  $114,427  $151,318  $(36,891) (24.4)

Cost of Products Sold

 167,002  155,028  11,974  7.7  86,701  115,603  (28,902) (25.0)

Operating Expenses

 22,880  22,154  726  3.3  12,777  16,034  (3,257) (20.3)

Depreciation and Amortization

 10,606  11,330  (724) (6.4) 7,485  7,101  384  5.4 

Operating Income

 $16,552  $15,331  $1,221  8.0  $7,464  $12,580  $(5,116) (40.7)

 

The $13.2$36.9 million increasedecrease in revenues in our Manufacturing segment includes the following:

 

 

Revenues at BTD increased $13.7decreased $36.2 million. Parts revenue was down $22.5 million duerelated to growthdecreased sales volumes to all end market customer categories served by BTD, in parts revenueorder of $16.2 million, including increased sales inmagnitude: recreational vehicle, construction, agricultural, and lawn and garden, agricultural, energy equipment and industrial end markets, partially offset by reduced sales in energy end markets. Included inas customers implemented temporary plant shutdowns due to the parts revenue increase isCOVID-19 pandemic. Lower prices related to the pass through of higherlower material costs of $6.9accounted for a $13.0 million with the remaining increase due to $8.7 milliondecrease in higher sales volume andparts revenue, partially offset by $0.6 million in price increases unrelated toexclusive of the pass through of material cost increases passed throughreductions. In addition to customers. The increasethe decrease in parts revenue, was partially offset by a $0.9scrap revenue decreased $1.4 million decrease in tooling and other revenues and a $1.6 million (24.6%) decrease in revenue from scrap metal sales due to a 23.2%30.1% decrease in scrap volume and a 13.0% decrease in scrap metal prices and a 1.9% decrease in scrap volume.prices.

 

 

Revenues at T.O. Plastics decreased $0.5$0.7 million primarily due to a $1.0$0.6 million decrease in industrial sales mainly due toand a customer bringing more production$0.3 million decrease in house,sales of life sciences products and scrap material, partially offset by increases of $0.3a $0.2 million fromincrease in sales of horticultural containers and $0.2containers. The $0.9 million in decreased sales of scrap material. The increase in horticultural salesindustrial and life sciences products is mainlyassociated with lower demand from customers due to growth of plug trayCOVID-19-related impacts on customer’s production and sales in certain horticultural markets.activity.

 

The $12.0$28.9 million increasedecrease in cost of products sold in our Manufacturing segment includes the following:

 

 

Cost of products sold at BTD increased $11.6decreased $29.1 million including $14.0 million in higher material costs,as a result of which $6.9 million was passed through to customers withboth the remaining $7.1 million due to increaseddecreased sales volume and cost increases notthe $13.0 million in lower material costs passed through to customers. The increase in material costs plus a $2.8 million increase in overhead costs was partially offset by a $5.2 million increase in recovery of tooling costs from customers.

 

 

Cost of products sold at T.O. Plastics increased $0.4$0.2 million mainly due to increased laboran increases in rental costs drivenfor more warehouse space and increases in part by increased production hoursother indirect costs, despite a $0.5 million decrease in responsematerial costs related to higherthe decrease in sales volume and in part by wage increases.volume.

 

The $0.7$3.3 million increasedecrease in operating expenses in our Manufacturing segment includes increases of $0.3a $2.5 million decrease in operating expenses at BTD related to initiatives taken at BTD to mitigate the negative impacts on sales related to COVID-19, mainly reductions in salaries, incentives and $0.4 millionbenefits, travel and outside services expenditures. Operating expenses at T.O. Plastics decreased $0.8 million, including $0.4 million as a result of the receipt of insurance settlement proceeds in the first quarter of 2020 and a $0.3 million write off of the value of destroyed property in 2019 related to the March 2019 partial roof collapse. T.O, Plastics travel and other selling expenses associateddecreased 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 partial collapseongoing 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 costs related to personal protective equipment. BTD also continued to pay health care costs for furloughed employees.

41

Plastics

  

Six Months Ended

         
  

June 30,

      

%

 

(in thousands)

 

2020

  

2019

  

Change

  

Change

 

Operating Revenues

 $95,076  $93,534  $1,542   1.6 

Cost of Products Sold

  73,017   72,995   22   -- 

Operating Expenses

  5,740   5,614   126   2.2 

Depreciation and Amortization

  1,762   1,752   10   0.6 

Operating Income

 $14,557  $13,173  $1,384   10.5 

Plastics segment revenues and operating income increased $1.5 million and $1.4 million, respectively, due to a warehouse roof4.4% increase in pounds of pipe sold, partially offset by a 2.6% decrease in PVC pipe prices. The sales volume increase resulted mainly from weather conditions that negatively impacted sales across our sales territory in the first quarter of 2019. Depreciation and amortization expense at BTD decreased $0.6 million as a result of certain assets reaching the ends of their depreciable lives.

Plastics

  

Nine Months Ended

         
  

September 30,

      

%

 

(in thousands)

 

2019

  

2018

  

Change

  

Change

 

Operating Revenues

 $142,100  $159,332  $(17,232)  (10.8)

Cost of Products Sold

  110,348   120,674   (10,326)  (8.6)

Operating Expenses

  8,486   9,136   (650)  (7.1)

Depreciation and Amortization

  2,617   2,812   (195)  (6.9)

Operating Income

 $20,649  $26,710  $(6,061)  (22.7)

Plastics segment revenues decreased $17.2 million due to a 7.7% decrease in pounds of PVC pipe sold and a 3.4% decrease in PVC pipe prices. Because of record first quarter sales volume in 2018, the overall decrease in year-over-year sales volume was expected. Weather conditions across our sales territory also negatively impacted first quarter 2019 sales. Cost of products sold decreased $10.3 million due toremained unchanged despite the decreaseincrease in sales volume anddue to a 0.9%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 an 11.0% decreasea 2.9% increase in gross margin per pound of PVC pipe sold. Plastics segment operating expenses decreased $0.7 million between periods mainly due to a decrease in incentive compensation related to the decrease in operating income.

46

 

Corporate

 

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

 

 

Nine Months Ended

      

Six Months Ended

     
 

September 30,

   

%

  

June 30,

   

%

 

(in thousands)

 

2019

 

2018

 

Change

 

Change

  

2020

 

2019

 

Change

 

Change

 

Operating Expenses

 $7,052  $6,420  $632  9.8  $4,167  $5,101  $(934) (18.3)

Depreciation and Amortization

 241  150  91  60.7  172  152  20  13.2 

 

Corporate operating expenses increased $0.6decreased $0.9 million mainly due to an increaseas a result of a net decrease in certain employeeincentive and benefit costs.costs of $0.5 million and a $0.3 million decrease in contracted service expenditures.

 

Interest Charges

 

Interest charges increased to $16.8 million in the six months ended June 30, 2020 from $15.7 million in the six months ended June 30, 2019. The $0.6$1.1 million increase in interest charges foris 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.

42

Income Tax Expense

Income tax expense increased $0.5 million in the ninesix months ended SeptemberJune 30, 20192020 compared with the ninesix months ended SeptemberJune 30, 2018 is due to a $49.7 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, partially offset by a $0.2 million increase in capitalized interest at OTP between the periods.

Nonservice Cost Components of Postretirement Benefits

The $1.0 million decrease in nonservice cost components of postretirement benefits in the nine months ended September 30, 2019 compared with the nine months ended September 30, 2018, is mostly due to a decrease in nonservice costs of the Company’s pension plan, mainly actuarial loss amortization expenses, partially offset by interest costs increases on all of the Company’s postretirement benefit plans.

Income Taxes

The $0.3 million decreased income tax expense in the nine months ended September 30, 2019 compared with the nine months ended September 30, 2018 reflects a $2.0 million adjustment to income tax expense at OTP in the third quarter of 2018 for the reversal of excess deferred taxes related to IRS guidance that clarified changes to bonus depreciation under the TCJA applicable to 2017 income taxes, a $0.7 million reduction in tax expense due to 2019 reconciliations and prior periods adjustments and a $0.4 million increase in research and development tax credits at BTD. These decreases were mostly offset by a $2.8 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 to income tax expense on our consolidated statements of income for the nine-month periods ended September 30, 2019 and 2018:income.

 

  

Nine Months Ended September 30,

 

(in thousands)

 

2019

  

2018

 

Income Before Income Taxes

 $80,402  $82,391 

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

 $20,905  $21,422 

Decreases in Tax from:

        

Differences Reversing in Excess of Federal Rates

  (2,690)  (2,932)

Research and Development Tax Credits

  (987)  (562)

Excess Tax Deduction – Equity Method Stock Awards

  (827)  (698)

North Dakota Wind Tax Credit Amortization – Net of Federal Taxes

  (774)  (774)

Reconciliation and Prior Period Adjustments

  (722)  2,028 

Corporate Owned Life Insurance

  (609)  (360)

Allowance for Funds Used During Construction – Equity

  (419)  (416)

Federal Production Tax Credits

  --   (2,757)

Other Comprehensive Income Deferred Tax Rate Adjustment

  --   (531)

Other Items – Net

  30   (213)

Income Tax Expense

 $13,907  $14,207 

Effective Income Tax Rate

  17.3%  17.2%

47

  

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 September 30, 2019 and December 31, 2018:

(in thousands)

 

Line Limit

  

In Use on

September 30,

2019

  

Restricted due to

Outstanding

Letters of Credit

  

Available on

September 30,

2019

  

Available on

December 31,

2018

 

Otter Tail Corporation Credit Agreement

 $130,000  $35,837  $--  $94,163  $120,785 

OTP Credit Agreement

  170,000   73,160   16,561   80,279   160,316 

Total

 $300,000  $108,997  $16,561  $174,442  $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 Securitiescurrent economic environment. We are closely monitoring our liquidity and Exchange Commission (SEC)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 shares or common shares purchased in the open market. The Company will begin issuing common shares in the fourth quarter of 2019 to meet the requirementsequity under these programs barring any further deteriorations of the Plan rather than purchasing shares incapital markets from the open market.COVID-19 pandemic or other factors. If weakened economic conditions persist for a prolonged period of time, we are prepared to add additional liquidity as necessary, including exercising the accordion features under our lines of credit to increase our available borrowing capacity under the lines by a combined $200 million.

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Equity and 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 $105.1$73.9 million for the ninesix months ended SeptemberJune 30, 20192020 compared with $100.9cash provided by operating activities of $69.3 million for the ninesix months ended SeptemberJune 30, 2018.2019. The $4.2primary reasons for the $4.6 million increase in cash provided by operations between periods reflects $3.8 million in noncash reductions in net income from increases in depreciation and stock-based compensation expenses. A $10.2the quarters were a $2.3 million increase in noncurrent labilities and deferred credits was almost entirely offset by a $7.5 million increase in deferred income taxes and other deferred debitsthe non-cash depreciation expense and a $2.5$2.1 million increasedecrease in discretionary pension fund contributions. Cashcash used for working capital decreased $1.1 million, as a $27.4 million increase in cash from reductions in inventory and collections of receivables was almost entirely offset by a $26.3 million increase in cash used initems between the payment of current obligations.quarters.

 

Net cash used in investing activities was $151.1$121.0 million for the ninesix months ended SeptemberJune 30, 20192020 compared with $75.9$55.4 million for the ninesix months ended SeptemberJune 30, 2018.2019. The $75.2$65.6 million increase is mainly due to a $70.3 million increase in cash used for investing activities is primarily due to an increaseconstruction 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 mainlytotaled $113.9 million in the first six months of 2020 compared with $43.6 million in the first six months of 2019. The majority of the 2020 expenditures at OTP related to the construction of the Merricourt Wind Energy Center (Merricourt) and Astoria Station projects and various transmission projects and upgrades.Merricourt.

48

 

Net cash provided by financing activities was $46.0$65.4 million infor the ninesix months ended SeptemberJune 30, 20192020 compared with $40.5 million innet cash used forin financing activities inof $13.8 million for the ninesix months ended SeptemberJune 30, 2018.2019. Financing activities in the first ninesix months of 2020 included $35.0 million in proceed from the issuance of long-term debt at OTP under its 2019 included proceeds of $90.4Note 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 from borrowings under the OTP and Otter Tail Corporation credit agreements which were used, together with cash flowsCredit Agreement and raised net proceeds of $24.8 million from operations,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 OTPs capitalits construction program expenditures. The CompanyFinancing activities in the six months of 2020 also paid $41.8included $29.9 million in common dividend payments in the first nine months of 2019.payments.

 

Financing activities in the first ninesix months of 20182019 included proceeds of $13.4 million from the issuance of $100 million in privately placed 4.07% Senior Unsecured Notes due February 7, 2048, which were used to pay down a portion of borrowings then outstanding under the OTP credit agreement. Additional borrowingsagreement to fund OTP capital expenditures and $4.6 million under the OTP and Otter Tail Corporation Credit Agreement to provide working capital for our manufacturing companies. The line of credit agreementsborrowings were used to fund a portion of capital expenditures in the first nine months of 2018. Common dividend payments of $39.9more than offset by $27.9 million in the first nine monthscommon dividend payments.

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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 was revised from $1.07 billion at year-end 2018 to $1.11 billion in the second quarter of 2019. 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 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 SeptemberJune 30, 2019,2020, OTP had capitalized approximately $54.8$131.7 million in project costs and allowances for funds used during construction (AFUDC) associated with Merricourt. OTP estimates its direct generation and transmission capital costs for the Merricourt project will be approximately $260 million. Additional transmission system upgrades for the project amounting to approximately $6.5 million will be made by a neighboring MISO transmission owner. OTP has received Notices of Force Majeure from EDF-RE US Development, LLC claiming rights to an extension of guaranteed project completion dates and adjustments to the consideration agreed upon in the TEPC Agreement due to COVID-19 impacts. While details regarding these claims and impact to the project remain uncertain, OTP currently expects Merricourt will cost approximately $258 million andto be completed in Octoberbefore 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 SeptemberJune 30, 2019,2020, OTP had capitalized approximately $36.8$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. For further detailsOTP 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 these two projects see disclosuressite and 26 have tested positive for COVID-19. Circumstances continue to evolve which could result in Note 3a delay in completion and increased costs for the project.

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

 

Contractual Obligations

In the first ninesix months of 2019,2020, OTP paid down mosta portion of its $64.5$317 million in obligations for commitments under contracts in place onas of December 31, 2018 and increased2019, reducing its construction program and other nonleaseobligations for commitments for the last three months of 2019 and the years 2020 and 2021under contracts to approximately $138.9$185 million as of SeptemberJune 30, 2019.2020. This includes commitments related to the construction of Astoria Station and Merricourt of $19.7$163 million for the remainder of 2019, $92.52020 and $6 million for 2021. In the first quarter of 2020, and $9.7OTP increased its debt obligations by $35 million for 2021.in the years beyond 2024.

 

49
45

 

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. TheOn November 8, 2019 the Company will begin issuingentered into a Distribution Agreement with KeyBanc under which we may offer and sell our common shares infrom 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 fourthsecond quarter of 2019 to meet2020, we received proceeds of $16,331,139, net of $206,723 in commissions, from the requirementsissuance of 388,304 common shares under this program.

Debt

Following are brief descriptions of the Plan rather than purchasing sharesshort-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 open market.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 September 30, 2019 and December 31, 2018:

(in thousands)

 

Line Limit

  

In Use on

September 30,

2019

  

Restricted due to

Outstanding

Letters of Credit

  

Available on

September 30,

2019

  

Available on

December 31,

2018

 

Otter Tail Corporation Credit Agreement

 $130,000  $35,837  $--  $94,163  $120,785 

OTP Credit Agreement

  170,000   73,160   16,561   80,279   160,316 

Total

 $300,000  $108,997  $16,561  $174,442  $281,101 

On October 29, 2012 we entered into a Third Amended and Restated Credit Agreement (the OTC Credit Agreement), which provided for an unsecured $130 million revolving credit facility that could be increased subject to certain terms and conditions. On October 31, 2019 the OTC Credit Agreement was amended to extend its expiration date by one year from October 31, 2023 to October 31, 2024, and to increase the amount of the revolving credit facility to $170 million. The amendment also provides this facility can be increased to $290 million subject to certain terms and conditions. We can draw on this credit facility to refinance certain indebtedness and support our operations and the operations of certain of our subsidiaries. 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, 2019 the OTP Credit Agreement was amended to extend its expiration date by one year from October 31, 2023 to October 31, 2024. OTP can draw on this credit facility to support the working capital needs and other capital requirements of its operations, including letters of credit in an aggregate amount not to exceed $50 million outstanding at any time. Borrowings under this line of credit bear interest at LIBOR plus 1.25%, subject to adjustment based on the ratings of OTP’s senior unsecured debt or the issuer rating if a rating is not provided for the senior unsecured debt. 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, 2024. 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

50

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

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,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 October 10, 2019,February 25, 2020, OTP issued the Series 2019A Notes, Series 2019B Notes and Series 2019C Notes (the 2019 Notes) pursuant to the 2019 Note Purchase Agreement. OTP used a portion of the $100 million proceeds from the issuance to repay $69.9 million of existing indebtedness under the OTP Credit Agreement, primarily incurred to fund OTP capital expenditures, and intends to use the remainder of the proceeds to pay for additional capital expenditures and for OTP general corporate purposes. The Series 2020A Notes, the Series 2020C Notes and the Series 2020D Notes are expectedpursuant 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 on February 25, 2020, andunder 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 may prepay all or any part of the 2019 Notes (in an amount not less than 10% of the aggregate principal amount of the 2019 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 2019A Notes then outstanding on or after April 10, 2029, (b) Series 2019B Notes then outstanding on or after April 10, 2039 or (c) Series 2019C Notes then outstanding on or after April 10, 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.

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2018 Note Purchase Agreement

On November 14, 2017, OTP entered into a Note Purchase Agreement (the 2018 Note Purchase Agreement) with the purchasers named therein, pursuant to which OTP agreed to issue to the purchasers, in a private placement transaction,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 part 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 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.

2016 Note Purchase Agreement

On September 23, 2016 we entered into a Note Purchase Agreement dated as of November 14, 2017 (the 20162018 Note Purchase Agreement) with the purchasers named therein, pursuant to which we agreed to issue to the purchasers, in a private placement transaction,.

46

On December 13, 2016 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.

52

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 SeptemberJune 30, 2019.2020.

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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 SeptemberJune 30, 2019,2020, our Interest and Dividend Coverage Ratio calculated under the requirements of the OTC Credit Agreement and the 2016 Note Purchase Agreement was 4.284.39 to 1.00.

 

 

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

 

 

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

 

 

Under the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, OTP may not permit the ratio of its Consolidated Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, in each case as provided in the related borrowing agreement, and OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement. As of SeptemberJune 30, 2019,2020, OTP’s Interest and Dividend Coverage Ratio and Interest Charges Coverage Ratio, calculated under the requirements of the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, was 3.443.70 to 1.00.

 

 

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

 

As of SeptemberJune 30, 2019,2020, our ratio of Interest-bearing Debt to Total Capitalization was 0.48 to 1.00 on a consolidated basis and 0.480.47 to 1.00 for OTP. Neither Otter Tail Corporation nor OTP had any Priority Indebtedness outstanding as of SeptemberJune 30, 2019.2020.

 

OFF-BALANCE-SHEET ARRANGEMENTS

 

We and our subsidiary companies have outstanding letters of credit totaling $19.3$12.1 million, but our line of credit borrowing limits are only restricted by $16.6$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.

 

47

20192020 BUSINESS OUTLOOK

 

We are narrowingraising our 20192020 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 $2.10 to $2.20 compared with our previously announced guidancebe 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 Wind Energy Center 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 announced 2019issued guidance are as follows:follows.

 

Diluted Earnings

 

2018 EPS

by

  

2019 Guidance

February 18, 2019

  

2019 Guidance

May 6, 2019

  

2019 Guidance

August 5, 2019

  

2019 Guidance

November 4, 2019

 
Per Share Segment  

Low

  

High

  

Low

  

High

  

Low

  

High

  

Low

  

High

 

Electric

 $1.36  $1.46  $1.49  $1.48  $1.51  $1.48  $1.51  $1.48  $1.50 

Manufacturing

 $0.32  $0.37  $0.41  $0.35  $0.39  $0.33  $0.37  $0.31  $0.33 

Plastics

 $0.60  $0.44  $0.48  $0.44  $0.48  $0.46  $0.50  $0.47  $0.50 

Corporate

 $(0.22) $(0.17) $(0.13) $(0.17) $(0.13) $(0.17) $(0.13) $(0.16) $(0.13)

Total

 $2.06  $2.10  $2.25  $2.10  $2.25  $2.10  $2.25  $2.10  $2.20 

Return on Equity

  11.5%  11.5%  12.3%  11.5%  12.3%  11.5%  12.3%  11.5%  12.0%

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2019 EPS
by
  

2020 Guidance

February 20, 2020

  

2020 Guidance

May 5, 2020

  

2020 Guidance

August 3, 2020

 
 Diluted Earnings Per Share   Segment  

Low

  

High

  

Low

  

High

  

Low

  

High

 

 Electric

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

 Manufacturing 

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

 Plastics

 $0.51  $0.43  $0.47  $0.43  $0.47  $0.50  $0.54 

 Corporate

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

 Total

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

 Return on Equity

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

 

The following items contributeOur latest 2020 guidance issued on August 3, 2020, as compared to our current 2019 earnings guidance.earlier guidance issued on May 5, 2020, is summarized below.

 

 

We expect 2019Our 2020 guidance for our Electric segment net income to be higher than 2018 segment net income based on:includes:

 

 

o

An annual net revenue increaseCapital spending on the Merricourt and Astoria Station rate base projects of approximately $2.6$177 million from the full approval of ourand $81 million, respectively, in 2020. The Merricourt project has rider recovery mechanisms in place in all three state jurisdictions. The Astoria Station project has rider recovery mechanisms in place in South Dakota and North Dakota. This project earns allowance for funds used during construction in Minnesota, has already been approved in our integrated resource plan and is expected to be recovered through a rate case settlementin Minnesota we expect to file in November 2020. The Astoria Station capital project is currently on May 14, 2019.budget and on schedule, but COVID-19-related disruptions to construction workforce have occurred in the second quarter. The settlement also allowed usMerricourt project continues to retainbe on budget but is now facing COVID-19-related project delays due to transportation delays of manufactured components for the impact of lower tax ratesproject. This project is still expected to be completed before December 31, 2020 but could see an increase in costs related to the TCJA from January 1, 2018 through October 17, 2018. This outcome favorably impacts 2019 earnings by approximately $0.02 per share.these delays.

48

o

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

 

 

o

Increases in AFUDCNo planned generation plant outages for planned capital projects, including Merricourt and Astoria Station, and an increase in North Dakota Generation Cost Recovery rider revenue related to Astoria Station Both projects began construction2020. Plant outage costs totaled $3.1 million in 2019.

 

 

o

Increased revenues from completionThe April 2020 decision by the Minnesota Supreme Court in OTP’s favor related to the excess return earned on Federal Energy Regulatory Commission jurisdiction transmission lines. The estimated impact of this decision is an increase to 2020 earnings of $0.05 per share. On a go-forward basis the positive impact of this decision on an annual basis is $0.01 per share. We have updated our Minnesota Transmission Cost Recovery rider filing with new rates incorporating the results of the Big Stone South–Ellendale project and additional transmission investments relateddecision to our South Dakota Transmission Reliability project.reflect the effect of this ruling.

 

 

o

Decreased operatingImplementation of cost reduction efforts such as lower discretionary spending, wage freezes, hiring freezes and maintenance expenses duereduction in overtime to decreasing costsmitigate the impact of pension, medical, workers compensationCOVID-19. These efforts are expected to positively impact earnings by $0.03 per share.

The above items are offset by:

o

The impact of unfavorable weather during the first quarter of 2020 and retiree medical benefits. The decrease in pension costs is a resultanticipated normal weather for the remaining months of an increase in the discount rate from 3.90%2020. Weather favorably impacted 2019 earnings by $0.08 per share compared to 4.50%.normal.

 

 

o

Expenses incurredReductions in the fourth quarter of 2018 that are not expected to occur in the fourth quarter of 2019 consist of $2.0 millioncommercial and industrial demand related to the Big Stone Plant outagenegative impacts of COVID-19 as some customers in our jurisdictions have had to either completely shut down operations or curtail operations given reduced demands for their products and services. We also expect to incur increased costs for bad debts, personal protective equipment and the contributionloss of late fee revenue. The total estimated earnings impact of these items ranges from $0.06 per share to $0.08 per share compared with our original estimate of $0.08 per share to $0.12 per share. OTP is working on obtaining regulatory relief to mitigate the Otter Tail Power Company Foundationimpact of $500,000.COVID-19 on its operating results. It has made joint filings with other investor-owned utilities in all three of its state jurisdictions and has made, or intends to make, additional filings on its own initiating processes for regulatory relief and recovery of current and future COVID-19-related lost commercial and industrial revenues, lost late fees and added expenses for increased bad debts, personal protective equipment and other increased operating and maintenance expenses.

 

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.

 

 

o

The extensionIncreased interest costs associated with a full year’s interest expense on the $100 million of senior unsecured notes issued in October 2019 and interest on the planned outage at Coyote Station due$35 million and $40 million of senior unsecured notes issued in February and expected to turbine rotor blade damage that was discoveredbe issued in the early stagesAugust of the outage, and the unplanned maintenance outage at Hoot Lake Plant.2020, respectively.

 

 

We now expect 2019 net income from our Manufacturing segment toearnings will be in line with 2018. The change is based on:lower than 2019, driven by the impact of the COVID-19 pandemic:

 

 

o

SoftnessWe now estimate a reduction in certain end markets served by BTDManufacturing segment earnings of $0.14 per share from the mid-point of our original segment guidance to the mid-point of our updated segment guidance. This is due to concerns over a slowing economythe effects of, and continued softness in scrap metal revenues based on lower scrap metal prices.response to, the COVID-19 pandemic.

 

 

o

A decreaseBTD has been impacted by COVID-19-related customer plant shutdowns across all end markets it serves and has cut back on operating levels. In addition to implementing temporary rotating furloughs in the second quarter of 2020 affecting approximately 55% of its employees, BTD reduced its headcount by approximately 180 positions across all its sites in the second quarter of 2020. Additional cost-cutting measures may be taken by BTD depending on the length and severity of this reduced demand for its products as the impacts from COVID-19 and related responses continue.

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 mainly duemay take additional cost-cutting measures depending on the length and severity of market softness for its products as the impact from COVID-19 and related responses continue to first quarter volume softness and the expected impact on business operations of the partial collapse and replacement of a warehouse roof, which was damaged in March of 2019 during a winter storm.develop.

 

 

o

Backlog for the manufacturing companiesManufacturing segment of approximately $56$96 million for 20192020 compared with $62$115 million one year ago. Raw material price deflation is driving backlog down by $10 million and the remaining $9 million decrease in backlog is volume driven.

49

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.

 

 

We expect 2019Our change in the guidance range for corporate costs, net income from the Plastics segment to be lower than 2018 based on lower expected operating margins in 2019. Thisof tax, is primarily due to the decline in values of our investments in corporate-owned life insurance and investments held at our captive insurance company related to COVID-19 and its related impacts on the stock market. While we have taken expense mitigation efforts to lower sales volumesour corporate labor and lower PVC pipe pricesnon-labor costs, we do not expect to fully recover the drop in 2019 compared with 2018.value of our investments before the end of 2020.

 

Corporate costs, net of tax, are expected to be lower in 2019 than in 2018. In 2018, we incurred expenses of $2 million for a contribution to the Otter Tail Corporation Foundation and $1.2 million for accruals related to certain tax matters. These expenses are not expected to occur during the remainder of 2019.

 

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 nine monthsquarter ended SeptemberJune 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.

 

55
50

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 us.the Company.

 

 

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

 

 

Economic conditions could negatively impact our businesses.

 

 

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

 

 

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

 

 

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

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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 us.the Company.

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

 

 

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

 

 

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

 

 

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

 

 

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

 

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

 

 

Changes to regulationRegulation of generating plant emissions including but not limited to carbon dioxide emissions and regional haze regulation under state implementation plans, could affect our operating costs and the costs of supplying electricity to our customers and the economic viability of continued operation of certain of ourOTP’s steam-powered electric plants.

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

 

 

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

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

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

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

 

 

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

 

 

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

 

 

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

 

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

 

At SeptemberJune 30, 20192020 we had exposure to market risk associated with interest rates because we had $35.8$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 $73.2 million in short-term debt outstanding on September 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 SeptemberJune 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 SeptemberJune 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 SeptemberJune 30, 2019.2020.

 

During the fiscal quarter ended SeptemberJune 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.

 

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

 

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.

 

Item 1A. Risk Factors

 

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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Item 6.      Exhibits

4.1

Note Purchase Agreement dated as of September 12, 2019 between Otter Tail Power Company and the Purchasers named therein (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by Otter Tail Corporation on September 16, 2019).

4.2

Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2019, among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West as a Bank (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by Otter Tail Corporation on November 5, 2019).

4.3

Seventh Amendment to Second Amended and Restated Credit Agreement, dated as of October 31, 2019, among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation Agent and as a Bank, and Wells Fargo Bank, National Association as a Bank (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by Otter Tail Corporation on November 5, 2019).

 

 

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.

 

 

104

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

 

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

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: November 8, 2019August 7, 2020

 

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