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Section 1: 10-Q (FORM 10-Q)

ottr20190331_10q.htm
 

Table of Contents

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

[ X]   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended

March 31, 2019

 

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:

 

April 30, 2019 39,754,652 Common Shares ($5 par value)

 

 

 

 

OTTER TAIL CORPORATION

 

INDEX

 

Part I. Financial Information

Page No.

   

Item 1.

Financial Statements

 
     
 

Consolidated Balance Sheets – March 31, 2019 and December 31, 2018 (not audited)

2 & 3

     
 

Consolidated Statements of Income – Three Months Ended March 31, 2019 and 2018 (not audited)

4

     
 

Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2019 and 2018 (not audited)

5

     
 

Consolidated Statements of Common Shareholders’ Equity – Three Months Ended March 31, 2019 and 2018 (not audited)

6

     
 

Consolidated Statements of Cash Flows – Three Months Ended March 31, 2019 and 2018 (not audited)

7

     
 

Condensed Notes to Consolidated Financial Statements (not audited)

8-34

     

Item 2.

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

35-47

     

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

47-48

     

Item 4.

Controls and Procedures

48

     

Part II. Other Information

 
     

Item 1.

Legal Proceedings

48

     

Item 1A.

Risk Factors 

48

     

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds 

48

     

Item 6.

Exhibits

49

     

Signatures

49

 

1

 

 

PART I. FINANCIAL INFORMATION

 

Item 1. financial statements

 

Otter Tail Corporation

 

Consolidated Balance Sheets

 

(not audited)

 
                 

(in thousands)

 

March 31,

2019

   

December 31,

2018

 
                 

Assets

               
                 

Current Assets

               

Cash and Cash Equivalents

  $ 891     $ 861  

Accounts Receivable:

               

Trade—Net

    113,144       75,144  

Other

    8,827       9,741  

Inventories

    106,732       106,270  

Unbilled Receivables

    18,928       23,626  

Income Taxes Receivable

    --       2,439  

Regulatory Assets

    15,193       17,225  

Other

    9,986       6,114  

Total Current Assets

    273,701       241,420  
                 

Investments

    9,220       8,961  

Other Assets

    38,653       35,759  

Goodwill

    37,572       37,572  

Other IntangiblesNet

    12,154       12,450  

Regulatory Assets

    133,427       135,257  
                 

Right of Use Assets - Operating Leases

    20,712       --  
                 

Plant

               

Electric Plant in Service

    2,160,321       2,019,721  

Nonelectric Operations

    231,135       228,120  

Construction Work in Progress

    49,054       181,626  

Total Gross Plant

    2,440,510       2,429,467  

Less Accumulated Depreciation and Amortization

    861,401       848,369  

Net Plant

    1,579,109       1,581,098  
                 

Total Assets

  $ 2,104,548     $ 2,052,517  

 

See accompanying condensed notes to consolidated financial statements.

 

2

Table of Contents

 

Otter Tail Corporation

 

Consolidated Balance Sheets

 

(not audited)

 

 

(in thousands, except share data)

March 31,

2019

 

December 31,

2018

 
             

Liabilities and Equity

           
             

Current Liabilities

           

Short-Term Debt

$ 43,601   $ 18,599  

Current Maturities of Long-Term Debt

  174     172  

Accounts Payable

  100,496     96,291  

Accrued Salaries and Wages

  15,139     24,857  

Accrued Federal and State Income Taxes

  2,459     --  

Other Accrued Taxes

  18,590     17,287  

Regulatory Liabilities

  7,787     738  

Current Operating Lease Liabilities

  3,900     --  

Other Accrued Liabilities

  8,575     12,149  

Total Current Liabilities

  200,721     170,093  
             

Pensions Benefit Liability

  88,223     98,358  

Other Postretirement Benefits Liability

  72,456     71,561  

Long-Term Operating Lease Liabilities

  17,160     --  

Other Noncurrent Liabilities

  26,354     24,326  
             

Commitments and Contingencies (note 9)

           
             

Deferred Credits

           

Deferred Income Taxes

  121,863     120,976  

Deferred Tax Credits

  19,637     19,974  

Regulatory Liabilities

  225,496     226,469  

Other

  2,117     1,895  

Total Deferred Credits

  369,113     369,314  
             

Capitalization

           

Long-Term Debt—Net

  590,022     590,002  
             

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—39,729,708 Shares; 2018—39,664,884 Shares

  198,649     198,324  

Premium on Common Shares

  342,991     344,250  

Retained Earnings

  203,619     190,433  

Accumulated Other Comprehensive Loss

  (4,760 )   (4,144 )

Total Common Equity

  740,499     728,863  
             

Total Capitalization

  1,330,521     1,318,865  
             

Total Liabilities and Equity

$ 2,104,548   $ 2,052,517  

 

See accompanying condensed notes to consolidated financial statements.

 

3

Table of Contents

 

 

Otter Tail Corporation

Consolidated Statements of Income

(not audited)

 

   

Three Months Ended

March 31,

 

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

 

2019

   

2018

 
                 

Operating Revenues

               

Electric:

               

Revenues from Contracts with Customers

  $ 129,144     $ 123,825  

Changes in Accrued Revenues under Alternative Revenue Programs

    (1,049 )     (875 )

Total Electric Revenues

    128,095       122,950  

Product Sales under Contracts with Customers

    117,877       118,316  

Total Operating Revenues

    245,972       241,266  
                 

Operating Expenses

               

Production Fuel – Electric

    18,920       18,706  

Purchased Power – Electric System Use

    21,952       21,593  

Electric Operation and Maintenance Expenses

    38,382       39,475  

Cost of Products Sold (depreciation included below)

    90,582       88,785  

Other Nonelectric Expenses

    13,477       12,494  

Depreciation and Amortization

    19,131       18,763  

Property Taxes – Electric

    3,959       3,835  

Total Operating Expenses

    206,403       203,651  

Operating Income

    39,569       37,615  

Interest Charges

    7,826       7,372  

Nonservice Cost Components of Postretirement Benefits

    1,035       1,417  

Other Income

    1,244       1,183  

Income Before Income Taxes

    31,952       30,009  

Income Tax Expense

    5,628       3,794  

Net Income

  $ 26,324     $ 26,215  

Average Number of Common Shares Outstanding—Basic

    39,657,321       39,550,874  

Average Number of Common Shares Outstanding—Diluted

    39,903,165       39,863,682  

Basic Earnings Per Common Share

  $ 0.66     $ 0.66  

Diluted Earnings Per Common Share

  $ 0.66     $ 0.66  

 

See accompanying condensed notes to consolidated financial statements.

 

4

Table of Contents

 

 

Otter Tail Corporation

Consolidated Statements of Comprehensive Income

(not audited)

 

   

Three Months Ended

March 31,

 

(in thousands)

 

2019

   

2018

 

Net Income

  $ 26,324     $ 26,215  

Other Comprehensive Income (Loss):

               

Unrealized Gains (Losses) on Available-for-Sale Securities:

               

Reversal of Previously Recognized Gains on Available for Sale Securities Included in Other Income During Period

    --       (110 )

Unrealized Gains (Losses) Arising During Period

    91       (66 )

Income Tax (Expense) Benefit

    (19 )     37  

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

    72       (139 )

Pension and Postretirement Benefit Plans:

               

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

    130       227  

Income Tax Expense

    (34 )     (59 )

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

    --       (531 )

Pension and Postretirement Benefit Plans – net-of-tax

    96       (363 )

Total Other Comprehensive Income (Loss)

    168       (502 )

Total Comprehensive Income

  $ 26,492     $ 25,713  

 

See accompanying condensed notes to consolidated financial statements.

 

5

Table of Contents

 

 
Otter Tail Corporation

Consolidated Statements of Common Shareholders’ Equity

For the Three-Month Periods Ended March 31, 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

 

Balance, December 31, 2018

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

Common Stock Issuances, Net of Expenses

    120,048       601       (601 )                     --  

Common Stock Retirements

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

Net Income

                            26,324               26,324  

Other Comprehensive Income

                                    168       168  

ASU 2018-02 2017 TCJA Stranded Tax Transfer

                            784       (784 )     --  

Employee Stock Incentive Plan Expense

                    1,796                       1,796  

Common Dividends ($0.35 per share)

                            (13,922 )             (13,922 )

Balance, March 31, 2019

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

Balance, December 31, 2017

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

Common Stock Issuances, Net of Expenses

    127,598       638       (638 )                     --  

Common Stock Retirements

    (58,495 )     (292 )     (2,117 )                     (2,409 )

Net Income

                            26,215               26,215  

Other Comprehensive Loss

                                    (502 )     (502 )

Employee Stock Incentive Plan Expense

                    1,146                       1,146  

Common Dividends ($0.335 per share)

                            (13,292 )             (13,292 )

Balance, March 31, 2018

    39,626,594     $ 198,133       341,841     $ 174,209     $ (6,133 )   $ 708,050  

 

6

Table of Contents

 

 

Otter Tail Corporation

Consolidated Statements of Cash Flows

(not audited)

   

Three Months Ended

March 31,

 

(in thousands)

 

2019

   

2018

 

Cash Flows from Operating Activities

               

Net Income

  $ 26,324     $ 26,215  

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

               

Depreciation and Amortization

    19,131       18,763  

Deferred Tax Credits

    (337 )     (354 )

Deferred Income Taxes

    835       2,901  

Change in Deferred Debits and Other Assets

    1,464       6,295  

Discretionary Contribution to Pension Plan

    (10,000 )     (20,000 )

Change in Noncurrent Liabilities and Deferred Credits

    8,787       (5,091 )

Allowance for Equity/Other Funds Used During Construction

    (330 )     (638 )

Stock Compensation Expense—Equity Awards

    1,796       1,146  

Other—Net

    375       (284 )

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

               

Change in Receivables

    (37,086 )     (25,047 )

Change in Inventories

    (462 )     35  

Change in Other Current Assets

    128       2,334  

Change in Payables and Other Current Liabilities

    4,088       (2,798 )

Change in Interest and Income Taxes Receivable/Payable

    2,437       1,163  

Net Cash Provided by Operating Activities

    17,150       4,640  

Cash Flows from Investing Activities

               

Capital Expenditures

    (24,687 )     (23,618 )

Net Proceeds from Disposal of Noncurrent Assets

    509       510  

Cash Used for Investments and Other Assets

    (1,258 )     (719 )

Net Cash Used in Investing Activities

    (25,436 )     (23,827 )

Cash Flows from Financing Activities

               

Change in Checks Written in Excess of Cash

    8       2,338  

Net Short-Term Borrowings (Repayments)

    25,002       (82,052 )

Payments for Retirement of Capital Stock

    (2,730 )     (2,409 )

Proceeds from Issuance of Long-Term Debt

    --       100,000  

Short-Term and Long-Term Debt Issuance Expenses

    --       (433 )

Payments for Retirement of Long-Term Debt

    (42 )     (60 )

Dividends Paid

    (13,922 )     (13,292 )

Net Cash Provided by Financing Activities

    8,316       4,092  

Net Change in Cash and Cash Equivalents

    30       (15,095 )

Cash and Cash Equivalents at Beginning of Period

    861       16,216  

Cash and Cash Equivalents at End of Period

  $ 891     $ 1,121  

 

See accompanying condensed notes to consolidated financial statements.

 

7

Table of Contents

 

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. Because of seasonal and other factors, the earnings for the three months ended March 31, 2019 should not be taken as an indication of earnings for all or any part of the balance of the year.

 

The following condensed notes are numbered to correspond to numbers of the notes included in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2018.

 

 

1. Summary of Significant Accounting Policies

 

Revenue Recognition

Due to the diverse business operations of the Company, recognition of revenue from contracts with customers depends on the product produced and sold or service performed. The Company recognizes revenue from contracts with customers, at prices that are fixed or determinable as evidenced by an agreement with the customer, when the Company has met its performance obligation under the contract and it is probable that the Company will collect the amount to which it is entitled in exchange for the goods or services transferred or to be transferred to the customer. Depending on the product produced and sold or service performed and the terms of the agreement with the customer, the Company recognizes revenue either over time, in the case of delivery or transmission of electricity or related services or the production and storage of certain custom-made products, or at a point in time for the delivery of standardized products and other products made to the customers 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) No. 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, Regulated Operations (ASC 980). The ARP revenue adjustments are recorded on the basis of recoverable costs incurred and returns earned under rate riders on a separate line on the face of the Company’s consolidated statements of income as they do not meet the criteria to be classified as revenue from contracts with customers.

 

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

 

Most Electric segment revenues are earned from the generation, transmission and sale of electricity to retail customers at rates approved by regulatory commissions in the states where Otter Tail Power Company (OTP) provides service. OTP also earns revenue from the transmission of electricity for others over the transmission assets it owns separately, or jointly with other transmission service providers, under rate tariffs established by the independent transmission system operator and approved by the Federal Energy Regulatory Commission (FERC). These revenues account for over 80% of other electric revenues reported in the table of disaggregated revenues in note 2. 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

 

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) and Conservation Improvement Program riders.

 

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

 

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

 

OTP accrues ARP revenue 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 ARP revenue adjustments 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-month periods ended March 31, 2019, and 2018.

 

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. 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-month periods ended March 31, 2019 and 2018.

 

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

 

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

 

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

 

March 31, 2019 (in thousands)

 

Level 1

   

Level 2

   

Level 3

 

Assets:

                       

Investments:

                       

Equity Funds – Held by Captive Insurance Company

  $ 1,444                  

Corporate Debt Securities – Held by Captive Insurance Company

          $ 5,975          

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

            1,644          

Other Assets:

                       

Money Market and Mutual Funds – Nonqualified Retirement Savings Plan

    1,396                  

Total Assets

  $ 2,840     $ 7,619          

 

December 31, 2018 (in thousands)

 

Level 1

   

Level 2

   

Level 3

 

Assets:

                       

Investments:

                       

Equity Funds – Held by Captive Insurance Company

  $ 1,294                  

Corporate Debt Securities – Held by Captive Insurance Company

          $ 5,898          

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

            1,586          

Other Assets:

                       

Money Market and Mutual Funds – Nonqualified Retirement Savings Plan

    838                  

Total Assets

  $ 2,132     $ 7,484          

 

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 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 they are required to buy the entity 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, 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 permitted by CCMC’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of March 31, 2019 could be as high as $53.1 million, OTP’s 35% share of unrecovered costs.

 

10

 

Inventories

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

 

   

March 31,

   

December 31,

 

(in thousands)

 

2019

   

2018

 

Finished Goods

  $ 35,771     $ 37,130  

Work in Process

    20,503       20,393  

Raw Material, Fuel and Supplies

    50,458       48,747  

Total Inventories

  $ 106,732     $ 106,270  

 

Goodwill and Other Intangible Assets

An assessment of the carrying amounts of goodwill of the Company’s operating units as of December 31, 2018 indicated the fair values are substantially in excess of their respective book values and not impaired.

 

The following table indicates there were no changes to goodwill by business segment during the first three 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)

March 31, 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 March 31, 2019 and December 31, 2018:

 

March 31, 2019 (in thousands)

 

Gross Carrying

Amount

   

Accumulated

Amortization

   

Net Carrying

Amount

   

Remaining

Amortization

Periods (months)

 

Amortizable Intangible Assets:

                                 

Customer Relationships

  $ 22,491     $ 10,410     $ 12,081      9 - 197  

Other

    154       81       73       17    

Total

  $ 22,645     $ 10,491     $ 12,154            

 

December 31, 2018 (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  

Other

    154       68       86       20    

Total

  $ 22,645     $ 10,195     $ 12,450            

 

The amortization expense for these intangible assets was:

 

   

Three Months Ended

 
   

March 31,

 

(in thousands)

 

2019

   

2018

 

Amortization Expense – Intangible Assets

  $ 296     $ 345  

 

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

 

(in thousands)

 

2019

   

2020

   

2021

   

2022

   

2023

 

Estimated Amortization Expense – Intangible Assets

  $ 1,184     $ 1,133     $ 1,099     $ 1,099     $ 1,099  

 

11

 

Supplemental Disclosures of Cash Flow Information

 

   

As of March 31,

 

(in thousands)

 

2019

   

2018

 

Noncash Investing Activities:

               

Transactions Related to Capital Additions not Settled in Cash

  $ 4,338     $ 10,451  

 

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

 

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.

 

 

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 three segments: Electric, Manufacturing and Plastics. The chart below indicates the companies included in each segment.

 

 

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

 

Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping, fabrication and painting, and production of plastic thermoformed horticultural containers, life science and industrial packaging, material handling components and extruded raw material stock. 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 regions of the United States.

 

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 no single customer accounted for over 10% of the Company’s consolidated revenue in 2018, certain customers provided a significant portion of each business segment’s 2018 revenue. The Electric segment has one customer that provided 11.2% of 2018 segment revenues. The Manufacturing segment has one customer that manufactures and sells recreational vehicles that provided 22.2% of 2018 segment revenues and one customer that manufactures and sells lawn and garden equipment that provided 11.2% of 2018 segment revenues. The Manufacturing segment’s top five revenue-generating customers provided over 52% of 2018 segment revenues. The Plastics segment has two customers that together provided 39.1% of 2018 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 99.0% and 98.3% of its operating revenues for the respective three-month periods ended March 31, 2019 and 2018 came from sales within the United States.

 

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 months ended March 31, 2019 and 2018 and total assets by business segment as of March 31, 2019 and December 31, 2018 are presented in the following tables:

 

Operating Revenue

 

   

Three Months Ended

 
   

March 31,

 

(in thousands)

 

2019

   

2018

 

Electric Segment:

               

Retail Sales Revenue from Contracts with Customers

  $ 114,955     $ 109,180  

Changes in Accrued ARP Revenues

    (1,049 )     (875 )

Total Retail Sales Revenue

    113,906       108,305  

Transmission Services Revenue

    10,862       11,903  

Wholesale Revenues – Company Generation

    1,527       1,015  

Other Revenues

    1,814       1,742  

Total Electric Segment Revenues

    128,109       122,965  

Manufacturing Segment:

               

Metal Parts and Tooling

    66,724       56,927  

Plastic Products and Tooling

    9,045       10,235  

Other

    2,053       1,500  

Total Manufacturing Segment Revenues

    77,822       68,662  

Plastics Segment – Sale of PVC Pipe Products

    40,058       49,653  

Intersegment Eliminations

    (17 )     (14 )

Total

  $ 245,972     $ 241,266  

 

Interest Charges

 

   

Three Months Ended

 
   

March 31,

 

(in thousands)

 

2019

   

2018

 

Electric

  $ 6,641     $ 6,390  

Manufacturing

    584       554  

Plastics

    149       150  

Corporate and Intersegment Eliminations

    452       278  

Total

  $ 7,826     $ 7,372  

 

Income Taxes

 

   

Three Months Ended

 
   

March 31,

 

(in thousands)

 

2019

   

2018

 

Electric

  $ 4,771     $ 2,098  

Manufacturing

    1,454       1,223  

Plastics

    1,329       2,414  

Corporate

    (1,926 )     (1,941 )

Total

  $ 5,628     $ 3,794  

 

Net Income (Loss)

 

   

Three Months Ended

 
   

March 31,

 

(in thousands)

 

2019

   

2018

 

Electric

  $ 18,700     $ 16,668  

Manufacturing

    4,842       4,164  

Plastics

    3,729       6,844  

Corporate

    (947 )     (1,461 )

Total

  $ 26,324     $ 26,215  

 

14

 

Identifiable Assets

 

   

March 31,

   

December 31,

 

(in thousands)

 

2019

   

2018

 

Electric

  $ 1,737,278     $ 1,728,534  

Manufacturing

    217,390       187,556  

Plastics

    104,544       91,630  

Corporate

    45,336       44,797  

Total

  $ 2,104,548     $ 2,052,517  

 

 

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 2019 and 2018.

 

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 Station. In a September 26, 2018 hearing the NDPSC established a GCR rider for future recovery of costs incurred for Astoria Station. The interconnection agreement for Astoria Station was executed by MISO in December 2018 and accepted by the FERC in January 2019. As of March 31, 2019, OTP had capitalized approximately $7.7 million in development and other costs associated with Astoria Station.

 

Merricourt Project—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 (EDF) to purchase and assume the development assets and certain specified liabilities associated with a 150-MW wind farm in southeastern North Dakota (the Merricourt Project) for a purchase price of approximately $34.7 million, subject to adjustments for interconnection costs. The Purchase Agreement will close on satisfaction of various closing conditions (including regulatory approvals). Also on November 16, 2016, OTP entered into a Turnkey Engineering, Procurement and Construction Services Agreement with EDF pursuant to which EDF will develop, design, procure, construct, interconnect, test and commission the wind farm with a targeted completion date in 2020 for consideration of approximately $200.5 million, subject to certain adjustments, payable following the closing of the Purchase Agreement in installments in connection with certain project construction milestones. 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 the Merricourt Project 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 Merricourt generation interconnection agreement with MISO was approved by the FERC in April 2019. Construction of the Merricourt Project will begin after closing on the Purchase Agreement, anticipated to occur in the last half of 2019. As of March 31, 2019, OTP had capitalized approximately $5.3 million in development costs associated with the Merricourt Project.

 

Big Stone South–Ellendale Multi-Value Transmission Project (MVP)—This 345-kilovolt transmission line, energized on February 6, 2019, extends 163 miles between a substation near Big Stone City, South Dakota and a substation near Ellendale, North Dakota. OTP jointly developed this project with Montana-Dakota Utilities Co., and the parties have equal ownership interest in the transmission line portion of the project. The MISO approved this project as an MVP under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff) in December 2011. MVPs are designed to enable the MISO region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation is designed to ensure the costs of transmission projects with regional benefits are properly assigned to those who benefit. OTP’s capitalized costs on this project as of March 31, 2019 were approximately $106 million, which includes assets that are 100% owned by OTP.

 

15

 

Recovery of OTP’s major transmission investments is through the MISO Tariff and, currently, Minnesota, North Dakota and South Dakota base rates and TCR riders.

 

Minnesota

 

General Rates—The MPUC rendered its final decision in OTP’s 2016 general rate case in March 2017 and issued its written order on May 1, 2017. Pursuant to the order, OTP’s allowed rate of return on rate base is 8.61% and its allowed rate of return on equity (ROE) is 10.74%.

 

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.

 

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 proposed decision on March 20, 2019 to extend all utilities 2017-2019 CIP plans one year, through 2020.

On April 1, 2019 OTP filed a request for approval of its 2018 energy savings, recovery of $3.0 million in accrued financial incentives and recovery of 2018 program costs not included in base rates.

 

Transmission Cost Recovery Rider—The Minnesota Public Utilities Act provides a mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that meet certain criteria, plus a return on investment at the level approved in a utility’s last general rate case. Additionally, following approval of the rate schedule, the MPUC may approve annual rate adjustments filed pursuant to the rate schedule.

 

In OTP’s 2016 general rate case order issued on May 1, 2017, the MPUC ordered OTP to include, in the TCR rider retail rate base, Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale 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 would vary over time and be dependent on the differences between the revenue requirements and returns in the two jurisdictions at any given time. On August 18, 2017 OTP filed an appeal of the MPUC 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 affirms the original decision by the Minnesota Court of Appeals to exclude the MVP projects from the TCR rider or overturns the Minnesota Court of Appeals decision and includes the two MVP projects in the TCR rider. Action by the Minnesota Supreme Court is expected later in 2019, increasing the likelihood the MPUC will delay its decision on the TCR rider update. 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 estimated amount credited to Minnesota customers through the TCR rider through March 31, 2019 is approximately $2.5 million.

 

16

 

Environmental Cost Recovery Rider—OTP had an ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant Air Quality Control System (AQCS). The ECR rider provided for a return on the project’s construction work in progress (CWIP) balance at the level approved in OTP’s 2010 general rate case. In its 2016 general rate case order, the MPUC approved OTP’s proposal to transition eligible rate base and expense recovery from the ECR rider to base rate recovery effective with implementation of final rates in November 2017. Accordingly, in its 2018 annual update filing OTP requested, and the MPUC approved, setting the Minnesota ECR rider rate to zero effective December 1, 2018. The remaining under-recovered balance was charged on customer billings in March and April 2019.

 

Renewable Resource Adjustment—Effective November 1, 2017, with the implementation of final rates in Minnesota, new rates were put into effect for the Minnesota RRA rider to address recovery of federal Production Tax Credits (PTCs) expiring on OTP’s wind farms in 2017 and 2018.

 

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. OTP has accrued an interim rate refund of $3.4 million as of March 31, 2019, which includes interest and $0.8 million in excess revenue collected for income taxes under interim rates in effect in January and February 2018.

 

Renewable Resource Adjustment—OTP has a North Dakota RRA which enables OTP to recover its North Dakota jurisdictional share of investments in renewable energy facilities. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed, along with a return on investment.

 

Effective in February 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 will remain subject to refund or recovery through this rider: Southwest Power Pool (SPP) costs and MISO Schedule 26 and 26A revenues and expenses and costs related to rider projects still under construction in the test year used in the 2017 general rate case. This rider will continue to be updated annually for new or modified electric transmission facilities and associated operating costs.

 

Environmental Cost Recovery Rider—OTP has an ECR rider in North Dakota. The ECR rider has provided for a return on investment at the level approved in OTP’s preceding general rate case and for recovery of OTP’s North Dakota share of environmental investments and costs approved for recovery under the rider. Prior to its 2017 general rate case reaching a final settlement and final rates going into effect on February 1, 2019, OTP’s North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects were being recovered through the ECR rider. Effective February 1, 2019 these rate base investments are being recovered under general rates and the rider was zeroed out except for an overcollection balance that will be refunded to ratepayers through the rider.

 

17

 

Generation Cost Recovery Rider—On March 1, 2019 OTP filed a request with the NDPSC to establish an initial GCR rider rate for recovery of OTP’s North Dakota jurisdictional share of the revenue requirements of its investment in Astoria Station.

 

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 the proposed Merricourt wind generation facility when the facility goes into service.

 

The SDPUC approved a partial settlement on March 1, 2019 on all issues of the rate case except ROE. The settlement includes approval of a phase-in plan to provide for a return on amounts invested in Astoria Station and the Merricourt Project, which addresses the second step of the request for increased rates in South Dakota. The partial settlement also includes a moratorium on filing another general rate case in South Dakota until the new generation projects have been in service for a year. The settlement also allows OTP to retain the impact of lower tax rates related to the TCJA from January 1, 2018 through October 17, 2018 resulting in the reversal of an accrued refund liability and recognition of $1.0 million in revenue in the first quarter of 2019. OTP expects a final determination on its allowed rate of ROE sometime during the second quarter of 2019.

 

OTP’s previously approved general rate increase in South Dakota of approximately $643,000 or approximately 2.32% was granted by the SDPUC in an order issued in April 2011 and effective in June 2011. Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.50%.

 

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 8, 2019 the SDPUC approved the supplemental filing and rates effective March 1, 2019. Two new projects were approved for recovery under the rider: The Lake Norden area transmission upgrade project with a recovery date effective January 1, 2019 and The Big Stone South – Ellendale project with a recovery date effective January 2020.

 

Environmental Cost Recovery Rider—OTP has an ECR rider in South Dakota. The ECR rider provides for a return on investment at the level approved in OTP’s most recent general rate case and for recovery of OTP’s South Dakota share of environmental investments and costs approved for recovery under the rider. Prior to interim rates going into effect on October 18, 2018 pending a final decision on OTP’s South Dakota general rate increase request, OTP’s South Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant Mercury and Air Toxics Standards projects were being recovered through the ECR rider. With the initiation of interim rates, recovery of the costs previously being recovered under the ECR rider was transitioned to recovery under interim rates and the South Dakota ECR rider rate was reset to provide a refund to customers while interim rates are in effect.

 

18

 

Rate Rider Updates

 

The following table provides summary information on the status of updates since January 1, 2017 for the rate riders described above:

 

 

Rate Rider

R - Request Date

A - Approval Date

Effective Date

Requested or

Approved

 

Annual

Revenue

($000s)

 

Rate

Minnesota

             

Conservation Improvement Program

             

2018 Incentive and Cost Recovery

R – April 1, 2019

October 1, 2019

  $ 11,926  

$0.00710/kwh

2017 Incentive and Cost Recovery

A – October 4, 2018

November 1, 2018

  $ 10,283  

$0.00600/kwh

2016 Incentive and Cost Recovery

A – September 15, 2017

October 1, 2017

  $ 9,868  

$0.00536/kwh

Transmission Cost Recovery

             

2018 Annual Update–Scenario A

R – November 30, 2018

June 1, 2019

  $ 6,475  

Various

–Scenario B

  $ 2,708  

Various

2017 Rate Reset

A – October 30, 2017

November 1, 2017

  $ (3,311 )

Various

Environmental Cost Recovery

             

2018 Annual Update

A – November 29, 2018

December 1, 2018

  $ --  

0% of base

2017 Rate Reset

A – October 30, 2017

November 1, 2017

  $ (1,943 )

-0.935% of base

Renewable Resource Adjustment

             

2018 Annual Update

A – August 29, 2018

November 1, 2018

  $ 5,886  

$.00244/kwh

2017 Rate Reset

A – October 30, 2017

November 1, 2017

  $ 1,279  

$.00049/kwh

North Dakota

             

Renewable Resource Adjustment

             

2019 Annual Update

A – May 1, 2019

June 1, 2019

  $ (235 )

-0.224% of base

2018 Rate Reset for effect of TCJA

A – February 27, 2018

March 1, 2018

  $ 9,650  

7.493% of base

2017 Rate Reset

A – December 20, 2017

January 1, 2018

  $ 9,989  

7.756% of base

Transmission Cost Recovery

             

2018 Supplemental Update

A – December 6, 2018

February 1, 2019

  $ 4,801  

Various

2018 Rate Reset for effect of TCJA

A – February 27, 2018

March 1, 2018

  $ 7,469  

Various

2017 Annual Update

A – November 29, 2017

January 1, 2018

  $ 7,959  

Various

Environmental Cost Recovery

             

2018 Update

A – December 19, 2018

February 1, 2019

  $ (378 )

-0.310% of base

2018 Rate Reset for effect of TCJA

A – February 27, 2018

March 1, 2018

  $ 7,718  

5.593% of base

2017 Rate Reset

A – December 20, 2017

January 1, 2018

  $ 8,537  

6.629% of base

Generation Cost Recovery

             

2019 Initial Request

R – March 1, 2019

July 1, 2019

  $ 2,720  

2.547% of base

South Dakota

             

Transmission Cost Recovery

             

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

 

19

 

 

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 for the three-month periods ended March 31:

 

Rate Rider (in thousands)

 

2019

   

2018

 

Minnesota

               

Conservation Improvement Program Costs and Incentives1

  $ 2,152     $ 2,516  

Renewable Resource Recovery

    1,316       525  

Transmission Cost Recovery

    641       (29 )

Environmental Cost Recovery

    (1 )     (31 )

North Dakota

               

Transmission Cost Recovery

    1,772       2,062  

Renewable Resource Adjustment

    729       1,967  

Environmental Cost Recovery

    575       1,821  

Generation Cost Recovery

    248       --  

South Dakota

               

Transmission Cost Recovery

    473       536  

Conservation Improvement Program Costs and Incentives

    244       229  

Environmental Cost Recovery

    (4 )     520  

Total

  $ 8,145     $ 10,116  

1Includes MNCIP costs recovered in base rates.

 

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. OTP expects the rate change to occur in the second quarter of 2019 and a one-time refund to occur in the third quarter of 2019, pending MPUC approval of OTP’s January 3, 2019 compliance filing.

 

As described above, OTP’s current general rate cases in North Dakota and South Dakota reflect the ongoing impact of the TCJA in interim rates. OTP has 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 incurs under the lower federal tax rates in the TCJA. As of March 31, 2019, accrued refund liabilities related to the tax rate reduction were $10.4 million in Minnesota, $0.8 million in North Dakota for amounts collected reflecting the higher tax rates under interim rates in effect in January and February 2018, and $0.3 million for FERC jurisdictional rates. The North Dakota liability was refunded with the interim rate refund in April 2019.

 

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.

 

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.

 

20

 

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.

 

On November 12, 2013 a group of industrial customers and other 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. The complainants sought to reduce 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 the base ROE at 10.32%. Several parties requested rehearing of the September 2016 order and the requests are pending FERC action.

 

On November 6, 2014 a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional 50 basis points for Regional Transmission Organization participation (RTO Adder). On January 5, 2015 the FERC granted the request, deferring collection of the RTO Adder until the FERC issued its order in the ROE complaint proceeding. Based on the FERC adjustment to the MISO Tariff ROE resulting from the November 12, 2013 complaint and OTP’s incentive rate filing, OTP’s ROE went to 10.82% (a 10.32% base ROE plus the 0.5% RTO Adder) effective September 28, 2016.

 

On February 12, 2015 another group of stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff from 12.38% to a proposed 8.67%. This second complaint established a second 15-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 first 15-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 March 31, 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; however, the Company expects FERC to issue an order in the third or fourth quarter of 2019.

 

OTP believes its estimated accrued MISO Tariff ROE refund liability of $1.6 million as of March 31, 2019 related to the second MISO tariff ROE complaint is appropriate.

 

21

 

 

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:

 

   

March 31, 2019

   

Remaining

Recovery/

 

(in thousands)

 

Current

   

Long-Term

   

Total

   

Refund Period

(months)

 

Regulatory Assets:

                               

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

  $ 6,355     $ 116,835     $ 123,190    

see below

 

Accumulated ARO Accretion/Depreciation Adjustment1

    --       7,302       7,302    

asset lives

 

Conservation Improvement Program Costs and Incentives2

    3,007       3,979       6,986       18  

Deferred Marked-to-Market Losses1

    1,432       557       1,989       21  

Minnesota Transmission Cost Recovery Rider Accrued Revenues2

    1,958       --       1,958       12  

Deferred Income Taxes1

    --       1,557       1,557    

asset lives

 

Big Stone II Unrecovered Project Costs – Minnesota1

    689       770       1,459       25  

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

    --       1,143       1,143    

asset lives

 

Debt Reacquisition Premiums1

    203       701       904       162  

North Dakota Deferred Rate Case Expenses Subject to Recovery1

    416       --       416       12  

Big Stone II Unrecovered Project Costs – South Dakota1

    117       292       409       42  

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

    180       130       310       33  

South Dakota Deferred Rate Case Expenses Subject to Recovery1

    267       --       267       12  

North Dakota Generation Cost Recovery Rider Accrued Revenues2

    248       --       248       12  

Recoverable Fuel and Purchased Power Costs – South Dakota1

    197       --       197       12  

Minnesota SPP Transmission Cost Recovery Tracker1

    --       117       117    

see below

 

Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues1

    52       --       52       4  

Deferred Lease Expenses1

    --       44       44       48  

Minnesota Environmental Cost Recovery Rider Accrued Revenues2

    38       --       38       12  

Minnesota Renewable Resource Recovery Rider Accrued Revenues2

    34       --       34       12  

Total Regulatory Assets

  $ 15,193     $ 133,427     $ 148,620          

Regulatory Liabilities:

                               

Deferred Income Taxes

  $ --     $ 141,452     $ 141,452    

asset lives

 

Accumulated Reserve for Estimated Removal Costs – Net of Salvage

    --       83,555       83,555    

asset lives

 

Refundable Fuel Clause Adjustment Revenues – Minnesota

    5,149       --       5,149       12  

North Dakota Renewable Resource Recovery Rider Accrued Refund

    901       --       901       12  

North Dakota Environmental Cost Recovery Rider Accrued Refund

    669       --       669       12  

Refundable Fuel Clause Adjustment Revenues – North Dakota

    537       --       537       12  

North Dakota Transmission Cost Recovery Rider Accrued Refund

    272       --       272       12  

Revenue for Rate Case Expenses Subject to Refund – Minnesota

    --       225       225    

see below

 

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

    --       187       187       21  

South Dakota Transmission Cost Recovery Rider Accrued Refund

    151       --       151       12  

South Dakota Environmental Cost Recovery Rider Accrued Refund

    103       --       103       12  

Other

    5       77       82       177  

Total Regulatory Liabilities

  $ 7,787     $ 225,496     $ 233,283          

Net Regulatory Asset/(Liability) Position

  $ 7,406     $ (92,069 )   $ (84,663 )        

 

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.

 

22

 

   

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  

Deferred Marked-to-Market Losses1

    1,661       743       2,404       24  

Minnesota Transmission Cost Recovery Rider Accrued Revenues2

    444       --       444       12  

Deferred Income Taxes1

    --       2,423       2,423    

asset lives

 

Big Stone II Unrecovered Project Costs – Minnesota1

    681       947       1,628       28  

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

    --       986       986    

asset lives

 

Debt Reacquisition Premiums1

    207       753       960       165  

North Dakota Deferred Rate Case Expenses Subject to Recovery1

    455       --       455       12  

Big Stone II Unrecovered Project Costs – South Dakota1

    100       342       442       53  

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  

Minnesota SPP Transmission Cost Recovery Tracker1

    --       176       176    

see below

 

Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues1

    328       --       328       4  

Minnesota Environmental Cost Recovery Rider Accrued Revenues2

    121       --       121       12  

Minnesota Renewable Resource Recovery Rider Accrued Revenues2

    452       --       452       12  

North Dakota Environmental Cost Recovery Rider Accrued Revenues2

    17       --       17       12  

Total Regulatory Assets

  $ 17,225     $ 135,257     $ 152,482          

Regulatory Liabilities:

                               

Deferred Income Taxes

  $ --     $ 142,779     $ 142,779    

asset lives

 

Accumulated Reserve for Estimated Removal Costs – Net of Salvage

    --       83,229       83,229    

asset lives

 

North Dakota Renewable Resource Recovery Rider Accrued Refund

    177       --       177       12  

North Dakota Transmission Cost Recovery Rider Accrued Refund

    60       --       60       12  

Revenue for Rate Case Expenses Subject to Refund – Minnesota

    --       166       166    

see below

 

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

    --       187       187       24  

South Dakota Transmission Cost Recovery Rider Accrued Refund

    168       --       168       12  

South Dakota Environmental Cost Recovery Rider Accrued Refund

    207       --       207       12  

Refundable Fuel Clause Adjustment Revenues

    121       --       121       12  

Other

    5       108       113       180  

Total Regulatory Liabilities

  $ 738     $ 226,469     $ 227,207          

Net Regulatory Asset/(Liability) Position

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

 

1Costs subject to recovery without a rate of return.

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

 

The regulatory asset related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. These unrecognized benefit costs and actuarial losses 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 based on their probable recovery in future retail electric rates.

 

The Accumulated Asset Retirement Obligation (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.

 

All Deferred Marked-to-Market Losses recorded as of March 31, 2019 relate to forward purchases of energy scheduled for delivery through December 2020.

 

23

 

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 are recoverable from Minnesota customers as of March 31, 2019.

 

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.

 

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.

 

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.

 

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 162 months.

 

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

 

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.

 

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

 

North Dakota Generation Cost Recovery (NDGCR) Rider Accrued Revenues relate to revenues earned on the North Dakota share of OTP’s investment in Astoria Station, a natural gas-fired combustion turbine generation facility under construction near Astoria, South Dakota. The March 31, 2019 balance represents amounts subject to recovery from North Dakota customers that have not been billed to North Dakota customers. The NDGCR is expected to go into effect in July 2019 pending NDPSC review and approval.

 

The Minnesota SPP Transmission Cost Recovery Tracker regulatory asset relates to costs incurred to serve Minnesota customers that are subject to recovery but that have not been billed to Minnesota customers as of March 31, 2019.

 

Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues relate to revenues recorded for fuel and purchased power costs reductions provided to customers in energy intensive trade exposed industries that are subject to recovery from other Minnesota customers.

 

Deferred Lease Expenses: Under ASC 842 accounting rules, for leases with scheduled escalating payments, rent expense is required to be recognized on a straight-line basis over the life of the lease based on the sum of those payments. Rate-regulated entities are generally only allowed to recover the amount of actual cash payments on leases and FERC accounting rules require that rent expense be recognized on the basis of cash payments. The balance in the deferred lease expense regulatory asset account on March 31, 2019 represents operating lease right of use asset cumulative amortization and interest costs in excess of cumulative lease payments that are subject to recovery in future periods under regulatory account treatment as cash payments are rendered.

 

The Minnesota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS project that are recoverable from Minnesota customers as of March 31, 2019.

 

The Minnesota Renewable Resource Recovery Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that are recoverable from Minnesota customers as of March 31, 2019. Currently, the rider is only being used to recover the amount of federal PTCs generated by OTP’s wind farms that were transferred from inclusion in the rider and applied as a reduction in revenue requirements to Minnesota base rates. Subsequent to applying the PTCs to base rates the PTCs expired. The Minnesota RRA rider is now being used to recover the shortfall in 

 

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base rates related to the expiration of the PTCs. Recovery will continue through the rider until interim or revised base rates are established in connection with OTP’s next Minnesota rate case.

 

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 are recoverable from North Dakota customers as of March 31, 2019.

 

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

 

North Dakota Renewable Resource Recovery Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of March 31, 2019.

 

The North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to North Dakota customers as of March 31, 2019. Effective February 1, 2019 these rate base investments are being recovered under general rates and the rider was zeroed out except for an overcollection balance that will be refunded to Minnesota ratepayers through the rider.

 

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 are refundable to North Dakota customers as of March 31, 2019.

 

Revenue for Rate Case Expenses Subject to Refund – Minnesota relates to revenues collected under general rates to recover costs related to prior rate case proceedings in excess of the actual costs incurred.

 

The South Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that are refundable to South Dakota customers as of March 31, 2019.

 

The South Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the South Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to South Dakota customers as of March 31, 2019.

 

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.

 

Common Shares

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2018 through March 31, 2019:

 

Common Shares Outstanding, December 31, 2018

    39,664,884  

Issuances:

       

Executive Stock Performance Awards (2016 shares earned)

    102,198  

Vesting of Restricted Stock Units

    17,850  

Retirements:

       

Shares Withheld for Individual Income Tax Requirements

    (55,224 )

Common Shares Outstanding, March 31, 2019

    39,729,708  

 

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Earnings Per Share

The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three-month periods ended March 31, 2019 and 2018. 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 and employees, which are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share. The denominator used in the calculation of diluted earnings per common share is derived by adjusting basic shares outstanding for the items listed in the following reconciliation for the three-month periods ended March 31:

 

   

2019

   

2018

 

Weighted Average Common Shares Outstanding – Basic

    39,657,321       39,550,874  

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

    158,159       223,162  

Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees

    63,398       59,130  

Nonvested Restricted Shares

    21,922       27,643  

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

    2,365       2,873  

Total Dilutive Shares

    245,844       312,808  

Weighted Average Common Shares Outstanding – Diluted

    39,903,165       39,863,682  

 

The effect of dilutive shares on earnings per share for the three-month periods ended March 31, 2019 and 2018, resulted in no differences greater than $0.01 between basic and diluted earnings per share in either period.

 

 

6. Share-Based Payments

 

Stock Incentive Awards

On February 13, 2019 the following stock incentive awards were granted under the 2014 Stock Incentive Plan:

 

Award

 

Shares/Units

Granted

   

Weighted

Average Grant-

Date Fair Value

per Award

 

Vesting

Restricted Stock Units Granted

    15,600     $ 49.6225  

25% per year through February 6, 2023

Stock Performance Awards Granted:

                 

Under Executive and Select Employee Agreements

    47,800     $ 42.875  

December 31, 2021

Under Legacy Agreement

    7,800     $ 45.885  

December 31, 2021

 

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. All restricted stock units granted to executive officers 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. The grant-date fair value of each restricted stock unit was the average of the high and low market price per share on the date of grant.

 

Under the performance share awards the aggregate award for performance at target is 55,600 shares. For target performance the participants would earn an aggregate of 27,800 common shares for achieving the target set for the Company’s 3-year average adjusted ROE. The participants would also earn an aggregate of 27,800 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, 2019 through December 31, 2021, 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, 2019 and the average closing price for the 20 trading days immediately preceding January 1, 2022. Actual payment may range from zero to 150% of the target amount, or up to 83,400 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.

 

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Under the 2019 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 end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the earlier of the indicated vesting period for the respective awards or the date the grantee becomes eligible for retirement as defined in their award agreement.

 

As of March 31, 2019, the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $6.2 million (before income taxes) which will be amortized over a weighted-average period of 2.2 years.

 

Amounts of compensation expense recognized under the Company’s stock-based payment programs for the three-month periods ended March 31, 2019 and 2018 are presented in the table below:

 

   

Three months ended

 
   

March 31,

 

(in thousands)

 

2019

   

2018

 

Stock Performance Awards Granted to Executive Officers

  $ 1,113     $ 651  

Restricted Stock Units Granted to Executive Officers

    427       249  

Restricted Stock Granted to Executive Officers

    --       16  

Restricted Stock Granted to Directors

    165       166  

Restricted Stock Units Granted to Non-Executive Employees

    91       64  

Totals

  $ 1,796     $ 1, 146  

 

 

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 March 31, 2019, the Company was in compliance with these financial covenants.

 

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

 

The MPUC indirectly limits the amount of dividends OTP can pay to the Company by requiring an equity-to-total-capitalization ratio between 47.9% and 58.5% based on OTP’s 2018 capital structure petition effective by order of the MPUC on October 18, 2018. As of March 31, 2019, OTP’s equity-to-total-capitalization ratio including short-term debt was 53.2% and its net assets restricted from distribution totaled approximately $484 million. Total capitalization for OTP cannot currently exceed $1.2 billion.

 

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8. Leases 

 

The Company adopted ASU 2016-02 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 sheet for all leases with terms longer than 12 months. Adoption of the standard resulted in the recognition of net lease assets and lease liabilities of $20 million on January 1, 2019. The adoption of the new standard did not have a material effect on the Company’s consolidated statements of income or cash flows. In addition, the adoption did not have a material impact on the Company’s liquidity or the Company’s covenant compliance under its current debt agreements.

 

The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allows for the carry forward of lease classifications determined under the requirements of ASC Topic 840. The Company also elected the practical expedient related to land easements, allowing for the continuation of historical accounting treatment for land easements on existing agreements at OTP. In addition, the Company has elected the hindsight practical expedient to determine the reasonably certain lease term for leases in place at the time of adoption. The Company has elected the practical expedient to not separate nonlease components from lease components on real estate leases for the purpose of determining the classification and the value of lease assets and lease liabilities at the inception of a lease.

 

The Company enters into leases for coal rail cars, warehouse and office space, land and certain office, manufacturing and material handling equipment under varying terms and conditions. The lengths of the leases vary from less than one year to approximately 10 years. If a lease contains an option to extend and there is reasonable certainty the option will be exercised, the option is considered in the lease term at inception. None of these leases met the criteria to be classified as financing leases. Of the operating leases in place on January 1, 2019, 50 were capitalized as right-of-use assets 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 March 31, 2019 by business segment is provided in the following table.

 

(in thousands)

 

Electric

   

Manufacturing

   

Plastics

   

Corporate

   

Total

 

Right of Use Assets – Operating Leases:

                                       

Gross

  $ 3,421     $ 16,976     $ 666     $ 767     $ 21,830  

Accumulated Amortization

    (257 )     (734 )     (97 )     (30 )     (1,118 )

Net of Accumulated Amortization

  $ 3,164     $ 16,242     $ 569     $ 737     $ 20,712  

Obligations:

                                       

Current Operating Lease Liabilities

  $ 913     $ 2,458     $ 379     $ 150     $ 3,900  

Long-Term Operating Lease Liabilities

    2,470       13,852       190       648       17,160  

Total Lease Liabilities

  $ 3,383     $ 16,310     $ 569     $ 798     $ 21,060  

 

 

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The amounts of the Company’s right-of-use operating lease obligations for each of the five years in the period 2019 through 2023 and in aggregate for the years beyond 2023 are presented in the following table, including obligations under lease agreements that had not commenced as of March 31, 2019.

 

 

 

Right-of-Use Operating Leases

 
(in thousands)  

OTP

   

Nonelectric

   

Total

 

2019

  $ 845     $ 3,078     $ 3,923  

2020

    1,115       3,948       5,063  

2021

    1,091       3,657       4,748  

2022

    207       3,529       3,736  

2023

    196       3,209       3,405  

Beyond 2023

    447       8,023       8,470  

Total Minimum Obligations

  $ 3,901     $ 25,443     $ 29,344  

Interest Component of Obligations

    (355 )     (4,376 )     (4,731 )

Present Value of Leases Commencing after March 31, 2019

    (163 )     (3,390 )     (3,553 )