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

ottr20180331_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, 2018

 

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)

 

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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 ☐
(Do not check if a smaller reporting 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, 2018 39,651,236 Common Shares ($5 par value)

 

 

 

 

OTTER TAIL CORPORATION

 

INDEX

 

Part I. Financial Information

Page No.

   

Item 1.

Financial Statements

 
     
 

Consolidated Balance Sheets – March 31, 2018 and December 31, 2017 (not audited)

2 & 3

     
 

Consolidated Statements of Income - Three Months Ended March 31, 2018 and 2017 (not audited)

4

     
 

Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2018 and 2017 (not audited)

5

     
 

Consolidated Statements of Cash Flows - Three Months Ended March 31, 2018 and 2017 (not audited)

6

     
 

Condensed Notes to Consolidated Financial Statements (not audited)

7-32

     

Item 2.

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

33-46

     

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

46

     

Item 4.

Controls and Procedures

46

     

Part II. Other Information

 
     

Item 1.

Legal Proceedings

47

     

Item 1A.

Risk Factors 

47

     

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds 

47

     

Item 6.

Exhibits

47

     

Signatures

48

 

1

 

 

 

PART I. FINANCIAL INFORMATION

 

Item 1. financial statements

 

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

 

(in thousands)

 

March 31,

2018

   

December 31,

2017

 
                 

Assets

               
                 

Current Assets

               

Cash and Cash Equivalents

  $ 1,121     $ 16,216  

Accounts Receivable:

               

Trade—Net

    94,265       68,466  

Other

    7,109       7,761  

Inventories

    87,999       88,034  

Unbilled Receivables

    18,692       22,427  

Income Taxes Receivable

    --       1,181  

Regulatory Assets

    19,736       22,551  

Other

    11,210       12,491  

Total Current Assets

    240,132       239,127  
                 

Investments

    8,648       8,629  

Other Assets

    35,763       36,006  

Goodwill

    37,572       37,572  

Other IntangiblesNet

    13,420       13,765  

Regulatory Assets

    125,667       129,576  
                 

Plant

               

Electric Plant in Service

    1,986,385       1,981,018  

Nonelectric Operations

    219,942       216,937  

Construction Work in Progress

    153,963       141,067  

Total Gross Plant

    2,360,290       2,339,022  

Less Accumulated Depreciation and Amortization

    814,074       799,419  

Net Plant

    1,546,216       1,539,603  

Total Assets

  $ 2,007,418     $ 2,004,278  

 

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,

2018

   

December 31,

2017

 
                 

Liabilities and Equity

               
                 

Current Liabilities

               

Short-Term Debt

  $ 30,319     $ 112,371  

Current Maturities of Long-Term Debt

    171       186  

Accounts Payable

    87,179       84,185  

Accrued Salaries and Wages

    14,806       21,534  

Accrued Federal and State Income Taxes

    984       --  

Accrued Taxes

    17,585       16,808  

Regulatory Liabilities

    5,119       9,688  

Other Accrued Liabilities

    9,940       11,389  

Liabilities of Discontinued Operations

    --       492  

Total Current Liabilities

    166,103       256,653  
                 

Pensions Benefit Liability

    89,552       109,708  

Other Postretirement Benefits Liability

    70,040       69,774  

Other Noncurrent Liabilities

    23,482       22,769  
                 

Commitments and Contingencies (note 8)

               
                 

Deferred Credits

               

Deferred Income Taxes

    103,009       100,501  

Deferred Tax Credits

    21,025       21,379  

Regulatory Liabilities

    233,279       232,893  

Other

    2,935       3,329  

Total Deferred Credits

    360,248       358,102  
                 

Capitalization

               

Long-Term Debt—Net

    589,943       490,380  
                 

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, 2018—39,626,594 Shares; 2017—39,557,491 Shares

    198,133       197,787  

Premium on Common Shares

    341,841       343,450  

Retained Earnings

    174,209       161,286  

Accumulated Other Comprehensive Loss

    (6,133 )     (5,631 )

Total Common Equity

    708,050       696,892  

Total Capitalization

    1,297,993       1,187,272  

Total Liabilities and Equity

  $ 2,007,418     $ 2,004,278  

 

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)

 

2018

   

2017

 
                 

Operating Revenues

               

Electric:

               

Revenues from Contracts with Customers

  $ 123,825     $ 119,782  

Changes in Accrued Revenues under Alternative Revenue Programs

    (875 )     (1,239 )

Total Electric Revenues

    122,950       118,543  

Product Sales under Contracts with Customers

    118,316       95,574  

Total Operating Revenues

    241,266       214,117  
                 

Operating Expenses

               

Production Fuel – Electric

    18,706       16,382  

Purchased Power - Electric

    21,593       19,188  

Electric Operation and Maintenance Expenses

    39,475       37,277  

Cost of Products Sold (depreciation included below)

    88,785       75,277  

Other Nonelectric Expenses

    12,494       10,135  

Depreciation and Amortization

    18,763       17,854  

Property Taxes – Electric

    3,835       3,798  

Total Operating Expenses

    203,651       179,911  
                 

Operating Income

    37,615       34,206  
                 

Interest Charges

    7,372       7,462  

Nonservice Cost Components of Postretirement Benefits

    1,417       1,405  

Other Income

    1,183       553  

Income Before Income TaxesContinuing Operations

    30,009       25,892  

Income Tax Expense – Continuing Operations

    3,794       6,363  

Net Income from Continuing Operations

    26,215       19,529  

Income from Discontinued Operations net of Income Tax Expense of $38 in 2017

    --       56  

Net Income

  $ 26,215     $ 19,585  
                 

Average Number of Common Shares Outstanding—Basic

    39,550,874       39,350,802  

Average Number of Common Shares Outstanding—Diluted

    39,863,682       39,640,725  
                 

Basic Earnings Per Common Share:

               

Continuing Operations

  $ 0.66     $ 0.50  

Discontinued Operations

    --       --  
    $ 0.66     $ 0.50  

Diluted Earnings Per Common Share:

               

Continuing Operations

  $ 0.66     $ 0.49  

Discontinued Operations

    --       --  
    $ 0.66     $ 0.49  
                 

Dividends Declared Per Common Share

  $ 0.335     $ 0.320  

 

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)

 

2018

   

2017

 

Net Income

  $ 26,215     $ 19,585  

Other Comprehensive (Loss) Income:

               

Unrealized Gains on Available-for-Sale Securities:

               

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

    (110 )     --  

Unrealized (Losses) Gains Arising During Period

    (66 )     17  

Income Tax Benefit (Expense)

    37       (6 )

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

    (139 )     11  

Pension and Postretirement Benefit Plans:

               

Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 10)

    227       157  

Income Tax Expense

    (59 )     (63 )

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

    (531 )     --  

Pension and Postretirement Benefit Plans – net-of-tax

    (363 )     94  

Total Other Comprehensive (Loss) Income

    (502 )     105  

Total Comprehensive Income

  $ 25,713     $ 19,690  

 

See accompanying condensed notes to consolidated financial statements.

 

5

Table of Contents

 

 

Otter Tail Corporation

Consolidated Statements of Cash Flows

(not audited)

 

   

Three Months Ended

March 31,

 

(in thousands)

 

2018

   

2017

 

Cash Flows from Operating Activities

               

Net Income

  $ 26,215     $ 19,585  

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

               

Net Income from Discontinued Operations

    --       (56 )

Depreciation and Amortization

    18,763       17,854  

Deferred Tax Credits

    (354 )     (366 )

Deferred Income Taxes

    2,901       4,512  

Change in Deferred Debits and Other Assets

    6,295       5,005  

Discretionary Contribution to Pension Plan

    (20,000 )     --  

Change in Noncurrent Liabilities and Deferred Credits

    (5,091 )     1,314  

Allowance for Equity/Other Funds Used During Construction

    (638 )     (170 )

Stock Compensation Expense—Equity Awards

    1,146       1,150  

Other—Net

    (284 )     (5 )

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

               

Change in Receivables

    (25,047 )     (15,521 )

Change in Inventories

    35       2,267  

Change in Other Current Assets

    2,334       (22 )

Change in Payables and Other Current Liabilities

    (2,598 )     (13,986 )

Change in Interest and Income Taxes Receivable/Payable

    1,163       (321 )

Net Cash Provided by Continuing Operations

    4,840       21,240  

Net Cash Used in Discontinued Operations

    (200 )     (39 )

Net Cash Provided by Operating Activities

    4,640       21,201  

Cash Flows from Investing Activities

               

Capital Expenditures

    (23,618 )     (30,113 )

Net Proceeds from Disposal of Noncurrent Assets

    510       612  

Cash Used for Investments and Other Assets

    (719 )     (508 )

Net Cash Used in Investing Activities

    (23,827 )     (30,009 )

Cash Flows from Financing Activities

               

Change in Checks Written in Excess of Cash

    2,338       7,999  

Net Short-Term (Repayments) Borrowings

    (82,052 )     16,293  

Proceeds from Issuance of Common Stock – net of Issuance Expenses

    --       1,958  

Payments for Retirement of Capital Stock

    (2,409 )     (1,759 )

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

    (60 )     (3,057 )

Dividends Paid

    (13,292 )     (12,626 )

Net Cash Provided by Financing Activities

    4,092       8,808  

Net Change in Cash and Cash Equivalents

    (15,095 )     --  

Cash and Cash Equivalents at Beginning of Period

    16,216       --  

Cash and Cash Equivalents at End of Period

  $ 1,121     $ --  

 

See accompanying condensed notes to consolidated financial statements.

 

6

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, 2017. Because of seasonal and other factors, the earnings for the three months ended March 31, 2018 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, 2017.

 

 

1. Summary of Significant Accounting Policies

 

Revenue Recognition

In May 2014 the Financial Accounting Standards Board (FASB) issued a major update to the Accounting Standards Codification (ASC), Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606). The Company adopted the updates in ASC 606 effective January 1, 2018 on a modified retrospective basis but did not record a cumulative effect adjustment to retained earnings on application of the updates because the adoption of the updates in ASC 606 had no material impact on the timing of revenue recognition for the Company or its subsidiaries. ASC 606 is a comprehensive, principles-based accounting standard which amends current revenue recognition guidance with the objective of improving revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and the timing of revenue recognition. ASC 606 also requires expanded disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

 

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. Based on review of the Company’s revenue streams, the Company has not identified any contracts where the timing of revenue recognition will change as a result of the adoption of the updates in ASC 606. 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 ASC 606, the Company also records adjustments to Electric segment revenues for amounts subject to future collection or refund 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 or refundable under ARPs.

 

Most Electric segment revenues are earned from the generation, transmission and sale of electricity to retail customers at rates approved by regulatory commissions in the states where Otter Tail Power Company (OTP) provides service. OTP also earns revenue from the transmission of electricity for others over the transmission assets it owns separately or jointly with other transmission service providers under rate tariffs established by the independent transmission system operator and approved by the Federal Energy Regulatory Commission (FERC). A third source of revenue for OTP comes from the generation and sale of electricity to wholesale customers at contract or market rates. Revenues from all these sources meet the criteria to be classified as revenue from contracts with customers and are recognized over time as energy is delivered or transmitted. Revenue is recognized based on the metered quantity of electricity delivered or transmitted at the applicable rates. For electricity delivered and consumed after a meter is read but prior to the end of the reporting period, OTP records revenue and an unbilled receivable based on estimates of the kilowatt-hours (kwh) of energy delivered to the customer.

 

7

 

ARPs provide for adjustments to rates outside of a general rate case proceeding, usually as a surcharge applied to future billings typically through the use of rate riders subject to periodic adjustments, to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. ARP riders generally provide for the recovery of specified costs and investments and include an incentive component to provide the regulated utility with a return on amounts invested. OTP currently is recovering costs and earning 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 (CIP) riders.

 

In North Dakota: TCR, ECR and RRA 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. Amounts accrued and subject to future recovery, or amounts billed that are subject to refund, 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, 2018 and 2017.

 

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 the customers 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 and adjusts the revenue for volume rebate variable pricing considerations the company expects the customer will earn and applicable early payment discounts the company expects the customer will take. For revenue recognized on products when shipped, the operating companies have no further obligation to provide services related to such product. 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. Billed amounts of revenue recognized are adjusted 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. 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 to consolidated financial statements for a disaggregation of the Company’s revenues by business segment for the three-month periods ended March 31, 2018 and 2017.

 

Agreements Subject to Legally Enforceable Netting Arrangements

OTP has certain derivative contracts that are designated as normal purchases and carried at historical cost in the accompanying balance sheet. 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. 

 

8

 

Fair Value Measurements

The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (ASC 820), for recurring fair value measurements. ASC 820 provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the hierarchy and examples of each level are as follows:

 

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange.

 

Level 2 – Pricing inputs are other than quoted prices in active markets but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

 

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

 

The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2018 and December 31, 2017:

 

March 31, 2018 (in thousands)

 

Level 1

   

Level 2

   

Level 3

 

Assets:

                       

Investments:

                       

Equity Funds – Held by Captive Insurance Company

  $ 1,220                  

Corporate Debt Securities – Held by Captive Insurance Company

          $ 5,341          

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

            1,779          

Other Assets:

                       

Money Market and Mutual Funds – Nonqualified Retirement Savings Plan

    870                  

Total Assets

  $ 2,090     $ 7,120          

 

December 31, 2017 (in thousands)

 

Level 1

   

Level 2

   

Level 3

 

Assets:

                       

Investments:

                       

Equity Funds – Held by Captive Insurance Company

  $ 1,285                  

Corporate Debt Securities – Held by Captive Insurance Company

          $ 5,373          

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

            1,787          

Other Assets:

                       

Money Market and Mutual Funds – Nonqualified Retirement Savings Plan

    823                  

Total Assets

  $ 2,108     $ 7,160          

 

The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows:

 

Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company – Fair values 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.

 

9

 

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, 2018 could be as high as $56.5 million, OTP’s 35% share of unrecovered costs.

 

Inventories

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

 

   

March 31,

   

December 31,

 

(in thousands)

 

2018

   

2017

 

Finished Goods

  $ 25,341     $ 26,605  

Work in Process

    17,224       14,222  

Raw Material, Fuel and Supplies

    45,434       47,207  

Total Inventories

  $ 87,999     $ 88,034  

 

Goodwill and Other Intangible Assets

 

An assessment of the carrying amounts of goodwill of the Company’s operating units as of December 31, 2017 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 2018:

 

 

(in thousands)

 

Gross Balance

December 31, 2017

   

Accumulated

Impairments

   

Balance

(net of impairments)

December 31, 2017

   

Adjustments to

Goodwill in

2018

   

Balance

(net of impairments)

March 31, 2018

 

Manufacturing

  $ 18,270     $ --     $ 18,270     $ --     $ 18,270  

Plastics

    19,302       --       19,302       --       19,302  

Total

  $ 37,572     $ --     $ 37,572     $ --     $ 37,572  

 

10

 

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, 2018 and December 31, 2017:

 

March 31, 2018 (in thousands)

 

Gross Carrying

Amount

   

Accumulated

Amortization

   

Net Carrying

Amount

   

Remaining

Amortization

Periods (months)

 

Amortizable Intangible Assets:

                                 

Customer Relationships

  $ 22,491     $ 9,277     $ 13,214      21 - 209  

Covenant not to Compete

    590       508       82       5    

Other

    154       30       124       29    

Total

  $ 23,235     $ 9,815     $ 13,420            

 

December 31, 2017 (in thousands)

 

Gross Carrying

Amount

   

Accumulated

Amortization

   

Net Carrying

Amount

   

Remaining

Amortization

Periods (months)

 

Amortizable Intangible Assets:

                                 

Customer Relationships

  $ 22,491     $ 8,994     $ 13,497      24 - 212  

Covenant not to Compete

    590       459       131       8    

Other

    154       17       137       32    

Total

  $ 23,235     $ 9,470     $ 13,765            

 

The amortization expense for these intangible assets was:

 

   

Three Months Ended

 
   

March 31,

 

(in thousands)

 

2018

   

2017

 

Amortization Expense – Intangible Assets

  $ 345     $ 332  

 

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

 

(in thousands)

 

2018

   

2019

   

2020

   

2021

   

2022

 

Estimated Amortization Expense – Intangible Assets

  $ 1,315     $ 1,184     $ 1,133     $ 1,099     $ 1,099  

 

Supplemental Disclosures of Cash Flow Information

 

   

As of March 31,

 

(in thousands)

 

2018

   

2017

 

Noncash Investing Activities:

               

Transactions Related to Capital Additions not Settled in Cash

  $ 10,451     $ 10,811  

 

New Accounting Standards Adopted

 

ASU 2014-09—In May 2014 the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). The Company adopted the updates in ASC 606 effective January 1, 2018 on a modified retrospective basis. See disclosures above under Revenue Recognition.

 

ASU 2016-01—In January 2016 the FASB issued ASU No. 2016-01, Financial Instruments—Overall (Subtopic 825-10) (ASU 2016-01). The amendments in ASU 2016-01 address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments and require equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. For the Company, the amendments in ASU 2016-01are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The Company adopted the updates in ASU 2016-01 in the first quarter of 2018, which resulted in changes in the fair value of equity instruments held as investments by the Company’s captive insurance company being classified in net income. The fair value of equity instruments held by the Company’s captive insurance company on March 31, 2018 were $1,220,000 and the amount of unrealized gains on those investments recorded in net income in the first quarter of 2018 was $87,000.

 

11

 

ASU 2017-07—In March 2017 the FASB issued ASU No. 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07), with the intent of improving the presentation of net periodic pension cost and net periodic postretirement benefit cost. ASC Topic 715, Compensation—Retirement Benefits (ASC 715), does not prescribe where the amount of net benefit cost should be presented in an employer’s income statement and does not require entities to disclose by line item the amount of net benefit cost that is included in the income statement or capitalized in assets. The amendments in ASU 2017-07 require that an employer report the service cost component of periodic benefit costs in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period, which the Company has provided in the electric operation and maintenance and other nonelectric expense lines on its income statement. The other components of net benefit cost as defined in ASC 715 are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The Company has provided the amount of the non-service cost components of net periodic postretirement benefit costs in a separate line below interest expense on the face of its consolidated income statement. The amendments in ASU 2017-07 also allow only the service cost component to be eligible for capitalization when applicable (for example, as a cost of internally manufactured inventory or a self-constructed asset). The amendments in ASU 2017-07 are effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The amendments have been applied retrospectively for the presentation of the service cost component and the other components of net periodic pension cost and net periodic postretirement benefit cost in the Company’s consolidated income statements and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension cost and net periodic postretirement benefit cost in assets.

 

The majority of the Company’s benefit costs to which the amendments in ASU 2017-07 apply are related to benefit plans in place at OTP, the Company’s regulated provider of electric utility services. The amendments in ASU 2017-07 deviate significantly from current prescribed ratemaking and regulatory accounting treatment of postretirement benefit costs applicable to OTP, which require the capitalization of a portion of all the components of net periodic benefit costs be included in rate base additions and provide for rate recovery of the non-capitalized portion of all the components of net periodic pension costs as recoverable operating expenses. The Company has assessed the impact adoption of the amendments in ASU 2017-07 will have on its consolidated financial statements, financial position and results of operations and OTP has established regulatory assets to reflect the effect of the required regulatory accounting treatment of the non-service cost components that cannot be capitalized to plant in service under ASU 2017-07.

 

The Company’s non-service cost components of net periodic post-retirement benefit costs that were capitalized to plant in service in 2017 that would have been recorded as regulatory assets if the amendments in ASU 2017-07 were applicable in 2017 were $0.8 million. The Company’s non-service costs components of net periodic postretirement benefit costs included in operating expense in 2017 and 2016 that will be reported in other income and deductions in the Company's 2018 annual report on Form 10-K after adoption of ASU 2017-07 were $5.6 million for 2017 and $5.1 million for 2016. Additional information on the allocation of postretirement benefit costs for the three-month periods ended March 31, 2018 and 2017 is provided in note 10 to these consolidated financial statements for the Company’s major benefit programs presented.

 

New Accounting Standards Pending Adoption

 

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 will supersede the current requirements under ASC Topic 840 on leases and require the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. Topic 842 affects any entity that enters into a lease, with some specified scope exemptions. 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. Topic 842 retains a distinction between finance leases and operating leases. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous guidance. Topic 842 also requires qualitative and specific quantitative disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. The amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in ASU 2016-02 is permitted. The Company has developed a list of all current leases outstanding and continues to review ASU 2016-02, identifying key impacts to its businesses to determine areas where the amendments in ASU 2016-02 will be applicable and is evaluating transition options. The Company does not currently plan to apply the amendments in ASU 2016-02 to its consolidated financial statements prior to 2019.

 

12

 

ASU 2017-04—In January 2017 the FASB issued ASU No. 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04), which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. In computing the implied fair value of goodwill under Step 2, an entity must perform procedures to determine the fair value at the impairment testing date of its assets and liabilities (including unrecognized assets and liabilities) following the procedure that would be required in determining the fair value of assets acquired and liabilities assumed in a business combination. Under the amendments in ASU 2017-04, an entity will perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized will not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity will consider income tax effects from any tax-deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable.

 

The amendments in ASU 2017-04 modify the concept of impairment from the condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of a reporting unit exceeds its fair value. An entity no longer will determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Because these amendments eliminate Step 2 from the goodwill impairment test, they should reduce the cost and complexity of evaluating goodwill for impairment. The amendments in ASU 2017-04 are effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017.

 

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 to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. Consequently, the amendments eliminate the stranded tax effects resulting from the 2017 Tax Cuts and Jobs Act (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. Early adoption of the amendments in ASU 2018-02 is permitted. 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 does not plan to adopt the amendments in ASU 2018-02 until the first quarter of 2019. On adoption, the Company will reclassify the $784,000 of income tax effects of the TCJA on the gross deferred tax amounts at the date of enactment of the TCJA related to items remaining in accumulated other comprehensive income from other comprehensive income to retained earnings so that the remaining gross deferred tax amounts related to items in other comprehensive income will reflect current effective tax rates.

 

 

 

2. Segment Information

 

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 makers. 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.

 

 

13

 

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

 

Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping, fabrication and painting, and production of plastic thermoformed horticultural containers, life science and industrial packaging, and material handling components. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States.

 

Plastics consists of businesses producing PVC pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the 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 (Varistar). 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.

 

No single customer accounted for over 10% of the Company’s consolidated revenues in 2017. The Electric segment has one customer that provided 11.7% of 2017 Electric segment revenues. The Manufacturing segment has one customer that manufactures and sells recreational vehicles that provided 24.3% of 2017 Manufacturing segment revenues and one customer that manufactures and sells lawn and garden equipment that provided 12.0% of 2017 Manufacturing segment revenues. The Plastics segment has two customers that individually provided 20.6% and 17.8% of 2017 Plastics 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 98.3% and 98.4% of its operating revenues for the respective three-month periods ended March 31, 2018 and 2017 came from sales within the United States.

 

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, 2018 and 2017 and total assets by business segment as of March 31, 2018 and December 31, 2017 are presented in the following tables:

 

 

Operating Revenue

 

   

Three Months Ended

 
   

March 31,

 

(in thousands)

 

2018

   

2017

 

Electric Segment:

               

Retail Sales Revenue from Contracts with Customers

  $ 109,180     $ 106,454  

Changes in Accrued ARP Revenues

    (875 )     (1,239 )

Total Retail Sales Revenue

    108,305       105,215  

Wholesale Revenues – Company Generation

    1,015       867  

Other Revenues

    13,645       12,469  

Total Electric Segment Revenues

  $ 122,965     $ 118,551  

Manufacturing Segment:

               
Metal Parts and Tooling   $ 56,927     $ 48,078  
Plastic Products     10,235       9,552  
Other     1,500       787  
Total Manufacturing Segment Revenues   $ 68,662     $ 58,417  

Plastics Segment – Sale of PVC Pipe Products

  $ 49,653     $ 37,157  

Intersegment Eliminations

  $ (14 )   $ (8 )

Total

  $ 241,266     $ 214,117  

 

14

 

Interest Charges

 

   

Three Months Ended

 
   

March 31,

 

(in thousands)

 

2018

   

2017

 

Electric

  $ 6,390     $ 6,386  

Manufacturing

    554       554  

Plastics

    150       153  

Corporate and Intersegment Eliminations

    278       369  

Total

  $ 7,372     $ 7,462  

 

 

Income Taxes

 

   

Three Months Ended

 
   

March 31,

 

(in thousands)

 

2018

   

2017

 

Electric

  $ 2,098     $ 6,062  

Manufacturing

    1,223       1,055  

Plastics

    2,414       1,390  

Corporate

    (1,941 )     (2,144 )

Total

  $ 3,794     $ 6,363  

 

 

Net Income (Loss)

 

   

Three Months Ended

 
   

March 31,

 

(in thousands)

 

2018

   

2017

 

Electric

  $ 16,668     $ 15,560  

Manufacturing

    4,164       2,172  

Plastics

    6,844       2,437  

Corporate

    (1,461 )     (640 )

Discontinued Operations

    --       56  

Total

  $ 26,215     $ 19,585  

 

 

Identifiable Assets

 

   

March 31,

   

December 31,

 

(in thousands)

 

2018

   

2017

 

Electric

  $ 1,686,255     $ 1,690,224  

Manufacturing

    180,319       167,023  

Plastics

    97,953       87,230  

Corporate

    42,891       59,801  

Total

  $ 2,007,418     $ 2,004,278  

  

15

 

 

3. Rate and Regulatory Matters

 

Below are descriptions of OTP’s major capital expenditure projects that have had, or will 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 2018 and 2017.

 

Major Capital Expenditure Projects

 

Big Stone South–Ellendale Multi-Value Transmission Project (MVP)—This is a 345-kiloVolt (kV) transmission line that will extend 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., a division of MDU Resources Group, Inc., and the parties will have equal ownership interest in the transmission line portion of the project. 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 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. Construction began on this line in the second quarter of 2016 and is expected to be completed in 2019. OTP’s capitalized costs on this project as of March 31, 2018 were approximately $96.5 million, which includes assets that are 100% owned by OTP.

 

Big Stone South–Brookings MVP—This 345-kV transmission line extends approximately 70 miles between a substation near Big Stone City, South Dakota and the Brookings County Substation near Brookings, South Dakota. OTP and Northern States Power–Minnesota, a subsidiary of Xcel Energy Inc., jointly developed this project and the parties have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP under the MISO Tariff in December 2011. Construction began on this line in the third quarter of 2015 and the line was energized on September 8, 2017. OTP’s capitalized costs on this project as of March 31, 2018 were approximately $72.4 million, which includes assets that are 100% owned by OTP.

 

Recovery of OTP’s major transmission investments is through the MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (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 decreased from 8.61% to 7.5056% and its allowed rate of return on equity decreased from 10.74% to 9.41%.

 

The MPUC’s order also included: (1) the determination that all costs (including FERC allocated costs and revenues) of the Big Stone South–Brookings and Big Stone South–Ellendale MVPs will be included in the Minnesota TCR rider and jurisdictionally allocated to OTP’s Minnesota customers, and (2) approval of OTP’s proposal to transition rate base, expenses and revenues from ECR and TCR riders to base rate recovery, with the transition occurring when final rates are implemented. The rate base balances, expense levels and revenue levels existing in the riders at the time of implementation of final rates will be used to establish the amounts transitioned to base rates. Certain MISO expenses and revenues will remain in the TCR rider to allow for the ongoing refund or recovery of these variable revenues and costs.

 

OTP accrued interim and rider rate refunds until final rates became effective. The final interim rate refund, including interest, of $9.0 million was applied as a credit to Minnesota customers’ electric bills beginning November 17, 2017. In addition to the interim rate refund, OTP will refund the difference between (1) amounts collected under its Minnesota ECR and TCR riders based on the return on equity (ROE) approved in its most recent rider update and (2) amounts that would have been collected based on the lower 9.41% ROE approved in its 2016 general rate case going back to April 16, 2016, the date interim rates were implemented. As of October 31, 2017, the revenues collected under the Minnesota ECR and TCR riders subject to refund due to the lower ROE rate and other adjustments were $0.9 million and $1.4 million, respectively. These amounts are being refunded to Minnesota customers over a 12-month period through reductions in the Minnesota ECR and TCR rider rates in effect November 1, 2017, as approved by the MPUC. The TCR rate is provisional and subject to revision under a separate docket.

 

16

 

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 the Minnesota Department of Commerce’s (MNDOC’s) proposed changes to the MNCIP financial incentive. The model provides utilities an incentive 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 is also limited to 40% of 2017 MNCIP spending, 35% of 2018 spending and 30% of 2019 spending.

 

Based on results from the 2017 MNCIP program year, OTP recognized a financial incentive of $2.6 million in 2017. The 2017 program resulted in an approximate 10% decrease in energy savings compared to 2016 program results. OTP requested approval for recovery of its 2017 MNCIP program costs not included in base rates, a $2.6 million financial incentive and an update to the MNCIP surcharge from the MPUC on March 31, 2018.

 

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 MVP Projects 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 diverts 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 will result in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC’s revenue requirements and authorized returns will vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision will 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 March 22, 2018 oral arguments were made before the Minnesota Court of Appeals. A decision is anticipated by the end of the second quarter 2018. OTP believes the MPUC-ordered treatment conflicts with federal authority over interstate transmission of electricity in and with FERC electric transmission rates as set forth in the Federal Power Act of 1935, as amended (Federal Power Act).

 

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.

 

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 $13.1 million increase is net of reductions in North Dakota RRA, TCR and ECR rider revenues that will result from a lower allowed rate of return on equity 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 return on equity of 10.30%. 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. OTP used the same rate of return on equity in the calculation of interim rates as the rate of return on equity used in its 2018 test-year rate request. 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 includes $4.8 million related to tax reform and $1.2 million related to other updates. OTP will continue to address the impacts of the TJCA in its current general rate case.

 

OTP’s most recently approved general rate increase in North Dakota of $3.6 million, or approximately 3.0%, was granted by the NDPSC in an order issued on November 25, 2009 and effective December 2009. Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.62%, and its allowed rate of return on equity was set at 10.75%.

 

17

 

Renewable Resource Adjustment—OTP has a North Dakota Renewable Resource Adjustment 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.

 

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.

 

Environmental Cost Recovery Rider—OTP has an ECR rider in North Dakota to recover its North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant Mercury and Air Toxic Standards (MATS) projects. 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 North Dakota share of reagent and emission allowance costs.

 

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. OTP requested an interim rate increase effective May 21, 2018 while the SDPUC considers OTP’s overall request. The SDPUC is scheduled to review the application and act on the request for interim rates on May 15, 2018. The full effects of the TCJA on South Dakota revenue requirements will be addressed in OTP’s current general rate case and incorporated into final rates at the conclusion of that case. The second step in the request is an additional 1.7% increase to be effective January 1, 2020 to recover costs for a wind generation facility scheduled to be in service by the end of 2019.

 

OTP’s most recently approved general rate increase in South Dakota of approximately $643,000 or approximately 2.32% was granted by the SDPUC in an order issued on April 21, 2011 and effective with bills rendered on and after June 1, 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.

 

Environmental Cost Recovery Rider—OTP has an ECR rider in South Dakota to recover its South Dakota jurisdictional share of revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects.

 

Reagent Costs and Emission Allowances—The SDPUC has approved the recovery of reagent and emission allowance costs in OTP’s South Dakota Fuel Clause Adjustment rider.

 

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)

 

2018

   

2017

 

Minnesota

               

Conservation Improvement Program Costs and Incentives1

  $ 2,516     $ 1,966  

Transmission Cost Recovery

    (29 )     2,170  

Environmental Cost Recovery

    (31 )     2,824  

Renewable Resource Recovery

    525       --  

North Dakota

               

Renewable Resource Adjustment

    1,967       1,770  

Transmission Cost Recovery

    2,062       2,511  

Environmental Cost Recovery

    1,821       2,488  

South Dakota

               

Transmission Cost Recovery

    536       441  

Environmental Cost Recovery

    520       597  

Conservation Improvement Program Costs and Incentives

    229       240  

Total

  $ 10,116     $ 15,007  

1Includes MNCIP costs recovered in base rates.

 

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Rate Rider Updates

 

The following table provides summary information on the status of updates since January 1, 2016 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

             

2017 Incentive and Cost Recovery

R – March 31, 2018

October 1, 2018

  $ 10,400  

$0.00600/kwh

2016 Incentive and Cost Recovery

A – September 15, 2017

October 1, 2017

  $ 9,868  

$0.00536/kwh

2015 Incentive and Cost Recovery

A – July 19, 2016

October 1, 2016

  $ 8,590  

$0.00275/kwh

Transmission Cost Recovery

             

2017 Rate Reset1

A – October 30, 2017

November 1, 2017

  $ (3,311 )

Various

2016 Annual Update

A – July 5, 2016

September 1, 2016

  $ 4,736  

Various

2015 Annual Update

A – March 9, 2016

April 1, 2016

  $ 7,203  

Various

Environmental Cost Recovery

             

2017 Rate Reset

A – October 30, 2017

November 1, 2017

  $ (1,943 )

-0.935% of base

2016 Annual Update

A – July 5, 2016

September 1, 2016

  $ 11,884  

6.927% of base

Renewable Resource Adjustment

             

2017 Rate Reset

A – October 30, 2017

November 1, 2017

  $ 1,279  

$.00049/kwh

North Dakota

             

Renewable Resource Adjustment

             

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

2016 Annual Update

A – March 15, 2017

April 1, 2017

  $ 9,156  

7.005% of base

2015 Annual Update

A – June 22, 2016

July 1, 2016

  $ 9,262  

7.573% of base

Transmission Cost Recovery

             

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

2016 Annual Update

A – December 14, 2016

January 1, 2017

  $ 6,916  

Various

Environmental Cost Recovery

             

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

2017 Annual Update

A – July 12, 2017

August 1, 2017

  $ 9,917  

7.633% of base

2016 Annual Update

A – June 22, 2016

July 1, 2016

  $ 10,359  

7.904% of base

South Dakota

             

Transmission Cost Recovery

             

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

2015 Annual Update

A – February 12, 2016

March 1, 2016

  $ 1,895  

Various

Environmental Cost Recovery

             

2017 Annual Update

A – October 13, 2017

November 1, 2017

  $ 2,082  

$0.00483/kwh

2016 Annual Update

A – October 26, 2016

November 1, 2016

  $ 2,238  

$0.00536/kwh

1Approved on a provisional basis in the Minnesota general rate case docket and subject to revision in a separate docket.

 

TCJA

 

The TCJA reduced the federal corporate income tax rate from 35% to 21%. Currently, all OTP rates have been developed using a 35% tax rate. The MPUC, the NDPSC, the SDPUC and the FERC have all initiated dockets or proceedings to assess the impact of the lower income tax rates under the TCJA on electric rates and develop regulatory strategies to incorporate the tax change into future rates, if warranted. The MPUC required regulated utilities providing service in Minnesota to make filings by February 15, 2018 but has not made a determination on rate treatment. The SDPUC required initial comments by February 1, 2018 and indicated that revenues collected after December 31, 2017 would be subject to refund, pending determination of the impacts of the TCJA. As described above, OTP’s pending general rate cases in North Dakota and South Dakota reflect the impact of the TCJA. OTP has accrued refund liabilities for revenues collected under rates set to recover higher levels of federal income taxes than OTP is currently incurring under the lower federal tax rates in the TCJA. The accrued refund liabilities as of March 31, 2018 related to the tax rate reduction were $1.9 million in Minnesota, $0.8 million in North Dakota and $0.5 million in South Dakota.

 

19

 

FERC

 

Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the 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 one-day suspension period, subject to ultimate approval by the FERC.

 

MVPs—On December 16, 2010 the FERC approved the cost allocation for a new classification of projects in the MISO region called MVPs. MVPs are designed to enable the 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%. A number of 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 will be 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, has 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, 2018.

 

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 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. If FERC were to act on a motion to dismiss, it would eliminate the refund obligation from the second complaint and the ROE from the first complaint would remain in effect.

  

20

 

 

4. Regulatory Assets and Liabilities

 

As a regulated entity, OTP accounts for the financial effects of regulation in accordance with ASC Topic 980, Regulated Operations (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, environmental upgrades and conservation initiatives. The following tables indicate the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheets:

 

   

March 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

  $ 9,090     $ 110,214     $ 119,304    

see below

 

Conservation Improvement Program Costs and Incentives2

    5,313       3,468       8,781       30  

Accumulated ARO Accretion/Depreciation Adjustment1

    --       6,779       6,779    

asset lives

 

Deferred Marked-to-Market Losses1

    3,463       1,989       5,452       33  

Big Stone II Unrecovered Project Costs – Minnesota1

    657       1,467       2,124       37  

Debt Reacquisition Premiums1

    246       904       1,150       174  

Big Stone II Unrecovered Project Costs – South Dakota1

    100       417       517       62  

North Dakota Deferred Rate Case Expenses Subject to Recovery1

    374       --       374       12  

Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues1

    322       --       322       12  

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

    --       196       196    

asset lives

 

Minnesota Southwest Power Pool Transmission Cost Recovery Tracker1

    --       166       166    

see below

 

North Dakota Transmission Cost Recovery Rider Accrued Revenues2

    133       --       133       21  

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

    --       67       67       21  

Minnesota Deferred Rate Case Expenses Subject to Recovery1

    38       --       38       1  

Total Regulatory Assets

  $ 19,736     $ 125,667     $ 145,403          

Regulatory Liabilities:

                               

Deferred Income Taxes

  $ --     $ 148,938     $ 148,938    

asset lives

 

Accumulated Reserve for Estimated Removal Costs – Net of Salvage

    --       84,223       84,223    

asset lives

 

Refundable Fuel Clause Adjustment Revenues

    2,414       --       2,414       12  

Minnesota Environmental Cost Recovery Rider Accrued Refund

    1,161       --       1,161       7  

North Dakota Renewable Resource Recovery Rider Accrued Refund

    371       --       371       9  

North Dakota Environmental Cost Recovery Rider Accrued Refund

    351       --       351       12  

South Dakota Environmental Cost Recovery Rider Accrued Refund

    317       --       317       12  

Minnesota Renewable Resource Recovery Rider Accrued Refund

    304       --       304       7  

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

    68       36       104       21  

Other

    6       82       88       189  

South Dakota Transmission Cost Recovery Rider Accrued Refund

    60       --       60       12  

Minnesota Transmission Cost Recovery Rider Accrued Refund

    37       --       37       7  

Revenue for Rate Case Expenses Subject to Refund – Minnesota

    30       --       30       1  

Total Regulatory Liabilities

  $ 5,119     $ 233,279     $ 238,398          

Net Regulatory Asset/(Liability) Position

  $ 14,617     $ (107,612 )   $ (92,995 )        

1Costs subject to recovery excluding a rate of return.

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

 

21

 

   

December 31, 2017

   

Remaining Recovery/

 

(in thousands)

 

Current

   

Long-Term

   

Total

    Refund Period (months)  

Regulatory Assets:

                               

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

  $ 9,090     $ 112,487     $ 121,577    

see below

 

Conservation Improvement Program Costs and Incentives2

    7,385       2,774       10,159       21  

Accumulated ARO Accretion/Depreciation Adjustment1

    --       6,651       6,651    

asset lives

 

Deferred Marked-to-Market Losses1

    4,063       2,405       6,468       36  

Big Stone II Unrecovered Project Costs – Minnesota1

    650       1,636       2,286       40  

Debt Reacquisition Premiums1

    254       960       1,214       177  

Big Stone II Unrecovered Project Costs – South Dakota1

    100       442       542       65  

North Dakota Deferred Rate Case Expenses Subject to Recovery1

    309       --       309       12  

Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues1

    75       --       75       12  

North Dakota Renewable Resource Rider Accrued Revenues2

    206       236       442       15  

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

    --       1,985       1,985       24  

Minnesota Deferred Rate Case Expenses Subject to Recovery1

    267       --       267       4  

North Dakota Environmental Cost Recovery Rider Accrued Revenues2

    152       --       152       12  

Total Regulatory Assets

  $ 22,551     $ 129,576     $ 152,127          

Regulatory Liabilities:

                               

Deferred Income Taxes

  $ --     $ 149,052     $ 149,052    

asset lives

 

Accumulated Reserve for Estimated Removal Costs – Net of Salvage

    --       83,100       83,100    

asset lives

 

Refundable Fuel Clause Adjustment Revenues

    5,778       --       5,778       12  

Minnesota Environmental Cost Recovery Rider Accrued Refund

    1,667       --       1,667       11  

South Dakota Environmental Cost Recovery Rider Accrued Refund

    187       --       187       12  

Minnesota Renewable Resource Recovery Rider Accrued Refund

    409       --       409       12  

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

    132       48       180       24  

Other

    5       84       89       192  

South Dakota Transmission Cost Recovery Rider Accrued Refund

    151       --       151       12  

Minnesota Transmission Cost Recovery Rider Accrued Refund

    802       --       802       10  

Revenue for Rate Case Expenses Subject to Refund – Minnesota

    208       --       208       4  

Minnesota Southwest Power Pool Transmission Cost Tracker Refund

    --       609       609       22  

North Dakota Transmission Cost Recovery Rider Accrued Refund

    349       --       349       12  

Total Regulatory Liabilities

  $ 9,688     $ 232,893     $ 242,581          

Net Regulatory Asset/(Liability) Position

  $ 12,863     $ (103,317 )   $ (90,454 )        

1Costs subject to recovery excluding 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.

 

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

 

All Deferred Marked-to-Market Losses recorded as of March 31, 2018 relate to forward purchases of energy scheduled for delivery through December 2020.

 

Big Stone II Unrecovered Project Costs – Minnesota are the Minnesota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project.

 

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 174 months.

 

22

 

Big Stone II Unrecovered Project Costs – South Dakota are the South Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project.

 

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

 

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.

 

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

 

The Minnesota Southwest Power Pool Transmission Cost Recovery Tracker relates to costs incurred, in excess of the rate at which the costs are being recovered under current rates, that are subject to future recovery under current rates or through future rate adjustments.

 

North Dakota Transmission Cost Recovery Rider Accrued Revenues relate to amounts recoverable for investments in qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of March 31, 2018.

 

North Dakota Renewable Resource Rider Accrued Revenues relate to qualifying renewable resource costs incurred to serve North Dakota customers that had not been billed to North Dakota customers as of December 31, 2017.

 

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.

 

Minnesota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s 2016 rate case in Minnesota currently being recovered over a 24-month period beginning with the establishment of interim rates in April 2016.

 

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 had not been billed to North Dakota customers as of December 31, 2017.

 

The regulatory liability related to Deferred Income Taxes results from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes.

 

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

 

The Minnesota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS project that are refundable to Minnesota customers as of March 31, 2018.

 

The North Dakota Renewable Resource 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, 2018.

 

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 and for reagent and emission allowances costs that are recoverable from North Dakota customers as of March 31, 2018.

 

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, 2018.

 

23

 

The Minnesota Renewable Resource Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve Minnesota customers that are refundable to Minnesota customers as of March 31, 2018.

 

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, 2018.

 

The Minnesota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that are refundable to Minnesota customers as of March 31, 2018.

 

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, which are subject to refund over a 24-month period beginning with the establishment of interim rates in April 2016.

 

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, 2018.

 

The Minnesota Southwest Power Pool Transmission Cost Tracker Refund relates to revenues billed for recovery of these transmission costs in excess of actual costs incurred that are subject to refund.

 

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. Reconciliation of Common Shareholders’ Equity, Common Shares and Earnings Per Share

 

Reconciliation of Common Shareholders’ Equity

 

(in thousands)

 

Par Value,

Common

Shares

   

Premium

on

Common

Shares

   

Retained

Earnings

   

Accumulated

Other

Comprehensive

Loss

   

Total

Common

Equity

 

Balance, December 31, 2017

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

Common Stock Issuances, Net of Expenses

    638       (638 )                     --  

Common Stock Retirements

    (292 )     (2,117 )                     (2,409 )

Net Income

                    26,215               26,215  

Other Comprehensive Loss

                            (502 )     (502 )

Employee Stock Incentive Plans Expense

            1,146                       1,146  

Common Dividends ($0.335 per share)

                    (13,292 )             (13,292 )

Balance, March 31, 2018

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

 

Shelf Registrations and Common Share Distribution Agreement

On May 3, 2018 the Company filed a shelf registration statement with the Securities and Exchange Commission (SEC) under which we may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, which expires on May 3, 2021. On May 3, 2018, the Company also filed a shelf registration statement with the SEC for the issuance of up to 1,500,000 common shares under the Company's Automatic Dividend Reinvestment (DRIP) and Share Purchase Plan (the Plan), which permits shares purchased by participants in the Plan to be either new issue common shares or common shares purchased in the open market. The shelf registration for the DRIP expires on May 3, 2021. The shelf registration statements replaced the Company’s prior shelf registration statements that were due to expire on May 11, 2018. On May 1, 2018 the Company’s Distribution Agreement with J.P. Morgan Securities (JPMS) ended as required under the agreement. This Distribution Agreement allowed the Company to offer and sell its common shares from time to time in an At-the-Market (ATM) offering program through JPMS, up to an aggregate sales price of $75 million. The Company expects to establish a new ATM offering program under which the Company may offer and sell its common shares from time to under the shelf registration statement.

 

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Common Shares

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2017 through March 31, 2018:

 

Common Shares Outstanding, December 31, 2017

    39,557,491  

Issuances:

       

Executive Stock Performance Awards (2015 shares earned)

    114,648  

Vesting of Restricted Stock Units

    12,950  

Retirements:

       

Shares Withheld for Individual Income Tax Requirements

    (58,495 )

Common Shares Outstanding, March 31, 2018

    39,626,594  

 

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, 2018 and 2017. 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:

 

   

2018

   

2017

 

Weighted Average Common Shares Outstanding – Basic

    39,550,874       39,350,802  

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

    223,162       201,639  

Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees

    59,130       57,873  

Nonvested Restricted Shares

    27,643       27,069  

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

    2,873       3,342  

Total Dilutive Shares

    312,808