ottr20180930_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

September 30, 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 ☐

     

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:

 

October 31, 2018 39,664,884 Common Shares ($5 par value)

 

 

 

OTTER TAIL CORPORATION

 

INDEX

 

Part I. Financial Information

Page No.

   

Item 1.

Financial Statements (not audited)

 
     
 

Consolidated Balance Sheets – September 30, 2018 and December 31, 2017 

2 & 3

     
 

Consolidated Statements of Income - Three and Nine Months Ended September 30, 2018 and 2017

4

     
 

Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2018 and 2017

5

     
 

Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2018 and 2017

6

     
 

Condensed Notes to Consolidated Financial Statements

7-34

     

Item 2.

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

35-53

     

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

54

     

Item 4.

Controls and Procedures

54

     

Part II. Other Information

 
     

Item 1.

Legal Proceedings

54

     

Item 1A.

Risk Factors

54

     

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

55

     

Item 6.

Exhibits

55

     

Signatures

55

 

 

 

PART I. FINANCIAL INFORMATION

 

Item 1. financial statements

 

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

 

(in thousands)

 

September 30,

2018

   

December 31,

2017

 
                 

Assets

               
                 

Current Assets

               

Cash and Cash Equivalents

  $ 649     $ 16,216  

Accounts Receivable:

               

Trade—Net

    96,095       68,466  

Other

    8,036       7,761  

Inventories

    94,615       88,034  

Unbilled Receivables

    16,855       22,427  

Income Taxes Receivable

    --       1,181  

Regulatory Assets

    16,552       22,551  

Other

    8,611       12,491  

Total Current Assets

    241,413       239,127  
                 

Investments

    9,123       8,629  

Other Assets

    36,721       36,006  

Goodwill

    37,572       37,572  

Other IntangiblesNet

    12,746       13,765  

Regulatory Assets

    124,553       129,576  
                 

Plant

               

Electric Plant in Service

    2,000,313       1,981,018  

Nonelectric Operations

    225,620       216,937  

Construction Work in Progress

    183,397       141,067  

Total Gross Plant

    2,409,330       2,339,022  

Less Accumulated Depreciation and Amortization

    844,042       799,419  

Net Plant

    1,565,288       1,539,603  
                 

Total Assets

  $ 2,027,416     $ 2,004,278  

 

See accompanying condensed notes to consolidated financial statements.

   

 

2

 

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

 

(in thousands, except share data)

 

September 30,

2018

   

December 31,

2017

 
                 

Liabilities and Equity

               
                 

Current Liabilities

               

Short-Term Debt

  $ 15,489     $ 112,371  

Current Maturities of Long-Term Debt

    169       186  

Accounts Payable

    91,033       84,185  

Accrued Salaries and Wages

    21,486       21,534  

Accrued Federal and State Income Taxes

    2,708       --  

Other Accrued Taxes

    15,269       16,808  

Regulatory Liabilities

    7,926       9,688  

Other Accrued Liabilities

    9,373       11,389  

Liabilities of Discontinued Operations

    --       492  

Total Current Liabilities

    163,453       256,653  
                 

Pensions Benefit Liability

    89,139       109,708  

Other Postretirement Benefits Liability

    70,703       69,774  

Other Noncurrent Liabilities

    25,889       22,769  
                 

Commitments and Contingencies (note 8)

               
                 

Deferred Credits

               

Deferred Income Taxes

    108,699       100,501  

Deferred Tax Credits

    20,325       21,379  

Regulatory Liabilities

    231,594       232,893  

Other

    2,328       3,329  

Total Deferred Credits

    362,946       358,102  
                 

Capitalization

               

Long-Term Debt—Net

    589,984       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—39,664,884 Shares; 2017—39,557,491 Shares

    198,324       197,787  

Premium on Common Shares

    343,210       343,450  

Retained Earnings

    189,575       161,286  

Accumulated Other Comprehensive Loss

    (5,807 )     (5,631 )

Total Common Equity

    725,302       696,892  
                 

Total Capitalization

    1,315,286       1,187,272  
                 

Total Liabilities and Equity

  $ 2,027,416     $ 2,004,278  

 

See accompanying condensed notes to consolidated financial statements.

 

3

 

 

Otter Tail Corporation

Consolidated Statements of Income

(not audited)

 

   

Three Months Ended

September 30,

   

Nine Months Ended

September 30,

 

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

 

2018

   

2017

   

2018

   

2017

 

Operating Revenues

                               

Electric:

                               

Revenues from Contracts with Customers

  $ 105,749     $ 102,923     $ 334,858     $ 325,360  

Changes in Accrued Revenues under Alternative Revenue Programs

    (317 )     471       (2,757 )     (1,192 )

Total Electric Revenues

    105,432       103,394       332,101       324,168  

Product Sales under Contracts with Customers

    122,230       113,063       363,175       318,492  

Total Operating Revenues

    227,662       216,457       695,276       642,660  

Operating Expenses

                               

Production Fuel – Electric

    17,129       16,096       51,723       44,955  

Purchased Power – Electric

    9,664       13,371       45,659       48,935  

Electric Operation and Maintenance Expenses

    33,897       35,469       111,113       109,494  

Cost of Products Sold (depreciation included below)

    93,361       86,230       275,691       245,520  

Other Nonelectric Expenses

    12,547       10,631       37,690       30,625  

Depreciation and Amortization

    18,708       17,927       56,216       53,689  

Property Taxes – Electric

    4,094       3,721       11,202       11,228  

Total Operating Expenses

    189,400       183,445       589,294       544,446  

Operating Income

    38,262       33,012       105,982       98,214  

Interest Charges

    7,549       7,393       22,597       22,382  

Nonservice Cost Components of Postretirement Benefits

    1,326       1,403       4,129       4,215  

Other Income

    1,245       592       3,135       1,697  

Income Before Income TaxesContinuing Operations

    30,632       24,808       82,391       73,314  

Income Tax ExpenseContinuing Operations

    7,359       7,035       14,207       19,295  

Net Income from Continuing Operations

    23,273       17,773       68,184       54,019  

Discontinued Operations

                               

(Loss) Income – net of Income Tax (Savings) Expense of $0, ($25), $0 and $53 for the respective periods

    --       (39 )     --       78  

Net Income

    23,273       17,734       68,184       54,097  
                                 

Average Number of Common Shares OutstandingBasic

    39,621,524       39,507,581       39,592,705       39,440,416  

Average Number of Common Shares OutstandingDiluted

    39,903,565       39,795,366       39,882,105       39,712,862  
                                 

Basic Earnings Per Common Share:

                               

Continuing Operations

  $ 0.59     $ 0.45     $ 1.72     $ 1.37  

Discontinued Operations

    --       --       --       --  
    $ 0.59     $ 0.45     $ 1.72     $ 1.37  

Diluted Earnings Per Common Share:

                               

Continuing Operations

  $ 0.58     $ 0.45     $ 1.71     $ 1.36  

Discontinued Operations

    --       --       --       --  
    $ 0.58     $ 0.45     $ 1.71     $ 1.36  
                                 

Dividends Declared Per Common Share

  $ 0.335     $ 0.320     $ 1.005     $ 0.960  

 

See accompanying condensed notes to consolidated financial statements.

 

4

 

 

Otter Tail Corporation

Consolidated Statements of Comprehensive Income

(not audited)

 

   

Three Months Ended

September 30,

   

Nine Months Ended

September 30,

 

(in thousands)

 

2018

   

2017

   

2018

   

2017

 

Net Income

  $ 23,273     $ 17,734     $ 68,184     $ 54,097  

Other Comprehensive Income (Loss):

                               

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

                               

Reversal of Previously Recognized Losses (Gains) Realized on Sale of Investments and Included in Other Income During Period

    4       (1 )     (106 )     (2 )

Unrealized (Losses) Gains Arising During Period

    (14 )     52       (93 )     90  

Income Tax Benefit (Expense)

    2       (18 )     42       (31 )

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

    (8 )     33       (157 )     57  

Pension and Postretirement Benefit Plans:

                               

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

    232       157       692       473  

Income Tax Expense

    (60 )     (63 )     (180 )     (189 )

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

    --       --       (531 )     --  

Pension and Postretirement Benefit Plans – net-of-tax

    172       94       (19 )     284  

Total Other Comprehensive Income (Loss)

    164       127       (176 )     341  

Total Comprehensive Income

  $ 23,437     $ 17,861     $ 68,008     $ 54,438  

 

See accompanying condensed notes to consolidated financial statements.

 

5

  

 

Otter Tail Corporation

Consolidated Statements of Cash Flows

(not audited)

 

   

Nine Months Ended

September 30,

 

(in thousands)

 

2018

   

2017

 

Cash Flows from Operating Activities

               

Net Income

  $ 68,184     $ 54,097  

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

               

Net Income from Discontinued Operations

    --       (78 )

Depreciation and Amortization

    56,216       53,689  

Deferred Tax Credits

    (1,054 )     (1,102 )

Deferred Income Taxes

    7,529       15,680  

Change in Deferred Debits and Other Assets

    10,641       7,875  

Discretionary Contribution to Pension Plan

    (20,000 )     --  

Change in Noncurrent Liabilities and Deferred Credits

    (191 )     1,788  

Allowance for Equity/Other Funds Used During Construction

    (1,586 )     (636 )

Stock Compensation Expense—Equity Awards

    3,402       2,765  

Other—Net

    (201 )     99  

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

               

Change in Receivables

    (27,804 )     (21,122 )

Change in Inventories

    (6,581 )     4,825  

Change in Other Current Assets

    3,827       3,079  

Change in Payables and Other Current Liabilities

    5,746       (5,153 )

Change in Interest and Income Taxes Receivable/Payable

    2,932       (1,595 )

Net Cash Provided by Continuing Operations

    101,060       114,211  

Net Cash Used in Discontinued Operations

    (200 )     (134 )

Net Cash Provided by Operating Activities

    100,860       114,077  

Cash Flows from Investing Activities

               

Capital Expenditures

    (74,489 )     (94,549 )

Net Proceeds from Disposal of Noncurrent Assets

    1,879       2,456  

Cash Used for Investments and Other Assets

    (3,324 )     (3,158 )

Net Cash Used in Investing Activities

    (75,934 )     (95,251 )

Cash Flows from Financing Activities

               

Change in Checks Written in Excess of Cash

    (7 )     4,826  

Net Short-Term (Repayments) Borrowings

    (96,882 )     60,754  

Proceeds from Issuance of Common Stock

    --       4,349  

Common Stock Issuance Expenses

    (108 )     --  

Payments for Retirement of Capital Stock

    (3,012 )     (1,799 )

Proceeds from Issuance of Long-Term Debt

    100,000       --  

Short-Term and Long-Term Debt Issuance Expenses

    (441 )     --  

Payments for Retirement of Long-Term Debt

    (148 )     (48,172 )

Dividends Paid

    (39,895 )     (37,958 )

Net Cash Used in Financing Activities

    (40,493 )     (18,000 )

Net Change in Cash and Cash Equivalents

    (15,567 )     826  

Cash and Cash Equivalents at Beginning of Period

    16,216       --  

Cash and Cash Equivalents at End of Period

  $ 649     $ 826  

 

See accompanying condensed notes to consolidated financial statements.

 

6

 

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- and nine-month periods ended September 30, 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 amended previous 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 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 under alternative revenue programs (ARPs) as defined in ASC Topic 980, Regulated Operations (ASC 980). The ARP revenue adjustments are recorded on the basis of recoverable costs incurred and returns earned under rate riders on a separate line on the face of the Company’s consolidated statements of income as they do not meet the criteria to be classified as revenue from contracts with customers.

 

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

 

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

 

 

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

 

 

In Minnesota: Transmission Cost Recovery (TCR), Environmental Cost Recovery (ECR), Renewable Resource Adjustment (RRA) and Conservation Improvement Program 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 net of amounts billed that are subject to refund through future rider adjustments. Amounts accrued and subject to recovery through future rider rate updates and adjustments are reported as ARP revenue adjustments on a separate line in the revenue section of the Company’s consolidated statement of income. See table in note 3 for total revenues billed and accrued under ARP riders for the three- and nine-month periods ended September 30, 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 customer specifications where the terms of the contract require transfer of the completed product, the operating company has met its performance obligation and recognizes revenue at the point in time when the product is shipped and adjusts the revenue for volume rebate variable pricing considerations the company expects the customer will earn and for 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 products. The shipping terms used in these instances are FOB shipping point.

 

Plastics Segment Revenues—Companies in our Plastics segment earn revenue predominantly from the sale and delivery of standardized polyvinyl-chloride (PVC) pipe products produced at their manufacturing facilities. Revenue from the sale of these products is recognized at the point in time when the product is shipped based on prices agreed to in a purchase order. 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 for a disaggregation of the Company’s revenues by business segment for the three- and nine-month periods ended September 30, 2018 and 2017.

 

Agreements Subject to Legally Enforceable Netting Arrangements

OTP has certain derivative contracts that are designated as normal purchases. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The Company does not offset assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet. 

 

 

Fair Value Measurements

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

 

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

 

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

 

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

 

The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2018 and December 31, 2017:

 

September 30, 2018 (in thousands)

 

Level 1

   

Level 2

   

Level 3

 

Assets:

                       

Investments:

                       

Equity Funds – Held by Captive Insurance Company

  $ 1,373                  

Corporate Debt Securities – Held by Captive Insurance Company

          $ 6,012          

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

            1,527          

Other Assets:

                       

Money Market and Mutual Funds – Nonqualified Retirement Savings Plan

    776                  

Total Assets

  $ 2,149     $ 7,539          

 

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.

 

 

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 September 30, 2018 could be as high as $54.8 million, OTP’s 35% share of unrecovered costs.

 

Inventories

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

 

   

September 30,

   

December 31,

 

(in thousands)

 

2018

   

2017

 

Finished Goods

  $ 28,907     $ 26,605  

Work in Process

    19,124       14,222  

Raw Material, Fuel and Supplies

    46,584       47,207  

Total Inventories

  $ 94,615     $ 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 nine 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) September 30, 2018

 

Manufacturing

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

Plastics

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

Total

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

 

 

Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360-10-35, Property, Plant, and Equipment—Overall—Subsequent Measurement.

 

The following table summarizes the components of the Company’s intangible assets at September 30, 2018 and December 31, 2017:

 

September 30, 2018 (in thousands)

 

Gross Carrying Amount

   

Accumulated Amortization

   

Net Carrying

Amount

   

Remaining Amortization

Periods (months)

 

Amortizable Intangible Assets:

                                 

Customer Relationships

  $ 22,491     $ 9,843     $ 12,648      15 - 203  

Other

    154       56       98       23    

Total

  $ 22,645     $ 9,899     $ 12,746            

 

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

   

Nine Months Ended

 
   

September 30,

   

September 30,

 

(in thousands)

 

2018

   

2017

   

2018

   

2017

 

Amortization Expense – Intangible Assets

  $ 329     $ 336     $ 1,019     $ 1,001  

 

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 September 30,

 

(in thousands)

 

2018

   

2017

 

Noncash Investing Activities:

               

Transactions Related to Capital Additions not Settled in Cash

  $ 12,059     $ 17,940  

 

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 2016-01 are 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 results in changes in the fair value of equity instruments held as investments by the Company’s captive insurance company being classified in net income.

 

 

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. 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 and nine-month periods ended September 30, 2018 and 2017 is provided in note 10 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. The Company has determined areas where the amendments in ASU 2016-02 are applicable to its businesses and has evaluated transition options and determined the practical expedients it will elect on implementation. The Company will not apply the amendments in ASU 2016-02 to its consolidated financial statements prior to 2019. Other than first-time recognition of these types of operating leases on the Company’s consolidated balance sheet, the implementation is not expected to have a significant impact on the Company’s consolidated financial statements.

 

 

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 2017 Tax Cuts and Jobs Act (TCJA). Consequently, the amendments eliminate the stranded tax effects resulting from the TCJA and will improve the usefulness of information reported to financial statement users. The amendments in ASU 2018-02 also require certain disclosures about stranded tax effects and are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. 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 $0.8 million 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.

 

 

 

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. 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 sales within the United States accounted for 98.1% and 97.9% of its operating revenues for the respective three-month periods ended September 30, 2018 and 2017, and 98.2% and 98.2% of its operating revenues for the respective nine-month periods ended September 30, 2018 and 2017.

 

The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three- and nine-month periods ended September 30, 2018 and 2017 and total assets by business segment as of September 30, 2018 and December 31, 2017 are presented in the following tables:

 

Operating Revenue

 

   

Three Months Ended

   

Nine Months Ended

 
   

September 30,

   

September 30,

 

(in thousands)

 

2018

   

2017

   

2018

   

2017

 

Electric Segment:

                               

Retail Sales Revenue from Contracts with Customers

  $ 88,750     $ 88,482     $ 287,330     $ 281,615  

Changes in Accrued ARP Revenues

    (317 )     471       (2,757 )     (1,192 )

Total Retail Sales Revenue

    88,433       88,953       284,573       280,423  

Wholesale Revenues – Company Generation

    2,826       1,549       6,380       3,600  

Other Revenues

    14,183       12,897       41,179       40,163  

Total Electric Segment Revenues

  $ 105,442     $ 103,399     $ 332,132     $ 324,186  

Manufacturing Segment:

                               

Metal Parts and Tooling

  $ 55,864     $ 44,750     $ 170,179     $ 142,278  

Plastic Products and Tooling

    8,790       7,905       26,986       24,833  

Other

    2,373       1,700       6,678       4,965  

Total Manufacturing Segment Revenues

  $ 67,027     $ 54,355     $ 203,843     $ 172,076  

Plastics Segment – Sale of PVC Pipe Products

  $ 55,203     $ 58,708     $ 159,332     $ 146,416  

Intersegment Eliminations

  $ (10 )   $ (5 )   $ (31 )   $ (18 )

Total

  $ 227,662     $ 216,457     $ 695,276     $ 642,660  

 

 

Interest Charges

 

   

Three Months Ended

   

Nine Months Ended

 
   

September 30,

   

September 30,

 

(in thousands)

 

2018

   

2017

   

2018

   

2017

 

Electric

  $ 6,509     $ 6,362     $ 19,586     $ 19,187  

Manufacturing

    555       555       1,664       1,662  

Plastics

    150       157       460       483  

Corporate and Intersegment Eliminations

    335       319       887       1,050  

Total

  $ 7,549     $ 7,393     $ 22,597     $ 22,382  

 

Income Taxes

 

   

Three Months Ended

   

Nine Months Ended

 
   

September 30,

   

September 30,

 

(in thousands)

 

2018

   

2017

   

2018

   

2017

 

Electric

  $ 5,172     $ 3,548     $ 7,881     $ 12,052  

Manufacturing

    799       676       3,040       3,304  

Plastics

    2,276       3,826       6,897       8,074  

Corporate

    (888 )     (1,015 )     (3,611 )     (4,135 )

Total

  $ 7,359     $ 7,035     $ 14,207     $ 19,295  

 

Net Income (Loss)

 

   

Three Months Ended

   

Nine Months Ended

 
   

September 30,

   

September 30,

 

(in thousands)

 

2018

   

2017

   

2018

   

2017

 

Electric

  $ 14,567     $ 10,869     $ 41,835     $ 36,563  

Manufacturing

    3,022       1,608       10,769       6,735  

Plastics

    6,432       6,092       19,505       13,166  

Corporate

    (748 )     (796 )     (3,925 )     (2,445 )

Discontinued Operations

    --       (39 )     --       78  

Total

  $ 23,273     $ 17,734     $ 68,184     $ 54,097  

 

Identifiable Assets

 

   

September 30,

   

December 31,

 

(in thousands)

 

2018

   

2017

 

Electric

  $ 1,695,659     $ 1,690,224  

Manufacturing

    186,973       167,023  

Plastics

    100,981       87,230  

Corporate

    43,803       59,801  

Total

  $ 2,027,416     $ 2,004,278  

 

 

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 September 30, 2018 were approximately $103.6 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 September 30, 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, in base rates and through the TCR Rider in Minnesota, and through TCR Riders in North Dakota and South Dakota.

 

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 (see discussion under Minnesota Transmission Cost Recovery Rider below), and (2) approval of OTP’s proposal to transition rate base, expenses and revenues from ECR and TCR riders to base rate recovery, 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 were 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 is currently refunding 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, effective November 1, 2017, as approved by the MPUC. The TCR rate is provisional and subject to revision under a separate docket.

 

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 a decrease in energy savings compared to 2016 program results of approximately 10%. OTP requested approval for recovery of its 2017 MNCIP program costs not included in base rates on March 30, 2018. The request included a $2.6 million financial incentive and an update to the MNCIP surcharge from the MPUC. On June 13, 2018, in reply comments to a MNDOC recommendation for approval filed on May 30, 2018, OTP increased its request for a financial incentive to $2.9 million. OTP’s MNCIP rate of Conservation Cost Recovery Adjustment (CCRA) for bills rendered on and after October 1, 2018 (or the first month following the order) was approved on October 4, 2018 with a variance and a compliance filing required. The final order in this docket was issued in October 2018, making November 1, 2018 the effective date for the new CCRA rate. The MPUC approved a financial incentive of $2.9 million subject to further review by the MPUC to ensure no previous decisions conflict with the decision, with $0.3 million at risk of subsequent refund.

 

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

 

In OTP’s 2016 general rate case order issued on May 1, 2017, the MPUC ordered OTP to include, in the TCR rider retail rate base, Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVPs and all revenues received from other utilities under MISO’s tariffed rates as a credit in its TCR revenue requirement calculations. In doing so, the MPUC’s order 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 resulted in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC’s revenue requirements and authorized returns vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision would vary over time and be dependent on the differences between the revenue requirements and returns in the two jurisdictions at any given time. On August 18, 2017 OTP filed an appeal of the MPUC order with the Minnesota Court of Appeals to contest the portion of the order requiring OTP to jurisdictionally allocate costs of the FERC MVP transmission projects in the TCR rider.

 

On June 11, 2018 the Minnesota Court of Appeals reversed the MPUC’s order related to the inclusion of Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVPs and all revenues received from other utilities under MISO’s tariffed rates as a credit in OTP Minnesota TCR revenue requirement calculations. On July 11, 2018 the MPUC filed a petition for review of the MVP decision to the Minnesota Supreme Court, which has determined to review the decision of the Minnesota Court of Appeals. A decision by the Minnesota Supreme Court is expected in second quarter 2019. OTP plans to file for an updated TCR rider rate, prior to the Minnesota Supreme Court decision, to include the portion of revenue subject to recovery arising from the MISO MVP investments and associated revenues. The amount credited to Minnesota customers through the TCR through September 30, 2018 and subject to recovery if the Minnesota Court of Appeals decision is upheld, is approximately $2.5 million.

 

Environmental Cost Recovery Rider—OTP had an ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant Air Quality Control System (AQCS). The ECR rider provided for a return on the project’s construction work in progress (CWIP) balance at the level approved in OTP’s 2010 general rate case. In its 2016 general rate case order, the MPUC approved OTP’s proposal to transition eligible rate base and expense recovery from the ECR rider to base rate recovery, effective with implementation of final rates in November 2017.

 

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 revenue reductions for federal Production Tax Credits (PTCs) included in base rates that expired for one of OTP’s wind farms in 2017 and 2018. On August 29, 2018 the MPUC issued an order approving OTP’s request for an increase in the recoverable amount in its 2018 annual update to the RRA rider.

 

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. 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. 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.

 

 

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

 

In a September 26, 2018 hearing the NDPSC approved an overall annual revenue increase of $4.6 million (3.1%) and a ROE of 9.77% on a 52.5% equity capital structure. This compares with OTP’s March 2018 adjusted annual revenue increase request of $7.1 million (4.8%) and a requested ROE of 10.3%. The NDPSC’s approval does not require any rate base adjustments from OTP’s original request and establishes a Generation Cost Recovery rider for future recovery of funds to be invested in the planned Astoria natural gas-fired generating facility. On September 28, 2018 the NDPSC issued its Order on Settlement. The net revenue increase reflects a reduction in income tax recovery requirements related to the TCJA and decreases in rider revenue recovery requirements. Final rates will be effective January 1, 2019, with refunds of excess revenues collected under interim rates applied to customers’ March 2019 bills. OTP has accrued an interim rate refund of $2.3 million as of September 30, 2018 for amounts billed under interim rates in excess of amounts OTP is entitled to under the approved revenue increase.

 

OTP’s previously 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%.

 

Renewable Resource Adjustment—OTP has a North Dakota RRA which enables OTP to recover its North Dakota jurisdictional share of investments in renewable energy facilities. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed, along with a return on investment. Based on the Order on Settlement in the general rate case, this rider will be zeroed out at the implementation of final rates, except for any under or over collections existing at the time of roll-in. Future revenue requirement increases resulting from the expiration of production tax credits will be subject to recovery through North Dakota RRA rider updates.

 

Transmission Cost Recovery Rider—North Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. For qualifying projects, the law authorizes a current return on CWIP and a return on investment at the level approved in the utility's most recent general rate case. Based on the Order on Settlement in the general rate case, only certain costs will remain subject to refund or recovery through this rider: Southwest Power Pool costs and MISO Schedule 26 and 26A revenues and expenses and costs related to rider projects still under construction in the test year used in the rate case. This rider will continue to be updated annually for new projects and updated costs for existing projects and associated recoverable expenses.

 

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 provided 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. Based on the Order on Settlement in the general rate case, this rider will be zeroed out at the implementation of final rates, except for any under or over collections existing at the time of roll-in.

 

South Dakota

 

General Rates—On April 20, 2018 OTP filed a request with the SDPUC to increase non-fuel rates in South Dakota by approximately $3.3 million annually, or 10.1%, as the first step in a two-step request. Interim rates went into effect October 18, 2018. The full effects of the TCJA on South Dakota revenue requirements will be addressed in the 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 recover costs for the proposed Merricourt wind generation facility when the facility goes into service.

 

OTP’s previously approved general rate increase in South Dakota of approximately $643,000 or approximately 2.32% was granted by the SDPUC in an order issued 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 and will continue to be used for the recovery or refund of amounts not included in interim or base rates.

 

 

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 and will continue to be used for the recovery or refund of amounts not included in interim or base rates.

 

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.

 

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

 

A – October 4, 2018

 

November 1, 2018

  $ 10,283    

$0.00600/kwh

2016 Incentive and Cost Recovery

 

A – September 15, 2017

 

October 1, 2017

  $ 9,868    

$0.00536/kwh

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

                   

2018 Annual Update

 

R – July 3, 2018

 

December 1, 2018

  $ --    

0% of base

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

                   

2018 Annual Update

 

A – August 29, 2018

 

November 1, 2018

  $ 5,886    

$.00244/kwh

2017 Rate Reset

 

A – October 30, 2017

 

November 1, 2017

  $ 1,279    

$.00049/kwh

North Dakota

                   

Renewable Resource Adjustment

                   

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

                   

2018 Interim Rate Reset

 

A – October 18, 2018

 

October 18, 2018

  $ 1,171    

Various

2017 Annual Update

 

A – February 28, 2018

 

March 1, 2018

  $ 1,779    

Various

2016 Annual Update

 

A – February 17, 2017

 

March 1, 2017

  $ 2,053    

Various

2015 Annual Update

 

A – February 12, 2016

 

March 1, 2016

  $ 1,895    

Various

Environmental Cost Recovery

                   

2018 Interim Rate Reset

 

A – October 18, 2018

 

October 18, 2018

  $ (189 )  

-$0.00075/kwh

2017 Annual Update

 

A – October 13, 2017

 

November 1, 2017

  $ 2,082    

$0.00483/kwh

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.

 

 

Revenues Recorded under Rate Riders

 

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

 

 

   

Three Months Ended

September 30,

   

Nine Months Ended

September 30,

 

Rate Rider (in thousands)

 

2018

   

2017

   

2018

   

2017

 

Minnesota

                               

Conservation Improvement Program Costs and Incentives

  $ 1,488     $ 1,806     $ 4,300     $ 4,215  

Renewable Resource Recovery

    817       --       2,001       --  

Environmental Cost Recovery

    24       1,669       (25 )     7,305  

Transmission Cost Recovery

    (1,196 )     (594 )     (1,683 )     2,849  

North Dakota

                               

Renewable Resource Adjustment

    2,220       2,213       6,266       5,822  

Environmental Cost Recovery

    1,823       2,396       5,474       7,272  

Transmission Cost Recovery

    1,922       2,410       5,149       6,305  

South Dakota

                               

Environmental Cost Recovery

    545       613       1,580       1,755  

Transmission Cost Recovery

    496       596       1,282       1,324  

Conservation Improvement Program Costs and Incentives

    238       104       589       520  

Total

  $ 8,377     $ 11,213     $ 24,933     $ 37,367  

 

TCJA

 

The TCJA reduced the federal corporate income tax rate from 35% to 21%. Until recently, OTP’s rates have been developed using a 35% tax rate. The MPUC, the NDPSC, the SDPUC and the FERC all initiated dockets or proceedings to assess the impact to electric rates from the lower income tax rates under the TCJA and to 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. On August 9, 2018 the MPUC determined the impacts of the TCJA as calculated, including amortization of excess accumulated deferred income taxes, should be refunded and rates should be adjusted going forward to account for the impacts of the TCJA. No order has been issued and the details and timing of implementation currently are not known.

 

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 current 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. As of September 30, 2018, accrued refund liabilities related to the tax rate reduction were $6.0 million in Minnesota, $0.8 million in North Dakota for amounts collected under interim rates in effect in January and February 2018, and $1.1 million in South Dakota.

 

FERC

 

Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935 (Federal Power Act). The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a one-day suspension period, subject to ultimate approval by the FERC.

 

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 September 30, 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 U.S. Court of Appeals for the District of Columbia Circuit (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.

 

On October 16, 2018 the FERC issued an order proposing a methodology for addressing the issues that were remanded to the FERC by the D.C. Circuit in April 2017. The FERC order established a paper hearing on how the methodology should apply to the proceedings pending before the FERC involving NETOs’ ROE. In the order, the FERC selected a preliminary just and reasonable ROE for NETOs of 10.41%, exclusive of incentives, with a proposed cap on any pre-existing incentive-based total ROE at 13.08% and directed participants to submit supplemental briefs and additional written evidence regarding the proposed approaches to the Federal Power Act Section 206 inquiry and how to apply them to the NETO ROE complaints. Initial briefs are due 60 days from the date of the order with responses to those initial briefs due 30 days later.

 

OTP believes its estimated accrued MISO Tariff ROE refund liability of $1.6 million as of September 30, 2018 related to the second MISO tariff ROE complaint is appropriate, based on the information discussed above.

 

 

 

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:

 

   

September 30, 2018

   

Remaining Recovery/

Refund Period

 

(in thousands)

 

Current

   

Long-Term

   

Total

    (months)  

Regulatory Assets:

                               

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

  $ 9,090     $ 105,675     $ 114,765       see below  

Conservation Improvement Program Costs and Incentives2

    2,799       4,722       7,521       24  

Accumulated ARO Accretion/Depreciation Adjustment1

    --       7,038       7,038       asset lives  

Deferred Marked-to-Market Losses1

    2,262       1,158       3,420       27  

Unrecovered Tax Adjustment to Deferred Income Tax Asset1

    --       2,739       2,739       see below  

Big Stone II Unrecovered Project Costs – Minnesota1

    673       1,123       1,796       31  

Debt Reacquisition Premiums1

    218       805       1,023       168  

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

    --       695       695       asset lives  

Minnesota Renewable Resource Recovery Rider Accrued Revenues2

    475       --       475       12  

Big Stone II Unrecovered Project Costs – South Dakota1

    100       367       467       56  

Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues1

    422       --       422       7  

North Dakota Deferred Rate Case Expenses Subject to Recovery1

    333       --       333       12  

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

    180       60       240       15  

Minnesota Southwest Power Pool Transmission Cost Recovery Tracker1

    --       131       131       see below  

Deferred Income Taxes1

    --       40       40       asset lives  

Total Regulatory Assets

  $ 16,552     $ 124,553     $ 141,105          

Regulatory Liabilities:

                               

Deferred Income Taxes

  $ --     $ 148,103     $ 148,103       asset lives  

Accumulated Reserve for Estimated Removal Costs – Net of Salvage

    --       83,123       83,123       asset lives  

Refundable Fuel Clause Adjustment Revenues

    6,632       --       6,632       12  

North Dakota Renewable Resource Recovery Rider Accrued Refund

    301       --       301       6  

South Dakota Environmental Cost Recovery Rider Accrued Refund

    266       --       266       12  

Minnesota Environmental Cost Recovery Rider Accrued Refund

    221       --       221       1  

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

    19       182       201       15  

South Dakota Transmission Cost Recovery Rider Accrued Refund

    181       --       181       12  

Minnesota Transmission Cost Recovery Rider Accrued Refund

    156       --       156       15  

North Dakota Environmental Cost Recovery Rider Accrued Refund

    117       --       117       12  

Revenue for Rate Case Expenses Subject to Refund – Minnesota

    --       107       107       see below  

Other

    6       79       85       183  

North Dakota Transmission Cost Recovery Rider Accrued Refund

    27       --       27       12  

Total Regulatory Liabilities

  $ 7,926     $ 231,594     $ 239,520          

Net Regulatory Asset/(Liability) Position

  $ 8,626     $ (107,041 )   $ (98,415 )        

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.

 

 

   

December 31, 2017

   

Remaining Recovery/

Refund Period

 

(in thousands)

 

Current

   

Long-Term

   

Total

    (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  

Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues1

    75       --       75       12  

North Dakota Deferred Rate Case Expenses Subject to Recovery1

    309       --       309       12  

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

    --       1,985       1,985       24  

North Dakota Renewable Resource Rider Accrued Revenues2

    206       236       442       15  

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  

South Dakota Environmental Cost Recovery Rider Accrued Refund

    187       --       187       12  

Minnesota Environmental Cost Recovery Rider Accrued Refund

    1,667       --       1,667       11  

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

    132       48       180       24  

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  

Other

    5       84       89       192  

North Dakota Transmission Cost Recovery Rider Accrued Refund

    349       --       349       12  

Minnesota Southwest Power Pool Transmission Cost Tracker Refund

    --       609       609       22  

Minnesota Renewable Resource Recovery Rider Accrued Refund

    409       --       409       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 715 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 September 30, 2018 relate to forward purchases of energy scheduled for delivery through December 2020.

 

The Unrecovered Tax Adjustment to Deferred Income Tax Asset results from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes, (ASC 740) and ASC 980.

 

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 168 months.

 

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.

 

Minnesota Renewable Resource Rider Accrued Revenues relate to an increase in renewable revenue requirements resulting from the expiration of tax credits for certain wind turbines. The balance represents amounts subject to recovery from Minnesota customers that have not been billed to Minnesota customers as of September 30, 2018.

 

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

 

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

 

North Dakota 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.

 

MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups relate to the over/under collection of revenue based on comparison of the expected versus actual construction on eligible projects in the period. The true-ups also include the state jurisdictional portion of MISO Schedule 26/26A for regional transmission cost recovery that was included in the calculation of the state transmission riders and subsequently adjusted to reflect actual billing amounts in the schedule.

 

The Minnesota Southwest Power Pool Transmission Cost Recovery Tracker regulatory asset relates to costs incurred to serve Minnesota customers that are subject to recovery but that have not been billed to Minnesota customers as of September 30, 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.

 

Minnesota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s 2016 rate case in Minnesota that were 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 asset and liability related to Deferred Income Taxes results from changes in statutory tax rates accounted for in accordance with ASC 740.

 

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

 

The North Dakota Renewable Resource 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 September 30, 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 September 30, 2018.

 

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 September 30, 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 September 30, 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 were refundable to Minnesota customers as of September 30, 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 refundable to North Dakota customers as of September 30, 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 were 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 September 30, 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 were subject to refund as of December 31, 2017.

 

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 December 31, 2017.

 

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

    893       (986 )                     (93 )

Common Stock Retirements

    (356 )     (2,656 )                     (3,012 )

Net Income

                    68,184               68,184  

Other Comprehensive Loss

                            (176 )     (176 )

Employee Stock Incentive Plans Expense

            3,402                       3,402  

Common Dividends ($1.005 per share)

                    (39,895 )             (39,895 )

Balance, September 30, 2018

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

 

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 the Company may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, which expires on May 3, 2021. On 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 and Share Purchase Plan (the Plan), which permits shares purchased by participants in the Plan to be either new issue common shares or common shares purchased in the open market. The shelf registration for the Plan expires on May 3, 2021. The shelf registration statements replaced the Company’s prior shelf registration statements which expired 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.

 

 

Common Shares

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2017 through September 30, 2018:

 

Common Shares Outstanding, December 31, 2017

    39,557,491  

Issuances:

       

Executive Stock Performance Awards (2015 awards)

    114,648  

Executive Stock Performance Awards (2016 and 2017 awards)

    18,600  

Vesting of Restricted Stock Units

    26,575  

Restricted Stock Issued to Directors

    18,200  

Directors Deferred Compensation

    578  

Retirements:

       

Shares Withheld for Individual Income Tax Requirements

    (71,208 )

Common Shares Outstanding, September 30, 2018

    39,664,884  

 

Earnings Per Share

The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three- and nine-month periods ended September 30, 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:

 

   

Three Months ended

September 30

   

Nine Months ended

September 30

 
   

2018

   

2017

   

2018

   

2017

 

Weighted Average Common Shares Outstanding – Basic

    39,621,524       39,507,581       39,592,705       39,440,416  

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

    206,268       211,996       210,691       195,869  

Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees

    58,680       55,975       58,475       54,645  

Nonvested Restricted Shares

    14,761       16,982       17,712       18,923  

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

    2,332       2,832       2,522       3,009  

Total Dilutive Shares

    282,041       287,785       289,400       272,446  

Weighted Average Common Shares Outstanding – Diluted

    39,903,565       39,795,366       39,882,105       39,712,862  

 

The effect of dilutive shares on earnings per share for the three- and nine-month periods ended September 30, 2018 and 2017, resulted in no differences greater than $0.0125 between basic and diluted earnings per share in total or from continuing or discontinued operations in any of the periods. 

 

 

 

6. Share-Based Payments

 

Stock Incentive Awards

The following stock incentive awards were granted under the 2014 Stock Incentive Plan during the nine-month period ended September 30, 2018:

 

Award

 

Grant-Date

 

Shares/Units

Granted

   

Weighted

Average

Grant-Date

Fair Value

per Award

   

Vesting

Stock Performance Awards Granted to Executive Officers

 

February 5, 2018

    54,000     $ 35.73    

December 31, 2020

Restricted Stock Units Granted to Executive Officers

 

February 5, 2018

    15,200     $ 41.325    

25% per year through February 6, 2022

Restricted Stock Units Granted to Key Employees

 

April 9, 2018

    12,945     $ 38.45    

100% on April 8, 2022

Restricted Stock Units Granted to Key Employee

 

June 20, 2018

    1,000     $ 42.46    

100% on April 8, 2022

Restricted Stock Units Granted to Key Employee

 

September 25, 2018

    835     $ 43.25    

100% on April 8, 2022

Restricted Stock Granted to Nonemployee Directors

 

April 9, 2018

    18,200     $ 43.40    

33% per year through April 8, 2021

 

Under the performance share awards the aggregate award for performance at target is 54,000 shares. For target performance the participants would earn an aggregate of 27,000 common shares for achieving the target set for the Company’s 3-year average adjusted ROE. The participants would also earn an aggregate of 27,000 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the Edison Electric Institute Index over the performance measurement period of January 1, 2018 through December 31, 2020, with the beginning and ending share values based on the average closing price of a share of the Company’s common stock for the 20 trading days immediately following January 1, 2018 and the average closing price for the 20 trading days immediately preceding January 1, 2021. Actual payment may range from zero to 150% of the target amount, or up to 81,000 common shares. There are no voting or dividend rights related to these awards until the shares, if any, are issued at the end of the performance measurement period. The amount of payment in the event of retirement, resignation for good reason or involuntary termination without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that the payment of performance awards granted to an officer who is party to an Executive Employment Agreement with the Company is to be made at target at the date of any such event. The terms of these awards are such that the entire award will be classified and accounted for as equity, as required under ASC Topic 718, Compensation—Stock Compensation, and will be measured over the performance period based on the grant-date fair value of the award. The grant-date fair value of each performance share award was determined using a Monte Carlo fair valuation simulation model.

 

The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration in certain cases. All restricted stock units granted to executive officers are eligible to receive dividend equivalent payments on all unvested awards over the awards’ respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The grant-date fair value of each restricted stock unit granted to an executive officer was the average of the high and low market price of one share of the Company’s common stock on the date of grant. The grant-date fair value of each restricted stock unit granted to a key employee that is not an executive officer was based on the average of the high and low market price of one share of the Company’s common stock on the date of grant, discounted for the value of the dividend exclusion on those restricted stock units over the respective vesting periods.

 

The restricted shares granted to the Company’s nonemployee directors are eligible for full dividend and voting rights. Restricted shares not vested and dividends on those restricted shares are subject to forfeiture under the terms of the restricted stock award agreements. The grant-date fair value of each restricted share was the average of the high and low market price of one share of the Company’s common stock on the date of grant.

 

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

 

 

As of September 30, 2018, the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $5.3 million (before income taxes) which will be amortized over a weighted-average period of 2.0 years.

 

Amounts of compensation expense recognized under the Company’s five stock-based payment programs for the three- and nine-month periods ended September 30, 2018 and 2017 are presented in the table below:

 

   

Three Months Ended

September 30,

   

Nine Months Ended

September 30,

 

(in thousands)

 

2018

   

2017

   

2018

   

2017

 

Stock Performance Awards Granted to Executive Officers

  $ 718     $ 494     $ 2,037     $ 1,568  

Restricted Stock Units Granted to Executive Officers

    174       104       596       472  

Restricted Stock Granted to Executive Officers

    --       16       16       54  

Restricted Stock Granted to Nonemployee Directors

    165       144       496       416  

Restricted Stock Units Granted to Key Employees

    92       87       257       255  

Totals

  $ 1,149     $ 845     $ 3,402     $ 2,765  

 

 

7. Retained Earnings and Dividend Restriction

 

The Company is a holding company with no significant operations of its own. The primary source of funds for payments of dividends to the Company’s shareholders is from dividends paid or distributions made by the Company’s subsidiaries. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by the Company’s subsidiaries.

 

Both the Company and OTP credit agreements contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be considered to have occurred if the Company did not meet certain financial covenants. As of September 30, 2018, the Company was in compliance with these financial covenants.

 

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

 

The MPUC indirectly limits the amount of dividends OTP can pay to the Company by requiring an equity-to-total-capitalization ratio between 47.9% and 58.5% based on OTP’s 2018 capital structure petition effective by order of the MPUC on October 18, 2018. As of September 30, 2018, OTP’s equity-to-total-capitalization ratio including short-term debt was 53.6% and its net assets restricted from distribution totaled approximately $469,000,000. Total capitalization for OTP cannot currently exceed $1,204,416,000.

 

 

8. Commitments and Contingencies

 

Construction and Other Purchase Commitments

At September 30, 2018 OTP had commitments under contracts, including its share of construction program commitments, extending into 2019 of approximately $26.2 million. At December 31, 2017 OTP had commitments under contracts, including its share of construction program commitments, extending into 2019 of approximately $41.0 million. At September 30, 2018 T.O. Plastics had commitments for the purchase of resin through December 31, 2021 of approximately $5.6 million. At December 31, 2017 T.O. Plastics had commitments for the purchase of resin through December 31, 2021 of approximately $6.7 million.

 

Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts

OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2041. OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. OTP’s current coal purchase agreements for Coyote Station expire at the end of 2040. OTP’s current coal purchase agreements for Big Stone Plant expire at the end of 2020. OTP entered into a coal purchase agreement with Peabody COALSALES, LLC effective May 14, 2018 for the purchase of subbituminous coal for Big Stone Plant’s coal requirements through December 31, 2020. OTP has no fixed minimum purchase requirements under this agreement but all of Big Stone Plant’s coal requirements for the period covered must be purchased under this agreement, except for the purchase of a portion of Big Stone Plant’s coal requirements contracted to be purchased in 2018 and 2019 under existing agreements with Contura Coal Sales, LLC. OTP has an all-requirements agreement with Cloud Peak Energy Resources LLC for the purchase of subbituminous coal for Hoot Lake Plant through December 31, 2023. OTP has no fixed minimum purchase requirements under this agreement.

 

 

Operating Leases

OTP has obligations to make future land easement payments and operating lease payments, primarily for coal rail-car leases. In the first quarter of 2018, OTP entered into an agreement to lease rail cars for transporting coal to Hoot Lake Plant. The lease period runs from May 2018 through June 2021, increasing OTP’s commitments under operating leases by $216,000 in 2018, $324,000 in 2019, $324,000 in 2020 and $162,000 in 2021. The Company’s nonelectric companies have obligations to make future operating lease payments primarily related to leases of buildings and manufacturing equipment. In June 2018 BTD entered into an agreement to lease manufacturing and warehouse space in a building near its Georgia plant for a term of 63 months from July 2018 through September 2023, increasing its commitments under operating leases by approximately $79,000 in 2018, $322,000 in 2019, $332,000 in 2020, $342,000 in 2021, $352,000 in 2022 and $271,000 in 2023.

 

Contingencies

OTP had a $1.6 million refund liability on its balance sheet as of September 30, 2018 representing its 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 the likelihood of the FERC reducing the ROE component of the MISO Tariff and ordering MISO to refund amounts charged in excess of the lower rate. As discussed in Note 3 in greater detail, OTP believes its estimated accrued refund liability is appropriate based on the current set of facts and circumstances and is awaiting further action by FERC before determining if a change in this estimate will be needed.

 

Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. In addition to the ROE refund described earlier, the most significant contingencies impacting the Company’s consolidated financial statements are those related to environmental remediation, risks associated with warranty claims relating to divested businesses that could exceed the established reserve amounts and litigation matters. Should all of these known items, excluding the ROE refund liability already recognized, result in liabilities being incurred, the loss could be as high as $1.0 million.

 

In 2015 the Environmental Protection Agency (EPA), acting under Section 111(d) of the Clean Air Act, issued the Clean Power Plan which required states to submit plans to limit CO2 emissions from certain fossil fuel-fired power plants. The rule is not currently in effect as a result of a stay by the Supreme Court in 2016. In 2017, EPA issued a Notice of Proposed Rulemaking to repeal the Clean Power Plan; comments were due in April 2018. 

 

On August 21, 2018 EPA proposed a replacement for the Clean Power Plan -- the Affordable Clean Energy (ACE) Rule. Among other things, the ACE Rule (1) determines that the Best System of Emission Reduction for greenhouse gas emissions from coal-fired power plants is to improve the plants’ heat rates, (2) identifies a list of “candidate technologies” for improving a plant’s heat rate and (3) proposes that physical or operational changes to a power plant would not be a “major modification” triggering extensive New Source Review, if the change does increase hourly emissions. Comments on the ACE Rule are due October 31, 2018. If the ACE Rule goes into effect, states will have three years after the final rule to submit a state implementation plan.

 

Other

The Company is a party to litigation and regulatory enforcement matters arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of September 30, 2018 will not be material. 

 

 

 

9. Short-Term and Long-Term Borrowings

 

The following table presents the status of the Company’s lines of credit as of September 30, 2018 and December 31, 2017:

 

(in thousands)

 

Line Limit

   

In Use on

September 30,

2018

   

Restricted due to Outstanding Letters of Credit

   

Available on

September 30,

2018

   

Available on

December 31,

2017

 

Otter Tail Corporation Credit Agreement

  $ 130,000     $ 15,489     $ --     $ 114,511     $ 130,000  

OTP Credit Agreement

    170,000       --       300       169,700       57,329  

Total

  $ 300,000     $ 15,489     $ 300     $ 284,211     $ 187,329  

 

On October 31, 2018 both credit agreements were amended to extend the expiration dates by one year from October 31, 2022 to October 31, 2023.

 

Debt Issuances

 

2018 Note Purchase Agreement

On November 14, 2017, OTP entered into a Note Purchase Agreement (the 2018 Note Purchase Agreement) with the purchasers named therein, pursuant to which OTP agreed to issue to the purchasers, in a private placement transaction, $100 million aggregate principal amount of OTP’s 4.07% Series 2018A Senior Unsecured Notes due February 7, 2048 (the 2018 Notes). The 2018 Notes were issued on February 7, 2018. Proceeds from the 2018 Notes were used to repay outstanding borrowings under the OTP Credit Agreement.

 

OTP may prepay all or any part of the Notes (in an amount not less than 10% of the aggregate principal amount of the Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount so prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the Note Purchase Agreement, any prepayment made by OTP of all of the Notes then outstanding on or after August 7, 2047 will be made without any make-whole amount. The 2018 Note Purchase Agreement also requires OTP to offer to prepay all outstanding Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2018 Note Purchase Agreement) of OTP.

 

The 2018 Note Purchase Agreement contains a number of restrictions on the business of OTP. These include restrictions on OTP’s abilities to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The 2018 Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants. The 2018 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. The 2018 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event the OTP Credit Agreement or any renewal, extension or replacement thereof, at any time contains any financial covenant or other provision providing for limitations on interest expense and such a covenant is not contained in the 2018 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the 2018 Notes than any analogous provision contained in the 2018 Note Purchase Agreement (Additional Covenant), then unless waived by the Required Holders (as defined in the 2018 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2018 Note Purchase Agreement. The 2018 Note Purchase Agreement also provides for the amendment, modification or deletion of an Additional Covenant if such Additional Covenant is amended or modified under or deleted from the OTP Credit Agreement, provided that no default or event of default has occurred and is continuing.

 

 

The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of September 30, 2018 and December 31, 2017:

 

September 30, 2018 (in thousands)

 

OTP

   

Otter Tail

Corporation

   

Otter Tail

Corporation

Consolidated

 

Short-Term Debt

  $ --     $ 15,489     $ 15,489  

Long-Term Debt:

                       

3.55% Guaranteed Senior Notes, due December 15, 2026

          $ 80,000     $ 80,000  

Senior Unsecured Notes 4.63%, due December 1, 2021

  $ 140,000               140,000  

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

    30,000               30,000  

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

    42,000               42,000  

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

    60,000               60,000  

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

    50,000               50,000  

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

    90,000               90,000  

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

    100,000               100,000  

North Dakota Development Note, 3.95%, fully repaid April 1, 2018

            --       --  

PACE Note, 2.54%, due March 18, 2021

            564       564  

Total

  $ 512,000     $ 80,564     $ 592,564  

Less: Current Maturities net of Unamortized Debt Issuance Costs

    --       169       169  

Unamortized Long-Term Debt Issuance Costs

    1,991       420       2,411  

Total Long-Term Debt net of Unamortized Debt Issuance Costs

  $ 510,009     $ 79,975     $ 589,984  

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

  $ 510,009     $ 95,633     $ 605,642  

 

December 31, 2017 (in thousands)

 

OTP

   

Otter Tail

Corporation

   

Otter Tail

Corporation

Consolidated

 

Short-Term Debt

  $ 112,371     $ --     $ 112,371  

Long-Term Debt:

                       

Term Loan, LIBOR plus 0.90%, due February 5, 2018

          $ --     $ --  

3.55% Guaranteed Senior Notes, due December 15, 2026

            80,000       80,000  

Senior Unsecured Notes 4.63%, due December 1, 2021

  $ 140,000               140,000  

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

    30,000               30,000  

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

    42,000               42,000  

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

    60,000               60,000  

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

    50,000               50,000  

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

    90,000               90,000  

North Dakota Development Note, 3.95%, due April 1, 2018

            27       27  

PACE Note, 2.54%, due March 18, 2021

            684       684  

Total

  $ 412,000     $ 80,711     $ 492,711  

Less: Current Maturities net of Unamortized Debt Issuance Costs

    --       186       186  

Unamortized Long-Term Debt Issuance Costs

    1,684       461       2,145  

Total Long-Term Debt net of Unamortized Debt Issuance Costs

  $ 410,316     $ 80,064     $ 490,380  

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

  $ 522,687     $ 80,250     $ 602,937  

  

 

 

10. Pension Plan and Other Postretirement Benefits

 

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

 

   

Three Months Ended

September 30,

   

Nine Months Ended

September 30,

 

(in thousands)

 

2018

   

2017

   

2018

   

2017

 

Service Cost—Benefit Earned During the Period

  $ 1,615     $ 1,407     $ 4,845     $ 4,221  

Interest Cost on Projected Benefit Obligation

    3,363       3,534       10,089       10,604  

Expected Return on Assets

    (5,300 )     (4,807 )     (15,899 )     (14,421 )

Amortization of Prior-Service Cost:

                               

From Regulatory Asset

    4       30       12       89  

From Other Comprehensive Income1

    --       1       --       3  

Amortization of Net Actuarial Loss:

                               

From Regulatory Asset

    1,784       1,273       5,351       3,818  

From Other Comprehensive Income1

    46       31       137       94  

Net Periodic Pension Cost2

  $ 1,512     $ 1,469     $ 4,535     $ 4,408  

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

                               

2Allocation of Costs:

                               

Costs included in OTP capital expenditures

  $ 455     $ 285     $ 1,162     $ 856  

Service costs included in electric operation and maintenance expenses

    1,119       1,100       3,561       3,300  

Service costs included in other nonelectric expenses

    41       33       121       101  

Nonservice costs capitalized as regulatory assets

    (29 )     --       (74 )     --  

Nonservice costs included in nonservice cost components of postretirement benefits

    (74 )     51       (235 )     151  

 

Cash flows—The Company had no minimum funding requirement as of December 31, 2017 but made discretionary plan contributions totaling $20 million in the first quarter of 2018.

 

Executive Survivor and Supplemental Retirement Plan—Components of net periodic pension benefit cost of the Company’s unfunded, nonqualified benefit plan for executive officers and certain key management employees are as follows:

 

   

Three Months Ended

September 30,

   

Nine Months Ended

September 30,

 

(in thousands)

 

2018

   

2017

   

2018

   

2017

 

Service Cost—Benefit Earned During the Period

  $ 100     $ 73     $ 300     $ 218  

Interest Cost on Projected Benefit Obligation

    399       421       1,197       1,264  

Amortization of Prior-Service Cost:

                               

From Regulatory Asset

    4       4       12       12  

From Other Comprehensive Income1

    10       10       29       29  

Amortization of Net Actuarial Loss:

                               

From Regulatory Asset

    66       70       200       213  

From Other Comprehensive Income1

    166       110       496       330  

Net Periodic Pension Cost2

  $ 745     $ 688     $ 2,234     $ 2,066  

1Amortization of prior service costs and net actuarial losses from other comprehensive income are included in nonservice cost components of postretirement benefits on the face of the Company’s consolidated statements of income.

                               

2Allocation of Costs:

                               

Service costs included in electric operation and maintenance expenses

  $ 24     $ 24     $ 74     $ 71  

Service costs included in other nonelectric expenses

    76       49       226       147  

Nonservice costs included in nonservice cost components of postretirement benefits

    645       615       1,934       1,848  

 

 

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

 

   

Three Months Ended

September 30,

   

Nine Months Ended

September 30,

 

(in thousands)

 

2018

   

2017

   

2018

   

2017

 

Service Cost—Benefit Earned During the Period

  $ 382     $ 357     $ 1,145     $ 1,069  

Interest Cost on Projected Benefit Obligation

    646       678       1,937       2,034  

Amortization of Net Actuarial Loss:

                               

From Regulatory Asset

    412       233       1,236       699  

From Other Comprehensive Income1

    11       5       32       17  

Net Periodic Postretirement Benefit Cost2

  $ 1,451     $ 1,273     $ 4,350     $ 3,819  

Effect of Medicare Part D Subsidy

  $ (37 )   $ (141 )   $ (110 )   $ (421 )

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

                               

2Allocation of Costs:

                               

Costs included in OTP capital expenditures

  $ 108     $ 247     $ 275     $ 742  

Service costs included in electric operation and maintenance expenses

    264       278       841       835  

Service costs included in other nonelectric expenses

    10       9       29       26  

Nonservice costs capitalized as regulatory assets

    301       --       769       --  

Nonservice costs included in nonservice cost components of postretirement benefits

    768       739       2,436       2,216  

  

 

11. Fair Value of Financial Instruments

 

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

 

Cash Equivalents—The carrying amount approximates fair value because of the short-term maturity of those instruments.

 

Short-Term Debt—The carrying amount approximates fair value because the debt obligations are short-term and the balances outstanding as of September 30, 2018 and December 31, 2017 related to the Otter Tail Corporation Credit Agreement and the OTP Credit Agreement were subject to variable interest rates of LIBOR plus 1.50% and LIBOR plus 1.25%, respectively, which approximate market rates.

 

Long-Term Debt including Current Maturities—The fair value of the Company's and OTP’s long-term debt is estimated based on the current market indications of rates available to the Company for the issuance of debt. The fair value measurements of the Company’s long-term debt issues fall into level 2 of the fair value hierarchy set forth in ASC 820.

 

   

September 30, 2018

   

December 31, 2017

 

(in thousands)

 

Carrying

Amount

   

Fair Value

   

Carrying

Amount

   

Fair Value

 

Cash and Cash Equivalents

  $ 649     $ 649     $ 16,216     $ 16,216  

Short-Term Debt

    (15,489 )     (15,489 )     (112,371 )     (112,371 )

Long-Term Debt including Current Maturities

    (590,153 )     (589,368 )     (490,566 )     (543,691 )

  

 

 

13. Income Tax Expense – Continuing Operations

 

The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on the Company’s consolidated statements of income:

 

   

Three Months Ended

September 30,

   

Nine Months Ended

September 30,

 

(in thousands)

 

2018

   

2017

   

2018

   

2017

 

Income Before Income Taxes – Continuing Operations

  $ 30,632     $ 24,808     $ 82,391     $ 73,314  

Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for 2018, 39% for 2017)

  $ 7,964     $ 9,675     $ 21,422     $ 28,592  

Increases (Decreases) in Tax from:

                               

Federal Production Tax Credits

    (707 )     (1,349 )     (2,757 )     (5,411 )

Property Related Differences and Other Regulatory Adjustments

    1,187       103       (911 )     243  

North Dakota Wind Tax Credit Amortization – Net of Federal Taxes

    (258 )     (212 )     (774 )     (637 )

Excess Tax Deduction – Equity Method Stock Awards

    (73 )     --       (698 )     (697 )

Research and Development and Other Tax Credits

    (227 )     (189 )     (636 )     (576 )

Other Comprehensive Income Deferred Tax Rate Adjustment

    --       --       (531 )     --  

Allowance for Funds Used During Construction – Equity

    (138 )     (92 )     (416 )     (250 )

Corporate-Owned Life Insurance

    (332 )     (118 )     (360 )     (620 )

Employee Stock Ownership Plan Dividend Deduction

    (99 )     (172 )     (298 )     (517 )

Section 199 Domestic Production Activities Deduction

    --       (330 )     --       (990 )

Other Items – Net

    42       (281 )     166       158  

Income Tax Expense – Continuing Operations

  $ 7,359     $ 7,035     $ 14,207     $ 19,295  

Effective Income Tax Rate – Continuing Operations

    24.0 %     28.4 %     17.2 %     26.3 %

 

The following table summarizes the activity related to the Company’s unrecognized tax benefits:

 

(in thousands)

 

2018

   

2017

 

Balance on January 1

  $ 684     $ 891  

Increases (Decreases) Related to Tax Positions for Prior Years

    6       28  

Increases Related to Tax Positions for Current Year

    113       220  

Uncertain Positions Resolved During Year

    (186 )     (206 )

Balance on September 30

  $ 617     $ 933  

 

The balance of unrecognized tax benefits as of September 30, 2018 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of September 30, 2018 is not expected to change significantly within the next 12 months. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes in its consolidated statement of income. There was no amount accrued for interest on tax uncertainties as of September 30, 2018.

 

The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of September 30, 2018, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2015 for federal and North Dakota income taxes and prior to 2014 for Minnesota state income taxes.

 

The Company recognized the income tax effects of the TCJA in its 2017 consolidated financial statements in accordance with Staff Accounting Bulletin No. 118, which provides SEC staff guidance for the application of ASC Topic 740, Income Taxes, and allowed up to one year to complete the required analyses and accounting for the TCJA. At December 31, 2017 the Company was able to make reasonable estimates of the impact of the TCJA for the reduction in the federal corporate tax rate, changes to bonus depreciation and consequences on the Company’s regulatory liabilities. The accounting for the income tax effects of the enactment of the TCJA is complete as of September 30, 2018. The Company did not make any material adjustments to the amounts recorded at December 31, 2017 in 2018.

 

 

 

Item 2.      Management's Discussion and Analysis of Financial Condition and Results of Operations

 

Results of Operations

 

Following is an analysis of the operating results of Otter Tail Corporation (the Company, we, us and our) by business segment for the three- and nine-month periods ended September 30, 2018 and 2017, followed by a discussion of changes in our consolidated financial position during the nine months ended September 30, 2018 and our business outlook for the remainder of 2018.

 

Comparison of the Three Months Ended September 30, 2018 and 2017

 

Consolidated operating revenues were $227.7 million for the three months ended September 30, 2018 compared with $216.5 million for the three months ended September 30, 2017. Operating income was $38.3 million for the three months ended September 30, 2018 compared with $33.0 million for the three months ended September 30, 2017. The Company recorded diluted earnings per share of $0.58 for the three months ended September 30, 2018 compared with $0.45 for the three months ended September 30, 2017.

 

Amounts presented in the segment tables that follow for operating revenues, cost of products sold and other nonelectric operating expenses for the three-month periods ended September 30, 2018 and 2017 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:

 

Intersegment Eliminations (in thousands)

 

September 30, 2018

   

September 30, 2017

 

Operating Revenues:

               

Electric

    $10       $5  

Costs of Products Sold

    4       8  

Other Nonelectric Expenses

    6       (3)  

 

Electric

 

   

Three Months Ended

                 
   

September 30,

           

%

 

(in thousands)

 

2018

   

2017

   

Change

   

Change

 

Retail Sales Revenues from Contracts with Customers

  $ 88,750     $ 88,482     $ 268       0.3  

Changes in Accrued Revenues under Alternative Revenue Programs

    (317 )     471       (788 )     (167.3 )

Total Retail Sales Revenue

  $ 88,433     $ 88,953     $ (520 )     (0.6 )

Wholesale Revenues – Company Generation

    2,826       1,549       1,277       82.4  

Other Revenues

    14,183       12,897       1,286       10.0  

Total Operating Revenues

  $ 105,442     $ 103,399     $ 2,043       2.0  

Production Fuel

    17,129       16,096       1,033       6.4  

Purchased Power – System Use

    9,664       13,371       (3,707 )     (27.7 )

Other Operation and Maintenance Expenses

    33,897       35,469       (1,572 )     (4.4 )

Depreciation and Amortization

    14,023       13,157       866       6.6  

Property Taxes

    4,094       3,721       373       10.0  

Operating Income

  $ 26,635     $ 21,585     $ 5,050       23.4  

Electric kilowatt-hour (kwh) Sales (in thousands)

                               

Retail kwh Sales

    1,079,622       1,060,858       18,764       1.8  

Wholesale kwh Sales – Company Generation

    93,790       57,400       36,390       63.4  

Heating Degree Days

    107       37       70       189.2  

Cooling Degree Days

    339       284       55       19.4  

 

35

 

The following table shows heating and cooling degree days as a percent of normal:

 

   

Three Months ended September 30,

 
   

2018

   

2017

 

Heating Degree Days

    209.8 %     69.8 %

Cooling Degree Days

    95.8 %     80.2 %

 

The following table summarizes the estimated effect on diluted earnings per share of the difference in retail kwh sales under actual weather conditions and expected retail kwh sales under normal weather conditions in the third quarters of 2018 and 2017 and between the quarters:

 

   

2018 vs Normal

   

2017 vs Normal

   

2018 vs 2017

 

Effect on Diluted Earnings Per Share

    $(0.00)       $(0.01)       $0.01  

 

The $0.5 million decrease in retail revenue includes:

 

 

A $4.0 million increase in revenues mainly due to the additional amount of interim rate refund recorded in third quarter 2017 related to the Minnesota Public Utilities Commission’s (MPUC’s) final order in the 2016 general rate case.

 

 

A $1.4 million increase in revenues, net of an estimated refund, related to an interim rate increase implemented in January 2018 in conjunction with OTP's 2017 general rate increase request in North Dakota.

 

 

A $0.8 million increase in Minnesota Renewable Resource Adjustment (RRA) rider revenues related to an increase in renewable revenue requirements resulting from the expiration of production tax credits for certain wind turbines.

 

 

A $0.8 million increase in revenues related to increased electricity consumption due to warmer weather in third quarter 2018, evidenced by a 19.4% increase in cooling degree days between the periods.

 

offset by:

 

 

A $4.2 million decrease in revenues related to the recovery of lower fuel and purchased power costs incurred to serve retail customers, driven by more kwhs generated from low-fuel-cost, company-owned resources combined with a reduction in higher-cost power purchases.

 

 

A $2.3 million reduction in revenues due to a provision for refunds to Minnesota and South Dakota customers related to lower federal income taxes under the 2017 Tax Cuts and Jobs Act (TCJA).

 

 

A $0.6 million decrease in North Dakota and South Dakota Environmental Cost Recovery (ECR) rider revenues due to a reduction in the return on equity (ROE) component of the North Dakota rider from 10.75% in 2017 to 9.77% in 2018, less federal taxes being recovered through the riders and a lower investment balance of environmental upgrades due to depreciation.

 

 

A $0.4 million reduction in revenues related to a reduction in transmission costs, including lower federal income taxes under the TCJA, recoverable in rates and through transmission cost recovery (TCR) riders in North Dakota and Minnesota.

 

Wholesale electric revenues increased $1.3 million due to a 63.4% increase in wholesale kwh sales and an 11.7% increase in wholesale electric prices. Increased demand and higher wholesale prices combined with increased availability of OTP generating units provided greater opportunity for economic dispatch and wholesale energy sales in third quarter 2018 compared with third quarter 2017.

 

Other electric revenues increased $1.3 million due to increases in transmission tariff and transmission services revenue.

 

Production fuel costs increased $1.0 million, due to a 21.5% increase in kwhs generated from OTP’s fuel burning plants to provide electricity for the increases in retail and wholesale demand driven by warmer weather in OTP’s service territory in third quarter 2018 compared with third quarter 2017.

 

The cost of purchased power to serve retail customers decreased $3.7 million in relation to a 47.5% decrease in kwhs purchased due to higher market prices and increased availability of, and sourcing from, company-owned generating units.

 

36

 

Electric operating and maintenance expenses decreased $1.6 million due to the establishment of a $2.7 million regulatory asset for deferred recovery of an income tax adjustment related to TCJA guidance issued in third quarter 2018. This decrease was partially offset by a $1.1 million increase in external service costs related to a scheduled eight-week maintenance outage at Big Stone Plant that began in September 2018. The income tax adjustment is the result of August 2018 Internal Revenue Service (IRS) guidance clarifying changes related to the treatment of bonus depreciation rules for 2017, affecting 2017 deductions and reversals of excess deferred taxes in 2018. The adjustments related to the guidance resulted in a $2.7 million increase in income tax expense, which is subject to recovery through future rate adjustments. In accordance with regulatory accounting treatment, OTP recorded a regulatory asset and offsetting credit to operating expense of $2.7 million. The regulatory asset will be amortized to expense as the related revenue is recovered in rates.

 

Property tax expense increased $0.4 million due to an increase in North Dakota property taxes in 2018.

 

Depreciation expense increased $0.9 million mainly due to an increase in transmission project unitization and the Big Stone South–Brookings transmission line being placed in service in September 2017.

 

Manufacturing

 

   

Three Months Ended

                 
   

September 30,

           

%

 

(in thousands)

 

2018

   

2017

   

Change

   

Change

 

Operating Revenues

  $ 67,027     $ 54,355     $ 12,672       23.3  

Cost of Products Sold

    51,143       41,638       9,505       22.8  

Operating Expenses

    7,842       6,161       1,681       27.3  

Depreciation and Amortization

    3,716       3,780       (64 )     (1.7 )

Operating Income

  $ 4,326     $ 2,776     $ 1,550       55.8  

 

The $12.7 million increase in revenues in our Manufacturing segment includes the following:

 

 

Revenues at BTD Manufacturing, Inc. (BTD) increased $11.8 million, including increases in parts revenue of $4.1 million to manufacturers of construction equipment, $2.2 million to manufacturers of agricultural equipment, $2.0 million to manufacturers of lawn and garden equipment, $1.7 million to manufacturers of industrial equipment and $1.1 million to manufacturers of recreational vehicles. Included in the parts revenue increases is the pass through of higher material costs of $4.2 million, with the remaining increase due to higher sales volume and a slight increase in pricing unrelated to material cost increases. Revenues from scrap metal sales increased $0.7 million due to higher scrap volume from increased production and a 6% increase in scrap metal pricing.

 

 

Revenues at T.O. Plastics, Inc. (T.O. Plastics), our manufacturer of thermoformed plastic and horticultural products, increased $0.9 million due to a $1.6 million increase in sales of horticultural containers, partially offset by decreases in sales of industrial and life sciences products totaling $0.7 million.

 

The $9.5 million increase in cost of products sold in our Manufacturing segment includes the following:

 

 

Cost of products sold at BTD increased $8.7 million due to increased sales volume and the $4.2 million in higher material costs recovered in revenue.

 

 

Cost of products sold at T.O. Plastics increased $0.8 million due to the increase in sales volume and higher labor costs.

 

The $1.7 million increase in operating expenses in our Manufacturing segment includes a $1.6 million increase in expenses at BTD resulting from increases in in labor, benefit and recruiting costs for additional employees.

 

37

 

Plastics

 

   

Three Months Ended

                 
   

September 30,

           

%

 

(in thousands)

 

2018

   

2017

   

Change

   

Change

 

Operating Revenues

  $ 55,203     $ 58,708     $ (3,505 )     (6.0 )

Cost of Products Sold

    42,222       44,600       (2,378 )     (5.3 )

Operating Expenses

    3,260       3,083       177       5.7  

Depreciation and Amortization

    907       976       (69 )     (7.1 )

Operating Income

  $ 8,814     $ 10,049     $ (1,235 )     (12.3 )

 

Plastics segment revenues decreased $3.5 million due to a 12.5% decrease in pounds of polyvinyl-chloride (PVC) pipe sold, partially offset by a 7.5% increase in PVC pipe prices. Higher sales volume in third quarter 2017 was mainly due to increased sales and pricing resulting from hurricanes in the Gulf Coast region of the United States, where the major U.S. resin production plants are located. Hurricane Harvey had a significant impact on market conditions for September 2017. Major resin suppliers shut down production facilities which impacted raw material availability. This created pipe-availability concerns among distributors and contractors, which accelerated pipe demand and created positive sales-price pressure in the market, impacting our third quarter 2017 diluted earnings by an estimated $0.04 per share.

 

Cost of products sold decreased $2.4 million due to the 12.5% decrease in sales volume, partially offset by an 8.2% increase in the cost per pound of pipe sold. Although sales volume decreased while the cost per pound of pipe sold increased, gross margin per pound of PVC pipe sold still improved by 5.2% as a result of the 7.5% increase in revenue per pound of PVC pipe sold. Plastics segment operating expenses increased by $0.2 million.

 

Corporate

 

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

 

   

Three Months Ended

                 
   

September 30,

           

%

 

(in thousands)

 

2018

   

2017

   

Change

   

Change

 

Operating Expenses

  $ 1,451     $ 1,384     $ 67       4.8  

Depreciation and Amortization

    62       14       48       342.9  

 

Other Income

 

The $0.7 million increase in other income in the three months ended September 30, 2018 compared with the three months ended September 30, 2017 includes $0.3 million of nontaxable life insurance benefits from corporate-owned life insurance and a $0.3 million increase in other income at OTP related to an increase in allowance for equity funds used during construction (AFUDC) resulting from an increase in construction work in progress subject to AFUDC.

 

38

 

Income Taxes – Continuing Operations

 

Income tax expense - continuing operations increased only $0.3 million in the three months ended September 30, 2018 compared with the three months ended September 30, 2017, despite a $5.8 million increase in income before income taxes, mainly due to the reduction in the federal income tax rate from 35% to 21% under the TCJA decreasing income taxes by approximately $2.0 million. The $2.0 million tax decrease due to the lower tax rate was offset by a $2.0 million increase due to the reversal of excess deferred taxes related to IRS guidance clarifying changes to bonus depreciation under the TCJA applied to 2017 income taxes at OTP. The following table provides a reconciliation of income tax expense calculated at our net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on our consolidated statements of income for the three-month periods ended September 30, 2018 and 2017:

 

   

Three Months Ended September 30,

 

(in thousands)

 

2018

   

2017

 

Income Before Income Taxes – Continuing Operations

  $ 30,632     $ 24,808  

Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for 2018, 39% for 2017)

  $ 7,964     $ 9,675  

Increases (Decreases) in Tax from:

               

Property Related Differences and Other Regulatory Adjustments

    1,187       103  

Federal Production Tax Credits (PTCs)

    (707 )     (1,349 )

Corporate-Owned Life Insurance

    (332 )     (118 )

North Dakota Wind Tax Credit Amortization – Net of Federal Taxes

    (258 )     (212 )

Research and Development and Other Tax Credits

    (227 )     (189 )

Allowance for Funds Used During Construction – Equity

    (138 )     (92 )

Employee Stock Ownership Plan Dividend Deduction

    (99 )     (172 )

Excess Tax Deduction – Equity Method Stock Awards

    (73 )     --  

Section 199 Domestic Production Activities Deduction

    --       (330 )

Other Items – Net

    42       (281 )

Income Tax Expense – Continuing Operations

  $ 7,359     $ 7,035  

Effective Income Tax Rate – Continuing Operations

    24.0 %     28.4 %

 

Federal PTCs are recognized as wind energy is generated based on a per kwh rate prescribed in applicable federal statutes. OTP’s kwh generation from its wind turbines eligible for PTCs decreased 46.9% in the three months ended September 30, 2018 compared with the three months ended September 30, 2017 due to the PTC eligibility period ending for one of OTP’s wind farms. North Dakota wind energy credits are based on dollars invested in qualifying facilities and are being recognized on a straight-line basis over 25 years.

 

Comparison of the Nine Months Ended September 30, 2018 and 2017

 

Consolidated operating revenues were $695.3 million for the nine months ended September 30, 2018 compared with
$642.7 million for the nine months ended September 30, 2017. Operating income was $106.0 million for the nine months ended September 30, 2018 compared with $98.2 million for the nine months ended September 30, 2017. The Company recorded diluted earnings per share of $1.71 for the nine months ended September 30, 2018 compared with $1.36 for the nine months ended September 30, 2017.

 

Amounts presented in the segment tables that follow for operating revenues, cost of products sold and other nonelectric operating expenses for the nine-month periods ended September 30, 2018 and 2017 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:

 

Intersegment Eliminations (in thousands)

 

September 30, 2018

   

September 30, 2017

 

Operating Revenues:

               

Electric

  $ 31     $ 18  

Costs of Products Sold

    11       11  

Other Nonelectric Expenses

    20       7  

 

39

 

Electric

 

   

Nine Months Ended

                 
   

September 30,

           

%

 

(in thousands)

 

2018

   

2017

   

Change

   

Change

 

Retail Sales Revenues from Contracts with Customers

  $ 287,330     $ 281,615     $ 5,715       2.0  

Changes in Accrued Revenues under Alternative Revenue Programs

    (2,757 )     (1,192 )     (1,565 )     131.3  

Total Retail Sales Revenue

  $ 284,573     $ 280,423     $ 4,150       1.5  

Wholesale Revenues – Company Generation

    6,380       3,600       2,780       77.2  

Other Revenues

    41,179       40,163       1,016       2.5  

Total Operating Revenues

  $ 332,132     $ 324,186     $ 7,946       2.5  

Production Fuel

    51,723       44,955       6,768       15.1  

Purchased Power – System Use

    45,659       48,935       (3,276 )     (6.7 )

Other Operation and Maintenance Expenses

    111,113       109,494       1,619       1.5  

Depreciation and Amortization

    41,924       39,317       2,607       6.6  

Property Taxes

    11,202       11,228       (26 )     (0.2 )

Operating Income

  $ 70,511     $ 70,257     $ 254       0.4  

Electric kwh Sales (in thousands)

                               

Retail kwh Sales

    3,669,841       3,524,468       145,373       4.1  

Wholesale kwh Sales – Company Generation

    228,669       141,642       87,027       61.4  

Heating Degree Days

    4,373       3,539       834       23.6  

Cooling Degree Days

    567       380       187       49.2  

 

The following table shows heating and cooling degree days as a percent of normal:

 

   

Nine Months ended September 30,

 
   

2018

   

2017

 

Heating Degree Days

    111.4 %     88.7 %

Cooling Degree Days

    124.1 %     82.4 %

 

The following table summarizes the estimated effect on diluted earnings per share of the difference in retail kwh sales under actual weather conditions and expected retail kwh sales under normal weather conditions in the first nine months of 2018 and 2017 and between the periods:

 

   

2018 vs Normal

   

2017 vs Normal

   

2018 vs 2017

 

Effect on Diluted Earnings Per Share

    $0.06       $(0.04)       $0.10  

 

The $4.1 million increase in retail revenue includes:

 

 

A $6.1 million increase related to increased electricity consumption due to colder weather in the first four months of 2018 and warmer weather from May through September 2018 compared with the same periods in 2017, evidenced by a 23.6% increase in heating-degree days and 49.2% increase in cooling degree days between the periods.

 

 

A $4.7 million increase mainly related to an increase in kwh sales to a major industrial customer.

 

 

A $4.4 million increase, net of an estimated refund, related to an interim rate increase implemented in January 2018 in conjunction with OTP's 2017 general rate increase request in North Dakota.

 

 

A $2.4 million increase in North Dakota and Minnesota RRA rider revenues related to the expiration of federal PTC eligibility on one of OTP’s wind farms, which increases revenue requirements under the RRAs.

 

 

A $0.8 million increase in Conservation Improvement Program (CIP) cost recovery revenues and incentives.

 

offset by:

 

 

A $7.1 million reduction in revenues due to a provision for refunds to Minnesota and South Dakota customers related to lower federal income taxes under the TCJA.

 

 

A $3.6 million reduction in revenues related to a reduction in transmission costs, including lower federal income taxes under the TCJA, recoverable in rates and through TCR riders.

 

40

 

 

A $2.0 million decrease in North Dakota and South Dakota ECR rider revenues due to a reduction in the ROE component of the North Dakota rider from 10.75% in 2017 to 9.77% in 2018, less federal taxes being recovered through the riders and a lower investment balance of environmental upgrades due to depreciation.

 

 

A $1.6 million decrease related to the recovery of decreased fuel and purchased power costs due to an increase in lower-fuel-cost kwhs generated relative to a decrease in higher-cost kwhs purchased to serve retail customers.

 

Wholesale electric revenues increased $2.8 million due to a 61.4% increase in wholesale kwh sales and a 9.8% increase in wholesale electric prices. Increased demand and higher wholesale prices combined with increased availability of OTP generating units provided greater opportunity for economic dispatch and wholesale energy sales in the first nine months of 2018 compared with the first nine months of 2017.

 

Other electric revenues increased $1.0 million mostly due to a $1.4 million net increase in transmission tariff revenues, partially offset by $0.4 million in sales tax refunds received in 2017. No similar refunds were received in 2018.

 

Production fuel costs increased $6.8 million, mainly due to a 32.1% increase in kwhs generated from OTP’s fuel burning plants to provide electricity for the increase in retail and wholesale demand driven by colder weather in the first four months of 2018 and warmer weather from May through September 2018 compared with the same periods in 2017.

 

The cost of purchased power to serve retail customers decreased $3.3 million in relation to a 20.0% decrease in kwhs purchased due to higher market prices and increased availability of, and sourcing from, company-owned generating units.

 

Electric operating and maintenance expenses increased $1.6 million, including:

 

 

A $2.0 million increase in labor and benefit costs mainly due to an increase in benefit and other labor related costs loaded on direct labor costs.

 

 

A $1.0 million increase in CIP costs.

 

 

A $1.0 million increase in external service costs at Big Stone Plant, mainly related to a scheduled eight-week maintenance outage that began in September 2018.

 

 

A $0.7 million increase in storm repair expenses related to damages caused by severe weather in first quarter and June 2018.

 

 

A $0.4 million increase in external service costs for software licensing.

 

 

A $0.4 million increase in pollution control reagent costs related to a 31% increase in kwhs generated at OTP’s coal-fired power plants.

 

offset by:

 

 

A $2.7 million reduction in expense due to the establishment of a regulatory asset for deferred recovery of an income tax adjustment resulting from August 2018 IRS guidance clarifying changes related to the treatment of bonus depreciation rules for 2017, affecting 2017 deductions and reversals of excess deferred taxes in 2018. The adjustments related to the guidance resulted in a $2.7 million increase in income tax expense, which is subject to recovery through future rate adjustments. In accordance with regulatory accounting treatment, OTP recorded a regulatory asset and offsetting credit to operating expense of $2.7 million. The regulatory asset will be amortized to expense as the related revenue is recovered in rates.

 

 

A $1.3 million reduction in MISO and SPP transmission service charges.

 

Depreciation expense increased $2.6 million mainly due to an increase in transmission project unitization and the Big Stone South–Brookings transmission line being placed in service in September 2017.

 

41

 

Manufacturing

 

   

Nine Months Ended

                 
   

September 30,

           

%

 

(in thousands)

 

2018

   

2017

   

Change

   

Change

 

Operating Revenues

  $ 203,843     $ 172,076     $ 31,767       18.5  

Cost of Products Sold

    155,028       131,401       23,627       18.0  

Operating Expenses

    22,154       17,583       4,571       26.0  

Depreciation and Amortization

    11,330       11,511       (181 )     (1.6 )

Operating Income

  $ 15,331     $ 11,581     $ 3,750       32.4  

 

The $31.8 million increase in revenues in our Manufacturing segment includes the following:

 

 

Revenues at BTD increased $29.6 million, including increases in parts sales of $7.5 million to manufacturers of recreational vehicles, $7.1 million to manufacturers of large construction equipment, $6.8 million to manufacturers of agricultural equipment, $3.4 million to manufacturers of industrial equipment and $3.4 million to manufacturers of lawn and garden equipment. Included in the parts revenue increases is the pass through of higher material costs of $8.3 million, with the remaining increase due to higher sales volume and a slight increase in pricing unrelated to material cost increases. Revenue from scrap metal sales increased $1.7 million due to higher scrap volume from increased production and a 6% increase in scrap metal pricing.

 

 

Revenues at T.O. Plastics increased $2.2 million due to increased sales of horticultural containers across its customer base, partially offset by decreases in sales of industrial and life sciences products totaling $0.5 million.

 

The $23.6 million increase in cost of products sold in our Manufacturing segment includes the following:

 

 

Cost of products sold at BTD increased $21.7 million due to increased sales volume and the $8.3 million in higher material costs recovered in revenue.

 

 

Cost of products sold at T.O. Plastics increased $1.9 million related to the increase in product sales.

 

The $4.6 million increase in operating expenses in our Manufacturing segment includes a $4.4 million increase in expenses at BTD due to a $2.2 million increase in short-term incentives, a $1.4 million increase in labor, benefit and recruiting expenses due to more employees and a $0.8 million increase in other administrative and general expenses.

 

Plastics

 

   

Nine Months Ended

                 
   

September 30,

           

%

 

(in thousands)

 

2018

   

2017

   

Change

   

Change

 

Operating Revenues

  $ 159,332     $ 146,416     $ 12,916       8.8  

Cost of Products Sold

    120,674       114,130       6,544       5.7  

Operating Expenses

    9,136       7,816       1,320       16.9  

Depreciation and Amortization

    2,812       2,830       (18 )     (0.6 )

Operating Income

  $ 26,710     $ 21,640     $ 5,070       23.4  

 

Plastics segment revenues increased $12.9 million due to a 12.5% increase in PVC pipe prices on a 3.3% decrease in pounds of pipe sold. Higher sales volume in third quarter 2017 was mainly due to increased sales and pricing resulting from hurricanes in the Gulf Coast region of the United States, where the major U.S. resin production plants are located. Hurricane Harvey had a significant impact on market conditions for September of 2017. Major resin suppliers shut down production facilities which impacted raw material availability. This created pipe-availability concerns among distributors and contractors, which accelerated pipe demand and created positive sales-price pressure in the market, impacting our diluted earnings by an estimated $0.04 per share for the nine months ended September 30, 2017.

 

Cost of products sold decreased $6.5 million due to the 3.3% decrease in sales volume, partially offset by an 9.3% increase in the cost per pound of pipe sold. Although sales volume decreased while the cost per pound of pipe sold increased, gross margin per pound of PVC pipe sold still improved by 23.8% as a result of the 12.5% increase in revenue per pound of PVC pipe sold. Plastics segment operating expenses increased by $1.3 million mainly due to increase in incentives earned and commissions paid on more profitable sales.

 

42

 

Corporate

 

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

 

   

Nine Months Ended

                 
   

September 30,

           

%

 

(in thousands)

 

2018

   

2017

   

Change

   

Change

 

Operating Expenses

  $ 6,420     $ 5,233     $ 1,187       22.7  

Depreciation and Amortization

    150       31       119       383.8  

 

Corporate operating expenses increased $1.2 million, mainly as a result of increased employee benefit and insurance costs.

 

Other Income

 

The $1.4 million increase in other income in the nine months ended September 30, 2018 compared with the nine months ended September 30, 2017 is mainly due to a $1.0 million increase in other income at OTP related to an increase in AFUDC resulting from an increase in construction work in progress subject to AFUDC.

 

Income Taxes – Continuing Operations

 

Income tax expense - continuing operations decreased $5.1 million in the nine months ended September 30, 2018 compared with the nine months ended September 30, 2017 mainly due to the reduction in the federal income tax rate from 35% to 21% under the TCJA, partially offset by an increase in income tax expense resulting from a $9.1 million increase in income from continuing operations before income taxes. A $7.2 million net tax decrease mostly due to the lower tax rate, was partially offset by a $2.0 million increase in income tax expense due to the reversal of excess deferred taxes related to IRS guidance clarifying changes to bonus depreciation under the TCJA applied to 2017 income taxes at OTP. The following table provides a reconciliation of income tax expense calculated at our net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on our consolidated statements of income for the nine-month periods ended September 30, 2018 and 2017:

 

   

Nine Months Ended September 30,

 

(in thousands)

 

2018

   

2017

 

Income Before Income Taxes – Continuing Operations

  $ 82,391     $ 73,314  

Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for 2018, 39% for 2017)

  $ 21,422     $ 28,592  

Increases (Decreases) in Tax from:

               

Federal PTCs

    (2,757 )     (5,411 )

Property Related Differences and Other Regulatory Adjustments

    (911 )     243  

North Dakota Wind Tax Credit Amortization – Net of Federal Taxes

    (774 )     (637 )

Excess Tax Deduction – Equity Method Stock Awards

    (698 )     (697 )

Research and Development and Other Tax Credits

    (636 )     (576 )

Other Comprehensive Income Deferred Tax Rate Adjustment

    (531 )     --  

Allowance for Funds Used During Construction – Equity

    (416 )     (250 )

Corporate-Owned Life Insurance

    (360 )     (620 )

Employee Stock Ownership Plan Dividend Deduction

    (298 )     (517 )

Section 199 Domestic Production Activities Deduction

    --       (990 )

Other Items – Net

    166       158  

Income Tax Expense – Continuing Operations

  $ 14,207     $ 19,295  

Effective Income Tax Rate – Continuing Operations

    17.2 %     26.3 %

 

Federal PTCs are recognized as wind energy is generated based on a per kwh rate prescribed in applicable federal statutes. OTP’s kwh generation from its wind turbines eligible for PTCs decreased 48.1% in the nine months ended September 30, 2018 compared with the nine months ended September 30, 2017 due to the PTC eligibility period ending for one of OTP’s wind farms. North Dakota wind energy credits are based on dollars invested in qualifying facilities and are being recognized on a straight-line basis over 25 years.

 

43

 

Financial Position

 

The following table presents the status of our lines of credit as of September 30, 2018 and December 31, 2017:

 

(in thousands)

 

Line Limit

   

In Use on

September 30,

2018

   

Restricted due to Outstanding

Letters of Credit

   

Available on

September 30,

2018

   

Available on

December 31,

2017

 

Otter Tail Corporation Credit Agreement

  $ 130,000     $ 15,489     $ --     $ 114,511     $ 130,000  

OTP Credit Agreement

    170,000       --       300       169,700       57,329  

Total

  $ 300,000     $ 15,489     $ 300     $ 284,211     $ 187,329  

 

We believe we have the necessary liquidity to effectively conduct business operations for an extended period if needed. Our balance sheet is strong, and we are in compliance with our debt covenants. Financial flexibility is provided by operating cash flows, unused lines of credit, strong financial coverages, investment grade credit ratings and alternative financing arrangements such as leasing.

 

We believe our financial condition is strong and our cash, other liquid assets, operating cash flows, existing lines of credit, access to capital markets and borrowing ability because of investment-grade credit ratings, when taken together, provide adequate resources to fund ongoing operating requirements and future capital expenditures related to expansion of existing businesses and development of new projects. On May 3, 2018 we filed a shelf registration statement with the SEC under which we may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, which expires on May 3, 2021. On May 3, 2018, we also filed a shelf registration statement with the SEC for the issuance of up to 1,500,000 common shares until May 3, 2021, under the Company's Automatic Dividend Reinvestment and Share Purchase Plan (the Plan), which permits shares purchased by participants in the Plan to be either new issue common shares or common shares purchased in the open market. On May 1, 2018 our Distribution Agreement with J.P. Morgan Securities (JPMS) ended as required under the agreement.

 

Equity or debt financing will be required in the period 2018 through 2022 given the expansion plans related to our Electric segment to fund construction of new rate base investments. Also, such financing will be required should we decide to reduce borrowings under our lines of credit or refund or retire early any of our presently outstanding debt, to complete acquisitions or for other corporate purposes. Our operating cash flows and access to capital markets can be impacted by macroeconomic factors outside our control. In addition, our borrowing costs can be impacted by changing interest rates on short-term and long-term debt and ratings assigned to us by independent rating agencies, which in part are based on certain credit measures such as interest coverage and leverage ratios.

 

The determination of the amount of future cash dividends to be declared and paid will depend on, among other things, our financial condition, improvement in earnings per share, cash flows from operations, the level of our capital expenditures and our future business prospects. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by our subsidiaries. See note 7 to consolidated financial statements for more information. The decision to declare a dividend is reviewed quarterly by the board of directors. On February 5, 2018 our board of directors increased the quarterly dividend from $0.32 to $0.335 per common share.

 

Net cash provided by operating activities was $100.9 million for the nine months ended September 30, 2018 compared with net cash provided by operating activities of $114.1 million for the nine months ended September 30, 2017. Primary reasons for the $13.2 million decrease in net cash provided by operations between the periods were:

 

 

A $20.0 million increase in discretionary contributions to the corporation’s funded pension plan.

 

 

An $8.2 million reduction in the level of increases in deferred tax liabilities related to the lower federal income tax rate under the TCJA.

 

 

A $1.9 million increase in cash used for working capital items.

 

offset by:

 

 

A $14.1 million increase in net income.

 

 

A $2.5 million increase in depreciation and amortization expense.

 

Net cash used in investing activities was $75.9 million for the nine months ended September 30, 2018 compared with $95.3 million for the nine months ended September 30, 2017. The $19.4 million decrease in cash used for investing activities includes a $20.0 million decrease in capital expenditures, mainly due to a $23.1 million reduction in cash used for capital expenditures at OTP as the Big Stone South–Brookings 345 kiloVolt (kV) transmission line project, placed in service September 2017, was under construction during the first nine months of 2017. OTP continues work on the Big Stone South–Ellendale

 

44

 

345-kV transmission line project and on a major project to replace its customer information system. OTP expects to implement its new customer information system in first quarter 2019. Cash used for capital expenditures at BTD increased $2.8 million between periods mainly due to the addition of manufacturing equipment to add capabilities and expand capacity at all of BTD’s manufacturing plants. Corporate capital expenditures increased $0.5 million between periods for leasehold improvements and office equipment purchased in 2018 in connection with an April 2018 office move.

 

Net cash used in financing activities was $40.5 million for the nine months ended September 30, 2018 compared with $18.0 million for the nine months ended September 30, 2017. Financing activities in the first nine months of 2018 included proceeds from the issuance of $100 million in privately placed 4.07% Senior Unsecured Notes due February 7, 2048, which were used to pay down a portion of borrowings then outstanding under the OTP Credit Agreement. Common dividend payments of $39.9 million in the first nine months of 2018 was the major item contributing to the $40.5 million in net cash used in financing activities for the nine months ended September 30, 2018.

 

Financing activities in the first nine months of 2017 included a $59.3 million increase in net short-term borrowings under OTP’s credit agreement, of which $33.0 million was used to repay OTP’s 5.95% Senior Unsecured Series A Notes which matured on August 20, 2017. The additional short-term borrowings were used to fund a portion of OTP’s 2017 capital expenditures. Operating cash flows from our Manufacturing and Plastics segments were used to repay an additional $15.2 million in long-term debt related to those operations. Financing activities in the first nine months of 2017 also included common stock dividend payments of $38.0 million,

 

CAPITAL REQUIREMENTS

 

2018-2022 Capital Expenditures

 

The following table shows our 2017 capital expenditures and 2018 through 2022 anticipated capital expenditures and electric utility average rate base:

 

(in millions)

 

2017

   

2018

   

2019

   

2020

   

2021

   

2022

   

Total

 

Capital Expenditures:

                                                       

Electric Segment:

                                                       

Renewables and Natural Gas Generation

          $ 2     $ 163     $ 267     $ 20     $ 82     $ 534  

Transformative Technology and Infrastructure

            2       16       30       40       38       126  

Transmission

            38       26       10       13       9       96  

Other

            49       44       41       44       46       224  

Total Electric Segment

  $ 119     $ 91     $ 249     $ 348     $ 117     $ 175     $ 980  

Manufacturing and Plastics Segments

    14       15       14       15       14       14       72  

Total Capital Expenditures

  $ 133     $ 106     $ 263     $ 363     $ 131     $ 189     $ 1,052  

Total Electric Utility Average Rate Base

  $ 1,055     $ 1,108     $ 1,171     $ 1,430     $ 1,561     $ 1,597          

 

The consolidated capital expenditure plan for the 2018-2022 time period calls for $1.05 billion based on the need for additional wind and solar in rate base and capital spending for Astoria Station, a natural gas-fired plant that will replace Hoot Lake Plant when it is retired in 2021. Given the increased capital expenditure plan, our compounded annual growth rate in rate base is projected to be approximately 9% from 2017 through 2022. Execution on the currently anticipated electric utility capital expenditure plan is expected to grow rate base and be a key driver in increasing utility earnings over the 2018 through 2022 timeframe.

 

On November 16, 2016 OTP entered into an Asset Purchase Agreement (the Purchase Agreement) with EDF Renewable Development, Inc. and certain of its affiliated companies (EDF) to purchase and assume the development assets associated with a 150-megawatt (MW) wind farm in southeastern North Dakota (the Merricourt Project) for a purchase price of $34.7 million, subject to adjustments for interconnection costs. The Purchase Agreement will close on the satisfactory receipt of regulatory reviews, interconnection costs and approval and other conditions. On the same day, OTP entered into a Turnkey Engineering, Procurement and Construction Services Agreement with EDF that will be effective upon the closing of the Purchase Agreement pursuant to which EDF will construct the wind farm with a targeted completion date in 2020 for consideration of $200.5 million, subject to certain adjustments, payable following the closing of the Purchase Agreement in installments in connection with certain project construction milestones. Dependent on the expected timing of MISO interconnection approval, construction of the Merricourt Project is currently anticipated to begin in 2019. The agreements contain representations, warranties, covenants and indemnities customary to transactions of this type and include provisions for

 

45

 

liquidated damages to be paid by EDF in the event of certain occurrences described in the agreements. As of September 30, 2018, OTP had capitalized approximately $4.7 million in development costs associated with the Merricourt Project. A final order for an Advance Determination of Prudence (ADP), subject to qualifications and compliance obligations, and a Certificate of Public Convenience and Necessity were issued by the North Dakota Public Service Commission (NDPSC) on November 3, 2017. On October 26, 2017 the MPUC approved the facility under the Renewable Energy Standard making the Merricourt Project eligible for cost recovery under the Minnesota Renewable Resource Recovery rider, subject to qualifications and reporting obligations.

 

In addition to the Merricourt Project, OTP is moving forward with plans for the development, construction and ownership of a 250-MW simple-cycle natural gas-fired combustion turbine generation facility near Astoria, South Dakota (Astoria Station) as part of its plan to reliably meet customers’ electric needs, replace expiring capacity purchase agreements and prepare for the planned retirement of its Hoot Lake Plant in 2021. OTP expects the project will cost approximately $165 million. As of September 30, 2018, OTP had capitalized approximately $6.1 million in development costs associated with Astoria Station. On August 3, 2018 the SDPUC voted to approve the site permit for Astoria Station. A final order granting ADP for Astoria Station was issued by the NDPSC on November 3, 2017, subject to certain qualifications and compliance obligations. The MISO interconnection agreement for Astoria Station is expected to be signed in fourth quarter 2018.

 

If a resource addition is determined to be prudent by the NDPSC, a public utility may recover in its rates for North Dakota customers, and in a timely manner consistent with the public utility's financial obligations, the jurisdictional share of amounts the public utility reasonably incurred or obligated on a prudent resource addition, including accrued allowance for funds used during construction, even though the resource addition may never be fully operational or used by the public utility to serve its North Dakota customers. The cost amortization period for a discontinued resource addition may not exceed five years from the date commencement of the recovery is approved by the NDPSC. No return on amounts incurred or obligated by the public utility may be authorized for the period after the resource addition is discontinued.

 

Contractual Obligations

 

In the first quarter of 2018 OTP entered into an agreement to lease rail cars for transporting coal to Hoot Lake Plant. In the second quarter of 2018 BTD entered into an agreement to lease manufacturing and warehouse space in a building near its Georgia plant for a term of five years from July 2018 through June 2023. As a result, our operating lease obligations reported in the table on page 50 of our Annual Report on Form 10-K for the year ended December 31, 2017 increased $0.3 million for 2018, $1.3 million for 2019 and 2020, $0.9 million for 2021 and 2022, and $0.3 million for 2023.

 

REGULATORY ISSUES

 

Fuel and Purchased Power Costs Recovery—On December 19, 2017, the MPUC issued an order authorizing the implementation of a new fuel clause adjustment mechanism to be implemented July 1, 2019. On September 20, 2018, the MPUC approved a delay of the implementation until January 1, 2020. Prior to implementation, OTP will be required to submit forecasted monthly fuel cost rates for the twelve-month period beginning January 1, 2020. Upon approval by the MPUC, those rates will be published in advance of each year to give customers notice of the next years’ monthly fuel rates, and those will be the rates OTP will charge per kwh to cover fuel costs. OTP will track its actual costs throughout the year and then file an annual report with the MPUC comparing the actual cost per kwh to the billed cost per kwh to determine if any over or under collection of costs occurred. OTP would refund any over-collections, or in the case of an under-collection, need to show prudence of costs before allowed recovery of under-collections. The refund of any over-collection or recovery of any under-collection would be handled through a true-up mechanism. OTP is working with other Minnesota utilities, the Minnesota Department of Commerce and other stakeholders to address questions and further develop the mechanism prior to implementation.

 

On implementation of the order, OTP will be required to reserve revenues, accrue a liability and refund amounts of fuel and purchased power and related costs collected in excess of amounts for which it was granted recovery in its rate case or annual fuel cost adjustment filing that preceded the annual period of recovery. OTP will no longer be able to accrue revenue and a regulatory asset for fuel and purchased power costs incurred in excess of amounts it was allowed to recover unless and until recovery of those excess amounts has been granted through a true-up mechanism that will be provided for in a subsequent order by the MPUC. This mechanism for recovery of fuel and purchased power and related costs incurred to serve Minnesota customers could result in reductions in Electric segment operating income margins and could increase variability in our consolidated net income in future periods if those costs exceed forecasted costs.

 

46

 

CAPITAL RESOURCES

 

On May 3, 2018 we filed a shelf registration statement with the SEC under which we may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, which expires on May 3, 2021. On May 3, 2018 we also filed a shelf registration statement with the SEC for the issuance of up to 1,500,000 common shares under our Automatic Dividend Reinvestment and Share Purchase Plan (the Plan), which permits shares purchased by participants in the Plan to be either new issue common shares or common shares purchased in the open market. The shelf registration for the Plan expires on May 3, 2021. On May 1, 2018 our Distribution Agreement with JPMS ended.

 

Short-Term Debt

 

The following table presents the status of our lines of credit as of September 30, 2018 and December 31, 2017:

 

(in thousands)

 

Line Limit

   

In Use on

September 30,

2018

   

Restricted due to Outstanding

Letters of Credit

   

Available on

September 30,

2018

   

Available on

December 31,

2017

 

Otter Tail Corporation Credit Agreement

  $ 130,000     $ 15,489     $ --     $ 114,511     $ 130,000  

OTP Credit Agreement

    170,000       --       300       169,700       57,329  

Total

  $ 300,000     $ 15,489     $ 300     $ 284,211     $ 187,329  

 

On October 29, 2012 we entered into a Third Amended and Restated Credit Agreement (the Otter Tail Corporation Credit Agreement), which is an unsecured $130 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the Otter Tail Corporation Credit Agreement. On October 31, 2018 the Otter Tail Corporation Credit Agreement was amended to extend its expiration date by one year from October 31, 2022 to October 31, 2023. We can draw on this credit facility to refinance certain indebtedness and support our operations and the operations of certain of our subsidiaries. Borrowings under the Otter Tail Corporation Credit Agreement bear interest at LIBOR plus 1.50%, subject to adjustment based on our senior unsecured credit ratings or the issuer rating if a rating is not provided for the senior unsecured credit. We are required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The Otter Tail Corporation Credit Agreement contains a number of restrictions on us and the businesses of our wholly owned subsidiary, Varistar Corporation and its subsidiaries, including restrictions on our and their ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of certain other parties and engage in transactions with related parties. The Otter Tail Corporation Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The Otter Tail Corporation Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in our credit ratings. Our obligations under the Otter Tail Corporation Credit Agreement are guaranteed by certain of our subsidiaries. Outstanding letters of credit issued by us under the Otter Tail Corporation Credit Agreement can reduce the amount available for borrowing under the line by up to $40 million.

 

On October 29, 2012 OTP entered into a Second Amended and Restated Credit Agreement (the OTP Credit Agreement), providing for an unsecured $170 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the OTP Credit Agreement. On October 31, 2018 the OTP Credit Agreement was amended to extend its expiration date by one year from October 31, 2022 to October 31, 2023. OTP can draw on this credit facility to support the working capital needs and other capital requirements of its operations, including letters of credit in an aggregate amount not to exceed $50 million outstanding at any time. Borrowings under this line of credit bear interest at LIBOR plus 1.25%, subject to adjustment based on the ratings of OTP’s senior unsecured debt or the issuer rating if a rating is not provided for the senior unsecured debt. OTP is required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The OTP Credit Agreement contains a number of restrictions on the business of OTP, including restrictions on its ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The OTP Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The OTP Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. OTP’s obligations under the OTP Credit Agreement are not guaranteed by any other party.

 

47

 

Long-Term Debt

 

2018 Note Purchase Agreement

On November 14, 2017, OTP entered into a Note Purchase Agreement (the 2018 Note Purchase Agreement) with the purchasers named therein, pursuant to which OTP agreed to issue to the purchasers, in a private placement transaction, $100 million aggregate principal amount of OTP’s 4.07% Series 2018A Senior Unsecured Notes due February 7, 2048 (the 2018 Notes). The 2018 Notes were issued on February 7, 2018. Proceeds from the 2018 Notes were used to repay outstanding borrowings under the OTP Credit Agreement.

 

OTP may prepay all or any part of the 2018 Notes (in an amount not less than 10% of the aggregate principal amount of the Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount so prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the 2018 Note Purchase Agreement, any prepayment made by OTP of all of the 2018 Notes then outstanding on or after August 7, 2047 will be made without any make-whole amount. The 2018 Note Purchase Agreement also requires OTP to offer to prepay all outstanding 2018 Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2018 Note Purchase Agreement) of OTP.

 

The 2018 Note Purchase Agreement contains a number of restrictions on the business of OTP. These include restrictions on OTP’s abilities to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The 2018 Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2018 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. The 2018 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event the OTP Credit Agreement or any renewal, extension or replacement thereof, at any time contains any financial covenant or other provision providing for limitations on interest expense and such a covenant is not contained in the 2018 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the 2018 Notes than any analogous provision contained in the 2018 Note Purchase Agreement (an Additional Covenant), then unless waived by the Required Holders (as defined in the 2018 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2018 Note Purchase Agreement. The 2018 Note Purchase Agreement also provides for the amendment, modification or deletion of an Additional Covenant if such Additional Covenant is amended or modified under or deleted from the OTP Credit Agreement, provided that no default or event of default has occurred and is continuing.

 

2016 Note Purchase Agreement

On September 23, 2016 we entered into a Note Purchase Agreement (the 2016 Note Purchase Agreement) with the purchasers named therein, pursuant to which we agreed to issue to the purchasers, in a private placement transaction, $80 million aggregate principal amount of our 3.55% Guaranteed Senior Notes due December 15, 2026 (the 2026 Notes). The 2026 Notes were issued on December 13, 2016. Our obligations under the 2016 Note Purchase Agreement and the 2026 Notes are guaranteed by our Material Subsidiaries (as defined in the 2016 Note Purchase Agreement, but specifically excluding OTP). The proceeds from the issuance of the 2026 Notes were used to repay the remaining $52,330,000 of our 9.000% Senior Notes due December 15, 2016, and to pay down a portion of the $50 million in funds borrowed in February 2016 under a Term Loan Agreement.

 

We may prepay all or any part of the 2026 Notes (in an amount not less than 10% of the aggregate principal amount of the 2026 Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the 2016 Note Purchase Agreement, any optional prepayment made by us of all of the 2026 Notes on or after September 15, 2026 will be made without any make-whole amount. We are required to offer to prepay all of the outstanding 2026 Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2016 Note Purchase Agreement) of the Company. In addition, if we and our Material Subsidiaries sell a “substantial part” of our or their assets and use the proceeds to prepay or retire senior Interest-bearing Debt (as defined in the 2016 Note Purchase Agreement) of the Company and/or a Material Subsidiary in accordance with the terms of the 2016 Note Purchase Agreement, we are required to offer to prepay a Ratable Portion (as defined in the 2016 Note Purchase Agreement) of the 2026 Notes held by each holder of the 2026 Notes.

 

The 2016 Note Purchase Agreement contains a number of restrictions on the business of the Company and our Material Subsidiaries. These include restrictions on our and our Material Subsidiaries’ abilities to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, engage in transactions with related parties, redeem or pay dividends on our and our Material Subsidiaries’ shares of capital stock, and make investments. The 2016 Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants as described below under the

 

48

 

heading “Financial Covenants.” The 2016 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in our or our Material Subsidiaries’ credit ratings.

 

2013 Note Purchase Agreement

On August 14, 2013 OTP entered into a Note Purchase Agreement (the 2013 Note Purchase Agreement) with the purchasers named therein, pursuant to which OTP agreed to issue to the purchasers, in a private placement transaction, $60 million aggregate principal amount of OTP’s 4.68% Series A Senior Unsecured Notes due February 27, 2029 (the Series A Notes) and $90 million aggregate principal amount of OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044 (the Series B Notes and, together with the Series A Notes, the Notes). The notes were issued on February 27, 2014.

 

The 2013 Note Purchase Agreement states that OTP may prepay all or any part of the Notes (in an amount not less than 10% of the aggregate principal amount of the Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount, provided that if no default or event of default under the 2013 Note Purchase Agreement exists, any optional prepayment made by OTP of (i) all of the Series A Notes then outstanding on or after November 27, 2028 or (ii) all of the Series B Notes then outstanding on or after November 27, 2043, will be made at 100% of the principal prepaid but without any make-whole amount. In addition, the 2013 Note Purchase Agreement states OTP must offer to prepay all of the outstanding Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2013 Note Purchase Agreement) of OTP.

 

The 2013 Note Purchase Agreement contains a number of restrictions on the business of OTP, including restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The 2013 Note Purchase Agreement also contains affirmative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2013 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. The 2013 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event the OTP Credit Agreement or any renewal, extension or replacement thereof, at any time contains any financial covenant or other provision providing for limitations on interest expense and such a covenant is not contained in the 2013 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the Notes than any analogous provision contained in the 2013 Note Purchase Agreement (an Additional Covenant), then unless waived by the Required Holders (as defined in the 2013 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2013 Note Purchase Agreement. The 2013 Note Purchase Agreement also provides for the amendment, modification or deletion of an Additional Covenant if such Additional Covenant is amended or modified under or deleted from the OTP credit agreement, provided that no default or event of default has occurred and is continuing.

 

2007 and 2011 Note Purchase Agreements

On December 1, 2011, OTP issued $140 million aggregate principal amount of its 4.63% Senior Unsecured Notes due December 1, 2021 pursuant to a Note Purchase Agreement dated as of July 29, 2011 (the 2011 Note Purchase Agreement). OTP also has outstanding its $122 million senior unsecured notes issued in three series consisting of $30 million aggregate principal amount of 6.15% Senior Unsecured Notes, Series B, due 2022; $42 million aggregate principal amount of 6.37% Senior Unsecured Notes, Series C, due 2027; and $50 million aggregate principal amount of 6.47% Senior Unsecured Notes, Series D, due 2037 (collectively, the 2007 Notes). The 2007 Notes were issued pursuant to a Note Purchase Agreement dated as of August 20, 2007 (the 2007 Note Purchase Agreement). On August 21, 2017 OTP used borrowings under the OTP Credit Agreement to retire its $33 million aggregate principal amount of 5.95% Senior Unsecured Notes, Series A, which had been issued under the 2007 Note Purchase Agreement and matured on August 20, 2017.

 

The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each states that OTP may prepay all or any part of the notes issued thereunder (in an amount not less than 10% of the aggregate principal amount of the notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount. The 2011 Note Purchase Agreement states in the event of a transfer of utility assets put event, the noteholders thereunder have the right to require OTP to repurchase the notes held by them in full, together with accrued interest and a make-whole amount, on the terms and conditions specified in the 2011 Note Purchase Agreement. The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each also states that OTP must offer to prepay all of the outstanding notes issued thereunder at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of OTP. The note purchase agreements contain a number of restrictions on OTP, including restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The note purchase agreements also include affirmative covenants and events of default, and certain financial covenants as described below under the heading “Financial Covenants.”

 

49

 

Financial Covenants

We were in compliance with the financial covenants in our debt agreements as of September 30, 2018.

 

No Credit or Note Purchase Agreement contains any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies.

 

Our borrowing agreements are subject to certain financial covenants. Specifically:

 

 

Under the Otter Tail Corporation Credit Agreement and the 2016 Note Purchase Agreement, we may not permit the ratio of our Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit our Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis). As of September 30, 2018, our Interest and Dividend Coverage Ratio calculated under the requirements of the Otter Tail Corporation Credit Agreement and the 2016 Note Purchase Agreement was 4.78 to 1.00.

 

 

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

 

 

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

 

 

Under the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, OTP may not permit the ratio of its Consolidated Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, in each case as provided in the related borrowing agreement, and OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement. As of September 30, 2018, OTP’s Interest and Dividend Coverage Ratio and Interest Charges Coverage Ratio, calculated under the requirements of the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, was 3.63 to 1.00.

 

 

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

 

As of September 30, 2018, our ratio of Interest-bearing Debt to Total Capitalization was 0.46 to 1.00 on a consolidated basis and 0.46 to 1.00 for OTP. Neither Otter Tail Corporation nor OTP had any Priority Indebtedness outstanding as of September 30, 2018.

 

OFF-BALANCE-SHEET ARRANGEMENTS

 

We and our subsidiary companies have outstanding letters of credit totaling $3.2 million, but our line of credit borrowing limits are only restricted by $0.3 million in outstanding letters of credit. We do not have any other off-balance-sheet arrangements or any relationships with unconsolidated entities or financial partnerships. These entities are often referred to as structured finance special purpose entities or variable interest entities, which are established for the purpose of facilitating off-balance-sheet arrangements or for other contractually narrow or limited purposes. We are not exposed to any financing, liquidity, market or credit risk that could arise if we had such relationships.

 

2018 BUSINESS OUTLOOK

 

We are narrowing our 2018 consolidated diluted earnings per share guidance to be in the range of $2.00 to $2.10 from our August 6, 2018 guidance range of $1.95 to $2.10. We have taken into consideration the cyclical nature of some of our businesses as well as current regulatory factors facing our Electric segment. We currently expect capital expenditures for 2018 to be $106 million compared with actual cash used for capital expenditures of $133 million in 2017. Our planned expenditures for 2018 include $18 million for the Big Stone South–Ellendale transmission line project, which positively impacts earnings by providing an immediate return on invested funds through rider recovery mechanisms.

 

50

 

Segment components of our 2018 earnings per share guidance range compared with 2017 actual earnings are as follows:

 

 

 

2017 EPS by

   

2018 Guidance

February 12, 2018

   

2018 Guidance

May 7, 2018

   

2018 Guidance

August 6, 2018

   

2018 Guidance

November 5, 2018

 
Diluted Earnings Per Share   Segment    

Low

   

High

   

Low

   

High

   

Low

   

High

   

Low

   

High

 

Electric

  $ 1.24     $ 1.34     $ 1.37     $ 1.34     $ 1.37     $ 1.34     $ 1.37     $ 1.34     $ 1.36  

Manufacturing

  $ 0.28     $ 0.26     $ 0.30     $ 0.26     $ 0.30     $ 0.26     $ 0.30     $ 0.28     $ 0.31  

Plastics

  $ 0.54     $ 0.36     $ 0.40     $ 0.48     $ 0.52     $ 0.55     $ 0.59     $ 0.59     $ 0.61  

Corporate

  $ (0.25 )   $ (0.16 )   $ (0.12 )   $ (0.18 )   $ (0.14 )   $ (0.20 )   $ (0.16 )   $ (0.21 )   $ (0.18 )

Total – Continuing Operations

  $ 1.81     $ 1.80     $ 1.95     $ 1.90     $ 2.05     $ 1.95     $ 2.10     $ 2.00     $ 2.10  

Return on Equity

    10.6 %     10.1 %     10.9 %     10.6 %     11.5 %     10.9 %     11.8 %     11.2 %     11.8 %

 

The following items contribute to our current earnings guidance for 2018.

 

 

We expect 2018 Electric segment net income to be higher than 2017 segment net income based on:

 

 

o

Normal weather for the remainder of 2018. Milder than normal weather in 2017 negatively impacted diluted earnings per share by an estimated $0.04 compared to normal.

 

 

o

Impact of our North Dakota rate case. In a September 26, 2018 hearing the NDPSC approved an overall annual revenue increase of $4.6 million (3.1%) and a ROE of 9.77% on a 52.5% equity capital structure. This compares with our March 2018 adjusted annual revenue increase request of $7.1 million (4.8%) and a requested ROE of 10.3%. The NDPSC’s approval results in no rate base adjustments from our original request and allows for future rider recovery of the planned Astoria natural gas-fired generating facility. Final rates will be effective January 1, 2019, with refunds of excess revenues collected under interim rates applied to customers’ March 2019 bills.

 

 

o

Increased revenue from our South Dakota rate case filed on April 20, 2018. Our request with the SDPUC is to increase non-fuel rates in South Dakota by approximately $3.3 million annually, or 10.1%. Interim rates based on this request went into effect October 18, 2018. We cannot provide assurance our interim rates will become final.

 

 

o

Increases in transmission investments and other revenues.

 

offset by: 

 

 

o

Increased operating and maintenance expenses of $0.05 per share due to a planned maintenance outage at our Big Stone Plant and $0.09 per share for increasing costs of pension, medical, workers compensation and retiree medical benefits. The increase in pension costs is a result of a decrease in the discount rate from 4.60% to 3.90%.

 

 

o

Higher depreciation expense due to large capital projects being put into service.

 

 

o

Increased interest expense related to replacing short-term debt at an average annual rate of 2.4% with long-term debt at a rate of 4.07% along with an increase in combined short-term and long-term borrowings to finance portions of 2018 planned capital expenditures.

 

 

We expect 2018 net income from our Manufacturing segment to increase over 2017 based on:

 

 

o

BTD’s year-over-year sales increase and planned improvement in operating margins through continued productivity gains.

 

 

o

T.O. Plastics’ year-over-year sales growth in horticulture markets.

 

 

o

Lower income taxes due to lower federal tax rates implemented as part of the TCJA.

 

 

o

Backlog of approximately $62 million for the remainder of 2018 compared with $53 million one year ago.

 

 

We expect 2018 net income from the Plastics Segment to increase over 2017 based on continued strong performance through third quarter driven by higher operating margins with business conditions expected to remain solid through the rest of the year. Earnings in 2017 included an estimated impact of $0.09 per diluted share due to market reaction to hurricanes in the Gulf of Mexico. Plastics segment net income for 2018 also will be positively affected by lower federal tax rates in the TCJA.

 

51

 

 

Corporate costs, net of tax, are expected to be higher in 2018 than in 2017, excluding the effect of revaluing deferred tax assets ($0.18 per share) related to tax reform on 2017 net losses. The higher net-of-tax costs expected in 2018 are due, in part, to the lower federal tax rate in effect in 2018 under the TCJA, as well as additional increases in employee benefit costs resulting from increased earnings, and planned contributions to Otter Tail Corporation’s Foundation, established in 2018.

 

The impact of 2017 tax reform legislation on future results is based on reasonable estimates and is subject to adjustment on obtaining additional information or to reflect any future legislation, rules, regulations or interpretations of the tax reform legislation.

 

Critical Accounting Policies Involving Significant Estimates

 

The discussion and analysis of the financial statements and results of operations are based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities.

 

We use estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used for such items as depreciable lives, asset impairment evaluations, tax provisions, collectability of trade accounts receivable, self-insurance programs, unbilled electric revenues, interim rate refunds, warranty reserves and actuarially determined benefits costs and liabilities. As better information becomes available or actual amounts are known, estimates are revised. Operating results can be affected by revised estimates. Actual results may differ from these estimates under different assumptions or conditions. Management has discussed the application of these critical accounting policies and the development of these estimates with the Audit Committee of the board of directors. A discussion of critical accounting policies is included under the caption “Critical Accounting Policies Involving Significant Estimates” on pages 57 through 59 of our Annual Report on Form 10-K for the year ended December 31, 2017. There were no material changes in critical accounting policies or estimates during the quarter ended September 30, 2018.

 

Forward Looking Information - Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995

In connection with the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995 (the Act), we have filed cautionary statements identifying important factors that could cause our actual results to differ materially from those discussed in forward-looking statements made by or on behalf of the Company. When used in this Form 10-Q and in future filings by the Company with the Securities and Exchange Commission, in our press releases and in oral statements, words such as "may", "will", "expect", "anticipate", "continue", "estimate", "project", "believes" or similar expressions are intended to identify forward-looking statements within the meaning of the Act and are included, along with this statement, for purposes of complying with the safe harbor provision of the Act. These forward-looking statements involve risks and uncertainties. Actual results may differ materially from those contemplated by the forward-looking statements due to, among other factors, the risks and uncertainties described in the section entitled “Risk Factors” in Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2017, as well as the various factors described below:

 

 

Federal and state environmental regulation could require us to incur substantial capital expenditures and increased operating costs.

 

 

Volatile financial markets and changes in our debt ratings could restrict our ability to access capital and increase borrowing costs and pension plan and postretirement health care expenses.

 

 

We rely on access to both short- and long-term capital markets as a source of liquidity for capital requirements not satisfied by cash flows from operations. If we are unable to access capital at competitive rates, our ability to implement our business plans may be adversely affected.

 

 

Disruptions, uncertainty or volatility in the financial markets can also adversely impact our results of operations, the ability of customers to finance purchases of goods and services, and our financial condition, as well as exert downward pressure on stock prices and/or limit our ability to sustain our current common stock dividend level.

 

 

We could be required to contribute additional capital to the pension plan in the future if the market value of pension plan assets significantly declines, plan assets do not earn in line with our long-term rate of return assumptions or relief under the Pension Protection Act is no longer granted.

 

 

Any significant impairment of our goodwill would cause a decrease in our asset values and a reduction in our net operating income.

 

52

 

 

Declines in projected operating cash flows at BTD or the Plastics segment may result in goodwill impairments that could adversely affect our results of operations and financial position, as well as financing agreement covenants.

 

 

The inability of our subsidiaries to provide sufficient earnings and cash flows to allow us to meet our financial obligations and debt covenants and pay dividends to our shareholders could have an adverse effect on us.

 

 

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

 

 

Economic conditions could negatively impact our businesses.

 

 

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

 

 

Our plans to grow and realign our business mix through capital projects, acquisitions and dispositions may not be successful, which could result in poor financial performance.

 

 

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

 

 

Significant warranty claims and remediation costs in excess of amounts normally reserved for such items could adversely affect our results of operations and financial condition.

 

 

We are subject to risks associated with energy markets.

 

 

Changes in tax laws, as well as judgments and estimates used in the determination of tax-related asset and liability amounts, could materially adversely affect our business, financial condition, results of operations and prospects.

 

 

Four of our operating companies have single customers that provide a significant portion of the individual operating company’s and the business segment’s revenue. The loss of, or significant reduction in revenue from, any one of these customers would have a significant negative financial impact on the operating company and its business segment and could have a significant negative financial impact on us.

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

Changes to regulation of generating plant emissions, including but not limited to carbon dioxide emissions, could affect our operating costs and the costs of supplying electricity to our customers.

 

 

Competition from foreign and domestic manufacturers, the price and availability of raw materials, prices and supply of scrap or recyclable material and general economic conditions could affect the revenues and earnings of our manufacturing businesses.

 

 

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

 

 

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

 

 

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

 

53

 

Item 3. Quantitative and Qualitative Disclosures about Market Risk

 

At September 30, 2018 we had exposure to market risk associated with interest rates because we had $15.5 million in short-term debt outstanding subject to variable interest rates indexed to LIBOR plus 1.50% under the Otter Tail Corporation Credit Agreement.

 

All of our remaining consolidated long-term debt outstanding on September 30, 2018 has fixed interest rates. We manage our interest rate risk through the issuance of fixed-rate debt with varying maturities, through economic refunding of debt through optional refundings, limiting the amount of variable interest rate debt, and the utilization of short-term borrowings to allow flexibility in the timing and placement of long-term debt.

 

We have not used interest rate swaps to manage net exposure to interest rate changes related to our portfolio of borrowings. We maintain a ratio of fixed-rate debt to total debt within a certain range. It is our policy to enter into interest rate transactions and other financial instruments only to the extent considered necessary to meet our stated objectives. We do not enter into interest rate transactions for speculative or trading purposes.

 

The companies in our Manufacturing segment are exposed to market risk related to changes in commodity prices for steel, aluminum and polystyrene and other plastics resins. The price and availability of these raw materials could affect the revenues and earnings of our Manufacturing segment.

 

The plastics companies are exposed to market risk related to changes in commodity prices for PVC resins, the raw material used to manufacture PVC pipe. The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices are rising or stable, sales volume has been higher and when resin prices are falling, sales volume has been lower. Operating income may decline when the supply of PVC pipe increases faster than demand. Due to the commodity nature of PVC resin and the dynamic supply and demand factors worldwide, it is very difficult to predict gross margin percentages or to assume that historical trends will continue.

 

Item 4. Controls and Procedures

 

Under the supervision and with the participation of company management, including our Chief Executive Officer and Chief Financial Officer, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of September 30, 2018, the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2018.

 

During the fiscal quarter ended September 30, 2018, there were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

PART II. OTHER INFORMATION

 

Item 1. Legal Proceedings

 

We are the subject of various pending or threatened legal actions and proceedings in the ordinary course of our business. Such matters are subject to many uncertainties and to outcomes that are not predictable with assurance. We record a liability in our consolidated financial statements for costs related to claims, including future legal costs, settlements and judgments, where we have assessed that a loss is probable and an amount can be reasonably estimated. We believe the final resolution of currently pending or threatened legal actions and proceedings, either individually or in the aggregate, will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

 

Item 1A. Risk Factors

 

There has been no material change in the risk factors set forth under Part I, Item 1A, “Risk Factors” on pages 27 through 33 of our Annual Report on Form 10-K for the year ended December 31, 2017.

 

54

 

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

 

We do not have a publicly announced stock repurchase program. The following table shows common shares of the Company that were surrendered to us by employees to pay taxes in connection with shares issued for incentive awards in July 2018 under our 2014 Stock Incentive Plan: 

 

Calendar Month

 

Total Number of

Shares Purchased

   

Average Price Paid

per Share

 

July 2018

    11,777     $ 47.65  

August 2018

    --       --  

September 2018

    --       --  

Total

    11,777          

 

Item 6.      Exhibits

 

 

4.1

Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2018, among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West as a Bank (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by Otter Tail Corporation on November 6, 2018).

 

 

4.2

Sixth Amendment to Second Amended and Restated Credit Agreement, dated as of October 31, 2018, among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation Agent and as a Bank, and Wells Fargo Bank, National Association as a Bank (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by Otter Tail Corporation on November 6, 2018).

 

 

31.1

Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

31.2

Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

32.1

Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

32.2

Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

101

Financial statements from the Quarterly Report on Form 10-Q of Otter Tail Corporation for the quarter ended September 30, 2018, formatted in Extensible Business Reporting Language: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Income, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Cash Flows and (v) the Condensed Notes to Consolidated Financial Statements.

 

SIGNATURES

 

 

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

 

 

OTTER TAIL CORPORATION

 

By:    /s/ Kevin G. Moug            

Kevin G. Moug
      Chief Financial Officer and Senior Vice President
   (Chief Financial Officer/Authorized Officer)

 

Dated: November 9, 2018

 

 

 

55