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

ottr20171231_10k.htm
 

Table of Contents

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

(Mark One)

 

(X)

Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

    For the fiscal year ended December 31, 2017

          

 

(  )

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 incorporation or organization) (I.R.S. Employer Identification No.)
   
215 SOUTH CASCADE STREET, BOX 496, FERGUS FALLS, MINNESOTA 56538-0496
(Address of principal executive offices) (Zip Code)

 

Registrant's telephone number, including area code: 866-410-8780

 

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class Name of each exchange on which registered
COMMON SHARES, par value $5.00 per share The NASDAQ Stock Market LLC

     

Securities registered pursuant to Section 12(g) of the Act: None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   Yes  ☑     No  ☐

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐    No ☑

 

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 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☑

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting 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. (Check one):

Large Accelerated Filer Accelerated Filer ☐       
Non-Accelerated Filer Smaller Reporting Company ☐
(Do not check if a 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 in Rule 12b-2 of the Exchange Act).   Yes ☐ No ☑

 

The aggregate market value of common stock held by non-affiliates, computed by reference to the last sales price on June 30, 2017 was $1,500,154,049.

 

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date: 39,626,594 Common Shares ($5 par value) as of February 8, 2018.

 

Documents Incorporated by Reference:

Proxy Statement for the 2018 Annual Meeting-Portions incorporated by reference into Part III

 

 

Table of Contents

 

 

OTTER TAIL CORPORATION

FORM 10-K TABLE OF CONTENTS

 

 

Description

Page

 

Definitions

2

PART I

   

ITEM 1.

Business

4

ITEM 1A.

Risk Factors

27

ITEM 1B.

Unresolved Staff Comments

34

ITEM 2.

Properties

34

ITEM 3.

Legal Proceedings

34

ITEM 3A.

Executive Officers of the Registrant (as of February 20, 2018)

35

ITEM 4.

Mine Safety Disclosures

35

     

PART II

   

ITEM 5.

Market for Registrant’s Common Equity, Related Stockholder Matters And Issuer Purchases of Equity Securities

36

ITEM 6.

Selected Financial Data

37

ITEM 7.

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

37

ITEM 7A.

Quantitative and Qualitative Disclosures About Market Risk

59

ITEM 8.

Financial Statements and Supplementary Data:

 
 

Report of Independent Registered Public Accounting Firm

60

 

Consolidated Balance Sheets

61

 

Consolidated Statements of Income

63

 

Consolidated Statements of Comprehensive Income

64

 

Consolidated Statements of Common Shareholders’ Equity

65

 

Consolidated Statements of Cash Flows

66

 

Consolidated Statements of Capitalization

67

 

Notes to Consolidated Financial Statements

68

 

Supplementary Financial Information - Quarterly Information

115

ITEM 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

116

ITEM 9A.

Controls and Procedures

116

ITEM 9B.

Other Information

116

     

PART III

   

ITEM 10.

Directors, Executive Officers and Corporate Governance

117

ITEM 11.

Executive Compensation

117

ITEM 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

118

ITEM 13.

Certain Relationships and Related Transactions and Director Independence

118

ITEM 14.

Principal Accountant Fees and Services

118

     

PART IV

   

ITEM 15.

Exhibits and Financial Statement Schedules

119

ITEM 16.

Form 10-K Summary

127

     

Signatures

 

128

 

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Table of Contents

 

 

Definitions

 

The following abbreviations or acronyms are used in the text. References in this report to “the Company”, “we”, “us” and “our” are to Otter Tail Corporation.

 

ADP

Advance Determination of Prudence

AFUDC

Allowance for Funds Used During Construction

ALJ

Administrative Law Judge

AQCS

Air Quality Control System

ARO

Accumulated Asset Retirement Obligation

ASC

Accounting Standards Codification

ASC 606

ASC Topic 606 – Revenue from Contracts with Customers

ASC 718

ASC Topic 718 – Compensation—Stock Compensation

ASC 820

ASC Topic 820 – Fair Value Measurement

ASC 980

ASC Topic 980 – Regulated Operations  

ASM

Ancillary Services Market

ASU

Accounting Standards Update

BACT

Best-Available Control Technology

BTD

BTD Manufacturing, Inc.

Btu

British Thermal Unit

CAA

Clean Air Act

CCMC

Coyote Creek Mining Company, L.L.C.

CCR

Coal Combustion Residuals

CIP

Conservation Improvement Program

CO2

carbon dioxide

CON

Certificate of Need

CPEC

Central Power Electric Cooperative

CPP

Clean Power Plan

CSAPR

Cross-State Air Pollution Rule

CWIP

Construction Work in Progress

D.C. Circuit

United States Court of Appeals for the District of Columbia

DRR

Data Requirement Rule

ECR

Environmental Cost Recovery

EDF

EDF Renewable Development, Inc.

EEI

Edison Electric Institute

EEP

Energy Efficiency Plan

EPA

Environmental Protection Agency

ESSRP

Executive Survivor and Supplemental Retirement Plan

Exchange Act

The Securities Exchange Act of 1934

FASB

Financial Accounting Standards Board

FCA

Fuel Clause Adjustment

FERC

Federal Energy Regulatory Commission

Foley

Foley Company

GAAP

Generally Accepted Accounting Principles in the United States

GHG

Greenhouse Gas

Impulse

Impulse Manufacturing, Inc.

IRP

Integrated Resource Plan

JPMS

J.P. Morgan Securities LLC

kV

kiloVolt

kW

kiloWatt

kwh

kilowatt-hour

LSA

Lignite Sales Agreement

MATS

Mercury and Air Toxics Standards

MISO

Midcontinent Independent System Operator, Inc.

MISO Tariff

MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff

MNCIP

Minnesota Conservation Improvement Program

MNDOC

Minnesota Department of Commerce

MPCA

Minnesota Pollution Control Agency

MPU Act

The Minnesota Public Utilities Act

MPUC

Minnesota Public Utilities Commission

 

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MRO

Midwest Reliability Organization

MVP

Multi-Value Project

MW

megawatts

NAAQS

National Ambient Air Quality Standards

NAEMA

North American Energy Marketers Association

NDPSC

North Dakota Public Service Commission

NDRRA

North Dakota Renewable Resource Adjustment

NERC

North American Electric Reliability Corporation

NETOs

New England Transmission Owners

NPDES

National Pollutant Discharge Elimination System

Northern Pipe

Northern Pipe Products, Inc.

NOx

nitrogen oxide

NSPS

New Source Performance Standards

OTP

Otter Tail Power Company

PACE

Partnership in Assisting Community Expansion

ppb

parts per billion

PSD

Prevention of Significant Deterioration

PTCs

Production Tax Credits

PVC

Polyvinyl Chloride

ROE

Return on Equity

RSG

Revenue Sufficiency Guarantee

RTO Adder

Incentive of additional 50-basis points for Regional Transmission Organization participation

SDPUC

South Dakota Public Utilities Commission

SEC

Securities and Exchange Commission

SF6

sulfur hexaflouride

SO2

sulfur dioxide

SPP

Southwest Power Pool

Standex

Standex International Corporation

T.O. Plastics

T.O. Plastics, Inc.

TCR

Transmission Cost Recovery

TCJA

2017 Tax Cuts and Jobs Act

Varistar

Varistar Corporation

VIE

Variable Interest Entity

Vinyltech

Vinyltech Corporation

WIIN

Water Infrastructure Improvements for the Nation

 

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PART I

 

Item 1.     BUSINESS

 

(a) General Development of Business

 

Otter Tail Power Company was incorporated in 1907 under the laws of the State of Minnesota. In 2001, the name was changed to “Otter Tail Corporation” to more accurately represent the broader scope of consolidated operations and the name Otter Tail Power Company (OTP) was retained for use by the electric utility. On July 1, 2009 Otter Tail Corporation completed a holding company reorganization whereby OTP, which had previously been operated as a division of Otter Tail Corporation, became a wholly owned subsidiary of the new parent holding company named Otter Tail Corporation (the Company). The new parent holding company was incorporated in June 2009 under the laws of the State of Minnesota in connection with the holding company reorganization. The Company’s executive offices are located at 215 South Cascade Street, P.O. Box 496, Fergus Falls, Minnesota 56538-0496 and 4334 18th Avenue SW, Suite 200, P.O. Box 9156, Fargo, North Dakota 58106-9156. The Company’s telephone number is (866) 410-8780.

 

The Company makes available free of charge at its website (www.ottertail.com) its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Forms 3, 4 and 5 filed on behalf of directors and executive officers and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (SEC). Information on the Company’s website is not deemed to be incorporated by reference into this Annual Report on Form 10-K.

 

Otter Tail Corporation and its subsidiaries conduct business primarily in the United States. The Company had approximately 2,097 full-time employees in its continuing operations at December 31, 2017. The Company’s businesses have been classified in three segments to be consistent with its business strategy and the reporting and review process used by the Company’s chief operating decision maker. The three segments are Electric, Manufacturing and Plastics.

 

From 2011 through 2015, the Company sold several businesses in order to realign its business portfolio to reduce its risk profile and dedicate a greater portion of its resources toward electric utility operations. Recent divestitures include:

 

 

In 2012 the Company completed the sale of the assets of its former wind tower company.

 

 

In 2013 the Company sold substantially all the assets of its former dock and boatlift company.

 

 

In 2015 the Company sold the assets of AEV, Inc., its former energy and electrical construction contractor and the Company sold Foley Company, its former water, wastewater, power and industrial construction contractor. With the sale of these two companies the Company eliminated its Construction segment.

 

On September 1, 2015 the Company acquired the assets of Impulse Manufacturing Inc. (Impulse) of Dawsonville, Georgia, now operating under the name BTD-Georgia, for $29.3 million. BTD-Georgia offers a wide range of metal fabrication services ranging from simple laser cutting services and high volume stamping to complex weldments and assemblies for metal fabrication buyers and original equipment manufacturers.

 

The chart below indicates the companies included in each of the Company’s reporting segments.

 

 

 

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

 

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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 polyvinyl chloride (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. The Company’s manufacturing and plastic pipe businesses are owned by its wholly owned subsidiary, Varistar Corporation (Varistar). The Company’s corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance that are not allocated to its subsidiary companies. 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.

 

The Company has lowered its overall risk by investing in rate base growth opportunities in its Electric segment and divesting certain nonelectric operating companies that no longer fit the Company’s portfolio criteria. This strategy has provided a more predictable earnings stream, improved the Company’s credit quality and preserved its ability to fund the dividend. The Company’s goal is to deliver annual growth in earnings per share between four to seven percent over the next several years, using 2017 diluted earnings per share from continuing operations as the base for measurement. The growth is expected to come from the substantial increase in the Company’s regulated utility rate base and from planned increased earnings from existing capacity in place at the Company’s manufacturing and plastic pipe businesses, including the 2015 acquisition of BTD-Georgia and the facilities expansion and addition of paint services at BTD Manufacturing Inc.’s Minnesota facilities completed in 2016. The Company will continue to review its business portfolio to see where additional opportunities exist to improve its risk profile, improve credit metrics and generate additional sources of cash to support the growth opportunities in its electric utility. The Company will also evaluate opportunities to allocate capital to potential acquisitions in its Manufacturing and Plastics segments. Over time, the Company expects the electric utility business will provide approximately 75% to 85% of its overall earnings. The Company expects its manufacturing and plastic pipe businesses will provide 15% to 25% of its earnings, and will continue to be a fundamental part of its strategy. The actual mix of earnings from continuing operations in 2017 was 69% from the electric utility and 31% from the manufacturing and plastic pipe businesses, including unallocated corporate costs.

 

The Company maintains criteria in evaluating whether its operating companies are a strategic fit. The operating company should:

 

 

Maintain a threshold level of net earnings and a return on invested capital in excess of the Company’s weighted average cost of capital.

 

 

Have a strategic differentiation from competitors and a sustainable cost advantage.

 

 

Operate within a stable and growing industry and be able to quickly adapt to changing economic cycles.

 

 

Have a strong management team committed to operational excellence.

 

For a discussion of the Company's results of operations, see "Management's Discussion and Analysis of Financial Condition and Results of Operations," on pages 37 through 59 of this Annual Report on Form 10-K.

 

(b) Financial Information about Industry Segments

 

The Company is engaged in businesses classified into three segments: Electric, Manufacturing and Plastics. Financial information about the Company's segments and geographic areas is included in note 2 of "Notes to Consolidated Financial Statements" on pages 76 through 79 of this Annual Report on Form 10-K.

 

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(c) Narrative Description of Business

 

ELECTRIC

 

General

 

Electric includes OTP which is headquartered in Fergus Falls, Minnesota, and provides electricity to more than 130,000 customers in a service area encompassing 70,000 square miles of western Minnesota, eastern North Dakota and northeastern South Dakota. The Company derived 51%, 53% and 52% of its consolidated operating revenues and 72%, 81% and 80% of its consolidated operating income from its Electric segment for the years ended December 31, 2017, 2016 and 2015, respectively.

 

The breakdown of retail electric revenues by state is as follows:

 

State

 

2017

   

2016

 

Minnesota

    52.8 %     53.0 %

North Dakota

    38.5       38.4  

South Dakota

    8.7       8.6  

Total

    100.0 %     100.0 %

 

The territory served by OTP is predominantly agricultural. The aggregate population of OTP’s retail electric service area is approximately 230,000. In this service area of 422 communities and adjacent rural areas and farms, approximately 126,000 people live in communities having a population of more than 1,000, according to the 2010 census. The only communities served which have a population in excess of 10,000 are Jamestown, North Dakota (15,427); Bemidji, Minnesota (13,431); and Fergus Falls, Minnesota (13,138). As of December 31, 2017 OTP served 132,146 customers. Although there are relatively few large customers, sales to commercial and industrial customers are significant. One customer accounted for 12% of the 2017 revenue from the Electric segment.

 

The following table provides a breakdown of electric revenues by customer category. All other sources include gross wholesale sales from utility generation and sales to municipalities.

 

Customer Category

 

2017

   

2016

 

Commercial

    35.2 %     36.1 %

Residential

    31.1       30.8  

Industrial

    31.8       31.0  

All Other Sources

    1.9       2.1  

Total

    100.0 %     100.0 %

 

Capacity and Demand

 

As of December 31, 2017 OTP’s owned net-plant dependable kilowatt (kW) capacity was:

 

Baseload Plants

       

Big Stone Plant

 

258,100

kW

Coyote Station

    149,800  

Hoot Lake Plant

    139,700  

Total Baseload Net Plant

 

547,600

kW

Combustion Turbine and Small Diesel Units

 

109,900

kW

Hydroelectric Facilities

 

2,800

kW

Owned Wind Facilities (rated at nameplate)

       

Luverne Wind Farm (33 turbines)

 

49,500

kW

Ashtabula Wind Center (32 turbines)

    48,000  

Langdon Wind Center (27 turbines)

    40,500  

Total Owned Wind Facilities

 

138,000

kW

 

The baseload net plant capacity for Big Stone Plant and Coyote Station constitutes OTP’s ownership percentages of 53.9% and 35%, respectively. OTP owns 100% of the Hoot Lake Plant. During 2017, about 56% of OTP’s retail kilowatt-hour (kwh) sales were supplied from OTP generating plants with the balance supplied by purchased power.

 

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In addition to the owned facilities described above, OTP had the following purchased power agreements in place on December 31, 2017:

 

Purchased Wind Power Agreements (rated at nameplate and greater than 2,000 kW)

 

Ashtabula Wind III

 

62,400

kW

Edgeley

    21,000  

Langdon

    19,500  

Total Purchased Wind

 

102,900

kW

Purchase of Capacity (in excess of 1 year and 500 kW)

       

Great River Energy1

 

80,000

kW

180,000 kW through May 2019 and 50,000 kW June 2019 – May 2021.

 

OTP has a direct control load management system which provides some flexibility to OTP to effect reductions of peak load. OTP also offers rates to customers which encourage off-peak usage.

 

OTP’s capacity requirement is based on MISO Module E requirements. OTP is required to have sufficient Zonal Resource Credits to meet its monthly weather-normalized forecast demand, plus a reserve obligation. OTP met its MISO obligation for the 2017-2018 MISO planning year. OTP generating capacity combined with additional capacity under purchased power agreements (as described above) and load management control capabilities is expected to meet 2018 system demand and MISO reserve requirements.

 

Fuel Supply

 

Coal is the principal fuel burned at the Big Stone, Coyote and Hoot Lake generating plants. Coyote Station, a mine-mouth facility, burns North Dakota lignite coal. Hoot Lake Plant and Big Stone Plant burn western subbituminous coal.

 

The following table shows the sources of energy used to generate OTP’s net output of electricity for 2017 and 2016:

 

   

2017

   

2016

 

Sources

 

Net kwhs

Generated

(Thousands)

   

% of Total

kwhs

Generated

   

Net kwhs

Generated

(Thousands)

   

% of Total

kwhs

Generated

 

Subbituminous Coal

    1,440,017       49.1 %     1,419,901       50.3 %

Lignite Coal

    920,451       31.4       844,225       29.9  

Wind and Hydro

    534,474       18.2       517,396       18.4  

Natural Gas and Oil

    36,703       1.3       40,257       1.4  

Total

    2,931,645       100.0 %     2,821,779       100.0 %

 

OTP has the following primary coal supply agreements:

 

Plant

Coal Supplier

Type of Coal

Expiration Date

Big Stone Plant

Contura Coal Sales, LLC

Wyoming subbituminous

December 31, 2019

Big Stone Plant

Peabody COALSALES, LLC

Wyoming subbituminous

December 31, 2018

Coyote Station

Coyote Creek Mining Company, L.L.C.

North Dakota lignite

December 31, 2040

Hoot Lake Plant

Cloud Peak Energy Resources LLC

Montana subbituminous

December 31, 2023

 

The above contracts for Big Stone Plant do not provide for 100% of Big Stone Plant’s anticipated coal needs in 2018 and 2019.

 

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 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 being paid by the Coyote Station owners under the LSA reflects the cost of production, along with an agreed profit and capital charge. The LSA provides for the Coyote Station owners to purchase the membership interests in CCMC in the event of certain early termination events and also at the end of the term of the LSA.

 

OTP’s coal supply requirements for Hoot Lake Plant are secured under contract through December 2023.

 

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Railroad transportation services to the Big Stone Plant and Hoot Lake Plant are provided under a common carrier rate by the BNSF Railway. The common carrier rate is subject to a mileage-based fuel surcharge. The basis for the fuel surcharge is the U.S. average price of retail on-highway diesel fuel. No coal transportation agreement is needed for Coyote Station as a mine-mouth facility.

 

The average cost of fuel consumed (including handling charges to the plant sites) per million British Thermal Units (Btu) for the years 2017, 2016, and 2015 was $2.224, $2.146 and $2.281, respectively.

 

General Regulation

 

OTP is subject to regulation of rates and other matters in each of the three states in which it operates and by the federal government for certain interstate operations.

 

A breakdown of electric rate regulation by each jurisdiction follows:

 

     

2017

   

2016

 

Rates

Regulation

 

% of Electric

Revenues

   

% of kwh

Sales

   

% of Electric

Revenues

   

% of kwh

Sales

 

MN Retail Sales

MN Public Utilities Commission

    46.4 %     54.0 %     47.5 %     54.0 %

ND Retail Sales

ND Public Service Commission

    33.9       37.1       34.4       37.1  

SD Retail Sales

SD Public Utilities Commission

    7.7       8.9       7.8       8.9  

Transmission & Wholesale

Federal Energy Regulatory Commission

    12.0       --       10.3       --  

Total

    100.0 %     100.0 %     100.0 %     100.0 %

 

OTP operates under approved retail electric tariffs in all three states it serves. OTP has an obligation to serve any customer requesting service within its assigned service territory. The pattern of electric usage can vary dramatically during a 24-hour period and from season to season. OTP’s tariffs are designed to recover the costs of providing electric service. To the extent peak usage can be reduced or shifted to periods of lower usage, the cost to serve all customers is reduced. In order to shift usage from peak times, OTP has approved tariffs in all three states for residential demand control, general service time of use and time of day, real-time pricing, and controlled and interruptible service. Each of these specialized rates is designed to improve efficient use of OTP resources, while giving customers more control over their electric bill. OTP also has approved tariffs in its three service territories which allow qualifying customers to release and sell energy back to OTP when wholesale energy prices make such transactions desirable.

 

With a few minor exceptions, OTP’s electric retail rate schedules currently provide for adjustments in rates based on the cost of fuel delivered to OTP’s generating plants, as well as for adjustments based on the cost of electric energy purchased by OTP. OTP also credits certain margins from wholesale sales to the fuel and purchased power adjustment. The adjustments for fuel and purchased power costs are presently based on a two month moving average in Minnesota and by the Federal Energy Regulatory Commission (FERC), a three month moving average in South Dakota and a four month moving average in North Dakota. These adjustments are applied to the next billing period after becoming applicable. These adjustments also include an over or under recovery mechanism, which is calculated on an annual basis in Minnesota and on a monthly basis in North Dakota and South Dakota.

 

2017 Tax Cuts and Jobs Act (TCJA)

 

The TCJA reduced the Federal Income Tax rate from 35% to 21%. Currently, all OTP rates have been developed using a 35% tax rate. The Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the FERC have all initiated dockets or proceedings to begin working with utilities to assess the impact of the lower income tax rate under the TCJA on electric rates, and to develop regulatory strategies to incorporate the tax change into future rates, if warranted. The MPUC required its regulated utilities to make filings by January 30, 2018 and February 15, 2018, but has not made a determination on rate treatment. OTP currently has an active rate case in North Dakota and anticipates incorporating the impact of the tax changes to North Dakota rates within that proceeding. The SDPUC required initial comments by February 1, 2018 and indicated that revenues collected subsequent to December 31, 2017 would be subject to refund, pending determination of the impacts of the TCJA. OTP is still assessing these impacts and will continue to work with the respective Commissions to determine if any rate adjustments are necessary and, if so, to determine the appropriate timing and approach for making those adjustments.

 

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Major Capital Expenditure Projects

 

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 the material regulations of each jurisdiction applicable to OTP’s electric operations, as well as any specific electric rate proceedings during the last three years with the MPUC, the NDPSC, the SDPUC and the FERC. The Company’s manufacturing and plastic pipe businesses are not subject to direct regulation by any of these agencies.

 

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 December 31, 2017 were approximately $90 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 December 31, 2017 were approximately $73 million, which includes assets that are 100% owned by OTP.

 

Fargo–Monticello 345-kV Project—OTP invested approximately $81 million and has a 14.2% ownership interest in the jointly-owned assets of this 240-mile transmission line, and owns 100% of certain assets of the project. The final phase of this project was energized on April 2, 2015.

 

Brookings–Southeast Twin Cities 345-kV Project—OTP invested approximately $26 million and has a 4.8% ownership interest in this 250-mile transmission line. The MISO granted unconditional approval of this project as an MVP under the MISO Tariff in December 2011. The final segments of this line were energized on March 26, 2015.

 

Big Stone Plant Air Quality Control System (AQCS)—OTP completed construction and testing of the Big Stone Plant AQCS in the fourth quarter of 2015 and placed the AQCS into commercial operation on December 29, 2015. OTP’s capitalized cost of the project, excluding allowance for funds used during construction, was approximately $200 million.

 

Recovery of OTP’s major transmission investments is through the MISO Tariff (several as MVPs) and, currently, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders.

 

Minnesota

 

Under the Minnesota Public Utilities Act (the MPU Act), OTP is subject to the jurisdiction of the MPUC with respect to rates, issuance of securities, depreciation rates, public utility services, construction of major utility facilities, establishment of exclusive assigned service areas, contracts and arrangements with subsidiaries and other affiliated interests, and other matters. The MPUC has the authority to assess the need for large energy facilities and to issue or deny certificates of need, after public hearings, within one year of an application to construct such a facility.

 

Pursuant to the Minnesota Power Plant Siting Act, the MPUC has authority to select or designate sites in Minnesota for new electric power generating plants (50,000 kW or more) and routes for transmission lines (100 kV or more) in an orderly manner compatible with environmental preservation and the efficient use of resources, and to certify such sites and routes as to environmental compatibility after an environmental impact study has been conducted by the Minnesota Department of Commerce (MNDOC) and the Office of Administrative Hearings has conducted contested case hearings.

 

The Minnesota Division of Energy Resources, part of the MNDOC, is responsible for investigating all matters subject to the jurisdiction of the MNDOC or the MPUC, and for the enforcement of MPUC orders. Among other things, the MNDOC is authorized to collect and analyze data on energy including the consumption of energy, develop recommendations as to energy policies for the governor and the legislature of Minnesota and evaluate policies governing the establishment of rates and prices for energy as related to energy conservation. The MNDOC also has the power, in the event of energy shortage or for a long-term basis, to prepare and adopt regulations to conserve and allocate energy.

 

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2016 General Rate Case—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%. On July 6, 2017 the MPUC denied OTP’s request for reconsideration of certain of the MPUC’s rulings in the rate case and confirmed its May 1, 2017 order.

 

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 MVP projects will be included in the Minnesota TCR rider and jurisdictionally allocated to OTP’s Minnesota customers, and (2) approval of OTP’s proposal to transition rate base, expenses and revenues from Environmental Cost Recovery (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.

 

Information on interim and final rate increases and interim revenue refunds accrued is detailed in the tables below:

 

($ in thousands)

 

Interim Rates Authorized

April 14, 2016

   

Final Rates

 

Revenue Increase – Annualized based on Test Year Data

  $ 16,816     $ 10,471  

Revenue Percent Increase

    9.56 %     5.34 %

Return on Rate Base

    8.07 %     7.5056 %

Jurisdictional Rate Base based on Test Year Data

  $ 483,000     $ 471,000  

Return on Equity

    10.40 %     9.41 %

Based on Equity to Total Capital of

    52.50 %     52.50 %

Debt to Total Capital

    47.50 %     47.50 %

 

Interim Revenue (in thousands)

 

April 16, 2016 through October 31, 2017

 

Billed

    $ 23,289  

Accrued Refund

     $ 8,779  

Net Interim Revenue

    $ 14,510  

Interest on Refundable Amount

    $ 265  

Final Refund

     $ 9,044  

 

The final interim rate refund, including interest was applied as a credit to Minnesota customers’ electric bills beginning November 17, 2017.

 

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

 

Integrated Resource Plan (IRP)—Minnesota law requires utilities to submit to the MPUC for approval a 15-year advance IRP. A resource plan is a set of resource options a utility could use to meet the service needs of its customers over a forecast period, including an explanation of the utility’s supply and demand circumstances, and the extent to which each resource option would be used to meet those service needs. The MPUC’s findings of fact and conclusions regarding resource plans shall be considered prima facie evidence, subject to rebuttal, in Certificate of Need (CON) hearings, rate reviews and other proceedings. Typically, the filings are submitted every two years.

 

On April 26, 2017 the MPUC issued an order approving OTP’s 2017-2031 IRP filing with modifications and setting requirements for the next resource plan. The approved plan with modifications included the following items:

 

 

The addition of 200 megawatts (MW) of wind resources in the 2018 to 2020 timeframe.

 

The addition of 30 MW of solar resources by 2020 to comply with Minnesota's Solar Energy Standard.

 

The addition of up to 250 MW of peaking capacity in 2021.

 

Average annual energy savings of 46.8 gigawatt-hours (1.6% of retail sales).

 

Modification of OTP’s IRP to include 100 MW to 200 MW of wind in the 2022 to 2023 timeframe.

 

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The MPUC ordered OTP to file its next IRP no later than June 3, 2019.

 

Fuel and Purchased Power Costs RecoveryOn December 19, 2017, the MPUC issued an order authorizing the implementation of a new fuel clause adjustment mechanism to be implemented July 1, 2019. Prior to implementation, OTP will be required to submit forecasted monthly fuel cost rates for the twelve-month period beginning July 1, 2019. 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 will be working with other Minnesota utilities, the MNDOC 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 to be issued 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 variability in the Company’s consolidated net income in future periods if those costs exceed forecasted costs.

 

Renewable Energy Standards, Conservation, Renewable Resource RidersMinnesota law favors conservation over the addition of new resources. In addition, Minnesota law requires the use of renewable resources where new supplies are needed, unless the utility proves that a renewable energy facility is not in the public interest. An existing environmental externality law requires the MPUC, to the extent practicable, to quantify the environmental costs associated with each method of electricity generation, and to use such monetized values in evaluating generation resources. The MPUC must disallow any nonrenewable rate base additions (whether within or outside of the state) or any related rate recovery, and may not approve any nonrenewable energy facility in an IRP, unless the utility proves that a renewable energy facility is not in the public interest. The state has prioritized the acceptability of new generation with wind and solar ranked first, the highest ranking and coal and nuclear ranked fifth, the lowest ranking. The MPUC’s currently applicable estimate of the range of costs of future carbon dioxide (CO2) regulation to be used in modeling analyses for resource plans is $9.00 to $34.00 per ton of CO2 commencing in 2022. The MPUC is required to annually update these estimates. The MNDOC and the Minnesota Pollution Control Agency (MPCA) have recommended the new range to be $5.00 to $25.00 per ton beginning in 2025. The MPUC will likely rule on this docket during the second quarter of 2018.

 

Minnesota has a renewable energy standard which requires OTP to generate or procure sufficient renewable generation such that the following percentages of total retail electric sales to Minnesota customers come from qualifying renewable sources: 17% by 2016; 20% by 2020 and 25% by 2025. In addition, Minnesota law requires 1.5% of total Minnesota electric sales by public utilities to be supplied by solar energy by 2020. For a public utility with between 50,000 and 200,000 retail electric customers, such as OTP, at least 10% of the 1.5% requirement must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 40 kWs or less. If approved by the MPUC, individual customer subscriptions to an OTP-operated community solar garden program of 40 kWs or less could be applied toward the 10% requirement. OTP has purchased enough utility-scale solar energy credits to meet its expected 2020 Minnesota obligation. Under certain circumstances and after consideration of costs and reliability issues, the MPUC may modify or delay implementation of the standards. OTP has acquired sufficient renewable resources to currently comply with Minnesota renewable energy standards. OTP is evaluating potential options for maintaining compliance and meeting the solar energy standard. Projected capital expenditures include $30 million for solar generation in 2021. OTP’s compliance with the Minnesota renewable energy standard will be measured through the Midwest Renewable Energy Tracking System.

 

Under the Next Generation Energy Act of 2007, an automatic adjustment mechanism was established to allow Minnesota electric utilities to recover investments and costs incurred to satisfy the requirements of the renewable energy standard. The MPUC is authorized to approve a rate schedule rider to enable utilities to recover the costs of qualifying renewable energy projects that supply renewable energy to Minnesota customers. Cost recovery for qualifying renewable energy projects can be authorized outside of a rate case proceeding, provided that such renewable projects have received previous MPUC approval. Renewable resource costs eligible for recovery may include return on investment, depreciation, operation and maintenance costs, taxes, renewable energy delivery costs and other related expenses.

 

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Minnesota Conservation Improvement Programs (MNCIP)—Under Minnesota law, every regulated public utility that furnishes electric service must make annual investments and expenditures in energy conservation improvements, or make a contribution to the state's energy and conservation account, in an amount equal to at least 1.5% of its gross operating revenues from service provided in Minnesota. On May 25, 2016 the MPUC adopted the MNDOC’s proposed changes to the MNCIP financial incentive. The new 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 new model will reduce the MNCIP financial incentive by approximately 50% compared to the previous incentive mechanism.

 

The MNDOC may require a utility to make investments and expenditures in energy conservation improvements whenever it finds that the improvement will result in energy savings at a total cost to the utility less than the cost to the utility to produce or purchase an equivalent amount of a new supply of energy. Such MNDOC orders can be appealed to the MPUC. Investments made pursuant to such orders generally are recoverable costs in rate cases, even though ownership of the improvement may belong to the property owner rather than the utility. 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 July 9, 2015 the MPUC granted approval of OTP’s 2014 financial incentive of $3.0 million along with an updated surcharge with an effective date of October 1, 2015.

 

Based on results from the 2015 MNCIP program year, OTP recognized a financial incentive of $4.2 million. The 2015 MNCIP program resulted in an approximate 39% increase in energy savings compared to 2014 program results. On April 1, 2016 OTP requested approval for recovery of its 2015 MNCIP program costs not included in base rates, a $4.3 million financial incentive and an update to the MNCIP surcharge from the MPUC. On July 19, 2016 the MPUC issued an order approving OTP’s request with an effective date of October 1, 2016.

 

Based on results from the 2016 MNCIP program year, OTP recognized MNCIP financial incentives of $5.1 million in 2016, which included a $0.1 million true-up of 2015 financial incentives earned. The 2016 program resulted in an approximate 18% increase in energy savings compared to 2015 program results. On March 31, 2017 OTP requested approval for recovery of its 2016 MNCIP program costs not included in base rates, $5.0 million in performance incentives and an update to the MNCIP surcharge from the MPUC. On September 15, 2017 the MPUC issued an order approving OTP’s request with an effective date of October 1, 2017.

 

Based on results from the 2017 MNCIP program year, OTP recognized a financial incentive of $2.6 million in 2017. The 2017 program resulted in an approximate 10% decrease in energy savings compared to 2016 program results. OTP will request approval for recovery of its 2017 MNCIP program costs not included in base rates, a $2.6 million financial incentive and an update to the MNCIP surcharge from the MPUC by April 1, 2018.

 

In 2016 the MNDOC opened a docket to investigate how investor-owned utilities calculate their avoided costs pertaining to transmission and distribution. Avoided costs are the basis of MNCIP program benefits which, going forward, will establish OTP’s financial incentive. On May 23, 2016 the MNDOC accepted OTP’s 2017 avoided costs calculation, but is requiring Minnesota investor-owned utilities to undergo an analysis of transmission and distribution avoided costs for 2018 and 2019. OTP is participating in a stakeholder group with the MNDOC, Xcel Energy Inc., and Minnesota Power to determine the best method for calculating avoided costs. On September 29, 2017, MNDOC issued a decision on utilities’ transmission and distribution avoided costs. The decision did not require OTP to update avoided costs or cost-effectiveness for the 2017-2019 MNCIP triennial plan. The decision directed OTP to use the discrete approach methodology to calculate avoided transmission and distribution costs as part of OTP’s 2020-2022 MNCIP triennial plans.

 

Transmission Cost Recovery Rider—The MPU Act provides a mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that have been previously approved by the MPUC in a CON proceeding, certified by the MPUC as a Minnesota priority transmission project, made to transmit the electricity generated from renewable generation sources ultimately used to provide service to the utility's retail customers, or exempt from the requirement to obtain a Minnesota CON. The MPUC may also authorize cost recovery via such TCR riders for charges incurred by a utility under a federally approved tariff that accrue from other transmission owners’ regionally planned transmission projects that have been determined by the MISO to benefit the utility or integrated transmission system. The MPU Act also authorizes TCR riders to recover the costs of new transmission facilities approved by the regulatory commission of the state in which the new transmission facilities are to be constructed, to the extent approval is required by the laws of that state, and determined by the MISO to benefit the utility or integrated transmission system. Finally, under certain circumstances, the MPU Act also authorizes TCR riders to recover the costs associated with distribution planning and investments in distribution facilities to modernize the utility grid. Such TCR riders allow 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. MISO regional cost allocation allows OTP to recover some of the costs of its transmission investment from other MISO customers.

 

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On February 18, 2015 the MPUC approved OTP’s 2014 TCR rider annual update with an effective date of March 1, 2015. OTP filed an annual update to its Minnesota TCR rider on September 30, 2015 requesting revenue recovery of approximately $7.8 million. A supplemental filing to the update was made on December 21, 2015 to address an issue surrounding the proration of accumulated deferred income taxes and, in an unrelated adjustment, the TCR rider update revenue request was reduced to $7.2 million. On March 9, 2016 the MPUC issued an order approving OTP’s annual update to its TCR rider, with an effective date of April 1, 2016.

 

OTP filed an update to its TCR rider on April 29, 2016 to incorporate the impact of bonus depreciation for income taxes, an adjusted rate of return on rate base and allocation factors to align with its 2016 general rate case request. On July 5, 2016 the MPUC issued an order approving the proposed rates on a provisional basis, as recommended by the MNDOC. The proposed rate changes went into effect on September 1, 2016. On October 30, 2017 the MPUC issued an order resetting OTP’s Minnesota TCR rates in effect since September 1, 2016 to refund $3.3 million previously collected under the rider, beginning November 1, 2017. The reset rates were approved on a provisional basis in the Minnesota general rate case docket, subject to revision in a separate docket.

 

In OTP’s 2016 general rate case order issued on May 1, 2017, the MPUC ordered OTP to include, in the TCR rider retail rate base, Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVP Projects and all revenues received from other utilities under MISO’s tariffed rates as a credit in its TCR revenue requirement calculations. In doing so, the MPUC’s order diverts interstate wholesale revenues that have been approved by the FERC to offset FERC-approved expenses, effectively reducing OTP’s recovery of those FERC-approved expense levels. The MPUC-ordered treatment will result in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC’s revenue requirements and authorized returns will vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision will vary over time and be dependent on the differences between the revenue requirements and returns in the two jurisdictions at any given time. On August 18, 2017 OTP filed an appeal of the MPUC order with the Minnesota Court of Appeals to contest the portion of the order requiring OTP to allocate costs between jurisdictions of the FERC MVP transmission projects in the TCR rider. OTP believes the MPUC-ordered treatment conflicts with federal authority over transmission of electricity in interstate commerce and rates for the transmission of electricity subject to the jurisdiction of the FERC as set forth in the Federal Power Act of 1935, as amended (Federal Power Act). The decision is expected in late 2018.

 

Environmental Cost Recovery Rider—The Minnesota ECR rider provided for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant 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. OTP filed its 2015 annual update on July 31, 2015, with a request to keep the 2014 annual update rate in place. On December 21, 2015 OTP filed a supplemental filing with updated financial information. The MPUC issued an order on March 9, 2016 approving OTP’s request to leave the 2014 annual update rate in place. OTP filed an update to its Minnesota ECR rider on April 29, 2016 to incorporate the impact of bonus depreciation for income taxes, an adjusted rate of return on rate base and allocation factors to align with its 2016 general rate case request, with an effective date of September 1, 2016. On July 5, 2016 the MPUC issued an order approving the proposed rates on a provisional basis. On October 30, 2017 the MPUC issued an order resetting OTP’s Minnesota ECR rate in effect since September 1, 2016 to refund $1.9 million previously collected under the rider, beginning November 1, 2017. 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.

 

Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed a request with the MPUC to revise its Fuel Clause Adjustment (FCA) rider in Minnesota to include recovery of reagent and emission allowance costs. On March 12, 2015 the MPUC denied OTP’s request to revise its FCA rider to include recovery of these costs. These costs were included in OTP’s 2016 general rate case in Minnesota and were considered for recovery either through the FCA rider or general rates. In its 2016 general rate case order issued May 1, 2017 the MPUC again denied OTP’s request for recovery of test-year reagent costs and emission allowances in base fuel costs or through the FCA rider. Instead, the test-year costs will be recovered in general rates and variability of those costs in excess of amounts included in general rates will only be recovered to the extent actual kwh sales exceed forecasted kwh sales used to establish general rates.

 

Capital Structure PetitionMinnesota law requires an annual filing of a capital structure petition with the MPUC. In this filing the MPUC reviews and approves the capital structure for OTP. Once the petition is approved, OTP may issue securities without further petition or approval, provided the issuance is consistent with the purposes and amounts set forth in the approved capital structure petition. The MPUC approved OTP’s most recent capital structure petition on September 1, 2017, allowing for an equity to total capitalization ratio between 47.4% and 58.0%, with total capitalization not to exceed $1,178,024,000 until the MPUC issues a new capital structure order for 2018. OTP is required to file its 2018 capital structure petition no later than May 1, 2018.

 

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North Dakota

 

OTP is subject to the jurisdiction of the NDPSC with respect to rates, services, certain issuances of securities, construction of major utility facilities and other matters. The NDPSC periodically performs audits of gas and electric utilities over which it has rate setting jurisdiction to determine the reasonableness of overall rate levels. In the past, these audits have occasionally resulted in settlement agreements adjusting rate levels for OTP.

 

The North Dakota Energy Conversion and Transmission Facility Siting Act grants the NDPSC the authority to approve sites in North Dakota for large electric generating facilities and high voltage transmission lines. This Act is similar to the Minnesota Power Plant Siting Act described above and applies to proposed wind energy electric power generating plants exceeding 500 kW of electricity, non-wind energy electric power generating plants exceeding 50,000 kW and transmission lines with a design in excess of 115 kV. OTP is required to submit a ten-year plan to the NDPSC biennially.

 

The NDPSC reserves the right to review the issuance of stocks, bonds, notes and other evidence of indebtedness of a public utility. However, the issuance by a public utility of securities registered with the SEC is expressly exempted from review by the NDPSC under North Dakota state law.

 

General RatesOn 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%. In the request, OTP proposed an allowed return on rate base of 7.97% and an allowed rate of return on equity of 10.30%. On December 20, 2017 the NDPSC approved OTP’s request for interim rates to increase annual revenue collections by $12.8 million, effective January 1, 2018. OTP used a lower rate of return on equity in the calculation of interim rates based on the rate of return on equity used in its 2018 test-year rate request.

 

OTP’s most recent 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 Renewable Resource Adjustment (NDRRA) which enables OTP to recover the North Dakota share of its investments in renewable energy facilities it owns in North Dakota. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed, along with a return on investment. The NDPSC approved OTP’s 2014 annual update to the NDRRA, including a change in rate design from an amount per kwh consumed to a percentage of a customer’s bill, on March 25, 2015 with an effective date of April 1, 2015. OTP submitted its 2015 annual update to the NDRRA rider rate on December 31, 2015 with a requested implementation date of April 1, 2016. On February 25, 2016 OTP made a supplemental filing to address the impact of bonus depreciation for income taxes and related deferred tax assets on the NDRRA, as well as an adjustment to the estimated amount of Federal Production Tax Credits used. The NDPSC approved the NDRRA 2015 annual update on June 22, 2016 with an effective date of July 1, 2016. The updated NDRRA reflects a reduction in the ROE component of the rate from 10.75%, approved in OTP’s most recent general rate case, to 10.50%. OTP submitted its 2016 annual update to the NDRRA rider rate on December 30, 2016, requesting a decrease to the NDRRA rate from 7.573% to 7.005%. The NDPSC approved the NDRRA 2016 annual update on March 15, 2017 with an effective date of April 1, 2017.

 

In conjunction with OTP’s November 2, 2017 general rate case filing, OTP submitted an updated proposal to adjust the NDRRA rate to reflect updated costs and collections, as well as reflect a rate of return and capital structure level consistent with those proposed in the general rate case. The NDPSC approved the update to the NDRRA rate in conjunction with approving the rate case interim rates. The new NDRRA rate increased from 7.005% to 7.756% with an effective date of January 1, 2018.

 

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.

 

On August 31, 2015 OTP filed its 2015 annual update to its North Dakota TCR rider rate requesting recovery of approximately $10.2 million for 2016 compared with $8.5 million for 2015, including costs assessed by the MISO as well as costs from the Southwest Power Pool (SPP) that OTP began incurring January 1, 2016. These costs are associated with OTP’s load connected to the transmission system of Central Power Electric Cooperative (CPEC). OTP’s load became subject to SPP transmission-related charges when CPEC transmission assets were added to the SPP. The NDPSC approved OTP’s 2015 annual update to its TCR rider rate on December 16, 2015, with an effective date of January 1, 2016.

 

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On September 1, 2016 OTP filed its annual update to the TCR rider requesting a revenue requirement of $5.7 million, which includes a reduction of $2.6 million for a projected over-collection for 2016. Primary drivers of the decrease from the 2015 updated rider rate include the impact of federal bonus depreciation and unresolved MISO ROE complaint proceedings. OTP filed a supplemental filing on September 14, 2016, requesting that the over-collection balance be spread over the next two years for purposes of reducing the volatility of the rates from year to year. The NDPSC approved the update on December 14, 2016. The new rates went into effect on January 1, 2017.

 

On August 31, 2017 OTP filed its annual update to the TCR rider requesting a revenue requirement of $8.6 million. OTP filed a supplemental filing on November 2, 2017, reducing its revenue requirement request by $0.6 million to $8.0 million to reflect the rate of return and allocation factors used in its submitted general rate case also filed on November 2, 2017. The NDPSC approved the update for recovery of the $8.0 million revenue requirement on November 29, 2017. The new rates went into effect on January 1, 2018.

 

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 Toxics Standards (MATS) projects. The ECR rider provides for a return on investment at the level approved in OTP’s most recent general rate case and for recovery of OTP’s North Dakota share of reagent and emission allowance costs.

 

On March 31, 2015 OTP filed its annual update to the ECR. This update included a request to increase the ECR rider rate from 7.531% to 9.193% of base rates. The NDPSC approved the annual update on June 17, 2015 with an effective date of July 1, 2015, along with the approval of recovery of OTP’s North Dakota jurisdictional share of Hoot Lake Plant MATS project costs.

 

On March 31, 2016 OTP filed its annual update to the ECR rider requesting a reduction in the rate from 9.193% to 7.904% of base rates, or a revenue requirement reduction from $12.2 million to $10.4 million, effective July 1, 2016. The rate reduction request was primarily due to the Company’s 2015 bonus depreciation election for income taxes, which reduces revenue requirements. The filing was approved on June 22, 2016.

 

On March 31, 2017 OTP filed its annual update to the ECR rider requesting a reduction in the rate from 7.904% to 7.633% of base rates, or a revenue requirement reduction from $10.4 million to $9.9 million, effective July 1, 2016. The rate reduction request was primarily due to a reduction in the projects’ unrecovered costs and lower net book values as a result of depreciation. The filing was approved on July 12, 2017.

 

In conjunction with OTP’s November 2, 2017 general rate case filing, OTP submitted an updated proposal to adjust the ECR rider rate to reflect updated costs and collections, as well as reflect a rate of return and capital structure level consistent with those proposed in the general rate case. The NDPSC approved the update to the ECR rider rate in conjunction with approving the general rate case interim rates. The new ECR rate decreased from 7.633% to 6.629% with an effective date of January 1, 2018.

 

Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed a request with the NDPSC to revise its FCA rider in North Dakota to include recovery of new reagent and emission allowance costs. On February 25, 2015 the NDPSC approved recovery of these costs through modification of the ECR rider, instead of recovery through the FCA as OTP had proposed. The ECR rider reagent and emissions allowance charge became effective May 1, 2015.

 

South Dakota

 

Under the South Dakota Public Utilities Act, OTP is subject to the jurisdiction of the SDPUC with respect to rates, public utility services, construction of major utility facilities, establishment of assigned service areas and other matters. Under the South Dakota Energy Facility Permit Act, the SDPUC has the authority to approve sites in South Dakota for large energy conversion facilities (100,000 kW or more) and most transmission lines with a design of 115 kV or more.

 

2010 General Rate Case—OTP’s most recent 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. OTP has a TCR rider in South Dakota to recover its South Dakota jurisdictional share of the revenue requirements associated with its investment in new or modified electric transmission facilities. The SDPUC approved OTP’s 2014 annual update on February 13, 2015 with an effective date of March 1, 2015. OTP filed its 2015 annual update on October 30, 2015 with a proposed effective date of March 1, 2016. A supplemental filing was made on February 3, 2016 to

 

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true-up the filing to include the impact of bonus depreciation elected for 2015, the inclusion of a deferred tax asset relating to a net operating loss and the proration of accumulated deferred income taxes. This update included the recovery of new SPP transmission costs OTP began to incur on January 1, 2016. On February 12, 2016 the SDPUC approved OTP’s annual update to its TCR rider, with an effective date of March 1, 2016. On November 1, 2016 OTP filed the annual update to the South Dakota TCR rider. OTP made a supplemental filing on January 20, 2017 to include updated costs through December 2016 as well as updated forecast information. On February 17, 2017 the SDPUC approved OTP’s annual update to its TCR rider, with an effective date of March 1, 2017. On November 1, 2017 OTP filed the annual update to the South Dakota TCR rider with a requested annual revenue requirement of $1.8 million and effective date of March 1, 2018. A supplemental filing was made on January 29, 2018 to reflect updated costs and collections and incorporate the impact of the reduction in the federal corporate income tax rate from 35% to 21% effective January 1, 2018. The updated revenue requirement requested is $1,778,992.

 

Environmental Cost Recovery Rider— OTP has an ECR rider in South Dakota to recover its South Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects. On August 31, 2015 OTP filed its annual update to the South Dakota ECR requesting recovery of approximately $2.7 million in annual revenue. The SDPUC approved the request on October 15, 2015 with an effective date of November 1, 2015. On August 31, 2016 OTP filed its 2016 update to the ECR rider, requesting recovery of approximately $2.3 million in annual revenue. The SDPUC approved the request on October 26, 2016 with an effective date of November 1, 2016. The lower revenue requirement is a result of the implementation of federal bonus depreciation taken on the Big Stone Plant AQCS. On August 31, 2017 OTP filed its 2017 update to the ECR rider, requesting recovery of approximately $2.1 million in annual revenue. The SDPUC approved the request on October 13, 2017 with an effective date of November 1, 2017.

 

Reagent Costs and Emission Allowances—OTP’s South Dakota jurisdictional share of reagent costs and emission allowances is currently being recovered in its South Dakota FCA rider.

 

Energy Efficiency Plan (EEP)—The SDPUC has encouraged all investor-owned utilities in South Dakota to be part of an Energy Efficiency Partnership to significantly reduce energy use. The plan is being implemented with program costs, carrying costs and a financial incentive being recovered through an approved rider.

 

On May 1, 2015 OTP filed its 2014 South Dakota EEP Status Report, financial incentive and surcharge adjustment along with a request for approval of an incentive of $105,000 and EEP surcharge increase to $0.00152/kwh. On July 14, 2015 the SDPUC issued a written order approving OTP’s 2014 EEP Status Report, incentive and surcharge increases.

 

On April 29, 2016 OTP filed its 2015 South Dakota EEP Status Report, financial incentive and surcharge adjustment with the SDPUC. The filing requested approval of an incentive of $105,900 and a decrease in the EEP surcharge from $0.00152/kwh to $0.00114/kwh effective July 1, 2016. The SDPUC approved the request. On April 29, 2016 OTP also filed its 2017-2019 goals and budgets for its South Dakota EEP triennial plan. For the 2017, 2018 and 2019 EEP planning years, OTP has proposed energy savings goals and budgets of 3,804,094 kwh and $449,000 in 2017, 3,805,177 kwh and $449,000 in 2018 and 3,806,262 kwh and $449,000 in 2019. On November 22, 2016 the SDPUC approved OTP’s 2017-2019 EEP triennial plan with certain conditions.

 

On May 1, 2017 OTP filed its 2016 South Dakota EEP Status Report, financial incentive and surcharge adjustment with the SDPUC. The filing requested approval of an incentive of $105,900 and an increase in the EEP surcharge from $0.00114/kwh to $0.00138/kwh effective July 1, 2017. The SDPUC approved the request on June 21, 2017.

 

FERC

 

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

 

Multi-Value Transmission Projects—On December 16, 2010 the FERC approved the cost allocation for a new classification of projects in the MISO region called MVPs. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. On October 20, 2011 the FERC reaffirmed the MVP cost allocation on rehearing.

 

Effective January 1, 2012 the FERC authorized OTP to recover 100% of prudently incurred CWIP and Abandoned Plant Recovery on two projects approved by MISO as MVPs in MISO’s 2011 Transmission Expansion Plan: the Big Stone South–Brookings MVP and the Big Stone South–Ellendale MVP.

 

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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 December 31, 2017.

 

In June 2014, the FERC adopted a two-step ROE methodology for electric utilities in an order issued in a complaint proceeding involving New England Transmission Owners (NETOs). The issue of how to apply the FERC ROE methodology has been contested in various complaint proceedings, including the two ROE complaints involving MISO transmission owners discussed above. In April 2017 the Court of Appeals for the District of Columbia (D.C. Circuit) vacated and remanded the FERC’s June 2014 ROE order in the NETOs’ complaint. The D.C. Circuit found that the FERC had not properly determined that the ROE authorized for NETOs prior to June 2014 was unjust and unreasonable. The D.C. Circuit also found that the FERC failed to justify the new ROE methodology. OTP will await the FERC response to the April 2017 action of the D.C. Circuit before determining if an adjustment to its accrued refund liability is required. On September 29, 2017 the MISO transmission owners filed a motion to dismiss the second complaint based on the D.C. Circuit decision in the NETO complaint. If the 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.

 

Together with as many as 200 utilities, generators and power marketers, OTP participated in proceedings before the FERC regarding the calculation, assessment and implementation of MISO Revenue Sufficiency Guarantee (RSG) charges for entities participating in the MISO wholesale energy market since that market’s start on April 1, 2005 until the conclusion of the proceedings on May 2, 2015. The proceedings fundamentally concerned MISO’s application of its MISO RSG rate on file with the FERC to market participants, revisions to the RSG rate based on several FERC orders, and the FERC’s decision to not resettle the markets based on MISO application of the RSG rate to market participants. Several of the FERC’s orders are on review in a set of consolidated cases before the D.C. Circuit. The consolidated petitions at the D.C. Circuit involve multiple petitioners and intervenors. OTP is an intervenor in these cases. Final briefs were filed in January 2018. Oral arguments for this case are expected in the spring of 2018 with a final decision expected late in 2018. MISO has not made available past billing or resettlement data necessary for determining amounts that might be payable if the FERC’s decisions are reversed. Therefore, the Company cannot estimate OTP’s exposure at this time from a final order reversing the relevant FERC orders, which could have an adverse effect on the Company’s results of operations.

 

NAEMA

 

OTP is a member of the North American Energy Marketers Association (NAEMA) which is an independent, non-profit trade association representing entities involved in the marketing of energy or in providing services to the energy industry. NAEMA has over 150 members with operations in 48 states and Canada. Power pool sales are conducted continuously through NAEMA in accordance with schedules filed by NAEMA with the FERC.

 

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North American Electric Reliability Corporation (NERC)

 

NERC is an international regulatory authority, subject to oversight by the FERC and governmental authorities in Canada, whose mission is to assure the reliability of the bulk power system in North America. As an owner and operator within the bulk power system, OTP is required to comply with NERC reliability standards, including standards on cybersecurity and protection of critical infrastructure.

 

Midwest Reliability Organization (MRO)

 

OTP is a member of the MRO. The MRO is a non-profit organization dedicated to ensuring the reliability and security of the bulk power system in the north central region of North America, including parts of both the United States and Canada. MRO began operations in 2005 and is one of eight regional entities in North America operating under authority from regulators in the United States and Canada through a delegation agreement with the NERC. The MRO is responsible for: (1) developing and implementing reliability standards, (2) enforcing compliance with those standards, (3) providing seasonal and long-term assessments of the bulk power system’s ability to meet demand for electricity, and (4) providing an appeals and dispute resolution process.

 

The MRO region covers roughly one million square miles spanning the provinces of Saskatchewan and Manitoba, the states of North Dakota, Minnesota, Nebraska and the majority of territory in the states of South Dakota, Iowa and Wisconsin. The region includes more than 130 organizations that are involved in the production and delivery of power to more than 20 million people. These organizations include municipal utilities, cooperatives, investor-owned utilities, a federal power marketing agency, Canadian Crown Corporations, independent power producers and others who have interests in the reliability of the bulk power system.

 

To ensure our compliance with NERC standards, the MRO periodically audits OTP. OTP’s most recent audit began with a notification in October 2015 and MRO audit staff conducted fieldwork in January 2016. On February 3, 2017 OTP received the final audit report from the MRO audit team. The MRO found no potential violations at OTP. OTP’s next audit will take place in the first quarter of 2019.

 

MISO

 

OTP is a member of the MISO. As the transmission provider and security coordinator for the region, the MISO seeks to optimize the efficiency of the interconnected system, provide regional solutions to regional planning needs and minimize risk to reliability through its security coordination, long-term regional planning, market monitoring, scheduling and tariff administration functions. The MISO covers a broad region containing all or parts of 15 states and the Canadian province of Manitoba. The MISO has operational control of OTP’s transmission facilities above 100 kV, but OTP continues to own and maintain its transmission assets.

 

Through the MISO Energy Markets, MISO seeks to develop options for energy supply, increase utilization of transmission assets, optimize the use of energy resources across a wider region and provide greater visibility of data. MISO aims to facilitate a more cost-effective and efficient use of the wholesale bulk electric system.

 

The MISO Ancillary Services Market (ASM) facilitates the provision of Regulation, Spinning Reserve and Supplemental Reserves. The ASM integrates the procurement and use of regulation and contingency reserves with the existing Energy Market. OTP has actively participated in the market since its commencement.

 

Other

 

OTP is subject to various federal laws, including the Public Utility Regulatory Policies Act of 1978 and the Energy Policy Act of 1992 (which are intended to promote the conservation of energy and the development and use of alternative energy sources) and the Energy Policy Act of 2005.

 

Competition, Deregulation and Legislation

 

Electric sales are subject to competition in some areas from municipally owned systems, rural electric cooperatives and, in certain respects, from on-site generators and cogenerators. Electricity also competes with other forms of energy. The degree of competition may vary from time to time depending on relative costs and supplies of other forms of energy.

 

The Company believes OTP is well positioned to be successful in a competitive environment. A comparison of OTP’s electric retail rates to the rates of other investor-owned utilities, cooperatives and municipals in the states OTP serves indicates OTP’s rates are competitive.

 

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Legislative and regulatory activity could affect operations in the future. OTP cannot predict the timing or substance of any future legislation or regulation. The Company does not expect retail competition to come to the states of Minnesota, North Dakota or South Dakota in the foreseeable future. There has been no legislative action regarding electric retail choice in any of the states where OTP operates. The Minnesota legislature has in the past considered legislation that, if passed, would have limited the Company’s ability to maintain and grow its nonelectric businesses.

 

OTP is unable to predict the impact on its operations resulting from future regulatory activities, from future legislation or from future taxes that may be imposed on the source or use of energy.

 

Environmental Regulation

 

Impact of Environmental Laws—OTP’s existing generating plants are subject to stringent federal and state standards and regulations regarding, among other things, air, water and solid waste pollution. In the five years ended December 31, 2017 OTP invested approximately $202 million in environmental control facilities. The 2018 and 2019 construction budgets include approximately $5 million and $4 million, respectively, for environmental equipment for existing facilities.

 

Air Quality - Criteria Pollutants—Pursuant to the Clean Air Act (CAA), the Environmental Protection Agency (EPA) has promulgated national primary and secondary standards for certain air pollutants.

 

The primary fuels burned by OTP’s steam generating plants are North Dakota lignite coal and western subbituminous coal. Hoot Lake Plant, Big Stone Plant, and Coyote Station are currently operating within all presently applicable federal and state air quality and emission standards.

 

The CAA, in addressing acid deposition, imposed requirements on power plants in an effort to reduce national emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx).

 

The national Acid Rain Program SO2 emission reduction goals are achieved through a market based system under which power plants are allocated "emissions allowances" that require plants to either reduce their SO2 emissions or acquire allowances from others to achieve compliance. Each allowance is an authorization to emit one ton of SO2. SO2 emission requirements are currently being met by all of OTP’s generating facilities without the need to acquire additional allowances for compliance.

 

The national Acid Rain Program NOx emission reduction goals are achieved by imposing mandatory emissions standards on individual sources. All of OTP’s generating facilities met the NOx standards during 2017.

 

The Cross-State Air Pollution Rule (CSAPR) requires SO2 and NOx emission reductions in primarily eastern states in order to allow downwind states to achieve national ambient air quality standards (NAAQS). CSAPR's Phase 1 emission budgets began on January 1, 2015 for the annual SO2 and NOx programs, with stricter Phase 2 budgets beginning in 2017.

 

The CSAPR rule applies to OTP’s Solway gas peaking plant and the Hoot Lake coal-fired plant in Minnesota. Minnesota is considered a Group 2 state for SO2 compliance. Any SO2 allowances that need to be obtained for Hoot Lake Plant will need to be from an entity in a Group 2 state. The impact of the CSAPR rule is anticipated to be minimal due to the sharp decline in Group 2 SO2 allowance prices since 2016 and reduced dispatch of Hoot Lake Plant.

 

On September 7, 2016 the EPA finalized an update to the CSAPR to address interstate emission transport with respect to the more recent 2008 ozone NAAQS. The updated CSAPR does not apply to Minnesota, North Dakota and South Dakota.

 

On October 1, 2015 the EPA announced that it tightened the primary and secondary NAAQS for ozone from 75 parts per billion (ppb) to 70 ppb. This was at the upper end of the range of which the EPA had proposed, which was 65 to 70 ppb. On November 16, 2017 EPA issued a final rule determining that all of the areas in the states in which OTP operates will be designated as attainment/unclassifiable.

 

In June 2010, the EPA established a new primary NAAQS for SO2 at a level of 75 ppb on a 1-hour average. Designations for this standard are proceeding under several different pathways. For certain large sources as defined by 2012 emissions, including Big Stone Plant and Coyote Station, the EPA entered into a consent decree with the Sierra Club/Natural Resources Defense Council that required the EPA to promulgate final designations near those sources by July 2, 2016. On June 30, 2016, the EPA signed a final rule that designated the areas around Big Stone Plant and Coyote Station as being in attainment/unclassifiable with the 1-hour SO2 NAAQS. Numerous other sources, including Hoot Lake Plant, are covered by the EPA's final Data Requirements Rule (DRR) that was finalized in August 2015. The DRR requires states to provide either modeling or monitoring data to adequately characterize SO2 emissions surrounding those sources. Based on modeling, in January 2018, the EPA published a final determination of attainment/unclassifiable for the county in which Hoot Lake Plant resides.

 

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Air Quality – Hazardous Air Pollutants—On December 16, 2011 the EPA signed a final rule to reduce mercury and other air toxics emissions from power plants known as the MATS rule. With the installation of new pollution control equipment in 2015, OTP's affected units are meeting current requirements. Emissions monitoring equipment and/or stack testing is being used to verify compliance with the standards. Litigation surrounding the MATS rule is ongoing despite the expiration of the compliance deadlines, and the rule remains in effect while the litigation continues. On April 15, 2016 the EPA issued a supplemental finding that the MATS rule continues to be “appropriate and necessary” when considering the costs of compliance. Litigation surrounding this finding is being held in abeyance while EPA considers whether it should be maintained, modified or otherwise reconsidered.

 

Air Quality – EPA New Source Review Enforcement Initiative—In 1998 the EPA announced its New Source Review Enforcement Initiative targeting coal-fired power plants, petroleum refineries, pulp and paper mills and other industries for alleged violations of the EPA’s New Source Review rules. These rules require owners or operators that construct new major sources or make major modifications to existing sources to obtain permits and install air pollution control equipment at affected facilities. Pursuant to the Initiative, the EPA has attempted to determine if emission sources violated certain provisions of the CAA by making major modifications to their facilities without installing state-of-the-art pollution controls. OTP has not received any recent requests from the EPA, pursuant to Section 114(a) of the CAA, to provide information relative to past operation and capital construction projects at its coal-fired plants.

 

Air Quality – Regional Haze Program— The Regional Haze Rule requires emissions reductions from certain sources that are deemed to contribute to visibility impairment in Class I air quality areas. Based on the South Dakota Department of Environment and Natural Resources’ determination and the final South Dakota Regional Haze State Implementation Plan approved by the EPA on March 29, 2012, Big Stone Plant was required to install Selective Catalytic Reduction and separated over-fire air to reduce NOx emissions, dry flue gas desulfurization to reduce SO2 emissions, and a new baghouse for particulate matter control. The Big Stone Plant compliant AQCS equipment was placed into commercial operation on December 29, 2015.

 

The North Dakota Regional Haze State Implementation Plan requires that Coyote Station reduce its NOx emissions to 0.5 pounds per million Btu as calculated on a 30-day rolling average basis beginning on July 1, 2018. The control equipment was installed during a spring 2016 outage.

 

Air Quality – Greenhouse Gas (GHG) Regulation—Combustion of fossil fuels for the generation of electricity is a considerable stationary source of CO2 emissions in the United States and globally. OTP is an owner or part-owner of three baseload, coal-fired electricity generating plants and three fuel-oil or natural gas-fired combustion turbine peaking plants with a combined net dependable capacity of 650 MW. In 2017 these plants emitted approximately 2.9 million tons of CO2.

 

In April 2007, the U.S. Supreme Court issued a decision that determined that the EPA has authority to regulate CO2 and other GHGs from automobiles as “air pollutants” under the CAA. The EPA thereafter conducted a rulemaking to determine whether GHG emissions contribute to climate change “which may reasonably be anticipated to endanger public health or welfare.” While this case addressed a provision of the CAA related to emissions from motor vehicles, a parallel provision of the CAA applies to stationary sources such as electric generators. The EPA determined that parallel provision would be automatically triggered once the EPA began regulating motor vehicle GHG emissions. The first step in the EPA rulemaking process was the publication of an endangerment finding in the December 15, 2009 Federal Register where the EPA found that CO2 and five other GHGs – methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride (SF6) – threaten public health and the environment.

 

The EPA’s endangerment finding for GHGs did not in and of itself impose any emission reduction requirements but rather authorized the EPA to finalize the GHG standards for new light-duty vehicles as part of the joint rulemaking with the Department of Transportation. These standards applied to motor vehicles as of January 2011, which the EPA determined made GHGs “subject to regulation” under the CAA. According to the EPA, this triggered the Prevention of Significant Deterioration (PSD) and Title V operating permits programs for stationary sources of GHGs.

 

On June 6, 2010 the EPA published a final “tailoring rule” that phased in application of its PSD and Title V programs to GHG emission sources, including power plants. The PSD program applies to existing sources if there is a physical change or change in the method of operation of the facility that results in a significant net emissions increase of any pollutant. As a result, PSD does not apply on a set timeline as is the case with other regulatory programs, but is triggered when certain activities take place at a major source. If triggered, the owner or operator of an affected facility must undergo a review which requires, among other things, the identification and implementation of best-available control technology (BACT) for the regulated air pollutants for which there is a significant net emissions increase, and an analysis of the ambient air quality impacts of the facility.

 

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In June 2012 the United States Court of Appeals for the D.C. Circuit upheld most of the EPA’s rules regarding the regulation of GHGs under the CAA, including the tailoring rule. However, in October 2013 the U.S. Supreme Court granted a petition for a writ of certiorari to review the question of whether the regulation of new motor vehicle GHG emissions does in fact automatically trigger PSD and Title V regulation of GHGs for stationary sources. On June 23, 2014 the U.S. Supreme Court issued its decision that, in summary, held the EPA exceeded its statutory authority and may not require a PSD or Title V permit based solely on GHG emissions. However, the U.S. Supreme Court also said the EPA could continue to require that PSD permits for sources otherwise subject to PSD based on emissions of conventional pollutants contain limitations on GHG emissions based on the application of BACT. The EPA revised its regulations to implement this ruling and in 2016 proposed a de minimis level of GHG emissions below which PSD would not apply. OTP does not anticipate making modifications that would trigger PSD requirements at any of its facilities or undertaking construction of a new unit that might trigger PSD.

 

The EPA has developed New Source Performance Standards (NSPS) for GHGs from new and existing fossil fuel-fired electric generating units. On October 23, 2015 the EPA published the final NSPS under section 111(b) of the CAA that requires certain new units (as well as modified and reconstructed units) to meet CO2 emission standards. New natural gas combustion turbines are required to meet a standard of 1,000 lbs. of CO2 per gross megawatt hour averaged over a 12-month period if they meet the definition of a baseload unit. New natural gas combined cycle units are anticipated to fit into this category. Simple cycle combustion turbines are regulated in a non-baseload category that is required to meet a heat input based standard that can be met by burning clean fuels such as natural gas. This rule was challenged by a number of parties and litigation is pending. Therefore, there is uncertainty regarding the future of the NSPS rules.

 

GHG performance standards for existing sources are being developed under CAA Section 111(d) (111(d) Standard). A 111(d) Standard, unlike those set under CAA Section 111(b), applies to existing sources of a pollutant. Under Section 111(d), the EPA promulgates emission guidelines and the states are then given a period of time to develop plans to implement the standard. The EPA reviews each state-developed standard and then approves it if the state’s plan comports with the federal emission guidelines. If the state does not submit a plan or the EPA finds that the plan is inadequate, the EPA will prescribe a plan for that state.

 

For both new and existing sources, the EPA must develop a “standard of performance,” which is defined as:

 

…a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any non-air quality health and environmental impact and energy requirements) the [EPA] Administrator determines has been adequately demonstrated.

 

For existing sources, Section 111(d) also requires the EPA to consider, “among other factors, remaining useful lives of the sources in the category of sources to which such standard applies.”

 

On October 23, 2015 the EPA published final Section 111(d) emission guidelines for existing fossil fuel-fired power plants, termed the Clean Power Plan (CPP). The final rule used a formula to calculate state goals that relied on three building blocks: (1) a heat rate improvement at each coal plant, (2) increased reliance on natural gas combined cycle units, and (3) increased deployment of renewable energy. These building blocks were applied to each grid interconnection that resulted in final national uniform emission rate standards of 1,305 pounds of CO2 per net megawatt hour for coal plants and 771 pounds of CO2 per net megawatt hour for natural gas combined cycle plants. The EPA then translated the rate goals into mass-based goals that can be applied to existing sources or, if a state chooses, a mass-based goal that applies to both existing sources and new sources.

 

A number of states, utilities, and trade groups filed petitions for review with the D.C. Circuit seeking to overturn the rule, and also moved to stay the rule. On January 14, 2016 the D.C. Circuit denied the stay motions. Numerous petitioners then sought an emergency stay in the U.S. Supreme Court. On February 9, 2016 the U.S. Supreme Court granted a stay of the CPP, pending disposition of petitions for review in the D.C. Circuit. The D.C. Circuit heard oral argument on challenges to the CPP on September 27, 2016 before the full court, and a decision was expected in the first half of 2017. However, pursuant to Executive Order 13783, Promoting Energy Independence and Economic Growth, the EPA was directed to consider suspending, revising or rescinding the CO2 rules discussed above. Thereafter, the EPA issued notices of its intent to review these rules pursuant to the Executive Order, and it filed motions to stay the pending litigation. The D.C. Circuit subsequently issued orders holding in abeyance the appeals of both the NSPS and the CPP, pending EPA review. On October 16, 2017 the EPA published a proposed rule to repeal the CPP, and on December 18, 2017, the EPA announced an Advance Notice of Proposed Rulemaking to solicit information in order to inform the EPA as the Agency considers proposing a future 111(d) rule that is consistent with the legal interpretation discussed in the proposed repeal rule. Therefore, there is uncertainty regarding the future of regulation of CO2 under Section 111(d).

 

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Several states and regional organizations have or will develop state-specific or regional legislative initiatives to reduce GHG emissions through mandatory programs. In 2007 the state of Minnesota passed legislation regarding renewable energy portfolio standards that requires retail electricity providers to obtain 25% of the electric energy sold to Minnesota customers from renewable sources by the year 2025. Additionally, in 2013 the state of Minnesota passed a provision that requires public utilities to generate or procure sufficient electricity generated by solar energy to serve its retail electricity customers in Minnesota so that by the end of 2020, at least 1.5% of the utility's total retail electric sales to retail customers in Minnesota is generated by solar energy. The Minnesota legislature set a January 1, 2008 deadline for the MPUC to establish an estimate of the likely range of costs of future CO2 regulation on electricity generation. The legislation also set state targets for reducing fossil fuel use, included goals for reducing the state's output of GHGs, and restricted importing electricity that would contribute to statewide power sector CO2 emission. The MPUC, in its order dated December 21, 2007, established an estimate of future CO2 regulation costs at between $4.00 per ton and $30.00 per ton emitted in 2012 and after. Annual updates of the range are required. For 2017 the range is $9.05 to $43.06 per ton, and the applicable effective date to begin using CO2 costs in resource planning decisions is 2020. The MNDOC and MPCA have proposed a range of $5.00 to $25.00 per ton beginning in 2025 to be used for 2018.

 

In 2013, Minnesota opened a new docket to investigate the environmental and socioeconomic costs of externalities associated with electricity generation. This docket studied the impact of CO2 and certain criteria pollutants. A final order was issued on January 3, 2018. The environmental cost values for CO2 range from a low of $8.44 per ton and a high of $39.76 per ton in 2017 to a low of $15.20 per ton and a high of $69.48 per ton in 2050. Low, medium, and high values were also set for various criteria pollutants for rural, metropolitan fringe, and urban areas in the state.

 

The states of North Dakota and South Dakota currently have no proposed or pending legislation related to the regulation of GHG emissions, but North Dakota and South Dakota have 10% renewable energy objectives. OTP currently has sufficient renewable generation to meet the renewable energy objectives in both North Dakota and South Dakota.

 

While the eventual outcome of GHG regulation is unknown, OTP is taking steps to reduce its carbon footprint and mitigate levels of CO2 emitted in the process of generating electricity for its customers through the following initiatives:

 

 

Supply efficiency and reliability: Since 2005, SO2, NOx and mercury emitted from OTP’s fossil fuel-fired plants have decreased 55%, 77% and 83%, respectively. OTP’s efforts to increase plant efficiency and add renewable energy to its resource mix have reduced its CO2 intensity. Between 2005 and 2017 OTP decreased its overall system average CO2 emissions intensity by approximately 26%. Further reductions are expected with the anticipated replacement of Hoot Lake Plant generation with natural gas-fired generation in the 2021 timeframe.

 

 

Conservation: Since 1992 OTP has helped its customers conserve more than 4.3 million cumulative megawatt-hours of electricity, which is roughly equivalent to the amount of electricity that 358,000 average homes would use in a year and represents approximately 352% of the annual energy sales of OTP’s entire residential customer base. Additionally, OTP’s conservation programs contribute 113 MW of load reduction to its system.

 

 

Renewable energy: Since 2002, OTP’s customers have been able to purchase 100% of their electricity from wind generation through OTP’s Tail Winds program. OTP has access to 102.9 MW of wind powered generation under power purchase agreements and owns 138 MW of wind powered generation. OTP is exploring options for meeting a Minnesota legislative mandate requiring Minnesota’s investor-owned utilities to serve 1.5% of their Minnesota retail electric sales with solar power by 2020.

 

 

Other: OTP is a participating member of the EPA’s SF6 Emission Reduction Partnership for Electric Power Systems program, which proactively is targeting a reduction in emissions of SF6, a potent GHG. SF6 has a global-warming potential 23,900 times that of CO2. OTP participates in carbon sequestration research through the Plains CO2 Reduction Partnership through the University of North Dakota’s Energy and Environmental Research Center. This Partnership is a collaborative effort of approximately 100 public and private sector stakeholders working toward a better understanding of the technical and economic feasibility of capturing and storing anthropogenic CO2 emissions from stationary sources in central North America.

 

While the future financial impact of any proposed or pending litigation or regulation of GHG emissions is unknown at this time, any capital and operating costs incurred for additional pollution control equipment or CO2 emission reduction measures, such as the cost of sequestration or purchasing allowances, or offset credits, or the imposition of a carbon tax or cap and trade program at the state or federal level could materially adversely affect the Company’s future results of operations, cash flows, and possibly financial condition, unless such costs could be recovered through regulated rates and/or future market prices for energy.

 

Water Quality—The Federal Water Pollution Control Act Amendments of 1972 and amendments thereto, provide for, among other things, the imposition of effluent limitations to regulate discharges of pollutants, including thermal discharges, into the waters of the United States, and the EPA has established effluent guidelines for the steam electric power generating industry. Discharges must also comply with state water quality standards.

 

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Effluent limits specific to Hoot Lake Plant and Coyote Station are incorporated into their National Pollutant Discharge Elimination System (NPDES) permits. Big Stone Plant is a zero discharge facility and therefore does not have a NPDES permit. On November 3, 2015 the EPA published the final rule that sets technology-based effluent limitations on certain types of discharges. Generally, the final rule establishes new requirements for wastewater streams from wet flue gas desulfurization, fly ash transport, and bottom ash transport. This includes zero discharge requirements for fly ash and bottom ash transport water. OTP’s facilities either utilize dry ash handling or use transport water in a closed loop manner. Therefore, OTP anticipates minimal impact from the rule.

 

On May 9, 2014 the EPA Administrator signed a final rule implementing Section 316(b) of the Clean Water Act establishing standards for cooling water intake structures for certain existing facilities. The final rule includes seven compliance options, plus a potential "de minimis" option that is not well defined. Although the impact of the Hoot Lake Plant intake structure has been extensively evaluated in two separate studies both of which showed minimal impact, OTP will need to have state agency discussions during the renewal of the Hoot Lake Plant NPDES permit to determine the appropriate path forward. Coyote Station provided various studies with their next NPDES permit renewal application, but minimal impact is anticipated since Coyote Station already uses closed-cycle cooling.

 

OTP has all federal and state water permits presently necessary for the operation of the Coyote Station, the Big Stone Plant and the Hoot Lake Plant.

 

OTP owns five small dams on the Otter Tail River, which are subject to FERC licensing requirements. A license for all five dams was issued on December 5, 1991. In June 2015 OTP notified the FERC of its intent to relicense these dams. The current FERC license expires in 2021 and the licensing process takes approximately 5 years. The FERC completed the scoping meeting in the fall of 2016 and issued a study plan determination in April 2017. OTP completed the first round of studies in 2017 and will complete the second round in 2018. These studies will be followed by the filing of the license application in 2019. OTP expects the FERC to issue an order on the license application in 2021. Total nameplate rating (manufacturer’s expected output) of the five dams is 3,250 kW.

 

Solid Waste—Permits for disposal of ash and other solid wastes have been issued for the Coyote Station, the Big Stone Plant and the Hoot Lake Plant.

 

On December 19, 2014 the EPA announced a final rule regulating coal combustion residuals (CCR) under the Resource Conservation and Recovery Act regulating the disposal of coal ash generated from the combustion of coal by electric utilities under Subtitle D’s nonhazardous provisions. The final rule was published on April 17, 2015. The rule requires OTP to complete certain actions, such as installing additional groundwater monitoring wells and investigating whether existing surface impoundments meet defined location restrictions, in order to determine whether existing surface impoundments should be retired or retrofitted with liners. The Big Stone Plant and Coyote Station surface impoundments are currently planned to be replaced with new ash handling technology in 2018 and 2019. Existing landfill cells can continue to operate as designed, but future expansions may require composite liner and leachate collection systems. On December 20, 2016 the Water Infrastructure Improvements for the Nation (WIIN) Act was signed into law. The WIIN Act allows states to regulate CCR if the state standards are at least as protective as the EPA CCR Rule. North Dakota and South Dakota have indicated they plan to incorporate the CCR rule, but that it will take a multi-year process.

 

At the request of the MPCA, OTP had an ongoing investigation at its former, closed Hoot Lake Plant ash disposal sites. The MPCA continues to monitor site activities under its Voluntary Investigation and Cleanup Program. OTP completed projects in 2014 through 2017 that removed the ash in its entirety from all four Voluntary Investigation and Cleanup Program areas and placed it in OTP’s permitted disposal area.

 

In 1980 the United States enacted the Comprehensive Environmental Response, Compensation and Liability Act, commonly known as CERCLA or the Federal Superfund law, which was reauthorized and amended in 1986. In 1983 Minnesota adopted the Minnesota Environmental Response and Liability Act, commonly known as the Minnesota Superfund law. In 1988 South Dakota enacted the Regulated Substance Discharges Act, commonly known as the South Dakota Superfund law. In 1989, North Dakota enacted the Environmental Emergency Cost Recovery Act. Among other requirements, the federal and state acts establish environmental response funds to pay for remedial actions associated with the release or threatened release of certain regulated substances into the environment. These federal and state Superfund laws also establish liability for cleanup costs and damage to the environment resulting from such release or threatened release of regulated substances. The Minnesota Superfund law also creates liability for personal injury and economic loss under certain circumstances. OTP has not incurred any significant costs to date related to these laws. OTP is not presently named as a potentially responsible party under the federal or state Superfund laws.

 

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Capital Expenditures

 

OTP is continually expanding, replacing and improving its electric facilities. During 2017 approximately $119 million in cash was invested for additions and replacements to its electric utility properties. During the five years ended December 31, 2017 gross electric property additions, including construction work in progress, were approximately $699 million and gross retirements were approximately $84 million. OTP estimates that during the five-year period 2018-2022 it will invest approximately $901 million for electric construction, including:

 

 

$302 million for renewable wind and solar energy generation projects.

 

 

$161 million for natural gas-fired generation to replace Hoot Lake Plant capacity.

 

 

$136 million for numerous potential technology and infrastructure projects to transform future operations, including automated metering, telecommunications, geographic information systems, work and asset management systems, financial information systems, system infrastructure reliability improvements, outage management systems, and storage projects.

 

 

$35 million for OTP’s Big Stone South–Ellendale 345 kV transmission line project.

 

The remainder of the 2018-2022 anticipated capital expenditures is for asset replacements, additions and improvements across OTP’s generation, transmission, distribution and general plant. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Requirements” section for further discussion.

 

Franchises

 

At December 31, 2017 OTP had franchises to operate as an electric utility in substantially all of the incorporated municipalities it serves. All franchises are nonexclusive and generally were obtained for 20-year terms, with varying expiration dates. No franchises are required to serve unincorporated communities in any of the three states that OTP serves. OTP believes that its franchises will be renewed prior to expiration.

 

Employees

 

At December 31, 2017 OTP had 668 equivalent full-time employees. A total of 390 OTP employees are represented by local unions of the International Brotherhood of Electrical Workers under two separate contracts expiring on August 31, 2020 and October 31, 2020. OTP has not experienced any strike, work stoppage or strike vote, and considers its present relations with employees to be good.

 

MANUFACTURING

 

General

 

Manufacturing consists of businesses engaged in the following 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.

 

The Company derived 27%, 28% and 28% of its consolidated operating revenues and 11%, 11% and 9% of its consolidated operating income from the Manufacturing segment for the years ended December 31, 2017, 2016 and 2015, respectively. Following is a brief description of each of these businesses:

 

BTD Manufacturing, Inc. (BTD), with headquarters located in Detroit Lakes, Minnesota, is a metal stamping and tool and die manufacturer that provides its services mainly to customers in the Midwest. BTD stamps, fabricates, welds, paints and laser cuts metal components according to manufacturers’ specifications primarily for the recreational vehicle, agricultural, oil and gas, lawn and garden, industrial equipment, health and fitness and enclosure industries in its facilities in Detroit Lakes and Lakeville, Minnesota, Washington, Illinois and Dawsonville, Georgia. BTD’s Illinois facility also manufactures and fabricates parts for off-road equipment, mining machinery, oil fields and offshore oil rigs, wind industry components, broadcast antennae and farm equipment. BTD-Georgia offers a wide range of metal fabrication services ranging from simple laser cutting services and high volume stamping to complex weldments and assemblies for metal fabrication buyers and original equipment manufacturers.

 

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T.O. Plastics, Inc. (T.O. Plastics), located in Otsego and Clearwater, Minnesota, manufactures and sells thermoformed products for the horticulture industry throughout the United States. T.O. Plastics also designs and manufactures quality thermoformed products and packaging solutions for the medical and life sciences, industrial, recreation and electronics industries. Examples of products produced for these industries are clamshell packing, blister packs, returnable pallets and handling trays for shipping and storing odd-shaped or difficult-to-handle parts.

 

Product Distribution

 

The principal method for distribution of the manufacturing companies’ products is by direct shipment to the customer by common carrier ground transportation. No single customer or product of the Company’s manufacturing companies accounted for 10% of the Company’s consolidated revenue. However, two customers combined accounted for 36% of the 2017 revenue of the Manufacturing segment.

 

Competition

 

The various markets in which the Manufacturing segment entities compete are characterized by intense competition from both foreign and domestic manufacturers. These markets have many established manufacturers with broader product lines, greater distribution capabilities, greater capital resources, excess capacity, labor advantages and larger marketing, research and development staffs and facilities than the Company’s manufacturing entities.

 

The Company believes the principal competitive factors in its Manufacturing segment are product performance, quality, price, technical innovation, cost effectiveness, customer service and breadth of product line. The Company’s manufacturing entities intend to continue to compete on the basis of high-performance products, innovative production technologies, cost-effective manufacturing techniques, close customer relations and support, and increasing product offerings.

 

Raw Materials Supply

 

The companies in the Manufacturing segment use raw materials in the products they manufacture, including steel, aluminum and polystyrene and other plastics resins. Both pricing increases and availability of these raw materials are concerns of companies in the Manufacturing segment. The companies in the Manufacturing segment attempt to pass increases in the costs of these raw materials on to their customers. Increases in the costs of raw materials that cannot be passed on to customers could have a negative effect on profit margins in the Manufacturing segment. Additionally, a certain amount of residual material (scrap) is a by-product of many of the manufacturing and production processes used by the Company’s manufacturing companies. Declines in commodity prices for these scrap materials due to weakened demand or excess supply can negatively impact the profitability of the Company’s manufacturing companies as it reduces their ability to mitigate the cost associated with excess material.

 

Backlog

 

The Manufacturing segment has backlog in place to support 2018 revenues of approximately $166 million compared with $118 million one year ago.

 

Capital Expenditures

 

Capital expenditures in the Manufacturing segment typically include additional investments in new manufacturing equipment or expenditures to replace worn-out manufacturing equipment. Capital expenditures may also be made for the purchase of land and buildings for plant expansion and for investments in management information systems. During 2017, cash expenditures for capital additions in the Manufacturing segment were approximately $10 million. Total capital expenditures for the Manufacturing segment during the five-year period 2018-2022 are estimated to be approximately $53 million.

 

Employees

 

At December 31, 2017 the Manufacturing segment had 1,229 full-time employees. There were 1,092 full-time employees at BTD and 137 full-time employees at T.O. Plastics as of December 31, 2017.

 

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PLASTICS

 

General

 

Plastics consists of businesses producing PVC pipe at plants in North Dakota and Arizona. The Company derived 22%, 19% and 20% of its consolidated operating revenues and 24%, 16% and 19% of its consolidated operating income from the Plastics segment for the years ended December 31, 2017, 2016 and 2015, respectively. Following is a brief description of these businesses:

 

Northern Pipe Products, Inc. (Northern Pipe), located in Fargo, North Dakota, manufactures and sells PVC pipe for municipal water, rural water, wastewater, storm drainage systems and other uses in the northern, midwestern, south-central and western regions of the United States as well as central and western Canada.

 

Vinyltech Corporation (Vinyltech), located in Phoenix, Arizona, manufactures and sells PVC pipe for municipal water, wastewater, water reclamation systems and other uses in the western, northwestern and south-central regions of the United States.

 

Together these companies have the current capacity to produce approximately 300 million pounds of PVC pipe annually.

 

Customers

 

PVC pipe products are marketed through a combination of independent sales representatives, company salespersons and customer service representatives. Customers for the PVC pipe products consist primarily of wholesalers and distributors throughout the northern, midwestern, south-central, western and northwest United States. The principal method for distribution of the PVC pipe companies’ products is by common carrier ground transportation. No single customer of the PVC pipe companies accounts for over 10% of the Company’s consolidated revenue. However, two customers combined accounted for 38% of the 2017 revenue of the Plastics segment.

 

Competition

 

The plastic pipe industry is fragmented and competitive due to the number of producers, the small number of raw material suppliers and the fungible nature of the product. Due to shipping costs, competition is usually regional, instead of national, in scope. The principal factors of competition are price, service, warranty, and product performance. Northern Pipe and Vinyltech compete not only against other plastic pipe manufacturers, but also ductile iron, steel and concrete pipe producers. Pricing pressure will continue to affect our Plastics segment operating margins in the future.

 

Northern Pipe and Vinyltech intend to continue to compete on the basis of their high quality products, cost-effective production techniques and close customer relations and support.

 

Manufacturing and Resin Supply

 

PVC pipe is manufactured through a process known as extrusion. During the production process, PVC compound (a dry powder-like substance) is introduced into an extrusion machine, where it is heated to a molten state and then forced through a sizing apparatus to produce the pipe. The newly extruded pipe is then pulled through a series of water cooling tanks, marked to identify the type of pipe and cut to finished lengths. Warehouse and outdoor storage facilities are used to store the finished product. Inventory is shipped from storage to distributors and customers by common carrier.

 

The PVC resins are acquired in bulk and shipped to point of use by rail car. There are four vendors that Northern Pipe and Vinyltech can source to supply their PVC resin requirements. Two vendors provided 100% of total resin purchases in 2017 and 2016. The supply of PVC resin may also be limited primarily due to manufacturing capacity and the limited availability of raw material components. A majority of U.S. resin production plants are located in the Gulf Coast region, which is subject to risk of damage to the plants and potential shutdown of resin production because of exposure to hurricanes that occur in that part of the United States. The loss of a key vendor, or any interruption or delay in the supply of PVC resin, could disrupt the ability of the Plastics segment to manufacture products, cause customers to cancel orders or require incurrence of additional expenses to obtain PVC resin from alternative sources, if such sources were available. Both Northern Pipe and Vinyltech believe they have good relationships with their key raw material vendors.

 

Due to the commodity nature of PVC resin and PVC pipe and the dynamic supply and demand factors worldwide, historically the markets for both PVC resin and PVC pipe have been very cyclical with significant fluctuations in prices and gross margins.

 

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Capital Expenditures

 

Capital expenditures in the Plastics segment typically include investments in extrusion machines and support equipment. During 2017, cash expenditures for capital additions in the Plastics segment were approximately $4 million. Total capital expenditures for the five-year period 2018-2022 are estimated to be approximately $19 million to replace existing equipment.

 

Employees

 

At December 31, 2017 the Plastics segment had 161 full-time employees. Northern Pipe had 95 full-time employees and Vinyltech had 66 full-time employees as of December 31, 2017.

 

 

Item 1A. RISK FACTORS

 

RISK FACTORS AND CAUTIONARY STATEMENTS

 

Our businesses are subject to various risks and uncertainties. Any of the risks described below or elsewhere in this Annual Report on Form 10-K or in our other SEC filings could materially adversely affect our business, financial condition and results of operations.

 

GENERAL

 

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

 

We are subject to federal, state and local environmental laws and regulations relating to air quality, water quality, waste management, natural resources and health safety. These laws and regulations regulate the modification and operation of existing facilities, the construction and operation of new facilities and the proper storage, handling, cleanup and disposal of hazardous waste and toxic substances. Compliance with these legal requirements requires us to commit significant resources and funds toward environmental monitoring, installation and operation of pollution control equipment, payment of emission fees and securing environmental permits. Obtaining environmental permits can entail significant expense and cause substantial construction delays. Failure to comply with environmental laws and regulations, even if caused by factors beyond our control, may result in civil or criminal liabilities, penalties and fines.

 

Existing environmental laws or regulations may be revised and new laws or regulations may be adopted or become applicable to us. Revised or additional regulations, which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material effect on our results of operations.

 

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

 

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. Market disruptions or a downgrade of our credit ratings may increase the cost of borrowing or adversely affect our ability to access one or more financial markets.

 

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.

 

Changes in the U.S. capital markets could also have significant effects on our pension plan. Our pension income or expense is affected by factors including the market performance of the assets in the master pension trust maintained for the pension plan for some of our employees, the weighted average asset allocation and long-term rate of return of our pension plan assets, the discount rate used to determine the service and interest cost components of our net periodic pension cost and assumed rates of increase in our employees’ future compensation. If our pension plan assets do not achieve positive rates of return, or if our estimates and assumed rates are not accurate, our earnings may decrease because net periodic pension costs would rise and we could be required to provide additional funds to cover our obligations to employees under the pension plan.

 

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.

 

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

 

We had approximately $37.6 million of goodwill recorded on our consolidated balance sheet as of December 31, 2017. We have recorded goodwill for businesses in our Manufacturing and Plastics business segments. If we make changes in our business strategy or if market or other conditions adversely affect operations in any of these businesses, we may be forced to record an impairment charge, which would lead to decreased assets and a reduction in net operating performance. Goodwill is tested for impairment annually or whenever events or changes in circumstances indicate impairment may have occurred. If the testing performed indicates that impairment has occurred, we are required to record an impairment charge for the difference between the carrying amount of the goodwill and the implied fair value of the goodwill in the period the determination is made. The testing of goodwill for impairment requires us to make significant estimates about our future performance and cash flows, as well as other assumptions. These estimates can be affected by numerous factors, including changes in economic, industry or market conditions, changes in business operations, future business operating performance, changes in competition or changes in technologies. Any changes in key assumptions or actual performance compared with key assumptions about our business and its future prospects or other assumptions could affect the fair value of one or more business segments, which may result in an impairment charge. 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 the Company.

 

Otter Tail Corporation is a holding company with no significant operations of its own. The primary source of funds for payment of our financial obligations and dividends to our shareholders is from cash provided by our subsidiary companies. Our ability to meet our financial obligations and pay dividends on our common stock principally depends on the actual and projected earnings, cash flows, capital requirements and general financial position of our subsidiary companies, as well as regulatory factors, financial covenants, general business conditions and other matters.

 

Under our $130 million revolving credit agreement we may not permit the ratio of our Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00. OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 under its $170 million revolving credit agreement. Both credit agreements contain restrictions on the payment of cash dividends on a default or event of default. As of December 31, 2017 we were in compliance with the debt 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 us by requiring an equity-to-total-capitalization ratio between 47.4% and 58.0% based on OTP’s 2017 capital structure petition. OTP’s equity-to-total-capitalization ratio, including short-term debt, was 48.6% as of December 31, 2017.

 

While these restrictions are not expected to affect our ability to pay dividends at the current level in the foreseeable future, there is no assurance that adverse financial results would not reduce or eliminate our ability to pay dividends.

 

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

 

All of our businesses require us to collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss. We also use third-party vendors to electronically process certain of our business transactions. The efficient operation of our business is dependent on computer hardware and software systems. Information systems, both ours and those of third-parties, are vulnerable to security breach by computer hackers and cyber terrorists.

 

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The breach of certain business systems could affect our ability to correctly record, process and report financial information and transactions. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to our reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. We have cybersecurity insurance related to a breach event covering expenses for notification, credit monitoring, investigation, crisis management, public relations and legal advice. The policy also provides coverage for regulatory action defense including fines and penalties, potential payment card industry fines and penalties and costs related to cyber extortion. We also maintain property and casualty insurance that may cover restoration of data, certain physical damage or third-party injuries caused by potential cybersecurity incidents. However, damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available.

 

We rely on industry accepted security measures and technology to securely maintain confidential and proprietary information maintained on our information systems. In an effort to reduce the likelihood and severity of cyber intrusions, we have cybersecurity processes and controls designed to protect and preserve the confidentiality, integrity and availability of data and systems. However, all these measures and technology may not adequately prevent security breaches or cyber-attacks. In addition, the unavailability of the information systems or failure of these systems to perform as anticipated for any reason could disrupt our business and could result in decreased performance and increased overhead costs, causing our business and results of operations to suffer. Any significant interruption or failure of our information systems or any significant breach of security due to cyber-attacks, hacking or internal security breaches could adversely affect our business and results of operations.

 

Economic conditions could negatively impact our businesses.

 

Our businesses are affected by local, national and worldwide economic conditions. Tightening of credit in financial markets could adversely affect the ability of customers to finance purchases of our goods and services, resulting in decreased orders, cancelled or deferred orders, slower payment cycles, and increased bad debt and customer bankruptcies. Our businesses may also be adversely affected by decreases in the general level of economic activity, such as decreases in business and consumer spending. A decline in the level of economic activity and uncertainty regarding energy and commodity prices could adversely affect our results of operations and our future growth.

 

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

 

We expect much of our growth in the next few years will come from major capital investment at existing companies. To achieve the organic growth we expect, we must have access to the capital markets, be successful with capital expansion programs related to organic growth, develop new products and services, expand our markets and increase efficiencies in our businesses. Competitive and economic factors could adversely affect our ability to do this. If we are unable to achieve and sustain consistent organic growth, we will be less likely to meet our revenue growth targets, which, together with any resulting impact on our net income growth, may adversely affect the market price of our common shares.

 

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.

 

As part of our business strategy, we intend to increase capital expenditures in our existing businesses and to continually assess our mix of businesses and potential strategic acquisitions or dispositions. There are risks associated with capital expenditures including not being granted timely or full recovery of rate base additions in our regulated utility business, the inability to recover the cost of capital additions due to an economic downturn, not being granted timely approval of requested interconnections to the transmission system for planned generation projects, lack of markets for new products, competition from producers of lower cost or alternative products, product defects, loss of customers or other factors. We may not be able to identify appropriate acquisition candidates or successfully negotiate, finance or integrate acquisitions. Future acquisitions could involve numerous risks including: difficulties in integrating the operations, services, products and personnel of the acquired business; and the potential loss of key employees, customers and suppliers of the acquired business. If we are unable to successfully manage these risks, we could face reductions in net income in future periods.

 

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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 also exposes us to additional risks associated with indemnification obligations under the applicable sales agreements and any related disputes.

 

As part of our business strategy, we continually assess our business portfolio to determine if our operating companies continue to meet our portfolio criteria. A loss on the sale of a business would be recognized if a company is sold for less than its book value.

 

In certain transactions we retain obligations that have arisen, or subsequently arise, out of our conduct of the business prior to the sale. These obligations are sometimes direct or, in other cases, take the form of an indemnification obligation to the buyer. These obligations include such things as warranty, environmental, and the collection of certain receivables. Unforeseen costs related to these obligations could result in future losses related to the business sold.

 

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.

 

Depending on the specific product or service, we may provide certain warranty terms against manufacturing defects and certain materials. We reserve for warranty claims based on industry experience and estimates made by management. For some of our products we have limited history on which to base our warranty estimate. Our assumptions could be materially different from any actual claim and could exceed reserve balances.

 

Expenses associated with the remediation of warranty claims for our manufacturing businesses, including our former wind tower manufacturer, could be substantial. The potential exists for multiple claims based on one defect repeated throughout the production process or for claims where the cost to repair or replace the defective part is highly disproportionate to the original cost of the part. If we are required to cover remediation expenses in addition to our regular warranty coverage, we could be required to accrue additional expenses and experience additional unplanned cash expenditures which could adversely affect our consolidated net income and financial condition.

 

We are subject to risks associated with energy markets.

 

Our businesses are subject to the risks associated with energy markets, including market supply and increasing energy prices. If we are faced with shortages in market supply, we may be unable to fulfill our contractual obligations to our retail, wholesale and other customers at previously anticipated costs. This could force us to obtain alternative energy or fuel supplies at higher costs or suffer increased liability for unfulfilled contractual obligations. Any significantly higher than expected energy or fuel costs would negatively affect our financial performance.

 

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.

 

Our provision for income taxes and reporting of tax-related assets and liabilities require significant judgments and the use of estimates. Amounts of tax-related assets and liabilities involve judgments and estimates of the timing and probability of recognition of income, deductions and tax credits, including, but not limited to, estimates for potential adverse outcomes regarding tax positions that have been taken and the ability to utilize tax benefit carryforwards, such as net operating loss and tax credit carryforwards. Actual income taxes could vary significantly from estimated amounts due to the future impacts of, among other things, changes in tax laws, regulations and interpretations, the financial condition and results of operations of Otter Tail Corporation, and the resolution of audit issues raised by taxing authorities. Ultimate resolution of income tax matters may result in material adjustments to tax-related assets and liabilities, which could materially adversely affect our business, financial condition, results of operations and prospects.

 

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

 

While no single customer of the Company provides more than 10% of consolidated revenue, each of the Company’s segments have large customers that provide over 10% of the operating company’s and its segment’s revenue. In 2017 one customer accounted for 12% of Electric segment revenue, two customers accounted for a total of 36% of Manufacturing segment revenue and two customers accounted for 38% of Plastics segment revenue. The loss of any one of these customers, or a significant decline in sales to these customers, would have a significant negative impact on the operating company’s and its business segment’s financial position and results of operations, and could have a significant negative impact on the Company’s consolidated financial position and results of operations.

 

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ELECTRIC

 

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

 

A number of factors, many of which are beyond our control, may contribute to fluctuations in our revenues and expenses from electric operations, causing our net income to fluctuate from period to period. These risks include fluctuations in the volume and price of sales of electricity to customers or other utilities, which may be affected by factors such as mergers and acquisitions of other utilities, geographic location of other utilities, transmission costs (including increased costs related to operations of regional transmission organizations), interconnection costs, changes in the manner in which wholesale power is sold and purchased, unplanned interruptions at OTP’s generating plants, the effects of regulation and legislation, demographic changes in OTP’s customer base and changes in OTP’s customer demand or load growth. Electric wholesale margins have been significantly and adversely affected by increased efficiencies in the MISO market. Other risks include weather conditions or changes in weather patterns (including severe weather that could result in damage to OTP’s assets), fuel and purchased power costs and the rate of economic growth or decline in OTP’s service areas. A decrease in revenues or an increase in expenses related to our electric operations may reduce the amount of funds available for our existing and future businesses, which could result in increased financing requirements, impair our ability to make expected distributions to shareholders or impair our ability to make 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.

 

We are subject to federal and state legislation, government regulations and regulatory actions that may have a negative impact on our business and results of operations. The electric rates that OTP is allowed to charge for its electric services are one of the most important items influencing our financial position, results of operations and liquidity. The rates that OTP charges its electric customers are subject to review and determination by state public utility commissions in Minnesota, North Dakota and South Dakota. OTP is also regulated by the FERC. Our ability to obtain rate adjustments to maintain reasonable rates of return depends on regulatory action under applicable statutes and regulations and we cannot provide assurance that rate adjustments will be obtained or reasonable authorized rates of return on capital will be earned. OTP will file rate cases with, or seek cost recovery authorization from, federal and state regulatory authorities. On November 2, 2017 OTP filed a rate request with the NDPSC, which is pending. OTP is also an intervenor in a matter pending before the D.C. Circuit regarding FERC orders relating to the refund of RSG charges. An adverse decision by one or more regulatory commissions concerning the level or method of determining electric utility rates, the authorized returns on equity, implementation of enforceable federal reliability standards or other regulatory matters, permitted business activities (such as ownership or operation of nonelectric businesses) or any prolonged delay in rendering a decision in a rate or other proceeding (including with respect to the recovery of capital expenditures in rates) could result in lower revenues and net income.

 

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.

 

We are subject to an extensive legal and regulatory framework imposed under federal and state law and regulatory agencies, including FERC and NERC. We could be subject to potential financial penalties for compliance violations. In addition, energy policy initiatives at the state or federal level could increase incentives for distributed generation or municipal utility ownership, or local initiatives could introduce generation or distribution requirements, that could change the current integrated utility model. Our transmission systems and electric generation facilities are subject to the NERC mandatory reliability standards, including cybersecurity standards. If a serious reliability incident did occur, it could have a material effect on our operations or financial results. Some states have the authority to impose substantial penalties in the event of non-compliance. We attempt to mitigate the risk of regulatory penalties through formal training. However, there is no guarantee our compliance program will be sufficient to ensure against violations.

 

These laws and regulations significantly influence our operations and may affect our ability to recover costs from our customers. We are required to have numerous permits, licenses, approvals and certificates from the agencies and other organizations that regulate our business. We believe we have obtained the necessary approvals for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies and other organizations. Changes in regulations or the imposition of additional regulations could have a material adverse impact on our results of operations.

 

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

 

OTP owns electric transmission and generation facilities subject to mandatory and enforceable standards advanced by the NERC. These bulk electric system facilities provide the framework for the electrical infrastructure of OTP’s service territory and interconnected systems, the operation of which is dependent on information technology systems. Further, the information systems that operate OTP’s electric system are interconnected to external networks. Parties that wish to disrupt the U.S. bulk power system or OTP’s operations could view OTP’s computer systems, software or networks as attractive targets for cyber-attack.

 

In addition, OTP’s generation and transmission facilities are spread throughout a large service territory. These facilities could be subject to physical attack or vandalism that could disrupt OTP’s operations or conceivably the regional or U.S. bulk power system.

 

OTP is subject to mandatory cybersecurity and physical security regulatory requirements. OTP implements the NERC standards for operating its transmission and generation assets and stays abreast of best practices within business and the utility industry to protect its computers and computer controlled systems from outside attack. We rely on industry accepted security measures and technology to securely maintain confidential and proprietary information necessary for the operation of our systems. In an effort to reduce the likelihood and severity of cyber intrusions, we have cybersecurity processes and controls designed to protect and preserve the confidentiality, integrity and availability of data and systems. We also take prudent and reasonable steps to protect the physical security of our generation and transmission facilities. However, all these measures and technology may not adequately prevent security breaches or cyber-attacks. Any significant interruption or failure of our information systems or any significant breach of security due to cyber-attacks, hacking or internal security breaches or physical attack of our generation or transmission facilities could adversely affect our business and results of operations.

 

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.

 

Operation of electric generating facilities involves risks which can adversely affect energy output and efficiency levels. Most of OTP’s generating capacity is coal-fired. OTP relies on a limited number of suppliers of coal, making it vulnerable to increased prices for fuel as existing contracts expire or in the event of unanticipated interruptions in fuel supply. OTP is a captive rail shipper of the BNSF Railway for shipments of coal to its Big Stone and Hoot Lake plants, making it vulnerable to increased prices for coal transportation from a sole supplier and disruptions in coal deliveries due to rail line congestion and constraints on the rail lines between the coal source mines and the plants. Higher fuel prices result in higher electric rates for OTP’s retail customers through fuel clause adjustments and could make it less competitive in wholesale electric markets. Operational risks also include facility shutdowns due to breakdown or failure of equipment or processes, labor disputes, operator error and catastrophic events such as fires, explosions, floods, intentional acts of destruction or other similar occurrences affecting OTP’s electric generating facilities. The loss of a major generating facility would require OTP to find other sources of supply, if available, and expose it to higher purchased power costs.

 

Changes to regulation of generating plant emissions, including but not limited to CO2 emissions, could affect our operating costs and the costs of supplying electricity to our customers.

 

Existing or new laws or regulations passed or issued by federal or state authorities addressing climate change or reductions of GHG emissions, such as mandated levels of renewable generation, mandatory reductions in CO2 emission levels, taxes on CO2 emissions or cap and trade regimes, could require us to incur significant new costs, which could negatively impact our net income, financial position and operating cash flows if such costs cannot be recovered through rates granted by ratemaking authorities in the states where OTP provides service or through increased market prices for electricity. Debate continues in Congress and in the new administration on the direction and scope of U.S. and international policy on climate change and regulation of GHGs. Congress has considered but has not adopted GHG legislation which would require a reduction in GHG emissions and there is no legislation under active consideration at this time. The likelihood of any federal mandatory CO2 emissions reduction program being adopted by Congress in the near future, and the specific requirements of any such program, are uncertain, as are the future of additional regulatory actions.

 

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Under the previous presidential administration, the EPA published final rules for the CPP, including NSPS regulations governing GHGs from new and existing fossil fuel-fired electric generating units and GHG performance and emissions standards for existing fossil fuel-fired power plants. The U.S. Supreme Court granted a stay of the CPP. After the new administration issued an executive order directing the EPA to consider suspending, revising, or rescinding the NSPS rule and the CPP, the D.C. Circuit issued orders holding the appellate challenges to both rules in abeyance. In October 2017, the EPA published a proposed rule to repeal the CPP and intends to solicit additional information regarding climate change and GHG emissions. The fate of the former administration’s GHG rules is uncertain, as is the outcome of EPA’s potential GHG regulatory actions under the new administration. The final outcome of this rulemaking process could have a material adverse impact on our business and financial results.

 

MANUFACTURING

 

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 manufacturing businesses are subject to intense risks associated with competition from foreign and domestic manufacturers, many of whom have broader product lines, greater distribution capabilities, greater capital resources, larger marketing, research and development staffs and facilities and other capabilities that may place downward pressure on margins and profitability. The companies in our Manufacturing segment use a variety of raw materials in the products they manufacture, including steel, aluminum and polystyrene and other plastics resins. Costs for these items can fluctuate significantly. If our manufacturing businesses are not able to pass on cost increases to their customers, it could have a negative effect on profit margins in our Manufacturing segment. Additionally, a certain amount of residual material (scrap) is a by-product of many of the manufacturing and production processes used by our manufacturing companies. Declines in commodity prices for these scrap materials due to weakened demand or excess supply, can negatively impact the profitability of our manufacturing companies as it reduces their ability to mitigate the cost associated with excess material. Changes in macroeconomic conditions can negatively impact demand in the end-use markets for products and parts that we manufacture, resulting in reduced sales and profits. There is no assurance that the initiatives underway to increase revenues and improve margins at our manufacturing businesses will be successful.

 

PLASTICS

 

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

 

We rely on a limited number of vendors to supply the PVC resin used in our plastics business. Two vendors accounted for 100% of our total purchases of PVC resin in 2017 and 2016. In addition, the supply of PVC resin may be limited primarily due to manufacturing capacity and the limited availability of raw material components. A majority of U.S. resin production plants are located in the Gulf Coast region, which may increase the risk of a shortage of resin in the event of a hurricane or other natural disaster in that region. The loss of a key vendor or any interruption or delay in the availability or supply of PVC resin could disrupt our ability to deliver our plastic products, cause customers to cancel orders or require us to incur additional expenses to obtain PVC resin from alternative sources, if such sources are available.

 

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

 

The plastic pipe industry is fragmented and competitive due to the number of producers and the fungible nature of the product. We compete not only against other plastic pipe manufacturers, but also against ductile iron, steel and concrete pipe manufacturers. Due to shipping costs, competition is usually regional instead of national in scope, and the principal areas of competition are a combination of price, service, warranty, and product performance. Our inability to compete effectively in each of these areas and to distinguish our plastic pipe products from competing products may adversely affect the financial performance of our plastics business.

 

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

 

The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices are rising or stable, margins and sales volume have been higher and when resin prices are falling, sales volumes and margins have been lower. Changes in PVC resin prices can negatively affect PVC pipe prices, profit margins on PVC pipe sales and the value of our finished goods inventory.

 

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Item 1B. UNRESOLVED STAFF COMMENTS

 

None.

 

 

Item 2.     PROPERTIES

 

The Coyote Station, which commenced operation in 1981, is a 414,000 kW (nameplate rating) mine-mouth plant located in the lignite coal fields near Beulah, North Dakota and is jointly owned by OTP, Northern Municipal Power Agency, Montana-Dakota Utilities Co. and Northwestern Public Service Company. OTP is the operating agent of the Coyote Station and owns 35% of the plant.

 

OTP, jointly with Northwestern Public Service Company and Montana-Dakota Utilities Co., owns the 414,000 kW (nameplate rating) Big Stone Plant in northeastern South Dakota which commenced operation in 1975. OTP is the operating agent of Big Stone Plant and owns 53.9% of the plant.

 

Located near Fergus Falls, Minnesota, the Hoot Lake Plant is comprised of two separate generating units: a unit built in 1959 (53,500 kW nameplate rating) and a unit added in 1964 (75,000 kW nameplate rating) and modified in 1988 to provide cycling capability, allowing this unit to be more efficiently brought online from a standby mode. These two generating units have a combined nameplate rating of 128,500 kW. Current plans are for both units to be retired from service in 2021.

 

OTP owns 27 wind turbines at the Langdon, North Dakota Wind Energy Center with a nameplate rating of 40,500 kW, 32 wind turbines at the Ashtabula Wind Energy Center located in Barnes County, North Dakota with a nameplate rating of 48,000 kW and 33 wind turbines at the Luverne Wind Farm located in Steele County, North Dakota with a nameplate rating of 49,500 kW.

 

As of December 31, 2017 OTP’s transmission facilities, which are interconnected with lines of other public utilities, consisted of 606 pole-miles of jointly owned 345 kV lines; 494 pole-miles of 230 kV lines, of which 70 miles are jointly owned; 879 pole-miles of 115 kV lines; and 3,973 pole-miles of lower voltage lines, principally 41.6 kV. OTP owns the uprated portion of 48 pole-miles of the 345 kV lines, with Minnkota Power Cooperative retaining title to the original 230 kV construction, and OTP owns an undivided interest in the remaining 345 kV line miles. OTP is a joint owner, with other regional utilities, in transmission lines with the following ownership interests: 14.8% in the 70 mile Bemidji-Grand Rapids 230 kV line, approximately 14.2% of 242 pole-miles of energized line in the Fargo-Monticello 345 kV project, approximately 4.8% of 255 pole-miles of energized line in the Brookings to Southeast Twin Cities 345 kV project, and 50.0% of 72 pole-miles of energized line in the Big Stone South–Brookings 345 kV project.

 

In addition to the properties mentioned above, all of which are utilized by the Electric segment, the Company owns and has investments in offices and service buildings utilized by each of its manufacturing and plastic pipe companies. The Company’s subsidiaries own facilities and equipment used in: the manufacture of PVC pipe, thermoformed products, heavy metal fabricated products, metal parts stamping, fabricating, painting and contract machining.

 

Management of the Company believes the facilities and equipment described above are adequate for the Company's present businesses.

 

 

Item 3.     LEGAL PROCEEDINGS

 

The Company is the subject of various pending or threatened legal actions and proceedings in the ordinary course of its business. Such matters are subject to many uncertainties and to outcomes that are not predictable with assurance. The Company records a liability in its consolidated financial statements for costs related to claims, including future legal costs, settlements and judgments, where the Company has assessed that a loss is probable and an amount can be reasonably estimated. The Company believes 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 its consolidated financial position, results of operations or cash flows.

 

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Item 3A.     EXECUTIVE OFFICERS OF THE REGISTRANT (AS OF FEBRUARY 20, 2018)

 

Set forth below is a summary of the principal occupations and business experience during the past five years of the executive officers as defined by rules of the SEC. Each of the executive officers, excluding John Abbott, has been employed by the Company for more than five years in an executive or management position either with the Company or its wholly owned subsidiary, Otter Tail Power Company.

 

NAME AND AGE

DATE ELECTED

TO OFFICE

PRESENT POSITION AND BUSINESS EXPERIENCE

Charles S. MacFarlane (53)

4/13/15

Present:

President and Chief Executive Officer

Kevin G. Moug (58)

4/9/01

Present:

Chief Financial Officer and Senior Vice President

Timothy J. Rogelstad (51)

4/14/14

Present:

Senior Vice President, Electric Platform

John Abbott (59)

2/11/15

Present:

Senior Vice President, Manufacturing Platform

Jennifer O. Smestad (47)

1/1/18

Present:

Vice President, General Counsel and Corporate Secretary

 

On April 13, 2015 Mr. MacFarlane was elected as the Company’s President and Chief Executive Officer and as member of the Company’s board of directors. On February 5, 2014 the Company’s board of directors appointed Mr. MacFarlane, then President and Chief Executive Officer of OTP and Senior Vice President, Electric Platform of the Company, to the role of President and Chief Operating Officer of the Company, effective April 14, 2014. Mr. MacFarlane joined OTP in 2001 and had served as its President from 2003 to 2014 and its Chief Executive Officer from 2007 to 2014. He served as Senior Vice President, Electric platform of the Company from 2012 to 2014. Prior to joining OTP, Mr. MacFarlane served as Director of Electric Distribution Planning and Engineering for Xcel Energy Inc.’s multi-state service territory. He was also Director of Delivery Construction and Field Operations for Northern States Power Company prior to its merger with New Centuries Energy and becoming Xcel Energy.

 

Kevin G. Moug has held his present positions with the Company for more than five years.

 

On April 14, 2014 Timothy J. Rogelstad was appointed to succeed Mr. MacFarlane as President of OTP and Senior Vice President, Electric Platform of the Company. Mr. Rogelstad joined OTP in June 1989 as an engineer in the System Engineering Department and served as Supervisor, Transmission Planning, and Manager, Delivery Planning, before being named Vice President, Asset Management, in 2012. In the role of Vice President, Asset Management at OTP, he was in charge of OTP’s Delivery Planning, Delivery Maintenance, Delivery Engineering, System Operations, and Project Management Departments. Mr. Rogelstad is a registered professional engineer in the three states where OTP serves, Minnesota, North Dakota, and South Dakota.

 

On February 5, 2015 John Abbott was selected to serve as Senior Vice President, Manufacturing Platform, and President of Varistar. Prior to coming to the Company, Mr. Abbott served as an officer and group vice president for eight years at Standex International Corporation (Standex), a group of restaurant equipment companies. During his last five years at Standex, Mr. Abbott served as Group Vice President, Food Service Equipment Group. In this role, Mr. Abbott was responsible for all strategic and operational aspects of the Food Service Equipment business. Prior to working at Standex, Mr. Abbott was with Pentair for 20 years, rising from product manager to president and global business unit leader of its water filtration division.

 

On December 19, 2017 the Company’s board of directors appointed Jennifer O. Smestad to the position of Vice President, General Counsel and Corporate Secretary of the Company, effective January 1, 2018, to succeed George A. Koeck, Senior Vice President, General Counsel and Corporate Secretary who retired effective December 31, 2017. Ms. Smestad joined the Company on May 14, 2001 as an Associate General Counsel and has served in various legal capacities of increasing responsibility at the Company and at OTP. She most recently served as General Counsel for OTP from March 1, 2013 to the present.

 

The term of office for each of the executive officers is one year and any executive officer elected may be removed by the vote of the board of directors at any time during the term. There are no family relationships between any of the executive officers or directors.

 

 

Item 4.

Mine Safety Disclosures

 

Not Applicable.

 

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PART II

 

Item 5.

MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

The Company’s common stock is traded on the NASDAQ Global Select Market under the NASDAQ symbol “OTTR”. The information required by this Item can be found on Page 37 of this Annual Report on Form 10-K under the heading “Selected Financial Data,” on Page 93 under the heading “Retained Earnings and Dividend Restriction” and on Page 115 under the heading “Supplementary Financial Information.” The Company does not have a publicly announced stock repurchase program. The Company did not repurchase any equity securities during the three months ended December 31, 2017. 

 

PERFORMANCE GRAPH

COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN

 

This graph compares the cumulative total shareholder return on the Company’s common shares for the last five fiscal years with the cumulative return of The NASDAQ Stock Market Index and the Edison Electric Institute (EEI) Index over the same period (assuming the investment of $100 in each vehicle on December 31, 2012, and reinvestment of all dividends).

 

 

 

 

   

2012

   

2013

   

2014

   

2015

   

2016

   

2017

 

OTC

  $ 100.00     $ 122.07     $ 134.51     $ 120.99     $ 192.46     $ 216.23  

EEI

  $ 100.00     $ 113.01     $ 145.68     $ 139.99     $ 164.40     $ 183.66  

NASDAQ

  $ 100.00     $ 133.48     $ 150.12     $ 150.84     $ 170.46     $ 206.91  

 

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Item 6.     SELECTED FINANCIAL DATA

 

(thousands, except number of shareholders and per-share data)

 

2017

   

2016

   

2015

   

2014

   

2013

 

Revenues

                                       

Electric

  $ 434,537     $ 427,383     $ 407,131     $ 407,743     $ 373,540  

Manufacturing

    229,738       221,289       215,011       219,583       204,997  

Plastics

    185,132       154,901       157,758       172,050       164,957  

Intersegment Eliminations

    (57 )     (34 )     (96 )     (114 )     (80 )

Total Operating Revenues

  $ 849,350     $ 803,539     $ 779,804     $ 799,262     $ 743,414  

Net Income from Continuing Operations

  $ 72,119     $ 62,037     $ 58,589     $ 56,883     $ 48,595  

Net Income from Discontinued Operations

    320       284       756       840       2,270  

Net Income

  $ 72,439     $ 62,321     $ 59,345     $ 57,723     $ 50,865  

Operating Cash Flow from Continuing Operations

  $ 173,603     $ 163,541     $ 131,540     $ 125,769     $ 142,408  

Operating Cash Flow - Continuing and Discontinued Operations

    173,577       163,386       117,540       112,474       147,781  

Capital Expenditures - Continuing Operations

    132,913       161,259       160,084       163,582       159,833  

Total Assets

    2,004,278       1,912,385       1,818,683       1,738,116       1,558,190  

Long-Term Debt

    490,380       505,341       443,846       495,906       387,212  

Basic Earnings Per Share - Continuing Operations (1)

    1.83       1.61       1.56       1.56       1.33  

Basic Earnings Per Share - Total (1)

    1.84       1.62       1.58       1.58       1.39  

Diluted Earnings Per Share - Continuing Operations (1)

    1.81       1.60       1.56       1.55       1.33  

Diluted Earnings Per Share - Total (1)

    1.82       1.61       1.58       1.57       1.39  

Return on Average Common Equity (2)

    10.6 %     9.8 %     10.1 %     10.4 %     9.5 %

Dividends Declared Per Common Share

    1.28       1.25       1.23       1.21       1.19  

Dividend Payout Ratio

    70 %     78 %     78 %     77 %     86 %

Common Shares Outstanding - Year End

    39,557       39,348       37,857       37,218       36,272  

Number of Common Shareholders (3)

    13,053       13,805       14,062       14,134       14,252  

(1) Based on average number of shares outstanding.

(2) Earnings available for common shares divided by the 13-month average of month-end common equity balances.

(3) Holders of record at year end.

 

Item 7.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Overview

 

Otter Tail Corporation and its subsidiaries form a diverse group of businesses with operations classified into three segments: Electric, Manufacturing and Plastics. Our primary financial goals are to maximize earnings and cash flows and to allocate capital profitably toward growth opportunities that will increase shareholder value. Meeting these objectives enables us to preserve and enhance our financial capability by maintaining desired capitalization ratios and a strong interest coverage position and preserving investment grade credit ratings on outstanding securities, which, in the form of lower interest rates, benefits both our customers and shareholders.

 

Our strategy is to continue to grow our largest business, the regulated electric utility, which will lower our overall risk, create a more predictable earnings stream, improve our credit quality and preserve our ability to fund the dividend. Over time, we expect the electric utility business will provide approximately 75% to 85% of our overall earnings. We expect our manufacturing and plastic pipe businesses will provide 15% to 25% of our earnings, and will continue to be a fundamental part of our strategy. The actual mix of earnings from continuing operations in 2017, 2016 and 2015 was 69%, 80% and 83%, respectively, from our electric utility business and 31%, 20% and 17%, respectively, from our manufacturing and plastic pipe businesses, including unallocated corporate costs.

 

Reliable utility performance along with rate base investment opportunities over the next five years will provide us with a strong base of revenues, earnings and cash flows. We also look to our manufacturing and plastic pipe companies to provide organic growth as well. Organic, internal growth comes from new products and services, market expansion and increased efficiencies. We expect much of our growth in these businesses in the next few years will come from utilizing expanded plant capacity from capital investments made in previous years. We will also evaluate opportunities to allocate capital to potential acquisitions in our Manufacturing and Plastics segments. We are a committed long-term owner and therefore we do not acquire companies in pursuit of short-term gains. However, we will divest operating companies that no longer fit into our strategy and risk profile over the long term. In the period 2011 through 2015 we sold several businesses in execution of our announced strategy to realign our portfolio of businesses and refocus our capital investment in the electric utility.

 

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Major growth strategies and initiatives in our future include:

 

 

Planned capital budget expenditures of up to $973 million for the years 2018 through 2022, of which $901 million are for capital projects at Otter Tail Power Company (OTP), including:

 

 

o

$302 million for renewable wind and solar energy generation projects including the Merricourt Wind Project. In November 2016 OTP signed agreements to purchase this 150-megawatt (MW) wind farm in southeastern North Dakota that EDF Renewable Energy will design and build in 2019, subject to certain conditions.

 

 

o

$161 million for natural gas-fired generation to replace Hoot Lake Plant capacity.

 

 

o

$136 million for transformative technology and infrastructure projects including automated metering, telecommunications, geographic information systems, work and asset management systems, financial information systems, system infrastructure reliability improvements, outage management systems, and storage projects.

 

 

o

$35 million for a transmission project designated by the Midcontinent Independent System Operator, Inc. (MISO) as a Multi-Value Project (MVP).

 

 

Continued investigation and evaluation of organic growth opportunities and evaluation of opportunities to allocate capital to potential acquisitions in our Manufacturing and Plastics segments.

 

In 2017:

 

 

Our Plastics segment net income increased 104.1% to $21.7 million from $10.6 million in 2016.

 

 

Our Manufacturing segment net income increased 94.1% to $11.1 million from $5.7 million in 2016.

 

 

Our Electric segment net income decreased 0.8% to $49.4 million from $49.8 million in 2016.

 

 

Our net cash from continuing operations was $173.6 million.

 

 

Capital expenditures at OTP totaled $118.4 million as work was completed on one major MISO-designated MVP and work continued on another MISO-designated MVP.

 

 

We raised net proceeds of $4.3 million from the issuance of 112,548 shares of common stock through our stock plans.

 

 

We increased short-term borrowing by $69.5 million, retiring long-term debt and funding a portion of OTP’s 2017 capital expenditures. We paid $48.2 million to repay long-term debt, including the retirement of $33.0 million of OTP’s 5.95% notes due in August 2017 and the early repayment of $15.0 million of our LIBOR plus 0.90% term loan due February 5, 2018.

 

 

We paid out $50.6 million in common dividends in 2017.

 

The following table summarizes our consolidated results of operations for the years ended December 31:

 

(in thousands)

 

2017

   

2016

 

Operating Revenues:

               

Electric

  $ 434,506     $ 427,349  

Manufacturing

    229,712       221,289  

Plastics

    185,132       154,901  

Total Operating Revenues

  $ 849,350     $ 803,539  

Net Income (Loss) From Continuing Operations:

               

Electric

  $ 49,446     $ 49,829  

Manufacturing

    11,050       5,694  

Plastics

    21,696       10,628  

Corporate

    (10,073 )     (4,114 )

Total Net Income From Continuing Operations

  $ 72,119     $ 62,037  

 

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Revenues in each of our business segments increased in 2017 compared with 2016. Major factors contributing to the $30.2 million (19.5%) increase in Plastics segment revenues were a 7.2% increase in pounds of polyvinyl chloride (PVC) pipe sold and 11.5% increase in PVC pipe prices. Buying spurred by concerns of product shortages and production delays related to 2017 hurricanes in the Gulf of Mexico resulted in an estimated $3.4 million increase in segment net income in 2017. Manufacturing segment revenues increased $8.4 million (3.8%). Revenues at BTD Manufacturing, Inc. (BTD) showed a net increase of $5.9 million, with revenue increases at BTD’s Minnesota and Georgia facilities increasing by 4.0% and 8.2%, respectively, as a result of increased product sales to manufacturers of recreational and lawn and garden equipment. Revenues at T.O. Plastics, Inc. (T.O. Plastics) increased $2.5 million as a result of significant increases in sales of life science and horticultural products. Electric segment revenues increased $7.2 million (1.7%) mainly as a result of increased transmission services revenue driven by increased investment in regional transmission lines with returns earned while the lines are under construction and increased revenues earned from the use of energized lines by other electric service providers.

 

The $10.1 million increase in net income from continuing operations in 2017 compared with 2016 reflects the following:

 

An $11.1 million increase in Plastics segment net income due to hurricane related sales, the positive effect of the 2017 Tax Cuts and Jobs Act (TCJA) tax rate reduction on the segment’s deferred tax liabilities and increases in normal business sales.

 

A $5.4 million increase in Manufacturing segment net income, mainly due to increased sales to manufacturers of recreational and lawn and garden equipment and life science and horticultural products. BTD also benefited from the effect of the TCJA tax rate reduction on its deferred tax liabilities.

 

offset by:

 

A $0.4 million decrease in Electric segment net income due to increases in fuel and purchased power costs and higher property tax expenses, and a negative effect of the TCJA tax rate reduction on Electric segment deferred tax assets related to a portion of accrued postretirement benefit costs which are not recoverable in regulated rates.

 

A $6.0 million net-of-tax increase in Corporate net losses mainly as a result of the negative effect of the TCJA tax rate reduction on deferred tax assets at the holding company.

 

As a result of the tax rate reduction included in the TCJA, deferred tax assets and liabilities were reduced in value. Following is the impact by segment on income tax expense:

 

(in thousands)

 

Decrease/(Increase)

 

Electric

  $ (458 )

Manufacturing

    2,637  

Plastics

    3,263  

Corporate

    (7,198 )

Total

  $ (1,756 )

 

These are provisional amounts based on reasonable estimates reflecting the anticipated impact of the TCJA.

 

Following is a more detailed analysis of our operating results by business segment for the years ended December 31, 2017, 2016 and 2015, followed by a discussion of our financial position at the end of 2017 and our outlook for 2018.

 

Results of Operations

 

This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes. See note 2 to consolidated financial statements for a complete description of our lines of business, locations of operations and principal products and services.

 

Intersegment EliminationsAmounts presented in the following segment tables for 2017, 2016 and 2015 operating revenues, cost of goods sold and other nonelectric operating expenses 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)

 

2017

   

2016

   

2015

 

Operating Revenues:

                       

Electric

  $ 31     $ 34     $ 92  

Product Sales

    26       --       4  

Cost of Products Sold

    18       6       9  

Other Nonelectric Expenses

    39       28       87  

 

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Electric

 

The following table summarizes the results of operations for our Electric segment for the years ended December 31:

 

 

(in thousands)

 

2017

   

%

change

   

2016

   

%

change

   

2015 

 

Retail Sales Revenues

  $ 374,931       --     $ 376,610       3     $ 364,614  

Wholesale Revenues – Company Generation

    5,173       13       4,584       83       2,499  

Net Revenue – Energy Trading Activity

    --       --       --       (100 )     186  

Other Revenues

    54,433       18       46,189       16       39,832  

Total Operating Revenues

  $ 434,537       2     $ 427,383       5     $ 407,131  

Production Fuel

    59,690       9       54,792       28       42,744  

Purchased Power – System Use

    64,807       3       63,226       (19 )     78,150  

Other Operation and Maintenance Expenses

    151,319       --       151,225       7       140,768  

Depreciation and Amortization

    53,276       (1 )     53,743       20       44,786  

Property Taxes

    15,053       6       14,266       6       13,512  

Operating Income

  $ 90,392       --     $ 90,131       3     $ 87,171  

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

                                       

Retail kwh Sales

    4,814,984       1       4,750,421       3       4,593,604  

Wholesale kwh Sales – Company Generation

    203,397       7       190,288       77       107,510  

Wholesale kwh Sales – Purchased Power Resold

    --       --       --       (100 )     5,547  

Heating Degree Days

    5,931       12       5,314       (6 )     5,633  

Cooling Degree Days

    380       (16 )     451       (7 )     483  

 

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

 

   

2017

   

2016

   

2015

 

Heating Degree Days

    93.9 %     84.1 %     88.2 %

Cooling Degree Days

    82.1 %     97.4 %     103.4 %

 

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 2017, 2016 and 2015, and between years:

 

   

2017 vs

Normal

   

2017 vs

2016

   

2016 vs

Normal

   

2016 vs

2015

   

2015 vs

Normal

 

Effect on Diluted Earnings Per Share

  $ (0.036 )   $ 0.031     $ (0.067 )   $ (0.023 )   $ (0.044 )

 

2017 Compared with 2016

The $1.7 million decrease in retail electric revenue includes:

 

 

A $5.3 million increase in retail revenue related to the recovery of increased fuel and purchased power costs due to a 1.4% increase in kwhs sold and a 4.8% increase in fuel and purchased power costs per kwh.

 

 

A $4.2 million increase in Minnesota base rate revenue mainly due to the transfer of recovery of environmental and transmission costs and investments from riders to base rates.

 

 

A $2.0 million increase in revenues due to increased consumption related to colder weather in 2017 reflected in the 11.6% increase in heating degree days between the years.

 

 

A $1.0 million increase in North Dakota Transmission Cost Recovery (TCR) rider revenues as a result of increased investment in transmission assets qualifying for revenue recovery through the TCR rider.

 

offset by:

 

 

A $7.1 million reduction in Minnesota Environmental Cost Recovery (ECR) rider and TCR rider revenues due to the transfer of recovery of qualifying costs from rider recovery into base rates, and due to declining revenue requirements related to lower asset values due to accumulated depreciation. Additionally, a lower return on equity in the MISO transmission tariff related to complaints currently under judicial review resulted in lower TCR revenues in Minnesota.

 

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A $3.7 million decrease in Minnesota Conservation Improvement Program (MNCIP) incentive and cost recovery revenues related to a $2.5 million reduction in incentives earned due to lower incentive rates and a $1.2 million reduction in spending on MNCIP programs. In 2017 OTP began operating under a new MNCIP program that was authorized by the Minnesota Public Utilities Commission. This new program lowered the incentive payout by 50% in 2017. The $1.2 million reduction in spending was due to a delay in regulatory approval for the implementation of an LED streetlight project.

 

 

A $1.9 million decrease in revenue due to a change in estimate that reduced unbilled revenues.

 

 

A $1.5 million decrease in North Dakota and South Dakota ECR rider revenues resulting from lower values on qualifying assets due to accumulated depreciation.

 

The $0.6 million increase in revenue from wholesale electric sales from company-owned generation was mostly offset by a $0.4 million increase in fuel costs for wholesale generation.

 

The $8.2 million increase in other electric revenues includes:

 

 

A $7.8 million increase in MISO transmission tariff revenues, mainly driven by increased investment in regional transmission lines and revenues earned from the use of those lines by other electric service providers.

 

 

A $0.4 million increase in other revenues, mainly steam sales at Big Stone Plant.

 

Production fuel costs increased $4.9 million due to a 4.0% increase in kwhs generated. This was due to increase generation from Coyote Station and Hoot Lake Plant because of Coyote Station’s greater availability, increased demand due to colder weather in 2017 and higher market prices for electricity that resulted in increased dispatch of Hoot Lake Plant.

 

The cost of purchased power to serve retail customers increased $1.6 million despite a 3.4% decrease in kwhs purchased. This was a result of higher market prices for electricity driven by increased demand in 2017 due, in part, to colder weather in 2017 than in 2016.

 

Electric operating and maintenance expenses increased $0.1 million as a result of:

 

 

A $3.2 million increase in labor and benefit costs due to increased wages and higher medical benefit payments.

 

offset by:

 

 

A $1.2 million decrease in transmission expenditures to independent system operators in 2017.

 

 

A $1.2 million decrease in MNCIP expenditures due to a delay in regulatory approval of an LED streetlight project planned for 2017.

 

 

A $0.7 million net reduction in other operating expenses.

 

Depreciation and amortization expense decreased $0.5 million due to lower depreciation rates.

 

Property tax expense increased $0.8 million mainly due to transmission line additions in South Dakota related to the construction of the Big Stone South–Ellendale and Big Stone South–Brookings 345-kiloVolt (kV) transmission projects.

 

2016 Compared with 2015

The $12.0 million increase in retail revenue includes:

 

 

An $11.0 million increase in retail revenue related to a 9.56% interim rate increase implemented in April 2016 in conjunction with OTP's 2016 general rate increase request in Minnesota.

 

 

A $4.4 million increase in ECR rider revenue due to the recovery of additional investment and costs related to the operation of the air quality control system (AQCS) at Big Stone Plant that was placed in service in December 2015.

 

 

A $4.3 million increase in revenue related to an increase in retail kwh sales, mainly to pipeline customers.

 

 

A $2.2 million increase in TCR rider revenues related to increased investment in transmission plant.

 

 

A $1.7 million increase in MNCIP cost recovery revenues directly related to additional MNCIP activities.

 

offset by:

 

 

A $5.7 million decrease in fuel and purchased power cost recovery revenues mainly due to an 11.4% decrease in kwhs purchased partially offset by a 19.7% kwh increase in generation.

 

 

A $3.6 million reduction in interim rate revenues recorded to provide for an estimated refund related to a modification in OTP’s original request and other expected outcomes in the pending Minnesota general rate case.

 

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A $1.6 million decrease in revenues related to decreased consumption due to milder weather in 2016, evidenced by a 5.7% reduction in heating-degree days and 6.6% reduction in cooling-degree days between the years.

 

 

A $0.6 million decrease in Renewable Resource Adjustment rider revenues in North Dakota, which were down as a result of earning more federal Production Tax Credits (PTCs) to pass back to customers due to a 3.6% increase in kwhs generated from wind turbines eligible for PTCs.

 

A $2.1 million increase in revenue from wholesale electric sales from company-owned generation was partially offset by a $1.5 million increase in fuel costs for wholesale generation, resulting in a $0.6 million increase in wholesale revenue net of fuel costs as increased plant availability in 2016 provided greater opportunity for OTP to respond to market demand.

 

Other electric revenues increased $6.4 million as a result of:

 

 

A $4.8 million increase in MISO transmission tariff revenues, mainly driven by increased investment in regional transmission lines and related returns on and recovery of Capacity Expansion 2020 and MISO-designated MVP investment costs and operating expenses.

 

 

A $3.0 million increase in MISO network integration transmission service revenues due to a regional transmission cooperative terminating its integrated transmission agreement with OTP and joining the Southwest Power Pool (SPP) in 2016.

 

offset by:

 

 

A $1.3 million decrease in revenue related to a reduction in integrated transmission agreement revenues from two regional transmission providers related to the curtailment of services under one agreement and the discontinuance of another agreement.

 

Production fuel costs increased $12.0 million as a result of a 27.1% increase in kwhs generated from our steam-powered and combustion turbine generators related to Big Stone Plant being fully operational in 2016 after the tie in of the AQCS in 2015, as well as Coyote Station being available to run at full load in 2016 after being restricted to half load in 2015 because of boiler feed water pump problems.

 

The cost of purchased power to serve retail customers decreased $14.9 million due to an 11.4% decrease in kwhs purchased in combination with an 8.7% decrease in the cost per kwh purchased. Greater availability of company-owned generation in 2016 reduced the need to purchase electricity to serve retail load. The decreased cost per kwh purchased was driven by lower market demand mainly resulting from milder weather in 2016 compared with 2015.

 

Electric operating and maintenance expenses increased $10.5 million as a result of:

 

 

$3.7 million in transmission expenses from the SPP as a result of a regional transmission cooperative terminating its integrated transmission agreement with OTP and joining the SPP in 2016.

 

 

A $1.9 million increase in pollution control reagent costs at Big Stone Plant and Coyote Station related to compliance with the Environmental Protection Agency power plant emission regulations.

 

 

A $1.7 million increase in MNCIP program expenditures related to additional MNCIP activities.

 

 

A $1.3 million increase in MISO transmission service charges due to increased transmission investment by other MISO members.

 

 

A $1.1 million increase in storm repair expenses associated with excessive storm damage in OTP’s Minnesota service area in July 2016 and in its North Dakota and South Dakota service areas in December 2016.

 

 

$0.8 million related to increases in other expense categories.

 

Depreciation and amortization expense increased $9.0 million mainly due to the AQCS at Big Stone Plant being placed in service in December 2015 along with increased investment in transmission assets with the final phases of the Fargo-Monticello and Brookings-Southeast Twin Cities 345-kV transmission lines placed in service near the end of the first quarter of 2015.

 

The $0.8 million increase in property tax expense is related to property additions in Minnesota and North Dakota in 2015.

 

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Manufacturing

 

The following table summarizes the results of operations for our Manufacturing segment for the years ended December 31:

 

(in thousands)

 

2017  

   

%  

change 

   

2016  

   

%  

change 

   

2015  

 

Operating Revenues

  $ 229,738       4     $ 221,289       3     $ 215,011  

Cost of Products Sold

    176,473       3       171,732       --       171,956  

Other Operating Expenses

    23,785       8       21,994       4       21,116  

Depreciation and Amortization

    15,379       (3 )     15,794       33       11,853  

Operating Income

  $ 14,101       20     $ 11,769       17     $ 10,086  

 

2017 Compared with 2016

The $8.4 million increase in revenues in our Manufacturing segment in 2017 compared with 2016 relates to the following:

 

 

Revenues at BTD increased $5.9 million. This is due to a $3.3 million increase in product sales to manufacturers of recreational and lawn and garden equipment from BTD’s Minnesota and Georgia manufacturing facilities, offset by lower sales in the energy end-use market at the Illinois facility. Scrap revenues increased $2.6 million due to increased volume and higher scrap-metal prices.

 

 

Revenues at T.O. Plastics, Inc. (T.O. Plastics) increased $2.5 million, including increases of $1.3 million from sales of life science products, $1.0 million from sales of horticultural products and $0.2 million from sales of industrial products.

 

The $4.7 million increase in cost of products sold in our Manufacturing segment includes the following:

 

 

Cost of products sold at BTD increased $2.3 million as a result of the increase in product sales.

 

 

Costs of products sold at T.O. Plastics increased $2.4 million due to the increase in sales.

 

The $1.8 million increase in Manufacturing segment operating expenses includes the following:

 

 

Operating expenses at BTD increased $1.9 million as a result of the following:

 

 

o

A $0.7 million increase in labor and benefit costs as a result of an increase in employees in a growing business.

 

 

o

A $0.4 million increase in contracted service expenditures for consulting, software and telecommunications in response to increased business needs.

 

 

o

A $0.4 million increase in property taxes.

 

 

o

A $0.4 million increase in insurance costs.

 

 

Operating expenses at T.O. Plastics decreased $0.1 million between the years.

 

The $0.4 million decrease in depreciation in our Manufacturing segment includes decreases of $0.3 million at T.O. Plastics million due to certain assets reaching the ends of their depreciable lives in 2017. Depreciation expense at BTD was down $0.1 million year over year.

 

2016 Compared with 2015

The increase of $6.3 million in revenues in our Manufacturing segment in 2016 compared with 2015 relates to the following:

 

 

Revenues at BTD increased $9.8 million, including:

 

 

o

A $15.4 million increase in revenues at BTD-Georgia as a result of BTD owning and operating this plant for the entire year of 2016 compared to four months in 2015.

 

 

o

A $9.6 million increase in revenues mainly related to the production of wind tower components.

 

offset by:

 

 

o

A $15.2 million decrease in revenues related to lower sales to manufacturers of recreational and agricultural equipment due to softness in end markets served by those manufacturers.

 

 

Revenues at T.O. Plastics decreased $3.5 million, including:

 

 

o

A $3.0 million decrease in revenue related to a continued decline in sales to a customer insourcing product into its own manufacturing facilities.

 

 

o

A $0.6 million decrease in sales of horticultural products due to sales execution challenges, including lower sales to a major distributor.

 

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offset by:

 

 

o

A net $0.1 million increase in sales of other products in the industrial and life sciences markets.

 

The $0.2 million decrease in cost of products sold in our Manufacturing segment includes the following:

 

 

Cost of products sold at BTD increased $1.7 million. This includes a $15.5 million increase in cost of products sold at BTD-Georgia, offset by a $13.8 million net decrease in cost of products sold at BTD’s other facilities. The $13.8 million decrease is related to the decrease in sales, partially offset by an increase in costs of products sold at BTD’s Illinois plant as a result of the increase in the production of wind tower components.

 

 

Cost of products sold at T.O. Plastics decreased $1.9 million related to the decrease in sales.

 

Gross margins at BTD were positively impacted in 2016 by changes in customer product mix between periods.

 

The $0.9 million increase in operating expenses in our Manufacturing segment includes the following:

 

 

Operating expenses at BTD increased $1.4 million, of which $1.2 million was due to a full year of operations at BTD-Georgia in 2016.

 

 

Operating expenses at T.O. Plastics decreased $0.4 million, primarily as a result of a $0.5 million decrease in selling expenses.

 

The $3.9 million increase in depreciation and amortization expenses in our Manufacturing segment includes a $2.3 million increase at BTD-Georgia and a $1.8 million increase at BTD’s other plants mainly as a result of placing new assets in service in Minnesota in 2015 and 2016. Depreciation expense at T.O. Plastics decreased $0.2 million between the years.

 

Plastics

 

The following table summarizes the results of operations for our Plastics segment for the years ended December 31:

 

(in thousands)

 

2017  

   

%  

change 

   

2016  

   

%  

change 

   

2015  

 

Operating Revenues

  $ 185,132       20     $ 154,901       (2 )   $ 157,758  

Cost of Products Sold

    140,107       13       123,496       --       123,085  

Other Operating Expenses

    11,564       23       9,402       (5 )     9,849  

Depreciation and Amortization

    3,817       (1 )     3,861       9       3,552  

Operating Income

  $ 29,644       63     $ 18,142       (15 )   $ 21,272  

 

2017 Compared with 2016

Plastics segment revenues increased $30.2 million as a result of a 7.2% increase in pounds of PVC pipe sold and an 11.5% increase in PVC pipe prices between the years. Reaction to the hurricanes in the Gulf Coast region of the United States resulted in an estimated $12.5 million increase in revenues. The majority of U.S. PVC resin production plants are located in the Gulf Coast region. Major resin suppliers shut down production facilities which impacted raw material availability. Distributors and contractors became concerned about pipe availability. This accelerated pipe demand and created positive sales price pressure in the market. Year over year improvement in normal business operations provided for the remainder of the revenue increase, along with increased prices. The $16.6 million increase in Plastics segment costs of product sold was due to the increase in sales volume and a 5.9% increase in the cost per pound of PVC pipe sold. The $2.2 million increase in operating expenses is mostly due to employee incentive pay related to the pipe companies’ stronger financial results compared with 2016.

 

2016 Compared with 2015

The $2.9 million decrease in Plastics segment revenues is the result of an 11.2% decrease in the price per pound of pipe sold, partially offset by a 10.5% increase in pounds of pipe sold. The decline in sales price per pound is related to lower raw material prices between the periods. Increased pipe sales in the Colorado, Utah, and the South Central and Northwest regions of the United States were partially offset by decreased sales volumes in Montana, South Dakota and Minnesota. Cost of products sold increased $0.4 million due to the increase in sales volume, partly offset by a 9.2% decrease in the cost per pound of PVC pipe sold, as sales prices declined more than raw material prices. Lower margins have resulted in reduced incentive compensation, which is the primary factor contributing to the $0.4 million decrease in Plastics segment operating expenses.

 

The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices are rising or stable, margins and sales volume have been higher and when resin prices are falling, sales volumes and margins have been lower.

 

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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.

 

(in thousands)

 

2017  

   

%  

change 

   

2016  

   

%  

change 

   

2015  

 

Other Operating Expenses

  $ 7,930       (11 )   $ 8,896       (3 )   $ 9,143  

Depreciation and Amortization

    73       55       47       (73 )     172  

 

Corporate operating expenses decreased $1.0 million mainly due to a $0.6 million increase in the level of corporate costs allocated to the corporation’s operating companies and a $0.5 million reduction in labor costs due to a reduction in the number of corporate employees.

 

Corporate operating expenses decreased $0.2 million in 2016 as compared to 2015 as a result of decreased expenditures for contracted services and a decrease in claims at our captive insurance company, partially offset by a decrease in expenses allocated to OTP.

 

Consolidated Interest Charges

 

(in thousands)

 

2017

   

%

change

   

2016

   

%

change

   

2015

 

Interest Charges

  $ 29,604       (7 )   $ 31,886       2     $ 31,160  

 

The $2.3 million decrease in interest charges in 2017 compared with 2016 is related to lower cost debt resulting from the issuance of $80.0 million of our 3.55% Guaranteed Senior Notes and the retirement of our remaining $52.3 million outstanding 9.000% Notes in December 2016 and the retirement of OTP’s $33.0 million outstanding 5.95%, Series A Senior Unsecured Notes at maturity on August 20, 2017. The average level of debt outstanding between the periods increased by approximately $13.0 million with lower cost short-term debt being issued to retire higher cost long-term debt and being used to fund a portion of OTP’s 2017 capital expenditures.

 

The $0.7 million increase in interest charges in 2016 compared with 2015 is due to an increase in interest expense on short-term debt at OTP as a result of a $24.7 million increase in OTP’s daily average balance of short-term debt outstanding between the years and a $0.2 million decrease in capitalized interest expense. The increase in OTP’s use of short-term borrowing is related to its increasing investment in two major MVP transmission line projects under construction.

 

Consolidated OTHER INCOME

 

(in thousands)

 

2017

   

%

change

   

2016

   

%

change

   

2015

 

Other Income

  $ 2,632       (9 )   $ 2,905       33     $ 2,177  

 

Other income decreased $0.3 million in 2017 compared with 2016, mainly as a result of the receipt of $0.7 million in nontaxable corporate-owned life insurance proceeds in 2016 while no similar proceeds were received in 2017, offset by an increase in the cash surrender value of the life insurance policies in 2017 that was $0.3 million more than the increase in the cash surrender value in 2016.

 

The $0.7 million increase in other income in 2016 compared with 2015 is mainly due to proceeds from corporate-owned life insurance received in 2016.

 

Consolidated Income Taxes

 

Income tax expense - continuing operations was $27.0 million in 2017 compared with $20.1 million in 2016 and $21.6 million in 2015. Income tax expense increased $6.9 million in 2017 compared with 2016 mainly as a result of a $17.0 million increase in income from continuing operations before income taxes.

 

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The following table provides a reconciliation of income tax expense – continuing operations calculated at the federal statutory rate on income from continuing operations before income taxes reported on our consolidated statements of income:

 

   

For the Year Ended December 31,

 

(in thousands)

 

2017

   

2016

   

2015

 

Tax Computed at Federal Statutory Rate – Continuing Operations

  $ 34,707     $ 28,741     $ 28,081  

Increases (Decreases) in Tax from:

                       

Federal PTCs

    (7,527 )     (7,175 )     (6,962 )

State Income Taxes Net of Federal Income Tax Expense

    4,341       2,848       4,945  

Section 199 Domestic Production Activities Deduction

    (1,471 )     (482 )     --  

North Dakota Wind Tax Credit Amortization – Net of Federal Taxes

    (850 )     (850 )     (850 )

Corporate-owned Life Insurance

    (845 )     (680 )     (167 )

Excess Tax deduction – Stock Compensation Awards

    (751 )     --       --  

Employee Stock Ownership Plan Dividend Deduction

    (509 )     (537 )     (560 )

AFUDC - Equity

    (322 )     (280 )     (426 )

Investment Tax Credit Amortization

    (164 )     (350 )     (571 )

Differences Reversing in Excess of Federal Rates

    551       77       (1,143 )

Permanent and Other Differences

    (1,873 )     (1,231 )     (705 )

Effect of TCJA Tax Rate Reduction on Value of Net Deferred Tax Assets

    1,756       --       --  

Total Income Tax Expense – Continuing Operations

  $ 27,043     $ 20,081     $ 21,642  

Effective Income Tax Rate – Continuing Operations

    27.3 %     24.5 %     27.0 %

 

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 increased 4.4% in 2017 compared with 2016 due to improved availability of the turbines and more favorable wind and operating conditions in 2017. OTP’s kwh generation from its wind turbines eligible for PTCs increased 3.6% in 2016 compared with 2015 primarily due to higher average wind speed in 2016 compared with 2015. 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.

 

DISCONTINUED OPERATIONS

 

On April 30, 2015 we sold Foley Company (Foley) for $12.0 million in cash, plus $6.3 million in adjustments for working capital and other related items received in October 2015, less $1.0 million in selling expenses. On February 28, 2015 we sold the assets of AEV, Inc. for $22.3 million in cash, plus $0.6 million in adjustments for working capital and fixed assets received in October 2015, less $0.8 million in selling expenses. Foley and AEV, Inc were included in our Construction segment. On February 8, 2013 we completed the sale of substantially all the assets of our dock and boatlift company, formerly included in our Manufacturing segment. On November 30, 2012 we completed the sale of the assets of our wind tower manufacturing business, formerly included in our Wind Energy segment. Our Construction and Wind Energy segments were eliminated as a result of these sales.

 

The financial position, results of operations and cash flows of Foley, AEV, Inc., our wind tower manufacturing business and our dock and boatlift company are reported as discontinued operations in our consolidated financial statements. Following are the results of discontinued operations by entity for the years ended December 31, 2017, 2016 and 2015:

 

(in thousands)

 

Foley

   

AEV, Inc.

   

Wind

Tower

Business

   

Dock and

Boatlift

Business

   

Intercompany

Transactions

Adjustment

   

Total

 

2017 Net (Loss) Income

  $ (140 )   $ --     $ 276     $ 184     $ --     $ 320  

2016 Net (Loss) Income

  $ (114 )   $ (5 )   $ 454     $