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

ottr20191231_10k.htm
0001466593 Otter Tail Corp false --12-31 FY 2019 0 0 1 0 0 0 0 0 0.3 0 0.016 0.016 33.3 33.3 4 0 20 6,237,000 6 2040 2020 5 5 1.50 1.25 21 2016 2017 2018 2019 2016 2017 2018 2019 2015 2016 2017 2018 2019 0 Holder is COBANK, a cooperative lender. Interest payments are subject to cash credits which may result in a lower effective interest rate. Corporate cost included in nonservice cost components of postretirement benefits. Allocation of Costs: 2019 2018 2017 Service costs included in OTP Capital Expenditures $ 1,365 $ 1,542 $ 1,094 Service costs included in electric operation and maintenance expenses 3,994 4,756 4,400 Service costs included in other nonelectric expenses 132 161 135 Nonservice costs capitalized (526 ) (99 ) 48 Nonservice costs included in nonservice cost components of postretirement benefits (1,589 ) (314 ) 200 Midcontinent Independent System Operator, Inc. (MISO) Multi-Value Project (MVP) designation provides for a return on invested funds while under construction under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff). Costs subject to recovery without a rate of return. Includes (but not limited to) High Yield Bond Fund and Emerging Markets Debt funds. Allocation of Costs: 2019 2018 2017 Service costs included in electric operation and maintenance expenses $ 104 $ 99 $ 94 Service costs included in other nonelectric expenses 314 309 196 Nonservice costs included in nonservice cost components of postretirement benefits 2,229 2,571 2,465 Amortization of prior service costs and net actuarial losses from other comprehensive income are included in nonservice cost components of postretirement benefits. Accumulated Other Comprehensive Loss on December 31 is comprised of the following: (in thousands) 2019 2018 2017 Unrealized Gain (Loss) on Marketable Equity Securities: Before Tax $ 68 $ (95 ) $ 71 Tax Effect (14 ) 20 (15 ) Stranded Tax Effect - (10 ) (10 ) Unrealized Gain (Loss) on Marketable Equity Securities net-of-tax 54 (85 ) 46 Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits: Before Tax (8,772 ) (6,558 ) (9,462 ) Tax Effect 2,281 1,705 2,991 Stranded Tax Effect - 794 794 Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits net-of-tax (6,491 ) (4,059 ) (5,677 ) Accumulated Other Comprehensive Loss: Before Tax (8,704 ) (6,653 ) (9,391 ) Tax Effect 2,267 1,725 2,976 Stranded Tax Effect - 784 784 Net Accumulated Other Comprehensive Loss $ (6,437 ) $ (4,144 ) $ (5,631 ) Other category may include cash, alternatives, and/or other investment strategies that may be classified other than equity or fixed income, such as the Dynamic Asset Allocation fund or the SEI Energy Debt Collective Fund. Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. Allocation of Cost: 2019 2018 2017 Service Costs included in OTP capital expenditures $ 320 $ 364 $ 277 Service costs included in electric operation and maintenance expenses 935 1,124 1,114 Service costs included in other nonelectric expenses 31 38 34 Nonservice costs capitalized 1,167 1,020 712 Nonservice costs included in nonservice cost components of postretirement benefits 3,525 3,253 2,955 1,339 1,407 1,500,000 1,500,000 0 0 0 0 1,000,000 1,000,000 0 0 0 0 5 5 50,000,000 50,000,000 40,157,591 39,664,884 1.28 1.34 1.40 3.55 3.55 December 15, 2026 December 15, 2026 2.54 2.54 March 18, 2021 March 18, 2021 4.63 4.63 December 1, 2021 December 1, 2021 6.15 6.15 August 20, 2022 August 20, 2022 6.37 6.37 August 20, 2027 August 20, 2027 4.68 4.68 February 27, 2029 February 27, 2029 3.07 October 10, 2029 6.47 6.47 August 20, 2037 August 20, 2037 3.52 October 10, 2039 5.47 5.47 February 27, 2044 February 27, 2044 4.07 4.07 February 7, 2048 February 7, 2048 3.82 October 10, 2049 3.55 3.55 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Table of Contents

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2019

 

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

Trading Symbol(s)

Name of each exchange on which registered

Common Shares, par value $5.00 per share

OTTR

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 every Interactive Data File required to be submitted 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 such files). Yes  ☑     No  ☐

 

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  

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 28, 2019 was $2,040,017,347.

 

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date: 40,214,375 Common Shares ($5 par value) as of February 6, 2020.

 

Documents Incorporated by Reference:

 

Proxy Statement for the 2020 Annual Meeting-Portions incorporated by reference into Part III

 

 
 

 

 

OTTER TAIL CORPORATION

FORM 10-K TABLE OF CONTENTS

 

 

Description

Page

 

Definitions

2

PART I

   

ITEM 1.

Business

4

ITEM 1A.

Risk Factors

29

ITEM 1B.

Unresolved Staff Comments

39

ITEM 2.

Properties

40

ITEM 3.

Legal Proceedings

40

ITEM 3A.

Information About Our Executive Officers (as of February 20, 2020) 

41

ITEM 4.

Mine Safety Disclosures

41

     

PART II

   

ITEM 5.

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

42

ITEM 6.

Selected Financial Data

43

ITEM 7.

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

43

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

63

 

Consolidated Statements of Income

65

 

Consolidated Statements of Comprehensive Income

66

 

Consolidated Statements of Common Shareholders’ Equity

67

 

Consolidated Statements of Cash Flows

68

 

Consolidated Statements of Capitalization

69

 

Notes to Consolidated Financial Statements

70

 

Supplementary Financial Information - Quarterly Information

119

ITEM 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

120

ITEM 9A.

Controls and Procedures

120

ITEM 9B.

Other Information

120

     

PART III

   

ITEM 10.

Directors, Executive Officers and Corporate Governance

121

ITEM 11.

Executive Compensation

121

ITEM 12.

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

122

ITEM 13.

Certain Relationships and Related Transactions, and Director Independence

122

ITEM 14.

Principal Accountant Fees and Services

122

     

PART IV

   

ITEM 15.

Exhibits and Financial Statement Schedules

123

ITEM 16.

Form 10-K Summary

131

     

Signatures

 

132

 

 
 

 

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.

 

2018 Notes

February 2018 issuance of $100 million in privately placed 4.07% Senior Unsecured Notes due February 7, 2048

ACE

Affordable Clean Energy

ADIT

Accumulated Deferred Income Taxes

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 326

ASC Topic 326 – Financial Instruments—Credit Losses

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 840

ASC Topic 840 – Leases

ASC 842

ASC Topic 842 – Leases

ASC 980

ASC Topic 980 – Regulated Operations

ASM

Ancillary Services Market

ASU

Accounting Standards Update

ASU 2016-02

ASU No. 2016-02, Leases (Topic 842)

BTD

BTD Manufacturing, Inc.

CAA

Clean Air Act

CCMC

Coyote Creek Mining Company, L.L.C.

CCR

Coal Combustion Residuals

CO2

carbon dioxide

CON

Certificate of Need

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

ECR

Environmental Cost Recovery

EDF

EDF Renewable Development, Inc.

EDF-USD

EDF-RE US Development, LLC

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

FERC

Federal Energy Regulatory Commission

GAAP

Generally Accepted Accounting Principles in the United States

GCR

Generation Cost Recovery

GHG

Greenhouse Gas

IRP

Integrated Resource Plan

kV

kiloVolt

kW

kiloWatt

kwh

kilowatt-hour

LSA

Lignite Sales Agreement

MATS

Mercury and Air Toxics Standards

Merricourt

Merricourt Wind Energy Center

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

 

2

 

MPUC

Minnesota Public Utilities Commission

MRO

Midwest Reliability Organization

MVP

Multi-Value Project

MW

megawatts

NAAQS

National Ambient Air Quality Standards

NAEMA

North American Energy Marketers Association

NDDEQ

North Dakota Department of Environmental Quality

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

NOI

Notice of Inquiry

Northern Pipe

Northern Pipe Products, Inc.

NOx

nitrogen oxide

NTEC

Navajo Transitional Energy Co.

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

RHR

Regional Haze Rule

ROE

Return on equity

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

SRECs

Solar renewable energy credits

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

 

3

 

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 4150 19th Avenue South, Suite 101, 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). These reports are also available on the SEC’s website (www.sec.gov). Information on the Company’s and the SEC’s websites is not deemed to be incorporated by reference into this report on Form 10-K.

 

Otter Tail Corporation and its subsidiaries conduct business primarily in the United States. The Company had approximately 2,208 full-time employees at December 31, 2019. 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.

 

The chart below indicates the operating 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.

 

 

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.

 

4

 

The Company maintains a moderate risk profile by investing in rate base growth opportunities in its Electric segment and organic growth opportunities in its manufacturing platform, which includes its Manufacturing and Plastics segments. This strategy and risk profile are designed to provide a more predictable earnings stream, maintain the Company’s credit quality and preserve its ability to fund the dividend. The Company’s goal is to deliver annual growth in earnings per share between five to seven percent over the next several years, using 2019 diluted earnings per share 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. 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 continue to be a fundamental part of its strategy. The actual mix of earnings in 2019 was 68% from the electric utility and 32% 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 and commercial 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 43 through 59 of this 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. See note 2 to our consolidated financial statements included in this report on Form 10-K for additional information about the Company's segments and geographic areas.

 

(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 50%, 49% and 51% of its consolidated operating revenues and 73%, 68% and 72% of its consolidated operating income from its Electric segment for the years ended December 31, 2019, 2018 and 2017, respectively.

 

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

 

State

 

2019

   

2018

 

Minnesota

  52.3 %   52.6 %

North Dakota

  37.7     38.6  

South Dakota

  10.0     8.8  

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, 2019, OTP served 132,578 customers. Although there are relatively few large customers, sales to commercial and industrial customers are significant. One customer accounted for 11.9% of 2019 Electric segment revenue.

 

5

 

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

 

2019

   

2018

 

Commercial

  35.4 %   37.0 %

Residential

  32.3     32.5  

Industrial

  30.0     30.0  

All Other Sources

  2.3     0.5  

Total

  100.0 %   100.0 %

 

Capacity and Demand

 

As of December 31, 2019, OTP’s owned net-plant dependable kilowatt (kW) capacity was:

 

Baseload Plants

       

Big Stone Plant

 

257,600

kW

Coyote Station

    149,500  

Hoot Lake Plant

    141,600  

Total Baseload Net Plant

 

548,700

kW

Combustion Turbine and Small Diesel Units

 

105,100

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 above 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 2019, about 54% of OTP’s retail kilowatt-hour (kwh) sales were supplied from OTP generating plants with the balance supplied by purchased power.

 

In addition to the owned facilities described above, OTP had the following purchased power agreements in place on December 31, 2019:

 

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 Energy (through May 2021)

 

50,000

kW

 

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 2019-2020 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 2020 system demand and MISO reserve requirements.

 

6

 

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 transported by rail.

 

The following table shows the sources of energy used to generate OTP’s net output of electricity for 2019 and 2018:

 

   

2019

   

2018

 

Sources

 

Net kwhs

Generated

(Thousands)

   

% of Total

kwhs

Generated

   

Net kwhs

Generated

(Thousands)

   

% of Total

kwhs

Generated

 

Subbituminous Coal

    1,754,708       58.3 %     1,891,394       53.5 %

Lignite Coal

    734,740       24.4       1,080,639       30.5  

Wind and Hydro

    467,301       15.5       494,394       14.0  

Natural Gas and Oil

    53,697       1.8       70,015       2.0  

Total

    3,010,446       100.0 %     3,536,442       100.0 %

 

OTP has the following primary coal supply agreements:

 

Plant

Coal Supplier

Type of Coal

Expiration Date

Big Stone Plant

Peabody COALSALES, LLC

Wyoming subbituminous

December 31, 2020

Coyote Station

Coyote Creek Mining Company, L.L.C.

North Dakota lignite

December 31, 2040

Hoot Lake Plant

Navajo Transitional Energy Co. (NTEC)

Montana subbituminous

December 31, 2023

 

OTP and its Big Stone Plant co-owners entered into the current coal purchase agreement with Peabody COALSALES, LLC in May 2018 for the purchase of subbituminous coal for Big Stone Plant’s coal requirements through December 31, 2020. There is no fixed minimum purchase requirement under this agreement but all of Big Stone Plant’s coal requirements for the period covered must be purchased under this agreement.

 

In October 2012, OTP and its Coyote Station co-owners 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 Coyote Station’s coal requirements for the period May 2016 through 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 share of unrecovered costs of CCMC as of December 31, 2019 were $50.4 million. See note 1 to our consolidated financial statements included in this report on Form 10-K for additional information.

 

OTP’s coal supply requirements for Hoot Lake Plant are secured under contract through December 2023. There are no fixed minimum purchase requirements under this agreement. In October 2019, NTEC purchased the assets of Cloud Peak Energy Resources LLC, including its Spring Creek Mine in southeast Montana, through bankruptcy court. For a two-day period in October, operations at the Spring Creek Mine were suspended due to a disagreement between the Montana Department of Environmental Quality and the NTEC. Subsequent to the suspension of operations, the two parties agreed to allow the mine to operate for an additional period while they work to resolve differences regarding the NTEC’s waiver of sovereign immunity from the state’s environmental laws.

 

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 for the years 2019, 2018, and 2017 was $2.129, $1.977 and $2.224, respectively.

 

Transmission Revenues

 

OTP earns significant revenues from the transmission of electricity for others over the transmission assets it separately owns, or jointly owns with other transmission service providers, under rate tariffs established by MISO and approved by the Federal Energy Regulatory Commission (FERC).

 

7

 

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:

 

      2019     2018  

Rates

Regulation

 

% of Electric

Revenues

   

% of kwh

Sales

   

% of Electric

Revenues

   

% of kwh

Sales

 

MN Retail Sales

MN Public Utilities Commission

    47.0 %     53.5 %     46.2 %     54.1 %

ND Retail Sales

ND Public Service Commission

    33.8       36.6       33.9       36.8  

SD Retail Sales

SD Public Utilities Commission

    9.0       9.9       7.7       9.1  

Transmission &Wholesale

Federal Energy Regulatory Commission

    10.2       --       12.2       --  

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.

 

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 for 2019 were based on a two-month moving average in Minnesota and were applied to the next billing period after becoming applicable. Adjustments for fuel and purchased power costs are presently based on a three-month moving average in South Dakota and a four-month moving average in North Dakota and 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. Minnesota has made changes to its fuel and purchased power cost recovery mechanism that took effect on January 1, 2020 (see discussion under Minnesota - Fuel and Purchased Power Costs Recovery below).

 

2017 Tax Cuts and Jobs Act (TCJA)

 

The TCJA, passed in December 2017, reduced the federal corporate income tax rate from 35% to 21%, effective January 1, 2018. At the time of passage, OTP’s electric rates had been developed using a 35% tax rate. The Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the FERC each initiated dockets or proceedings to begin working with utilities to assess the impact of the lower rates on electric rates, and to develop regulatory strategies to incorporate the tax reduction into future electric rates, if warranted.

 

The MPUC required regulated utilities providing service in Minnesota to make filings by February 15, 2018. On August 9, 2018 the MPUC determined the impacts of the TCJA as calculated, including amortization of excess accumulated deferred income taxes, should be refunded and rates should be adjusted going forward to account for the impacts of the TCJA. On December 5, 2018 the MPUC issued its final order related to the TCJA docket directing OTP to return to ratepayers, in a one-time refund, the TCJA-related savings accrued prior to the refund effective date. The order also directs OTP to use these savings to reduce customers’ base rates prospectively, allocating the savings to customers in proportion to the size of each customer’s bill, or to each customer class in proportion to the class’s size. New rates reflecting the reduction in revenue requirements related to the TCJA tax rate reduction went into effect June 1, 2019. A one-time refund to Minnesota customers of $11.5 million in excess of amounts billed from January 2018 through May 2019 occurred in August and September 2019.

 

OTP’s recent general rate cases in North Dakota and South Dakota reflected the impact of the TCJA in interim rates. OTP accrued refund liabilities for the time periods during which revenues were collected under rates set to recover higher levels of federal income taxes than OTP incurred under the lower federal tax rates in the TCJA.

 

8

 

Electric Segment Major Capital Expenditure Projects

 

Below are descriptions of OTP’s major capital expenditure projects that have had, or are expected to have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of 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.

 

Merricourt Wind Energy Center (Merricourt)—On November 16, 2016 OTP entered into an Asset Purchase Agreement (the Purchase Agreement) with EDF Renewable Development, Inc. and certain of its affiliated companies (collectively, EDF) to purchase and assume the development assets and certain specified liabilities associated with Merricourt, a 150-megawatt (MW) wind farm in southeastern North Dakota, for a purchase price of approximately $34.7 million, subject to adjustments for interconnection costs. Also on November 16, 2016, OTP entered into a Turnkey Engineering, Procurement and Construction Services Agreement (the TEPC Agreement) with EDF-RE US Development, LLC (EDF-USD) pursuant to which EDF-USD will develop, design, procure, construct, interconnect, test and commission the wind farm with a targeted completion date in 2020 for consideration of approximately $200.5 million, subject to certain adjustments, payable following the closing of the Purchase Agreement in installments in connection with certain project construction milestones. The agreements contain customary representations, warranties, covenants and indemnities for this type of transaction. On October 26, 2017 the MPUC approved the facility under the Renewable Energy Standard making Merricourt eligible for cost recovery under the Minnesota Renewable Resource Recovery rider, subject to qualifications and reporting obligations. The MPUC’s final written order was issued on January 10, 2018. A final order for an Advance Determination of Prudence (ADP) for Merricourt, subject to qualifications and compliance obligations, and a Certificate of Public Convenience and Necessity were issued by the NDPSC on November 3, 2017. The phase-in rider approved by order of the SDPUC on March 6, 2019 includes recovery of Merricourt costs. The Merricourt generator interconnection agreement with MISO was approved by the FERC in April 2019.

 

In connection with action by the FERC, OTP and EDF-USD agreed, in the First Amendment to the Purchase Agreement and the TEPC Agreement dated June 11, 2019, to change the purchase price to $37.7 million and to make a related reallocation of responsibility for interconnection costs and liabilities. On July 16, 2019, OTP closed on the purchase of substantially all of the development assets and assumed certain specified liabilities from EDF related to Merricourt pursuant to the Purchase Agreement, as amended, for a purchase price of approximately $37.7 million, subject to certain adjustments, and issued the notice to EDF-USD to begin construction in August 2019. As of December 31, 2019, OTP had capitalized approximately $81.7 million in project costs and allowance for funds used during construction (AFUDC) associated with Merricourt. OTP expects the project will be completed in October 2020 and cost approximately $258 million.

 

Astoria Station—OTP is constructing this 245 MW simple-cycle natural gas-fired combustion turbine generation facility near Astoria, South Dakota, as part of its plan to reliably meet customers’ electric needs, replace expiring capacity purchase agreements and prepare for the planned retirement of its Hoot Lake Plant in 2021. A final order granting an ADP for Astoria Station was issued by the NDPSC on November 3, 2017, subject to certain qualifications and compliance obligations. On August 3, 2018 the SDPUC issued an order granting a site permit for Astoria Station. In a September 26, 2018 hearing the NDPSC established a Generation Cost Recovery Rider for future recovery of costs incurred for Astoria Station. On March 6, 2019 the SDPUC issued an order approving a settlement that allows a phase-in rider which includes recovery of Astoria Station costs. The interconnection agreement for Astoria Station was executed by MISO in December 2018 and accepted by the FERC in January 2019. Site preparation and excavation began in May 2019. As of December 31, 2019, OTP had capitalized approximately $58.7 million in project costs and AFUDC associated with Astoria Station. OTP expects the project will be completed in late 2020 or early 2021 and cost approximately $158 million.

 

Big Stone South–Ellendale Multi-Value Transmission Project (MVP)— This 345-kiloVolt (kV) transmission line, energized on February 6, 2019, extends 162 miles between a substation near Big Stone City, South Dakota and a substation near Ellendale, North Dakota. OTP jointly developed this project with Montana-Dakota Utilities Co., and the parties have equal ownership interest in the transmission line portion of the project. The MISO approved this project as an MVP under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff) in December 2011. MVPs are designed to enable the MISO region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation is designed to ensure the costs of transmission projects with regional benefits are properly assigned to those who benefit from the MVP. OTP capitalized costs of approximately $106 million on this project, including assets that are 100% owned by OTP.

 

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

 

9

 

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.

 

General Rates—The MPUC rendered its final decision in OTP’s 2016 general rate case in March 2017 and issued its written order on May 1, 2017. Pursuant to the order, OTP’s allowed rate of return on rate base decreased from 8.61% to 7.5056% and its allowed rate of return on equity (ROE) decreased from 10.74% to 9.41%. The MPUC denied OTP’s request for reconsideration of certain of the MPUC’s rulings in the rate case.

 

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

 

OTP accrued interim and rider rate refunds until final rates became effective. The final interim rate refund, including interest, of $9.0 million was applied as a credit to Minnesota customers’ electric bills beginning in November 2017. In addition to the interim rate refund, OTP refunded the difference between (1) amounts collected under its Minnesota ECR and TCR riders based on the 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. 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 were refunded to Minnesota customers over a 12-month period beginning in November 2017 through reductions in the Minnesota ECR and TCR rider rates. The TCR rider 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, resource plans 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 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 an additional 100 MW to 200 MW of wind in the 2022 to 2023 timeframe.

 

10

 

On November 29, 2018 the MPUC extended the deadline for OTP’s next IRP filing from June 3, 2019 to June 1, 2020. The MPUC order cited two key environmental regulations for which the impacts on OTP facilities were not yet ascertainable: the federal Regional Haze Rule (RHR) promulgated by the Environmental Protection Agency (EPA) in 1999 and the Affordable Clean Energy (ACE) Rule proposed by the EPA in August 2018. On August 29, 2019 OTP filed a request to extend the next resource plan filing date from June 1, 2020 to September 1, 2021. The main reason for this request was to have more certainty on the North Dakota Department of Environmental Quality (NDDEQ) decision on the technology required to comply with the RHR. On December 5, 2019 the MPUC granted OTP’s request for an extension until September 1, 2021 to file its next resource plan. In connection with the extension, OTP is required to file a document detailing its bidding process and timeline for a solar project by April 15, 2020 and to make a compliance filing with the MPUC detailing proposed next steps for contract negotiations and filings by July 1, 2020. By December 31, 2020 OTP is required to make a supplemental filing modeling scenarios showing differing levels of RHR compliance costs, including a scenario where Coyote Station closes as an alternative to adding environmental controls. OTP is also required to provide a number of sensitivities for each scenario, including Minnesota environmental externalities and carbon regulatory costs.

 

Fuel and Purchased Power Costs Recovery—The MPUC issued an order authorizing the implementation of a new fuel clause adjustment mechanism to be implemented January 1, 2020. OTP will submit forecasted monthly fuel cost rates in advance for the upcoming twelve-month period beginning January 1 of each year. On approval by the MPUC, those rates will be published in advance of each year to give customers notice of the next year’s 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, be required to show prudence of costs incurred over forecast before being authorized recovery. The refund of any over-collection or recovery of any under-collection would be handled through a true-up mechanism.

 

This mechanism could result in reductions in Electric segment operating income margins, increase variability in consolidated net income in future periods if costs per kwh vary from forecasted costs per kwh, and cause an increase in working capital and short-term borrowings in the event recovery of all or a portion of excess costs is delayed or denied by the MPUC.

 

Renewable Energy Standards, Conservation, Renewable Resource Riders—Minnesota law favors energy conservation and load-management measures over the addition of new generation 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. Minnesota 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 $5.00 to $25.00 per ton of CO2 commencing in 2025, but this range is currently under review by the MPUC. The MPUC is required to annually update these estimates.

 

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. OTP meets the current renewable sources requirements with a combination of owned renewable generation and purchases from renewable generation sources. Minnesota law also 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 sufficient solar renewable energy credits (SRECs) to meet 100% of its 2020 obligation and approximately 70% of its 2021 obligation.

 

Under certain circumstances and after consideration of costs and reliability issues, the MPUC may modify or delay implementation of the standards. OTP is evaluating potential options for maintaining compliance and meeting the solar energy standard beyond 2021. OTP’s compliance with the Minnesota renewable energy standard will be measured through the Midwest Renewable Energy Tracking System.

 

11

 

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.

 

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.

 

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 included as 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 May 25, 2016 the MPUC adopted changes to the MNCIP financial incentive. The model provides utilities an incentive of 13.5% of 2017 net benefits, 12% of 2018 net benefits and 10% of 2019 net benefits, assuming the utility achieves 1.7% savings compared to retail sales. The financial incentive is also limited to 40% of 2017 MNCIP spending, 35% of 2018 spending and 30% of 2019 spending. The new model reduces the MNCIP financial incentive by approximately 50% compared to the previous incentive mechanism. The MNDOC issued a decision on May 20, 2019 to extend all utilities 2017-2019 MNCIP plans one year, through 2020, with an incentive based on 30% of spending and 10% of net benefits.

 

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 a decrease in energy savings compared to 2016 program results of approximately 10%. OTP requested approval for recovery of its 2017 MNCIP program costs not included in base rates on March 30, 2018. The request included a $2.6 million financial incentive and an update to the MNCIP surcharge from the MPUC. On June 13, 2018, in reply comments to a MNDOC recommendation for approval filed on May 30, 2018, OTP increased its request for a financial incentive to $2.9 million. On October 4, 2018, the MPUC issued an order approving OTP’s request of $2.9 million with an effective date of November 1, 2018, subject to further review by the MPUC to ensure no previous decisions conflict with the decision, with $0.3 million reserved for potential future refund. No refund was required, and the $0.3 million reserve was reversed and recorded as revenue in 2019.

 

Based on results from the 2018 MNCIP program year, OTP recognized a financial incentive of $3.0 million in 2018. OTP requested approval for recovery of its 2018 MNCIP program costs not included in base rates on April 1, 2019. The request included a $3.0 million financial incentive and an update to the MNCIP surcharge from the MNPUC. On October 24, 2019 the MPUC approved a $3.0 million financial incentive for 2018.

 

Based on results from the 2019 MNCIP program year, OTP recognized a financial incentive of $2.7 million in 2019. By April 1, 2020 OTP will request approval from the MPUC for recovery of the 2019 financial incentive and its 2019 program costs not included in base rates.

 

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 required Minnesota investor-owned utilities to undergo an analysis of transmission and distribution avoided costs for 2018 and 2019. On September 29, 2017, the 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 plans. On May 20, 2019 the MNDOC issued a decision allowing OTP to use its 2017-2019 avoided costs for the 2020 MNCIP year. The decision also approved the use of OTP’s newly established avoided costs for the 2021-2023 MNCIP triennial plan expected to be filed with the MNDOC on June 1, 2020.

 

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Transmission Cost Recovery Rider—The MPU Act authorizes the MPUC to approve 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 that are 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 most recently completed general rate case or such other rate of return the MPUC determines is in the public interest. Additionally, following approval of a 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.

 

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 MVPs and all revenues received from other utilities under MISO’s tariffed rates as a credit in its TCR revenue requirement calculations. In doing so, the MPUC’s order diverted interstate wholesale revenues approved by the FERC to offset FERC-approved expenses, effectively reducing OTP’s recovery of those FERC-approved expense levels. The MPUC-ordered treatment resulted in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC’s revenue requirements and authorized returns vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision can vary over time and be dependent on the differences between the revenue requirements and returns in the two jurisdictions at any given time. On August 18, 2017 OTP filed an appeal of the MPUC order with the Minnesota Court of Appeals to contest the portion of the order requiring OTP to jurisdictionally allocate costs of the FERC MVP transmission projects in the TCR rider.

 

On June 11, 2018 the Minnesota Court of Appeals reversed the MPUC’s order related to the inclusion of Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVPs and all revenues received from other utilities under MISO’s tariffed rates as a credit in OTP Minnesota TCR revenue requirement calculations. On July 11, 2018 the MPUC filed a petition for review of the MVP decision to the Minnesota Supreme Court, which has granted review of the Minnesota Court of Appeals decision. A decision by the Minnesota Supreme Court is expected in the second quarter of 2020.

 

On November 30, 2018 OTP filed its annual update and supplemental filing to the Minnesota TCR rider. In this filing two scenarios were submitted based on whether the Minnesota Supreme Court affirms the original decision by the Minnesota Court of Appeals to exclude the MVP projects from the TCR rider or overturns the Minnesota Court of Appeals decision and includes the two MVP projects in the TCR rider. In addition, on April 1, 2019, the MNDOC filed comments in OTP’s TCR rider docket, opposing OTP’s proposal for TCR rider recovery of these costs. The MPUC is not expected to act on the TCR rider until after the Minnesota Supreme Court has acted and additional briefing has occurred in the docket. The estimated amount credited to Minnesota customers under the TCR rider through December 31, 2019 and subject to recovery if the Minnesota Court of Appeals decision is upheld, is approximately $2.6 million. If the Minnesota Court of Appeals decision is upheld, there will be additional briefing in the pending TCR rider docket regarding the recovery of these costs.

 

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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 Air Quality Control System (AQCS). The ECR rider provided for a return on the project’s construction work in progress (CWIP) balance at the level approved in OTP’s 2010 general rate case. 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. Accordingly, in its 2018 annual update filing OTP requested, and the MPUC approved, setting the Minnesota ECR rider rate to zero effective December 1, 2018.

 

Capital Structure Petition—Minnesota law requires an annual filing of a capital structure petition with the MPUC. In this filing the MPUC reviews 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 July 19, 2019, allowing for an equity-to-total-capitalization ratio between 46.0% and 56.2%, with total capitalization not to exceed $1,331,302,000 until the MPUC issues a new capital structure order for 2020. OTP is required to file its 2020 capital structure petition no later than May 1, 2020.

 

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 and routes in North Dakota for large electric generating facilities and high voltage transmission lines, respectively. 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 also required to submit a ten-year facility 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 Rates—On November 2, 2017 OTP filed a request with the NDPSC for a rate review and an effective increase in annual revenues from non-fuel base rates of $13.1 million or 8.72%. The requested $13.1 million increase was net of reductions in North Dakota Renewable Resource Adjustment (NDRRA), TCR and ECR rider revenues that would have resulted from a lower allowed ROE and changes in allocation factors in the general rate case. In the request, OTP proposed an allowed return on rate base of 7.97% and an allowed ROE of 10.30%. On December 20, 2017 the NDPSC approved OTP’s request for interim rates to increase annual revenue collections by $12.8 million, effective January 1, 2018. In response to the reduction in the federal corporate tax rate under the TCJA, the NDPSC issued an order on February 27, 2018 reducing OTP’s annual revenue requirement for interim rates by $4.5 million to $8.3 million, effective March 1, 2018.

 

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

 

In a September 26, 2018 hearing the NDPSC approved an overall annual revenue increase of $4.6 million (3.1%) and a ROE of 9.77% on a 52.5% equity capital structure. This compares with OTP’s March 2018 adjusted annual revenue increase request of $7.1 million (4.8%) and a requested ROE of 10.3%. The NDPSC’s approval does not require any rate base adjustments from OTP’s original request and establishes a Generation Cost Recovery (GCR) rider for future recovery of costs incurred for Astoria Station. The net revenue increase reflects a reduction in income tax recovery requirements related to the TCJA and decreases in rider revenue recovery requirements. Final rates were effective February 1, 2019, with refunds of excess revenues collected under interim rates applied to customers’ April 2019 bills, including $0.8 million for amounts collected reflecting the higher tax rates under interim rates in effect in January and February 2018.

 

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Renewable Resource Adjustment—OTP has a NDRRA rider which enables OTP to recover the North Dakota share of its investments in renewable energy facilities it owns. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed, along with a return on investment. 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 and the NDRRA rate increased from 7.005% to 7.756% with an effective date of January 1, 2018. A reset of the NDRRA rate to reflect the effect of the federal corporate tax rate reduction under the TCJA was approved on February 27, 2018, reducing the NDRRA rate to 7.493%, effective March 1, 2018.

 

On May 1, 2019 the NDPSC approved OTP's request for an annual update to its NDRRA rider rate to -0.224% of base charges, based on an annual refund requirement of $235,000, effective for bills rendered on and after June 1, 2019. The refund requirement results from recovery of the Ashtabula, Langdon, and Luverne wind projects being moved into base rates as of December 31, 2018 as well as a reduction in revenue requirements related to the difference between the deferred tax asset for federal Production Tax Credits (PTCs) included in base rates and actual amounts associated with the Ashtabula and Langdon wind projects.

 

Effective in February 2019 with the implementation of general rates based on the results of OTP’s 2017 general rate case, recovery of renewable resource costs previously being recovered through the NDRRA rider transitioned to recovery in base rates.

 

On December 31, 2019 OTP filed its annual update to the NDRRA requesting approval for recovery of $3.8 million in renewable energy costs from its North Dakota customers. The $3.8 million is net of a credit of $0.5 million for amounts over-collected under the North Dakota ECR that will be credited to North Dakota customers through this RRA update.

 

Transmission Cost Recovery Rider—North Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. For qualifying projects, the law authorizes a current return on CWIP and a return on investment at the level approved in the utility's most recent general rate case. Based on the order in the general rate case, only certain costs will remain subject to refund or recovery through this rider: Southwest Power Pool (SPP) costs and MISO Schedule 26 and 26A revenues and expenses and costs related to rider projects still under construction in the test year used in the 2017 general rate case. This rider continues to be updated annually for new or modified electric transmission facilities and associated operating costs.

 

On August 31, 2017 OTP filed its annual update to the TCR rider requesting a revenue requirement of $8.6 million. OTP made a supplemental filing on November 2, 2017, reducing its request by $0.6 million to $8.0 million to reflect the rate of return and allocation factors used in its general rate case filed the same day. The NDPSC approved the update for recovery of the $8.0 million revenue requirement on November 29, 2017 and the new rates went into effect on January 1, 2018. A reset of the TCR rate to reflect the effect of the federal corporate tax rate reduction under the TCJA was approved on February 27, 2018, reducing annual revenue recovery under the TCR rate by $0.5 million effective March 1, 2018.

 

On August 31, 2018 OTP filed its annual update to the TCR rider. The filing included three new projects along with updates to collections, actual costs and forecasted amounts for rider-eligible projects. The filing also reflected projects moving to base rates proposed to become effective in October 2018, in the above-described general rate case. On November 7, 2018 OTP filed a supplement to the TCR rider update indicating two of the three new projects had been postponed and the roll-in of rider costs to base rates was calculated based on a change to January 1, 2019. The update request was approved by the NDPSC on December 6, 2018 and the updated rates went into effect with bills rendered on or after February 1, 2019 to coincide with the launch of OTP’s new customer information and billing system.

 

OTP filed its annual update to the North Dakota TCR rider on August 30, 2019 seeking recovery of approximately $5.7 million with a proposed effective date of January 1, 2020. The filing included seven new projects, updated costs associated with existing projects, details about the pending MISO ROE complaint, and details about SPP-related expenses. On December 18, 2019 the NDPSC approved the request.

 

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Environmental Cost Recovery Rider—OTP has an ECR rider in North Dakota to recover its North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant Mercury and Air Toxic Standards (MATS) projects. The ECR rider has provided for a return on investment at the level approved in OTP’s preceding general rate case and for recovery of OTP’s North Dakota share of reagent and emission allowance costs.

 

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 August 1, 2017. 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 and 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. A reset of the ECR rate to reflect the effect of the federal corporate tax rate reduction under the TCJA was approved on February 27, 2018, reducing the ECR rate to 5.593%, effective March 1, 2018.

 

Based on the order in the 2017 general rate case, project costs previously being recovered under the ECR rider will be recovered in base rates and reagent and emission allowance costs will be recovered through the energy adjustment rider. The rider was zeroed out at the implementation of final rates on February 1, 2019. On October 22, 2019 the NDPSC approved OTP’s request to decrease the ECR rate to zero effective November 1, 2019 and to include the final tracker balance in OTP’s December 31, 2019 annual update to its North Dakota RRA.

 

Generation Cost Recovery Rider—On May 15, 2019 the NDPSC approved OTP’s request to establish an initial GCR rider rate for recovery of OTP’s North Dakota jurisdictional share of the revenue requirements on its investment in Astoria Station, effective on bills rendered after July 1, 2019.

 

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.

 

General Rates—On April 20, 2018 OTP filed a request with the SDPUC to increase non-fuel rates in South Dakota by approximately $3.3 million annually, or 10.1%, as the first step in a two-step request. Interim rates were effective October 18, 2018. The second step in the request was an additional 1.7% revenue increase to recover costs for Merricourt when the wind generation facility goes into service.

 

The SDPUC approved a partial settlement on March 1, 2019 on all issues of the rate case except ROE. The partial settlement included approval of a phase-in plan to provide for a return on amounts invested in Astoria Station and Merricourt, which addressed the second step of the request for increased rates in South Dakota. The partial settlement also included a moratorium on filing another general rate case in South Dakota until the new generation projects have been in service for a year. The partial settlement also allowed OTP to retain the impact of lower tax rates related to the TCJA from January 1, 2018 through October 17, 2018 resulting in the reversal of an accrued refund liability and recognition of $1.0 million in revenue in the first quarter of 2019. The SDPUC approved the ROE portion of the rate case on May 14, 2019. Pursuant to the May 30, 2019 order, OTP’s allowed ROE was set at 8.75%, resulting in an annual revenue increase of approximately $2.2 million prior to the approval of a June 28, 2019 stipulation agreement discussed below. Final rates went into effect August 1, 2019. An interim rate refund for the lower ROE going back to October 18, 2018 was applied to South Dakota customers’ October 2019 bills.

 

On July 9, 2019 the SDPUC approved a stipulation agreement entered into by OTP with SDPUC staff for the purpose of correcting a mistake in OTP’s rate base in its 2018 general rate case docket. The revenue requirement stated in the SDPUC’s final order dated May 30, 2019 understated the correct amount of OTP's South Dakota share of electric transmission plant in service by approximately $4.1 million. For South Dakota ratemaking purposes, the understatement resulted in an annual revenue requirement shortfall of approximately $341,000. To address the shortfall, the parties agreed that OTP would file an update to its South Dakota TCR rider. OTP was authorized full recovery of the transmission rate base correction reflected in the TCR rider tracker beginning as of the first date of interim rates, October 18, 2018, with the TCR rider rate update going into effect on October 1, 2019. The stipulation agreement had the effect of increasing the non-fuel annual revenue increase in the general rate case to approximately $2.6 million or 7.7%, which is 69% of the adjusted requested annual revenue increase of approximately $3.7 million or 11.1%.

 

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

 

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.

 

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 federal corporate income tax rate under the TCJA. The updated annual revenue requirement request remained at $1.8 million and was approved by the SDPUC on February 28, 2018 with an effective date of March 1, 2018. Effective October 18, 2018, with the implementation of interim rates under South Dakota general rate case proceedings, the TCR rate was decreased to reflect an annual revenue requirement of $1.2 million as a result of certain costs being transitioned to recovery through interim rates and proposed for ongoing recovery in final base rates at the end of the 2018 general rate case.

 

OTP made a supplemental filing for the South Dakota TCR rider on February 1, 2019. In an order dated February 20, 2019 the SDPUC approved the supplemental filing and rates effective March 1, 2019. Two new projects were approved for recovery under the rider: The Lake Norden area transmission upgrade project with a recovery date effective January 1, 2019 and the Big Stone South – Ellendale project with a recovery date effective January 1, 2020.

 

On September 17, 2019 the SDPUC approved OTP’s supplemental TCR rider filing update request to address the transmission rate base correction disclosed in the 2018 general rate case docket with updated rates effective October 1, 2019.

 

OTP filed its annual update to the South Dakota TCR rider on October 31, 2019 seeking recovery of $2.4 million with a proposed effective date of March 1, 2020.

 

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, 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. Effective October 18, 2018, with the implementation of interim rates under South Dakota general rate case proceedings, the ECR rate was decreased to -$0.00075/kwh to refund $0.2 million previously collected under the rider. The ending balance of the South Dakota ECR rider at the conclusion of interim rates was refunded to South Dakota customers along with their October 2019 interim rate refunds.

 

Phase-In Rate Plan Rider—On May 31, 2019 OTP petitioned the SDPUC for approval of its initial rate for the Phase-In Rate Plan Rider as described in OTP’s most recent South Dakota general rate case settlement stipulation and approved by the SDPUC’s order in that rate case. The petition is OTP’s initial filing for the rider to recover, in OTP’s South Dakota jurisdiction, actual and forecasted costs for Astoria Station and Merricourt, and forecasted net benefits associated with additional load growth in the Lake Norden area.

 

On August 21, 2019 the SDPUC approved OTP’s supplemental filing for its South Dakota Phase-In Rate Plan Rider effective September 1, 2019.

 

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, 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.

 

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On May 1, 2018 OTP filed its 2017 South Dakota EEP Status Report, financial incentive, and surcharge adjustment with the SDPUC. The filing requested approval of an incentive of $134,700 and an increase in the EEP surcharge from $0.00138/kwh to $0.00155/kwh effective July 1, 2018. The SDPUC approved the request on June 26, 2018. On September 21, 2018 OTP filed a modification to its 2016-2019 EEP Plan. This modification requested an additional $250,000 annually for three years starting in 2019. The increased budget was requested to pay additional rebates for a large customer that is planning to make significant energy efficiency investments in its expanding facilities. On December 11, 2018, the SDPUC approved the request.

 

On May 1, 2019 OTP filed its 2018 South Dakota EEP Status Report, financial incentive and surcharge adjustment with the SDPUC. The filing requested approval of an incentive of $134,700 and an increase in the EEP surcharge to $0.00164/kwh effective July 1, 2019. The SDPUC approved the request on June 13, 2019. By May 1, 2020 OTP plans to file its 2019 South Dakota EEP Status Report, financial incentive and surcharge adjustment with the SDPUC. The filing will request approval of an incentive of $209,700 and an update of the EEP surcharge with a July 1, 2020 effective date.

 

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 suspension period, subject to ultimate approval by the FERC.

 

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

 

Transmission Tariff ROE Complaints—On November 12, 2013 a group of industrial customers and other stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff. The complainants sought to reduce the 12.38% ROE used in MISO’s transmission rates to a proposed 9.15%. The complaint established a 15-month refund period from November 12, 2013 to February 11, 2015. A non-binding decision by the presiding Administrative Law Judge (ALJ) was issued on December 22, 2015 finding that the MISO transmission owners’ ROE should be 10.32%, and the FERC issued an order on September 28, 2016 setting the base ROE at 10.32%. Several parties requested rehearing of the September 2016 order.

 

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

 

On February 12, 2015 another group of stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff from 12.38% to a proposed 8.67%. This second complaint established a second 15-month refund period from February 12, 2015 to May 11, 2016. The FERC issued an order on June 18, 2015 setting the complaint for hearings before an ALJ, which were held the week of February 16, 2016. A non-binding decision by the presiding ALJ was issued on June 30, 2016 finding that the MISO transmission owners’ ROE should be 9.7%.

 

Based on the probable reduction by the FERC in the ROE component of the MISO Tariff, OTP had a $2.7 million liability on its balance sheet as of December 31, 2016, representing OTP’s best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a reduced ROE. MISO processed the refund for the FERC-ordered reduction in the MISO Tariff allowed ROE for the first 15-month refund period in its February and June 2017 billings. The refund, in combination with a decision in the 2016 Minnesota general rate case that affected the Minnesota TCR rider, resulted in a reduction in OTP’s accrued MISO Tariff ROE refund liability from $2.7 million on December 31, 2016 to $1.6 million as of September 30, 2019.

 

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

 

On November 21, 2019 the FERC adopted a different two-step ROE model and capital asset pricing model to determine whether a jurisdictional public utility’s rate of ROE is just and reasonable under section 206 of the Federal Power Act. Applying the new methodology in complaints against the MISO transmission owners, the FERC determined that the MISO transmission owners’ current base ROE should be 9.88%. The FERC also stated it will use ranges of presumptively just and reasonable ROEs in its analysis of whether existing ROEs have become unjust and unreasonable. This order also implemented the FERC’s revised methodology in the two complaints against the MISO transmission owners’ base ROE. The order granted rehearing on the first complaint, found the existing 12.38% ROE unjust and unreasonable, and directed the MISO transmission owners to adopt a 9.88% ROE effective September 28, 2016, and to provide refunds. The order also dismissed the second complaint and found the record in that proceeding did not support a finding that the 9.88% ROE established in the first complaint proceeding had become unjust and unreasonable.

 

As a result of the FERC granting rehearing on the first complaint and finding the existing 12.38% ROE unjust and unreasonable and directing the MISO transmission owners to adopt a 9.88% ROE, OTP increased its total refund provision related to the ROE complaints from $1.6 million to $3.0 million as of December 31, 2019. The $3.0 million includes provisions for:

 

 

an additional $0.2 million refund related to the first complaint as a result of reducing the reasonable ROE from 10.32%, established in the FERC’s September 28, 2016 refund order, to the newly established 9.88% ROE,

     
 

a $1.3 million refund for the period from September 28, 2016 through December 31, 2019 related to a reduction in the current ROE from 10.82% to 10.38% based on the newly established 9.88% reasonable ROE for the first complaint period plus the 50-point RTO adder granted by the FERC on January 5, 2015, and

     
 

a $1.5 million refund related to the second complaint period in response to requests for rehearing on the FERC’s decision to dismiss the second complaint based on a potential reduction in the reasonable ROE for that period from 12.38% to 9.88% plus the 50-point RTO adder.

 

In response to the FERC’s November 21, 2019 order, the MISO Transmission Owners (including OTP) and others filed requests seeking rehearing of the FERC’s November 21, 2019 order, and a group of parties filed with the U.S. Court of Appeals for the District of Columbia (D.C. Circuit) a protective appeal.

 

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.

 

North American Electric Reliability Corporation (NERC)

 

NERC has regulatory authority spanning the United States, Canada and the northern portion of Baja California, Mexico, and is subject to oversight by the FERC and governmental authorities in Canada. NERC’s 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.

 

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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. MRO’s 2019 audit of OTP has concluded without any material findings.

 

MISO

 

OTP is a member of the MISO. The MISO operates the transmission facilities owned by others and administers energy and generation capacity markets. As the transmission provider and security coordinator for the region, the MISO seeks to optimize the efficiency of the interconnected system, provide 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 including 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 day-ahead and real-time 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. The 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.

 

OTP has been involved in a MISO process re-establishing the right of transmission owners to elect the initial funding of electric transmission projects required to support the interconnection of the generator’s project to the MISO transmission system. In 2018 the D.C. Circuit vacated earlier FERC orders limiting transmission owners’ initial funding of transmission upgrade projects required by generator interconnections. As a result, the MISO Tariff and related agreements establish once again that MISO transmission owners have the option to initially fund the construction of certain qualifying interconnection-related transmission upgrades, sometimes referred to as the “self-fund option” or “self-fund.” Thus, under the self-fund option, the Company, as a MISO transmission owner, can invest the initial capital for such qualifying upgrades and earn a return on and of the capital investment from interconnection customers over the period of the applicable service agreements.

 

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.

 

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 currently participating in a Distributed Generation (DG) Workgroup in Minnesota in a docket established by the MPUC. Distributed energy resources are utility- or customer-owned resources on the distribution grid that can include combined heat and power, solar photovoltaic, wind, battery storage, thermal storage, and demand-response technologies. DG

 

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is the generation of electricity on-site or close to where it is needed in small facilities designed to meet local needs. Advances in technology and economics are contributing to increasing interest in DG in Minnesota and consumer requests for DG will likely grow. OTP is working to accurately identify and quantify the impacts (including costs and values) of DG; this can be difficult because the impacts of DG vary geographically and over time.

 

In 2011 the FERC required some electric transmission providers, including the MISO, to remove from their tariffs a federal right of first refusal to construct transmission facilities selected in a regional transmission plan for purposes of cost allocation. However, state laws allowing rights of first refusal to construct electric transmission infrastructure still exist in Minnesota, North Dakota and South Dakota.

 

OTP and other Minnesota electric transmission owners (collectively, Amici Utilities) are involved in a federal lawsuit and subsequent 8th Circuit appeal filed by LSP Transmission Holdings, LLC (LSP) challenging a Minnesota statute granting incumbent electric transmission owners a right of first refusal to construct new transmission facilities connected to existing facilities. LSP has argued that the Minnesota law violates the dormant Commerce Clause of the U.S. Constitution. A federal district court rejected that argument, and LSP appealed. The Amici Utilities support the Minnesota right of first refusal law as a reasoned policy judgment by the State of Minnesota and thus not subject to challenge under the dormant Commerce Clause. The appeal has been briefed and oral arguments heard, with a decision expected in early 2020.

 

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, 2019 OTP invested approximately $39.5 million in environmental control facilities. The 2020 and 2021 construction budgets include approximately $0.4 million and $1.2 million, respectively, for environmental equipment for existing facilities. Additional expenditures may be required depending on the outcome of various environmental regulations currently under consideration for implementation, and such expenditures could be material.

 

Air Quality - Criteria Pollutants—Pursuant to the Clean Air Act (CAA), the 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 2019.

 

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. Hoot Lake met the CSAPR requirements in 2019 without acquiring additional allowances.

 

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

 

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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. On November 16, 2017 the 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. 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. Based on modeling, in January 2018, the EPA published a final determination of attainment/unclassifiable for the county in which Hoot Lake Plant is located.

 

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. On December 28, 2018 the EPA issued a proposed rule that provides that it is not “appropriate and necessary” to regulate hazardous air pollutants from power plants; however, the EPA declined to propose rescission or repeal of MATS. The proposed rule also addresses the CAA requirement to conduct a risk and technology review for power plants, which concludes no revisions to MATS are warranted.

 

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 CAA establishes a national visibility goal to prevent any future, and remedy any existing, anthropogenic visibility impairment in Class I air quality areas. The EPA’s RHR, as adopted in 1999 and revised most recently on January 10, 2017, implements the CAA’s visibility protection provisions. The RHR requires states to determine the consistent rate of progress over time necessary to attain natural visibility conditions on the twenty percent most anthropogenically impaired days by the year 2064. The first RHR implementation period covered the years 2008-2018 (Round 1) and focused on applying Best Available Retrofit Technology (BART) to certain large stationary sources that were in existence on August 7, 1977 but were not in operation before August 7, 1962. Big Stone Plant was determined to be subject to BART, and therefore 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. Coyote Station is not a BART-eligible source but was ultimately required to install separated over-fire air to reduce NOx emissions as a reasonable progress source.

 

The second RHR implementation period will cover the years 2018-2028 (Round 2), with state implementation plans (SIPs) due to be submitted to the EPA by July 31, 2021 and an anticipated compliance date on or before December 31, 2028. For Round 2, states are required to assess reasonable progress with the RHR and determine what additional emission reductions are appropriate. As part of this assessment, the NDDEQ requested that Coyote Station provide an analysis of technically feasible SO2 and NOx emissions control options, which OTP provided in January 2019.

 

On August 20, 2019 the EPA released a guidance document to assist states with preparation of Round 2 SIPs. The guidance describes eight steps for states to follow, including a step which involves decisions on which emissions control measures are necessary to make reasonable progress. The guidance stresses that a state should generally make control decisions that are reasonably consistent among and across sources within the state.

 

OTP understands the NDDEQ intends to require sources subject to Round 2 reasonable progress determinations, including Coyote Station, to undertake emissions control measures that are reasonably consistent with those required of sources during Round 1. While this process is still in the early stages, if the NDDEQ maintains its initial position, OTP anticipates that significant emissions controls would be required at Coyote Station by December 31, 2028 in order to maintain compliance with the RHR. In light of the costs for such emissions control equipment, there are scenarios where it may not be economically feasible to invest in such equipment and an early retirement of the Coyote Station would therefore be necessary. OTP and the other three co-owners of Coyote Station have been evaluating, and will continue to evaluate, alternative scenarios for the future of Coyote Station as the process with the NDDEQ and other stakeholders evolves. This process could take several years to finalize. The costs related to an early retirement of Coyote Station would be material to OTP and the Company and would be subject to state commission approval for recovery from customers. See note 1 to our consolidated financial statements included in this report on Form 10-K for additional information on Coyote Station.

 

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In order to meet the July 31, 2021 SIP submittal deadline, the NDDEQ has indicated that it will begin drafting a SIP in mid-2020 and provide preliminary control scenarios to the Western Regional Air Partnership in the first quarter of 2020 (for purposes of regional visibility modeling). The NDDEQ expects to provide a proposed SIP for public comment in the first or second quarter of 2021.

 

As discussed above, OTP was required by the MPUC to model a scenario in which Coyote Station is retired in 2028.

 

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 2019 these plants emitted approximately 3.0 million (short) 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 the 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. 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 NSPS under section 111(b) of the CAA that require 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 cleaner fuels such as natural gas. On December 20, 2018 the EPA proposed revisions to the 2015 NSPS; however, the revisions would only impact the standards for new, reconstructed, and modified coal or coal-refuse steam generating units. No changes are being proposed to the NSPS for natural gas combustion turbines.

 

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.

 

The final ACE Rule under CAA Section 111(d) went into effect on September 6, 2019. The rule establishes guidelines for states to use in developing plans to address GHG emissions from existing coal fired power plants. Notably, the final rule establishes heat rate improvements as the best system of emissions reductions for reducing carbon dioxide emissions. Heat rate is a measure of the amount of energy required to generate a unit of electricity. States will establish unit-specific standards of performance that reflect the emission limitation achievable through certain candidate heat-rate improvement technologies. Simultaneously with the final ACE Rule, the EPA took action to repeal the Clean Power Plan, and the EPA also finalized revisions to the timing and content requirements of Section 111(d) state implementation plan submissions. The final ACE Rule does not include any final action regarding New Source Review. States now have until mid-2022 to submit a state implementation plan. Several petitioners have filed challenges to the rule in the D.C. Circuit. On November 22, 2019 the court denied the EPA’s request for expedited review and petitioners’ requests to hold the case in abeyance, pending administrative reconsideration of the ACE Rule.

 

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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 2018 and 2019 the range is $5 to $25 per ton, and the applicable effective date to begin using CO2 costs in resource planning decisions is 2025. Both the range of costs and the effective date are currently under review by the MPUC. A decision is expected by March 31, 2020. It is likely that both the range of costs and the effective date will remain the same for 2020-2021.

 

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. The costs are updated periodically. The most recent 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 61%, 78% and 29%, respectively. OTP’s efforts to increase plant efficiency and add renewable energy to its resource mix have reduced its CO2 intensity. Between 2005 and 2019 OTP decreased its overall system average CO2 emissions intensity by approximately 24%. Further reductions are expected with the planned addition of Merricourt and replacement of Hoot Lake Plant generation with the Astoria Station natural gas-fired generation plant.

 

Conservation: Since 1992 OTP has helped its customers conserve more than 4.7 million cumulative megawatt-hours of electricity, which is roughly equivalent to the amount of electricity that 398,500 average homes would use in a year and represents approximately 389% of the annual energy sales of OTP’s entire residential customer base.

 

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. Minnesota’s legislative mandate requires investor-owned utilities to serve 1.5% of their Minnesota retail electric sales with solar power by 2020. OTP has purchased sufficient SRECs to meet 100% of its 2020 obligation and approximately 70% of its 2021 obligation. OTP is exploring options for constructing a solar project to meet its continuing obligation after 2021.

 

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 or other emissions is unknown at this time, any capital and operating costs incurred for additional pollution control equipment or 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.

 

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Water Quality—The Federal Water Pollution Control Act Amendments of 1972, now known as the Clean Water Act, 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.

 

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. Although the EPA is currently reconsidering portions of the 2015 rule, 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’s NPDES permit was renewed in 2018 with minimal impact 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 a second round in 2018. These studies were followed by the filing of the license application in November 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.