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Otter Tail Power Company Before the

North Dakota Public Service Commission

Application for Authority to Increase Electric Rates in North Dakota

Case No. PU-17-

November 2, 2017

Volume 2B Direct Testimony and Supporting Schedules

1/3

Volume 2B

Index

Otter Tail Power Company

North Dakota General Rate Case Documents

Case No. PU-17-

Volume

1 Notice of Change in Rates – Interim Rate Petition

Index

Filing Letter

Notice of Change in Rates

Alternative Petition for Interim Rates

Interim Supporting Schedules and Workpapers

Summary of Present and Interim Revenue

Interim Tariff Sheets – Legislative

Interim Tariff Sheets – Non-Legislative

2A Direct Testimony and Supporting Schedules

Index

Bruce G. Gerhardson

Policy

Stuart D. Tommerdahl

Capital Projects

Corporate Costs

ADIT Proration

Bryce C. Haugen

Rider Roll in

Gina S. Ice

Jurisdictional and Class Allocators

Class Cost of Service Study

Class Revenue Responsibilities

Tyler A. Akerman

Rate Base

Operating Statement

Capital Budgeting Process

Christine L. Petersen

Budget Process

Operations and Maintenance Expenses

Pension and Post Employment Expenses

2B Direct Testimony and Supporting Schedules

Index

Kevin G. Moug

Financial Soundness

Capital Structure

Cost of Capital

Robert B. Hevert

Return on Equity

Kirk A. Phinney

Big Stone AQCS and Hoot Lake MATS Capital Projects

David G. Prazak

Rate Design



Case No. PU-17-

Volume

2C Direct Testimony and Supporting Schedules

Index

Brian H. Draxten

Sales and Revenue Forecast

Peter E. Wasberg

Employee Compensation

2D Proposed Legislative and Non-Legislative Tariff Sheets

Index

Proposed Tariff Sheets – Legislative

Proposed Tariff Sheets – Non-Legislative

3 Supporting Information

Index

Supporting Information

A. Jurisdictional Financial Summary Schedules

1. Summary of Revenue Requirements – 2018 Test Year

2. Summary of Revenue Requirements – Jurisdictional

B. Rate Base Schedules

1. Rate Base Summary

2. Rate Base Components – 2018 Test Year

3. Rate Base Components - 2018 Test Year to Most Recent General

Rate Case

4. Cash Working Capital

5. Rate Base Adjustments

6. Summary of Approaches and Assumptions Used

7. Rate Base Jurisdictional Allocation Factors

C. Operating Income Schedules

1. Jurisdictional Statement of Operating Income

2. Statement of Operating Income - Jurisdictional

3. Statement of Operating Income – 2018 Test Year

4. Statement of Operating Income – 2018 Test Year to Most Recent

General Rate Case

5. Computation of Federal and State Income Taxes

6. Computation of Deferred Income Taxes

7. Development of Federal and State Income Tax Rates

8. Operating Income Statement Adjustments Schedule

9. Summary of Approaches and Assumptions Used

10. Operating Income Statement Allocation Factors

D. Rate of Return / Cost of Capital Schedules

1. Summary Schedule

2. Cost of Long-Term Debt

3. Cost of Short-Term Debt

4. Common-Equity



Case No. PU-17-

Volume

3 E. Rate Structure and Design Information

1. Test Year 2018 Operating Revenue Summary Comparison

2. Test Year 2018 Operating Revenue Detailed Comparison

3. Class Cost of Service Study

F. Other Supplemental Information

1. Annual Report

2. Gross Revenue Conversion Factor

4A Work Papers

Index

A. 2018 Test Year Workpapers

1. Jurisdictional Cost of Service Study (JCOSS)

2. Class Cost of Service Study (CCOSS)

3. Functionalization

4. Input Summary

5. 2018 Test Year Adjustments

TY-01 – Normalized Plant in Service

TY-02 – Rate Case Expenses

TY-03 – Normalized Plant Outage

TY-04 – Removal of PTC’s

TY-05 – Economic Development

TY-06 – Prorate ADIT

B. 2018 Base Year Workpapers

1. Jurisdictional Cost of Service Study (JCOSS)

2. Functionalization

3. Input Summary

4. Work Papers A-D, ND

C. Interim Cost of Service Study

D. Hevert Cost of Capital Workpapers

4B Lead Lag Study

Index

Lead Lag Study

5 Budget Documentation

Index

O&M Budget Process

Capital Budget Process

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Volume 2B

Direct Testimony and Supporting Schedules

1/5

Volume 2B

Direct Testimony and Supporting Schedules:

Kevin G. Moug

Before the North Dakota Public Service Commission

State of North Dakota

In the Matter of the Application of Otter Tail Power Company

For Authority to Increase Rates for Electric Utility

Service in North Dakota

Case No. PU-17-

Exhibit___

FINANCIAL SOUNDNESS, CAPITAL STRUCTURE

AND COST OF CAPITAL

Direct Testimony and Schedules of

Kevin G. Moug

November 2, 2017

TABLE OF CONTENTS

I. INTRODUCTION AND QUALIFICATIONS...............................................................1

II. PURPOSE AND OVERVIEW OF DIRECT TESTIMONY .........................................1

III DESCRIPTION OF OTP AND OTTER TAIL CORPORATION .................................3

IV. OTP EQUITY RATIO AND CAPITAL STRUCTURE ................................................5

V. OTP RECENT CAPITAL EXPENDITURES AND ONGOING CAPITAL

EXPENDITURES PLANS .............................................................................................8

VI. OTP’S CREDIT RATINGS AND COST OF BORROWING .....................................13

VII. EFFECTS OF OTP’S BUSINESS AND FINANCIAL RISKS ON ITS CREDIT

RATINGS .....................................................................................................................16

VIII. COMPONENTS OF OTP’S PROPOSED CAPITAL STRUCTURE ..........................19

A. LONG-TERM DEBT ....................................................................................... 19

B. SHORT-TERM DEBT ..................................................................................... 20

C. COMMON EQUITY ....................................................................................... 20

XI. CONCLUSION .............................................................................................................22

ATTACHED SCHEDULES

Schedule 1 – Qualifications, Duties and Responsibilities of Kevin G. Moug

Schedule 2 – Proposed Cost of Capital for 2018 Test Year

Schedule 3 – Effect of One-Notch Change in Credit Rating

Schedule 4 – Moody’s Rating Factors for OTP from October 7, 2015 Credit Opinion for OTP

Schedule 5 – Levels and Cost of Long-Term Debt for 2018 Test Year

Schedule 6 – Levels and Cost of Short-Term Debt for 2018 Test Year

Schedule 7 – Common Equity for 2018 Test Year

Schedule 8 – Public and Non-Public Issuances of Common Equity by Otter Tail Corporation

1 Case No. PU-17-

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I. INTRODUCTION AND QUALIFICATIONS 1

Q. PLEASE STATE YOUR NAME AND OCCUPATION. 2

A. My name is Kevin G. Moug. I am the Chief Financial Officer and Senior Vice President 3

of Otter Tail Corporation and the Treasurer for Otter Tail Power Company (OTP). OTP 4

is a wholly owned subsidiary of Otter Tail Corporation. 5

6

Q. PLEASE SUMMARIZE YOU QUALIFICATIONS AND EXPERIENCE. 7

A. I have been Senior Vice President and Chief Financial Officer of Otter Tail Corporation 8

since 2001. A copy of my resume is included as Exhibit___(KGM-1), Schedule 1. 9

II. PURPOSE AND OVERVIEW OF DIRECT TESTIMONY 10

Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY? 11

A. The purpose of my Direct Testimony is to demonstrate the reasonableness of OTP’s 12

2018 Test Year capital structure and costs of Long-Term Debt (LTD), Short-Term Debt 13

(STD), and the overall Rate of Return (ROR) for the 2018 Test Year. I will discuss the 14

financial impacts and scope of OTP’s recent capital expenditures and OTP’s estimated 15

future capital expenditures. I will also discuss the importance of the decisions in this 16

proceeding, including a reasonable Return on Equity (ROE) to: (1) OTP strong credit 17

ratings; (2) the long-term cost of completing OTP’s capital expenditures plans; and (3) 18

OTP’s ability to attract capital and provide service at a fair and reasonable cost. 19

20

Q. PLEASE PROVIDE A BRIEF OVERVIEW OF YOUR DIRECT TESTIMONY. 21

A. OTP’s 2018 Test Year capital structure, costs of OTP’s LTD, STD and OTP’s ROR are 22

reasonable and should be adopted for determining OTP’s rates. OTP has been engaged 23

in an extensive capital expenditure program, involving capital expenditures of 24

approximately $687 million from 2012 through 2016.1 OTP required external sources 25

1 Otter Tail Corporation Form 10-K for year ended December 31, 2014, p 50 and Otter Tail Corporation Form 10-

K for year ended December 31, 2016, p 49.

2 Case No. PU-17-

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of debt and equity capital to fund those investments, in addition to substantial amounts 1

of internally generated equity. OTP’s extensive capital expenditures plan is expected 2

to continue from 2017 through 2021 with an additional approximately $862 million of 3

further capital expenditures by OTP.2 Completion of OTP’s capital expenditures plan 4

will also require external sources of equity and debt capital in addition to internally 5

generated equity. 6

The Commission’s decisions in this proceeding, including the Commission’s 7

decisions with respect to OTP’s capital structure and ROE, may significantly affect 8

OTP’s financial outlook and OTP’s senior unsecured credit ratings. The credit ratings 9

in effect when OTP places LTD to help finance the rest of its capital expenditures plan 10

will affect OTP’s cost of service for 10 to 30 years. As a result, the Commission’s 11

decisions in this proceeding may affect OTP’s cost of service for a 10 to 30 year period. 12

OTP recommends an overall ROR of 7.97 percent. This ROR is based on the 13

capital components and related costs summarized in Table 1 below and shown on 14

attached Exhibit ___(KMG-1), Schedule 2: 15

16

Table 1 17

Recommended 2018 Test Year Capital Structure and ROR 18

19

Component Percentage Cost Weighted Cost

Long-Term Debt 46.01% 5.43% 2.50%

Short-Term Debt 1.49% 4.02% 0.06%

Common Equity 52.50% 10.30% 5.41%

Total 100.0% 7.97%

20

The proposed 7.97 percent ROR is 64 basis points lower than the 8.61 percent 21

ROR approved by the Commission for OTP’s 2007 Test Year in OTP’s last North 22

Dakota general rate case, Case No. PU-08-862. The proposed 10.30 percent ROE is 45 23

basis points lower than the 10.75 percent ROE approved by the Commission for OTP’s 24

2007 Test Year in OTP’s last North Dakota general rate case. 25

26

2 Otter Tail Corporation Form 10-K for year ended December 31, 2016, p 49.

3 Case No. PU-17-

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Q. HOW IS THE BALANCE OF YOUR DIRECT TESTIMONY ORGANIZED? 1

A. Section III provides a brief description of the financial characteristics of OTP and Otter 2

Tail Corporation. Section IV compares the equity ratio in OTP’s proposed capital 3

structure to the equity ratios of other utilities, including equity ratios recently approved 4

by the Commission, and explains that OTP’s capital structure is an actual capital 5

structure recognized and relied on by lenders and investors. Section V describes our 6

historic and planned financing and capital expenditures and credit ratings and explains 7

the importance of OTP’s regulatory environment and investor perceptions to our long 8

term capital costs, and the impacts on our capital expenditures plans and costs. Section 9

VI explains OTP’s credit ratings and their effect on the costs of borrowing. Section VII 10

explains the effects of business and financial risks on OTP’s credit ratings. Section VIII 11

provides a detailed description of the components of OTP’s capital structure and costs 12

of LTD and STD for the 2018 Test Year. Section IX includes my conclusions and 13

recommendations. 14

15

Q. HAS OTP ALSO PROVIDED SUPPLEMENTAL COST OF CAPITAL 16

INFORMATION? 17

A. Yes. Information is included in the Supporting Information in Volume 3, Rate of 18

Return/Cost of Capital Schedules Tab, Schedules D-1 through D-4. 19

III DESCRIPTION OF OTP AND OTTER TAIL CORPORATION 20

Q. PLEASE PROVIDE A SUMMARY DESCRIPTION OF OTP. 21

A. OTP is a wholly owned subsidiary of Otter Tail Corporation and is a separate legal 22

entity from Otter Tail Corporation. OTP issues its own LTD and has its own credit 23

facility with banks that provide OTP’s short-term borrowing. Otter Tail Corporation 24

owns all of OTP’s outstanding common stock. There are no loans outstanding between 25

OTP and Otter Tail Corporation. Otter Tail Corporation is publicly held and traded on 26

the NASDAQ. OTP is Otter Tail Corporation’s only utility operating company. 27

28

4 Case No. PU-17-

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Q. HAS OTP ALWAYS BEEN A SEPARATE LEGAL ENTITY? 1

A. No. As I explained in my Direct Testimony in OTP’s last North Dakota rate case, the 2

implementation of a holding company structure (with Otter Tail Corporation as the 3

holding company and OTP as a subsidiary) had not been completed at the time of the 4

filing of OTP’s last North Dakota rate case. The holding company structure was 5

implemented as of July 1, 2009, at which time OTP became a separate legal entity and 6

subsidiary of Otter Tail Corporation. 7

8

Q. HOW DO OTTER TAIL CORPORATION AND OTP COMPARE IN SIZE TO 9

OTHER ELECTRIC UTILITIES? 10

A. Otter Tail Corporation is the second smallest publicly traded investor owned utility in 11

the United States,3 and it is much smaller than the average of publicly traded investor 12

owned utilities. Otter Tail Corporation’s total market capitalization is $1.7 billion4 13

while the average total market capitalization of publicly traded investor owned utilities 14

is $15.0 billion.5 Otter Tail Corporation is also much smaller than the other publicly 15

traded investor owned utilities doing business in North Dakota, with MDU having a 16

market capitalization of $5.1 billion6 and Xcel Energy having a market capitalization of 17

$24.1 billion.7 18

19

Q. HOW DOES OTTER TAIL CORPORATION’S COMMON STOCK OWNERSHIP 20

PROFILE COMPARE TO OTHER ELECTRIC UTILITIES? 21

A. Otter Tail Corporation has a far lower level of institutional ownership of its common 22

stock. As explained by OTP witness Mr. Robert B. Hevert, Otter Tail Corporation has 23

51.94 percent institutional ownership while the average institutional ownership of the 24

3http://www.eei.org/resourcesandmedia/industrydataanalysis/industryfinancialanalysis/QtrlyFinancialUpdates/D

ocuments/QFU_Stock/2017_Q1_Stock_Performance.xlsx. 4 http://www.nasdaq.com/symbol/ottr 9-28-17. 5 EEI 2016 Financial Review Page 75, total industry $659,845 million divided by 44 utilities

http://www.eei.org/resourcesandmedia/industrydataanalysis/industryfinancialanalysis/finreview/Documents/Fina

ncialReview_2016.pdf. 6 http://www.nasdaq.com/symbol/mdu 9-28-17. 7 http://www.nasdaq.com/symbol/xel 9-28-17.

http://www.eei.org/resourcesandmedia/industrydataanalysis/industryfinancialanalysis/QtrlyFinancialUpdates/Documents/QFU_Stock/2017_Q1_Stock_Performance.xlsx

http://www.eei.org/resourcesandmedia/industrydataanalysis/industryfinancialanalysis/QtrlyFinancialUpdates/Documents/QFU_Stock/2017_Q1_Stock_Performance.xlsx

http://www.eei.org/resourcesandmedia/industrydataanalysis/industryfinancialanalysis/finreview/Documents/FinancialReview_2016.pdf

http://www.eei.org/resourcesandmedia/industrydataanalysis/industryfinancialanalysis/finreview/Documents/FinancialReview_2016.pdf

http://www.nasdaq.com/symbol/xel

5 Case No. PU-17-

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electric utilities in Mr. Hevert’s comparable group is approximately 86.89 percent, the 1

institutional ownership of MDU is 66.23 percent, and the institutional ownership of Xcel 2

Energy is 77.71 percent. 3

4

Q. IS THE LOWER LEVEL OF INSTITUTIONAL OWNERSHIP SIGNIFICANT? 5

A. Yes. As Mr. Hevert will further explain, institutional investors are an important and 6

efficient source of equity capital. Otter Tail Corporation’s significantly lower level of 7

institutional ownership is related its high level of retail ownership and the impact that 8

has on its average daily trading volume of approximately 100,000 shares a day. This 9

creates a challenge for an institutional investor’s ability to acquire or sell the large 10

blocks of stock that are typically held by an institutional investor. This low level of 11

liquidity in Otter Tail Corporation’s common stock indicates there is a lower level of 12

equity capital available (from institutional demand) to Otter Tail Corporation and OTP. 13

14

Q. HOW DOES OTTER TAIL CORPORATION’S TRADING VOLUME COMPARE 15

TO OTHER ELECTRIC UTILITIES? 16

A. Otter Tail Corporation also has a far lower daily trading volume than other utilities. The 17

daily trading volume of Otter Tail Corporation shares is far below the average daily 18

trading volume of Mr. Evert’s comparable group and the levels of MDU and Xcel 19

Energy, as described in Mr. Hevert’s Direct Testimony. This has an adverse effect on 20

liquidity for owners of Otter Tail Corporation common stock and implications for OTP’s 21

cost of equity, as Mr. Hevert also explains in his Direct Testimony. 22

IV. OTP EQUITY RATIO AND CAPITAL STRUCTURE 23

Q. PLEASE SUMMARIZE THE CHARACTERISTICS OF OTP’S EQUITY RATIO 24

AND CAPITAL STRUCTURE. 25

A. OTP’s equity ratio and capital structure are comparable to other utilities in Mr. Hevert’s 26

comparable group. OTP’s capital structure is an actual, not hypothetical, capital 27

structure that is very significant to rating agencies and investors. OTP’s capital structure 28

provides significant benefits to customers. 29

6 Case No. PU-17-

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Q. HOW DOES OTP’S PROPOSED 52.5 PERCENT EQUITY RATIO COMPARE TO 1

EQUITY RATIOS OF MR. HEVERT’S COMPARABLE GROUP COMPANIES? 2

A. As Mr. Hevert explains, OTP’s equity ratio is well within the range of the equity ratios 3

of companies in his comparable group. Mr. Hevert notes the mean equity ratio from the 4

operating utilities in his comparable group is 52.16 percent, the median equity ratio is 5

52.59 percent, and the range is from 44.59 percent to 59.14 percent. OTP’s proposed 6

52.5 percent equity ratio is well within that range and is within 34 basis points of the 7

mean and 9 basis points below the median. 8

9

Q. HOW DOES OTP’S PROPOSED EQUITY RATIO COMPARE TO EQUITY RATIOS 10

RECENTLY APPROVED BY THE COMMISSION? 11

A. OTP’s proposed 52.5 percent equity ratio is comparable to equity ratios recently 12

approved by the Commission for other North Dakota electric utilities, including: (1) the 13

52.56 percent equity ratio approved in Xcel Energy’s 2012 rate case;8 and (2) the 51.4 14

percent common equity approved in MDU’s 2016 rate case.9 15

16

Q. WHY IS OTP’S CAPITAL STRUCTURE AN ACTUAL CAPITAL STRUCTURE? 17

A. OTP’s capital structure is an actual capital structure as a result of OTP being a legally 18

separate Minnesota corporation that is a wholly-owned subsidiary of Otter Tail 19

Corporation. As a result of being a separate legal entity, OTP has a separate capital 20

structure and a separate short-term credit facility, and issues separate LTD securities. 21

22

Q. HOW DO LENDORS AND INVESTORS RECOGNIZE AND RELY ON OTP’S 23

SEPARATE CAPITAL STRUCTURE? 24

A. Because OTP is a separate legal entity with a separate credit facility and separately 25

issued LTD (in private placements to institutional investors): (1) banks and investors 26

recognize the importance of OTP’s separate capital structure; and (2) OTP’s capital 27

structure is subject to capital market scrutiny from those banks and institutional 28

8 Case No. PU-12-813. 9 Case No. PU-16-666.

7 Case No. PU-17-

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investors. OTP also has separate debt ratings from Moody’s Investors Services 1

(Moody’s), Standard & Poor’s (S&P) and Fitch Ratings (Fitch). As a result, Moody’s, 2

S&P and Fitch also scrutinize OTP and its capital structure. 3

4

Q. DO OTP’S CAPITAL STRUCTURE AND EQUITY RATIO PROVIDE CUSTOMER 5

BENEFITS? 6

A. Yes. OTP’s capital structure and equity ratio have contributed to OTP’s ability to 7

simultaneously finance its significant capital expenditures at reasonable costs, 10 and 8

reduce its cost of LTD. We also expect that OTP’s capital structure and equity ratio 9

will also facilitate OTP’s completion of its capital expenditures over the next 5 years. 10

All of these result in benefits to OTP customers. 11

12

Q. HOW DOES OTP’S PROPOSED EQUITY RATIO COMPARE TO OTP’S PRIOR 13

EQUITY RATIOS AND PROJECTED EQUITY RATIOS? 14

A. OTP’s proposed 52.5 percent equity ratio is consistent with OTP’s actual equity ratios 15

over prior years and consistent with OTP’s projected equity ratios of future years, as 16

shown in Figure 1 below: 17

18

Figure 1 19

OTP Equity Ratios (2013-2021) 20

21

22 23

10 Otter Tail Corporation 2016 Form 10(K), p. 50.

51.8%

52.7% 52.7% 52.5%

52.2% 52.0%

53.1%

51.0%

52.0%

53.0%

54.0%

Dec-15 Dec-16 Dec-17 Dec-18 Dec-19 Dec-20 Dec-21

13 Month Average - Equity Ratio2015-2021

8 Case No. PU-17-

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OTP’s projected actual equity ratios are somewhat higher than OTP’s prior actual equity 1

ratios. 2

3

Q. WHY ARE OTP’S PROJECTED EQUITY RATIOS SOMEWHAT HIGHER THAN 4

ITS PRIOR ACTUAL EQUITY RATIOS? 5

A. OTP has been engaged in a substantial capital expenditures program that began in 2012 6

and is projected to continue through 2017 – 2020 and beyond. OTP has determined it 7

is prudent to strengthen its balance sheet in order to support it capital expenditures plan 8

and help maintain strong senior unsecured credit ratings. 9

V. OTP RECENT CAPITAL EXPENDITURES AND ONGOING 10

CAPITAL EXPENDITURES PLANS 11

Q. PLEASE SUMMARIZE OTP’S RECENT CAPITAL EXPENDITURES. 12

A. OTP’s capital expenditures increased significantly in 2012 and have remained very 13

substantial since then as shown on Table 2 below: 14

15

Table 2 16

OTP Capital Expenditures 2012 – 2016 11 17

18

Year Capital Expenditure

($ millions)

2012 $102

2013 $150

2014 $149

2015 $136

2016 $150

Total $687

Average $137

19

OTP witness Mr. Bruce Gerhardson provides further information regarding the various 20

projects that were included in these capital expenditures. 21

11 Otter Tail Corporation Form 10-K for year ended December 31, 2014, p 50 and Otter Tail Corporation Form

10-K for year ended December 31, 2016, p 49.

9 Case No. PU-17-

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Q. HOW DO THESE PRIOR EXPENDITURES COMPARE TO OTP’S NET PLANT IN 1

SERVICE WHEN THEY BEGAN? 2

A. OTP’s net electric plant in service as of December 31, 2011 was approximately $922 3

million.12 OTP’s $687 million investment during 2012-2016 represented approximately 4

75 percent of its net electric plant as of December 31, 2011. 5

6

Q. HOW HAS OTP PROVIDED LONG-TERM FUNDING FOR ITS 2012-2016 7

CAPITAL EXPENDITURES? 8

A. OTP provided long-term funding for its $687 million of capital expenditures in 2012-9

2016 with a combination of approximately $150 million of LTD issued by OTP, 10

earnings retained by OTP, and equity infusions from Otter Tail Corporation. Earnings 11

retained by OTP and equity infusions from Otter Tail Corporation increased OTP’s 12

equity balance from $330 million at year end 2011 to $562 million at year end 2016. 13

14

Q. HAVE YOU COMPARED OTP’S NET REINVESTMENT LEVELS TO OTP’S NET 15

INCOME LEVELS FOR 2012 THROUGH 2016? 16

A. Yes. From 2012-2016, almost 92 percent of OTP’s net income has been reinvested, 17

either as retained earnings or added infusions of equity from Otter Tail Corporation, as 18

shown in Table 3 below: 19

20

12 Otter Tail Corporation, 2011 Form 10-K, p. 115.

10 Case No. PU-17-

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Table 3 1

Net Reinvestment of OTP Earnings 2

($ millions) 3

OTP Net

Income

Net Reinvestment

(Retained Earnings + Otter Tail

Corporation equity infusions)

Effective rate of

reinvestment

2012 $38.5 $24.1 62.6%

2013 $38.2 $26.1 68.3%

2014 $43.7 $52.3 119.7%

2015 $47.6 $52.8 110.9%

2016 $49.8 $48.2 96.8%

Total $217.8 $203.5 91.7%

Average $43.6 $40.7 91.7%

4

Q. WERE THE LEVELS OF THESE NET REINVESTMENTS RELATED TO OTP’S 5

CAPITAL EXPENDITURES DURING THE 2012-2016 TIME PERIOD? 6

A. Yes. These equity reinvestments provided needed funding for OTP’s capital 7

expenditures and were also needed essential to maintain a balance of debt and equity 8

and a balanced capital structure for OTP. 9

10

Q. HAVE OTP’S CAPITAL EXPENDITURES AND RELATED FUNDING BEEN A 11

SIGNIFICANT PART OF OTTER TAIL CORPORATION’S STRATEGY? 12

A. Yes. OTP is Otter Tail Corporation’s largest business, and Otter Tail Corporation has 13

focused on OTP as two platforms, electric and manufacturing. That focus on OTP has 14

been successful, but $862 million of planned capital expenditures for OTP remains for 15

the five-year period of 2017-2021, as shown in Table 4 below:13 16

13 Otter Tail Corporation Form 10-K for year ended December 31, 2016, p 49.

11 Case No. PU-17-

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Table 4 1

Projected OTP Capital Expenditures 2017 – 202114 2

3

Year Capital Expenditure

($ millions)

2017 $135

2018 $173

2019 $346

2020 $130

2021 $78

Total $862

Average $172

4

Q. HOW DO THESE CAPITAL EXPENDITURES COMPARE TO OTHER UTILITIES? 5

A. As Mr. Hevert notes in his Direct Testimony, OTP’s planned capital expenditure level 6

is within one percent of the highest company in his proxy group, as shown in Chart 1: 7

8

Chart 1: 9

Comparison of OTP and Hevert Comparable Group 10

Planned Capital Expenditures 11

(As a percentage of net plant) 12

13

14 Otter Tail Corporation Form 10-K for year ended December 31, 2014, p 50 and Otter Tail Corporation Form

10-K for year ended December 31, 2016, p 49.

12 Case No. PU-17-

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As Mr. Hevert also notes, OTP’s projected capital expenditures level is also higher than 1

Northern States Power Company’s (at 49 percent) and higher than MDU’s (at 56 2

percent).15 3

4

Q. WILL THE ROE AND CAPITAL STRUCTURE AUTHORIZED IN THIS 5

PROCEEDING HAVE AN EFFECT ON FINANCING OF OTP’S CAPITAL 6

EXPENDITURE PLANS? 7

A. Yes. The ROE and capital structure authorized in this proceeding will have a substantial 8

impact on OTP’s financing of its capital expenditures plan in two important ways. First, 9

the ROE and capital structure will have a direct impact on the level of OTP’s authorized 10

earnings. The level of authorized earnings will, in turn, directly impact OTP’s ability 11

to fund capital expenditures with internally generated retained earnings. 12

As I explained earlier in my Direct Testimony, OTP has reinvested almost 92 13

percent of its earnings in the 2012-2016 period of its previous substantial capital 14

expenditures. Previously authorized ROEs have had a significant effect on the 15

availability of these internally generated retained earnings, which have been a 16

significant source of funding for OTP’s capital expenditures, and are expected to remain 17

a significant source of funding for the remainder of OTP’s capital expenditures plan. 18

Second, the authorized ROE and capital structure will have a significant effect 19

on the perceptions of rating agencies and investors, which is likely to be heightened by 20

the scale of the OTP capital expenditures plan. These perceptions could have a 21

substantial impact on credit ratings and the availability and external debt and equity 22

capital that will be needed to complete OTP’s capital expenditures plans. Later in my 23

Direct Testimony, I will also discuss plans for issuance of new LTD and external 24

sources of equity in the 2017-2021 time period during which OTP will be completing 25

its capital expenditures plan. 26

15 Hevert Direct Testimony, Section VI, Capital Expenditures.

13 Case No. PU-17-

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VI. OTP’S CREDIT RATINGS AND COST OF BORROWING 1

Q. HOW DOES OTP ARRANGE ITS LTD FINANCING? 2

A. OTP raises the LTD needed for financing its operations, including its capital 3

expenditures, through private placements with institutional investors rather than through 4

public issuances of LTD. OTP uses private placements because the size of its debt 5

offerings attract better interest in the private placement market from fixed income 6

investors as well as not incurring the added costs of issuing public debt and having to 7

incur an additional borrowing cost for a small size premium that would exist in the 8

public debt market. OTP’s private placements of LTD are for terms of 10 to 30 years. 9

10

Q. DOES OTP’S USE OF PRIVATE PLACEMENTS FOR LTD MAKE CREDIT 11

RATINGS UNIMPORTANT TO OTP AND OTP’S CUSTOMERS? 12

A. No. Credit ratings remain very important to OTP and OTP customers because 13

institutional investors use these ratings, along with their own analysis, in making 14

decisions regarding whether to invest in OTP’s LTD debt and the interest rate to require 15

in order to make an investment in OTP’s LTD. 16

17

Q. WHAT ARE OTP’S CURRENT CREDIT RATINGS? 18

A. OTP’s current credit ratings are set out in Table 5 below: 19

20

Table 5 21

OTP Credit Ratings16 22

23

Moody’s Fitch S&P

Corporate Credit/Long term

issuer Default Rating

A3 BBB BBB

Outlook Stable Stable Positive

24

25

16 Moody’s August 9, 2017 Credit Opinion for OTP (“Moody’s 2017”); Fitch, August 17, 2017 (“Fitch 2017”);

S&P August 21, 2017 Ratings for OTP and Otter Tail Corporation (“S&P 2017”).

14 Case No. PU-17-

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The “Positive” outlook from S&P reflects a change in outlook from Stable on August 1

21, 2017.17 2

3

Q. HAVE YOU ESTIMATED THE EFFECTS ON LTD INTEREST RATES OF A ONE-4

NOTCH CHANGE IN OTP’S CREDIT RATING? 5

A. Yes. Based on recent history, a one-notch change by Moody’s (from OTP’s current A3 6

rating to Baa1) would lead to a 25 to 40 basis point change in interest rates, with an 7

increase in the Credit Rating reducing interest rates and a decrease in the Credit Rating 8

increasing interest rates. This change in interest rates would not apply to LTD that is 9

now outstanding, but would apply to LTD that would be placed when the change in the 10

Credit Rating became effective. 11

12

Q. WOULD A CREDIT RATING CHANGE ALSO HAVE AN EFFECT ON THE 13

COSTS OF OTP’S SHORT TERM DEBT? 14

A. Yes. OTP’s STD credit agreement contains a defined pricing grid. A one notch 15

downgrade in OTP’s credit ratings would result in higher short-term borrowing costs of 16

25 basis points under the current credit agreement. 17

18

Q. DOES OTP PLAN TO ISSUE LTD DURING THE 2016-2021 TIME PERIOD IN 19

ORDER TO COMPLETE ITS CAPITAL EXPENDITURE PLAN? 20

A. Yes. In order to maintain an appropriate balance of debt and equity as OTP completes 21

its capital expenditure plan, OTP also plans to issue approximately $300 million of LTD 22

in the 2017-2021 timeframe. The planned LTD issuances by OTP are directly related 23

to OTP’s planned capital expenditures in 2017 through 2021. The current financing 24

plan shows these expected debt issuances in Table 6 below: 25

26

17 S&P 2017, p. 1.

15 Case No. PU-17-

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Table 6 1

OTP Expected LTD Issuances 2

($ millions) 3

4

Year 2017 2018 2019 2020 2021 Total

Expected debt

issuances

$0 $100 $100 $0 $100 $300

5

When the actual interest rate for the 2018 issuance is determined, we will inform the 6

parties to this proceeding. 7

8

Q. HAVE YOU ESTIMATED THE POTENTIAL EFFECTS ON OTP’S INTEREST 9

EXPENSES IF THERE IS A RATING CHANGE? 10

A. Yes. Table 7 below summarizes the effects on OTP total interest expenses per $200 11

million of LTD that may be issued if there is a one-notch downgrade and interest rates 12

increase by 25 and 40 basis points, with that LTD outstanding from 10 years to 30 years. 13

Those calculations are shown on Exhibit___(KGM-2), Schedule 3. 14

15

Table 7 16

Effect of 25 basis point interest rate increase on 17

$250 million issuance of LTD 18

19

OTP Total

@ 25 basis points

OTP Total

@ 40 basis points

Annual increase $625,000 $1,000,000

Cumulative increase over 10 years $6,250,000 $10,000,000



20

Q. WILL THE CHANGE IN THE COST OF THIS ADDITIONAL LTD AFFECT LONG 21

TERM COSTS OF SERVICE? 22

A. Yes. The terms of the expected $300 million in newly issued debt are expected to range 23

from 10 to 30 years. As a result, these costs will remain part of the costs of service for 24

a substantial period of time. 25

16 Case No. PU-17-

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VII. EFFECTS OF OTP’S BUSINESS AND FINANCIAL RISKS ON ITS 1

CREDIT RATINGS 2

Q. DO RATING AGENCIES CONSIDER BOTH BUSINESS RISKS AND FINANCIAL 3

METRICS IN ESTABLISHING A UTILITY’S CREDIT RATINGS? 4

A. Yes. Credit rating agencies assess, and assign ratings to, both a utility’s: (1) Business 5

Risk; and (2) Financial Risk when making rating determinations. A utility’s Financial 6

Risk is based on credit metrics. Business Risk and Financial Risk are considered 7

together when a credit rating agency determines a utility’s credit rating and each 8

category of risk affects the level of risk that the rating agency requires of the other 9

category in order to maintain a given rating. For example, the required Financial Risk 10

becomes more stringent (i.e. the credit metrics must be better) to maintain a given credit 11

rating as the utility’s Business Risk rating decreases (indicating higher level business 12

risk). 13

14

Q. WHAT ARE THE COMPONENTS THAT ARE CONSIDERED IN DETERMINING 15

A UTILITY’S BUSINESS RISK? 16

A. A utility’s business risk considers a number of factors, including: (1) the regulatory 17

environment in which the utility provides service, including the timing and ability to 18

recover of investment; (2) the risk of environmental and other changes that may affect 19

the utility’s costs and ability to provide service; (3) the size and diversity of a utility’s 20

customer base; and (4) the economic strength of the utility’s service area. Because a 21

utility’s ability to set rates and recover its costs is so dependent on cost of service 22

regulation, a utility’s regulatory environment is a key element of its business risk rating. 23

The scope of a utility’s investments is also a very significant factor in assessing a 24

utility’s risk. 25

26

Q. HAVE THE RATING AGENCIES ADDRESSED THE LARGE SCOPE OF OTP’S 27

CAPITAL EXPENDITURES? 28

A. Yes. Moody’s, Fitch, and S&P have each explicitly recognized the large scope of OTP’s 29

capital expenditure program. Moody’s has noted “OTP’s current five-year capital 30

17 Case No. PU-17-

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investment program is approximately $862 million.”18 Fitch similarly noted the “Large 1

capex program at OTP totaling $862 million through 2021.”19 S&P stated it could revise 2

the outlook downward from positive to stable “if rising capital spending continues 3

without adequate and timely recovery of costs.”20 Rating agencies (and the capital 4

markets) are particularly aware of the need for regulatory decisions that support the 5

recovery of capital expenditures during periods of substantial expenditures 6

7

Q. HAVE THE RATING AGENCIES ADDRESSED THE RELATIONSHIP OF 8

REGULATORY DECISIONS TO OTP’S CAPEX PROGRAM? 9

A. Yes. The importance and connection of supportive regulatory decisions to OTP’s 10

capital expenditures plan has been explicitly discussed. Moody’s recently said: 11

OTP’s rating outlook reflects Moody’s expectation that the regulatory 12

environments for OTP remain credit supportive and that OTP will 13

continue to produce predictable and stable cash flows. 14

*** 15

For OTP, a rating downgrade is possible if its regulatory support wanes 16

and becomes less credit supportive such that regulatory lag increases or 17

cost recovery is negatively affected.21 18

19

Fitch has similarly said: 20

Otter Tail Power’s (OTP) Stable Outlook reflects that regulated nature 21

of its electric utility operations and a balanced regulatory environment 22

across its three state jurisdictions …..22 23

24

S&P has noted the Positive outlook may not lead to an upgrade of the credit 25

rating: 26

[I]f rising capital spending continues without adequate and timely 27

recovery of costs.”23 28

29

Q. HOW IMPORTANT ARE REGULATORY AND COST RECOVERY IN RELATION 30

TO FINANCIAL METRICS IN DETERMINING OTP’S RATINGS? 31

18 Moody’s 2017, p. 4. 19 Fitch 2017, p. 4. 20 S&P 2017, p. 2. 21 Moody’s 2017, pp 1, 2. 22 Fitch 2017, p 2. 23 S&P 2017, p. 2.

18 Case No. PU-17-

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A. Regulatory and cost recovery appear to be as important as financial metrics in 1

determining OTP’s credit ratings. Exhibit___(KGM-1), Schedule 4 is a copy of 2

Moody’s Rating Factors for OTP from the August 9, 2017 Credit Opinion for OTP. The 3

August 9, 2017 Credit Opinion shows the four factors Moody’s considered in its rating 4

decisions for OTP along with the weightings given to each. Regulatory Framework was 5

weighted 25 percent. Ability to Recover Costs and Earn Returns (which reflect 6

regulation) was weighted 25 percent. Diversification was weighted 10 percent. 7

Financial Strength was weighted 40 percent.24 The impact of regulation and resulting 8

ability to recover costs and earn returns accounted for 50 percent of the ratings. 9

10

Q. WILL THE ROE AUTHORIZED IN THIS PROCEEDING BE IMPORTANT TO 11

OTP’S CREDIT RATINGS, INVESTORS, AND COST OF CAPITAL? 12

A. Yes. While ROE is certainly not the only factor considered in the evaluation of a rate 13

case or a potential investment in a utility doing business in a particular state, it is easy 14

for rating agencies and investors to identify and compare ROEs to expectations and to 15

ROEs from other jurisdictions. The ROEs are also regarded as an indicator of regulatory 16

support or the lack of support. Moody’s recently noted “A rating upgrade could be 17

considered if OTP’s regulatory environments improved materially, further shortening 18

regulatory lag and improving rates and returns.”25 19

20

Q. IS OTP’S CAPITAL STRUCTURE IMPORTANT TO OTP’S RATING AGENCIES, 21

INVESTORS, AND COST OF CAPITAL? 22

A. Yes. A utility’s capital structure provides the long-term structural foundation for the 23

financing required to support its operations and capital investment plans. It is 24

particularly important when a utility is making significant capital expenditures, as 25

reflected in Fitch’s recent Rating Report noting that: 26

24 Moody’s 2017, p. 5. 25 Moody’s 2017, p. 2.

19 Case No. PU-17-

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Fitch expects … that future funding needs will be met by a balanced mix of 1

debt and equity and that [Otter Tail Corporation] will downstream 2

additional equity as needed to support the balanced capital structure.26 3

4

Q. WHAT IS YOUR CONCLUSION? 5

A. When a utility is engaged in an extensive capital expenditure program, a decision in a 6

single rate case can have adverse effects that last long beyond the term of the rates set 7

in that case. This is true in the case of OTP at this time, which continues to be engaged 8

in an extensive capital expenditure program that will involve capital expenditures of 9

approximately $862 million in the 2017-2021 timeframe. As a result, OTP requests the 10

Commission take these facts into consideration when determining where to set the ROE 11

for OTP within the range of reasonable ROEs. 12

VIII. COMPONENTS OF OTP’s PROPOSED CAPITAL STRUCTURE 13

Q. WHAT ARE THE COMPONENTS OF OTP’S CAPITAL STRUCTURE? 14

A. OTP’s capital structure consists of LTD, STD and common equity. 15

A. LONG-TERM DEBT 16

Q. WHAT IS THE AMOUNT AND COST OF OTP’S LTD IN THE PROPOSED 17

CAPITAL STRUCTURE FOR THE 2018 TEST YEAR? 18

A. The 13-month average of OTP’s LTD is $492.7 million and the cost of LTD is 5.43 19

percent, as shown on Exhibit___(KGM-1), Schedule 5. 20

21

Q. HOW DO THE AMOUNT AND THE COST OF OTP’S 2018 LTD COMPARE TO 22

OTP’S LAST RATE CASE? 23

A. Since OTP’s last rate case, LTD has increased by approximately $307.0 million and the 24

cost has decreased by approximately 90 basis points as shown in Table 8 below: 25

26

26 Fitch 2017, p.3.

20 Case No. PU-17-

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Table 8 1

OTP LTD 2008 Rate Case and Current Case 2

($ millions) 3

2008 Rate Case Current Rate Case Difference

Amount $185.7 $492.7 $307.0

Cost 6.33% 5.43% (0.90)%

4

B. SHORT-TERM DEBT 5

Q. WHAT IS THE AMOUNT OF OTP’S STD IN THE PROPOSED CAPITAL 6

STRUCTURE FOR THE 2018 TEST YEAR? 7

A. The 13-month average of OTP’s STD is $15.98 million and the cost of STD is 4.02 8

percent, as shown on Exhibit___(KGM-1), Schedule 6. 9

10

Q. HOW WAS THE COST OF STD DETERMINED? 11

A. The 4.02 percent cost of STD includes the estimated interest expense plus the monthly 12

commitment and other fees associated with OTP’s $170 million short-term credit 13

facility. The estimated interest rate averages approximately 3.05 percent and is based 14

on projected 1-month LIBOR rates plus a 1.25 percent spread. 15

C. COMMON EQUITY 16

Q. WHAT IS THE AMOUNT OF OTP’S 2018 TEST YEAR COMMON EQUITY AND 17

HOW WAS IT DETERMINED? 18

A. OTP’s common equity is $562.3 million, which reflects the average of 13 month-end 19

expected equity balances from December 2016 through December 2018. Exhibit___ 20

(KGM-1), Schedule 7 shows the 2018 Test Year equity balance by month. 21

22

21 Case No. PU-17-

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Q. HAS OTTER TAIL CORPORATION RECENTLY ISSUED COMMON STOCK? 1

A. Yes. Otter Tail Corporation has had follow on offerings of its common stock since 2004 2

and 2008. Otter Tail Corporation also issued common stock during the 2014-2017 3

timeframe using its “At the Market Program,” its Dividend Reinvestment Plan (DRIP), 4

and its Employee Stock Purchase Plan (ESPP). All of these common stock issuances 5

are included on Exhibit___KGM-1), Schedule 8. 6

7

Q. ARE THERE COSTS OF ISSUING COMMON STOCK? 8

A. Yes. When common stock is issued, the corporation issuing the stock incurs costs in 9

the process of issuance, including underwriter discounts, audit, legal, printing and listing 10

fees, and other expenses of issuance. When these issuance costs (also known as 11

“flotation costs”) are incurred, they reduce the net proceeds received by the corporation 12

issuing the stock (under generally accepted accounting principles). Flotation costs are 13

comparable to the issuance costs for LTD. The flotation costs associated with Otter Tail 14

Corporation’s common stock issuances are identified in Exhibit___KGM-1), Schedule 15

8, which Mr. Hevert used to determine the flotation cost adjustment. All of these 16

flotation costs were treated as a reduction in proceeds and reflected on the balance sheet 17

and not expensed, which is the standard practice with all flotation costs. 18

19

Q. WERE THESE 2014-2017 COMMON STOCK ISSUANCES BY OTTER TAIL 20

CORPORATION RELATED TO OTP’S CAPITAL EXPENDITURES? 21

A. Yes. These Otter Tail Corporation common stock issuances were directly related to 22

OTP’s prior capital expenditures, its current capital expenditures and its planned future 23

capital expenditures. 24

25

Q. PLEASE SUMMARIZE OTTER TAIL CORPORATION’S PLANNED COMMON 26

STOCK ISSUANCES. 27

A. Otter Tail Corporation has publicly announced its plans to use its ATM, DRIP, and 28

ESPP to issue approximately $70 million to $85 million of common equity during the 29

2017 - 2021 timeframe. 30

22 Case No. PU-17-

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Q. ARE THE 2014-2016 AND PLANNED COMMON STOCK ISSUANCES 1

DIRECTLY RELATED TO OTP’S INVESTMENT PLANS? 2

A. Yes. The 2014-2016 common stock issuances and planned issuances of common stock 3

by Otter Tail Corporation are directly related to the current and planned capital 4

expenditures for OTP. 5

XI. CONCLUSION 6

Q. CAN YOU PLEASE SUMMARIZE YOUR CONCLUSIONS? 7

A. Yes. I recommend the Commission approve a capital structure for the 2018 Test Year 8

including 52.5 percent equity, a 10.30 percent ROE, and an ROR of 7.97 percent. 9

10

Q. DOES THIS CONCLUDE YOUR TESTIMONY? 11

A. Yes, it does. 12

Case No. Exhibit ___(KGM-1), Schedule 1

Page 1 of 1

KEVIN G. MOUG

EMPLOYMENT_________________________________________________________

2001-PRESENT Otter Tail Corporation Fargo, ND

Sr. Vice President & Chief Financial Officer

1996-PRESENT Varistar Corporation Fargo, ND

Chief Financial Officer & Treasurer

1993-1996 Advance Dental Management Mondovi, WI

Chief Financial Officer

1981-1993 Deloitte & Touche Minneapolis, MN

Senior Manager – Middle Market Practice

EDUCATION___________________________________________________________

• Bachelor of Science in Business Administration University of North Dakota

INDUSTRY CERTIFICATIONS___________________________________________

• Certified Public Accountant (Inactive)

PROFESSIONAL AFFILIATIONS_________________________________________

• American Institute of Certified Public Accountants Member

• Financial Executive International Member

• US Bank Advisory Board Board Member

• Essentia Health West Region Board of Directors

• Essentia Health System Board of Directors

Audit Committee Chair

OTTER TAIL POWER COMPANY Case No. PU-17-

Electric Utility - State of North Dakota Exhibit ___(KGM-1), Schedule 2

Page 1 of 1

PROPOSED COST OF CAPITAL FOR 2018 TEST YEAR

(A) (B) (C) (D) (E)

Weighted

Line Percent Cost of Cost of

No. Capitalization Amount of Total Capital Capital

1 Short term debt $15,979,875 1.49% 4.02% 0.06%

2 Long term debt 492,672,120 46.01% 5.43% 2.50%

3 Total debt $508,651,995 47.5% 5.39% 2.56%

4 Common equity $562,251,832 52.5% 10.30% 5.41%

5 Total Capitalization $1,070,903,827 100.0% 7.97%



Page 1 of 1

Line No. Description Amount

1 Hypothetical amout of debt issuance $250,000,000

2 25 basis points increase in Interest Rate 0.0025

3 Total Interest Cost $625,000

Line No. Description Amount

4 Hypothetical amout of debt issuance $250,000,000

5 40 basis points increase in Interest Rate 0.0040

6 Total Interest Cost $1,000,000

Impact of 25 Basis Point Debt Cost Increase on $200 Million

Impact of 40 Basis Point Debt Cost Increase on $250 Million



Page 1 of 1

Moody's Rating Factors


Line No.

1 Regulated Electric and Gas Utilities Industry Current LTM [3]Moody's 12-18 Month

2 Grid [1][2] 3/31/2017

Forward View As of March

2017

3 Factor 1 : Regulatory Framework (25%) Measure Score Measure Score

4 a) Legislative and Judicial Underpinnings of A A A A

5 the Regulatory Framework

6 b) Consistency and Predictability of A A A A

7 Regulation

8 Factor 2 : Ability to Recover Costs and Earn

9 Returns (25%)

10 a) Timeliness of Recovery of Operating and A A Aa Aa

11 Capital Costs

12 b) Sufficiency of Rates and Returns Baa Baa Baa Baa

13 Factor 3 : Diversification (10%)

14 a) Market Position Baa Baa Baa Baa

15 b) Generation and Fuel Diversity Ba Ba Baa Baa

16 Factor 4 : Financial Strength (40%)

17 a) CFO pre-WC + Interest / Interest (3 Year 5.5x A 6x-6.4x Aa

18 Avg)

19 b) CFO pre-WC / Debt (3 Year Avg) 22.5% A 23%-27% A

20 c) CFO pre-WC - Dividends / Debt (3 Year 15.7% Baa 16%-20% A

21 Avg)

22 d) Debt / Capitalization (3 Year Avg) 42.7% A 36%-40% A

23 Rating:

24 Grid-Indicated Rating Before Notching A3 A2

25 Adjustment

26 HoldCo Structural Subordination Notching 0 0 0 0

27 a) Indicated Rating from Grid A3 A2

28 b) Actual Rating Assigned A3 A3

29 [1] All ratios are based on 'Adjusted' financial data and incorporate Moody's Global Standard Adjustments for Non-

Financial Corporations. [2] As of 3/31/2017(L) [3] This represents Moody's

forward view; not the view of the issuer; and unless noted in the text, does not incorporate significant acquisitions

and divestitures. Source: Moody's Financial MetricsTM



Page 1 of 1

COMPOSITE COST OF LONG-TERM DEBT FOR 2018 TEST YEAR

\

Line DESCRIPTION Interest

No. Debentures Rate Dec-17 Jan-18 Feb-18 Mar-18 Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18 Total Interest Cost

1 4.630% Series for 2021 4.630% $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $140,000,000 $6,482,000

2 6.150% Unsecured Series B 2022 Senior Notes 6.150% 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 30,000,000 1,845,000

3 6.370% Unsecured Series C 2027 Senior Notes 6.370% 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 42,000,000 2,675,400

4 6.470% Series D 2037 Unsecured Senior Notes 6.470% 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 50,000,000 3,235,000

5 4.500% LT Debt Forecast for 2018 4.500% 0 0 100,000,000 100,000,000 100,000,000 100,000,000 100,000,000 100,000,000 100,000,000 100,000,000 100,000,000 100,000,000 100,000,000 84,615,385 4,125,000

6 Total Debentures 0 $262,000,000 $262,000,000 $362,000,000 $362,000,000 $362,000,000 $362,000,000 $362,000,000 $362,000,000 $362,000,000 $362,000,000 $362,000,000 $362,000,000 $362,000,000 $346,615,385 $18,362,400

7 Series Bonds

8 4.680% 2029 Series 4.680% $60,000,000 $60,000,000 $60,000,000 $60,000,000 $60,000,000 $60,000,000 60,000,000 $60,000,000 60000000 60,000,000 60,000,000 60,000,000 60,000,000 60,000,000 2,808,000

9 5.470% 2044 Series 5.470% 90,000,000 90,000,000 90,000,000 90,000,000 90,000,000 90,000,000 90,000,000 90,000,000 90000000 90,000,000 90,000,000 90,000,000 90,000,000 90,000,000 4,923,000

10 Total Series Bonds $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $150,000,000 $7,731,000

11

12 Subtotal Bond Balances $412,000,000 $412,000,000 $512,000,000 $512,000,000 $512,000,000 $512,000,000 $512,000,000 $512,000,000 $512,000,000 $512,000,000 $512,000,000 $512,000,000 $512,000,000 $496,615,385 $26,093,400

13

14 Loss/Gain on Reacquired Debt (3,434,337) (3,380,088) (4,325,839) (4,268,817) (4,211,795) (4,154,773) (4,097,751) (4,040,729) (3,983,707) (3,926,685) (3,869,663) (3,812,641) (3,755,619) (3,943,265) 678,719

15 Total Long-Term Debt Capital $408,565,663 $408,619,912 $507,674,161 $507,731,183 $507,788,205 $507,845,227 $507,902,249 $507,959,271 $508,016,293 $508,073,315 $508,130,337 $508,187,359 $508,244,381 $492,672,120 $26,772,119

WEIGHTED COST OF LONG-TERM DEBT 5.43%

PRINCIPAL AMOUNTS OUTSTANDING



Page 1 of 1

Short-term Debt

Line No. Month

Month end

balances

Monthly

Interest

Expense

Monthly Fee

Expense

Average Short-

Term Debt

Cost

1 2017 Dec 98,868,111

2 2018 Jan 97,109,150 230,692 11,271

3 2018 Feb 1,065,735 233,062 11,272

4 2018 Mar 2,062,808 2,522 11,681

5 2018 Apr 0 4,951 12,912

6 2018 May 0 12,788

7 2018 Jun 1,742,979 12,949

8 2018 Jul 0 4,285 13,836

9 2018 Aug 2,513,778 13,478

10 2018 Sep 2,392,451 6,347 7,026

11 2018 Oct 0 6,220 32,563

12 2018 Nov 0 6,735

13 2018 Dec 1,983,358 8,184

14 Average $15,979,875

15 Total $ Cost $488,080 $154,695 $642,773

16 Total % Cost 3.05% 0.97% 4.02%

Cost of Short-Term Debt



Page 1 of 1

COMMON EQUITY FOR 2018 TEST YEAR

Line

No.

CONTRIBUTED

CAPITAL

RETAINED

EARNINGS

TOTAL

COMMON

EQUITY

1 December 2017 376,989,466 181,478,644 558,468,110

2 January 376,989,466 187,131,648 564,121,114

3 February 376,989,466 190,877,392 567,866,858

4 March 376,989,466 184,304,662 561,294,128

5 April 376,989,466 186,499,101 563,488,566

6 May 376,989,466 188,178,472 565,167,937

7 June 376,989,466 180,477,234 557,466,700

8 July 376,989,466 185,197,716 562,187,182

9 August 376,989,466 189,674,530 566,663,996

10 September 376,989,466 182,377,990 559,367,456

11 October 376,989,466 183,091,677 560,081,143

12 November 376,989,466 187,384,550 564,374,015

13 December 376,989,466 181,737,136 558,726,602

14 Average Common Equity $562,251,832

Month-end Balances



Page 1 of 1

Floation Costs

Line

No. Issuing Entity Mechanism Date Shares issued Offering Price

Underwriting

Discount

Offering

Expense Gross Proceeds

Total Flotation

Costs Net Proceeds

Flotation

cost %

1 Otter Tail Corp. ESSP 2004 66,958 NA -$ -$ 1,292,959$ -$ 1,292,959$ 0.00%

2 Otter Tail Corp. ESSP 2009 62,450 NA -$ -$ 1,197,791$ -$ 1,197,791$ 0.00%

3 Otter Tail Corp. ESPP 2014 39,222 NA -$ -$ 1,049,188$ -$ 1,049,188$ 0.00%

4 Otter Tail Corp. ESPP 2015 42,253 NA -$ -$ 1,095,620$ -$ 1,095,620$ 0.00%

5 Otter Tail Corp. ESPP 2016 53,875 NA -$ -$ 1,491,266$ 1,159$ 1,490,107$ 0.08%

6 Otter Tail Corp. ESPP YTD - 2017 5,284 NA -$ -$ 210,585$ 367$ 210,218$ 0.17%

7 Otter Tail Corp. DRIP 2004 223,165 NA -$ -$ 4,308,033$ -$ 4,308,033$ 0.00%

8 Otter Tail Corp. DRIP 2009 233,943 NA -$ -$ 4,493,385$ 5,877$ 4,487,508$ 0.13%

9 Otter Tail Corp. DRIP 2014 288,045 NA -$ -$ 7,707,964$ -$ 7,707,964$ 0.00%

10 Otter Tail Corp. DRIP 2015 330,379 NA -$ 56,545$ 8,566,009$ 56,545$ 8,509,464$ 0.66%

11 Otter Tail Corp. DRIP 2016 302,524 NA -$ -$ 11,095,328$ 32,973$ 11,062,355$ 0.30%

12 Otter Tail Corp. DRIP YTD - 2017 107,285 NA -$ -$ 4,139,552$ 17,554$ 4,121,998$ 0.42%

13 Otter Tail Corp. ATM 2014 519,636 30$ 306,727$ 780,616$ 15,336,352$ 1,087,343$ 14,249,009$ 7.09%

14 Otter Tail Corp. ATM 2015 133,197 28$ 56,485$ 339,160$ 3,785,244$ 395,645$ 3,389,599$ 10.45%

15 Otter Tail Corp. ATM 2016 1,014,115 33$ 561,548$ 33,235,729$ 561,548$ 32,674,181$ 1.69%

16 Otter Tail Corp. Secondary 2004-05 3,075,000 25$ 2,921,250$ 391,452$ 78,258,750$ 3,312,702$ 74,946,048$ 4.23%

17 Otter Tail Corp. Secondary 2008 5,175,000 30$ 5,627,812$ 807,185$ 155,250,000$ 6,434,997$ 148,815,003$ 4.14%

18 Weighted Average 3.58%

1/5

Volume 2B


Robert B. Hevert






Case No. PU-17-

Exhibit___(RBH-1)

RETURN ON EQUITY

DIRECT TESTIMONY AND SCHEDULES OF

ROBERT B. HEVERT

November 2, 2017

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TABLE OF CONTENTS

I. WITNESS IDENTIFICATION AND QUALIFICATIONS ...............................................1

II. PURPOSE AND OVERVIEW OF TESTIMONY ..............................................................1

III. SUMMARY OF ANALYTICAL RESULTS ......................................................................5

IV. SUMMARY OF ISSUES SURROUNDING COST OF EQUITY ESTIMATION IN

REGULATORY PROCEEDINGS ......................................................................................7

V. PROXY GROUP SELECTION .........................................................................................11

VI. COST OF EQUITY ESTIMATION ..................................................................................15

Constant Growth DCF Model ............................................................................................16

Multi-Stage Discounted Cash Flow Model ........................................................................24

CAPM Analysis ..................................................................................................................30

Bond Yield Plus Risk Premium Analysis ............................................................................33

VII. BUSINESS RISKS AND OTHER CONSIDERATIONS .................................................36

Capital Expenditures .........................................................................................................36

Small Size ...........................................................................................................................40

Customer Concentration ....................................................................................................43

Other Evidence of OTP’s Relatively Higher Cost of Equity ..............................................44

Institutional Ownership .............................................................................................45 Trading Volume and Liquidity Risk .........................................................................46 Relative Beta Coefficients ........................................................................................48

Cost Savings for Customers ...............................................................................................49

VIII. CAPITAL MARKET ENVIRONMENT ..........................................................................51

IX. CAPITAL STRUCTURE ..................................................................................................61

X. CONCLUSIONS AND RECOMMENDATION ..............................................................64

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Schedules

Constant Growth DCF Results Schedule 1

Flotation Costs Schedule 2

Multi-Stage DCF Results Schedule 3

Market Risk Premium Calculations Schedule 4

Beta Coefficient Estimates Schedule 5

Capital Asset Pricing Model Results Schedule 6

Bond Yield Plus Risk Premium Analysis Schedule 7

Capital Expenditures Relative to Net Plant Schedule 8

Small Size Premium and Service Area Comparability Schedule 9

Customer Concentration Schedule 10

Institutional Ownership Schedule 11

Proxy Group Capital Structure Schedule 12

Resume and Testimony Listing Attachment A

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I. WITNESS IDENTIFICATION AND QUALIFICATIONS

Q. PLEASE STATE YOUR NAME, AFFILIATION, AND BUSINESS ADDRESS. 1

A. My name is Robert B. Hevert. I am a Partner of ScottMadden, Inc. (“ScottMadden”). My 2

business address is 1900 West Park Drive, Suite 250, Westborough, MA 01581. 3

Q. ON WHOSE BEHALF ARE YOU SUBMITTING THIS TESTIMONY? 4

A. I am submitting this direct testimony (“Direct Testimony”) before the North Dakota Public 5

Service Commission (“Commission”) on behalf of Otter Tail Power Company (“OTP” or 6

the “Company”), a wholly-owned subsidiary of Otter Tail Corporation (“OTTR”). 7

Q. PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND. 8

A. I hold a Bachelor’s degree in Business and Economics from the University of Delaware, 9

and an MBA with a concentration in Finance from the University of Massachusetts. I also 10

hold the Chartered Financial Analyst designation. 11

Q. PLEASE DESCRIBE YOUR EXPERIENCE IN THE ENERGY AND UTILITY 12

INDUSTRIES. 13

A. I have worked in regulated industries for over thirty years, having served as an executive 14

and manager with consulting firms, a financial officer of a publicly-traded natural gas 15

utility (at the time, Bay State Gas Company), and an analyst at a telecommunications 16

utility. In my role as a consultant, I have advised numerous energy and utility clients on a 17

wide range of financial and economic issues, including corporate and asset-based 18

transactions, asset and enterprise valuation, transaction due diligence, and strategic matters. 19

As an expert witness, I have provided testimony in more than 200 proceedings regarding 20

various financial and regulatory matters before numerous state utility regulatory agencies, 21

the Federal Energy Regulatory Commission, and the Alberta Utilities Commission. A 22

summary of my professional and educational background, including a list of my testimony 23

in prior proceedings, is included in Attachment A to my Direct Testimony. 24

II. PURPOSE AND OVERVIEW OF TESTIMONY


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A. My Direct Testimony presents evidence and a determination as to OTP’s current Cost of 1

Equity and provides a recommendation as to OTP’s Return on Equity (“ROE”).1 My 2

analysis and conclusions are supported by the data presented in Exhibit__(RBH-1), 3

Schedules 1 through 12, which have been prepared by me or under my supervision in 4

connection with my Direct Testimony. 5

Q. WHAT ARE YOUR CONCLUSIONS REGARDING THE APPROPRIATE ROE AND 6

CAPITAL STRUCTURE FOR OTP? 7

A. My analyses indicate that OTP’s Cost of Equity currently is in the range of 10.00 percent 8

to 10.60 percent. Based on the quantitative and qualitative analyses discussed throughout 9

my Direct Testimony, including an assessment of the Company’s relative risk, it is my 10

view that 10.30 percent would be the appropriate ROE in this proceeding. 11

Q. PLEASE PROVIDE A BRIEF OVERVIEW OF THE ANALYSES THAT LED TO 12

YOUR ROE DETERMINATION. 13

A. Because all financial models are subject to various assumptions and constraints, equity 14

analysts and investors tend to use multiple methods to develop their return requirements. I 15

therefore relied on three widely accepted approaches to develop my ROE determination: 16

(1) the Discounted Cash Flow (“DCF”) model, including the Constant Growth and Multi-17

Stage forms; (2) the Capital Asset Pricing Model (“CAPM”); and (3) the Bond Yield Plus 18

Risk Premium approach. In addition to the methods noted above, my recommendation also 19

takes into consideration: (1) OTP’s planned capital investment program; (2) OTP’s small 20

size, which is related to OTTR’s low level of institutional ownership and low common 21

stock trading volume; and (3) OTP’s customer concentration. OTP has planned capital 22

expenditures in 2017 – 2021 that are approximately 66.00 percent of its net plant in service, 23

the second highest of the companies that I included in my analysis. OTTR has an 24

approximately 52.00 percent level of institutional ownership of its common stock, which 25

is the lowest of any company in my proxy group, and approximately 35.00 percent lower 26

than the average of my proxy group, and has an average trading volume that is 27

1 Throughout my Direct Testimony, I interchangeably use the terms “ROE” and “Cost of Equity” to refer to

the market-required rate of return.

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approximately 18.00 to 19.00 percent of the average for the proxy group. OTP also has a 1

substantial concentration of revenues in its commercial and industrial customers. The 2

combination of those factors indicates a somewhat greater degree of business risk relative 3

to the proxy companies, suggesting an ROE toward the upper end of the range to account 4

for that incremental risk. 5

6

As a practical matter, in light of OTP’s substantial capital investment plan, it will be 7

important to set a return that will support and enhance OTP’s internally generated funds, 8

and enable it to access capital markets at reasonable terms. The costs at which OTP can 9

obtain capital to fund its capital expenditures will influence customer costs over an 10

extended period (i.e., ten to 30 years). The need to support internal fund generation and 11

efficient capital market access becomes increasingly important as Federal Reserve 12

monetary policy continues its process of “normalization.” As discussed later in my Direct 13

Testimony, coincident with monetary policy normalization, economists and market data 14

indicate expectations for increasing interest rates into 2018. 15

16

Lastly, it is appropriate to consider OTP’s low customer rates in general and OTP’s very 17

high levels of customer satisfaction (as explained by OTP witness Mr. Bruce Gerhardson) 18

and the customer savings that have resulted from OTP’s under-budget completion of recent 19

capital expenditures (as explained by OTP witness Mr. Stuart Tommerdahl). As further 20

discussed below, OTP’s recent completion of its single largest capital expenditure at 21

approximately 26.00 percent below budget results in North Dakota customer savings of 22

approximately $3.40 million in the 2018 Test Year, approximately $32.70 million in the 23

first ten years, and approximately $69.50 million over 30-year life of the project. Setting 24

an ROE that recognizes overall performance in reducing costs and providing high quality 25

of service is an appropriate element of the Commission’s regulatory discretion. The 26

combination of OTP’s cost savings and its high quality of service merits consideration by 27

the Commission in determining OTP’s ROE. 28

Q. DO THE ROE DECISIONS OF OTHER JURISDICTIONS ALSO PROVIDE 29

RELEVANT INFORMATION? 30

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A. Yes, I believe so. Investors have many options available to them and will allocate their 1

capital based on expected risks and returns associated with those alternatives. Although I 2

am not suggesting that the Commission should be bound by decisions in other regulatory 3

jurisdictions, the regulatory environment is one of the most important factors considered 4

by debt and equity investors in assessing the risks and prospects of utility companies. 5

ROEs awarded by regulatory commissions are important to the financial community’s view 6

of the regulatory environment and, therefore, a utility’s risk profile. For example, if a 7

company in a given jurisdiction is authorized a significantly lower ROE than a company 8

of equivalent risk is authorized in another jurisdiction, capital will flow from the lower 9

return to the higher return. 10

Q. PLEASE SUMMARIZE RECENT RETURNS FROM OTHER JURISDICTIONS. 11

A. In 2017, there have been 14 regulatory decisions establishing authorized ROEs for 12

vertically integrated electric utilities. The average of those authorized ROEs was 9.70 13

percent and four of the allowed ROEs were at or above 10.00 percent. In 2016, there were 14

20 regulatory decisions establishing allowed ROEs for vertically integrated electric 15

utilities; the average of those authorized ROEs was 9.77 percent and five of the authorized 16

ROEs were at or above 10.00 percent. 17

Q. HOW IS THE REMAINDER OF YOUR DIRECT TESTIMONY ORGANIZED? 18

A. The remainder of my Direct Testimony is organized as follows: 19

• Section III – provides a summary of the results of analytical models; 20

• Section IV – provides a summary of issues regarding Cost of Equity estimation in 21

regulatory proceedings and discusses the regulatory guidelines pertinent to the 22

development of the cost of capital; 23

• Section V – explains my selection of the proxy group used to develop my analytical 24

results; 25

• Section VI – explains my analyses and the analytical bases for my ROE 26

determination; 27

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• Section VII – provides a discussion of specific business risks and other 1

considerations that have a direct bearing on OTP’s Cost of Equity; 2

• Section VIII – highlights the current capital market conditions and their effect on 3

OTP’s Cost of Equity; 4

• Section IX – provides my analysis of OTP’s capital structure; and 5

• Section X – summarizes my conclusions. 6

7

III. SUMMARY OF ANALYTICAL RESULTS

Q. WHAT ARE THE RESULTS OF YOUR ANALYTICAL MODELS? 8

A. The analytical results are summarized in Table 1. 9

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Table 1: Summary of Analytical Results 1

Discounted Cash Flow Mean Low Mean Mean High

Constant Growth DCF – Including Flotation Costs2

30-Day Constant Growth DCF 8.05% 9.26% 10.19%



Multi-Stage DCF – Including Flotation Costs

30-Day Multi-Stage DCF 8.49% 9.15% 9.77%



CAPM Results

Bloomberg

Derived

Market Risk

Premium

Value Line

Derived

Market Risk

Premium

Average Bloomberg Beta Coefficient

Current 30-Year Treasury (2.77%) 9.42% 9.72%

Near Term Projected 30-Year Treasury (3.30%) 9.95% 10.25%

Average Value Line Beta Coefficient



Bond Yield Plus Risk Premium Approach

Current 30-Year Treasury (2.77%) 9.96%

Near Term Projected 30-Year Treasury (3.30%) 10.02%

Long Term Projected 30-Year Treasury (4.40%) 10.33%

2

Based on the analytical results presented in Table 1, and in light of the considerations 3

discussed throughout the balance of my testimony regarding the Company’s business risks 4

relative to the proxy group, it is my view that an ROE of 10.30 percent is reasonable and 5

appropriate. 6

2 Constant Growth DCF results exclude Hawaiian Electric Industries, Inc., IDACORP, Inc., and Northwestern

Corporation.

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1

IV. SUMMARY OF ISSUES SURROUNDING COST OF EQUITY ESTIMATION IN

REGULATORY PROCEEDINGS

Q. PLEASE PROVIDE AN OVERVIEW OF THE ISSUES SURROUNDING THE COST 2

OF EQUITY IN REGULATORY PROCEEDINGS, GENERALLY. 3

A. In very general terms, the Cost of Equity is the return that investors require to make an 4

equity investment in a firm. That is, investors will provide funds to a firm only if the return 5

that they expect is equal to, or greater than, the return that they require to accept the risk of 6

providing funds to the firm. From the firm’s perspective, that required return, whether it 7

is provided to debt or equity investors, has a cost. Individually, we speak of the “Cost of 8

Debt” and the “Cost of Equity” as measures of those costs; together, they are referred to as 9

the “Cost of Capital.” 10

11

The Cost of Capital (including the costs of both debt and equity) is based on the economic 12

principle of “opportunity costs.” Investing in any asset, whether debt or equity securities, 13

implies a forgone opportunity to invest in alternative assets. For any investment to be 14

sensible, its expected return must be at least equal to the return expected on alternative, 15

comparable risk investment opportunities. Because investments with like risks should 16

offer similar returns, the opportunity cost of an investment should equal the return available 17

on an investment of comparable risk. 18

19

Although both debt and equity have required costs, they differ in certain fundamental ways. 20

Most noticeably, the Cost of Debt is contractually defined and can be directly observed as 21

the interest rate, or yield, on debt securities.3 The Cost of Equity, on the other hand, is 22

neither directly observable nor a contractual obligation. Rather, equity investors have a 23

claim on cash flows only after debt holders are paid; the uncertainty (or risk) associated 24

with those residual cash flows determines the Cost of Equity. Because equity investors 25

3 The observed interest rate may be adjusted to reflect issuance or other directly observable costs.

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bear the “residual risk,” they take greater risks and require higher returns than debt holders. 1

In that basic sense, equity and debt investors differ: they invest in different securities, face 2

different risks, and require different returns. 3

4

Whereas the Cost of Debt can be directly observed, the Cost of Equity must be estimated 5

or inferred based on market data and various financial models. As discussed throughout 6

my Direct Testimony, each of those models is subject to certain assumptions, which may 7

be more or less applicable under differing market conditions. In addition, since the Cost 8

of Equity is premised on opportunity costs, the models typically are applied to a group of 9

“comparable” or “proxy” companies. The choice of models (including their inputs), the 10

selection of proxy companies, and the interpretation of the model results all require the 11

application of reasoned judgment. That judgment should consider data and information 12

that is not necessarily included in the models themselves. In the end, the estimated Cost 13

of Equity should reflect the return that investors require in light of the subject company’s 14

risks, and the returns available on comparable investments. 15

Q. PLEASE PROVIDE A SUMMARY OF THE GUIDELINES FOR THE PURPOSE OF 16

DETERMINING THE RETURN ON EQUITY. 17

A. The United States Supreme Court (the “Court”) established the guiding principles for 18

establishing a fair return for capital in two cases: (1) Bluefield Water Works and 19

Improvement Co. v. Public Service Comm’n. (“Bluefield”);4 and (2) Federal Power 20

Comm’n v. Hope Natural Gas Co. (“Hope”).5 In Bluefield, the Court stated: 21

A public utility is entitled to such rates as will permit it to earn a return upon 22

the value of the property which it employs for the convenience of the public 23

equal to that generally being made at the same time and in the same general 24

part of the country on investments in other business undertakings which are 25

attended by corresponding risks and uncertainties; but it has no 26

constitutional right to profits such as are realized or anticipated in highly 27

profitable enterprises or speculative ventures. The return should be 28

reasonably sufficient to assure confidence in the financial soundness of the 29

4 See Bluefield Water Works and Improvement Co. v. Public Service Comm’n. 262 U.S. 679, 692 (1923). 5 See Federal Power Comm’n v. Hope Natural Gas Co., 320 U.S. 591, 603 (1944).

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utility and should be adequate, under efficient and economical management, 1

to maintain and support its credit, and enable it to raise the money necessary 2

for the proper discharge of its public duties.6 3

The Court therefore recognized that: (1) a regulated public utility cannot remain financially 4

sound unless the return it is allowed to earn on its invested capital is at least equal to the 5

Cost of Capital (the principle relating to the demand for capital); and (2) a regulated public 6

utility will not be able to attract capital if it does not offer investors an opportunity to earn 7

a return on their investment equal to the return they expect to earn on other investments of 8

similar risk (the principle relating to the supply of capital). 9

10

In Hope, the Court reiterates the financial integrity and capital attraction principles of the 11

Bluefield case: 12

From the investor or company point of view it is important that there be 13

enough revenue not only for operating expenses but also for the capital costs 14

of the business. These include service on the debt and dividends on the 15

stock... By that standard the return to the equity owner should be 16

commensurate with returns on investments in other enterprises having 17

corresponding risks. That return, moreover, should be sufficient to assure 18

confidence in the financial integrity of the enterprise, so as to maintain its 19

credit and to attract capital.7 20

In summary, the Court clearly has recognized that the fair rate of return on equity should 21

be: (1) comparable to returns investors expect to earn on other investments of similar risk; 22

(2) sufficient to assure confidence in the company’s financial integrity; and (3) adequate to 23

maintain and support the company’s credit and to attract capital. 24

Q. WHY IS IT IMPORTANT FOR A UTILITY TO BE ALLOWED THE OPPORTUNITY 25

TO EARN A RETURN ADEQUATE TO ATTRACT CAPITAL AT REASONABLE 26

TERMS? 27

A. A return that is adequate to attract capital at reasonable terms enables the utility to provide 28

service while maintaining its financial integrity. The ability to attract capital is particularly 29

6 Bluefield, 262 U.S. at 692. 7 Hope, 320 U.S. at 603.

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important when a utility is engaged in an extensive capital expenditure program, such as 1

OTP is at this time. As discussed above, and in keeping with the Hope and Bluefield 2

standards, that return should be commensurate with the returns expected elsewhere in the 3

market for investments of equivalent risk. Based on those standards, the Commission’s 4

decision in this case should provide the Company with the opportunity to earn an ROE that 5

is: (1) adequate to attract capital at reasonable terms; (2) sufficient to ensure its financial 6

integrity; and (3) commensurate with returns on investments in enterprises having 7

corresponding risks. The allowed ROE should enable the Company to finance capital 8

expenditures at reasonable cost rates and maintain its financial flexibility over the period 9

during which rates are expected to remain in effect. To the extent OTP is provided a 10

reasonable opportunity to earn its market-based Cost of Equity, neither customers nor 11

shareholders should be disadvantaged. In fact, a return that is adequate to attract capital at 12

reasonable terms enables OTP to provide safe, reliable electric utility service while 13

maintaining its financial integrity. 14

Q. HOW IS THE COST OF EQUITY ESTIMATED IN REGULATORY PROCEEDINGS? 15

A. As noted earlier (and as discussed in more detail later in my Direct Testimony), the Cost 16

of Equity is estimated by the use of various financial models. By their very nature, those 17

models produce a range of results from which the ROE is determined. That determination 18

must be based on a comprehensive review of relevant data and information; it does not 19

necessarily lend itself to a strict mathematical solution. The key consideration in 20

determining the ROE is to ensure that the overall analysis reasonably reflects investors’ 21

view of the financial markets in general, and the subject company (in the context of the 22

proxy companies) in particular. Both practitioners and academics, however, recognize that 23

financial models simply are tools to be used in the ROE estimation process, and that strict 24

adherence to any single approach, or to the specific results of any single approach, can lead 25

to flawed or misleading conclusions. That position is consistent with the Hope and 26

Bluefield principle that it is the analytical result, as opposed to the methodology employed 27

that is controlling in arriving at ROE determinations. Thus, a reasonable ROE estimate 28

appropriately considers alternative methodologies and the reasonableness of their 29

individual and collective results in the context of observable, relevant market information. 30

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1

V. PROXY GROUP SELECTION

Q. AS A PRELIMINARY MATTER, WHY IS IT NECESSARY TO SELECT A GROUP 2

OF PROXY COMPANIES TO DETERMINE THE COST OF EQUITY FOR OTP? 3

A. The ROE is a market-based concept and OTP is not a publicly traded entity. Rather, it is 4

a subsidiary of OTTR. Accordingly, it is necessary to establish a group of comparable, 5

publicly traded companies to serve as its “proxy.” Even if OTP were a publicly traded 6

entity, short-term events could bias its market value during a given period of time. A 7

significant benefit of using a proxy group is that it moderates the effects of anomalous, 8

short-term events associated with any one company. At the same time, the risk profile of 9

the subject company should be taken into consideration when determining the appropriate 10

ROE. 11

Q. DOES THE SELECTION OF A PROXY GROUP SUGGEST THAT ANALYTICAL 12

RESULTS WILL BE TIGHTLY CLUSTERED AROUND AVERAGE (I.E., MEAN) 13

RESULTS? 14

A. No. For example, the Constant Growth DCF approach defines the Cost of Equity as the 15

sum of the expected dividend yield and projected long-term growth. Despite the care taken 16

to ensure risk comparability, market expectations with respect to future risks and growth 17

opportunities will vary from company to company. Therefore, even within a group of 18

similarly situated companies, it is common for analytical results to reflect a seemingly wide 19

range. Consequently, at issue is how to estimate the Cost of Equity from within that range. 20

Such a determination necessarily must consider a wide range of both quantitative and 21

qualitative information, including the risk profile of the subject company (i.e. OTP). 22

Q. PLEASE PROVIDE A SUMMARY PROFILE OF OTP. 23

A. OTP provides electric production, transmission, and distribution services to approximately 24

58,500 customers in North Dakota.8 OTP is engaged in an extensive capital expenditure 25

8 Company website.

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plan that began in 2012 and is expected to continue through 2021. OTP currently has long-1

term issuer credit ratings of BBB from S&P, A3 from Moody’s Investor Service, and 2

BBB+ from Fitch Ratings.9 The following table provides summary financial and operating 3

statistics for OTP for the past three years. 4

Table 2: OTP Operating and Financial Results 2014-201610 5

(in thousands) 2014 2015 2016

Electric Operations

ND Electric Customers 58.12 58.30 58.50

Total Electric Customers 130.49 129.99 131.55

Electric Revenues $407,743 $407,131 $427,383

Electric Net Income $43,684 $48,370 $49,829

Electric Net Plant $1,126,088 $1,217,931 $1,307,293

Electric Capital Expenditures $148,719 $135,572 $149,648

6

Q. WHAT ARE THE IMPLICATIONS OF THE COMPANY’S BUSINESS RISKS FOR 7

OTP’S COST OF EQUITY? 8

A. Consistent with the principles established in Hope11 and to provide a return to equity 9

holders that is risk appropriate, it is reasonable to consider a proxy group of companies 10

with a commensurate level of risk. Compared to other investor-owned electric utilities, no 11

company has the same service territory and risk profile as OTP. Thus, selecting a proxy 12

group without regard to OTP’s size and service territory would be inconsistent with the 13

principles set forth in Hope and would lead to in inaccurate ROE analysis. As such, I have 14

included screening criteria that account for OTP’s profile relative to its service territory 15

and other operating risk factors. 16

9 SNL Financial. 10 SNL Financial, Otter Tail Corporation SEC Form 10-K for year ending December 31, 2016, at 77-78, and

Company website. 11 Hope, 320 U.S. at 603. See, Bluefield, 262 U.S. at 692.

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Q. HOW DID YOU SELECT THE COMPANIES INCLUDED IN YOUR PROXY GROUP? 1

A. A proxy group should consist of companies with risk profiles relatively comparable to the 2

subject company. In selecting a proxy group, my objective was to balance the competing 3

interests of selecting companies that are highly representative of the risks and prospects 4

faced by OTP, while at the same time ensuring that there are a sufficient number of 5

companies in the proxy group. Based on those two considerations, I began with the 6

universe of companies that Value Line classifies as Electric Utilities, and applied the 7

following screening criteria: 8

• I excluded companies that do not consistently pay quarterly cash dividends; 9

• I excluded companies that were not covered by at least two utility industry equity 10

analysts; 11

• I excluded companies that do not have investment grade senior unsecured bond 12

and/or corporate credit ratings from S&P; 13

• I excluded companies that were not vertically-integrated, i.e. utilities that own and 14

operate regulated generation, transmission and distribution assets; 15

• I excluded companies whose regulated operating income over the three most 16

recently reported fiscal years comprised less than 60.00 percent of the respective 17

totals for that company; 18

• I excluded companies whose regulated electric operating income over the three 19

most recently reported fiscal years represented less than 60.00 percent of total 20

regulated operating income; 21

• I excluded companies with a market capitalization greater than $10.00 billion, or 22

“large cap” companies (OTTR is a “small cap” company); 23

• I excluded companies with more than 250 customers per square mile (OTP has 24

approximately four customers per square mile) to eliminate companies with service 25

territories primarily located in densely populated, or urban areas;12 26

12 See, Exhibit___(RBH-1), Schedule 9. OTP’s aggregate service area has a population of approximately

230,000, of which only approximately 126,000 residents live in communities with a population of at least

1,000. See, Otter Tail Corporation, SEC Form 10-K for the Period Ending December 31, 2016, at 6.

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• I eliminated companies that are currently known to be party to a merger or other 1

significant transaction; 2

Q. DID YOU INCLUDE OTTR IN YOUR ANALYSIS? 3

A. No. To avoid the circular logic that otherwise would occur, it is my practice to exclude the 4

subject company, or its parent holding company, from the proxy group. 5

Q. WHAT COMPANIES MET THOSE SCREENING CRITERIA? 6

A. The criteria discussed above resulted in a proxy group of the following nine companies: 7

Table 3: Proxy Group Screening Results 8

Company Ticker

ALLETE, Inc. ALE

Alliant Energy Corporation LNT

Black Hills Corporation BKH

El Paso Electric Company EE

Hawaiian Electric Industries, Inc. HE

IDACORP, Inc. IDA

NorthWestern Corporation NWE

OGE Energy Corp. OGE

PNM Resources, Inc. PNM

9

Q. DO YOU BELIEVE THAT A PROXY GROUP OF NINE COMPANIES IS 10

SUFFICIENTLY LARGE? 11

A. Yes, I do. The analyses performed in estimating the ROE are more likely to be 12

representative of the subject utility’s Cost of Equity to the extent that the chosen proxy 13

companies are fundamentally comparable to the subject utility. Because all analysts use 14

some form of screening process to arrive at a proxy group, the group, by definition, is not 15

randomly drawn from a larger population. Consequently, there is no reason to place more 16

reliance on the quantitative results of a larger proxy group simply by virtue of the resulting 17

larger number of observations. 18

19

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VI. COST OF EQUITY ESTIMATION

Q. PLEASE BRIEFLY DISCUSS THE ROE IN THE CONTEXT OF THE REGULATED 1

RATE OF RETURN. 2

A. Regulated utilities primarily use common stock and long-term debt to finance their 3

permanent property, plant, and equipment. The overall rate of return (“ROR”) for a 4

regulated utility is based on its weighted average Cost of Capital, in which the costs of the 5

individual sources of capital are weighted by their respective book values. As noted above, 6

the ROE is market-based and, therefore, must be estimated based on observable market 7

information. 8

Q. HOW IS THE REQUIRED ROE DETERMINED? 9

A. I estimated the ROE using analyses based on market data to quantify a range of investor 10

expectations of required equity returns. By their very nature, quantitative models produce 11

a range of results from which the market required ROE must be estimated. As discussed 12

throughout my Direct Testimony, that estimation must be based on a comprehensive review 13

of relevant data and information, and does not necessarily lend itself to a strict 14

mathematical solution. Consequently, the key consideration in determining the ROE is to 15

ensure that the overall analysis reasonably reflects investors’ view of the financial markets 16

in general, and the subject company (in the context of the proxy companies) in particular. 17

18

Because the Cost of Equity is not directly observable, it must be estimated based on both 19

quantitative and qualitative information. Although a number of empirical models have 20

been developed for that purpose, all are subject to limiting assumptions or other constraints. 21

Consequently, many finance texts recommend using multiple approaches to estimate the 22

Cost of Equity.13 When faced with the task of estimating the Cost of Equity, analysts and 23

investors are inclined to gather and evaluate as much relevant data as reasonably can be 24

analyzed and, therefore, rely on multiple analytical approaches. 25

26

13 See, e.g., Eugene Brigham, Louis Gapenski, Financial Management: Theory and Practice, 7th Ed., 1994, at

341, and Tom Copeland, Tim Koller and Jack Murrin, Valuation: Measuring and Managing the Value of

Companies, 3rd ed., 2000, at 214.

16

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I also note that as a practical matter, no individual model is more reliable than all others 1

under all market conditions. Therefore, it is both prudent and appropriate to use multiple 2

methodologies to mitigate the effects of assumptions and inputs associated with any single 3

approach. As such, I have considered the results of the Constant Growth and Multi-Stage 4

forms of the DCF model; the CAPM; and the Bond Yield Plus Risk Premium approach. 5

Constant Growth DCF Model 6

Q. PLEASE DESCRIBE THE CONSTANT GROWTH DCF APPROACH. 7

A. The Constant Growth DCF approach is based on the theory that a stock’s current price 8

represents the present value of all expected future cash flows. In its simplest form, the 9

Constant Growth DCF model expresses the Cost of Equity as the discount rate that sets the 10

current price equal to expected cash flows: 11

Equation [1] 12

where P0 represents the current stock price, D1 … D represent expected future dividends, 13

and k is the discount rate, or required ROE. Equation [1] is a standard present value 14

calculation that can be simplified and rearranged into the familiar form: 15

Equation [2] 16

Equation [2] is often referred to as the “Constant Growth DCF” model in which the first 17

term is the expected dividend yield and the second term is the expected long-term growth 18

rate. 19

Q. WHAT ASSUMPTIONS ARE REQUIRED FOR THE CONSTANT GROWTH DCF 20

MODEL? 21

A. The Constant Growth DCF model assumes: (1) earnings, book value, and dividends all 22

grow at the same, constant rate in perpetuity; (2) the dividend payout ratio remains 23

constant; (3) a Price to Earnings (“P/E”) multiple remains constant in perpetuity; and (4) 24

the discount rate is greater than the expected growth rate. 25

)1(...

)1()1( 2

210

k

D

k

D

k

DP

gP

gDk

0

)1(

17

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Q. WHAT MARKET DATA DID YOU USE TO CALCULATE THE DIVIDEND YIELD 1

IN YOUR DCF MODEL? 2

A. The dividend yield is based on the proxy companies’ current annualized dividend and 3

average closing stock prices over the 30-, 90-, and 180-trading day periods as of September 4

29, 2017. 5

Q. WHY DID YOU USE THREE AVERAGING PERIODS TO CALCULATE AN 6

AVERAGE STOCK PRICE? 7

A. I did so to ensure that the model’s results are not skewed by anomalous events that may 8

affect stock prices on any given trading day. At the same time, the averaging period should 9

be reasonably representative of expected capital market conditions over the long term. In 10

my view, using 30-, 90-, and 180-day averaging periods reasonably balances those 11

concerns. 12

Q. DID YOU MAKE ANY ADJUSTMENTS TO THE DIVIDEND YIELD TO ACCOUNT 13

FOR PERIODIC GROWTH IN DIVIDENDS? 14

A. Yes, I did. Since utility companies tend to increase their quarterly dividends at different 15

times throughout the year, it is reasonable to assume that dividend increases will be evenly 16

distributed over calendar quarters. Given that assumption, it is appropriate to calculate the 17

expected dividend yield by applying one-half of the long-term growth rate to the current 18

dividend yield. That adjustment ensures that the expected dividend yield is, on average, 19

representative of the coming twelve-month period, and does not overstate the dividends to 20

be paid during that time. 21

Q. IS IT IMPORTANT TO SELECT APPROPRIATE MEASURES OF LONG-TERM 22

GROWTH IN APPLYING THE DCF MODEL? 23

A. Yes. In its Constant Growth form, the DCF model (i.e., as presented in Equation [2] above) 24

assumes a single growth estimate in perpetuity. Accordingly, to reduce the long-term 25

growth rate to a single measure, one must assume a fixed payout ratio, and the same 26

constant growth rate for earnings per share (“EPS”), dividends per share, and book value 27

per share. Since dividend growth can only be sustained by earnings growth, the model 28

18

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should incorporate a variety of measures of long-term earnings growth. That can be 1

accomplished by averaging those measures of long-term growth that tend to be least 2

influenced by capital allocation decisions that companies may make in response to near-3

term changes in the business environment. Because such decisions may directly affect 4

near-term dividend payout ratios, estimates of earnings growth are more indicative of long-5

term investor expectations than are dividend growth estimates. For the purposes of the 6

Constant Growth DCF model, therefore, growth in EPS represents the appropriate measure 7

of long-term growth. 8

Q. PLEASE SUMMARIZE THE FINDINGS OF ACADEMIC RESEARCH ON THE 9

APPROPRIATE MEASURE FOR ESTIMATING EQUITY RETURNS USING THE 10

DCF MODEL. 11

A. The relationship between various growth rates and stock valuation metrics has been the 12

subject of much academic research.14 As noted over 40 years ago by Charles Phillips in 13

The Economics of Regulation: 14

For many years, it was thought that investors bought utility stocks largely 15

on the basis of dividends. More recently, however, studies indicate that the 16

market is valuing utility stocks with reference to total per share earnings, so 17

that the earnings-price ratio has assumed increased emphasis in rate cases.15 18

Phillips’ conclusion continues to hold true. Subsequent academic research has clearly and 19

consistently indicated that measures of earnings and cash flow are strongly related to 20

returns, and that analysts’ forecasts of growth are superior to other measures of growth in 21

predicting stock prices.16 For example, Vander Weide and Carleton state that “[our] results 22

… are consistent with the hypothesis that investors use analysts’ forecasts, rather than 23

14 See Harris, Robert, Using Analysts’ Growth Forecasts to Estimate Shareholder Required Rate of Return,

Financial Management (Spring 1986). 15 Charles F. Phillips, Jr., The Economics of Regulation, at 285 (Rev. ed. 1969). 16 See, e.g., Christofi, Christofi, Lori and Moliver, Evaluating Common Stocks Using Value Line’s Projected

Cash Flows and Implied Growth Rate, Journal of Investing (Spring 1999); Harris and Marston, Estimating

Shareholder Risk Premia Using Analysts’ Growth Forecasts, Financial Management, 21 (Summer 1992);

and Vander Weide and Carleton, Investor Growth Expectations: Analysts vs. History, The Journal of Portfolio

Management (Spring 1988).

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historically oriented growth calculations, in making stock buy-and-sell decisions.”17 Other 1

research specifically notes the importance of analysts’ growth estimates in determining the 2

Cost of Equity, and in the valuation of equity securities. Dr. Robert Harris noted that “a 3

growing body of knowledge shows that analysts’ earnings forecasts are indeed reflected in 4

stock prices.” Citing Cragg and Malkiel, Dr. Harris notes that those authors “found that 5

the evaluations of companies that analysts make are the sorts of ones on which market 6

valuation is based.”18 Similarly, Brigham, Shome, and Vinson noted that “evidence in the 7

current literature indicates that (i) analysts’ forecasts are superior to forecasts based solely 8

on time series data, and (ii) investors do rely on analysts’ forecasts.”19 9

10

To that point, the research of Carleton and Vander Weide demonstrates that earnings 11

growth projections have a statistically significant relationship to stock valuation levels, 12

while dividend growth rates do not.20 Those findings suggest that investors form their 13

investment decisions based on expectations of growth in earnings, not dividends. 14

Consequently, earnings growth, not dividend growth, is the appropriate estimate for the 15

purpose of the Constant Growth DCF model. 16

Q. PLEASE SUMMARIZE YOUR INPUTS TO THE CONSTANT GROWTH DCF 17

MODEL. 18

A. I applied the Constant Growth DCF model to the proxy group of electric utility companies 19

using the following inputs for the price and dividend terms: 20

• The average daily closing prices for the 30-trading days, 90-trading days, and 180-21

trading days ended September 29, 2017 for the term P0; and 22

17 Vander Weide and Carleton, Investor Growth Expectations: Analysts vs. History, The Journal of Portfolio

Management (Spring 1988). The Vander Weide and Carleton study was updated in 2004 under the direction

of Dr. Vander Weide. The results of the updated study were consistent with the original study’s conclusions. 18 Robert S. Harris, Using Analysts’ Growth Forecasts to Estimate Shareholder Required Rate of Return,

Financial Management (Spring 1986). 19 Eugene F. Brigham, Dilip K. Shome, and Steve R. Vinson, The Risk Premium Approach to Measuring a

Utility’s Cost of Equity, Financial Management (Spring 1985). 20 See Vander Weide and Carleton, Investor Growth Expectations: Analysts vs. History, The Journal of Portfolio

Management (Spring 1988).

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• The annualized dividend per share as of September 29, 2017 for the term D0. 1

I then calculated the DCF results using each of the following growth terms: 2

• The Zack’s consensus long-term EPS growth estimates; 3

• The First Call consensus long-term EPS growth estimates; and 4

• The Value Line EPS growth estimates. 5

Q. HOW DID YOU CALCULATE THE DCF RESULTS? 6

A. For each proxy company, I calculated the mean, mean high, and mean low results. For the 7

mean result, I combined the average of the EPS growth rate estimates reported by Value 8

Line, Zacks, and First Call with the subject company’s dividend yield for each proxy 9

company and then calculated the average result for those estimates. I calculated the high 10

DCF result by combining the maximum EPS growth rate estimate as reported by Value 11

Line, Zacks, and First Call with the subject company’s dividend yield. The mean high 12

result simply is the average of those estimates. I used the same approach to calculate the 13

low DCF result, using instead the minimum of the Value Line, Zacks, and First Call 14

estimate for each proxy company, and calculating the average result for those estimates. 15

16

The Constant Growth DCF model is predicated on a number of assumptions, one of which 17

is that the P/E ratio will remain constant, in perpetuity. Because the utility sector P/E ratios 18

have expanded to the point that they recently have exceeded both their long-term average 19

and the market P/E ratio, Constant Growth DCF model’s results should be viewed with 20

caution. As such, it is appropriate to consider additional methods, such as the Multi-Stage 21

DCF model, CAPM approach, and the Bond Yield Plus Risk Premium model. 22

Q. DID YOU MAKE ANY ADJUSTMENTS AS PART OF YOUR DCF ANALYSIS? 23

A. Yes, I made an adjustment for flotation costs. 24

Q. WHAT ARE FLOTATION COSTS? 25

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A. Flotation costs are the costs associated with the sale of new issues of common stock. These 1

include out-of-pocket expenditures for preparation, filing, underwriting, and other costs of 2

issuance. 3

Q. WHY IS IT IMPORTANT TO RECOGNIZE FLOTATION COSTS IN THE ALLOWED 4

ROE? 5

A. To attract and retain new investors, a regulated utility must have the opportunity to earn a 6

return that is both competitive and compensatory. To the extent a company is denied the 7

opportunity to recover prudently-incurred flotation costs, actual returns will fall short of 8

expected (or required) returns, thereby diminishing its ability to attract adequate capital on 9

reasonable terms. 10

Q. ARE FLOTATION COSTS PART OF THE UTILITY’S INVESTED COSTS OR PART 11

OF THE UTILITY’S EXPENSES? 12

A. Flotation costs are part of the invested costs of the utility, which are properly reflected on 13

the balance sheet under “paid in capital.” They are not current expenses, and therefore are 14

not reflected on the income statement. Rather, like investments in rate base or the issuance 15

costs of long-term debt, flotation costs are incurred over time. As a result, the great 16

majority of a utility’s flotation cost is incurred prior to the test year, but remains part of the 17

cost structure that exists during the test year and beyond, and as such, should be recognized 18

for ratemaking purposes. Therefore, even if no new issuances were planned in the near 19

future, recovery of flotation costs would be appropriate because failure to allow such cost 20

recovery could deny OTP the opportunity to earn its required rate of return in the future. 21

In this case, new issuances are planned as described in the Direct Testimony of OTP 22

witness Mr. Kevin G. Moug, which further supports the need for flotation cost recovery. 23

Q. DOES THE FACT THAT OTP IS A WHOLLY OWNED SUBSIDIARY OF OTTR 24

AFFECT THE NEED TO INCLUDE FLOTATION COSTS? 25

A. No. Although the Company is a wholly owned subsidiary of OTTR, it is appropriate to 26

consider flotation costs because wholly owned subsidiaries receive equity capital from their 27

parents and provide returns on the capital that roll up to the parent, which is designated to 28

22

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attract and raise capital based on the returns of those subsidiaries. This is important for 1

companies such as OTP that are planning continued capital expenditures in the near term, 2

and for which access to capital (at reasonable cost rates) to fund such required expenditures 3

will be critical. 4

Q. DO THE DCF AND CAPM MODELS ALREADY INCORPORATE INVESTOR 5

EXPECTATIONS OF A RETURN TO COMPENSATE FOR FLOTATION COSTS? 6

A. No. The models used to estimate the appropriate ROE assume no “friction” or transaction 7

costs, as these costs are not reflected in the market price (in the case of the DCF model) or 8

risk premium (in the case of the CAPM and the Bond Yield Plus Risk Premium model). 9

Q. IS THE NEED TO CONSIDER FLOTATION COSTS RECOGNIZED BY THE 10

ACADEMIC AND FINANCIAL COMMUNITIES? 11

A. Yes. The need to reimburse investors for equity issuance costs is recognized by the 12

academic and financial communities in the same spirit that investors are reimbursed for the 13

costs of issuing debt. That treatment is consistent with the philosophy of a fair rate of 14

return. As explained by Dr. Shannon Pratt: 15

Flotation costs occur when a company issues new stock. The business 16

usually incurs several kinds of flotation or transaction costs, which reduce 17

the actual proceeds received by the business. Some of these are direct out-18

of-pocket outlays, such as fees paid to underwriters, legal expenses, and 19

prospectus preparation costs. Because of this reduction in proceeds, the 20

business’s required returns must be greater to compensate for the additional 21

costs. Flotation costs can be accounted for either by amortizing the cost, 22

thus reducing the net cash flow to discount, or by incorporating the cost into 23

the cost of equity capital. Since flotation costs typically are not applied to 24

operating cash flow, they must be incorporated into the cost of equity 25

capital.21 26

Q. HAS OTTR RECENTLY ISSUED COMMON EQUITY? 27

A. Yes. As stated in the Direct Testimony of Mr. Moug, OTTR has had issuances of common 28

stock in 2014 through 2017, including issuances under OTTR’s “At the Market Program” 29

21 Shannon P. Pratt, Roger J. Grabowski, Cost of Capital: Applications and Examples, 4th ed. (John Wiley &

Sons, Inc., 2010), page 586.

23

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and under OTTR’s Employee Stock Purchase Plan and Dividend Reinvestment Plan.22 Mr. 1

Moug further explains that these OTTR common stock issuances are directly related to the 2

Company’s current and planned capital expenditures.23 OTTR has also publicly announced 3

its plans to use these programs to issue approximately $70 million to $85 million of 4

common equity during the 2017 through 2021 timeframe.24 5

Q. DID YOU CALCULATE A FLOTATION COST RECOVERY ADJUSTMENT? 6

A. Yes, I have. I modified the DCF calculation to derive the dividend yield that would 7

reimburse investors for direct issuance costs. Based on the weighted average issuance costs 8

shown in Exhibit___(RBH-1), Schedule 2, a reasonable estimate of flotation costs is 9

approximately 0.11 percent (11 basis points). 10

Q. DID YOU CONSIDER ANY OTHER INFORMATION TO ESTIMATE THE RESULTS 11

OF YOUR CONSTANT GROWTH DCF ANALYSIS? 12

A. It is important to review the extent of model results within the context of the current capital 13

market environment. That is especially true with DCF-based models, which assume that 14

the conditions prevailing at the time the model is applied will remain in place in perpetuity. 15

The point simply is that in the short-run, prices may be influenced by temporary demand, 16

with utility stocks subject to the type of “risk-on/risk-off” dynamics that cause investors to 17

move into or out of securities for reasons other than long-term, fundamental valuation. 18

Because DCF-based models assume current prices measure long-term, fundamental value, 19

it is extremely important to interpret their results in the context of other observable data. 20

Failing to do so could produce results that fall far from investors’ required returns, putting 21

the Company at a significant disadvantage in its ability to raise capital. 22

Q. DID YOU MAKE ANY ADJUSTMENTS TO YOUR CONSTANT GROWTH DCF 23

RESULTS BECAUSE OF THOSE CONSIDERATIONS? 24

22 Direct Testimony of Kevin G. Moug, at 21; Exhibit___(KGM-1), Schedule 8. 23 Ibid. 24 Ibid.

24

Case No. PU-17-

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A. Yes, I did. I first estimated the Constant Growth DCF results of each of the proxy 1

companies. Three companies, Hawaiian Electric Industries, Inc., IDACORP, Inc., and 2

Northwestern Corporation, had Constant Growth DCF results of 6.04 percent to 6.65 3

percent using the 30-day average stock price. Those results are approximately 305 to 365 4

basis points below the average authorized return in 2017, and approximately 235 to 295 5

basis points below the lowest authorized return ever for a vertically integrated electric 6

utility. As such, I believe it is more reasonable to consider the Constant Growth DCF 7

results excluding those companies. These results also underscore the need to consider the 8

results of approaches other than the Constant Growth DCF under current market 9

conditions. 10

Q. WHAT ARE THE RESULTS OF YOUR CONSTANT GROWTH DCF ANALYSES? 11

A. My Constant Growth DCF results, excluding the three companies noted above, are 12

summarized in Table 4 below (see also Exhibit __(RBH-1), Schedule 1). 13

Table 4: Constant Growth DCF Results25 14

Mean Low Mean Mean High

30-Day Average 8.05% 9.26% 10.19%

90-Day Average 8.12% 9.33% 10.26%

180-Day Average 8.22% 9.43% 10.36%

15

As noted above, current market conditions are incompatible with the underlying 16

assumptions of the Constant Growth DCF model. Considering the results of the other 17

analytical models and the business risks faced by the Company, the mean high results in 18

Table 4 represent a more reasonable estimate of the Company’s ROE. 19

20

Multi-Stage Discounted Cash Flow Model 21

Q. WHAT OTHER FORMS OF THE DCF MODEL HAVE YOU USED? 22

25 Results include flotation costs. See, also Exhibit __(RBH-1), Schedule 1.

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A. To address certain limiting assumptions underlying the Constant Growth form of the DCF 1

model, I also applied the Multi-Stage (three-stage) Discounted Cash Flow Model. The 2

Multi-Stage model, which is an extension of the Constant Growth form and has been 3

applied in regulatory proceedings, enables the analyst to specify growth rates over three 4

distinct stages. As with the Constant Growth form of the DCF model, the Multi-Stage form 5

defines the Cost of Equity as the discount rate setting the current price equal to the 6

discounted value of future cash flows. Unlike the Constant Growth form, however, the 7

Multi-Stage model must be solved in an iterative fashion. 8

Q. PLEASE SUMMARIZE WHY YOU HAVE INCLUDED THE MULTI-STAGE DCF 9

MODEL AMONG THOSE USED TO ESTIMATE THE COST OF EQUITY. 10

A. First, it is both prudent and appropriate to use multiple methodologies to mitigate the 11

effects of assumptions and inputs associated with any single approach. Second, the 12

Constant Growth DCF model assumes earnings, dividends, and book value will grow at 13

the same, constant rate in perpetuity; that the payout ratio will remain constant in 14

perpetuity; and that the P/E ratio will remain constant. The Constant Growth DCF model 15

further assumes that the return required today will be the same return required every year 16

in the future. Those assumptions, however, are not likely to hold. In particular, it is likely 17

that over time, payout ratios will increase from their current levels and, to the extent long-18

term interest rates increase over the next few years, it is likely the Cost of Equity also will 19

increase. In my view, the Multi-Stage DCF model enables analysts to consider those 20

issues, and to address the limiting and likely unrealistic assumptions underlying the 21

Constant Growth form of the model. 22

Q. PLEASE GENERALLY DESCRIBE THE STRUCTURE OF YOUR MULTI-STAGE 23

MODEL. 24

A. As noted above, the model sets the subject company’s stock price equal to the present value 25

of future cash flows received over three “stages.” In the first two stages, “cash flows” are 26

defined as projected dividends. In the third stage, “cash flows” equal both dividends and 27

the expected price at which the stock will be sold at the end of the period (i.e., the “terminal 28

price”). I calculated the terminal price based on the Gordon model, which defines the price 29

26

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as the expected dividend divided by the difference between the Cost of Equity (i.e., the 1

discount rate) and the long-term expected growth rate. In essence, the terminal price is 2

defined by the present value of the remaining “cash flows” in perpetuity. In each of the 3

three stages, the dividend is the product of the projected earnings per share and the expected 4

dividend payout ratio. A summary description of the model is provided in Table 5 (below). 5

Table 5: Multi-Stage DCF Structure 6

Stage 0 1 2 3

Cash Flow

Component

Initial Stock

Price

Expected

Dividend

Expected

Dividend

Expected

Dividend +

Terminal

Value

Inputs Stock Price;

EPS;

Dividends

Per Share

(“DPS”)

Expected

EPS;

Expected

DPS

Expected

EPS;

Expected

DPS

Expected

EPS;

Expected

DPS;

Terminal

Value

Assumptions 30-, 90-, and

180-day

average stock

price

EPS Growth

Rate;

Payout Ratio

Growth Rate

Change;

Payout Ratio

Change

Long-term

Growth Rate;

Long-term

Payout Ratio

7

Q. WHAT ARE THE ANALYTICAL BENEFITS OF YOUR THREE-STAGE MODEL? 8

A. The principal benefits relate to the flexibility provided by the model’s formulation. 9

Because the model provides the ability to specify near-term, intermediate, and long-term 10

growth rates, for example, it avoids the sometimes-limiting assumption that the subject 11

company will grow at the same, constant rate in perpetuity. In addition, by calculating the 12

dividend as the product of earnings and the payout ratio, the model enables analysts to 13

reflect assumptions regarding the timing and extent of changes in the payout ratio to reflect, 14

for example, increases or decreases in expected capital spending, or transition from current 15

payout levels to long-term expected levels. In that regard, because the model is not limited 16

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to a single provider, such as Value Line, for all inputs, it mitigates the potential bias 1

associated with relying on a single source of growth rate projections.26 2

3

The Multi-Stage model also enables the analyst to assess the reasonableness of the inputs 4

and results by reference to certain market-based metrics. For example, the terminal stock 5

price can be divided by the expected earnings per share in the terminal year to calculate the 6

expected P/E ratio. Similarly, the terminal P/E ratio can be divided by the terminal growth 7

rate to develop a Price to Earnings Growth (“PEG”) ratio. To the extent the projected P/E 8

or PEG ratios are inconsistent with historical experience, it may indicate incorrect or 9

inconsistent assumptions within the balance of the model. 10

Q. PLEASE SUMMARIZE YOUR INPUTS TO THE MULTI-STAGE DCF MODEL. 11

A. I applied the Multi-Stage model to the proxy group described earlier in my Direct 12

Testimony. My assumptions with respect to the various model inputs are described in 13

Table 6 (below). 14

26 See, for example, Harris and Marston, Estimating Shareholder Risk Premia Using Analysts’ Growth

Forecasts, Financial Management, 21 (Summer 1992).

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Table 6: Multi-Stage DCF Model Assumptions 1

Stage Initial First Transition Terminal

Stock Price 30-, 90-, and

180-day

average stock

price as of

September

29, 2017

Earnings

Growth

2016 actual

EPS escalated

by Period 1

growth rate

EPS growth

as average of:

(1) Value

Line; (2)

Zacks; (3)

First Call

Transition to

Long-term

GDP growth

Long-term GDP

growth

Payout Ratio Value Line

company-

specific

Transition to

long-term

industry

payout ratio

Long-term expected

payout ratio

Terminal

Value

Expected dividend in

final year divided by

solved Cost of Equity

less long-term growth

rate

2

Q. HOW DID YOU CALCULATE THE LONG-TERM GDP GROWTH RATE? 3

A. The long-term growth rate of 5.35 percent is based on the real GDP growth rate of 3.22 4

percent from 1929 through 2016, and an inflation rate of 2.05 percent. The GDP growth 5

rate is calculated as the compound growth rate in the chain-weighted GDP for the period 6

from 1929 through 2016.27 The rate of inflation of 2.05 percent is an average of two 7

components: (1) the compound annual forward rate starting in ten years (i.e., 2027, which 8

is the beginning of the terminal period) based on the 30-day average spread between yields 9

on long-term nominal Treasury Securities and long-term Treasury Inflation Protected 10

27 See, Bureau of Economic Analysis, “Current-Dollar and ‘Real’ Gross Domestic Product,” September 28,

2017 update.

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Securities, known as the “TIPS spread” of 1.91 percent;28 and (2) and the projected Blue 1

Chip Financial Forecast of the CPI for 2024 – 2028 of 2.20 percent.29 2

3

In essence, the real GDP growth rate projection is based on the assumption that absent 4

specific knowledge to the contrary, it is reasonable to assume that over time, real GDP 5

growth will revert to its long-term mean. In addition, because estimating the Cost of Equity 6

is a market-based exercise, it is important to reflect, to the extent possible, the sentiments 7

and expectations of investors; those expectations are directly captured in the market-based 8

measure of inflation. In that important respect, the TIPS spread represents the collective 9

views of investors regarding long-term inflation expectations. Equally important, by using 10

forward yields, we are able to infer the level of long-term inflation expected by investors 11

as of the terminal period of the Multi-Stage model (that is, ten years in the future). 12

Q. WHAT WERE YOUR SPECIFIC ASSUMPTIONS WITH RESPECT TO THE PAYOUT 13

RATIO? 14

A. As noted in Table 6, for the first two periods I relied on the first year and long-term 15

projected payout ratios reported by Value Line30 for each of the proxy group companies. I 16

then assumed that, by the end of the second period (i.e., the end of year 10), the payout 17

ratio will converge to the long-term industry average of 64.42 percent.31 18

Q. WHAT WAS YOUR PRINCIPAL ASSUMPTION REGARDING THE TERMINAL 19

VALUE? 20

A. Although I performed a series of analyses in which the terminal value is calculated based 21

on the assumed long-term nominal GDP growth rate,32 I also performed a series of analyses 22

28 See, Board of Governors of the Federal Reserve System, “Table H.15 Selected Interest Rates.” 29 Blue Chip Financial Forecasts, June 1, 2017, at 14. 30 As reported in the Value Line Investment Survey as “All Div’ds to Net Prof.” 31 Source: Bloomberg Professional. The assumption of mean reversion in payout ratios is consistent with

published texts. As noted by Morin, “Most firms, including utilities, tend to maintain a fixed payout ratio

when it is averaged over several years.” See Roger A. Morin, PhD, New Regulatory Finance, Public Utilities

Reports, June 2006, at 258. 32 See, Exhibit __(RBH-1), Schedule 3.

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in which the terminal value is based on the current P/E ratio.33 The results of that analysis 1

are shown in Table 7, below (see also Exhibit __(RBH-1), Schedule 3). 2

Table 7: Multi-Stage DCF Results, Terminal P/E Method34 3

Low Mean High

30-Day Average 8.49% 9.15% 9.77%

90-Day Average 8.65% 9.31% 9.93%

180-Day Average 8.91% 9.57% 10.19%

4

Q. DID YOU UNDERTAKE ANY ADDITIONAL ANALYSES TO SUPPORT YOUR 5

RECOMMENDATION? 6

A. Yes, I also applied the CAPM and Risk Premium approaches. 7

8

CAPM Analysis 9

Q. PLEASE BRIEFLY DESCRIBE THE GENERAL FORM OF THE CAPM. 10

A. The CAPM is a risk premium method that estimates the Cost of Equity for a given security 11

as a function of a risk-free return plus a risk premium (to compensate investors for the non-12

diversifiable or “systematic” risk of that security). As shown in Equation [3], the CAPM 13

is defined by four components, each of which theoretically must be a forward-looking 14

estimate: 15

Ke = rf + β(rm – rf) Equation [3] 16

where: 17

Ke = the required market ROE; 18

β = Beta of an individual security; 19

rf = the risk-free rate of return; and 20

rm = the required return on the market as a whole. 21

33 Defined as the 30-day average of the proxy group P/E ratio, calculated as an Index. 34 Results include flotation costs. See, Exhibit __(RBH-1), Schedule 3.

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1

In Equation [3], the term (rm – rf) represents the Market Risk Premium.35 According to the 2

theory underlying the CAPM, since unsystematic risk can be diversified away by adding 3

securities to investment portfolios, investors should be concerned only with systematic or 4

non-diversifiable risk. Non-diversifiable risk is measured by the Beta coefficient, which is 5

defined as: 6

Equation [4] 7

Where is the standard deviation of returns for company “j,” is the standard deviation 8

of returns for the broad market (as measured, for example, by the S&P 500 Index), and 9

is the correlation of returns in between company j and the broad market. The Beta 10

coefficient therefore represents both relative volatility (i.e., the standard deviation) of 11

returns and the correlation in returns between the subject company and the overall market. 12

Intuitively, higher Beta coefficients indicate that the subject company’s returns have 13

moved in tandem with the overall market. Consequently, if a company has a Beta 14

coefficient of 1.00, it is as risky as the market and does not provide any diversification 15

benefit. 16

Q. WHAT ASSUMPTIONS DID YOU INCLUDE IN YOUR CAPM ANALYSIS? 17

A. Since utility equity is a long duration investment, I used two different measures of the risk-18

free rate: (1) the current 30-day average yield on 30-year Treasury bonds (i.e., 2.77 19

percent); and (2) the near-term projected 30-year Treasury yield (i.e., 3.30 percent). 20

Q. WHY HAVE YOU RELIED ON THE 30-YEAR TREASURY YIELD FOR YOUR 21

CAPM ANALYSIS? 22

A. In determining the security most relevant to the application of the CAPM, it is important 23

to select the term (or maturity) that best matches the life of the underlying investment. 24

35 The Market Risk Premium is defined as the incremental return of the market portfolio over the risk-free rate.

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Electric utilities typically are long-duration investments and, as such, the 30-year Treasury 1

yield is more suitable for the purpose of calculating the Cost of Equity. 2

Q. PLEASE DESCRIBE YOUR EX-ANTE APPROACH TO ESTIMATING THE MARKET 3

RISK PREMIUM. 4

A. The approach is based on the market-required return, less the current 30-year Treasury 5

yield. To estimate the market required return, I calculated the market capitalization 6

weighted average total return based on the Constant Growth DCF model. To do so, I relied 7

on data from two sources: (1) Bloomberg; and (2) Value Line. With respect to Bloomberg-8

derived growth estimates, I calculated the expected dividend yield (using the same one-9

half growth rate assumption described earlier), and combined that amount with the 10

projected earnings growth rate to arrive at the market capitalization weighted average DCF 11

result. I performed that calculation for each of the S&P 500 companies for which 12

Bloomberg provided consensus growth rates. I then subtracted the current 30-year 13

Treasury yield from that amount to arrive at the market DCF-derived ex-ante market risk 14

premium estimate. In the case of Value Line, I performed the same calculation, again using 15

all companies for which five-year earnings growth rates were available. The results of 16

those calculations are provided in Exhibit __(RBH-1), Schedule 4. 17

Q. HOW DID YOU APPLY YOUR EXPECTED MARKET RISK PREMIUM AND RISK-18

FREE RATE ESTIMATES? 19

A. I relied on the ex-ante Market Risk Premia discussed above, together with the current and 20

near-term projected 30-year Treasury yields as inputs to my CAPM analyses. 21

Q. WHAT BETA COEFFICIENT DID YOU USE IN YOUR CAPM MODEL? 22

A. As shown in Exhibit __(RBH-1), Schedule 5, I considered the Beta coefficients reported 23

by Bloomberg and Value Line. While both of those services adjust their calculated (or 24

“raw”) Beta coefficients to reflect the tendency of the Beta coefficient to regress to the 25

market mean of 1.00, Value Line calculates the Beta coefficient over a five-year period, 26

while Bloomberg’s calculation is based on two years of data. 27

Q. WHAT ARE THE RESULTS OF YOUR CAPM ANALYSES? 28

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A. As shown in Table 8 (below) the CAPM analyses suggest an ROE range of 9.42 percent to 1

12.04 percent (see also Exhibit __(RBH-1), Schedule 6). 2

Table 8: Summary of CAPM Results36 3

Bloomberg

Derived

Market Risk

Premium

Value Line

Derived

Market Risk

Premium







4

Bond Yield Plus Risk Premium Analysis 5

Q. PLEASE DESCRIBE THE BOND YIELD PLUS RISK PREMIUM APPROACH. 6

A. This approach is based on the basic financial tenet that equity investors bear the residual 7

risk associated with ownership and therefore require a premium over the return they would 8

have earned as a bondholder. That is, since returns to equity holders are more risky than 9

returns to bondholders, equity investors must be compensated for bearing that additional 10

risk. Risk premium approaches, therefore, estimate the Cost of Equity as the sum of the 11

equity risk premium and the yield on a particular class of bonds. As noted in my discussion 12

of the CAPM, since the equity risk premium is not directly observable, it typically is 13

estimated using a variety of approaches, some of which incorporate ex-ante, or forward-14

looking estimates of the Cost of Equity, and others that consider historical, or ex-post, 15

estimates. An alternative approach is to use actual authorized returns for electric utilities 16

to estimate the Equity Risk Premium. 17

Q. PLEASE EXPLAIN HOW YOU PERFORMED YOUR BOND YIELD PLUS RISK 18

PREMIUM ANALYSIS. 19

36 See Exhibit __(RBH-1), Schedule 6.

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A. As suggested above, I first defined the Risk Premium as the difference between the 1

authorized ROE and the then-prevailing level of long-term (i.e., 30-year) Treasury yield. I 2

used the current and near-term 30-year Treasury yield discussed earlier and a long-term 3

projected 30-year Treasury yield as well. I then gathered data for 1,522 electric utility rate 4

proceedings between January 1980 and September 29, 2017. In addition to the authorized 5

ROE, I also calculated the average period between the filing of the case and the date of the 6

final order (the “lag period”). To reflect the prevailing level of interest rates during the 7

pendency of the proceedings, I calculated the average 30-year Treasury yield over the 8

average lag period (approximately 201 days). 9

10

Because the data cover a number of economic cycles, the analysis also may be used to 11

assess the stability of the Equity Risk Premium. Prior research, for example, has shown 12

that the Equity Risk Premium is inversely related to the level of interest rates. That analysis 13

is particularly relevant given the relatively low, but increasing level of current Treasury 14

yields. 15

Q. HOW DID YOU ANALYZE THE RELATIONSHIP BETWEEN INTEREST RATES 16

AND THE EQUITY RISK PREMIUM? 17

A. The basic method used was regression analysis, in which the observed Equity Risk 18

Premium is the dependent variable, and the average 30-year Treasury yield is the 19

independent variable. Relative to the long-term historical average, the analytical period 20

includes interest rates and authorized ROEs that are quite high during one period (i.e., the 21

1980s) and that are quite low during another (i.e., the post-Lehman bankruptcy period). To 22

account for that variability, I used the semi-log regression, in which the Equity Risk 23

Premium is expressed as a function of the natural log of the 30-year Treasury yield (“T30”): 24

Equation [5] 25

As shown on Chart 1 (below), the semi-log form is useful when measuring an absolute 26

change in the dependent variable (in this case, the Risk Premium) relative to a proportional 27

change in the independent variable (the 30-year Treasury yield). 28

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Chart 1: Equity Risk Premium37 1

2

As Chart 1 illustrates, over time there has been a statistically significant, negative 3

relationship between the 30-year Treasury yield and the Equity Risk Premium. 4

Consequently, simply applying the long-term average Equity Risk Premium of 4.49 percent 5

would significantly understate the Cost of Equity and produce results well below any 6

reasonable estimate. Based on the regression coefficients in Chart 1, however, the implied 7

ROE is between 9.96 percent and 10.33 percent (see Table 9 and Exhibit __(RBH-1), 8

Schedule 7). 9

Table 9: Summary of Bond Yield Plus Risk Premium Results38 10

Return on Equity



Long-Term Projected 30-Year Treasury (4.40%) 10.33%

11

37 See Exhibit __(RBH-1), Schedule 7. 38 See Exhibit __(RBH-1), Schedule 7.

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VII. BUSINESS RISKS AND OTHER CONSIDERATIONS

Q. WHAT ADDITIONAL INFORMATION DID YOU CONSIDER IN ASSESSING THE 1

ANALYTICAL RESULTS NOTED ABOVE? 2

A. Because the analytical methods discussed above provide a range of estimates, there are 3

several additional factors that should be taken into consideration when establishing a 4

reasonable range for the Company’s Cost of Equity. In my view, there are additional 5

factors that must be taken into consideration when determining where OTP’s Cost of 6

Equity falls within the range of results for the Proxy Group. Those factors include OTP’s 7

planned capital investment program, small size, degree of customer concentration, other 8

market data, including institutional ownership, trading volumes and liquidity, and relative 9

Beta coefficients. Those factors, which are discussed below, should be considered in terms 10

of their overall effect on OTP’s business risk and, therefore, its Cost of Equity. Doing so 11

is consistent with both cost-based regulations. And as noted earlier, given the Company’s 12

substantial capital investment plan, it will be important to set a return that will enhance 13

internally generated funds and enable access to capital markets at reasonable terms. OTP’s 14

combination of low customer rates, cost savings, and providing a high quality of service 15

also merit consideration by the Commission in determining OTP’s ROE. Considering 16

these factors when setting the ROE is consistent with the long-standing latitude of 17

regulators to recognize low cost, efficient service in setting a compensating return. 18

19

Capital Expenditures 20

Q. PLEASE SUMMARIZE OTP’S CAPITAL EXPENDITURE PLANS. 21

A. The Company’s capital expenditure program is significant. As discussed in more detail 22

below, that investment represents a significant increase over its existing net plant. As also 23

discussed below, in the context of existing net plant, the Company’s capital investment 24

plans are substantial relative to the proxy companies’ projected capital expenditures and 25

are substantially above the average of the proxy companies. 26

Q. HOW DO OTP’S EXPECTED CAPITAL EXPENDITURES COMPARE TO THE 27

PROXY GROUP? 28

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A. OTP currently plans to invest approximately $862 million of additional capital over the 1

five-year period from 2017-2021.39 To reasonably compare that level of investment to the 2

proxy companies, I calculated the ratio of expected capital expenditures to net plant for 3

each of the companies in the proxy group. For the period 2017-2021, I performed that 4

calculation using the Company’s projected capital expenditures relative to its total net plant 5

as of December 31, 2016. As shown in Exhibit __(RBH-1), Schedule 8, and Chart 2 below, 6

relative to the proxy group, OTP’s ratio of projected capital expenditures to net plant is 7

65.94 percent, which is the second highest of any of the proxy companies. OTP’s ratio of 8

projected capital expenditures to net plant is only approximately 1.00 percentage point 9

lower than the company with the highest ratio, but is over 18.00 percentage points above 10

the next highest proxy company. 11

Chart 2: Capital Expenditures 12

13

14

As a further point of reference, I compared OTP’s ratio of projected capital expenditures 15

to net plant to the comparable ratio for Northern States Power Company and for MDU 16

Resources Group Inc. (“MDU”). OTP’s 65.94 percent projected capital expenditure ratio 17

is higher than Northern States Power Company’s 48.91 percent ratio and MDU’s 56.27 18

39 Direct Testimony of Kevin G. Moug, at 11.

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percent ratio. As described in more detail below, pressure on cash flows from high levels 1

of capital expenditures places downward pressure on credit metrics. 2

Q. DO CREDIT RATING AGENCIES RECOGNIZE RISK ASSOCIATED WITH 3

INCREASED CAPITAL EXPENDITURES? 4

A. Yes, they do. From the perspective of debt investors, the additional pressure on cash flows 5

associated with high levels of capital expenditures exerts corresponding pressure on credit 6

metrics and, therefore, credit ratings. S&P has noted that: 7

For regulated utilities, infrastructure spending leads to rate-base growth. 8

But for a company to preserve its financial strength, it must be able to 9

quickly begin recovering this spending. 10

*** 11

To retain critical access to the debt markets, utilities will need to continue 12

to seek and receive supportive cost recovery from regulators.40 13

14

The rating agency views noted above also are consistent with certain observations 15

discussed earlier in my testimony: (1) the benefits of maintaining a strong financial profile 16

are significant when capital access is required, and become particularly acute during 17

periods of market instability; and (2) the Commission’s decision in this proceeding will 18

have a direct bearing on the Company’s credit profile, and its ability to access the capital 19

needed to fund its investments. 20

Q. DO SUBSTANTIAL CAPITAL EXPENDITURES DIRECTLY RELATE TO A 21

UTILITY TO BEING ALLOWED THE OPPORTUNITY TO EARN A RETURN 22

ADEQUATE TO ATTRACT CAPITAL AT REASONABLE TERMS? 23

A. Yes, they do. The allowed ROE should enable the subject utility to finance capital 24

expenditures and working capital requirements at reasonable rates, and to maintain its 25

financial integrity in a variety of economic and capital market conditions. As discussed 26

throughout my Direct Testimony, a return that is adequate to attract capital at reasonable 27

40 Standard & Poor’s, U.S. Utilities’ Capital Spending is Rising, and Cost-Recovery is Vital, RatingsDirect,

May 14, 2012, at 6.

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terms enables the utility to provide safe, reliable service while maintaining its financial 1

soundness. To the extent a utility is provided the opportunity to earn its market-based cost 2

of capital, neither customers nor shareholders should be disadvantaged. These 3

requirements are of particular importance to a utility when it is engaged in a substantial 4

capital expenditure program. 5

6

The ratemaking process is predicated on the principle that, for investors and companies to 7

commit the capital needed to provide safe and reliable utility services, the utility must have 8

the opportunity to recover the return of, and the market-required return on, invested capital. 9

Regulatory commissions recognize that since utility operations are capital intensive, 10

regulatory decisions should enable the utility to attract capital at reasonable terms; doing 11

so balances the long-term interests of the utility and its ratepayers. 12

13

Further, the financial community carefully monitors the current and expected financial 14

condition of utility companies, as well as the regulatory environment in which those 15

companies operate. In that respect, the regulatory environment is one of the most important 16

factors considered in both debt and equity investors’ assessments of risk. That is especially 17

important during periods in which the utility expects to make significant capital 18

investments and, therefore, may require access to capital markets. 19

Q. WILL OTP NEED CONTINUED ACCESS TO THE CAPITAL MARKETS TO 20

FINANCE ITS CAPITAL EXPENDITURE PLAN? 21

A. Yes. As discussed by Mr. Moug, although OTP has been retaining a significant portion of 22

its earnings which are being used to finance its capital expenditures, it will require 23

continued access to the capital markets, at reasonable terms, to finance its capital 24

expenditure plan.41 25

Q. WHAT ARE YOUR CONCLUSIONS REGARDING THE EFFECT OF OTP’S 26

CAPITAL INVESTMENT PLAN ON ITS RISK PROFILE AND COST OF CAPITAL? 27

41 Direct Testimony of Kevin G. Moug, at 12.

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A. It is clear that OTP is projecting a substantial capital expenditure program over the next 1

five years that will require continued access to the capital markets. It also is clear that 2

equity investors and credit rating agencies recognize the additional risks associated with 3

substantial capital expenditures. These additional risk factors suggest that an ROE toward 4

the upper end of the reasonable range of returns would be appropriate. As such, the 5

Commission’s decision in this proceeding will have a direct bearing on OTP’s ability to 6

maintain its financial profile, and its ability to access the capital market at reasonable cost 7

rates. 8

Q. HAVE YOU CONSIDERED OTP’S EXTENSIVE CAPITAL EXPENDITURES IN 9

YOUR RECOMMENDED RETURN ON EQUITY FOR OTP? 10

A. Yes, I have. Although I have not quantified the effect of OTP’s extensive capital 11

expenditures, or proposed a specific premium, I have considered OTP’s relative level of 12

capital expenditures in my assessment of business risks to determine where, within a 13

reasonable range of returns, OTP’s required ROE appropriately falls. 14

15

Small Size 16

Q. PLEASE EXPLAIN THE RISK ASSOCIATED WITH SMALL SIZE. 17

A. Both the financial and academic communities have long accepted the proposition that the 18

Cost of Equity for small firms is subject to a “size effect”.42 Although empirical evidence 19

of the size effect often is based on studies of industries beyond regulated utilities, utility 20

analysts also have noted the risks with associated small market capitalizations. 21

Specifically, Ibbotson Associates noted: 22

For small utilities, investors face additional obstacles, such as smaller 23

customer base, limited financial resources, and a lack of diversification 24

42 See, Mario Levis, The record on small companies: A review of the evidence, Journal of Asset Management

2, March 2002, at 368-397, for a review of literature relating to the size effect.

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across customers, energy sources, and geography. These obstacles imply 1

a higher investor return.43 2

Small size, therefore, leads to two categories of increased risk for investors: (1) liquidity 3

risk (i.e., the risk of not being able to sell one’s shares in a timely manner due to the 4

relatively thin market for the securities); and (2) fundamental business risks. 5

Q. HOW DOES OTP COMPARE IN SIZE TO THE PROXY COMPANIES? 6

A. OTP is substantially smaller than the average for the proxy group companies both in terms 7

of numbers of customers and annual revenues. Exhibit__(RBH-1), Schedule 9 estimates 8

the implied market capitalization for OTP (i.e., the implied market capitalization if the 9

Company were a stand-alone, publicly traded entity). That is, since OTP is a subsidiary of 10

OTTR, an estimated stand-alone market capitalization for OTP must be calculated. To do 11

so, I applied the median market to book ratio for the nine member proxy group to OTP’s 12

implied equity of $186 million.44 The implied market capitalization based on that 13

calculation is $382 million, which is approximately 10.00 percent of the median level of 14

the proxy group and approximately 17.00 percent of the smallest of the proxy companies. 15

I also note that OTTR’s market capitalization of $1.68 billion is smaller than any of the 16

proxy companies. 17

Q. HOW DOES THE SMALLER SIZE OF OTP AFFECT ITS BUSINESS RISKS 18

RELATIVE TO THE PROXY GROUP OF COMPANIES? 19

A. In general, smaller companies are less able to withstand adverse events that affect their 20

revenues and expenses. The effect of weather variability, the loss of large customers to 21

bypass opportunities, or the destruction of demand as a result of general macroeconomic 22

conditions or fuel price volatility will have a proportionately greater impact on the earnings 23

and cash flow volatility of smaller utilities. Similarly, capital expenditures for non-revenue 24

producing investments such as system maintenance and replacements will put 25

proportionately greater pressure on customer costs, potentially leading to customer attrition 26

43 Michael Annin, Equity and the Small-Stock Effect, Public Utilities Fortnightly, October 15, 1995. 44 The implied market capitalization was calculated by applying the proposed equity ratio of 52.50 percent to

the proposed rate base for the Company (i.e., $354 million).

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or demand reduction. Taken together, these risks affect the return required by investors for 1

smaller companies. 2

Q. IS THERE SUPPORT IN THE FINANCIAL COMMUNITY FOR THE USE OF A 3

SMALL SIZE PREMIUM? 4

A. Yes, there have been several studies conducted that demonstrate the size premium. One of 5

the earliest works in this area found that over a period of 40 years “the common stock of 6

small firms had, on average, higher risk-adjusted returns than the common stock of large 7

firms.”45 The author, who referred to that finding as the “size effect,” suggested that the 8

CAPM was mis-specified in that on average, smaller firms had significantly larger risk-9

adjusted returns than larger firms. The author also concluded that the size effect was “most 10

pronounced for the smallest firms in the sample.”46 Since then, additional empirical 11

research has focused on explaining the size effect as a function of lower trading volume 12

and other factors, but the proposition that Beta fails to reflect the risks of smaller firms 13

persists.47 14

15

In 1994, Fama and French also focused on the issue of whether the CAPM adequately 16

explained security returns and proposed a "three factor" model for expected security 17

returns. Those factors include: (1) the covariance with the market; (2) size; and (3) 18

financial risk as determined by the book-to-market ratio. As explained by Morningstar, 19

Fama and French “found that the returns on stocks are better explained as a function of size 20

and book-to-market value in addition to the single market factor of the CAPM, with the 21

company’s size capturing the size effect and its book-to-market ratio capturing the financial 22

distress of a firm.”48 23

Q. HOW DID YOU ESTIMATE THE SIZE PREMIUM FOR OTP? 24

45 R. W. Banz, The Relationship Between Return and Market Value of Common Stocks, Journal of Financial

Economics, 9, 1981. 46 Ibid. 47 See, for example, Mario Levis, The record on small companies: A review of the evidence, Journal of Asset

Management, March, 2002. 48 Morningstar, Ibbotson SBBI 2013 Valuation Yearbook, at 109.

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A. In its 2017 Valuation Handbook, Duff & Phelps presents its calculation of the size premium 1

for deciles of market capitalizations relative to the S&P 500 Index. An additional estimate 2

of the size premium associated with OTP, therefore, is the difference in the Duff & Phelps 3

size risk premiums for the proxy group median market capitalization relative to the implied 4

market capitalization for OTP. 5

6

As shown on Exhibit__(RBH-1), Schedule 9, based on recent market data, the median 7

market capitalization of the proxy group was approximately $3.72 billion, which 8

corresponds to the fourth decile of Duff & Phelps’s market capitalization data. Based on 9

the Duff & Phelps analysis, that decile has a size premium of 0.98 percent (or 98 basis 10

points). The implied market capitalization for OTP is approximately $382 million, which 11

falls within the ninth decile and corresponds to a size premium of 2.68 percent (or 268 12

basis points). The difference between those size premiums is 176 basis points (2.68 percent 13

– 0.98 percent). 14

Q. HAVE YOU CONSIDERED THE SMALLER SIZE OF OTP IN YOUR 15

RECOMMENDED RETURN ON EQUITY FOR OTP? 16

A. Yes. While I have quantified the small size effect, rather than proposing a specific 17

premium, I have considered the small size of OTP in my assessment of business risks to 18

determine where, within a reasonable range of returns, OTP’s required ROE appropriately 19

falls. 20

21

Customer Concentration 22

Q. HOW DOES OTP’S CUSTOMER CONCENTRATION AFFECT ITS BUSINESS RISK? 23

A. OTP’s customer base is largely comprised of commercial and industrial customers. 24

Approximately 69.50 percent of OTP’s total revenues, and 74.30 percent of its total sales 25

volume are attributable to sales to commercial and industrial customers.49 Relative to the 26

proxy group, OTP has the second highest commercial customer concentration by percent 27

49 Estimated as total sales less residential sales based on 2016 data.

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of revenues, and the second highest commercial customer concentration by percent of 1

volume (in kilowatt-hours) (see Exhibit__(RBH-1), Schedule 10). OTP’s dependence on 2

sales to commercial users subjects its operations to greater cash flow volatility, and risk of 3

demand destruction and bypass. Although OTP currently believes its rates are sufficiently 4

competitive to retain its commercial customers, OTP remains highly exposed to such risks. 5

Q. DOES THE ABSENCE OF ECONOMIC DIVERSITY IN OTP’S SERVICE 6

TERRITORY AFFECT THE COMPANY’S RISK PROFILE? 7

A. Yes. OTP’s service territory is predominantly agricultural.50 It generally is understood 8

that diversity is an important factor in the economic stability of a given market area. That 9

is, a diversified economy is less susceptible to the economic cycles of, or shocks associated 10

with a single industry. Consequently, a relatively undiversified market, such as that served 11

by OTP, represents meaningful financial risks to the host utility. 12

Q. HAVE YOU CONSIDERED THE LACK OF CUSTOMER AND ECONOMIC 13

DIVERSIFICATION OF OTP IN YOUR RECOMMENDED RETURN ON EQUITY 14

FOR OTP? 15

A. Yes. Although I have not proposed a specific premium, I have considered OTP’s higher 16

level of risk due to its lack of customer diversification in my assessment of business risks 17

to determine where, within a reasonable range of returns, OTP’s required ROE 18

appropriately falls. 19

20

Other Evidence of OTP’s Relatively Higher Cost of Equity 21

Q. ARE THERE OTHER OBSERVABLE FACTORS THAT SUPPORT YOUR POSITION 22

THAT OTP’S COST OF EQUITY FALLS IN THE UPPER END OF THE RANGE OF 23

ROE ESTIMATES? 24

A. Yes, there are. The Company’s relatively low degree of institutional ownership and the 25

low trading volume of its common stock indicate that investors require a “liquidity 26

50 Otter Tail Corporation, SEC Form 10-K for the Period Ending December 31, 2016, at 6.

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premium”. Although that premium is difficult to quantify, it does support the position that 1

OTP’s ROE should be set toward the upper end of the range of results. The position that 2

the ROE falls in the upper end of the range also is supported by OTTR’s relative risk as 3

measured by Beta coefficients. Those issues, and their implications for the Company’s 4

Cost of Equity, are discussed in more detail below. 5

Institutional Ownership 6

Q. AS A PRELIMINARY MATTER, WHAT IS “INSTITUTIONAL OWNERSHIP” AS IT 7

RELATES TO COMMON EQUITY? 8

A. Institutional ownership refers to the extent to which a given company’s common stock is 9

owned by large financial institutions, mutual funds, insurance companies, and 10

endowments.51 Because they tend to have more resources than retail investors, institutional 11

investors are able to perform more in-depth research, and tend to take larger positions in a 12

given company’s stock. A significant benefit of institutional investors to capital-intensive 13

companies such as OTP is that they tend to be an efficient source of equity capital. In 14

addition, because they buy and sell large stock positions based on their individual research 15

and portfolio objectives, institutional investors provide a significant source of liquidity. As 16

discussed below, a more liquid market means that an investor can sell stocks without the 17

risk of losing value. 18

19

There is little question that institutional ownership is important to equity investors. Value 20

Line, for example provides institutional buy and sell decisions (by quarter) as well as total 21

institutional ownership. Similarly, Yahoo! Finance reports institutional ownership as a 22

percentage of float and shares held. Because access to this efficient source of equity capital 23

and market liquidity is diminished, companies with lower levels of institutional ownership 24

are at a competitive disadvantage, and their investors face greater liquidity risk. Those 25

companies therefore must provide higher returns to compensate investors for that 26

disadvantaged position and incremental risk. As discussed below, that higher return has 27

been referred to as the “liquidity premium”. 28

51 As opposed to institutional ownership, “retail” ownership refers to ownership by individual investors.

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Q. HOW DOES OTTR’S PERCENTAGE OF INSTITUTIONAL OWNERSHIP COMPARE 1

TO THE UTILITIES INCLUDED IN THE PROXY GROUP? 2

A. OTTR’s 51.94 percent institutional ownership is significantly lower than any of the proxy 3

companies. More specifically, OTTR’s institutional ownership is significantly below the 4

86.89 percent average institutional ownership of my proxy group. OTTR’s institutional 5

ownership is also below that of MDU and Xcel Energy, Inc. (“Xcel Energy”), 66.23 percent 6

and 77.71 percent, respectively. The relative portions of institutional ownership are 7

provided in Exhibit__(RBH-1), Schedule 11. Because OTTR’s level of institutional 8

ownership is significantly below its peers, there is a lower level of equity capital available 9

from institutional investors to OTTR and OTP. 10

Trading Volume and Liquidity Risk 11

Q. DOES THE TRADING VOLUME OF A COMPANY AFFECT A LARGE INVESTOR’S 12

ABILITY TO SELL ITS STAKE IN THE COMPANY? 13

A. Yes. Smaller companies (such as OTTR) typically have fewer shares outstanding, and 14

fewer shares traded than their larger counterparts. This is significant to institutional 15

investors, who typically hold larger numbers of shares in each of their investments as a 16

matter of management efficiency. In other words, institutional investors tend to have 17

minimum dollar amounts for individual investments, which lead to positions involving 18

larger numbers of shares. If an institutional investor holds a relatively large portion of the 19

shares of a company, its ability to sell its position (without adversely affecting the market 20

price of shares) may be limited by the volume of shares traded each day. That uncertainty, 21

which often is referred to as “liquidity risk”, requires a higher expected return (that is, the 22

“liquidity premium” noted earlier). As noted by Amihud and Mendelson: 23

…investors prefer to commit capital to liquid investments, which can be 24

traded quickly and at low cost whenever the need arises. Investments with 25

less liquidity must offer higher expected returns to attract investors.52 26

Q. HOW DOES THE DAILY TRADING VOLUME OF OTTR SHARES COMPARE TO 27

OTHER UTILITIES IN YOUR PROXY GROUP? 28

52 Yakov Amihud, Haim Mendelson, Liquidity, Asset Prices and Financial Policy, Financial Analysts Journal,

Vol. 47, No. 6 (Nov-Dec 1991), at 56.

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A. The daily trading volume of OTTR shares is far below the average volume of my proxy 1

group. As Table 10 (below) indicates, OTTR’s average daily volume has been only about 2

18.00 to 19.00 percent of the average daily volume for the Proxy Group. Again, that low 3

volume indicates low liquidity and the corresponding requirement for a liquidity premium. 4

Table 10: Average Daily Trading Volumes 5

Group Jan 2013 –

Sep 2017 Jan 2014 –

Sep 2017 Jan 2015 –

Sep 2017 Jan 2016 –

Sep 2017 Jan 2017 –

Sep 2017 OTTR 95,617 97,503 96,781 104,286 96,766

Proxy Group 508,954 536,151 547,036 550,354 496,761

OTTR Volume as a % of: Proxy Group 18.79% 18.19% 17.69% 18.95% 19.48%

OTTR’s average daily trading volume is also significantly lower than the averages for Xcel 6

Energy and MDU, which were approximately 3.00 million (3.00 percent) and 1.00 million 7

(10.00 percent), respectively. 8

9

Taken from a slightly different perspective, OTTR’s average daily trading volume is less 10

than one-half of its peers’ (see Table 11, below). Again, that low volume indicates a degree 11

of illiquidity that strongly suggests the need for a liquidity premium. 12

Table 11: Average Daily Volume as a Percentage of Shares Outstanding 13

Group Jan 2013 –

Sep 2017 Jan 2014 –

Sep 2017 Jan 2015 –

Sep 2017 Jan 2016 –

Sep 2017 Jan 2017 –

Sep 2017 OTTR 0.255% 0.257% 0.252% 0.268% 0.245%

Proxy Group 0.547% 0.571% 0.579% 0.579% 0.529%

14

OTTR’s average daily trading volume is also significantly lower than the averages for Xcel 15

Energy and MDU, which were approximately 0.600 percent and 0.500 percent, 16

respectively. 17

Q. WHAT DO YOU CONCLUDE FROM THAT DATA? 18

A. First, there is little question that OTTR has a small percentage of institutional ownership, 19

and very low daily trading volumes relative to its peers. As a consequence, equity investors 20

face greater liquidity risk for which they would require a liquidity premium. Because 21

OTP’s Cost of Equity is estimated based on a proxy group of companies with greater 22

degrees of institutional ownership and higher daily trading volumes, the liquidity premium 23

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required to invest in OTTR’s shares is not reflected in the analytical results. Although it is 1

difficult to estimate the required liquidity premium, OTTR’s relatively illiquid shares 2

provide further support for moving toward the upper end of the range of analytical results. 3

Relative Beta Coefficients 4

Q. PLEASE BRIEFLY EXPLAIN BETA COEFFICIENTS, AND HOW THEY RELATE TO 5

THE COST OF EQUITY. 6

A. As discussed in Section VI, Beta coefficients (which are an important component of the 7

CAPM) measure the risk of a given security relative to the market, as a whole. In that 8

regard, a company with a Beta coefficient equal to 1.0 is as risky as the market; Beta 9

coefficients greater (less) than 1.0 indicate more (less) risk than the market. Because they 10

include relative returns over time, Beta coefficients can be calculated a number of ways. 11

As a general matter, however, higher Beta coefficients indicate higher Costs of Equity. 12

Q. HOW DOES OTTR’S BETA COEFFICIENT COMPARE TO THOSE OF THE PROXY 13

COMPANIES? 14

A. OTTR’s Beta coefficient has been consistently above that of the proxy group. In fact, 15

OTTR’s Beta coefficient has been greater than the proxy group’s Beta coefficient since at 16

least January 2016 or June 2016 depending on the calculation period. This indicates that 17

from the perspective of relative betas, OTTR has been riskier than the proxy group. 18

Q. PLEASE DESCRIBE THE ANALYSES YOU PERFORMED REGARDING RELATIVE 19

BETA COEFFICIENTS. 20

A. I calculated OTTR’s Beta coefficient over both 24- and 60-month periods (that is, the same 21

periods used by Value Line and Bloomberg53); I performed that calculation each day from 22

January 2016 through September 2017. I then took the ratio of OTTR’s calculated Beta 23

coefficient to the proxy group, and plotted that ratio each day over the calculation period. 24

Those results are provided in Chart 3, below. 25

53 Although Bloomberg enables analysts to calculate Beta coefficients over different periods, its default period

is two years. Please note that because of slight differences in the method of calculation, the Beta coefficients

provided in Chart 3 will not equal those reported by either Bloomberg or Value Line. Any such differences,

however, do not negate the findings discussed herein.

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Chart 3: Relative Beta Coefficients54 1

2

Q. WHAT ARE YOUR CONCLUSIONS OF YOUR ANALYSIS RELATIVE BETA 3

COEFFICIENTS? 4

A. Chart 3 demonstrates that OTTR has been riskier than the proxy group when calculated 5

over both 24- and 60- month periods, because the relative Beta coefficient (i.e., the Beta 6

coefficient for OTTR divided by the Beta coefficient for the proxy group) has been 7

consistently above 1.0. As such, the review of relative Beta coefficients supports the 8

conclusion that OTTR, and by extension OTP, are riskier than the proxy group. 9

10

Cost Savings for Customers 11

Q. HAS OTP DEMONSTRATED THE COMBINATION OF SUBSTANTIAL COST 12

SAVINGS FOR CUSTOMERS AND VERY HIGH LEVELS OF CUSTOMER 13

SATISFACTION? 14

A. Yes. OTP witnesses Mr. Kirk A. Phinney has explained that OTP has completed the largest 15

capital project it has undertaken, the Big Stone Air Quality Control System project (“AQCS 16

Project”), on time and approximately 26.00 percent under budget. Mr. Phinney also 17

54 Source: SNL Financial.

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explained that the smaller Hoot Lake Mercury Air Toxins Standard project has also been 1

completed substantially under budget. 2

3

OTP witnesses Mr. Stuart Tommerdahl has explained the very substantial savings to all 4

OTP customers, including approximately $3.40 million in the 2018 Test Year, 5

approximately $32.70 million in the first 10 years, and approximately $69.50 million over 6

30-year life of the AQCS Project. OTP witness Mr. Bruce Gerhardson explains the high 7

levels of customer satisfaction and low rates that OTP has maintained for a number of 8

years. 9

Q. IS IT APPROPRIATE FOR A REGULATORY ENTITY SUCH AS THE COMMISSION 10

TO RECOGNIZE SIGNIFICANT SAVINGS AND HIGH LEVELS OF CUSTOMER 11

SATISFACTION WHEN SETTING THE ROE? 12

A. Yes. The rationale for setting an ROE that recognizes utility performance that results in 13

substantial cost savings for customers, and the mutual benefits to customers and investors 14

from doing so, are summarized by Professor Roger Morin in his text New Regulatory 15

Finance, in which he discusses incentive-based regulation: 16

In essence, an incentive premium in excess of the authorized rate of return 17

is granted as an incentive device and/or to reward the attainment of a certain 18

performance objective. Benefits accrue to both investors and ratepayers, 19

the former in the form of enhanced profitability, and the latter in the form 20

of reduced costs. The ROE increment is frequently tied to a specific 21

performance target, for example a given ratio of actual/filed capital 22

spending program. More importantly, the ROE increment is applied in 23

order to reward overall management performance as opposed to the 24

attainment of a narrow, specific objective.55 25

26

Although Dr. Morin’s discussion specifically addresses formal incentive plans, I believe 27

that the same rationale applies to setting the ROE in a traditional rate case. 28

55 Morin in New Regulatory Finance, Chapter 20, section 20.3 Alternatives To Rate Of Return/Rate Base

Regulation, p. 539.

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Q. IS SUCH A PREMIUM PART OF THE COST OF EQUITY? 1

A. No. Such a premium would represent an award above the Cost of Equity to reflect a 2

recognition and reward for the performance of the utility. 3

Q. WHAT ARE YOUR CONCLUSIONS REGARDING OTP’S COST SAVINGS, LOW 4

RATES, AND CUSTOMER SATISFACTION? 5

A. Although I have not made an explicit adjustment to my ROE recommendation based on 6

the cost savings for customers, I note that it will be important to set a return that will 7

enhance internally generated funds and enable access to capital markets at reasonable terms 8

given OTP’s extensive capital expenditure program. These factors, along with OTP’s 9

higher risk factors and need to access debt and equity capital, support my 10.30 percent 10

recommendation. 11

12

VIII. CAPITAL MARKET ENVIRONMENT

Q. DO ECONOMIC CONDITIONS INFLUENCE THE REQUIRED COST OF CAPITAL 13

AND REQUIRED RETURN ON COMMON EQUITY? 14

A. Yes. As discussed in Section VI, the models used to estimate the Cost of Equity are meant 15

to reflect, and therefore are influenced by, current and expected capital market conditions. 16

As such, it is important to assess the reasonableness of any financial model’s results in the 17

context of observable market data. To the extent certain ROE estimates are incompatible 18

with such data or inconsistent with basic financial principles, it is appropriate to consider 19

whether alternative estimation techniques are likely to provide more meaningful and 20

reliable results. 21

Q. DO YOU HAVE ANY GENERAL OBSERVATIONS REGARDING THE 22

RELATIONSHIP BETWEEN FEDERAL RESERVE MONETARY POLICY, CAPITAL 23

MARKET CONDITIONS, AND THE COMPANY’S COST OF EQUITY? 24

A. Yes, I do. Much has been reported about the Federal Reserve’s Quantitative Easing policy 25

and its effect on interest rates. Although the Federal Reserve completed its Quantitative 26

Easing initiative in October 2014, it was not until December 2015 that it raised the Federal 27

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Funds rate, and began the process of rate normalization.56 Therefore, a significant issue is 1

how investors will react as that process continues, and eventually is completed. A viable 2

outcome is that investors will perceive greater prospects of macroeconomic growth, which 3

will increase the growth rates included in the Constant Growth DCF model. At the same 4

time, higher growth and the absence of Federal market intervention could provide the 5

opportunity for interest rates to increase, thereby increasing the dividend yield portion of 6

the DCF model. In that case, both terms of the Constant Growth DCF model would 7

increase, producing increased ROE estimates. 8

9

As noted below, market-based data indicate that investors see a probability of increasing 10

interest rates. Because those dynamics affect different models in different ways, it would 11

be inappropriate to rely on a single method to estimate the Company’s Cost of Equity. A 12

more reasoned approach is to understand the relationships among Federal monetary policy, 13

interest rates, and measures of market risk, and to consider how those factors may affect 14

different models and their results. As discussed throughout my Direct Testimony, it 15

remains important to consider a broad range of data and models when determining the 16

Company’s Cost of Equity. 17

Q. PLEASE SUMMARIZE THE EFFECT OF RECENT FEDERAL RESERVE POLICIES 18

ON INTEREST RATES AND THE COST OF CAPITAL. 19

A. Beginning in 2008, the Federal Reserve proceeded on a steady path of initiatives intended 20

to lower long-term Treasury yields.57 The Federal Reserve’s policy actions “were designed 21

to put downward pressure on longer-term interest rates by having the Federal Reserve take 22

onto its balance sheet some of the duration and prepayment risks that would otherwise have 23

been borne by private investors.”58 Under that policy, “Securities held outright” on the 24

Federal Reserve’s balance sheet increased from approximately $489 billion at the 25

beginning of October 2008 to $4.25 trillion by September 2017.59 To put that increase in 26

56 See Federal Reserve Press Release (December 16, 2015). 57 See Federal Reserve Press Release, dated June 19, 2013. 58 Federal Reserve Bank of New York, Domestic Open Market Operations During 2012, April 2013, at 29. 59 Source: Federal Reserve Board Schedule H.4.1. “Securities held outright” include U.S. Treasury securities,

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context, the securities held by the Federal Reserve represented approximately 3.29 percent 1

of Gross Domestic Product (GDP) at the end of September 2008, and had risen to 2

approximately 22.06 percent of GDP in September 2017.60 As such, the Federal Reserve 3

provided a significant source of liquidity, and had a substantial effect on capital markets. 4

Q. DOES YOUR RECOMMENDATION CONSIDER THE INTEREST RATE 5

ENVIRONMENT? 6

A. Yes, it does. From an analytical perspective, it is important that the inputs and assumptions 7

used to arrive at an ROE recommendation, including assessments of capital market 8

conditions, are consistent with the recommendation itself. Although all analyses require 9

an element of judgment, the application of that judgment must be made in the context of 10

the quantitative and qualitative information available to the analyst, and the capital market 11

environment in which the analyses were undertaken. Because the Cost of Equity is 12

forward-looking, the salient issue is whether investors see the likelihood of increased 13

interest rates during the period in which the rates set in this proceeding will be in effect. 14

15

The low interest rate environment associated with central bank intervention may lead some 16

analysts to conclude that current capital costs, including the Cost of Equity, are low and 17

will remain as such. However, that conclusion only holds true under the hypothesis of 18

Perfectly Competitive Capital Markets (“PCCM”) and the classical valuation framework 19

which, under normal economic and capital market conditions, underpin the traditional Cost 20

of Equity models. Perfectly Competitive Capital Markets are those in which no single 21

trader, or “market-mover”, would have the power to change the prices of goods or services, 22

including bond and common stock securities. In other words, under the PCCM hypothesis, 23

no single trader would have a significant effect on market prices. 24

Classic valuation theory assumes investors trade securities rationally, with prices reflecting 25

their perceptions of value. Although central banks may set benchmark interest rates, they 26

have maintained below-normal rates to stimulate economic expansion and capital market 27

Federal agency debt securities, and mortgage-backed securities

60 Source: Federal Reserve Board Schedule H.4.1; Bureau of Economic Analysis.

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recovery. It therefore is reasonable to conclude that the Federal Reserve and other central 1

banks have been acting as market-movers, thereby having a significant effect on the market 2

prices of both bonds and stocks. The presence of market-movers, such as the Federal 3

Reserve, runs counter to the PCCM hypothesis, which underlies traditional Cost of Equity 4

models. Consequently, the results of those models should be considered in the context of 5

both quantitative and qualitative information. 6

7

Although the Federal Reserve’s market intervention policies have kept interest rates 8

historically low, since July 8, 2016 (when the 30-year Treasury yield hit an all-time low of 9

2.11 percent), rates have risen. As the Federal Reserve increased the Federal Funds target 10

rate by 25 basis points in December 2016 (from 0.25 percent - 0.50 percent to 0.50 percent 11

- 0.75 percent), March 2017 (to 0.75 percent - 1.00 percent) and June 2017 (to 1.00 percent 12

– 1.25 percent), short-term and long-term interest rates increased by a corresponding 13

amount (see Chart 4 below).61 14

61 Federal Reserve Board Schedule H.15. 6-month and 1-year Treasury yields increased by 84 basis points and

83 basis points, respectively, July 8, 2016 to September 29, 2017. The ten-year and 30-year Treasury yields

increasing by 96 basis points and 75 basis points, respectively, by September 29, 2017.

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Chart 4: Treasury Yield Curve: 7/8/2016, 9/29/2017 and Projected Q1 201962 1

2

Lastly, on September 20, 2017, the Federal Reserve announced that it will “initiate the 3

balance sheet normalization program described in the June 2017 Addendum to the 4

Committee’s Policy Normalization Principles and Plans.”63 Those “Principles and Plans” 5

call for reducing the reinvestment of principal payments received from its holdings of 6

Treasury securities by up to $30 billion per month, and mortgage-backed securities by up 7

to $20 billion per month.64 At the same time, the Federal Reserve will continue considering 8

increases to the Federal Funds target rate; as noted below, current market data indicate an 9

approximately 85.00 percent likelihood of further rate increases by January 2018. 10

Q. DOES MARKET-BASED DATA INDICATE THAT INVESTORS SEE A 11

PROBABILITY OF INCREASING INTEREST RATES? 12

A. Yes. Forward Treasury yields implied by the slope of the yield curve and published 13

projections by sources such as Blue Chip Financial Forecasts (which provides consensus 14

estimates from approximately 50 professional economists) indicate investors expect long-15

62 Sources: Federal Reserve Board Schedule H.15.; Blue Chip Financial Forecasts, Vol. 36, No. 10, October 1,

2017, at 2. 3-year, 7-year and 20-year projected Treasury yields interpolated. 63 Federal Reserve Press Release, September 20, 2017. 64 Federal Reserve Addendum to the Policy Normalization Principles and Plans As adopted effective June 13,

2017.

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

1m 3m 6m 1y 2y 3y 5y 7y 10y 20y 30y

7/8/2016 9/29/2017 Blue Chip Q1 2019

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term interest rates to increase. Similarly, investors’ expectations for increased long-term 1

Treasury yields are apparent in the prices investors are willing to pay today for the option 2

to buy or sell long-term Government bonds, at today’s price, in the future. Because the 3

value of bonds falls as interest rates increase, the option to sell bonds at today’s price 4

becomes more valuable when interest rates are expected to increase.65 Currently option 5

prices show that investors are willing to pay about 50.00 percent more for the option to sell 6

bonds in the future (at today’s price) than they are willing to pay for the option to buy those 7

bonds.66 That market-based data tells us that investors consider an increase in interest rates 8

as likely. 9

10

Looking to short-term interest rates, data compiled by CME Groups indicates that investors 11

see a high likelihood of further Federal Funds rate increases, even after the three increases 12

between December 14, 2016 and June 14, 2017. As shown in Table 12, (below) the market 13

is now anticipating at least one additional rate hike (95.10 percent probability) and possibly 14

two or more (64.50 percent) by September 2018. 15

Table 12: Probability of Federal Funds Rate Increases67 16

Target

Rate

(bps)

Federal Reserve Meeting Date

11/1/17 12/13/17 1/31/18 3/21/18 5/2/18 6/13/18 8/1/18 9/26/18

100-125 98.5% 17.1% 16.4% 11.8% 11.3% 7.3% 7.2% 4.9%

125-150 1.5% 81.7% 79.0% 61.4% 59.3% 42.5% 41.8% 30.6%

150-175 1.2% 4.6% 25.5% 27.0% 38.3% 38.4% 39.5%

175-200 0.1% 1.3% 2.3% 11.0% 11.5% 20.2%

200-225 0.1% 0.9% 1.1% 4.4%

225-250 0.4%

17

65 In other words, if there is a high probability that interest rates will increase and bond prices will fall, there is

value in the option to sell those bonds in the future at today’s price. Conversely, if there is a strong probability

that interest rates will decrease (price of bonds will increase), there is value in the option to buy those bonds

in the future at today’s price. 66 The option to sell the TLT index in January 2018 at today’s price is approximately one and a half times the

value of the option to buy the fund. Source: http://www.nasdaq.com/symbol/tlt/option-chain?dateindex=7

accessed October 4, 2017. 67 Source: http://www.cmegroup.com/trading/interest-rates/countdown-to-fomc.html, accessed October 4,

2017.

http://www.nasdaq.com/symbol/tlt/option-chain?dateindex=7

http://www.cmegroup.com/trading/interest-rates/countdown-to-fomc.html

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Lastly, we can view the market’s expectations of future interest rates based on the current 1

yield curve. Those expected rates, often referred to as “forward yields” are derived from 2

the “Expectations” theory, which states that (for example) the current 30-year Treasury 3

yield equals the combination of the current one-year Treasury yield, and the 29-year 4

Treasury yield expected in one year. That is, an investor would be indifferent to (1) holding 5

a 30-year Treasury to maturity, or (2) holding a one-year Treasury to maturity, then a 29-6

year Treasury bond, also to maturity.68 Chart 5, below, shows the difference between the 7

forward and spot Treasury yields over time. As Chart 5 indicates, since 2006 the implied 8

forward 29- and 28- year yields (one and two years hence, respectively) consistently 9

exceeded the (interpolated) spot yields. That is, just as economists’ projections implied 10

increased interest rates, so did observable Treasury yields. 11

68 In addition to the Expectations theory, there are other theories regarding the term structure of interest rates

including: the Liquidity Premium Theory, which asserts that investors require a premium for holding long

term bonds; the Market Segmentation Theory, which states that securities of different terms are not

substitutable and, as such, the supply of and demand for short-term and long-term instruments is developed

independently; and the Preferred Habitat Theory, which states that in addition to interest rate expectations,

certain investors have distinct investment horizons and will require a return premium for bonds with

maturities outside of that preference.

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Chart 5: Forward vs. Interpolated Treasury Yields69 1

2

Q. HAVE YOU ALSO REVIEWED THE RELATIONSHIP BETWEEN CREDIT 3

SPREADS FOR A-RATED UTILITY DEBT RELATIVE TO A-RATED CORPORATE 4

DEBT? 5

A. Yes, I have. Given the historical volatility in the spread between corporate and utility A-6

rated debt, there is no reason to conclude that utility yields are different than those of their 7

corporate counterparts. That conclusion is consistent with the finding that over time, there 8

has been a nearly one-to-one relationship between credit spreads on A-rated corporate and 9

utility bonds. In fact, a regression analysis in which corporate credit spreads are the 10

explanatory variable and utility credit spreads are the dependent variable shows that slope 11

is approximately 1.00 and highly significant (see Chart 6, below). Because the intercept 12

term is nearly zero, we can conclude that there has been no material difference between the 13

two, and there certainly is no meaningful difference in the current market. 14

69 Source: Federal Reserve Schedule H.15. Spot yields are interpolated.

-0.10%

-0.05%

0.00%

0.05%

0.10%

0.15%

0.20%

0.25%

0.30%

0.35%

0.40%

Feb-06 Feb-08 Feb-10 Feb-12 Feb-14 Feb-16

Expected 29 year Yield in 1 Year Expected 28 year Yield in 2 Years

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Chart 6: Corporate and Utility Credit Spreads (A-Rated)70 1

2

Q. WHAT DO YOU CONCLUDE FROM THOSE ANALYSES? 3

A. First, it is clear that interest rates have increased from the low levels experienced in early 4

2016. Second, it is clear that market-based data indicate investors’ expectations of rising 5

interest rates in the near- and longer-term. The observation that interest rates have 6

increased indicates that the financial community sees the strong prospect of increased 7

growth throughout the economy. As that occurs, and as interest rates continue to rise, it 8

would be reasonable to expect lower utility valuations, higher dividend yields, and higher 9

growth rates. In the context of the Discounted Cash Flow model, those variables would 10

combine to indicate increases in the Cost of Equity. 11

12

Although the market data discussed above indicate increasing costs of capital, it is 13

important to keep in mind that estimating the Cost of Equity is an empirical exercise, but 14

rote application of a specific form of an analysis, or the mechanical use of specific model 15

inputs, may well produce misleading results. The methods used to estimate the Cost of 16

Equity, or the weight given to any one method, may change from case to case; and that the 17

returns authorized in other jurisdictions provide a relevant, observable, and verifiable 18

70 Source: Federal Reserve Schedule H.15.

y = 0.9449x + 0.0436R² = 0.9915

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 4.50 5.00

A-U

tiit

y C

red

it S

pre

ad

A-Corporate Credit Spread

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benchmark for assessing the reasonableness of analytical assumptions, results, and 1

conclusions. 2

Q. HAVE THERE BEEN RECENT PERIODS WHEN UTILITY VALUATION LEVELS 3

WERE HIGH RELATIVE TO BOTH THEIR LONG-TERM AVERAGE AND THE 4

MARKET? 5

A. Yes. For example, between July and December 2016, the S&P Electric Utility Index lost 6

approximately 9.00 percent of its value. At the same time, the S&P 500 increased by 7

approximately 7.00 percent, indicating that the utility sector under-performed the market 8

by about 16.00 percent. Also during that time, the 30-year Treasury yield increased by 9

approximately 95 basis points (an increase of nearly 45.00 percent). The point simply is 10

that as interest rates increased, utility valuations fell. Because (as noted above) investors 11

see the strong likelihood of further interest rate increases, there is a continuing risk of losses 12

in the utility sector. 13

Q. WHAT CONCLUSIONS DO YOU DRAW FROM YOUR ANALYSES OF THE 14

CURRENT CAPITAL MARKET ENVIRONMENT, AND HOW DO THOSE 15

CONCLUSIONS AFFECT YOUR ROE RECOMMENDATION? 16

A. In my view, we cannot conclude that the recent levels of utility valuations are due to a 17

fundamental change in the risk perceptions of utility investors. There is no measurable 18

difference between credit spreads of A-rated utility debt, and A-rated corporate debt. That 19

is, based on analyses of credit spreads, there is no reason to conclude that investors see 20

utilities as less risky relative to either historical levels or to their corporate counterparts. 21

22

From an analytical perspective, it is important that the inputs and assumptions used to 23

arrive at an ROE determination, including assessments of capital market conditions, are 24

consistent with the conclusion itself. Although all analyses require an element of judgment, 25

the application of that judgment must be made in the context of the quantitative and 26

qualitative information available to the analyst and the capital market environment in 27

which the analyses were undertaken. Because the application of financial models and 28

interpretation of their results often is the subject of differences among analysts in regulatory 29

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proceedings, I believe that it is important to review and consider a variety of data points; 1

doing so enables us to put in context both quantitative analyses and the associated 2

recommendations. 3

4

Because not all models used to estimate the Cost of Equity adequately reflect those 5

changing market dynamics, it is important to give appropriate weight to the methods and 6

to their results. Moreover, because those models produce a range of results, it is important 7

to consider the type of data discussed above in determining where the Companies’ ROE 8

falls within that range. As described in Section VII, on balance, I believe that the DCF-9

based results should be viewed very carefully, and that somewhat more weight should be 10

afforded the Risk Premium-based methods. I believe that doing so supports my 11

recommended range of 10.00 percent to 10.60 percent, and my ROE recommendation of 12

10.30 percent. 13

14

IX. CAPITAL STRUCTURE

Q. WHAT IS OTP’S PROPOSED CAPITAL STRUCTURE? 15

A. As described in the Direct Testimony of Mr. Moug, OTP’s proposed capital structure 16

consists of 52.50 percent common equity, 46.00 percent long-term debt and 1.50 percent 17

short-term debt. 18

Q. IS THERE A GENERALLY ACCEPTED APPROACH TO DEVELOPING ASSESSING 19

THE APPROPRIATE CAPITAL STRUCTURE FOR A REGULATED ELECTRIC 20

UTILITY? 21

A. Yes, there is. In general, it is important to consider the capital structure in light of industry 22

norms and investor requirements. That is, the capital structure should be reasonably 23

consistent with industry practice, and enable the subject company to maintain its financial 24

integrity, thereby enabling access to capital at competitive rates under a variety of 25

economic and financial market conditions. 26

Q. HOW DOES THE CAPITAL STRUCTURE AFFECT THE COST OF CAPITAL? 27

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A. It is well understood that from a financial perspective, there are two general categories of 1

risk: business risk and financial risk. Business risk includes operating, market, regulatory, 2

and competitive uncertainties, while financial risk is the incremental risk to investors 3

associated with additional levels of debt. As such, the capital structure relates to a 4

Company’s financial risk, which represents the risk that a company may not have adequate 5

cash flows to meet its financial obligations, and is a function of the percentage of debt (or 6

financial leverage) in its capital structure. In that regard, as the percentage of debt in the 7

capital structure increases, so do the fixed obligations for the repayment of that debt. 8

Consequently, as the degree of financial leverage increases, the risk of financial distress 9

(i.e., financial risk) also increases.71 10

Q. PLEASE SUMMARIZE YOUR ANALYSIS OF THE PROXY COMPANIES’ CAPITAL 11

STRUCTURES? 12

A. First, it is important to keep in mind that the proxy group has been selected to reflect 13

comparable companies in terms of financial and business risk. As such, it is appropriate to 14

review the proxy companies’ capital structures as a means of assessing whether the 15

proposed capital structure is consistent with industry practice. To make that assessment, I 16

calculated the average capital structure for each of the proxy companies over the last eight 17

quarters (see Exhibit __(RBH-1), Schedule 12). 18

Q. WHAT IS THE BASIS FOR USING AVERAGE CAPITAL COMPONENTS RATHER 19

THAN A POINT-IN-TIME MEASUREMENT? 20

A. Measuring the capital components at a particular point in time can skew the capital 21

structure by the specific circumstances of a particular period. Therefore, it is more 22

appropriate to normalize the relative relationship between the capital components over a 23

period of time. 24

Q HOW DOES OTP’S RATIO OF COMMON EQUITY TO TOTAL DEBT COMPARE 25

TO YOUR PROXY GROUP? 26

71 See Roger A. Morin, New Regulatory Finance, Public Utility Reports, Inc., 2006, at 45-46.

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Case No. PU-17-

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A. The mean of the proxy group actual capital structures over the last eight quarters is 51.45 1

percent common equity and the median is 52.56 percent. The common equity ratios of the 2

proxy group range from 44.59 percent to 59.14 percent.72 OTP’s proposed 52.50 percent 3

equity ratio is above the mean and approximately equal to the median of the proxy 4

companies’ equity ratios. 5

Q. IS THE PROPOSED CAPITAL STRUCTURE CONSISTENT WITH PRIOR 6

COMMISSION DECISIONS? 7

A. Yes, it is. As Mr. Moug notes in his Direct Testimony, OTP’s proposed 52.50 percent 8

equity ratio is somewhat below the Company’s current equity ratio approved by the 9

Commission in Docket No. PU-08-862 and comparable to the capital structures authorized 10

for Northern States Power and MDU in their most recent rate cases.73 11

Q. WILL THE CAPITAL STRUCTURE AND ROE AUTHORIZED IN THIS 12

PROCEEDING AFFECT OTP’S ABILITY TO COMPLETE ITS CAPITAL 13

EXPENDITURE PLAN? 14

A. Yes, I believe so. As Mr. Moug states in his Direct Testimony, the level of earnings 15

authorized by the Commission directly affects the Company’s ability to fund capital 16

investment with internally generated funds; and both lenders and equity investors expect a 17

significant portion of on-going capital investments to be financed with internally generated 18

funds.74 19

20

It also is important to realize that investors weigh a given utility’s authorized ROE in the 21

context of the nature of its expected capital investments. Because a utility’s investment 22

horizon is very long, investors require the assurance of a sufficiently high return to satisfy 23

the long-run financing requirements of the assets put into service. Those assurances, which 24

72 Source: SNL Financial. 73 MDU was authorized an equity ratio of 51.40 percent in Case No. PU-16-666. See, Montana-Dakota Utilities

Co., a Division of MDU Resources Group, Inc. 2016 Electric Rate Increase Application, Finding of Fact,

Conclusions of Law and Order, June 16, 2017. Northern States Power was authorized an equity ratio of

52.56 percent. See, Northern States Power Company 2013 Electric Rate Increase Application, Order

Adopting Settlement, Case No. PU-12-813, February 26, 2014. 74 Direct Testimony of Kevin G. Moug, at 12.

64

Case No. PU-17-

Hevert Direct

often are measured by the relationship between internally generated cash flows and debt 1

(or interest expense), depend quite heavily on the capital structure. As a consequence, both 2

the ROE and capital structure are very important to both debt and equity investors. 3

Q. WHAT IS YOUR CONCLUSION REGARDING AN APPROPRIATE CAPITAL 4

STRUCTURE FOR OTP? 5

A. I believe that the Company’s proposed capital structure, which consists of 52.50 percent 6

common equity 46.00 percent long-term debt and 1.50 percent short-term debt, is 7

appropriate. 8

9

X. CONCLUSIONS AND RECOMMENDATION

Q. HAVE YOU PREPARED A SUMMARY OF YOUR ANALYTICAL RESULTS? 10

A. Yes, I have. As discussed in Section VI, I have performed several analyses to estimate 11

OTP’s Cost of Equity, including two applications of the DCF model, the CAPM approach, 12

and the Bond Yield Plus Risk Premium model. Tables 13a and 13b below summarize my 13

analytical results. 14

Table 13a: Summary of DCF Results75

Mean Low Mean Mean High

Constant Growth DCF – Including Flotation Costs76




Multi-Stage DCF – Including Flotation Costs




75 See, also Exhibit __(RBH-1), Schedules 1 and 3. 76 Constant Growth DCF results exclude Hawaiian Electric Industries, Inc., IDACORP, Inc., and Northwestern

Corporation.

65

Case No. PU-17-

Hevert Direct

Table 13b: Summary of Risk Premium Results77

Bloomberg Derived

Market Risk

Premium

Value Line

Derived

Market Risk

Premium







Bond Yield Plus Risk Premium Approach



Long Term Projected 30-Year Treasury (4.40%) 10.33%

Q. PLEASE SUMMARIZE YOUR CONCLUSIONS REGARDING THE COMPANY’S 1

COST OF EQUITY. 2

A. As discussed throughout my Direct Testimony, it is important to consider a variety of 3

empirical and qualitative information in reviewing analytical results and arriving at ROE 4

determinations. Here, we have a situation in which the proxy companies have traded at 5

P/E ratios in excess of their historical average, and, for a time, in excess of the market. 6

Because that condition is unlikely to persist, it violates a principal assumption of the 7

Constant Growth DCF model, i.e., that the P/E ratio will not change, ever. A more balanced 8

approach is to consider additional methods, including the CAPM approach, and the Bond 9

Yield Plus Risk Premium model. Based on that data, I believe that an ROE in the range of 10

10.00 percent to 10.60 percent represents the range of equity investors’ required ROE for 11

investment in OTP in today’s capital markets. Within that range, I conclude that an ROE 12

of 10.30 percent represents the Cost of Equity for OTP and an appropriate ROE in this 13

matter. 14

77 See, also Exhibit __(RBH-1), Schedule 6 and Schedule 7.

66

Case No. PU-17-

Hevert Direct

1

My conclusion reflects OTP’s risk profile relative to the proxy group, along with market 2

indications of increasing capital costs. My analysis demonstrates that OTP’s level of 3

projected capital expenditures (65.94 percent of net plant) is higher than all but one proxy 4

company, and is substantially higher than the proxy group mean (43.45 percent of net 5

plant). My analysis also shows that OTP’s estimated stand-alone market capitalization is 6

approximately 17.00 percent of the smallest company in the proxy group. In addition, 7

OTTR’s level of institutional ownership, trading volume, and liquidity are all below the 8

proxy group, and the relative Beta coefficient is above 1.00 suggesting that OTTR is riskier 9

than the proxy group. Although I have not made a specific adjustment for any of these 10

factors, these factors support an ROE above the mean analytical results. 11

12

My recommendation is also supported by the substantial customer savings that OTP has 13

achieved while maintaining the highest levels of customer service and satisfaction. Mr. 14

Tommerdahl has demonstrated that North Dakota customers will receive customer savings 15

of approximately (approximately $3.40 million in the 2018 Test Year, approximately 16

$32.70 million in the first ten years, and approximately $69.50 million over 30 years) as 17

the result of OTP’s under-budget completion of the AQCS Project. Mr. Gerhardson has 18

explained the high levels of customer satisfaction with OTP service. Here too, although I 19

have not made a specific adjustment for these factors, they do support my recommended 20

10.30 percent ROE. 21

22

On balance, based on those considerations, I believe that an ROE of 10.30 percent is 23

reasonable for OTP. 24

Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 25

A. Yes, it does. 26

Case No. PU-17-

Exhibit___(RBH-1), Schedule 1

Page 1 of 3

Constant Growth Discounted Cash Flow Model30 Day Average Stock Price

[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11]

Company Ticker

Annualized

Dividend

Average

Stock

Price

Dividend

Yield

Expected

Dividend

Yield

Zacks

Earnings

Growth

First Call

Earnings

Growth

Value Line

Earnings

Growth

Average

Earnings

Growth

Low

ROE

Mean

ROE

High

ROE

ALLETE, Inc. ALE $2.14 $77.39 2.77% 2.84% 6.10% 5.00% 6.00% 5.70% 7.83% 8.54% 8.95%Alliant Energy Corporation LNT $1.26 $42.56 2.96% 3.05% 5.50% 6.90% 6.00% 6.13% 8.54% 9.18% 9.96%Black Hills Corporation BKH $1.78 $69.64 2.56% 2.64% 5.00% 7.65% 7.50% 6.72% 7.62% 9.36% 10.30%El Paso Electric Company EE $1.34 $55.14 2.43% 2.51% 7.20% 6.50% 5.00% 6.23% 7.49% 8.74% 9.72%Hawaiian Electric Industries, Inc. HE $1.24 $33.54 3.70% 3.74% 4.00% 1.40% 1.50% 2.30% 5.12% 6.04% 7.77%IDACORP, Inc. IDA $2.36 $89.09 2.65% 2.70% 4.50% 3.80% 3.50% 3.93% 6.20% 6.63% 7.21%Northwestern Corporation NWE $2.10 $59.29 3.54% 3.60% 1.60% 3.05% 4.50% 3.05% 5.17% 6.65% 8.12%OGE Energy Corp. OGE $1.33 $36.07 3.69% 3.80% 5.30% 6.30% 6.00% 5.87% 9.08% 9.66% 10.10%PNM Resources, Inc. PNM $0.97 $42.01 2.31% 2.39% 4.70% 7.35% 9.00% 7.02% 7.06% 9.41% 11.41%

Proxy Group Mean 2.96% 3.03% 4.88% 5.33% 5.44% 5.22% 7.12% 8.25% 9.28%Proxy Group Median 2.77% 2.84% 5.00% 6.30% 6.00% 5.87% 7.49% 8.74% 9.72%Proxy Group Mean - Including Flotation Costs 7.24% 8.36% 9.40%Proxy Group Median - Including Flotation Costs 7.60% 8.85% 9.83%Proxy Group Mean Excl. HE, IDA, NWE 7.94% 9.15% 10.07%Proxy Group Median Excl. HE, IDA, NWE 7.73% 9.27% 10.03%Proxy Group Mean Excl. HE, IDA, NWE - Including Flotation Costs 8.05% 9.26% 10.19%Proxy Group Median Excl. HE, IDA, NWE - Including Flotation Costs 7.84% 9.38% 10.15%Flotation Costs 0.11% 0.11% 0.11%

Notes:[1] Source: Bloomberg Professional[2] Source: Bloomberg Professional, equals indicated number of trading day average as of September 29, 2017[3] Equals [1] / [2][4] Equals [3] x (1 + 0.5 x [8])[5] Source: Zacks[6] Source: Yahoo! Finance[7] Source: Value Line[8] Equals Average([5], [6], [7])[9] Equals [3] x (1 + 0.5 x Minimum([5], [6], [7])) + Minimum([5], [6], [7])[10] Equals [4] + [8][11] Equals [3] x (1 + 0.5 x Maximum([5], [6], [7])) + Maximum([5], [6], [7])

Case No. PU-17-


Page 2 of 3


[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11]

Company Ticker

Annualized

Dividend

Average

Stock

Price

Dividend

Yield

Expected

Dividend

Yield

Zacks

Earnings

Growth

First Call

Earnings

Growth

Value Line

Earnings

Growth

Average

Earnings

Growth

Low

ROE

Mean

ROE

High

ROE




Case No. PU-17-


Page 3 of 3


[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11]

Company Ticker

Annualized

Dividend

Average

Stock

Price

Dividend

Yield

Expected

Dividend

Yield

Zacks

Earnings

Growth

First Call

Earnings

Growth

Value Line

Earnings

Growth

Average

Earnings

Growth

Low

ROE

Mean

ROE

High

ROE




Case No. PU-17-


Page 1 of 1Flotation Cost Adjustment

Two most recent open market common stock issuances per company, if available

[1] [2] [3] [4] [5] [6] [7] [8] [9]

Company Date

Shares

Issued

Offering

Price

Underwriting

Discount

Offering

Expense

Net

Proceeds Per

Share

Total

Flotation

Costs

Gross Equity

Issue Before

Costs Net Proceeds

Flotation

Cost

Percentage

Otter Tail Corporation 12/7/2004 3,075,000 $25.45 $0.9500 $391,452 $24.37 $3,312,702 $78,258,750 $74,946,048 4.233%

Otter Tail Corporation 9/18/2008 5,175,000 $30.00 $1.0875 $807,185 $28.76 $6,434,997 $155,250,000 $148,815,003 4.145%

Otter Tail Corporation - ESPP 2004 66,958 $19.31 $0.0000 $0 $19.31 $0 $1,292,959 $1,292,959 0.000%




Otter Tail Corporation - ESPP 2016 53,875 $27.68 $0.0000 $0 $27.66 $1,159 $1,491,266 $1,490,107 0.078%

Otter Tail Corporation - ESPP 2017 5,284 $39.85 $0.0000 $0 $39.78 $367 $210,585 $210,218 0.174%

Otter Tail Corporation - DRIP 2004 223,165 $19.30 $0.0000 $0 $19.30 $0 $4,308,033 $4,308,033 0.000%

Otter Tail Corporation - DRIP 2009 233,943 $19.21 $0.0000 $0 $19.18 $5,877 $4,493,385 $4,487,508 0.131%

Otter Tail Corporation - DRIP 2014 288,045 $26.76 $0.0000 $0 $26.76 $0 $7,707,964 $7,707,964 0.000%

Otter Tail Corporation - DRIP 2015 330,379 $25.93 $0.0000 $56,545 $25.76 $56,545 $8,566,009 $8,509,464 0.660%



Otter Tail Corporation - ATM 2014 519,636 $29.69 $0.5903 $780,616 $27.42 $1,087,343 $15,336,352 $14,249,009 7.090%

Otter Tail Corporation - ATM 2015 133,197 $28.00 $0.4241 $339,160 $25.45 $395,645 $3,785,244 $3,389,599 10.452%

Otter Tail Corporation - ATM 2016 1,014,115 $33.00 $0.0000 $561,548 $32.22 $561,548 $33,235,729 $32,674,181 1.690%

Mean $700,395 $19,559,633

WEIGHTED AVERAGE FLOTATION COSTS: 3.581% [10]

Constant Growth Discounted Cash Flow Model Adjusted for Flotation Costs - 30 Day Average Stock Price

[11] [12] [13] [14] [15] [16] [17] [18] [19] [20] [21]

Average Expected Dividend Yield Zacks First Call Value Line Average Flotation

Annualized Stock Dividend Adjusted for Earnings Earnings Earnings Earnings Adjusted

Company Ticker Dividend Price Yield Current Flot. Costs Growth Growth Growth Growth DCF k(e) DCF k(e)

ALLETE, Inc. ALE $2.14 $77.39 2.77% 2.84% 2.95% 6.10% 5.00% 6.00% 5.70% 8.54% 8.65%

Alliant Energy Corporation LNT $1.26 $42.56 2.96% 3.05% 3.16% 5.50% 6.90% 6.00% 6.13% 9.18% 9.30%

Black Hills Corporation BKH $1.78 $69.64 2.56% 2.64% 2.74% 5.00% 7.65% 7.50% 6.72% 9.36% 9.46%

El Paso Electric Company EE $1.34 $55.14 2.43% 2.51% 2.60% 7.20% 6.50% 5.00% 6.23% 8.74% 8.83%

Hawaiian Electric Industries, Inc. HE $1.24 $33.54 3.70% 3.74% 3.88% 4.00% 1.40% 1.50% 2.30% 6.04% 6.18%

IDACORP, Inc. IDA $2.36 $89.09 2.65% 2.70% 2.80% 4.50% 3.80% 3.50% 3.93% 6.63% 6.73%

Northwestern Corporation NWE $2.10 $59.29 3.54% 3.60% 3.73% 1.60% 3.05% 4.50% 3.05% 6.65% 6.78%

OGE Energy Corp. OGE $1.33 $36.07 3.69% 3.80% 3.94% 5.30% 6.30% 6.00% 5.87% 9.66% 9.80%

PNM Resources, Inc. PNM $0.97 $42.01 2.31% 2.39% 2.48% 4.70% 7.35% 9.00% 7.02% 9.41% 9.50%

PROXY GROUP MEAN 8.25% 8.36%

DCF Result Adjusted For Flotation Costs: 8.36%

DCF Result Unadjusted For Flotation Costs: 8.25%

Difference (Flotation Cost Adjustment): 0.11% [22]

Notes:

[1] Source: Company provided information [12] Source: Bloomberg Professional

[2] Source: Company provided information [13] Equals [11] / [12]

[3] Source: Company provided information [14] Equals [3] x (1 + 0.5 x [19])

[4] Source: Company provided information [15] Equals [4] / (1 - 0.0358)

[5] Equals [8] / [1] [16] Source: Zacks

[6] Equals [4] + ([1] x [3]) [17] Source: Yahoo! Finance

[7] Equals [1] x [2] [18] Source: Value Line

[8] Equals [7] - [6] [19] Equals Average([16], [17], [18])

[9] Equals [6] / [7] [20] Equals [14] + [19]

[10] Equals average [6] / average [7] [21] Equals [15] + [19]

[11] Source: Bloomberg Professional [22] Equals average [21] - average [20]

The proxy group DCF result is adjusted for flotation costs by dividing each company's expected dividend yield

by (1 - flotation cost). The flotation cost adjustment is derived as the difference between the unadjusted DCF

result and the DCF result adjusted for flotation costs.

Case No. PU-17-


Page 1 of 20

Inputs [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13]

Stock EPS Growth Rate Estimates Long-Term Payout Ratio Iterative Solution Terminal Terminal

Company Ticker Price Zacks First Call

Value

Line Average Growth 2017 2021 2027 Proof IRR P/E Ratio PEG Ratio

ALLETE, Inc. ALE $77.39 6.10% 5.00% 6.00% 5.70% 5.35% 64.00% 58.00% 65.91% $0.00 8.41% 22.63 4.23

Alliant Energy Corporation LNT $42.56 5.50% 6.90% 6.00% 6.13% 5.35% 63.00% 63.00% 65.91% $0.00 8.39% 22.83 4.27

Black Hills Corporation BKH $69.64 5.00% 7.65% 7.50% 6.72% 5.35% 50.00% 51.00% 65.91% ($0.00) 8.33% 23.28 4.36

El Paso Electric Company EE $55.14 7.20% 6.50% 5.00% 6.23% 5.35% 53.00% 58.00% 65.91% $0.00 8.70% 20.67 3.87

Hawaiian Electric Industries, Inc. HE $33.54 4.00% 1.40% 1.50% 2.30% 5.35% 77.00% 70.00% 65.91% $0.00 9.69% 15.99 2.99

IDACORP, Inc. IDA $89.09 4.50% 3.80% 3.50% 3.93% 5.35% 55.00% 61.00% 65.91% $0.00 8.31% 23.40 4.38

Northwestern Corporation NWE $59.29 1.60% 3.05% 4.50% 3.05% 5.35% 61.00% 62.00% 65.91% ($0.00) 9.00% 19.01 3.56

OGE Energy Corp. OGE $36.07 5.30% 6.30% 6.00% 5.87% 5.35% 65.00% 72.00% 65.91% ($0.00) 9.04% 18.81 3.52

PNM Resources, Inc. PNM $42.01 4.70% 7.35% 9.00% 7.02% 5.35% 52.00% 56.00% 65.91% ($0.00) 8.54% 21.75 4.07 Including Flotation Costs

DCF Result DCF Result

Mean 8.71% 8.82%

Max 9.69% 9.80%

Min 8.31% 8.42%

Projected Annual

Earnings per Share [14] [15] [16] [17] [18] [19] [20] [21] [22] [23] [24] [25] [26] [27] [28] [29] [30]

Company Ticker 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE $3.14 $3.32 $3.51 $3.71 $3.92 $4.14 $4.38 $4.62 $4.88 $5.14 $5.42 $5.71 $6.02 $6.34 $6.68 $7.03 $7.41

Alliant Energy Corporation LNT $1.65 $1.75 $1.86 $1.97 $2.09 $2.22 $2.36 $2.49 $2.64 $2.78 $2.94 $3.09 $3.26 $3.43 $3.62 $3.81 $4.01

Black Hills Corporation BKH $2.63 $2.81 $3.00 $3.20 $3.41 $3.64 $3.88 $4.12 $4.37 $4.62 $4.88 $5.14 $5.41 $5.70 $6.01 $6.33 $6.67

El Paso Electric Company EE $2.39 $2.54 $2.70 $2.87 $3.04 $3.23 $3.43 $3.63 $3.84 $4.06 $4.28 $4.51 $4.75 $5.01 $5.28 $5.56 $5.86

Hawaiian Electric Industries, Inc. HE $2.29 $2.34 $2.40 $2.45 $2.51 $2.57 $2.64 $2.73 $2.83 $2.95 $3.09 $3.26 $3.43 $3.62 $3.81 $4.02 $4.23

IDACORP, Inc. IDA $3.94 $4.09 $4.26 $4.42 $4.60 $4.78 $4.98 $5.20 $5.44 $5.70 $5.99 $6.31 $6.65 $7.01 $7.38 $7.78 $8.19

Northwestern Corporation NWE $3.39 $3.49 $3.60 $3.71 $3.82 $3.94 $4.07 $4.23 $4.41 $4.61 $4.84 $5.10 $5.37 $5.66 $5.96 $6.28 $6.61

OGE Energy Corp. OGE $1.69 $1.79 $1.89 $2.01 $2.12 $2.25 $2.38 $2.51 $2.65 $2.80 $2.95 $3.11 $3.28 $3.45 $3.64 $3.83 $4.03

PNM Resources, Inc. PNM $1.65 $1.77 $1.89 $2.02 $2.16 $2.32 $2.47 $2.63 $2.79 $2.96 $3.13 $3.29 $3.47 $3.65 $3.85 $4.06 $4.27

Projected Annual

Dividend Payout Ratio [31] [32] [33] [34] [35] [36] [37] [38] [39] [40] [41] [42] [43] [44] [45] [46]

Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE 64.00% 62.50% 61.00% 59.50% 58.00% 59.32% 60.64% 61.95% 63.27% 64.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%

Alliant Energy Corporation LNT 63.00% 63.00% 63.00% 63.00% 63.00% 63.48% 63.97% 64.45% 64.94% 65.42% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%

Black Hills Corporation BKH 50.00% 50.25% 50.50% 50.75% 51.00% 53.48% 55.97% 58.45% 60.94% 63.42% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%

El Paso Electric Company EE 53.00% 54.25% 55.50% 56.75% 58.00% 59.32% 60.64% 61.95% 63.27% 64.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%

Hawaiian Electric Industries, Inc. HE 77.00% 75.25% 73.50% 71.75% 70.00% 69.32% 68.64% 67.95% 67.27% 66.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%

IDACORP, Inc. IDA 55.00% 56.50% 58.00% 59.50% 61.00% 61.82% 62.64% 63.45% 64.27% 65.09% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%

Northwestern Corporation NWE 61.00% 61.25% 61.50% 61.75% 62.00% 62.65% 63.30% 63.95% 64.60% 65.25% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%

OGE Energy Corp. OGE 65.00% 66.75% 68.50% 70.25% 72.00% 70.98% 69.97% 68.95% 67.94% 66.92% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%

PNM Resources, Inc. PNM 52.00% 53.00% 54.00% 55.00% 56.00% 57.65% 59.30% 60.95% 62.60% 64.25% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%

Projected Annual

Cash Flows [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63]

Terminal

Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 Value

ALLETE, Inc. ALE $2.12 $2.19 $2.26 $2.33 $2.40 $2.60 $2.80 $3.02 $3.25 $3.50 $3.76 $3.96 $4.18 $4.40 $4.63 $4.88 $167.68





IDACORP, Inc. IDA $2.25 $2.40 $2.57 $2.74 $2.91 $3.08 $3.25 $3.45 $3.67 $3.90 $4.16 $4.38 $4.62 $4.87 $5.13 $5.40 $191.72




Projected Annual Data

Investor Cash Flows [64] [65] [66] [67] [68] [69] [70] [71] [72] [73] [74] [75] [76] [77] [78] [79] [80] [81]

Initial

Company Ticker Outflow 9/29/17 12/31/17 6/30/18 6/30/19 6/30/20 6/30/21 6/30/22 6/30/23 6/30/24 6/30/25 6/30/26 6/30/27 6/30/28 6/30/29 6/30/30 6/30/31 6/30/32

ALLETE, Inc. ALE ($77.39) $0.00 $0.54 $2.18 $2.26 $2.33 $2.40 $2.60 $2.80 $3.02 $3.25 $3.50 $3.76 $3.96 $4.18 $4.40 $4.63 $172.56

Alliant Energy Corporation LNT ($42.56) $0.00 $0.28 $1.14 $1.24 $1.32 $1.40 $1.50 $1.60 $1.70 $1.81 $1.92 $2.04 $2.15 $2.26 $2.38 $2.51 $94.31

Black Hills Corporation BKH ($69.64) $0.00 $0.36 $1.45 $1.61 $1.73 $1.86 $2.07 $2.31 $2.55 $2.82 $3.09 $3.39 $3.57 $3.76 $3.96 $4.17 $159.61

El Paso Electric Company EE ($55.14) $0.00 $0.34 $1.39 $1.59 $1.73 $1.88 $2.03 $2.20 $2.38 $2.57 $2.77 $2.97 $3.13 $3.30 $3.48 $3.66 $124.88

Hawaiian Electric Industries, Inc. HE ($33.54) $0.00 $0.46 $1.82 $1.80 $1.80 $1.80 $1.83 $1.87 $1.92 $1.99 $2.06 $2.15 $2.26 $2.38 $2.51 $2.65 $70.40

IDACORP, Inc. IDA ($89.09) $0.00 $0.57 $2.30 $2.57 $2.74 $2.91 $3.08 $3.25 $3.45 $3.67 $3.90 $4.16 $4.38 $4.62 $4.87 $5.13 $197.12

Northwestern Corporation NWE ($59.29) $0.00 $0.54 $2.16 $2.28 $2.36 $2.44 $2.55 $2.68 $2.82 $2.98 $3.16 $3.36 $3.54 $3.73 $3.93 $4.14 $130.05

OGE Energy Corp. OGE ($36.07) $0.00 $0.30 $1.20 $1.37 $1.49 $1.62 $1.69 $1.76 $1.83 $1.90 $1.98 $2.05 $2.16 $2.27 $2.40 $2.52 $78.57

PNM Resources, Inc. PNM ($42.01) $0.00 $0.23 $0.95 $1.09 $1.19 $1.30 $1.43 $1.56 $1.70 $1.85 $2.01 $2.17 $2.29 $2.41 $2.54 $2.67 $95.73

Multi-Stage Growth Discounted Cash Flow Model

30 Day Average Stock Price

Average EPS Growth Rate Estimate in First Stage

Case No. PU-17-


Page 2 of 20

Inputs [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13]



Value

Line

High

Growth Growth 2017 2021 2027 Proof IRR P/E Ratio PEG Ratio

ALLETE, Inc. ALE $77.39 6.10% 5.00% 6.00% 6.10% 5.35% 64.00% 58.00% 65.91% $0.00 8.49% 22.05 4.12





IDACORP, Inc. IDA $89.09 4.50% 3.80% 3.50% 4.50% 5.35% 55.00% 61.00% 65.91% $0.00 8.43% 22.53 4.22





Mean 8.95% 9.07%

Max 10.21% 10.33%

Min 8.43% 8.54%

Projected Annual


Company Ticker 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE $3.14 $3.33 $3.53 $3.75 $3.98 $4.22 $4.47 $4.74 $5.01 $5.29 $5.58 $5.87 $6.19 $6.52 $6.87 $7.23 $7.62





IDACORP, Inc. IDA $3.94 $4.12 $4.30 $4.50 $4.70 $4.91 $5.14 $5.38 $5.65 $5.93 $6.24 $6.58 $6.93 $7.30 $7.69 $8.10 $8.53




Projected Annual


Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE 64.00% 62.50% 61.00% 59.50% 58.00% 59.32% 60.64% 61.95% 63.27% 64.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%





IDACORP, Inc. IDA 55.00% 56.50% 58.00% 59.50% 61.00% 61.82% 62.64% 63.45% 64.27% 65.09% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%




Projected Annual

Cash Flows [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63]

Terminal


ALLETE, Inc. ALE $2.13 $2.21 $2.29 $2.37 $2.45 $2.65 $2.87 $3.10 $3.35 $3.60 $3.87 $4.08 $4.30 $4.53 $4.77 $5.02 $168.03





IDACORP, Inc. IDA $2.26 $2.43 $2.61 $2.80 $3.00 $3.18 $3.37 $3.58 $3.81 $4.06 $4.33 $4.57 $4.81 $5.07 $5.34 $5.62 $192.26






Initial #######


ALLETE, Inc. ALE ($77.39) $0.00 $0.54 $2.20 $2.29 $2.37 $2.45 $2.65 $2.87 $3.10 $3.35 $3.60 $3.87 $4.08 $4.30 $4.53 $4.77 $173.06





IDACORP, Inc. IDA ($89.09) $0.00 $0.58 $2.32 $2.61 $2.80 $3.00 $3.18 $3.37 $3.58 $3.81 $4.06 $4.33 $4.57 $4.81 $5.07 $5.34 $197.88






High EPS Growth Rate Estimate in First Stage

Case No. PU-17-


Page 3 of 20

Inputs [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13]



Value

Line

Low


ALLETE, Inc. ALE $77.39 6.10% 5.00% 6.00% 5.00% 5.35% 64.00% 58.00% 65.91% $0.00 8.27% 23.71 4.43





IDACORP, Inc. IDA $89.09 4.50% 3.80% 3.50% 3.50% 5.35% 55.00% 61.00% 65.91% $0.00 8.23% 24.10 4.51

Northwestern Corporation NWE $59.29 1.60% 3.05% 4.50% 1.60% 5.35% 61.00% 62.00% 65.91% $0.00 8.66% 20.97 3.92


PNM Resources, Inc. PNM $42.01 4.70% 7.35% 9.00% 4.70% 5.35% 52.00% 56.00% 65.91% $0.00 8.09% 25.31 4.73 Including Flotation Costs


Mean 8.48% 8.59%

Max 9.43% 9.54%

Min 8.01% 8.12%

Projected Annual


Company Ticker 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE $3.14 $3.30 $3.46 $3.63 $3.82 $4.01 $4.21 $4.43 $4.65 $4.90 $5.16 $5.43 $5.72 $6.03 $6.35 $6.69 $7.05





IDACORP, Inc. IDA $3.94 $4.08 $4.22 $4.37 $4.52 $4.68 $4.86 $5.06 $5.28 $5.53 $5.81 $6.12 $6.45 $6.79 $7.16 $7.54 $7.94




Projected Annual


Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE 64.00% 62.50% 61.00% 59.50% 58.00% 59.32% 60.64% 61.95% 63.27% 64.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%





IDACORP, Inc. IDA 55.00% 56.50% 58.00% 59.50% 61.00% 61.82% 62.64% 63.45% 64.27% 65.09% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%




Projected Annual

Cash Flows [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63]

Terminal


ALLETE, Inc. ALE $2.11 $2.16 $2.22 $2.27 $2.32 $2.50 $2.68 $2.88 $3.10 $3.33 $3.58 $3.77 $3.97 $4.19 $4.41 $4.65 $167.08





IDACORP, Inc. IDA $2.24 $2.38 $2.53 $2.69 $2.85 $3.00 $3.17 $3.35 $3.55 $3.78 $4.03 $4.25 $4.48 $4.72 $4.97 $5.23 $191.33






Initial #######


ALLETE, Inc. ALE ($77.39) $0.00 $0.54 $2.16 $2.22 $2.27 $2.32 $2.50 $2.68 $2.88 $3.10 $3.33 $3.58 $3.77 $3.97 $4.19 $4.41 $171.73





IDACORP, Inc. IDA ($89.09) $0.00 $0.57 $2.28 $2.53 $2.69 $2.85 $3.00 $3.17 $3.35 $3.55 $3.78 $4.03 $4.25 $4.48 $4.72 $4.97 $196.57






Low EPS Growth Rate Estimate in First Stage

Case No. PU-17-


Page 4 of 20

Inputs [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13]



Value


ALLETE, Inc. ALE $74.35 6.10% 5.00% 6.00% 5.70% 5.35% 64.00% 58.00% 65.91% ($0.00) 8.54% 21.75 4.07

Alliant Energy Corporation LNT $41.54 5.50% 6.90% 6.00% 6.13% 5.35% 63.00% 63.00% 65.91% ($0.00) 8.46% 22.29 4.17




IDACORP, Inc. IDA $87.63 4.50% 3.80% 3.50% 3.93% 5.35% 55.00% 61.00% 65.91% $0.00 8.36% 23.02 4.31





Mean 8.77% 8.88%

Max 9.75% 9.86%

Min 8.33% 8.44%

Projected Annual


Company Ticker 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE $3.14 $3.32 $3.51 $3.71 $3.92 $4.14 $4.38 $4.62 $4.88 $5.14 $5.42 $5.71 $6.02 $6.34 $6.68 $7.03 $7.41





IDACORP, Inc. IDA $3.94 $4.09 $4.26 $4.42 $4.60 $4.78 $4.98 $5.20 $5.44 $5.70 $5.99 $6.31 $6.65 $7.01 $7.38 $7.78 $8.19




Projected Annual


Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE 64.00% 62.50% 61.00% 59.50% 58.00% 59.32% 60.64% 61.95% 63.27% 64.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%





IDACORP, Inc. IDA 55.00% 56.50% 58.00% 59.50% 61.00% 61.82% 62.64% 63.45% 64.27% 65.09% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%




Projected Annual

Cash Flows [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63]

Terminal


ALLETE, Inc. ALE $2.12 $2.19 $2.26 $2.33 $2.40 $2.60 $2.80 $3.02 $3.25 $3.50 $3.76 $3.96 $4.18 $4.40 $4.63 $4.88 $161.11





IDACORP, Inc. IDA $2.25 $2.40 $2.57 $2.74 $2.91 $3.08 $3.25 $3.45 $3.67 $3.90 $4.16 $4.38 $4.62 $4.87 $5.13 $5.40 $188.58






Initial #######


ALLETE, Inc. ALE ($74.35) $0.00 $0.54 $2.18 $2.26 $2.33 $2.40 $2.60 $2.80 $3.02 $3.25 $3.50 $3.76 $3.96 $4.18 $4.40 $4.63 $165.99





IDACORP, Inc. IDA ($87.63) $0.00 $0.57 $2.30 $2.57 $2.74 $2.91 $3.08 $3.25 $3.45 $3.67 $3.90 $4.16 $4.38 $4.62 $4.87 $5.13 $193.98







Case No. PU-17-


Page 5 of 20

Inputs [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13]



Value

Line

High


ALLETE, Inc. ALE $74.35 6.10% 5.00% 6.00% 6.10% 5.35% 64.00% 58.00% 65.91% $0.00 8.62% 21.19 3.96




Hawaiian Electric Industries, Inc. HE $33.13 4.00% 1.40% 1.50% 4.00% 5.35% 77.00% 70.00% 65.91% ($0.00) 10.28% 14.08 2.63

IDACORP, Inc. IDA $87.63 4.50% 3.80% 3.50% 4.50% 5.35% 55.00% 61.00% 65.91% ($0.00) 8.48% 22.16 4.15





Mean 9.02% 9.13%

Max 10.28% 10.39%

Min 8.48% 8.59%

Projected Annual


Company Ticker 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE $3.14 $3.33 $3.53 $3.75 $3.98 $4.22 $4.47 $4.74 $5.01 $5.29 $5.58 $5.87 $6.19 $6.52 $6.87 $7.23 $7.62





IDACORP, Inc. IDA $3.94 $4.12 $4.30 $4.50 $4.70 $4.91 $5.14 $5.38 $5.65 $5.93 $6.24 $6.58 $6.93 $7.30 $7.69 $8.10 $8.53




Projected Annual


Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE 64.00% 62.50% 61.00% 59.50% 58.00% 59.32% 60.64% 61.95% 63.27% 64.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%





IDACORP, Inc. IDA 55.00% 56.50% 58.00% 59.50% 61.00% 61.82% 62.64% 63.45% 64.27% 65.09% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%




Projected Annual

Cash Flows [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63]

Terminal


ALLETE, Inc. ALE $2.13 $2.21 $2.29 $2.37 $2.45 $2.65 $2.87 $3.10 $3.35 $3.60 $3.87 $4.08 $4.30 $4.53 $4.77 $5.02 $161.46





IDACORP, Inc. IDA $2.26 $2.43 $2.61 $2.80 $3.00 $3.18 $3.37 $3.58 $3.81 $4.06 $4.33 $4.57 $4.81 $5.07 $5.34 $5.62 $189.12






Initial #######


ALLETE, Inc. ALE ($74.35) $0.00 $0.54 $2.20 $2.29 $2.37 $2.45 $2.65 $2.87 $3.10 $3.35 $3.60 $3.87 $4.08 $4.30 $4.53 $4.77 $166.48





IDACORP, Inc. IDA ($87.63) $0.00 $0.58 $2.32 $2.61 $2.80 $3.00 $3.18 $3.37 $3.58 $3.81 $4.06 $4.33 $4.57 $4.81 $5.07 $5.34 $194.74







Case No. PU-17-


Page 6 of 20

Inputs [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13]



Value

Line

Low


ALLETE, Inc. ALE $74.35 6.10% 5.00% 6.00% 5.00% 5.35% 64.00% 58.00% 65.91% $0.00 8.39% 22.77 4.26



El Paso Electric Company EE $53.56 7.20% 6.50% 5.00% 5.00% 5.35% 53.00% 58.00% 65.91% ($0.00) 8.53% 21.77 4.07


IDACORP, Inc. IDA $87.63 4.50% 3.80% 3.50% 3.50% 5.35% 55.00% 61.00% 65.91% ($0.00) 8.27% 23.70 4.43





Mean 8.53% 8.64%

Max 9.48% 9.60%

Min 8.01% 8.13%

Projected Annual


Company Ticker 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE $3.14 $3.30 $3.46 $3.63 $3.82 $4.01 $4.21 $4.43 $4.65 $4.90 $5.16 $5.43 $5.72 $6.03 $6.35 $6.69 $7.05





IDACORP, Inc. IDA $3.94 $4.08 $4.22 $4.37 $4.52 $4.68 $4.86 $5.06 $5.28 $5.53 $5.81 $6.12 $6.45 $6.79 $7.16 $7.54 $7.94




Projected Annual


Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE 64.00% 62.50% 61.00% 59.50% 58.00% 59.32% 60.64% 61.95% 63.27% 64.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%





IDACORP, Inc. IDA 55.00% 56.50% 58.00% 59.50% 61.00% 61.82% 62.64% 63.45% 64.27% 65.09% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%




Projected Annual

Cash Flows [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63]

Terminal


ALLETE, Inc. ALE $2.11 $2.16 $2.22 $2.27 $2.32 $2.50 $2.68 $2.88 $3.10 $3.33 $3.58 $3.77 $3.97 $4.19 $4.41 $4.65 $160.51





IDACORP, Inc. IDA $2.24 $2.38 $2.53 $2.69 $2.85 $3.00 $3.17 $3.35 $3.55 $3.78 $4.03 $4.25 $4.48 $4.72 $4.97 $5.23 $188.19






Initial #######


ALLETE, Inc. ALE ($74.35) $0.00 $0.54 $2.16 $2.22 $2.27 $2.32 $2.50 $2.68 $2.88 $3.10 $3.33 $3.58 $3.77 $3.97 $4.19 $4.41 $165.16





IDACORP, Inc. IDA ($87.63) $0.00 $0.57 $2.28 $2.53 $2.69 $2.85 $3.00 $3.17 $3.35 $3.55 $3.78 $4.03 $4.25 $4.48 $4.72 $4.97 $193.43







Case No. PU-17-


Page 7 of 20

Inputs [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13]



Value


ALLETE, Inc. ALE $70.80 6.10% 5.00% 6.00% 5.70% 5.35% 64.00% 58.00% 65.91% ($0.00) 8.70% 20.71 3.87





IDACORP, Inc. IDA $84.87 4.50% 3.80% 3.50% 3.93% 5.35% 55.00% 61.00% 65.91% $0.00 8.46% 22.29 4.17





Mean 8.87% 8.98%

Max 9.74% 9.85%

Min 8.42% 8.53%

Projected Annual


Company Ticker 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE $3.14 $3.32 $3.51 $3.71 $3.92 $4.14 $4.38 $4.62 $4.88 $5.14 $5.42 $5.71 $6.02 $6.34 $6.68 $7.03 $7.41





IDACORP, Inc. IDA $3.94 $4.09 $4.26 $4.42 $4.60 $4.78 $4.98 $5.20 $5.44 $5.70 $5.99 $6.31 $6.65 $7.01 $7.38 $7.78 $8.19




Projected Annual


Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE 64.00% 62.50% 61.00% 59.50% 58.00% 59.32% 60.64% 61.95% 63.27% 64.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%





IDACORP, Inc. IDA 55.00% 56.50% 58.00% 59.50% 61.00% 61.82% 62.64% 63.45% 64.27% 65.09% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%




Projected Annual

Cash Flows [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63]

Terminal


ALLETE, Inc. ALE $2.12 $2.19 $2.26 $2.33 $2.40 $2.60 $2.80 $3.02 $3.25 $3.50 $3.76 $3.96 $4.18 $4.40 $4.63 $4.88 $153.43





IDACORP, Inc. IDA $2.25 $2.40 $2.57 $2.74 $2.91 $3.08 $3.25 $3.45 $3.67 $3.90 $4.16 $4.38 $4.62 $4.87 $5.13 $5.40 $182.62






Initial #######


ALLETE, Inc. ALE ($70.80) $0.00 $0.54 $2.18 $2.26 $2.33 $2.40 $2.60 $2.80 $3.02 $3.25 $3.50 $3.76 $3.96 $4.18 $4.40 $4.63 $158.32





IDACORP, Inc. IDA ($84.87) $0.00 $0.57 $2.30 $2.57 $2.74 $2.91 $3.08 $3.25 $3.45 $3.67 $3.90 $4.16 $4.38 $4.62 $4.87 $5.13 $188.02







Case No. PU-17-


Page 8 of 20

Inputs [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13]



Value

Line

High


ALLETE, Inc. ALE $70.80 6.10% 5.00% 6.00% 6.10% 5.35% 64.00% 58.00% 65.91% $0.00 8.79% 20.18 3.77





IDACORP, Inc. IDA $84.87 4.50% 3.80% 3.50% 4.50% 5.35% 55.00% 61.00% 65.91% ($0.00) 8.58% 21.46 4.02





Mean 9.12% 9.23%

Max 10.27% 10.38%

Min 8.58% 8.69%

Projected Annual


Company Ticker 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE $3.14 $3.33 $3.53 $3.75 $3.98 $4.22 $4.47 $4.74 $5.01 $5.29 $5.58 $5.87 $6.19 $6.52 $6.87 $7.23 $7.62





IDACORP, Inc. IDA $3.94 $4.12 $4.30 $4.50 $4.70 $4.91 $5.14 $5.38 $5.65 $5.93 $6.24 $6.58 $6.93 $7.30 $7.69 $8.10 $8.53




Projected Annual


Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE 64.00% 62.50% 61.00% 59.50% 58.00% 59.32% 60.64% 61.95% 63.27% 64.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%





IDACORP, Inc. IDA 55.00% 56.50% 58.00% 59.50% 61.00% 61.82% 62.64% 63.45% 64.27% 65.09% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%




Projected Annual

Cash Flows [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63]

Terminal


ALLETE, Inc. ALE $2.13 $2.21 $2.29 $2.37 $2.45 $2.65 $2.87 $3.10 $3.35 $3.60 $3.87 $4.08 $4.30 $4.53 $4.77 $5.02 $153.79





IDACORP, Inc. IDA $2.26 $2.43 $2.61 $2.80 $3.00 $3.18 $3.37 $3.58 $3.81 $4.06 $4.33 $4.57 $4.81 $5.07 $5.34 $5.62 $183.16






Initial #######


ALLETE, Inc. ALE ($70.80) $0.00 $0.54 $2.20 $2.29 $2.37 $2.45 $2.65 $2.87 $3.10 $3.35 $3.60 $3.87 $4.08 $4.30 $4.53 $4.77 $158.81





IDACORP, Inc. IDA ($84.87) $0.00 $0.58 $2.32 $2.61 $2.80 $3.00 $3.18 $3.37 $3.58 $3.81 $4.06 $4.33 $4.57 $4.81 $5.07 $5.34 $188.78







Case No. PU-17-


Page 9 of 20

Inputs [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13]



Value

Line

Low


ALLETE, Inc. ALE $70.80 6.10% 5.00% 6.00% 5.00% 5.35% 64.00% 58.00% 65.91% $0.00 8.55% 21.69 4.06





IDACORP, Inc. IDA $84.87 4.50% 3.80% 3.50% 3.50% 5.35% 55.00% 61.00% 65.91% ($0.00) 8.37% 22.95 4.29





Mean 8.62% 8.73%

Max 9.48% 9.59%

Min 8.10% 8.21%

Projected Annual


Company Ticker 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE $3.14 $3.30 $3.46 $3.63 $3.82 $4.01 $4.21 $4.43 $4.65 $4.90 $5.16 $5.43 $5.72 $6.03 $6.35 $6.69 $7.05





IDACORP, Inc. IDA $3.94 $4.08 $4.22 $4.37 $4.52 $4.68 $4.86 $5.06 $5.28 $5.53 $5.81 $6.12 $6.45 $6.79 $7.16 $7.54 $7.94




Projected Annual


Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE 64.00% 62.50% 61.00% 59.50% 58.00% 59.32% 60.64% 61.95% 63.27% 64.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%





IDACORP, Inc. IDA 55.00% 56.50% 58.00% 59.50% 61.00% 61.82% 62.64% 63.45% 64.27% 65.09% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%




Projected Annual

Cash Flows [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63]

Terminal


ALLETE, Inc. ALE $2.11 $2.16 $2.22 $2.27 $2.32 $2.50 $2.68 $2.88 $3.10 $3.33 $3.58 $3.77 $3.97 $4.19 $4.41 $4.65 $152.84





IDACORP, Inc. IDA $2.24 $2.38 $2.53 $2.69 $2.85 $3.00 $3.17 $3.35 $3.55 $3.78 $4.03 $4.25 $4.48 $4.72 $4.97 $5.23 $182.23






Initial #######


ALLETE, Inc. ALE ($70.80) $0.00 $0.54 $2.16 $2.22 $2.27 $2.32 $2.50 $2.68 $2.88 $3.10 $3.33 $3.58 $3.77 $3.97 $4.19 $4.41 $157.49





IDACORP, Inc. IDA ($84.87) $0.00 $0.57 $2.28 $2.53 $2.69 $2.85 $3.00 $3.17 $3.35 $3.55 $3.78 $4.03 $4.25 $4.48 $4.72 $4.97 $187.47







Case No. PU-17-


Page 10 of 20 Multi-Stage DCF Notes:

[1] Source: Bloomberg; based on 30-, 90-, and 180-day historical average as of September 29, 2017

[2] Source: Zacks

[3] Source: Yahoo! Finance

[4] Source: Value Line

[5] Equals indicated value (average, minimum, maximum) of Columns [2], [3], [4]

[6] Source: Federal Reserve, Bureau of Economic Analysis, Blue Chip Financial Forecast



[9] Source: Bloomberg Professional

[10] Equals Column [1] + Column [64]

[11] Equals result of Excel Solver function; goal: Column [10] equals $0.00

[12] Equals Column [63] / Column [30]

[13] Equals Column [12] / (Column [6] x 100)


[15] Equals Column [14] x (1 + Column [5])





[20] Equals (1 + (Column [5] + (((Column [6] − Column [5]) / (2027 − 2022 + 1)) x (2022 − 2021)))) x Column [19]











[31] Equals Column [7]

[32] Equals Column [31] + ((Column [35] − Column [31]) / 4)















[47] Equals Column [15] x Column [31]
















[63] Equals (Column [62] x (1 + Column [6])) / (Column [11] − Column [6])

[64] Equals negative net present value; discount rate equals Column [11], cash flows equal Column [65] through Column [81]

[65] Equals $0.00

[66] Equals Column [47] x (12/31/2017 - 09/29/2017) / 365

[67] Equals Column [47] x (1 + (0.5 x Column [5]))














[81] Equals Column [62] + [63]

Case No. PU-17-


Page 11 of 20

Inputs [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13]



Value


ALLETE, Inc. ALE $77.39 6.10% 5.00% 6.00% 5.70% 5.35% 64.00% 58.00% 65.91% ($0.00) 8.26% 22.05 4.12





IDACORP, Inc. IDA $89.09 4.50% 3.80% 3.50% 3.93% 5.35% 55.00% 61.00% 65.91% ($0.00) 7.96% 22.05 4.12





Mean 9.04% 9.15%

Max 11.45% 11.57%

Min 7.96% 8.08%

Projected Annual


Company Ticker 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE $3.14 $3.32 $3.51 $3.71 $3.92 $4.14 $4.38 $4.62 $4.88 $5.14 $5.42 $5.71 $6.02 $6.34 $6.68 $7.03 $7.41





IDACORP, Inc. IDA $3.94 $4.09 $4.26 $4.42 $4.60 $4.78 $4.98 $5.20 $5.44 $5.70 $5.99 $6.31 $6.65 $7.01 $7.38 $7.78 $8.19




Projected Annual


Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE 64.00% 62.50% 61.00% 59.50% 58.00% 59.32% 60.64% 61.95% 63.27% 64.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%





IDACORP, Inc. IDA 55.00% 56.50% 58.00% 59.50% 61.00% 61.82% 62.64% 63.45% 64.27% 65.09% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%




Projected Annual

Cash Flows [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63]

Terminal


ALLETE, Inc. ALE $2.12 $2.19 $2.26 $2.33 $2.40 $2.60 $2.80 $3.02 $3.25 $3.50 $3.76 $3.96 $4.18 $4.40 $4.63 $4.88 $163.33





IDACORP, Inc. IDA $2.25 $2.40 $2.57 $2.74 $2.91 $3.08 $3.25 $3.45 $3.67 $3.90 $4.16 $4.38 $4.62 $4.87 $5.13 $5.40 $180.62






Initial #######


ALLETE, Inc. ALE ($77.39) $0.00 $0.54 $2.18 $2.26 $2.33 $2.40 $2.60 $2.80 $3.02 $3.25 $3.50 $3.76 $3.96 $4.18 $4.40 $4.63 $168.21





IDACORP, Inc. IDA ($89.09) $0.00 $0.57 $2.30 $2.57 $2.74 $2.91 $3.08 $3.25 $3.45 $3.67 $3.90 $4.16 $4.38 $4.62 $4.87 $5.13 $186.02







Case No. PU-17-


Page 12 of 20

Inputs [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13]



Value

Line

High


ALLETE, Inc. ALE $77.39 6.10% 5.00% 6.00% 6.10% 5.35% 64.00% 58.00% 65.91% $0.00 8.49% 22.05 4.12





IDACORP, Inc. IDA $89.09 4.50% 3.80% 3.50% 4.50% 5.35% 55.00% 61.00% 65.91% ($0.00) 8.30% 22.05 4.12





Mean 9.65% 9.77%

Max 12.56% 12.67%

Min 8.30% 8.41%

Projected Annual


Company Ticker 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE $3.14 $3.33 $3.53 $3.75 $3.98 $4.22 $4.47 $4.74 $5.01 $5.29 $5.58 $5.87 $6.19 $6.52 $6.87 $7.23 $7.62





IDACORP, Inc. IDA $3.94 $4.12 $4.30 $4.50 $4.70 $4.91 $5.14 $5.38 $5.65 $5.93 $6.24 $6.58 $6.93 $7.30 $7.69 $8.10 $8.53




Projected Annual


Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE 64.00% 62.50% 61.00% 59.50% 58.00% 59.32% 60.64% 61.95% 63.27% 64.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%





IDACORP, Inc. IDA 55.00% 56.50% 58.00% 59.50% 61.00% 61.82% 62.64% 63.45% 64.27% 65.09% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%




Projected Annual

Cash Flows [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63]

Terminal


ALLETE, Inc. ALE $2.13 $2.21 $2.29 $2.37 $2.45 $2.65 $2.87 $3.10 $3.35 $3.60 $3.87 $4.08 $4.30 $4.53 $4.77 $5.02 $168.03





IDACORP, Inc. IDA $2.26 $2.43 $2.61 $2.80 $3.00 $3.18 $3.37 $3.58 $3.81 $4.06 $4.33 $4.57 $4.81 $5.07 $5.34 $5.62 $188.13






Initial #######


ALLETE, Inc. ALE ($77.39) $0.00 $0.54 $2.20 $2.29 $2.37 $2.45 $2.65 $2.87 $3.10 $3.35 $3.60 $3.87 $4.08 $4.30 $4.53 $4.77 $173.05





IDACORP, Inc. IDA ($89.09) $0.00 $0.58 $2.32 $2.61 $2.80 $3.00 $3.18 $3.37 $3.58 $3.81 $4.06 $4.33 $4.57 $4.81 $5.07 $5.34 $193.75







Case No. PU-17-


Page 13 of 20

Inputs [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13]



Value

Line

Low


ALLETE, Inc. ALE $77.39 6.10% 5.00% 6.00% 5.00% 5.35% 64.00% 58.00% 65.91% $0.00 7.85% 22.05 4.12





IDACORP, Inc. IDA $89.09 4.50% 3.80% 3.50% 3.50% 5.35% 55.00% 61.00% 65.91% ($0.00) 7.71% 22.05 4.12





Mean 8.38% 8.49%

Max 10.87% 10.98%

Min 7.02% 7.14%

Projected Annual


Company Ticker 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE $3.14 $3.30 $3.46 $3.63 $3.82 $4.01 $4.21 $4.43 $4.65 $4.90 $5.16 $5.43 $5.72 $6.03 $6.35 $6.69 $7.05





IDACORP, Inc. IDA $3.94 $4.08 $4.22 $4.37 $4.52 $4.68 $4.86 $5.06 $5.28 $5.53 $5.81 $6.12 $6.45 $6.79 $7.16 $7.54 $7.94




Projected Annual


Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE 64.00% 62.50% 61.00% 59.50% 58.00% 59.32% 60.64% 61.95% 63.27% 64.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%





IDACORP, Inc. IDA 55.00% 56.50% 58.00% 59.50% 61.00% 61.82% 62.64% 63.45% 64.27% 65.09% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%




Projected Annual

Cash Flows [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63]

Terminal


ALLETE, Inc. ALE $2.11 $2.16 $2.22 $2.27 $2.32 $2.50 $2.68 $2.88 $3.10 $3.33 $3.58 $3.77 $3.97 $4.19 $4.41 $4.65 $155.39





IDACORP, Inc. IDA $2.24 $2.38 $2.53 $2.69 $2.85 $3.00 $3.17 $3.35 $3.55 $3.78 $4.03 $4.25 $4.48 $4.72 $4.97 $5.23 $175.06






Initial #######


ALLETE, Inc. ALE ($77.39) $0.00 $0.54 $2.16 $2.22 $2.27 $2.32 $2.50 $2.68 $2.88 $3.10 $3.33 $3.58 $3.77 $3.97 $4.19 $4.41 $160.04





IDACORP, Inc. IDA ($89.09) $0.00 $0.57 $2.28 $2.53 $2.69 $2.85 $3.00 $3.17 $3.35 $3.55 $3.78 $4.03 $4.25 $4.48 $4.72 $4.97 $180.29







Case No. PU-17-


Page 14 of 20

Inputs [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13]



Value


ALLETE, Inc. ALE $74.35 6.10% 5.00% 6.00% 5.70% 5.35% 64.00% 58.00% 65.91% ($0.00) 8.62% 22.05 4.12





IDACORP, Inc. IDA $87.63 4.50% 3.80% 3.50% 3.93% 5.35% 55.00% 61.00% 65.91% ($0.00) 8.11% 22.05 4.12





Mean 9.20% 9.31%

Max 11.58% 11.69%

Min 8.01% 8.12%

Projected Annual


Company Ticker 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE $3.14 $3.32 $3.51 $3.71 $3.92 $4.14 $4.38 $4.62 $4.88 $5.14 $5.42 $5.71 $6.02 $6.34 $6.68 $7.03 $7.41





IDACORP, Inc. IDA $3.94 $4.09 $4.26 $4.42 $4.60 $4.78 $4.98 $5.20 $5.44 $5.70 $5.99 $6.31 $6.65 $7.01 $7.38 $7.78 $8.19




Projected Annual


Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE 64.00% 62.50% 61.00% 59.50% 58.00% 59.32% 60.64% 61.95% 63.27% 64.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%





IDACORP, Inc. IDA 55.00% 56.50% 58.00% 59.50% 61.00% 61.82% 62.64% 63.45% 64.27% 65.09% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%




Projected Annual

Cash Flows [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63]

Terminal


ALLETE, Inc. ALE $2.12 $2.19 $2.26 $2.33 $2.40 $2.60 $2.80 $3.02 $3.25 $3.50 $3.76 $3.96 $4.18 $4.40 $4.63 $4.88 $163.33





IDACORP, Inc. IDA $2.25 $2.40 $2.57 $2.74 $2.91 $3.08 $3.25 $3.45 $3.67 $3.90 $4.16 $4.38 $4.62 $4.87 $5.13 $5.40 $180.62






Initial #######


ALLETE, Inc. ALE ($74.35) $0.00 $0.54 $2.18 $2.26 $2.33 $2.40 $2.60 $2.80 $3.02 $3.25 $3.50 $3.76 $3.96 $4.18 $4.40 $4.63 $168.21





IDACORP, Inc. IDA ($87.63) $0.00 $0.57 $2.30 $2.57 $2.74 $2.91 $3.08 $3.25 $3.45 $3.67 $3.90 $4.16 $4.38 $4.62 $4.87 $5.13 $186.02







Case No. PU-17-


Page 15 of 20

Inputs [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13]



Value

Line

High


ALLETE, Inc. ALE $74.35 6.10% 5.00% 6.00% 6.10% 5.35% 64.00% 58.00% 65.91% ($0.00) 8.85% 22.05 4.12





IDACORP, Inc. IDA $87.63 4.50% 3.80% 3.50% 4.50% 5.35% 55.00% 61.00% 65.91% ($0.00) 8.45% 22.05 4.12





Mean 9.82% 9.93%

Max 12.69% 12.80%

Min 8.45% 8.56%

Projected Annual


Company Ticker 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE $3.14 $3.33 $3.53 $3.75 $3.98 $4.22 $4.47 $4.74 $5.01 $5.29 $5.58 $5.87 $6.19 $6.52 $6.87 $7.23 $7.62





IDACORP, Inc. IDA $3.94 $4.12 $4.30 $4.50 $4.70 $4.91 $5.14 $5.38 $5.65 $5.93 $6.24 $6.58 $6.93 $7.30 $7.69 $8.10 $8.53




Projected Annual


Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE 64.00% 62.50% 61.00% 59.50% 58.00% 59.32% 60.64% 61.95% 63.27% 64.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%





IDACORP, Inc. IDA 55.00% 56.50% 58.00% 59.50% 61.00% 61.82% 62.64% 63.45% 64.27% 65.09% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%




Projected Annual

Cash Flows [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63]

Terminal


ALLETE, Inc. ALE $2.13 $2.21 $2.29 $2.37 $2.45 $2.65 $2.87 $3.10 $3.35 $3.60 $3.87 $4.08 $4.30 $4.53 $4.77 $5.02 $168.03





IDACORP, Inc. IDA $2.26 $2.43 $2.61 $2.80 $3.00 $3.18 $3.37 $3.58 $3.81 $4.06 $4.33 $4.57 $4.81 $5.07 $5.34 $5.62 $188.13






Initial #######


ALLETE, Inc. ALE ($74.35) $0.00 $0.54 $2.20 $2.29 $2.37 $2.45 $2.65 $2.87 $3.10 $3.35 $3.60 $3.87 $4.08 $4.30 $4.53 $4.77 $173.05





IDACORP, Inc. IDA ($87.63) $0.00 $0.58 $2.32 $2.61 $2.80 $3.00 $3.18 $3.37 $3.58 $3.81 $4.06 $4.33 $4.57 $4.81 $5.07 $5.34 $193.75







Case No. PU-17-


Page 16 of 20

Inputs [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13]



Value

Line

Low


ALLETE, Inc. ALE $74.35 6.10% 5.00% 6.00% 5.00% 5.35% 64.00% 58.00% 65.91% ($0.00) 8.21% 22.05 4.12





IDACORP, Inc. IDA $87.63 4.50% 3.80% 3.50% 3.50% 5.35% 55.00% 61.00% 65.91% ($0.00) 7.85% 22.05 4.12





Mean 8.54% 8.65%

Max 10.99% 11.10%

Min 7.03% 7.14%

Projected Annual


Company Ticker 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE $3.14 $3.30 $3.46 $3.63 $3.82 $4.01 $4.21 $4.43 $4.65 $4.90 $5.16 $5.43 $5.72 $6.03 $6.35 $6.69 $7.05





IDACORP, Inc. IDA $3.94 $4.08 $4.22 $4.37 $4.52 $4.68 $4.86 $5.06 $5.28 $5.53 $5.81 $6.12 $6.45 $6.79 $7.16 $7.54 $7.94




Projected Annual


Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE 64.00% 62.50% 61.00% 59.50% 58.00% 59.32% 60.64% 61.95% 63.27% 64.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%





IDACORP, Inc. IDA 55.00% 56.50% 58.00% 59.50% 61.00% 61.82% 62.64% 63.45% 64.27% 65.09% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%




Projected Annual

Cash Flows [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63]

Terminal


ALLETE, Inc. ALE $2.11 $2.16 $2.22 $2.27 $2.32 $2.50 $2.68 $2.88 $3.10 $3.33 $3.58 $3.77 $3.97 $4.19 $4.41 $4.65 $155.39





IDACORP, Inc. IDA $2.24 $2.38 $2.53 $2.69 $2.85 $3.00 $3.17 $3.35 $3.55 $3.78 $4.03 $4.25 $4.48 $4.72 $4.97 $5.23 $175.06






Initial #######


ALLETE, Inc. ALE ($74.35) $0.00 $0.54 $2.16 $2.22 $2.27 $2.32 $2.50 $2.68 $2.88 $3.10 $3.33 $3.58 $3.77 $3.97 $4.19 $4.41 $160.04





IDACORP, Inc. IDA ($87.63) $0.00 $0.57 $2.28 $2.53 $2.69 $2.85 $3.00 $3.17 $3.35 $3.55 $3.78 $4.03 $4.25 $4.48 $4.72 $4.97 $180.29







Case No. PU-17-


Page 17 of 20

Inputs [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13]



Value


ALLETE, Inc. ALE $70.80 6.10% 5.00% 6.00% 5.70% 5.35% 64.00% 58.00% 65.91% ($0.00) 9.06% 22.05 4.12





IDACORP, Inc. IDA $84.87 4.50% 3.80% 3.50% 3.93% 5.35% 55.00% 61.00% 65.91% ($0.00) 8.40% 22.05 4.12





Mean 9.46% 9.57%

Max 11.56% 11.68%

Min 8.28% 8.40%

Projected Annual


Company Ticker 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE $3.14 $3.32 $3.51 $3.71 $3.92 $4.14 $4.38 $4.62 $4.88 $5.14 $5.42 $5.71 $6.02 $6.34 $6.68 $7.03 $7.41





IDACORP, Inc. IDA $3.94 $4.09 $4.26 $4.42 $4.60 $4.78 $4.98 $5.20 $5.44 $5.70 $5.99 $6.31 $6.65 $7.01 $7.38 $7.78 $8.19




Projected Annual


Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE 64.00% 62.50% 61.00% 59.50% 58.00% 59.32% 60.64% 61.95% 63.27% 64.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%





IDACORP, Inc. IDA 55.00% 56.50% 58.00% 59.50% 61.00% 61.82% 62.64% 63.45% 64.27% 65.09% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%




Projected Annual

Cash Flows [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63]

Terminal


ALLETE, Inc. ALE $2.12 $2.19 $2.26 $2.33 $2.40 $2.60 $2.80 $3.02 $3.25 $3.50 $3.76 $3.96 $4.18 $4.40 $4.63 $4.88 $163.33





IDACORP, Inc. IDA $2.25 $2.40 $2.57 $2.74 $2.91 $3.08 $3.25 $3.45 $3.67 $3.90 $4.16 $4.38 $4.62 $4.87 $5.13 $5.40 $180.62






Initial #######


ALLETE, Inc. ALE ($70.80) $0.00 $0.54 $2.18 $2.26 $2.33 $2.40 $2.60 $2.80 $3.02 $3.25 $3.50 $3.76 $3.96 $4.18 $4.40 $4.63 $168.21





IDACORP, Inc. IDA ($84.87) $0.00 $0.57 $2.30 $2.57 $2.74 $2.91 $3.08 $3.25 $3.45 $3.67 $3.90 $4.16 $4.38 $4.62 $4.87 $5.13 $186.02







Case No. PU-17-


Page 18 of 20

Inputs [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13]



Value

Line

High


ALLETE, Inc. ALE $70.80 6.10% 5.00% 6.00% 6.10% 5.35% 64.00% 58.00% 65.91% ($0.00) 9.30% 22.05 4.12





IDACORP, Inc. IDA $84.87 4.50% 3.80% 3.50% 4.50% 5.35% 55.00% 61.00% 65.91% ($0.00) 8.73% 22.05 4.12


OGE Energy Corp. OGE $35.23 5.30% 6.30% 6.00% 6.30% 5.35% 65.00% 72.00% 65.91% $0.00 10.42% 22.05 4.12



Mean 10.08% 10.19%

Max 12.68% 12.79%

Min 8.73% 8.85%

Projected Annual


Company Ticker 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE $3.14 $3.33 $3.53 $3.75 $3.98 $4.22 $4.47 $4.74 $5.01 $5.29 $5.58 $5.87 $6.19 $6.52 $6.87 $7.23 $7.62





IDACORP, Inc. IDA $3.94 $4.12 $4.30 $4.50 $4.70 $4.91 $5.14 $5.38 $5.65 $5.93 $6.24 $6.58 $6.93 $7.30 $7.69 $8.10 $8.53




Projected Annual


Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE 64.00% 62.50% 61.00% 59.50% 58.00% 59.32% 60.64% 61.95% 63.27% 64.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%





IDACORP, Inc. IDA 55.00% 56.50% 58.00% 59.50% 61.00% 61.82% 62.64% 63.45% 64.27% 65.09% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%




Projected Annual

Cash Flows [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63]

Terminal


ALLETE, Inc. ALE $2.13 $2.21 $2.29 $2.37 $2.45 $2.65 $2.87 $3.10 $3.35 $3.60 $3.87 $4.08 $4.30 $4.53 $4.77 $5.02 $168.03





IDACORP, Inc. IDA $2.26 $2.43 $2.61 $2.80 $3.00 $3.18 $3.37 $3.58 $3.81 $4.06 $4.33 $4.57 $4.81 $5.07 $5.34 $5.62 $188.13






Initial #######


ALLETE, Inc. ALE ($70.80) $0.00 $0.54 $2.20 $2.29 $2.37 $2.45 $2.65 $2.87 $3.10 $3.35 $3.60 $3.87 $4.08 $4.30 $4.53 $4.77 $173.05





IDACORP, Inc. IDA ($84.87) $0.00 $0.58 $2.32 $2.61 $2.80 $3.00 $3.18 $3.37 $3.58 $3.81 $4.06 $4.33 $4.57 $4.81 $5.07 $5.34 $193.75







Case No. PU-17-


Page 19 of 20

Inputs [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13]



Value

Line

Low


ALLETE, Inc. ALE $70.80 6.10% 5.00% 6.00% 5.00% 5.35% 64.00% 58.00% 65.91% ($0.00) 8.64% 22.05 4.12





IDACORP, Inc. IDA $84.87 4.50% 3.80% 3.50% 3.50% 5.35% 55.00% 61.00% 65.91% ($0.00) 8.14% 22.05 4.12





Mean 8.80% 8.91%

Max 10.98% 11.09%

Min 7.29% 7.41%

Projected Annual


Company Ticker 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE $3.14 $3.30 $3.46 $3.63 $3.82 $4.01 $4.21 $4.43 $4.65 $4.90 $5.16 $5.43 $5.72 $6.03 $6.35 $6.69 $7.05





IDACORP, Inc. IDA $3.94 $4.08 $4.22 $4.37 $4.52 $4.68 $4.86 $5.06 $5.28 $5.53 $5.81 $6.12 $6.45 $6.79 $7.16 $7.54 $7.94




Projected Annual


Company Ticker 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

ALLETE, Inc. ALE 64.00% 62.50% 61.00% 59.50% 58.00% 59.32% 60.64% 61.95% 63.27% 64.59% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%





IDACORP, Inc. IDA 55.00% 56.50% 58.00% 59.50% 61.00% 61.82% 62.64% 63.45% 64.27% 65.09% 65.91% 65.91% 65.91% 65.91% 65.91% 65.91%




Projected Annual

Cash Flows [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63]

Terminal


ALLETE, Inc. ALE $2.11 $2.16 $2.22 $2.27 $2.32 $2.50 $2.68 $2.88 $3.10 $3.33 $3.58 $3.77 $3.97 $4.19 $4.41 $4.65 $155.39





IDACORP, Inc. IDA $2.24 $2.38 $2.53 $2.69 $2.85 $3.00 $3.17 $3.35 $3.55 $3.78 $4.03 $4.25 $4.48 $4.72 $4.97 $5.23 $175.06






Initial #######


ALLETE, Inc. ALE ($70.80) $0.00 $0.54 $2.16 $2.22 $2.27 $2.32 $2.50 $2.68 $2.88 $3.10 $3.33 $3.58 $3.77 $3.97 $4.19 $4.41 $160.04





IDACORP, Inc. IDA ($84.87) $0.00 $0.57 $2.28 $2.53 $2.69 $2.85 $3.00 $3.17 $3.35 $3.55 $3.78 $4.03 $4.25 $4.48 $4.72 $4.97 $180.29







Case No. PU-17-


Page 20 of 20

Multi-Stage DCF Notes:

[1] Source: Bloomberg; based on 30-, 90-, and 180-day historical average as of September 29, 2017

[2] Source: Zacks

[3] Source: Yahoo! Finance


[5] Equals indicated value (average, minimum, maximum) of Columns [2], [3], [4]

[6] Source: Federal Reserve, Bureau of Economic Analysis, Blue Chip Financial Forecast




[10] Equals Column [1] + Column [64]

[11] Equals result of Excel Solver function; goal: Column [10] equals $0.00

[12] Equals Proxy Group 30-day average PE ratio. Source: SNL Financial

[13] Equals Column [12] / (Column [6] x 100)



















































[64] Equals negative net present value; discount rate equals Column [11], cash flows equal Column [65] through Column [81]

[65] Equals $0.00

[66] Equals Column [47] x (12/31/2017 - 09/29/2017) / 365

[67] Equals Column [47] x (1 + (0.5 x Column [5]))














[81] Equals Column [62] + [63]

Case No. PU-17-


Page 1 of 12

Ex-Ante Market Risk Premium

Market DCF Method Based - Bloomberg

[1] [2] [3]

S&P 500

Est. Required

Market Return

Current 30-Year

Treasury (30-day

average)

Implied Market

Risk Premium

13.83% 2.77% 11.06%

[4] [5] [6] [7] [8] [9]

Company Ticker

Market

Capitalization Weight in Index

Estimated

Dividend Yield

Long-Term

Growth Est. DCF Result

Weighted

DCF Result

AGILENT TECHNOLOGIES INC A 20,661.36 0.09% 0.82% 9.53% 10.39% 0.0097%

AMERICAN AIRLINES GROUP INC AAL 23,128.07 0.10% 0.89% -3.23% -2.35% -0.0024%

ADVANCE AUTO PARTS INC AAP 7,327.17 0.03% 0.26% 8.96% 9.23% 0.0030%

APPLE INC AAPL 796,064.94 3.58% 1.55% 10.98% 12.61% 0.4516%

ABBVIE INC ABBV 141,651.25 0.64% 2.88% 8.60% 11.61% 0.0740%

AMERISOURCEBERGEN CORP ABC 18,131.48 N/A 1.76% N/A N/A N/A

ABBOTT LABORATORIES ABT 92,709.97 0.42% 2.01% 11.77% 13.90% 0.0580%

ACCENTURE PLC-CL A ACN 87,221.75 0.39% 1.97% 10.63% 12.71% 0.0499%

ADOBE SYSTEMS INC ADBE 73,537.24 0.33% 0.00% 19.82% 19.82% 0.0656%

ANALOG DEVICES INC ADI 31,681.93 0.14% 1.97% 11.55% 13.64% 0.0194%

ARCHER-DANIELS-MIDLAND CO ADM 23,912.95 0.11% 3.02% 9.80% 12.97% 0.0140%

AUTOMATIC DATA PROCESSING ADP 48,586.48 0.22% 2.16% 11.48% 13.76% 0.0301%

ALLIANCE DATA SYSTEMS CORP ADS 12,292.36 0.06% 0.82% 14.00% 14.88% 0.0082%

AUTODESK INC ADSK 24,606.52 0.11% 0.00% 26.00% 26.00% 0.0288%

AMEREN CORPORATION AEE 14,034.00 N/A 3.11% N/A N/A N/A

AMERICAN ELECTRIC POWER AEP 34,546.87 0.16% 3.39% 5.00% 8.47% 0.0132%

AES CORP AES 7,276.03 0.03% 4.36% 8.00% 12.53% 0.0041%

AETNA INC AET 52,807.22 0.24% 1.26% 11.46% 12.79% 0.0304%

AFLAC INC AFL 32,167.70 0.14% 2.14% 2.85% 5.02% 0.0073%

ALLERGAN PLC AGN 68,516.05 0.31% 1.37% 12.33% 13.78% 0.0425%

AMERICAN INTERNATIONAL GROUP AIG 55,460.07 0.25% 2.09% 11.00% 13.20% 0.0329%

APARTMENT INVT & MGMT CO -A AIV 6,887.02 0.03% 3.30% 19.07% 22.68% 0.0070%

ASSURANT INC AIZ 5,147.27 N/A 2.25% N/A N/A N/A

ARTHUR J GALLAGHER & CO AJG 11,089.09 0.05% 2.53% 10.83% 13.50% 0.0067%

AKAMAI TECHNOLOGIES INC AKAM 8,351.74 0.04% 0.00% 13.40% 13.40% 0.0050%

ALBEMARLE CORP ALB 15,058.54 0.07% 0.94% 12.17% 13.17% 0.0089%

ALIGN TECHNOLOGY INC ALGN 14,929.65 0.07% 0.00% 30.00% 30.00% 0.0201%

ALASKA AIR GROUP INC ALK 9,410.73 0.04% 1.58% 6.33% 7.96% 0.0034%

ALLSTATE CORP ALL 33,212.56 0.15% 1.59% 16.27% 17.99% 0.0269%

ALLEGION PLC ALLE 8,213.35 0.04% 0.69% 13.09% 13.83% 0.0051%

ALEXION PHARMACEUTICALS INC ALXN 31,310.66 0.14% 0.00% 20.50% 20.50% 0.0289%

APPLIED MATERIALS INC AMAT 55,553.32 0.25% 0.79% 16.71% 17.57% 0.0439%

ADVANCED MICRO DEVICES AMD 12,071.43 0.05% 0.00% 5.00% 5.00% 0.0027%

AMETEK INC AME 15,241.73 0.07% 0.58% 11.62% 12.23% 0.0084%

AFFILIATED MANAGERS GROUP AMG 10,622.95 0.05% 0.42% 15.79% 16.24% 0.0078%

AMGEN INC AMGN 136,047.86 0.61% 2.44% 4.67% 7.16% 0.0438%

AMERIPRISE FINANCIAL INC AMP 22,268.06 0.10% 2.19% 10.40% 12.70% 0.0127%

AMERICAN TOWER CORP AMT 58,659.97 0.26% 1.92% 20.68% 22.80% 0.0602%

AMAZON.COM INC AMZN 461,812.85 2.08% 0.00% 27.82% 27.82% 0.5779%

ANDEAVOR ANDV 16,184.40 0.07% 2.20% 18.94% 21.34% 0.0155%

ANSYS INC ANSS 10,402.68 0.05% 0.00% 12.40% 12.40% 0.0058%

ANTHEM INC ANTM 49,859.58 0.22% 1.42% 9.78% 11.27% 0.0253%

AON PLC AON 37,158.68 0.17% 0.97% 11.86% 12.88% 0.0215%

SMITH (A.O.) CORP AOS 10,253.99 0.05% 0.94% 15.00% 16.01% 0.0074%

APACHE CORP APA 17,446.78 0.08% 2.18% -20.64% -18.68% -0.0147%

ANADARKO PETROLEUM CORP APC 27,373.50 0.12% 0.41% -10.30% -9.91% -0.0122%

AIR PRODUCTS & CHEMICALS INC APD 32,959.51 0.15% 2.44% 9.29% 11.85% 0.0176%

AMPHENOL CORP-CL A APH 25,852.86 0.12% 0.78% 11.23% 12.05% 0.0140%

ALEXANDRIA REAL ESTATE EQUIT ARE 11,138.70 0.05% 2.85% 6.80% 9.74% 0.0049%

ARCONIC INC ARNC 10,972.85 0.05% 0.96% 16.90% 17.95% 0.0089%

ACTIVISION BLIZZARD INC ATVI 48,699.96 0.22% 0.47% 13.63% 14.12% 0.0309%

AVALONBAY COMMUNITIES INC AVB 24,636.80 0.11% 3.18% 6.42% 9.71% 0.0108%

BROADCOM LTD AVGO 98,951.31 0.45% 1.68% 15.32% 17.13% 0.0762%

AVERY DENNISON CORP AVY 8,692.09 0.04% 1.73% 7.65% 9.44% 0.0037%

AMERICAN WATER WORKS CO INC AWK 14,424.82 0.06% 2.02% 7.95% 10.05% 0.0065%

AMERICAN EXPRESS CO AXP 79,964.80 0.36% 1.48% 9.70% 11.25% 0.0405%

ACUITY BRANDS INC AYI 7,209.74 0.03% 0.30% 17.67% 18.00% 0.0058%

AUTOZONE INC AZO 16,681.35 0.08% 0.00% 13.07% 13.07% 0.0098%

BOEING CO/THE BA 150,259.31 0.68% 2.26% 15.20% 17.63% 0.1192%

BANK OF AMERICA CORP BAC 267,351.71 1.20% 1.54% 10.47% 12.09% 0.1454%

BAXTER INTERNATIONAL INC BAX 34,190.65 0.15% 0.99% 13.56% 14.62% 0.0225%

BB&T CORP BBT 37,931.86 0.17% 2.68% 9.75% 12.56% 0.0214%

BEST BUY CO INC BBY 17,041.55 0.08% 2.38% 12.68% 15.21% 0.0117%

CR BARD INC BCR 23,291.23 0.10% 0.32% 11.00% 11.34% 0.0119%

BECTON DICKINSON AND CO BDX 44,591.36 0.20% 1.47% 12.53% 14.08% 0.0282%

FRANKLIN RESOURCES INC BEN 24,823.29 0.11% 1.79% 10.00% 11.88% 0.0133%

BROWN-FORMAN CORP-CLASS B BF/B 21,100.91 0.09% 1.40% 9.72% 11.19% 0.0106%

BRIGHTHOUSE FINANCIAL INC BHF 7,282.20 0.03% 0.00% 8.00% 8.00% 0.0026%

BAKER HUGHES A GE CO BHGE 41,935.10 0.19% 1.37% 6.50% 7.91% 0.0149%

BIOGEN INC BIIB 66,203.51 0.30% 0.00% 6.48% 6.48% 0.0193%

BANK OF NEW YORK MELLON CORP BK 54,777.94 0.25% 1.62% 13.24% 14.97% 0.0369%

BLACKROCK INC BLK 72,681.20 0.33% 2.24% 13.60% 16.00% 0.0523%

BALL CORP BLL 14,528.75 0.07% 0.74% 7.23% 7.99% 0.0052%

BRISTOL-MYERS SQUIBB CO BMY 104,528.91 0.47% 2.46% 8.00% 10.56% 0.0497%

BERKSHIRE HATHAWAY INC-CL B BRK/B 452,055.88 N/A 0.00% N/A N/A N/A

BOSTON SCIENTIFIC CORP BSX 40,024.95 0.18% 0.00% 10.33% 10.33% 0.0186%

BORGWARNER INC BWA 10,812.73 0.05% 1.10% 5.09% 6.22% 0.0030%

BOSTON PROPERTIES INC BXP 18,962.56 0.09% 2.43% 4.46% 6.95% 0.0059%

CITIGROUP INC C 198,184.21 0.89% 1.31% 12.97% 14.36% 0.1280%

CA INC CA 14,062.00 0.06% 3.06% 2.97% 6.07% 0.0038%

Case No. PU-17-


Page 2 of 12 [4] [5] [6] [7] [8] [9]

Company Ticker

Market


Estimated

Dividend Yield

Long-Term


Weighted

DCF Result

CONAGRA BRANDS INC CAG 14,024.20 0.06% 2.55% 7.00% 9.64% 0.0061%

CARDINAL HEALTH INC CAH 21,094.25 0.09% 2.76% 10.97% 13.88% 0.0132%

CATERPILLAR INC CAT 73,700.22 0.33% 2.50% 10.00% 12.62% 0.0418%

CHUBB LTD CB 66,345.06 0.30% 1.99% 10.60% 12.70% 0.0379%

CBRE GROUP INC - A CBG 12,800.99 0.06% 0.00% 9.35% 9.35% 0.0054%

CBOE HOLDINGS INC CBOE 12,138.23 0.05% 0.97% 22.39% 23.46% 0.0128%

CBS CORP-CLASS B NON VOTING CBS 23,312.19 0.10% 1.26% 13.37% 14.71% 0.0154%

CROWN CASTLE INTL CORP CCI 40,618.60 0.18% 3.86% 21.60% 25.88% 0.0473%

CARNIVAL CORP CCL 46,370.73 0.21% 2.38% 13.28% 15.82% 0.0330%

CADENCE DESIGN SYS INC CDNS 11,059.53 0.05% 0.00% 11.45% 11.45% 0.0057%

CELGENE CORP CELG 114,082.37 0.51% 0.00% 19.46% 19.46% 0.0999%

CERNER CORP CERN 23,648.47 0.11% 0.00% 12.00% 12.00% 0.0128%

CF INDUSTRIES HOLDINGS INC CF 8,200.97 0.04% 3.41% 6.00% 9.52% 0.0035%

CITIZENS FINANCIAL GROUP CFG 18,960.41 0.09% 1.68% 21.44% 23.30% 0.0199%

CHURCH & DWIGHT CO INC CHD 12,088.71 0.05% 1.57% 9.14% 10.79% 0.0059%

CHESAPEAKE ENERGY CORP CHK 3,905.86 0.02% 0.00% -13.02% -13.02% -0.0023%

C.H. ROBINSON WORLDWIDE INC CHRW 10,683.38 0.05% 2.84% 9.20% 12.17% 0.0058%

CHARTER COMMUNICATIONS INC-A CHTR 104,821.38 0.47% 0.00% 23.96% 23.96% 0.1130%

CIGNA CORP CI 47,067.40 0.21% 0.01% 12.91% 12.93% 0.0274%

CINCINNATI FINANCIAL CORP CINF 12,556.13 N/A 2.61% N/A N/A N/A

COLGATE-PALMOLIVE CO CL 64,169.34 0.29% 2.22% 9.47% 11.79% 0.0340%

CLOROX COMPANY CLX 17,003.62 0.08% 2.54% 6.72% 9.34% 0.0071%

COMERICA INC CMA 13,414.97 0.06% 1.43% 8.00% 9.49% 0.0057%

COMCAST CORP-CLASS A CMCSA 181,370.57 0.82% 1.63% 9.13% 10.84% 0.0884%

CME GROUP INC CME 46,119.28 0.21% 4.36% 10.47% 15.05% 0.0312%

CHIPOTLE MEXICAN GRILL INC CMG 8,776.80 0.04% 0.00% 50.05% 50.05% 0.0198%

CUMMINS INC CMI 28,165.29 0.13% 2.47% 10.23% 12.82% 0.0162%

CMS ENERGY CORP CMS 13,062.83 0.06% 2.86% 5.00% 7.94% 0.0047%

CENTENE CORP CNC 16,690.47 0.08% 0.00% 12.48% 12.48% 0.0094%

CENTERPOINT ENERGY INC CNP 12,590.22 0.06% 3.68% 6.00% 9.79% 0.0055%

CAPITAL ONE FINANCIAL CORP COF 40,949.42 0.18% 1.89% 5.97% 7.92% 0.0146%

CABOT OIL & GAS CORP COG 12,371.68 0.06% 0.64% 31.95% 32.68% 0.0182%

COACH INC COH 11,382.51 0.05% 3.42% 11.57% 15.19% 0.0078%

ROCKWELL COLLINS INC COL 21,237.22 0.10% 1.04% 10.73% 11.82% 0.0113%

COOPER COS INC/THE COO 11,606.35 0.05% 0.03% 9.75% 9.78% 0.0051%

CONOCOPHILLIPS COP 60,908.31 0.27% 2.12% 7.00% 9.19% 0.0252%

COSTCO WHOLESALE CORP COST 72,056.50 0.32% 2.85% 10.18% 13.18% 0.0427%

COTY INC-CL A COTY 12,381.14 0.06% 3.15% 17.00% 20.41% 0.0114%

CAMPBELL SOUP CO CPB 14,070.74 0.06% 3.18% 4.46% 7.71% 0.0049%

SALESFORCE.COM INC CRM 67,140.95 0.30% 0.00% 28.05% 28.05% 0.0847%

CISCO SYSTEMS INC CSCO 166,534.28 0.75% 3.53% 6.43% 10.07% 0.0754%

CSRA INC CSRA 5,275.34 0.02% 1.24% 7.55% 8.84% 0.0021%

CSX CORP CSX 49,556.36 0.22% 1.44% 11.33% 12.85% 0.0286%

CINTAS CORP CTAS 15,587.98 0.07% 1.03% 11.58% 12.67% 0.0089%

CENTURYLINK INC CTL 10,387.62 0.05% 11.43% -2.86% 8.41% 0.0039%

COGNIZANT TECH SOLUTIONS-A CTSH 42,843.77 0.19% 0.69% 14.35% 15.09% 0.0291%

CITRIX SYSTEMS INC CTXS 11,639.10 0.05% 0.00% 13.10% 13.10% 0.0069%

CVS HEALTH CORP CVS 82,667.04 0.37% 2.50% 13.33% 15.99% 0.0595%

CHEVRON CORP CVX 222,662.82 1.00% 3.69% 42.57% 47.05% 0.4712%

CONCHO RESOURCES INC CXO 19,588.37 0.09% 0.00% 20.00% 20.00% 0.0176%

DOMINION ENERGY INC D 49,434.14 0.22% 3.93% 5.60% 9.64% 0.0214%

DELTA AIR LINES INC DAL 34,912.74 0.16% 2.09% 5.57% 7.71% 0.0121%

DEERE & CO DE 40,351.67 0.18% 1.91% 4.50% 6.46% 0.0117%

DISCOVER FINANCIAL SERVICES DFS 24,009.25 0.11% 1.99% 3.98% 6.00% 0.0065%

DOLLAR GENERAL CORP DG 22,147.64 0.10% 1.28% 8.55% 9.88% 0.0098%

QUEST DIAGNOSTICS INC DGX 12,773.01 0.06% 1.90% 6.95% 8.92% 0.0051%

DR HORTON INC DHI 14,945.12 0.07% 0.98% 12.66% 13.70% 0.0092%

DANAHER CORP DHR 59,590.50 0.27% 0.65% 7.57% 8.25% 0.0221%

WALT DISNEY CO/THE DIS 152,140.92 0.68% 1.65% 7.19% 8.90% 0.0609%

DISCOVERY COMMUNICATIONS-A DISCA 12,044.58 0.05% 0.00% 6.35% 6.35% 0.0034%

DISH NETWORK CORP-A DISH 25,277.28 0.11% 0.00% -7.33% -7.33% -0.0083%

DELPHI AUTOMOTIVE PLC DLPH 26,257.47 0.12% 1.20% 12.18% 13.45% 0.0159%

DIGITAL REALTY TRUST INC DLR 24,551.66 0.11% 3.10% 5.58% 8.77% 0.0097%

DOLLAR TREE INC DLTR 20,562.85 0.09% 0.00% 12.88% 12.88% 0.0119%

DOVER CORP DOV 14,232.56 0.06% 2.00% 15.47% 17.62% 0.0113%

DR PEPPER SNAPPLE GROUP INC DPS 16,077.19 0.07% 2.62% 8.58% 11.31% 0.0082%

DUKE REALTY CORP DRE 10,252.20 0.05% 5.37% 4.52% 10.01% 0.0046%

DARDEN RESTAURANTS INC DRI 9,875.18 0.04% 3.21% 9.57% 12.92% 0.0057%

DTE ENERGY COMPANY DTE 19,259.13 0.09% 3.10% 5.35% 8.53% 0.0074%

DUKE ENERGY CORP DUK 58,734.20 0.26% 4.20% 2.00% 6.24% 0.0165%

DAVITA INC DVA 11,355.37 0.05% 0.00% 3.75% 3.75% 0.0019%

DEVON ENERGY CORP DVN 19,291.66 0.09% 0.65% 18.42% 19.13% 0.0166%

DOWDUPONT INC DWDP 161,719.36 0.73% 2.45% 7.83% 10.37% 0.0754%

DXC TECHNOLOGY CO DXC 24,449.14 0.11% 0.82% 15.25% 16.13% 0.0177%

ELECTRONIC ARTS INC EA 36,448.39 0.16% 0.00% 14.17% 14.17% 0.0232%

EBAY INC EBAY 41,164.33 0.19% 0.00% 8.54% 8.54% 0.0158%

ECOLAB INC ECL 37,217.33 0.17% 1.17% 12.86% 14.10% 0.0236%

CONSOLIDATED EDISON INC ED 24,996.36 N/A 3.42% N/A N/A N/A

EQUIFAX INC EFX 12,758.28 0.06% 1.45% 11.03% 12.56% 0.0072%

EDISON INTERNATIONAL EIX 25,142.85 0.11% 2.84% 6.23% 9.16% 0.0104%

ESTEE LAUDER COMPANIES-CL A EL 39,742.79 0.18% 1.38% 11.49% 12.95% 0.0231%

EASTMAN CHEMICAL CO EMN 13,110.11 0.06% 2.27% 7.53% 9.89% 0.0058%

EMERSON ELECTRIC CO EMR 40,218.83 0.18% 3.06% 7.45% 10.63% 0.0192%

EOG RESOURCES INC EOG 55,862.33 0.25% 0.70% -18.26% -17.63% -0.0443%

EQUINIX INC EQIX 34,786.91 0.16% 1.79% 29.25% 31.30% 0.0490%

EQUITY RESIDENTIAL EQR 24,216.96 0.11% 3.06% 5.87% 9.02% 0.0098%

EQT CORP EQT 11,307.85 0.05% 0.18% 15.00% 15.20% 0.0077%

EVERSOURCE ENERGY ES 19,152.58 0.09% 3.15% 6.10% 9.34% 0.0080%

EXPRESS SCRIPTS HOLDING CO ESRX 36,570.40 0.16% 0.00% 13.28% 13.28% 0.0218%

ESSEX PROPERTY TRUST INC ESS 16,763.37 0.08% 2.75% 5.99% 8.82% 0.0067%

E*TRADE FINANCIAL CORP ETFC 11,980.10 0.05% 0.00% 15.37% 15.37% 0.0083%

Case No. PU-17-


Page 3 of 12 [4] [5] [6] [7] [8] [9]

Company Ticker

Market


Estimated

Dividend Yield

Long-Term


Weighted

DCF Result

EATON CORP PLC ETN 34,156.19 0.15% 3.12% 10.22% 13.50% 0.0207%

ENTERGY CORP ETR 13,708.15 0.06% 4.61% -3.83% 0.70% 0.0004%

ENVISION HEALTHCARE CORP EVHC 5,431.16 0.02% 0.00% 8.03% 8.03% 0.0020%

EDWARDS LIFESCIENCES CORP EW 23,081.68 0.10% 0.00% 16.60% 16.60% 0.0172%

EXELON CORP EXC 36,166.51 0.16% 3.49% 3.57% 7.12% 0.0116%

EXPEDITORS INTL WASH INC EXPD 10,818.98 0.05% 1.40% 8.40% 9.86% 0.0048%

EXPEDIA INC EXPE 21,826.57 0.10% 0.79% 17.98% 18.85% 0.0185%

EXTRA SPACE STORAGE INC EXR 10,069.93 0.05% 4.01% 6.57% 10.72% 0.0049%

FORD MOTOR CO F 47,541.91 0.21% 5.01% -2.07% 2.89% 0.0062%

FASTENAL CO FAST 13,126.05 0.06% 2.82% 15.40% 18.43% 0.0109%

FACEBOOK INC-A FB 496,199.68 2.23% 0.00% 26.79% 26.79% 0.5979%

FORTUNE BRANDS HOME & SECURI FBHS 10,354.15 0.05% 1.06% 12.12% 13.24% 0.0062%

FREEPORT-MCMORAN INC FCX 20,320.20 0.09% 0.00% 24.46% 24.46% 0.0224%

FEDEX CORP FDX 60,488.75 0.27% 0.90% 12.50% 13.45% 0.0366%

FIRSTENERGY CORP FE 13,697.91 N/A 4.67% N/A N/A N/A

F5 NETWORKS INC FFIV 7,661.18 0.03% 0.00% 11.85% 11.85% 0.0041%

FIDELITY NATIONAL INFO SERV FIS 31,044.04 0.14% 1.25% 8.23% 9.54% 0.0133%

FISERV INC FISV 27,141.64 0.12% 0.00% 10.80% 10.80% 0.0132%

FIFTH THIRD BANCORP FITB 20,613.59 0.09% 2.14% 4.20% 6.38% 0.0059%

FOOT LOCKER INC FL 4,367.19 0.02% 3.36% 3.40% 6.81% 0.0013%

FLIR SYSTEMS INC FLIR 5,338.28 N/A 1.44% N/A N/A N/A

FLUOR CORP FLR 5,889.74 0.03% 2.02% 11.89% 14.03% 0.0037%

FLOWSERVE CORP FLS 5,563.85 0.03% 1.80% 12.68% 14.59% 0.0037%

FMC CORP FMC 11,979.01 0.05% 0.75% 12.60% 13.40% 0.0072%

TWENTY-FIRST CENTURY FOX-A FOXA 48,359.78 0.22% 1.55% 9.23% 10.85% 0.0236%

FEDERAL REALTY INVS TRUST FRT 9,010.56 0.04% 3.20% 4.67% 7.94% 0.0032%

TECHNIPFMC PLC FTI 13,044.83 0.06% 0.91% 8.59% 9.54% 0.0056%

FORTIVE CORP FTV 24,571.32 0.11% 0.31% 9.37% 9.69% 0.0107%

GENERAL DYNAMICS CORP GD 61,563.36 0.28% 1.61% 8.51% 10.19% 0.0282%

GENERAL ELECTRIC CO GE 209,349.13 0.94% 3.97% 11.23% 15.43% 0.1453%

GGP INC GGP 18,319.21 0.08% 4.49% 4.65% 9.24% 0.0076%

GILEAD SCIENCES INC GILD 105,806.14 0.48% 2.64% -7.44% -4.90% -0.0233%

GENERAL MILLS INC GIS 29,417.20 0.13% 3.85% 9.57% 13.60% 0.0180%

CORNING INC GLW 27,023.25 0.12% 2.09% 8.58% 10.75% 0.0131%

GENERAL MOTORS CO GM 58,842.07 0.26% 3.78% 9.04% 13.00% 0.0344%

ALPHABET INC-CL A GOOGL 669,246.15 3.01% 0.00% 16.64% 16.64% 0.5008%

GENUINE PARTS CO GPC 14,044.38 0.06% 2.82% 8.92% 11.86% 0.0075%

GLOBAL PAYMENTS INC GPN 14,491.01 0.07% 0.05% 14.50% 14.55% 0.0095%

GAP INC/THE GPS 11,580.45 0.05% 3.11% 7.00% 10.21% 0.0053%

GARMIN LTD GRMN 10,130.33 0.05% 3.78% 5.68% 9.56% 0.0044%

GOLDMAN SACHS GROUP INC GS 95,563.85 0.43% 1.28% 11.19% 12.54% 0.0539%

GOODYEAR TIRE & RUBBER CO GT 8,371.14 N/A 1.20% N/A N/A N/A

WW GRAINGER INC GWW 10,369.90 0.05% 2.82% 9.55% 12.51% 0.0058%

HALLIBURTON CO HAL 40,119.54 0.18% 1.56% 74.00% 76.14% 0.1374%

HASBRO INC HAS 12,216.67 0.05% 2.33% 9.70% 12.15% 0.0067%

HUNTINGTON BANCSHARES INC HBAN 15,216.63 0.07% 2.49% 10.71% 13.34% 0.0091%

HANESBRANDS INC HBI 8,980.76 0.04% 2.44% 10.45% 13.01% 0.0053%

HCA HEALTHCARE INC HCA 28,751.86 0.13% 0.00% 12.07% 12.07% 0.0156%

WELLTOWER INC HCN 25,924.79 0.12% 4.96% 2.61% 7.64% 0.0089%

HCP INC HCP 13,051.24 0.06% 5.33% 3.11% 8.52% 0.0050%

HOME DEPOT INC HD 192,807.40 0.87% 2.18% 13.69% 16.02% 0.1389%

HESS CORP HES 14,903.69 0.07% 2.18% -14.74% -12.72% -0.0085%

HARTFORD FINANCIAL SVCS GRP HIG 20,193.16 0.09% 1.72% 9.50% 11.30% 0.0103%

HILTON WORLDWIDE HOLDINGS IN HLT 22,291.94 0.10% 0.86% 15.76% 16.69% 0.0167%

HARLEY-DAVIDSON INC HOG 8,224.37 0.04% 3.05% 7.85% 11.02% 0.0041%

HOLOGIC INC HOLX 10,290.57 0.05% 0.00% 9.18% 9.18% 0.0042%

HONEYWELL INTERNATIONAL INC HON 107,803.07 0.48% 1.91% 9.95% 11.95% 0.0580%

HELMERICH & PAYNE HP 5,658.18 N/A 5.37% N/A N/A N/A

HEWLETT PACKARD ENTERPRIS HPE 23,822.32 0.11% 1.77% -3.56% -1.82% -0.0020%

HP INC HPQ 33,338.28 0.15% 2.67% 4.09% 6.80% 0.0102%

H&R BLOCK INC HRB 5,535.91 0.02% 3.63% 11.00% 14.83% 0.0037%

HORMEL FOODS CORP HRL 16,964.40 0.08% 2.12% 6.15% 8.33% 0.0064%

HARRIS CORP HRS 15,684.35 N/A 1.70% N/A N/A N/A

HENRY SCHEIN INC HSIC 12,963.60 0.06% 0.00% 10.25% 10.25% 0.0060%

HOST HOTELS & RESORTS INC HST 13,683.56 0.06% 4.40% 4.10% 8.59% 0.0053%

HERSHEY CO/THE HSY 23,192.82 0.10% 2.34% 9.53% 11.98% 0.0125%

HUMANA INC HUM 35,208.73 0.16% 0.66% 12.93% 13.63% 0.0216%

INTL BUSINESS MACHINES CORP IBM 135,205.90 0.61% 4.04% 2.38% 6.46% 0.0393%

INTERCONTINENTAL EXCHANGE IN ICE 40,429.44 0.18% 1.20% 10.98% 12.24% 0.0223%

IDEXX LABORATORIES INC IDXX 13,570.52 0.06% 0.00% 10.81% 10.81% 0.0066%

INTL FLAVORS & FRAGRANCES IFF 11,286.42 0.05% 1.86% 4.00% 5.90% 0.0030%

ILLUMINA INC ILMN 29,083.20 0.13% 0.00% 15.48% 15.48% 0.0202%

INCYTE CORP INCY 24,591.25 0.11% 0.00% 44.05% 44.05% 0.0487%

IHS MARKIT LTD INFO 17,583.22 0.08% 0.00% 13.51% 13.51% 0.0107%

INTEL CORP INTC 178,937.92 0.80% 2.84% 8.14% 11.10% 0.0893%

INTUIT INC INTU 36,241.93 0.16% 1.08% 14.88% 16.04% 0.0262%

INTERNATIONAL PAPER CO IP 23,461.84 0.11% 3.25% 7.23% 10.59% 0.0112%

INTERPUBLIC GROUP OF COS INC IPG 8,176.06 0.04% 3.46% 8.64% 12.25% 0.0045%

INGERSOLL-RAND PLC IR 22,619.57 0.10% 1.89% 10.71% 12.70% 0.0129%

IRON MOUNTAIN INC IRM 10,284.80 N/A 5.44% N/A N/A N/A

INTUITIVE SURGICAL INC ISRG 38,994.39 0.18% 0.00% 10.05% 10.05% 0.0176%

GARTNER INC IT 11,271.22 0.05% 0.00% 17.50% 17.50% 0.0089%

ILLINOIS TOOL WORKS ITW 50,920.35 0.23% 1.85% 9.20% 11.14% 0.0255%

INVESCO LTD IVZ 14,257.49 0.06% 3.30% 12.29% 15.79% 0.0101%

HUNT (JB) TRANSPRT SVCS INC JBHT 12,156.09 0.05% 0.83% 13.35% 14.23% 0.0078%

JOHNSON CONTROLS INTERNATION JCI 37,566.35 0.17% 2.50% 8.47% 11.07% 0.0187%

JACOBS ENGINEERING GROUP INC JEC 7,010.76 0.03% 1.03% 8.73% 9.80% 0.0031%

JOHNSON & JOHNSON JNJ 348,946.80 1.57% 2.58% 6.03% 8.69% 0.1364%

JUNIPER NETWORKS INC JNPR 10,583.99 0.05% 1.51% 8.62% 10.19% 0.0049%

JPMORGAN CHASE & CO JPM 336,096.29 1.51% 2.22% 3.00% 5.25% 0.0794%

NORDSTROM INC JWN 7,838.20 0.04% 3.19% 6.00% 9.29% 0.0033%

Case No. PU-17-


Page 4 of 12 [4] [5] [6] [7] [8] [9]

Company Ticker

Market


Estimated

Dividend Yield

Long-Term


Weighted

DCF Result

KELLOGG CO K 21,526.05 0.10% 3.42% 6.23% 9.76% 0.0094%

KEYCORP KEY 20,467.60 0.09% 2.02% 10.90% 13.03% 0.0120%

KRAFT HEINZ CO/THE KHC 94,475.37 0.42% 3.17% 8.39% 11.69% 0.0497%

KIMCO REALTY CORP KIM 8,321.19 0.04% 5.58% 19.92% 26.06% 0.0098%

KLA-TENCOR CORP KLAC 16,631.09 0.07% 2.11% 7.90% 10.09% 0.0076%

KIMBERLY-CLARK CORP KMB 41,576.68 0.19% 3.27% 6.22% 9.59% 0.0179%

KINDER MORGAN INC KMI 42,833.30 0.19% 2.61% 20.00% 22.87% 0.0441%

CARMAX INC KMX 13,790.13 0.06% 0.00% 13.79% 13.79% 0.0086%

COCA-COLA CO/THE KO 191,981.34 0.86% 3.28% 5.61% 8.99% 0.0776%

MICHAEL KORS HOLDINGS LTD KORS 7,254.59 0.03% 0.00% 7.00% 7.00% 0.0023%

KROGER CO KR 17,843.81 0.08% 2.52% 5.57% 8.15% 0.0065%

KOHLS CORP KSS 7,695.67 0.03% 4.90% 5.45% 10.48% 0.0036%

KANSAS CITY SOUTHERN KSU 11,457.17 0.05% 1.30% 14.00% 15.40% 0.0079%

LOEWS CORP L 16,109.74 N/A 0.52% N/A N/A N/A

L BRANDS INC LB 11,810.85 0.05% 5.77% 6.81% 12.78% 0.0068%

LEGGETT & PLATT INC LEG 6,313.99 0.03% 2.95% 19.00% 22.23% 0.0063%

LENNAR CORP-A LEN 12,139.68 0.05% 0.30% 11.29% 11.61% 0.0063%

LABORATORY CRP OF AMER HLDGS LH 15,368.75 0.07% 0.00% 11.35% 11.35% 0.0078%

LKQ CORP LKQ 11,115.91 0.05% 0.00% 12.50% 12.50% 0.0063%

L3 TECHNOLOGIES INC LLL 14,738.63 0.07% 1.63% 6.90% 8.59% 0.0057%

ELI LILLY & CO LLY 94,178.59 0.42% 2.44% 8.50% 11.04% 0.0468%

LOCKHEED MARTIN CORP LMT 89,360.69 0.40% 2.38% 9.42% 11.91% 0.0479%

LINCOLN NATIONAL CORP LNC 16,277.85 0.07% 1.59% 9.25% 10.92% 0.0080%

ALLIANT ENERGY CORP LNT 9,605.26 0.04% 3.02% 5.50% 8.61% 0.0037%

LOWE'S COS INC LOW 66,575.01 0.30% 1.96% 14.38% 16.48% 0.0493%

LAM RESEARCH CORP LRCX 30,068.35 0.14% 0.97% 7.70% 8.71% 0.0118%

LEUCADIA NATIONAL CORP LUK 9,055.55 0.04% 1.43% 18.00% 19.55% 0.0080%

SOUTHWEST AIRLINES CO LUV 33,507.69 0.15% 0.88% 6.43% 7.34% 0.0111%

LEVEL 3 COMMUNICATIONS INC LVLT 19,327.85 0.09% 0.00% 5.00% 5.00% 0.0043%

LYONDELLBASELL INDU-CL A LYB 39,204.38 0.18% 3.58% 6.50% 10.20% 0.0180%

MACY'S INC M 6,645.48 0.03% 7.10% -0.48% 6.61% 0.0020%

MASTERCARD INC - A MA 150,363.50 0.68% 0.62% 16.63% 17.30% 0.1170%

MID-AMERICA APARTMENT COMM MAA 12,142.39 N/A 3.27% N/A N/A N/A

MACERICH CO/THE MAC 7,773.55 0.03% 5.51% 7.66% 13.38% 0.0047%

MARRIOTT INTERNATIONAL -CL A MAR 41,063.04 0.18% 1.15% 14.94% 16.18% 0.0299%

MASCO CORP MAS 12,428.34 0.06% 1.07% 14.33% 15.47% 0.0087%

MATTEL INC MAT 5,305.40 0.02% 5.36% 11.30% 16.96% 0.0040%

MCDONALD'S CORP MCD 126,910.27 0.57% 2.44% 10.09% 12.65% 0.0722%

MICROCHIP TECHNOLOGY INC MCHP 20,894.36 0.09% 1.61% 17.06% 18.80% 0.0177%

MCKESSON CORP MCK 32,298.12 0.15% 0.87% 5.30% 6.20% 0.0090%

MOODY'S CORP MCO 26,589.11 0.12% 1.10% 8.00% 9.14% 0.0109%

MONDELEZ INTERNATIONAL INC-A MDLZ 61,300.64 0.28% 1.95% 11.64% 13.71% 0.0378%

MEDTRONIC PLC MDT 105,346.58 0.47% 2.39% 6.43% 8.89% 0.0421%

METLIFE INC MET 55,121.71 0.25% 3.10% 35.90% 39.56% 0.0981%

MGM RESORTS INTERNATIONAL MGM 18,745.51 0.08% 1.35% 17.46% 18.93% 0.0160%

MOHAWK INDUSTRIES INC MHK 18,399.44 0.08% 0.00% 8.48% 8.48% 0.0070%

MCCORMICK & CO-NON VTG SHRS MKC 13,440.79 0.06% 1.82% 9.60% 11.51% 0.0070%

MARTIN MARIETTA MATERIALS MLM 12,959.43 0.06% 0.82% 21.24% 22.15% 0.0129%

MARSH & MCLENNAN COS MMC 42,954.71 0.19% 1.72% 12.86% 14.69% 0.0284%

3M CO MMM 125,261.42 0.56% 2.24% 8.80% 11.14% 0.0628%

MONSTER BEVERAGE CORP MNST 31,391.34 0.14% 0.00% 20.30% 20.30% 0.0287%

ALTRIA GROUP INC MO 121,675.56 0.55% 4.04% 0.61% 4.67% 0.0255%

MONSANTO CO MON 52,639.69 0.24% 1.80% 7.47% 9.34% 0.0221%

MOSAIC CO/THE MOS 7,579.16 0.03% 3.38% 11.70% 15.28% 0.0052%

MARATHON PETROLEUM CORP MPC 28,390.72 0.13% 2.73% 12.68% 15.58% 0.0199%

MERCK & CO. INC. MRK 174,632.50 0.79% 2.94% 6.07% 9.10% 0.0714%

MARATHON OIL CORP MRO 11,523.76 0.05% 1.47% 5.00% 6.51% 0.0034%

MORGAN STANLEY MS 88,468.09 0.40% 1.88% 16.72% 18.76% 0.0746%

MICROSOFT CORP MSFT 573,740.15 2.58% 2.24% 10.54% 12.90% 0.3330%

MOTOROLA SOLUTIONS INC MSI 13,804.41 0.06% 2.22% 4.10% 6.37% 0.0040%

M & T BANK CORP MTB 24,467.12 0.11% 1.87% 10.19% 12.16% 0.0134%

METTLER-TOLEDO INTERNATIONAL MTD 16,072.31 0.07% 0.00% 12.08% 12.08% 0.0087%

MICRON TECHNOLOGY INC MU 43,816.21 0.20% 0.32% 0.83% 1.15% 0.0023%

MYLAN NV MYL 16,823.13 0.08% 0.00% 3.20% 3.20% 0.0024%

NAVIENT CORP NAVI 4,117.05 N/A 4.34% N/A N/A N/A

NOBLE ENERGY INC NBL 13,798.42 0.06% 1.41% 3.72% 5.15% 0.0032%

NASDAQ INC NDAQ 12,938.39 0.06% 1.88% 9.08% 11.05% 0.0064%

NEXTERA ENERGY INC NEE 68,766.29 0.31% 2.68% 6.67% 9.44% 0.0292%

NEWMONT MINING CORP NEM 20,003.01 0.09% 0.72% -11.65% -10.97% -0.0099%

NETFLIX INC NFLX 78,297.82 0.35% 0.00% 40.60% 40.60% 0.1430%

NEWFIELD EXPLORATION CO NFX 5,913.80 0.03% 0.00% 12.19% 12.19% 0.0032%

NISOURCE INC NI 8,339.02 0.04% 2.74% 6.10% 8.92% 0.0033%

NIKE INC -CL B NKE 85,106.27 0.38% 1.48% 8.53% 10.07% 0.0386%

NIELSEN HOLDINGS PLC NLSN 14,780.13 0.07% 3.22% 10.00% 13.38% 0.0089%

NORTHROP GRUMMAN CORP NOC 50,090.41 0.23% 1.34% 7.67% 9.06% 0.0204%

NATIONAL OILWELL VARCO INC NOV 13,578.78 N/A 0.56% N/A N/A N/A

NRG ENERGY INC NRG 8,098.23 N/A 0.47% N/A N/A N/A

NORFOLK SOUTHERN CORP NSC 38,109.17 0.17% 1.85% 13.57% 15.54% 0.0266%

NETAPP INC NTAP 11,804.59 0.05% 1.84% 9.90% 11.83% 0.0063%

NORTHERN TRUST CORP NTRS 21,004.71 0.09% 1.74% 12.14% 13.99% 0.0132%

NUCOR CORP NUE 17,900.63 0.08% 2.69% 12.00% 14.85% 0.0120%

NVIDIA CORP NVDA 107,262.00 0.48% 0.32% 12.52% 12.86% 0.0621%

NEWELL BRANDS INC NWL 20,912.57 0.09% 2.06% 11.32% 13.50% 0.0127%

NEWS CORP - CLASS A NWSA 7,794.32 0.04% 1.65% 12.59% 14.35% 0.0050%

REALTY INCOME CORP O 15,674.36 0.07% 4.44% 4.42% 8.96% 0.0063%

ONEOK INC OKE 21,056.26 0.09% 5.15% 13.25% 18.74% 0.0178%

OMNICOM GROUP OMC 17,091.96 0.08% 3.04% 4.95% 8.06% 0.0062%

ORACLE CORP ORCL 201,767.11 0.91% 1.46% 8.77% 10.29% 0.0934%

O'REILLY AUTOMOTIVE INC ORLY 18,956.15 0.09% 0.00% 15.32% 15.32% 0.0131%

OCCIDENTAL PETROLEUM CORP OXY 49,093.24 0.22% 4.78% -3.39% 1.31% 0.0029%

PAYCHEX INC PAYX 21,503.37 0.10% 3.27% 7.70% 11.10% 0.0107%

Case No. PU-17-


Page 5 of 12 [4] [5] [6] [7] [8] [9]

Company Ticker

Market


Estimated

Dividend Yield

Long-Term


Weighted

DCF Result

PEOPLE'S UNITED FINANCIAL PBCT 6,250.49 0.03% 3.80% 2.00% 5.84% 0.0016%

PACCAR INC PCAR 25,418.57 0.11% 2.47% 6.73% 9.28% 0.0106%

P G & E CORP PCG 34,918.03 N/A 3.04% N/A N/A N/A

PRICELINE GROUP INC/THE PCLN 89,818.23 0.40% 0.00% 17.26% 17.26% 0.0697%

PATTERSON COS INC PDCO 3,698.92 0.02% 2.80% 10.63% 13.58% 0.0023%

PUBLIC SERVICE ENTERPRISE GP PEG 23,397.41 0.11% 3.72% 2.90% 6.67% 0.0070%

PEPSICO INC PEP 158,844.63 0.71% 2.85% 6.06% 8.99% 0.0642%

PFIZER INC PFE 212,320.36 0.96% 3.57% 8.43% 12.15% 0.1161%

PRINCIPAL FINANCIAL GROUP PFG 18,591.73 0.08% 2.87% 10.40% 13.42% 0.0112%

PROCTER & GAMBLE CO/THE PG 232,000.29 1.04% 3.10% 7.18% 10.39% 0.1084%

PROGRESSIVE CORP PGR 28,134.36 0.13% 1.70% 11.83% 13.63% 0.0173%

PARKER HANNIFIN CORP PH 23,312.67 0.10% 1.55% 11.88% 13.52% 0.0142%

PULTEGROUP INC PHM 8,245.70 0.04% 1.20% 18.40% 19.71% 0.0073%

PACKAGING CORP OF AMERICA PKG 10,820.23 0.05% 2.15% 8.25% 10.49% 0.0051%

PERKINELMER INC PKI 7,601.50 0.03% 0.41% 10.42% 10.85% 0.0037%

PROLOGIS INC PLD 33,605.86 0.15% 2.75% 6.21% 9.04% 0.0137%

PHILIP MORRIS INTERNATIONAL PM 172,419.41 0.78% 3.81% 9.61% 13.60% 0.1055%

PNC FINANCIAL SERVICES GROUP PNC 64,582.67 0.29% 1.93% 10.12% 12.14% 0.0353%

PENTAIR PLC PNR 12,333.32 0.06% 2.05% 8.04% 10.18% 0.0056%

PINNACLE WEST CAPITAL PNW 9,438.97 0.04% 3.14% 5.50% 8.73% 0.0037%

PPG INDUSTRIES INC PPG 27,869.09 0.13% 1.56% 8.09% 9.71% 0.0122%

PPL CORP PPL 25,836.03 N/A 4.16% N/A N/A N/A

PERRIGO CO PLC PRGO 12,072.03 0.05% 0.75% 5.97% 6.74% 0.0037%

PRUDENTIAL FINANCIAL INC PRU 45,398.64 0.20% 2.86% 8.00% 10.97% 0.0224%

PUBLIC STORAGE PSA 37,234.85 0.17% 3.77% 5.54% 9.40% 0.0158%

PHILLIPS 66 PSX 46,859.50 0.21% 2.99% -3.74% -0.81% -0.0017%

PVH CORP PVH 9,760.12 0.04% 0.15% 10.96% 11.11% 0.0049%

QUANTA SERVICES INC PWR 5,798.71 0.03% 0.00% 8.00% 8.00% 0.0021%

PRAXAIR INC PX 39,974.74 0.18% 2.27% 10.35% 12.74% 0.0229%

PIONEER NATURAL RESOURCES CO PXD 25,096.19 0.11% 0.05% 20.00% 20.06% 0.0226%

PAYPAL HOLDINGS INC PYPL 76,989.48 0.35% 0.00% 19.83% 19.83% 0.0687%

QUINTILES IMS HOLDINGS INC Q 20,585.20 0.09% 0.00% 14.33% 14.33% 0.0133%

QUALCOMM INC QCOM 76,519.30 0.34% 4.23% 8.75% 13.16% 0.0453%

QORVO INC QRVO 8,995.28 0.04% 0.00% 13.18% 13.18% 0.0053%

ROYAL CARIBBEAN CRUISES LTD RCL 25,499.26 0.11% 1.68% 19.10% 20.94% 0.0240%

EVEREST RE GROUP LTD RE 9,378.55 0.04% 2.23% 10.00% 12.34% 0.0052%

REGENCY CENTERS CORP REG 10,563.56 0.05% 3.40% 9.26% 12.82% 0.0061%

REGENERON PHARMACEUTICALS REGN 47,909.90 0.22% 0.00% 18.00% 18.00% 0.0388%

REGIONS FINANCIAL CORP RF 18,201.07 0.08% 2.08% 13.86% 16.09% 0.0132%

ROBERT HALF INTL INC RHI 6,352.12 0.03% 1.90% 8.30% 10.28% 0.0029%

RED HAT INC RHT 19,673.18 0.09% 0.00% 17.00% 17.00% 0.0150%

RAYMOND JAMES FINANCIAL INC RJF 12,159.34 0.05% 1.03% 15.45% 16.56% 0.0091%

RALPH LAUREN CORP RL 7,174.67 0.03% 2.34% 0.29% 2.63% 0.0009%

RESMED INC RMD 10,951.44 0.05% 1.86% 11.56% 13.52% 0.0067%

ROCKWELL AUTOMATION INC ROK 22,874.89 0.10% 1.73% 11.84% 13.67% 0.0141%

ROPER TECHNOLOGIES INC ROP 24,880.27 0.11% 0.57% 12.93% 13.54% 0.0152%

ROSS STORES INC ROST 24,897.68 0.11% 0.97% 13.60% 14.64% 0.0164%

RANGE RESOURCES CORP RRC 4,855.95 0.02% 0.41% -19.59% -19.22% -0.0042%

REPUBLIC SERVICES INC RSG 22,246.52 0.10% 2.02% 11.46% 13.60% 0.0136%

RAYTHEON COMPANY RTN 54,154.66 0.24% 1.70% 8.41% 10.18% 0.0248%

SBA COMMUNICATIONS CORP SBAC 17,337.53 0.08% 0.00% 23.05% 23.05% 0.0180%

STARBUCKS CORP SBUX 77,551.87 0.35% 1.89% 16.52% 18.57% 0.0648%

SCANA CORP SCG 6,930.04 0.03% 5.05% 3.23% 8.37% 0.0026%

SCHWAB (CHARLES) CORP SCHW 58,573.09 0.26% 0.73% 19.46% 20.25% 0.0534%

SEALED AIR CORP SEE 8,118.14 0.04% 1.50% 8.12% 9.67% 0.0035%

SHERWIN-WILLIAMS CO/THE SHW 33,444.58 0.15% 0.95% 10.99% 11.99% 0.0180%

SIGNET JEWELERS LTD SIG 4,023.66 0.02% 1.84% 3.40% 5.27% 0.0010%

JM SMUCKER CO/THE SJM 11,918.43 0.05% 3.00% 3.96% 7.02% 0.0038%

SCHLUMBERGER LTD SLB 96,584.41 0.43% 2.88% 41.71% 45.19% 0.1963%

SL GREEN REALTY CORP SLG 10,179.18 0.05% 3.08% 0.64% 3.73% 0.0017%

SNAP-ON INC SNA 8,580.66 0.04% 2.30% 10.85% 13.27% 0.0051%

SCRIPPS NETWORKS INTER-CL A SNI 11,149.62 0.05% 1.37% 8.53% 9.95% 0.0050%

SYNOPSYS INC SNPS 12,099.44 0.05% 0.00% 9.12% 9.12% 0.0050%

SOUTHERN CO/THE SO 49,114.15 0.22% 4.70% 2.00% 6.75% 0.0149%

SIMON PROPERTY GROUP INC SPG 50,048.80 0.23% 4.41% 7.06% 11.62% 0.0262%

S&P GLOBAL INC SPGI 40,171.67 0.18% 1.05% 10.00% 11.10% 0.0201%

STERICYCLE INC SRCL 6,111.96 0.03% 0.15% 7.68% 7.83% 0.0022%

SEMPRA ENERGY SRE 28,655.49 0.13% 2.88% 14.25% 17.33% 0.0223%

SUNTRUST BANKS INC STI 28,685.77 0.13% 2.22% 9.42% 11.74% 0.0152%

STATE STREET CORP STT 35,727.70 0.16% 1.67% 11.80% 13.57% 0.0218%

SEAGATE TECHNOLOGY STX 9,547.33 0.04% 7.72% 8.73% 16.79% 0.0072%

CONSTELLATION BRANDS INC-A STZ 38,922.45 0.18% 1.05% 16.36% 17.50% 0.0306%

STANLEY BLACK & DECKER INC SWK 23,121.43 0.10% 1.59% 11.00% 12.68% 0.0132%

SKYWORKS SOLUTIONS INC SWKS 18,723.12 0.08% 1.14% 13.59% 14.81% 0.0125%

SYNCHRONY FINANCIAL SYF 24,695.16 0.11% 1.80% 8.09% 9.97% 0.0111%

STRYKER CORP SYK 53,124.47 0.24% 1.21% 9.23% 10.49% 0.0251%

SYMANTEC CORP SYMC 20,163.06 0.09% 0.94% 13.14% 14.14% 0.0128%

SYSCO CORP SYY 28,479.22 0.13% 2.52% 10.04% 12.69% 0.0163%

AT&T INC T 240,503.80 1.08% 5.03% 5.25% 10.41% 0.1126%

MOLSON COORS BREWING CO -B TAP 17,603.51 0.08% 2.03% 7.32% 9.42% 0.0075%

TRANSDIGM GROUP INC TDG 13,270.93 0.06% 0.00% 10.21% 10.21% 0.0061%

TE CONNECTIVITY LTD TEL 29,352.08 0.13% 1.84% 6.87% 8.77% 0.0116%

TARGET CORP TGT 32,233.14 0.14% 4.20% -0.78% 3.41% 0.0049%

TIFFANY & CO TIF 11,427.73 0.05% 2.07% 10.10% 12.28% 0.0063%

TJX COMPANIES INC TJX 46,912.50 0.21% 1.65% 12.52% 14.28% 0.0301%

TORCHMARK CORP TMK 9,316.09 0.04% 0.74% 8.00% 8.77% 0.0037%

THERMO FISHER SCIENTIFIC INC TMO 75,719.21 0.34% 0.32% 13.00% 13.34% 0.0454%

TRIPADVISOR INC TRIP 5,623.65 0.03% 0.00% 14.50% 14.50% 0.0037%

T ROWE PRICE GROUP INC TROW 21,788.45 0.10% 2.52% 12.85% 15.53% 0.0152%

TRAVELERS COS INC/THE TRV 33,809.03 0.15% 2.30% 11.58% 14.01% 0.0213%

TRACTOR SUPPLY COMPANY TSCO 8,018.59 0.04% 1.65% 13.65% 15.41% 0.0056%

Case No. PU-17-


Page 6 of 12 [4] [5] [6] [7] [8] [9]

Company Ticker

Market


Estimated

Dividend Yield

Long-Term


Weighted

DCF Result

TYSON FOODS INC-CL A TSN 27,558.49 0.12% 1.26% 8.60% 9.92% 0.0123%

TOTAL SYSTEM SERVICES INC TSS 12,067.59 0.05% 0.69% 11.14% 11.87% 0.0064%

TIME WARNER INC TWX 79,685.75 0.36% 1.67% 8.30% 10.04% 0.0360%

TEXAS INSTRUMENTS INC TXN 88,747.06 0.40% 2.27% 10.53% 12.92% 0.0516%

TEXTRON INC TXT 14,262.78 0.06% 0.16% 8.78% 8.95% 0.0057%

UNDER ARMOUR INC-CLASS A UAA 6,918.82 0.03% 0.00% 13.17% 13.17% 0.0041%

UNITED CONTINENTAL HOLDINGS UAL 18,521.24 0.08% 0.00% -0.23% -0.23% -0.0002%

UDR INC UDR 10,175.81 0.05% 3.26% 6.13% 9.48% 0.0043%

UNIVERSAL HEALTH SERVICES-B UHS 10,612.22 0.05% 0.23% 8.69% 8.93% 0.0043%

ULTA BEAUTY INC ULTA 13,887.00 0.06% 0.00% 21.60% 21.60% 0.0135%

UNITEDHEALTH GROUP INC UNH 189,359.52 0.85% 1.47% 12.15% 13.71% 0.1168%

UNUM GROUP UNM 11,539.15 0.05% 1.68% 5.00% 6.72% 0.0035%

UNION PACIFIC CORP UNP 92,820.64 0.42% 2.14% 11.63% 13.90% 0.0580%

UNITED PARCEL SERVICE-CL B UPS 103,994.12 0.47% 2.76% 11.90% 14.83% 0.0694%

UNITED RENTALS INC URI 11,729.09 0.05% 0.00% 14.17% 14.17% 0.0075%

US BANCORP USB 89,643.75 0.40% 2.16% 12.13% 14.43% 0.0582%

UNITED TECHNOLOGIES CORP UTX 92,721.54 0.42% 2.36% 8.72% 11.19% 0.0467%

VISA INC-CLASS A SHARES V 240,659.19 1.08% 0.63% 16.76% 17.44% 0.1888%

VARIAN MEDICAL SYSTEMS INC VAR 9,185.60 0.04% 0.00% 7.20% 7.20% 0.0030%

VF CORP VFC 25,022.51 0.11% 2.69% 7.96% 10.75% 0.0121%

VIACOM INC-CLASS B VIAB 11,633.81 0.05% 2.88% 2.96% 5.88% 0.0031%

VALERO ENERGY CORP VLO 33,977.21 0.15% 3.64% 10.45% 14.28% 0.0218%

VULCAN MATERIALS CO VMC 15,820.09 0.07% 0.84% 21.82% 22.75% 0.0162%

VORNADO REALTY TRUST VNO 14,566.07 0.07% 3.31% -0.83% 2.46% 0.0016%

VERISK ANALYTICS INC VRSK 13,689.40 0.06% 0.00% 7.96% 7.96% 0.0049%

VERISIGN INC VRSN 10,630.56 0.05% 0.00% 10.20% 10.20% 0.0049%

VERTEX PHARMACEUTICALS INC VRTX 38,332.15 0.17% 0.00% 72.50% 72.50% 0.1250%

VENTAS INC VTR 23,196.06 0.10% 4.80% 3.03% 7.91% 0.0083%

VERIZON COMMUNICATIONS INC VZ 201,889.90 0.91% 4.72% 1.92% 6.69% 0.0607%

WATERS CORP WAT 14,329.93 0.06% 0.00% 8.28% 8.28% 0.0053%

WALGREENS BOOTS ALLIANCE INC WBA 82,632.85 0.37% 1.95% 9.03% 11.07% 0.0411%

WESTERN DIGITAL CORP WDC 25,503.39 0.11% 2.33% 11.74% 14.21% 0.0163%

WEC ENERGY GROUP INC WEC 19,811.90 0.09% 3.31% 5.55% 8.96% 0.0080%

WELLS FARGO & CO WFC 273,761.55 1.23% 2.79% 11.46% 14.41% 0.1774%

WHIRLPOOL CORP WHR 13,460.33 0.06% 2.29% 14.19% 16.65% 0.0101%

WILLIS TOWERS WATSON PLC WLTW 20,711.37 0.09% 1.36% 10.00% 11.43% 0.0107%

WASTE MANAGEMENT INC WM 34,441.60 0.15% 2.17% 10.22% 12.50% 0.0194%

WILLIAMS COS INC WMB 24,807.79 N/A 4.00% N/A N/A N/A

WAL-MART STORES INC WMT 233,419.94 1.05% 2.62% 5.12% 7.81% 0.0820%

WESTROCK CO WRK 14,409.45 0.06% 2.83% 9.67% 12.63% 0.0082%

WESTERN UNION CO WU 8,908.70 0.04% 3.65% 8.00% 11.79% 0.0047%

WEYERHAEUSER CO WY 25,622.57 0.12% 3.66% 7.40% 11.20% 0.0129%

WYNDHAM WORLDWIDE CORP WYN 10,834.65 0.05% 2.22% 14.25% 16.63% 0.0081%

WYNN RESORTS LTD WYNN 15,274.14 0.07% 1.37% 31.90% 33.48% 0.0230%

CIMAREX ENERGY CO XEC 10,830.25 0.05% 0.28% 63.66% 64.03% 0.0312%

XCEL ENERGY INC XEL 24,027.34 0.11% 3.04% 6.05% 9.19% 0.0099%

XL GROUP LTD XL 10,175.89 0.05% 2.12% 9.00% 11.22% 0.0051%

XILINX INC XLNX 17,608.45 0.08% 1.99% 8.37% 10.44% 0.0083%

EXXON MOBIL CORP XOM 347,357.94 1.56% 3.73% 19.49% 23.59% 0.3685%

DENTSPLY SIRONA INC XRAY 13,726.51 0.06% 0.58% 9.80% 10.40% 0.0064%

XEROX CORP XRX 8,461.31 0.04% 3.06% 2.90% 6.00% 0.0023%

XYLEM INC XYL 11,246.37 0.05% 1.15% 15.00% 16.24% 0.0082%

YUM! BRANDS INC YUM 25,378.76 0.11% 1.75% 12.74% 14.60% 0.0167%

ZIMMER BIOMET HOLDINGS INC ZBH 23,675.12 0.11% 0.82% 8.38% 9.23% 0.0098%

ZIONS BANCORPORATION ZION 9,538.48 0.04% 0.93% 9.00% 9.97% 0.0043%

ZOETIS INC ZTS 31,185.76 0.14% 0.66% 14.75% 15.46% 0.0217%

Total Market Capitalization: 22,230,344 13.83%

Notes:

[1] Equals sum of Col. [9]


[3] Equals [1] − [2]


[5] Equals weight in S&P 500 based on market capitalization



[8] Equals ([6] x (1 + (0.5 x [7]))) + [7]

[9] Equals Col. [5] x Col. [8]

Case No. PU-17-


Page 7 of 12

Ex-Ante Market Risk Premium

Market DCF Method Based - Value Line

[1] [2] [3]

S&P 500

Est. Required

Market Return

Current 30-Year

Treasury (30-day

average)

Implied Market

Risk Premium

14.33% 2.77% 11.56%

[4] [5] [6] [7] [8] [9]

Company Ticker

Market


Estimated

Dividend Yield

Long-Term


Weighted

DCF Result

AGILENT TECHNOLOGIES INC A 21,226.24 0.10% 0.80% 7.00% 7.83% 0.0082%

AMERICAN AIRLINES GROUP INC AAL 22,573.87 0.11% 0.86% 1.50% 2.37% 0.0026%

ADVANCE AUTO PARTS INC AAP 6,919.49 0.03% 0.26% 9.50% 9.77% 0.0033%

APPLE INC AAPL 792,992.90 3.92% 1.72% 11.00% 12.81% 0.5024%

ABBVIE INC ABBV 139,307.20 0.69% 2.93% 11.50% 14.60% 0.1005%

AMERISOURCEBERGEN CORP ABC 17,606.12 0.09% 1.82% 8.00% 9.89% 0.0086%

ABBOTT LABORATORIES ABT 89,356.70 0.44% 2.06% 8.50% 10.65% 0.0470%

ACCENTURE PLC-CL A ACN 87,285.16 0.43% 1.95% 9.00% 11.04% 0.0476%

ADOBE SYSTEMS INC ADBE 73,653.27 0.36% 0.00% 29.50% 29.50% 0.1074%

ANALOG DEVICES INC ADI 30,972.35 0.15% 2.14% 16.00% 18.31% 0.0280%

ARCHER-DANIELS-MIDLAND CO ADM 24,372.27 0.12% 2.96% 4.00% 7.02% 0.0085%

AUTOMATIC DATA PROCESSING ADP 47,831.24 0.24% 2.25% 9.00% 11.35% 0.0268%

ALLIANCE DATA SYSTEMS CORP ADS 11,977.46 0.06% 0.96% 11.00% 12.01% 0.0071%

AUTODESK INC ADSK 24,613.07 N/A 0.00% N/A N/A N/A

AMEREN CORPORATION AEE 14,267.30 0.07% 3.10% 6.00% 9.19% 0.0065%

AMERICAN ELECTRIC POWER AEP 35,141.75 0.17% 3.47% 4.00% 7.54% 0.0131%

AES CORP AES 7,347.94 N/A 4.31% N/A N/A N/A

AETNA INC AET 50,940.82 0.25% 1.30% 9.00% 10.36% 0.0261%

AFLAC INC AFL 33,117.40 0.16% 2.13% 4.00% 6.17% 0.0101%

ALLERGAN PLC AGN 67,708.70 0.33% 1.38% 10.00% 11.45% 0.0383%

AMERICAN INTERNATIONAL GROUP AIG 54,655.28 0.27% 2.12% 27.00% 29.41% 0.0795%

APARTMENT INVT & MGMT CO -A AIV - N/A 3.21% N/A N/A N/A

ASSURANT INC AIZ 5,060.48 0.03% 2.27% 4.00% 6.32% 0.0016%

ARTHUR J GALLAGHER & CO AJG 10,932.73 0.05% 2.57% 15.50% 18.27% 0.0099%

AKAMAI TECHNOLOGIES INC AKAM 8,174.72 0.04% 0.00% 12.50% 12.50% 0.0051%

ALBEMARLE CORP ALB 14,890.64 0.07% 0.95% 9.50% 10.50% 0.0077%

ALIGN TECHNOLOGY INC ALGN 14,932.43 0.07% 0.00% 21.50% 21.50% 0.0159%

ALASKA AIR GROUP INC ALK 9,005.92 0.04% 1.65% 10.00% 11.73% 0.0052%

ALLSTATE CORP ALL 32,731.87 0.16% 1.63% 7.50% 9.19% 0.0149%

ALLEGION PLC ALLE 7,927.98 0.04% 0.77% 10.00% 10.81% 0.0042%

ALEXION PHARMACEUTICALS INC ALXN 32,014.08 0.16% 0.00% 23.50% 23.50% 0.0372%

APPLIED MATERIALS INC AMAT 50,261.90 0.25% 0.98% 21.00% 22.08% 0.0549%

ADVANCED MICRO DEVICES AMD 12,699.27 N/A 0.00% N/A N/A N/A

AMETEK INC AME 15,257.86 0.08% 0.55% 5.50% 6.07% 0.0046%

AFFILIATED MANAGERS GROUP AMG 10,774.53 0.05% 0.43% 7.00% 7.45% 0.0040%

AMGEN INC AMGN 136,377.90 0.67% 2.63% 8.00% 10.74% 0.0724%

AMERIPRISE FINANCIAL INC AMP 21,361.91 0.11% 2.34% 11.50% 13.97% 0.0148%

AMERICAN TOWER CORP AMT 59,826.99 0.30% 2.04% 10.50% 12.65% 0.0374%

AMAZON.COM INC AMZN 463,032.00 2.29% 0.00% 56.00% 56.00% 1.2819%

ANDEAVOR ANDV 16,459.91 0.08% 2.27% 5.50% 7.83% 0.0064%

ANSYS INC ANSS 10,235.03 0.05% 0.00% 7.00% 7.00% 0.0035%

ANTHEM INC ANTM 48,278.12 0.24% 1.53% 11.00% 12.61% 0.0301%

AON PLC AON 37,061.16 0.18% 0.99% 9.50% 10.54% 0.0193%

SMITH (A.O.) CORP AOS 10,179.80 0.05% 0.95% 11.50% 12.50% 0.0063%

APACHE CORP APA 16,517.04 0.08% 2.31% 23.00% 25.58% 0.0209%

ANADARKO PETROLEUM CORP APC 26,790.72 N/A 0.41% N/A N/A N/A

AIR PRODUCTS & CHEMICALS INC APD 32,922.40 0.16% 2.52% 9.00% 11.63% 0.0189%

AMPHENOL CORP-CL A APH 25,394.70 0.13% 0.91% 8.50% 9.45% 0.0119%

ALEXANDRIA REAL ESTATE EQUIT ARE N/A N/A 0.00% N/A N/A N/A

ARCONIC INC ARNC 11,815.22 N/A 0.90% N/A N/A N/A

ACTIVISION BLIZZARD INC ATVI 48,391.51 0.24% 0.47% 9.00% 9.49% 0.0227%

AVALONBAY COMMUNITIES INC AVB - N/A 3.32% N/A N/A N/A

BROADCOM LTD AVGO 97,967.59 0.48% 1.70% 44.00% 46.07% 0.2231%

AVERY DENNISON CORP AVY 8,734.70 0.04% 1.90% 8.50% 10.48% 0.0045%

AMERICAN WATER WORKS CO INC AWK 14,581.44 0.07% 2.08% 8.50% 10.67% 0.0077%

AMERICAN EXPRESS CO AXP 78,251.70 0.39% 1.45% 6.00% 7.49% 0.0290%

ACUITY BRANDS INC AYI 6,754.94 0.03% 0.32% 16.50% 16.85% 0.0056%

AUTOZONE INC AZO 15,583.51 0.08% 0.00% 11.50% 11.50% 0.0089%

BOEING CO/THE BA 151,882.70 0.75% 2.46% 11.00% 13.60% 0.1021%

BANK OF AMERICA CORP BAC 248,533.50 1.23% 1.91% 16.00% 18.06% 0.2219%

BAXTER INTERNATIONAL INC BAX 34,515.54 0.17% 1.01% 4.00% 5.03% 0.0086%

BB&T CORP BBT 36,558.13 0.18% 2.92% 5.50% 8.50% 0.0154%

BEST BUY CO INC BBY 16,185.00 0.08% 2.52% 8.00% 10.62% 0.0085%

CR BARD INC BCR 23,063.91 0.11% 0.34% 9.50% 9.86% 0.0112%

BECTON DICKINSON AND CO BDX 43,592.35 0.22% 1.61% 9.00% 10.68% 0.0230%

FRANKLIN RESOURCES INC BEN 23,757.94 0.12% 2.02% 5.00% 7.07% 0.0083%

BROWN-FORMAN CORP-CLASS B BF/B 20,746.79 0.10% 1.37% 9.00% 10.43% 0.0107%

BRIGHTHOUSE FINANCIAL INC BHF N/A N/A 0.00% N/A N/A N/A

BAKER HUGHES A GE CO BHGE N/A N/A 0.00% N/A N/A N/A

BIOGEN INC BIIB 66,607.43 0.33% 0.00% 7.00% 7.00% 0.0231%

BANK OF NEW YORK MELLON CORP BK 54,158.04 0.27% 1.83% 8.50% 10.41% 0.0279%

BLACKROCK INC BLK 69,874.27 0.35% 2.31% 8.50% 10.91% 0.0377%

BALL CORP BLL 14,286.08 0.07% 0.98% 15.00% 16.05% 0.0113%

BRISTOL-MYERS SQUIBB CO BMY 103,856.50 0.51% 2.46% 14.50% 17.14% 0.0880%

BERKSHIRE HATHAWAY INC-CL B BRK/B - N/A 0.00% N/A N/A N/A

BOSTON SCIENTIFIC CORP BSX 39,414.57 0.19% 0.00% 18.50% 18.50% 0.0360%

BORGWARNER INC BWA 10,466.56 0.05% 1.13% 8.00% 9.18% 0.0047%

BOSTON PROPERTIES INC BXP - N/A 2.44% N/A N/A N/A

CITIGROUP INC C 195,514.10 0.97% 1.78% 11.00% 12.88% 0.1245%

CA INC CA 13,470.82 0.07% 3.21% 7.00% 10.32% 0.0069%

Case No. PU-17-


Page 8 of 12[4] [5] [6] [7] [8] [9]

Company Ticker

Market


Estimated

Dividend Yield

Long-Term


Weighted

DCF Result

CONAGRA BRANDS INC CAG 14,220.28 0.07% 2.39% 1.00% 3.40% 0.0024%

CARDINAL HEALTH INC CAH 21,099.32 0.10% 2.82% 13.00% 16.00% 0.0167%

CATERPILLAR INC CAT 73,747.52 0.36% 2.50% 10.00% 12.63% 0.0460%

CHUBB LTD CB 66,525.36 0.33% 1.99% 8.00% 10.07% 0.0331%

CBRE GROUP INC - A CBG 12,567.62 0.06% 0.00% 8.50% 8.50% 0.0053%

CBOE HOLDINGS INC CBOE 11,983.68 0.06% 1.02% 12.50% 13.58% 0.0080%

CBS CORP-CLASS B NON VOTING CBS 23,692.37 0.12% 1.23% 12.00% 13.30% 0.0156%

CROWN CASTLE INTL CORP CCI 37,197.39 0.18% 4.02% 6.00% 10.14% 0.0186%

CARNIVAL CORP CCL 46,661.80 0.23% 2.48% 12.50% 15.14% 0.0349%

CADENCE DESIGN SYS INC CDNS 10,768.13 0.05% 0.00% 10.00% 10.00% 0.0053%

CELGENE CORP CELG 112,450.30 0.56% 0.00% 25.00% 25.00% 0.1390%

CERNER CORP CERN 23,036.23 0.11% 0.00% 9.50% 9.50% 0.0108%

CF INDUSTRIES HOLDINGS INC CF 8,387.02 0.04% 3.48% 10.00% 13.65% 0.0057%

CITIZENS FINANCIAL GROUP CFG 20,479.16 0.10% 1.99% 10.50% 12.59% 0.0128%

CHURCH & DWIGHT CO INC CHD 12,087.78 0.06% 1.57% 7.00% 8.62% 0.0052%

CHESAPEAKE ENERGY CORP CHK 3,776.52 N/A 0.00% N/A N/A N/A

C.H. ROBINSON WORLDWIDE INC CHRW 10,269.57 0.05% 2.47% 6.00% 8.54% 0.0043%

CHARTER COMMUNICATIONS INC-A CHTR 93,116.76 0.46% 0.00% 26.00% 26.00% 0.1197%

CIGNA CORP CI 45,856.33 0.23% 0.02% 12.00% 12.02% 0.0273%

CINCINNATI FINANCIAL CORP CINF 12,387.56 0.06% 2.65% 6.50% 9.24% 0.0057%

COLGATE-PALMOLIVE CO CL 62,865.69 0.31% 2.24% 11.00% 13.36% 0.0415%

CLOROX COMPANY CLX 16,943.41 0.08% 2.56% 7.50% 10.16% 0.0085%

COMERICA INC CMA 12,899.70 0.06% 1.64% 13.50% 15.25% 0.0097%

COMCAST CORP-CLASS A CMCSA 176,610.10 0.87% 1.68% 11.00% 12.77% 0.1115%

CME GROUP INC CME 45,314.84 0.22% 1.97% 8.50% 10.55% 0.0236%

CHIPOTLE MEXICAN GRILL INC CMG 8,953.39 0.04% 0.00% 15.50% 15.50% 0.0069%

CUMMINS INC CMI 27,902.05 0.14% 2.60% 7.50% 10.20% 0.0141%

CMS ENERGY CORP CMS 13,252.09 0.07% 2.98% 6.50% 9.58% 0.0063%

CENTENE CORP CNC 15,649.66 0.08% 0.00% 14.00% 14.00% 0.0108%

CENTERPOINT ENERGY INC CNP 12,710.81 0.06% 3.73% 6.00% 9.84% 0.0062%

CAPITAL ONE FINANCIAL CORP COF 39,459.68 0.20% 1.96% 4.00% 6.00% 0.0117%

CABOT OIL & GAS CORP COG 12,214.44 N/A 0.76% N/A N/A N/A

COACH INC COH 11,134.37 0.06% 3.41% 9.50% 13.07% 0.0072%

ROCKWELL COLLINS INC COL 21,185.12 0.10% 1.04% 8.00% 9.08% 0.0095%

COOPER COS INC/THE COO 11,388.09 0.06% 0.03% 16.50% 16.53% 0.0093%

CONOCOPHILLIPS COP 59,253.25 0.29% 2.22% 60.50% 63.39% 0.1857%

COSTCO WHOLESALE CORP COST 70,837.89 0.35% 1.24% 9.00% 10.30% 0.0361%

COTY INC-CL A COTY 11,962.21 0.06% 3.13% 6.00% 9.22% 0.0055%

CAMPBELL SOUP CO CPB 14,748.18 0.07% 3.07% 5.00% 8.15% 0.0059%

SALESFORCE.COM INC CRM 68,175.88 N/A 0.00% N/A N/A N/A

CISCO SYSTEMS INC CSCO 163,434.60 0.81% 3.55% 7.00% 10.67% 0.0862%

CSRA INC CSRA 5,242.45 N/A 1.25% N/A N/A N/A

CSX CORP CSX 48,268.59 0.24% 1.51% 10.00% 11.59% 0.0276%

CINTAS CORP CTAS 14,487.23 0.07% 1.06% 11.00% 12.12% 0.0087%

CENTURYLINK INC CTL 10,164.75 0.05% 11.68% 6.50% 18.56% 0.0093%

COGNIZANT TECH SOLUTIONS-A CTSH 42,397.40 0.21% 0.84% 12.00% 12.89% 0.0270%

CITRIX SYSTEMS INC CTXS 11,533.84 0.06% 0.00% 5.50% 5.50% 0.0031%

CVS HEALTH CORP CVS 80,753.40 0.40% 2.51% 9.00% 11.62% 0.0464%

CHEVRON CORP CVX 220,711.00 1.09% 3.73% 15.00% 19.01% 0.2074%

CONCHO RESOURCES INC CXO 18,783.71 0.09% 0.00% 24.50% 24.50% 0.0228%

DOMINION ENERGY INC D 48,699.00 0.24% 4.14% 5.50% 9.75% 0.0235%

DELTA AIR LINES INC DAL 34,869.29 0.17% 2.53% 10.50% 13.16% 0.0227%

DEERE & CO DE 40,091.44 0.20% 1.92% 6.00% 7.98% 0.0158%

DISCOVER FINANCIAL SERVICES DFS 22,697.36 0.11% 2.31% 5.00% 7.37% 0.0083%

DOLLAR GENERAL CORP DG 20,978.10 0.10% 1.36% 9.50% 10.92% 0.0113%

QUEST DIAGNOSTICS INC DGX 13,810.80 0.07% 1.77% 9.50% 11.35% 0.0078%

DR HORTON INC DHI 13,793.90 0.07% 1.17% 12.00% 13.24% 0.0090%

DANAHER CORP DHR 60,035.97 0.30% 0.65% 9.00% 9.68% 0.0287%

WALT DISNEY CO/THE DIS 158,224.00 0.78% 1.58% 8.00% 9.64% 0.0754%

DISCOVERY COMMUNICATIONS-A DISCA 8,090.95 0.04% 0.00% 13.50% 13.50% 0.0054%

DISH NETWORK CORP-A DISH 24,820.41 0.12% 0.00% 2.50% 2.50% 0.0031%

DELPHI AUTOMOTIVE PLC DLPH 26,961.92 0.13% 1.23% 13.50% 14.81% 0.0197%

DIGITAL REALTY TRUST INC DLR - N/A 3.34% N/A N/A N/A

DOLLAR TREE INC DLTR 19,687.55 0.10% 0.00% 16.50% 16.50% 0.0161%

DOVER CORP DOV 14,333.76 0.07% 2.04% 4.50% 6.59% 0.0047%

DR PEPPER SNAPPLE GROUP INC DPS 16,308.33 0.08% 2.64% 7.00% 9.73% 0.0078%

DUKE REALTY CORP DRE - 0.00% 2.69% 33.50% 36.64% 0.0000%

DARDEN RESTAURANTS INC DRI 10,415.72 0.05% 3.03% 11.00% 14.20% 0.0073%

DTE ENERGY COMPANY DTE 19,557.54 0.10% 3.24% 6.00% 9.34% 0.0090%

DUKE ENERGY CORP DUK 59,612.00 0.29% 4.23% 4.50% 8.83% 0.0260%

DAVITA INC DVA 11,712.91 0.06% 0.00% 10.00% 10.00% 0.0058%

DEVON ENERGY CORP DVN 18,594.10 0.09% 0.68% 15.00% 15.73% 0.0145%

DOWDUPONT INC DWDP N/A N/A 0.00% N/A N/A N/A

DXC TECHNOLOGY CO DXC 11,976.01 0.06% 0.85% 18.00% 18.93% 0.0112%

ELECTRONIC ARTS INC EA 36,468.18 0.18% 0.00% 12.00% 12.00% 0.0216%

EBAY INC EBAY 41,004.00 0.20% 0.00% 9.50% 9.50% 0.0193%

ECOLAB INC ECL 37,894.04 0.19% 1.13% 8.50% 9.68% 0.0181%

CONSOLIDATED EDISON INC ED 25,223.58 0.12% 3.42% 2.50% 5.96% 0.0074%

EQUIFAX INC EFX 11,829.30 0.06% 1.59% 10.50% 12.17% 0.0071%

EDISON INTERNATIONAL EIX 25,628.29 0.13% 2.90% 4.00% 6.96% 0.0088%

ESTEE LAUDER COMPANIES-CL A EL 40,259.37 0.20% 1.26% 11.50% 12.83% 0.0255%

EASTMAN CHEMICAL CO EMN 12,426.24 0.06% 2.38% 10.00% 12.50% 0.0077%

EMERSON ELECTRIC CO EMR 40,599.51 0.20% 3.04% 5.00% 8.12% 0.0163%

EOG RESOURCES INC EOG 54,211.62 0.27% 0.77% 29.00% 29.88% 0.0801%

EQUINIX INC EQIX 34,807.90 0.17% 1.79% 23.00% 25.00% 0.0430%

EQUITY RESIDENTIAL EQR - N/A 3.08% N/A N/A N/A

EQT CORP EQT 11,065.20 0.05% 0.19% 20.50% 20.71% 0.0113%

EVERSOURCE ENERGY ES 19,469.48 0.10% 3.22% 6.50% 9.82% 0.0095%

EXPRESS SCRIPTS HOLDING CO ESRX 35,643.30 0.18% 0.00% 14.50% 14.50% 0.0256%

ESSEX PROPERTY TRUST INC ESS - N/A 2.77% N/A N/A N/A

E*TRADE FINANCIAL CORP ETFC 11,491.76 0.06% 0.00% 14.00% 14.00% 0.0080%

Case No. PU-17-


Page 9 of 12[4] [5] [6] [7] [8] [9]

Company Ticker

Market


Estimated

Dividend Yield

Long-Term


Weighted

DCF Result

EATON CORP PLC ETN 34,721.09 0.17% 3.08% 7.00% 10.19% 0.0175%

ENTERGY CORP ETR 13,995.30 0.07% 4.57% -3.50% 0.99% 0.0007%

ENVISION HEALTHCARE CORP EVHC 5,306.75 N/A 0.00% N/A N/A N/A

EDWARDS LIFESCIENCES CORP EW 23,290.66 0.12% 0.00% 17.00% 17.00% 0.0196%

EXELON CORP EXC 35,667.27 0.18% 3.58% 7.00% 10.71% 0.0189%

EXPEDITORS INTL WASH INC EXPD 10,374.04 0.05% 1.46% 8.00% 9.52% 0.0049%

EXPEDIA INC EXPE 21,718.32 0.11% 0.84% 23.00% 23.94% 0.0257%

EXTRA SPACE STORAGE INC EXR - N/A 4.22% N/A N/A N/A

FORD MOTOR CO F 47,548.04 0.24% 5.12% 2.50% 7.68% 0.0181%

FASTENAL CO FAST 12,812.14 0.06% 2.88% 4.00% 6.94% 0.0044%

FACEBOOK INC-A FB 496,732.30 2.46% 0.00% 31.50% 31.50% 0.7736%

FORTUNE BRANDS HOME & SECURI FBHS 9,993.77 0.05% 1.11% 12.00% 13.18% 0.0065%

FREEPORT-MCMORAN INC FCX 22,046.46 N/A 0.00% N/A N/A N/A

FEDEX CORP FDX 58,509.67 0.29% 0.91% 12.50% 13.47% 0.0390%

FIRSTENERGY CORP FE 13,840.07 0.07% 4.62% 9.00% 13.83% 0.0095%

F5 NETWORKS INC FFIV 7,479.77 0.04% 0.00% 10.00% 10.00% 0.0037%

FIDELITY NATIONAL INFO SERV FIS 30,783.04 0.15% 1.25% 10.00% 11.31% 0.0172%

FISERV INC FISV 26,299.41 0.13% 0.00% 9.00% 9.00% 0.0117%

FIFTH THIRD BANCORP FITB 20,348.56 0.10% 2.36% 5.00% 7.42% 0.0075%

FOOT LOCKER INC FL 4,418.07 0.02% 3.68% 9.00% 12.85% 0.0028%

FLIR SYSTEMS INC FLIR 5,418.48 0.03% 1.75% 7.50% 9.32% 0.0025%

FLUOR CORP FLR 5,748.94 0.03% 2.04% 2.00% 4.06% 0.0012%

FLOWSERVE CORP FLS 5,496.98 0.03% 1.80% 2.50% 4.32% 0.0012%

FMC CORP FMC 12,130.54 0.06% 0.75% 7.50% 8.28% 0.0050%

TWENTY-FIRST CENTURY FOX-A FOXA 49,528.88 0.24% 1.35% 9.50% 10.91% 0.0267%

FEDERAL REALTY INVS TRUST FRT - N/A 3.31% N/A N/A N/A

TECHNIPFMC PLC FTI N/A N/A 0.00% N/A N/A N/A

FORTIVE CORP FTV 24,265.71 N/A 0.40% N/A N/A N/A

GENERAL DYNAMICS CORP GD 61,605.32 0.30% 1.63% 5.50% 7.17% 0.0219%

GENERAL ELECTRIC CO GE 214,284.20 1.06% 3.88% 14.00% 18.15% 0.1923%

GGP INC GGP - N/A 4.63% N/A N/A N/A

GILEAD SCIENCES INC GILD 107,901.70 0.53% 2.52% -3.50% -1.02% -0.0055%

GENERAL MILLS INC GIS 29,819.96 0.15% 3.81% 5.00% 8.91% 0.0131%

CORNING INC GLW 27,150.20 0.13% 2.13% 11.50% 13.75% 0.0185%

GENERAL MOTORS CO GM 56,976.83 0.28% 3.99% 5.50% 9.60% 0.0270%

ALPHABET INC-CL A GOOGL N/A N/A 0.00% N/A N/A N/A

GENUINE PARTS CO GPC 12,678.86 0.06% 3.13% 7.00% 10.24% 0.0064%

GLOBAL PAYMENTS INC GPN 14,697.34 0.07% 0.04% 12.00% 12.04% 0.0088%

GAP INC/THE GPS 10,921.12 0.05% 3.30% 0.50% 3.81% 0.0021%

GARMIN LTD GRMN 9,760.56 0.05% 3.98% 5.00% 9.08% 0.0044%

GOLDMAN SACHS GROUP INC GS 89,789.79 0.44% 1.30% 9.50% 10.86% 0.0482%

GOODYEAR TIRE & RUBBER CO GT 8,179.92 0.04% 1.36% 10.00% 11.43% 0.0046%

WW GRAINGER INC GWW 10,129.96 0.05% 2.92% 4.50% 7.49% 0.0037%

HALLIBURTON CO HAL 37,827.60 0.19% 1.66% 21.50% 23.34% 0.0436%

HASBRO INC HAS 11,862.49 0.06% 2.40% 10.50% 13.03% 0.0076%

HUNTINGTON BANCSHARES INC HBAN 14,606.21 0.07% 3.28% 10.00% 13.44% 0.0097%

HANESBRANDS INC HBI 8,928.66 0.04% 2.45% 9.00% 11.56% 0.0051%

HCA HEALTHCARE INC HCA 28,178.79 0.14% 0.00% 10.50% 10.50% 0.0146%

WELLTOWER INC HCN - N/A 4.83% N/A N/A N/A

HCP INC HCP - N/A 5.25% N/A N/A N/A

HOME DEPOT INC HD 188,003.40 0.93% 2.51% 10.50% 13.14% 0.1221%

HESS CORP HES 13,867.53 N/A 2.29% N/A N/A N/A

HARTFORD FINANCIAL SVCS GRP HIG 19,719.27 0.10% 1.69% 12.50% 14.30% 0.0139%

HILTON WORLDWIDE HOLDINGS IN HLT 21,901.32 0.11% 0.89% 7.00% 7.92% 0.0086%

HARLEY-DAVIDSON INC HOG 8,181.74 0.04% 3.04% 8.00% 11.16% 0.0045%

HOLOGIC INC HOLX 10,516.96 0.05% 0.00% 27.00% 27.00% 0.0140%

HONEYWELL INTERNATIONAL INC HON 107,133.70 0.53% 1.89% 8.50% 10.47% 0.0555%

HELMERICH & PAYNE HP 5,475.79 0.03% 5.55% 8.00% 13.77% 0.0037%

HEWLETT PACKARD ENTERPRIS HPE 22,394.96 0.11% 1.89% 1.50% 3.40% 0.0038%

HP INC HPQ 33,015.90 N/A 2.83% N/A N/A N/A

H&R BLOCK INC HRB 5,479.38 0.03% 3.66% 8.00% 11.81% 0.0032%

HORMEL FOODS CORP HRL 16,460.21 0.08% 2.24% 10.50% 12.86% 0.0105%

HARRIS CORP HRS 15,678.58 0.08% 1.76% 10.50% 12.35% 0.0096%

HENRY SCHEIN INC HSIC 12,563.50 0.06% 0.00% 8.50% 8.50% 0.0053%

HOST HOTELS & RESORTS INC HST - N/A 4.43% N/A N/A N/A

HERSHEY CO/THE HSY 22,845.23 0.11% 2.44% 7.00% 9.53% 0.0108%

HUMANA INC HUM 34,487.54 0.17% 0.67% 10.00% 10.70% 0.0182%

INTL BUSINESS MACHINES CORP IBM 135,373.60 N/A 4.27% N/A N/A N/A

INTERCONTINENTAL EXCHANGE IN ICE 39,362.87 0.19% 1.20% 12.00% 13.27% 0.0258%

IDEXX LABORATORIES INC IDXX 13,620.75 0.07% 0.00% 15.00% 15.00% 0.0101%

INTL FLAVORS & FRAGRANCES IFF 11,354.38 0.06% 1.97% 7.50% 9.54% 0.0054%

ILLUMINA INC ILMN 29,235.04 0.14% 0.00% 17.00% 17.00% 0.0246%

INCYTE CORP INCY 23,657.85 0.12% 0.00% 69.50% 69.50% 0.0813%

IHS MARKIT LTD INFO 19,229.32 0.10% 0.00% 17.50% 17.50% 0.0166%

INTEL CORP INTC 174,802.80 0.86% 2.93% 7.50% 10.54% 0.0911%

INTUIT INC INTU 37,026.14 0.18% 0.94% 13.00% 14.00% 0.0256%

INTERNATIONAL PAPER CO IP 23,655.04 0.12% 3.23% 18.50% 22.03% 0.0258%

INTERPUBLIC GROUP OF COS INC IPG 8,325.40 0.04% 3.45% 10.00% 13.62% 0.0056%

INGERSOLL-RAND PLC IR 22,637.33 0.11% 2.02% 9.50% 11.62% 0.0130%

IRON MOUNTAIN INC IRM 10,514.39 0.05% 5.53% 11.00% 16.83% 0.0088%

INTUITIVE SURGICAL INC ISRG 38,220.79 0.19% 0.00% 14.00% 14.00% 0.0265%

GARTNER INC IT 11,179.96 0.06% 0.00% 17.00% 17.00% 0.0094%

ILLINOIS TOOL WORKS ITW 50,699.69 0.25% 2.12% 10.00% 12.23% 0.0306%

INVESCO LTD IVZ 13,655.29 0.07% 3.46% 5.50% 9.06% 0.0061%

HUNT (JB) TRANSPRT SVCS INC JBHT 11,454.56 0.06% 0.93% 9.00% 9.97% 0.0056%

JOHNSON CONTROLS INTERNATION JCI 37,277.32 0.18% 2.50% 0.50% 3.01% 0.0055%

JACOBS ENGINEERING GROUP INC JEC 6,904.53 0.03% 1.08% 8.00% 9.12% 0.0031%

JOHNSON & JOHNSON JNJ 353,773.80 1.75% 2.61% 9.50% 12.23% 0.2140%

JUNIPER NETWORKS INC JNPR 10,543.66 0.05% 1.59% 8.00% 9.65% 0.0050%

JPMORGAN CHASE & CO JPM 334,407.20 1.65% 2.38% 5.50% 7.95% 0.1314%

NORDSTROM INC JWN 7,691.74 0.04% 3.20% 2.00% 5.23% 0.0020%

Case No. PU-17-


Page 10 of 12[4] [5] [6] [7] [8] [9]

Company Ticker

Market


Estimated

Dividend Yield

Long-Term


Weighted

DCF Result

KELLOGG CO K 22,116.32 0.11% 3.38% 6.50% 9.99% 0.0109%

KEYCORP KEY 19,942.49 0.10% 2.36% 11.50% 14.00% 0.0138%

KRAFT HEINZ CO/THE KHC 96,248.63 N/A 3.19% N/A N/A N/A

KIMCO REALTY CORP KIM - N/A 5.87% N/A N/A N/A

KLA-TENCOR CORP KLAC 15,608.72 0.08% 2.37% 13.50% 16.03% 0.0124%

KIMBERLY-CLARK CORP KMB 41,732.15 0.21% 3.29% 10.50% 13.96% 0.0288%

KINDER MORGAN INC KMI 43,086.80 0.21% 2.59% 24.00% 26.90% 0.0573%

CARMAX INC KMX 12,657.82 0.06% 0.00% 10.00% 10.00% 0.0063%

COCA-COLA CO/THE KO 193,767.20 0.96% 3.35% 4.50% 7.93% 0.0759%

MICHAEL KORS HOLDINGS LTD KORS 6,961.15 0.03% 0.00% 2.00% 2.00% 0.0007%

KROGER CO KR 18,056.46 0.09% 2.47% 6.50% 9.05% 0.0081%

KOHLS CORP KSS 7,575.99 0.04% 4.90% 7.00% 12.07% 0.0045%

KANSAS CITY SOUTHERN KSU 11,371.77 0.06% 1.33% 9.50% 10.89% 0.0061%

LOEWS CORP L 16,059.23 0.08% 0.52% 14.50% 15.06% 0.0120%

L BRANDS INC LB 10,547.68 0.05% 6.51% 0.50% 7.03% 0.0037%

LEGGETT & PLATT INC LEG 6,077.17 0.03% 3.14% 7.50% 10.76% 0.0032%

LENNAR CORP-A LEN 11,839.65 0.06% 0.32% 10.50% 10.84% 0.0063%

LABORATORY CRP OF AMER HLDGS LH 15,696.78 0.08% 0.00% 9.00% 9.00% 0.0070%

LKQ CORP LKQ 10,675.17 0.05% 0.00% 11.50% 11.50% 0.0061%

L3 TECHNOLOGIES INC LLL 14,845.53 0.07% 1.58% 10.00% 11.66% 0.0086%

ELI LILLY & CO LLY 91,745.41 0.45% 2.50% 11.00% 13.64% 0.0619%

LOCKHEED MARTIN CORP LMT 88,704.11 0.44% 2.54% 10.00% 12.67% 0.0555%

LINCOLN NATIONAL CORP LNC 16,074.40 0.08% 1.71% 7.00% 8.77% 0.0070%

ALLIANT ENERGY CORP LNT 9,718.47 0.05% 3.00% 6.50% 9.60% 0.0046%

LOWE'S COS INC LOW 65,319.47 0.32% 2.10% 13.50% 15.74% 0.0508%

LAM RESEARCH CORP LRCX 28,248.58 0.14% 1.13% 20.50% 21.75% 0.0304%

LEUCADIA NATIONAL CORP LUK 8,776.04 0.04% 1.64% 31.50% 33.40% 0.0145%

SOUTHWEST AIRLINES CO LUV 32,699.60 0.16% 1.10% 12.00% 13.17% 0.0213%

LEVEL 3 COMMUNICATIONS INC LVLT 19,057.17 0.09% 0.00% 14.50% 14.50% 0.0137%

LYONDELLBASELL INDU-CL A LYB 38,072.40 0.19% 3.76% 4.00% 7.84% 0.0147%

MACY'S INC M 6,444.47 0.03% 7.14% 2.00% 9.21% 0.0029%

MASTERCARD INC - A MA 151,215.20 0.75% 0.62% 12.50% 13.16% 0.0984%

MID-AMERICA APARTMENT COMM MAA N/A N/A 0.00% N/A N/A N/A

MACERICH CO/THE MAC - N/A 5.54% N/A N/A N/A

MARRIOTT INTERNATIONAL -CL A MAR 40,061.22 0.20% 1.23% 15.00% 16.32% 0.0323%

MASCO CORP MAS 11,896.89 0.06% 1.11% 14.00% 15.19% 0.0089%

MATTEL INC MAT 5,140.50 0.03% 4.00% 11.50% 15.73% 0.0040%

MCDONALD'S CORP MCD 128,814.30 0.64% 2.52% 9.50% 12.14% 0.0773%

MICROCHIP TECHNOLOGY INC MCHP 20,568.32 0.10% 1.68% 13.00% 14.79% 0.0150%

MCKESSON CORP MCK 32,039.70 0.16% 0.89% 11.00% 11.94% 0.0189%

MOODY'S CORP MCO 26,105.07 0.13% 1.11% 8.50% 9.66% 0.0125%

MONDELEZ INTERNATIONAL INC-A MDLZ 60,719.02 0.30% 1.99% 10.00% 12.09% 0.0363%

MEDTRONIC PLC MDT 107,730.60 0.53% 2.31% 5.50% 7.87% 0.0419%

METLIFE INC MET 53,651.86 0.27% 3.41% 7.00% 10.53% 0.0279%

MGM RESORTS INTERNATIONAL MGM 19,009.80 0.09% 1.33% 41.50% 43.11% 0.0405%

MOHAWK INDUSTRIES INC MHK 18,890.03 0.09% 0.00% 8.50% 8.50% 0.0079%

MCCORMICK & CO-NON VTG SHRS MKC 12,067.22 0.06% 2.00% 7.50% 9.58% 0.0057%

MARTIN MARIETTA MATERIALS MLM 12,555.43 0.06% 0.88% 17.50% 18.46% 0.0115%

MARSH & MCLENNAN COS MMC 42,224.28 0.21% 1.82% 10.00% 11.91% 0.0249%

3M CO MMM 125,583.60 0.62% 2.23% 8.00% 10.32% 0.0641%

MONSTER BEVERAGE CORP MNST 31,570.48 0.16% 0.00% 12.00% 12.00% 0.0187%

ALTRIA GROUP INC MO 118,128.80 0.58% 4.29% 9.50% 13.99% 0.0817%

MONSANTO CO MON 52,445.25 0.26% 1.81% 8.00% 9.88% 0.0256%

MOSAIC CO/THE MOS 7,350.99 0.04% 2.96% 3.00% 6.00% 0.0022%

MARATHON PETROLEUM CORP MPC 27,511.22 0.14% 3.02% 5.50% 8.60% 0.0117%

MERCK & CO. INC. MRK 178,899.70 0.88% 2.87% 5.50% 8.45% 0.0747%

MARATHON OIL CORP MRO 10,820.50 N/A 1.57% N/A N/A N/A

MORGAN STANLEY MS 88,778.04 0.44% 2.07% 10.50% 12.68% 0.0556%

MICROSOFT CORP MSFT 573,123.90 2.83% 2.26% 8.00% 10.35% 0.2933%

MOTOROLA SOLUTIONS INC MSI 13,827.87 0.07% 2.41% 10.50% 13.04% 0.0089%

M & T BANK CORP MTB 23,555.07 0.12% 1.94% 8.00% 10.02% 0.0117%

METTLER-TOLEDO INTERNATIONAL MTD 16,207.03 0.08% 0.00% 11.00% 11.00% 0.0088%

MICRON TECHNOLOGY INC MU 39,860.11 0.20% 0.00% 25.50% 25.50% 0.0503%

MYLAN NV MYL 16,748.45 0.08% 0.00% 10.00% 10.00% 0.0083%

NAVIENT CORP NAVI 3,844.22 0.02% 4.56% 6.00% 10.70% 0.0020%

NOBLE ENERGY INC NBL 13,112.39 N/A 1.48% N/A N/A N/A

NASDAQ INC NDAQ 12,662.51 0.06% 2.00% 10.00% 12.10% 0.0076%

NEXTERA ENERGY INC NEE 68,839.82 0.34% 2.86% 7.00% 9.96% 0.0339%

NEWMONT MINING CORP NEM 19,960.37 0.10% 0.80% 0.50% 1.30% 0.0013%

NETFLIX INC NFLX 81,505.77 0.40% 0.00% 44.50% 44.50% 0.1793%

NEWFIELD EXPLORATION CO NFX 5,674.98 0.03% 0.00% 18.00% 18.00% 0.0051%

NISOURCE INC NI 8,508.77 0.04% 2.68% 5.50% 8.25% 0.0035%

NIKE INC -CL B NKE 87,869.88 0.43% 1.35% 15.50% 16.95% 0.0737%

NIELSEN HOLDINGS PLC NLSN 14,448.50 N/A 3.36% N/A N/A N/A

NORTHROP GRUMMAN CORP NOC 48,835.42 0.24% 1.43% 8.00% 9.49% 0.0229%

NATIONAL OILWELL VARCO INC NOV 13,377.83 0.07% 0.57% 3.00% 3.58% 0.0024%

NRG ENERGY INC NRG 7,647.02 N/A 0.50% N/A N/A N/A

NORFOLK SOUTHERN CORP NSC 37,668.27 0.19% 1.87% 8.00% 9.94% 0.0185%

NETAPP INC NTAP 11,302.20 0.06% 1.96% 12.50% 14.58% 0.0081%

NORTHERN TRUST CORP NTRS 20,755.67 0.10% 1.85% 7.50% 9.42% 0.0097%

NUCOR CORP NUE 17,411.91 0.09% 2.77% 20.50% 23.55% 0.0203%

NVIDIA CORP NVDA 108,456.00 0.54% 0.31% 19.50% 19.84% 0.1064%

NEWELL BRANDS INC NWL 20,051.43 0.10% 2.22% 23.50% 25.98% 0.0258%

NEWS CORP - CLASS A NWSA 7,608.92 0.04% 1.53% 48.00% 49.90% 0.0188%

REALTY INCOME CORP O - N/A 4.47% N/A N/A N/A

ONEOK INC OKE 20,923.07 0.10% 5.41% 22.00% 28.01% 0.0290%

OMNICOM GROUP OMC 17,128.87 0.08% 3.10% 7.50% 10.72% 0.0091%

ORACLE CORP ORCL 200,082.90 0.99% 1.58% 8.00% 9.64% 0.0954%

O'REILLY AUTOMOTIVE INC ORLY 17,798.68 0.09% 0.00% 11.00% 11.00% 0.0097%

OCCIDENTAL PETROLEUM CORP OXY 47,976.96 0.24% 4.94% 25.00% 30.56% 0.0725%

PAYCHEX INC PAYX 20,901.85 0.10% 3.51% 8.50% 12.16% 0.0126%

Case No. PU-17-


Page 11 of 12[4] [5] [6] [7] [8] [9]

Company Ticker

Market


Estimated

Dividend Yield

Long-Term


Weighted

DCF Result

PEOPLE'S UNITED FINANCIAL PBCT 5,994.26 0.03% 3.96% 10.50% 14.67% 0.0043%

PACCAR INC PCAR 24,840.43 0.12% 2.33% 6.50% 8.91% 0.0109%

P G & E CORP PCG 35,435.45 0.18% 3.14% 9.50% 12.79% 0.0224%

PRICELINE GROUP INC/THE PCLN 91,557.54 0.45% 0.00% 15.50% 15.50% 0.0702%

PATTERSON COS INC PDCO 3,552.50 0.02% 2.91% 13.00% 16.10% 0.0028%

PUBLIC SERVICE ENTERPRISE GP PEG 23,341.10 0.12% 3.81% 1.00% 4.83% 0.0056%

PEPSICO INC PEP 160,852.80 0.80% 2.90% 7.50% 10.51% 0.0836%

PFIZER INC PFE 213,926.20 1.06% 3.56% 11.00% 14.76% 0.1561%

PRINCIPAL FINANCIAL GROUP PFG 18,161.60 0.09% 2.99% 4.50% 7.56% 0.0068%

PROCTER & GAMBLE CO/THE PG 236,537.40 1.17% 2.98% 10.00% 13.13% 0.1535%

PROGRESSIVE CORP PGR 27,702.08 0.14% 2.01% 8.00% 10.09% 0.0138%

PARKER HANNIFIN CORP PH 23,428.22 0.12% 1.50% 7.50% 9.06% 0.0105%

PULTEGROUP INC PHM 7,789.88 0.04% 1.48% 16.50% 18.10% 0.0070%

PACKAGING CORP OF AMERICA PKG 11,214.72 0.06% 2.12% 8.50% 10.71% 0.0059%

PERKINELMER INC PKI 7,515.37 0.04% 0.41% 8.00% 8.43% 0.0031%

PROLOGIS INC PLD - N/A 2.74% N/A N/A N/A

PHILIP MORRIS INTERNATIONAL PM 175,385.90 0.87% 3.79% 7.50% 11.43% 0.0991%

PNC FINANCIAL SERVICES GROUP PNC 64,008.00 0.32% 2.25% 5.50% 7.81% 0.0247%

PENTAIR PLC PNR 12,119.17 0.06% 2.07% 11.50% 13.69% 0.0082%

PINNACLE WEST CAPITAL PNW 9,724.60 0.05% 3.11% 5.50% 8.70% 0.0042%

PPG INDUSTRIES INC PPG 27,953.76 0.14% 1.65% 10.50% 12.24% 0.0169%

PPL CORP PPL 26,603.21 N/A 4.20% N/A N/A N/A

PERRIGO CO PLC PRGO 12,127.64 0.06% 0.79% -0.50% 0.29% 0.0002%

PRUDENTIAL FINANCIAL INC PRU 44,745.67 0.22% 2.86% 5.50% 8.44% 0.0187%

PUBLIC STORAGE PSA - N/A 3.86% N/A N/A N/A

PHILLIPS 66 PSX 45,596.09 0.23% 3.30% 5.00% 8.38% 0.0189%

PVH CORP PVH 9,762.69 0.05% 0.12% 7.50% 7.62% 0.0037%

QUANTA SERVICES INC PWR 5,650.80 0.03% 0.00% 15.00% 15.00% 0.0042%

PRAXAIR INC PX 39,634.35 0.20% 2.41% 8.00% 10.51% 0.0206%

PIONEER NATURAL RESOURCES CO PXD 24,155.48 0.12% 0.06% 38.50% 38.57% 0.0461%

PAYPAL HOLDINGS INC PYPL 77,685.27 N/A 0.00% N/A N/A N/A

QUINTILES IMS HOLDINGS INC Q 20,389.21 0.10% 0.00% 12.00% 12.00% 0.0121%

QUALCOMM INC QCOM 76,796.28 0.38% 4.38% 3.00% 7.45% 0.0283%

QORVO INC QRVO 8,983.36 0.04% 0.00% 28.00% 28.00% 0.0124%

ROYAL CARIBBEAN CRUISES LTD RCL 24,992.12 0.12% 2.07% 12.50% 14.70% 0.0182%

EVEREST RE GROUP LTD RE 9,334.07 0.05% 2.33% 3.50% 5.87% 0.0027%

REGENCY CENTERS CORP REG N/A N/A 0.00% N/A N/A N/A

REGENERON PHARMACEUTICALS REGN 45,603.71 0.23% 0.00% 23.00% 23.00% 0.0519%

REGIONS FINANCIAL CORP RF 17,305.42 0.09% 2.70% 9.50% 12.33% 0.0105%

ROBERT HALF INTL INC RHI 6,051.79 0.03% 2.09% 4.50% 6.64% 0.0020%

RED HAT INC RHT 18,966.24 0.09% 0.00% 17.50% 17.50% 0.0164%

RAYMOND JAMES FINANCIAL INC RJF 11,902.40 0.06% 1.06% 11.00% 12.12% 0.0071%

RALPH LAUREN CORP RL 7,193.42 0.04% 2.26% 1.00% 3.27% 0.0012%

RESMED INC RMD 10,962.74 0.05% 1.81% 8.50% 10.39% 0.0056%

ROCKWELL AUTOMATION INC ROK 22,769.17 0.11% 1.81% 5.50% 7.36% 0.0083%

ROPER TECHNOLOGIES INC ROP 25,203.36 0.12% 0.57% 7.00% 7.59% 0.0095%

ROSS STORES INC ROST 23,486.41 0.12% 1.10% 8.50% 9.65% 0.0112%

RANGE RESOURCES CORP RRC 4,664.58 0.02% 0.43% 28.00% 28.49% 0.0066%

REPUBLIC SERVICES INC RSG 22,292.55 0.11% 2.09% 8.50% 10.68% 0.0118%

RAYTHEON COMPANY RTN 53,661.60 0.27% 1.72% 8.00% 9.79% 0.0260%

SBA COMMUNICATIONS CORP SBAC 17,543.46 0.09% 0.00% 87.50% 87.50% 0.0759%

STARBUCKS CORP SBUX 79,527.96 0.39% 2.18% 15.00% 17.34% 0.0682%

SCANA CORP SCG 8,171.02 0.04% 4.43% 4.00% 8.52% 0.0034%

SCHWAB (CHARLES) CORP SCHW 56,311.63 0.28% 0.76% 14.00% 14.81% 0.0412%

SEALED AIR CORP SEE 8,065.21 0.04% 1.51% 12.00% 13.60% 0.0054%

SHERWIN-WILLIAMS CO/THE SHW 32,657.07 0.16% 0.99% 13.50% 14.56% 0.0235%

SIGNET JEWELERS LTD SIG 4,410.81 0.02% 1.98% 1.50% 3.49% 0.0008%

JM SMUCKER CO/THE SJM 12,032.51 0.06% 2.95% 6.50% 9.55% 0.0057%

SCHLUMBERGER LTD SLB 94,272.23 0.47% 2.94% 17.50% 20.70% 0.0965%

SL GREEN REALTY CORP SLG - N/A 3.17% N/A N/A N/A

SNAP-ON INC SNA 8,555.83 0.04% 1.91% 8.50% 10.49% 0.0044%

SCRIPPS NETWORKS INTER-CL A SNI 11,172.07 0.06% 1.39% 6.50% 7.94% 0.0044%

SYNOPSYS INC SNPS 12,028.05 0.06% 0.00% 9.50% 9.50% 0.0056%

SOUTHERN CO/THE SO 49,225.65 0.24% 4.79% 3.50% 8.37% 0.0204%

SIMON PROPERTY GROUP INC SPG - N/A 4.51% N/A N/A N/A

S&P GLOBAL INC SPGI 40,027.75 0.20% 1.05% 11.50% 12.61% 0.0250%

STERICYCLE INC SRCL 5,971.03 0.03% 0.00% 5.50% 5.50% 0.0016%

SEMPRA ENERGY SRE 29,093.41 0.14% 2.96% 8.00% 11.08% 0.0159%

SUNTRUST BANKS INC STI 27,458.53 0.14% 2.81% 7.00% 9.91% 0.0135%

STATE STREET CORP STT 35,895.57 0.18% 1.79% 7.50% 9.36% 0.0166%

SEAGATE TECHNOLOGY STX 9,547.70 0.05% 7.82% 4.50% 12.50% 0.0059%

CONSTELLATION BRANDS INC-A STZ 39,252.37 0.19% 1.07% 13.00% 14.14% 0.0274%

STANLEY BLACK & DECKER INC SWK 23,274.66 0.12% 1.66% 9.50% 11.24% 0.0129%

SKYWORKS SOLUTIONS INC SWKS 18,761.28 0.09% 1.25% 14.50% 15.84% 0.0147%

SYNCHRONY FINANCIAL SYF 22,976.91 0.11% 2.08% 7.50% 9.66% 0.0110%

STRYKER CORP SYK 52,610.59 0.26% 1.21% 14.00% 15.29% 0.0398%

SYMANTEC CORP SYMC 20,187.14 0.10% 0.91% 10.50% 11.46% 0.0114%

SYSCO CORP SYY 28,879.65 0.14% 2.56% 11.50% 14.21% 0.0203%

AT&T INC T 234,662.50 1.16% 5.21% 5.50% 10.85% 0.1259%

MOLSON COORS BREWING CO -B TAP 17,828.99 0.09% 2.11% 14.50% 16.76% 0.0148%

TRANSDIGM GROUP INC TDG 13,712.18 0.07% 0.00% 12.00% 12.00% 0.0081%

TE CONNECTIVITY LTD TEL 29,076.78 0.14% 1.95% 8.50% 10.53% 0.0151%

TARGET CORP TGT 31,858.86 0.16% 4.25% 4.50% 8.85% 0.0139%

TIFFANY & CO TIF 11,186.33 0.06% 2.28% 8.00% 10.37% 0.0057%

TJX COMPANIES INC TJX 46,333.48 0.23% 1.72% 10.50% 12.31% 0.0282%

TORCHMARK CORP TMK 9,143.77 0.05% 0.76% 7.50% 8.29% 0.0037%

THERMO FISHER SCIENTIFIC INC TMO 73,307.45 0.36% 0.32% 9.00% 9.33% 0.0338%

TRIPADVISOR INC TRIP 6,137.68 0.03% 0.00% 8.00% 8.00% 0.0024%

T ROWE PRICE GROUP INC TROW 20,655.32 0.10% 2.72% 8.00% 10.83% 0.0111%

TRAVELERS COS INC/THE TRV 33,519.09 0.17% 2.37% 1.00% 3.38% 0.0056%

TRACTOR SUPPLY COMPANY TSCO 7,729.28 0.04% 1.78% 10.00% 11.87% 0.0045%

Case No. PU-17-


Page 12 of 12[4] [5] [6] [7] [8] [9]

Company Ticker

Market


Estimated

Dividend Yield

Long-Term


Weighted

DCF Result

TYSON FOODS INC-CL A TSN 23,453.47 0.12% 1.52% 9.50% 11.09% 0.0129%

TOTAL SYSTEM SERVICES INC TSS 12,675.97 0.06% 0.76% 10.50% 11.30% 0.0071%

TIME WARNER INC TWX 79,634.73 0.39% 1.57% 9.50% 11.14% 0.0439%

TEXAS INSTRUMENTS INC TXN 85,337.25 0.42% 2.32% 9.50% 11.93% 0.0503%

TEXTRON INC TXT 14,066.89 0.07% 0.15% 12.00% 12.16% 0.0085%

UNDER ARMOUR INC-CLASS A UAA 7,270.82 0.04% 0.00% 14.00% 14.00% 0.0050%

UNITED CONTINENTAL HOLDINGS UAL 17,852.23 0.09% 0.00% 4.50% 4.50% 0.0040%

UDR INC UDR - N/A 3.25% N/A N/A N/A

UNIVERSAL HEALTH SERVICES-B UHS 10,372.09 0.05% 0.37% 9.50% 9.89% 0.0051%

ULTA BEAUTY INC ULTA 13,545.87 0.07% 0.00% 21.00% 21.00% 0.0141%

UNITEDHEALTH GROUP INC UNH 188,377.60 0.93% 1.54% 13.00% 14.64% 0.1363%

UNUM GROUP UNM 11,311.88 0.06% 1.84% 10.50% 12.44% 0.0070%

UNION PACIFIC CORP UNP 92,523.31 0.46% 2.10% 8.00% 10.18% 0.0466%

UNITED PARCEL SERVICE-CL B UPS 101,429.90 0.50% 2.83% 10.00% 12.97% 0.0650%

UNITED RENTALS INC URI 11,000.21 0.05% 0.00% 8.00% 8.00% 0.0044%

US BANCORP USB 90,226.07 0.45% 2.23% 5.00% 7.29% 0.0325%

UNITED TECHNOLOGIES CORP UTX 91,459.51 0.45% 2.45% 8.00% 10.55% 0.0477%

VISA INC-CLASS A SHARES V 220,097.90 1.09% 0.71% 11.50% 12.25% 0.1333%

VARIAN MEDICAL SYSTEMS INC VAR 9,594.57 0.05% 0.00% 7.00% 7.00% 0.0033%

VF CORP VFC 24,326.16 0.12% 2.72% 8.50% 11.34% 0.0136%

VIACOM INC-CLASS B VIAB 11,025.76 0.05% 2.92% 2.00% 4.95% 0.0027%

VALERO ENERGY CORP VLO 32,425.34 0.16% 3.90% 5.00% 9.00% 0.0144%

VULCAN MATERIALS CO VMC 15,465.18 0.08% 0.86% 20.50% 21.45% 0.0164%

VORNADO REALTY TRUST VNO 14,329.24 0.07% 3.17% 14.50% 17.90% 0.0127%

VERISK ANALYTICS INC VRSK 13,482.50 0.07% 0.00% 10.50% 10.50% 0.0070%

VERISIGN INC VRSN 10,599.21 0.05% 0.00% 10.50% 10.50% 0.0055%

VERTEX PHARMACEUTICALS INC VRTX 38,132.09 N/A 0.00% N/A N/A N/A

VENTAS INC VTR - N/A 4.81% N/A N/A N/A

VERIZON COMMUNICATIONS INC VZ 199,646.20 0.99% 4.82% 2.00% 6.87% 0.0678%

WATERS CORP WAT 14,508.84 0.07% 0.00% 8.50% 8.50% 0.0061%

WALGREENS BOOTS ALLIANCE INC WBA 83,681.51 0.41% 2.05% 11.00% 13.16% 0.0545%

WESTERN DIGITAL CORP WDC 25,134.06 0.12% 2.52% 13.50% 16.19% 0.0201%

WEC ENERGY GROUP INC WEC 20,282.13 0.10% 3.36% 6.00% 9.46% 0.0095%

WELLS FARGO & CO WFC 268,503.60 1.33% 2.90% 5.00% 7.97% 0.1058%

WHIRLPOOL CORP WHR 12,606.37 0.06% 2.55% 9.50% 12.17% 0.0076%

WILLIS TOWERS WATSON PLC WLTW 20,382.42 N/A 1.40% N/A N/A N/A

WASTE MANAGEMENT INC WM 34,420.58 0.17% 2.17% 8.50% 10.76% 0.0183%

WILLIAMS COS INC WMB 24,771.74 0.12% 4.00% 18.50% 22.87% 0.0280%

WAL-MART STORES INC WMT 239,469.90 1.18% 2.55% 4.00% 6.60% 0.0781%

WESTROCK CO WRK 14,627.18 N/A 2.78% N/A N/A N/A

WESTERN UNION CO WU 8,779.91 0.04% 3.70% 5.50% 9.30% 0.0040%

WEYERHAEUSER CO WY 25,155.60 0.12% 3.71% 14.50% 18.48% 0.0230%

WYNDHAM WORLDWIDE CORP WYN 10,598.85 0.05% 2.25% 6.50% 8.82% 0.0046%

WYNN RESORTS LTD WYNN 14,912.66 0.07% 1.38% 14.00% 15.48% 0.0114%

CIMAREX ENERGY CO XEC 10,427.55 0.05% 0.29% 31.00% 31.33% 0.0162%

XCEL ENERGY INC XEL 24,377.70 0.12% 3.08% 4.50% 7.65% 0.0092%

XL GROUP LTD XL 10,579.48 0.05% 2.22% 13.00% 15.36% 0.0080%

XILINX INC XLNX 17,131.16 0.08% 2.03% 8.00% 10.11% 0.0086%

EXXON MOBIL CORP XOM 338,493.90 1.67% 3.86% 10.50% 14.56% 0.2437%

DENTSPLY SIRONA INC XRAY 13,255.83 0.07% 0.61% 8.50% 9.14% 0.0060%

XEROX CORP XRX 8,369.82 0.04% 3.04% 4.00% 7.10% 0.0029%

XYLEM INC XYL 11,475.43 0.06% 1.13% 12.00% 13.20% 0.0075%

YUM! BRANDS INC YUM 26,385.60 0.13% 1.69% 6.50% 8.24% 0.0108%

ZIMMER BIOMET HOLDINGS INC ZBH 22,849.43 0.11% 0.96% 11.00% 12.01% 0.0136%

ZIONS BANCORPORATION ZION 9,168.66 0.05% 1.59% 14.50% 16.21% 0.0073%

ZOETIS INC ZTS 31,455.76 0.16% 0.65% 11.50% 12.19% 0.0190%

Total Market Capitalization: 20,227,489.89 14.33%

Notes:

[1] Equals sum of Col. [9]


[3] Equals [1] − [2]


[5] Equals weight in S&P 500 based on market capitalization



[8] Equals ([6] x (1 + (0.5 x [7]))) + [7]

[9] Equals Col. [5] x Col. [8]

Case No. PU-17-


Page 1 of 1

[1] [2]

Company Ticker Bloomberg Value Line

ALLETE, Inc. ALE 0.686 0.750

Alliant Energy Corporation LNT 0.471 0.700

Black Hills Corporation BKH 0.519 0.850

El Paso Electric Company EE 0.728 0.750

Hawaiian Electric Industries, Inc. HE 0.479 0.700

IDACORP, Inc. IDA 0.707 0.700

Northwestern Corporation NWE 0.595 0.650

OGE Energy Corp. OGE 0.636 0.950

PNM Resources, Inc. PNM 0.592 0.750

Mean 0.601 0.756

Notes:



Bloomberg and Value Line Beta Coefficients

Case No. PU-17-


Page 1 of 1

Capital Asset Pricing Model Results

Bloomberg, and Value Line Derived Market Risk Premium

[1] [2] [3] [4] [5] [6]

CAPM

Risk-Free

Rate

Average

Beta

Coefficient

Bloomberg

Market DCF

Derived

Value Line

Market DCF

Derived

Bloomberg

MRP

Value Line

MRP

PROXY GROUP AVERAGE BLOOMBERG BETA COEFFICIENT

Current 30-Year Treasury [7] 2.77% 0.601 11.06% 11.56% 9.42% 9.72%

Near-Term Projected 30-Year Treasury [8] 3.30% 0.601 11.06% 11.56% 9.95% 10.25%

Mean 9.69% 9.99%

CAPM

Risk-Free

Rate

Average

Beta

Coefficient

Bloomberg

Market DCF

Derived

Value Line

Market DCF

Derived

Bloomberg

MRP

Value Line

MRP

PROXY GROUP AVERAGE VALUE LINE AVERAGE BETA COEFFICIENT

Current 30-Year Treasury [7] 2.77% 0.756 11.06% 11.56% 11.13% 11.51%

Near-Term Projected 30-Year Treasury [8] 3.30% 0.756 11.06% 11.56% 11.65% 12.04%

Mean 11.39% 11.77%

Notes:

[1] See Notes [7] and [8]

[2] Source: Exhibit___(RBH-1), Schedule 4



[5] Equals Col. [1] + (Col. [2] x Col. [3])

[6] Equals Col. [1] + (Col. [2] x Col. [4])


[8] Blue Chip Financial Forecasts, Vol. 36, No. 10, October 1, 2017, at 2.

Case No. PU-17-


Page 1 of 24

Bond Yield Plus Risk Premium

[1] [2] [3] [4] [5]

Constant Slope

30-Year

Treasury

Yield

Risk

Premium

Return on

Equity

-2.59% -2.73%

Current 30-Year Treasury 2.77% 7.19% 9.96%

Near-Term Projected 30-Year Treasury 3.30% 6.72% 10.02%

Long-Term Projected 30-Year Treasury 4.40% 5.93% 10.33%

Notes:

[1] Constant of regression equation

[2] Slope of regression equation

[3] Source: Current = Bloomberg Professional,

[3] Near Term Projected = Blue Chip Financial Forecasts, Vol. 36, No. 10, October 1, 2017, at 2,

[3] Long Term Projected = Blue Chip Financial Forecasts, Vol. 36, No. 6, June 1, 2017, at 14.

[4] Equals [1] + ln([3]) x [2]

[5] Equals [3] + [4]

[6] Source: SNL Financial


[8] Source: Bloomberg Professional, equals 201-trading day average (i.e. lag period)

[9] Equals [7] - [8]

y = -0.0273ln(x) - 0.0259R² = 0.7291

-6.00%

-4.00%

-2.00%

0.00%

2.00%

4.00%

6.00%

8.00%

10.00%

0.00% 2.00% 4.00% 6.00% 8.00% 10.00% 12.00% 14.00% 16.00%

Equ

ity

Ris

k P

rem

ium

Treasury Yield

Case No. PU-17-


Page 2 of 24Bond Yield Plus Risk Premium

[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

1/1/1980 14.50% 9.36% 5.14%

1/7/1980 14.39% 9.38% 5.01%

1/9/1980 15.00% 9.40% 5.60%

1/14/1980 15.17% 9.42% 5.75%

1/17/1980 13.93% 9.44% 4.49%

1/23/1980 15.50% 9.47% 6.03%

1/30/1980 13.86% 9.52% 4.34%

1/31/1980 12.61% 9.53% 3.08%

2/6/1980 13.71% 9.58% 4.13%

2/13/1980 12.80% 9.63% 3.17%

2/14/1980 13.00% 9.65% 3.35%

2/19/1980 13.50% 9.68% 3.82%

2/27/1980 13.75% 9.78% 3.97%

2/29/1980 13.75% 9.81% 3.94%

2/29/1980 14.00% 9.81% 4.19%

2/29/1980 14.77% 9.81% 4.96%

3/7/1980 12.70% 9.89% 2.81%

3/14/1980 13.50% 9.97% 3.53%

3/26/1980 14.16% 10.10% 4.06%

3/27/1980 14.24% 10.12% 4.12%

3/28/1980 14.50% 10.13% 4.37%

4/11/1980 12.75% 10.27% 2.48%

4/14/1980 13.85% 10.29% 3.56%

4/16/1980 15.50% 10.31% 5.19%

4/22/1980 13.25% 10.35% 2.90%

4/22/1980 13.90% 10.35% 3.55%

4/24/1980 16.80% 10.38% 6.43%

4/29/1980 15.50% 10.41% 5.09%

5/6/1980 13.70% 10.45% 3.25%

5/7/1980 15.00% 10.45% 4.55%

5/8/1980 13.75% 10.46% 3.29%

5/9/1980 14.35% 10.47% 3.88%

5/13/1980 13.60% 10.48% 3.12%

5/15/1980 13.25% 10.49% 2.76%

5/19/1980 13.75% 10.51% 3.24%

5/27/1980 13.62% 10.54% 3.08%

5/27/1980 14.60% 10.54% 4.06%

5/29/1980 16.00% 10.56% 5.44%

5/30/1980 13.80% 10.56% 3.24%

6/2/1980 15.63% 10.57% 5.06%

6/9/1980 15.90% 10.60% 5.30%

6/10/1980 13.78% 10.60% 3.18%

6/12/1980 14.25% 10.61% 3.64%

6/19/1980 13.40% 10.62% 2.78%

6/30/1980 13.00% 10.65% 2.35%

6/30/1980 13.40% 10.65% 2.75%

7/9/1980 14.75% 10.67% 4.08%

7/10/1980 15.00% 10.68% 4.32%

7/15/1980 15.80% 10.70% 5.10%

7/18/1980 13.80% 10.71% 3.09%

7/22/1980 14.10% 10.72% 3.38%

7/24/1980 15.00% 10.73% 4.27%

7/25/1980 13.48% 10.73% 2.75%

7/31/1980 14.58% 10.75% 3.83%

8/8/1980 13.50% 10.78% 2.72%

8/8/1980 14.00% 10.78% 3.22%

8/8/1980 15.45% 10.78% 4.67%

8/11/1980 14.85% 10.78% 4.07%

8/14/1980 14.00% 10.79% 3.21%

8/14/1980 16.25% 10.79% 5.46%

8/25/1980 13.75% 10.82% 2.93%

8/27/1980 13.80% 10.83% 2.97%

8/29/1980 12.50% 10.84% 1.66%

9/15/1980 13.50% 10.88% 2.62%

9/15/1980 13.93% 10.88% 3.05%

9/15/1980 15.80% 10.88% 4.92%

9/24/1980 12.50% 10.93% 1.57%

9/24/1980 15.00% 10.93% 4.07%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

9/26/1980 13.75% 10.94% 2.81%

9/30/1980 14.10% 10.96% 3.14%

9/30/1980 14.20% 10.96% 3.24%

10/1/1980 13.90% 10.97% 2.93%

10/3/1980 15.50% 10.98% 4.52%

10/7/1980 12.50% 10.99% 1.51%

10/9/1980 13.25% 11.00% 2.25%

10/9/1980 14.50% 11.00% 3.50%

10/9/1980 14.50% 11.00% 3.50%

10/16/1980 16.10% 11.02% 5.08%

10/17/1980 14.50% 11.03% 3.47%

10/31/1980 13.75% 11.11% 2.64%

10/31/1980 14.25% 11.11% 3.14%

11/4/1980 15.00% 11.12% 3.88%

11/5/1980 13.75% 11.12% 2.63%

11/5/1980 14.00% 11.12% 2.88%

11/8/1980 13.75% 11.14% 2.61%

11/10/1980 14.85% 11.15% 3.70%

11/17/1980 14.00% 11.18% 2.82%

11/18/1980 14.00% 11.19% 2.81%

11/19/1980 13.00% 11.19% 1.81%

11/24/1980 14.00% 11.21% 2.79%

11/26/1980 14.00% 11.21% 2.79%

12/8/1980 14.15% 11.22% 2.93%

12/8/1980 15.10% 11.22% 3.88%

12/9/1980 15.35% 11.22% 4.13%

12/12/1980 15.45% 11.23% 4.22%

12/17/1980 13.25% 11.23% 2.02%

12/18/1980 15.80% 11.23% 4.57%

12/19/1980 14.50% 11.23% 3.27%

12/19/1980 14.64% 11.23% 3.41%

12/22/1980 13.45% 11.23% 2.22%

12/22/1980 15.00% 11.23% 3.77%

12/30/1980 14.50% 11.22% 3.28%

12/30/1980 14.95% 11.22% 3.73%

12/31/1980 13.39% 11.22% 2.17%

1/2/1981 15.25% 11.22% 4.03%

1/7/1981 14.30% 11.21% 3.09%

1/19/1981 15.25% 11.20% 4.05%

1/23/1981 13.10% 11.20% 1.90%

1/23/1981 14.40% 11.20% 3.20%

1/26/1981 15.25% 11.20% 4.05%

1/27/1981 15.00% 11.21% 3.79%

1/31/1981 13.47% 11.22% 2.25%

2/3/1981 15.25% 11.23% 4.02%

2/5/1981 15.75% 11.25% 4.50%

2/11/1981 15.60% 11.28% 4.32%

2/20/1981 15.25% 11.33% 3.92%

3/11/1981 15.40% 11.49% 3.91%

3/12/1981 14.51% 11.50% 3.01%

3/12/1981 16.00% 11.50% 4.50%

3/13/1981 13.02% 11.52% 1.50%

3/18/1981 16.19% 11.55% 4.64%

3/19/1981 13.75% 11.56% 2.19%

3/23/1981 14.30% 11.58% 2.72%

3/25/1981 15.30% 11.60% 3.70%

4/1/1981 14.53% 11.68% 2.85%

4/3/1981 19.10% 11.71% 7.39%

4/9/1981 15.00% 11.78% 3.22%

4/9/1981 15.30% 11.78% 3.52%

4/9/1981 16.50% 11.78% 4.72%

4/9/1981 17.00% 11.78% 5.22%

4/10/1981 13.75% 11.80% 1.95%

4/13/1981 13.57% 11.82% 1.75%

4/15/1981 15.30% 11.85% 3.45%

4/16/1981 13.50% 11.87% 1.63%

4/17/1981 14.10% 11.87% 2.23%

4/21/1981 14.00% 11.90% 2.10%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

4/21/1981 16.80% 11.90% 4.90%

4/24/1981 16.00% 11.95% 4.05%

4/27/1981 12.50% 11.97% 0.53%

4/27/1981 13.61% 11.97% 1.64%

4/29/1981 13.65% 12.00% 1.65%

4/30/1981 13.50% 12.02% 1.48%

5/4/1981 16.22% 12.05% 4.17%

5/5/1981 14.40% 12.07% 2.33%

5/7/1981 16.25% 12.11% 4.14%

5/7/1981 16.27% 12.11% 4.16%

5/8/1981 13.00% 12.13% 0.87%

5/8/1981 16.00% 12.13% 3.87%

5/12/1981 13.50% 12.16% 1.34%

5/15/1981 15.75% 12.22% 3.53%

5/18/1981 14.88% 12.23% 2.65%

5/20/1981 16.00% 12.26% 3.74%

5/21/1981 14.00% 12.27% 1.73%

5/26/1981 14.90% 12.30% 2.60%

5/27/1981 15.00% 12.31% 2.69%

5/29/1981 15.50% 12.34% 3.16%

6/1/1981 16.50% 12.35% 4.15%

6/3/1981 14.67% 12.37% 2.30%

6/5/1981 13.00% 12.39% 0.61%

6/10/1981 16.75% 12.42% 4.33%

6/17/1981 14.40% 12.46% 1.94%

6/18/1981 16.33% 12.47% 3.86%

6/25/1981 14.75% 12.51% 2.24%

6/26/1981 16.00% 12.52% 3.48%

6/30/1981 15.25% 12.54% 2.71%

7/1/1981 15.50% 12.56% 2.94%

7/1/1981 17.50% 12.56% 4.94%

7/10/1981 16.00% 12.62% 3.38%

7/14/1981 16.90% 12.64% 4.26%

7/15/1981 16.00% 12.65% 3.35%

7/17/1981 15.00% 12.67% 2.33%

7/20/1981 15.00% 12.68% 2.32%

7/21/1981 14.00% 12.69% 1.31%

7/28/1981 13.48% 12.74% 0.74%

7/31/1981 13.50% 12.78% 0.72%

7/31/1981 15.00% 12.78% 2.22%

7/31/1981 16.00% 12.78% 3.22%

8/5/1981 15.71% 12.83% 2.88%

8/10/1981 14.50% 12.87% 1.63%

8/11/1981 15.00% 12.88% 2.12%

8/20/1981 13.50% 12.95% 0.55%

8/20/1981 16.50% 12.95% 3.55%

8/24/1981 15.00% 12.97% 2.03%

8/28/1981 15.00% 13.01% 1.99%

9/3/1981 14.50% 13.05% 1.45%

9/10/1981 14.50% 13.11% 1.39%

9/11/1981 16.00% 13.12% 2.88%

9/16/1981 16.00% 13.15% 2.85%

9/17/1981 16.50% 13.16% 3.34%

9/23/1981 15.85% 13.20% 2.65%

9/28/1981 15.50% 13.23% 2.27%

10/9/1981 15.75% 13.33% 2.42%

10/15/1981 16.25% 13.37% 2.88%

10/16/1981 15.50% 13.38% 2.12%

10/16/1981 16.50% 13.38% 3.12%

10/19/1981 14.25% 13.39% 0.86%

10/20/1981 15.25% 13.41% 1.84%

10/20/1981 17.00% 13.41% 3.59%

10/23/1981 16.00% 13.45% 2.55%

10/27/1981 10.00% 13.48% -3.48%

10/29/1981 14.75% 13.51% 1.24%

10/29/1981 16.50% 13.51% 2.99%

11/3/1981 15.17% 13.53% 1.64%

11/5/1981 16.60% 13.55% 3.05%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

11/6/1981 15.17% 13.56% 1.61%

11/24/1981 15.50% 13.61% 1.89%

11/25/1981 15.25% 13.61% 1.64%

11/25/1981 15.35% 13.61% 1.74%

11/25/1981 16.10% 13.61% 2.49%

11/25/1981 16.10% 13.61% 2.49%

12/1/1981 15.70% 13.61% 2.09%

12/1/1981 16.00% 13.61% 2.39%

12/1/1981 16.49% 13.61% 2.88%

12/1/1981 16.50% 13.61% 2.89%

12/4/1981 16.00% 13.61% 2.39%

12/11/1981 16.25% 13.63% 2.62%

12/14/1981 14.00% 13.63% 0.37%

12/15/1981 15.81% 13.63% 2.18%

12/15/1981 16.00% 13.63% 2.37%

12/16/1981 15.25% 13.63% 1.62%

12/17/1981 16.50% 13.63% 2.87%

12/18/1981 15.45% 13.63% 1.82%

12/30/1981 14.25% 13.67% 0.58%

12/30/1981 16.00% 13.67% 2.33%

12/30/1981 16.25% 13.67% 2.58%

12/31/1981 16.15% 13.67% 2.48%

1/4/1982 15.50% 13.67% 1.83%

1/11/1982 14.50% 13.72% 0.78%

1/11/1982 17.00% 13.72% 3.28%

1/13/1982 14.75% 13.74% 1.01%

1/14/1982 15.75% 13.75% 2.00%

1/15/1982 15.00% 13.76% 1.24%

1/15/1982 16.50% 13.76% 2.74%

1/22/1982 16.25% 13.79% 2.46%

1/27/1982 16.84% 13.81% 3.03%

1/28/1982 13.00% 13.81% -0.81%

1/29/1982 15.50% 13.82% 1.68%

2/1/1982 15.85% 13.82% 2.03%

2/3/1982 16.44% 13.84% 2.60%

2/8/1982 15.50% 13.86% 1.64%

2/11/1982 16.00% 13.88% 2.12%

2/11/1982 16.20% 13.88% 2.32%

2/17/1982 15.00% 13.89% 1.11%

2/19/1982 15.17% 13.89% 1.28%

2/26/1982 15.25% 13.89% 1.36%

3/1/1982 15.03% 13.89% 1.14%

3/1/1982 16.00% 13.89% 2.11%

3/3/1982 15.00% 13.88% 1.12%

3/8/1982 17.10% 13.88% 3.22%

3/12/1982 16.25% 13.88% 2.37%

3/17/1982 17.30% 13.88% 3.42%

3/22/1982 15.10% 13.89% 1.21%

3/27/1982 15.40% 13.89% 1.51%

3/30/1982 15.50% 13.90% 1.60%

3/31/1982 17.00% 13.91% 3.09%

4/1/1982 14.70% 13.91% 0.79%

4/1/1982 16.50% 13.91% 2.59%

4/2/1982 15.50% 13.91% 1.59%

4/5/1982 15.50% 13.92% 1.58%

4/8/1982 16.40% 13.93% 2.47%

4/13/1982 14.50% 13.94% 0.56%

4/23/1982 15.75% 13.94% 1.81%

4/27/1982 15.00% 13.94% 1.06%

4/28/1982 15.75% 13.94% 1.81%

4/30/1982 14.70% 13.94% 0.76%

4/30/1982 15.50% 13.94% 1.56%

5/3/1982 16.60% 13.94% 2.66%

5/4/1982 16.00% 13.94% 2.06%

5/14/1982 15.50% 13.92% 1.58%

5/18/1982 15.42% 13.92% 1.50%

5/19/1982 14.69% 13.92% 0.77%

5/20/1982 15.00% 13.91% 1.09%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

5/20/1982 15.10% 13.91% 1.19%

5/20/1982 15.50% 13.91% 1.59%

5/20/1982 16.30% 13.91% 2.39%

5/21/1982 17.75% 13.91% 3.84%

5/27/1982 15.00% 13.89% 1.11%

5/28/1982 15.50% 13.89% 1.61%

5/28/1982 17.00% 13.89% 3.11%

6/1/1982 13.75% 13.89% -0.14%

6/1/1982 16.60% 13.89% 2.71%

6/9/1982 17.86% 13.88% 3.98%

6/14/1982 15.75% 13.88% 1.87%

6/15/1982 14.85% 13.88% 0.97%

6/18/1982 15.50% 13.87% 1.63%

6/21/1982 14.90% 13.87% 1.03%

6/23/1982 16.00% 13.86% 2.14%

6/23/1982 16.17% 13.86% 2.31%

6/24/1982 14.85% 13.86% 0.99%

6/25/1982 14.70% 13.86% 0.84%

7/1/1982 16.00% 13.84% 2.16%

7/2/1982 15.62% 13.84% 1.78%

7/2/1982 17.00% 13.84% 3.16%

7/13/1982 14.00% 13.82% 0.18%

7/13/1982 16.80% 13.82% 2.98%

7/14/1982 15.76% 13.82% 1.94%

7/14/1982 16.02% 13.82% 2.20%

7/19/1982 16.50% 13.80% 2.70%

7/22/1982 14.50% 13.77% 0.73%

7/22/1982 17.00% 13.77% 3.23%

7/27/1982 16.75% 13.75% 3.00%

7/29/1982 16.50% 13.74% 2.76%

8/11/1982 17.50% 13.68% 3.82%

8/18/1982 17.07% 13.63% 3.44%

8/20/1982 15.73% 13.60% 2.13%

8/25/1982 16.00% 13.57% 2.43%

8/26/1982 15.50% 13.56% 1.94%

8/30/1982 15.00% 13.55% 1.45%

9/3/1982 16.20% 13.53% 2.67%

9/8/1982 15.00% 13.52% 1.48%

9/15/1982 13.08% 13.50% -0.42%

9/15/1982 16.25% 13.50% 2.75%

9/16/1982 16.00% 13.50% 2.50%

9/17/1982 15.25% 13.50% 1.75%

9/23/1982 17.17% 13.47% 3.70%

9/24/1982 14.50% 13.46% 1.04%

9/27/1982 15.25% 13.46% 1.79%

10/1/1982 15.50% 13.42% 2.08%

10/15/1982 15.90% 13.32% 2.58%

10/22/1982 15.75% 13.24% 2.51%

10/22/1982 17.15% 13.24% 3.91%

10/29/1982 15.54% 13.16% 2.38%

11/1/1982 15.50% 13.15% 2.35%

11/3/1982 17.20% 13.13% 4.07%

11/4/1982 16.25% 13.11% 3.14%

11/5/1982 16.20% 13.09% 3.11%

11/9/1982 16.00% 13.05% 2.95%

11/23/1982 15.50% 12.89% 2.61%

11/23/1982 15.85% 12.89% 2.96%

11/30/1982 16.50% 12.81% 3.69%

12/1/1982 17.04% 12.79% 4.25%

12/6/1982 15.00% 12.73% 2.27%

12/6/1982 16.35% 12.73% 3.62%

12/10/1982 15.50% 12.66% 2.84%

12/13/1982 16.00% 12.65% 3.35%

12/14/1982 15.30% 12.63% 2.67%

12/14/1982 16.40% 12.63% 3.77%

12/20/1982 16.00% 12.57% 3.43%

12/21/1982 14.75% 12.56% 2.19%

12/21/1982 15.85% 12.56% 3.29%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

12/22/1982 16.25% 12.54% 3.71%

12/22/1982 16.58% 12.54% 4.04%

12/22/1982 16.75% 12.54% 4.21%

12/29/1982 14.90% 12.48% 2.42%

12/29/1982 16.25% 12.48% 3.77%

12/30/1982 16.00% 12.47% 3.53%

12/30/1982 16.35% 12.47% 3.88%

12/30/1982 16.77% 12.47% 4.30%

1/5/1983 17.33% 12.40% 4.93%

1/11/1983 15.90% 12.34% 3.56%

1/12/1983 14.63% 12.33% 2.30%

1/12/1983 15.50% 12.33% 3.17%

1/20/1983 17.75% 12.24% 5.51%

1/21/1983 15.00% 12.22% 2.78%

1/24/1983 14.50% 12.21% 2.29%

1/24/1983 15.50% 12.21% 3.29%

1/25/1983 15.85% 12.19% 3.66%

1/27/1983 16.14% 12.17% 3.97%

2/1/1983 18.50% 12.13% 6.37%

2/4/1983 14.00% 12.10% 1.90%

2/10/1983 15.00% 12.06% 2.94%

2/21/1983 15.50% 11.98% 3.52%

2/22/1983 15.50% 11.97% 3.53%

2/23/1983 15.10% 11.96% 3.14%

2/23/1983 16.00% 11.96% 4.04%

3/2/1983 15.25% 11.89% 3.36%

3/9/1983 15.20% 11.82% 3.38%

3/15/1983 13.00% 11.77% 1.23%

3/18/1983 15.25% 11.73% 3.52%

3/23/1983 15.40% 11.69% 3.71%

3/24/1983 15.00% 11.67% 3.33%

3/29/1983 15.50% 11.63% 3.87%

3/30/1983 16.71% 11.61% 5.10%

3/31/1983 15.00% 11.59% 3.41%

4/4/1983 15.20% 11.58% 3.62%

4/8/1983 15.50% 11.51% 3.99%

4/11/1983 14.81% 11.49% 3.32%

4/19/1983 14.50% 11.38% 3.12%

4/20/1983 16.00% 11.36% 4.64%

4/29/1983 16.00% 11.24% 4.76%

5/1/1983 14.50% 11.24% 3.26%

5/9/1983 15.50% 11.15% 4.35%

5/11/1983 16.46% 11.12% 5.34%

5/12/1983 14.14% 11.11% 3.03%

5/18/1983 15.00% 11.05% 3.95%

5/23/1983 14.90% 11.01% 3.89%

5/23/1983 15.50% 11.01% 4.49%

5/25/1983 15.50% 10.98% 4.52%

5/27/1983 15.00% 10.96% 4.04%

5/31/1983 14.00% 10.95% 3.05%

5/31/1983 15.50% 10.95% 4.55%

6/2/1983 14.50% 10.93% 3.57%

6/17/1983 15.03% 10.84% 4.19%

7/1/1983 14.80% 10.78% 4.02%

7/1/1983 14.90% 10.78% 4.12%

7/8/1983 16.25% 10.76% 5.49%

7/13/1983 13.20% 10.75% 2.45%

7/19/1983 15.00% 10.74% 4.26%

7/19/1983 15.10% 10.74% 4.36%

7/25/1983 16.25% 10.73% 5.52%

7/28/1983 15.90% 10.74% 5.16%

8/3/1983 16.34% 10.75% 5.59%

8/3/1983 16.50% 10.75% 5.75%

8/19/1983 15.00% 10.80% 4.20%

8/22/1983 15.50% 10.80% 4.70%

8/22/1983 16.40% 10.80% 5.60%

8/31/1983 14.75% 10.84% 3.91%

9/7/1983 15.00% 10.86% 4.14%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

9/14/1983 15.78% 10.89% 4.89%

9/16/1983 15.00% 10.90% 4.10%

9/19/1983 14.50% 10.91% 3.59%

9/20/1983 16.50% 10.91% 5.59%

9/28/1983 14.50% 10.94% 3.56%

9/29/1983 15.50% 10.95% 4.55%

9/30/1983 15.25% 10.95% 4.30%

9/30/1983 16.15% 10.95% 5.20%

10/4/1983 14.80% 10.96% 3.84%

10/7/1983 16.00% 10.97% 5.03%

10/13/1983 15.52% 10.99% 4.53%

10/17/1983 15.50% 11.00% 4.50%

10/18/1983 14.50% 11.00% 3.50%

10/19/1983 16.25% 11.01% 5.24%

10/19/1983 16.50% 11.01% 5.49%

10/26/1983 15.00% 11.04% 3.96%

10/27/1983 15.20% 11.04% 4.16%

11/1/1983 16.00% 11.06% 4.94%

11/9/1983 14.90% 11.09% 3.81%

11/10/1983 14.35% 11.10% 3.25%

11/23/1983 16.00% 11.13% 4.87%

11/23/1983 16.15% 11.13% 5.02%

11/30/1983 15.00% 11.14% 3.86%

12/5/1983 15.25% 11.15% 4.10%

12/6/1983 15.07% 11.15% 3.92%

12/8/1983 15.90% 11.16% 4.74%

12/9/1983 14.75% 11.17% 3.58%

12/12/1983 14.50% 11.17% 3.33%

12/15/1983 15.56% 11.19% 4.37%

12/19/1983 14.80% 11.21% 3.59%

12/20/1983 14.69% 11.22% 3.47%

12/20/1983 16.00% 11.22% 4.78%

12/20/1983 16.25% 11.22% 5.03%

12/22/1983 14.75% 11.23% 3.52%

12/22/1983 15.75% 11.23% 4.52%

1/3/1984 14.75% 11.27% 3.48%

1/10/1984 15.90% 11.30% 4.60%

1/12/1984 15.60% 11.31% 4.29%

1/18/1984 13.75% 11.33% 2.42%

1/19/1984 15.90% 11.33% 4.57%

1/30/1984 16.10% 11.37% 4.73%

1/31/1984 15.25% 11.37% 3.88%

2/1/1984 14.80% 11.38% 3.42%

2/6/1984 13.75% 11.40% 2.35%

2/6/1984 14.75% 11.40% 3.35%

2/9/1984 15.25% 11.42% 3.83%

2/15/1984 15.70% 11.44% 4.26%

2/20/1984 15.00% 11.46% 3.54%

2/20/1984 15.00% 11.46% 3.54%

2/22/1984 14.75% 11.47% 3.28%

2/28/1984 14.50% 11.51% 2.99%

3/2/1984 14.25% 11.54% 2.71%

3/20/1984 16.00% 11.64% 4.36%

3/23/1984 15.50% 11.67% 3.83%

3/26/1984 14.71% 11.68% 3.03%

4/2/1984 15.50% 11.71% 3.79%

4/6/1984 14.74% 11.75% 2.99%

4/11/1984 15.72% 11.78% 3.94%

4/17/1984 15.00% 11.81% 3.19%

4/18/1984 16.20% 11.82% 4.38%

4/25/1984 14.64% 11.85% 2.79%

4/30/1984 14.40% 11.87% 2.53%

5/16/1984 14.69% 11.98% 2.71%

5/16/1984 15.00% 11.98% 3.02%

5/22/1984 14.40% 12.02% 2.38%

5/29/1984 15.10% 12.06% 3.04%

6/13/1984 15.25% 12.15% 3.10%

6/15/1984 15.60% 12.17% 3.43%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

6/22/1984 16.25% 12.21% 4.04%

6/29/1984 15.25% 12.26% 2.99%

7/2/1984 13.35% 12.27% 1.08%

7/10/1984 16.00% 12.31% 3.69%

7/12/1984 16.50% 12.32% 4.18%

7/13/1984 16.25% 12.33% 3.92%

7/17/1984 14.14% 12.35% 1.79%

7/18/1984 15.30% 12.36% 2.94%

7/18/1984 15.50% 12.36% 3.14%

7/19/1984 14.30% 12.37% 1.93%

7/24/1984 16.79% 12.39% 4.40%

7/31/1984 16.00% 12.43% 3.57%

8/3/1984 14.25% 12.44% 1.81%

8/17/1984 14.30% 12.49% 1.81%

8/20/1984 15.00% 12.49% 2.51%

8/27/1984 16.30% 12.51% 3.79%

8/31/1984 15.55% 12.52% 3.03%

9/6/1984 16.00% 12.53% 3.47%

9/10/1984 14.75% 12.54% 2.21%

9/13/1984 15.00% 12.55% 2.45%

9/17/1984 17.38% 12.56% 4.82%

9/26/1984 14.50% 12.57% 1.93%

9/28/1984 15.00% 12.57% 2.43%

9/28/1984 16.25% 12.57% 3.68%

10/9/1984 14.75% 12.58% 2.17%

10/12/1984 15.60% 12.59% 3.01%

10/22/1984 15.00% 12.59% 2.41%

10/26/1984 16.40% 12.58% 3.82%

10/31/1984 16.25% 12.58% 3.67%

11/7/1984 15.60% 12.58% 3.02%

11/9/1984 16.00% 12.58% 3.42%

11/14/1984 15.75% 12.58% 3.17%

11/20/1984 15.25% 12.58% 2.67%

11/20/1984 15.92% 12.58% 3.34%

11/23/1984 15.00% 12.58% 2.42%

11/28/1984 16.15% 12.57% 3.58%

12/3/1984 15.80% 12.56% 3.24%

12/4/1984 16.50% 12.56% 3.94%

12/18/1984 16.40% 12.53% 3.87%

12/19/1984 14.75% 12.53% 2.22%

12/19/1984 15.00% 12.53% 2.47%

12/20/1984 16.00% 12.53% 3.47%

12/28/1984 16.00% 12.50% 3.50%

1/3/1985 14.75% 12.49% 2.26%

1/10/1985 15.75% 12.47% 3.28%

1/11/1985 16.30% 12.46% 3.84%

1/23/1985 15.80% 12.43% 3.37%

1/24/1985 15.82% 12.43% 3.39%

1/25/1985 16.75% 12.42% 4.33%

1/30/1985 14.90% 12.40% 2.50%

1/31/1985 14.75% 12.39% 2.36%

2/8/1985 14.47% 12.35% 2.12%

3/1/1985 13.84% 12.31% 1.53%

3/8/1985 16.85% 12.28% 4.57%

3/14/1985 15.50% 12.25% 3.25%

3/15/1985 15.62% 12.25% 3.37%

3/29/1985 15.62% 12.17% 3.45%

4/3/1985 14.60% 12.14% 2.46%

4/9/1985 15.50% 12.11% 3.39%

4/16/1985 15.70% 12.06% 3.64%

4/22/1985 14.00% 12.02% 1.98%

4/26/1985 15.50% 11.98% 3.52%

4/29/1985 15.00% 11.97% 3.03%

5/2/1985 14.68% 11.94% 2.74%

5/8/1985 15.62% 11.89% 3.73%

5/10/1985 16.50% 11.87% 4.63%

5/29/1985 14.61% 11.73% 2.88%

5/31/1985 16.00% 11.71% 4.29%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

6/14/1985 15.50% 11.61% 3.89%

7/9/1985 15.00% 11.45% 3.55%

7/16/1985 14.50% 11.39% 3.11%

7/26/1985 14.50% 11.33% 3.17%

8/2/1985 14.80% 11.29% 3.51%

8/7/1985 15.00% 11.27% 3.73%

8/28/1985 14.25% 11.15% 3.10%

8/28/1985 15.50% 11.15% 4.35%

8/29/1985 14.50% 11.15% 3.35%

9/9/1985 14.60% 11.11% 3.49%

9/9/1985 14.90% 11.11% 3.79%

9/17/1985 14.90% 11.08% 3.82%

9/23/1985 15.00% 11.06% 3.94%

9/27/1985 15.50% 11.05% 4.45%

9/27/1985 15.80% 11.05% 4.75%

10/2/1985 14.00% 11.03% 2.97%

10/2/1985 14.75% 11.03% 3.72%

10/3/1985 15.25% 11.03% 4.22%

10/24/1985 15.40% 10.96% 4.44%

10/24/1985 15.82% 10.96% 4.86%

10/24/1985 15.85% 10.96% 4.89%

10/28/1985 16.00% 10.95% 5.05%

10/29/1985 16.65% 10.94% 5.71%

10/31/1985 15.06% 10.93% 4.13%

11/4/1985 14.50% 10.92% 3.58%

11/7/1985 15.50% 10.90% 4.60%

11/8/1985 14.30% 10.89% 3.41%

12/12/1985 14.75% 10.73% 4.02%

12/18/1985 15.00% 10.69% 4.31%

12/20/1985 14.50% 10.67% 3.83%

12/20/1985 14.50% 10.67% 3.83%

12/20/1985 15.00% 10.67% 4.33%

1/24/1986 15.40% 10.41% 4.99%

1/31/1986 15.00% 10.35% 4.65%

2/5/1986 15.00% 10.32% 4.68%

2/5/1986 15.75% 10.32% 5.43%

2/10/1986 13.30% 10.29% 3.01%

2/11/1986 12.50% 10.28% 2.22%

2/14/1986 14.40% 10.24% 4.16%

2/18/1986 16.00% 10.23% 5.77%

2/24/1986 14.50% 10.18% 4.32%

2/26/1986 14.00% 10.15% 3.85%

3/5/1986 14.90% 10.08% 4.82%

3/11/1986 14.50% 10.02% 4.48%

3/12/1986 13.50% 10.00% 3.50%

3/27/1986 14.10% 9.86% 4.24%

3/31/1986 13.50% 9.84% 3.66%

4/1/1986 14.00% 9.83% 4.17%

4/2/1986 15.50% 9.81% 5.69%

4/4/1986 15.00% 9.78% 5.22%

4/14/1986 13.40% 9.69% 3.71%

4/23/1986 15.00% 9.57% 5.43%

5/16/1986 14.50% 9.32% 5.18%

5/16/1986 14.50% 9.32% 5.18%

5/29/1986 13.90% 9.19% 4.71%

5/30/1986 15.10% 9.18% 5.92%

6/2/1986 12.81% 9.17% 3.64%

6/11/1986 14.00% 9.07% 4.93%

6/24/1986 16.63% 8.94% 7.69%

6/26/1986 12.00% 8.91% 3.09%

6/26/1986 14.75% 8.91% 5.84%

6/30/1986 13.00% 8.87% 4.13%

7/10/1986 14.34% 8.75% 5.59%

7/11/1986 12.75% 8.73% 4.02%

7/14/1986 12.60% 8.71% 3.89%

7/17/1986 12.40% 8.66% 3.74%

7/25/1986 14.25% 8.57% 5.68%

8/6/1986 13.50% 8.44% 5.06%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

8/14/1986 13.50% 8.35% 5.15%

9/16/1986 12.75% 8.06% 4.69%

9/19/1986 13.25% 8.03% 5.22%

10/1/1986 14.00% 7.95% 6.05%

10/3/1986 13.40% 7.93% 5.47%

10/31/1986 13.50% 7.77% 5.73%

11/5/1986 13.00% 7.75% 5.25%

12/3/1986 12.90% 7.58% 5.32%

12/4/1986 14.44% 7.58% 6.86%

12/16/1986 13.60% 7.52% 6.08%

12/22/1986 13.80% 7.51% 6.29%

12/30/1986 13.00% 7.49% 5.51%

1/2/1987 13.00% 7.49% 5.51%

1/12/1987 12.40% 7.47% 4.93%

1/27/1987 12.71% 7.46% 5.25%

3/2/1987 12.47% 7.47% 5.00%

3/3/1987 13.60% 7.47% 6.13%

3/4/1987 12.38% 7.47% 4.91%

3/10/1987 13.50% 7.47% 6.03%

3/13/1987 13.00% 7.47% 5.53%

3/31/1987 13.00% 7.46% 5.54%

4/6/1987 13.00% 7.47% 5.53%

4/14/1987 12.50% 7.49% 5.01%

4/16/1987 14.50% 7.50% 7.00%

4/27/1987 12.00% 7.54% 4.46%

5/5/1987 12.85% 7.58% 5.27%

5/12/1987 12.65% 7.62% 5.03%

5/28/1987 13.50% 7.70% 5.80%

6/15/1987 13.20% 7.78% 5.42%

6/29/1987 15.00% 7.83% 7.17%

6/30/1987 12.50% 7.84% 4.66%

7/8/1987 12.00% 7.86% 4.14%

7/10/1987 12.90% 7.86% 5.04%

7/15/1987 13.50% 7.88% 5.62%

7/16/1987 13.50% 7.88% 5.62%

7/16/1987 15.00% 7.88% 7.12%

7/27/1987 13.00% 7.92% 5.08%

7/27/1987 13.40% 7.92% 5.48%

7/27/1987 13.50% 7.92% 5.58%

7/31/1987 12.98% 7.95% 5.03%

8/26/1987 12.63% 8.06% 4.57%

8/26/1987 12.75% 8.06% 4.69%

8/27/1987 13.25% 8.06% 5.19%

9/9/1987 13.00% 8.14% 4.86%

9/30/1987 12.75% 8.31% 4.44%

9/30/1987 13.00% 8.31% 4.69%

10/2/1987 11.50% 8.33% 3.17%

10/15/1987 13.00% 8.43% 4.57%

11/2/1987 13.00% 8.55% 4.45%

11/19/1987 13.00% 8.64% 4.36%

11/30/1987 12.00% 8.68% 3.32%

12/3/1987 14.20% 8.70% 5.50%

12/15/1987 13.25% 8.77% 4.48%

12/16/1987 13.50% 8.78% 4.72%

12/16/1987 13.72% 8.78% 4.94%

12/17/1987 11.75% 8.79% 2.96%

12/18/1987 13.50% 8.80% 4.70%

12/21/1987 12.01% 8.81% 3.20%

12/22/1987 12.00% 8.81% 3.19%

12/22/1987 12.00% 8.81% 3.19%

12/22/1987 12.75% 8.81% 3.94%

12/22/1987 13.00% 8.81% 4.19%

1/20/1988 13.80% 8.94% 4.86%

1/26/1988 13.90% 8.95% 4.95%

1/29/1988 13.20% 8.96% 4.24%

2/4/1988 12.60% 8.96% 3.64%

3/1/1988 11.56% 8.94% 2.62%

3/23/1988 12.87% 8.92% 3.95%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

3/24/1988 11.24% 8.92% 2.32%

3/30/1988 12.72% 8.92% 3.80%

4/1/1988 12.50% 8.92% 3.58%

4/7/1988 13.25% 8.93% 4.32%

4/25/1988 10.96% 8.96% 2.00%

5/3/1988 12.91% 8.97% 3.94%

5/11/1988 13.50% 8.99% 4.51%

5/16/1988 13.00% 8.99% 4.01%

6/30/1988 12.75% 9.00% 3.75%

7/1/1988 12.75% 8.99% 3.76%

7/20/1988 13.40% 8.96% 4.44%

8/5/1988 12.75% 8.92% 3.83%

8/23/1988 11.70% 8.93% 2.77%

8/29/1988 12.75% 8.94% 3.81%

8/30/1988 13.50% 8.94% 4.56%

9/8/1988 12.60% 8.95% 3.65%

10/13/1988 13.10% 8.93% 4.17%

12/19/1988 13.00% 9.02% 3.98%

12/20/1988 12.25% 9.02% 3.23%

12/20/1988 13.00% 9.02% 3.98%

12/21/1988 12.90% 9.02% 3.88%

12/27/1988 13.00% 9.03% 3.97%

12/28/1988 13.10% 9.03% 4.07%

12/30/1988 13.40% 9.04% 4.36%

1/27/1989 13.00% 9.05% 3.95%

1/31/1989 13.00% 9.05% 3.95%

2/17/1989 13.00% 9.05% 3.95%

2/20/1989 12.40% 9.05% 3.35%

3/1/1989 12.76% 9.05% 3.71%

3/8/1989 13.00% 9.05% 3.95%

3/30/1989 14.00% 9.05% 4.95%

4/5/1989 14.20% 9.05% 5.15%

4/18/1989 13.00% 9.05% 3.95%

5/5/1989 12.40% 9.05% 3.35%

6/2/1989 13.20% 9.00% 4.20%

6/8/1989 13.50% 8.98% 4.52%

6/27/1989 13.25% 8.91% 4.34%

6/30/1989 13.00% 8.90% 4.10%

8/14/1989 12.50% 8.77% 3.73%

9/28/1989 12.25% 8.63% 3.62%

10/24/1989 12.50% 8.54% 3.96%

11/9/1989 13.00% 8.49% 4.51%

12/15/1989 13.00% 8.34% 4.66%

12/20/1989 12.90% 8.32% 4.58%

12/21/1989 12.90% 8.31% 4.59%

12/27/1989 12.50% 8.29% 4.21%

12/27/1989 13.00% 8.29% 4.71%

1/10/1990 12.80% 8.24% 4.56%

1/11/1990 12.90% 8.24% 4.66%

1/17/1990 12.80% 8.22% 4.58%

1/26/1990 12.00% 8.20% 3.80%

2/9/1990 12.10% 8.17% 3.93%

2/24/1990 12.86% 8.15% 4.71%

3/30/1990 12.90% 8.16% 4.74%

4/4/1990 15.76% 8.17% 7.59%

4/12/1990 12.52% 8.18% 4.34%

4/19/1990 12.75% 8.20% 4.55%

5/21/1990 12.10% 8.28% 3.82%

5/29/1990 12.40% 8.30% 4.10%

5/31/1990 12.00% 8.30% 3.70%

6/4/1990 12.90% 8.30% 4.60%

6/6/1990 12.25% 8.31% 3.94%

6/15/1990 13.20% 8.32% 4.88%

6/20/1990 12.92% 8.32% 4.60%

6/27/1990 12.90% 8.33% 4.57%

6/29/1990 12.50% 8.33% 4.17%

7/6/1990 12.10% 8.34% 3.76%

7/6/1990 12.35% 8.34% 4.01%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

8/10/1990 12.55% 8.41% 4.14%

8/16/1990 13.21% 8.43% 4.78%

8/22/1990 13.10% 8.45% 4.65%

8/24/1990 13.00% 8.46% 4.54%

9/26/1990 11.45% 8.59% 2.86%

10/2/1990 13.00% 8.61% 4.39%

10/5/1990 12.84% 8.62% 4.22%

10/19/1990 13.00% 8.67% 4.33%

10/25/1990 12.30% 8.68% 3.62%

11/21/1990 12.70% 8.69% 4.01%

12/13/1990 12.30% 8.67% 3.63%

12/17/1990 12.87% 8.67% 4.20%

12/18/1990 13.10% 8.67% 4.43%

12/19/1990 12.00% 8.66% 3.34%

12/20/1990 12.75% 8.66% 4.09%

12/21/1990 12.50% 8.66% 3.84%

12/27/1990 12.79% 8.66% 4.13%

1/2/1991 13.10% 8.65% 4.45%

1/4/1991 12.50% 8.65% 3.85%

1/15/1991 12.75% 8.64% 4.11%

1/25/1991 11.70% 8.63% 3.07%

2/4/1991 12.50% 8.60% 3.90%

2/7/1991 12.50% 8.59% 3.91%

2/12/1991 13.00% 8.58% 4.43%

2/14/1991 12.72% 8.57% 4.15%

2/22/1991 12.80% 8.55% 4.25%

3/6/1991 13.10% 8.53% 4.57%

3/8/1991 12.30% 8.52% 3.78%

3/8/1991 13.00% 8.52% 4.48%

4/22/1991 13.00% 8.49% 4.51%

5/7/1991 13.50% 8.47% 5.03%

5/13/1991 13.25% 8.47% 4.78%

5/30/1991 12.75% 8.44% 4.31%

6/12/1991 12.00% 8.41% 3.59%

6/25/1991 11.70% 8.39% 3.31%

6/28/1991 12.50% 8.38% 4.12%

7/1/1991 12.00% 8.38% 3.62%

7/3/1991 12.50% 8.37% 4.13%

7/19/1991 12.10% 8.34% 3.76%

8/1/1991 12.90% 8.32% 4.58%

8/16/1991 13.20% 8.29% 4.91%

9/27/1991 12.50% 8.23% 4.27%

9/30/1991 12.25% 8.23% 4.02%

10/17/1991 13.00% 8.20% 4.80%

10/23/1991 12.50% 8.20% 4.30%

10/23/1991 12.55% 8.20% 4.35%

10/31/1991 11.80% 8.19% 3.61%

11/1/1991 12.00% 8.19% 3.81%

11/5/1991 12.25% 8.19% 4.06%

11/12/1991 12.50% 8.18% 4.32%

11/12/1991 13.25% 8.18% 5.07%

11/25/1991 12.40% 8.18% 4.22%

11/26/1991 11.60% 8.18% 3.42%

11/26/1991 12.50% 8.18% 4.32%

11/27/1991 12.10% 8.18% 3.92%

12/18/1991 12.25% 8.15% 4.10%

12/19/1991 12.60% 8.15% 4.45%

12/19/1991 12.80% 8.15% 4.65%

12/20/1991 12.65% 8.14% 4.51%

1/9/1992 12.80% 8.09% 4.71%

1/16/1992 12.75% 8.07% 4.68%

1/21/1992 12.00% 8.06% 3.94%

1/22/1992 13.00% 8.06% 4.94%

1/27/1992 12.65% 8.05% 4.60%

1/31/1992 12.00% 8.04% 3.96%

2/11/1992 12.40% 8.03% 4.37%

2/25/1992 12.50% 8.01% 4.49%

3/16/1992 11.43% 7.98% 3.45%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

3/18/1992 12.28% 7.98% 4.30%

4/2/1992 12.10% 7.95% 4.15%

4/9/1992 11.45% 7.94% 3.51%

4/10/1992 11.50% 7.93% 3.57%

4/14/1992 11.50% 7.93% 3.57%

5/5/1992 11.50% 7.89% 3.61%

5/12/1992 11.87% 7.88% 3.99%

5/12/1992 12.46% 7.88% 4.58%

6/1/1992 12.30% 7.87% 4.43%

6/12/1992 10.90% 7.86% 3.04%

6/26/1992 12.35% 7.85% 4.50%

6/29/1992 11.00% 7.85% 3.15%

6/30/1992 13.00% 7.85% 5.15%

7/13/1992 11.90% 7.84% 4.06%

7/13/1992 13.50% 7.84% 5.66%

7/22/1992 11.20% 7.83% 3.37%

8/3/1992 12.00% 7.81% 4.19%

8/6/1992 12.50% 7.80% 4.70%

9/22/1992 12.00% 7.71% 4.29%

9/28/1992 11.40% 7.71% 3.69%

9/30/1992 11.75% 7.70% 4.05%

10/2/1992 13.00% 7.70% 5.30%

10/12/1992 12.20% 7.70% 4.50%

10/16/1992 13.16% 7.70% 5.46%

10/30/1992 11.75% 7.71% 4.04%

11/3/1992 12.00% 7.71% 4.29%

12/3/1992 11.85% 7.68% 4.17%

12/15/1992 11.00% 7.66% 3.34%

12/16/1992 11.90% 7.66% 4.24%

12/16/1992 12.40% 7.66% 4.74%

12/17/1992 12.00% 7.66% 4.34%

12/22/1992 12.30% 7.65% 4.65%

12/22/1992 12.40% 7.65% 4.75%

12/29/1992 12.25% 7.63% 4.62%

12/30/1992 12.00% 7.63% 4.37%

12/31/1992 11.90% 7.63% 4.27%

1/12/1993 12.00% 7.61% 4.39%

1/21/1993 11.25% 7.59% 3.66%

2/2/1993 11.40% 7.56% 3.84%

2/15/1993 12.30% 7.52% 4.78%

2/24/1993 11.90% 7.49% 4.41%

2/26/1993 11.80% 7.48% 4.32%

2/26/1993 12.20% 7.48% 4.72%

4/23/1993 11.75% 7.29% 4.46%

5/11/1993 11.75% 7.25% 4.50%

5/14/1993 11.50% 7.24% 4.26%

5/25/1993 11.50% 7.23% 4.27%

5/28/1993 11.00% 7.22% 3.78%

6/3/1993 12.00% 7.21% 4.79%

6/16/1993 11.50% 7.19% 4.31%

6/18/1993 12.10% 7.18% 4.92%

6/25/1993 11.67% 7.17% 4.50%

7/21/1993 11.38% 7.10% 4.28%

7/23/1993 10.46% 7.09% 3.37%

8/24/1993 11.50% 6.96% 4.54%

9/21/1993 10.50% 6.81% 3.69%

9/29/1993 11.47% 6.77% 4.70%

9/30/1993 11.60% 6.76% 4.84%

11/2/1993 10.80% 6.60% 4.20%

11/12/1993 12.00% 6.57% 5.43%

11/26/1993 11.00% 6.52% 4.48%

12/14/1993 10.55% 6.48% 4.07%

12/16/1993 10.60% 6.48% 4.12%

12/21/1993 11.30% 6.47% 4.83%

1/4/1994 10.07% 6.44% 3.63%

1/13/1994 11.00% 6.42% 4.58%

1/21/1994 11.00% 6.40% 4.60%

1/28/1994 11.35% 6.39% 4.96%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

2/3/1994 11.40% 6.38% 5.02%

2/17/1994 10.60% 6.36% 4.24%

2/25/1994 11.25% 6.35% 4.90%

2/25/1994 12.00% 6.35% 5.65%

3/1/1994 11.00% 6.35% 4.65%

3/4/1994 11.00% 6.35% 4.65%

4/25/1994 11.00% 6.41% 4.59%

5/10/1994 11.75% 6.45% 5.30%

5/13/1994 10.50% 6.46% 4.04%

6/3/1994 11.00% 6.54% 4.46%

6/27/1994 11.40% 6.65% 4.75%

8/5/1994 12.75% 6.88% 5.87%

10/31/1994 10.00% 7.33% 2.67%

11/9/1994 10.85% 7.39% 3.46%

11/9/1994 10.85% 7.39% 3.46%

11/18/1994 11.20% 7.45% 3.75%

11/22/1994 11.60% 7.47% 4.13%

11/28/1994 11.06% 7.49% 3.57%

12/8/1994 11.50% 7.54% 3.96%

12/8/1994 11.70% 7.54% 4.16%

12/14/1994 10.95% 7.56% 3.39%

12/15/1994 11.50% 7.57% 3.93%

12/19/1994 11.50% 7.58% 3.92%

12/28/1994 12.15% 7.61% 4.54%

1/9/1995 12.28% 7.64% 4.64%

1/31/1995 11.00% 7.69% 3.31%

2/10/1995 12.60% 7.70% 4.90%

2/17/1995 11.90% 7.70% 4.20%

3/9/1995 11.50% 7.71% 3.79%

3/20/1995 12.00% 7.72% 4.28%

3/23/1995 12.81% 7.72% 5.09%

3/29/1995 11.60% 7.72% 3.88%

4/6/1995 11.10% 7.71% 3.39%

4/7/1995 11.00% 7.71% 3.29%

4/19/1995 11.00% 7.70% 3.30%

5/12/1995 11.63% 7.68% 3.95%

5/25/1995 11.20% 7.65% 3.55%

6/9/1995 11.25% 7.60% 3.65%

6/21/1995 12.25% 7.56% 4.69%

6/30/1995 11.10% 7.52% 3.58%

9/11/1995 11.30% 7.20% 4.10%

9/27/1995 11.30% 7.12% 4.18%

9/27/1995 11.50% 7.12% 4.38%

9/27/1995 11.75% 7.12% 4.63%

9/29/1995 11.00% 7.11% 3.89%

11/9/1995 11.38% 6.90% 4.48%

11/9/1995 12.36% 6.90% 5.46%

11/17/1995 11.00% 6.86% 4.14%

12/4/1995 11.35% 6.78% 4.57%

12/11/1995 11.40% 6.74% 4.66%

12/20/1995 11.60% 6.70% 4.90%

12/27/1995 12.00% 6.66% 5.34%

2/5/1996 12.25% 6.48% 5.77%

3/29/1996 10.67% 6.42% 4.25%

4/8/1996 11.00% 6.42% 4.58%

4/11/1996 12.59% 6.43% 6.16%

4/11/1996 12.59% 6.43% 6.16%

4/24/1996 11.25% 6.43% 4.82%

4/30/1996 11.00% 6.43% 4.57%

5/13/1996 11.00% 6.44% 4.56%

5/23/1996 11.25% 6.43% 4.82%

6/25/1996 11.25% 6.48% 4.77%

6/27/1996 11.20% 6.48% 4.72%

8/12/1996 10.40% 6.57% 3.83%

9/27/1996 11.00% 6.71% 4.29%

10/16/1996 12.25% 6.76% 5.49%

11/5/1996 11.00% 6.81% 4.19%

11/26/1996 11.30% 6.83% 4.47%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

12/18/1996 11.75% 6.83% 4.92%

12/31/1996 11.50% 6.83% 4.67%

1/3/1997 10.70% 6.83% 3.87%

2/13/1997 11.80% 6.82% 4.98%

2/20/1997 11.80% 6.82% 4.98%

3/31/1997 10.02% 6.80% 3.22%

4/2/1997 11.65% 6.80% 4.85%

4/28/1997 11.50% 6.81% 4.69%

4/29/1997 11.70% 6.81% 4.89%

7/17/1997 12.00% 6.77% 5.23%

12/12/1997 11.00% 6.60% 4.40%

12/23/1997 11.12% 6.57% 4.55%

2/2/1998 12.75% 6.39% 6.36%

3/2/1998 11.25% 6.29% 4.96%

3/6/1998 10.75% 6.27% 4.48%

3/20/1998 10.50% 6.22% 4.28%

4/30/1998 12.20% 6.12% 6.08%

7/10/1998 11.40% 5.94% 5.46%

9/15/1998 11.90% 5.78% 6.12%

11/30/1998 12.60% 5.58% 7.02%

12/10/1998 12.20% 5.54% 6.66%

12/17/1998 12.10% 5.52% 6.58%

2/5/1999 10.30% 5.38% 4.92%

3/4/1999 10.50% 5.34% 5.16%

4/6/1999 10.94% 5.32% 5.62%

7/29/1999 10.75% 5.52% 5.23%

9/23/1999 10.75% 5.70% 5.05%

11/17/1999 11.10% 5.90% 5.20%

1/7/2000 11.50% 6.05% 5.45%

1/7/2000 11.50% 6.05% 5.45%

2/17/2000 10.60% 6.17% 4.43%

3/28/2000 11.25% 6.20% 5.05%

5/24/2000 11.00% 6.18% 4.82%

7/18/2000 12.20% 6.16% 6.04%

9/29/2000 11.16% 6.03% 5.13%

11/28/2000 12.90% 5.89% 7.01%

11/30/2000 12.10% 5.88% 6.22%

1/23/2001 11.25% 5.79% 5.46%

2/8/2001 11.50% 5.77% 5.73%

5/8/2001 10.75% 5.62% 5.13%

6/26/2001 11.00% 5.62% 5.38%

7/25/2001 11.02% 5.60% 5.42%

7/25/2001 11.02% 5.60% 5.42%

7/31/2001 11.00% 5.59% 5.41%

8/31/2001 10.50% 5.56% 4.94%

9/7/2001 10.75% 5.55% 5.20%

9/10/2001 11.00% 5.55% 5.45%

9/20/2001 10.00% 5.55% 4.45%

10/24/2001 10.30% 5.54% 4.76%

11/28/2001 10.60% 5.49% 5.11%

12/3/2001 12.88% 5.49% 7.39%

12/20/2001 12.50% 5.50% 7.00%

1/22/2002 10.00% 5.50% 4.50%

3/27/2002 10.10% 5.45% 4.65%

4/22/2002 11.80% 5.45% 6.35%

5/28/2002 10.17% 5.46% 4.71%

6/10/2002 12.00% 5.47% 6.53%

6/18/2002 11.16% 5.48% 5.68%

6/20/2002 11.00% 5.48% 5.52%

6/20/2002 12.30% 5.48% 6.82%

7/15/2002 11.00% 5.48% 5.52%

9/12/2002 12.30% 5.45% 6.85%

9/26/2002 10.45% 5.41% 5.04%

12/4/2002 11.55% 5.29% 6.26%

12/13/2002 11.75% 5.27% 6.48%

12/20/2002 11.40% 5.25% 6.15%

1/8/2003 11.10% 5.19% 5.91%

1/31/2003 12.45% 5.13% 7.32%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

2/28/2003 12.30% 5.05% 7.25%

3/6/2003 10.75% 5.03% 5.72%

3/7/2003 9.96% 5.02% 4.94%

3/20/2003 12.00% 4.98% 7.02%

4/3/2003 12.00% 4.96% 7.04%

4/15/2003 11.15% 4.94% 6.21%

6/25/2003 10.75% 4.79% 5.96%

6/26/2003 10.75% 4.79% 5.96%

7/9/2003 9.75% 4.79% 4.96%

7/16/2003 9.75% 4.79% 4.96%

7/25/2003 9.50% 4.80% 4.70%

8/26/2003 10.50% 4.83% 5.67%

12/17/2003 9.85% 4.94% 4.91%

12/17/2003 10.70% 4.94% 5.76%

12/18/2003 11.50% 4.94% 6.56%

12/19/2003 12.00% 4.94% 7.06%

12/19/2003 12.00% 4.94% 7.06%

12/23/2003 10.50% 4.94% 5.56%

1/13/2004 12.00% 4.95% 7.05%

3/2/2004 10.75% 4.99% 5.76%

3/26/2004 10.25% 5.02% 5.23%

4/5/2004 11.25% 5.03% 6.22%

5/18/2004 10.50% 5.07% 5.43%

5/25/2004 10.25% 5.08% 5.17%

5/27/2004 10.25% 5.08% 5.17%

6/2/2004 11.22% 5.08% 6.14%

6/30/2004 10.50% 5.10% 5.40%

6/30/2004 10.50% 5.10% 5.40%

7/16/2004 11.60% 5.11% 6.49%

8/25/2004 10.25% 5.10% 5.15%

9/9/2004 10.40% 5.10% 5.30%

11/9/2004 10.50% 5.07% 5.43%

11/23/2004 11.00% 5.06% 5.94%

12/14/2004 10.97% 5.07% 5.90%

12/21/2004 11.25% 5.07% 6.18%

12/21/2004 11.50% 5.07% 6.43%

12/22/2004 10.70% 5.07% 5.63%

12/22/2004 11.50% 5.07% 6.43%

12/29/2004 9.85% 5.07% 4.78%

1/6/2005 10.70% 5.08% 5.62%

2/18/2005 10.30% 4.98% 5.32%

2/25/2005 10.50% 4.96% 5.54%

3/10/2005 11.00% 4.93% 6.07%

3/24/2005 10.30% 4.90% 5.40%

4/4/2005 10.00% 4.88% 5.12%

4/7/2005 10.25% 4.87% 5.38%

5/18/2005 10.25% 4.78% 5.47%

5/25/2005 10.75% 4.76% 5.99%

5/26/2005 9.75% 4.76% 4.99%

6/1/2005 9.75% 4.75% 5.00%

7/19/2005 11.50% 4.64% 6.86%

8/5/2005 11.75% 4.62% 7.13%

8/15/2005 10.13% 4.61% 5.52%

9/28/2005 10.00% 4.54% 5.46%

10/4/2005 10.75% 4.54% 6.21%

12/12/2005 11.00% 4.55% 6.45%

12/13/2005 10.75% 4.55% 6.20%

12/21/2005 10.29% 4.54% 5.75%

12/21/2005 10.40% 4.54% 5.86%

12/22/2005 11.00% 4.54% 6.46%

12/22/2005 11.15% 4.54% 6.61%

12/28/2005 10.00% 4.54% 5.46%

12/28/2005 10.00% 4.54% 5.46%

1/5/2006 11.00% 4.53% 6.47%

1/27/2006 9.75% 4.52% 5.23%

3/3/2006 10.39% 4.53% 5.86%

4/17/2006 10.20% 4.61% 5.59%

4/26/2006 10.60% 4.64% 5.96%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

5/17/2006 11.60% 4.69% 6.91%

6/6/2006 10.00% 4.74% 5.26%

6/27/2006 10.75% 4.80% 5.95%

7/6/2006 10.20% 4.83% 5.37%

7/24/2006 9.60% 4.86% 4.74%

7/26/2006 10.50% 4.86% 5.64%

7/28/2006 10.05% 4.86% 5.19%

8/23/2006 9.55% 4.89% 4.66%

9/1/2006 10.54% 4.90% 5.64%

9/14/2006 10.00% 4.91% 5.09%

10/6/2006 9.67% 4.92% 4.75%

11/21/2006 10.08% 4.95% 5.13%

11/21/2006 10.08% 4.95% 5.13%

11/21/2006 10.12% 4.95% 5.17%

12/1/2006 10.25% 4.95% 5.30%

12/1/2006 10.50% 4.95% 5.55%

12/7/2006 10.75% 4.95% 5.80%

12/21/2006 10.90% 4.95% 5.95%

12/21/2006 11.25% 4.95% 6.30%

12/22/2006 10.25% 4.95% 5.30%

1/5/2007 10.00% 4.95% 5.05%

1/11/2007 10.10% 4.95% 5.15%

1/11/2007 10.10% 4.95% 5.15%

1/11/2007 10.90% 4.95% 5.95%

1/12/2007 10.10% 4.95% 5.15%

1/13/2007 10.40% 4.95% 5.45%

1/19/2007 10.80% 4.94% 5.86%

3/21/2007 11.35% 4.87% 6.48%

3/22/2007 9.75% 4.86% 4.89%

5/15/2007 10.00% 4.81% 5.19%

5/17/2007 10.25% 4.81% 5.44%

5/17/2007 10.25% 4.81% 5.44%

5/22/2007 10.20% 4.80% 5.40%

5/22/2007 10.50% 4.80% 5.70%

5/23/2007 10.70% 4.80% 5.90%

5/25/2007 9.67% 4.80% 4.87%

6/15/2007 9.90% 4.82% 5.08%

6/21/2007 10.20% 4.83% 5.37%

6/22/2007 10.50% 4.83% 5.67%

6/28/2007 10.75% 4.84% 5.91%

7/12/2007 9.67% 4.86% 4.81%

7/19/2007 10.00% 4.87% 5.13%

7/19/2007 10.00% 4.87% 5.13%

8/15/2007 10.40% 4.88% 5.52%

10/9/2007 10.00% 4.91% 5.09%

10/17/2007 9.10% 4.91% 4.19%

10/31/2007 9.96% 4.90% 5.06%

11/29/2007 10.90% 4.87% 6.03%

12/6/2007 10.75% 4.86% 5.89%

12/13/2007 9.96% 4.86% 5.10%

12/14/2007 10.70% 4.86% 5.84%

12/14/2007 10.80% 4.86% 5.94%

12/19/2007 10.20% 4.86% 5.34%

12/20/2007 10.20% 4.85% 5.35%

12/20/2007 11.00% 4.85% 6.15%

12/28/2007 10.25% 4.85% 5.40%

12/31/2007 11.25% 4.85% 6.40%

1/8/2008 10.75% 4.83% 5.92%

1/17/2008 10.75% 4.81% 5.94%

1/28/2008 9.40% 4.80% 4.60%

1/30/2008 10.00% 4.79% 5.21%

1/31/2008 10.71% 4.79% 5.92%

2/29/2008 10.25% 4.75% 5.50%

3/12/2008 10.25% 4.73% 5.52%

3/25/2008 9.10% 4.68% 4.42%

4/22/2008 10.25% 4.60% 5.65%

4/24/2008 10.10% 4.60% 5.50%

5/1/2008 10.70% 4.59% 6.11%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

5/19/2008 11.00% 4.56% 6.44%

5/27/2008 10.00% 4.55% 5.45%

6/10/2008 10.70% 4.54% 6.16%

6/27/2008 10.50% 4.54% 5.96%

6/27/2008 11.04% 4.54% 6.50%

7/10/2008 10.43% 4.52% 5.91%

7/16/2008 9.40% 4.52% 4.88%

7/30/2008 10.80% 4.51% 6.29%

7/31/2008 10.70% 4.51% 6.19%

8/11/2008 10.25% 4.51% 5.74%

8/26/2008 10.18% 4.50% 5.68%

9/10/2008 10.30% 4.50% 5.80%

9/24/2008 10.65% 4.48% 6.17%

9/24/2008 10.65% 4.48% 6.17%

9/24/2008 10.65% 4.48% 6.17%

9/30/2008 10.20% 4.48% 5.72%

10/8/2008 10.15% 4.46% 5.69%

11/13/2008 10.55% 4.45% 6.10%

11/17/2008 10.20% 4.44% 5.76%

12/1/2008 10.25% 4.40% 5.85%

12/23/2008 11.00% 4.27% 6.73%

12/29/2008 10.00% 4.24% 5.76%

12/29/2008 10.20% 4.24% 5.96%

12/31/2008 10.75% 4.22% 6.53%

1/14/2009 10.50% 4.15% 6.35%

1/21/2009 10.50% 4.12% 6.38%

1/21/2009 10.50% 4.12% 6.38%

1/21/2009 10.50% 4.12% 6.38%

1/27/2009 10.76% 4.09% 6.67%

1/30/2009 10.50% 4.08% 6.42%

2/4/2009 8.75% 4.06% 4.69%

3/4/2009 10.50% 3.96% 6.54%

3/12/2009 11.50% 3.93% 7.57%

4/2/2009 11.10% 3.85% 7.25%

4/21/2009 10.61% 3.80% 6.81%

4/24/2009 10.00% 3.79% 6.21%

4/30/2009 11.25% 3.78% 7.47%

5/4/2009 10.74% 3.77% 6.97%

5/20/2009 10.25% 3.74% 6.51%

5/28/2009 10.50% 3.74% 6.76%

6/22/2009 10.00% 3.76% 6.24%

6/24/2009 10.80% 3.77% 7.03%

7/8/2009 10.63% 3.77% 6.86%

7/17/2009 10.50% 3.78% 6.72%

8/31/2009 10.25% 3.82% 6.43%

10/14/2009 10.70% 4.01% 6.69%

10/23/2009 10.88% 4.06% 6.82%

11/2/2009 10.70% 4.09% 6.61%

11/3/2009 10.70% 4.10% 6.60%

11/24/2009 10.25% 4.15% 6.10%

11/25/2009 10.75% 4.16% 6.59%

11/30/2009 10.35% 4.17% 6.18%

12/3/2009 10.50% 4.18% 6.32%

12/7/2009 10.70% 4.18% 6.52%

12/16/2009 10.90% 4.21% 6.69%

12/16/2009 11.00% 4.21% 6.79%

12/18/2009 10.40% 4.22% 6.18%

12/18/2009 10.40% 4.22% 6.18%

12/22/2009 10.20% 4.23% 5.97%

12/22/2009 10.40% 4.23% 6.17%

12/22/2009 10.40% 4.23% 6.17%

12/30/2009 10.00% 4.26% 5.74%

1/4/2010 10.80% 4.28% 6.52%

1/11/2010 11.00% 4.30% 6.70%

1/26/2010 10.13% 4.35% 5.78%

1/27/2010 10.40% 4.35% 6.05%

1/27/2010 10.40% 4.35% 6.05%

1/27/2010 10.70% 4.35% 6.35%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

2/9/2010 9.80% 4.38% 5.42%

2/18/2010 10.60% 4.40% 6.20%

2/24/2010 10.18% 4.41% 5.77%

3/2/2010 9.63% 4.41% 5.22%

3/4/2010 10.50% 4.41% 6.09%

3/5/2010 10.50% 4.41% 6.09%

3/11/2010 11.90% 4.42% 7.48%

3/17/2010 10.00% 4.41% 5.59%

3/25/2010 10.15% 4.42% 5.73%

4/2/2010 10.10% 4.43% 5.67%

4/27/2010 10.00% 4.46% 5.54%

4/29/2010 9.90% 4.46% 5.44%

4/29/2010 10.06% 4.46% 5.60%

4/29/2010 10.26% 4.46% 5.80%

5/12/2010 10.30% 4.45% 5.85%

5/12/2010 10.30% 4.45% 5.85%

5/28/2010 10.10% 4.44% 5.66%

5/28/2010 10.20% 4.44% 5.76%

6/7/2010 10.30% 4.44% 5.86%

6/16/2010 10.00% 4.44% 5.56%

6/28/2010 9.67% 4.43% 5.24%

6/28/2010 10.50% 4.43% 6.07%

6/30/2010 9.40% 4.43% 4.97%

7/1/2010 10.25% 4.43% 5.82%

7/15/2010 10.53% 4.43% 6.10%

7/15/2010 10.70% 4.43% 6.27%

7/30/2010 10.70% 4.41% 6.29%

8/4/2010 10.50% 4.41% 6.09%

8/6/2010 9.83% 4.41% 5.42%

8/25/2010 9.90% 4.37% 5.53%

9/3/2010 10.60% 4.35% 6.25%

9/14/2010 10.70% 4.33% 6.37%

9/16/2010 10.00% 4.33% 5.67%

9/16/2010 10.00% 4.33% 5.67%

9/30/2010 9.75% 4.29% 5.46%

10/14/2010 10.35% 4.24% 6.11%

10/28/2010 10.70% 4.21% 6.49%

11/2/2010 10.38% 4.20% 6.18%

11/4/2010 10.70% 4.20% 6.50%

11/19/2010 10.20% 4.18% 6.02%

11/22/2010 10.00% 4.18% 5.82%

12/1/2010 10.13% 4.16% 5.97%

12/6/2010 9.86% 4.15% 5.71%

12/9/2010 10.25% 4.15% 6.10%

12/13/2010 10.70% 4.15% 6.55%

12/14/2010 10.13% 4.15% 5.98%

12/15/2010 10.44% 4.15% 6.29%

12/17/2010 10.00% 4.15% 5.85%

12/20/2010 10.60% 4.15% 6.45%

12/21/2010 10.30% 4.14% 6.16%

12/27/2010 9.90% 4.14% 5.76%

12/29/2010 11.15% 4.14% 7.01%

1/5/2011 10.15% 4.13% 6.02%

1/12/2011 10.30% 4.12% 6.18%

1/13/2011 10.30% 4.12% 6.18%

1/18/2011 10.00% 4.12% 5.88%

1/20/2011 9.30% 4.12% 5.18%

1/20/2011 10.13% 4.12% 6.01%

1/31/2011 9.60% 4.12% 5.48%

2/3/2011 10.00% 4.12% 5.88%

2/25/2011 10.00% 4.14% 5.86%

3/25/2011 9.80% 4.18% 5.62%

3/30/2011 10.00% 4.18% 5.82%

4/12/2011 10.00% 4.21% 5.79%

4/25/2011 10.74% 4.23% 6.51%

4/26/2011 9.67% 4.23% 5.44%

4/27/2011 10.40% 4.24% 6.16%

5/4/2011 10.00% 4.24% 5.76%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

5/4/2011 10.00% 4.24% 5.76%

5/24/2011 10.50% 4.27% 6.23%

6/8/2011 10.75% 4.30% 6.45%

6/16/2011 9.20% 4.32% 4.88%

6/17/2011 9.95% 4.32% 5.63%

7/13/2011 10.20% 4.36% 5.84%

8/1/2011 9.20% 4.39% 4.81%

8/8/2011 10.00% 4.38% 5.62%

8/11/2011 10.00% 4.38% 5.62%

8/12/2011 10.35% 4.37% 5.98%

8/19/2011 10.25% 4.36% 5.89%

9/2/2011 12.88% 4.32% 8.56%

9/22/2011 10.00% 4.24% 5.76%

10/12/2011 10.30% 4.14% 6.16%

10/20/2011 10.50% 4.10% 6.40%

11/30/2011 10.90% 3.87% 7.03%

11/30/2011 10.90% 3.87% 7.03%

12/14/2011 10.00% 3.80% 6.20%

12/14/2011 10.30% 3.80% 6.50%

12/20/2011 10.20% 3.76% 6.44%

12/21/2011 10.20% 3.76% 6.44%

12/22/2011 9.90% 3.75% 6.15%

12/22/2011 10.40% 3.75% 6.65%

12/23/2011 10.19% 3.74% 6.45%

1/25/2012 10.50% 3.57% 6.93%

1/27/2012 10.50% 3.56% 6.94%

2/15/2012 10.20% 3.47% 6.73%

2/23/2012 9.90% 3.44% 6.46%

2/27/2012 10.25% 3.43% 6.82%

2/29/2012 10.40% 3.41% 6.99%

3/29/2012 10.37% 3.32% 7.05%

4/4/2012 10.00% 3.30% 6.70%

4/26/2012 10.00% 3.21% 6.79%

5/2/2012 10.00% 3.18% 6.82%

5/7/2012 9.80% 3.17% 6.63%

5/15/2012 10.00% 3.14% 6.86%

5/29/2012 10.05% 3.11% 6.94%

6/7/2012 10.30% 3.08% 7.22%

6/14/2012 9.40% 3.06% 6.34%

6/15/2012 10.40% 3.06% 7.34%

6/18/2012 9.60% 3.06% 6.54%

6/19/2012 9.25% 3.05% 6.20%

6/26/2012 10.10% 3.04% 7.06%

6/29/2012 10.00% 3.04% 6.96%

7/9/2012 10.20% 3.03% 7.17%

7/16/2012 9.80% 3.02% 6.78%

7/20/2012 9.31% 3.01% 6.30%

7/20/2012 9.81% 3.01% 6.80%

9/13/2012 9.80% 2.94% 6.86%

9/19/2012 9.80% 2.94% 6.86%

9/19/2012 10.05% 2.94% 7.11%

9/26/2012 9.50% 2.94% 6.56%

10/12/2012 9.60% 2.93% 6.67%

10/23/2012 9.75% 2.93% 6.82%

10/24/2012 10.30% 2.93% 7.37%

11/9/2012 10.30% 2.92% 7.38%

11/28/2012 10.40% 2.90% 7.50%

11/29/2012 9.75% 2.89% 6.86%

11/29/2012 9.88% 2.89% 6.99%

12/5/2012 9.71% 2.89% 6.82%

12/5/2012 10.40% 2.89% 7.51%

12/12/2012 9.80% 2.88% 6.92%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

12/13/2012 9.50% 2.88% 6.62%

12/13/2012 10.50% 2.88% 7.62%

12/14/2012 10.40% 2.88% 7.52%

12/19/2012 9.71% 2.87% 6.84%

12/19/2012 10.25% 2.87% 7.38%

12/20/2012 9.50% 2.87% 6.63%

12/20/2012 9.80% 2.87% 6.93%

12/20/2012 10.25% 2.87% 7.38%

12/20/2012 10.25% 2.87% 7.38%

12/20/2012 10.30% 2.87% 7.43%

12/20/2012 10.40% 2.87% 7.53%

12/20/2012 10.45% 2.87% 7.58%

12/21/2012 10.20% 2.87% 7.33%

12/26/2012 9.80% 2.86% 6.94%

1/9/2013 9.70% 2.85% 6.85%

1/9/2013 9.70% 2.85% 6.85%

1/9/2013 9.70% 2.85% 6.85%

1/16/2013 9.60% 2.84% 6.76%

1/16/2013 9.60% 2.84% 6.76%

2/13/2013 10.20% 2.84% 7.36%

2/22/2013 9.75% 2.85% 6.90%

2/27/2013 10.00% 2.86% 7.14%

3/14/2013 9.30% 2.88% 6.42%

3/27/2013 9.80% 2.90% 6.90%

5/1/2013 9.84% 2.94% 6.90%

5/15/2013 10.30% 2.96% 7.34%

5/30/2013 10.20% 2.98% 7.22%

5/31/2013 9.00% 2.98% 6.02%

6/11/2013 10.00% 3.00% 7.00%

6/21/2013 9.75% 3.02% 6.73%

6/25/2013 9.80% 3.03% 6.77%

7/12/2013 9.36% 3.07% 6.29%

8/8/2013 9.83% 3.14% 6.69%

8/14/2013 9.15% 3.16% 5.99%

9/11/2013 10.20% 3.26% 6.94%

9/11/2013 10.25% 3.26% 6.99%

9/24/2013 10.20% 3.31% 6.89%

10/3/2013 9.65% 3.33% 6.32%

11/6/2013 10.20% 3.41% 6.79%

11/21/2013 10.00% 3.44% 6.56%

11/26/2013 10.00% 3.45% 6.55%

12/3/2013 10.25% 3.47% 6.78%

12/4/2013 9.50% 3.47% 6.03%

12/5/2013 10.20% 3.48% 6.72%

12/9/2013 8.72% 3.48% 5.24%

12/9/2013 9.75% 3.48% 6.27%

12/13/2013 9.75% 3.50% 6.25%

12/16/2013 9.95% 3.50% 6.45%

12/16/2013 9.95% 3.50% 6.45%

12/16/2013 10.12% 3.50% 6.62%

12/17/2013 9.50% 3.51% 5.99%

12/17/2013 10.95% 3.51% 7.44%

12/18/2013 8.72% 3.51% 5.21%

12/18/2013 9.80% 3.51% 6.29%

12/19/2013 10.15% 3.51% 6.64%

12/30/2013 9.50% 3.54% 5.96%

2/20/2014 9.20% 3.68% 5.52%

2/26/2014 9.75% 3.69% 6.06%

3/17/2014 9.55% 3.72% 5.83%

3/26/2014 9.40% 3.73% 5.67%

3/26/2014 9.96% 3.73% 6.23%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

4/2/2014 9.70% 3.73% 5.97%

5/16/2014 9.80% 3.70% 6.10%

5/30/2014 9.70% 3.68% 6.02%

6/6/2014 10.40% 3.67% 6.73%

6/30/2014 9.55% 3.64% 5.91%

7/2/2014 9.62% 3.64% 5.98%

7/10/2014 9.95% 3.63% 6.32%

7/23/2014 9.75% 3.61% 6.14%

7/29/2014 9.45% 3.60% 5.85%

7/31/2014 9.90% 3.60% 6.30%

8/20/2014 9.75% 3.57% 6.18%

8/25/2014 9.60% 3.56% 6.04%

8/29/2014 9.80% 3.54% 6.26%

9/11/2014 9.60% 3.51% 6.09%

9/15/2014 10.25% 3.51% 6.74%

10/9/2014 9.80% 3.45% 6.35%

11/6/2014 9.56% 3.37% 6.19%

11/6/2014 10.20% 3.37% 6.83%

11/14/2014 10.20% 3.35% 6.85%

11/26/2014 9.70% 3.33% 6.37%

11/26/2014 10.20% 3.33% 6.87%

12/4/2014 9.68% 3.31% 6.37%

12/10/2014 9.25% 3.29% 5.96%

12/10/2014 9.25% 3.29% 5.96%

12/11/2014 10.07% 3.29% 6.78%

12/12/2014 10.20% 3.28% 6.92%

12/17/2014 9.17% 3.27% 5.90%

12/18/2014 9.83% 3.26% 6.57%

1/23/2015 9.50% 3.14% 6.36%

2/24/2015 9.83% 3.04% 6.79%

3/18/2015 9.75% 2.98% 6.77%

3/25/2015 9.50% 2.96% 6.54%

3/26/2015 9.72% 2.95% 6.77%

4/23/2015 10.20% 2.87% 7.33%

4/29/2015 9.53% 2.86% 6.67%

5/1/2015 9.60% 2.85% 6.75%

5/26/2015 9.75% 2.83% 6.92%

6/17/2015 9.00% 2.82% 6.18%

6/17/2015 9.00% 2.82% 6.18%

9/2/2015 9.50% 2.79% 6.71%

9/10/2015 9.30% 2.79% 6.51%

10/15/2015 9.00% 2.81% 6.19%

11/19/2015 10.00% 2.88% 7.12%

11/19/2015 10.30% 2.88% 7.42%

12/3/2015 10.00% 2.90% 7.10%

12/9/2015 9.14% 2.90% 6.24%

12/9/2015 9.14% 2.90% 6.24%

12/11/2015 10.30% 2.90% 7.40%

12/15/2015 9.60% 2.91% 6.69%

12/17/2015 9.70% 2.91% 6.79%

12/18/2015 9.50% 2.91% 6.59%

12/30/2015 9.50% 2.93% 6.57%

1/6/2016 9.50% 2.94% 6.56%

2/23/2016 9.75% 2.94% 6.81%

3/16/2016 9.85% 2.91% 6.94%

4/29/2016 9.80% 2.83% 6.97%

6/3/2016 9.75% 2.80% 6.95%

6/8/2016 9.48% 2.80% 6.68%

6/15/2016 9.00% 2.78% 6.22%

6/15/2016 9.00% 2.78% 6.22%

7/18/2016 9.98% 2.71% 7.27%

Case No. PU-17-



[6] [7] [8] [9]

Date of

Electric Rate

Case

Return on

Equity

30-Year

Treasury

Yield

Risk

Premium

8/9/2016 9.85% 2.66% 7.19%

8/18/2016 9.50% 2.63% 6.87%

8/24/2016 9.75% 2.62% 7.13%

9/1/2016 9.50% 2.59% 6.91%

9/8/2016 10.00% 2.58% 7.42%

9/28/2016 9.58% 2.54% 7.04%

9/30/2016 9.90% 2.53% 7.37%

11/9/2016 9.80% 2.48% 7.32%

11/10/2016 9.50% 2.48% 7.02%

11/15/2016 9.55% 2.49% 7.06%

11/18/2016 10.00% 2.50% 7.50%

11/29/2016 10.55% 2.51% 8.04%

12/1/2016 10.00% 2.51% 7.49%

12/6/2016 8.64% 2.52% 6.12%

12/6/2016 8.64% 2.52% 6.12%

12/7/2016 10.10% 2.52% 7.58%

12/12/2016 9.60% 2.53% 7.07%

12/14/2016 9.10% 2.53% 6.57%

12/19/2016 9.00% 2.54% 6.46%

12/19/2016 9.37% 2.54% 6.83%

12/22/2016 9.60% 2.55% 7.05%

12/22/2016 9.90% 2.55% 7.35%

12/28/2016 9.50% 2.55% 6.95%

1/18/2017 9.45% 2.58% 6.87%

1/24/2017 9.00% 2.59% 6.41%

1/31/2017 10.10% 2.60% 7.50%

2/15/2017 9.60% 2.62% 6.98%

2/22/2017 9.60% 2.64% 6.96%

2/24/2017 9.75% 2.64% 7.11%

2/28/2017 10.10% 2.64% 7.46%

3/2/2017 9.41% 2.65% 6.76%

3/20/2017 9.50% 2.68% 6.82%

4/4/2017 10.25% 2.71% 7.54%

4/12/2017 9.40% 2.74% 6.66%

4/20/2017 9.50% 2.76% 6.74%

5/3/2017 9.50% 2.79% 6.71%

5/11/2017 9.20% 2.81% 6.39%

5/18/2017 9.50% 2.83% 6.67%

5/23/2017 9.70% 2.84% 6.86%

6/16/2017 9.65% 2.89% 6.76%

6/22/2017 9.70% 2.90% 6.80%

6/22/2017 9.70% 2.90% 6.80%

7/24/2017 9.50% 2.95% 6.55%

8/15/2017 10.00% 2.97% 7.03%

9/22/2017 9.60% 2.93% 6.67%

9/28/2017 9.80% 2.92% 6.88%

# of Cases: 1522

Average: 4.58%

Case No. PU-17-


Page 1 of 1

Company Ticker

5-Year CAPEX /

2016 Net Plant

[1]

ALLETE, Inc. ALE 31.29%

Alliant Energy Corporation LNT 67.33%

Black Hills Corporation BKH 39.54%

El Paso Electric Company EE 47.81%

Hawaiian Electric Industries, Inc. HE 47.43%

IDACORP, Inc. IDA 40.37%

Northwestern Corporation NWE 38.28%

OGE Energy Corp. OGE 33.87%

PNM Resources, Inc. PNM 45.10%

Median 43.45%

Otter Tail Power Company [2] 65.94%

Notes:

[1] Source: Value Line; Value Line estimates 2017, 2018 and 2020-2022 CAPEX

[2] Source: Company provided data and SNL Financial

Capital Expenditures Relative to Net Plant

31%34%

38% 40% 40%

45%47% 48%

66% 67%

0%

10%

20%

30%

40%

50%

60%

70%

80%

ALE OGE NWE BKH IDA PNM HE EE OTP LNT

Case No. PU-17-


Page 1 of 1

Small Size Premium and Service Area Comparability

[1] [2] [3] [4]

Customers

(Mil)

Service Area

(Sq. Miles)

Customer

Density

(cust./sq. mi.)

Market Cap

($Bil)

Otter Tail Power Company 0.13 33,727 3.89 $0.186Median Market to Book for Proxy Group 2.06OTP Implied Market Cap $0.382

[5] [6] [7] [8] [9] [10]

Company Name Ticker

Customers

(Mil)

Service Area

(Sq. Miles)

Customer

Density

(Cust./Sq. mi.)

Market Cap

($Bil)

Market to

Book Ratio

Included in

Proxy Group

ALLETE, Inc. ALE 0.16 2,437 65.79 $3.94 1.96 ✓

Alliant Energy Corporation LNT 0.95 18,499 51.59 $9.83 2.43 ✓

Ameren Corporation AEE 2.43 26,553 91.65 $14.44 2.02

American Electric Power Company, Inc. AEP 4.35 112,433 38.69 $35.74 2.00

Black Hills Corporation BKH 0.21 18,830 11.06 $3.72 2.22 ✓

CMS Energy Corporation CMS 1.80 28,175 64.05 $13.48 3.03

Dominion Resources, Inc. D 2.55 13,239 192.61 $50.46 3.30

DTE Energy Company DTE 2.17 7,775 279.03 $19.88 2.19

Duke Energy Corporation DUK 7.45 99,739 74.68 $60.49 1.47

El Paso Electric Company EE 0.41 7,012 58.26 $2.24 2.06 ✓

Hawaiian Electric Industries, Inc. HE 0.46 5,800 79.15 $3.65 1.76 ✓

IDACORP, Inc. IDA 0.53 28,944 18.31 $4.49 2.06 ✓

Northwestern Corporation NWE 0.43 100,767 4.23 $2.87 1.68 ✓

OGE Energy Corp. OGE 0.83 27,304 30.40 $7.20 2.06 ✓

Pinnacle West Capital Corporation PNW 1.19 3,014 396.04 $9.89 2.03

PNM Resources, Inc. PNM 0.76 7,212 105.93 $3.35 1.94 ✓

Portland General Electric Company POR 0.86 3,074 279.55 $4.17 1.74

Southern Company SO 4.58 118,840 38.53 $49.02 2.10

WEC Energy Group, Inc. WEC 1.59 11,910 133.75 $20.50 2.24

Xcel Energy Inc. XEL 3.54 56,639 62.54 $24.83 2.23

ALL COMPANIES - MEAN 1.1 18,665 64.92 $9.86 2.06

ALL COMPANIES - MEDIAN 1.9 34,910 103.79 $17.21 2.13

PROXY COMPANIES - MEAN 0.5 24,090 47.19 $4.59 2.02

PROXY COMPANIES - MEDIAN 0.5 18,499 51.59 $3.72 2.06

Market Capitalization ($Mil) [11]

Decile Low High Size Premium

2 10,784.101$ 24,233.747$ 0.61%

3 5,683.991$ 10,711.194$ 0.89%

4 3,520.566$ 5,676.716$ 0.98%

5 2,392.689$ 3,512.913$ 1.51%

6 1,571.193$ 2,390.899$ 1.66%

7 1,033.341$ 1,569.984$ 1.72%

8 569.279$ 1,030.426$ 2.08%

9 263.715$ 567.843$ 2.68%

10 2.516$ 262.891$ 5.59%

Notes:



[3] Equals [1] / [2]

[4] Proposed Rate Base x Equity ratio



[7] Equals [5] / [6]

[8] Source: SNL Financial, 30-day average

[9] Source: SNL Financial, 30-day average

[10] Indicates if proxy group screening criteria were met

[11] Source: Duff and Phelps 2017 Valuation Handbook

Case No. PU-17-


Page 1 of 1

[1] [2]

Company Ticker C&I Revenue C&I Sales Volume

ALLETE, Inc. ALE 88.48% 87.76%

Alliant Energy Corporation LNT 65.19% 71.88%

Black Hills Corporation BKH 67.53% 72.86%

El Paso Electric Company EE 58.89% 64.09%

Hawaiian Electric Industries, Inc. HE 69.33% 73.63%

IDACORP, Inc. IDA 56.43% 64.75%

Northwestern Corporation NWE 61.21% 60.76%

OGE Energy Corp. OGE 55.35% 65.34%

PNM Resources, Inc. PNM 58.21% 65.41%

Mean 64.51% 69.61%

Median 61.21% 65.41%

Otter Tail Power Company 69.49% 74.30%

Source: SNL Financial

Customer Concentration

Case No. PU-17-


Page 1 of 1

Institutional Ownership as a Percentage of Total Shares Outstanding

Company Ticker

Institutional

Ownership

ALLETE, Inc. ALE 77.85%

Alliant Energy Corporation LNT 72.38%

Black Hills Corporation BKH 111.21%

El Paso Electric Company EE 104.04%

Hawaiian Electric Industries, Inc. HE 52.79%

IDACORP, Inc. IDA 78.92%

Northwestern Corporation NWE 107.45%

OGE Energy Corp. OGE 67.07%

PNM Resources, Inc. PNM 110.26%

Average 86.89%

Otter Tail Corporation OTTR 51.94%

Source: Bloomberg Professional as of September 29, 2017

Case No. PU-17-


Page 1 of 3Proxy Group Capital Structure Proxy Group Capital Structure

% Common Equity % Long-Term Debt

Company Ticker 2017Q2 2017Q1 2016Q4 2016Q3 2016Q2 2016Q1 2015Q4 2015Q3 Average

ALLETE, Inc. ALE 60.62% 60.28% 59.02% 59.28% 59.08% 58.83% 58.04% 58.01% 59.14%

Alliant Energy Corporation LNT 49.72% 50.12% 50.34% 50.60% 50.88% 51.46% 51.09% 51.27% 50.68%

Black Hills Corporation BKH 53.84% 53.20% 52.81% 52.73% 52.55% 52.57% 52.51% 52.06% 52.78%

El Paso Electric Company EE 45.25% 45.60% 46.83% 47.33% 44.87% 44.93% 47.39% 47.97% 46.27%

Hawaiian Electric Industries, Inc. HE 56.96% 57.68% 57.70% 57.60% 56.98% 57.27% 57.48% 56.88% 57.32%

IDACORP, Inc. IDA 53.48% 53.22% 52.84% 53.15% 52.46% 50.70% 52.34% 52.25% 52.56%

Northwestern Corporation NWE 44.74% 45.64% 44.30% 44.83% 44.33% 45.37% 44.30% 43.16% 44.59%

OGE Energy Corp. OGE 52.75% 53.46% 56.09% 56.23% 55.50% 55.17% 54.30% 54.38% 54.74%

PNM Resources, Inc. PNM 46.32% 46.13% 45.11% 45.44% 43.06% 43.57% 45.32% 44.76% 44.96%

Mean 51.52% 51.70% 51.67% 51.91% 51.08% 51.10% 51.42% 51.19% 51.45%

Median 52.75% 53.20% 52.81% 52.73% 52.46% 51.46% 52.34% 52.06% 52.56%

Operating Company Capital Structure Operating Company Capital Structure

% Common Equity % Long-Term Debt

Operating Company Parent 2017Q2 2017Q1 2016Q4 2016Q3 2016Q2 2016Q1 2015Q4 2015Q3 Average

ALLETE (Minnesota Power) ALE 59.16% 58.71% 56.92% 56.90% 56.63% 56.60% 55.86% 55.62% 57.05%

Superior Water, Light and Power Company ALE 62.08% 61.85% 61.12% 61.65% 61.52% 61.06% 60.23% 60.40% 61.24%

Interstate Power and Light Company LNT 50.89% 50.12% 50.24% 48.99% 50.54% 51.52% 50.91% 50.90% 50.51%

Wisconsin Power and Light Company LNT 48.55% 50.12% 50.44% 52.20% 51.22% 51.40% 51.27% 51.63% 50.85%

Black Hills Colorado Electric Utility Company, LP BKH 55.01% 53.08% 52.20% 51.85% 51.39% 51.06% 50.85% 49.16% 51.82%

Black Hills Power, Inc. BKH 53.26% 53.24% 52.88% 53.13% 53.13% 53.27% 53.35% 53.22% 53.18%

Cheyenne Light, Fuel and Power Company BKH 53.27% 53.29% 53.35% 53.22% 53.14% 53.36% 53.32% 53.80% 53.34%


Hawaiian Electric Company, Inc. HE 56.96% 57.68% 57.70% 57.60% 56.98% 57.27% 57.48% 56.88% 57.32%

Idaho Power Co. IDA 53.48% 53.22% 52.84% 53.15% 52.46% 50.70% 52.34% 52.25% 52.56%

NorthWestern Corporation NWE 44.74% 45.64% 44.30% 44.83% 44.33% 45.37% 44.30% 43.16% 44.59%

Oklahoma Gas and Electric Company OGE 52.75% 53.46% 56.09% 56.23% 55.50% 55.17% 54.30% 54.38% 54.74%

Public Service Company of New Mexico PNM 46.32% 46.13% 45.11% 45.44% 43.06% 43.57% 45.32% 44.76% 44.96%

Texas-New Mexico Power Company PNM NA NA NA NA NA NA NA NA NA

Mean 52.44% 52.47% 52.31% 52.50% 51.91% 51.94% 52.07% 51.86% 52.19%

Median 53.26% 53.22% 52.84% 53.13% 52.46% 51.52% 52.34% 52.25% 52.56%

Source: SNL Financial

Case No. PU-17-


Page 2 of 3Proxy Group Capital Structure Proxy Group Capital Structure

% Long-Term Debt % Short-Term Debt


ALLETE, Inc. ALE 39.38% 39.72% 40.98% 40.72% 40.92% 41.17% 41.96% 41.99% 40.86%





IDACORP, Inc. IDA 46.52% 46.78% 46.58% 46.85% 47.54% 49.30% 47.66% 47.75% 47.37%




Mean 46.34% 46.96% 46.87% 47.08% 47.16% 47.63% 47.29% 47.33% 47.08%

Median 47.25% 46.80% 47.19% 47.27% 47.54% 48.18% 47.66% 47.94% 47.37%

Operating Company Capital Structure Operating Company Capital Structure

% Long-Term Debt % Short-Term Debt
















Mean 45.86% 46.49% 46.62% 46.79% 46.83% 47.14% 47.02% 47.12% 46.73%

Median 46.73% 46.78% 47.12% 46.87% 47.48% 47.87% 47.66% 47.75% 47.37%

Case No. PU-17-


Page 3 of 3Proxy Group Capital Structure

% Short-Term Debt


ALLETE, Inc. ALE 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%





IDACORP, Inc. IDA 0.00% 0.00% 0.58% 0.00% 0.00% 0.00% 0.00% 0.00% 0.07%




Mean 2.13% 1.34% 1.46% 1.01% 1.76% 1.28% 1.29% 1.47% 1.47%

Median 1.22% 0.05% 0.58% 0.17% 0.65% 0.37% 0.00% 0.00% 0.82%

Operating Company Capital Structure

% Short-Term Debt
















Mean 1.70% 1.03% 1.07% 0.71% 1.27% 0.91% 0.91% 1.02% 1.08%

Median 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.03%

Attachment A Resume of:

Robert B. Hevert Partner

Summary

Bob Hevert is a financial and economic consultant with more than 30 years of broad experience in the energy and utility industries. He has an extensive background in the areas of corporate finance, mergers and acquisitions, project finance, asset and business unit valuation, rate and regulatory matters, energy market assessment, and corporate strategic planning. He has provided expert testimony on a wide range of financial, strategic, and economic matters on more than 200 occasions at the state, provincial, and federal levels. Prior to joining ScottMadden, Bob served as managing partner at Sussex Economic Advisors, LLC. Throughout the course of his career, he has worked with numerous leading energy companies and financial institutions throughout North America. He has provided expert testimony and support of litigation in various regulatory proceedings on a variety of energy and economic issues. Bob earned a B.S. in business and economics from the University of Delaware and an M.B.A. with a concentration in finance from the University of Massachusetts at Amherst. Bob also holds the Chartered Financial Analyst designation.

Areas of Specialization

Regulation and rates Utilities Fossil/hydro generation Markets and RTOs Nuclear generation Mergers and acquisitions Regulatory strategy and rate case support Capital project planning Strategic and business planning

Recent Expert Testimony Submission/Appearance

Federal Energy Regulatory Commission – Return on Equity New Jersey Board of Public Utilities – Merger Approval New Mexico Public Regulation Commission – Cost of Capital and Financial Integrity United States District Court – PURPA and FERC Regulations Alberta Utilities Commission – Return on Equity and Capital Structure

Recent Assignments

Provided expert testimony on the cost of capital for ratemaking purposes before numerous state utility regulatory agencies, the Alberta Utilities Commission, and the Federal Energy Regulatory Commission

For an independent electric transmission provider in Texas, prepared an expert report on the economic damages with respect to failure to meet guaranteed completion dates. The report was filed as part of an arbitration proceeding and included a review of the ratemaking implications of economic damages

Advised the board of directors of a publicly traded electric and natural gas combination utility on dividend policy issues, earnings payout trends and related capital market considerations

Assisted a publicly traded utility with a strategic buy-side evaluation of a gas utility with more than $1 billion in assets. The assignment included operational performance benchmarking, calculation of merger synergies, risk analysis, and review of the regulatory implications of the transaction

Provided testimony before the Arkansas Public Service Commission in support of the acquisition of SourceGas LLC by Black Hills Corporation. The testimony addressed certain balance sheet capitalization and credit rating issues

For the State of Maine Public Utility Commission, prepared a report that summarized the Northeast and Atlantic Canada natural gas power markets and analyzed the potential benefits and costs associated with natural gas pipeline expansions. The independent report was filed at the Maine Public Utility Commission



SPONSOR DATE CASE/APPLICANT DOCKET NO. SUBJECT

Regulatory Commission of Alaska

ENSTAR Natural Gas Company 06/16 ENSTAR Natural Gas Company Matter No. TA 285-4 Return on Equity

ENSTAR Natural Gas Company 08/14 ENSTAR Natural Gas Company Matter No. TA 262-4 Return on Equity

Alberta Utilities Commission

EPCOR Energy Alberta G.P. Inc. 01/17 EPCOR Energy Alberta G.P. Inc. Proceeding 22357 Energy Price Setting Plan

Altalink, L.P., and EPCOR Distribution & Transmission, Inc.

02/16 Altalink, L.P., and EPCOR Distribution & Transmission, Inc.

2016 General Cost of Capital, Proceeding ID. 20622

Rate of Return

Arizona Corporation Commission

Southwest Gas Corporation 05/16 Southwest Gas Corporation Docket No. G-01551A-16-017 Return on Equity

Southwest Gas Corporation 11/10 Southwest Gas Corporation Docket No. G-01551A-10-0458 Return on Equity

Arkansas Public Service Commission

Oklahoma Gas and Electric Company 09/16 Oklahoma Gas and Electric Company Docket No. 16-052-U Return on Equity

CenterPoint Energy Resources Corp. d/b/a CenterPoint Energy Arkansas Gas

11/15 CenterPoint Energy Resources Corp. d/b/a CenterPoint Energy Arkansas Gas

Docket No. 15-098-U Return on Equity

SourceGas Arkansas, Inc. 03/15 SourceGas Arkansas, Inc. Docket No. 15-011-U Return on Equity

CenterPoint Energy Resources Corp. d/b/a CenterPoint Energy Arkansas Gas

01/07 CenterPoint Energy Resources Corp. d/b/a CenterPoint Energy Arkansas Gas

Docket No. 06-161-U Return on Equity

California Public Utilities Commission

Southwest Gas Corporation 12/12 Southwest Gas Corporation Docket No. A-12-12-024 Return on Equity

Colorado Public Utilities Commission

Atmos Energy Corporation 06/17 Atmos Energy Corporation Docket No. 17AL-0429G Return on Equity

Xcel Energy, Inc. 03/15 Public Service Company of Colorado Docket No. 15AL-0135G Return on Equity (gas)

Xcel Energy, Inc. 06/14 Public Service Company of Colorado Docket No. 14AL-0660E Return on Equity (electric)

Xcel Energy, Inc. 12/12 Public Service Company of Colorado Docket No. 12AL-1268G Return on Equity (gas)

Xcel Energy, Inc. 11/11 Public Service Company of Colorado Docket No. 11AL-947E Return on Equity (electric)

Xcel Energy, Inc. 12/10 Public Service Company of Colorado Docket No. 10AL-963G Return on Equity (electric)

Atmos Energy Corporation 07/09 Atmos Energy Colorado-Kansas Division Docket No. 09AL-507G Return on Equity (gas)

Xcel Energy, Inc. 12/06 Public Service Company of Colorado Docket No. 06S-656G Return on Equity (gas)




Xcel Energy, Inc. 04/06 Public Service Company of Colorado Docket No. 06S-234EG Return on Equity (electric)

Xcel Energy, Inc. 08/05 Public Service Company of Colorado Docket No. 05S-369ST Return on Equity (steam)

Xcel Energy, Inc. 05/05 Public Service Company of Colorado Docket No. 05S-246G Return on Equity (gas)

Connecticut Public Utilities Regulatory Authority

Connecticut Light and Power Company 06/14 Connecticut Light and Power Company Docket No. 14-05-06 Return on Equity

Southern Connecticut Gas Company 09/08 Southern Connecticut Gas Company Docket No. 08-08-17 Return on Equity

Southern Connecticut Gas Company 12/07 Southern Connecticut Gas Company Docket No. 05-03-17PH02 Return on Equity

Connecticut Natural Gas Corporation 12/07 Connecticut Natural Gas Corporation Docket No. 06-03-04PH02 Return on Equity

Delaware Public Service Commission

Delmarva Power & Light Company 08/17 Delmarva Power & Light Company Docket No. 17-0977 (Electric) Return on Equity

Delmarva Power & Light Company 08/17 Delmarva Power & Light Company Docket No. 17-0978 (Gas) Return on Equity

Delmarva Power & Light Company 05/16 Delmarva Power & Light Company Case No. 16-649 (Electric) Return on Equity

Delmarva Power & Light Company 05/16 Delmarva Power & Light Company Case No. 16-650 (Gas) Return on Equity

Delmarva Power & Light Company 03/13 Delmarva Power & Light Company Case No. 13-115 Return on Equity



District of Columbia Public Service Commission

Potomac Electric Power Company 07/16 Potomac Electric Power Company Formal Case No. FC1139 Return on Equity

Washington Gas Light Company 02/16 Washington Gas Light Company Formal Case No. FC1137 Return on Equity

Potomac Electric Power Company 03/13 Potomac Electric Power Company Formal Case No. FC1103-2013-E Return on Equity

Potomac Electric Power Company 07/11 Potomac Electric Power Company Formal Case No. FC1087 Return on Equity

Federal Energy Regulatory Commission

Sabine Pipeline, LLC 09/15 Sabine Pipeline, LLC Docket No. RP15-1322-000 Return on Equity

NextEra Energy Transmission West, LLC 07/15 NextEra Energy Transmission West, LLC Docket No. ER15-2239-000 Return on Equity

Maritimes & Northeast Pipeline, LLC 05/15 Maritimes & Northeast Pipeline, LLC Docket No. RP15-1026-000 Return on Equity

Public Service Company of New Mexico 12/12 Public Service Company of New Mexico Docket No. ER13-685-000 Return on Equity

Public Service Company of New Mexico 10/10 Public Service Company of New Mexico Docket No. ER11-1915-000 Return on Equity




Portland Natural Gas Transmission System 05/10 Portland Natural Gas Transmission System Docket No. RP10-729-000 Return on Equity

Florida Gas Transmission Company, LLC 10/09 Florida Gas Transmission Company, LLC Docket No. RP10-21-000 Return on Equity

Maritimes and Northeast Pipeline, LLC 07/09 Maritimes and Northeast Pipeline, LLC Docket No. RP09-809-000 Return on Equity

Spectra Energy 02/08 Saltville Gas Storage Docket No. RP08-257-000 Return on Equity

Panhandle Energy Pipelines 08/07 Panhandle Energy Pipelines Docket No. PL07-2-000 Response to draft policy statement regarding inclusion of MLPs in proxy groups for determination of gas pipeline ROEs

Southwest Gas Storage Company 08/07 Southwest Gas Storage Company Docket No. RP07-541-000 Return on Equity

Southwest Gas Storage Company 06/07 Southwest Gas Storage Company Docket No. RP07-34-000 Return on Equity

Sea Robin Pipeline LLC 06/07 Sea Robin Pipeline LLC Docket No. RP07-513-000 Return on Equity

Transwestern Pipeline Company 09/06 Transwestern Pipeline Company Docket No. RP06-614-000 Return on Equity

GPU International and Aquila 11/00 GPU International Docket No. EC01-24-000 Market Power Study

Florida Public Service Commission

Florida Power & Light Company 03/16 Florida Power & Light Company Docket No. 160021-EI Return on Equity

Tampa Electric Company 04/13 Tampa Electric Company Docket No. 130040-EI Return on Equity

Georgia Public Service Commission

Atlanta Gas Light Company 05/10 Atlanta Gas Light Company Docket No. 31647-U Return on Equity

Hawaii Public Utilities Commission

Maui Electric Company, Limited 10/17 Maui Electric Company, Limited Docket No. 2017-0150 Return on Equity

Hawaiian Electric Company, Inc. 12/16 Hawaiian Electric Company, Inc. Docket No. 2016-0328 Return on Equity

Hawai‘i Electric Light Company, Inc. 09/16 Hawai‘i Electric Light Company, Inc. Docket No. 2015-0170 Return on Equity

Maui Electric Company, Limited 12/14 Maui Electric Company, Limited Docket No. 2014-0318 Return on Equity

Hawaiian Electric Company, Inc. 06/14 Hawaiian Electric Company, Inc. Docket No. 2013-0373 Return on Equity

Hawai’i Electric Light Company, Inc. 08/12 Hawai’i Electric Light Company, Inc. Docket No. 2012-0099 Return on Equity




Illinois Commerce Commission

Ameren Illinois Company d/b/a Ameren Illinois

01/15 Ameren Illinois Company d/b/a Ameren Illinois Docket No. 15-0142 Return on Equity

Liberty Utilities (Midstates Natural Gas) Corp. d/b/a Liberty Utilities

03/14 Liberty Utilities (Midstates Natural Gas) Corp. d/b/a Liberty Utilities

Docket No. 14-0371 Return on Equity


01/13 Ameren Illinois Company d/b/a Ameren Illinois

Docket No. 13-0192 Return on Equity



Docket No. 11-0279 Return on Equity (electric)



Docket No. 11-0282 Return on Equity (gas)

Indiana Utility Regulatory Commission

Indiana Michigan Power Company 7/17 Indiana Michigan Power Company Cause No. 44967 Return on Equity

Duke Energy Indiana, Inc. 12/15 Duke Energy Indiana, Inc. Cause No. 44720 Return on Equity

Duke Energy Indiana, Inc. 12/14 Duke Energy Indiana, Inc. Cause No. 44526 Return on Equity

Northern Indiana Public Service Company 05/09 Northern Indiana Public Service Company Cause No. 43894 Assessment of Valuation Approaches

Kansas Corporation Commission

Kansas City Power & Light Company 01/15 Kansas City Power & Light Company Docket No. 15-KCPE-116-RTS Return on Equity

Maine Public Utilities Commission

Northern Utilities, Inc. 05/17 Northern Utilities, Inc. Docket No. 2017-00065 Return on Equity

Central Maine Power Company 06/11 Central Maine Power Company Docket No. 2010-327 Response to Bench Analysis provided by Commission Staff relating to the Company’s credit and collections processes

Maryland Public Service Commission

Delmarva Power & Light Company 07/17 Delmarva Power & Light Company Case No. 9455 Return on Equity

Potomac Electric Power Company 03/17 Potomac Electric Power Company Case No. 9443 Return on Equity












Massachusetts Department of Public Utilities

NSTAR Electric Company Western and Massachusetts Electric Company each d/b/a Eversource Energy

01/17 NSTAR Electric Company Western Massachusetts Electric Company each d/b/a Eversource Energy

DPU 17-05 Return on Equity

National Grid 11/15 Massachusetts Electric Company and Nantucket Electric Company d/b/a National Grid


Fitchburg Gas and Electric Light Company d/b/a Unitil

06/15 Fitchburg Gas and Electric Light Company d/b/a Unitil


NSTAR Gas Company 12/14 NSTAR Gas Company DPU 14-150 Return on Equity

Fitchburg Gas and Electric Light Company d/b/a Unitil

07/13 Fitchburg Gas and Electric Light Company d/b/a Unitil


Bay State Gas Company d/b/a Columbia Gas of Massachusetts

04/12 Bay State Gas Company d/b/a Columbia Gas of Massachusetts

DPU 12-25 Capital Cost Recovery

National Grid 08/09 Massachusetts Electric Company d/b/a National Grid

DPU 09-39 Revenue Decoupling and Return on Equity

National Grid 08/09 Massachusetts Electric Company and Nantucket Electric Company d/b/a National Grid

DPU 09-38 Return on Equity – Solar Generation

Bay State Gas Company 04/09 Bay State Gas Company DPU 09-30 Return on Equity

NSTAR Electric 09/04 NSTAR Electric DTE 04-85 Divestiture of Power Purchase Agreement








Unitil Corporation 01/04 Fitchburg Gas and Electric DTE 03-52 Integrated Resource Plan; Gas Demand Forecast

Bay State Gas Company 01/93 Bay State Gas Company DPU 93-14 Divestiture of Shelf Registration

Bay State Gas Company 01/91 Bay State Gas Company DPU 91-25 Divestiture of Shelf Registration

Michigan Public Service Commission

Indiana Michigan Power Company 05/17 Indiana Michigan Power Company Case No. U-18370 Return on Equity

Minnesota Public Utilities Commission

CenterPoint Energy Resources Corp. d/b/a CenterPoint Energy Minnesota Gas

08/17 CenterPoint Energy Resources Corp. d/b/a CenterPoint Energy Minnesota Gas

Docket No. G-008/GR-17-285 Return on Equity

ALLETE, Inc., d/b/a Minnesota Power Inc. 11/16 ALLETE, Inc., d/b/a Minnesota Power Inc. Docket No. E015/GR-16-664 Return on Equity

Otter Tail Power Corporation 02/16 Otter Tail Power Company Docket No. E017/GR-15-1033 Return on Equity

Minnesota Energy Resources Corporation 09/15 Minnesota Energy Resources Corporation Docket No. G-011/GR-15-736 Return on Equity




Xcel Energy, Inc. 11/13 Northern States Power Company Docket No. E002/GR-13-868 Return on Equity




Xcel Energy, Inc. 11/12 Northern States Power Company Docket No. E002/GR-12-961 Return on Equity

Otter Tail Power Corporation 04/10 Otter Tail Power Company Docket No. E-017/GR-10-239 Return on Equity

Minnesota Power a division of ALLETE, Inc. 11/09 Minnesota Power Docket No. E-015/GR-09-1151 Return on Equity





11/08 CenterPoint Energy Minnesota Gas Docket No. G-008/GR-08-1075 Return on Equity

Otter Tail Power Corporation 10/07 Otter Tail Power Company Docket No. E-017/GR-07-1178 Return on Equity

Xcel Energy, Inc. 11/05 Northern States Power Company -Minnesota Docket No. E-002/GR-05-1428 Return on Equity (electric)

Xcel Energy, Inc. 09/04 Northern States Power Company - Minnesota Docket No. G-002/GR-04-1511 Return on Equity (gas)

Mississippi Public Service Commission

CenterPoint Energy Resources, Corp. d/b/a CenterPoint Energy Entex and CenterPoint Energy Mississippi Gas

07/09 CenterPoint Energy Mississippi Gas Docket No. 09-UN-334

Return on Equity

Missouri Public Service Commission

Liberty Utilities (Midstates Natural Gas) Corp. d/b/a/ Liberty Utilities

09/17 Liberty Utilities (Midstates Natural Gas) Corp. d/b/a/ Liberty Utilities

Case No. GR-2018-0013 New Ratemaking Mechanisms

Union Electric Company d/b/a Ameren Missouri

07/16 Union Electric Company d/b/a Ameren Missouri

Case No. ER-2016-0179 Return on Equity (electric)

Kansas City Power & Light Company 07/16 Kansas City Power & Light Company Case No. ER-2016-0285 Return on Equity (electric)








Case No. EC-2014-0223 Return on Equity (electric)

Liberty Utilities (Midstates Natural Gas) Corp. d/b/a Liberty Utilities

02/14 Liberty Utilities (Midstates Natural Gas) Corp. d/b/a Liberty Utilities

Case No. GR-2014-0152 Return on Equity

Laclede Gas Company 12/12 Laclede Gas Company Case No. GR-2013-0171 Return on Equity




Union Electric Company d/b/a AmerenUE 09/10 Union Electric Company d/b/a AmerenUE Case No. ER-2011-0028 Return on Equity (electric)

Union Electric Company d/b/a AmerenUE 06/10 Union Electric Company d/b/a AmerenUE Case No. GR-2010-0363 Return on Equity (gas)




Montana Public Service Commission

Northwestern Corporation 09/12 Northwestern Corporation d/b/a Northwestern Energy

Docket No. D2012.9.94 Return on Equity (gas)

Nevada Public Utilities Commission

Southwest Gas Corporation 04/12 Southwest Gas Corporation Docket No. 12-04005 Return on Equity (gas)

Nevada Power Company 06/11 Nevada Power Company Docket No. 11-06006 Return on Equity (electric)

New Hampshire Public Utilities Commission

Northern Utilities, Inc. 06/17 Northern Utilities, Inc. Docket No. DG 17-070 Return on Equity

Liberty Utilities d/b/a EnergyNorth Natural Gas

04/17 Liberty Utilities d/b/a EnergyNorth Natural Gas Docket No. DG 17-048 Return on Equity

Unitil Energy Systems, Inc. 04/16 Unitil Energy Systems, Inc. Docket No. DE 16-384 Return on Equity

Liberty Utilities d/b/a Granite State Electric Company

04/16 Liberty Utilities d/b/a Granite State Electric Company

Docket No. DE 16-383 Return on Equity

Liberty Utilities d/b/a EnergyNorth Natural Gas

08/14 Liberty Utilities d/b/a EnergyNorth Natural Gas Docket No. DG 14-180 Return on Equity

Liberty Utilities d/b/a Granite State Electric Company

03/13 Liberty Utilities d/b/a Granite State Electric Company

Docket No. DE 13-063 Return on Equity

EnergyNorth Natural Gas d/b/a National Grid NH

02/10 EnergyNorth Natural Gas d/b/a National Grid NH

Docket No. DG 10-017 Return on Equity

Unitil Energy Systems, Inc., EnergyNorth Natural Gas, Inc. d/b/a National Grid NH, Granite State Electric Company d/b/a National Grid, and Northern Utilities, Inc. – New Hampshire Division

08/08 Unitil Energy Systems, Inc., EnergyNorth Natural Gas, Inc. d/b/a National Grid NH, Granite State Electric Company d/b/a National Grid, and Northern Utilities, Inc. – New Hampshire Division

Docket No. DG 07-072 Carrying Charge Rate on Cash Working Capital

New Jersey Board of Public Utilities

Atlantic City Electric Company 03/17 Atlantic City Electric Company Docket No. ER17030308 Return on Equity

Pivotal Utility Holdings, Inc. 08/16 Elizabethtown Gas Docket No. GR16090826 Return on Equity

The Southern Company; AGL Resources Inc.; AMS Corp. and Pivotal Holdings, Inc. d/b/a Elizabethtown Gas

04/16 The Southern Company; AGL Resources Inc.; AMS Corp. and Pivotal Holdings, Inc. d/b/a Elizabethtown Gas

BPU Docket No. GM15101196 Merger Approval





Pepco Holdings, Inc. 04/14 Atlantic City Electric Company Docket No. ER14030245 Return on Equity

Orange and Rockland Utilities 11/13 Rockland Electric Company Docket No. ER13111135 Return on Equity



Pepco Holdings, Inc. 09/06 Atlantic City Electric Company Docket No. EM06090638

Divestiture and Valuation of Electric Generating Assets

Pepco Holdings, Inc. 12/05 Atlantic City Electric Company Docket No. EM05121058 Market Value of Electric Generation Assets; Auction

Conectiv 06/03 Atlantic City Electric Company Docket No. EO03020091 Market Value of Electric Generation Assets; Auction Process

New Mexico Public Regulation Commission

Public Service Company of New Mexico 12/16 Public Service Company of New Mexico Case No. 16-00276-UT Return on Equity (electric)



Public Service Company of New Mexico 12/14 Public Service Company of New Mexico Case No. 13-00390-UT Cost of Capital and Financial Integrity

Southwestern Public Service Company 02/11 Southwestern Public Service Company Case No. 10-00395-UT Return on Equity (electric)



Xcel Energy, Inc. 07/07 Southwestern Public Service Company Case No. 07-00319-UT Return on Equity (electric)

New York State Public Service Commission

Consolidated Edison Company of New York, Inc.

01/15 Consolidated Edison Company of New York, Inc.

Case No. 15-E-0050 Return on Equity (electric)

Orange and Rockland Utilities, Inc. 11/14 Orange and Rockland Utilities, Inc. Case Nos. 14-E-0493 and 14-G-0494

Return on Equity (electric and gas)







Niagara Mohawk Corporation d/b/a National Grid for Electric Service

04/12 Niagara Mohawk Corporation d/b/a National Grid for Electric Service


Niagara Mohawk Corporation d/b/a National Grid for Gas Service

04/12 Niagara Mohawk Corporation d/b/a National Grid for Gas Service

Case No. 12-G-0202 Return on Equity (gas)

Orange and Rockland Utilities, Inc. 07/11 Orange and Rockland Utilities, Inc. Case No. 11-E-0408 Return on Equity (electric)

Orange and Rockland Utilities, Inc. 07/10 Orange and Rockland Utilities, Inc. Case No. 10-E-0362 Return on Equity (electric)



Case No. 09-G-0795 Return on Equity (gas)



Case No. 09-S-0794 Return on Equity (steam)

Niagara Mohawk Power Corporation 07/01 Niagara Mohawk Power Corporation Case No. 01-E-1046 Power Purchase and Sale Agreement; Standard Offer Service Agreement

North Carolina Utilities Commission

Duke Energy Carolinas, LLC 08/17 Duke Energy Carolinas, LLC Docket No. E-7, Sub 1146 Return on Equity

Duke Energy Progress, LLC 06/17 Duke Energy Progress, LLC Docket No. E-2, Sub 1142 Return on Equity

Public Service Company of North Carolina, Inc.

03/16 Public Service Company of North Carolina, Inc.

Docket No. G-5, Sub 565 Return on Equity

Dominion North Carolina Power 03/16 Dominion North Carolina Power Docket No. E-22, Sub 532 Return on Equity

Duke Energy Carolinas, LLC 02/13 Duke Energy Carolinas, LLC Docket No. E-7, Sub 1026 Return on Equity

Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.

10/12 Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.

Docket No. E-2, Sub 1023 Return on Equity

Virginia Electric and Power Company d/b/a Dominion North Carolina Power

03/12 Virginia Electric and Power Company d/b/a Dominion North Carolina Power

Docket No. E-22, Sub 479 Return on Equity (electric)

Duke Energy Carolinas, LLC 07/11 Duke Energy Carolinas, LLC Docket No. E-7, Sub 989 Return on Equity (electric)

North Dakota Public Service Commission

Otter Tail Power Company 11/08 Otter Tail Power Company Docket No. 08-862 Return on Equity (electric)




Oklahoma Corporation Commission

CenterPoint Energy Resources Corp., d/b/a CenterPoint Energy Oklahoma Gas

03/16 CenterPoint Energy Resources Corp., d/b/a CenterPoint Energy Oklahoma Gas

Cause No. PUD201600094 Return on Equity

Oklahoma Gas & Electric Company 12/15 Oklahoma Gas & Electric Company Cause No. PUD201500273 Return on Equity

Public Service Company of Oklahoma 07/15 Public Service Company of Oklahoma Cause No. PUD201500208 Return on Equity

Oklahoma Gas & Electric Company 07/11 Oklahoma Gas & Electric Company Cause No. PUD201100087 Return on Equity

CenterPoint Energy Resources Corp., d/b/a CenterPoint Energy Oklahoma Gas

03/09 CenterPoint Energy Oklahoma Gas

Cause No. PUD200900055 Return on Equity

Pennsylvania Public Utility Commission

Pike County Light & Power Company 01/14 Pike County Light & Power Company Docket No. R-2013-2397237 Return on Equity (electric & gas)

Veolia Energy Philadelphia, Inc. 12/13 Veolia Energy Philadelphia, Inc. Docket No. R-2013-2386293 Return on Equity (steam)

Rhode Island Public Utilities Commission

The Narragansett Electric Company d/b/a National Grid

04/12 The Narragansett Electric Company d/b/a National Grid

Docket No. 4323 Return on Equity (electric & gas)

National Grid RI – Gas 08/08 National Grid RI – Gas Docket No. 3943 Revenue Decoupling and Return on Equity

South Carolina Public Service Commission

Duke Energy Progress, LLC 07/16 Duke Energy Progress, LLC Docket No. 2016-227-E Return on Equity

Duke Energy Carolinas, LLC 03/13 Duke Energy Carolinas, LLC Docket No. 2013-59-E Return on Equity

South Carolina Electric & Gas 06/12 South Carolina Electric & Gas Docket No. 2012-218-E Return on Equity

Duke Energy Carolinas, LLC 08/11 Duke Energy Carolinas, LLC Docket No. 2011-271-E Return on Equity

South Carolina Electric & Gas 03/10 South Carolina Electric & Gas Docket No. 2009-489-E Return on Equity

South Dakota Public Utilities Commission

Otter Tail Power Company 08/10 Otter Tail Power Company Docket No. EL10-011 Return on Equity (electric)

Northern States Power Company 06/09 South Dakota Division of Northern States Power

Docket No. EL09-009 Return on Equity (electric)

Otter Tail Power Company 10/08 Otter Tail Power Company Docket No. EL08-030 Return on Equity (electric)




Texas Public Utility Commission

Southwestern Public Service Company 08/17 Southwestern Public Service Company Docket No. 47527 Return on Equity

Oncor Electric Delivery Company, LLC 03/17 Oncor Electric Delivery Company, LLC Docket No. 46957 Return on Equity

El Paso Electric Company 02/17 El Paso Electric Company Docket No. 46831 Return on Equity

Southwestern Public Service Company 12/16 Southwestern Public Service Company Docket No. 46449 Return on Equity (electric)

Sharyland Utilities, L.P. 12/16 Sharyland Utilities, L.P. Docket No. 45414 Return on Equity


Wind Energy Transmission Texas, LLC 05/15 Wind Energy Transmission Texas, LLC Docket No. 44746 Return on Equity

Cross Texas Transmission 12/14 Cross Texas Transmission Docket No. 43950 Return on Equity


Sharyland Utilities, L.P. 05/13 Sharyland Utilities, L.P. Docket No. 41474 Return on Equity

Wind Energy Texas Transmission, LLC 08/12 Wind Energy Texas Transmission, LLC Docket No. 40606 Return on Equity

Southwestern Electric Power Company 07/12 Southwestern Electric Power Company Docket No. 40443 Return on Equity

Oncor Electric Delivery Company, LLC 01/11 Oncor Electric Delivery Company, LLC Docket No. 38929 Return on Equity

Texas-New Mexico Power Company 08/10 Texas-New Mexico Power Company Docket No. 38480 Return on Equity (electric)

CenterPoint Energy Houston Electric LLC 06/10 CenterPoint Energy Houston Electric LLC Docket No. 38339 Return on Equity

Xcel Energy, Inc. 05/10 Southwestern Public Service Company Docket No. 38147 Return on Equity (electric)

Texas-New Mexico Power Company 08/08 Texas-New Mexico Power Company Docket No. 36025 Return on Equity (electric)

Xcel Energy, Inc. 05/06 Southwestern Public Service Company Docket No. 32766 Return on Equity (electric)

Texas Railroad Commission

Atmos Pipeline - Texas 01/17 Atmos Pipeline - Texas Docket No. 10580 Return on Equity

CenterPoint Energy Resources Corp. D/B/A CenterPoint Energy Entex And CenterPoint Energy Texas Gas

12/16 CenterPoint Energy Resources Corp. D/B/A CenterPoint Energy Entex And CenterPoint Energy Texas Gas

D-GUD-10567 Return on Equity

CenterPoint Energy Resources Corp. d/b/a CenterPoint Energy Entex and CenterPoint Energy Texas Gas

03/15 CenterPoint Energy Resources Corp. d/b/a CenterPoint Energy Entex and CenterPoint Energy Texas Gas

GUD 10432 Return on Equity







Atmos Energy Corporation – West Texas Division

06/12 Atmos Energy Corporation – West Texas Division


Atmos Energy Corporation – Mid-Texas Division

06/12 Atmos Energy Corporation – Mid-Texas Division





Atmos Pipeline – Texas 09/10 Atmos Pipeline - Texas GUD 10000 Return on Equity




CenterPoint Energy Resources Corp. d/b/a CenterPoint Energy Texas Gas

03/08 CenterPoint Energy Resources Corp. d/b/a CenterPoint Energy Texas Gas


Utah Public Service Commission

Questar Gas Company 12/07 Questar Gas Company Docket No. 07-057-13 Return on Equity

Vermont Public Service Board

Central Vermont Public Service Corporation; Green Mountain Power

02/12 Central Vermont Public Service Corporation; Green Mountain Power

Docket No. 7770 Merger Policy

Central Vermont Public Service Corporation 12/10 Central Vermont Public Service Corporation Docket No. 7627 Return on Equity (electric)

Green Mountain Power 04/06 Green Mountain Power Docket Nos. 7175 and 7176 Return on Equity (electric)

Vermont Gas Systems, Inc. 12/05 Vermont Gas Systems Docket Nos. 7109 and 7160 Return on Equity (gas)

Virginia State Corporation Commission

Virginia Electric and Power Company 03/17 Virginia Electric and Power Company Case No. PUR-2017-00038 Return on Equity

Virginia Natural Gas, Inc. 03/17 Virginia Natural Gas, Inc. Case No. PUE-2016-00143 Return on Equity

Virginia Electric and Power Company 10/16 Virginia Electric and Power Company Case No. PUE-2016-00112; PUE-2016-00113; PUE-2016-00136

Return on Equity

Washington Gas Light Company 07/16 Washington Gas Light Company Case No. PUE-2016-00001 Return on Equity




Virginia Electric and Power Company 06/16 Virginia Electric and Power Company

Case Nos. PUE-2016-00063; PUE-2016-00062; PUE-2016-00061; PUE-2016-00060; PUE-2016-00059

Return on Equity

Virginia Electric and Power Company 12/15 Virginia Electric and Power Company Case Nos. PUE-2015-0058; PUE-2015-0059; PUE-2015-0060; PUE-2015-0061; PUE-2015-0075; PUE-2015-0089; PUE-2015-0102; PUE-2015-0104

Return on Equity

Virginia Electric and Power Company 03/15 Virginia Electric and Power Company Case No. PUE-2015-00027 Return on Equity

Virginia Electric and Power Company 03/13 Virginia Electric and Power Company Case No. PUE-2013-00020 Return on Equity

Virginia Natural Gas, Inc. 02/11 Virginia Natural Gas, Inc. Case No. PUE-2010-00142 Capital Structure

Columbia Gas of Virginia, Inc. 06/06 Columbia Gas of Virginia, Inc. Case No. PUE-2005-00098 Merger Synergies

Dominion Resources 10/01 Virginia Electric and Power Company Case No. PUE000584 Corporate Structure and Electric Generation Strategy

Expert Report

United States District Court, Western District of Texas, Austin Division

Southwestern Public Service Company 02/12 Southwestern Public Service Company C.A. No. A-09-CA-917-SS PURPA and FERC regulations

1/5

Volume 2B


Kirk A. Phinney






Case No. PU-17-

Exhibit___

BIG STONE AQCS AND HOOT LAKE MATS CAPITAL PROJECTS


KIRK A. PHINNEY

November 02, 2017

TABLE OF CONTENTS

I. INTRODUCTION AND QUALIFICATIONS .................................................................. 1

II. PURPOSE AND OVERVIEW OF DIRECT TESTIMONY ............................................. 1

III. BIG STONE AQCS AND HOOT LAKE MATS CAPITAL PROJECTS......................... 2

IV. CAPITAL PROJECT COST AND IMPLEMENTATION ................................................ 4

A. Big Stone AQCS Project ........................................................................................... 5

1. Budgeted AQCS Project Costs ............................................................................. 6

2. Management of AQCS Project Costs ................................................................... 7 3. Timeliness and Safety of Big Stone AQCS Project Implementation ................. 11

B. Hoot Lake MATS Project ....................................................................................... 13

V. CONCLUSION ................................................................................................................. 15

1 Case No. PU-17-

Phinney Direct



A. My name is Kirk A. Phinney. I am the Manager, Generation Services for Otter Tail 3

Power Company (OTP). 4

5

Q. PLEASE SUMMARIZE YOUR QUALIFICATIONS AND EXPERIENCE. 6

A. I have a Bachelor of Science Degree in Mechanical Engineering from South Dakota 7

School of Mines and Technology. I have worked in the power generation business for 15 8

years and for OTP for 12 years. I have experience with coal-fired generation as a plant 9

engineer at Coyote Station and Big Stone Power Plant (Big Stone). I was the Principal 10

Engineer, and later, the Commissioning Manager for the Big Stone Air Quality Control 11

System (AQCS) project. I was also responsible for all close-out activities relating to the 12

Big Stone AQCS project. In my current role at OTP, I provide support to various 13

generation assets within OTP’s Energy Supply Department. 14


Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY IN THIS 16

PROCEEDING? 17

A. My Direct Testimony supports the reasonableness of the costs of the Big Stone AQCS 18

project, as required by the Commission’s May 9, 2012 Order in Case No. PU-11-165, the 19

AQCS Advance Determination of Prudence Docket (AQCS ADP Docket). I will explain 20

how OTP achieved an approximately 26 percent savings in the construction cost of the 21

Big Stone AQCS project. I will also discuss how OTP completed the Hoot Lake plant 22

(Hoot Lake) Mercury Air Toxins Standard (MATS) project under budget. 23

24


A. OTP has completed its Big Stone AQCS and Hoot Lake MATS capital projects 26

significantly under budget, resulting in substantial savings for OTP’s customers. 27

28

2 Case No. PU-17-

Phinney Direct

Q. DID YOU USE ANY LABELING CONVENTIONS IN YOUR DIRECT 1

TESTIMONY? 2

A. Yes. There are certain power plant projects where OTP is only a part owner. In those 3

circumstances, I included each of the following: the total project costs, labeled as (Total 4

Plant or Total Project), the OTP ownership allocation of the project amounts, labeled as 5

(OTP Total), and the North Dakota jurisdictional share, labeled as (OTP ND). There may 6

also be instances with project-related amounts where an estimate must be made of OTP’s 7

jurisdictional share of such costs, which are labeled as (OTP ND EST). 8

9

Q. HOW IS YOUR DIRECT TESTIMONY ORGANIZED? 10

A. In Section III, I describe OTP’s Big Stone AQCS and Hoot Lake MATS capital projects. 11

In Section IV, I explain how OTP successfully completed these projects substantially 12

under budget. Section V provides my conclusion. 13

III. BIG STONE AQCS AND HOOT LAKE MATS CAPITAL PROJECTS 14

Q. PLEASE DESCRIBE THE BIG STONE PLANT. 15

A. Big Stone is a 475 megawatt (MW) coal-fired generation facility located near Milbank, 16

South Dakota, approximately two miles west of the Minnesota border. Big Stone is 17

jointly owned by OTP, Montana-Dakota Utilities Co., and NorthWestern Energy. OTP 18

owns 53.9 percent of Big Stone and is the operating agent, which means that the 19

employees at the plant are OTP employees and are subject to OTP management policies 20

and procedures. Significant decisions that impact the plant are approved by co-owner 21

governance. The plant output supplies customers in North Dakota, South Dakota and 22

Minnesota. 23

24

Q. PLEASE DESCRIBE THE HOOT LAKE PLANT. 25

A. Hoot Lake is a 138 MW coal-fired generation facility located near Fergus Falls, 26

Minnesota. Hoot Lake is wholly owned by OTP. 27

28

3 Case No. PU-17-

Phinney Direct

Q. WHAT IS THE BIG STONE AQCS PROJECT? 1

A. The Big Stone AQCS project refers to the installation of the following equipment at Big 2

Stone: a dry Flue Gas Desulfurization (FGD) system with a new baghouse, an ammonia-3

based Selective Catalytic Reduction (SCR) system, a Separated Overfire Air (SOFA) 4

system and an Activated Carbon Injection (ACI) system. The purpose of the FGD 5

system and baghouse is to control sulfur dioxide (SO2) and particulate matter (PM) 6

emissions. The SCR and SOFA technologies are designed to control nitrogen oxide 7

compounds (NOX) emissions. The ACI system controls mercury. 8

9

Q. WHAT IS THE HOOT LAKE MATS PROJECT? 10

A. The Hoot Lake MATS project involved the upgrade of Electrostatic Precipitators (ESP) 11

and the installation of an ACI system at Hoot Lake. The Hoot Lake MATS project is 12

designed to control mercury and PM emissions at the plant. 13

14

Q. WHY DID OTP UNDERTAKE THESE PROJECTS? 15

A. The Big Stone AQCS project was primarily designed to comply with two separate 16

environmental regulations that needed to be met in order to maintain operation of the Big 17

Stone plant: (1) the South Dakota Department of Environment and Natural Resources’ 18

Regional Haze State Implementation Plan (SD Regional Haze SIP); and (2) the 19

Environmental Protection Agency (EPA) Mercury and Air Toxic Standards (MATS) rule 20

(MATS Rule). The Hoot Lake MATS project was designed to comply with the MATS 21

Rule, and without it, OTP would have had to discontinue operating the plant at the end of 22

2015. 23

24

Q. PLEASE BRIEFLY DESCRIBE THE REGIONAL HAZE REGULATIONS. 25

A. The EPA Regional Haze Rule required installation of Best Available Retrofit Technology 26

(BART) at certain power plants, including Big Stone, to control visibility-impairing 27

emissions, such as SO2, NOX, and PM. The SD Regional Haze SIP was established to 28

meet the EPA Regional Haze Rule, and required the installation of the following control 29

technologies at Big Stone: 30

4 Case No. PU-17-

Phinney Direct

• Selective Catalytic Reduction with Separated Overfire Air: This technology 1

provides the highest feasible level of control for NOX. 2

• Dry Flue Gas Desulfurization: This technology provides the maximum control of 3

SO2 consistent with reducing visibility impact, given the technologies required to 4

control NOX and PM. 5

• Baghouse: This technology provides the highest feasible level of control for PM. 6

7

Q. PLEASE BRIEFLY DESCRIBE THE MATS RULE. 8

A. The MATS Rule established emissions standards for new and existing power plants. The 9

MATS Rule focuses on mercury and other hazardous air pollutants. 10

11

Q. DID OTP INSTALL ACI SYSTEMS AT BIG STONE AND HOOT LAKE TO 12

COMPLY WITH THE MATS RULE? 13

A. Yes. The ACI systems at both the Big Stone and Hoot Lake plants help control mercury 14

emissions to comply with the MATS Rule. 15

IV. CAPITAL PROJECT COST AND IMPLEMENTATION 16

Q. IS OTP PROPOSING TO INCLUDE THE BIG STONE AQCS PROJECT AND HOOT 17

LAKE MATS PROJECT IN THE 2018 TEST YEAR RATE BASE? 18

A. Yes. The Big Stone AQCS system was put into commercial operation on 19

December 29, 2015 and it is included in the 2018 Test Year rate base. The Hoot Lake 20

MATS project was placed into commercial operation on August 21, 2015 and is also 21

included in the 2018 Test Year rate base. 22

23

Q. ARE THE BIG STONE AQCS PROJECT COSTS NECESSARY AND 24

REASONABLE? 25

A. Yes. The Big Stone AQCS project is necessary to comply with the EPA Regional Haze 26

Rule, the SD Regional Haze SIP and the MATS Rule. The Commission also made an 27

advance determination that the AQCS project was prudent in the AQCS ADP Docket. 28

Further, as discussed in more detail below, OTP and the other Big Stone owners 29

undertook significant efforts that resulted in the Big Stone AQCS project coming in 30

5 Case No. PU-17-

Phinney Direct

substantially under budget. Thus, not only are the Big Stone AQCS project and its costs 1

necessary, the costs are reasonable, and were prudently incurred. OTP Witness Mr. 2

Stuart D. Tommerdahl explains that the savings associated with the under-budget 3

completion of the Big Stone AQCS project provide a substantial benefit for OTP 4

customers in North Dakota and other states. 5

6

Q. WHAT IS AN ADP? 7

A. North Dakota Century Code §49-05-16 provides that a public utility, like OTP, that 8

intends to make a resource addition (including modification of a generation facility) may 9

file an application with the Commission for an advance determination that the resource 10

addition is prudent. This is done in advance of the project being constructed. This 11

process is not required, but OTP followed this procedure in connection with the Big 12

Stone AQCS project. 13

14

Q. DID OTP OBTAIN APPROVAL FOR RECOVERY OF THE HOOT LAKE MATS 15

PROJECT? 16

A. Yes. In Case No. PU-15-131, the Commission approved OTP recovering the costs of the 17

project through the Environmental Cost Recovery Rider. 18

A. Big Stone AQCS Project 19

Q. IS OTP REQUESTING BASE RATE RECOVERY FOR AQCS PROJECT COSTS? 20

A. Yes. To date, OTP has recovered the eligible cost of the Big Stone AQCS project 21

through its Environmental Cost Recovery Rider (ECRR), as approved in Order PU-13-79 22

and PU-13-84. OTP proposes to move these costs from the rider recovery to base rate 23

recovery in this case. OTP witness Mr. Bryce C. Haugen discusses OTP’s proposal to 24

roll the costs of the Big Stone AQCS Project into base rates as part of this case. 25

26

Q. WHY IS OTP FURTHER EXPLAINING THE COST OF THE BIG STONE AQCS 27

PROJECT IN THIS DOCKET? 28

A. The Commission’s May 9, 2012 Order in the AQCS ADP Docket required that OTP 29

“must be prepared to demonstrate in subsequent rate recovery proceedings the 30

reasonableness of all costs incurred or obligated to implement the AQCS project” and 31

6 Case No. PU-17-

Phinney Direct

that OTP “must also be prepared to demonstrate in subsequent rate recovery proceedings 1

that any costs incurred, other than AFUDC, of the AQCS were prudently incurred.” 2

Similarly, in OTP’s consolidated Environmental Rider Tariff (Case No. PU-13-79) and 3

Rates (Case No. PU-13-84), the Commission determined that: “When the project is 4

completed and the final costs are known, Otter Tail will provide the Commission 5

sufficient information to enable the Commission to perform a final reasonableness review 6

of costs incurred in the execution of the project.” The project is now complete and all 7

costs have been accounted for. As I will explain, the costs for completing the Big Stone 8

AQCS Project were substantially under budget and were reasonable and prudent. 9

1. Budgeted AQCS Project Costs 10

Q. WHAT WAS THE INITIAL BUDGET OF THE AQCS PROJECT? 11

A. The original budget that was presented as part of the AQCS ADP Docket was 12

approximately $489 million (Total Plant), $263.6 million (OTP Total), $96.0 million 13

(OTP ND). An additional cost for the ACI of $5 million (Total Plant), $2.7 million (OTP 14

Total), $1.0 million (OTP ND) was also presented as part of the AQCS ADP. 15

16

Q. HOW WAS THAT ORIGINAL BUDGET DEVELOPED? 17

A. The original budget was based on cost estimates compiled by Sargent & Lundy, a global 18

engineering firm with extensive expertise and experience with electric power generation 19

and power delivery systems. 20

21

Q. WHY WAS SARGENT & LUNDY SELECTED? 22

A. Sargent & Lundy had more experience engineering AQCS systems than any other firm in 23

the country, having worked on 57 percent of the dry FGD projects, 46 percent of the wet 24

FGD projects, and 30 percent of the SCR projects in the industry. Sargent & Lundy also 25

prepared a very detailed and thorough estimate that included budgetary quotes for all of 26

the major procurements. Additionally, Sargent & Lundy compared the AQCS project 27

estimate against similar projects. 28

29

7 Case No. PU-17-

Phinney Direct

Q. DID OTHER FACTORS ALSO PROVIDE CONFIDENCE IN THE ESTIMATE? 1

A. Yes. OTP’s project team also reviewed the virtually identical emission reduction projects 2

installed at Xcel Energy’s Allen S. King Plant and Minnesota Power’s Boswell Unit 3 3

and provided input to Sargent & Lundy. The AQCS project was expected to be slightly 4

higher in cost than those projects because of the boiler work that would be required for 5

the Big Stone SCR to operate properly. Even so, after adjusting for plant size and year of 6

completion, the Sargent & Lundy cost estimate for Big Stone was consistent with the 7

costs incurred by these comparable projects. 8

9

Q. HOW HAVE THE ACTUAL COSTS COMPARED TO THE BUDGET? 10

A. The final cost of the AQCS project, including the ACI System, is $365.5 million (Total 11

Plant), $197 million (OTP Total), $71.8 million (OTP ND), or approximately 26 percent 12

below budget. I will explain the factors contributing to the project being completed 13

below budget. 14

2. Management of AQCS Project Costs 15

Q. HOW DID OTP AND THE OTHER BIG STONE OWNERS MANAGE AQCS 16

PROJECT COSTS AND COMPLETE THE PROJECT BELOW BUDGET? 17

A. There were three primary drivers of bringing the project in under budget: (1) prudent 18

design/engineering modifications; (2) project delivery method, timing and market 19

conditions; and (3) project management. 20

21

Q. PLEASE DISCUSS THE EFFECT OF PRUDENT DESIGN/ENGINEERING 22

MODIFICATIONS. 23

A. Through prudent engineering, there were a number of changes in the project design and 24

specifications that resulted in considerable cost savings without compromising the 25

performance or operability of the project. For example, changes to the requirements and 26

design of the boiler modifications eliminated major structural changes that were 27

originally contemplated. Another example was the reuse of the Big Stone plant’s 13.8 28

kV switchgear that had been replaced in 2011. Reusing the switchgear eliminated the 29

need for a new plant substation and transformer to feed the Big Stone AQCS project. 30

31

8 Case No. PU-17-

Phinney Direct

Q. PLEASE DISCUSS THE EFFECT OF PROJECT DELIVERY METHOD, TIMING 1

AND MARKET CONDITIONS. 2

A. The combination of the project delivery method, which was a general work contract 3

target pricing methodology, and a “buyer’s market” allowed OTP and the Big Stone 4

owners to take advantage of many very competitive situations that often yielded bid 5

prices below what we expected. Market conditions were favorable and OTP and the Big 6

Stone owners were active in taking advantage of these conditions to reduce costs. 7

8

Q. HOW DID PROJECT DELIVERY AFFECT THESE SAVINGS? 9

A. OTP selected the project delivery method to allow us to get to the market at the right 10

time, and we aggressively pushed ahead to be in the market during this opportune time. 11

12

Q. CAN YOU PROVIDE EXAMPLES OF PROCUREMENT STRATEGIES THAT 13

HELPED CONTROL COSTS? 14

A. OTP selected Sargent & Lundy as the engineer for the project based on Sargent & 15

Lundy’s demonstrated ability to control costs as compared to its competitors. Also, based 16

on a recommendation from Sargent & Lundy, OTP solicited bids from suppliers for each 17

of the AQCS major systems (the FGD, the SCR, and the remaining plant modifications) 18

rather than issue a single engineer-procure-construct solicitation under which a single 19

contractor would complete the entire project. This approach increased the competition in 20

the bidding process and allowed OTP to go to market sooner to take advantage of 21

favorable market conditions. We also contracted with a single construction contractor to 22

efficiently coordinate site work. 23

24

Q. HOW WAS PROJECT MANAGEMENT HANDLED? 25

A. OTP took on the duties of construction management for the project and added people to 26

the project staff to ensure that we could fulfill our obligations. With a project delivery 27

method focused on having a single contractor for the construction of the AQCS 28

equipment, the Big Stone owners felt OTP could take on the construction management of 29

the project rather than using a third party. While this is not the typical approach, OTP 30

9 Case No. PU-17-

Phinney Direct

and the Big Stone owners believed that it provided the opportunity for significant 1

savings. This decision did lead to substantial savings. 2

3

Q. HOW DID OTP’S CONSTRUCTION MANAGEMENT REDUCE THE COSTS OF 4

THE BIG STONE AQCS PROJECT? 5

A. Management by OTP eliminated the costs of having a third-party manage the 6

construction. A third-party construction manager, even if procured through a competitive 7

bidding process, would necessarily include a premium in its costs to account for the risk 8

of meeting the project deliverables. By deciding that OTP would accept this risk, the risk 9

premium that would have been charged by a third party was essentially removed from the 10

total project costs. Taking on this risk also aligned OTP’s goals of completing the project 11

on time and at the lowest achievable cost with the interests of OTP’s customers. 12

13

Q. PLEASE DESCRIBE OTP’S SYSTEM TO MANAGE CONTRACTORS. 14

A. There were several key elements to contractor management on the project. The first was 15

the creation of a project execution manual. This manual described the information and 16

process for clear communication on the project. It included definitions around Requests 17

for Information, Fieldwork Authorization, and Non-Conformance Reports. This was a 18

clear communications protocol for everyone on the project team to manage information. 19

Second, there was early discussion of performance indices before contractors 20

mobilized to the site. The performance indices were cost performance index, schedule 21

performance index, labor productivity index, OSHA Rate, Lost time rate, etc. Third, 22

regularly scheduled information exchange with the contractors was routine at the site, 23

with daily and weekly coordination meetings and monthly recording meetings. 24

25

Q. WHAT WAS THE FINANCIAL IMPACT OF THE DESIGN MODIFICATIONS, 26

PROJECT DELIVERY, AND PROJECT MANAGEMENT ELEMENTS? 27

A. Table 1 quantifies the total savings of each of these elements. 28

29

10 Case No. PU-17-

Phinney Direct

Table 1 1

AQCS Project Budget Savings 2

Total Savings

(Total Plant)

Total Savings

(OTP Total)

Total Savings

(OTP ND)

Percent of

Original Budget

2013 Budget Reduction1 $89,235,100 $48,097,719 $17,518,337 18.0%

2014 Budget Reduction2 $20,975,000 $11,305,525 $4,117,742 4.2%

Final Project Cost $18,686,185 $10,071,854 $3,668,409 3.8%

Total Budget Reduction $128,896,285 $69,475,098 $25,304,488 26.1%

Drivers Percent of Total

Reduction

Design / Engineering

Modifications3 $48,761,465 $26,282,429 $9,572,688 37.83%

Project Delivery Method/

Market Conditions4 $37,921,287 $20,439,574 $7,444,580 29.42%

Project Management5 $14,088,364 $7,593,628 $2,765,781 10.93%

Remainder $28,125,169 $15,159,466 $5,521,439 21.82%

Total $128,896,285 $69,475,098 $25,304,488

3

Q. WERE THESE REDUCTIONS REFLECTED IN PRIOR REPORTS TO THE 4

COMMISSION? 5

A. Yes. The Commission’s May 9, 2012 Order in the AQCS ADP Docket required OTP to 6

file reports regarding the project. OTP filed quarterly reports with the Commission in the 7

AQCS ADP Docket through June 2017. These quarterly reports explained the then-8

current status of the project, important milestones achieved, costs incurred, and changed 9

circumstances that could have affected cost or project installation. The 2013 and 2014 10

1 April 9, 2013 Compliance Filing in AQCS ADP Docket. 2 April 14, 2014 Compliance Filing in AQCS ADP Docket. 3 April 9, 2013 Compliance Filing in AQCS ADP Docket attributed approximately 45 percent of the 2013 budget

reduction to prudent design / engineering modifications. 4 April 9, 2013 Compliance Filing in AQCS ADP Docket attributed approximately 35 percent of the 2013 budget

reduction to the project delivery method and market conditions. 5 April 9, 2013 Compliance Filing in AQCS ADP Docket attributed approximately 13 percent of the 2013 budget

reduction to OTP’s project management.

11 Case No. PU-17-

Phinney Direct

budget reductions were discussed in our April 9, 2013 and April 14, 2014 quarterly report 1

filings in the AQCS ADP Docket. 2

3

Q. WHAT IS THE OVERALL IMPACT OF THE EFFORTS TO MANAGE THE COSTS 4

OF THE BIG STONE AQCS PROJECT? 5

A. The final cost of the Big Stone AQCS project is $365.5 million (Total Plant), $197 6

million (OTP Total), $71.8 million (OTP ND). Through the efforts of OTP and the other 7

Big Stone owners, we were able to reduce the cost of the project by more than $128.9 8

million (Total Plant), $69.5 million (OTP Total), $25.3 million (OTP ND), or 9

approximately 26 percent below budget. 10

11

Q. DO THESE COST REDUCTIONS PROVIDE BENEFITS TO OTP’S NORTH 12

DAKOTA CUSTOMERS? 13

A. Yes. As explained by Mr. Tommerdahl, these cost savings will provide significant and 14

long-lasting benefits to OTP’s customers in North Dakota and other states. 15

3. Timeliness and Safety of Big Stone AQCS Project Implementation 16

Q. PLEASE SUMMARIZE THE BIG STONE AQCS PROJECT TIMELINE. 17

A. Work began in 2011. Detailed engineering was carried out in 2011 and 2012, with major 18

procurements beginning in the first half of 2012. Actual on-site construction started in 19

March of 2013 and continued through the summer of 2015, with the last construction 20

personnel leaving the site on September 4, 2015. Construction milestones throughout 21

2014 kept the project on schedule. The majority of construction was completed by the 22

spring of 2015 when the Big Stone Plant was taken off-line to make needed modifications 23

to the boiler and to tie the new AQCS equipment in to the existing plant. 24

The AQCS equipment was then started up and operated for the first time in 25

August 2015. For the next three months, the system was tuned and then tested to insure it 26

was performing as intended. The AQCS system was put into commercial operation on 27

December 29, 2015. Demolition of equipment that was no longer needed occurred in 28

2016 along with closing out of major contracts. The final payments to equipment 29

suppliers were made in October of 2017. 30

31

12 Case No. PU-17-

Phinney Direct

Q. DID OTP PRIORITIZE SAFETY AS PART OF THE PROJECT IMPLEMENTATION? 1

A. Yes. Safety is a primary concern for every project, but because of the size and 2

complexity of this project, we placed an increased emphasis on safety. For example, 3

project employees were required to complete safety orientation, and were instructed on 4

10 “Cardinal Rules” of safety with zero tolerance for safety violations. Sub-contractors 5

held daily safety meetings where safety concerns were identified and communicated to 6

the workforce through a Task Safety Analysis. 7

Our contract required a specific safety representative for every 50 workers. 8

During peak construction, we had a workforce of approximately 500 people, and during 9

the tie-in outages we had approximately 650 people working on site. There were over 2.3 10

million work-hours spent on the project with only one lost time accident. 11

OSHA’s metric for safety performance measures the number of injuries that meet 12

the reporting criteria for each 100 employees working a full year. Our OSHA rate for the 13

entire project has been 0.88. For comparison purposes, in 2014, the overall OSHA rate 14

reported by the Bureau of Labor Statistics for utility construction projects nationwide was 15

2.6. 16

17

Q. DID THE PROJECT STAY ON SCHEDULE? 18

A. Yes, the Big Stone AQCS project stayed on schedule. The start-up and commercial 19

operation of the AQCS equipment was delayed approximately two months, but as 20

discussed below, this adjustment to the commercial operation date was not due to any 21

issues with the Big Stone AQCS project. It was due to an issue with existing equipment 22

at the Big Stone plant that was identified for correction during the scheduled outage 23

during which the AQCS tie-in occurred. Furthermore, the two-month delay did not have 24

a material impact on the cost of the Big Stone AQCS project. 25

26

Q. WHAT CAUSED THE APPROXIMATE TWO-MONTH DELAY IN THE 27

COMMERCIAL OPERATION DATE OF THE AQCS PROJECT? 28

A. The scheduled Big Stone plant outage began on February 27, 2015. During a routine 29

inspection, it was discovered that all ten rows and the control stage blades of the plant’s 30

high pressure (HP) turbine needed to be replaced. This issue was unrelated to the Big 31

13 Case No. PU-17-

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Stone AQCS project. Replacing the blades extended the outage by approximately two 1

months (June 11 to August 4). It also delayed when we could begin testing the Big Stone 2

AQCS project equipment because testing could only start when the plant was back 3

online. 4

5

Q. WHY DID THE TWO MONTH DELAY NOT HAVE A MATERIAL IMPACT ON 6

COST OF THE PROJECT? 7

A. The most important schedule consideration as it relates to project cost was having the 8

AQCS equipment ready to be tied-in to the existing Big Stone plant infrastructure during 9

a scheduled outage. The two-month delay had no impact on this factor. The tie-in could 10

only occur during a plant outage. Plant outages, which generally occur every three to 11

five years, are expensive and planned well in advance of the outage date. When the Big 12

Stone AQCS project timeline was developed, the Big Stone plant was scheduled for an 13

outage in 2015 for non-AQCS scheduled maintenance. Performing the tie-in during the 14

planned 2015 outage allowed us to avoid a second outage. 15

16

Q. IS THE AQCS EQUIPMENT NOW FULLY FUNCTIONAL AND OPERATING AS 17

EXPECTED? 18

A. Yes. The AQCS equipment was put into commercial operation on December 29, 2015, 19

has achieved the desired emissions reductions necessary to comply with regulations and 20

is performing as expected. 21

B. Hoot Lake MATS Project 22

Q. IS OTP REQUESTING BASE RATE RECOVERY FOR THE HOOT LAKE MATS 23

PROJECT COSTS? 24

A. Yes. To date, OTP has recovered the eligible cost of the Hoot Lake MATS project 25

through its Environmental Cost Recovery Rider (ECRR), as approved in Order PU-15-26

131. OTP proposes to move these costs from the rider recovery to base rate recovery in 27

this case. The Commission also approved recovery of the reagents related to the Hoot 28

Lake MATS project in Case No. PU-14-668. Mr. Haugen discusses the roll-in process in 29

greater detail. 30

31

14 Case No. PU-17-

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Q. WHAT WAS THE PROPOSED HOOT LAKE MATS PROJECT BUDGET? 1

A. After getting firm bids on the project and further project development, the overall 2

projection for the project was $8.6 million (OTP Total), $3.1 million (OTP ND). This is 3

approximately $1.4 million (OTP Total), $510,000 (OTP ND) lower than the cost of 4

environmental compliance identified in the 2012 Baseload Diversification Study. 5

6

Q. PLEASE DESCRIBE THE PROCESS FOR COMPLETING THE HOOT LAKE MATS 7

PROJECT. 8

A. OTP began issuing contracts and plans in 2013. Various components were ordered and 9

fabricated in 2013 and 2014, and Hoot Lake was shut down in March of 2014 for a 10

planned 10-week outage to upgrade the ESPs, install the ACI system, and install the new 11

emissions monitoring systems. The installation went very well. After startup in June 12

through August 2014, the system was verified to meet all performance guarantees. After 13

both Hoot Lake units were placed back into service, the balance of the project was to 14

install and verify the emissions monitoring equipment, and complete the required testing 15

to demonstrate compliance with the MATS Rule. The entire Hoot Lake MATS project 16

was deemed in compliance and in service on August 21, 2015. 17

18

Q. DID THE HOOT LAKE PROJECT MEET THE PLANNED OBJECTIVES? 19

A. Yes. The MATS Rule became effective on April 16, 2015. The entire Hoot Lake MATS 20

remains in compliance with the MATS Rule. Compared to the project budget originally 21

identified in the 2012 Baseload Diversification Study of approximately $10 million (OTP 22

Total), $3.6 million (OTP ND), the final project cost was $2.8 million (OTP Total), $1.0 23

million (OTP ND), or approximately 28 percent below budget. 24

25

Q. WHAT WAS THE FINAL COST OF THE HOOT LAKE MATS PROJECT? 26

A. The final cost of the Hoot Lake MATS project was $7.145 million (OTP Total), $2.6 27

million (OTP ND). 28

29

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V. CONCLUSION 1

Q. HAVE THE BIG STONE AQCS PROJECT AND HOOT LAKE MATS PROJECT 2

ACHIEVED THE DESIRED REDUCTIONS IN EMISSIONS? 3

A. Yes. The Big Stone AQCS project and Hoot Lake MATS project have achieved the 4

desired reductions necessary to comply with regulations and are performing as expected. 5

6

Q. WERE THE BIG STONE AQCS PROJECT AND THE HOOT LAKE MATS PROJECT 7

COMPLETED UNDER THE ORIGINAL BUDGETS? 8

A. Yes. The Big Stone AQCS project, which was OTP’s largest-ever capital expenditure, 9

has been completed for a cost approximately 26 percent under budget. OTP also 10

completed the Hoot Lake MATS project approximately 28 percent under budget. I have 11

explained the sources of these savings in my Direct Testimony. 12

13

Q. WAS THE BIG STONE AQCS PROJECT COMPLETED ON SCHEDULE? 14

A. Yes. The Big Stone AQCS project was completed on schedule and within the time 15

period required by the regulations. Commercial operation was delayed by approximately 16

two months from the anticipated in-service date because of issues identified during 17

routine maintenance of the Big Stone plant. The delay was not related to the AQCS 18

project. 19

20

Q. HAS THE ON TIME AND UNDER-BUDGET COMPLETION OF THESE CAPITAL 21

EXPENDITURES RESULTED IN SIGNIFICANT CUSTOMER SAVINGS? 22

A. Yes. Mr. Tommerdahl explains the significant savings that have resulted for all OTP 23

customers, including a significantly lower revenue requirement for North Dakota 24

customers in this rate case. Mr. Tommerdahl also explains the lasting benefits to 25

customers that will continue for many years into the future. 26

27


A. Yes, it does. 29

1/5

Volume 2B


David G. Prazak

Before the North Dakota Public Service Commission State of North Dakota




Case No. PU-17-

Exhibit___

RATE DESIGN


DAVID G. PRAZAK

November 2, 2017

TABLE OF CONTENTS

I. INTRODUCTION AND QUALIFICATIONS .................................................................. 1

II. PURPOSE AND OVERVIEW OF DIRECT TESTIMONY ............................................. 1

III. RATE DESIGN PROCESS ................................................................................................ 2

A. Overall Rate Structure Objectives ................................................................................ 2

B. Intra-Class Revenue Allocation .................................................................................... 2

1. 2018 Marginal Cost Study ..................................................................................... 4

2. Proposed Intra-Class Revenue Allocation ............................................................. 7 C. Development of Individual Rate Components ............................................................ 11

1. Fixed Charges Defined ........................................................................................ 11 2. Proposed Fixed Charges ...................................................................................... 13

IV. INDIVIDUAL RATE PROPOSALS ................................................................................ 23

A. Residential Class ......................................................................................................... 23

B. Farm Class .................................................................................................................. 26

C. General Service Class ................................................................................................. 28

D. Large General Service Class ....................................................................................... 33

E. Irrigation Class ............................................................................................................ 38

F. Outdoor Lighting Class ............................................................................................... 40

G. Other Public Authority Service Class ......................................................................... 41

H. Water Heating Service Class ...................................................................................... 44

I. Controlled Service – Interruptible Class ..................................................................... 46

J. Deferred Load Service Class ...................................................................................... 51

K. Mandatory and Voluntary Riders................................................................................ 54

V. NEW RATE PROPOSALS .............................................................................................. 54

A. Residential Time of Day ............................................................................................. 55

B. Super LGS ................................................................................................................... 59

C. Generation Cost Recovery Rider ................................................................................ 63

D. LED Street and Area Lighting – Dusk to Dawn ......................................................... 64

E. Air Conditioning Rider ............................................................................................... 69

VI. TARIFF CHANGES OTHER THAN RATES ................................................................. 70

VII. CONCLUSION ................................................................................................................. 70

ATTACHED SCHEDULES

Schedule 1 – Statement of Qualifications and Experience

Schedule 2 – 2018 Marginal Cost Study

Schedule 3 – Summary of Proposed Class and Intra-Class Increases

Schedule 4 – Customer and Rate Class Proposed Allocations and Revenues

Schedule 5 – Comparison of Customer Charges and Marginal Costs

Schedule 6 – Residential Customer Usage Analysis

Schedule 7 – Comparison of Current and Proposed Time of Day Pricing Periods

Schedule 8 – LED Outdoor Lighting Supporting Papers

Schedule 9 – Matrix of Tariff Changes

Other Sponsored Schedules

Volume 2D – Proposed Legislative and Non-Legislative Tariff Sheets

Volume 3 – Section E Rate Structure and Design Information, Schedules E.1. 2018 Test

Year Operating Revenue Summary Comparison and E.2. 2018 Test Year Operating

Revenue Detailed Comparison

1 Case No. PU-17-

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A. My name is David G. Prazak. I am employed by Otter Tail Power Company (OTP) as its 3

Supervisor of Pricing and Tariff Administration. 4

5

Q. PLEASE SUMMARIZE YOUR QUALIFICATIONS AND EXPERIENCE. 6

A. I have over 27 years of experience in the energy industry and over 20 years of experience 7

in the Regulatory Administration Department in Pricing and Rate Design. My current 8

duties include managing the design and implementation of retail pricing strategies for rate 9

schedule and contract pricing, including rates and rate design and tariff administration. 10

My qualifications and experience are more fully described on Exhibit___(DGP-1), 11

Schedule 1. 12



A. The purpose of my Direct Testimony is to: (1) describe the rate structure objectives that 15

were used in developing the proposed rates; (2) explain the role of marginal costs in 16

OTP’s rate design; (3) describe the proposed rate design for OTP’s rate schedules and 17

riders; (4) introduce new rate designs, and (5) support the proposed language changes of 18

OTP’s rate schedule provisions. 19

20


A. OTP’s rate design provides a reasonable opportunity to achieve OTP’s revenue 22

requirement. The rate design is based on marginal costs, and as such, promotes efficient 23

use of resources. 24

25

Q. HOW IS YOUR DIRECT TESTIMONY ORGANIZED? 26

A. In Section III, I discuss OTP’s rate design process, including the objectives that guide our 27

rate design, the role of marginal costs in rate design and OTP’s fixed charge proposals. 28

In Section IV, I identify our rate design proposals for each customer class. Section V 29

2 Case No. PU-17-

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identifies new rate proposals, Section VI identifies tariff changes other than rates. 1

Section VII provides my conclusion. 2

III. RATE DESIGN PROCESS 3

A. Overall Rate Structure Objectives 4

Q. WHAT ARE THE RATE STRUCTURE OBJECTIVES THAT GUIDE OTP’S RATE 5

DESIGN? 6

A. OTP identified the following rate structure objectives: 7

• The rate design should give OTP a reasonable opportunity to achieve its revenue 8

requirement. This implies rate structures that follow OTP’s marginal cost 9

structure, thereby allowing revenues to track costs. 10

• The rate design should promote efficient use of resources. This implies giving 11

consumers price signals that reflect marginal costs, including seasonal differences 12

and, where reasonably possible, time-of-day (TOD) differences. 13

• Rate design changes should be gradual where necessary to avoid abrupt bill 14

impacts. 15

• The rate design should be based on structures that are reasonable and 16

nondiscriminatory. This includes minimizing cross-subsidies within rate classes to 17

the extent reasonably possible. 18

• The rate design should result in rates that are administratively feasible. This 19

includes taking metering and billing system constraints into account and avoiding 20

unnecessary complexity that might confuse customers. 21

• The rate design should preserve the attractiveness of load control/interruptible 22

riders as those riders provide substantial benefits to all OTP customers. 23

B. Intra-Class Revenue Allocation 24

Q. PLEASE SUMMARIZE THIS PORTION OF YOUR DIRECT TESTIMONY. 25

A. This portion of my Direct Testimony makes two main points: 26

• Consistent with OTP’s rate design objectives, I based our rate structures on the 27

structure of OTP’s marginal costs, tempered by the need to control bill impacts 28

3 Case No. PU-17-

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and maintain a suitable inter- and intra-class relationship between the regular rates 1

and riders available to OTP’s customers. 2

• The proposed intra-class revenue requirement allocation was determined by 3

applying the Equal Percentage Marginal Cost (EPMC) methodology, where 4

applicable. The EPMC methodology follows our rate structure objectives by 5

improving the efficiency of price signals and reducing cross-subsidies. 6

7

Q. WHAT IS THE STARTING POINT FOR THE RATE DESIGN? 8

A. The rate design begins with the marginal cost study and its application to the rate design 9

process. The first step in that process is to allocate to rate classes the class revenue 10

responsibilities developed by OTP Witness Ms. Gina S. Ice, as described in her Direct 11

Testimony. This is done using the EPMC methodology. I then develop the individual 12

rate components (energy, demand, fixed) for each rate class, based on marginal costs, 13

which are designed to recover the overall revenue requirement. 14

15

Q. HOW ARE MARGINAL COSTS USED IN THE RATE DESIGN PROCESS? 16

A. Marginal costs are used in the process of allocating class revenue responsibilities to rate 17

classes and in the development of individual rate components. I describe the allocation 18

of class revenue responsibilities to rate classes in this Section of my Direct Testimony, 19

and I focus on the development of individual rate components further in this section and 20

in Section IV, below. 21

22

Q. DOES OTP USE BOTH EMBEDDED AND MARGINAL COSTS IN ITS RATE 23

DESIGN? 24

A. Yes. OTP’s revenue requirement and the class revenue responsibilities recommended by 25

Ms. Ice are calculated to recover the cost of service, which is measured by embedded 26

costs. Rates must give the utility the opportunity to recover its embedded costs. By 27

using marginal costs to design those rates, OTP’s rate design maintains the benefits of 28

marginal cost price signals while still producing overall revenues that recover the cost of 29

service. The benefits of marginal cost price signals include designing rates with seasonal, 30

4 Case No. PU-17-

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and where possible, time of day differences, and promoting the efficient use of electricity 1

through appropriate price signals. 2

1. 2018 Marginal Cost Study 3

Q. WHAT IS THE DIFFERENCE BETWEEN MARGINAL COSTS AND EMBEDDED 4

COSTS? 5

A. The most important difference between these two types of costs are historical costs 6

(embedded) versus future costs (marginal). Marginal cost, as defined in OTP’s 2018 7

Marginal Cost Study, is the change in total cost of service with respect to a small change 8

in demand of a product or service. These marginal costs take into consideration changes 9

in forecasted investments at various service levels and their impacts on utility system 10

operations. 11

12

Q. HOW ARE MARGINAL COSTS DEVELOPED? 13

A. OTP engaged Ms. Amparo Nieto of NH Regulatory Consulting, LLC to develop a 14

marginal cost study covering the period 2018-2022 applicable to service in our three 15

jurisdictions (the 2018 Marginal Cost Study). The 2018 Marginal Cost Study was 16

developed with input from OTP staff regarding OTP’s planning and operating practices, 17

regional market price data, and system characteristics. OTP staff has also closely 18

reviewed the 2018 Marginal Cost Study to make sure it does in fact reflect OTP’s 19

marginal costs. A copy of the 2018 Marginal Cost Study is included as Exhibit___(DGP-20

1), Schedule 2. 21

22

Q. HOW ARE THE RESULTS OF THE 2018 MARGINAL COST STUDY APPLIED TO 23

THE RATE DESIGN PROPOSAL? 24

A. The 2018 Marginal Cost Study provides an accurate calculation of current marginal costs. 25

But those marginal costs are significantly different than those calculated in the marginal 26

cost study filed in our last rate case (the 2008 Marginal Cost Study). In order to avoid an 27

abrupt reflection of the new marginal costs in our proposed rate design, OTP tempered 28

the 2018 Marginal Cost Study results when allocating class revenue responsibilities to 29

rate classes and in the development of individual rate components. 30

31

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Q. WHAT ARE THE MAIN DIFFERENCES IN THE RESULTS OF THE 2018 1

MARGINAL COST STUDY AND THE RESULTS OF THE 2008 MARGINAL COST 2

STUDY? 3

A. All marginal energy costs have decreased, and seasonal marginal capacity costs have 4

undergone significant change. For example: 5

• Annual, summer and winter marginal energy costs are lower in the 2018 Marginal 6

Cost Study than they were in the 2008 Marginal Cost Study. Both annual marginal 7

energy costs and winter marginal energy costs have decreased by 67 percent and 64 8

percent, respectively, while summer marginal energy costs have declined 71 percent. 9

• Annual marginal capacity costs have increased 55 percent, but summer marginal 10

capacity costs have increased nearly 90 percent. At the same time, winter marginal 11

capacity costs have increased 16 percent. 12

13

Q. WHAT IS DRIVING THESE CHANGES? 14

A. There are two general drivers. First, marginal costs should reflect the wholesale market 15

place. The wholesale market is influenced by any number of factors, including federal 16

and state energy policies, various generation mixes, improvements in transmission 17

capability, other infrastructure investment, and energy consumers themselves. These 18

factors are combining in the Midcontinent Independent System Operator (MISO) market 19

in a way that results in a general trend of low energy prices and rising capacity costs for 20

the near-term. 21

The second driver is based on a change in assumptions behind the 2008 and 2018 22

Marginal Cost Studies. The 2008 Marginal Cost Study reflected OTP’s resource 23

planning approach at that time. That approach required OTP to build its system to meet 24

its system peak, which occurs during the winter. The 2018 Marginal Cost Study, 25

however, reflects OTP’s current resource planning approach. The current resource 26

planning approach is based upon OTP’s obligation to meet its MISO obligations, which 27

are measured as OTP’s load coincident with MISO’s peak. MISO’s peak occurs during 28

the summer. This shift from a planning approach focused on winter peak to one focused 29

on summer peak has a significant impact on marginal capacity costs. 30

31

6 Case No. PU-17-

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Q. ARE THERE OTHER REASONS TO USE MODIFIED RESULTS FROM THE 2018 1

MARGINAL COST STUDY WHEN DESIGNING RATES? 2

A. Yes. MISO is currently considering changes to its resource planning construct that would 3

move away from a summer-only peak and move towards a dual (i.e. summer and winter) 4

peak structure. As discussed above, the MISO capacity construct has a significant impact 5

on marginal costs, so this potential change could impact marginal costs over the next 6

several years. Reflecting this change now allows us to design rates in a way that better 7

reflects marginal costs during the period in which the rates will be in effect. 8

9

Q. HOW DID YOU MODIFY THE 2018 MARGINAL COST STUDY RESULTS? 10

A. We utilized the 2018 Marginal Cost Study to create a baseline of marginal costs and then 11

made the following adjustments: 12

• Use a modified average of marginal energy and capacity costs of years 2018-13

2022, as OTP anticipates rates to be in place for at least 3 years. 14

• Moderate the generation capacity estimates in 2018-2022 by allocating 60 percent 15

of their value to summer, and allocate the remaining 40 percent to winter. 16

17

Q. HOW DID YOU DECIDE ON A 60-40 ALLOCATION OF GENERATION 18

CAPACITY VALUES? 19

A. This allocation was a judgment decision that balances the current MISO capacity 20

construct (i.e. 100 percent of generation value in the summer, 0 percent in winter), the 21

expected MISO capacity construct (i.e., less than 100 percent of generation value in the 22

summer and greater than 0 percent in the winter), and the current levels of demand-23

capacity charges in OTP’s rate schedules. 24

25

Q. HOW WILL YOUR 60-40 PROPOSAL IMPACT RATE DESIGN? 26

A. Rate classes without demand charges will see relatively lower increases in summer rates 27

that would have occurred using the unmodified 2018 Marginal Cost Study results. The 28

60-40 proposal also results in slight increases in winter rates. All else being equal, rate 29

classes with separate energy and capacity charges will be designed with essentially the 30

7 Case No. PU-17-

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same energy charge relationships as in the unadjusted marginal cost study, but with lower 1

increases in summer demand charges and increases in winter demand charges. 2

3

Q. WHAT ARE THE BENEFITS IN THIS CASE OF USING MODIFIED RESULTS OF 4

THE 2018 MARGINAL COST STUDY? 5

A. The modifications I propose approximate the expected MISO capacity construct in the 6

near term. Further, even if the 2018 Marginal Cost Study results were not modified as I 7

propose, the pure marginal cost price signals would have been diluted at the individual 8

rate design level because the pure price signals would have been too extreme to 9

implement in a single case. Finally, by using this approach, all rates will be designed 10

based on my proposed allocation, thereby providing improved consistency across all 11

classes and important price signals for expected generation seasonal capacity values. 12

2. Proposed Intra-Class Revenue Allocation 13

Q. HOW ARE CLASS REVENUE RESPONSIBILITIES ALLOCATED TO RATE 14

CLASSES? 15

A. When the customer class has two or more rate classes, the class revenue responsibilities 16

developed by Ms. Ice generally are allocated to the individual rate classes based on the 17

EPMC methodology.1 18

19

Q. DO THE CLASS REVENUE RESPONSIBILITIES DEVELOPED BY MS. ICE 20

INCLUDE FUEL COSTS? 21

A. Yes. The class revenue responsibilities developed by Ms. Ice include amounts currently 22

in base rates for fuel.2 OTP Witness Mr. Stuart D. Tommerdahl explains that OTP is 23

proposing to move all fuel costs out of base rates and recover those costs entirely through 24

the Energy Adjustment Rider. Exhibit___(DGP-1), Schedule 3 shows the proposed intra-25

1 A customer class is a group of customers with similar usage patterns and electrical facilities. Customers within the

customer class may have more than one rate option – or rate class. For example, the current Residential customer

class has two rates; a general service rate and a demand-controlled rate, each with their own applicability

requirements. 2 Direct Testimony of Ms. Gina S. Ice, Table 8.

8 Case No. PU-17-

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class revenue allocations, while Exhibit___(DGP-1), Schedule 4 shows the proposed intra 1

class revenue allocations including and excluding fuel costs from base rates. 2

3

Q. WHAT IS THE EPMC METHODOLOGY? 4

A. The EPMC methodology allocates the class revenue responsibilities to rate classes based 5

on each rate class’s marginal cost revenues. Marginal cost revenues for a rate class are 6

determined by multiplying the marginal cost (modified as discussed above) times the rate 7

class billing determinants. Schedule 4 describes total marginal cost revenues by 8

customer and rate class. 9

10

Q. CAN YOU PROVIDE AN EXAMPLE OF THE EPMC METHODOLOGY? 11

A. Yes. The table below provides a simplified example of the “pure” version of the EPMC 12

methodology, meaning it allocates class revenues to rate classes based entirely on the 13

marginal cost revenues calculated using the results of the marginal cost study. The 14

example is based on a customer class with two rate classes, where one rate class provides 15

80 percent of the overall marginal cost revenues for that customer class and the other rate 16

class provides 20 percent of the overall marginal cost revenues for that customer class. 17

18

Table 1 19

Simplified EPMC Methodology Example 20

Marginal Cost

Revenue

Percentage

Revenue

Responsibility

Rate Class A 80% (a)

Rate Class B 20% (b)

Class Revenue Responsibility $100,000 (c)

Rate Class A $80,000 [(a)*(c)]

Rate Class B $20,000 [(b)*(c)]

21

Q. WHAT ARE THE BENEFITS OF THE EPMC METHODOLOGY? 22

A. The EPMC methodology is aligned with two of our rate structure objectives – efficiency 23

and gradualism. Using marginal cost-based revenues to allocate revenue from customer 24

classes to rate classes sets efficient revenue targets for rates within a class. 25

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Q. HAS THE EPMC METHODOLOGY BEEN USED AND ACCEPTED IN OTP’S 1

JURISDICTIONS? 2

A. Yes. The Commission approved OTP’s use of the EPMC methodology in OTP’s last 3

general rate case (Case No. PU-08-862). The Minnesota Public Utilities Commission and 4

the South Dakota Public Utilities Commission approved the use of the EPMC 5

methodology in OTP’s last general rate cases in each of those jurisdictions (MN PUC 6

Docket No. E017/GR-15-1033 and SD PUC Docket No. EL10-011). 7

8

Q. IS OTP PROPOSING TO USE A MODIFIED VERSION OF THE EPMC 9

METHODOLOGY? 10

A. Yes. I recommend using a modified version of the EPMC methodology to allocate class 11

revenues to rate classes. 12

13

Q. WHY IS OTP PROPOSING TO USE A MODIFIED VERSION OF THE EPMC 14

METHODOLOGY IN ALLOCATING CLASS REVENUES TO RATE CLASSES? 15

A. The pure EPMC method would have resulted in dramatic changes in rate class revenue 16

responsibilities, which is inconsistent with our rate structure objectives of gradualism and 17

rate continuity. Using the modified version of the EPMC methodology allowed us to 18

balance the efficiency benefits of marginal cost-based rates with other important rate 19

structure objectives. 20

21

Q. PLEASE DESCRIBE HOW OTP APPLIED THE EPMC METHODOLOGY. 22

A. OTP utilized three EPMC approaches to allocate class revenues for those classes that 23

have more than one rate class (except for Other Public Authority class, discussed below). 24

The three approaches have different levels of gradualism from the pure or strict 25

application of EPMC, thereby mitigating the abruptness of rate changes. 26

1. Method 1 – This method modifies the results from strict application of EPMC 27

within a class and was applied to four of the six customer classes. Under this 28

method, the target revenue for a rate class is 50 percent of the difference between: 29

(1) the overall percentage revenue increase proposed by Ms. Ice for the customer 30

class (excluding fuel); and (2) the percentage revenue increase that would result 31

10 Case No. PU-17-

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from applying EPMC to each rate class within the customer class. This approach 1

also recognizes the objective of gradualism. 2

2. Method 2 – This method utilizes a blended variation between Method 1 and a 3

strict application of EPMC within a customer class. This method was applied to 4

two customer classes. The purpose of this method is to bring the rate classes 5

within the customer class into better alignment with cost responsibility. Under 6

this method, we continue to gradually reduce the distance between revenue 7

increase allocation within the Rate Class. 8

3. Method 3 – This is an iterative method that uses a blended variation between two 9

rate classes within the Lighting customer class. It is an iterative continuation of 10

Method 2, with the goal to reach a reasonable target as close as possible to the 11

overall class percent change. 12

13

Q. WHICH EPMC METHODOLOGY DID YOU USE FOR EACH CUSTOMER CLASS? 14

A. The table below identifies which EPMC method for each customer class. 15

16

Table 2 17

Summary of EPMC Methods for Customer Classes with Multiple Rate Classes 18

19

Customer Class EPMC

Method

Residential Method 2

Farm N/A

General Service Method 2

Large General Service Method 1

Irrigation Method 1

Outdoor Lighting Method 3

Water Heating Control N/A

Other Public Authority N/A

Controlled Service - Interruptible Method 1

Controlled Service - Deferred Method 1

20

For further details on individual rate EPMC results, see Schedule 4. 21

22

11 Case No. PU-17-

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Q. HOW DID YOU ALLOCATE THE OTHER PUBLIC AUTHORITY CUSTOMER 1

CLASS REVENUES TO RATE CLASSES? 2

A. Other public authority class revenues were allocated to each rate class uniformly at the 3

same percentage increase as recommended by Ms. Ice for the customer class overall. An 4

EPMC approach was not required because a majority of the revenues from this class are 5

from one rate class. 6

C. Development of Individual Rate Components 7

Q. WHAT IS THE NEXT STEP IN THE RATE DESIGN PROCESS AFTER 8

ALLOCATING CUSTOMER CLASS REVENUES TO RATE CLASSES? 9

A. After class revenues are allocated to rate classes, the individual rate components for each 10

class are developed. 11

12

Q. WHAT ARE THE COMPONENTS OF CUSTOMER RATES? 13

A. There are three general rate components: energy charges, demand or capacity charges, 14

and fixed charges. The rate design for different rate classes may or may not include each 15

component. For example, the standard Residential rate currently does not include a 16

separate demand or capacity charge because omitting such charges makes the rate 17

structure simpler and avoids the need to install more costly metering that has the 18

capability to measure demand. In contrast, the Residential Demand Control rate is a more 19

complicated rate and does employ a more costly meter to measure demand. And for 20

further contrast, the proposed Residential Time of Day rate utilizes three charge periods 21

per season versus the other rates with only a single charge period per season. 22

1. Fixed Charges Defined 23

Q. WHAT ARE FIXED CHARGES? 24

A. Fixed charges are monthly per-customer charges that do not vary with usage. They 25

typically take the form of customer charges and local facilities charges. OTP’s rate 26

schedules include both customer charges and facilities charges, though for most classes, 27

the facilities charge is set at $0.00. 28

29

12 Case No. PU-17-

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Q. WHAT COSTS ARE TYPICALLY RECOVERED THROUGH FIXED CHARGES? 1

A. Fixed charges are typically used to recover costs of service that do not vary with 2

electricity consumption after the customer connects to the grid. These costs include 3

marginal customer-related expenses, such as installing, operating and maintaining the 4

meter and service drop, conducting meter reading and billing activities, and providing 5

marketing or other informational services. 6

Fixed charges can also recover the cost of connecting to the local distribution 7

system, including the required transformers, secondary lines or local primary lines that 8

may need to be added or expanded to accommodate the customer’s expected maximum 9

demand over the life of the facilities. The type of distribution connection policy in place 10

will determine the local facilities costs that are to be recovered in rates as opposed to up-11

front. If customers within the class are relatively homogeneous, the local facilities costs 12

may be recovered in a per-customer monthly fixed charge, calculated on the basis of the 13

class average kW of design demand, as opposed to the individual customer’s design 14

demand.3 Distribution facilities costs are recovered as a monthly fixed charge in the 15

2018 Marginal Cost Study. 16

17

Q. PLEASE PROVIDE ADDITIONAL DISCUSSION OF WHAT COSTS ARE 18

CLASSIFIED AS CUSTOMER-RELATED IN THE 2018 MARGINAL COST STUDY. 19

A. Marginal customer-related costs are costs that vary with the number of customers on the 20

system. Marginal customer costs vary by customer type within the class but do not vary 21

with on-going changes in usage. The following costs are classified as customer-related in 22

the 2018 Marginal Cost Study: annualized investment and operation and maintenance 23

(O&M) expenses on meters and service drops; customer account expenses (such as 24

3 A “design demand” or “contract demand” is equivalent to a capacity that is reserved in the transformer for all

customers connected to it. It is thus appropriate for a per-contract kW charge, or else as part of the fixed customer

charge assuming that there is enough heterogeneity in the peak demands within the class. A daily demand charge

measures actual metered demand, and recognizes that demand reductions can free up space for other customers at

the high voltage distribution system, and therefore it is appropriate for recovery in volumetric charges. If there are

different customer densities in the service territory, such as rural and urban areas, rural local facilities costs may be

higher than urban and in that case, it may be best to have a monthly facilities cost per kW that differs by area type to

avoid subsidization of rural areas by urban customers, unless the line extension policy already corrects for that. A

facility charge may not be feasible by OTP at this time, however, since it would require metering capability that is

able to register non-coincident peak demand.

13 Case No. PU-17-

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meter-reading, billing, and collection); and customer service and informational expenses 1

such as call centers. Certain supervisory costs and administrative and general expenses 2

associated with growth in customer-related costs are also classified as customer-related. 3

Ultimately, because these costs do not vary with usage, they are appropriately recovered 4

in a fixed monthly component of the rate. 5

2. Proposed Fixed Charges 6

Q. WHAT CUSTOMER CHARGES IS OTP PROPOSING IN THIS CASE? 7

A. The table below shows the proposed customer charge component of the fixed charges. 8

9

Table 3 10

Proposed Customer Charges 11

($/Month) 12

Class Present Proposed

Residential $8.00 $17.70

Residential – Demand Control $18.38 $20.10

Farm Service – Single Phase $12.00 $17.40

Farm Service – Three Phase $12.00 $17.40

Small General Service $13.00 $24.90

General Service (Secondary) $12.00 $31.90

General Service – Time of Use $16.00 $219.00

Large General Service (Secondary) $40.00 $215.90

Large General Service – Time of Day (Primary) $60.00 $282.00

Irrigation – Option 1 $1.00 $24.30

Irrigation – Option 2 $5.00 $24.30

Outdoor Lighting – Metered $2.00 $2.00

Outdoor Lighting – Non-metered $0.00 $0.00

Municipal Pumping (All) $4.00 $26.50

Civil Defense $1.00 $1.22

Water Heating $1.00 $4.00

Controlled Service – Interruptible- Large #1 $4.00 $20.20

Controlled Service – Interruptible- Large #2 $5.00 $20.20

Controlled Service – Interruptible - Small $2.00 $8.50

Deferred Load Service $3.00 $8.80

Fixed Time of Service (Secondary) $1.50 $6.70

13

14 Case No. PU-17-

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Q. DID OTP CONSIDER MARGINAL COST IN SETTING THE PROPOSED 1

CUSTOMER CHARGES? 2

A. Yes. Exhibit___(DGP-1), Schedule 5 compares present customer charges to marginal 3

customer-related costs from the 2018 Marginal Cost Study. OTP recommends bringing 4

customer charges for all classes into better alignment with marginal costs. 5

6

Table 4 7

Proposed Customer Charge as Percentage of Marginal Cost – Secondary Service 8

($/Month) 9

Class 2018

Marginal Cost

Proposed

Customer Charge

Proposed

Customer Charge

as Percent of

2018 Marginal Cost

Present

Customer Charge as

Percent of

2008 Marginal Cost

Residential $17.70 $17.70 100.0% 79%

Residential –

Demand Control $20.18 $20.10 99.6% 110%

Farm Service –

Single Phase $17.42 $17.40 99.9% 97%

Farm Service –

Three Phase $17.42 $17.40 99.9% 97%

Small General

Service $24.94 $24.90 99.8% 74%

General Service

(Secondary) $31.91 $31.90 100.0% 45%

General Service

TOU $219.05 $219.00 100.0% 6%

Large General

Service (Secondary) $215.95 $215.90 100.0% 16%

Large General

Service – Time of

Day (Primary)

$282.08 $282.00 100.0% 20%

Irrigation – Option 1 $24.33 $24.30 99.9% 4%

Irrigation – Option 2 $24.33 $24.30 99.9% 2%

Outdoor Lighting –

Metered $0.30 $2.00 667% 47%

Outdoor Lighting –

Non-metered $0.30 $0.00 0.0% 0%

Municipal Pumping

(All) $26.55 $26.50 99.8% 16%

Civil Defense $26.55 $1.22 4.6% 4%

Water Heating $5.59 $4.00 71.6% 15%

Controlled Service -

Interruptible- Large

#1

$20.27 $20.20 99.7% 12%

15 Case No. PU-17-

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Class 2018

Marginal Cost

Proposed

Customer Charge

Proposed

Customer Charge

as Percent of

2018 Marginal Cost

Present

Customer Charge as

Percent of

2008 Marginal Cost

Controlled Service -

Interruptible- Large

#2

$20.27 $20.20 99.7% 15%

Controlled Service –

Interruptible-Small $20.27 $8.50 41.9% 14%

Deferred Load

Service $8.86 $8.80 99.3% 17%

Fixed Time of

Service $6.71 $6.70 99.9% 9%

1

Q. IS IT IMPORTANT FOR FIXED CHARGES TO BE ALIGNED WITH MARGINAL 2

COSTS? 3

A. Yes. As discussed in more detail below, aligning fixed charges with marginal costs 4

promotes fairness among customers and encourages the efficient use of resources. 5

a) Intra-Class Equity 6

Q. WHY DOES ALIGNING FIXED CHARGES WITH MARGINAL COSTS PROMOTE 7

FAIRNESS AMONG CUSTOMERS? 8

A. When fixed charges are set below marginal cost, the balance of the costs that should be 9

recovered through fixed charges are instead recovered through volumetric charges. This 10

means that customers with usage that exceeds the class average pay more than their fair 11

share of the fixed cost of service. By aligning fixed charges with marginal costs, OTP’s 12

proposed rate design makes important steps to improve customer equity. 13

14

Q. SHOULD FIXED CHARGES BE KEPT UNREASONABLY BELOW MARGINAL 15

COSTS AS A MEANS OF ADDRESSING AFFORDABILITY FOR RESIDENTIAL 16

CUSTOMERS? 17

A. No. Low usage is not always correlated with low income and some low-income 18

customers are in fact, high electricity users. Keeping fixed charges unreasonably below 19

marginal cost helps Residential customers with usage below the class average usage, but 20

there is nothing in this approach that means the benefits go to those that need them. 21

Ultimately, keeping fixed charges unreasonably below marginal cost is a very inefficient 22

means of helping low income customers, as the benefits flow to both low income and 23

16 Case No. PU-17-

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higher income customers. Direct assistance such as the Low Income Home Energy 1

Assistance Program (LIHEAP) is a more reasonable approach for addressing 2

affordability. 3

4

Q. DO YOU HAVE ANY DATA SHOWING THAT AN ARTIFICIALLY LOW FIXED 5

CHARGE IS NOT AN APPROPRIATE MEANS OF ADDRESSING 6

AFFORDABILITY FOR OTP’S LOW-INCOME RESIDENTIAL CUSTOMERS? 7

A. Yes. The table below shows the average usage of OTP’s low-income Residential 8

customers4 is greater than the average usage of the OTP Residential population overall 9

and is greater than the average usage of the OTP non-low income Residential customer 10

population. Further, OTP’s low-income customers are more likely than the OTP 11

Residential population at large to fall into the group that pays more than their fair share of 12

the cost of service when fixed charges are kept artificially low. All of this means that 13

more low-income Residential customers are harmed by keeping fixed charges below 14

marginal cost than are helped. 15

16

Table 5 17

Comparison of Residential Service (Section 9.01) Usage 18

(2016 Usage Data) 19

Residential

Customers

Low-Income

Customers

Non-Low Income

Customers

Average Monthly Usage (kWh / Month) 786 1,184 774

Percentage of Customers with Usage in

Excess of 750 kWh / Month5 41% 58% 40%

Number of Customers with Usage in

Excess of 750 kWh / Month 15,241 617 14,624

20

Additional details regarding the usage characteristics of the Residential class are 21

available in Exhibit___(DGP-1), Schedule 6. At least for OTP’s customers, there does 22

not appear to be a strong relationship between income and usage. 23

24

4 For purposes of this Direct Testimony, low-income is defined as those customers receiving LIHEAP assistance. 5 The true breakeven point for full recovery of marginal costs is the class average, or approximately 786 kWh. For

analytical purposes, we have used 750 kWh as the breakeven point.

17 Case No. PU-17-

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Q. ARE THERE OTHER ELEMENTS OF OTP’S CUSTOMER POPULATION THAT 1

MAKE INTRA-CLASS EQUITY ESPECIALLY IMPORTANT? 2

A. Yes. Our service area is predominantly rural and many customers rely on electricity for 3

heating. Customers with electric heating are more likely to have usage that exceeds the 4

class average, meaning they end up paying more than their fair share of the cost of 5

service when fixed charges are kept below marginal cost. The mere fact that these 6

customers live where they do and have limited heating options means they are uniquely 7

harmed by keeping fixed charges at unreasonably low levels. 8

9

Q. IS THERE ANY DATA THAT INDICATES LOW-INCOME CUSTOMERS ARE 10

PARTICULARLY RELIANT ON ELECTRICITY FOR HEATING PURPOSES? 11

A. Yes. The figure below compares average monthly usage for OTP’s overall Residential 12

customer population and the low-income and non-low income subgroups. Low-income 13

customers’ winter usage is significantly higher than the usage of the Residential 14

population overall and of non-low income customers during winter months. The 15

differential in usage being so much more pronounced in the winter months indicates that 16

the low-income population relies more on electricity for heating purposes than does the 17

non-low income and Residential populations overall. 18

18 Case No. PU-17-

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Figure 1 1

Comparison of Monthly Residential Service (Section 9.01) Customer Usage 2

(2016 Usage Data) 3

4

5

Q. HOW DOES OTP’S PROPOSED RESIDENTIAL CUSTOMER CHARGE COMPARE 6

TO CUSTOMER CHARGES PAID BY OTHER, NON-OTP CUSTOMERS? 7

A. The figure below compares OTP’s present and proposed Residential customer charges to 8

those of other North Dakota investor owned utilities and cooperatives that serve 9

customers in close proximity to the areas served by OTP. OTP’s proposed Residential 10

customer charge is moderate when compared to other Residential customer charges. 11

19 Case No. PU-17-

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Figure 2 1

Comparison of Residential Fixed Charges 2

($/Month) 3

4

5

Importantly, many of our customers have neighbors that pay significantly higher 6

fixed charges than what we propose. For example, the figure below shows a group of 7

premises: some served by OTP and others served by Northern Plains Electric Cooperative 8

(inside the marked box). The OTP customers currently pay a monthly customer charge 9

of $8.00; the Northern Plains Electric Cooperative customers pay a monthly customer 10

charge of $39.00. 11

20 Case No. PU-17-

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Figure 3 1

Comparison of Customers 2

3

4

Q. ARE THERE COST-BASED REASONS FOR OTP’S FIXED CHARGES TO BE 5

HIGHER THAN OTHER NORTH DAKOTA INVESTOR OWNED UTILITIES? 6

A. Yes. As discussed above, fixed charges are intended to recover costs that do not change 7

when a customer uses more (or less) electricity or demand after connecting to the grid. 8

Some of these costs have little relationship to the number of customers served. For 9

example, every utility, no matter the size, needs a billing system. A larger utility can 10

spread the costs of that billing system across more customers, which, all else being equal, 11

would lead to lower fixed charges. OTP is smaller than North Dakota’s other investor 12

owned utilities and therefore has fewer customers over which to spread customer-related 13

costs. 14

Also, some of the costs recovered through fixed charges depend on customer 15

density. Meter reading would be an example: a more densely packed system will have 16

lower meter reading costs, again, all else being equal. Unlike North Dakota’s other 17

investor owned utilities, OTP does not serve North Dakota’s major cities. 18

19

21 Case No. PU-17-

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Q. ARE THERE OTHER REASONS FOR OTP TO HAVE HIGHER FIXED CHARGES 1

THAN LARGER, MORE URBAN UTILITIES? 2

A. Yes. With a less densely populated system, OTP must deploy more transformers per 3

customer than do more urban utilities. Also, we deploy larger transformers (and the 4

minimum load our system is designed to handle is larger) given our customers’ use of 5

electricity for heating purposes. All else being equal, more and larger transformers 6

would lead to higher fixed costs that are recovered through fixed charges. 7

8

Q. ARE THERE ANY OTHER FACTORS THAT RELATE TO THE FAIRNESS OF 9

OTP’S PROPOSED FIXED CHARGES? 10

A. Yes. OTP’s rate design proposal does not change the total amount to be collected from 11

customers – only the balance between amounts collected through the fixed charges and 12

the amounts collected through the energy charge. Increases in fixed charges are offset by 13

reductions in energy charges. Customers with usage that is equal to the class average will 14

see no change in the total bill as a result of the fixed charge proposal. 15

b) Conservation and Self-Generation 16

Q. DO OTP’S PROPOSED FIXED CHARGES COMPROMISE EFFICIENT 17

CONSERVATION INCENTIVES? 18

A. No. OTP’s proposed fixed charges do not harm efficient conservation initiatives. By 19

using marginal costs to design rates, OTP’s overall rate structure includes price signals 20

that allow customers to compare the incremental cost of service (though averaged over 21

the season) with the incremental value of using more energy. Such price signals 22

encourage the efficient use of resources and provide a sound basis for customers to assess 23

the value of conservation. 24

25

Q. WHAT IS THE IMPORTANCE OF THE WORD “EFFICIENT” IN THE PHRASE 26

“EFFICIENT CONSERVATION INCENTIVES”? 27

A. Public policy does not support conservation at any cost. We want to encourage 28

economically efficient conservation efforts. Setting rates that reflect the marginal cost of 29

30

22 Case No. PU-17-

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service helps send appropriate price signals that ultimately incentivize economically 1

efficient conservation. 2

3

Q. PLEASE EXPLAIN HOW ARTIFICIALLY LOW FIXED CHARGES DO NOT 4

ENCOURAGE ECONOMICALLY EFFICIENT CONSERVATION. 5

A. When fixed charges are set too low, costs that are unrelated to usage are more likely to be 6

shifted to volumetric charges. Artificially high volumetric prices, all else being equal, 7

incentivize customers to reduce usage below optimal levels or self-generate. Such 8

reductions result in an inefficient use of the capacity that is available. If customers self-9

generate due to excessive volumetric charges, that decision represents uneconomic 10

bypass of the system because the total cost of service for all customers (those with self-11

generation and those without self-generation) will increase. 12

13

Q. ARE THERE BETTER WAYS TO PROMOTE CONSERVATION? 14

A. Yes. OTP’s Water Heating – Controlled Service Rider is a very effective way to achieve 15

energy conservation goals and promote more optimal patterns of usage. A well designed 16

direct load control program keeps marginal cost principles in mind so that customers’ 17

benefits (in the form of bill reductions) are aligned with avoided cost to the utility over 18

time. Marginal cost-based rates that signal the higher cost of service in the hours in the 19

day when electricity costs are the highest or when capacity is strained so that load 20

reductions provide the highest value to the utility and the system overall. 21

Dynamic rates (such as Critical Peak Pricing, or Peak Time Rebate) can provide 22

the strongest conservation signals. Less dynamic but still useful for conservation 23

purposes are marginal-cost based time of use (TOU) rates, which may include either a 24

super peak kWh charge or an on-peak demand charge to reflect peak marginal energy and 25

capacity costs, including marginal generation capacity, transmission and high-voltage 26

distribution costs. 27

28

23 Case No. PU-17-

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IV. INDIVIDUAL RATE PROPOSALS 1

A. Residential Class 2

Q. WHAT RATE SCHEDULES ARE INCLUDED IN THE RESIDENTIAL CLASS? 3

A. There are two rate schedules in the Residential Class: Residential Service (Section 9.01) 4

and Residential – Controlled Demand (Section 9.02). 5

6

Q. PLEASE DESCRIBE YOUR RATE DESIGN PROPOSAL FOR THE 9.01 7

RESIDENTIAL SERVICE RATE. 8

A. We are proposing to eliminate the winter declining block and make rate level 9

adjustments. This rate includes a monthly customer charge, a minimum bill equal to that 10

customer charge, and a flat seasonally differentiated energy charge. The energy charges 11

are set at levels necessary to meet the revenue requirement not satisfied by the customer 12

charge. The proposed energy charges, although purposely above marginal cost, provide 13

an efficient price signal for Residential customers. The proposed customer charge is 100 14

percent of marginal cost, as discussed above. Marginal costs for facilities were 15

developed based on customer usage, a proxy for design demand, tied to transformer and 16

other customer-related distribution equipment. 17

18

Table 6 19

Comparison of Current and Proposed 9.01 Residential Rate and Marginal Costs 20

21

22

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Q. WHAT ARE THE BILL IMPACTS OF YOUR PROPOSED 9.01 RESIDENTIAL 1

RATE? 2

A. To analyze bill impacts from each of OTP’s proposed rates, we computed an average 3

customer’s billing determinants for each customer duo-decile (20 equal segments) and 4

calculated that customer’s bill under current rates and under proposed rates for each rate 5

schedule within each class, using 2018 forecasted billing information (OTP’s Test Year). 6

We then created bar charts showing the average monthly bill changes (dollar amounts 7

and percentage) for the duo-deciles of customers, ordered by average monthly kWh use. 8

Each bar represents 5 percent of customer accounts in the class. It is important to keep in 9

mind that the smallest one or two bars probably include significant numbers of customers 10

who were not on the system for the entire year, are seasonal customers, or are anomalies 11

such as customers who shifted from one rate to another (or shifted load to a rider) during 12

the year. 13

As the bar chart for Residential customers shows, most of the Residential 9.01 14

customers will see annual average monthly impacts of less than $10. 15

16

Figure 4 17

18

19

25 Case No. PU-17-

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RESIDENTIAL-CONTROLLED DEMAND RATE. 2

A. OTP’s proposed Residential Controlled Demand (RCD) rate retains the current rate 3

design. As shown in the table below, the proposal continues with seasonal energy 4

charges above marginal cost to achieve the embedded revenue requirement for this class. 5

The demand charges for summer and winter are set at equal rates. The flat demand 6

charge proposal deviates from marginal costs because the rate design is in transition. 7

This rate is designed for reducing demand in the winter when OTP’s system peaks. As 8

discussed above, however, OTP’s capacity obligation under MISO’s Module E construct 9

is based upon summer peak. Therefore, setting seasonal demand charges equally signals 10

to the customer the value of demand in both seasons and the importance of responding to 11

demand signals. The current demand charges are levied with a 12-month ratchet, using 12

only the winter season. The facilities charges are not included as a separate charge in the 13

rate design. Customer Charge is at 99.6 percent of the marginal cost. 14

15

Table 7 16

Comparison of Current and Proposed 9.02 Residential Controlled Demand 17

and Marginal Costs 18

19

20

Q. WHAT ARE THE BILL IMPACTS FROM YOUR PROPOSED 9.02 RESIDENTIAL 21

CONTROLLED DEMAND RATE? 22

A. The bill impacts, shown in the figure below, are fairly consistent in percentage terms, 23

ranging from 24 to 30 percent, across groups of customers with increasing average 24

monthly energy consumption. For comparison purposes, the 2018 Test-Year average 25

26 Case No. PU-17-

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customer usage on Residential Controlled Demand is greater than the Residential Service 1

Customer by a factor of about 2.6. 2

3

Figure 5 4

5

6

B. Farm Class 7

Q. ARE YOU PROPOSING ANY RATE STRUCTURE CHANGES FOR THE FARM 8

CLASS? 9

A. Yes. In the table below, the energy charges for summer and winter are above marginal 10

cost. The customer charges are set at 100 percent of marginal cost. My rate structure 11

proposal is to collapse the facilities charges into a single charge for both single and three-12

phase service. Facilities charges for single phase and three phase are set at levels 13

necessary to meet the revenue requirement not satisfied by the energy charges. 14

27 Case No. PU-17-

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Table 8 1

Comparison of Current and Proposed 9.03 Farm Service and Marginal Costs 2

3

4

Q. WHAT ARE THE BILL IMPACTS FROM YOUR PROPOSED FARM RATE? 5

A. As shown in the figure below, approximately 80 percent of customers (the first 16 duo-6

deciles) see annual average monthly bill increases of less than $20 per month. The 7

remaining four duo-deciles (20 percent of the customers) have increases of approximately 8

10 to 11 percent. 9

28 Case No. PU-17-

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Figure 6 1

2

3

C. General Service Class 4

Q. WHAT RATE SCHEDULES ARE YOU PROPOSING TO INCLUDE IN THE 5

GENERAL SERVICE CLASS? 6

A. There are three rates within the General Service Class: Small General Service (Under 20 7

kW) (Section 10.01); General Service (20 kW or Greater) (Section 10.02); and General 8

Service – Time of Use (Currently Section 10.04, proposed to be Section 10.03). 9

10

Q. PLEASE DESCRIBE YOUR RATE DESIGN PROPOSAL FOR THE 10.01 SMALL 11

GENERAL SERVICE (UNDER 20 KW) RATE. 12

A. As shown in the table below, OTP proposed energy charges for the Small General 13

Service (Under 20 kW) above marginal cost. I also propose a customer charge at 99.9 14

percent of marginal cost. The minimum bill is equal to the sum of the customer charge 15

and facilities charge. 16

29 Case No. PU-17-

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Table 9 1

Comparison of Current and Proposed 10.01 Small General Service (Under 20 kW) 2

Rate and Marginal Costs 3

4

5

Q. WHAT ARE THE BILL IMPACTS FROM YOUR PROPOSED 10.01 SMALL 6

GENERAL SERVICE (UNDER 20 KW) RATE? 7

A. The average annual monthly bill increases for the Small General Service (Under 20 kW) 8

rate range from a negative 2 to 93 percent. About 90 percent of the class (represented by 9

the first 18 duo-deciles) will see an increase of less than $10.00/month. The rest will see 10

some savings. 11

30 Case No. PU-17-

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Figure 7 1

2 3

Q. PLEASE DESCRIBE YOUR RATE DESIGN PROPOSAL FOR 10.02 GENERAL 4

SERVICE (20 KW OR GREATER). 5

A. In this case, we have introduced a differentiation between the customer charges for 6

primary and secondary service in order to reflect the difference in marginal cost of 7

service between the two. As shown in the table below, the proposed customer charges 8

and facilities charges are set approximately at cost. The proposed energy charge is set 9

above marginal energy costs to meet the revenue requirement not satisfied by other 10

charges. The minimum bill is the sum of the customer and facilities charges. 11

31 Case No. PU-17-

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Table 10 1

Comparison of Current and Proposed 10.02 General Service (20 kW or Greater) 2


4

5

Q. WHAT ARE THE BILL IMPACTS FROM YOUR PROPOSED RATE CHANGES TO 6

THIS RATE? 7

A. The figure below shows about 50 percent of customers have annual average monthly bill 8

increases of 10 percent or less. The dollar-level impacts are fairly consistent for most of 9

the duo-deciles because of fixed charge increases. 10

32 Case No. PU-17-

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Figure 8 1

2

3

Q. PLEASE DESCRIBE YOUR RATE DESIGN PROPOSAL FOR THE 10.03 GENERAL 4

SERVICE-TIME OF USE RATE. 5

A. The proposed rate, shown in the table below, continues with seasonally differentiated 6

charges and sets the on-peak (declared peak) energy charges at full marginal cost (i.e. 7

energy plus demand) expected in the hours likely to be defined as system peak hours. 8

The declared peak hours are proposed to move from approximately 200 hours per year to 9

approximately 100 hours per year. The proposed shoulder and off-peak energy charges 10

are set above marginal energy costs to meet the revenue requirement not satisfied by 11

other charges. This rate structure continues to give a strong, efficient, and transparent 12

price signal to customers during critical hours. The rate includes a customer charge and 13

sets the minimum bill at the sum of the customer charge, the facilities charge, and a 14

minimum 20 kW demand (same concept as in the Large General Service, 10.04). 15

We are also proposing a slight modification to the classification of peak and off-16

peak hours under this rate by extending the time of day concept to Sundays. 17

33 Case No. PU-17-

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Table 11 1

Comparison of Current and Proposed 10.03 General Service Time of Use 2


4

5

Q. WHAT ARE THE BILL IMPACTS FROM THE PROPOSED 10.03 GENERAL 6

SERVICE-TIME OF USE RATE? 7

A. There is only one customer on this rate; therefore we cannot present the duo-decile chart. 8

Bill impacts will depend on each customer’s usage patterns (season, level, and frequency 9

of use by each customer in the three different periods (on, shoulder, and off-peak)). 10

Therefore, there is a wide range of impacts that could be further influenced by how 11

customers respond to these new prices. Finally, individualized bill analysis could 12

compromise the privacy of the customer. 13

D. Large General Service Class 14

Q. WHAT RATE SCHEDULES ARE INCLUDED IN THE LARGE GENERAL SERVICE 15

CLASS? 16

A. There are five rates within the Large General Service Class: Large General Service 17

(Section 10.04), Large General Service Time of Day (Section 10.05) and Standby Service 18

(Section 11.01), Real-Time Pricing Rider (Section 14.02), and a Large General Service 19

Rider (Section 14.03). 20

21

34 Case No. PU-17-

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Q. PLEASE DESCRIBE YOUR OVERALL RATE DESIGN PROPOSAL FOR THE 1

LARGE GENERAL SERVICE CLASS. 2

A. OTP’s proposal for the Large General Service Class removes the LGS Rate declining 3

block rates in both summer and winter and otherwise continues the current designs, with 4

adjustments to rate levels, and minor language changes. 5

6

Q. PLEASE DESCRIBE YOUR RATE DESIGN PROPOSAL FOR THE 10.04 LGS 7

RATE. 8

A. The proposed LGS rate continues with single block seasonal demand but removes the 9

declining block energy charges. These charges are based on marginal costs. As shown in 10

the table below, seasonal energy charges are set above marginal costs, with summer 11

energy costs slightly lower than winter energy costs, consistent with the results of the 12

2018 Marginal Cost Study. Seasonal demand charges are set below marginal costs, with 13

the differential between summer and winter demand charges increasing from proposed 14

levels to reflect the difference in seasonal marginal costs 15

The facilities charge continues to vary by size of customer (in terms of maximum 16

annual kW) and by voltage level. These charges are approximately 100 percent of 17

marginal cost. The customer charge continues to move closer to marginal cost, and set at 18

99.9 percent. The minimum bill is set at the sum of the customer, facility, and demand 19

charges. The proposed rate retains the minimum demand at 80 kW. 20

35 Case No. PU-17-

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Table 12 1

Comparison of Current and Proposed 10.04 Large General Service 2

Rate and Marginal 3

4

5

Q. WHAT ARE THE BILL IMPACTS FROM YOUR PROPOSED 10.04 LGS RATE? 6

A. The figure below shows the annual average monthly bill impacts to the LGS Rate 7

customers. The bill impacts for this class are in the range of 7 percent to 31 percent. 8

About 75 percent of the customers on this rate will see an increase of about $400 or less 9

per month. 10

36 Case No. PU-17-

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Figure 9 1

2

3

Q. PLEASE DESCRIBE YOUR RATE DESIGN PROPOSAL FOR THE 10.05 LARGE 4

GENERAL SERVICE -- TIME-OF-DAY RATE. 5

A. OTP’s proposal for the Large General Service Time of Day (LGS TOD) rate is to 6

generally continue with the current design and adjust rate levels, as shown below. 7

We are also proposing to modify the time of day pricing periods under the LGS 8

TOD rate. This time of day pricing period modification was examined in the 2018 9

Marginal Cost Study.6 That analysis showed that the current time of day pricing periods 10

should be updated to better reflect marginal costs. The current and proposed time of day 11

pricing periods are shown in Exhibit___(DGP-1), Schedule 7. 12

The table below shows the current and proposed LGS TOD rates. 13

6 See Section II of the 2018 Marginal Cost Study.

37 Case No. PU-17-

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Table 13 1

Comparison of Current and Proposed 10.05 Large General Service Time of Day 2


4

5

Q. HAVE YOU INCLUDED A BILL IMPACTS ANALYSIS FOR THE 10.05 LARGE 6

GENERAL SERVICE – TIME-OF-DAY RATE? 7

A. No. There is only one customer currently on this rate. Bill impacts will depend on 8

customer usage patterns (season, level, and frequency of use in the three different periods 9

(on, shoulder, and off-peak)). Therefore, there is a wide range of impacts that could be 10

further influenced by how a customer responds to these new prices. Finally, 11

individualized bill analysis could compromise the confidentiality of the customer. 12

13

Q. PLEASE DESCRIBE YOUR RATE DESIGN PROPOSAL FOR THE 11.01 STANDBY 14

RATE. 15

A. OTP proposes to continue with the current design, but does propose to adjust rate levels. 16

The proposed Standby Service rate, as shown in the table below, provides three services 17

under one rate schedule. These services are Backup, Scheduled Maintenance, and 18

Supplemental Service: 19

• Backup Services is the energy and demand supplied by the utility during 20

unscheduled outages of a Customer’s generator. 21

• Scheduled Maintenance Service is the energy and demand supplied by the utility 22

during scheduled outages of a Customer’s generator. 23

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• Supplemental Service is the energy and demand supplied by the utility in addition 1

to the capability of the on-site generator. 2

3

Table 14 4

Comparison of Current and Proposed Standby Service 5


7

8

Q. WHAT ARE THE BILL IMPACTS FROM YOUR PROPOSED 11.01 STANDBY 9

SERVICE RATES? 10

A. OTP has only one customer currently taking Standby Service, therefore there are no bill 11

impacts available for the same reasons as mentioned above for the TOU rate. 12

E. Irrigation Class 13

Q. WHAT RATE SCHEDULES ARE YOU INCLUDING IN THE IRRIGATION 14

SERVICE CLASS? 15

A. There is only one rate schedule in the Irrigation Class, the Irrigation Service rate (Section 16

11.02). However, there are two service options offered under this rate. 17

18

39 Case No. PU-17-

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IRRIGATION SERVICE RATE. 2

A. OTP’s proposed rate, shown the table below, maintains the current two service options, 3

both of which provide service from April 15 through November 1. The proposal for both 4

Option 1 and Option 2 retain the customer-specific facilities charges included in the 5

current rate. 6

The Option 1 (Non-Time-Of-Use) rate continues with seasonal energy charges. 7

The Option 2 (Time-of-Use) rate consists of energy charges for off-peak, intermediate, 8

and on-peak or “declared” periods. The declared hours are defined by OTP when the 9

system is experiencing peak conditions. Like the General Service Time of Use rate, the 10

declared peak hours are proposed to move from approximately 200 hours per year to 11

approximately 100 hours per year. The proposal for Irrigation Option 2 is to set the price 12

for hours when OTP is experiencing peak conditions at 100 percent of marginal cost 13

(energy plus capacity), thereby giving Option 2 irrigation customers a transparent signal 14

to curtail use during peak periods. These “on peak” or “declared-peak” marginal costs 15

are the average marginal costs expected in the hours defined to be declared peak by OTP, 16

and they vary by season. In the intermediate hours (which include the remainder of peak 17

period hours and shoulder hours), energy and demand charges will apply. In the off-peak 18

hours, only energy charges apply. The customer charge is set at 99.9 percent of marginal 19

costs. 20

We are also proposing a slight modification to the classification of peak and off-21

peak hours under this rate by extending the time of day concept to Sundays. And the 22

proposed tariff sheets provide clarifications for the process of notifying customers of 23

declared peak periods. 24

40 Case No. PU-17-

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Table 15 1

Comparison of Current and Proposed 11.02 Irrigation Service Option 1 & 2 2


4

5

F. Outdoor Lighting Class 6

Q. WHAT RATE SCHEDULES ARE YOU INCLUDING IN THE LIGHTING SERVICE 7

CLASS? 8

A. There are two rates in the Outdoor Lighting Class: Outdoor Lighting – Energy Only 9

(Section 11.03) and Outdoor Lighting (Section 11.04). OTP is proposing to close the 10

Outdoor Lighting (Section 11.04) to new customers and replacements. This proposal is 11

discussed further in Section V.D, below. 12

13


OUTDOOR LIGHTING-ENERGY ONLY RATE (RATE CODES 748 AND 749 AND 15

744). 16

A. OTP’s proposal is shown in the table below. Customer charge will be unchanged and 17

would remain at $2.00 per month. Energy charges were increased to meet the class 18

revenue requirement. 19

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Table 16 1

Comparison of Current and Proposed 11.03 Outdoor Lighting Energy-Only 2


4

5

Q. WHAT ARE THE BILL IMPACTS OF THE PROPOSED 11.03 OUTDOOR 6

LIGHTING-ENERGY ONLY RATE. 7

A. The overall bill impacts for the rate are 25.67 percent. 8

9

Q. WHAT ARE THE BILL IMPACTS OF THE PROPOSED 11.04 OUTDOOR 10

LIGHTING RATE? 11

A. The bill impacts for each current lighting fixture are the same, 11.02 percent. 12

G. Other Public Authority Service Class 13

Q. WHAT RATE SCHEDULES ARE YOU INCLUDING IN THE OTHER PUBLIC 14

AUTHORITY SERVICE CLASS? 15

A. There are two rates in the Other Public Authority Class: Municipal Pumping Service 16

(Section 11.05) and Civil Defense – Fire Siren Service (Section 11.06). 17

18

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Q. PLEASE DESCRIBE YOUR RATE DESIGN PROPOSAL FOR THE MUNICIPAL 1

PUMPING SERVICE. 2

A. As shown in the table below, the customer charge is set at approximately 100 percent of 3

marginal costs. OTP is eliminating the fixed facilities charge per month and proposing a 4

$/kW facilities charge per month. The new facilities charges are set at marginal costs. 5

6

Table 17 7

Current and Recommended 11.05 Municipal Pumping 8

Rates and Marginal Costs 9

10

11

Q. WHAT ARE THE BILL IMPACTS OF YOUR RECOMMENDED 11.05 MUNICIPAL 12

PUMPING RATE? 13

A. The figure below reflects varied bill impacts, estimated based on similar usage and 14

demand characteristics, as the consumption levels of customers vary significantly under 15

this rate. Most of the customers have bill impacts of less than $20.00 per month. 16

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Figure 10 1

2

3

Q. PLEASE DESCRIBE YOUR RATE DESIGN PROPOSAL FOR THE 11.06 CIVIL 4

DEFENSE-FIRE SIREN SERVICE RATE. 5

A. The proposed Civil Defense-Fire Siren Rate components are shown in the table below. 6

7

Table 18 8

Current and Recommended 11.06 Civil Defense-Fire Sire Service 9

Rate and Marginal Cost 10

11

12

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Q. WHAT ARE THE BILL IMPACTS OF THE PROPOSED CIVIL DEFENSE-FIRE 1

SIREN SERVICE RATE SCHEDULE? 2

A. The bill impacts are presented in a simple monthly bill comparison in the figure below. 3

The proposed increase for this rate is 16 percent. The greatest annual dollar impact is 4

$0.12. 5

6

Figure 11 7

Monthly Bill Impacts - 11.06 Civil Defense-Fire Siren Service 8

9

H. Water Heating Service Class 10

Q. WHAT RATE SCHEDULES ARE YOU INCLUDING IN THE WATER HEATING 11

SERVICE CLASS? 12

A. There is only one rate in the Water Heating Class, the Water Heating – Controlled 13

Service Rider (Section 14.01). 14

15

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Q. PLEASE DESCRIBE YOUR RATE DESIGN PROPOSAL FOR THE 14.01 WATER 1

HEATING-CONTROLLED SERVICE RIDER. 2

A. The proposal for the Metered Water Heating Control Service (Rate Code 30-91) shown in 3

the table below increases the customer charge to approximately 71 percent of marginal 4

cost, retains the current method for calculating the Minimum Bill, and sets both seasonal 5

energy charges at levels necessary to match rate revenues to the rate’s revenue 6

requirement. The marginal costs of providing service to customers on this rate are lower 7

than the marginal cost for standard rates because OTP controls the water heaters during 8

high-cost periods. 9

10

Table 19 11

Current and Proposed 14.01 Water Heating-Controlled Service Rider 12


14

15

The Water Heating Control Service Credit (Rate Code 192) is essentially a direct 16

load-control program similar to direct load-control of central air conditioners. Under the 17

rate, in exchange for allowing OTP to interrupt the water heating service during high-cost 18

periods, OTP compensates the customer in the form of a bill credit. The credit increases 19

to $8.00 per month. 20

21

Q. WHAT ARE THE BILL IMPACTS OF THE PROPOSED 14.01 WATER HEATING-22

CONTROLLED SERVICE RIDER? 23

A. Under OTP’s proposal, shown in the figure below, no Metered Water Heating Control 24

Service (Rate Code 30-91) customer sees a monthly increase of more than $4.00. The 25

bill impacts for the Water Heating Control Service Credit (Rate Code 192), not shown in 26

the figure below, will continue to reduce the customers’ standard firm service total bill by 27

46 Case No. PU-17-

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$8.00 per month. The impact of the $8.00 credit is reflected in the duo-deciles for the 1

appropriate firm service rates (e.g. Residential Service, Section IV.A, above). 2

3

Figure 12 4

5

6

I. Controlled Service – Interruptible Class 7

Q. WHAT RATE SCHEDULES ARE YOU TO INCLUDE IN THE CONTROLLED 8

SERVICE - INTERRUPTIBLE CLASS? 9

A. There are three current rates in the Interruptible Service Class: Controlled Service – 10

Interruptible Load (CT Metering, Section 14.04) Rider; Controlled Service – Interruptible 11

Load (Self-contained metering, Section 14.05); and Controlled Service – Interruptible 12

Load (CT Metering – Option 2, Section 14.04). 13

14

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CONTROLLED SERVICE-INTERRUPTIBLE LOAD (CT METERING) RIDER, 2

OPTION 1. 3

A. The proposed Controlled Service – Option 1 Rider, shown in the table below, includes 4

increases to customer and facilities charges. The customer and facilities charge are set at 5

100 percent of marginal costs. The energy rate is at about 30 percent of marginal costs. 6

The penalty rate for energy consumed during control periods is based on the total 7

marginal cost over a year and separated into summer and winter seasons. The penalty 8

rate per kWh has been calculated based on the hourly marginal costs during periods usage 9

would be controlled. Fundamentally, the penalty rate charges customers for unauthorized 10

use during control periods. 11

12

Table 20 13

Current and Proposed 14

Option 1 Controlled Service-Interruptible Load (CT Metering) Rider 14.04 15


17

18


CONTROLLED SERVICE-INTERRUPTIBLE LOAD (CT METERING) RIDER, 20

OPTION 2. 21

A. As shown in the table below, the customer and facilities charges are set at almost 100 22

percent of marginal costs while the energy rate is at about 30 percent of marginal costs. 23

The penalty rate described above in reference to Option 1 also applies to Option 2 for 24

unauthorized use during control periods. 25

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Table 21 1

Current and Proposed 2

Option 2 Controlled Service-Interruptible Load (CT Metering) Rider Section 14.04 3


5

6

Q. WHAT ARE THE BILL IMPACTS OF THE PROPOSED 14.04 CONTROLLED 7

INTERRUPTIBLE LOAD (CT METERING) RIDER – OPTIONS 1 AND 2? 8

A. As shown in the figure below the proposed rate for Option 1 shows 65 percent of the 9

customers with average annual monthly increases around $100 and the rest of the 10

customers with increases from 8 to 23 percent. 11

The proposed rate for Option 2 shows a rate class increase of 9.5 percent. Only 11 12

customers represent this rate class, so no duo decile is available. 13

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Figure 13 1

2

3


CONTROLLED SERVICE-INTERRUPTIBLE LOAD (SELF-CONTAINED 5

METERING) RIDER. 6

A. OTP’s proposal for this rate, as shown in the table below, increases the customer and 7

facilities charges, and sets both seasonal energy charges below marginal costs. The 8

penalty for energy used during a control period is intended to deter customers from 9

unauthorized use during control periods. 10

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Table 22 1

Current and Proposed 14.05 Controlled Service-Interruptible Load (Self-Contained) Rider 2


4

5

Q. WHAT ARE THE BILL IMPACTS OF THE PROPOSED 14.05 CONTROLLED 6

INTERRUPTIBLE LOAD (SELF-CONTAINED) RIDER? 7

A. The figure below shows about 90 percent of the class customers have annual average bill 8

impacts under $14.00 per month. The remaining 10 percent of customers will see some 9

savings. 10

11

Figure 14 12

13

14

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J. Deferred Load Service Class 1

Q. WHAT RATE SCHEDULES ARE YOU PROPOSING TO INCLUDE IN THE 2

DEFERRED LOAD SERVICE CLASS? 3

A. There are two rates in the Deferred Load Service Class: Controlled Service – Deferred 4

Load Rider (Section 14.06) and Fixed Time of Service Rider (Section 14.07). 5

6


DEFERRED LOAD SERVICE RIDER. 8

A. The proposed Deferred Load Service Rider, as shown in the table below, moves the 9

customer charge to approximately 100 percent of marginal costs and increases the 10

facilities charge from $4.00 per month to $11.60 per month, at 99.9 percent of marginal 11

cost. Seasonally differentiated energy charges in the proposed design were adjusted to 12

account for the change in the customer and facilities charges. 13

The penalty for energy used during a control period is intended to deter customers 14

from unauthorized use during control periods. 15

16

Table 23 17

Current and Proposed 14.06 Deferred Load Rider Rates and Marginal Costs. 18

19

20

Q. WHAT ARE THE BILL IMPACTS OF PROPOSED 14.06 DEFERRED LOAD 21

RIDER? 22

A. As the figure below shows, 90 percent of the customers on this rider, will see bill 23

increases of less than $10.00 per month. Forty percent of the customers will see savings 24

up to 13 percent. 25

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Figure 15 1

2

3

Q. PLEASE DESCRIBE YOUR RATE DESIGN PROPOSAL FOR THE 14.07 FIXED 4

TIME OF SERVICE RIDER 5

A. The proposed Fixed Time of Service (f/k/a Fixed Time of Delivery) rider introduces 6

increases to customer charges for secondary service and increases to facilities charges for 7

all voltages to bring both customer and facilities charges closer to marginal costs. As 8

shown in the table below, the seasonal energy charges are approximately equal to 9

marginal costs expected in the hours when customers will receive service under the rider. 10

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Table 24 1

Current and Recommended 14.07 Fixed Time of Service Rider 2


4

5

Q. WHAT ARE THE BILL IMPACTS OF THE PROPOSED 14.07 FIXED TIME OF 6

SERVICE RIDER? 7

A. The figure below shows varied bill impacts for all customers on the proposed Fixed Time 8

of Service Rider, most of the customers will see a bill increase around or less than $10. 9

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Figure 16 1

2

3

K. Mandatory and Voluntary Riders 4

Q. ARE THERE ANY OTHER CHANGES TO OTP’S MANDATORY AND 5

VOLUNTARY RIDERS? 6

A. Yes. Mr. Tommerdahl and Ms. Ice discuss certain proposed changes to OTP’s 7

Mandatory Riders contained in Section 13.0 of the rate schedule. 8

V. NEW RATE PROPOSALS 9

Q. IS OTP MAKING ANY NEW RATE PROPOSALS IN THIS CASE? 10

A. Yes. We are requesting the addition of three rate schedules to allow us to better meet 11

customers’ needs. We are also proposing a new rider to facilitate the recovery of future 12

investments, modifying our Lighting service and expanding our Air Conditioning rider to 13

business customers. These proposals are discussed in more detail below. 14

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A. Residential Time of Day 1

Q. PLEASE PROVIDE A SUMMARY OF THE RESIDENTIAL TIME OF DAY-PILOT. 2

A. The Residential Time-of-Day Pilot (Pilot) proposal is aligned with our rate structure 3

objectives to offer rates with seasonal and time of day differences. It is being offered to 4

certain Residential customers, limited to 50 single-metered customers served on the 5

Residential Service (Section 9.01). The Pilot utilizes three time-of-day periods (on-peak, 6

shoulder, and off-peak) for each season (summer and winter). These time of day periods 7

are designed based on forecasts of the MISO energy market and reflect the marginal cost 8

of service. The Pilot will be under proposed Rate Schedule 9.04, a copy of which is 9

included in Volume 2D. 10

11

Q, WHAT ARE THE OBJECTIVES OF THE RESIDENTIAL TIME OF DAY-PILOT? 12

A. OTP has identified three objectives: 13

1. Learn from and respond to customers; 14

2. Assess system costs and revenues; and 15

3. Inform future Automated Metering Infrastructure (AMI) investments. 16

17

Q. PLEASE FURTHER EXPLAIN THE PILOT OBJECTIVES. 18

A. The over-arching theme of the Pilot is to learn from our customers and the impacts they 19

can make in relation to system costs and infrastructure investments. 20

1. Learn from and Respond to Customers: The Pilot introduces more granular 21

pricing that can help customers to better affect their bills through behavioral 22

changes. Some of those behavioral changes could come in the form of 23

automation (e.g. programable timers and wi-fi enabled thermostats for electric 24

vehicles/conditioned spaces), while others may relate to shifting usage to certain 25

times of the date in response to the prices charged. Once customers become 26

acclimated and comfortable with the Pilot, we expect to learn from customers 27

what strategies they used to change their usage behavior. We also expect some 28

customers may not acclimate to the designed time periods – which is also useful 29

information. Finally, we intend to assess the extent customers are able to realize 30

56 Case No. PU-17-

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bill savings without changing behavior in order to further refine future rate 1

designs. 2

2. Assess System Costs and Revenues: If customers react to the Pilot price signals 3

by shifting usage during high-price periods to lower priced-periods, OTP may 4

experience a lower cost of service. Time-shifting can also impact revenue 5

collections. Understanding these tradeoffs is important before expanding a time-6

of-day rate structure to the entire Residential class. 7

3. Inform Future AMI Investment: Facilitating additional rate options is a key 8

functionality of AMI. Lessons learned from the Pilot will help us better 9

understand the true value of that functionality. We also anticipate the Pilot will 10

help OTP assess what equipment and features are useful and provide lessons that 11

can be applied to a potential future AMI roll-out. 12

13

Q. HOW WAS THE PILOT DESIGNED? 14

A. The Pilot is built from the 2018 Marginal Cost Study time-of-day periods and associated 15

marginal costs. We compiled representative billing determinants for each pricing period 16

(e.g. summer on-peak/shoulder/off-peak; winter on-peak/shoulder/off-peak) from OTP’s 17

2016 hourly Residential load research data for customers that would be eligible for the 18

Pilot. Then, we used the 2018 Marginal Cost Study time-of-day periods and associated 19

marginal costs and the billing determinants to establish revenue neutral rates. 20

21

Q. WHAT DO YOU MEAN BY THE TERM “REVENUE NEUTRAL”? 22

A. When more than one rate is designed for a specific rate class, and the same customers can 23

choose between one or more rates in the rate class, rates are designed to recover the same 24

amount of revenue for that specific rate class no matter which rate the customer chooses. 25

It is important to design rates to be revenue neutral to maintain revenue adequacy and 26

stability. 27

28

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Q. DOES A REVENUE NEUTRAL DESIGN MEAN CUSTOMERS WILL NOT SAVE 1

MONEY IN THE PILOT? 2

A. No. The Pilot is designed based on historical usage data, meaning it reflects customers’ 3

behavior without the Pilot price signals being in place. Customers that are able to change 4

their behaviors in response to the Pilot price signals may save money. Some customers 5

participating in the Pilot may also save money without changing behavior simply because 6

their existing usage is aligned with the pricing period. 7

8

Q. ARE THESE OUTCOMES EQUALLY DESIRABLE? 9

A. No. Customers that change their usage in response to the Pilot pricing help lower costs, 10

which will ultimately benefit all customers and OTP. Capturing these kind of behavioral 11

and cost changes is one of the main goals of time-of-day pricing. One of the goals of the 12

Pilot is to better understand customers’ usage (including their ability to change usage in 13

response to more granular price signals) so that the rate design can be further refined to 14

make sure that customer savings are aligned with reductions in the cost of providing 15

service. 16

17

Q. WHAT CUSTOMERS ARE ELIGIBLE FOR THE PILOT? 18

A. There are currently about 30,500 Residential customers that are eligible for the Pilot. 19

Pilot eligibility is limited to single-metered customers taking Residential Service (Section 20

9.01). This means that customers taking Residential – Controlled Demand (Section 9.02) 21

service or utilizing our Water Heating – Controlled Service Rider (Section 14.01), other 22

Controlled Service Riders (Sections 14.04-14.05), Controlled Service – Deferred Load 23

Rider (Section 14.06) and Fixed Time of Service Rider (Section 14.07) are not eligible 24

for the Pilot. We have not included these customers in the Pilot to simplify and focus on 25

usage delivered under a single meter. This allows customers to face a single price signal 26

and funnels all electricity usage through a single point of measurement. I do note that 27

most of OTP’s Voluntary Riders are interruptible services. 28

29

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Q. HOW WILL CUSTOMERS ENTER INTO THE PILOT? 1

A. Customers will opt-in to the Pilot on a voluntary basis. OTP will, however, encourage 2

eligible customers that already participate in OTP’s load research program to enter into 3

the Pilot. As participants in OTP’s load research program, these customers already have 4

metering that is compatible with the Pilot. Data from these customers is also especially 5

valuable because OTP already has historical time-based usage data from these customers 6

that can serve as a baseline for measuring the impact of the Pilot. We also anticipate 7

participation by customers outside of the load research group in order to achieve the 8

desired sample size. To reach the desired sample size, we will utilize simple random 9

sampling of the target population, described in the Pilot eligibility above. For those that 10

agree to participate, based on availability, we will proceed to engage the customer with 11

the Pilot welcome packet containing important information about the pilot and schedule a 12

start date. 13

14

Q. WHY LIMIT THE PILOT TO ONLY 50 CUSTOMERS? 15

A. This level of customers will allow for both cost effectiveness and statistically meaningful 16

results. 17

18

Q. WHAT IS YOUR STATISTICAL BASIS FOR 50 CUSTOMERS BEING A 19

MEANINGFUL SAMPLE? 20

A. We are relying on the central limit theorem which essentially states the more sample 21

points you collect, the more the sampling distribution of the sampling mean approaches a 22

normal distribution (i.e., a bell curve). The theorem holds true for sample sizes over 30. 23

We are including additional sample points for attrition purposes. 24

25

Q. WHAT IS THE PROPOSED LENGTH OF THE RESIDENTIAL TIME OF DAY 26

PILOT? 27

A. If approved, OTP plans for the Pilot to remain open for two years, effective 28

January 1, 2019. The additional time between the final Order and implementation is 29

necessary to develop Pilot marketing materials, install metering, and establish other 30

59 Case No. PU-17-

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program monitoring. We also believe that 2-4 months is an appropriate amount of time 1

to sign customers up for the Pilot. 2

3

Q. WILL CUSTOMERS REMAIN IN THE PILOT FOR THE ENTIRE TWO YEARS? 4

A. It is OTP’s expectation that most of the Pilot participants remain engaged in the Pilot for 5

the full two years. One of the Residential Time of Day Pilot rules states: 6

Preference for participation will be given to customers who agree to a 7

minimum of 12 months participation. Customers may elect service under 8

this schedule for a trial period of three months. If a customer chooses to 9

return to other available rate schedules after the trial period, the customer 10

will pay a charge of $20.00 for removal of time of day metering 11

equipment. 12

13

Q. WILL OTP ENDEAVOR TO KEEP THE PILOT FULLY SUBSCRIBED? 14

A. Yes. We are aiming to have the Pilot fully subscribed pilot at the initial start date of 15

January 1, 2019. If there is customer attrition, we will continue outreach in order to 16

encourage participation. 17

18

Q. WILL OTP WORK WITH CUSTOMERS DURING THE PILOT? 19

A. Yes. We are seeking engaged customers that are willing to work smart on managing their 20

energy usage and OTP will be available to assist customers along the way. Specifically, 21

one of the Pilot rules is that: 22

The Company will endeavor to work with participants to assist with 23

various measures to improve energy efficiency and other cost saving 24

measures. 25

B. Super LGS 26

Q. PLEASE PROVIDE A SUMMARY OF THE SUPER LARGE GENERAL SERVICE 27

PROPOSAL. 28

A. The Super Large General Service (SLGS) proposal is primarily designed to attract high 29

load factor large/commercial customers into OTP’s service territory. Customers that meet 30

the criteria will have access to individual contract pricing based on OTP’s marginal cost 31

of service. The proposal incorporates a regulatory pre-approval process and ratepayer 32

protections that will ensure net benefits to all customers. OTP believes its proposal will 33

provide prospective customers improved speed and price certainty, making it easier for 34

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businesses to invest in North Dakota. Additional details regarding the SLGS proposal are 1

available in Proposed Rate Schedule 10.06, a copy of which is included in Volume 2D. 2

3

Q. WHY INTRODUCE A NEW RATE WHEN OTP ALREADY HAS A LARGE 4

GENERAL SERVICE RATE? 5

A. The customers OTP is targeting have much larger volume characteristics and higher load 6

factors than the existing classes and rates, which leads to a relatively lower per-kWh 7

average cost of service versus those on the existing rates. By making this proposal, OTP 8

is positioning itself to offer competitive rates that will attract these types of customers to 9

its service territory. 10

11

Q. WHAT IS THE ELIGIBILITY CRITERIA FOR THE SLGS RATE? 12

A. The SLGS rate will be available to new load (i.e. new customers or new facility opened 13

by an existing customer) that has the following characteristics: (1) expected metered 14

demand of at least 25 MW at a single metering point; (2) a load factor of at least 80 15

percent; and (3) and annual energy sales of at least 175,000 MWh’s over 12 consecutive 16

billing months. 17

18

Q. PLEASE DISCUSS WHAT YOU MEAN BY “INDIVIDUAL CONTRACT PRICING 19

BASED ON OTP’S MARGINAL COST TO SERVE.” 20

A. Unlike standard rate schedules where customers within the same rate class essentially pay 21

the same rates for customer, facility, energy and demand charges, customers served under 22

the SLGS rate would have customized rates based on their specific load characteristics 23

and investment needed to serve them. SLGS customers also would pay marginal costs 24

versus embedded costs.7 25

26

7 As discussed above, marginal costs are costs on a prospective basis (expected or forecasted) versus embedded

costs which are retrospective (historical).

61 Case No. PU-17-

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Q. DESCRIBE A NEW CUSTOMER SITUATION AND THE ASSOCIATED 1

MARGINAL COSTS OTP WOULD INCUR. 2

A. A new customer taking service under the SLGS rate will require OTP to incur marginal 3

energy and capacity costs, and may also require upstream distribution system 4

reinforcement (if the SGLG is a distribution customer), new local dedicated facilities, 5

marginal transmission costs (FERC-approved transmission rate), as well as marginal 6

customer costs (meter, service drop, and associated customer services). OTP would 7

develop marginal costs associated with the customer addition from OTP’s most recent 8

Marginal Cost Study. 9

10

Q. IS THIS MARGINAL COST-BASED PRICING APPROACH SUPPORTED BY 11

ECONOMIC THEORY? 12

A. Yes. The SLGS rate will be such that customers are paying at least their marginal cost of 13

service. This means other customers are not harmed by the SLGS pricing. Further, to the 14

extent that the marginal costs associated with the addition of a SLGS customer includes 15

certain fixed costs, adding these customers to the system makes a valuable contribution to 16

the cost of service. 17

18

Q. DOES OTP HAVE ANY OTHER SERVICE OFFERINGS THAT UTILIZE 19

MARGINAL COST-BASED RATES? 20

A. Yes. OTP offers a few rates that are priced on a marginal (prospective) basis. In the 21

Large General Service Class, there are two riders (the LGS Rider and the Real-Time 22

Pricing (RTP) Rider) that utilize estimates of day-ahead pricing in the MISO market. 23

Another group of rates of this type are known as the Small Power Production rates. For 24

those rates, OTP estimates its avoided costs and uses those estimates to pay customers 25

with distributed generation systems avoided cost rates for energy and/or capacity when 26

delivered to the OTP system. 27

28

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Q. PLEASE DISCUSS THE REGULATORY PRE-APPROVAL PROCESS IN THIS 1

PROPOSAL. 2

A. The foundation of the regulatory pre-approval process is to utilize a marginal cost-to-3

serve model and provide the model to the Commission Staff for verification of rate 4

offerings. The model houses OTP’s expected marginal unit cost to serve and the 5

customer’s expected load requirements. The marginal unit costs applied to the expected 6

customer load requirements will determine the minimum incremental revenue expected to 7

be collected under this rate. Since the individualized rate development can be verified by 8

Commission Staff, OTP can provide a price quote to the potential customer with 9

increased speed and certainty. This process offers OTP the ability to react to business 10

opportunities and to potentially serve customers in our North Dakota service territory. 11

12

Q. PLEASE DESCRIBE YOUR PROPOSED SLGS RATE 13

A. The proposed SLGS rate is shown in proposed Rate Schedule 10.06, included in Volume 14

2D. The rate schedule follows a similar design and headings as our other approved 15

schedules, with a few exceptions, as noted. 16

• Standard Rate Design Headings/Sections: 17

o Description of Service Levels and Rate Codes for Revenue/Sales Tracking 18

o Regulations, Application of Rider, and Mandatory and Voluntary Riders 19

• Non-Standard or Expanded Rate Design Headings/Sections: 20

o Scope of Rate Schedule: This non-standard addition is used to 21

communicate the purpose of the SLGS rate. Most importantly, it states the 22

rate schedule provides net benefits to all ratepayers and the use/intention 23

of marginal costs. 24

o Commission-Approved Process: As noted above, OTP is seeking a pre-25

approved process for improved speed and price certainty to assist 26

businesses in becoming a part of North Dakota and its communities. 27

Therefore, it is vital for the public to understand that OTP must seek 28

approval of rate quotes and final rates. 29

o Rate Determination: This item communicates to prospective customers 30

that marginal costs are utilized to develop the individualized rates, with 31

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revenue expectations to support the scope of the rate schedule: namely 1

provide net benefits to ratepayers, at or above OTP’s marginal costs. 2

o Terms and Conditions: This section is typical but the content is very 3

important for prospective SLGS rate eligibility and company compliance. 4

5

Q. PLEASE COMPARE THE SLGS RATE PROPOSAL TO OTP’S PROPOSED 6

ECONOMIC DEVELOPMENT RIDER. 7

A. OTP filed an Economic Development Rider (EDR) in late May 2017 (approval 8

pending).8 Both rate proposals9 fulfill a similar goal: attract business customers into 9

OTP’s service territory and provide net benefits to its ratepayers. Both the EDR and 10

SLGS rate utilize the marginal cost-to-serve model, customer load data, and OTP’s 11

standard rates and riders. The differences are by design: the EDR is designed to offer 12

customer-specific, marginal cost-based discounts on OTP’s existing rates for a period of 13

up to 5 years, whereas the SLGS offers individualized rates designed upon marginal costs 14

to serve and can be applied indefinitely, although the customer has the ability to return to 15

existing standard rates or to a real time pricing rate after a period of 5 years. 16

17

Q. WHAT IS THE RELEVANT TIMEFRAME FOR THE MARGINAL COST 18

ANALYSIS? 19

A. The relevant time-frame for the marginal cost analysis depends on the term of the SLGS 20

rate, i.e., the period before any changes to price are made. The risk of SLGS rates falling 21

significantly below actual marginal generation costs may be relatively low if SLGS rates 22

are updated every three to five years. 23

C. Generation Cost Recovery Rider 24

Q. PLEASE PROVIDE A SUMMARY OF THE PROPOSED GENERATION COST 25

RECOVERY RIDER 26

A. The proposed Generation Cost Recovery Rider (GCRR), Section 13.06, is a new recovery 27

8 Case No. PU-17-238. 9 OTP engaged the services of NH Regulatory Consulting LLC for both EDR & SLGS proposals.

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mechanism dedicated to recovering generation additions. As Mr. Tommerdahl describes, 1

the GCRR is similar to OTP’s current Transmission, Environmental, and Renewable 2

Resource recovery riders. The GCRR recovery mechanism will recover costs associated 3

with OTP’s proposed Astoria Station generation project. OTP is only proposing to 4

establish the recovery mechanism framework in this case – not to establish a rate. 5

6

Q. PLEASE DESCRIBE THE PROPOSED GENERATION COST RECOVERY 7

FRAMEWORK 8

A. OTP’s GCRR follows the same design as its current Environmental Cost Recovery Rider 9

(ECRR) (recently updated and approved in Case No. PU-17-122). Like the ECRR, the 10

proposed GCRR utilizes a cost recovery factor which will apply to customers’ bills on a 11

percentage basis. The GCRR will have its own tracker, annual revenue requirement, and 12

true-up adjustment. Finally, OTP proposes the GCRR charges be included in the current 13

“Energy and Renewable Adj” line item on the customers’ bills. 14

15

Q. WHAT IS OTP’S PROPOSED GENERATION COST RECOVERY FACTOR? 16

A. The rate will initially be set at 0.000 percent. As Mr. Tommerdahl states, OTP will make 17

a separate filing to request approval of recovery of the current and proposed costs, 18

estimated to occur in late 2018 or early 2019. 19

D. LED Street and Area Lighting – Dusk to Dawn 20

Q. PLEASE PROVIDE A SUMMARY OF THE PROPOSED LED STREET AND AREA 21

LIGHTING – DUSK TO DAWN SERVICE (LED LIGHTING SERVICE). 22

A. The proposed Light-Emitting Diode (LED) Lighting Service (Section 11.07) is a new 23

lighting products schedule comprising of LED Outdoor and Flood lighting, Aluminum 24

alloy poles, and a LED Floor Visor. Customers taking LED Lighting Service will receive 25

the same service as provided under the current Lighting offerings (illumination service, 26

including equipment installation, asset rental, electricity, and maintenance in a 27

convenient, monthly charge on the customer’s electric service bill). The LED Lighting 28

Service, however, provides LED technology advantages over conventional High-Intensity 29

Discharge (HID) lighting systems. 30

31

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Q. PLEASE DESCRIBE THE ADVANTAGES LED LIGHTING HAS OVER HID 1

LIGHTING. 2

A. The advantages are as follows: 3

1. Equipment life. LED fixture life in street and area lighting applications is often 4

rated at 100,000 hours, where equivalent HID products operate with rated lives of 5

only 10,000 to 24,000 hours. 6

2. Lumen depreciation. Lumen depreciation for most HID products can reach 50 7

percent, where most LED fixtures often operate at 70 percent of rated lumen output at 8

end of rated life. 9

3. Energy efficiency. E Source reports that the average efficacy of 100-, 250- and 400-10

watt HID street and area lighting fixtures is about 61 lumens per watt. Equivalent 11

LED fixtures operate at an average efficacy of 94 lumens per watt, or about 55 12

percent more efficiently, than HID. 13

4. Light quality. Today’s LED fixtures operate at a much higher color rendering index 14

(CRI) than most HID products, enabling drivers and pedestrians to more safely 15

observe night time conditions due to improved light quality. 16

17

Q. WHY IS OTP MAKING THIS PROPOSAL? 18

A. OTP believes the time is right where prices for the technology are now reasonable, and 19

the technology is a proven long-lasting efficient lighting solution. In addition, numerous 20

North Dakota communities served by OTP are requesting LED lighting. 21

22

Q, WILL YOUR NEW LED FIXTURES BE COMPATIBLE WITH YOUR CURRENT 23

OFFERINGS? 24

A. Yes. We have worked closely with our lighting supplier to provide compatibility with our 25

existing offerings. OTP also took the opportunity to go further regarding our selections. 26

We are aware some communities would like to meet Dark Sky Compliance rules. 27

Because of their interest, we are adding a visor option for the proposed flood lights to 28

limit light trespass and potential up-light. The products are known as “nighttime friendly” 29

66 Case No. PU-17-

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and consistent with LEED10® goals and Green Globes11™ criteria for light pollution 1

reduction. 2

3

Q. DID OTP SELECT NEW AND AVAILABLE LED TECHNOLOGIES WITH 4

EQUIVALENT LIGHTING CHARACTERISTICS TO THE CURRENT STREET AND 5

AREA LIGHTING OPTIONS? 6

A. Yes. OTP’s Materials Engineering Department worked with our lighting supplier to 7

develop a set of LED fixture offerings that handle the current lighting offering to a 8

greatly reduced set of new LED technologies. The table below lists the current HID 9

lighting type and the equivalent new replacement LED lighting types. 10

11

Table 25 12

Comparisons of HID and LED Lighting Types 13

14 15

10 Leadership in Energy and Environmental Design (LEED). 11 The Green Globes system delivers an online assessment protocol, rating system and guidance for green building

design, operation and management. It is interactive, flexible, and affordable, and provides market recognition of a

building’s environmental attributes through third-party verification.

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Q. HOW DID OTP DESIGN THE LED LIGHTING SERVICE RATE? 1

A. OTP assessed the marginal cost of service for the proposed LED fixtures and pole 2

offerings. The results of this study are included in Exhibit___(DGP-1), Schedule 8. This 3

study calculated the proposed LED Lighting Service rates based on the capital and O&M 4

costs of the new LED fixtures. 5

OTP then compared those marginal cost-based revenues to the embedded cost 6

proposed revenues for the Lighting class. The goal is to design revenues so total Lighting 7

class revenues are equal to those proposed by Ms. Ice. To reach that goal, we allocated 8

the intra-class Lighting revenues to the different Lighting rate classes using a Weighted 9

Average Method of Allocating revenue requirements for the current fixtures in the 10

corresponding LED fixture types. Additional detail on this process is included in 11

Schedule 8. This method was used over the EPMC method to limit the impact to 12

customers, thereby making the transition to the LED lighting technology to be as smooth 13

as possible. 14

15

Q. PLEASE DESCRIBE THE PROPOSED CUSTOMER BILL IMPACTS. 16

A. The figure below is an illustration of the relationship between the marginal cost-based 17

rates for LED fixtures and the proposed LED Lighting Service rate. 18

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Figure 17 1

2

3

The proposed LED5 type, which comprises the former lighting types, has the 4

greatest proportion of revenue, at over 63 percent. In this transition, OTP proposes a 5

balance of currently offered rates versus the marginal costs. Furthermore, not all marginal 6

cost based prices are higher than the proposed prices, e.g. LED30-Flood, but overall, we 7

believe have a balanced proposal to offer to our customers. 8

9

Q. PLEASE EXPLAIN OTP’S PLAN TO TRANSITION TO LED SERVICES. 10

A. OTP is proposing to close the Outdoor Lighting (Section 11.04) to new customers and 11

replacements. Current customers will be served on the closed rate until their existing light 12

fails. The new proposed LED Lighting Service (Section 11.07) will provide services to 13

new customers and replacements. 14

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E. Air Conditioning Rider 1

Q. PLEASE PROVIDE A SUMMARY OF THE PROPOSED ADDITION TO THE AIR 2

CONDITIONING CONTROL RIDER. 3

A. OTP is proposing to add a new option to the existing Air Conditioning Control Rider for 4

Commercial customers (only those customers taking service on Sections 10.01 and 5

10.02). This addition to the rider allows Commercial customers to reduce their summer 6

peak demand obligation. By reducing peak demand obligations, OTP avoids unnecessary 7

generation additions and helps to maintain lower energy costs for all customers. 8

9

Q. IS THE COMMERCIAL CUSTOMER INCENTIVE DIFFERENT THAN THE 10

RESIDENTIAL CUSTOMER INCENTIVE? 11

A. Yes. OTP is proposing compensation that recognizes the differences between Residential 12

and Commercial sized cooling systems and the difference in corresponding demand side 13

benefits. Commercial cooling loads are more complex than typical Residential cooling 14

systems with variability in system sizes, use of multiple units within a system, and use of 15

multi-stage compressors per unit within systems. To account for this variability among 16

Commercial customers’ systems, a bill credit per ton of cooling capacity is warranted for 17

Commercial customers. 18

19

Q. WHAT IS THE PROPOSED CREDIT FOR THE PROPOSED COMMERCIAL 20

PROGRAM? 21

A. OTP proposes a credit of $6.00 per ton of cooling capacity, per month, during the 22

program billing months of June through September. This credit amount is consistent with 23

other utilities in the region, and consistent with pricing offered to OTP’s Minnesota 24

customers. Further it is significant enough to attract participation in the program. 25

26

Q. IS THIS CUSTOMER CREDIT FOR AIR CONDITIONING CONTROL COST 27

EFFECTIVE? 28

A. Yes. OTP utilized DSMore™ to analyze this program. DSMore™ is an accepted 29

evaluation tool for energy efficiency programs and can also be used to analyze demand 30

response programs, including the Air Conditioning Control Rider. Preliminary analysis, 31

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assuming 10 customers with 6 tons of cooling capacity each participate in the program, 1

shows more benefits than costs (as indicated by a number greater than 1) across the five 2

common benefit categories. 3

4

Table 26 5

Commercial Air Conditioning Rider Benefit/Cost Analysis 6

Benefit Category

Participant Ratepayer Utility Total

Resource Societal

Infinite 1.41 1.46 1.47 2.25

7

Q. WILL CONTROL METHODS BE CONSISTENT WITH RESIDENTIAL CONTROL? 8

A. Yes. The total hours of interruptions per year will not differ from the existing Residential 9

program. We are proposing to add language to the Terms and Conditions to describe 10

how control will be achieved on both single and dual stage air conditioning. 11

VI. TARIFF CHANGES OTHER THAN RATES 12

Q. IS OTP PROPOSING ANY CHANGES TO ITS TARIFF SCHEDULES OTHER THAN 13

THOSE RELATING TO RATES? 14

A. Yes. OTP is proposing improvements and updates to its rate book that clarify service 15

conditions and other aspects of the rate book. All of the changes are reflected in the 16

Matrix of Tariff Changes included as Exhibit___(DGP-1), Schedule 9. 17

These changes include cancelling the Released Energy Rider. The Released 18

Energy Rider was put in place to protect OTP customers from extreme market prices that 19

had materialized in certain hours during the infancy of the MISO market. Since that 20

time, the MISO market has matured and the kind of market failures that caused extreme 21

prices have been corrected. Other than one test in 2001, OTP has never used the 22

Released Energy Rider. We therefore believe the Released Energy Rider is no longer 23

necessary. 24

VII. CONCLUSION 25

Q. WHAT ARE YOUR CONCLUSIONS? 26

A. The facts presented in my Direct Testimony support the conclusions that: 27

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• OTP’s proposed rate design appropriately balances important considerations, 1

including the cost of service and impact on customers; 2

• OTP’s proposed rate components, included proposed fixed charges, are 3

reasonable; and 4

• OTP’s rate schedule changes should be adopted. 5

6


A. Yes. 8

Case No. PU-17- Exhibit___(DGP-1), Schedule 1

Page 1 of 1

Mr. David G. Prazak, MPA Supervisor, Pricing & Tariff Administration

Regulatory Services

215 South Cascade Street

Fergus Falls, Minnesota 56537

218-739-8595 [email protected]

CURRENT RESPONSIBILITIES (2012 – Present)

Manage the design and implementation of retail pricing strategies for rate

schedule and contract pricing, including rates, rate design, load research, revenue

forecast, and tariff administration

PREVIOUS POSITIONS


2012-Present Supervisor, Pricing & Tariff Administration

2000– 2012 Supervisor, Pricing

1997-2000 Senior Pricing Analyst

EPS Solutions

1990-1997 Associate I & II: Consultant in demand-side management

planning, evaluation, and training

Northern States Power

1989-1990 Demand-Side Management (Intern): Aided in DSM

activities

EDUCATION

Walden University Masters of Public Administration, 2012

Minnesota State University, B.S., Energy Management, concentration in Industrial

Moorhead Technologies

mailto:[email protected]

Otter Tail Power Company’s

Marginal Cost of Electric Service Study

October 26, 2017

Prepared by

NH Regulatory Consulting


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Contents

I. INTRODUCTION ..................................................................................................................... 1

II. MARGINAL GENERATION COSTS ........................................................................................ 1

III. MARGINAL TRANSMISSION COST...................................................................................... 4

IV. MARGINAL ANCILLARY SERVICE COSTS .......................................................................... 6

V. MARGINAL DISTRIBUTION COSTS ...................................................................................... 7

VI. MARGINAL CUSTOMER COSTS ......................................................................................... 9

VII. COMPUTATION OF ANNUAL MARGINAL COSTS ........................................................... 10

VIII. SUMMARY OF MARGINAL COSTS FOR YEARS 2018 - 2022 ......................................... 13

APPENDIX 1: MARGINAL CAPACITY COSTS MODIFIED FOR GRADUALISM IN RATE

DESIGN ........................................................................................................................ 26

APPENDIX 2: ANNUALIZATION OF MARGINAL COSTS ....................................................... 28


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List of Tables

Table 1. Time of Day and Seasonal Periods ................................................................. 2

Table 2. Economic Carrying Charges .......................................................................... 12

Table 3. 2018 Summary of Time-differentiated Marginal Costs per kWh..................... 13

Table 4. 2018 Summary of Marginal Time-Differentiated Costs per-kW ...................... 14


Table 6. 2019 Summary of Marginal Time-Differentiated Costs per kW ...................... 16


Table 8. 2020 Summary of Marginal Time-Differentiated Costs per kW ...................... 18


Table 10. 2021 Summary of Marginal Time-Differentiated Costs per kW .................... 20

Table 11. 2022 Summary of Time-differentiated Marginal Costs per kWh ................... 21

Table 12. 2022 Summary of Marginal Time-Differentiated Costs per kW .................... 22

Table 13: Summary of Monthly Marginal Local Distribution Facilities (and

Lighting) Costs 23

Table 14. Summary of Monthly Marginal Customer Costs ........................................... 24

Table 15. Summary of Monthly Marginal Customer Cost for Small Power

Producers by Rate Class ....................................................................................... 25


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I. INTRODUCTION

Otter Tail Power Company (OTP) retained NH Regulatory Consulting to prepare an

update of the 2015 company’s system-wide marginal cost of electricity study (MCOS)

for the time frame 2018 - 2022. This report describes the approach used for estimating

marginal generation, transmission, distribution and customer-related costs, and

presents the results. Economic theory holds that economic efficiency is maximized

when customers respond to prices that reflect marginal costs. Marginal cost is defined

as the change in total cost of service with respect to a small change in the demand of

a product or service at any given time.

In an electricity ratemaking process, estimates of marginal generation, transmission

and distribution costs may be used as a guide to determine revenue requirement

allocations by class, decide on the appropriate rate components, and the level of time

differentiation by costing period and seasons. Best practice electricity service marginal

cost analysis requires identifying the utility’s wholesale market where the utility

operates, the system planning process, the latest capital expansion plan, including

planned growth-related investment at the various levels of service, and expected

impact of growth on utility system operations or contracting decisions. Marginal cost

estimates were summarized for voltage level and each year and time-differentiated

where appropriate.

II. MARGINAL GENERATION COSTS

As a member of the Midwest ISO’s electricity wholesale market, OTP buys and sells

on an hourly basis as required for achieving the lowest cost of serving its retail

customers. In a competitive electricity market, the utility’s marginal cost of generation

associated with an increase in its retail demand is given by the market prices of

energy, as well as the marginal cost of capacity if the change occurs at a time of

system peak demand.

Estimating the marginal energy cost for each hour requires a forecast of market

energy prices. Estimating the annual marginal cost of capacity requires an estimate of

annual forward capacity prices in the MISO region and the specific MISO reserve

margin rules. These prices are then converted into hourly marginal capacity costs and

aggregated to time of use periods taking into account the estimated probability of peak

by period. The costing periods that were used in the study are shown in Table 1.


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Table 1. Time of Day and Seasonal Periods

Summer: June – September

Peak: Monday - Friday, 1 pm - 7 pm

Shoulder: Monday - Friday, 11 am - 1 pm and 7 pm - 10 pm; Weekends, 11 am – 10 pm

Off-Peak: Monday - Friday, 10 pm - 11 am; Weekends, 10 pm - 11 am

Winter: October – May

Peak: Monday - Friday, 7 am - 11 am

Shoulder: Monday - Friday, 6 am - 7 am, 11am- 10 pm; Weekends, 6 pm - 10 pm

Off-Peak: Monday - Friday, 10 pm - 6 am; Weekends, 10 pm - 6 pm

A. Marginal Energy Cost

An increment of native load in any hour requires OTP to purchase more energy or

allows incremental energy sales to the market. MISO’s forward monthly peak and off-

peak prices1 measured at the OTP node for the period January 2018 through Dec

ember 2022 were used as a starting point. OTP developed the forward prices at the

OTP node using a forecast of the price difference between the Indiana node and OTP

node, based on 24 months of historical hourly price differentials.2 We shaped the

monthly energy peak and off-peak forward price at the OTP node using historical

monthly averages of day-ahead hourly market prices for the period May 1, 2014 to

July 31, 2017. The resulting forecasts of energy market prices for 2018-2022 were

then averaged by costing period as per the definitions shown in Table 1 above.

The energy prices are quoted at the OTP Hub and thus losses need to be applied from

that location to customer’s meters at each voltage level of service. To convert market

prices to energy marginal costs at customers’ meters, we adjusted for the financial

cost of working capital required and marginal energy losses incurred from the OTP

hub to customer meters. Hourly losses were estimated from information on variable

1 MISO On-peak period for purposes of the forward prices is Monday – Friday, hours ending 7-22. All

other hours are off-peak.

2 Intercontinental Exchange (ICE) provides forward prices for the Indiana node which is the main trading

node in MISO.


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losses at system peak load (from OTP’s 2010 loss study) and year 2016 OTP’s hourly

control area loads.

B. Marginal Generation Capacity Cost

OTP procures capacity through bilateral capacity contracts and it expects to continue

doing so to meet its obligations in the region through the study period (2018-2022).3

The MCOS relied on the most up to date forecast of the regional market prices for

capacity as a proxy for expected contract prices.

MISO establishes minimum planning reserve requirements for its members. As

directed by Module E-1 of the MISO Tariff, MISO conducts a Loss of Load Expectation

(LOLE) study that determines the required resources and Planning Reserve Margin

(PRM) that would allow achieving the target LOLE level. MISO calculates a target

PRM such that the LOLE for next planning year is 1 day in 10 years. MISO

coordinates with stakeholders to determine the appropriate PRM taking into account

the forecast of coincident peak loads and installed capacity resources (“PRMUCAP”) as

well as a PRM on unforced capacity (PRMUCAP) by adjusting the Installed Capacity

PRM by the weighted average forced outage rate of all the regional resources.4

Under the existing construct, the PRMUCAP is applied to the expected peak of each

LSE coincident with the MISO peak. OTP’s annual marginal cost of capacity cost is

triggered by an increment of native load at the time of MISO coincident system peak,

which may require OTP to reduce the size of a capacity sale or contract for additional

resources. Thus, given MISO RA rules OTP’s marginal generation capacity cost in any

hour on a planning basis is a function of: (1) the forecast annual capacity price, which

varies with the level of capacity surplus in the region, (2) the required PRM, and (3) the

probability that each hour is MISO’s system annual peak hour. While OTP is a winter

peaking utility, MISO is mostly a summer-peaking region.

The calculation of OTP’s marginal generation capacity cost took into account MISO’s

expected planning reserve margins for each year of the study period. For the current

planning year 2017/18, ICAP reserve margin over the region-wide coincident peak

3 The MCOS assumes that OTP is able to contract sufficient capacity to meet target PRM and do not

rely on MISO voluntary annual capacity auction.

4 MISO determines the UCAP value annually for each generating unit and then credits them their

specific UCAP value for the purpose of meeting resource adequacy requirements.


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demand is 15.8% and the PRMUCAP is 7.8%.5 Table 2 below shows the expected target

PRMs by MISO. The MCOS uses PRM-ICAP percentages.6

Table 2. MISO Annual Planning Reserve Margins (2018-2022)

2018 2019 2020 2021 2022 Average

PRM-ICAP 15.80% 15.60% 15.40% 15.50% 15.50% 15.6%

PRM-UCAP 7.80% 7.50% 7.30% 7.40% 7.50% 7.5%

The probability of peak analysis used MISO’s historical hourly native loads for a

historical 5-year period. Upon calculating probability of peak for each daytype and

season, the MCOS estimated OTP’s hourly marginal generation capacity costs, and

adjusted them by marginal losses and working capital.

III. MARGINAL TRANSMISSION COST

OTP’s transmission system consists of the Company’s networked transmission,

including 345 kV, 230 kV, 115 kV, 69 kV and 41.6 kV facilities. Transmission greater

than 100 kV is under the functional control of MISO and included as part of the MISO

regional transmission expansion plan. OTP has operational control of its transmission

facilities at or below 100 kV and are included in the calculation of FERC-approved

MISO Network Integration Transmission Service rate (NITS) for OTP’s Control Area.7

The Network Upgrade Charge (NUC) rate generally recovers the costs of new

transmission facilities above 100 kV. The cost of all new projects rated 345 kV and

above with a project cost of $5M or greater is allocated through a hybrid method, so

that 20% of the costs are allocated on a system-wide basis and the remaining 80% are

allocated to planning sub-regions (West, Central and East) and pricing zones under a

5 “Planning Year 2017-2018 Loss of Load Expectation Study Report”. MISO Loss of Load Expectation

Working Group.

6 OTP’s MCOS uses the PRM icap percentage as opposed to PRM ucap since OTP’s capacity price

forecasts have not been adjusted to reflect expected forced outages or any planned maintenance.

7 OTP operates in a joint pricing zone within the Midwest ISO. In addition to OTP’s revenue

requirement, NITS recovers the annual transmission revenue requirements for the Great River Energy

(GRE) facilities located in the OTP Pricing Zone and for OTP transmission facilities.


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method that differs between economic and reliability projects.8 For transmission

projects rated below 345-kV, all costs get allocated on a zonal basis and then each

individual pricing zone based on each zone’s contribution to MISO’s 12 CPs.

A. Network Integration Transmission Service Rate

The NITS rate is recovered from each transmission user9 in the OTP Pricing Zone

based on their monthly coincident peak loads. From the point of view of OTP, the

marginal cost of transmission is reflected by the impact of an increase in monthly

coincident peak on its MISO transmission bill. These charges are a financial marginal

cost to OTP. The MISO NITS and NUC charges are constant every month, as they

reflect 1/12 of the applicable annual revenue requirement per kW.

The starting point for the financial marginal transmission cost in MCOS was 2017

OTP’s NITS rate. Estimating the change in NITS charges beyond 2017 required

identifying the projected annual increase in NITS revenue requirement associated with

OTP’s applicable new transmission projects, using OTP budgets for 115-kV (below $5

million), 41.6 and 69 kV projects expected to come into service in the period 2018-

2022, and excluding the projects that qualify for transmission cost rider (TCR). MISO’s

estimates of annual carrying charges were applied to the budget figures to compute an

annual incremental revenue requirement for the OTP Pricing Zone NITS and divided

by the forecast of 12 monthly OTP’s control area CPs to compute an annual per-kW

NITS charge.

B. Network Upgrade Charge Rate

To estimate the second component of the financial transmission marginal cost, the

NUC rate, MCOS relied on MISO’s calculation of projected annual revenue

requirement as per Schedule 26. The total NUC transmission revenue requirement

allocated to the OTP Pricing Zone is the sum of a system-wide allocation, a sub-

regional allocation, and the individual allocations corresponding to new projects. To

estimate the NUC charges corresponding to the OTP Pricing Zone for the period 2018

through 2022, MISO’s projections of the NUC-related annual incremental transmission

revenue requirements that have been allocated to OTP’s pricing zone were divided by

8 To qualify for regional cost sharing under a postage stamp rate, both Baseline Reliability Projects and

Regionally Beneficial Projects must include facilities 345kV and above.

9 Except for certain grandfathered transmission agreements.


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the expected 12 monthly coincident peak forecast in each year used. The total dollar

revenue requirement amount is then divided by the sum of 12 CPs in the OTP zone to

establish the corresponding NUC rate forecast.

Because both the NITS and NUC charges are assessed on the basis of a transmission

user’s monthly peak demands, the MCOS allocated the monthly transmission cost to

hours using the probability of a given hour’s being the monthly peak. These

probabilities relied on four years of OTP Control Area’s historical hourly loads. The

results were adjusted by losses and cash working capital. The 2018 marginal

transmission costs stated on a per kWh and kW basis are shown in the summary

tables at the end of the report.

IV. MARGINAL ANCILLARY SERVICE COSTS

MISO implemented ancillary services markets (ASM) in January 2009. Prior to

January 2009, all ancillary services for Otter Tail were self-provided. The costs of

ancillary services are also marginal financial costs to OTP. Two types of ancillary

services provided via these markets are Regulation and Operating Reserves (Spinning

and Supplemental). OTP pays an hourly rate that is the total cost of each of these

services procured by the MISO divided by the total hourly MISO load. OTP provided

an average annual cost for each type of service for 2016. A forecast of the hourly cost

of these services for future years was not available. The expected cost was adjusted

by marginal losses at each service voltage level and working capital.


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V. MARGINAL DISTRIBUTION COSTS

The various components of OTP’s distribution system include distribution substations,

primary feeders, local distribution facilities such as secondary lines, primary-to-

secondary transformers and switchgear and local primary taps, dedicated feeders

used by some large primary customers;10 and service drops. The service drop in most

cases serves a single customer. The MCOS treated the service, along with the meter

and associated equipment such as current transformer as part of the marginal

customer cost for each class.

A. Distribution Substation and Trunkline Feeder Costs

Stations and trunkline feeders from the substation to the point where the line branches

to create a primary tap line is expanded as distribution area peak demands grow.

Estimating the marginal cost of distribution substation and trunkline feeder expansion

per kW of demand, required identifying the cost of budgeted growth-related projects

from OTP’s capital expansion plan for the period 2018-2022. The sum of OTP’s

growth-related investment (in 2018 dollars) was divided by the estimated addition to

distribution substation non-coincident peak demand over the same period. 11

Distribution O&M expenses are a component of marginal distribution cost, since they

grow with the amount of plant in service. The MCOS allocated OTP’s FERC Form 1

distribution O&M expenses by FERC account for 2012-2016 annual distribution

substation O&M expenses, plus associated overheads, were divided by estimates of

the sum of non-coincident peak demands at the substations and converted to 2018

dollars. After reviewing the trend in expense per kW (in constant dollars), the average

of the 2014-2016 values was considered a reasonable proxy for marginal substation

O&M expenses.

To time differentiate this component, the relative probability of peak for months, day-

types (weekdays, Saturday, and Sunday) were estimated based on historical hourly

loads on all of OTP distribution substations for the years 2010-2014. The analysis

10 This study does not calculate separate marginal costs for such customers, since the costs are

recovered outside of standard rates.

11 OTP was only able to provide non-coincident distribution peak demand for 2016. We estimated

OTP’s NCP for the period 2018-2022 based on expected growth rate of OTP’s annual peak

demands.


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accounted for the relative lower carrying capability of this equipment in summer

months as compared to the winter.

B. Local Distribution Facility Costs

Local distribution facilities, including secondary lines, transformers, and a portion of

primary taps, are less extensively shared and are designed using engineering

standards that take into consideration the expected number of customers connected

and their maximum expected loads over the life of the facilities. Different design

standards are used for local distribution systems in rural versus urban areas, and for

customers that use all electric appliances instead of relying partially on gas. In general

the marginal cost of local distribution facilities is incurred based on design demand, not

customer’s actual peak load from month to month. Local distribution facilities for

commercial and industrial customers are generally designed on a case-by-case basis,

taking into consideration the expected long-term peak demand.

OTP provided estimates of the typical investment in local distribution facilities for

various types and sizes of customers, by applying its standard distribution cost

estimation to a range of typical customer characteristics.12 The MCOS estimated

marginal costs as fixed monthly cost per kW of design demand. The transformer

capacity divided by the number of customers served from that transformer was used

as a proxy for the estimated design demand by class.

The MCOS also estimated marginal distribution facility O&M from historical data given

that there was not a forecast of O&M expenses. The average of 2014 -2016 expense

per kW of design demand, separated into primary and secondary categories on the

basis of miles of circuit, was used as the estimated marginal distribution facilities O&M

expense. The total design demand was the product of customer counts and per-

customer design demand estimates by customer category, developed by OTP from

load survey data for years 2015 and 2016.

OTP books expenses for both lighting facilities and distribution facilities used by lights

in the FERC lighting O&M accounts. The MCOS used the average expense during the

period 2014-2016 as the estimate of the marginal level of these expenses.

12 OTP also used this approach to estimate the cost of customer service drops.


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VI. MARGINAL CUSTOMER COSTS

A. Meter and Service Costs

OTP provided the current installed cost of a typical meter, including current

transformerif applicable, and service drop for customer categories. The labor cost

components of these costs were adjusted to account for expected annual increase of

3% to state them in 2018 dollars. The average expense in 2015 and 2016 was used to

represent the marginal level of these expenses.

Meter requirements for small power producers vary with the specific rider and/or

jurisdictional legislation. When a bi-directional and/or a generation meter are required

for reporting purposes, there are incremental costs of installing these meters. The

MCOS calculated an annual installed bi-directional meter cost incremental to the

regular meter cost, by rate category.

B. Customer Accounts and Customer Expenses

Customer accounts expenses, composed mainly of meter-reading and billing

expenses, are costs that are the function of a number of customers on the system.

OTP’s FERC Form 1 historical customer account and service expense levels for the

period 2012-2016 were divided by class weighted customers to obtain an estimate of

customer accounts expense per weighted customer. After considering the declining

trend in expenses, the average expense per customer in 2015 and 2016 was used as

an estimate of marginal expense.

Customer service and informational expenses, which include the costs of

disseminating information to consumers, vary with the number of customers on the

system and are, therefore, marginal.13 The same procedure used for customer

accounts expenses was followed using the class weights developed from OTP’s 2017

embedded cost of service study. Given the decrease of unit expense per customer

observed in recent years, the average of 2014 through 2016 values was assumed to

be a reasonable approximation of the estimated future marginal expense.

13 Expenses associated with CIP and EEP, programs mandated by Minnesota and South Dakota to

promote demand side measures, were omitted from the marginal cost calculations since these costs

are intended to reduce energy and capacity costs.


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C. One-time customer cost for Small Power Producer

Customers under the Small Power Producer Rider are responsible for system

upgrades caused by the installation of the generation system. The most important one-

time cost impact is related to the interconnection process, i.e., processing and

energizing the interconnection. OTP does not currently charge any fee directly

associated with the incremental expenses involved with this work and so this cost is

currently shared by all customers. The MCOS estimated a typical one-time cost of

interconnecting a small power producer involved estimating the time to review the

application form filled out by customer, a site inspection, an interconnection study and

conclusion, and a final site visit prior to the energizing of the generator.

The labor cost reflects the mid-point of the expected 2018 average hourly salary of the

employees directly involved in handling the interconnection assuming. This hourly cost

was then multiplied by the 20 hours typically required to process the interconnection,

excluding the time required to install a bi-directional meter, which is computed

separately. The cost was then adjusted for non-plant related loaders and cash working

capital.

VII. COMPUTATION OF ANNUAL MARGINAL COSTS

The MCOS estimated marginal annualized cost for each component of service by

adjusting the investment per unit by the general plant loading factor. We multiplied the

resulting figures by the annual economic carrying charge percentage and added a

plant-related A&G loading factor to yield the annualized plant costs. To these costs,

associated O&M and non-plant related A&G expenses, and revenue requirements for

working capital are added to finalize the computation of annualized costs. The

computation of working capital includes components for cash, materials, supplies and

prepayments. The working capital needs were estimated based on recent historical

amounts. The revenue requirement for this working capital was developed from OTP’s

weighted average cost of capital plus an income tax component that recognizes that

the equity portion of return on capital is taxable. Appendix 2 includes the derivation of

the annual distribution substation and trunkline feeder costs, the development of the

annual marginal cost for local distribution facilities and lighting, and the derivation of

annualized cost of meters and service drops, as well as other annualized marginal

customer-related expenses.


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A. Loaders

Marginal cost estimates need to be adjusted by either plant-related A&G, non-plant-

related A&G or general plant loading factors as required to capture the additional plant

or O&M expenses, or overhead costs incurred when electric plant or electric O&M

increase. Certain administrative and general (A&G) expenses can grow either with

plant or with O&M expenses. Accounts not marginal with respect to other expenses or

plant must be excluded.14

A non-plant-related A&G loader was estimated based on the average ratio of non-

plant-related A&G expenses (FERC Accounts 926 and 408.1) to O&M expenses over

the period 1982-2014, or 13.23%. For plant-related A&G, there are two A&G FERC

accounts clearly vary with the amount of plant in service: Maintenance of General

Plant (FERC Account 935) and Property Insurance (FERC Account 924). Account 935

was regressed on cumulative net additions to total electric plant, all in constant dollars,

for the period 1982 to 2014, yielding a loader of 0.10%. A second component of plant-

related A&G was average property and terrorism insurance rate, $0.0729 per $100 or

0.0729%. The total plant-related A&G loader applicable to distribution substations was

0.17%, and 0.10% for all other distribution plant that does not require insurance.

General plant typically grows with other types of plant. General plant consists of items

such as office buildings, warehouses, cars, trucks and other equipment. Since 1996

there has been very little change in OTP’s general plant. A regression of cumulative

net additions to general plant on cumulative net additions to total plant (less general

plant) using data from 1996-2014 resulted in a General Plant loader of 1.30%.

B. Economic Carrying Charges

To be useful in ratemaking and other marginal cost applications, estimates of marginal

investment in several categories of distribution plant investment must be converted

into annual costs using an economic carrying charge. The annual charge reflects the

elements of OTP’s revenue requirement associated with incremental plant. Key inputs

for the economic carrying charge calculation include: the utility’s incremental cost of

capital (mix of debt and equity and their respective long-term market costs), the

14 OTP’s MC study excluded FERC Accounts 922 Administrative Expenses Transferred (Credit), 923

Outside Services Employed, 927 Franchise Requirements, 928 Regulatory Requirements, 930.1

Institutional and Goodwill Advertising Expenses, and 931 Rents.


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expected inflation rate for that type of plant, net of technical progress, and the average

service life and patterns of failure (“Iowa curve”) for that type of plant. OTP provided

3.0 percent as an approximation of the rate of future inflation, based on its 10-year

financial model. OTP foresees financing of incremental investment through sales of

common stock (52.44%) and debt (47.56%). The long-term incremental cost of debt is

expected to be 5.05% and the incremental cost of common stock is expected to be

9.50%. The resulting economic carrying charges are presented below.

Table 2. Economic Carrying Charges

Distribution Distribution

Substation Facilities Meters

(1) (2) (3)

(1) Present Value of Revenue Requirements

Related to Incremental $1,000 Investment $1,429.76 $1,467.31 $1,413.82

(2) Present Value Cost of Replacing

Dispersed Retirements Related to

Incremental $1,000 Investment $177.79 $26.34 $75.89

(3) Total Present Value Cost Related to

Incremental $1,000 Investment (1)+(2) $1,607.55 $1,493.65 $1,489.71

(4) First-Year Annual Economic Charge

Related to Incremental $1,000 Investment $74.69 $63.66 $91.45

(5) First-Year Annual Economic Charge Related to

Incremental Investment [(4)/$1,000] 7.47% 6.37% 9.14%

C. Demand losses

Marginal capacity losses are applied to distribution substation and trunkline feeder

costs to reflect the fact that, to accommodate a kW of additional peak load at the

customer’s meter, facilities must be expanded by successively more than a kW as you

move up the distribution system to accommodate the fixed and variable losses on the

system in the peak hour. Peak demand loss factors were developed from OTP’s 2010

loss study. The loss-adjusted costs are then time-differentiated, using estimates of the

relative probability of distribution substation peak.


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VIII. SUMMARY OF MARGINAL COSTS FOR YEARS 2018 - 2022

The results of time-differentiated costs (including energy, generation capacity,

transmission and distribution substation costs) on a per-kWh basis and on a per-kW

basis, averaged over the hours in the period and for each year are shown in Tables 3

through 12 below.

Table 3. 2018 Summary of Time-differentiated Marginal Costs per kWh

Summer Season Winter Season

Peak Shoulder Off-Peak Peak Shoulder Off-Peak

(1) (2) (3) (4) (5) (6)

(1) Secondary

Energy 4.1280 3.0849 1.9980 3.5766 3.1773 2.1663

Generation Capacity 7.0240 0.9055 0.0147 0.0018 0.0014 0.0000

Regulation and Op. Reserves 0.0863 0.0863 0.0863 0.0863 0.0863 0.0863

Transmission 3.9633 0.3757 0.0062 5.0471 0.5198 0.0911

Distribution Substation 4.1771 0.1404 0.0008 0.0000 0.0000 0.0000

Total 19.3787 4.5927 2.1060 8.7117 3.7848 2.3436

Seasonal 5.8861 3.6851

Annual 4.4207

(2) Primary

Energy 3.9747 2.9799 1.9393 3.4241 3.0528 2.0883



Transmission 3.7955 0.3597 0.0059 4.7856 0.4912 0.0858


Total 18.6402 4.4273 2.0444 8.2957 3.6297 2.2584

Seasonal 5.6746 3.5322

Annual 4.2483

(3) Transmission

Energy 3.7304 2.8110 1.8438 3.1850 2.8557 1.9640



Transmission 3.5314 0.3345 0.0055 4.3853 0.4479 0.0778

Distribution Substation

Total 13.5937 4.0326 1.9432 7.6527 3.3857 2.1227

Seasonal 4.6082 3.2922

Annual 3.7321

---------------------------- (2018 Cents per kWh) --------------------------


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Table 4. 2018 Summary of Marginal Time-Differentiated Costs per-kW



(1) (2) (3) (4) (5) (6)

(1) Secondary

Monthly Costs per Kilowatt (2018 Dollars per Kilowatt)

Generation Capacity $9.181 $1.854 $0.058 $0.002 $0.004 $0.000

Transmission $5.181 $0.769 $0.025 $4.380 $1.534 $0.316

Distribution Substation $5.460 $0.288 $0.003 $0.000 $0.000 $0.000

Total $19.82 $2.91 $0.09 $4.38 $1.54 $0.32

Seasonal $22.82 $6.24

Annual $11.76

(2) Primary



Transmission $4.961 $0.737 $0.023 $4.153 $1.450 $0.298


Total $19.06 $2.79 $0.08 $4.15 $1.45 $0.30

Seasonal $21.93 $5.91

Annual $11.25

(3) Transmission



Transmission $4.616 $0.685 $0.022 $3.806 $1.322 $0.270


Total $12.79 $2.34 $0.07 $3.81 $1.33 $0.27

Seasonal $15.20 $5.40

Annual $8.67


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(1) (2) (3) (4) (5) (6)

(1) Secondary

Energy 4.0044 3.0282 1.9776 3.4868 3.0948 2.1316



Transmission 3.9196 0.3715 0.0061 4.9915 0.5141 0.0901


Total 27.9048 5.6429 2.1059 8.5711 3.7008 2.3106

Seasonal 7.7024 3.6186

Annual 4.9836

(2) Primary

Energy 3.8555 2.9252 1.9196 3.3373 2.9728 2.0546



Transmission 3.7537 0.3557 0.0059 4.7328 0.4858 0.0849


Total 26.8026 5.4324 2.0443 8.1607 3.5484 2.2263

Seasonal 7.4133 3.4679

Annual 4.7867

(3) Transmission

Energy 3.6183 2.7595 1.8253 3.1031 2.7799 1.9318



Transmission 3.4925 0.3308 0.0054 4.3370 0.4429 0.0770


Total 21.0680 4.9629 1.9430 7.5268 3.3088 2.0921

Seasonal 6.2031 3.2316

Annual 4.2248

---------------------------- (2019 Cents per kWh) --------------------------


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Table 6. 2019 Summary of Marginal Time-Differentiated Costs per kW



(1) (2) (3) (4) (5) (6)

(1) Secondary



Transmission $5.124 $0.761 $0.024 $4.332 $1.517 $0.313


Total $31.13 $5.17 $0.16 $4.34 $1.53 $0.31

Seasonal $36.45 $6.17

Annual $16.27

(2) Primary



Transmission $4.907 $0.728 $0.023 $4.107 $1.434 $0.295


Total $29.88 $4.96 $0.15 $4.11 $1.44 $0.29

Seasonal $34.99 $5.85

Annual $15.56

(3) Transmission



Transmission $4.565 $0.678 $0.022 $3.764 $1.307 $0.267


Total $22.70 $4.34 $0.14 $3.77 $1.31 $0.27

Seasonal $27.18 $5.35

Annual $12.63


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(1) (2) (3) (4) (5) (6)

(1) Secondary

Energy 4.0255 3.0317 1.9717 3.3931 3.0124 2.1232



Transmission 3.8625 0.3661 0.0060 4.9188 0.5066 0.0888


Total 31.0318 6.0388 2.1090 8.4081 3.6142 2.3035

Seasonal 8.3732 3.5608

Annual 5.1693

(2) Primary

Energy 3.8758 2.9284 1.9139 3.2475 2.8935 2.0466



Transmission 3.6990 0.3505 0.0058 4.6639 0.4787 0.0836


Total 29.7978 5.8115 2.0472 8.0053 3.4653 2.2197

Seasonal 8.0557 3.4126

Annual 4.9646

(3) Transmission

Energy 3.6370 2.7624 1.8197 3.0194 2.7056 1.9245



Transmission 3.4416 0.3260 0.0054 4.2738 0.4365 0.0758


Total 23.7359 5.3115 1.9455 7.3830 3.2311 2.0862

Seasonal 6.7783 3.1802

Annual 4.3829

---------------------------- (2020 Cents per kWh) --------------------------


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(1) (2) (3) (4) (5) (6)

(1) Secondary



Transmission $5.049 $0.750 $0.024 $4.269 $1.495 $0.308


Total $35.18 $5.97 $0.18 $4.27 $1.51 $0.31

Seasonal $41.33 $6.09

Annual $17.84

(2) Primary



Transmission $4.835 $0.718 $0.023 $4.048 $1.413 $0.290


Total $33.77 $5.72 $0.17 $4.05 $1.42 $0.29

Seasonal $39.66 $5.76

Annual $17.06

(3) Transmission



Transmission $4.499 $0.668 $0.021 $3.709 $1.288 $0.263


Total $26.16 $5.04 $0.16 $3.71 $1.30 $0.26

Seasonal $31.36 $5.27

Annual $13.97


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(1) (2) (3) (4) (5) (6)

(1) Secondary

Energy 3.8734 2.9366 1.9083 3.4626 3.0701 2.1003



Transmission 3.7911 0.3593 0.0059 4.8278 0.4972 0.0871


Total 31.1867 5.9754 2.0487 8.3893 3.6653 2.2818

Seasonal 8.3505 3.5689

Annual 5.1671

(2) Primary

Energy 3.7295 2.8367 1.8524 3.3144 2.9493 2.0246



Transmission 3.6305 0.3440 0.0000 4.5776 0.4699 0.0821


Total 29.9474 5.7503 1.9831 7.9885 3.5149 2.1988

Seasonal 8.0306 3.4208

Annual 4.9616

(3) Transmission

Energy 3.4999 2.6761 1.7614 3.0820 2.7582 1.9038



Operating Reserve 0.0526 0.0526 0.0526 0.0526 0.0526 0.0526

Transmission 3.3779 0.3200 0.0053 4.1947 0.4284 0.0744


Total 23.8064 5.3021 1.9427 7.4218 3.3308 2.1192

Seasonal 6.7868 3.2409

Annual 4.4261

---------------------------- (2021 Cents per kWh) --------------------------


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(1) (2) (3) (4) (5) (6)

(1) Secondary



Transmission $4.955 $0.736 $0.023 $4.190 $1.467 $0.302


Total $35.58 $6.03 $0.18 $4.19 $1.48 $0.30

Seasonal $41.79 $5.97

Annual $17.91

(2) Primary



Transmission $4.746 $0.705 $0.000 $3.973 $1.386 $0.285


Total $34.15 $5.78 $0.15 $3.98 $1.40 $0.29

Seasonal $40.08 $5.66

Annual $17.13

(3) Transmission



Transmission $4.415 $0.655 $0.021 $3.640 $1.264 $0.258


Total $26.36 $5.09 $0.16 $3.64 $1.27 $0.26

Seasonal $31.61 $5.18

Annual $13.99


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(1) (2) (3) (4) (5) (6)

(1) Secondary

Energy 3.9477 3.0113 1.9819 3.5345 3.1424 2.1820



Transmission 3.7750 0.3578 0.0059 4.8073 0.4951 0.0868


Total 31.6568 6.0911 2.1258 8.4438 3.7384 2.3659

Seasonal 8.5085 3.6450

Annual 5.2706

(2) Primary

Energy 3.8010 2.9089 1.9240 3.3832 3.0187 2.1033



Transmission 3.6152 0.3426 0.0056 4.5582 0.4679 0.0817


Total 30.4000 5.8618 2.0636 8.0409 3.5851 2.2800

Seasonal 8.1863 3.4941

Annual 5.0624

(3) Transmission

Energy 3.5671 2.7442 1.8296 3.1461 2.8231 1.9779



Transmission 3.3637 0.3186 0.0052 4.1770 0.4266 0.0741


Total 24.0515 5.3502 1.9614 7.4182 3.3440 2.4364

Seasonal 6.8541 3.3968

Annual 4.5524

---------------------------- (2022 Cents per kWh) --------------------------


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(1) (2) (3) (4) (5) (6)

(1) Secondary



Transmission $4.934 $0.733 $0.023 $4.172 $1.461 $0.301


Total $36.09 $6.11 $0.19 $4.18 $1.47 $0.30

Seasonal $42.39 $5.95

Annual $18.10

(2) Primary



Transmission $4.726 $0.702 $0.022 $3.956 $1.381 $0.284


Total $34.64 $5.85 $0.18 $3.96 $1.39 $0.28

Seasonal $40.67 $5.64

Annual $17.32

(3) Transmission



Transmission $4.397 $0.653 $0.021 $3.625 $1.259 $0.257


Total $26.66 $5.15 $0.16 $3.63 $1.27 $0.26

Seasonal $31.97 $5.15

Annual $14.09

Table 13 summarizes monthly marginal local distribution facilities costs per kW of

design demand and on a per customer basis, by class.


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Table 13: Summary of Monthly Marginal Local Distribution Facilities (and

Lighting) Costs

Customer Class

Monthly

Facility Cost

per kW

of Design

Demand

Estimate of

Typical

Design

Demand by

Customer

Monthly

Facility Cost

per

Customer

($/kW) kW ($/customer/mo.)

(1)*(2)

(1) (2) (3)

Residential

(1) Urban $1.40 8 $11.69

(2) Rural $2.63 18 46.11

(3) Apartment, Gas $1.24 5 5.61

(4) Apartment, Elec $0.89 9 8.08

(5) Farm $2.67 18 46.65

Small Commercial

(6) Stand-Alone customer, overhead $0.69 50 34.64

(7) Stand-Alone customer 3ph, overhead $0.83 75 62.61

Shared-customer 3ph, overhead $0.89 75 66.67

Stand-Alone customer, underground $1.13 50 56.63

(8) Stand-Alone 3ph, underground $1.34 75 100.37

Large Commercial (Secondary)

(9) 101-150kVa, 3ph $0.99 150 148.72

(10) 151-300kVa, 3ph $0.76 300 228.64

(11) 301-500kVa, 3ph $0.66 500 328.92

(12) 501-1000 kVa, 3ph $0.61 1,000 612.44

Very Large Commercial (Secondary)

(13) 1001-1500kVa, 3ph $0.57 1,500 859.48

(14) 1501-2000kVa, 3ph $0.55 2,000 1,107.27

Very Large Commercial (Primary)

(15) 3000kVa $0.48 3,000 1,449.95

(16) 5000kVa $0.47 5,000 2,325.56

Lighting $/Fixture

(17) Area Light, underground 10.36

(18) Area Light, overhead 9.42

(19) Street Light, underground 5.96

(20) Street Light, overhead 5.02

Table 14 summarizes the monthly marginal customer cost by customer class.


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Table 14. Summary of Monthly Marginal Customer Costs

Monthly

Marginal Customer

Cost per Customer

(2018$ /mo.)

Residential

9.01 Residential 15.21

9.02 Residential Controlled Demand 20.13

14.01 Residential Water Heating Control Rider 5.55

14.04 Residential Controlled Service - Large Dual Fuel Rider 17.64

14.05 Residential Controlled Service - Small Dual Fuel Rider 4.13

14.06 Residential Controlled Service - Deferred Load Rider 6.34

14.07 Residential Fixed Time of Service Rider 4.03

11.03, 11.04 Residential Outdoor/Area Lighting 0.30

Commercial and Industrial

9.03 Farm Service 17.37

10.01 General Service < 20 kW 24.86

10.02 General Service >= 20 kW 31.84

10.04 Large Commercial Service - Secondary 215.75

Large Commercial Service - Primary 281.15

10.05 Large General Service - Time of Day (Secondary) 215.75

Large General Service - Time of Day (Primary) 281.15

14.01 Commercial Water Heating Control Rider 5.55

14.02 Large GS - Real Time Pricing Rider (Secondary) 216.66

Large GS - Real Time Pricing Rider (Primary) 281.15

14.04 Commercial Controlled Service - Large Dual Fuel Rider 20.06

14.05 Commercial Controlled Service - Small Dual Fuel Rider 7.94

14.06 Commercial Controlled Service - Deferred Load 8.80

14.07 Commercial Fixed Time of Service Rider 6.65

11.02 Irrigation 24.21

10.03 General Service - Time of Use 218.88

11.03, 11.04 Commercial Outdoor/Area Lighting 0.30

Miscellaneous

11.03, 11.04 Street Lighting 0.30

11.05, 11.06 Other Public Authority 26.55


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Table 15. Summary of Monthly Marginal Customer Cost for Small Power

Producers by Rate Class

Monthly

Incremental

Customer Cost

(2018$/cust/mo.)

Residential Small Power Producer

(1) Residential 0.82

(2) Residential Demand Control Residential Demand Control0.77

Commercial and Industrial Small Power Producer

(3) General Service <20 kW 1.04

(4) General Service >= 20 kW 1.04

(5) Farm Service 0.84

(6) General Service - Time of Use 1.09

(7) Large General Service (Secondary) 1.16

(8) Large General Service (Primary) 1.18

(9) Large General Service - Time of Day (Secondary) 1.16

(10) Large General Service - Time of Day (Primary) 1.18

(11) Irrigation Service 1.16


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APPENDIX 1: MARGINAL CAPACITY COSTS MODIFIED FOR

GRADUALISM IN RATE DESIGN

To recognize the need for gradualism in reforming OTP’s marginal cost-based seasonal

rates, OTP required an alternative capacity cost allocation scenario that would assign

60% of the annual generation capacity cost to the summer and 40% of the annual cost

to the winter season. The resulting cost estimates under this hypothetical split of the

marginal generation capacity cost, averaged for years 2018 through 2022 and stated in

2018$, are shown in Table A.1.1. Marginal capacity costs, stated on a per kW basis, are

shown in Table A.1.2.

Table A.1.1. Average 2018 – 2022 Marginal Time-Differentiated Costs per kWh

using a 60/40 generation capacity cost split



Average 2018-2022

(1) Secondary

Energy 3.8440 2.9034 1.8922 3.3569 2.9806 2.0584



Transmission 3.6466 0.3456 0.0057 4.6438 0.4782 0.0838

Distribution Substation 4.1771 0.1404 0.0008 0.0000 0.0000 0.00000.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 20.6420 4.6230 2.0053 9.5413 4.6917 2.2416

Seasonal 6.0656 4.1023

Annual 4.7585

(2) Primary

Energy 3.7012 2.8046 1.8368 3.2132 2.8633 1.9841



Transmission 3.4922 0.3309 0.0044 4.4032 0.4520 0.0789


Total 19.8474 4.4548 1.9457 9.0928 4.4972 2.1600

Seasonal 5.8444 3.9313

Annual 4.5708

(3) Transmission

Energy 3.4734 2.6457 1.7465 2.9880 2.6778 1.8658



Transmission 2.6406 0.2589 0.0137 3.2767 0.3433 0.0676


Total 14.8773 4.0801 1.8604 8.5996 4.2205 2.0431

Seasonal 4.8059 3.7050

Annual 4.0729

---------------------------- (2018 Cents per kWh) --------------------------


29 of 43

Table A.1.2. Average 2018 – 2022 Marginal Time-Differentiated Costs per kW

using a 60/40 generation capacity cost split


Average 2018-2022 Peak Shoulder Off-Peak Peak Shoulder Off-Peak

(1) (2) (3) (4) (5) (6)

(1) Secondary



Transmission $4.767 $0.708 $0.023 $4.030 $1.411 $0.291


Total $21.84 $3.34 $0.10 $5.29 $4.79 $0.33

Seasonal $25.28 $10.41

Annual $15.37

(2) Primary



Transmission $4.565 $0.678 $0.018 $3.821 $1.334 $0.274


Total $20.99 $3.20 $0.09 $5.03 $4.57 $0.31

Seasonal $24.29 $9.91

Annual $14.70

(3) Transmission



Transmission $3.452 $0.530 $0.054 $2.844 $1.013 $0.235


Total $13.79 $2.62 $0.12 $3.97 $4.02 $0.27

Seasonal $16.53 $8.26

Annual $11.01


30 of 43

APPENDIX 2: ANNUALIZATION OF MARGINAL COSTS

Table A.2.1. Annualized Distribution Substation Costs ............................................................ 29

Table A.2.2 Annualized Distribution Facilities Costs ................................................................ 30

Table A.2.3. Annualized Annual Distribution Facilities Costs ................................................... 31

Table A.2.4. Annualized Distribution Facilities Costs ............................................................... 32

Table A.2.5. Annualized Lighting Costs ................................................................................... 33

Table A.2.6. Annualized Customer-Related Costs ................................................................... 34




Table A.2.10. Annualized Customer-Related Costs ................................................................. 38

Table A.2.11. One-Time Labor Expense per Interconnection of Small Power Producer .......... 39

Table A.2.12. Incremental Annualized Cost of Meter for Small Power Producers by Class 40 40


31 of 43

Table A.2.1. Annualized Distribution Substation Costs

2018

Dollars per

kW

(1) Marginal Investment per kW $244.10

(2) With General Plant Loading (1) x 1.0130 247.27

(3) Annual Economic Carrying Charge Related to

Capital Investment 7.47%

(4) A&G Loading (plant related) 0.17%

(5) Total Annual Carrying Charge (3) + (4) 7.64%

(6) Annualized Costs (2) x (5) 18.89

(7) O&M Expenses 1.54

(8) With A&G (7) x 1.1323 (Non-plant Related) 1.75

(9) Subtotal (6) + (8) 20.64

Working Capital

(10) Material and Supplies (2) x 1.03% 2.55

(11) Prepayments (2) x 0.03% 0.07

(12) Cash Working Capital Allowance (8) x 6.67% 0.12

(13) Total Working Capital (10) + (11) + (12) 2.74

(14) Revenue Requirement for Working

Capital (13) x 10.61% 0.29

(15) Total Distribution Substation Costs (9) + (14) $20.93


32 of 43

Table A.2.2 Annualized Distribution Facilities Costs

Single

Family

Urban

Single

Family

Rural

Apartment

Gas

Apartment

Electric Farm

(1) Marginal Investment per kW $174.73 $396.62 $144.46 $82.17 $402.18

(2) With General Plant Loading (1) x 1.0130 177.00 401.78 146.34 83.24 407.41


Capital Investment 6.37% 6.37% 6.37% 6.37% 6.37%

(4) A&G Loading (plant-related) 0.10% 0.10% 0.10% 0.10% 0.10%

(5) Total Annual Carrying Charge (3) + (4) 6.46% 6.46% 6.46% 6.46% 6.46%

(6) Annualized Costs (2) x (5) 11.44 25.97 9.46 5.38 26.33

(7) O&M Expense per kW 4.56 4.56 4.56 4.56 4.56

(8) With A&G Loading (7) x 1.1323 5.16 5.16 5.16 5.16 5.16

(non-plant related)

(9) Distribution Facilities Related Costs (6) + (8) 16.60 31.13 14.62 10.54 31.49

Working Capital

(10) Material and Supplies (2) x 1.03% 1.82 4.14 1.51 0.86 4.20

(11) Prepayments (2) x 0.03% 0.05 0.12 0.04 0.02 0.12

(12) Cash Working Capital Allowance (8) x 6.67% 0.34 0.34 0.34 0.34 0.34

(13) Total Working Capital (10) + (11) + (12) 2.22 4.60 1.90 1.23 4.66


Capital (13) x 10.61% 0.24 0.49 0.20 0.13 0.49

(15) Total Annual Marginal Distribution

Facilities Related Costs (9) + (14) $16.84 $31.62 $14.82 $10.67 $31.99

--------------------------- (2018 Dollars per kW) ----------------------------

Residential


33 of 43

Table A.2.3. Annualized Annual Distribution Facilities Costs

Stand-Alone

customer,

overhead

Stand-Alone

customer

3ph,

overhead

Shared-

customer

3ph,

overhead

Stand-Alone

customer,

underground

Stand-Alone

3ph,

underground

------------------------------ (2018 Dollars per kW) -------------------------------

(1) Marginal Investment per kW $46.77 $72.34 $82.10 $125.99 163.03

(2) With General Plant Loading (1) x 1.0130 47.38 73.28 83.17 127.63 165.15



(4) A&G Loading (plant-related) 0.10% 0.10% 0.10% 0.10% 0.10%

(5) Total Annual Carrying Charge (3) + (4) 6.46% 6.46% 6.46% 6.46% 6.46%

(6) Annualized Costs (2) x (5) 3.06 4.74 5.38 8.25 10.68

(7) O&M Expense per kW 4.56 4.56 4.56 4.56 4.56

(8) With A&G Loading (7) x 1.1323 5.16 5.16 5.16 5.16 5.16

(non-plant related)

(9) Distribution Facilities Related Costs (6) + (8) 8.22 9.90 10.54 13.41 15.84

Working Capital

(10) Material and Supplies (2) x 1.03% 0.49 0.75 0.86 1.31 1.70

(11) Prepayments (2) x 0.03% 0.01 0.02 0.02 0.04 0.05

(12) Cash Working Capital Allowance (8) x 6.67% 0.34 0.34 0.34 0.34 0.34

(13) Total Working Capital (10) + (11) + (12) 0.85 1.12 1.23 1.70 2.09


Capital (13) x 10.61% 0.09 0.12 0.13 0.18 0.22


Facilities Related Costs (9) + (14) $8.31 $10.02 $10.67 $13.59 $16.06

Small Commercial


34 of 43

Table A.2.4. Annualized Distribution Facilities Costs

Very Large

Large Commercial Commercial Large Commercial

(Secondary) (Secondary TOU) (Primary)

101-

150kVa,

3ph

151-

300kVa,

3ph

301-

500kVa,

3ph

501-

1000

kVa,

3ph

1001-

1500

kVa,

3ph

1501-

2000

kVa, 3ph

3000

kVa

(LGS),

3ph

5000 kVa

(LGS TOU),

3ph

------------------------------------- (2018 Dollars per kW) ------------------------------------------

(1) Marginal Investment per kW $100.57 $59.26 $40.47 $32.30 $25.19 $21.70 $9.04 $5.76

(2) With General Plant Loading (1) x 1.0130 101.87 60.03 41.00 32.72 25.51 21.98 9.15 5.83


Capital Investment 6.37% 6.37% 6.37% 6.37% 6.37% 6.37% 6.37% 6.37%

(4) A&G Loading (plant-related) 0.10% 0.10% 0.10% 0.10% 0.10% 0.10% 0.10% 0.10%

(5) Total Annual Carrying Charge (3) + (4) 6.46% 6.46% 6.46% 6.46% 6.46% 6.46% 6.46% 6.46%

(6) Annualized Costs (2) x (5) 6.58 3.88 2.65 2.11 1.65 1.42 0.59 0.38

(7) O&M Expense per kW 4.56 4.56 4.56 4.56 4.56 4.56 4.56 4.56

(8) With A&G Loading (7) x 1.1323 5.16 5.16 5.16 5.16 5.16 5.16 5.16 5.16

(non-plant related)

(9) Distribution Facilities Related Costs (6) + (8) 11.75 9.04 7.81 7.28 6.81 6.58 5.75 5.54

Working Capital

(10) Material and Supplies (2) x 1.03% 1.05 0.62 0.42 0.34 0.26 0.23 0.09 0.06

(11) Prepayments (2) x 0.03% 0.03 0.02 0.01 0.01 0.01 0.01 0.00 0.00

(12) Cash Working Capital Allowance (8) x 6.67% 0.34 0.34 0.34 0.34 0.34 0.34 0.34 0.34

(13) Total Working Capital (10) + (11) + (12) 1.42 0.98 0.78 0.69 0.61 0.58 0.44 0.41


Capital (13) x 10.61% 0.15 0.10 0.08 0.07 0.07 0.06 0.05 0.04


Facilities Related Costs (9) + (14) $11.90 $9.15 $7.89 $7.35 $6.88 $6.64 $5.80 $5.58


35 of 43

Table A.2.5. Annualized Lighting Costs

Area Light,

underground

Area Light,

overhead

Street Light,

underground

Street Light,

overhead

(1) Marginal Investment per fixture $1,415.08 $1,245.71 $622.85 $453.48

(2) With General Plant Loading (1) x 1.0130 1,433.48 1,261.90 630.95 459.38


Capital Investment 6.37% 6.37% 6.37% 6.37%

(4) A&G Loading (plant-related) 0.10% 0.10% 0.10% 0.10%

(5) Total Annual Carrying Charge (3) + (4) 6.46% 6.46% 6.46% 6.46%

(6) Annualized Costs (2) x (5) 92.66 81.57 40.78 29.69

(7) Lighting O&M Expenses 26.31 26.31 26.31 26.31

(8) With A&G Loading (7) x 1.1323 29.79 29.79 29.79 29.79

(non-plant related)

(9) Distribution Facilities Related Costs (6) + (8) 122.44 111.35 70.57 59.48

Working Capital

(10) Material and Supplies (2) x 1.03% 14.76 13.00 6.50 4.73

(11) Prepayments (2) x 0.03% 0.43 0.38 0.19 0.14

(12) Cash Working Capital Allowance (8) x 6.67% 1.99 1.99 1.99 1.99

(13) Total Working Capital (10) + (11) + (12) 17.18 15.36 8.67 6.86


Capital (13) x 10.61% 1.82 1.63 0.92 0.73


Facilities Related Costs (9) + (14) $124.26 $112.98 $71.49 $60.21

----------------------------- (2018 Dollars per fixture) -------------------------

Lighting


36 of 43

Table A.2.6. Annualized Customer-Related Costs

Residential

Residential

Demand

Control

Residential

Water

Heating

Control

Rider

Residential

Controlled

Service -

Large Dual

Fuel Rider

Residential

Controlled

Service -

Small Dual

Fuel Rider

Residential

Controlled

Service -

Deferred

Load Rider

Residential

Fixed Time

of Service

Rider

------------------------------------------- (2018 Dollars per Customer) ---------------------------------------------

a) Investment - Meter Costs

(1) Meter Cost Investment per Customer $120.49 $519.81 $415.84 $1,978.59 $423.11 $533.27 $237.91

(2) With General Plant Loading (1) x 1.0130 122.05 526.56 421.25 2,004.31 428.61 540.20 241.00

(3) Annual Economic Charge Related to

Capital Investment 9.14% 9.14% 9.14% 9.14% 9.14% 9.14% 9.14%

(4) A&G Loading (Plant Related) 0.10% 0.10% 0.10% 0.10% 0.10% 0.10% 0.10%

(5) Total Carrying Charge Meters (3) + (4) 9.24% 9.24% 9.24% 9.24% 9.24% 9.24% 9.24%

(6) Total Annualized Meter Costs (2) x (5) 11.28 48.67 38.93 185.24 39.61 49.93 22.27

b) Investment - Meter Service Drops

(7) Service Cost Investment per Customer $586.71 $586.71 $0.00 $0.00 $0.00 $0.00 $0.00

(8) With General Plant Loading (1) x 1.0130 594.33 594.33 0.00 0.00 0.00 0.00 0.00


Capital Investment 6.37% 6.37% 6.37% 6.37% 6.37% 6.37% 6.37%

(10) A&G Loading (Plant Related) 0.10% 0.10% 0.10% 0.10% 0.10% 0.10% 0.10%

(11) Total Carrying Charge Services (9) + (10) 6.46% 6.46% 6.46% 6.46% 6.46% 6.46% 6.46%

(12) Total Annualized Service Costs (8) x (11) 38.42 38.42 0.00 0.00 0.00 0.00 0.00

c) O&M - Meter, Customer Accounts Expenses, Customer Service

(13) Meter and CT O&M Expenses 8.21 10.95 8.21 8.21 8.21 8.21 8.21

(14) Customer Accounts Expenses 87.43 103.41 15.98 14.72 0.00 14.19 14.19

(15) Customer Service and Informational Expenses 20.95 21.08 0.13 0.58 0.58 0.56 0.56

(16) With A&G [(13)+(14)+(15)] x 1.1323 132.01 153.36 27.54 26.62 9.95 26.00 26.00

(Non-plant Related)

(17) Customer-Related Costs (6) + (12) + (16) 181.71 240.44 66.47 211.86 49.57 75.92 48.27

Working Capital

(18) Materials and Supplies (2) x 1.03% 1.26 5.42 4.34 20.64 4.41 5.56 2.48

(19) Prepayments (2) x 0.030% 0.04 0.16 0.13 0.60 0.13 0.16 0.07

(20) Cash Working Capital (16) x 6.67% 8.81 10.23 1.84 1.78 0.66 1.73 1.73

(21) Revenue Requirement for Working Capital

[(18)+(19)+(20)] x 10.61% 1.07 1.68 0.67 2.44 0.55 0.79 0.46

(22) Total Annual Marginal Customer-Related

Costs (11) + (15) $182.78 $242.12 $67.14 $214.31 $50.12 $76.72 $48.73


37 of 43


General

Service

< 20 kW

General

Service

>= 20 kW

Farm

Service

Large

Commercial

Secondary

Large

Commercial

Primary

General

Service -

Time of Use

------------------ (2018 Dollars per Customer) --------------


(1) Meter Cost Investment per Customer $705.79 $705.79 $423.88 $1,744.38 $9,549.89 $1,568.68

(2) With General Plant Loading (1) x 1.0130 714.96 714.96 429.39 1,767.06 9,674.04 1,589.07


Capital Investment 9.14% 9.14% 9.14% 9.14% 9.14% 9.14%

(4) A&G Loading (Plant Related) 0.10% 0.10% 0.10% 0.10% 0.10% 0.10%

(5) Total Carrying Charge Meters (3) + (4) 9.24% 9.24% 9.24% 9.24% 9.24% 9.24%

(6) Total Annualized Meter Costs (2) x (5) 66.08 66.08 39.69 163.32 894.10 146.87


(7) Service Cost Investment per Customer $879.73 $1,716.37 $621.57 $27,581.04 $28,403.08 $28,403.08

(8) With General Plant Loading (1) x 1.0130 891.17 1,738.68 629.65 27,939.60 28,772.32 28,772.32


Capital Investment 6.37% 6.37% 6.37% 6.37% 6.37% 6.37%

(10) A&G Loading (Plant Related) 0.10% 0.10% 0.10% 0.10% 0.10% 0.10%

(11) Total Carrying Charge Services (9) + (10) 6.46% 6.46% 6.46% 6.46% 6.46% 6.46%

(12) Total Annualized Service Costs (8) x (11) 57.60 112.38 40.70 1,805.92 1,859.75 1,859.75


(13) Meter and CT O&M Expenses 8.21 33.60 10.95 403.24 403.24 403.24

(14) Customer Accounts Expenses 124.26 124.26 82.60 38.37 38.37 38.37

(15) Customer Service and Informational Expenses 20.77 20.77 18.82 102.27 102.27 102.27

(16) With A&G Loading [(13)+(14)+(15)] x 1.1323 173.51 202.26 127.24 615.83 615.83 615.83

(Non-plant Related)

(17) Customer-Related Costs (6) + (12) + (16) 297.19 380.72 207.62 2,585.07 3,369.68 2,622.44

Working Capital

(18) Materials and Supplies (2) x 1.03% 7.36 7.36 4.42 18.20 99.64 16.37

(19) Prepayments (2) x 0.030% 0.21 0.21 0.13 0.53 2.90 0.48

(20) Cash Working Capital (16) x 6.67% 11.57 13.49 8.49 41.08 41.08 41.08


[(18)+(19)+(20)] x 10.61% 2.03 2.24 1.38 6.35 15.24 6.15


Costs (11) + (15) $299.23 $382.96 $209.00 $2,591.41 $3,384.92 $2,628.59


38 of 43


Large GS (Real

Time Pricing)

Secondary

Large GS (Real

Time Pricing)

Primary

Large GS -

TOD

Secondary

Large GS -

TOD Primary


(1) Meter Cost Investment per Customer $1,834.37 $9,549.89 $1,744.38 $9,549.89

(2) With General Plant Loading (1) x 1.0130 1,858.22 9,674.04 1,767.06 9,674.04



(4) A&G Loading (Plant Related) 0.10% 0.10% 0.10% 0.10%

(5) Total Carrying Charge Meters (3) + (4) 9.24% 9.24% 9.24% 9.24%

(6) Total Annualized Meter Costs (2) x (5) 171.74 894.10 163.32 894.10


(7) Service Cost Investment per Customer $27,581.04 $28,403.08 $27,581.04 $28,403.08

(8) With General Plant Loading (1) x 1.0130 27,939.60 28,772.32 27,939.60 28,772.32



(10) A&G Loading (Plant Related) 0.10% 0.10% 0.10% 0.10%

(11) Total Carrying Charge Services (9) + (10) 6.46% 6.46% 6.46% 6.46%

(12) Total Annualized Service Costs (8) x (11) 1,805.92 1,859.75 1,805.92 1,859.75


(13) Meter and CT O&M Expenses 403.24 403.24 403.24 403.24

(14) Customer Accounts Expenses 38.37 38.37 38.37 38.37

(15) Customer Service and Informational Expenses 102.27 102.27 102.27 102.27

(16) With A&G Loading [(13)+(14)+(15)] x 1.1323 615.83 615.83 615.83 615.83

(Non-plant Related)

(17) Customer-Related Costs (6) + (12) + (16) 2,593.49 3,369.68 2,585.07 3,369.68

Working Capital

(18) Materials and Supplies (2) x 1.03% 19.14 99.64 18.20 99.64

(19) Prepayments (2) x 0.030% 0.56 2.90 0.53 2.90

(20) Cash Working Capital (16) x 6.67% 41.08 41.08 41.08 41.08


[(18)+(19)+(20)] x 10.61% 6.45 15.24 6.35 15.24


Costs (11) + (15) $2,599.94 $3,384.92 $2,591.41 $3,384.92

--------------------------- (2018 Dollars per Customer) ------------------------------


39 of 43


Commercial

Water

Heating

Control

Commercial

Controlled

Service -

Large Dual

Fuel (14.04)

Commercial

Controlled

Service - Small

Dual Fuel

(14.05)

Commercial

Controlled

Service -

Deferred Load

(14.06)

Small

Commercial

Fixed Time of

Service

(14.07)

--------------------------------------------------------- (2018 Dollars per Customer) --------------------------------------------------------


(1) Meter Cost Investment per Customer $415.84 $1,978.59 $423.11 $533.27 $533.27

(2) With General Plant Loading (1) x 1.0130 421.25 2,004.31 428.61 540.20 540.20



(4) A&G Loading (Plant Related) 0.10% 0.10% 0.10% 0.10% 0.10%

(5) Total Carrying Charge Meters (3) + (4) 9.24% 9.24% 9.24% 9.24% 9.24%

(6) Total Annualized Meter Costs (2) x (5) 38.93 185.24 39.61 49.93 49.93


(7) Meter and CT O&M Expenses 8.21 33.60 33.60 33.60 10.95

(8) Customer Accounts Expenses 15.98 14.72 14.72 14.72 14.72

(9) Customer Service and Informational Expenses 0.13 0.58 0.58 0.58 0.58

(10) With A&G Loading [(7)+(8)+(9)] x 1.1323 27.54 55.37 55.37 55.37 29.72

(Non-plant Related)

(11) Customer-Related Costs (6) + (10) 66.47 240.61 94.98 105.30 79.65

Working Capital

(12) Materials and Supplies (2) x 1.03% 4.34 20.64 4.41 5.56 5.56

(13) Prepayments (2) x 0.030% 0.13 0.60 0.13 0.16 0.16

(14) Cash Working Capital (16) x 6.67% 1.84 3.69 3.69 3.69 1.98


[(12)+(13)+(14)] x 10.61% 0.67 2.65 0.87 1.00 0.82


Costs (11) + (15) $67.14 $243.26 $95.86 $106.30 $80.47


40 of 43


Irrigation

(11.02)

Other Public

Authority


(1) Meter Cost Investment per Customer $1,245.54 $437.73

(2) With General Plant Loading (1) x 1.0130 1,261.73 443.42


Capital Investment 9.14% 9.14%

(4) A&G Loading (Plant Related) 0.10% 0.10%

(5) Total Carrying Charge Meters (3) + (4) 9.24% 9.24%

(6) Total Annualized Meter Costs (2) x (5) 116.61 40.98


(7) Service Cost Investment per Customer $586.71 $1,716.37

(8) With General Plant Loading (1) x 1.0130 594.33 1,738.68


Capital Investment 6.37% 6.37%

(10) A&G Loading (Plant Related) 0.10% 0.10%

(11) Total Carrying Charge Services (9) + (10) 6.46% 6.46%

(12) Total Annualized Service Costs (8) x (11) 38.42 112.38


(13) Meter and CT O&M Expenses 25.20 33.60

(14) Customer Accounts Expenses 83.16 91.97

(15) Customer Service and Informational Expenses 10.53 18.95

(16) With A&G Loading [(13)+(14)+(15)] x 1.1323 134.62 163.64

(Non-plant Related)

(17) Customer-Related Costs (6) + (12) + (16) 289.65 317.00

Working Capital

(18) Materials and Supplies (2) x 1.03% 13.00 4.57

(19) Prepayments (2) x 0.030% 0.38 0.13

(20) Cash Working Capital (16) x 6.67% 8.98 10.91


[(18)+(19)+(20)] x 10.61% 2.37 1.66


Costs (11) + (15) $292.02 $318.66


41 of 43

Table A.2.11. One-Time Expense per Interconnection of Small Power Producer

Interconnection

Labor Cost

Small Power Producer Rider (2018$)

(1) Average Annual Salary of Technical &

Admin Personnel Involved $96,516.21

(2) Annual hours net of paid vacation & holiday 1,880.00

(3) Hourly average labor cost $48.39

(4) Hours required per interconnection $20.00

(5) Expense per Interconnection Request $967.83

(6) With Non-Plant Related A&G (5) x 1.1323 $1,095.86

(7) Working Capital

(8) Cash Working Capital (6) x 6.67% $73.09


(10) (8) x 11.20% $7.76

(11) Total One-time Incremental Cost to Process

and Energize Interconnection (6) + (10) $1,103.62


42 of 43

Table A.2.12. Incremental Annualized Cost of Meter for Small Power Producers by Rate Class

Residential Residential

Demand

Control

General

Service

< 20 kW

General

Service

>= 20 kW

Farm

Service

General

Service -

Time of

Use

Large

Comm.

Secondary

Large

Comm.

Primary

Large GS -

TOD

Secondary

Large GS -

TOD

Primary

Irrigation

(11.02)

Incremental Bi-directional Meter Costs for Small PP

(1) Meter Cost Investment per Customer $103.96 $99.24 $134.44 $134.44 107.49 141.82 150.97 156.25 150.97 156.25 149.90

(2) With General Plant Loading (1) x 1.0130 105.31 100.53 136.19 136.19 108.89 143.67 152.93 158.28 152.93 158.28 151.85


Capital Investment 9.14% 9.14% 9.14% 9.14% 9.14% 9.14% 9.14% 9.14% 9.14% 9.14% 9.14%

(4) A&G Loading (Plant Related) 0.10% 0.10% 0.10% 0.10% 0.10% 0.10% 0.10% 0.10% 0.10% 0.10% 0.10%

(5) Total Carrying Charge Meters (3) + (4) 9.24% 9.24% 9.24% 9.24% 9.24% 9.24% 9.24% 9.24% 9.24% 9.24% 9.24%

(6) Total Annualized Meter Costs (2) x (5) 9.73 9.29 12.59 12.59 10.06 13.28 14.13 14.63 14.13 14.63 14.03

(7) Working Capital

(8) Materials and Supplies (2) x 1.03% 1.08 1.04 1.40 1.40 1.12 1.48 1.58 1.63 1.58 1.63 1.56

(9) Prepayments (2) x 0.030% 0.03 0.03 0.04 0.04 0.03 0.04 0.05 0.05 0.05 0.05 0.05

Revenue Requirement for Working Capital

(10) [(8)+(9)] x 10.61% 0.12 0.11 0.15 0.15 0.12 0.16 0.17 0.18 0.17 0.18 0.17

(11) Total Annual Incremental Bi-Directional Meter

Costs (6) + (10) $9.85 $9.40 $12.74 $12.74 $10.19 $13.44 $14.31 $14.81 $14.31 $14.81 $14.21

--------------------------------------- (2018 Dollars per Customer) -------------------------------------


43 of 43

Case No. PU-17-

Exhibit__(DGP-1), Schedule 3

Schedule E-1

Page 1 of 1

Present Proposed

1 9.01 Residential Service (Rate 101) 41,898,051$ 47,011,619$ 5,113,568$ 12.20%

2 9.02 Residential Demand Control (Rate 241) 6,311,866$ 7,803,055$ 1,491,189$ 23.63%

3 Total Residential: 48,209,916$ 54,814,675$ 6,604,759$ 13.70%

4

5 9.03 Farm Service (Rate 361) 2,612,687$ 2,970,625$ 357,938$ 13.70%

6 Total Farm: 2,612,687$ 2,970,625$ 357,938$ 13.70%

7

8 10.01 Small General Service - Under 20 kW - Metered Service Secondary (Rate 404) 9,525,909$ 10,315,886$ 789,977$ 8.29%

9 10.01 Small General Service - Under 20 kW - Metered Service Primary (Rate 405) 532$ 580$ 48$ 8.96%

10 10.02 General Service - 20 kW or Greater - Secondary Service (Rate 401) 29,345,494$ 31,774,386$ 2,428,892$ 8.28%

11 10.02 General Service - 20 kW or Greater - Primary Service (Rate 403) 69,010$ 70,401$ 1,391$ 2.02%

12 10.03 General Service - Time of Use (Commercial TOU) - (Rates 708, 709, 710) 9,671$ 11,268$ 1,597$ 16.52%

13 Total General Service: 38,950,615$ 42,172,520$ 3,221,905$ 8.27%

14

15 10.04 Large General Service - Secondary Service (Rate 603) 31,657,902$ 33,821,005$ 2,163,104$ 6.83%

16 10.04 Large General Service - Primary Service (Rate 602) with RTP Rider (Rate 662) 11,449,285$ 12,844,033$ 1,394,749$ 12.18%

17 10.04 Large General Service - Transmission Service (Rate 632) -$ -$ -$ 0.00%

18 10.05 Large General Service Time of Day - Secondary Service (Rates 611, 615, 613) 38,758$ 43,947$ 5,189$ 13.39%

19 10.05 Large General Service Time of Day - Primary Service (Rates 610, 614, 612) -$ -$ -$ 0.00%

20 10.05 Large General Service Time of Day - Transmission Service (Rates 639, 637, 640) -$ -$ -$ 0.00%

21 11.01 Stanby Service Rider 14,765$ 16,799$ 2,034$ 13.78%

22 Total Large General Service: 43,160,710$ 46,725,785$ 3,565,075$ 8.26%

23

24 11.02 Irrigation Service - Option 1: Non-Time-of-Use (Rate 703) 27,950$ 31,103$ 3,153$ 11.28%

25 11.02 Irrigation Service - Option 2 (Rates 704, 705, 706) 31,131$ 39,203$ 8,073$ 25.93%

26 Total Irrigation: 59,081$ 70,307$ 11,226$ 19.00%

27

28 11.03 Outdoor Lighting - Metered - Energy Only (Rate 748) 97,912$ 119,790$ 21,878$ 22.34%

29 11.03 Outdoor Lighting - Non-Metered - Energy Only (Rate 749) 248,383$ 320,152$ 71,769$ 28.89%

30 11.03 Outdoor Lighting - Signal (Rate 744) 37,481$ 47,143$ 9,662$ 25.78%

31 11.04 Outdoor Lighting - Street & Area Lighting (Rate 741) 1,900,540$ 2,103,818$ 203,278$ 10.70%

32 11.04 Outdoor Lighting - Flood Lighting (Rate 743) 584,826$ 651,228$ 66,402$ 11.35%

33 Total Lighting: 2,869,142$ 3,242,131$ 372,989$ 13.00%

34

35 11.05 Municipal Pumping - Secondary Service (Rate 872) 1,200,018$ 1,357,078$ 157,060$ 13.09%

36 11.06 Civil Defense - Fire Sirens (Rate 843) 3,969$ 3,426$ (542)$ -13.66%

37 Total Other Public Authority: 1,203,986$ 1,360,505$ 156,519$ 13.00%

38

39 14.01 Water Heating - Controlled Service (Rate 191) 1,085,033$ 1,233,682$ 148,650$ 13.70%

40 Total Water Heating: 1,085,033$ 1,233,682$ 148,650$ 13.70%

41

42 14.04 Controlled Service - Interruptible Load Rider CT Metering (Rates 170, 165, 881, 168, 268, 169, 269) 2,480,828$ 2,974,204$ 493,377$ 11.83%

43 14.05 Controlled Service - Interruptible Load Rider Self-Contained Metering (Rates 190, 185, 882) 5,916,326$ 6,573,361$ 657,034$ 11.11%

44 Total Interruptible: 8,397,155$ 9,547,565$ 1,150,411$ 13.70%

45

46 14.06 Controlled Service - Deferred Load Rider (Rates 197, 195, 883) 1,036,142$ 1,064,957$ 28,815$ 2.78%

47 14.07 Fixed Time of Service Rider - Self-Contained Metering (Rates 301, 884) 281,954$ 336,896$ 54,942$ 19.49%

48 14.07 Fixed Time of Service Rider - CT Metering (Rates 302, 885) 205,527$ 247,622$ 42,094$ 20.48%

49 Total Deferred Load: 1,523,624$ 1,649,475$ 125,851$ 8.26%

50

51 TOTAL REVENUE: 148,071,950$ 163,787,270$ 15,715,320$ 10.61%

52

Proposed Test Year 2018 Operating Revenue Summary Comparison - By Rate Schedule

Line

No.Difference

Percent Change

Operating RevenuesRate Schedule

CCOSS or

EPMC

Method

Rate ClassesProposed Intra-

Class Increase

Total Present

Revenues

(including Riders)

Total Proposed

Revenues

(including Riders)

Change in Non-

Fuel Base

Revenues

Present Base Rate

Revenue 2018 (excluding

Riders)

Proposed Base

Rate Revenue

(excluding Riders)

2018 Average

Revenue 100%

Marginal Cost

2018

Proposed

Revenue as

% of 100%

MC

Marginal

Revenue

Allocation

Method 2 Residential Service 12.20% 41,898,051$ 47,011,619$ -1.56% 36,601,009$ 36,030,409$ 35,298,607$ 102.1% 84.9%

Res. Demand Control 23.63% 6,311,866$ 7,803,055$ 3.49% 5,364,879$ 5,552,254$ 6,271,651$ 88.5% 15.1%

RESIDENTIAL CLASS 13.70% 48,209,916$ 54,814,675$ -0.91% 41,965,888$ 41,582,663$ 41,570,258$ 100.0% 100.0%

CCOSS Farm Service 13.70% 2,612,687$ 2,970,625$ -2.08% 2,155,303$ 2,110,506$ 2,324,518$ 90.8%

Small General Service 8.29% 9,526,441$ 10,316,466$ -4.67% 8,376,479$ 7,985,135$ 6,809,680$ 117.3% 27.7%

Method 2 General Service 8.26% 29,414,504$ 31,844,787$ -8.25% 25,575,200$ 23,464,413$ 17,754,659$ 132.2% 72.3%

GS Time of Use 16.52% 9,671$ 11,268$ -1.75% 8,328$ 8,182$ 7,807$ 104.8% 0.032%

GENERAL SERVICE CLASS 8.27% 38,950,615$ 42,172,520$ -7.37% 33,960,007$ 31,457,729$ 24,572,147$ 128.0% 100.0%

Method 1 LGS CLASS 8.26% 43,160,710$ 46,725,785$ -17.00% 37,389,529$ 31,031,481$ 36,590,771$ 84.8% 100.0%

LGS Secondary 6.83% 31,657,902$ 33,821,005$ -17.24% 27,517,756$ 22,773,982$ 27,358,886$ 83.2% 74.8%

LGS Primary & RTP Rider 12.18% 11,449,285$ 12,844,033$ -16.41% 9,824,615$ 8,212,272$ 9,195,390$ 89.3% 25.1%

LGS Transmission n/a -$ -$ n/a -$ -$ -$ 0.0% 0.0%

LGS Subtotal 8.25% 43,107,186$ 46,665,039$ -17.02% 37,342,371$ 30,986,254$ 36,554,276$ 84.8% 99.90%

LGS TOD Secondary 13.39% 38,758$ 43,947$ -5.68% 34,024$ 32,093$ 36,495$ 87.9% 0.1%

LGS TOD Primary n/a -$ -$ n/a -$ -$ -$ 0.0% 0.0%

LGS TOD Transmission n/a -$ -$ n/a -$ -$ -$ 0.0% 0.0%

Standby Service 13.78% 14,765$ 16,799$ 0.00% 13,134$ 13,134$ -$ 0% 0%

LGS TOD Subtotal 13.5% 53,523$ 60,746$ -4.1% 47,158$ 45,227$ 36,495$ 123.9% 0.10%

Method 1 Irrigation 11.28% 27,950$ 31,103$ -9.43% 26,344$ 23,859$ 25,462$ 93.7% 47.1%

Irrigation Time of Use 25.93% 31,131$ 39,203$ -9.19% 29,401$ 26,698$ 28,569$ 93.5% 52.9%

IRRIGATION CLASS 19.0% 59,081$ 70,307$ -9.3% 55,745$ 50,557$ 54,031$ 93.6% 100.00%

Method 3 Lighting Energy Only 26.92% 383,776$ 487,085$ 5.28% 339,322$ 357,222$ 148,674$ 240.3% 21.6%

Area Lighting 10.85% 2,485,366$ 2,755,046$ 1.43% 2,258,606$ 2,290,951$ 540,068$ 424.2% 78.4%

OUTDOOR LIGHTING CLASS 13.00% 2,869,143$ 3,242,131$ 1.93% 2,597,928$ 2,648,173$ 688,742$ 384.5% 100.00%

CCOSS Municipal Pumping 13.09% 1,200,018$ 1,357,078$ -10.73% 1,039,969$ 928,426$ 978,639$ 94.9% 99.8%

Fire Sirens -13.66% 3,969$ 3,426$ -8.06% 3,727$ 3,426$ 2,423$ 141.4% 0.2%

OPA CLASS 13.00% 1,203,986$ 1,360,504$ -10.72% 1,043,696$ 931,853$ 981,062$ 95.0% 100.00%

CCOSS Water Heating 13.70% 1,085,033$ 1,233,682$ -13.09% 987,779$ 858,515$ 1,319,964$ 65.0% 100.0%

Method 1 Large Dual Fuel 19.89% 2,480,828$ 2,974,204$ -40.80% 2,130,188$ 1,261,089$ 2,819,159$ 44.7% 27.1%

Small Dual Fuel 11.11% 5,916,326$ 6,573,361$ -37.59% 5,165,773$ 3,223,769$ 7,600,519$ 42.4% 72.9%

CONTROLLED SERVICE INTERRUPTIBLE 11.5% 8,397,155$ 9,547,565$ 11.5% 7,295,962$ 4,484,858$ 10,419,677$ 43.0% 100.00%

Method 1 Deferred Load 2.78% 1,036,142.38$ 1,064,957.03$ -32.02% 918,394$ 624,307$ 806,358$ 77.4% 71.5%

Fixed Time of Service 19.91% 487,482$ 584,518$ -34.07% 242,868$ 160,130$ 321,682$ 49.8% 28.5%

CONTROLLED SERVICE DEFERRED 8.26% 1,523,624$ 1,649,475$ -32.83% 1,337,726$ 898,580$ 1,128,041$ 79.7% 100.00%

Total 10.61% 148,071,950$ 163,787,269$ -9.89% 128,789,562$ 116,054,915$ 82,406,193$ 140.8%


Page 1 of 1

Class

Present

Customer

Charge

($/Month)

Proposed

Customer

Charge

($/Month)

2008

Marginal

Cost

($/Month)

2018

Marginal

Cost

($/Month)

Present Customer

Charge as Percent

of 2008 Marginal

Cost

Proposed Customer

Charge as Percent

of 2018 Marginal

Cost

Residential $8.00 $17.70 $10.11 $17.70 79% 100.0%

Residential – Demand Control $18.38 $20.10 $16.77 $20.18 110% 99.6%

Farm Service – Single Phase $12.00 $17.40 $12.34 $17.42 97% 99.9%

Farm Service – Three Phase $12.00 $17.40 $12.34 $17.42 97% 99.9%

Small General Service $13.00 $24.90 $17.51 $24.94 74% 99.8%

General Service (Secondary) $12.00 $31.90 $26.50 $31.91 45% 100.0%

General Service TOU $16.00 $219.00 $259.06 $219.05 6% 100.0%

Large General Service (Secondary) $40.00 $215.90 $254.44 $215.95 16% 100.0%

Large General Service – Time of Day

(Primary)$60.00 $282.00 $303.69 $282.08 20% 100.0%

Irrigation – Option 1 $1.00 $24.30 $23.56 $24.33 4% 99.9%

Irrigation – Option 2 $5.00 $24.30 $259.06 $24.33 2% 99.9%

Outdoor Lighting – Metered $2.00 $2.00 $4.26 $0.30 47% 667%

Outdoor Lighting – Non-metered $0.00 $0.00 $3.67 $0.30 0% 0.0%

Municipal Pumping (All) $4.00 $26.50 $25.21 $26.55 16% 99.8%

Civil Defense $1.00 $1.22 $25.21 $26.55 4% 4.6%

Water Heating $1.00 $4.00 $6.70 $5.59 15% 71.6%

Controlled Service - Interruptible- Large #1 $4.00 $20.20 $34.17 $20.27 12% 99.7%

Controlled Service - Interruptible- Large #2 $5.00 $20.20 $34.17 $20.27 15% 99.7%

Controlled Service – Interruptible-Small $2.00 $8.50 $14.35 $20.27 14% 41.9%

Deferred Load Service $3.00 $8.80 $17.23 $8.86 17% 99.3%

Fixed Time of Service $1.50 $6.70 $17.23 $6.71 9% 99.9%

Case No. PU-17- Exhibit___(DGP), Schedule 5

Page 1 of 1

Residential Service (Section 9.01) Usage Analysis

(2016 Actual Data ‐ ND)

All Low‐Income1

Non‐ Low Income

Total number of residential customers on the standard residential tariff 37,593 1,068 36,525

Total number of residential customers using less than 750 kwh 22,352 451 21,901

Total number of residential customers using 750 kwh or more 15,241 617 14,624

Average monthly usage for residential customers 786 1184 774

Average monthly usage for residential customers using less than 750 kwh 376 435 375

Average monthly usage for residential customers using 750 kwh or more 1,387 1,731 1,372

Average bill for residential customers $86.10 $122.71 $85.03

Average bill for residential customers using less than 750 kwh $46.54 $52.61 $46.42

Average bill for residential customers using 750 kwh or more $144.10 $173.94 $142.84

Total number of residential customers using less than 750 kwh 59% 42% 60%

Total number of residential customers using 750 kwh or more 41% 58% 40%

Average monthly usage for residential customers using less than 750 kwh 48% 37% 48%

Average monthly usage for residential customers using 750 kwh or more 176% 146% 177%

Average bill for residential customers using less than 750 kwh 54% 43% 55%

Average bill for residential customers using 750 kwh or more 167% 142% 168%

Notes

1. Defined as customers in the LIHEAP Program.


Page 1 of 1

ELECTRIC RATE SCHEDULE 10.05

Large General Service - Time of Day

PRESENTTIME OF DAY PRICE PERIOD DESIGNATIONS

Summer season June, July, Aug, Sept Winter season Oct through May

Sun Mon Tue Wed Thu Fri Sat Sun Mon Tue Wed Thu Fri SatHour

Ending

Hour

Ending

1 1

2 2

3 3

4 4

5 5

6 6

7 7

8 8

9 9

10 10

11 11

12 12

13 13

14 14

15 15

16 16

17 17

18 18

19 19

20 20

21 21

22 22

23 23

24 24

"On-peak" price period

"Shoulder" price period

"Off-peak" price period

OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota


Page 1 of 2

ELECTRIC RATE SCHEDULE 10.05

Large General Service - Time of Day

TIME OF DAY PRICE PERIOD DESIGNATIONS

Summer season June, July, Aug, Sept Winter season Oct through May

Sun Mon Tue Wed Thu Fri Sat Sun Mon Tue Wed Thu Fri SatHour

Ending

Hour

Ending

1 1

2 2

3 3

4 4

5 5

6 6

7 7

8 8

9 9

10 10

11 11

12 12

13 13

14 14

15 15

16 16

17 17

18 18

19 19

20 20

21 21

22 22

23 23

24 24

"On-peak" price period

"Shoulder" price period

"Off-peak" price period

PROPOSED

OTTER TAIL POWER COMPANY Electric Utility - State of Minnesota


Page 2 of 2

Facilities and O&M Related Costs

LED5 LED10 LED3PT LED5PT LED8 LED13 LED20 FLOOD LED30 FLOOD

SECURITY

LIGHT (OPEN

BOTTOM) LED5

(1) Marginal Investment per fixture (all costs and labor) Input-Lighting Cost workpapers $268.37 $399.58 $552.41 $586.58 $317.57 $440.58 $975.83 $1,180.84 $1,100.73

(2) With General Plant Loading (1) x 1.0130 $271.86 $404.77 $559.59 $594.21 $321.70 $446.31 $988.52 $1,196.19 $1,115.04


Capital Investment (9) Input - Marginal Cost Study T29 P5 9.49% 9.49% 9.49% 9.49% 9.49% 9.49% 9.49% 9.49% 9.49%

(4) A&G Loading (plant-related) (10) Input - Marginal Cost Study T29 P5 0.10% 0.10% 0.10% 0.10% 0.10% 0.10% 0.10% 0.10% 0.10%

(5) Total Annual Carrying Charge (3) + (4) 9.59% 9.59% 9.59% 9.59% 9.59% 9.59% 9.59% 9.59% 9.59%

(6) Annualized Costs (2) x (5) $26.06 $38.81 $53.65 $56.97 $30.84 $42.79 $94.77 $114.68 $106.90

(7) Annual Lighting O&M Expenses Input-Lighting Cost workpapers $11.76 $11.76 $11.76 $11.76 $11.76 $11.76 $11.76 $11.76 $0.00

(8) With A&G Loading (non-plant related) (7) x 1 1323 Input-Marginal Cost Study $13.32 $13.32 $13.32 $13.32 $13.32 $13.32 $13.32 $13.32 $0.00

(9) Distribution Facilities Related Costs (6) + (8) $39.38 $52.12 $66.97 $70.28 $44.16 $56.11 $108.09 $128.00 $106.90

Working Capital

(10) Material and Supplies (2) x 1 20% $3.26 $4.86 $6.72 $7.13 $3.86 $5.36 $11.86 $14.35 $13.38

(11) Prepayments (2) x 0 03% $0.08 $0.12 $0.17 $0.18 $0.10 $0.13 $0.30 $0.36 $0.33

(12) Cash Working Capital Allowance (8) x 6 67% $0.89 $0.89 $0.89 $0.89 $0.89 $0.89 $0.89 $0.89 $0.00

(13) Total Working Capital (10) + (11) + (12) $4.23 $5.87 $7.77 $8.20 $4.85 $6.38 $13.05 $15.60 $13.71

(14) Revenue Requirement for Working Capital (13) x 11 20% $0.47 $0.66 $0.87 $0.92 $0.54 $0.71 $1.46 $1.75 $1.54


Facilities Related Costs (9) + (14) $39.85 $52.78 $67.84 $71.20 $44.70 $56.82 $109.55 $129.75 $108.44

O&M - Meter, Customer Accounts Expenses, Customer Service

(16) Meter and CT O&M Expenses (13) Input - Marginal Cost Study T29 P5 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00

(17) Customer Accounts Expenses (14) Input - Marginal Cost Study T29 P5 $2.39 $2.39 $2.39 $2.39 $2.39 $2.39 $2.39 $2.39 $2.39

(18) Customer Service and Informational Expenses (15) Input - Marginal Cost Study T29 P5 $1.10 $1.10 $1.10 $1.10 $1.10 $1.10 $1.10 $1.10 $1.10

(19) With A&G Loading (Non-plant Related) [(16)+(17)+(18)] x 1 1323 $3.95 $3.95 $3.95 $3.95 $3.95 $3.95 $3.95 $3.95 $3.95

(20) Customer-Related Costs (6) + (12) + (16) $26.95 $39.70 $54.54 $57.86 $31.73 $43.68 $95.66 $115.57 $106.90

Working Capital

(21) Materials and Supplies $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00

(22) Prepayments $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00

(23) Cash Working Capital (19) x 6 67% $0.26 $0.26 $0.26 $0.26 $0.26 $0.26 $0.26 $0.26 $0.26

(24) Revenue Requirement for Working Capital [(21)+(22)+(23)]x11 20% $0.03 $0.03 $0.03 $0.03 $0.03 $0.03 $0.03 $0.03 $0.03

(25) Total Annual Marginal Customer-Related Costs (20) + (24) $26.98 $39.73 $54.57 $57.89 $31.76 $43.71 $95.69 $115.60 $106.93

(26) Total Annual Marginal Facilites & Customer-Related Costs per fixture (15) + (25) $66.84 $92.51 $122.40 $129.09 $76.46 $100.53 $205.24 $245.35 $215.37

(27) Monthly Marginal Facilities & Customer-Related Costs per lighting fixture (26) / 12 $5.57 $7.71 $10.20 $10.76 $6.37 $8.38 $17.10 $20.45 $17.95

Energy Costs Calculation per Fixture

(26) Lighting fixture input (connected kW) input - Mfg data 0.047 0.095 0.026 0.047 0.076 0.133 0.199 0.261 0.047

(27) Monthly charge per connected k(Marginal KWH rate/4100/12month) $7.26 input Section 11 03, Rate Code 31-749 $7.26 $7.26 $7.26 $7.26 $7.26 $7.26 $7.26 $7.26 $7.26

(28) Monthly kWh charge (26 * 27) $0.34 $0.69 $0.19 $0.34 $0.55 $0.97 $1.44 $1.89 $0.34

Total Monthly Fixture Cost

(29) Monthly Marginal Cost per fixture (excluding monthly energy) (27) $5.57 $7.71 $10.20 $10.76 $6.37 $8.38 $17.10 $20.45 $17.95

(30) Monthly kWh charge (28) $0.34 $0.69 $0.19 $0.34 $0.55 $0.97 $1.44 $1.89 $0.34

(30) Total Monthly Pole Cost (29) $9.53 $9.53 $8.89 $10.45 $9.53 $11.43 $11.43 $16.00 $9.53

(32) Total Monthly Fixture Cost (27) + (28)+(29) $15.44 $17.93 $19.28 $21.55 $16.45 $20.77 $29.98 $38.34 $27.82

----------------------------- (2016 Dollars per fixture) -------------------------


Page 1 of 3

Facilities and O&M Related Costs

(1) Marginal Investment per fixture (all costs and labor) Input-Lighting Cost workpapers

(2) With General Plant Loading (1) x 1.0130


Capital Investment (9) Input - Marginal Cost Study T29 P5

(4) A&G Loading (plant-related) (10) Input - Marginal Cost Study T29 P5

(5) Total Annual Carrying Charge (3) + (4)

(6) Annualized Costs (2) x (5)

(7) Annual Lighting O&M Expenses Input-Lighting Cost workpapers

(8) With A&G Loading (non-plant related) (7) x 1 1323 Input-Marginal Cost Study

(9) Distribution Facilities Related Costs (6) + (8)

Working Capital

(10) Material and Supplies (2) x 1 20%

(11) Prepayments (2) x 0 03%

(12) Cash Working Capital Allowance (8) x 6 67%

(13) Total Working Capital (10) + (11) + (12)

(14) Revenue Requirement for Working Capital (13) x 11 20%


Facilities Related Costs (9) + (14)

O&M - Meter, Customer Accounts Expenses, Customer Service

(16) Meter and CT O&M Expenses (13) Input - Marginal Cost Study T29 P5

(17) Customer Accounts Expenses (14) Input - Marginal Cost Study T29 P5

(18) Customer Service and Informational Expenses (15) Input - Marginal Cost Study T29 P5

(19) With A&G Loading (Non-plant Related) [(16)+(17)+(18)] x 1 1323

(20) Customer-Related Costs (6) + (12) + (16)

Working Capital

(21) Materials and Supplies

(22) Prepayments

(23) Cash Working Capital (19) x 6 67%

(24) Revenue Requirement for Working Capital [(21)+(22)+(23)]x11 20%

(25) Total Annual Marginal Customer-Related Costs (20) + (24)

(26) Total Annual Marginal Facilites & Customer-Related Costs per fixture (15) + (25)

(27) Monthly Marginal Facilities & Customer-Related Costs per lighting fixture (26) / 12

Energy Costs Calculation per Fixture

(26) Lighting fixture input (connected kW) input - Mfg data

(27) Monthly charge per connected k(Marginal KWH rate/4100/12month) $7.26 input Section 11 03, Rate Code 31-749

(28) Monthly kWh charge (26 * 27)

Total Monthly Fixture Cost

(29) Monthly Marginal Cost per fixture (excluding monthly energy) (27)

(30) Monthly kWh charge (28)

(30) Total Monthly Pole Cost (29)

(32) Total Monthly Fixture Cost (27) + (28)+(29)

FIBERGLASS

STANDARDS

FS18

FIBERGLAS

S

STANDARD

S FS23

ALUMINUM

ALLOY

STANDARDS

30'

ALUMINUM

ALLOY

STANDARDS40

'

STANDARD

POLE (LED5,

LED8 & LED10)

STANDARD

POLE (LED13 &

LED20 FLOOD)

STANDARD

POLE (LED30

FLOOD)

FLOOD

LIGHTING

VISOR LED 20

FLOOD

FLOOD

LIGHTING

VISOR LED30

FLOOD

$766.89 $901.15 $2,979.13 $3,237.00 $821.72 $985.76 $1,380.09 $65.23 $118.94

$776.86 $912.86 $3,017.86 $3,279.08 $832.40 $998.57 $1,398.03 $66.08 $120.49

6.70% 6.70% 6.70% 6.70% 6.70% 6.70% 6.70% 6.70% 6.70%

0.10% 0.10% 0.10% 0.10% 0.10% 0.10% 0.10% 0.10% 0.10%

6.80% 6.80% 6.80% 6.80% 6.80% 6.80% 6.80% 6.80% 6.80%

$52.81 $62.05 $205.14 $222.90 $56.58 $67.88 $95.03 $4.49 $8.19

$0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00

$0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00

$52.81 $62.05 $205.14 $222.90 $56.58 $67.88 $95.03 $4.49 $8.19

$9.32 $10.95 $36.21 $39.35 $9.99 $11.98 $16.78 $0.79 $1.45

$0.23 $0.27 $0.91 $0.98 $0.25 $0.30 $0.42 $0.02 $0.04

$0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00

$9.56 $11.23 $37.12 $40.33 $10.24 $12.28 $17.20 $0.81 $1.48

$1.07 $1.26 $4.16 $4.52 $1.15 $1.38 $1.93 $0.09 $0.17

$53.88 $63.31 $209.30 $227.42 $57.73 $69.25 $96.96 $4.58 $8.36

$0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00

$2.39 $2.39 $2.39 $2.39 $2.39 $2.39 $2.39 $2.39 $2.39

$1.10 $1.10 $1.10 $1.10 $1.10 $1.10 $1.10 $1.10 $1.10

$3.95 $3.95 $3.95 $3.95 $3.95 $3.95 $3.95 $3.95 $3.95

$52.81 $62.05 $205.14 $222.90 $56.58 $67.88 $95.03 $4.49 $8.19

$0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00

$0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00

$0.26 $0.26 $0.26 $0.26 $0.26 $0.26 $0.26 $0.26 $0.26

$0.03 $0.03 $0.03 $0.03 $0.03 $0.03 $0.03 $0.03 $0.03

$52.84 $62.08 $205.17 $222.93 $56.61 $67.91 $95.06 $4.52 $8.22

$106.72 $125.39 $414.47 $450.34 $114.34 $137.16 $192.02 $9.10 $16.58

$8.89 $10.45 $34.54 $37.53 $9.53 $11.43 $16.00 $0.76 $1.38

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

$7.26 $7.26 $7.26 $7.26 $7.26 $7.26 $7.26 $7.26 $7.26

$0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00

$8.89 $10.45 $34.54 $37.53 $9.53 $11.43 $16.00 $0.76 $1.38

$0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00

$8.89 $10.45 $34.54 $37.53 $9.53 $11.43 $16.00 $0.76 $1.38


Page 2 of 3

New & Existing

Light Type

Annual Bill

Quantity

Current

Monthly

Rate

LED Weighted

Monthly Rate

Current

LED Weighted

Monthly Rate

(Rate Case)

Proposed

LED

MARGINAL

RATE

LED10 604.15 15.44$ 15.71$ $10.56

HPS23 557.78 15.40$

MA20 - 18.38$

MV11 8.03 12.70$

MV21 38.34 16.72$

LED13 429.15 20.32$ 20.66$ $12.13

HPS44 381.86 19.01$

MA110 29.90 38.41$

MA36 17.39 18.00$

MV35 - 24.53$

MV55 - 31.36$

LED20FLOOD 1,730.04 18.56$ 18.98$ $17.01

400 MV 165.78 17.35$

4CHPS 16.84 12.94$

400 HPS 968.90 18.90$

400 MA 578.52 18.49$

LED30FLOOD 378.55 30.45$ 30.96$ $21.45

1M-HPSF 1.08 30.44$

1000-MV 376.23 30.44$

1000-MA 1.25 32.11$

LED3PT 454.39 9.83$ 10.01$ $11.00

HPS9PT 273.60 9.72$

MV6PT 180.78 10.00$

LED5 16,359.73 7.32$ 7.44$ $9.14

HPS14 195.86 11.71$

HPS9 7,095.74 7.52$

MA8 391.31 8.46$

MV6 8,676.82 7.01$

LED5PT 47.51 12.53$ 12.75$ $12.21

HPS14PT 47.51 12.53$

MA8PT - -$

LED8 89.10 13.64$ 13.88$ $9.75

HPS19 88.10 13.61$

MA14 1.00 16.10$


Page 3 of 3

Schedule 9

David G. Prazak

Schedule Number(s)

Schedule Description Changes

All • Updating all footers for the new successor to:

• Approved: Bruce G. Gerhardson, Vice President, Regulatory Affairs

Index • Removing “Prior Sheet” Column, as this is no longer applicable

4.01 Meter and Service Installations

• Including new language in paragraph 2 beginning “The Company will connect electric service to a previously served location” to define the four rules under which reconnection will occur

4.13 Account History Charge • Defining to whom the charges will be applicable by including “by a landlord/building owner or other party”

• Adding additional clarification by including “The Account History Charge shall not excel $100 per request set. The landlord/building owner or other third-party request must be accompanied by a signed release from each Customer.”

5.01 Extension Rules and Minimum Revenue Guarantees

• Removing language in paragraph 1 regarding the energy adjustment rider and base costs of energy, as they are no longer applicable and adding “schedule(s) under which the customer is taking service.” To complete the sentence

• Removing language regarding the energy adjustment rider and base costs of energy in paragraph 3, as they are no longer applicable

5.04 Standard Installation • Removing paragraph seven (duplication of paragraph 6)

• Removing the language in paragraph 1 under Service Installation regarding the energy-cost recovery, as it is no longer applicable

9.01-15.00 • In the Description Box, updating the rate level from 50 to 52 for all rate codes

9.01 Residential Service • Removing the designation of two levels, “First 1,000” and “Excess”, of kWh charges as the rate design is changing to a single kWh charge

• Removing paragraph 4 under 2. on page 2 regarding bills “rendered on a two-month basis” as this is no longer applicable

• Rate Changes

9.02 Residential Demand Control Service

• Rate Changes

9.03 Farm Service • Removing the levels of Three Phase designations to just Three Phase only with a single charge

• Removing the designation of two levels, “First 1,000” and “Excess”, of kWh charges as the rate design is changing to a single kWh charge

• Rate Changes

9.04 Residential Time of Day Service – Pilot

• New Rate Schedule: Residential Time-of-Day Service - Pilot

10.01 Small General Service • Under Application of Schedule: Adding “dusk to dawn” to clarify the hours of use under this schedule

• Under Terms and Conditions, updating the language to explain that a customer will be moved to the General Service Schedule (10.02) during their next billing cycle if their Demand equals or exceeds 20kW three times within the recent 12 months

• Rate Changes

10.02 General Service • Under Application of Schedule: Adding “dusk to dawn” to clarify the hours of use under this schedule

• Under Rate: Adding the language “Per annual Max. kW (Minimum 20 kW per Month)” under Facilities Charge per Month for clarity

• Rate Changes

10.03 General Service – Time of Use • Updating this schedule to General Service – Time of Use (currently called Large General Service) by: o Relocating the language from Schedule 10.04 Commercial Service – Time of

Use: Description, Rate Codes, Application of Schedule, Rate definitions, Terms and Conditions, Definition of Declared, Intermediate and Off-Peak Periods by Season, Declared-Peak Notification, Determination of Demand

Case No. PU-17- Exhibit___(DGP-1), Sechedule 9

Page 1 of 4

• Adding additional language to the “Definition of Declared, Intermediate and Off-Peak Periods by Season” section to better define the Declared-Peak, Intermediate, and Off-Peak designations

• Rate Changes

10.04 Large General Service • Updating this schedule to Large General Service (currently called Commercial Service – Time of Use) by: o Relocating the language from Schedule 10.03 Large General Service:

Description, Application of Schedule, Rate definitions (including tiered Facilities Charges), Definition of Seasons, Determination of Facilities Charge, Determination of Billing Demand, Adjustment for Excess Reactive Demand

• Removing the designation of two levels, “First 1,000” and “Excess”, of kWh charges under each of the Primary, Secondary and Transmission rate definitions as the rate design is changing to a single kWh charge

• Including “(Minimum of 80 kw) under our Demand Charge per kw under each of the Primary, Secondary and Transmission rate definitions for clarity

• Rate Changes

10.05 Large General Service – Time of Day

• Removing “Experimental” from the name of this schedule, including the header

• In the Rate box, including (Minimum of 80 kW per Month) under the Demand Charge per kW under each of the Primary, Secondary and Transmission rates

• Updating the Definition of On-Peak, Shoulder and Off-Peak Periods by Season to the new Time of Day time periods

• Rate Changes

10.06 Super Large General Service – Applications and Eligibility Requirements

• New Rate Schedule: Super Large General Service – Applications and Eligibility Requirements

11.01 Standby Service • Relocating the order of seasonal information, both Summer and Winter, for consistency with other schedules

• Adding specific hours for the Off-Peak timeframes

• Rate Changes

11.02 Irrigation Service • Including additional definition to the Winter and Summer season for better clarity

• On Page 3, adding Declared-Peak Notification paragraph to provide definition of expectations

• Rate Changes

11.03 Outdoor Lighting – Energy Only

• Changing Rate Code 744 to “Closed to New Installations”

• Rate Changes

11.04 Outdoor Lighting • Including the designation of “Closed to New Installations and Replacements” for each Rate Code within the Description area, as the rates within the new LED Schedule 11.07 will provide service for Outdoor Lighting

• On Page 2 under section “Underground Service”, removing the words “or sign“ as it is not applicable

• Rate Changes

11.05 Municipal Pumping Service • In the Rate box for both Secondary and Primary, including “Annual Maximum kW per” to provide more clarity to the required Facilities Charge

• Rate Changes

11.06 Civil Defense – Fire Sirens • Rate Changes

11.07 LED Street and Area Lighting – Dusk to Dawn

• New Rate Schedule: LED Street and Area Lighting - Dusk to Dawn

• Rate Changes

12.00 Purchase Power Riders & Applicability Matrix

• Including new rows for the following new rates and checking the applicable Small Power Producer Riders: o Under Residential & Farm Services: Residential Time of Day Service (9.04) o Under General Services: Super Large General Service (10.06) o Under Other Services: LED Street and Area Lighting (11.07)


Page 2 of 4

• Under General Services, modifying the rows for General Service – Time of Use and Large General Service to reflect the schedule number change for each

13.00 Mandatory Riders & Applicability Matrix

• Including new rows for the following new rates and applying the proper setting for the applicable Mandatory Riders: Page 1: o Under Residential & Farm Services: Residential Time of Day Service (9.04) o Under General Services: Super Large General Service (10.06) o Under Other Services: LED Street and Area Lighting (11.07) Page 2: o Under Mandatory Riders: Generation Cost Recovery Rider (13.06)


• Under Mandatory Riders, moving Transmission Cost Recovery Rider (13.05) below Renewable Resource Cost Recovery Rider to fall in line with the section numbers

• Under Mandatory Riders, setting 13.07 to “Reserved for Future Use” due to the move of the Transmission Cost Recovery Rider to 13.05

• Under Voluntary Riders, setting 14.12 to “Reserved for Future Use” due to the cancellation of the Released Energy Access Program Rider

• Updating the column for section 13.05 for the Transmission Cost Recovery Rider and carrying over the proper Base Tariff settings for this rider

• Updating the column for 13.06 for the Generation Cost Recovery Rider and applying the proper settings for the Base Tariffs

• Setting the column for 13.07 to “Reserved for Future Use” due to the move of the Transmission Cost Recovery rider to 13.05

13.01 Energy Adjustment Rider/Energy Adjustment Rider by Service Category

• Providing two versions of this Schedule: Energy Adjustment Rider and Energy Adjustment Rider by Service Category; Both include: o Additional language to the Energy Adjustment Charge section to define how

this charge will be applied o A new section titled “Energy Adjustment Factor (EAF) to define how the EAF

is calculated, including a table of each Service Category, the applicable Schedules, and the EAF Ratio for that category

o The average cost of energy has been modified to include the addition of language in section 1. regarding the included costs of reagents and emission allowances

• Energy Adjustment Rider has a set EAF Ratio of 1.000 for all categories due to the limitations within our current CIS system

• Energy Adjustment Rider by Service Category has a unique EAF Ratio for each of the categories in preparation for our new CIS system

• Rate Changes

13.04 Renewable Resource Cost Recovery Rider

• Rate Changes

13.05 Transmission Cost Recovery Rider

• This tariff will be Cancelled as the Economic Development Cost Removal Rider

• This tariff is becoming the Transmission Cost Recovery Rider for consistency with our schedules within the Company – relocating all language from 13.07 to 13.05

13.06 Generation Cost Recovery Rider

• New Rate Schedule: Generation Cost Recovery Rider

13.07 Cancelled/Reserved for Future Use

• This tariff will be closed and Reserved for Future Use as the Transmission Cost Recovery Rider moves to 13.05

14.00 Voluntary Riders – Applicability Matrix

• Including new rows for the following new rates and applying the proper setting for the applicable Voluntary Riders: o Under Residential & Farm Services: Residential Time of Day Service (9.04) o Under General Services: Super Large General Service (10.06) o Under Other Services: LED Street and Area Lighting (11.07)


Page 3 of 4


• Setting the column for 14.11 to “Reserved for Future Use” due to the cancellation of the Released Energy Access Program Rider and removing the checks from all rows

14.01 Water Heating Control Rider • Rate Changes

14.02 Real Time Pricing Rider • Rate Changes

14.03 Large General Service Rider • Administrative Charge Rate Change

14.04 Controlled Service – Interruptible Load CT Metering Rider (LDF)

• In the Availability section, including additional language to more clearly define the acceptable loads and back-up system options

• Rate Changes

14.05 Controlled Service – Interruptible Load Self-Contained Metering Rider (SDF)

• In the Availability section, including additional language to more clearly define the acceptable loads and back-up system options

• Within the Rate table on page 2, changing “INTERR” to include the full word “INTERRUPTIBLE”

• Rate Changes

14.06 Controlled Service Deferred Load Rider

• In the Availability section, correcting grammar and including additional language to more clearly define the acceptable loads

• Rate Changes

14.07 Fixed Time of Service Rider • In the Availability section, including additional language to more clearly define the acceptable loads

• Updated title of Section from Fixed Time of Delivery to Fixed Time of Service

• Rate Changes

14.08 Air Conditioning Control Rider (CoolSavings)

• Adding a new Rate 52-762 with description of “Commercial Air Conditioning Control Rider”

• Modifying the Availability section to define the addition of customer groups to “Residential, Residential associated with a Farm and Commercial Customers”, equipment requirements to include heat pumps, and to whom these rates will be unavailable

• Under the Compensation section, designated the existing language for the Residential (52-760) rate and added an addition paragraph for Commercial (52-762) and the applicable compensation details

• Updating 2. under the Terms and Conditions section, to more clearly define the responsibility of costs regarding non-standard facilities

• Under Terms and Conditions, adding 6. for a description of how Commercial cooling will be controlled

• Rate Addition and Change

14.09 Voluntary Renewable Energy Rider (TailWinds)

• Rate Change

14.10 WAPA Bill Crediting Program Rider

• No language changes

14.11 Reserved for Future Use • Cancelling the existing Released Energy Access Program (REAP) Rider

• Reserving for Future Use

14.12 Bulk Interruptible Service • No language changes


Page 4 of 4