MONTANA-DAKOTA UTILITIES CO.

Before the Public Service Commission of Wyoming

Docket No. 30013-351-GR-19

Direct Testimony of

Nicole A. Kivisto

Q. Please state your name and business address. 1

A. My name is Nicole A. Kivisto and my business address is 400 North 2

Fourth Street, Bismarck, North Dakota 58501. 3

Q. By whom are you employed and in what capacity? 4

A. I am the President and Chief Executive Officer (CEO) of Montana-5

Dakota Utilities Co. (Montana-Dakota), Cascade Natural Gas Corporation 6

and Intermountain Gas Company, subsidiaries of MDU Resources Group, 7

Inc. as well as Great Plains Natural Gas Co., a division of Montana-8

Dakota, collectively the MDU Utilities Group. 9

Q. Have you testified in other proceedings before regulatory bodies? 10

A. Yes. I have previously presented testimony before this Commission, 11

the Public Service Commissions of Montana and North Dakota, the Public 12

Utilities Commissions of Idaho, Minnesota and South Dakota, the Public 13

Utility Commission of Oregon, and the Washington Utilities and 14

Transportation Commission. 15

Q. Please describe your duties and responsibilities with Montana-16

Dakota. 17

2

A. I have executive responsibility for the development, coordination, 1

and implementation of strategies and policies relative to operations of the 2

above mentioned companies that, in combination, serve over one million 3

customers in eight states. 4

Q. Please outline your educational and professional background. 5

A. I hold a Bachelor’s Degree in Accounting from Minnesota State 6

University Moorhead. I began working for MDU Resources/Montana-7

Dakota in 1995 and have been in my current capacity since January 2015. 8

I was the Vice President-Operations of Montana-Dakota and Great Plains 9

from January of 2014 until assuming my present position. 10

Prior to that, I was the Vice President, Controller and Chief 11

Accounting Officer for MDU Resources for nearly four years and held 12

other finance related positions prior to that. 13

Q. What is the purpose of your testimony? 14

A. The purpose of my testimony is to provide an overview of the 15

Company’s Wyoming natural gas operations, explain the Company’s 16

request for a natural gas distribution rate increase and discuss the policies 17

and reasons underlying the major aspects of the request. I will also 18

introduce the other Company witnesses that will present testimony and 19

exhibits in further support of the Company’s request. 20

Q. Would you provide a summary of Montana-Dakota's gas operations 21

in Wyoming? 22

3

A. Montana-Dakota provides natural gas service to approximately 1

19,059 customers in nine communities, operating approximately 656 miles 2

of distribution mains and approximately 19,600 services. The customer 3

base is 87 percent residential and 13 percent commercial and industrial. 4

As of December 31, 2018, the Company had 31 full and part time 5

employees who live and work throughout the Wyoming service area. 6

Montana-Dakota's Wyoming district office is located in Sheridan, 7

Wyoming. Additionally, there are gas related service technicians and 8

construction employees headquartered in Lovell and Powell. A gas 9

service technician is also located in Buffalo. In addition to Sheridan, these 10

three Wyoming communities are deemed strategic to the safe and reliable 11

operation of the Company’s natural gas distribution system. 12

Service technicians and construction employees in Montana, North 13

Dakota and South Dakota support operations in Wyoming communities as 14

needed. A map of the gas distribution system in Wyoming is included as 15

Exhibit No. ___(NAK-1). 16

Montana-Dakota’s customers have toll-free access to the Customer 17

Service Center located in Meridian, Idaho and Bismarck, North Dakota as 18

well as the Credit Center in Bismarck, North Dakota, to place routine utility 19

service requests and inquiries from 7:00 am to 7:00 pm local time, 20

Monday through Friday and emergency calls on a 24-hour basis. A 21

scheduling center, located in Meridian, Idaho transmits electronic service 22

orders to the mobile terminals placed in our fleet of service and 23

4

construction vehicles. This network allows the Company to respond 1

quickly to customer requests and emergency situations. 2

Q. Would you please provide more information regarding the customers 3

the Company serves? 4

A. Yes. The residential, firm general service and small interruptible 5

customers use natural gas primarily for space and water heating. As 6

such, Montana-Dakota’s system has a low load factor with peak gas 7

requirements occurring during the winter. Summer loads are small by 8

comparison. The total annual natural gas used by our Wyoming 9

customers is 5,252,781 Dk as identified for the test period in this 10

proceeding. 11

The Company is proposing to discontinue the non-core revenue 12

credit wherein interruptible volumes and revenues have previously been 13

eliminated for purposes of establishing the firm core rates and the revenue 14

associated with the non-core customers is tracked and has been 15

subsequently credited to the core firm residential and general service 16

customer classes. 17

Montana-Dakota has included interruptible customers’ volumes and 18

revenues in the development of the revenue requirement in this filing. The 19

Company has experienced reasonably stable volume usage for these 20

customers in recent years and expects the current price environment 21

surrounding natural gas to continue to make natural gas an economic and 22

environmental choice for its customers well into the future. Discontinuing 23

5

the non-core credit will increase price transparency for customers and will 1

better match the recovery of costs from customers with the costs incurred 2

by the Company to serve the same customers. 3

Q. Would you please describe the basic elements that make up the total 4

costs of providing natural gas service? 5

A. For a natural gas distribution utility, the basic elements which make 6

up the cost of providing natural gas service are the cost of gas delivered at 7

the town border stations in its service territory and the cost of distributing 8

the gas from the town border station to the end use customer. It is the 9

second of these two elements, the distribution costs, which are the subject 10

of this application for a general rate increase. 11

The natural gas the Company purchases from suppliers is a 12

commodity like wheat or corn, the price of which is not regulated. The 13

cost of delivering the gas to the Company’s distribution system at the town 14

border station is regulated by the FERC or other regulatory agencies. 15

These gas costs are passed on to customers on a dollar-for-dollar basis 16

as specified in the Commission approved Purchased Gas Cost Adjustment 17

tariff. The gas portion of the cost of providing natural gas service 18

comprises about 58 percent of a typical residential bill for gas service. 19

The distribution cost portion of the Company’s cost of service is the 20

subject of this proceeding. This element includes the costs of new 21

distribution investments, replacement of aging infrastructure, operation 22

and maintenance expenses, depreciation, taxes, and the opportunity to 23

6

earn a return on the Company’s investments in facilities that provide 1

natural gas service. Distribution costs are currently about 42 percent of a 2

typical residential bill. 3

Q. Ms. Kivisto, did you authorize the filing of the rate application in this 4

proceeding? 5

A. Yes, I did. 6

Q. What is the amount of the increase requested? 7

A. As will be fully explained by other Company witnesses, the 8

Company is requesting a natural gas rate increase of $1,052,167 9

representing a 6.96 percent increase in revenues based on a 2018 test 10

year adjusted for known and measurable changes through year end 2019. 11

Q. Why has Montana-Dakota filed this application for a natural gas rate 12

increase? 13

A. Montana-Dakota is requesting an increase in its general gas rates 14

at this time because the current rates do not reflect the cost of providing 15

natural gas service to the Company’s Wyoming customers. 16

Q. When was the Company’s last general rate case? 17

A. The Company’s last rate case was Docket No. 30013-297-GR-14. 18

The resulting rate increase was $501,000, or a 2.62 percent overall 19

increase. Final rates in that case became effective on June 1, 2015. 20

Q. What are the primary reasons that Montana-Dakota needs an 21

increase at this time? 22

7

A. As noted earlier, the last rate increase was implemented June 1, 1

2015 and was based on a pro forma 2014 revenue requirement. The 2

primary reason for the need for an increase in rates is increased operating 3

expenses and Montana-Dakota's continued investment in distribution 4

facilities to improve system safety and reliability. The additional 5

investment has generally increased the associated depreciation, taxes 6

and operation and maintenance expenses. 7

Without an increase in distribution rates, the Company projects its 8

2019 rate of return will be 2.399 percent, well below its cost of capital. 9

Q. Would you please describe the investment in distribution facilities to 10

improve system safety and integrity in greater detail? 11

A. The investment in system safety and integrity is a focused effort 12

based on the Company's Distribution Integrity Management Program 13

(DIMP). The objective of the DIMP is to develop a model to assist in 14

determining which areas of the gas distribution system to focus 15

replacement, maintenance, and repair efforts and resources due to known 16

or predicted threats to the distribution system. 17

The model assesses nine different threat categories: Corrosion, 18

Natural Forces, Equipment Failure, Material Failure, Excavation Damage, 19

Incorrect Operation, Weld/Joint Failure, Outside Force, and Other all 20

equally weighted. 21

The DIMP model data was updated in 2019, as it will be each year, 22

by an internal Integrity Department group comprised of Subject Matter 23

8

Experts where updates will be made each year to 1) document progress 1

from the prior year and 2) reassess the risk attributed to each community 2

to determine if the course of replacement should be modified for the 3

upcoming construction year. 4

Q. How much has the gross investment increased since the last rate 5

case? 6

The pro forma 2019 investment is $37.6 million representing an 7

increase of $6.3 million or approximately 20 percent greater than the 8

investment as of 2013. 9

Q. What other adjustments are contributing to the need for an increase 10

in distribution rates? 11

A. In addition to the operating expenses, the Company is requesting 12

the inclusion of the provision for pension and post-retirement benefits, net 13

of the associated deferred taxes, to be added to rate base. 14

Q. Why has the Company proposed to include these assets and 15

liabilities in rate base at this time? 16

A. Recent contributions to the Company’s pension trust fund have 17

resulted in a significant prepaid asset related to the Company’s pension 18

plan as shown in Table 1 below: 19

9

Table 1

Total Company Pension Contributions

Cash Pension Balance

Contributions Pension Expense Debit (Credit) Beginning Balance - 12/31/2009 ($2,294,232 )

Activity - 2010 $3,871,657 ($5,328 ) 1,582,753 Activity - 2011 13,757,133 1,610,332 13,729,554 Activity - 2012 12,038,687 (740,118) 26,508,359 Activity - 2013 10,014,592 1,830,351 34,692,600 Activity - 2014 12,202,457 594,340 46,300,717 Activity - 2015 2,182,143 1,398,780 47,084,080 Activity - 2016 - 1,746,833 45,337,247 Activity - 2017 422,015 1,422,159 44,337,103 Activity - 2018 7,200,692 720,403 50,817,392 Total Funding $61,689,376 $8,577,752 Ending Balance - 12/31/2018 $50,817,392

1

As shown in Table 1, the cash contributions made by the Company 2

have significantly exceeded the pension expense, which is the amount 3

included in the Company’s revenue requirement and recovered through 4

rates charged to customers. Similar to other investments, Montana-5

Dakota has a significant outlay in cash and its only opportunity to earn a 6

return on the outlay of cash is by inclusion in the Company’s rate base. 7

Montana-Dakota has taken a number of steps to minimize pension 8

costs. They include closing the pension plan to new participants as well 9

as freezing the level of benefits accrued. In addition, the Company’s 10

contributions generally result in lower pension expense recovered through 11

the revenue requirement. 12

10

The post retirement prepaid asset, while much smaller in size, has 1

similar characteristics as the prepaid pension asset and was included in 2

the pro forma rate base as well. 3

Q. Have the benefits of the Tax Cuts and Jobs Act of 2017 (TCJA) been 4

reflected in this request for increased revenues? 5

A. Yes. 2018 was the first year of the TCJA and is the test year in this 6

general rate case. As such, the provisions of the TCJA were incorporated 7

in the test year and have been included as pro forma adjustments as 8

explained in detail by Mr. Jacobson. 9

Q. Have you included any provisions related to the TCJA for calendar 10

year 2018? 11

A. Montana-Dakota has accrued a reserve of $80,000 for calendar 12

year 2018. However, the Company's position remains the same as 13

presented in Docket No. 30013-344-GR-18. The rates set in this 14

proceeding will properly reflect the benefits of the TCJA and a separate 15

adjustment is not appropriate for calendar year 2018 as demonstrated by 16

the rate of return of 5.052 percent earned in 2018. As also noted in 17

Docket No. 30013-344-GR-18, Montana-Dakota supports the combination 18

of that docket into this rate case docket to allow both customers and the 19

Commission an opportunity to properly analyze the impact of the TCJA 20

and to provide a reasonable and fair outcome. 21

11

Q. Ms. Kivisto, would you explain how Montana-Dakota strives to 1

efficiently provide safe and reliable service to its Wyoming 2

customers? 3

A. Montana-Dakota works hard to control its costs by continually 4

looking for opportunities that create efficiencies and control costs. In spite 5

of Montana-Dakota’s efforts to control costs, the Company is seeing a 6

need for increased revenue as the need to replace existing infrastructure 7

and add new infrastructure continues. 8

The MDU Utilities Group, which encompasses the four brands I 9

discussed previously, has recently moved forward from a regional 10

operations structure by brand to a functional approach across all brands 11

covering an eight-state service area, striving for operational consistency. 12

The goal is to develop an operations organizational structure to 13

operate as one utility with one vision. 14

• Create efficiencies in operations, technology and support services 15

through common approaches and standards 16

• Gain economics of scale by using resources more effectively 17

• Streamline decision making 18

• Reduce duplication of effort 19

• Better manage the need for additional resources 20

• Implementation of a Pipeline Safety Management System 21

• Ensure the organization is better prepared for growth 22

• Evolution of continuous improvement 23

12

• Build specialized groups with a high level of expertise in their field 1

The functions are organized as follows, each reporting to a Vice 2

President who will oversee the function across all brands and eight states: 3

• Field Operations (Eric Martuscelli - Vice President) 4

Directs and coordinates activities for the entire gas and electric 5

distribution field operations across the eight-state service territory. 6

Oversee the delivery of regulated products and services to our 7

customers. 8

• Operations and Engineering Services (Pat Darras - Vice 9

President) 10

Oversee the development, design and execution of critical and 11

transformative operational strategic initiatives including but not 12

limited to asset management, infrastructure upgrades, and 13

compliance while maintaining engineering and operational 14

excellence across the MDU Utilities Group. 15

• Safety, Process Improvement, and Operations Technology 16

(Hart Gilchrest - Vice President) 17

Oversee the development, design and execution of critical and 18

transformative operational excellence strategic initiatives including 19

but not limited to safety, technical training, safety management 20

systems, process improvement and operations technology. 21

Q. What return is Montana-Dakota requesting in this case? 22

13

A. Montana-Dakota is requesting an overall return of 7.754 percent, 1

inclusive of a return on equity (ROE) of 10.3 percent. Ms. Bulkley’s 2

analysis indicates that a 10.3 percent ROE is fully justified and supported 3

based on the results of her studies. 4

Q. How will the requested increase affect the various classes of 5

customers? 6

A. The proposed percentage change in rates by customer class is as 7

follows: 8

Customer Class Percent

Increase Residential 8.41

Firm General 5.36

Small Interruptible (1.03 ) Large Interruptible (3.06 ) Overall 6.96

Q. Would you please identify the witnesses who will testify on behalf of 9

Montana-Dakota in this proceeding? 10

A. Yes. Following is a list of witnesses that will provide testimony 11

and/or exhibits in support of the Company’s application: 12

• Ms. Tammy J. Nygard, Controller for Montana-Dakota, will testify 13

regarding the overall cost of capital, capital structure and overall 14

debt costs. 15

• Ms. Ann Bulkley, Senior Vice President of Concentric Energy 16

Advisors, Inc. will testify regarding the appropriate cost of common 17

equity for Montana-Dakota’s Wyoming gas operations. 18

14

• Mr. Travis R. Jacobson, Regulatory Analysis Manager for Montana-1

Dakota, will testify regarding the total revenue requirement 2

necessary for Wyoming gas operations. 3

• Mr. Jordan R. Hatzenbuhler, Senior Regulatory Analyst for 4

Montana-Dakota will testify regarding the Company’s embedded 5

class cost of service study and proposed rate design. 6

• Ms. Stephanie Bosch, Regulatory Affairs Manager for Montana-7

Dakota will testify regarding proposed tariff changes as well as 8

volume and revenue analysis. 9

Q. Ms. Kivisto, are the rates requested in this proceeding just and 10

reasonable? 11

A. Yes. In my opinion, the proposed rates are just and reasonable as 12

they are reflective of the total costs being incurred by Montana-Dakota to 13

provide safe and reliable natural gas service to its customers. The 14

proposed rates will provide Montana-Dakota the opportunity to earn a fair 15

and reasonable return on its Wyoming natural gas operations. 16

Q. Does this complete your direct testimony? 17

A. Yes, it does. 18

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Docket N

o. 30013-351-GR

-19 Exhibit N

o. ____ (NAK-1)

Page 1 of 1

1

MONTANA-DAKOTA UTILITIES CO.

Before the Public Service Commission of Wyoming

Docket No. 30013-351-GR-19

Direct Testimony of

Tammy J. Nygard

Q. Please state your name and business address. 1

A. My name is Tammy J. Nygard, and my business address is 400 2

North Fourth Street, Bismarck, North Dakota 58501. 3

Q. By whom are you employed and in what capacity? 4

A. I am the Controller for Montana-Dakota Utilities Co. (Montana-5

Dakota), Cascade Natural Gas Corporation and Intermountain Gas 6

Company, subsidiaries of MDU Resources Group, Inc. as well as Great 7

Plains Natural Gas Co., a division of Montana-Dakota, collectively the 8

MDU Utilities Group. 9

Q. Please describe your duties and responsibilities with Montana-10

Dakota. 11

A. I am responsible for providing leadership and management of the 12

accounting and the financial forecasting/planning functions, including the 13

analysis and reporting of all financial transactions for the MDU Utilities 14

Group. 15

Q. Would you please outline your educational and professional 16

background? 17

2

A. I graduated from the University of Mary with a Bachelor of Science 1

degree in Accounting and Computer Information Systems. I have over 17 2

years of experience in the utility industry. During my tenure with the MDU 3

Utilities Group, I have held positions of increasing responsibility, including 4

Financial Analyst for Montana-Dakota, Director of Accounting and Finance 5

for Cascade, and now as MDU Utilities Group Controller. 6

Q. What is the purpose of your testimony in this proceeding? 7

A. I am responsible for presenting Statement E. 8

Q. Was this statement and the data contained therein prepared by you 9

or under your supervision? 10

A. Yes, it was. 11

Q. Is it true to the best of your knowledge and belief? 12

A. Yes, it is. 13

Q. Would you please explain Statement E? 14

A. Statement E shows the utility capital structure of Montana-Dakota 15

for the twelve months ended December 31, 2018 and the projected capital 16

structure for 2019. Statement E includes the associated costs of debt and 17

common equity. This capital structure and the associated costs serve as 18

the basis for the overall rate of return requested by Montana-Dakota in this 19

rate filing of 7.754 percent. The basis for the requested 10.30 percent 20

return on common equity contained within the overall requested rate of 21

return is supported by the testimony of Ms. Ann Bulkley. 22

3

The components of the 2019 projected overall annual rate of return, 1

which are used by Mr. Jacobson to calculate the revenue requirement, 2

are: 3

Weighted Cost of Capital

Long Term Debt 2.294%

Short Term Debt 0.096% Common Equity 5.364% Required Rate of Return 7.754%

Q. How does the Company finance its natural gas utility operations and 4

determine the amount of common equity and debt to be included in 5

its capital structure? 6

A. As a regulated public utility, the Company has a duty and obligation 7

to provide safe and reliable service to its customers across its service 8

territory while prudently balancing cost and risk. In order to fulfill its 9

service obligations, the Company has made significant capital 10

expenditures for new plant investment throughout its service territory, 11

especially in mains and services. These new investments also have 12

associated operating and maintenance costs. Through its financial 13

planning process, the Company determines the amounts of necessary 14

financing required to support these activities. Montana-Dakota finances its 15

operations with a year-end target of 50 percent common equity. Capital 16

expenditure investments are financed through a mix of internally 17

generated funds, the utilization of the Company’s short-term credit line 18

4

and the issuance of additional debt and common equity financing as 1

required to maintain targeted capital ratios and finance the combined utility 2

operations. 3

The Company obtained $30.0 million of additional common equity 4

in 2018 in order to achieve and maintain the targeted capital structure. 5

The Company redeemed $100.0 million of senior notes upon 6

maturity in September 2018 and issued a thirteen month $100 million 7

London Interbank Offered Rate (LIBOR) floating rate note in September 8

2018 and another in October 2018, for a total of $200 million. This 9

temporary bridge financing was put in place to delay issuance of 10

permanent private placement debt in order to aggregate debt issuances 11

and achieve more attractive long-term pricing and avoid duplication of 12

issuance costs. The Company anticipates a $175 million debt issuance in 13

August 2019. 14

Q. What does Statement E, Schedule E-1 show? 15

A. The debt costs reflected on Statement E, Schedule E-1, page 1 16

represent the actual weighted embedded costs of the long-term debt at 17

December 31, 2018 and those projected to be outstanding at December 18

31, 2019. In calculating the debt costs, the “Yield-to-Maturity” method 19

(also referred to as the Internal Rate of Return (IRR) method) is used to 20

determine the total cost for each respective debt issue, shown on pages 2 21

through 3. The yield-to-maturity calculation of each debt issue outstanding 22

gives consideration to the stated rates of interest being paid on such debt, 23

5

the timing of the interest payments, related issuance expenses, 1

underwriters' commissions, the discount or premium realized upon 2

issuance and the amortization of losses on bond redemption transactions. 3

Q. Would you please describe Statement E, Schedule E-2? 4

A. Schedule E-2 presents the twelve-month average short-term debt 5

balance for 2018 and projected 2019 as well as the average cost of short-6

term debt. A twelve-month average of short-term debt is used in the cost 7

of capital calculation to reflect the seasonality in the short-term debt 8

balance. Short-term debt is historically at or near its peak in December 9

and the twelve-month average calculation is more reflective of the 10

borrowing level than a year-end balance. 11

Q. What does Statement E, Schedule E-3 show? 12

A. The schedule presents the common equity balance at December 13

31, 2018 and the projected balance for December 31, 2019 reflecting the 14

projected activity in the balance. 15

Q. Montana-Dakota's previous capital structure included preferred 16

stock. Has the preferred stock been redeemed? 17

A. Yes, all preferred stock issued and outstanding was redeemed on 18

April 1, 2017. Preferred stock comprised about 0.6 percent of the 2017 19

average capital structure and was replaced with lower cost long-term debt. 20

The redemption reduces the administrative burden associated with the 21

preferred stock and, at the same time, reduces the overall cost of capital. 22

The Company did incur a redemption premium to redeem the preferred 23

6

stock and has deferred the costs of the redemption. As further discussed 1

in the testimony of Mr. Jacobson, Montana-Dakota has included those 2

costs in the rate base similar to debt redemption costs. The inclusion of 3

deferred preferred stock redemption charges in rate base continues to 4

show a net present value benefit to customers. 5

Q. Was it prudent to redeem the preferred stock? 6

A. Yes. By redeeming preferred stock, Montana-Dakota reduced its 7

financing costs. The preferred stock had dividend rates of 4.5% and 4.7%. 8

This was replaced with the fifteen year long-term debt issuance issued in 9

March 2017 at an interest rate of 3.36%. The result of the redemption is a 10

lower overall cost of capital. An analysis has been prepared which 11

demonstrates the overall net benefit of the redemption, inclusive of the 12

rate base impact, is beneficial to customers. 13

Q. Does this conclude your direct testimony? 14

A. Yes, it does. 15

Exhibit No.___(AEB-1)

1

MONTANA-DAKOTA UTILITIES CO. A Subsidiary of MDU Resources Group, Inc.

BEFORE THE WYOMING PUBLIC SERVICE COMMISSION

Docket No. 30013-351-GR-19

PREPARED DIRECT TESTIMONY OF

ANN E. BULKLEY

Q1. Please state your name and business address. 1

A1. My name is Ann E. Bulkley. My business address is 293 Boston Post Road West, 2

Suite 500, Marlborough, Massachusetts 01752. 3

Q2. What is your position with Concentric Energy Advisors, Inc. (“Concentric”)? 4

A2. I am employed by Concentric as a Senior Vice President. 5

Q3. On whose behalf are you submitting this Direct Testimony? 6

A3. I am submitting this Direct Testimony before the Wyoming Public Service 7

Commission (“Commission”) on behalf of Montana-Dakota Utilities Co. 8

(“Montana-Dakota” or the “Company”), which is a wholly-owned subsidiary of 9

MDU Resources Group, Inc. (“MDU Resources”). 10

Q4. Please describe your education and experience. 11

A4. I hold a Bachelor’s degree in Economics and Finance from Simmons College and 12

a Master’s degree in Economics from Boston University, with more than 20 years 13

of experience consulting to the energy industry. I have advised numerous energy 14

and utility clients on a wide range of financial and economic issues with primary 15

concentrations in valuation and utility rate matters. Many of these assignments 16

2

have included the determination of the cost of capital for valuation and ratemaking 1

purposes. I have included my resume and a summary of testimony that I have filed 2

in other proceedings as Exhibit No.___(AEB-2), Schedule 1 to this testimony. 3

Q5. Please describe Concentric’s activities in energy and utility engagements. 4

A5. Concentric provides financial and economic advisory services to many and various 5

energy and utility clients across North America. Our regulatory, economic, and 6

market analysis services include utility ratemaking and regulatory advisory 7

services; energy market assessments; market entry and exit analysis; corporate and 8

business unit strategy development; demand forecasting; resource planning; and 9

energy contract negotiations. Our financial advisory activities include buy and sell-10

side merger, acquisition and divestiture assignments; due diligence and valuation 11

assignments; project and corporate finance services; and transaction support 12

services. In addition, we provide litigation support services on a wide range of 13

financial and economic issues on behalf of clients throughout North America. 14

Q6. Have you testified before any regulatory authorities? 15

A6. Yes. A list of proceedings in which I have provided testimony is provided in 16

Exhibit No.___(AEB-2), Schedule 1 to this testimony. 17

PURPOSE AND OVERVIEW OF DIRECT TESTIMONY 18

Q7. What is the purpose of your Direct Testimony? 19

A7. The purpose of my Direct Testimony is to present evidence and provide a 20

recommendation regarding the appropriate Return on Equity (“ROE”) 1 for the 21

1 Throughout my Direct Testimony, I interchangeably use the terms “ROE” and “cost of equity”.

3

Company’s natural gas utility operations in Wyoming and to provide an assessment 1

of its proposed capital structure to be used for ratemaking purposes. My analyses 2

and recommendations are supported by the data presented in Exhibit No.___(AEB-3

2), Schedules 2 through 14, which were prepared by me or under my direction. 4

Q8. Please provide a brief overview of the analyses that led to your ROE 5

recommendation. 6

A8. As discussed in more detail in Section VI, I applied the Constant Growth form of 7

the Discounted Cash Flow (“DCF”) model, the Capital Asset Pricing Model 8

(“CAPM”), the Risk Premium Approach and the Expected Earnings Analysis. My 9

recommendation also takes into consideration: (1) the Company’s small size; (2) 10

Flotation Cost; (3) the Company’s capital expenditure requirements; (4) the 11

regulatory environment in which the Company operates; and (5) the Company’s 12

adjustment mechanisms. Finally, I considered the Company’s proposed capital 13

structure as compared to the capital structures of the proxy companies.2 While I 14

did not make any specific adjustments to my ROE estimates for any of these factors, 15

I did take them into consideration in aggregate when determining where the 16

Company’s ROE falls within the range of analytical results. 17

Q9. How is the remainder of your Direct Testimony organized? 18

A9. Section II provides a summary of my analyses and conclusions. Section III reviews 19

the regulatory guidelines pertinent to the development of the cost of capital. 20

Section IV discusses current and projected capital market conditions and the effect 21

2 The selection and purpose of developing a group of comparable companies will be discussed in

detail in Section VI of my Direct Testimony.

4

of those conditions on Montana-Dakota’s cost of equity in Wyoming. Section V 1

explains my selection of a proxy group of natural gas utilities. Section VI describes 2

my analyses and the analytical basis for the recommendation of the appropriate 3

ROE for Montana-Dakota. Section VII provides a discussion of specific regulatory, 4

business, and financial risks that have a direct bearing on the ROE to be authorized 5

for Montana-Dakota in this case. Section VIII assesses the proposed capital 6

structure of Montana-Dakota as compared with the capital structures of the utility 7

operating subsidiaries of the proxy group companies. Section IX presents my 8

conclusions and recommendations for the market cost of equity. 9

SUMMARY OF ANALYSIS AND CONCLUSIONS 10

Q10. Please summarize the key factors considered in your analyses and upon which 11

you base your recommended ROE. 12

A10. My analyses and recommendations considered the following: 13

• The Hope and Bluefield decisions 3 that established the standards for 14

determining a fair and reasonable allowed ROE, including consistency of 15

the allowed return with other businesses having similar risk, adequacy of 16

the return to provide access to capital and support credit quality, and that 17

result must lead to just and reasonable rates. 18

• The effect of current and projected capital market conditions on investors’ 19

return requirements. 20

3 Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591 (1944); Bluefield Waterworks

& Improvement Co., v. Public Service Commission of West Virginia, 262 U.S. 679 (1923).

5

• The Company’s regulatory, business, and financial risks relative to the 1

proxy group of comparable companies and the implications of those risks 2

in arriving at the appropriate ROE for Montana-Dakota. 3

Q11. Please explain how you considered those factors. 4

A11. I have relied on several analytical approaches to estimate the Company’s cost of 5

equity based on a proxy group of publicly traded companies. As shown in Figure 6

1, those ROE estimation models produce a wide range of results. My conclusion 7

as to where within that range of results Montana-Dakota’s ROE falls is based on 8

the Company’s business and financial risk relative to the proxy group. Although 9

the companies in my proxy group are generally comparable to Montana-Dakota, 10

each company is unique, and no two companies have the exact business and 11

financial risk profiles. Accordingly, we settle on a proxy group with similar, but 12

not the same risk profiles; and adjust the results of our analysis either upwards or 13

downwards within the reasonable range of results to account for any residual 14

differences in risk. 15

Q12. Please summarize the ROE estimation models that you considered to establish 16

the range of ROEs for Montana-Dakota. 17

A12. I considered the results of the Constant Growth DCF model using current dividends, 18

earnings growth rates and stock prices. In addition, I considered two risk premium 19

approaches, the CAPM and a Bond Yield Plus Risk Premium methodology, as well 20

as an Expected Earnings analysis. Figure 1 summarizes the range of results 21

established using each of these estimation methodologies. 22

6

Figure 1: Summary of Cost of Equity Analytical results4 1

2 As shown on Figure 1 (and in Exhibit No.___(AEB-2), Schedule 2), the range of 3

the DCF model results is wide, particularly in relation to the results of the other 4

methodologies. While it is common to consider multiple models to estimate the 5

cost of equity, it is particularly important when the range of results is wide. 6

The requested ROE is for the future rate period; therefore, the analyses supporting 7

my recommendation rely on forward-looking inputs and assumptions (e.g., 8

projected growth rates in the DCF model, forecasted risk-free rate and Market Risk 9

Premium in the CAPM analysis, etc.) and takes into consideration the current high 10

valuations of utility stocks and the market’s expectation for higher interest rates. 11

The use of historical inputs and assumptions would tend to understate the required 12

4 The analytical results reflect the results of the Constant Growth DCF analysis excluding the results

for individual companies that did not meet the minimum threshold of 7.00 percent.

7

ROE for Montana-Dakota, when considering current and projected conditions in 1

capital markets. 2

As discussed in more detail in Sections IV and VI, the DCF models are influenced 3

by current market conditions that are not projected to be sustained in the long-term. 4

Those conditions result in lower estimates of the ROE using the DCF model. For 5

example, the median low Constant Growth DCF results (prior to exclusions for 6

outliers) for the proxy group, ranging from 7.34 to 7.51 percent for the 30-, 90-, 7

and 180-day assumption, are below an acceptable range of returns for a natural gas 8

utility and are below any authorized ROE for an electric utility or natural gas utility 9

in the U.S. since at least 1980. 5,6 Based on prospective capital market conditions, 10

and the inverse relationship between the market risk premium and interest rates, I 11

conclude that the median low DCF results do not provide a sufficient risk premium 12

to compensate equity investors for the residual risks of ownership, including the 13

risk that they have the lowest claim on the assets and income of Montana-Dakota. 14

Due to these concerns about the results produced by the DCF model, my ROE 15

recommendation considers the median and median-high results of the DCF model, 16

a forward-looking CAPM analysis, a Bond Yield plus Risk Premium analysis, and 17

an Expected Earnings analysis. I also consider company-specific risk factors and 18

current and prospective capital market conditions. 19

5 My DCF models generated a median low, median, and median high result. The median low result

is the median of the proxy group DCF results calculated using the lowest earnings growth rate for each company from Value Line, Yahoo! Finance or Zacks.

6 Source: Regulatory Research Associates, Rate Case History, January 1, 1980 – January 31, 2019.

8

Q13. What is your recommended ROE for Montana-Dakota? 1

A13. In addition to the analytical results presented in Figure 1, I also considered the level 2

of regulatory, business, and financial risk faced by Montana-Dakota’s natural gas 3

operations in Wyoming relative to the proxy group to establish the range of 4

reasonable returns. Considering these factors, I believe a range from 10.00 to 10.75 5

percent is reasonable. This recommendation reflects the range of results for the 6

proxy group companies, the relative risk of Montana-Dakota’s natural gas 7

operations in Wyoming as compared to the proxy group, and current capital market 8

conditions. Within that range, a return of 10.30 percent is reasonable. 9

Q14. Please summarize the analysis you conducted in determining that Montana-10

Dakota’s requested capital structure is reasonable and appropriate. 11

A14. Based on the analysis presented in Section VII of my testimony, I conclude that 12

Montana-Dakota’s proposed 52.076 percent common equity is reasonable. To 13

determine if Montana-Dakota’s requested capital structure was reasonable, I 14

reviewed the capital structures of the utility subsidiaries of the proxy companies. 15

As shown in Exhibit No.___(AEB-2), Schedule 13, the results of that analysis 16

demonstrate that the average equity ratios for the utility operating companies of the 17

proxy group range from 47.00 percent to 63.18 percent with an average of 52.94 18

percent. Montana-Dakota’s proposed equity ratio of 52.076 percent is slightly 19

below the average equity ratio for the utility operating subsidiaries of the proxy 20

group companies and is therefore reasonable, especially considering that Federal 21

tax reform legislation has had a negative effect on the cash flows and credit metrics 22

of regulated utilities. 23

9

REGULATORY GUIDELINES 1

Q15. Please describe the guiding principles to be used in establishing the cost of 2

capital for a regulated utility. 3

A15. The United States Supreme Court’s precedent-setting Hope and Bluefield cases 4

established the standards for determining the fairness or reasonableness of a 5

utility’s allowed ROE. Among the standards established by the Court in those cases 6

are: (1) consistency with other businesses having similar or comparable risks; (2) 7

adequacy of the return to support credit quality and access to capital; and (3) that 8

the result, as opposed to the methodology employed, is the controlling factor in 9

arriving at just and reasonable rates.7 10

Q16. Has the Commission provided similar guidance in establishing the appropriate 11

return on common equity? 12

A16. Yes, it has. In Docket No. 20000-ER-03-198, PacifiCorp’s 2003 rate case, the 13

Commission stated that: 14

Consistent with the discretion given to the Commission in 15 examining cases and reaching a just result (discussed 16 generally, infra), there are no precise bases in Wyoming law 17 to guide the Commission in determining a utility’s rate of 18 return on equity. Therefore, the Commission must apply its 19 informed judgment to all of the evidence in the case. In this 20 traditional rate-base rate-of-return case, the Commission must 21 determine the cost of capital, and we are guided by the 22 earnings and capital attraction standards of Bluefield Water 23 Works & Improvement Co. v. Public Service Commission of 24 West Virginia, 262 U. S. 679 (1923); and Federal Power 25 Comm’n v. Hope Natural Gas Co., 320 U. S. 391 (1944); 26 accepted in Wyoming in In re Northern Utilities, 70 Wyo. 275, 27 249 P.2d 769 (Wyo. 1952). A public utility remains entitled to 28

7 Hope, 320 U.S. 591 (1944); Bluefield, 262 U.S. 679 (1923).

10

rates which will permit it a reasonable opportunity to earn a 1 return on its investment properly reflecting the risk of the 2 business and which will reasonably preserve the financial 3 soundness of the company and allow it to raise the capital 4 needed to provide service in the public interest. Having said 5 that, we also acknowledge that the measurement of the 6 required level of return is not a matter of simple mathematics 7 but is a matter requiring judgment and the employment of 8 discretion. The United States Supreme Court, in Hope, supra, 9 noted that a “just and reasonable end result” is the desired 10 outcome and that it is the end reached, rather than the method 11 employed in achieving it, that should control.8 12

My view accords with this guidance that an allowed ROR must be sufficient to 13

enable regulated companies, like Montana-Dakota, the ability to attract capital on 14

reasonable terms. 15

Q17. Why is it important for a utility to be allowed the opportunity to earn an ROE 16

that is adequate to attract capital at reasonable terms? 17

A17. An ROE that is adequate to attract capital at reasonable terms enables the Company 18

to continue to provide safe, reliable natural gas service while maintaining its 19

financial integrity. To the extent the Company is provided the opportunity to earn 20

its market-based cost of capital, neither customers nor shareholders are 21

disadvantaged. 22

Q18. Is a utility’s ability to attract capital also affected by the ROEs that are 23

authorized for other utilities? 24

A18. Yes. Utilities compete directly for capital with other investments of similar risk, 25

which include other natural gas and electric utilities. Therefore, the ROE awarded 26

to a utility sends an important signal to investors regarding whether there is 27

8 PacifiCorp, Docket No. 20000-ER-03-198, Order, February 28, 2004, at ¶ 34 a13.

11

regulatory support for financial integrity, dividends, growth, and fair compensation 1

for business and financial risk. The cost of capital represents an opportunity cost 2

to investors. If higher returns are available for other investments of comparable 3

risk, investors have an incentive to direct their capital to those investments. Thus, 4

an authorized ROE significantly below authorized ROEs for other natural gas and 5

electric utilities can inhibit the utility’s ability to attract capital for investment in 6

Wyoming. 7

While Montana-Dakota is committed to investing the required capital to provide 8

safe and reliable service, because Montana-Dakota is a subsidiary of MDU 9

Resources, Montana-Dakota competes with the other MDU Resources subsidiaries 10

for discretionary investment capital. In determining how to allocate its finite 11

discretionary capital resources, it would be reasonable for MDU Resources to 12

consider the authorized ROE of each of its subsidiaries. 13

Q19. What are your conclusions regarding regulatory guidelines? 14

A19. The ratemaking process is premised on the principle that, for investors and 15

companies to commit the capital needed to provide safe and reliable utility services, 16

a utility must have the opportunity to recover the return of, and the market-required 17

return on, its invested capital. Because utility operations are capital-intensive, 18

regulatory decisions should enable the utility to attract capital at reasonable terms 19

under a variety of economic and financial market conditions; doing so balances the 20

long-term interests of the utility and its ratepayers. 21

12

The financial community carefully monitors the current and expected financial 1

condition of utility companies, and the regulatory framework in which they operate. 2

In that respect, the regulatory framework is one of the most important factors in 3

both debt and equity investors’ assessments of risk. The Commission’s order in 4

this proceeding, therefore, should establish rates that provide the Company with the 5

opportunity to earn an ROE that is: (1) adequate to attract capital at reasonable 6

terms under a variety of economic and financial market conditions; (2) sufficient to 7

ensure good financial management and firm integrity; and (3) commensurate with 8

returns on investments in enterprises with similar risk. To the extent Montana-9

Dakota is authorized the opportunity to earn its market-based cost of capital, the 10

proper balance is achieved between customers’ and shareholders’ interests. 11

CAPITAL MARKET CONDITIONS 12

Q20. Why is it important to analyze capital market conditions? 13

A20. The ROE estimation models rely on market data that are either specific to the proxy 14

group, in the case of the DCF model, or to the expectations of market risk, in the 15

case of the CAPM. The results of the ROE estimation models can be affected by 16

prevailing market conditions at the time the analysis is performed. While the ROE 17

that is established in a rate proceeding is intended to be forward-looking, the analyst 18

uses current and projected market data, specifically stock prices, dividends, growth 19

rates and interest rates in the ROE estimation models to estimate the required return 20

for the subject company. 21

13

As discussed in the remainder of this section, analysts and regulatory commissions 1

have concluded that current market conditions have affected the results of the ROE 2

estimation models. As a result, it is important to consider the effect of these 3

conditions on the ROE estimation models when determining the appropriate range 4

and recommended ROE for a future period. If investors do not expect current 5

market conditions to be sustained in the future, it is possible that the ROE 6

estimation models will not provide an accurate estimate of investors’ required 7

return during that rate period. Therefore, it is very important to consider projected 8

market data to estimate the return for that forward-looking period. 9

Q21. What factors are affecting the cost of equity for regulated utilities in the 10

current and prospective capital markets? 11

A21. The cost of equity for regulated utility companies is being affected by several 12

factors in the current and prospective capital markets, including: (1) the current low 13

interest rate environment and the corresponding effect on valuations and dividend 14

yields of utility stocks relative to historical levels; (2) the market’s expectation for 15

interest rates; and (3) recent Federal tax reform. In this section, I discuss each of 16

these factors and how it affects the models used to estimate the cost of equity for 17

regulated utilities. 18

A. The Effect of Market Conditions on Valuations 19

Q22. How has the Federal Reserve’s monetary policy affected capital markets in 20

recent years? 21

A22. Extraordinary and persistent federal intervention in capital markets artificially 22

lowered government bond yields after the Great Recession of 2008-2009, as the 23

14

Federal Open Market Committee (“FOMC”) used monetary policy (both reductions 1

in short-term interest rates and purchases of Treasury bonds and mortgage-backed 2

securities) to stimulate the U.S. economy. As a result of very low or zero returns 3

on short-term government bonds, yield-seeking investors have been forced into 4

longer-term instruments, bidding up prices and reducing yields on those 5

investments. As investors have moved along the risk spectrum in search of yields 6

that meet their return requirements, there has been increased demand for dividend-7

paying equities, such as natural gas and electric utility stocks. 8

Q23. How has the period of abnormally low interest rates affected the valuations 9

and dividend yields of utility shares? 10

A23. The Federal Reserve’s accommodative monetary policy has caused investors to 11

seek alternatives to the historically low interest rates available on Treasury bonds. 12

A result of this search for higher yield is that the share prices for many common 13

stocks, especially dividend-paying stocks such as utilities, have been driven higher 14

while the dividend yields (which are computed by dividing the dividend payment 15

by the stock price) have decreased to levels well below the historical average. As 16

shown in Figure 2, over the period from 2009 through 2017, since the Federal 17

Reserve intervened to stabilize financial markets and support the economic 18

recovery after the Great Recession of 2008-09, Treasury bond yields and utility 19

dividend yields declined. Specifically, Treasury bond yields declined by 20

approximately 118 basis points, and natural gas utility dividend yields have 21

decreased by about 144 basis points over this same period. 22

15

Figure 2: Dividend Yields for Natural Gas Utility Stocks 1

2 Note: Figure includes 2019 data through March 29, 2019. 3 Source: Bloomberg Professional 4

Q24. How have higher stock valuations and lower dividend yields for utility 5

companies affected the results of the DCF model? 6

A24. During periods of general economic and capital market stability, the DCF model 7

may adequately reflect market conditions and investor expectations. However, in 8

the current market environment, the DCF model results are distorted by the 9

historically low level of interest rates and the higher valuation of utility stocks. 10

Value Line recently commented on the high valuations of electric utilities: 11

Even after a pullback in late 2018, most stocks in the Electric 12 Utility Industry are still priced expensively, in our view. Many 13 of the equities are still trading within our 2021-2023 Target 14 Price Range. The industry’s average dividend yield is 3.5%, 15 and some stocks have yields that aren’t significantly higher 16 than the median of all stocks under our coverage. For the 3- to 17

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

3.5%

4.0%

4.5%

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

Dividend Yield 30 Year Treasury Yield

16

5-year period, the group’s average total return potential is just 1 5%.9 2

This is further supported by a recent Edward Jones report on the utility sector: 3

Utility valuations have climbed back to near-record levels as 4 10-year Treasury bond rates have fallen back to around 2.5%. 5 On a price-to-earnings basis, remain significantly above their 6 historical average, and have been trading near all-time highs. 7 We have seen utility valuations moving in line with interest 8 rate movements, although there have been exceptions to this. 9 Overall, however, we believe the low-interest rate 10 environment has been the biggest factor in pushing utilities 11 higher since many investors buy them for their dividend yield. 12

Utilities recently hit new all-time highs, and are still trading 13 significantly above their average price-to-earnings ratio over 14 the past decade. The premium valuation continues to reflect 15 not only the low interest rate environment, but also the stable 16 and predominantly regulated earnings growth we foresee.10 17

As noted by Value Line and Edward Jones, over the last few years, utility stocks 18

have experienced high valuations and low dividend yields; driven by investors 19

moving into dividend paying stocks from bonds due to the low interest rates in the 20

bond market, however, those dynamics are changing. Value Line and Edward 21

Jones recognize that as interest rates increase, bonds become a substitute for utility 22

stocks. As utility stock prices decline, the dividend yields will increase. This 23

change in market conditions implies that the ROE calculated using historical market 24

data in the DCF model may understate the forward-looking cost of equity. 25

9 Value Line Investment Survey, Electric Utility (West) Industry, January 25, 2019, at 2217. 10 Andy Pusateri and Andy Smith. Edward Jones, Utilities Sector Outlook (April 10, 2019), at 2-3.

[Reference to figure omitted.]

17

Q25. How did the Standard & Poor’s (“S&P”) Utilities Index respond to the market 1

conditions that existed following the Great Recession of 2008-2009? 2

A25. Figure 3, demonstrates market conditions from 2007-2019 as measured by the S&P 3

Utilities index and the yield on 30-year Treasury bonds. As shown in Figure 3, the 4

S&P Utilities index increased steadily from the beginning of 2009 through early 5

November 2017, as yields on 30-year Treasury bonds declined in response to 6

accommodative federal monetary policy. 7

Figure 3: S&P Utilities Index and U.S. Treasury Bond Yields (2007-2019) 8

9 Source: Bloomberg Professional 10

Q26. How do the valuations of public utilities compare to the historical average? 11

A26. Figure 4 summarizes the average historical and projected P/E ratios for the proxy 12

companies calculated using data from Bloomberg Professional and Value Line.11 13

As shown in Figure 4, the average P/E ratio for the proxy companies was higher in 14

11 Selection of the Proxy Companies is discussed in detail in Section V of my Direct Testimony.

18

2017 than at any other time in the last seventeen years and is significantly higher 1

than the average projected P/E ratio for the group for the period from 2022-2024. 2

In 2018 however, the average P/E ratio for the proxy companies has decreased to 3

19.66 from the high in 2017 of 24.63. All else equal, if P/E ratios for the proxy 4

companies continue to decline, as Value Line projects, the ROE results from the 5

DCF model would be higher. Therefore, the DCF model using historical market 6

data is likely understating the forward-looking cost of equity for the proxy group 7

companies. 8

Figure 4: Average Historical Proxy Group P/E Ratios 9

10 Note: Figure includes data through March 29, 2019. 11 Source: Bloomberg Professional 12

0.0

5.0

10.0

15.0

20.0

25.0

30.0

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 -2024

P/E

Ratio

S5UTILX Index Proxy Group Average

19

Q27. Have you reviewed any other market indicators that compare the current 1

valuation of utilities to the historical average? 2

A27. Yes. To further assess how the current low interest rate environment has affected 3

the valuations of the companies in my proxy group, I reviewed the price/earnings 4

to growth (“PEG”) ratio for the S&P Utilities Index. The PEG ratio is commonly 5

used by investors to determine if a company is considered over- or under-valued. 6

The ratio compares the P/E ratio of a company to the expected growth rate of future 7

earnings. This allow investors to compare companies with similar P/E ratios but 8

different earnings growth projections. If two companies have a P/E ratio of 20, but 9

Company A is growing at a rate of 6 percent and Company B is growing at a rate 10

of 15 percent, then on a relative valuation basis Company B is the better investment. 11

As shown on page 7 of Exhibit __(AEB-2), Schedule 14, which is a report 12

published by Yardeni Research, Inc., the PEG ratio for the S&P Utilities Index has 13

been significantly higher than it has historically as a result of the accommodative 14

monetary policy pursued by the Federal Reserve following the Great Recession of 15

2008/09. 12 While the PEG ratio has declined in recent years due to the Federal’s 16

Reserve’s shift to normalize monetary policy, the PEG ratio for the S&P Utilities 17

Index is still above the historical average. In general, stocks with lower long-term 18

PEG ratios are considered better values. As the PEG ratio increases above the long-19

term historical average, as has been the case with the S&P Utilities Index, then the 20

stocks are considered relatively over-valued unless the growth rate increases to 21

12 Yardeni Research, Inc. “S&P 500 Industry Briefing: Utilities.” April 30, 2019,

https://www.yardeni.com/pub/if-sut.pdf, p. 5.

20

support the higher valuation. The PEG ratio for the S&P Utilities Index as of April 1

2019 is close to 3.5, which indicates that many of the stocks contained in the index 2

are currently trading at levels well above the historical average. Based on this 3

valuation metric, investors should expect the stock prices of utilities to decline in 4

the future. This analysis supports the P/E Ratio projections produced by Value 5

Line, which as noted above, are projecting the P/E ratios of utilities to decline over 6

the near-term. 7

Q28. How do equity investors view the utilities sector based on these recent market 8

conditions? 9

A28. Investment advisors have suggested that utility stocks may underperform as a result 10

of market conditions. Barron’s recently published the results of its survey of 148 11

profession money manager in which 64 percent of the professional money 12

managers surveyed recommended selling utility stocks.13 This position was further 13

supported in a separate article where Barron’s noted that: 14

Utilities, by contrast, have returned about 19% in the past year. 15 Investors view them as a safer bet and more-reliable dividend 16 plays. Higher share prices have pushed down their yields, 17 which have averaged about 3.8% over the past 10 years, 18 according to FactSet. 19

Nancy Tengler, chief investment strategist at Tengler Wealth 20 Management, is avoiding utility stocks, which in her view 21 offer "high multiples for no growth."14 22

13 Jasinski, Nicholas. “Stock Market Highs Are Making Even Bullish Money Managers Cautious,

Exclusive Poll Finds.” Barron's, Barron's, 26 Apr. 2019, https://www.barrons.com/articles/stock-market-big-money-poll-51556309101?mod=past_editions.

14 Strauss, Lawrence C. “Dividends Can Tell You a Lot About a Sector's Strength.” Barron's, Barron's, 5 Apr. 2019, www.barrons.com/articles/this-dividend-metric-can-help-you-understand-an-industry-51554463800.

21

Similarly, a recent report on the market outlook for 2019 from J.P. Morgan Asset 1

Management noted that due to higher volatility the Fed may pause increasing the 2

federal funds rate; however, they are not recommending rotation into the utility 3

sector: 4

As prospects for slower economic growth become clearer in 5 the middle of next year, the Fed may signal it will pause. Such 6 a signal, or a trade agreement with China, could lead multiples 7 to expand, pushing the stock market higher and potentially 8 adding years to this already old bull market. However, even if 9 the bull market does end in the next few years, it is important 10 to remember that late-cycle returns have typically been quite 11 strong. 12

This leaves investors in a tough spot – should they focus on a 13 fundamental story that is softening, or invest with an 14 expectation that multiples will expand as the bull market runs 15 its course? The best answer is probably a little bit of each. We 16 are comfortable holding stocks as long as earnings growth is 17 positive, but do not want to be over-exposed given an 18 expectation for higher volatility. As such, higher-income 19 sectors like financials and energy look more attractive than 20 technology and consumer discretionary, and we would lump 21 the new communication services sector in with the latter 22 names, rather than the former. However, given our 23 expectation of still some further interest rate increases, it does 24 not yet seem appropriate to fully rotate into defensive sectors 25 like utilities and consumer staples. Rather, a focus on cyclical 26 value should allow investors to optimize their 27 upside/downside capture as this bull market continues to 28 age.15 29

This view was further supported by UBS who underweights utilities: 30

Our underweight views on consumer staples and utilities 31 sectors reflect our preference for sectors that are more 32 leveraged to continued favorable economic growth than these 33 two defensive sectors. In addition, consumer staples are 34

15 J.P. Morgan Asset Management, “The investment outlook for 2019: Late-cycle risks and

opportunities”, November 30, 2018, at 5.

22

contending with sluggish organic growth. High dividend 1 yields for the utilities sector makes it most negatively exposed 2 to higher interest rates. Our industrials underweight is a bit of 3 a hedge against a potential increase in trade frictions.16 4

Q29. Have regulators recently responded to the historically low dividend yields for 5

utility companies and the corresponding effect on the DCF model? 6

A29. Yes. The FERC recently proposed a methodology that reflects their current view 7

that investors rely on multiple ROE estimation models. The proposed methodology 8

includes an equal weighting of the DCF, CAPM, Expected Earnings and Risk 9

Premium models to better reflect investor behavior and capital market conditions.17 10

In addition, the Illinois Commerce Commission (“ICC”), the Pennsylvania Public 11

Utility Commission (“PPUC”) and the Missouri Public Service Commission 12

(“Missouri PSC”) have all considered the effect of low dividend yields on the DCF 13

results in recent decisions. I discuss the response of these regulators to historically 14

low dividend yields and the impact on the DCF model in detail later in my 15

testimony. 16

B. The Current and Expected Interest Rate Environment 17

Q30. Please provide a brief summary of the recent monetary policy actions of the 18

Federal Reserve. 19

A30. Based on stronger conditions in employment markets, a relatively stable inflation 20

rate, steady economic growth, and increased household spending, the Federal 21

Reserve raised the short-term borrowing rate by 25 basis points on four occasions 22

16 UBS, “2019 outlook: Aging gracefully”, December 5, 2018, at 7. 17 Federal Energy Regulatory Commission, Docket No. EL 11-66-001, et al., Order Directing Briefs,

issued October 16, 2018, at para. 32.

23

in 2018. Since December 2015, the Federal Reserve has increased interest rates 1

nine times, bringing the federal funds rate to the range of 2.25 percent to 2.50 2

percent. While, the Federal Reserve recently indicated at the March 2019 meeting 3

that going forward it will be patient in determining future adjustments to the federal 4

funds rate due to recent global economic and financial developments and low 5

inflationary pressures, the FOMC has not indicated that they will not raise interest 6

rates over the coming year. In fact, Bloomberg recently noted that some officials 7

saw higher rates as appropriate later this year if economic growth continued above 8

its longer-run trend rate, according to the minutes. 18 This view was further 9

supported following the May 2019 meeting by Federal Reserve Bank of 10

Philadelphia President Patrick Harker who indicated that he still expects the Federal 11

Reserve to increase rates once in both 2019 and 2020.19 12

Additionally, in October 2017, the FOMC started reducing the size of the Federal 13

Reserve’s $4.5 trillion bond portfolio by no longer reinvesting the proceeds of the 14

bonds it holds. In response to the Great Recession, the Federal Reserve pursued a 15

policy known as “Quantitative Easing,” in which it systematically purchased 16

mortgage-backed securities and long-term Treasury bonds to provide liquidity in 17

financial markets and drive down yields on long-term government bonds. Although 18

the Federal Reserve discontinued the Quantitative Easing program in October 2014, 19

18 FOMC, Federal Reserve press release, March 20, 2019. See also, Torres, Craig. “Fed Minutes Show

Some Rate Flexibility During Year of Patience.” Bloomberg.com, Bloomberg, 10 Apr. 2019, www.bloomberg.com/news/articles/2019-04-10/fed-minutes-show-some-rate-flexibility-during-year-of-patience.

19 Derby, Michael. “Fed's Harker Expects One More Rate Hike in 2019 and Another in 2020.” The Wall Street Journal, 6 May 2019, www.wsj.com/articles/feds-harker-expects-one-more-rate-hike-in-2019-and-another-in-2020-11557151277.

24

it continued to reinvest the proceeds from the bonds it holds. Under the initial 1

balance sheet normalization policy, the FOMC gradually reduced the Federal 2

Reserve’s securities holdings by $10 billion per month initially, ramping up to $50 3

billion per month by the end of the first twelve months.20 However, at the March 4

2019 meeting, the FOMC announced that it intends to slow the reduction of its 5

holdings of Treasury Securities starting in May 2019 and ultimately conclude the 6

program in September 2019.21 7

Q31. How does the recent change in the Federal Reserve’s policy affect the yields 8

on long-term government bonds? 9

A31. While the Federal Reserve has recently indicated to that will it will be patient in 10

determining future adjustments the federal funds rate, this is not unusual as 11

monetary policy has a lagged effect on the economy. As Federal Reserve Bank of 12

San Francisco notes: 13

It can take a fairly long time for a monetary policy action to 14 affect the economy and inflation. And the lags can vary a lot, 15 too. For example, the major effects on output can take 16 anywhere from three months to two years. And the effects on 17 inflation tend to involve even longer lags, perhaps one to three 18 years, or more.22 19

Since December 2015, the Federal Reserves has increased the federal funds rate 20

nine times, four of which occurred in 2018 and three in 2017. Therefore, given 21

20 Federal Reserve press release, Addendum to the Policy Normalization Principles and Plans, June

14, 2017, implemented at FOMC meeting, September 20, 2017. 21 Federal Reserve press release, Balance Sheet Normalization Principles and Plans, March 20, 2019. 22 Federal Reserve Bank of San Francisco, "U.S. Monetary Policy: An Introduction - How does

monetary policy affect the U.S. economy?", February 6, 2004. https://www.frbsf.org/education/teacher-resources/us-monetary-policy-introduction/real-interest-rates-economy/

25

recent market volatility and lagged effect that monetary policy has on the economy, 1

it is reasonable to expect the Federal Reserve to be patient with future increases. 2

However, it is important to note, that the Federal Reserve is continuing to reduce 3

the size of its balance sheet by no longer reinvesting the proceeds of the bonds it 4

holds over the near-term. This policy in conjunction with the lagged effect of past 5

increases in the federal funds rate suggests that the yields on long-term government 6

bonds should continue to increase over the near-term which is consistent with 7

investors’ expectations. 8

Q32. Have you examined the effect of the Federal Reserve’s monetary policy on the 9

yields of long-term government bonds over the past few years? 10

A32. Yes. The increase in long-term government bond yields has not been as 11

pronounced as the rise in short-term interest rates. This is due to a shift in the supply 12

and demand of long-term government bonds that has occurred since 2009. For 13

example, since the Great Recession of 2008-2009, federal debt has increased 14

significantly which has resulted in an increase in the supply of Treasury bonds in 15

the market. In general, an increase in supply should result in a decrease in the price 16

of Treasury bonds and an increase in yield. However, long-term government bonds 17

yields have not increased as fast as expected given the increase in supply. This is 18

because the demand for Treasury bonds has also increased since 2009. As noted in 19

a recent article published by the St. Louis Federal Reserve, the demand for 20

government bonds increased for a number of reasons some of which included 21

increased holdings by foreign governments as countries in Europe and Asia faced 22

their own economic uncertainty, and increased holdings from commercial banks 23

26

due to new regulations that required banks to hold a larger portion of high-quality 1

liquid assets.23 This has resulted in a more gradual increase in the yields on long-2

term government bonds over the past few years. 3

Q33. Is the demand for long-term government bonds currently increasing? 4

A33. No, it is not. As noted in the Federal Reserve article: 5

Some evidence suggests that the growth in demand for 6 Treasuries has already begun to soften. Returning to Figures 7 1 and 2, foreign holdings have remained more or less constant 8 since 2014, largely because of declining holdings in Japan and 9 China. Likewise, regulation and policy changes such as the 10 Dodd-Frank Act and new rules for prime money market funds 11 may have only transitory effects on the demand for Treasuries. 12 For example, the pace of growth of the ratio of commercial 13 bank Treasury security holdings to private loans has slowed 14 since 2014 (see Figure 3), as has the growth of investment in 15 government money market funds since 2017 (Figure 4).24 16

Furthermore, another indicator of the demand for Treasury bonds is the bid-to-17

cover ratio, which represents the dollar amount of bids received versus the dollar 18

amount sold in a Treasury security auction. Therefore, a higher bid-to-cover ratio 19

is indicative of an increase in the demand for government bonds. As shown in 20

Figure 5, the bid-to-cover ratio for the 10-year U.S. Treasury bond is currently at 21

its lowest point since 2009, which indicates that the demand for long-term 22

government bonds has declined. The decline in demand is occurring at a time when 23

the supply of Treasury bonds is expected to increase as the Federal Reserve 24

continues its balance sheet unwind over the near-term and the federal government 25

23 David Andolfatto and Andrew Spewak, Federal Reserve Bank of St. Louis, "On the Supply of, and

Demand for, U.S. Treasury Debt," Economic Synopses, No. 5, 2018. https://doi.org/10.20955/es.2018.5.

24 Ibid.

27

issues bonds to offset the reduced tax revenue associated with the implementation 1

of the TCJA. As a result, yields on long-term government bonds are expected to 2

continue to increase over the near-term. 3

Figure 5: U.S. 10-year Treasury Bond Bid-to-Cover-Ratio 4

5 Q34. What effect do rising interest rates have on the cost of equity? 6

A34. As interest rates increase, the cost of equity for the proxy companies using the DCF 7

model is likely to be an overly conservative estimate of investors’ required returns 8

because the proxy group average dividend yield reflects the increase in stock prices 9

that resulted from substantially lower interest rates. As such, rising interest rates 10

support the selection of a return toward the upper end of a reasonable range of ROE 11

estimates resulting from the DCF analysis. Alternatively, my CAPM and Bond 12

Yield Plus Risk Premium analyses include estimated returns based on near-term 13

projected interest rates, reflecting investors’ expectations of market conditions over 14

the period that the rates that are determined in this case will be set. 15

28

C. Effect of Tax Reform on the ROE and Capital Structure 1

Q35. Are there other factors that should be considered in determining the cost of 2

equity for Montana-Dakota? 3

A35. Yes. The effect of the TCJA should also be considered in the determination of the 4

cost of equity. The credit rating agencies have commented on the effect of the 5

TCJA on regulated utilities. In summary, the TCJA is expected to reduce utility 6

revenues due to the lower federal income taxes and the requirement to return excess 7

accumulated deferred income taxes. This change in revenue is expected to reduce 8

Funds From Operations (“FFO”) metrics across the sector, and absent regulatory 9

mitigation strategies, is expected to lead to weaker credit metrics and negative 10

ratings actions for some utilities.25 11

Q36. Have credit or equity analysts commented on the effect of the TCJA on 12

utilities? 13

A36. Yes. Moody’s Investors Services (“Moody’s”) indicated that while the TCJA was 14

credit positive for many sectors, it has an overall negative credit impact on 15

regulated operating companies of utilities and their holding companies due to the 16

reduction in cash flow metrics that results from the change in the federal tax rate 17

and the loss of bonus depreciation. 18

Moody’s noted that the rates that regulators allow utilities to charge customers is 19

based on a cost-plus model, with tax expense being one of the pass-through items. 20

Utilities will collect less taxes at the lower rate, reducing revenue. While the taxes 21

25 FitchRatings, Special Report, What Investors Want to Know, “Tax Reform Impact on the U.S.

Utilities, Power & Gas Sector”, January 24, 2018.

29

are ultimately paid out as an expense, under the new law utilities lose the timing 1

benefit, reducing cash that may have been carried over a number of years. The 2

lower tax rate combined with the loss of bonus depreciation will have a negative 3

effect on utility cash flows and will ultimately negatively impact the utilities’ ability 4

to fund ongoing operations and capital improvement programs. 5

Q37. How has Moody’s responded to the increased risk for utilities resulting from 6

the TCJA? 7

A37. In January 2018, Moody’s issued a report changing the rating outlook for several 8

regulated utilities from Stable to Negative.26 At that time, Moody’s noted that the 9

rating change affected companies with limited cushion in their ratings for 10

deterioration in financial performance. In June 2018, Moody’s issued a report in 11

which the rating agency downgraded the outlook for the entire regulated utility 12

industry from Stable to Negative for the first time ever. Moody’s cites ongoing 13

concerns about the negative effect of the TCJA on cash flows of regulated utilities. 14

While noting that “[r]egulatory commissions and utility management teams are 15

taking important first steps” 27 and that “we have seen some credit positive 16

developments in some states in response to tax reform,”28 Moody’s concludes that 17

“we believe that it will take longer than 12-18 months for the majority of the sector 18

to show any material financial improvement from such efforts.”29 19

26 Moody’s Investor Service, Global Credit Research, Rating Action: Moody’s changes outlooks on

25 US regulated utilities primarily impacted by tax reform, January 19, 2018. 27 Moody’s Investors Service, “Regulated utilities – US: 2019 outlook shifts to negative due to weaker

cash flows, continued high leverage”, June 18, 2018, at 3. 28 Ibid. 29 Ibid.

30

Q38. Has Moody’s changed its outlook for utilities in 2019? 1

A38. No. Consistent with the prior reports issued by Moody’s in January and June of 2

2018, Moody’s is maintaining its negative outlook for regulated utilities in 2019 as 3

a result of continued concerns over the effect of the TCJA on cash flows as well as 4

increasing debt.30 Moody’s notes that “[t]he combination of financial pressures is 5

expected to keep the sector’s ratio of FFO to debt down around 15% in the year 6

ahead.” 31 7

Q39. What does it mean for Moody’s to downgrade a credit outlook? 8

A39. A Moody’s rating outlook is an opinion regarding the likely rating direction over 9

what it refers to as “the medium term.” A Stable outlook indicates a low likelihood 10

of a rating change in the medium term. A Negative outlook indicates a higher 11

likelihood of a rating change over the medium term. While Moody’s indicates that 12

the time period for changing a rating subsequent to a change in the outlook from 13

Stable will vary, on average Moody’s indicates that a rating change will follow 14

within a year of a change in outlook.32 15

Q40. Have any utilities experienced a downgrade related to cash flow metrics 16

resulting from the TCJA? 17

A40. Yes. Figure 6 summarizes credit rating downgrades for utilities that have resulted 18

from tax reform. 19

30 Moody’s Investors Service, Research Announcement: Moody's: US regulated utilities sector

outlook for 2019 remains negative, November 8, 2018. 31 Ibid. 32 Moody’s Investors Service, Rating Symbols and Definitions, July 2017, at 27.

31

Figure 6: Credit Rating Downgrades Resulting from TCJA 1

Utility Rating Agency

Credit Rating before TCJA

Credit Rating after

TCJA

Downgrade Date

American Water Works Moody’s A3 Baa1 4/1/2019 Niagara Mohawk Power Corporation Moody’s A2 A3 3/29/2019 KeySpan Gas East Corporation (KEDLI) Moody’s A2 A3 3/29/2019 Xcel Energy Moody’s A3 Baa1 3/28/2019 ALLETE, Inc. Moody’s A3 Baa1 3/26/2019 Brooklyn Union Gas Company (KEDNY) Moody’s A2 A3 2/22/2019 Avista Corp. Moody’s Baa1 Baa2 12/30/2018 Consolidated Edison Company of New York Moody's A2 A3 10/30/2018 Consolidated Edison, Inc. Moody's A3 Baa1 10/30/2018 Orange and Rockland Utilities Moody's A3 Baa1 10/30/2018 Southwestern Public Service Company Moody's Baa1 Baa2 10/19/2018 Dominion Energy Gas Holdings Moody's A2 A3 9/20/2018 Piedmont Natural Gas Company, Inc. Moody's A2 A3 8/1/2018 WEC Energy Group, Inc. Moody's A3 Baa1 7/12/2018 Integrys Holdings Inc. Moody's A3 Baa1 7/12/2018 OGE Energy Corp. Moody's A3 Baa1 7/5/2018 Oklahoma Gas & Electric Company Moody's A1 A2 7/5/2018

2 Q41. Have other rating agencies commented on the effect of the TCJA on ratings? 3

A41. Yes. S&P and Fitch have also commented on the implications of the TCJA on 4

utilities. S&P published a report on January 24, 2018, entitled “U.S. Tax Reform: 5

For Utilities’ Credit Quality, Challenges Abound” in which S&P concludes: 6

The impact of tax reform on utilities is likely to be negative to 7 varying degrees depending on a company’s tax position going 8 into 2018, how its regulators react, and how the company 9 reacts in return. It is negative for credit quality because the 10 combination of a lower tax rate and the loss of stimulus 11 provisions related to bonus depreciation or full expensing of 12 capital spending will create headwinds in operating cash-flow 13 generation capabilities as customer rates are lowered in 14 response to the new tax code. The impact could be sharpened 15 or softened by regulators depending on how much they want 16 to lower utility rates immediately instead of using some of the 17 lower revenue requirement from tax reform to allow the utility 18 to retain the cash for infrastructure investment or other 19

32

expenses. Regulators must also recognize that tax reform is a 1 strain on utility credit quality, and we expect companies to 2 request stronger capital structures and other means to offset 3 some of the negative impact. 4

Finally, if the regulatory response does not adequately 5 compensate for the lower cash flows, we will look to the 6 issuers, especially at the holding company level, to take steps 7 to protect credit metrics if necessary. Some deterioration in 8 the ability to deduct interest expense could occur at the parent, 9 making debt there relatively more expensive. More equity 10 may make sense and be necessary to protect ratings if financial 11 metrics are already under pressure and regulators are 12 aggressive in lowering customer rates. It will probably take 13 the remainder of this year to fully assess the financial impact 14 on each issuer from the change in tax liabilities, the regulatory 15 response, and the company's ultimate response. We have 16 already witnessed differing responses. We revised our outlook 17 to negative on PNM Resources Inc. and its subsidiaries on Jan. 18 16 after a Public Service Co. of New Mexico rate case decision 19 incorporated tax savings with no offsetting measures taken to 20 alleviate the weaker cash flows. It remains to be seen whether 21 PNM will eventually do so, especially as it is facing other 22 regulatory headwinds. On the other hand, FirstEnergy Corp. 23 issued $1.62 billion of mandatory convertible stock and $850 24 million of common equity on Jan. 22 and explicitly referenced 25 the need to support its credit metrics in the face of the new tax 26 code in announcing the move. That is exactly the kind of 27 proactive financial management that we will be looking for to 28 fortify credit quality and promote ratings stability.33 29

In S&P’s 2019 trends report, the rating agency notes that the utility industry’s 30

financial measures weakened in 2018 and attributed that to tax reform, capital 31

spending and negative load growth. In addition, S&P expects that weaker credit 32

metrics will continue into 2019 for those utilities operating with minimal financial 33

cushion. S&P further expects that these utilities will look to offset the revenue 34

reductions from tax reform with equity issuances. The rating agency reported that 35

33 Standard and Poor’s Global Ratings, “U.S. Tax Reform: For Utilities’ Credit Quality, Challenges

Abound”, January 24, 2018.

33

in 2018 regulated utilities issued nearly $35 billion in equity, which is more than 1

twice the equity issuances in 2016 and 2017.34 2

Finally, FitchRatings recognized the implications of tax reform but indicated that 3

any ratings actions will be guided by the response of regulators and the management 4

of the utilities. Fitch notes that the solution will depend on the ability of utility 5

management to manage the cash flow implications of the TCJA. Fitch offers 6

several solutions to provide rate stability and to moderate changes to cash flow in 7

the near term, including increasing the authorized ROE and/or equity ratio.35 8

Q42. What conclusions do you draw from your analysis of capital market 9

conditions? 10

A42. The important conclusions resulting from capital market conditions are: 11

• The assumptions used in the ROE estimation models have been affected by 12

recent historical market conditions. 13

• Recent market conditions are not expected to persist as yields on long-term 14

bonds are expected to increase. As a result, the recent historical market 15

conditions are not reflective of the market conditions that will be present 16

when the rates for Montana-Dakota will be in effect. 17

• It is important to consider the results of a variety of ROE estimation models, 18

using forward-looking assumptions to estimate the cost of equity. 19

34 Standard & Poor’s Ratings, “Industry Top Trends 2019, North America Regulated Utilities”,

November 8, 2019. 35 FitchRatings, Special Report, What Investors Want to Know, “Tax Reform Impact on the U.S.

Utilities, Power & Gas Sector”, January 24, 2018.

34

• Without adequate regulatory support, the TCJA will have a negative effect 1

on utility cash flows, which increases investor risk expectations for utilities. 2

PROXY GROUP SELECTION 3

Q43. Why have you used a group of proxy companies to estimate the cost of equity 4

for Montana-Dakota? 5

A43. In this proceeding, we are focused on estimating the cost of equity for a natural gas 6

utility company that is not itself publicly traded. Because the cost of equity is a 7

market-based concept and given that Montana-Dakota’s natural gas operations in 8

Wyoming do not make up the entirety of a publicly traded entity, it is necessary to 9

establish a group of companies that is both publicly traded and comparable to 10

Montana-Dakota in certain fundamental business and financial respects to serve as 11

its “proxy” in the ROE estimation process. 12

Even if Montana-Dakota was a publicly-traded entity, it is possible that transitory 13

events could bias its market value over a given period. A significant benefit of 14

using a proxy group is that it moderates the effects of unusual events that may be 15

associated with any one company. The proxy companies used in my analyses all 16

possess a set of operating and risk characteristics that are substantially comparable 17

to the Company, and thus provide a reasonable basis to derive and estimate the 18

appropriate ROE for Montana-Dakota. 19

Q44. Please provide a brief profile of Montana-Dakota. 20

A44. Montana-Dakota is a natural gas distribution company that is a wholly-owned 21

subsidiary of MDU Resources. The Company operates in Montana, North Dakota, 22

South Dakota and Wyoming. In Wyoming, the Company distributes natural gas to 23

35

approximately 19,000 residential, commercial and industrial customers in 9 1

communities.36 As of December 31, 2018, Montana-Dakota’s net utility natural 2

gas plant in Wyoming was approximately $16.89 million.37 In addition, Montana-3

Dakota had total natural gas sales in Wyoming in 2018 of approximately 5.56 4

million Dths, made up of 28.67 percent residential, 19.56 percent commercial, 0.29 5

percent industrial, 0.05 percent interdepartmental and 51.43 percent 6

transportation. 38 For Montana-Dakota’s parent company, MDU Resources, 7

Wyoming accounted for 2.00 percent of the natural gas distribution operating sales 8

revenues in 2018, while Idaho (30.00 percent), Washington (26.00 percent), North 9

Dakota (15.00 percent), Montana (9.00 percent), Oregon (8.00 percent), South 10

Dakota (7.00 percent), and Minnesota (3.00 percent) accounted for the other 98.00 11

percent of retail gas distribution operating sales revenues. 39 Montana-Dakota 12

currently has an investment grade long-term rating of A- (Outlook: Stable) from 13

S&P and A- (Outlook: Stable) from Fitch.40 14

Q45. How did you select the companies included in your proxy group? 15

A45. I began with the group of 10 companies that Value Line classifies as Natural Gas 16

Distribution Utilities and applied the following screening criteria to select 17

companies that: 18

36 Montana-Dakota Utilities, 2018 Annual Report to the Wyoming Public Service Commission, at 40

and Montana-Dakota Utilities Co., Wyoming Natural Gas Tariff, Communities Served. 37 Montana-Dakota Utilities, 2018 Annual Report to the Wyoming Public Service Commission, at 10

and 18. 38 Id., at 40. 39 MDU Resources Group, 2018 SEC Form 10-K, at 12. 40 SNL Financial, May 3, 2019.

36

• pay consistent quarterly cash dividends, because companies that do not 1

cannot be analyzed using the Constant Growth DCF model; 2

• have investment grade long-term issuer ratings from S&P and/or Moody’s; 3

• are covered by at least two utility industry analysts; 4

• have positive long-term earnings growth forecasts from at least two utility 5

industry equity analysts; 6

• derive more than 70.00 percent of their total operating income from 7

regulated operations; 8

• derive more than 60.00 percent of regulated operating income from gas 9

distribution operations; and 10

• were not parties to a merger or transformative transaction during the 11

analytical periods relied on. 12

Q46. Did you eliminate any other companies that otherwise met your screening 13

criteria? 14

A46. Yes. On September 13, 2018, Columbia Gas of Massachusetts, a wholly-owned 15

subsidiary of NiSource Inc. (“NiSource”) experienced a significant event as a result 16

of over pressured lines on their system. The market response to this incident was 17

immediate. In fact, NiSource’s stock price fell approximately 12.00 percent 18

immediately following the incident. The total cost to NiSource for this event is 19

not yet defined. Given the impact the incident had on the stock price of NiSource, 20

and the potential effect on the company’s financial performance, it is appropriate 21

to exclude NiSource from my proxy group. 22

37

Q47. What is the composition of your proxy group? 1

A47. The screening criteria discussed above is shown in Exhibit No.___(AEB-2), 2

Schedule 3 and resulted in a proxy group consisting of the companies shown in 3

Figure 7 below. 4

Figure 7: Proxy Group 5

Company Ticker Atmos Energy Corporation ATO

New Jersey Resources Corporation NJR

Northwest Natural Gas Company NWN

ONE Gas, Inc. OGS

South Jersey Industries, Inc. SJI

Southwest Gas Corporation SWX

Spire, Inc. SR

COST OF EQUITY ESTIMATION 6

Q48. Please briefly discuss the ROE in the context of the regulated rate of return. 7

A48. The overall ROR for a regulated utility is based on its weighted average cost of 8

capital, in which the cost rates of the individual sources of capital are weighted by 9

their respective book values. While the costs of debt and preferred stock can be 10

directly observed, the cost of equity is market-based and, therefore, must be 11

estimated based on observable market data. 12

Q49. How is the required ROE determined? 13

A49. The required ROE is estimated by using one or more analytical techniques that rely 14

on market-based data to quantify investor expectations regarding required equity 15

returns, adjusted for certain incremental costs and risks. Informed judgment is then 16

38

applied to determine where the company’s cost of equity falls within the range of 1

results. The key consideration in determining the cost of equity is to ensure that 2

the methodologies employed reasonably reflect investors’ views of the financial 3

markets in general, as well as the subject company (in the context of the proxy 4

group), in particular. 5

Q50. What methods did you use to determine Montana-Dakota’s ROE? 6

A50. I considered the results of the Constant Growth DCF model, the CAPM model, the 7

Bond Yield Plus Risk Premium methodology and an Expected Earnings analysis. 8

As discussed in more detail below, a reasonable ROE estimate appropriately 9

considers alternative methodologies and the reasonableness of their individual and 10

collective results. 11

A. Importance of Multiple Analytical Approaches 12

Q51. Why is it important to use more than one analytical approach? 13

A51. Because the cost of equity is not directly observable, it must be estimated based on 14

both quantitative and qualitative information. When faced with the task of 15

estimating the cost of equity, analysts and investors are inclined to gather and 16

evaluate as much relevant data as reasonably can be analyzed. Several models have 17

been developed to estimate the cost of equity, and I use multiple approaches to 18

estimate the cost of equity. As a practical matter, however, all of the models 19

available for estimating the cost of equity are subject to limiting assumptions or 20

other methodological constraints. Consequently, many well-regarded finance texts 21

recommend using multiple approaches when estimating the cost of equity. For 22

39

example, Copeland, Koller, and Murrin41 suggest using the CAPM and Arbitrage 1

Pricing Theory model, while Brigham and Gapenski42 recommend the CAPM, 2

DCF, and Bond Yield Plus Risk Premium approaches. 3

Q52. Is it important given the current market conditions to use more than one 4

analytical approach? 5

A52. Yes. As discussed in Section IV above, the U.S. economy is beginning to emerge 6

from an unprecedented period of low interest rates. Low interest rates, and the 7

effects of the investor “flight to quality” can be seen in high utility share valuations, 8

relative to historical levels and relative to the broader market. Higher utility stock 9

valuations produce lower dividend yields and result in lower cost of equity 10

estimates from a DCF analysis. Low interest rates also impact the CAPM in two 11

ways: (1) the risk-free rate is lower, and (2) because the market risk premium is a 12

function of interest rates, (i.e., it is the return on the broad stock market less the 13

risk-free interest rate), the risk premium should move higher when interest rates are 14

lower. Therefore, it is important to use multiple analytical approaches to moderate 15

the impact that the current low interest rate environment is having on the ROE 16

estimates for the proxy group and, where possible, consider using projected market 17

data in the models to estimate the return for the forward-looking period. 18

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

Companies, 3rd Ed. (New York: McKinsey & Company, Inc., 2000), at 214. 42 Eugene Brigham, Louis Gapenski, Financial Management: Theory and Practice, 7th Ed. (Orlando:

Dryden Press, 1994), at 341.

40

Q53. Are you aware of any regulatory commissions who have recognized that recent 1

conditions in capital markets are causing ROE recommendations based on 2

DCF models to be unreasonable? 3

A53. Yes, several regulatory commissions have addressed the effect of capital market 4

conditions on the DCF model, including FERC, the ICC, the PPUC and the 5

Missouri PSC. 6

Q54. Please summarize how the FERC has responded to the effect of market 7

conditions on the DCF. 8

A54. Understanding the important role that dividend yields play in the DCF model, the 9

FERC determined that capital market conditions have caused the DCF model to 10

understate equity costs for regulated utilities. In Opinion No. 531, the FERC noted: 11

There is ‘model risk’ associated with the excessive reliance or 12 mechanical application of a model when the surrounding 13 conditions are outside of the normal range. ‘Model risk’ is the 14 risk that a theoretical model that is used to value real world 15 transactions fails to predict or represent the real phenomenon 16 that is being modeled.43 17

In Opinion No. 531, the FERC also noted that the low interest rates and bond yields 18

that persisted throughout the analytical period that was relied on (study period) had 19

affected the results of the DCF model and recognized the need to move away from 20

the midpoint of the DCF analysis. In that case, the FERC relied on the CAPM and 21

other risk premium methodologies to inform its judgment to set the return above 22

43 FERC Docket No. EL11-66-001, Opinion No. 531 (June 19, 2014), fn 286.

41

the midpoint of the DCF results. These positions were affirmed by the FERC in 1

Opinion No. 551 in September 2016. 44 2

Finally, in October 2018, the FERC issued an Order in response to the remand from 3

the U.S. Court of Appeals for the District of Columbia indicating plans to establish 4

ROEs based on an equal weighting of the results of four financial models: the DCF, 5

CAPM, Expected Earnings and Risk Premium. FERC explains its reasons for 6

moving away from sole reliance on the DCF model as follows: 7

Our decision to rely on multiple methodologies in these four 8 complaint proceedings is based on our conclusion that the 9 DCF methodology may no longer singularly reflect how 10 investors make their decisions. We believe that, since we 11 adopted the DCF methodology as our sole method for 12 determining utility ROEs in the 1980s, investors have 13 increasingly used a diverse set of data sources and models to 14 inform their investment decisions. Investors appear to base 15 their decisions on numerous data points and models, including 16 the DCF, CAPM, Risk Premium, and Expected Earnings 17 methodologies. As demonstrated in Figure 2 below, which 18 shows the ROE results from the four models over the four test 19 periods at issue in this proceeding, these models do not 20 correlate such that the DCF methodology captures the other 21 methodologies. In fact, in some instances, their cost of equity 22 estimates may move in opposite directions over time. 23 Although we recognize the greater administrative burden on 24 parties and the Commission to evaluate multiple models, we 25 believe that the DCF methodology alone no longer captures 26 how investors view utility returns because investors do not 27 rely on the DCF alone and the other methods used by investors 28 do not necessarily produce the same results as the DCF. 29 Consequently, it is appropriate for our analysis to consider a 30 combination of the DCF, CAPM, Risk Premium, and 31 Expected Earnings approaches.45 32

44 FERC Docket No. EL14-12-002, Opinion No. 551, at para. 121. 45 Federal Energy Regulatory Commission, Docket No. EL 11-66-001, et al., Order Directing Briefs,

issued October 16, 2018, at para. 40. [Figure 2 was omitted]

42

Q55. How have the PPUC, the ICC and the Missouri PSC addressed the effect of 1

market conditions on the DCF? 2

A55. In a 2012 decision for PPL Electric Utilities, while noting that the PPUC has 3

traditionally relied primarily on the DCF method to estimate the cost of equity for 4

regulated utilities, the PPUC recognized that market conditions were causing the 5

DCF model to produce results that were much lower than other models such as the 6

CAPM and Bond Yield Plus Risk Premium. The PPUC’s Order supported the 7

consideration of multiple ROE estimation methodologies.46 8

The PPUC ultimately concluded: 9

As such, where evidence based on the CAPM and RP methods 10 suggest that the DCF-only results may understate the utility’s 11 current cost of equity capital, we will give consideration to 12 those other methods, to some degree, in determining the 13 appropriate range of reasonableness for our equity return 14 determination.47 15

In a recent ICC case, Docket No. 16-0093, Staff relied on a DCF analysis that 16

resulted in average returns for their proxy groups of 7.24 percent to 7.51 percent. 17

The company demonstrated that these results were uncharacteristically too low, by 18

comparing the results of Staff’s models to recently authorized ROEs for regulated 19

utilities and the return on the S&P 500.48 In Order No. 16-0093, the ICC agreed 20

with the Company that Staff's proposed ROE of 8.04 percent was anomalous and 21

46 Pennsylvania Public Utility Commission, PPL Electric Utilities, R-2012-2290597, meeting held

December 5, 2012, at 80. 47 Id., at 81. 48 State of Illinois Commerce Commission, Docket No. 16-0093, Illinois-American Water Company

Initial Brief, August 31, 2016, at 10.

43

recognized that a return that is not competitive will deter investment in Illinois.49 1

In setting the return in this proceeding the ICC recognized that it was necessary to 2

consider other factors beyond the outputs of the financial models, particularly 3

whether or not the return is sufficient to attract capital, maintain financial integrity, 4

and is commensurate with returns for companies of comparable risk, while 5

balancing the interests of customers and shareholders.50 6

Finally, in February 2018, the Missouri PSC issued a decision in Spire’s 2017 gas 7

rate case, in which the allowed ROE was set at 9.80 percent. In explaining the 8

rationale for its decision, the Commission cited the importance of considering 9

multiple methodologies to estimate the cost of equity and the need for the 10

authorized ROE to be consistent with returns in other jurisdictions and to reflect 11

the growing economy and investor expectations for higher interest rates. 12

Based on the competent and substantial evidence in the record, 13 on its analysis of the expert testimony offered by the parties, 14 and on its balancing of the interests of the company’s 15 ratepayers and shareholders, as fully explained in its findings 16 of fact and conclusions of law, the Commission finds that 9.8 17 percent is a fair and reasonable return on equity for Spire 18 Missouri. That rate is nearly the midpoint of all the experts’ 19 recommendations and is consistent with the national average, 20 the growing economy, and the anticipated increasing interest 21 rates. The Commission finds that this rate of return will allow 22 Spire Missouri to compete in the capital market for the funds 23 needed to maintain its financial health.51 24

49 Illinois Staff’s analysis and recommendation in that proceeding were based on its application of the

multi-stage DCF model and the CAPM to a proxy group of water utilities. 50 State of Illinois Commerce Commission Decision, Docket No. 16-0093, Illinois-American Water

Company, 2016 WL 7325212 (2016), at 55. 51 File No. GR-2017-0215 and File No. GR-2017-0216, Missouri Public Service Commission, Report

and Order, Issue Date February 21, 2018, at 34.

44

Q56. Has the Commission made similar findings regarding the reliance on multiple 1

models? 2

A56. Yes. It is my understanding that the Commission has emphasized that “[t]he 3

determination of cost of capital in rate proceedings, as noted above, combines 4

economic science, economic art and sound judgment as to what yields the most 5

reasonable result.”52 Moreover, in Docket No. 20000-ER-02-184, the Commission 6

concluded that the ROE should not be set based on one specific model or a variation 7

of a specific model and encouraged the evolution of economic thought be presented 8

in future cases.53 9

Q57. What are your conclusions about the results of the DCF and CAPM models? 10

A57. Recent market data that is used as the basis for the assumptions for both models 11

have been affected by market conditions. As a result, relying exclusively on 12

historical assumptions in these models, without considering whether these 13

assumptions are consistent with investors’ future expectations, will underestimate 14

the cost of equity that investors would require over the period that the rates in this 15

case are to be in effect. In this instance, relying on the historical average of 16

abnormally high stock prices results in low dividend yields that are not expected to 17

continue over the period that the new rates will be in effect. This, in turn, 18

underestimates the ROE for the rate period. 19

The use of recent historical Treasury bond yields in the CAPM also tends to 20

underestimate the projected cost of equity. Recent experience indicates that interest 21

52 PacifiCorp, Docket No. 20000-ER-03-198, Order, February 28, 2004, at ¶ 34 b1. 53 PacifiCorp, Docket No. 20000-ER-02-184, Order, March 6, 2003, at ¶ 260.

45

rates are increasing. The expectation that bond yields will not remain at currently 1

low levels means that the expected cost of equity would be higher than is suggested 2

by the CAPM using historical average yields. The use of projected yields on 3

Treasury bonds results in CAPM estimates that are more reflective of the market 4

conditions that investors expect during the period that the Company’s rates will be 5

in effect. 6

B. Constant Growth DCF Model 7

Q58. Please describe the DCF approach. 8

A58. The DCF approach is based on the theory that a stock’s current price represents the 9

present value of all expected future cash flows. In its most general form, the DCF 10

model is expressed as follows: 11

[1] 12

Where P0 represents the current stock price, D1…D∞ are all expected future 13

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

present value calculation that can be simplified and rearranged into the following 15

form: 16

[2] 17

Equation [2] is often referred to as the Constant Growth DCF model in which the 18

first term is the expected dividend yield and the second term is the expected long-19

term growth rate. 20

( ) ( ) ( )∞∞

+++

++

+=

kD

kD

kDP

1...

11 221

0

( ) gP

gDk ++

=0

0 1

46

Q59. What assumptions are required for the Constant Growth DCF model? 1

A59. The Constant Growth DCF model requires the following four assumptions: (1) a 2

constant growth rate for earnings and dividends; (2) a stable dividend payout ratio; 3

(3) a constant price-to-earnings ratio; and (4) a discount rate greater than the 4

expected growth rate. To the extent that any of these assumptions is violated, 5

considered judgment and/or specific adjustments should be applied to the results. 6

Q60. What market data did you use to calculate the dividend yield in your Constant 7

Growth DCF model? 8

A60. The dividend yield in my Constant Growth DCF model is based on the proxy 9

companies’ current annualized dividend and average closing stock prices over the 10

30-, 90-, and 180-trading days ended March 29, 2019. 11

Q61. Why did you use 30-, 90-, and 180-day averaging periods? 12

A61. In my Constant Growth DCF model, I use an average of recent trading days to 13

calculate the term P0 in the DCF model to ensure that the ROE is not skewed by 14

anomalous events that may affect stock prices on any given trading day. The 15

averaging period should also be reasonably representative of expected capital 16

market conditions over the long-term. However, the averaging periods that I use 17

rely on historical data that is not consistent with the forward-looking expectation 18

that interest rates will increase. Therefore, the results of my Constant Growth DCF 19

model using historical data may underestimate the forward-looking cost of equity. 20

As a result, I place more weight on the median to median-high results produced by 21

my Constant Growth DCF model. 22

47

Q62. Did you make any adjustments to the dividend yield to account for periodic 1

growth in dividends? 2

A62. Yes, I did. Because utility companies tend to increase their quarterly dividends at 3

different times throughout the year, it is reasonable to assume that dividend 4

increases will be evenly distributed over calendar quarters. Given that assumption, 5

it is reasonable to apply one-half of the expected annual dividend growth rate for 6

purposes of calculating the expected dividend yield component of the DCF model. 7

This adjustment ensures that the expected first year dividend yield is, on average, 8

representative of the coming twelve-month period, and does not overstate the 9

aggregated dividends to be paid during that time. 10

Q63. Why is it important to select appropriate measures of long-term growth in 11

applying the DCF model? 12

A63. In its Constant Growth form, the DCF model (i.e., Equation [2]) assumes a single 13

growth estimate in perpetuity. To reduce the long-term growth rate to a single 14

measure, one must assume a constant payout ratio, and that earnings per share, 15

dividends per share and book value per share all grow at the same constant rate. 16

Over the long run, however, dividend growth can only be sustained by earnings 17

growth. Therefore, it is important to incorporate a variety of sources of long-term 18

earnings growth rates into the Constant Growth DCF model. 19

Q64. Which sources of long-term earnings growth rates did you use? 20

A64. My Constant Growth DCF model incorporates three sources of long-term earnings 21

growth rates: (1) Zacks Investment Research; (2) Thomson First Call (provided by 22

Yahoo!Finance); and (3) Value Line Investment Survey. 23

48

C. Discounted Cash Flow Model Results 1

Q65. How did you calculate the range of results for the Constant Growth DCF 2

Model? 3

A65. I calculated the low result for my DCF models using the minimum growth rate (i.e., 4

the lowest of the First Call, Zacks, and Value Line earnings growth rates) for each 5

of the proxy group companies. Thus, the low result reflects the minimum DCF 6

result for the proxy group. I used a similar approach to calculate the high results, 7

using the highest growth rate for each proxy group company. The mean results 8

were calculated using the average growth rates from all sources. 9

Q66. Have you excluded any of the Constant Growth DCF results for individual 10

companies in your proxy group? 11

A66. Yes, I have. It is appropriate to exclude Constant Growth DCF results below a 12

specified threshold at which equity investors would consider such returns to provide 13

an insufficient return increment above long-term debt costs. The average credit 14

rating for the companies in my proxy group is A-/A3. The average yield on 15

Moody’s A-rated utility bonds for the 30 trading days ending March 29, 2019, was 16

4.18 percent. 54 As shown on Exhibit No.___(AEB-2), Schedule 4, I have 17

eliminated Constant Growth DCF results lower than 7.00% because such returns 18

would provide equity investors a risk premium only 282 basis points above A-rated 19

utility bonds. 20

54 Source: Bloomberg Professional.

49

Q67. Has the Office of Consumer Advocate (“OCA”) considered a low-end 1

threshold for ROE results? 2

A67. Yes. In Docket No. 20000-469-ER-15, OCA witness Mr. Ornelas indicated that 3

the results of his CAPM analysis which resulted in an ROE of 8.40 percent 4

represented the minimum authorized ROE that could be authorized in the 5

proceeding.55 However, Mr. Ornelas concluded that this absolute minimum ROE 6

of 8.40 percent would not be adequate to balance the interests of Rocky Mountain 7

Power Company.56 Specifically, Mr. Ornelas noted that: 8

I believe the results of my CAPM (8.40%) represent the 9 absolute minimum cost of equity which could be authorized in 10 this proceeding. However, establishing the cost of equity at its 11 absolute minimum does not adequately balance the interests of 12 RMP and could discourage continued investment which is 13 necessary for the provision of safe and reliable service. 14 Therefore, I have looked primarily toward the remaining DCF 15 estimates to base my recommendation.57 16

Thus, the OCA determined that an ROE of 8.40 percent would not provide a 17

sufficient risk premium to compensate investors for the additional risk of an equity 18

investment. As shown in Exhibit __(AEB-2), Schedule 4, the 30-day average mean 19

ROE result using the low growth rate scenario would have been 7.34 percent prior 20

to my exclusion of the low-end outliers and would have been eliminated based on 21

the OCA’s criterion. Therefore, the low-end screen of 7.00 percent that I have 22

applied to the individual results of my Constant Growth DCF analysis is generally 23

55 PacifiCorp, Docket No. 20000-469-ER-15, Direct Testimony of Anthony Ornelas on behalf of the

Office of Consumer Advocate, July 28, 2015, at 31. 56 Ibid. 57 Ibid.

50

consistent with the OCA’s position and well below the minimum threshold outlined 1

by the OCA above in the case for Rocky Mountain Power Company. 2

Q68. What were the results of your DCF analyses? 3

A68. Figure 8 summarizes the results of my DCF analyses. As shown in Figure 8, the 4

median DCF results range from 9.10 percent to 9.30 percent and the median high 5

results are in the range of 11.12 percent to 11.22 percent. While I also summarize 6

the median low DCF results, I do not believe that the low DCF results provide a 7

reasonable spread over the expected yields on Treasury bonds to compensate 8

investors for the incremental risk related to an equity investment. 9

Figure 8: Discounted Cash Flow Results 10 Median Low Median Median High

Constant Growth DCF58 30-Day Average 8.67% 9.30% 11.12% 90-Day Average 8.63% 9.10% 11.21% 180-Day Average 8.78% 9.16% 11.22%

Q69. What are your conclusions about the results of the DCF models? 11

A69. As discussed previously, one primary assumption of the DCF models is a constant 12

P/E ratio. That assumption is heavily influenced by the market price of utility 13

stocks. To the extent that utility valuations are high and may not be sustainable, it 14

is important to consider the results of the DCF models with caution. As I indicated 15

previously, this is due to the high utility equity valuations that occurred in the lower 16

interest rate environment as investors have sought higher returns. With the 17

expectation of rising long-term interest rates, such levels are not expected to be 18

sustained in the upcoming years. Because the low dividend yields may result in the 19

58 See Exhibit No.___(AEB-2), Schedule 4.

51

DCF model understating investors’ expected return, I have given primary weight 1

to the median and high-end DCF results. My overall recommendation also relies 2

on the results of other ROE estimation models. 3

D. CAPM Analysis 4

Q70. Please briefly describe the Capital Asset Pricing Model. 5

A70. The CAPM is a risk premium approach that estimates the cost of equity for a given 6

security as a function of a risk-free return plus a risk premium to compensate 7

investors for the non-diversifiable or “systematic” risk of that security. This second 8

component is the product of the market risk premium and the Beta coefficient, 9

which measures the relative riskiness of the security being evaluated. 10

The CAPM is defined by four components, each of which must theoretically be a 11

forward-looking estimate: 12

[3] 13 Where: 14

Ke = the required market ROE; 15

β = Beta coefficient of an individual security; 16

rf = the risk-free rate of return; and 17

rm = the required return on the market. 18

In this specification, the term (rm – rf) represents the market risk premium. 19

According to the theory underlying the CAPM, because unsystematic risk can be 20

( )fmfe rrrK −+= β

52

diversified away, investors should only be concerned with systematic or non-1

diversifiable risk. Non-diversifiable risk is measured by Beta, which is defined as: 2

β = Covariance(re,

rm) [4] Variance(rm)

The variance of the market return (i.e., Variance (rm)) is a measure of the 3

uncertainty of the general market, and the covariance between the return on a 4

specific security and the general market (i.e., Covariance (re, rm)) reflects the extent 5

to which the return on that security will respond to a given change in the general 6

market return. Thus, Beta represents the risk of the security relative to the general 7

market. 8

Q71. What risk-free rate did you use in your CAPM analysis? 9

A71. I relied on three sources for my estimate of the risk-free rate: (1) the current 30-day 10

average yield on 30-year U.S. Treasury bonds of 2.99 percent;59 (2) the average 11

projected 30-year U.S. Treasury bond yield for Q3 2019 through Q3 2020 of 3.16 12

percent;60 and (3) the average projected 30-year U.S. Treasury bond yield for 2020 13

through 2024 of 3.90 percent.61 14

Q72. Would you place more weight on one of these scenarios? 15

A72. Yes. Based on current market conditions, I place more weight on the results of the 16

projected yields on the 30-year Treasury bonds. As discussed previously, the 17

estimation of the cost of equity in this case should be forward looking because it is 18

59 Bloomberg Professional, as of March 29, 2019. 60 Blue Chip Financial Forecasts, Vol. 38, No. 4, April 1, 2019, at 2. 61 Blue Chip Financial Forecasts, Vol. 37, No. 12, December 1, 2018, at 14.

53

the return that investors would receive over the future rate period. Therefore, the 1

inputs and assumptions used in the CAPM analysis should reflect the expectations 2

of the market at that time. As discussed above, leading economists surveyed by 3

Blue Chip are expecting an increase in long-term interest rates over the next five 4

years. This is an important consideration for equity investors as they assess their 5

return requirements. While I have included the results of a CAPM analysis that 6

relies on the current average risk-free rate, this analysis fails to take into 7

consideration the effect of the market’s expectations for interest rate increases on 8

the cost of equity. 9

Q73. What Beta coefficients did you use in your CAPM analysis? 10

A73. As shown on Exhibit No.___(AEB-2), Schedule 5, I used the average Beta 11

coefficients for the proxy group companies as reported by Bloomberg and Value 12

Line. The Beta coefficients reported by Bloomberg were calculated using ten years 13

of weekly returns relative to the S&P 500 Index. Value Line’s calculation is based 14

on five years of weekly returns relative to the New York Stock Exchange 15

Composite Index. 16

Q74. Why did you select a ten-year period to calculate the Beta coefficients from 17

Bloomberg? 18

A74. As I discussed in Section IV, the TCJA has had a significant effect on utility 19

companies. While other industries are able to retain the benefits of a reduced 20

corporate income tax rate, this benefit has largely been passed through to customers 21

by utility companies. This fundamental difference affected investors’ view of the 22

utility industry relative to other industries. As shown in Figure 9, after the Senate 23

54

passed the TCJA on December 2, 2017, utilities significantly deviated from the 1

broader market. 2

Figure 9: Performance of the Utility Industry Relative to the S&P 500 3

4 The TCJA’s effect on the utility industry relative to other industries caused a short-5

term significant shift in the returns on the utility industry relative to the broader 6

market. Over the last three to five years, volatility for the utility industry has been 7

higher than the broader market (as measured by the S&P 500),62 suggesting higher 8

Beta coefficients for utility companies. However, in short-term calculations of the 9

Beta coefficient, the significant effect of the shift in returns related to the TCJA has 10

outweighed the effect of longer-term measures of relative volatility. As such, to 11

reflect the long-term relationship that suggests utility stocks are less volatile than 12

the broader market (i.e. the relative volatility for utility companies has been lower 13

62 See, S&P Dow Jones Indices, Equity, S&P 500 Utilities, March 29, 2019.

0.8

0.9

1.0

1.1

1.2

1.3

1.4

1.5

1.6

1.7

Feb-14 Sep-14 Apr-15 Nov-15 Jun-16 Jan-17 Aug-17 Mar-18 Oct-18

Rela

tive

perf

orm

ance

S&P 500 Index S&P 500 Utilities Index

After TCJA Passes Senate

55

than the S&P 500 over the ten-year measure63), I selected a ten-year period to 1

calculate the Beta coefficients from Bloomberg. 2

Q75. How did you estimate the market risk premium in the CAPM? 3

A75. I estimated the market risk premium based on the expected return on S&P 500 4

Index less the yield on the 30-year Treasury bond. I calculate the expected return 5

on the S&P 500 Index companies for which dividend yields and long-term earnings 6

projections are available using the Constant Growth DCF model discussed earlier 7

in my Direct Testimony. Based on an estimated market capitalization-weighted 8

dividend yield of 2.00 percent and a weighted long-term growth rate of 11.69 9

percent, the estimated required market return for the S&P 500 Index is 13.80 10

percent. As shown in Exhibit No.___(AEB-2), Schedule 6, the implied market risk 11

premium over the current 30-day average of the 30-year U.S. Treasury bond yield, 12

and projected yields on the 30-year U.S. Treasury bond, range from 9.90 percent to 13

10.81 percent. 14

Q76. Have other regulators endorsed the use of a forward-looking market risk 15

premium? 16

A76. Yes. The FERC and the Staff in the Maine Public Utilities Commission (“Maine 17

PUC”) have supported the forward-looking market risk premium. In Opinion No. 18

531-B, the FERC specifically endorsed a method that is similar to the method I 19

have used to calculate the forward-looking market risk premium (i.e., applying a 20

63 Ibid.

56

Constant Growth DCF analysis to the S&P 500 and using the 30-year Treasury 1

bond yields).64 2

In response to arguments against this methodology, the FERC stated: 3

We are also unpersuaded that the growth rate projection in the 4 NETOs’ CAPM study was skewed by the NETOs’ reliance on 5 analysts’ projections of non-utility companies’ medium-term 6 earnings growth, or that the study failed to consider that those 7 analysts’ estimates reflect unsustainable short-term stock 8 repurchase programs and are not long-term projections. As 9 explained above, the NETOs based their growth rate input on 10 data from IBES, which the Commission has found to be a 11 reliable source of such data. Thus, the time periods used for 12 the growth rate projections in the NETOs’ CAPM study are 13 the time periods over which IBES forecasts earnings growth. 14 Petitioners’ arguments against the time period on which the 15 NETOs’ CAPM analysis is based are, in effect, arguments that 16 IBES data are insufficient in a CAPM study. 65 17

*** 18 While an individual company cannot be expected to sustain 19 high short term growth rates in perpetuity, the same cannot be 20 said for a stock index like the S&P 500 that is regularly 21 updated to contain only companies with high market 22 capitalization, and the record in this proceeding does not 23 indicate that the growth rate of the S&P 500 stock index is 24 unsustainable.66 25

In the Bench Analysis in Docket No. 2018-00194 for Central Maine Power 26

Company, Docket No. 2017-00198 for Emera Maine and Docket No. 2017-00065 27

for Northern Utilities, the Staff accepted the forward-looking methodology for 28

64 150 FERC ¶ 61,165, Docket Nos. EL11-66-002, Opinion No. 531-B (March 3, 2015), at para. 109-

111. 65 Id., at para. 112. 66 Id., at para. 113.

57

calculating the market return that was proposed by the companies.67 In each case, 1

the market return was the expected return for the S&P 500 which was calculated 2

using a Constant Growth DCF model. In Docket No. 2017-00198, Staff noted the 3

following: 4

Staff has no issue with the methodology used by Mr. Perkins 5 in calculating market parameters based on the S&P 500 and 6 used the model provided by Mr. Perkins with the revised risk 7 free rate to re-calculate the market risk premiums.68 8

Furthermore, the Maine PUC in Docket No. 2017-0198 used the CAPM results 9

calculated by Staff and Emera Maine as a check on the reasonableness of the DCF 10

results in the case and did not dispute the use of the forward-looking market risk 11

premium by the parties (i.e., Staff and Emera Maine).69 12

Q77. What are the results of your CAPM analyses? 13

A77. As shown in Figure 10 (see also Exhibit No.___(AEB-2), Schedule 6), my CAPM 14

analysis produces a range of returns from 10.41 percent to 10.84 percent. The mean 15

returns using Bloomberg’s average Beta coefficient and three measures of the risk-16

free rate is 10.68 percent. Using the average Value Line Beta coefficient and three 17

measures of the risk-free rate, the mean result is 10.52 percent. 18

67 Central Maine Power Company, Investigation into Rates and Revenue Requirements of Central

Maine Power Company, Docket No. 2018-00194, Bench Analysis at 52 (February 22, 2019); Emera Maine, Request for Approval of a Proposed Rate Increase, Docket No. 2017-00198, Bench Analysis at 71-72 (December 21, 2017); Northern Utilities, Inc. d/b/a UNITIL, Request for Approval of Rate Change Pursuant to Section 307, Docket No. 2017-00065, Bench Analysis, at 15-16 (October 6, 2017).

68 Emera Maine, Request for Approval of a Proposed Rate Increase, Docket No. 2017-00198, Bench Analysis, at 71-72 (December 21, 2017).

69 Emera Maine, Request for Approval of Proposed Rate Increase, Docket No. 2017-00198, June 28, 2018, at 41

58

Figure 10: CAPM Results 1

Bloomberg

Beta Value Line

Beta Current Risk-Free Rate (2.99%) 10.57% 10.41% Q3 2019-Q3 2020 Projected Risk-Free Rate (3.16%) 10.62% 10.46% 2020-2024 Projected Risk-Free Rate (3.90%) 10.84% 10.69% Mean Result 10.68% 10.52%

2

E. Bond Yield Plus Risk Premium Analysis 3

Q78. Please describe the Bond Yield Plus Risk Premium approach. 4

A78. In general terms, this approach is based on the fundamental principle that equity 5

investors bear the residual risk associated with equity ownership and therefore 6

require a premium over the return they would have earned as a bondholder. That 7

is, because returns to equity holders have greater risk than returns to bondholders, 8

equity investors must be compensated to bear that risk. Risk premium approaches, 9

therefore, estimate the cost of equity as the sum of the equity risk premium and the 10

yield on a particular class of bonds. In my analysis, I used actual authorized returns 11

for natural gas utility companies as the historical measure of the cost of equity to 12

determine the risk premium. 13

Q79. Are there other considerations that should be addressed in conducting this 14

analysis? 15

A79. Yes. It is important to recognize both academic literature and market evidence 16

indicating that the equity risk premium (as used in this approach) is inversely 17

related to the level of interest rates. That is, as interest rates increase (decrease), 18

the equity risk premium decreases (increases). Consequently, it is important to 19

develop an analysis that: (1) reflects the inverse relationship between interest rates 20

59

and the equity risk premium; and (2) relies on recent and expected market 1

conditions. Such an analysis can be developed based on a regression of the risk 2

premium as a function of U.S. Treasury bond yields. If we let authorized ROEs for 3

natural gas utilities serve as the measure of required equity returns and define the 4

yield on the long-term U.S. Treasury bond as the relevant measure of interest rates, 5

the risk premium simply would be the difference between those two points.70 6

Q80. Is the Bond Yield Plus Risk Premium analysis relevant to investors? 7

A80. Yes. Investors are aware of ROE awards in other jurisdictions, and they consider 8

those awards as a benchmark for a reasonable level of equity returns for utilities of 9

comparable risk operating in other jurisdictions. Because my Bond Yield Plus Risk 10

Premium analysis is based on authorized ROEs for utility companies relative to 11

corresponding Treasury yields, it provides relevant information to assess the return 12

expectations of investors. 13

Q81. What did your Bond Yield Plus Risk Premium analysis reveal? 14

A81. As shown in Figure 11 below, from 1992 through March 2019, there was a strong 15

negative relationship between risk premia and interest rates. To estimate that 16

relationship, I conducted a regression analysis using the following equation: 17

𝑅𝑅𝑅𝑅 = 𝑎𝑎 + 𝑏𝑏(𝑇𝑇) [5] 18 Where: 19

70 See e.g., S. Keith Berry, Interest Rate Risk and Utility Risk Premia during 1982-93, Managerial and

Decision Economics, Vol. 19, No. 2 (March, 1998), in which the author used a methodology similar to the regression approach described below, including using allowed ROEs as the relevant data source, and came to similar conclusions regarding the inverse relationship between risk premia and interest rates. See also Robert S. Harris, Using Analysts’ Growth Forecasts to Estimate Shareholders Required Rates of Return, Financial Management, Spring 1986, at 66.

60

RP = Risk Premium (difference between allowed ROEs and the yield on 30-year 1

U.S. Treasury bonds) 2

a = intercept term 3

b = slope term 4

T = 30-year U.S. Treasury bond yield 5

Data regarding allowed ROEs were derived from 614 natural gas utility rate cases 6

from 1992 through March 2019 as reported by Regulatory Research Associates 7

(“RRA”).71 This equation’s coefficients were statistically significant at the 99.00 8

percent level. 9

Figure 11: Risk Premium Results 10

11 As shown on Exhibit No.___(AEB-2), Schedule 7, based on the current 30-day 12

average of the 30-year U.S. Treasury bond yield (i.e., 2.99 percent), the risk 13

71 This analysis began with a total of 960 cases and was screened to eliminate limited issue rider cases,

transmission-only cases, and cases that were silent with respect to the authorized ROE. After applying those screening criteria, the analysis was based on data for 614 cases.

y = -0.5527x + 0.0838R² = 0.8154

2.00%

3.00%

4.00%

5.00%

6.00%

7.00%

8.00%

2.00% 3.00% 4.00% 5.00% 6.00% 7.00% 8.00%

Risk

Pre

miu

m

U.S. Government 30-year Treasury Yield

61

premium would be 6.73 percent, resulting in an estimated ROE of 9.72 percent. 1

Based on the near-term (Q3 2019 – Q3 2020) projections of the 30-year U.S. 2

Treasury bond yield (i.e., 3.16 percent), the risk premium would be 6.64 percent, 3

resulting in an estimated ROE of 9.80 percent. Based on longer-term (2020-2024) 4

projections of the 30-year U.S. Treasury bond yield (i.e., 3.90 percent), the risk 5

premium would be 6.23 percent, resulting in an estimated ROE of 10.13 percent. 6

Q82. How did the results of the Bond Yield Risk Premium inform your 7

recommended ROE for Montana-Dakota? 8

A82. I have considered the results of the Bond Yield Risk Premium analysis in setting 9

my recommended ROE for Montana-Dakota. The results of both my CAPM and 10

Bond Yield Risk Premium analyses provide support for my view that the DCF 11

model is understating investors’ return requirements under current market 12

conditions. Also, as noted above, investors will consider the ROE award of a 13

company when assessing the risk of that company as compared to utilities of 14

comparable risk operating in other jurisdictions. The risk premium analysis takes 15

into account this comparison by estimating the return expectations of investors 16

based on the current and past ROE awards of gas utilities across the US. 17

F. Expected Earnings Analysis 18

Q83. Have you considered any additional analysis to estimate the cost of equity for 19

Montana-Dakota? 20

A83. Yes. I have considered an Expected Earnings analysis based on the projected ROEs 21

for each of the proxy group companies. 22

62

Q84. What is an Expected Earnings Analysis? 1

A84. The Expected Earnings methodology is a comparable earnings analysis that 2

calculates the earnings that an investor expects to receive on the book value of a 3

stock. The expected earnings analysis is a forward-looking estimate of investors’ 4

expected returns. The use of an Expected Earnings approach based on the proxy 5

companies provides a range of the expected returns on a group of risk comparable 6

companies to the subject company. This range is useful in helping to determine the 7

opportunity cost of investing in the subject company, which is relevant in 8

determining a company’s ROE. 9

Q85. Have regulators endorsed the use of an Expected Earnings Analysis? 10

A85. Yes. As discussed above, the FERC issued an Order in October 2018 indicating 11

plans to establish ROEs based on an equal weighting of the results of four financial 12

models: the DCF, CAPM, Expected Earnings and Risk Premium. In regard to the 13

expected earnings analysis, FERC noted the following: 14

A comparable earnings analysis is a method of calculating the 15 earnings an investor expects to receive on the book value of a 16 particular stock. The analysis can be either backward looking 17 using the company’s historical earnings on book value, as 18 reflected on the company’s accounting statements, or forward-19 looking using estimates of earnings on book value, as reflected 20 in analysts’ earnings forecasts for the company. The latter 21 approach is often referred to as an “Expected Earnings 22 analysis.” The returns on book equity that investors expect to 23 receive from a group of companies with risks comparable to 24 those of a particular utility are relevant to determining that 25 utility’s cost of equity, because those returns on book equity 26 help investors determine the opportunity cost of investing in 27 that particular utility instead of other companies of comparable 28 risk. Because investors rely on Expected Earnings analyses to 29 help estimate the opportunity cost of investing in a particular 30

63

utility, we find this type of analysis useful in determining a 1 utility’s ROE.72 2

Q86. Have any other regulators considered the use of an Expected Earnings 3

Analysis? 4

A86. Yes. The Washington Utilities & Transportation Commission (“Washington 5

UTC”), in its order in Dockets UE-170485 and UG-170486, considered the results 6

of the Comparable Earnings analysis 73 in establishing the authorized ROE for 7

Avista Corporation. The Washington UTC noted that it tends to place more weight 8

on the results of the DCF, CAPM and Risk Premium analyses; however, given the 9

wide range of CAPM results presented by the ROE witnesses in the case, the 10

Washington UTC decided to apply weight to the results of the Comparable 11

Earnings analysis.74 Specifically, the Washington UTC stated the following: 12

Finally, as additional data points for our consideration of 13 establishing Avista’s ROE, we note that two witness, Mr. 14 McKenzie for Avista and Mr. Parcell for Staff, employ the CE 15 approach to two proxy groups of companies. The respective 16 mid-points of each witnesses’ CE analysis are 10.5 and 9.5 17 percent, respectively, with an average of 10.0 percent. 18 Although we generally do not apply material weight to the CE 19 method, having stronger reliance on the DCF, CAPM and RP 20 methods, we are inclined to include the CE method here given 21 the anomalous CAPM results described previously.75 22

72 Federal Energy Regulatory Commission, Docket No. EL 11-66-001, et al., Order Directing Briefs,

issued October 16, 2018, at 42. 73 The Expected Earnings analysis is a form of the Comparable Earnings analysis that relies

exclusively on forward-looking projections. 74 Wash. Utils. & Transp. Comm’n v. Avista Corp., Docket Nos. UE-170485 and UG-170486, Order

07, ¶ 65 (April 26,2018). 75 Ibid.

64

Q87. How did you develop the Expected Earnings Approach? 1

A87. I relied primarily on the projected ROE capital for the proxy companies as reported 2

by Value Line for the period from 2022-2024. The projected ROEs are adjusted to 3

account for the fact that the ROEs reported by Value Line are calculated on the 4

basis of common shares outstanding at the end of the period, as opposed to average 5

shares outstanding over the period. This adjustment is consistent with FERC’s 6

methodology for the Expected Earnings analysis that was included in its October 7

2018 order. As shown in Exhibit No.___(AEB-2), Schedule 8, the Expected 8

Earnings analysis results in a mean of 11.04 percent and a median of 10.66 percent. 9

REGULATORY AND BUSINESS RISKS 10

Q88. Do the median DCF and mean CAPM, Risk Premium and Expected Earnings 11

results for the proxy group, taken alone, provide an appropriate estimate of 12

the cost of equity for Montana-Dakota? 13

A88. No. These results provide only a range of the appropriate estimate of the 14

Company’s cost of equity. There are several additional factors that must be taken 15

into consideration when determining where the Company’s cost of equity falls 16

within the range of results. These factors, which are discussed below, should be 17

considered with respect to their overall effect on the Company’s risk profile. 18

A. Small Size Risk 19

Q89. Please explain the risk associated with small size. 20

A89. Both the financial and academic communities have long accepted the proposition 21

that the cost of equity for small firms is subject to a “size effect.” While empirical 22

65

evidence of the size effect often is based on studies of industries other than 1

regulated utilities, utility analysts also have noted the risk associated with small 2

market capitalizations. Specifically, an analyst for Ibbotson Associates noted: 3

For small utilities, investors face additional obstacles, such as 4 a smaller customer base, limited financial resources, and a lack 5 of diversification across customers, energy sources, and 6 geography. These obstacles imply a higher investor return.76 7

Q90. How does the smaller size of a utility affect its business risk? 8

A90. In general, smaller companies are less able to withstand adverse events that affect 9

their revenues and expenses. The impact of weather variability, the loss of large 10

customers to bypass opportunities, or the destruction of demand as a result of 11

general macroeconomic conditions or fuel price volatility will have a 12

proportionately greater impact on the earnings and cash flow volatility of smaller 13

utilities. Similarly, capital expenditures for non-revenue producing investments, 14

such as system maintenance and replacements, will put proportionately greater 15

pressure on customer costs, potentially leading to customer attrition or demand 16

reduction. Taken together, these risks affect the return required by investors for 17

smaller companies. 18

Q91. How does Montana-Dakota’s natural gas distribution operations in Wyoming 19

compare in size to the proxy group companies? 20

A91. As noted previously, Montana-Dakota serves approximately 19,000 residential, 21

commercial and industrial customers in 9 communities and as of year-end 2018, 22

76 Michael Annin, Equity and the Small-Stock Effect, Public Utilities Fortnightly, October 15, 1995.

66

had net utility natural gas plant in Wyoming of approximately $16.89 million.77 1

Montana-Dakota’s natural gas distribution operations in Wyoming are substantially 2

smaller than the median for the proxy group companies in terms of market 3

capitalization. Exhibit No.___(AEB-2), Schedule 9 provides the actual market 4

capitalization for the proxy group companies and estimates the implied market 5

capitalization for Montana-Dakota (i.e., the implied market capitalization if 6

Montana-Dakota’s natural gas distribution operations in Wyoming were a stand-7

alone publicly-traded entity). To estimate the size of the Company’s market 8

capitalization relative to the proxy group, I calculated Montana-Dakota’s proposed 9

capital structure equity component of $18.06 million by multiplying Montana-10

Dakota’s test year rate base of $15.39 million by Montana-Dakota’s test year 11

common equity ratio of 52.076 percent. I then applied the median market-to-book 12

ratio for the proxy group of 2.25 to Montana-Dakota’s implied common equity 13

balance and arrived at an implied market capitalization of approximately $18.06 14

million, or 0.41 percent of the median market capitalization for the proxy group. 15

Q92. How did you estimate the size premium for Montana-Dakota? 16

A92. Given this relative size information, it is possible to estimate the impact of size on 17

the ROE for Montana-Dakota using Duff and Phelps data that estimates the stock 18

risk premia based on the size of a company’s market capitalization. As shown in 19

Exhibit No.___(AEB-2), Schedule 9, the median market capitalization of the proxy 20

group of approximately $4.36 billion corresponds to the fifth decile of the Duff and 21

77 Montana-Dakota Utilities, 2018 Annual Report to the Wyoming Public Service Commission, at 10,

18, 40 and Montana-Dakota Utilities Co., Wyoming Natural Gas Tariff, Communities Served.

67

Phelps market capitalization data. Based on Duff and Phelps’ analysis, that decile 1

corresponds to a size premium of 1.28 percent (i.e., 128 basis points). Montana-2

Dakota’s implied market capitalization of approximately $18.06 million falls 3

within the tenth decile, which comprises market capitalization levels up to $321.578 4

million and corresponds to a size premium of 5.22 percent (i.e., 522 basis points). 5

The difference between those size premia is 394 basis points (i.e., 5.22 percent 6

minus 1.28 percent). 7

Q93. Have regulators in other jurisdictions made a specific risk adjustment to the 8

ROE results based on a company’s small size? 9

A93. Yes. In Order No. 15, the Regulatory Commission of Alaska (“RCA”) concluded 10

that Alaska Electric Light and Power Company (“AEL&P”) was riskier than the 11

proxy group companies due to small size as well as other business risks. The RCA 12

did “not believe that adopting the upper end of the range of ROE analyses in this 13

case, without an explicit adjustment, would adequately compensate AEL&P for its 14

greater risk.”78 Thus, the RCA awarded AEL&P an ROE of 12.875 percent which 15

was 108 basis points above the highest return on equity estimate from any model 16

presented in the case.79 Similarly, in Order No. 19, the RCA noted that small size 17

as well as other business risks such as structural regulatory lag, weather risk, 18

alternative rate mechanisms, gas supply risk, geographic isolation and economic 19

78 Docket No. U-10-29, In the Matter of the Revenue Requirement and Cost of Service Study

Designated as TA381-1 Filed by Alaska Electric Light and Power Company, Order entered September 2, 2011 (Order No. 15) at 37.

79 Id, at 32 and 37.

68

conditions increased the risk of ENSTAR Natural Gas Company.80 Ultimately, the 1

RCA concluded that: 2

Although we agree that the risk factors identified by ENSTAR 3 increase its risk, we do not attempt to quantify the amount of 4 that increase. Rather, we take the factors into consideration 5 when evaluating the remainder of the record and the 6 recommendations presented by the parties. After applying our 7 reasoned judgment to the record, we find that 11.875% 8 represents a fair ROE for ENSTAR.81 9

Q94. How have you considered the smaller size of Montana-Dakota in your 10

recommendation? 11

A94. While I have estimated the effect of Montana-Dakota’s small size on the ROE, I 12

am not proposing a specific adjustment for this risk factor. Rather, I believe it is 13

important to consider the small size of Montana-Dakota’s natural gas distribution 14

operations in Wyoming in the determination of where, within the range of analytical 15

results, the Company’s required ROE falls. Therefore, the additional risk 16

associated with small size indicates that the Company’s ROE should be established 17

above the mean results for the proxy group companies. 18

B. Flotation Cost 19

Q95. What are flotation costs? 20

A95. Flotation costs are the costs associated with the sale of new issues of common stock. 21

These costs include out-of-pocket expenditures for preparation, filing, 22

underwriting, and other issuance costs. 23

80 Docket No. U-16-066, In the Matter of the Tariff Revision Designated as TA285-4 Filed by

ENSTAR Natural Gas Company, A Division of Semco Energy, Inc., Order entered September 22, 2017 (Order No. 19) at 50-52.

81 Ibid.

69

Q96. Why is it important to consider flotation costs in the allowed ROE? 1

A96. A regulated utility must have the opportunity to earn an ROE that is both 2

competitive and compensatory to attract and retain new investors. To the extent 3

that a company is denied the opportunity to recover prudently incurred flotation 4

costs, actual returns will fall short of expected (or required) returns, thereby diluting 5

equity share value. 6

Q97. Are flotation costs part of the utility’s invested costs or part of the utility’s 7

expenses? 8

A97. Flotation costs are part of the invested costs of the utility, which are properly 9

reflected on the balance sheet under “paid in capital.” They are not current 10

expenses, and, therefore, are not reflected on the income statement. Rather, like 11

investments in rate base or the issuance costs of long-term debt, flotation costs are 12

incurred over time. As a result, the great majority of a utility’s flotation cost is 13

incurred prior to the test year but remains part of the cost structure that exists during 14

the test year and beyond, and as such, should be recognized for ratemaking 15

purposes. Therefore, whether an issuance occurs during the test year, or is planned 16

for the test year, is irrelevant, because failure to allow recovery of past flotation 17

costs may deny Montana-Dakota the opportunity to earn its required ROR in the 18

future. 19

Q98. Please provide an example of why a flotation cost adjustment is necessary to 20

compensate investors for the capital they have invested. 21

A98. Suppose MDU Resources issues stock with a value of $100, and an equity investor 22

invests $100 in MDU Resources in exchange for that stock. Further suppose that, 23

70

after paying the flotation costs associated with the equity issuance, which include 1

fees paid to underwriters and attorneys, among others, MDU Resources ends up 2

with only $97 of issuance proceeds, rather than the $100 the investor contributed. 3

MDU Resources invests that $97 in plant used to serve its customers, which 4

becomes part of rate base. Absent a flotation cost adjustment, the investor will 5

thereafter earn a return on only the $97 invested in rate base, even though she 6

contributed $100. Making a small flotation cost adjustment gives the investor a 7

reasonable opportunity to earn the authorized return, rather than the lower return 8

that results when the authorized return is applied to an amount less than what the 9

investor contributed. 10

Q99. Is the date of MDU Resources last issued common equity important in the 11

determination of flotation costs? 12

A99. No. As shown in Exhibit No.___(AEB-2), Schedule 10, MDU Resources closed 13

on equity issuances of approximately $58 million and $54 million (for a total of 4.7 14

million shares of common stock) in November 2002 and February 2004, 15

respectively. The vintage of the issuance, however, is not particularly important 16

because the investor suffers a shortfall in every year that he should have a 17

reasonable opportunity to earn a return on the full amount of capital that he has 18

contributed. Returning to my earlier example, the investor who contributed $100 19

is entitled to a reasonable opportunity to earn a return on $100 not only in the first 20

year after the investment, but in every subsequent year in which he has the $100 21

invested. Leaving aside depreciation, which is dealt with separately, there is no 22

basis to conclude that the investor is entitled to earn a return on $100 in the first 23

71

year after issuance, but thereafter is entitled to earn a return on only $97. As long 1

as the $100 is invested, the investor should have a reasonable opportunity to earn a 2

return on the entire amount. 3

Q100. Is the need to consider flotation costs recognized by the academic and financial 4

communities? 5

A100. Yes. The need to reimburse shareholders for the lost returns associated with equity 6

issuance costs is recognized by the academic and financial communities in the same 7

spirit that investors are reimbursed for the costs of issuing debt. This treatment is 8

consistent with the philosophy of a fair ROR. According to Dr. Shannon Pratt: 9

Flotation costs occur when new issues of stock or debt are sold 10 to the public. The firm usually incurs several kinds of flotation 11 or transaction costs, which reduce the actual proceeds received 12 by the firm. Some of these are direct out-of-pocket outlays, 13 such as fees paid to underwriters, legal expenses, and 14 prospectus preparation costs. Because of this reduction in 15 proceeds, the firm’s required returns on these proceeds equate 16 to a higher return to compensate for the additional costs. 17 Flotation costs can be accounted for either by amortizing the 18 cost, thus reducing the cash flow to discount, or by 19 incorporating the cost into the cost of capital. Because 20 flotation costs are not typically applied to operating cash flow, 21 one must incorporate them into the cost of capital.82 22

Q101. How did you calculate the flotation costs for Montana-Dakota? 23

A101. My flotation cost calculation is based on the costs of issuing equity that were 24

incurred by MDU Resources in its two most recent common equity issuances. 25

Those issuance costs were applied to my proxy group. Based on the issuance costs 26

82 Shannon P. Pratt, Cost of Capital Estimation and Applications, Second Edition, at 220-221.

72

provided in Exhibit No.___(AEB-2), Schedule 10, flotation costs for Montana-1

Dakota are approximately 0.09 percent (i.e., 9 basis points) for the proxy group. 2

Q102. Do your final results include an adjustment for flotation cost recovery? 3

A102. No. I did not make an explicit adjustment for flotation costs to any of my 4

quantitative analyses. Rather, I provide the above result for consideration in my 5

recommended ROE, which reflects the range of results from my Constant Growth 6

DCF, CAPM, Risk Premium and Expected Earnings analyses. 7

C. Capital Expenditures 8

Q103. Please summarize the Company’s capital expenditure requirements. 9

A103. The Company’s current projections for 2019 through 2023 include approximately 10

$12.43 million in capital investments for the period.83 Based on the Company’s net 11

utility plant of approximately $17.07 million as of December 31, 2017,84 the $12.43 12

million anticipated capital expenditures are approximately 72.80 percent of 13

Montana-Dakota’s net utility plant as of December 31, 2017. 14

Q104. How is the Company’s risk profile affected by their substantial capital 15

expenditure requirements? 16

A104. As with any utility faced with substantial capital expenditure requirements, the 17

Company’s risk profile may be adversely affected in two significant and related 18

ways: (1) the heightened level of investment increases the risk of under recovery or 19

83 Data provided by Montana-Dakota Utilities Co. for Capital Expenditures 2019-2023. 84 Data provided by Montana-Dakota Utilities Co.

73

delayed recovery of the invested capital; and (2) an inadequate return would put 1

downward pressure on key credit metrics. 2

Q105. Do credit rating agencies recognize the risks associated with elevated levels of 3

capital expenditures? 4

A105. Yes, they do. From a credit perspective, the additional pressure on cash flows 5

associated with high levels of capital expenditures exerts corresponding pressure 6

on credit metrics and, therefore, credit ratings. To that point, S&P explains the 7

importance of regulatory support for large capital projects: 8

When applicable, a jurisdiction’s willingness to support large 9 capital projects with cash during construction is an important 10 aspect of our analysis. This is especially true when the project 11 represents a major addition to rate base and entails long lead 12 times and technological risks that make it susceptible to 13 construction delays. Broad support for all capital spending is 14 the most credit-sustaining. Support for only specific types of 15 capital spending, such as specific environmental projects or 16 system integrity plans, is less so, but still favorable for 17 creditors. Allowance of a cash return on construction work-18 in-progress or similar ratemaking methods historically were 19 extraordinary measures for use in unusual circumstances, but 20 when construction costs are rising, cash flow support could be 21 crucial to maintain credit quality through the spending 22 program. Even more favorable are those jurisdictions that 23 present an opportunity for a higher return on capital projects 24 as an incentive to investors.85 25

Therefore, to the extent that Montana-Dakota’s rates do not permit the opportunity 26

to recover its capital investments on a regular basis, the Company will face 27

increased recovery risk and thus increased pressure on its credit metrics. 28

85 S&P Global Ratings, “Assessing U.S. Investor-Owned Utility Regulatory Environments,” August

10, 2016, at 7.

74

Q106. How do Montana-Dakota’s capital expenditure requirements compare to 1

those of the proxy group companies? 2

A106. As shown in Exhibit No.___(AEB-2), Schedule 11, I calculated the ratio of 3

expected capital expenditures to net utility plant for Montana-Dakota and each of 4

the companies in the proxy group by dividing each company’s projected capital 5

expenditures for the period from 2019-2023 by its total net utility plant as of 6

December 31, 2017. As shown in Exhibit No.___(AEB-2), Schedule 11 (see also 7

Figure 12 below), Montana-Dakota’s ratio of capital expenditures as a percentage 8

of net utility plant of 72.80 percent is approximately 1.01 times the median for the 9

proxy group companies of 71.83 percent. This result indicates moderately elevated 10

risk relative to the companies in the proxy group. 11

Figure 12: Comparison of Capital Expenditures – Proxy Group Companies 12

13

38.44%44.52%

59.20%

71.83% 72.80%

88.73%

99.74% 101.56%

0.00%

20.00%

40.00%

60.00%

80.00%

100.00%

120.00%

NJR NWN OGS SJI MDU SR SWX ATO

Proxy Group Median = 71.83%

75

Q107. Does Montana-Dakota have a capital tracking mechanism to recover the costs 1

associated with its capital expenditures plan between rate cases? 2

A107. No. Montana-Dakota currently has not requested approval to recover capital 3

investment costs between rate cases utilizing a capital tracking mechanism. 4

Therefore, Montana-Dakota depends entirely on rate case filings for capital cost 5

recovery. However, significant programs like Montana-Dakota’s that drive capital 6

expenditure requirements generally receive cost recovery through infrastructure 7

and capital trackers. As shown in Exhibit No.___(AEB-2), Schedule 12, 67.00 8

percent of the proxy group utilities recover costs through capital tracking 9

mechanisms. Since Montana-Dakota does not currently have a capital tracking 10

mechanism, Montana-Dakota’s risk relative to the proxy group is increased. 11

Q108. What are your conclusions regarding the effect of the Company’s capital 12

spending requirements on its risk profile and cost of capital? 13

A108. The Company’s capital expenditure requirements as a percentage of net utility plant 14

are significant and will continue over the next few years. Additionally, unlike a 15

number of the operating subsidiaries of the proxy group, Montana-Dakota does not 16

have a comprehensive capital tracking mechanism to recover the Company’s 17

projected capital expenditures. Therefore, Montana-Dakota’s significant capital 18

expenditures plan and limited ability to recover the capital investment on an as-19

incurred basis results in a risk profile that is greater than that of the proxy group 20

and supports an ROE toward the higher end of the reasonable range of ROEs. 21

76

D. Regulatory Risk 1

Q109. Please explain how the regulatory environment affects investors’ risk 2

assessments. 3

A109. The ratemaking process is premised on the principle that, for investors and 4

companies to commit the capital needed to provide safe and reliable utility service, 5

the subject utility must have the opportunity to recover the return of, and the 6

market-required return on, invested capital. Regulatory authorities recognize that 7

because utility operations are capital intensive, regulatory decisions should enable 8

the utility to attract capital at reasonable terms; doing so balances the long-term 9

interests of investors and customers. Montana-Dakota is no exception. They must 10

finance their operations and require the opportunity to earn a reasonable return on 11

their invested capital to maintain their financial profiles. In that respect, the 12

regulatory environment is one of the most important factors considered in both debt 13

and equity investors’ risk assessments. 14

From the perspective of debt investors, the authorized return should enable the 15

Company to generate the cash flow needed to meet their near-term financial 16

obligations, make the capital investments needed to maintain and expand their 17

systems, and maintain the necessary levels of liquidity to fund unexpected events. 18

This financial liquidity must be derived not only from internally generated funds, 19

but also by efficient access to capital markets. Moreover, because fixed income 20

investors have many investment alternatives, even within a given market sector, the 21

Company’s financial profiles must be adequate on a relative basis to ensure their 22

77

ability to attract capital under a variety of economic and financial market 1

conditions. 2

Equity investors require that the authorized return be adequate to provide a risk-3

comparable return on the equity portion of the Company’s capital investments. 4

Because equity investors are the residual claimants on the Company’s cash flows 5

(which is to say that the equity return is subordinate to interest payments), they are 6

particularly concerned with the strength of regulatory support and its effect on 7

future cash flows. 8

Q110. Please explain how credit rating agencies consider regulatory risk in 9

establishing a company’s credit rating. 10

A110. Both S&P and Moody’s consider the overall regulatory framework in establishing 11

credit ratings. Moody’s establishes credit ratings based on four key factors: (1) 12

regulatory framework; (2) the ability to recover costs and earn returns; (3) 13

diversification; and (4) financial strength, liquidity and key financial metrics. Of 14

these criteria, regulatory framework and the ability to recover costs and earn returns 15

are each given a broad rating factor of 25.00 percent. Therefore, Moody’s assigns 16

regulatory risk a 50.00 percent weighting in the overall assessment of business and 17

financial risk for regulated utilities.86 18

S&P also identifies the regulatory framework as an important factor in credit ratings 19

for regulated utilities, stating: “One significant aspect of regulatory risk that 20

86 Moody’s Investors Service, Rating Methodology: Regulated Electric and Gas Utilities, June 23,

2017, at 4.

78

influences credit quality is the regulatory environment in the jurisdictions in which 1

a utility operates.”87 S&P identifies four specific factors that it uses to assess the 2

credit implications of the regulatory jurisdictions of investor-owned regulated 3

utilities: (1) regulatory stability; (2) tariff-setting procedures and design; (3) 4

financial stability; and (4) regulatory independence and insulation.88 5

Q111. How does the regulatory environment in which a utility operates affect its 6

access to and cost of capital? 7

A111. The regulatory environment can significantly affect both the access to, and cost of 8

capital in several ways. First, the proportion and cost of debt capital available to 9

utility companies are influenced by the rating agencies’ assessment of the 10

regulatory environment. As noted by Moody’s, “[f]or rate regulated utilities, which 11

typically operate as a monopoly, the regulatory environment and how the utility 12

adapts to that environment are the most important credit considerations.” 89 13

Moody’s further highlighted the relevance of a stable and predictable regulatory 14

environment to a utility’s credit quality, noting: “[b]roadly speaking, the 15

Regulatory Framework is the foundation for how all the decisions that affect 16

utilities are made (including the setting of rates), as well as the predictability and 17

consistency of decision-making provided by that foundation.”90 18

87 Standard & Poor’s Global Ratings, Ratings Direct, U.S. and Canadian Regulatory Jurisdictions

Support Utilities’ Credit Quality—But Some More So Than Others, June 25, 2018, at 2. 88 Id., at 1. 89 Moody’s Investors Service, Rating Methodology: Regulated Electric and Gas Utilities, June 23,

2017, at 6. 90 Ibid.

79

Q112. Have you conducted any analysis of the regulatory framework in Wyoming 1

relative to the jurisdictions in which the companies in your proxy group 2

operate? 3

A112. Yes. I have evaluated the regulatory framework in Wyoming on four factors that 4

are important in terms of providing a regulated utility an opportunity to earn its 5

authorized ROE. These are: 1) test year convention (i.e., forecast vs. historical); 6

2) method for determining rate base (i.e., average vs. year-end); 3) use of revenue 7

decoupling mechanisms or other clauses that mitigate volumetric risk; and 4) 8

prevalence of capital cost recovery between rate cases. The results of this 9

regulatory risk assessment are shown in Exhibit No.___(AEB-2), Schedule 12 and 10

are summarized below. 11

Test year convention: Montana-Dakota uses a historical test year adjusted for 12

known and measurable changes in Wyoming, while 39.00 percent of the 13

operating companies held by the proxy group provide service in jurisdictions 14

that use a fully or partially forecast test year. Forecast test years have been relied 15

on for several years and produce cost estimates that are more reflective of future 16

costs which results in more accurate recovery of incurred costs and mitigates 17

the regulatory lag associated with historical test years. As Lowry, Hovde, 18

Getachew, and Makos explain in their 2010 report, Forward Test Years for US 19

Electric Utilities: 20

This report provides an in depth discussion of the test year 21 issue. It includes the results of empirical research which 22 explores why the unit costs of electric IOUs are rising and 23 shows that utilities operating under forward test years realize 24 higher returns on capital and have credit ratings that are 25

80

materially better than those of utilities operating under 1 historical test years. The research suggests that shifting to a 2 future test year is a prime strategy for rebuilding utility credit 3 ratings as insurance against an uncertain future.91 4

Rate Base: The Company’s rate base in Wyoming is determined using the year-5

end methodology. As shown in Exhibit No.___(AEB-2), Schedule 12, 61.00 6

percent of the operating companies held by proxy group have also relied on a 7

year-end rate base. The year-end methodology means that the rate base includes 8

capital additions that occurred in the second half of the test year and is more 9

reflective of net utility plant going forward. 10

Volumetric Risk: Montana-Dakota has protection against volumetric risk in 11

Wyoming through customer charges that recover a high percentage of the 12

Company’s fixed costs. By comparison, 89 percent of the operating companies 13

held by the proxy group have some form of protection against volumetric risk 14

either through a revenue decoupling mechanism or a weather normalization 15

adjustment clause. Therefore, these operating companies have a slightly better 16

opportunity to achieve their authorized return than Montana-Dakota does due 17

to more stable revenues and cash flows. 18

Capital Cost Recovery: As discussed above, Montana-Dakota does not have a 19

capital tracking mechanism to recover capital investment costs between rate 20

cases. However, 67 percent of the operating companies held by the proxy group 21

have some form of capital cost recovery mechanism in place. 22

91 M.N. Lowry, D. Hovde, L. Getachew, and M. Makos, Forward Test Years for US Electric Utilities,

prepared for Edison Electric Institute, August 2010, at 1.

81

Q113. Has RRA provided recent commentary regarding its regulatory ranking for 1

Wyoming? 2

A113. Yes. In May 2017, RRA updated its evaluation of the regulatory environment in 3

Wyoming and lowered the overall rating of this regulatory jurisdiction. RRA noted 4

that the regulatory climate was restrictive and that the authorized ROEs were below 5

industry averages. 6

The Wyoming regulatory climate is relatively restrictive from 7 an investor point of view. A majority of the base rate 8 proceedings that have come before the PSC have been 9 resolved via settlements, and the authorized ROEs in both 10 settled and fully litigated cases have generally approximated 11 or have been somewhat below prevailing industry averages. 12 Retail electric competition has not been implemented, and the 13 state's electric utilities have fuel and purchased power 14 mechanisms in place, some of which contain incentive 15 provisions. In addition, several of the state's utilities have 16 mechanisms in place that provide for expedited recovery of 17 demand-side management costs. The PSC has generally relied 18 on a year-end original-cost rate base for a historical test period, 19 updated to reflect known-and-measurable changes. In more 20 recent cases for PacifiCorp, the PSC permitted the company to 21 utilize test years that have contained forecasted data. While 22 earning a cash return on construction work in progress 23 associated with new generation projects is permitted, such 24 treatment has only been granted by the PSC on a limited basis. 25 In the gas regulatory sphere, retail customers are permitted to 26 select an alternative supplier, and the utilities have the ability 27 to recover stranded costs related to retail competition. Gas 28 supply costs for those customers that do not opt to be served 29 by an alternative supplier may be recovered through an 30 automatic adjustment mechanism, and the gas utilities operate 31 under incentive mechanisms that permit the companies to 32 retain a portion of gas cost savings relative to PSC-approved 33 benchmarks. In addition, the state's gas utilities operate under 34 a partial revenue decoupling mechanism. In May 2017, RRA 35 performed a comprehensive audit of its regulatory rankings. 36 The ranking accorded Wyoming was lowered as a result of this 37

82

process. RRA now accords Wyoming an Average/3 ranking, 1 versus the previous Average/2 ranking.92 2

Q114. What are your conclusions regarding the perceived risks related to the 3

Wyoming regulatory environment? 4

A114. As discussed throughout this section of my testimony, both Moody’s, and S&P 5

have identified the supportiveness of the regulatory environment as an important 6

consideration in developing their overall credit ratings for regulated utilities. 7

Considering the regulatory adjustment mechanisms, many of the companies in the 8

proxy group have slightly more timely cost recovery through forecasted test years, 9

year-end rate base, cost recovery trackers and revenue stabilization mechanisms 10

than Montana-Dakota has in Wyoming. In addition, RRA recently lowered its 11

regulatory ranking for Wyoming from an Average/2 to an Average/3 ranking. 12

Therefore, the average ROE for the proxy group would understate the return on 13

equity that an investor would require in Wyoming because the risks of timely and 14

full cost recovery are moderately greater for Montana-Dakota in Wyoming than for 15

the proxy group. For that reason, I conclude that the authorized ROE for Montana-16

Dakota should be higher than the proxy group mean. 17

CAPITAL STRUCTURE 18

Q115. Is the capital structure of the Company an important consideration in the 19

determination of the appropriate ROE? 20

A115. Yes, it is. Assuming other factors equal, a higher debt ratio increases the risk to 21

investors. For debt holders, higher debt ratios result in a greater portion of the 22

92 Regulatory Research Associates, Profile of Wyoming Public Commission, accessed May 7, 2019.

83

available cash flow being required to meet debt service, thereby increasing the risk 1

associated with the payments on debt. The result of increased risk is a higher 2

interest rate. The incremental risk of a higher debt ratio is more significant for 3

common equity shareholders. Common shareholders are the residual claimants on 4

the cash flow of the Company. Therefore, the greater the debt service requirement, 5

the less cash flow available for common equity holders. 6

Q116. What is Montana-Dakota’s proposed capital structure? 7

A116. The Company’s proposal is to establish a capital structure consisting of 52.076 8

percent common equity, 45.717 percent long-term debt and 2.207 percent short-9

term debt. 10

Q117. Did you conduct any analysis to determine if this requested equity ratio was 11

reasonable? 12

A117. Yes, I did. I reviewed the Company’s historical actual capital structure and the 13

capital structures of the utility operating subsidiaries of the proxy companies. 14

Because the ROE is set based on the return that is derived from the risk-comparable 15

proxy group, it is reasonable to look to the proxy group average capital structure to 16

benchmark the equity ratio for the Company. 17

Q118. Please discuss your analysis of the capital structures of the proxy group 18

companies. 19

A118. I calculated the mean proportions of common equity, long-term debt, short-term 20

debt and preferred equity for the most recent year for each of the companies in the 21

84

proxy group at the operating subsidiary level. 93 My analysis of the capital 1

structures of the proxy group companies is provided in Exhibit No.___(AEB-2), 2

Schedule 13. As shown in Exhibit No.___(AEB-2), Schedule 13, the equity ratios 3

for the proxy group at the operating utility company level ranged from 47.00 4

percent to 63.18 percent with an average of 52.94 percent. Montana-Dakota’s 5

proposed equity ratio of 52.076 percent is well within the range of equity ratios for 6

the utility operating subsidiaries of the proxy group companies and is therefore 7

reasonable. 8

Q119. Are there other factors to be considered in setting the Company’s capital 9

structure? 10

A119. Yes. The credit rating agencies’ response to the TCJA must also be considered 11

when determining the equity ratio. As discussed previously in my testimony, all 12

three rating agencies have noted that the TCJA has negative implications for utility 13

cash flows. S&P and FitchRatings have specifically identified increasing the equity 14

ratio as one approach to ensure that utilities have sufficient cash flows following 15

the tax cuts and the loss of bonus depreciation. Furthermore, Moody’s 16

unprecedented downgrade of the rating outlook for the entire utilities sector in June 17

2018 stresses the importance of maintaining adequate cash flow metrics for the 18

industry as a whole and Montana-Dakota in the context of this proceeding. 19

93 Source: SNL Financial and FERC Form 1 and FERC Form 2 annual reports.

85

Q120. Is there a relationship between the equity ratio and the authorized ROE? 1

A120. Yes. The equity ratio is the primary indicator of financial risk for a regulated utility 2

such as Montana-Dakota. To the extent the equity ratio is reduced, it is necessary 3

to increase the authorized ROE to compensate investors for the greater financial 4

risk associated with a lower equity ratio. 5

Q121. What is your conclusion regarding an appropriate capital structure for 6

Montana-Dakota? 7

A121. Considering the actual capital structures of the proxy group operating companies, I 8

believe that Montana-Dakota’s proposed common equity ratio of 52.076 percent is 9

reasonable. The proposed equity ratio is well within the range established by the 10

capital structures of the utility operating subsidiaries of the proxy companies. In 11

addition, based on the cash flow concerns raised by credit rating agencies as a result 12

of the TCJA, it is reasonable to rely on a higher equity ratio than the Company may 13

have relied on in prior. 14

CONCLUSIONS AND RECOMMENDATION 15

Q122. What is your conclusion regarding a fair ROE for Montana-Dakota? 16

A122. Based on the quantitative and qualitative analyses presented in my Direct 17

Testimony, and in light of the business and financial risks of Montana-Dakota 18

compared to the proxy group, and the effects of Federal tax reform on the cash flow 19

metrics of utilities, it is my view that an ROE of 10.30 percent is reasonable and 20

would fairly balance the interests of customers and shareholders. This ROE would 21

enable the Company to maintain its financial integrity and therefore its ability to 22

86

attract capital at reasonable rates under a variety of economic and financial market 1

conditions, while continuing to provide safe, reliable and affordable natural gas 2

utility service to customers in Wyoming. 3

Figure 13: Summary of Analytical Results94 4

Constant Growth DCF Median Low Median Median High

30-Day Average Price 8.67% 9.30% 11.12% 90-Day Average Price 8.63% 9.10% 11.21% 180-Day Average Price 8.78% 9.16% 11.22%

Capital Asset Pricing Model

Current Risk-

Free Rate (2.99%)

Q3 2019 – Q3 2020 Projected Risk-Free Rate

(3.16%)

2020-2024 Projected Risk-

Free Rate (3.90%)

Bloomberg Beta 10.57% 10.62% 10.84% Value Line Beta 10.41% 10.46% 10.69%

Bond Yield Plus Risk Premium

Current Risk-

Free Rate (2.99%)

Q3 2019 – Q3 2020 Projected Risk-Free Rate

(3.16%)

2020-2024 Projected Risk-

Free Rate (3.90%)

Risk Premium Results 9.72% 9.80% 10.13% Expected Earnings Analysis

Mean Median Expected Earnings Results 11.04% 10.66%

5

Q123. What is your conclusion with respect to Montana-Dakota’s proposed capital 6

structure? 7

A123. My conclusion is that Montana-Dakota’s proposal to establish a capital structure 8

consisting of 52.076 percent common equity, 45.717 percent long-term debt, and 9

94 The analytical results included in Figure 13 reflect the results of the Constant Growth DCF analysis

excluding the results for individual companies that did not meet the minimum threshold of 7.00 percent.

87

2.207 percent short-term debt is reasonable when compared to the capital structures 1

of the companies in the proxy group and taking in consideration the impact of the 2

TCJA on the cash flows and therefore should be adopted. 3

Q124. Does this conclude your Direct Testimony? 4

A124. Yes, it does. 5

Docket No. 30013-351-GR-19 Exhibit No.___(AEB-2)

Schedule 1 Page 1 of 10

Concentric Energy Advisors | Pg. 1

Ann E. Bulkley Senior Vice President

Ms. Bulkley has more than two decades of management and economic consulting experience in the energy industry. Ms. Bulkley has extensive state and federal regulatory experience on both electric and natural gas issues including rate of return, cost of equity and capital structure issues. Ms. Bulkley has provided expert testimony on the cost of capital in more than 30 regulatory proceedings before regulatory commissions in Arizona, Arkansas, Colorado, Connecticut, Kansas, Massachusetts, Michigan, Minnesota, Missouri, New Jersey, New Mexico, New York, North Dakota, Oklahoma, Pennsylvania, Texas, South Dakota, West Virginia, and the Federal Energy Regulatory Commission. In addition, Ms. Bulkley has prepared and provided supporting analysis for at least forty Federal and State regulatory proceedings. In addition, Ms. Bulkley has worked on acquisition teams with investors seeking to acquire utility assets, providing valuation services including an understanding of regulation, market expected returns, and the assessment of utility risk factors. Ms. Bulkley has assisted clients with valuations of public utility and industrial properties for ratemaking, purchase and sale considerations, ad valorem tax assessments, and accounting and financial purposes. In addition, Ms. Bulkley has experience in the areas of contract and business unit valuation, strategic alliances, market restructuring and regulatory and litigation support. Prior to joining Concentric, Ms. Bulkley held senior expertise-based consulting positions at several firms, including Reed Consulting Group and Navigant Consulting, Inc. where she specialized in valuation. Ms. Bulkley holds an M.A. in economics from Boston University and a B.A. in economics and finance from Simmons College. Ms. Bulkley is a Certified General Appraiser licensed in the Commonwealth of Massachusetts and the State of New Hampshire.

REPRESENTATIVE PROJECT EXPERIENCE

Regulatory Analysis and Ratemaking

Ms. Bulkley has provided a range of advisory services relating to regulatory policy analysis and many aspects of utility ratemaking. Specific services have included: cost of capital and return on equity testimony, cost of service and rate design analysis and testimony, development of ratemaking strategies; development of merchant function exit strategies; analysis and program development to address residual energy supply and/or provider of last resort obligations; stranded costs assessment and recovery; performance-based ratemaking analysis and design; and many aspects of traditional utility ratemaking (e.g., rate design, rate base valuation).

Cost of Capital

Ms. Bulkley has provided expert testimony on the cost of capital in more than 30 regulatory proceedings before regulatory commissions in Arizona, Arkansas, Colorado, Connecticut, Kansas,

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Massachusetts, Michigan, Minnesota, Missouri, New Jersey, New Mexico, New York, North Dakota, Oklahoma, Pennsylvania, Texas, South Dakota, West Virginia, and the Federal Energy Regulatory Commission. In addition, Ms. Bulkley has prepared and provided supporting analysis for at least forty Federal and State regulatory proceedings in which she did not testify.

Valuation

Ms. Bulkley has provided valuation services to utility clients, unregulated generators and private equity clients for a variety of purposes including ratemaking, fair value, ad valorem tax, litigation and damages, and acquisition. Ms. Bulkley’s appraisal practices are consistent with the national standards established by the Uniform Standards of Professional Appraisal Practice. In addition, Ms. Bulkley has relied on other simulation based valuation methodologies.

Representative projects/clients have included:

• Northern Indiana Fuel and Light: Provided expert testimony regarding the fair value of the company’s natural gas distribution system assets. Valuation relied on cost approach.

• Kokomo Gas: Provided expert testimony regarding the fair value of the company’s natural gas distribution system assets. Valuation relied on cost approach.

• Prepared fair value rate base analyses for Northern Indiana Public Service Company for several electric rate proceedings. Valuation approaches used in this project included income, cost and comparable sales approaches.

• Confidential Utility Client: Prepared valuation of fossil and nuclear generation assets for financing purposes for regulated utility client.

• Prepared a valuation of a portfolio of generation assets for a large energy utility to be used for strategic planning purposes. Valuation approach included an income approach, a real options analysis and a risk analysis.

• Assisted clients in the restructuring of NUG contracts through the valuation of the underlying assets. Performed analysis to determine the option value of a plant in a competitively priced electricity market following the settlement of the NUG contract.

• Prepared market valuations of several purchase power contracts for large electric utilities in the sale of purchase power contracts. Assignment included an assessment of the regional power market, analysis of the underlying purchase power contracts, a traditional discounted cash flow valuation approach, as well as a risk analysis. Analyzed bids from potential acquirers using income and risk analysis approached. Prepared an assessment of the credit issues and value at risk for the selling utility.

• Prepared appraisal of a portfolio of generating facilities for a large electric utility to be used for financing purposes.

• Prepared an appraisal of a fleet of fossil generating assets for a large electric utility to establish the value of assets transferred from utility property.

• Conducted due diligence on an electric transmission and distribution system as part of a buy-side due diligence team.

• Provided analytical support for and prepared appraisal reports of generation assets to be used in ad valorem tax disputes.

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Concentric Energy Advisors | Pg. 3

• Provided analytical support and prepared testimony regarding the valuation of electric distribution system assets in five communities in a condemnation proceeding.

• Valued purchase power agreements in the transfer of assets to a deregulated electric market.

Ratemaking

Ms. Bulkley has assisted several clients with analysis to support investor-owned and municipal utility clients in the preparation of rate cases. Sample engagements include:

• Assisted several investor-owned and municipal clients on cost allocation and rate design issues including the development of expert testimony supporting recommended rate alternatives.

• Worked with Canadian regulatory staff to establish filing requirements for a rate review of a newly regulated electric utility. Analyzed and evaluated rate application. Attended hearings and conducted investigation of rate application for regulatory staff. Prepared, supported and defended recommendations for revenue requirements and rates for the company. Developed rates for gas utility for transportation program and ancillary services.

Strategic and Financial Advisory Services

Ms. Bulkley has assisted several clients across North America with analytically based strategic planning, due diligence and financial advisory services.

Representative projects include:

• Preparation of feasibility studies for bond issuances for municipal and district steam clients.

• Assisted in the development of a generation strategy for an electric utility. Analyzed various NERC regions to identify potential market entry points. Evaluated potential competitors and alliance partners. Assisted in the development of gas and electric price forecasts. Developed a framework for the implementation of a risk management program.

• Assisted clients in identifying potential joint venture opportunities and alliance partners. Contacted interviewed, and evaluated potential alliance candidates based on company-established criteria for several LDCs and marketing companies. Worked with several LDCs and unregulated marketing companies to establish alliances to enter into the retail energy market. Prepared testimony in support of several merger cases and participated in the regulatory process to obtain approval for these mergers.

• Assisted clients in several buy-side due diligence efforts, providing regulatory insight and developing valuation recommendations for acquisitions of both electric and gas properties.

PROFESSIONAL HISTORY

Concentric Energy Advisors, Inc. (2002 – Present) Senior Vice President Vice President Assistant Vice President Project Manager

Docket No. 30013-351-GR-19 Exhibit No.___(AEB-2)

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Concentric Energy Advisors | Pg. 4

Navigant Consulting, Inc. (1995 – 2002) Project Manager Cahners Publishing Company (1995) Economist

EDUCATION

M.A., Economics, Boston University, 1995

B.A., Economics and Finance, Simmons College, 1991

Certified General Appraiser licensed in the Commonwealth of Massachusetts and the States of Michigan and New Hampshire

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SPONSOR DATE CASE/APPLICANT DOCKET /CASE NO. SUBJECT Arizona Corporation Commission

Tucson Electric Power Company

04/19 Tucson Electric Power Company Docket No. E-01933A-19-0028 Return on Equity

Tucson Electric Power Company

11/15 Tucson Electric Power Company Docket No. E-01933A-15-0322 Return on Equity

UNS Electric 05/15 UNS Electric Docket No. E-04204A-15-0142 Return on Equity UNS Electric 12/12 UNS Electric Docket No. E-04204A-12-0504 Return on Equity Arkansas Public Service Commission

Arkansas Oklahoma Gas Corporation

10/13 Arkansas Oklahoma Gas Corporation Docket No. 13-078-U Return on Equity

Colorado Public Utilities Commission

Public Service Company of Colorado

01/19 Public Service Company of Colorado 19AL-0063ST Return on Equity

Atmos Energy Corporation

05/15 Atmos Energy Corporation Docket No. 15AL-0299G Return on Equity

Atmos Energy Corporation

04/14 Atmos Energy Corporation Docket No. 14AL-0300G Return on Equity

Atmos Energy Corporation

05/13 Atmos Energy Corporation Docket No. 13AL-0496G Return on Equity

Connecticut Public Utilities Regulatory Authority

Connecticut Natural Gas Corporation

06/18 Connecticut Natural Gas Corporation Docket No. 18-05-16 Return on Equity

Yankee Gas Services Co. d/b/a Eversource Energy

06/18 Yankee Gas Services Co. d/b/a Eversource Energy

Docket No. 18-05-10 Return on Equity

The Southern Connecticut Gas Company

06/17 The Southern Connecticut Gas Company

Docket No. 17-05-42 Return on Equity

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SPONSOR DATE CASE/APPLICANT DOCKET /CASE NO. SUBJECT The United Illuminating Company

07/16 The United Illuminating Company Docket No. 16-06-04 Return on Equity

Federal Energy Regulatory Commission

Sea Robin Pipeline Company LLC

11/18 Sea Robin Pipeline Company LLC Docket# RP19-___-000 Return on Equity

Tallgrass Interstate Gas Transmission

10/15 Tallgrass Interstate Gas Transmission RP16-137 Return on Equity

Indiana Utility Regulatory Commission

Indiana and Michigan American Water Company

09/18 Indiana and Michigan American Water Company

IURC Cause No. 45142 Return on Equity

Northern Indiana Public Service Company

09/17 Northern Indiana Public Service Company

Cause No. 44988 Fair Value

Indianapolis Power and Light Company

12/16 Indianapolis Power and Light Company Cause No.44893 Fair Value

Northern Indiana Public Service Company

10/15 Northern Indiana Public Service Company

Cause No. 44688 Fair Value

Indianapolis Power and Light Company

09/15 Indianapolis Power and Light Company Cause No. 44576 Cause No. 44602

Fair Value

Kokomo Gas and Fuel Company

09/10 Kokomo Gas and Fuel Company Cause No. 43942 Fair Value

Northern Indiana Fuel and Light Company, Inc.

09/10 Northern Indiana Fuel and Light Company, Inc.

Cause No. 43943 Fair Value

Kansas Corporation Commission Atmos Energy Corporation

08/15 Atmos Energy Corporation Docket No. 16-ATMG-079-RTS Return on Equity

Kentucky Public Service Commission Kentucky American Water Company

11/18 Kentucky American Water Company Docket No. 2018-00358 Return on Equity

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SPONSOR DATE CASE/APPLICANT DOCKET /CASE NO. SUBJECT Maine Public Utilities Commission

Central Maine Power 10/18 Central Maine Power Docket No. 2018-00194 Return on Equity

Maryland Public Service Commission

Maryland American Water Company

06/18 Maryland American Water Company Case No. 9487 Return on Equity

Massachusetts Appellate Tax Board

FirstLight Hydro Generating Company

06/17 FirstLight Hydro Generating Company Docket No. F-325471 Docket No. F-325472 Docket No. F-325473 Docket No. F-325474

Valuation of Electric Generation Assets

Massachusetts Department of Public Utilities Berkshire Gas Company 05/18 Berkshire Gas Company DPU 18-40 Rate Case Unitil Corporation 01/04 Fitchburg Gas and Electric DTE 03-52 Integrated Resource Plan; Gas

Demand Forecast Michigan Public Service Commission Wisconsin Electric Power Company

12/11 Wisconsin Electric Power Company Case No. U-16830 Return on Equity

Michigan Tax Tribunal New Covert Generating Co., LLC.

03/18 The Township of New Covert Michigan MTT Docket No. 000248TT and 16-001888-TT

Valuation of Electric Generation Assets

Covert Township 07/14 New Covert Generating Co., LLC. Docket No. 399578 Valuation of Electric Generation Assets

Minnesota Public Utilities Commission

Minnesota Energy Resources Corporation

10/17 Minnesota Energy Resources Corporation

Docket No. G011/GR-17-563 Return on Equity

Missouri Public Service Commission

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SPONSOR DATE CASE/APPLICANT DOCKET /CASE NO. SUBJECT Missouri American Water Company

06/17 Missouri American Water Company Case No. WR-17-2085 Case No. SR-17-2086

Return on Equity

Montana Public Service Commission

Montana-Dakota Utilities Co.

09/18 Montana-Dakota Utilities Co. D0218.9.60 Return on Equity

New Hampshire-Merrimack County Superior Court

Northern New England Telephone Operations, LLC d/b/a FairPoint Communications, NNE

04/18 Northern New England Telephone Operations, LLC d/b/a FairPoint Communications, NNE

220-2012-CV-1100 Valuation of Utility Property

New Hampshire-Rockingham Superior Court

Eversource Energy 05/18 Public Service Commission of New Hampshire

218-2016-CV-00899 218-2017-CV-00917

Valuation of Utility Property

New Jersey Board of Public Utilities

Public Service Electric and Gas Company

04/19 Public Service Electric and Gas Company EO18060629 GO18060630

Return on Equity

Public Service Electric and Gas Company

02/18 Public Service Electric and Gas Company GR17070776 Return on Equity

Public Service Electric and Gas Company

01/18 Public Service Electric and Gas Company ER18010029 GR18010030

Return on Equity

New Mexico Public Regulation Commission

Southwestern Public Service Company

10/17 Southwestern Public Service Company Case No. 17-00255-UT Return on Equity

Southwestern Public Service Company

12/16 Southwestern Public Service Company Case No. 16-00269-UT Return on Equity

Southwestern Public Service Company

10/15 Southwestern Public Service Company Case No. 15-00296-UT Return on Equity

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SPONSOR DATE CASE/APPLICANT DOCKET /CASE NO. SUBJECT Southwestern Public Service Company

06/15 Southwestern Public Service Company Case No. 15-001398-UT Return on Equity

New York State Department of Public Service Central Hudson Gas and Electric Corporation

07/17 Central Hudson Gas and Electric Corporation

Gas 17-G-0460 Electric 17-E-0459

Return on Equity

Niagara Mohawk Power Corporation

04/17 National Grid USA Case No. C-17-E-0238 Return on Equity

Corning Natural Gas Corporation

06/16 Corning Natural Gas Corporation Case No. 16-G-0369 Return on Equity

National Fuel Gas Company

04/16 National Fuel Gas Company Case No. 16-G-0257 Return on Equity

KeySpan Energy Delivery 01/16 KeySpan Energy Delivery Case No. 15-G-0059 Return on Equity New York State Electric and Gas Company

05/15 New York State Electric and Gas Company

Case No. 15-G-0284 Return on Equity

North Dakota Public Service Commission Northern States Power Company

12/12 Northern States Power Company C-PU-12-813 Return on Equity

Northern States Power Company

12/10 Northern States Power Company C-PU-10-657 Return on Equity

Oklahoma Corporation Commission Arkansas Oklahoma Gas Corporation

01/13 Arkansas Oklahoma Gas Corporation Cause No. PUD 201200236 Return on Equity

Pennsylvania Public Utility Commission American Water Works Company Inc.

04/17 Pennsylvania-American Water Company Docket No. R-2017-2595853 Return on Equity

South Dakota Public Utilities Commission Northern States Power Company

06/14 Northern States Power Company Docket No. EL14-058 Return on Equity

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Texas Public Utility Commission Southwestern Public Service Company

01/14 Southwestern Public Service Company Docket No. 42004 Return on Equity

Virginia State Corporation Commission Virginia American Water Company, Inc.

11/18 Virginia American Water Company, Inc. Docket No. PUR-2018-00175 Return on Equity

Washington Utilities Transportation Commission Cascade Natural Gas Corporation

04/19 Cascade Natural Gas Corporation Docket NO. UG-19___ Return on Equity

West Virginia Public Service Commission West Virginia American Water Company

04/18 West Virginia American Water Company Case No. 18-0573-W-42T Case No. 18-0576-S-42T

Return on Equity

Wisconsin Public Service Commission Wisconsin Electric Power Company and Wisconsin Gas LLC

03/19 Wisconsin Electric Power Company and Wisconsin Gas LLC

Docket No. 05-UR-109 Return on Equity

Wisconsin Public Service Corporation

03/19 Wisconsin Public Service Corporation 6690-UR-126 Return on Equity

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 2Page 1 of 1

Median Low Median Median High30-Day Average 8.67% 9.30% 11.12%90-Day Average 8.63% 9.10% 11.21%

180-Day Average 8.78% 9.16% 11.22%Constant Growth Average 8.70% 9.18% 11.18%

Current 30-day Average Treasury

Bond Yield

Near-Term Blue Chip Forecast

Yield

Long-Term Blue Chip Forecast

YieldBloomberg Beta 10.57% 10.62% 10.84%Value Line Beta 10.41% 10.46% 10.69%

Current 30-day Average Treasury

Bond Yield

Near-Term Blue Chip Forecast

Yield

Long-Term Blue Chip Forecast

Yield

Risk Premium Analysis 9.72% 9.80% 10.13%Risk Premium Mean Result

MedianExpected Earnings Result 10.66%

Notes:

Mean11.04%

[1] The analytical results included in the table reflect the results of the Constant Growth DCF analysis excluding the results for individual companies that did not meet the minimum threshold of 7 percent.

SUMMARY OF ROE ANALYSES RESULTS

Constant Growth DCF

CAPM

Treasury Yield Plus Risk Premium

9.88%Expected Earnings Analysis

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 3Page 1 of 1

[1] [2] [3] [4] [5] [6] [7]

Company Dividends

S&P Credit Rating

Between BBB- and AAA

Covered by More Than 1

Analyst

Postive Growth Rates from at least two sources (Value Line, Yahoo! First Call, and Zacks)

% Regulated Operating

Income > 70%

% Regulated Natural Gas Operating

Income > 60%Announced

MergerAtmos Energy Corporation ATO YES A Yes Yes 100.00% 68.59% NoNew Jersey Resources Corporation NJR YES BBB+ Yes Yes 96.45% 88.91% NoNorthwest Natural Gas Company NWN YES A+ Yes Yes 99.50% 96.47% NoOne Gas Inc. OGS YES A Yes Yes 100.00% 100.00% NoSouth Jersey Industries, Inc. SJI YES BBB Yes Yes 80.31% 100.00% NoSouthwest Gas Corporation SWX YES BBB+ Yes Yes 82.19% 100.00% NoSpire Inc. SR YES A- Yes Yes 99.77% 100.00% No

Notes:[1] Source: SNL Financial[2] Source: SNL Financial[3] Source: Yahoo! Finance and Zacks[4] Source: Yahoo! Finance, Value Line Investment Survey, and Zacks[5] to [6] Source: Form 10-Ks for 2017, 2016 & 2015[7] SNL Financial News Releases

PROXY GROUP SCREENING DATA AND RESULTS - FINAL PROXY GROUP

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 4Page 1 of 3

30-DAY CONSTANT GROWTH DCF -- MDU WYOMING PROXY GROUP

[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14]

CompanyAnnualized Dividend Stock Price

Dividend Yield

Expected Dividend

Yield

Value Line Earnings Growth

Yahoo! Finance Earnings Growth

Zacks Earnings Growth

Average Growth

Low Growth Rate ROE

Mean Growth

Rate ROEHigh Growth Rate ROE ##

Low Growth

Rate ROEMean Growth

Rate ROE

High Growth

Rate ROE

Atmos Energy Corporation ATO $2.10 $100.49 2.09% 2.16% 7.50% 6.40% 6.50% 6.80% 8.56% 8.96% 9.67% 8.56% 8.96% 9.67%New Jersey Resources Corporation NJR $1.17 $49.10 2.38% 2.44% 2.50% 6.00% 7.00% 5.17% 4.91% 7.61% 9.47% 7.61% 9.47%Northwest Natural Gas Company NWN $1.90 $64.88 2.93% 3.09% 25.50% 4.00% 4.30% 11.27% 6.99% 14.36% 28.80% 14.36% 28.80%One Gas Inc. OGS $2.00 $87.59 2.28% 2.36% 9.00% 5.00% 5.90% 6.63% 7.34% 8.99% 11.39% 7.34% 8.99% 11.39%South Jersey Industries, Inc. SJI $1.15 $31.08 3.70% 3.84% 9.50% 5.90% 7.20% 7.53% 9.71% 11.37% 13.38% 9.71% 11.37% 13.38%Southwest Gas Corporation SWX $2.08 $82.75 2.51% 2.60% 8.50% 6.30% 6.20% 7.00% 8.79% 9.60% 11.12% 8.79% 9.60% 11.12%Spire, Inc. SR $2.37 $79.78 2.97% 3.03% 5.50% 2.42% 3.90% 3.94% 5.43% 6.97% 8.55% 8.55%

MEDIAN 2.51% 2.60% 8.50% 5.90% 6.20% 6.80% 7.34% 8.99% 11.12% 8.67% 9.30% 11.12%

Notes[1] Source: Bloomberg Professional[2] Source: Bloomberg Professional, equals 30-day average as of March 29, 2019[3] Equals [1] / [2][4] Equals [3] x (1 + 0.50 x [8])[5] Source: Value Line Investment Survey[6] Source: Yahoo! Finance[7] Source: Zacks[8] Equals Average ([5], [6], [7])[9] Equals [3] x (1 + 0.50 x Minimum ([5], [6], [7]) + Minimum ([5], [6], [7])[10] Equals [4] + [8][11] Equals [3] x (1 + 0.50 x Maximum ([5], [6], [7]) + Maximum ([5], [6], [7])[12] Equals [9] if greater than 7.00%[13] Equals [10] if greater than 7.00%[14] Equals [11] if greater than 7.00%

All Proxy Group With Exclusions

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 4Page 2 of 3

90-DAY CONSTANT GROWTH DCF -- MDU WYOMING PROXY GROUP

[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14]

CompanyAnnualized Dividend Stock Price

Dividend Yield

Expected Dividend

Yield

Value Line Earnings Growth

Yahoo! Finance Earnings Growth

Zacks Earnings Growth

Average Growth

Low Growth Rate ROE

Mean Growth

Rate ROEHigh Growth Rate ROE ##

Low Growth

Rate ROEMean Growth

Rate ROE

High Growth

Rate ROE

Atmos Energy Corporation ATO $2.10 $97.06 2.16% 2.24% 7.50% 6.40% 6.50% 6.80% 8.63% 9.04% 9.74% 8.63% 9.04% 9.74%New Jersey Resources Corporation NJR $1.17 $47.80 2.45% 2.51% 2.50% 6.00% 7.00% 5.17% 4.98% 7.68% 9.53% 7.68% 9.53%Northwest Natural Gas Company NWN $1.90 $63.56 2.99% 3.16% 25.50% 4.00% 4.30% 11.27% 7.05% 14.42% 28.87% 7.05% 14.42% 28.87%One Gas, Inc. OGS $2.00 $83.88 2.38% 2.46% 9.00% 5.00% 5.90% 6.63% 7.44% 9.10% 11.49% 7.44% 9.10% 11.49%South Jersey Industries, Inc. SJI $1.15 $30.23 3.80% 3.95% 9.50% 5.90% 7.20% 7.53% 9.82% 11.48% 13.48% 9.82% 11.48% 13.48%Southwest Gas Corporation SWX $2.08 $80.00 2.60% 2.69% 8.50% 6.30% 6.20% 7.00% 8.88% 9.69% 11.21% 8.88% 9.69% 11.21%Spire, Inc. SR $2.37 $77.82 3.05% 3.11% 5.50% 2.42% 3.90% 3.94% 5.50% 7.05% 8.63% 7.05% 8.63%

MEDIAN 2.60% 2.69% 8.50% 5.90% 6.20% 6.80% 7.44% 9.10% 11.21% 8.63% 9.10% 11.21%

Notes[1] Source: Bloomberg Professional[2] Source: Bloomberg Professional, equals 90-day average as of March 29, 2019[3] Equals [1] / [2][4] Equals [3] x (1 + 0.50 x [8])[5] Source: Value Line Investment Survey[6] Source: Yahoo! Finance[7] Source: Zacks[8] Equals Average ([5], [6], [7])[9] Equals [3] x (1 + 0.50 x Minimum ([5], [6], [7]) + Minimum ([5], [6], [7])[10] Equals [4] + [8][11] Equals [3] x (1 + 0.50 x Maximum ([5], [6], [7]) + Maximum ([5], [6], [7])[12] Equals [9] if greater than 7.00%[13] Equals [10] if greater than 7.00%[14] Equals [11] if greater than 7.00%

With ExclusionsAll Proxy Group

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 4Page 3 of 3

180-DAY CONSTANT GROWTH DCF -- MDU WYOMING PROXY GROUP

[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14]

CompanyAnnualized Dividend Stock Price

Dividend Yield

Expected Dividend

Yield

Value Line Earnings Growth

Yahoo! Finance Earnings Growth

Zacks Earnings Growth

Average Growth

Low Growth Rate ROE

Mean Growth

Rate ROEHigh Growth Rate ROE ##

Low Growth

Rate ROEMean Growth

Rate ROE

High Growth

Rate ROE

Atmos Energy Corporation ATO $2.10 $95.24 2.21% 2.28% 7.50% 6.40% 6.50% 6.80% 8.68% 9.08% 9.79% 8.68% 9.08% 9.79%New Jersey Resources Corporation NJR $1.17 $46.96 2.49% 2.56% 2.50% 6.00% 7.00% 5.17% 5.02% 7.72% 9.58% 7.72% 9.58%Northwest Natural Gas Company NWN $1.90 $64.96 2.92% 3.09% 25.50% 4.00% 4.30% 11.27% 6.98% 14.36% 28.80% 14.36% 28.80%One Gas, Inc. OGS $2.00 $81.78 2.45% 2.53% 9.00% 5.00% 5.90% 6.63% 7.51% 9.16% 11.56% 7.51% 9.16% 11.56%South Jersey Industries, Inc. SJI $1.15 $31.88 3.61% 3.74% 9.50% 5.90% 7.20% 7.53% 9.61% 11.28% 13.28% 9.61% 11.28% 13.28%Southwest Gas Corporation SWX $2.08 $79.79 2.61% 2.70% 8.50% 6.30% 6.20% 7.00% 8.89% 9.70% 11.22% 8.89% 9.70% 11.22%Spire, Inc. SR $2.37 $75.93 3.12% 3.18% 5.50% 2.42% 3.90% 3.94% 5.58% 7.12% 8.71% 7.12% 8.71%

MEDIAN 2.61% 2.70% 8.50% 5.90% 6.20% 6.80% 7.51% 9.16% 11.22% 8.78% 9.16% 11.22%

Notes[1] Source: Bloomberg Professional[2] Source: Bloomberg Professional, equals 180-day average as of March 29, 2019[3] Equals [1] / [2][4] Equals [3] x (1 + 0.50 x [8])[5] Source: Value Line Investment Survey[6] Source: Yahoo! Finance[7] Source: Zacks[8] Equals Average ([5], [6], [7])[9] Equals [3] x (1 + 0.50 x Minimum ([5], [6], [7]) + Minimum ([5], [6], [7])[10] Equals [4] + [8][11] Equals [3] x (1 + 0.50 x Maximum ([5], [6], [7]) + Maximum ([5], [6], [7])[12] Equals [9] if greater than 7.00%[13] Equals [10] if greater than 7.00%[14] Equals [11] if greater than 7.00%

All Proxy Group With Exclusions

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 5Page 1 of 1

[1] [2]Proxy Group Ticker Bloomberg Value Line

Atmos Energy Corporation ATO 0.698 0.600New Jersey Resources Corporation NJR 0.723 0.700Northwest Natural Gas Company NWN 0.700 0.650ONE Gas, Inc. OGS 0.641 0.650South Jersey Industries, Inc. SJI 0.749 0.850Southwest Gas Corporation SWX 0.753 0.700Spire, Inc. SR 0.644 0.650

MEAN 0.701 0.686

Notes:[1] Source: Bloomberg Professional, March 29, 2019[2] Source: Value Line; March 1, 2019

BETAAS OF MARCH 29, 2019

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 6Page 1 of 9

[4] [5] [6] [7] [8]Market

Risk-Free Market RiskRate Beta Return Premium ROE(Rf) (β) (Rm) (Rm − Rf) (K)

Proxy Group Average Bloomberg BetaCurrent 30-day average of 30-year U.S. Treasury bond yield [1] 2.99% 0.701 13.80% 10.81% 10.57%Near-term projected 30-year U.S. Treasury bond yield (Q3 2019 - Q3 2020) [2] 3.16% 0.701 13.80% 10.64% 10.62%Projected 30-year U.S. Treasury bond yield (2020 - 2024) [3] 3.90% 0.701 13.80% 9.90% 10.84%

MEAN 10.68%

Proxy Group Average Value Line BetaCurrent 30-day average of 30-year U.S. Treasury bond yield [1] 2.99% 0.686 13.80% 10.81% 10.41%Near-term projected 30-year U.S. Treasury bond yield (Q3 2019 - Q3 2020) [2] 3.16% 0.686 13.80% 10.64% 10.46%Projected 30-year U.S. Treasury bond yield (2020 - 2024) [3] 3.90% 0.686 13.80% 9.90% 10.69%

MEAN 10.52%

Notes:[1] Source: Bloomberg Professional, 30-day average as of March 29, 2019[2] Source: Blue Chip Financial Forecasts, Vol. 38, No. 4, April 1, 2019, at 2[3] Source: Blue Chip Financial Forecasts, Vol. 37, No. 12, December 1, 2018, at 14[4] See Notes [1], [2] and [3][5] Source: Schedule-5[6] Source: Schedule-6, p.2[7] Equals [6] - [4][8] Equals [4] + ([5] x [7])

CAPITAL ASSET PRICING MODEL

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 6Page 2 of 9

[9] Estimated Weighted Average Dividend Yield

[10] Estimated Weighted Average Long-Term Growth Rate

[11] S&P 500 Estimated Required Market Return

[12] Risk-Free Rate 2.99% 3.16% 3.90%

[13] Implied Market Risk Premium 10.81% 10.64% 9.90%

STANDARD AND POOR'S 500 INDEX

[14] [15] [16] [17] [18]Cap-Weighted

Weight in Estimated Cap-Weighted Long-Term Long-TermName Ticker Index Dividend Yield Dividend Yield Growth Est. Growth Est.

LyondellBasell Industries NV LYB 0.13% 4.76% 0.01% 6.80% 0.01%American Express Co AXP 0.37% 1.43% 0.01% 12.95% 0.05%Verizon Communications Inc VZ 1.00% 4.08% 0.04% 2.30% 0.02%Broadcom Inc AVGO 0.49% 3.53% 0.02% 14.11% 0.07%Boeing Co/The BA 0.88% 2.16% 0.02% 15.15% 0.13%Caterpillar Inc CAT 0.32% 2.54% 0.01% 13.35% 0.04%JPMorgan Chase & Co JPM 1.35% 3.16% 0.04% 6.77% 0.09%Chevron Corp CVX 0.95% 3.86% 0.04% 2.03% 0.02%Coca-Cola Co/The KO 0.82% 3.41% 0.03% 6.22% 0.05%AbbVie Inc ABBV 0.49% 5.31% 0.03% 5.21% 0.03%Walt Disney Co/The DIS 0.81% 1.59% 0.01% 6.92% 0.06%FleetCor Technologies Inc FLT 0.09% n/a n/a 16.50% 0.01%Extra Space Storage Inc EXR 0.05% 3.38% 0.00% 5.28% 0.00%Exxon Mobil Corp XOM 1.40% 4.06% 0.06% 15.81% 0.22%Phillips 66 PSX 0.18% 3.36% 0.01% -10.13% -0.02%General Electric Co GE 0.35% 0.40% 0.00% 8.87% 0.03%HP Inc HPQ 0.12% 3.30% 0.00% 3.08% 0.00%Home Depot Inc/The HD 0.86% 2.84% 0.02% 10.72% 0.09%International Business Machines Corp IBM 0.51% 4.45% 0.02% 0.72% 0.00%Concho Resources Inc CXO 0.09% 0.45% 0.00% 18.60% 0.02%Johnson & Johnson JNJ 1.52% 2.58% 0.04% 7.34% 0.11%McDonald's Corp MCD 0.59% 2.44% 0.01% 8.47% 0.05%Merck & Co Inc MRK 0.88% 2.65% 0.02% 8.70% 0.08%3M Co MMM 0.49% 2.77% 0.01% 7.70% 0.04%American Water Works Co Inc AWK 0.08% 1.75% 0.00% 8.72% 0.01%Bank of America Corp BAC 1.08% 2.17% 0.02% 9.45% 0.10%Brighthouse Financial Inc BHF 0.02% n/a n/a 11.56% 0.00%Baker Hughes a GE Co BHGE 0.06% 2.60% 0.00% 40.82% 0.02%Pfizer Inc PFE 0.96% 3.39% 0.03% 4.95% 0.05%Procter & Gamble Co/The PG 1.06% 2.76% 0.03% 6.51% 0.07%AT&T Inc T 0.93% 6.51% 0.06% 4.92% 0.05%Travelers Cos Inc/The TRV 0.15% 2.25% 0.00% 17.72% 0.03%United Technologies Corp UTX 0.45% 2.28% 0.01% 9.80% 0.04%Analog Devices Inc ADI 0.16% 2.05% 0.00% 11.98% 0.02%Walmart Inc WMT 1.14% 2.17% 0.02% 3.57% 0.04%Cisco Systems Inc CSCO 0.97% 2.59% 0.03% 6.84% 0.07%Intel Corp INTC 0.98% 2.35% 0.02% 8.54% 0.08%General Motors Co GM 0.21% 4.10% 0.01% 6.03% 0.01%Microsoft Corp MSFT 3.69% 1.56% 0.06% 11.68% 0.43%Dollar General Corp DG 0.13% 1.07% 0.00% 12.85% 0.02%Cigna Corp CI 0.25% 0.02% 0.00% 11.25% 0.03%Kinder Morgan Inc/DE KMI 0.18% 4.00% 0.01% 85.80% 0.16%Citigroup Inc C 0.59% 2.89% 0.02% 11.23% 0.07%American International Group Inc AIG 0.15% 2.97% 0.00% 11.00% 0.02%Honeywell International Inc HON 0.47% 2.06% 0.01% 7.88% 0.04%Altria Group Inc MO 0.44% 5.57% 0.02% 5.57% 0.02%HCA Healthcare Inc HCA 0.18% 1.23% 0.00% 11.56% 0.02%Under Armour Inc UAA 0.02% n/a n/a 34.85% 0.01%International Paper Co IP 0.08% 4.32% 0.00% 6.08% 0.00%Hewlett Packard Enterprise Co HPE 0.09% 2.92% 0.00% 6.09% 0.01%Abbott Laboratories ABT 0.57% 1.60% 0.01% 11.06% 0.06%Aflac Inc AFL 0.15% 2.16% 0.00% 3.43% 0.01%Air Products & Chemicals Inc APD 0.17% 2.43% 0.00% 12.30% 0.02%Royal Caribbean Cruises Ltd RCL 0.10% 2.44% 0.00% 11.72% 0.01%American Electric Power Co Inc AEP 0.17% 3.20% 0.01% 6.05% 0.01%

MARKET RISK PREMIUM DERIVED FROM ANALYSTS LONG-TERM GROWTH ESTIMATES

2.00%

11.69%

13.80%

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 6Page 3 of 9

STANDARD AND POOR'S 500 INDEX

[14] [15] [16] [17] [18]Cap-Weighted

Weight in Estimated Cap-Weighted Long-Term Long-TermName Ticker Index Dividend Yield Dividend Yield Growth Est. Growth Est.

Hess Corp HES 0.07% 1.66% 0.00% -9.23% -0.01%Anadarko Petroleum Corp APC 0.09% 2.64% 0.00% 19.98% 0.02%Aon PLC AON 0.17% 0.94% 0.00% 10.57% 0.02%Apache Corp APA 0.05% 2.89% 0.00% -5.19% 0.00%Archer-Daniels-Midland Co ADM 0.10% 3.25% 0.00% 1.40% 0.00%Automatic Data Processing Inc ADP 0.28% 1.98% 0.01% 16.00% 0.05%Verisk Analytics Inc VRSK 0.09% 0.75% 0.00% 9.57% 0.01%AutoZone Inc AZO 0.10% n/a n/a 13.45% 0.01%Avery Dennison Corp AVY 0.04% 1.84% 0.00% 5.75% 0.00%MSCI Inc MSCI 0.07% 1.17% 0.00% 9.25% 0.01%Ball Corp BLL 0.08% 0.69% 0.00% 6.50% 0.01%Bank of New York Mellon Corp/The BK 0.20% 2.22% 0.00% 7.33% 0.01%Baxter International Inc BAX 0.17% 0.93% 0.00% 11.62% 0.02%Becton Dickinson and Co BDX 0.27% 1.23% 0.00% 14.11% 0.04%Berkshire Hathaway Inc BRK/B 1.12% n/a n/a -1.60% -0.02%Best Buy Co Inc BBY 0.08% 2.81% 0.00% 6.81% 0.01%H&R Block Inc HRB 0.02% 4.18% 0.00% 10.00% 0.00%Boston Scientific Corp BSX 0.22% n/a n/a 9.62% 0.02%Bristol-Myers Squibb Co BMY 0.32% 3.44% 0.01% 8.52% 0.03%Fortune Brands Home & Security Inc FBHS 0.03% 1.85% 0.00% 9.97% 0.00%Brown-Forman Corp BF/B 0.07% 1.26% 0.00% 9.52% 0.01%Cabot Oil & Gas Corp COG 0.05% 1.07% 0.00% 27.91% 0.01%Campbell Soup Co CPB 0.05% 3.67% 0.00% 1.85% 0.00%Kansas City Southern KSU 0.05% 1.24% 0.00% 12.67% 0.01%Hilton Worldwide Holdings Inc HLT 0.10% 0.72% 0.00% 13.26% 0.01%Carnival Corp CCL 0.11% 3.94% 0.00% 10.53% 0.01%Qorvo Inc QRVO 0.04% n/a n/a 11.83% 0.00%CenturyLink Inc CTL 0.05% 8.34% 0.00% 2.50% 0.00%UDR Inc UDR 0.05% 3.01% 0.00% 5.49% 0.00%Clorox Co/The CLX 0.08% 2.39% 0.00% 4.91% 0.00%CMS Energy Corp CMS 0.06% 2.75% 0.00% 6.83% 0.00%Newell Brands Inc NWL 0.03% 6.00% 0.00% -5.93% 0.00%Colgate-Palmolive Co CL 0.24% 2.51% 0.01% 5.59% 0.01%Comerica Inc CMA 0.05% 3.66% 0.00% 13.20% 0.01%IPG Photonics Corp IPGP 0.03% n/a n/a 7.37% 0.00%Conagra Brands Inc CAG 0.05% 3.06% 0.00% 6.60% 0.00%Consolidated Edison Inc ED 0.11% 3.49% 0.00% 4.13% 0.00%SL Green Realty Corp SLG 0.03% 3.78% 0.00% -0.59% 0.00%Corning Inc GLW 0.11% 2.42% 0.00% 10.39% 0.01%Cummins Inc CMI 0.10% 2.89% 0.00% 6.66% 0.01%Danaher Corp DHR 0.39% 0.52% 0.00% 9.01% 0.03%Target Corp TGT 0.17% 3.19% 0.01% 6.44% 0.01%Deere & Co DE 0.21% 1.90% 0.00% 10.39% 0.02%Dominion Energy Inc D 0.25% 4.79% 0.01% 5.44% 0.01%Dover Corp DOV 0.06% 2.05% 0.00% 10.97% 0.01%Alliant Energy Corp LNT 0.05% 3.01% 0.00% 6.29% 0.00%Duke Energy Corp DUK 0.27% 4.12% 0.01% 5.10% 0.01%Regency Centers Corp REG 0.05% 3.47% 0.00% 5.21% 0.00%Eaton Corp PLC ETN 0.14% 3.53% 0.00% 8.98% 0.01%Ecolab Inc ECL 0.21% 1.04% 0.00% 13.43% 0.03%PerkinElmer Inc PKI 0.04% 0.29% 0.00% 13.59% 0.01%Emerson Electric Co EMR 0.17% 2.86% 0.00% 8.95% 0.02%EOG Resources Inc EOG 0.23% 0.92% 0.00% 9.90% 0.02%Entergy Corp ETR 0.07% 3.81% 0.00% -1.22% 0.00%Equifax Inc EFX 0.06% 1.32% 0.00% 7.16% 0.00%IQVIA Holdings Inc IQV 0.12% n/a n/a 17.05% 0.02%Gartner Inc IT 0.06% n/a n/a 14.02% 0.01%FedEx Corp FDX 0.19% 1.43% 0.00% 14.05% 0.03%Macy's Inc M 0.03% 6.28% 0.00% 1.67% 0.00%FMC Corp FMC 0.04% 2.08% 0.00% 9.87% 0.00%Ford Motor Co F 0.14% 6.83% 0.01% -0.70% 0.00%NextEra Energy Inc NEE 0.38% 2.59% 0.01% 4.95% 0.02%Franklin Resources Inc BEN 0.07% 3.14% 0.00% 10.00% 0.01%Freeport-McMoRan Inc FCX 0.08% 1.55% 0.00% -12.55% -0.01%Gap Inc/The GPS 0.04% 3.71% 0.00% 7.90% 0.00%General Dynamics Corp GD 0.20% 2.41% 0.00% 10.09% 0.02%General Mills Inc GIS 0.13% 3.79% 0.00% 6.00% 0.01%Genuine Parts Co GPC 0.07% 2.72% 0.00% 6.34% 0.00%Atmos Energy Corp ATO 0.05% 2.04% 0.00% 6.50% 0.00%

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 6Page 4 of 9

STANDARD AND POOR'S 500 INDEX

[14] [15] [16] [17] [18]Cap-Weighted

Weight in Estimated Cap-Weighted Long-Term Long-TermName Ticker Index Dividend Yield Dividend Yield Growth Est. Growth Est.

WW Grainger Inc GWW 0.07% 1.81% 0.00% 12.47% 0.01%Halliburton Co HAL 0.10% 2.46% 0.00% 30.08% 0.03%Harley-Davidson Inc HOG 0.02% 4.21% 0.00% 8.60% 0.00%Harris Corp HRS 0.08% 1.72% 0.00% 7.00% 0.01%HCP Inc HCP 0.06% 4.73% 0.00% 2.57% 0.00%Helmerich & Payne Inc HP 0.02% 5.11% 0.00% 96.36% 0.02%Fortive Corp FTV 0.11% 0.33% 0.00% 13.89% 0.02%Hershey Co/The HSY 0.07% 2.52% 0.00% 7.20% 0.00%Synchrony Financial SYF 0.09% 2.63% 0.00% 1.55% 0.00%Hormel Foods Corp HRL 0.10% 1.88% 0.00% 5.80% 0.01%Arthur J Gallagher & Co AJG 0.06% 2.20% 0.00% 9.84% 0.01%Mondelez International Inc MDLZ 0.29% 2.08% 0.01% 6.89% 0.02%CenterPoint Energy Inc CNP 0.06% 3.75% 0.00% 6.40% 0.00%Humana Inc HUM 0.15% 0.83% 0.00% 13.93% 0.02%Willis Towers Watson PLC WLTW 0.09% 1.48% 0.00% 13.97% 0.01%Illinois Tool Works Inc ITW 0.19% 2.79% 0.01% 7.27% 0.01%Ingersoll-Rand PLC IR 0.11% 1.96% 0.00% 9.79% 0.01%Foot Locker Inc FL 0.03% 2.51% 0.00% 8.18% 0.00%Interpublic Group of Cos Inc/The IPG 0.03% 4.47% 0.00% 11.49% 0.00%International Flavors & Fragrances Inc IFF 0.06% 2.27% 0.00% 8.00% 0.00%Jacobs Engineering Group Inc JEC 0.04% 0.90% 0.00% 13.96% 0.01%Hanesbrands Inc HBI 0.03% 3.36% 0.00% 3.72% 0.00%Kellogg Co K 0.08% 3.90% 0.00% 3.05% 0.00%Broadridge Financial Solutions Inc BR 0.05% 1.87% 0.00% 10.00% 0.00%Perrigo Co PLC PRGO 0.03% 1.58% 0.00% 0.25% 0.00%Kimberly-Clark Corp KMB 0.17% 3.33% 0.01% 6.09% 0.01%Kimco Realty Corp KIM 0.03% 6.05% 0.00% 3.26% 0.00%Kohl's Corp KSS 0.05% 3.90% 0.00% 9.80% 0.00%Oracle Corp ORCL 0.75% 1.79% 0.01% 7.54% 0.06%Kroger Co/The KR 0.08% 2.28% 0.00% 5.98% 0.00%Leggett & Platt Inc LEG 0.02% 3.60% 0.00% 10.00% 0.00%Lennar Corp LEN 0.06% 0.33% 0.00% 10.32% 0.01%Jefferies Financial Group Inc JEF 0.02% 2.66% 0.00% n/a n/aEli Lilly & Co LLY 0.55% 1.99% 0.01% 12.95% 0.07%L Brands Inc LB 0.03% 4.35% 0.00% 10.72% 0.00%Charter Communications Inc CHTR 0.32% n/a n/a 41.16% 0.13%Lincoln National Corp LNC 0.05% 2.52% 0.00% 9.00% 0.00%Loews Corp L 0.06% 0.52% 0.00% n/a n/aLowe's Cos Inc LOW 0.36% 1.75% 0.01% 16.33% 0.06%Host Hotels & Resorts Inc HST 0.06% 4.23% 0.00% 12.53% 0.01%Marsh & McLennan Cos Inc MMC 0.19% 1.77% 0.00% 12.27% 0.02%Masco Corp MAS 0.05% 1.22% 0.00% 12.50% 0.01%Mattel Inc MAT 0.02% n/a n/a 10.00% 0.00%S&P Global Inc SPGI 0.21% 1.08% 0.00% 9.20% 0.02%Medtronic PLC MDT 0.50% 2.20% 0.01% 7.70% 0.04%CVS Health Corp CVS 0.29% 3.71% 0.01% 7.78% 0.02%DowDuPont Inc DWDP 0.49% 2.85% 0.01% 6.17% 0.03%Micron Technology Inc MU 0.19% n/a n/a -3.70% -0.01%Motorola Solutions Inc MSI 0.09% 1.62% 0.00% 4.10% 0.00%Cboe Global Markets Inc CBOE 0.04% 1.30% 0.00% 13.46% 0.01%Mylan NV MYL 0.06% n/a n/a 4.86% 0.00%Laboratory Corp of America Holdings LH 0.06% n/a n/a 7.08% 0.00%Newmont Mining Corp NEM 0.08% 1.57% 0.00% 5.55% 0.00%NIKE Inc NKE 0.43% 1.05% 0.00% 19.11% 0.08%NiSource Inc NI 0.04% 2.79% 0.00% 5.80% 0.00%Noble Energy Inc NBL 0.05% 1.78% 0.00% 16.07% 0.01%Norfolk Southern Corp NSC 0.20% 1.84% 0.00% 11.68% 0.02%Principal Financial Group Inc PFG 0.06% 4.30% 0.00% 4.16% 0.00%Eversource Energy ES 0.09% 3.02% 0.00% 5.76% 0.01%Northrop Grumman Corp NOC 0.19% 1.78% 0.00% 6.97% 0.01%Wells Fargo & Co WFC 0.89% 3.73% 0.03% 11.26% 0.10%Nucor Corp NUE 0.07% 2.74% 0.00% 0.85% 0.00%PVH Corp PVH 0.04% 0.12% 0.00% 9.65% 0.00%Occidental Petroleum Corp OXY 0.20% 4.71% 0.01% 7.67% 0.02%Omnicom Group Inc OMC 0.07% 3.56% 0.00% 3.78% 0.00%ONEOK Inc OKE 0.12% 4.93% 0.01% 12.82% 0.02%Raymond James Financial Inc RJF 0.05% 1.69% 0.00% 17.00% 0.01%Parker-Hannifin Corp PH 0.09% 1.77% 0.00% 9.52% 0.01%Rollins Inc ROL 0.06% 1.01% 0.00% 10.00% 0.01%

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 6Page 5 of 9

STANDARD AND POOR'S 500 INDEX

[14] [15] [16] [17] [18]Cap-Weighted

Weight in Estimated Cap-Weighted Long-Term Long-TermName Ticker Index Dividend Yield Dividend Yield Growth Est. Growth Est.

PPL Corp PPL 0.09% 5.20% 0.00% 2.37% 0.00%Exelon Corp EXC 0.20% 2.89% 0.01% 3.95% 0.01%ConocoPhillips COP 0.31% 1.83% 0.01% 5.00% 0.02%PulteGroup Inc PHM 0.03% 1.57% 0.00% 7.17% 0.00%Pinnacle West Capital Corp PNW 0.04% 3.09% 0.00% 5.14% 0.00%PNC Financial Services Group Inc/The PNC 0.23% 3.10% 0.01% 7.37% 0.02%PPG Industries Inc PPG 0.11% 1.70% 0.00% 7.49% 0.01%Progressive Corp/The PGR 0.17% 0.55% 0.00% 9.80% 0.02%Public Service Enterprise Group Inc PEG 0.12% 3.16% 0.00% 6.47% 0.01%Raytheon Co RTN 0.21% 2.07% 0.00% 9.37% 0.02%Robert Half International Inc RHI 0.03% 1.90% 0.00% 9.25% 0.00%Edison International EIX 0.08% 3.96% 0.00% 5.51% 0.00%Schlumberger Ltd SLB 0.25% 4.59% 0.01% 33.69% 0.08%Charles Schwab Corp/The SCHW 0.23% 1.59% 0.00% 15.65% 0.04%Sherwin-Williams Co/The SHW 0.16% 1.05% 0.00% 10.99% 0.02%JM Smucker Co/The SJM 0.05% 2.92% 0.00% 3.20% 0.00%Snap-on Inc SNA 0.04% 2.43% 0.00% 7.93% 0.00%AMETEK Inc AME 0.08% 0.67% 0.00% 8.98% 0.01%Southern Co/The SO 0.22% 4.64% 0.01% 3.38% 0.01%BB&T Corp BBT 0.14% 3.48% 0.01% 9.85% 0.01%Southwest Airlines Co LUV 0.12% 1.23% 0.00% 8.64% 0.01%Stanley Black & Decker Inc SWK 0.08% 1.94% 0.00% 10.50% 0.01%Public Storage PSA 0.15% 3.67% 0.01% 5.17% 0.01%Arista Networks Inc ANET 0.10% n/a n/a 21.64% 0.02%SunTrust Banks Inc STI 0.11% 3.38% 0.00% 8.04% 0.01%Sysco Corp SYY 0.14% 2.34% 0.00% 12.83% 0.02%Texas Instruments Inc TXN 0.41% 2.90% 0.01% 10.48% 0.04%Textron Inc TXT 0.05% 0.16% 0.00% 11.26% 0.01%Thermo Fisher Scientific Inc TMO 0.45% 0.28% 0.00% 12.00% 0.05%Tiffany & Co TIF 0.05% 2.08% 0.00% 9.78% 0.01%TJX Cos Inc/The TJX 0.27% 1.73% 0.00% 11.57% 0.03%Torchmark Corp TMK 0.04% 0.84% 0.00% 7.53% 0.00%Total System Services Inc TSS 0.07% 0.55% 0.00% 12.14% 0.01%Johnson Controls International plc JCI 0.14% 2.82% 0.00% 7.63% 0.01%Ulta Beauty Inc ULTA 0.08% n/a n/a 21.20% 0.02%Union Pacific Corp UNP 0.49% 2.11% 0.01% 13.86% 0.07%Keysight Technologies Inc KEYS 0.07% n/a n/a 17.00% 0.01%UnitedHealth Group Inc UNH 0.97% 1.46% 0.01% 13.84% 0.13%Unum Group UNM 0.03% 3.07% 0.00% 9.00% 0.00%Marathon Oil Corp MRO 0.06% 1.20% 0.00% 0.45% 0.00%Varian Medical Systems Inc VAR 0.05% n/a n/a 9.00% 0.00%Ventas Inc VTR 0.09% 4.97% 0.00% 3.83% 0.00%VF Corp VFC 0.14% 2.35% 0.00% -25.52% -0.04%Vornado Realty Trust VNO 0.05% 3.91% 0.00% 0.74% 0.00%Vulcan Materials Co VMC 0.06% 1.05% 0.00% 15.13% 0.01%Weyerhaeuser Co WY 0.08% 5.16% 0.00% 8.70% 0.01%Whirlpool Corp WHR 0.03% 3.46% 0.00% 5.75% 0.00%Williams Cos Inc/The WMB 0.14% 5.29% 0.01% 3.90% 0.01%WEC Energy Group Inc WEC 0.10% 2.98% 0.00% 4.89% 0.00%Xerox Corp XRX 0.03% 3.13% 0.00% -0.10% 0.00%Adobe Inc ADBE 0.53% n/a n/a 17.12% 0.09%AES Corp/VA AES 0.05% 3.02% 0.00% 7.62% 0.00%Amgen Inc AMGN 0.48% 3.05% 0.01% 5.83% 0.03%Apple Inc AAPL 3.65% 1.54% 0.06% 9.40% 0.34%Autodesk Inc ADSK 0.14% n/a n/a 60.74% 0.08%Cintas Corp CTAS 0.09% 1.01% 0.00% 12.12% 0.01%Comcast Corp CMCSA 0.74% 2.10% 0.02% 11.03% 0.08%Molson Coors Brewing Co TAP 0.05% 2.75% 0.00% 0.26% 0.00%KLA-Tencor Corp KLAC 0.08% 2.51% 0.00% 8.58% 0.01%Marriott International Inc/MD MAR 0.17% 1.31% 0.00% 10.81% 0.02%McCormick & Co Inc/MD MKC 0.08% 1.51% 0.00% 6.10% 0.00%Nordstrom Inc JWN 0.03% 3.33% 0.00% 8.25% 0.00%PACCAR Inc PCAR 0.10% 1.88% 0.00% 5.90% 0.01%Costco Wholesale Corp COST 0.43% 0.94% 0.00% 10.09% 0.04%First Republic Bank/CA FRC 0.07% 0.72% 0.00% 12.39% 0.01%Stryker Corp SYK 0.30% 1.05% 0.00% 8.54% 0.03%Tyson Foods Inc TSN 0.08% 2.16% 0.00% n/a n/aLamb Weston Holdings Inc LW 0.04% 1.07% 0.00% 11.02% 0.00%Applied Materials Inc AMAT 0.15% 2.12% 0.00% 9.23% 0.01%

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 6Page 6 of 9

STANDARD AND POOR'S 500 INDEX

[14] [15] [16] [17] [18]Cap-Weighted

Weight in Estimated Cap-Weighted Long-Term Long-TermName Ticker Index Dividend Yield Dividend Yield Growth Est. Growth Est.

American Airlines Group Inc AAL 0.06% 1.26% 0.00% 20.69% 0.01%Cardinal Health Inc CAH 0.06% 3.96% 0.00% 3.02% 0.00%Celgene Corp CELG 0.27% n/a n/a 19.52% 0.05%Cerner Corp CERN 0.08% n/a n/a 12.33% 0.01%Cincinnati Financial Corp CINF 0.06% 2.61% 0.00% n/a n/aDR Horton Inc DHI 0.06% 1.45% 0.00% 13.10% 0.01%Flowserve Corp FLS 0.02% 1.68% 0.00% 13.05% 0.00%Electronic Arts Inc EA 0.12% n/a n/a 11.87% 0.01%Expeditors International of Washington Inc EXPD 0.05% 1.19% 0.00% 7.70% 0.00%Fastenal Co FAST 0.08% 2.67% 0.00% 14.85% 0.01%M&T Bank Corp MTB 0.09% 2.55% 0.00% 7.98% 0.01%Xcel Energy Inc XEL 0.12% 2.88% 0.00% 5.74% 0.01%Fiserv Inc FISV 0.14% n/a n/a 7.40% 0.01%Fifth Third Bancorp FITB 0.08% 3.49% 0.00% 3.95% 0.00%Gilead Sciences Inc GILD 0.34% 3.88% 0.01% 7.61% 0.03%Hasbro Inc HAS 0.04% 3.20% 0.00% 10.85% 0.00%Huntington Bancshares Inc/OH HBAN 0.05% 4.42% 0.00% 8.20% 0.00%Welltower Inc WELL 0.13% 4.48% 0.01% 6.80% 0.01%Biogen Inc BIIB 0.19% n/a n/a 4.66% 0.01%Northern Trust Corp NTRS 0.08% 2.65% 0.00% 10.65% 0.01%Packaging Corp of America PKG 0.04% 3.18% 0.00% 8.25% 0.00%Paychex Inc PAYX 0.12% 2.79% 0.00% 8.77% 0.01%People's United Financial Inc PBCT 0.03% 4.26% 0.00% 2.00% 0.00%QUALCOMM Inc QCOM 0.28% 4.35% 0.01% 11.71% 0.03%Roper Technologies Inc ROP 0.14% 0.54% 0.00% 11.33% 0.02%Ross Stores Inc ROST 0.14% 1.10% 0.00% 10.38% 0.01%IDEXX Laboratories Inc IDXX 0.08% n/a n/a 16.24% 0.01%Starbucks Corp SBUX 0.38% 1.94% 0.01% 13.22% 0.05%KeyCorp KEY 0.06% 4.32% 0.00% 13.17% 0.01%Fox Corp FOXA 0.05% n/a n/a 0.79% 0.00%Fox Corp FOX 0.04% n/a n/a n/a n/aState Street Corp STT 0.10% 2.86% 0.00% 8.69% 0.01%Norwegian Cruise Line Holdings Ltd NCLH 0.05% n/a n/a 11.00% 0.01%US Bancorp USB 0.31% 3.07% 0.01% 6.70% 0.02%AO Smith Corp AOS 0.03% 1.65% 0.00% 9.33% 0.00%Symantec Corp SYMC 0.06% 1.30% 0.00% 7.50% 0.00%T Rowe Price Group Inc TROW 0.10% 3.04% 0.00% 5.40% 0.01%Waste Management Inc WM 0.18% 1.97% 0.00% 7.69% 0.01%CBS Corp CBS 0.07% 1.51% 0.00% 15.05% 0.01%Allergan PLC AGN 0.20% 2.02% 0.00% 5.45% 0.01%Constellation Brands Inc STZ 0.12% 1.69% 0.00% 8.92% 0.01%Xilinx Inc XLNX 0.13% 1.14% 0.00% 12.60% 0.02%DENTSPLY SIRONA Inc XRAY 0.05% 0.71% 0.00% 9.81% 0.00%Zions Bancorp NA ZION 0.03% 2.64% 0.00% 6.78% 0.00%Alaska Air Group Inc ALK 0.03% 2.49% 0.00% 25.37% 0.01%Invesco Ltd IVZ 0.03% 6.21% 0.00% 6.34% 0.00%Linde PLC LIN 0.40% 1.99% 0.01% 18.90% 0.07%Intuit Inc INTU 0.28% 0.72% 0.00% 16.03% 0.04%Morgan Stanley MS 0.29% 2.84% 0.01% 8.99% 0.03%Microchip Technology Inc MCHP 0.08% 1.76% 0.00% 12.39% 0.01%Chubb Ltd CB 0.26% 2.08% 0.01% 10.60% 0.03%Hologic Inc HOLX 0.05% n/a n/a 3.10% 0.00%Citizens Financial Group Inc CFG 0.06% 3.94% 0.00% 16.69% 0.01%O'Reilly Automotive Inc ORLY 0.12% n/a n/a 12.40% 0.02%Allstate Corp/The ALL 0.13% 2.12% 0.00% 9.00% 0.01%FLIR Systems Inc FLIR 0.03% 1.43% 0.00% n/a n/aEquity Residential EQR 0.11% 3.01% 0.00% 6.69% 0.01%BorgWarner Inc BWA 0.03% 1.77% 0.00% 4.54% 0.00%Incyte Corp INCY 0.08% n/a n/a 44.43% 0.03%Simon Property Group Inc SPG 0.23% 4.50% 0.01% 5.23% 0.01%Eastman Chemical Co EMN 0.04% 3.27% 0.00% 6.73% 0.00%Twitter Inc TWTR 0.10% n/a n/a 37.35% 0.04%AvalonBay Communities Inc AVB 0.11% 3.03% 0.00% 5.61% 0.01%Prudential Financial Inc PRU 0.15% 4.35% 0.01% 11.43% 0.02%United Parcel Service Inc UPS 0.32% 3.44% 0.01% 8.93% 0.03%Apartment Investment & Management Co AIV 0.03% 3.20% 0.00% 8.73% 0.00%Walgreens Boots Alliance Inc WBA 0.24% 2.78% 0.01% 8.43% 0.02%McKesson Corp MCK 0.09% 1.33% 0.00% 7.12% 0.01%Lockheed Martin Corp LMT 0.35% 2.93% 0.01% 7.01% 0.02%

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 6Page 7 of 9

STANDARD AND POOR'S 500 INDEX

[14] [15] [16] [17] [18]Cap-Weighted

Weight in Estimated Cap-Weighted Long-Term Long-TermName Ticker Index Dividend Yield Dividend Yield Growth Est. Growth Est.

AmerisourceBergen Corp ABC 0.07% 2.01% 0.00% 8.05% 0.01%Capital One Financial Corp COF 0.16% 1.96% 0.00% 4.10% 0.01%Waters Corp WAT 0.07% n/a n/a 11.50% 0.01%Dollar Tree Inc DLTR 0.10% n/a n/a 9.41% 0.01%Darden Restaurants Inc DRI 0.06% 2.47% 0.00% 10.58% 0.01%NetApp Inc NTAP 0.07% 2.31% 0.00% 13.23% 0.01%Citrix Systems Inc CTXS 0.05% 1.40% 0.00% 11.85% 0.01%DXC Technology Co DXC 0.07% 1.18% 0.00% 6.70% 0.00%DaVita Inc DVA 0.04% n/a n/a 19.15% 0.01%Hartford Financial Services Group Inc/The HIG 0.07% 2.41% 0.00% 9.50% 0.01%Iron Mountain Inc IRM 0.04% 6.89% 0.00% 8.96% 0.00%Estee Lauder Cos Inc/The EL 0.15% 1.04% 0.00% 12.04% 0.02%Cadence Design Systems Inc CDNS 0.07% n/a n/a 10.35% 0.01%Universal Health Services Inc UHS 0.05% 0.30% 0.00% 10.88% 0.00%E*TRADE Financial Corp ETFC 0.05% 1.21% 0.00% 12.08% 0.01%Skyworks Solutions Inc SWKS 0.06% 1.84% 0.00% 8.87% 0.01%National Oilwell Varco Inc NOV 0.04% 0.75% 0.00% 77.76% 0.03%Quest Diagnostics Inc DGX 0.05% 2.36% 0.00% 8.05% 0.00%Activision Blizzard Inc ATVI 0.14% 0.81% 0.00% 6.65% 0.01%Rockwell Automation Inc ROK 0.09% 2.21% 0.00% 8.94% 0.01%Kraft Heinz Co/The KHC 0.16% 4.90% 0.01% 2.44% 0.00%American Tower Corp AMT 0.35% 1.83% 0.01% 21.72% 0.08%HollyFrontier Corp HFC 0.03% 2.68% 0.00% 5.93% 0.00%Regeneron Pharmaceuticals Inc REGN 0.18% n/a n/a 13.88% 0.02%Amazon.com Inc AMZN 3.57% n/a n/a 37.60% 1.34%Jack Henry & Associates Inc JKHY 0.04% 1.15% 0.00% 11.00% 0.00%Ralph Lauren Corp RL 0.03% 1.93% 0.00% 6.84% 0.00%Boston Properties Inc BXP 0.08% 2.84% 0.00% 4.91% 0.00%Amphenol Corp APH 0.11% 0.97% 0.00% 10.85% 0.01%Arconic Inc ARNC 0.04% 0.42% 0.00% 14.35% 0.01%Pioneer Natural Resources Co PXD 0.10% 0.42% 0.00% 26.85% 0.03%Valero Energy Corp VLO 0.14% 4.24% 0.01% 28.50% 0.04%Synopsys Inc SNPS 0.07% n/a n/a 14.50% 0.01%L3 Technologies Inc LLL 0.07% 1.65% 0.00% 5.00% 0.00%Western Union Co/The WU 0.03% 4.33% 0.00% 3.89% 0.00%CH Robinson Worldwide Inc CHRW 0.05% 2.30% 0.00% 9.07% 0.00%Accenture PLC ACN 0.46% 1.66% 0.01% 10.33% 0.05%TransDigm Group Inc TDG 0.10% n/a n/a 11.07% 0.01%Yum! Brands Inc YUM 0.12% 1.68% 0.00% 13.12% 0.02%Prologis Inc PLD 0.19% 2.95% 0.01% 6.85% 0.01%FirstEnergy Corp FE 0.09% 3.65% 0.00% -0.04% 0.00%VeriSign Inc VRSN 0.09% n/a n/a 8.80% 0.01%Quanta Services Inc PWR 0.02% 0.42% 0.00% 22.00% 0.00%Henry Schein Inc HSIC 0.04% n/a n/a 7.11% 0.00%Ameren Corp AEE 0.07% 2.58% 0.00% 6.35% 0.00%ANSYS Inc ANSS 0.06% n/a n/a 11.70% 0.01%NVIDIA Corp NVDA 0.44% 0.36% 0.00% 9.64% 0.04%Sealed Air Corp SEE 0.03% 1.39% 0.00% 6.04% 0.00%Cognizant Technology Solutions Corp CTSH 0.17% 1.10% 0.00% 11.40% 0.02%SVB Financial Group SIVB 0.05% n/a n/a 11.00% 0.01%Intuitive Surgical Inc ISRG 0.27% n/a n/a 12.82% 0.03%Affiliated Managers Group Inc AMG 0.02% 1.20% 0.00% 4.98% 0.00%Take-Two Interactive Software Inc TTWO 0.04% n/a n/a 10.30% 0.00%Republic Services Inc RSG 0.11% 1.87% 0.00% 13.01% 0.01%eBay Inc EBAY 0.14% 1.51% 0.00% 10.67% 0.01%Goldman Sachs Group Inc/The GS 0.29% 1.67% 0.00% 6.74% 0.02%SBA Communications Corp SBAC 0.09% n/a n/a 25.05% 0.02%Sempra Energy SRE 0.14% 3.07% 0.00% 9.95% 0.01%Moody's Corp MCO 0.14% 1.10% 0.00% 7.05% 0.01%Booking Holdings Inc BKNG 0.32% n/a n/a 12.50% 0.04%F5 Networks Inc FFIV 0.04% n/a n/a 8.41% 0.00%Akamai Technologies Inc AKAM 0.05% n/a n/a 15.40% 0.01%Devon Energy Corp DVN 0.06% 1.14% 0.00% 5.82% 0.00%Alphabet Inc GOOGL 1.44% n/a n/a 15.06% 0.22%Red Hat Inc RHT 0.13% n/a n/a 20.30% 0.03%Teleflex Inc TFX 0.06% 0.45% 0.00% 12.45% 0.01%Allegion PLC ALLE 0.03% 1.19% 0.00% 10.22% 0.00%Netflix Inc NFLX 0.63% n/a n/a 32.07% 0.20%Agilent Technologies Inc A 0.10% 0.82% 0.00% 9.50% 0.01%

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 6Page 8 of 9

STANDARD AND POOR'S 500 INDEX

[14] [15] [16] [17] [18]Cap-Weighted

Weight in Estimated Cap-Weighted Long-Term Long-TermName Ticker Index Dividend Yield Dividend Yield Growth Est. Growth Est.

Anthem Inc ANTM 0.30% 1.12% 0.00% 12.04% 0.04%CME Group Inc CME 0.24% 1.82% 0.00% 12.23% 0.03%Juniper Networks Inc JNPR 0.04% 2.87% 0.00% 8.76% 0.00%BlackRock Inc BLK 0.28% 3.09% 0.01% 8.53% 0.02%DTE Energy Co DTE 0.09% 3.03% 0.00% 5.53% 0.01%Celanese Corp CE 0.05% 2.19% 0.00% 7.05% 0.00%Nasdaq Inc NDAQ 0.06% 2.01% 0.00% 14.34% 0.01%Philip Morris International Inc PM 0.56% 5.16% 0.03% 7.98% 0.04%salesforce.com Inc CRM 0.50% n/a n/a 22.30% 0.11%Huntington Ingalls Industries Inc HII 0.04% 1.66% 0.00% 40.00% 0.01%MetLife Inc MET 0.17% 3.95% 0.01% 9.27% 0.02%Under Armour Inc UA 0.02% n/a n/a 35.87% 0.01%Tapestry Inc TPR 0.04% 4.16% 0.00% 10.58% 0.00%Fluor Corp FLR 0.02% 2.28% 0.00% 20.49% 0.00%CSX Corp CSX 0.25% 1.28% 0.00% 7.63% 0.02%Edwards Lifesciences Corp EW 0.16% n/a n/a 14.00% 0.02%Ameriprise Financial Inc AMP 0.07% 2.81% 0.00% 11.80% 0.01%TechnipFMC PLC FTI 0.04% 2.21% 0.00% 19.94% 0.01%Zimmer Biomet Holdings Inc ZBH 0.11% 0.75% 0.00% 4.74% 0.01%CBRE Group Inc CBRE 0.07% n/a n/a 8.55% 0.01%Mastercard Inc MA 0.97% 0.56% 0.01% 21.22% 0.21%CarMax Inc KMX 0.05% n/a n/a 12.92% 0.01%Intercontinental Exchange Inc ICE 0.18% 1.44% 0.00% 10.09% 0.02%Fidelity National Information Services Inc FIS 0.15% 1.24% 0.00% 8.10% 0.01%Chipotle Mexican Grill Inc CMG 0.08% n/a n/a 20.31% 0.02%Wynn Resorts Ltd WYNN 0.05% 2.51% 0.00% 31.10% 0.02%Assurant Inc AIZ 0.02% 2.53% 0.00% n/a n/aNRG Energy Inc NRG 0.05% 0.28% 0.00% 41.05% 0.02%Monster Beverage Corp MNST 0.12% n/a n/a 14.35% 0.02%Regions Financial Corp RF 0.06% 3.96% 0.00% 10.88% 0.01%Mosaic Co/The MOS 0.04% 0.37% 0.00% 11.40% 0.00%Expedia Group Inc EXPE 0.07% 1.08% 0.00% 17.20% 0.01%Evergy Inc EVRG 0.06% 3.27% 0.00% 6.67% 0.00%Discovery Inc DISCA 0.02% n/a n/a 12.30% 0.00%CF Industries Holdings Inc CF 0.04% 2.94% 0.00% 18.60% 0.01%Viacom Inc VIAB 0.04% 2.85% 0.00% 4.93% 0.00%Alphabet Inc GOOG 1.67% n/a n/a 15.06% 0.25%TE Connectivity Ltd TEL 0.11% 2.18% 0.00% 11.18% 0.01%Cooper Cos Inc/The COO 0.06% 0.02% 0.00% 5.23% 0.00%Discover Financial Services DFS 0.09% 2.25% 0.00% 7.20% 0.01%TripAdvisor Inc TRIP 0.03% n/a n/a 11.39% 0.00%Visa Inc V 1.11% 0.64% 0.01% 15.59% 0.17%Mid-America Apartment Communities Inc MAA 0.05% 3.51% 0.00% 7.00% 0.00%Xylem Inc/NY XYL 0.06% 1.21% 0.00% 14.00% 0.01%Marathon Petroleum Corp MPC 0.16% 3.54% 0.01% 10.64% 0.02%Advanced Micro Devices Inc AMD 0.11% n/a n/a 12.50% 0.01%Tractor Supply Co TSCO 0.05% 1.27% 0.00% 11.06% 0.01%ResMed Inc RMD 0.06% 1.42% 0.00% 12.50% 0.01%Mettler-Toledo International Inc MTD 0.07% n/a n/a 12.14% 0.01%Copart Inc CPRT 0.06% n/a n/a 20.00% 0.01%Fortinet Inc FTNT 0.06% n/a n/a 22.10% 0.01%Albemarle Corp ALB 0.04% 1.79% 0.00% 12.75% 0.00%Essex Property Trust Inc ESS 0.08% 2.70% 0.00% 6.54% 0.01%Realty Income Corp O 0.09% 3.69% 0.00% 4.39% 0.00%Seagate Technology PLC STX 0.05% 5.26% 0.00% 3.37% 0.00%Westrock Co WRK 0.04% 4.75% 0.00% 4.73% 0.00%IHS Markit Ltd INFO 0.09% n/a n/a 11.22% 0.01%Wabtec Corp WAB 0.05% 0.65% 0.00% 14.00% 0.01%Western Digital Corp WDC 0.06% 4.16% 0.00% 2.72% 0.00%PepsiCo Inc PEP 0.70% 3.03% 0.02% 5.39% 0.04%Diamondback Energy Inc FANG 0.07% 0.49% 0.00% 22.91% 0.02%Nektar Therapeutics NKTR 0.02% n/a n/a n/a n/aMaxim Integrated Products Inc MXIM 0.06% 3.46% 0.00% 8.93% 0.01%Church & Dwight Co Inc CHD 0.07% 1.28% 0.00% 7.71% 0.01%Duke Realty Corp DRE 0.04% 2.81% 0.00% 0.27% 0.00%Federal Realty Investment Trust FRT 0.04% 2.96% 0.00% 5.91% 0.00%MGM Resorts International MGM 0.06% 2.03% 0.00% 11.76% 0.01%JB Hunt Transport Services Inc JBHT 0.04% 1.03% 0.00% 18.78% 0.01%Lam Research Corp LRCX 0.11% 2.46% 0.00% -0.42% 0.00%

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 6Page 9 of 9

STANDARD AND POOR'S 500 INDEX

[14] [15] [16] [17] [18]Cap-Weighted

Weight in Estimated Cap-Weighted Long-Term Long-TermName Ticker Index Dividend Yield Dividend Yield Growth Est. Growth Est.

Mohawk Industries Inc MHK 0.04% n/a n/a 7.09% 0.00%Pentair PLC PNR 0.03% 1.62% 0.00% 10.29% 0.00%Vertex Pharmaceuticals Inc VRTX 0.19% n/a n/a 46.46% 0.09%Facebook Inc FB 1.62% n/a n/a 22.05% 0.36%United Rentals Inc URI 0.04% n/a n/a 17.76% 0.01%Alexandria Real Estate Equities Inc ARE 0.07% 2.72% 0.00% 4.80% 0.00%ABIOMED Inc ABMD 0.05% n/a n/a 29.00% 0.02%Delta Air Lines Inc DAL 0.14% 2.71% 0.00% 10.19% 0.01%United Continental Holdings Inc UAL 0.09% n/a n/a 12.62% 0.01%News Corp NWS 0.01% 1.60% 0.00% -9.13% 0.00%Centene Corp CNC 0.09% n/a n/a 13.68% 0.01%Macerich Co/The MAC 0.02% 6.92% 0.00% -0.09% 0.00%Martin Marietta Materials Inc MLM 0.05% 0.95% 0.00% 13.29% 0.01%PayPal Holdings Inc PYPL 0.50% n/a n/a 23.04% 0.11%Coty Inc COTY 0.04% 4.35% 0.00% 8.76% 0.00%DISH Network Corp DISH 0.03% n/a n/a -11.00% 0.00%Alexion Pharmaceuticals Inc ALXN 0.12% n/a n/a 16.38% 0.02%Everest Re Group Ltd RE 0.04% 2.59% 0.00% 10.00% 0.00%WellCare Health Plans Inc WCG 0.06% n/a n/a 17.08% 0.01%News Corp NWSA 0.02% 1.61% 0.00% -9.13% 0.00%Global Payments Inc GPN 0.09% 0.03% 0.00% 17.00% 0.01%Crown Castle International Corp CCI 0.22% 3.52% 0.01% 16.20% 0.04%Aptiv PLC APTV 0.08% 1.11% 0.00% 8.99% 0.01%Advance Auto Parts Inc AAP 0.05% 0.14% 0.00% 15.47% 0.01%Capri Holdings Ltd CPRI 0.03% n/a n/a 6.73% 0.00%Align Technology Inc ALGN 0.09% n/a n/a 23.19% 0.02%Illumina Inc ILMN 0.19% n/a n/a 23.66% 0.04%Alliance Data Systems Corp ADS 0.04% 1.44% 0.00% -2.33% 0.00%LKQ Corp LKQ 0.04% n/a n/a 13.05% 0.00%Nielsen Holdings PLC NLSN 0.03% 5.91% 0.00% n/a n/aGarmin Ltd GRMN 0.07% 2.64% 0.00% 7.28% 0.00%Cimarex Energy Co XEC 0.03% 1.14% 0.00% 66.37% 0.02%Zoetis Inc ZTS 0.20% 0.65% 0.00% 15.36% 0.03%Digital Realty Trust Inc DLR 0.10% 3.63% 0.00% 17.36% 0.02%Equinix Inc EQIX 0.15% 2.17% 0.00% 18.39% 0.03%Discovery Inc DISCK 0.04% n/a n/a 12.30% 0.00%

Notes:[9] Equals sum of Col. [16][10] Equals sum of Col. [18][11] Equals ([9] x (1 + (0.5 x [10]))) + [10][12] Source: Schedule-6, at 1[13] Equals [11] − [12][14] Equals weight in S&P 500 based on market capitalization [15] Source: Bloomberg Professional, as of March 29, 2019[16] Equals [14] x [15][17] Source: Bloomberg Professional, as of March 29, 2019[18] Equals [14] x [17]

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 7Page 1 of 3

[1] [2] [3]Average

Authorized Gas ROE

U.S. Govt. 30-year

TreasuryRisk

Premium1992.1 12.42% 7.80% 4.62%1992.2 11.98% 7.89% 4.09%1992.3 11.87% 7.45% 4.42%1992.4 11.94% 7.52% 4.42%1993.1 11.75% 7.07% 4.68%1993.2 11.71% 6.86% 4.85%1993.3 11.39% 6.31% 5.07%1993.4 11.16% 6.14% 5.02%1994.1 11.12% 6.57% 4.55%1994.2 10.84% 7.35% 3.48%1994.3 10.87% 7.58% 3.28%1994.4 11.53% 7.96% 3.57%1995.2 11.00% 6.94% 4.06%1995.3 11.07% 6.71% 4.35%1995.4 11.61% 6.23% 5.37%1996.1 11.45% 6.29% 5.16%1996.2 10.88% 6.92% 3.96%1996.3 11.25% 6.96% 4.29%1996.4 11.19% 6.62% 4.58%1997.1 11.31% 6.81% 4.49%1997.2 11.70% 6.93% 4.77%1997.3 12.00% 6.53% 5.47%1997.4 10.92% 6.14% 4.78%1998.2 11.37% 5.85% 5.52%1998.3 11.41% 5.47% 5.94%1998.4 11.69% 5.10% 6.59%1999.1 10.82% 5.37% 5.44%1999.2 11.25% 5.79% 5.46%1999.4 10.38% 6.25% 4.12%2000.1 10.66% 6.29% 4.36%2000.2 11.03% 5.97% 5.06%2000.3 11.33% 5.79% 5.55%2000.4 12.10% 5.69% 6.41%2001.1 11.38% 5.44% 5.93%2001.2 10.75% 5.70% 5.05%2001.4 10.65% 5.30% 5.35%2002.1 10.67% 5.51% 5.15%2002.2 11.64% 5.61% 6.03%2002.3 11.50% 5.08% 6.42%2002.4 11.01% 4.93% 6.08%2003.1 11.38% 4.85% 6.53%2003.2 11.36% 4.60% 6.76%2003.3 10.61% 5.11% 5.50%2003.4 10.84% 5.11% 5.73%2004.1 11.06% 4.88% 6.18%2004.2 10.57% 5.32% 5.25%2004.3 10.37% 5.06% 5.31%2004.4 10.66% 4.86% 5.79%2005.1 10.65% 4.69% 5.96%2005.2 10.54% 4.47% 6.07%2005.3 10.47% 4.44% 6.03%2005.4 10.32% 4.68% 5.63%2006.1 10.68% 4.63% 6.05%2006.2 10.60% 5.14% 5.46%2006.3 10.34% 4.99% 5.34%2006.4 10.14% 4.74% 5.40%2007.1 10.52% 4.80% 5.72%2007.2 10.13% 4.99% 5.14%2007.3 10.03% 4.95% 5.08%2007.4 10.12% 4.61% 5.50%2008.1 10.38% 4.41% 5.97%2008.2 10.17% 4.57% 5.60%2008.3 10.55% 4.44% 6.11%2008.4 10.34% 3.65% 6.69%2009.1 10.24% 3.44% 6.81%2009.2 10.11% 4.17% 5.94%2009.3 9.88% 4.32% 5.56%2009.4 10.31% 4.34% 5.97%2010.1 10.24% 4.62% 5.61%2010.2 9.99% 4.36% 5.62%2010.3 10.43% 3.86% 6.57%2010.4 10.09% 4.17% 5.93%2011.1 10.10% 4.56% 5.54%2011.2 9.85% 4.34% 5.51%2011.3 9.65% 3.69% 5.96%2011.4 9.88% 3.04% 6.84%2012.1 9.63% 3.14% 6.50%2012.2 9.83% 2.93% 6.90%2012.3 9.75% 2.74% 7.01%2012.4 10.06% 2.86% 7.19%2013.1 9.57% 3.13% 6.44%2013.2 9.47% 3.14% 6.33%

BOND YIELD PLUS RISK PREMIUM

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 7Page 2 of 3

[1] [2] [3]Average

Authorized Gas ROE

U.S. Govt. 30-year

TreasuryRisk

Premium

BOND YIELD PLUS RISK PREMIUM

2013.3 9.60% 3.71% 5.89%2013.4 9.83% 3.79% 6.04%2014.1 9.54% 3.69% 5.85%2014.2 9.84% 3.44% 6.39%2014.3 9.45% 3.26% 6.19%2014.4 10.28% 2.96% 7.32%2015.1 9.47% 2.55% 6.91%2015.2 9.43% 2.88% 6.55%2015.3 9.75% 2.96% 6.79%2015.4 9.68% 2.96% 6.72%2016.1 9.48% 2.72% 6.76%2016.2 9.42% 2.57% 6.85%2016.3 9.47% 2.28% 7.19%2016.4 9.67% 2.83% 6.84%2017.1 9.60% 3.04% 6.56%2017.2 9.47% 2.90% 6.58%2017.3 10.14% 2.82% 7.32%2017.4 9.70% 2.82% 6.88%2018.1 9.68% 3.02% 6.66%2018.2 9.43% 3.09% 6.34%2018.3 9.71% 3.06% 6.65%2018.4 9.53% 3.27% 6.26%2019.1 9.55% 3.01% 6.54%

AVERAGE 10.53% 4.81% 5.72%MEDIAN 10.47% 4.74% 5.85%

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 7Page 3 of 3

SUMMARY OUTPUT

Regression StatisticsMultiple R 0.902985 R Square 0.815382 Adjusted R Square 0.813589 Standard Error 0.003947 Observations 105

ANOVAdf SS MS F Significance F

Regression 1 0.007088 0.007088 454.907941 0.000000 Residual 103 0.001605 0.000016 Total 104 0.008693

Coefficients Standard Error t Stat P-value Lower 95% Upper 95% Lower 95.0% Upper 95.0%Intercept 0.0838 0.001305 64.23 0.000000 0.081234 0.086410 0.081234 0.086410 X Variable 1 (0.5527) 0.025913 (21.33) 0.000000 (0.604083) (0.501298) (0.604083) (0.501298)

[7] [8] [9]U.S. Govt.

30-year RiskTreasury Premium ROE

Current 30-Day Average [4] 2.99% 6.73% 9.72%Blue Chip Consensus Forecast (Q3 2019 - Q3 2020) [5] 3.16% 6.64% 9.80%Blue Chip Consensus Forecast (2020-2024) [6] 3.90% 6.23% 10.13%AVERAGE 9.88%

Notes:[1] Source: Regulatory Research Associates, accessed May 5, 2019[2] Source: Bloomberg Professional, quarterly bond yields are the average of each trading day in the quarter[3] Equals Column [1] − Column [2][4] Source: Bloomberg Professional, 30-day average as of March 29, 2019[5] Source: Blue Chip Financial Forecasts, Vol. 38, No. 4, April 1, 2019, at 2[6] Source: Blue Chip Financial Forecasts, Vol. 37, No. 12, December 1, 2018, at 14[7] See notes [4], [5] & [6][8] Equals 0.083822 + (-0.552691 x Column [7])[9] Equals Column [7] + Column [8]

y = -0.5527x + 0.0838R² = 0.8154

2.00%

3.00%

4.00%

5.00%

6.00%

7.00%

8.00%

2.00% 3.00% 4.00% 5.00% 6.00% 7.00% 8.00%

Ris

k Pr

emiu

m

U.S. Government 30-year Treasury Yield

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 8Page 1 of 1

[1] [2] [3] [4] [5] [6] [7] [8] [9] [10]

Value Line ROE2022-2024

Value LineTotal Capital

2018

Value LineCommon Equity

Ratio 2018

Total Equity 2018

Value LineTotal Capital2022-2024

Value LineCommon Equity

Ratio2022-2024

Total Equity 2022-2024

Compound Annual Growth Rate

Adjustment Factor

Adjusted Return on Common

Equity

Atmos Energy Corporation ATO 10.00% 7,263.60 65.70% 4,772 12,500 65.00% 8,125 11.23% 1.053 10.53%New Jersey Resources Corporation NJR 11.00% 2,599.60 54.60% 1,419 3,200 59.50% 1,904 6.05% 1.029 11.32%Northwest Natural Gas Company NWN 12.00% 1,485.00 52.50% 780 1,750 53.50% 936 3.73% 1.018 12.22%One Gas Inc. OGS 10.00% 3,330.00 61.50% 2,048 4,250 62.00% 2,635 5.17% 1.025 10.25%South Jersey Industries, Inc. SJI 12.00% 2,645.00 50.00% 1,323 3,950 50.50% 1,995 8.57% 1.041 12.49%Southwest Gas Corporation SWX 9.50% 4,375.00 51.00% 2,231 5,975 52.50% 3,137 7.05% 1.034 9.82%Spire, Inc. SR 10.50% 4,155.50 54.30% 2,256 4,600 57.00% 2,622 3.05% 1.015 10.66%

Mean 11.04%Median 10.66%

Notes:[1] Source: Value Line, March 1, 2019[2] Source: Value Line, March 1, 2019[3] Source: Value Line, March 1, 2019[4] Equals [2] x [3][5] Source: Value Line, March 1, 2019[6] Source: Value Line, March 1, 2019[7] Equals [5] x [6][8] Equals ([7] / [4]) ^ (1/5) - 1[9] Equals 2 x (1 + [8]) / (2 + [8])[10] Equals [1] x [9]

EXPECTED EARNINGS ANALYSIS

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 9Page 1 of 1

SIZE PREMIUM CALCULATION

Proxy Group Market Capitalization and Market-to-Book Ratio

[1] [2]Market

Capitalization Market-to-Company Ticker ($ billions) Book Ratio

Atmos Energy Corporation ATO 11.75 2.20New Jersey Resources Corporation NJR 4.36 2.91Northwest Natural Gas Company NWN 1.87 2.45ONE Gas Inc. OGS 4.60 2.25South Jersey Industries, Inc. SJI 2.87 2.26Southwest Gas Corporation SWX 4.39 1.95Spire, Inc. SR 4.05 1.77

Average 4.84 2.26Median 4.36 2.25

Montana-Dakota Utilities Co. - WY Natural GasCommon Equity ($ millions) [3] 8.01Implied Market Capitalization [4] 18.06

As a percent of Proxy Group Median Market Capitalization 0.41%

Duff & Phelps Cost of Capital Navigator -- Size Premium

[5] [6]Market

Capitalizationof LargestCompany Size

Breakdown of Deciles 1-10 ($ millions) Premium1-Largest 1,073,390.57 -0.30%2 29,022.867 0.52%3 13,455.802 0.81%4 7,254.230 0.85%5 4,503.549 1.28%6 2,992.251 1.50%7 1,960.201 1.58%8 1,292.224 1.80%9 727.843 2.46%10-Smallest 321.578 5.22%

Montana-Dakota Utilities Co. - WY Natural Gas - Implied Market Capitalization 18 5.22%Proxy Group Median Market Capitalization 4,358 1.28%

Size Premium [7] 3.94%

Notes:[1] Source: Bloomberg Professional; equals 30-day average as of March 29,2019[2] Source: Bloomberg Professional; equals 30-day average as of March 29, 2019[3] Data provided by MDU-Wyoming[4] Equals [3] x proxy group median market-to-book ratio[5] Duff & Phelps Cost of Capital Navigator - Size Premium: Annual Data as of 12/31/2018[6] Duff & Phelps Cost of Capital Navigator - Size Premium: Annual Data as of 12/31/2018[7] Equals 5.22% − 1.28%

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 10Page 1 of 1

Company Date [i]

Shares Issued(000)

Offering Price

Under-writing

Discount [ii]

Offering Expense ($000)

Net Proceeds Per Share

Total Flotation

Costs($000)

Equity Issue

Before Costs($000)

Net Proceeds

($000)Flotation Cost Percentage

MDU Resources Group 2/4/2004 2,300 23.32$ 0.7930$ 350$ 22.37$ 2,174$ 53,636$ 51,462$ 4.05%MDU Resources Group 11/19/2002 2,400 24.00$ 0.7200$ 193$ 23.20$ 1,921$ 57,600$ 55,680$ 3.33%

4,094$ 111,236$ 107,142$ 3.68%

Notes:[i] Offering Completion Date[ii] Underwriting discount was calculated as the market price minus the offering price when not explicitly given in the prospectus.

The flotation cost adjustment is derived by dividing the dividend yield by 1 − F (where F = flotation costs expressed in percentage terms), or by 0.9632, and adding that result to the constant growth rateto determine the cost of equity. Using the formulas shown previously in my testimony, the Constant Growth DCF calculation is modified as follows to accommodate an adjustment for flotation costs:

[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11]

Company TickerAnnualized Dividend Stock Price

Dividend Yield

Expected Dividend

Yield

Expected Dividend Yield Adjusted for

Flotation Costs

Value Line Earnings Growth

Yahoo! Finance Earnings Growth

Zacks Earnings Growth

Average Earnings Growth ROE

ROE Adjusted for

Flotation Costs

Atmos Energy Corporation ATO $2.10 $100.49 2.09% 2.16% 2.24% 7.50% 6.40% 6.50% 6.80% 8.96% 9.04%New Jersey Resources Corporation NJR $1.17 $49.10 2.38% 2.44% 2.54% 2.50% 6.00% 7.00% 5.17% 7.61% 7.70%Northwest Natural Gas Company NWN $1.90 $64.88 2.93% 3.09% 3.21% 25.50% 4.00% 4.30% 11.27% 14.36% 14.48%One Gas Inc. OGS $2.00 $87.59 2.28% 2.36% 2.45% 9.00% 5.00% 5.90% 6.63% 8.99% 9.08%South Jersey Industries, Inc. SJI $1.15 $31.08 3.70% 3.84% 3.99% 9.50% 5.90% 7.20% 7.53% 11.37% 11.52%Southwest Gas Corporation SWX $2.08 $82.75 2.51% 2.60% 2.70% 8.50% 6.30% 6.20% 7.00% 9.60% 9.70%Spire, Inc. SR $2.37 $79.78 2.97% 3.03% 3.14% 5.50% 2.42% 3.90% 3.94% 6.97% 7.08%

Median 8.99% 9.08%Flotation Cost Adjustment [12] 0.09%

Notes:[1] Source: Bloomberg Professional[2] Source: Bloomberg Professional, equals 30-day average as of March 29, 2019[3] Equals [1] / [2][4] Equals [3] x (1 + 0.5 x [9])[5] Equals [4] / (1 − Flotation Cost)[6] Source: Value Line[7] Source: Yahoo! Finance[8] Source: Zacks[9] Equals Average ([6], [7], [8])[10] Equals [4] + [9][11] Equals [5] + [9][12] Equals Average ([11]) − Average ([10])

FLOTATION COST ADJUSTMENT -- MDU WYOMING PROXY GROUP

( )( ) g

FPgDk +

−×+×

=1

5.01

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 11Page 1 of 2

2019-2023 CAPITAL EXPENDITURES AS A PERCENT OF 2017 NET PLANT($ Millions)

[1] [2] [3] [4] [5] [6] [7]2019-23

Cap. Ex. /2018

2017 2019 2020 2021 2022 2023 Net Plant

Atmos Energy Corporation ATOCapital Spending per Share $14.15 $14.40 $14.10 $13.80 $13.80Common Shares Outstanding 120.00 125.00 135.00 145.00 145.00Capital Expenditures $1,698.0 $1,800.0 $1,903.5 $2,001.0 $2,001.0 101.56%Net Plant $9,259.2

New Jersey Resources Corporation NJRCapital Spending per Share $2.20 $2.25 $2.28 $2.30 $2.30Common Shares Outstanding 88.00 88.25 88.63 89.00 89.00Capital Expenditures $193.6 $198.6 $201.6 $204.7 $204.7 38.44%Net Plant $2,609.7

Northwest Natural Gas Company NWNCapital Spending per Share $6.65 $6.65 $6.45 $6.25 $6.25Common Shares Outstanding 30.00 30.50 31.25 32.00 32.00Capital Expenditures $199.5 $202.8 $201.6 $200.0 $200.0 44.52%Net Plant $2,255.0

ONE Gas, Inc. OGSCapital Spending per Share $8.50 $8.70 $8.80 $8.90 $8.90Common Shares Outstanding 53.00 53.50 54.25 55.00 55.00Capital Expenditures $450.5 $465.5 $477.4 $489.5 $489.5 59.20%Net Plant $4,007.6

South Jersey Industries, Inc. SJICapital Spending per Share $3.10 $3.35 $4.13 $4.90 $4.90Common Shares Outstanding 90.00 92.00 95.00 98.00 98.00Capital Expenditures $279.0 $308.2 $391.9 $480.2 $480.2 71.83%Net Plant $2,700.2

Southwest Gas Corporation SWXCapital Spending per Share $14.35 $15.00 $16.13 $17.25 $17.25Common Shares Outstanding 54.00 55.00 56.50 58.00 58.00Capital Expenditures $774.9 $825.0 $911.1 $1,000.5 $1,000.5 99.74%Net Plant $4,523.7

Spire, Inc. SRCapital Spending per Share $10.95 $11.70 $12.23 $12.75 $12.75Common Shares Outstanding 52.00 53.00 54.00 55.00 55.00Capital Expenditures $569.4 $620.1 $660.2 $701.3 $701.3 88.73%Net Plant $3,665.2

Montana-Dakota Utilities Co. MDUCapital Expenditures [8] $2.5 $2.6 $2.4 $2.4 $2.4 72.80%Net Plant in Service [9] $17.07

MDU CapEx Total (2019 - 2023) $12.43MDU CapEx Annual Average $2.5Proxy Group Median 71.8%MDU as % Proxy Group Median 1.01

Notes:[1] - [6] Value Line, March 1, 2019[7] Equals (Column [2] + [3] + [4] + [5] + [6]) / Column [1] [8] - [9] Data provided by Montana-Dakota Utilities Co.

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 11Page 2 of 2

Projected CAPEX / 2017 Net Plant

Company Ticker 2019-2023New Jersey Resources Corporation NJR 38.44%Northwest Natural Gas Company NWN 44.52%ONE Gas, Inc. OGS 59.20%South Jersey Industries, Inc. SJI 71.83%Montana-Dakota Utilities Co. MDU 72.80%Spire, Inc. SR 88.73%Southwest Gas Corporation SWX 99.74%Atmos Energy Corporation ATO 101.56%

Proxy Group Median 71.83%MDU/Proxy Group 1.01

Notes:Source: Schedule-11 page 1 col. [7]

2019-2023 CAPITAL EXPENDITURES AS A PERCENT OF 2017 NET PLANT

38.44%44.52%

59.20%

71.83% 72.80%

88.73%

99.74% 101.56%

0.00%

20.00%

40.00%

60.00%

80.00%

100.00%

120.00%

NJR NWN OGS SJI MDU SR SWX ATO

Proxy Group Median = 71.83%

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 12Page 1 of 1

Generation GenericProxy Group Company Operation State Operation Test Year Rate Base Full Partial Capacity Infrastructure

Atmos Energy Corporation Kansas Gas 1 Historical Year End x xKentucky Gas 1 Fully Forecast Year End x xLouisiana Gas 1 Historical Average x xMississippi Gas 1 Fully Forecast Average x xTennessee Gas 1 Fully Forecast Average xTexas RRC Gas 1 Historical Year End x x

New Jersey Resources Corporation New Jersey Gas 1 Partially Forecast Year End x x

Northwest Natural Gas Company Oregon Gas 1 Fully Forecast Average xWashington Gas 1 Historical Average

ONE Gas, Inc. Kansas Gas 1 Historical Year End x xOklahoma Gas 1 Historical Year End xTexas RRC Gas 1 Historical Year End x x

South Jersey Industries, Inc. New Jersey Gas 1 Partially Forecast Year End x x

Southwest Gas Corporation Arizona Gas 1 Historical Year End x xCalifornia Gas 1 Fully Forecast Average xNevada Gas 1 Historical Year End x x

Spire, Inc. Alabama Gas 1 Historical Average xMissouri Gas 1 Historical Year End x

Historical: 11 Average: 7Proxy Companies Forecast: 7 Year End: 11 4 12 0 12

Total Jurisdictions 18

Percent of Jurisdictions Forecast: 39% Year End: 61% 22% 67% 0% 67%Montana-Dakota Utilities Co. [2] Wyoming Historical Year End

Notes:[1] S&P Global Market Intelligence, Regulatory Focus: Adjustment Clauses, dated September 28, 2018. Operating subsidiaries not covered in this report were excluded from this exhibit. [2] Data provided by Montana-Dakota Utilities Co.

COMPARISON OF MONTANA-DAKOTA AND PROXY GROUP COMPANIES REGULATORY FRAMEWORK - ADJUSTMENT CLAUSES

Decoupling New Capital

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 13Page 1 of 4

Proxy Group Company Ticker 2017 2016 MRYAtmos Energy Corporation ATO 55.84% 49.78% 55.84%New Jersey Resources Corporation NJR 55.79% 55.51% 55.79%Northwest Natural Gas Company NWN 47.00% 52.22% 47.00%ONE Gas, Inc. OGS 63.18% 62.08% 63.18%South Jersey Industries, Inc. SJI 51.12% 53.05% 51.12%Southwest Gas Corporation SWX 48.38% 54.25% 48.38%Spire, Inc. SR 49.28% 58.04% 49.28%MEAN 52.94% 54.99% 52.94%LOW 47.00% 49.78% 47.00%HIGH 63.18% 62.08% 63.18%

Company Name Ticker 2017 2016 MRYAtmos Energy Corporation ATO 55.84% 49.78% 55.84%New Jersey Natural Gas Company NJR 55.79% 55.51% 55.79%Northwest Natural Gas Company NWN 47.00% 52.22% 47.00%Kansas Gas Service Company OGS 63.35% 62.01% 63.35%Oklahoma Natural Gas Company OGS 62.13% 62.13%Texas Gas Service Company OGS 63.01% 62.09% 63.01%South Jersey Gas Company SJI 51.12% 53.05% 51.12%Southwest Gas Corporation SWX 48.38% 54.25% 48.38%Spire Alabama Inc. SR 72.32% 72.32%Spire Gulf Inc. SR 38.43% 52.83% 38.43%Spire Mississippi Inc. SR 53.10% 53.08% 53.10%Spire Missouri Inc. SR 49.78% 50.39% 49.78%

Notes:

CAPITAL STRUCTURE ANALYSIS

COMMON EQUITY RATIO - UTILITY OPERATING COMPANIES [2]

COMMON EQUITY RATIO [1]

[2] Natural Gas and Electric Operating Subsidiaries with data listed as N/A from SNL Financial have been excluded from the analysis.

[1] Ratios are weighted by actual common capital, long-term debt and short-term debt of Operating Subsidiaries

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 13Page 2 of 4

Proxy Group Company Ticker 2017 2016 MRYAtmos Energy Corporation ATO 37.80% 31.37% 37.80%New Jersey Resources Corporation NJR 33.68% 42.24% 33.68%Northwest Natural Gas Company NWN 43.47% 42.07% 43.47%ONE Gas, Inc. OGS 36.82% 37.92% 36.82%South Jersey Industries, Inc. SJI 42.46% 26.73% 42.46%Southwest Gas Corporation SWX 45.89% 44.94% 45.89%Spire, Inc. SR 38.02% 32.36% 38.02%MEAN 39.73% 36.80% 39.73%LOW 33.68% 26.73% 33.68%HIGH 45.89% 44.94% 45.89%

Company Name Ticker 2017 2016 MRYAtmos Energy Corporation ATO 37.80% 31.37% 37.80%New Jersey Natural Gas Company NJR 33.68% 42.24% 33.68%Northwest Natural Gas Company NWN 43.47% 42.07% 43.47%Kansas Gas Service Company OGS 36.65% 37.99% 36.65%Oklahoma Natural Gas Company OGS 37.87% 37.87%Texas Gas Service Company OGS 36.99% 37.91% 36.99%South Jersey Gas Company SJI 42.46% 26.73% 42.46%Southwest Gas Corporation SWX 45.89% 44.94% 45.89%Spire Alabama Inc. SR 20.85% 20.85%Spire Gulf Inc. SR 54.12% 41.00% 54.12%Spire Mississippi Inc. SR 24.97% 46.57% 24.97%Spire Missouri Inc. SR 37.34% 38.12% 37.34%

Notes:

CAPITAL STRUCTURE ANALYSIS

LONG-TERM DEBT RATIO - UTILITY OPERATING COMPANIES [2]

LONG-TERM DEBT RATIO [1]

[2] Natural Gas and Electric Operating Subsidiaries with data listed as N/A from SNL Financial have been excluded from the analysis.

[1] Ratios are weighted by actual common capital, long-term debt and short-term debt of Operating Subsidiaries

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 13Page 3 of 4

Proxy Group Company Ticker 2017 2016 MRYAtmos Energy Corporation ATO 0.00% 0.00% 0.00%New Jersey Resources Corporation NJR 0.00% 0.00% 0.00%Northwest Natural Gas Company NWN 0.00% 0.00% 0.00%ONE Gas, Inc. OGS 0.00% 0.00% 0.00%South Jersey Industries, Inc. SJI 0.00% 0.00% 0.00%Southwest Gas Corporation SWX 0.00% 0.00% 0.00%Spire, Inc. SR 0.00% 0.00% 0.00%MEAN 0.00% 0.00% 0.00%LOW 0.00% 0.00% 0.00%HIGH 0.00% 0.00% 0.00%

Company Name Ticker 2017 2016 MRYAtmos Energy Corporation ATO 0.00% 0.00% 0.00%New Jersey Natural Gas Company NJR 0.00% 0.00% 0.00%Northwest Natural Gas Company NWN 0.00% 0.00% 0.00%Kansas Gas Service Company OGS 0.00% 0.00% 0.00%Oklahoma Natural Gas Company OGS 0.00% 0.00%Texas Gas Service Company OGS 0.00% 0.00% 0.00%South Jersey Gas Company SJI 0.00% 0.00% 0.00%Southwest Gas Corporation SWX 0.00% 0.00% 0.00%Spire Alabama Inc. SR 0.00% 0.00%Spire Gulf Inc. SR 0.00% 0.00% 0.00%Spire Mississippi Inc. SR 0.00% 0.00% 0.00%Spire Missouri Inc. SR 0.00% 0.00% 0.00%

Notes:

CAPITAL STRUCTURE ANALYSIS

PREFERRED EQUITY RATIO - UTILITY OPERATING COMPANIES [2]

PREFERRED EQUITY RATIO [1]

[1] Ratios are weighted by actual common capital, long-term debt and short-term debt of Operating Subsidiaries[2] Natural Gas and Electric Operating Subsidiaries with data listed as N/A from SNL Financial have been excluded from the analysis.

Docket No. 30013-351-GR-19Exhibit No.___(AEB-2)

Schedule 13Page 4 of 4

Proxy Group Company Ticker 2017 2016 MRYAtmos Energy Corporation ATO 6.35% 18.85% 6.35%New Jersey Resources Corporation NJR 10.53% 2.25% 10.53%Northwest Natural Gas Company NWN 9.53% 5.72% 9.53%ONE Gas, Inc. OGS 0.00% 0.00% 0.00%South Jersey Industries, Inc. SJI 6.42% 20.22% 6.42%Southwest Gas Corporation SWX 5.74% 0.81% 5.74%Spire, Inc. SR 12.70% 9.60% 12.70%MEAN 7.33% 8.21% 7.33%LOW 0.00% 0.00% 0.00%HIGH 12.70% 20.22% 12.70%

Company Name Ticker 2017 2016 MRYAtmos Energy Corporation ATO 6.35% 18.85% 6.35%New Jersey Natural Gas Company NJR 10.53% 2.25% 10.53%Northwest Natural Gas Company NWN 9.53% 5.72% 9.53%Kansas Gas Service Company OGS 0.00% 0.00% 0.00%Oklahoma Natural Gas Company OGS 0.00% 0.00%Texas Gas Service Company OGS 0.00% 0.00% 0.00%South Jersey Gas Company SJI 6.42% 20.22% 6.42%Southwest Gas Corporation SWX 5.74% 0.81% 5.74%Spire Alabama Inc. SR 6.84% 6.84%Spire Gulf Inc. SR 7.45% 6.16% 7.45%Spire Mississippi Inc. SR 21.94% 0.35% 21.94%Spire Missouri Inc. SR 12.88% 11.49% 12.88%

Notes:

CAPITAL STRUCTURE ANALYSIS

[1] Ratios are weighted by actual common capital, long-term debt and short-term debt of Operating Subsidiaries

SHORT-TERM DEBT RATIO - UTILITY OPERATING COMPANIES [2]

SHORT-TERM DEBT RATIO [1]

[2] Natural Gas and Electric Operating Subsidiaries with data listed as N/A from SNL Financial have been excluded from the analysis.

S&P 500 Industry Briefing:Utilities

Yardeni Research, Inc.

April 30, 2019

Dr. Ed Yardeni516-972-7683

eyardeni@yardeni.com

Joe Abbott732-497-5306

jabbott@yardeni.com

Please visit our sites atwww.yardeni.comblog.yardeni.com

thinking outside the box

Docket No. 30013-351-GR-19 Exhibit No.___(AEB-2) Schedule 14 Page 1 of 8

Table Of Contents Table Of ContentsTable Of Contents

April 30, 2019 / S&P 500 Industry Briefing: Utilities www.yardeni.com

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S&P 500 UtilitiesStock Price Index 1Forward Revenues & Earnings with Annual Squiggles 2Annual Growth Squiggles 3Margins & NERI 4Forward Growth & Valuation 5

Docket No. 30013-351-GR-19 Exhibit No.___(AEB-2) Schedule 14 Page 2 of 8

95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 2075

125

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125

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325

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200-day moving average.* Ratio scale.

Source: Standard & Poor’s and Haver Analytics.

S&P 500 UTILITIES STOCK PRICE INDEX*

Figure 1.

95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 2075

135

195

255

315

375

75

135

195

255

315

375

x10

x14

x18

S&P 500 UTILITIES INDEX, FORWARD EARNINGS, & VALUATIONUtilities IndexDaily: 04/30/19

Blue Angels Implied Price Index*Weekly: 04/18/19

* Implied price index calculated using forward earnings times forward P/Es.

yardeni.com

Source: Standard & Poor’s and I/B/E/S data by Refinitiv.

Figure 2.

Stock Price Index

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Docket No. 30013-351-GR-19 Exhibit No.___(AEB-2) Schedule 14 Page 3 of 8

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020110

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* Time-weighted average of consensus estimates for current year and next year. Monthly through December 2005, then weekly.Source: I/B/E/S data by Refinitiv.

S&P 500 UTILITIES REVENUES PER SHARE(analysts’ average forecasts, ratio scale)

Consensus ForecastsAnnual estimates

Forward revenues*

Figure 3.

95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 208

9

10

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* Time-weighted average of consensus estimates for current year and next year. Monthly through December 2005, then weekly.Source: I/B/E/S data by Refinitiv.

S&P 500 UTILITIES OPERATING EARNINGS PER SHARE(analysts’ average forecasts, ratio scale)

Consensus ForecastsAnnual estimates

Forward earnings*

Figure 4.

Forward Revenues & Earnings with Annual Squiggles

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Docket No. 30013-351-GR-19 Exhibit No.___(AEB-2) Schedule 14 Page 4 of 8

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020-4

-2

0

2

4

6

8

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-4

-2

0

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2016

17

yardeni.com

Source: I/B/E/S data by Refinitiv.

S&P 500 UTILITIES ANNUAL REVENUE GROWTH FORECASTS(based on analysts’ consensus estimates, percent, weekly)

2011 (5.1)2012 (-0.6)2013 (5.8)2014 (5.9)2015 (-2.0)

2016 (2.4)2017 (4.3)2018 (1.9)2019 (4.1)2020 (2.7)

Latest data thru 04/18/19

Figure 5.

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020-10

-8

-6

-4

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0

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2016

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yardeni.com

Source: I/B/E/S data by Refinitiv.

S&P 500 UTILITIES ANNUAL EARNINGS GROWTH FORECASTS(based on analysts’ consensus estimates, percent, weekly)

2011 (-0.7)2012 (-6.1)2013 (0.4)2014 (8.4)2015 (-0.5)2016 (5.9)2017 (2.1)2018 (7.6)2019 (4.4)2020 (6.1)

Latest data thru 04/18/19

Figure 6.

Annual Growth Squiggles

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Docket No. 30013-351-GR-19 Exhibit No.___(AEB-2) Schedule 14 Page 5 of 8

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 20207

8

9

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7

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204/18

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(using analysts’ average earnings and revenues forecasts)

* Time-weighted average of the consensus estimates for current year and next year. Monthly through December 2005, weekly thereafter.Source: I/B/E/S data by Refinitiv.

S&P 500 UTILITIES PROJECTED PROFIT MARGIN

Consensus ForecastsAnnual estimates

Forward profit margin* (12.9)

Figure 7.

95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 20-35

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NERI Feb -0.7 Mar -2.2 Apr -3.3

Apr

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* Three-month moving average of the number of forward earnings estimates up less number of estimates down, expressed as a percentageof the total number of forward earnings estimates.Source: I/B/E/S data by Refinitiv.

S&P 500 UTILITIES NET EARNINGS REVISIONS*

Figure 8.

Margins & NERI

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Docket No. 30013-351-GR-19 Exhibit No.___(AEB-2) Schedule 14 Page 6 of 8

95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 20-10

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Note: STEG is year-ahead forward consensus expected short-term earnings growth. STRG is year-ahead forward consensus expected short-termrevenue growth. LTEG is five-year consensus expected long-term earnings growth.Monthly data through 2005, weekly thereafter.Source: I/B/E/S data by Refinitiv.

S&P 500 UTILITIES STRG, STEG, & LTEG(percent)

LTEG* (5.3)

STEG* (4.9)

STRG* (3.6)

Figure 9.

5

10

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95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 200

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4/18yardeni.com

* Price divided by 12-month forward consensus expected operating earnings per share.** Sector or industry forward P/E relative to S&P 500 forward P/E.

*** Sector or industry forward P/E relative to sector or industry consensus 5-year LTEG forecast.Source: I/B/E/S data by Refinitiv.

S&P 500 UTILITIES VALUATION

Forward P/E* (18.2)

Relative P/E** (1.1)

PEG Ratio*** (3.5)

Figure 10.

Forward Growth & Valuation

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Docket No. 30013-351-GR-19 Exhibit No.___(AEB-2) Schedule 14 Page 7 of 8

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Docket No. 30013-351-GR-19 Exhibit No.___(AEB-2) Schedule 14 Page 8 of 8

1

MONTANA-DAKOTA UTILITIES CO.

Before the Public Service Commission of Wyoming

Docket No. 30013-351-GR-19

Direct Testimony

of

Travis R. Jacobson

Q. Would you please state your name and business address? 1

A. Yes. My name is Travis R. Jacobson and my business address is 2

400 North Fourth Street, Bismarck, North Dakota 58501. 3

Q. What is your position with Montana-Dakota Utilities Co.? 4

A. I am the Regulatory Analysis Manager for Montana-Dakota Utilities 5

Co. (Montana-Dakota or Company). 6

Q. Would you please describe your duties as Regulatory Analysis 7

Manager? 8

A. I am responsible for the preparation of cost of service studies, fuel 9

cost adjustments, purchased gas cost adjustments and gas tracking 10

adjustments in each of the jurisdictions in which Montana-Dakota 11

operates. 12

Q. Would you please describe your education and professional 13

background? 14

A. I graduated from Minot State University with a Bachelor of Science 15

degree in Accounting and I am a Certified Public Accountant (CPA). I 16

started my career with Montana-Dakota in 1999 as a financial analyst in 17

2

the Financial Reporting area and during my tenure with the Company 1

have held positions of increasing responsibility, including Supervisor, 2

Financial Reporting & Planning and Manager, Financial Reporting & 3

Planning before attaining my current position. 4

Q. Are you familiar with the books and records of Montana-Dakota and 5

the manner in which they are kept? 6

A. Yes. Montana-Dakota's books and records are kept in accordance 7

with the Federal Energy Regulatory Commission (FERC) Uniform System 8

of Accounts. 9

Q. What is the purpose of your testimony in this proceeding? 10

A. The purpose of my testimony is to present the per books cost of 11

service for the twelve months ended December 31, 2018, the pro forma 12

cost of service reflecting known and measurable adjustments that will 13

occur by December 2019 and the calculation of the revenue deficiency of 14

$1,051,927 based on an overall cost of capital of 7.754 percent. 15

Q. What statements, schedules and exhibits are you sponsoring? 16

A. I am sponsoring Statements A through D, Statement F, Schedule F-17

1 and F-4, Statements G through J, Statement M, Purchased Gas Cost 18

Adjustment - Rate 88 and Exhibit No.___(TRJ-1). 19

Pro Forma Revenue Requirement 20

Q. What were the results of Wyoming gas operations for the twelve 21

months ended December 31, 2018? 22

3

A. Statement A, pages 2 and 4 show the per books income statement 1

and rate base for Wyoming. As shown on page 2, Wyoming gas 2

operations had a return on rate base of 5.052 percent and a return on 3

equity of 5.366 percent for the twelve months ended December 31, 2018. 4

The details for each line item (i.e. sales revenue, other revenue, etc.) are 5

included in the applicable Statement listed. Pages 3 and 5 list the pro 6

forma adjustments to operating revenues, expenses and rate base. All 7

adjustments were calculated on either a Wyoming specific basis or on a 8

total Company basis and allocated to Wyoming, as indicated on the 9

statement or schedule detailing each adjustment. 10

Q. How was the per books cost of service allocated to Wyoming? 11

A. The Company utilizes a jurisdictional accounting system that 12

directly assigns and/or allocates every item of revenue, expense and rate 13

base to the jurisdictions as part of the regular accounting process on a 14

monthly basis. The allocation methods and procedures are the same as 15

have previously been used in Commission proceedings and are based on 16

the principle of assigning and/or allocating costs to the cost causer. The 17

Company’s Cost Allocation Manual details the method of assigning costs 18

to the Wyoming gas operations and is included in Statement M. 19

Q. What criteria were used to determine the pro forma adjustments? 20

A. The pro forma adjustments to operating revenue, expenses and 21

rate base were based on known and measurable changes occurring by 22

December 31, 2019, conform to past Commission practices and are listed 23

4

on pages 3 and 5 of Statement A. All adjustments are reasonably certain 1

to occur and can be measured with reasonable accuracy, thus meeting the 2

criteria of known and measurable. 3

Q. Would you describe the pro forma adjustments to the income 4

statement and rate base? 5

A. Yes. The adjustments to the income statement are summarized on 6

Statement A, page 3 and consist of adjustments to revenue, operation and 7

maintenance expenses, depreciation expense, taxes other, and current 8

and deferred income taxes. The adjustments to rate base are 9

summarized on Statement A, page 5 and include plant, accumulated 10

reserve and associated additions and deductions. 11

Pro Forma Income Statement 12

Q. What adjustments were made to operating revenues? 13

A. The adjustments to operating revenues are contained in Statement 14

F. Retail sales and transportation revenues are presented in Schedule F-15

1. Adjustment No. 1 restates the per books consumption at current rates, 16

adjusted to reflect the March 2019 cost of gas, exclusive of the surcharge 17

adjustment, and eliminates the unbilled revenue and reserve for refunds, 18

increasing revenue by $700,555. 19

Adjustment No. 2 decreases revenues by $895,249 to reflect the 20

effect of normal weather on sales and transportation volumes, as weather 21

was 13.2 percent colder than normal in 2018. As discussed in Ms. 22

Kivisto’s testimony, Montana-Dakota is proposing to discontinue the non-23

5

core revenue credit in this filing. Therefore, interruptible volumes have 1

been included in the normalized revenues. 2

Adjustment No. 3 is an increase to revenues of $113,480 to reflect 3

the annualization of firm customers to the December 2018 level. 4

Interruptible volumes were based on two- or three-year average usage 5

and do not require annualization. 6

Montana-Dakota did not include customer growth within its revenue 7

analysis. The recent level of customer additions has been insignificant 8

and not reliably predictable. Because incremental customers and volumes 9

have not been included the Company has not included the associated 10

investment required to connect new customers. 11

Adjustment No. 4, presented in Schedule F-4, includes adjustments 12

to other operating revenues. The pro forma adjustment consists of the 13

adjustment to late payment revenue based on the three-year average ratio 14

of late payment revenues to sales and transportation revenue applied to 15

pro forma revenue, and a three-year average of reconnect fees, NSF 16

check fees, sale of junk material and penalty revenue. 17

Q. What adjustments were made to operations and maintenance (O&M) 18

expenses? 19

A. The adjustments to operation and maintenance expenses are 20

contained in Statement G with each adjustment set forth in Statement G, 21

Schedule G-1. 22

6

The $74,417 reduction to the cost of gas (Adjustment No. 5), 1

shown on page 4, uses the pro forma dk sales, adjusted for losses, and 2

the cost of gas calculated in the March 2019 Purchased Gas Cost 3

Adjustment. The distribution loss factor of 0.68 percent represents the 4

loss factor currently used in the Company’s cost of gas filings. 5

Q. How were the pro forma labor and benefits developed? 6

A. The adjustment to labor is Adjustment No. 6. The pro forma labor 7

was developed by applying a weighted average percentage increase in 8

labor costs to the actual 2018 Wyoming labor expense. Wages and 9

salaries for straight time, premium time and vacation were based on total 10

Company costs with the application of an increase of 2.92 percent for 11

union employees and 3.46 percent for nonunion employees effective in 12

2019 resulting in an overall increase in wages of 3.25 percent. Bonuses 13

and commissions have been adjusted to reflect ongoing stock 14

compensation and miscellaneous bonuses. In addition, incentive 15

compensation has been adjusted to reflect an average level of 11.05% of 16

straight time and vacation. These changes result in an overall increase in 17

labor of 5.84 percent, or $102,261. 18

Benefits are shown on page 6 of Schedule G-1. Adjustment No. 7 19

is an overall increase of $15,133 in benefits. Benefits expense consists of 20

medical/dental insurance, pension expense, post-retirement, 401-K, 21

workers compensation, and other benefits (primarily disability insurance). 22

7

Each of these items was adjusted individually using current information 1

and applying the percentage increase to each type of benefit. 2

Medical and dental expense is increasing 8.0 percent and is based 3

on the Company’s actual 2019 premium increase compared to 2018. 4

Pension expense is decreasing 45.05 percent based on the actuarial 5

results of the total Company pension estimates. Post-retirement expense 6

is increasing by 3.50 percent from 2018. The 401K expense, workers 7

compensation and other benefits are tied to labor costs and increase 3.25 8

percent to reflect the overall average increase in wages and salaries. 9

Q. Would you describe the other adjustments made to O&M expense? 10

A. Yes. Vehicles and work equipment (Adjustment No. 8) reflects all 11

expenses associated with the Company’s vehicles and work equipment, 12

such as backhoes, including the costs of fuel, insurance, maintenance and 13

depreciation expense. Adjustment No. 8 reflects an increase of $65,567 in 14

this account due to the change in the depreciation component of the 15

expense. It is calculated based on the pro forma vehicle and work 16

equipment investment and the depreciation rates in Statement H. The 17

depreciation component on these items is not charged to depreciation 18

expense but rather is charged to a clearing account where it is then 19

recorded in O&M expense as the vehicles or work equipment is used. 20

This method allows the Company to match the cost of vehicles or work 21

equipment to the service provided or as a component of the associated 22

capital investment. 23

8

Company consumption (Adjustment No. 9) is the expense for 1

electric and natural gas consumption in Company buildings. An overall 2

decrease of $927 reflects the electric volumes at current rates and the 3

normalized gas volumes at current rates. 4

Uncollectible accounts (Adjustment No. 10) is a decrease of $5,694 5

based on the ratio of the five-year average ratio of net write-offs to sales 6

and transportation revenues and applied to pro forma revenues. The 7

decrease is due to a slight decrease in the write-off ratio and revenues. 8

Postage expense (Adjustment No. 11) is a decrease of $592 and 9

reflects the annualized December 2018 e-billing (electronic billing) level, 10

partially offset by a 1.32 percent increase in postage rates effective 11

1/1/2019. 12

Advertising expense (Adjustment No. 12) is shown on page 11 and 13

represents a decrease of $9,276. Pursuant to Wyoming General 14

Regulations Section 248, general promotional and institutional advertising 15

expense has been eliminated. Informational advertising is adjusted to 16

exclude advertising not directly applicable to Wyoming gas operations. 17

Insurance expense (Adjustment No. 13) reflects the expense at 18

current levels for 2019 and represents an increase of $7,274. Self-19

insurance expense was adjusted to reflect a five-year average of claims 20

and related expenses paid. 21

9

Materials expense (Adjustment No. 14) is an increase of $9,982 1

and is adjusted to reflect an increase in materials associated with pipeline 2

safety and integrity replacement projects. 3

Software maintenance (Adjustment No. 15) is found on page 14 4

and is an increase of $20,983. The Pro Forma increase is related to 5

contract increases as well as the purchase of additional cyber security 6

software. 7

Industry dues (Adjustment No. 16) reflects the removal of dues not 8

applicable to Wyoming gas operations for a decrease of $654. All other 9

industry dues remain at the current level. 10

Regulatory Commission Expense (Adjustment No. 17) reflects a 11

three-year average of ongoing regulatory commission expenses, the 12

expenses expected to be incurred in this filing, amortized over a three-13

year period, and a five-year average of the costs of performing gas and 14

common depreciation studies. The adjustment is an increase of $48,812. 15

Adjustment No. 18 is related to the allocation of MDU Resources 16

Group, Inc. (MDUR) expenses (Corporate Charges). MDUR charges that 17

are not specifically allocable to Montana-Dakota, or another subsidiary of 18

MDUR, are allocated based on the average invested capital for each 19

subsidiary. A three-factor formula for corporate charges was 20

recommended by the Office of Consumer Advocate (OCA) in the 21

Settlement Agreement approved by the Commission in Docket No. 20004-22

117-ER-16. The three-factor formula is comprised of employees and 23

10

earnings in addition to average invested capital. Adjustment No. 18 1

reflects the application of the resulting three-factor formula and is a 2

decrease in expense of $77,834. 3

The items adjusted individually above represent approximately 90 4

percent of total Wyoming gas O&M, as shown on pages 19 through 21. 5

The remaining items, which make up approximately 2.4 percent of total 6

O&M, are assumed to remain flat. 7

Q. What adjustments were made to depreciation expense? 8

A. The adjustment to depreciation expense is contained in Statement 9

H. Adjustment No. 19, as shown in Schedule H-1, restates annual 10

depreciation expense to the pro forma level of plant in service and 11

proposed depreciation rates. The depreciation rates for distribution and 12

general plant are from a 2015 study prepared by AUS Associates. The 13

depreciation rates are shown in Statement Workpapers H1 – H4. The 14

proposed depreciation rates for common plant match the rates approved 15

in Docket No. 20004-117-ER-16. 16

On April 1, 2017, Montana-Dakota redeemed all outstanding 17

preferred stock. Preferred stock has characteristics of both debt and 18

equity. For instance, only $180,000 of the $685,000 in dividends paid 19

each year are deductible on the Company’s tax return. Similar to debt, 20

quarterly dividends paid are based on a stated rate of 4.5 and 4.7 percent. 21

$20 million of long-term debt issued in the first quarter of 2017 provided an 22

opportunity to redeem the preferred stock and replace it with long term 23

11

debt with a stated interest cost of 3.36 percent. At the same time, interest 1

on the debt outstanding is deductible for tax purposes which further 2

reduces the revenue requirement. The result of the redemption is a lower 3

overall cost of capital. 4

As discussed in the testimony of Ms. T. Nygard, a call premium of 5

$600,000 was incurred upon redemption of preferred stock. The call 6

premium has been deferred on the Company’s books. The Company is 7

now proposing to include this regulatory asset in its rate base and began 8

amortizing the balance over the life of the long-term debt of 15 years. An 9

analysis has been prepared which demonstrates the overall net benefit of 10

the redemption, inclusive of the rate base impact, is beneficial to Montana-11

Dakota’s customers. The analysis has been included in the Statement 12

Workpapers beginning on H5. This item has been reflected in the revenue 13

requirement in a manner similar to the unamortized loss on debt 14

Montana-Dakota began amortizing the preferred stock redemption 15

costs during 2018 and has included a pro forma adjustment to reflect the 16

annualization of the amortization as a part of Adjustment 19. 17

Q. What adjustments were made to taxes other than income? 18

A. The adjustments to taxes other than income are contained in 19

Statement I. Adjustment No. 20 restates ad valorem taxes to the pro 20

forma level of plant in service based on the 2018 ratio of ad valorem taxes 21

to plant. The net result is an increase of $4,056. 22

12

The adjustment to payroll taxes (Adjustment No. 21) is an increase 1

of $6,961 based on the ratio of payroll taxes to labor expense for 2018 2

applied to pro forma labor expense. 3

The Wyoming franchise taxes are restated to the pro forma 4

revenue levels by applying the composite franchise rate to pro forma 5

revenues. Likewise, the Wyoming Uniform Assessment tax is also 6

restated to reflect projected revenues and the tax rate effective July 1, 7

2018. Adjustment No. 22 is an increase of $62 and Adjustment No. 23 is a 8

decrease of $664. 9

All other taxes other than income remained at the 2018 level. 10

Q. Does this filing incorporate the changes resulting from the 11

enactment of The Tax Cuts and Jobs Act of 2017 (TCJA)? 12

A. The Tax Cuts and Jobs Act of 2017 (TCJA) was signed into law on 13

December 22, 2017 and incorporated a number of changes which 14

impacted Montana-Dakota’s Wyoming gas operations. The primary 15

impact of the TCJA is the reduction in the corporate income tax rate from 16

35 percent to 21 percent. The rate reduction has a two-fold effect: 17

• A reduction in prospective income taxes on the Company’s income 18

statement beginning January 1, 2018; and 19

• The Company was required to remeasure utility-related deferred 20

income taxes based on the 21 percent tax rate with a regulatory 21

liability established representing the difference between the old and 22

new tax rate and referred to as excess deferred taxes (EDITs). 23

13

As noted, 2018 was the first full year of the reduced income tax 1

rate. Therefore, the per books current and deferred tax calculations for 2

2018 were based on a 21 percent federal income tax rate. The per books 3

deferred income tax expense also reflected the actual EDIT amortizations 4

of all plant related EDITs based on the average rate assumption method 5

(ARAM) that occurred in 2018 as well as first year of straight line 6

amortization of non-plant related EDITs. 7

Q. What adjustments were made to income taxes? 8

A. The adjustments to income taxes are contained in Statement J. 9

The adjustment to current income tax (Adjustment No. 24) reflecting the 10

previously mentioned pro forma revenue and expense adjustment has 11

been calculated on Schedule J-1, page 1 of Statement J. Current income 12

tax expense also incorporates the adjustments to operating income for the 13

change in interest expense and book/tax differences related to 14

depreciation. 15

The adjustment to operating income to reflect the change in interest 16

expense (Adjustment No. 25) is shown on Schedule J-1, page 2. Interest 17

is deductible for tax purposes and interest expense is calculated on the 18

pro forma rate base using the weighted cost of debt and debt ratio from 19

Statement E. The resulting interest expense is an increase of $22,537 20

from the per books level. 21

14

The income tax expense adjustments for the difference between 1

book and tax depreciation and deferred income tax expense on the pro 2

forma plant additions are shown as Adjustment I on Schedule J-2, page 3. 3

The closing/filing and prior period adjustments in the current 4

income tax accrual and in the deferred taxes are eliminated in Adjustment 5

No. 26. Adjusted current and deferred income taxes match those 6

calculated for Wyoming and conform to past Commission practices. 7

As mentioned previously, the plant related EDITs are recognized 8

based on the ARAM method. The amortization does change each year 9

depending on the level of tax depreciation relative to the level of book 10

depreciation. The pro forma amount for the TCJA Excess DIT Plant – 11

ARAM is shown in Adjustment No. 27 on Schedule J-2, page 2 and is an 12

increase in the amortization to deferred taxes of $26,265. 13

Pro Forma Rate Base 14

Q. How was the rate base developed? 15

A. Per books and pro forma rate base for Wyoming gas operations is 16

summarized in Statement A, page 4. The pro forma rate base is based on 17

the year end 2018 rate base and reflects known and measurable 18

adjustments that will occur within twelve months of December 31, 2018. 19

The pro forma adjustments to rate base are summarized on Statement A, 20

page 5. 21

Statement B, page 1 summarizes the pro forma plant in service. 22

Adjustment A is the known and measurable plant additions that will be in 23

15

service by December 31, 2019. The additions of $1,751,297 include 1

additions to distribution, general and common plant and are shown on 2

Statement B, Schedule B-2, pages 1-3. 3

Projects that typically result in incremental customers and 4

associated volumes, labeled Growth Projects, have not been included in 5

the Company’s capital additions to plant as the level of customer additions 6

has typically been insignificant and not reliably predictable. In addition, 7

the Company’s extension policy should result in a matching level of 8

revenue to allow a reasonable return in the capital investments associated 9

with growth projects. 10

Adjustment B, shown in Statement C, increases the reserve for 11

depreciation on the per books plant by $1,712,591 to restate the reserve 12

to the pro forma level in order to match the pro forma plant levels. 13

Q. How were the pro forma adjustments to working capital derived? 14

A. The working capital items are shown in Statement D. Materials and 15

supplies are restated to a thirteen-month average balance, with actual 16

balances through December 31, 2018, in Adjustment C, for an increase of 17

$17,383. 18

Prepaid insurance expense is restated to a thirteen-month average 19

balance in Adjustment D with actual balances through December 31, 2018 20

Pro Forma balances reflect the 2018 levels of insurance expense and is 21

an increase of $30,414. 22

16

The unamortized loss on reacquired debt balance reflects the pro 1

forma 2019 amortization as well as the January 1, 2019 reallocation 2

adjustment and is included as Adjustment E. 3

Adjustment F is the Unamortized Redemption Cost of Preferred 4

Stock and is a decrease of $424 reflecting the pro forma amortization 5

based on a 15 year amortization. The 15 year amortization matches the 6

life of the long term debt that was used in the redemption of the preferred 7

stock. 8

As discussed in the testimony of Ms. Kivisto, the Company’s 9

required contributions to the pension account resulted in a significant 10

prepaid asset and exceeded the amount of pension expense (commonly 11

referred to as FAS 87 or ASC 715 expense) through the revenue 12

requirement. The contributions are tax deductible for Montana-Dakota 13

and any earnings on those contributions in the pension trust account are 14

not subject to income tax. With that in mind, the contributions help 15

maintain the required funding level and, at the same time, typically result 16

in lower FAS 87 expense. 17

Post retirement contributions are typically much more closely 18

matched to the annual expense, so the prepaid asset is much smaller. 19

However, Montana-Dakota considers the benefits and the circumstances 20

surrounding the creation of the prepaid assets or liabilities that it is 21

appropriate to include both pension and post retirement similarly. 22

17

Adjustments G and H are to add the Provision for Pension Benefits 1

of $2,021,350 and Provision for Post Retirements of $27,242 to rate base. 2

Although the 2018 per books amount was recorded on Montana-Dakota’s 3

books it has not been included in order to provide the return on rate base 4

comparable to the authorized rate base. 5

Q. Would you describe the deductions to rate base? 6

A. The adjustments to accumulated deferred income taxes are 7

summarized on Statement J, Schedule J-2, page 1. Adjustment I – 8

Liberalized Depreciation reflects the deferred income taxes related to the 9

2019 plant additions and book/tax differences for 2018 and prior vintage 10

assets and is shown on page 3. 11

Adjustment J shown on Schedule J-2, page 5 is associated with 12

excess deferred income taxes resulting from changes in tax rates. These 13

EDITs are associated with assets and liabilities that are included on the 14

Company’s rate base statement for Wyoming gas operations. Adjustment 15

J includes full normalization, non-plant rate base items and EDITs related 16

to the pension and post retirement prepaid assets the Company has 17

proposed to include in rate base in this filing. 18

Full normalization reflects plant related EDITs from the 1986 tax 19

reform and have been amortized on a straight-line basis using the South 20

Georgia amortization approach. The amortization of the non-plant and 21

pension and post retirement benefits were established upon the 22

enactment of the TCJA. The non-plant and pension and post retirement 23

18

EDITs amortization began in January 2018 and have been proposed to be 1

amortized over a 10 year time frame. 2

The deferred taxes associated with the unamortized loss on debt 3

(Adjustment E, Statement D, Schedule D-1, page 3), included on page 1 4

reflects the anticipated 2019 amortization and Adjustment J is the 5

decrease to deferred taxes to reflect the amortization of the full 6

normalization adjustment for 2019 as shown on Schedule J-2, page 5. 7

As previously discussed, Montana-Dakota is proposing to include 8

Provision for Pension Benefits (Adjustment G) and Provision for Post-9

Retirement (Adjustment H) in rate base. Both prepaid assets have an 10

associated deferred income tax liability associated and has been reflected 11

in these adjustments in Statement D, Schedule D-1, pages 5 and 6, 12

respectively. 13

These are all of the pro forma adjustments to revenue, expense 14

and rate base. 15

Q. Are you proposing changes to the Purchased Gas Cost Adjustment - 16

Rate 88? 17

A. Yes. As discussed above, Montana-Dakota has proposed to 18

include revenues from interruptible customers in the development of the 19

revenue requirement in this proceeding. As such, Subsection 6 will no 20

longer be necessary and the Company has proposed to remove this 21

section from its tariff. 22

19

Upon implementation of final rates in this Docket, the non-core 1

revenue credit will be eliminated and the Company will establish a non-2

core revenue credit balance that will be returned to firm customers. In the 3

Company’s next annual Rate 88 filing, the remaining non-core credit 4

balance will included as a component of the surcharge for firm customers 5

only. The following year, any remaining balance will be included in the 6

unrecovered purchased gas cost account. 7

Q. What is the additional revenue requirement calculated on Exhibit 8

No.__(TRJ-1)? 9

A. Exhibit No.__(TRJ-1), which is identical to Statement A, page 1, 10

shows the calculation of the revenue deficiency of $1,051,927 based on 11

the pro forma operating income and rate base and using the overall rate of 12

return of 7.754 percent from Statement E, page 1. 13

Q. Does this complete your direct testimony? 14

A. Yes, it does. 15

MONTANA-DAKOTA UTILITIES CO.PRO FORMA OPERATING INCOME AND RATE OF RETURN

GAS UTILITY - WYOMINGTWELVE MONTHS ENDED DECEMBER 31, 2018 WITH PRO FORMA ADJUSTMENTS

REFLECTING ADDITIONAL REVENUE REQUIREMENTS

Before ReflectingAdditional Additional AdditionalRevenue Revenue Revenue

Requirements 1/ Requirements Requirements

Operating Revenues Sales $14,715,757 $1,051,927 $15,767,684 Transportation 391,062 391,062 Other 121,514 121,514 Total Revenues $15,228,333 $1,051,927 $16,280,260

Operating Expenses Operation and Maintenance Cost of Gas $9,564,389 $9,564,389 Other O&M 3,455,960 3,455,960 Total O&M 13,020,349 0 13,020,349 Depreciation 1,577,875 1,577,875 Taxes Other Than Income 364,843 9,547 374,390 Current Income Taxes (3,444) 218,900 2/ 215,456 Deferred Income Taxes (100,185) (100,185) Total Expenses $14,859,438 $228,447 $15,087,885

Operating Income $368,895 $823,480 $1,192,375

Rate Base $15,377,547 $15,377,547

Rate of Return 2.399% 7.754%

1/ See Statement A, Page 2.2/ Reflects taxes at 21% after deducting franchise and revenue taxes at 0.9076%.

Docket No. 30013-351-GR-19 Exhibit No. ___ (TRJ-1)

Page 1 of 1

1

MONTANA-DAKOTA UTILITIES CO.

Before the Public Service Commission of Wyoming

Docket No. 30013-351-GR-19

Direct Testimony

of

Jordan R. Hatzenbuhler

Q. Would you please state your name and business address? 1

A. Yes. My name is Jordan R. Hatzenbuhler, and my business 2

address is 400 North Fourth Street, Bismarck, North Dakota 58501. 3

Q. What is your position with Montana-Dakota Utilities Co.? 4

A. I am a Senior Regulatory Analyst in the Regulatory Affairs 5

Department for Montana-Dakota Utilities Co. (Montana-Dakota or 6

Company). 7

Q. Would you please describe your duties as a Senior Regulatory 8

Analyst? 9

A. I assist in preparing various filings required by state commissions, 10

class cost of service studies, and the development of rate design. 11

Q. Would you please outline your educational and professional 12

background? 13

A. I graduated from the University of North Dakota in Grand Forks, 14

North Dakota with a Bachelor of Accountancy degree, and I am a Certified 15

Public Accountant (CPA). I started my career with 16

PricewaterhouseCoopers as an audit associate and have since held 17

multiple positions within MDU Resources Group prior to starting in my 18

2

current role in 2015, including: Internal Auditor, Investor Relations 1

Financial Analyst, and Senior Financial Reporting and Planning Analyst. 2

Q. What is the purpose of your testimony in this proceeding? 3

A. The purpose of my testimony is to present the results of the class 4

cost of service study and to address the effect of the proposed revenue 5

deficiency of $1,051,927, as identified by Mr. Jacobson's direct testimony, 6

on each of the Company's natural gas rates, including the distribution of 7

the revenue requirement to the various customer classes. 8

Q. What statements and exhibits are you sponsoring in this 9

proceeding? 10

A. I am sponsoring Statement K, Statement L, Exhibit No.___(JRH-1) 11

and Exhibit No.___(JRH-2). 12

Q. Would you please explain the embedded class cost of service study 13

contained in Statement K? 14

A. Statement K contains a summary of the results of the embedded 15

class cost of service study by the major rate classifications, Residential, 16

Small Firm General, Large Firm General, Small Interruptible Sales and 17

Transportation, and Large Interruptible Sales and Transportation. 18

Statement K, Schedule K-1 provides a report entitled "Cost of Service by 19

Component." This report shows the total dollars and unit cost required 20

under each rate if the Pro Forma rate of return of 7.754 percent were to be 21

earned for the demand, energy and customer cost components of each 22

rate schedule. 23

3

Statement K, Schedule K-2, is a report of the rate base, income 1

statement and Pro Forma adjustments as allocated to each rate schedule. 2

The description of the distribution plant allocators is provided in Statement 3

K, Schedule K-3. The allocation factors for each class and cost 4

component are provided in Statement K, Schedule K-4. 5

The embedded class cost of service study is based on the 6

Wyoming natural gas operations results for the 12 months ended 7

December 31, 2018 as adjusted to reflect the Pro Forma adjustments as 8

sponsored by Mr. Jacobson. 9

Q. What were the results of the embedded class cost of service study? 10

A. The overall Wyoming natural gas rate of return based on the actual 11

results for the 12 months ending December 31, 2018 adjusted for known 12

and measurable changes is 2.399 percent. The returns by customer class 13

are as shown below: 14

Customer Class ROR Residential Service 0.498 % Small Firm General Service 1.764 % Large Firm General Service 2.575 % Small Interruptible Service 40.312 % Large Interruptible Service 63.687 %

Q. How did you determine what costs should be assigned to each class 15

of customers? 16

A. The starting point was classifying the functionalized costs by 17

FERC account for all rate base and income statement items as demand, 18

energy or customer related based on the component of service being 19

4

provided. Demand-related costs are costs that vary with the demand 1

imposed by the customer, energy-related costs are costs that vary with the 2

amount of natural gas used by the customer and customer-related costs 3

are fixed costs driven by the number of customers served. 4

Next the plant, expense and revenue items that were identified as 5

directly related to a specific class of customers were directly assigned to 6

the appropriate class. Finally, the remaining costs were allocated using 7

the various allocation factors shown in Statement K, Schedule K-4, on the 8

basis of cost responsibility. 9

Q. Would you please provide an overview of the allocation process 10

including the rationale underlying the choice of allocation factors? 11

A. Yes. I will start with the plant in service items from the Gas Utility 12

Plant in Service, Statement B starting on Statement K, Schedule K-2, 13

Page 1. The allocation of distribution plant serves as the basis for 14

allocating many of the rate base items. 15

Turning now to the distribution plant investment; each distribution 16

plant account is analyzed and allocated based on the cause for the 17

investment. Distribution mains, services and meters represent 18

approximately 93 percent of the total gross distribution investment and 19

therefore the allocation of these three accounts drives the allocation of the 20

remaining distribution investment. The investment in distribution mains 21

has been assigned 75 percent to the demand component and 25 percent 22

to the customer component. The amount classified as demand related 23

was allocated to each rate class based on the design day demand 24

5

attributed to each class and the amount classified as customer related 1

was allocated to each rate class based on the average number of 2

customers in each rate class. The investment in services, service 3

regulators and meters is related solely to a customer connection and 4

therefore classified as customer related. Service regulators and meters 5

were allocated to the rate classes based on Factor 10 which represents a 6

meter weight for each customer class. The meter weights were derived by 7

comparing the installed cost per meter for each rate class to the cost 8

necessary to serve residential customers with the residential class 9

weighted as one. A description of the distribution plant allocators is 10

provided in Statement K, Schedule K-3. 11

The allocation of the remainder of the rate base items is self-12

explanatory with the allocation factor noted for each line item. 13

Q. Can you elaborate on why the investment in distribution mains was 14

assigned 75 percent to the demand component and 25 percent to the 15

customer component? 16

A. If all customer classes had equal but minimal gas service needs, 17

the Company would install a system comprised of only two-inch mains. 18

Seeing that two-inch mains would be the minimal size of a system, it is 19

appropriate to assign a portion of the main costs to the customer 20

component to reflect the system design the Company would employ if all 21

customers were to use little or no gas. To reflect customer needs, or 22

demands on the system, the Company installs larger mains when 23

6

customers use more gas than can be served from a two-inch main 1

system. 2

To estimate the portion of the mains balance that is customer-3

related the Company utilizes the minimum system method. In general 4

terms, the approach calls for the analyst to compute the cost of the 5

distribution system’s total footage utilizing the average book cost of the 6

minimum sized pipe commonly in use (two-inch mains) and compare this 7

amount to the actual mains plant balance. The cost of the minimum 8

system divided into the actual mains plant balance is thought to be the 9

approximate customer-related component, with the remainder being 10

demand-related. 11

The Company’s financial data at the level of detail required is 12

limited to the mains with a vintage of 1995 or later so the minimum system 13

study was performed using only that data. The data available reflects 14

approximately 41% of the total footage of mains and approximately 65% of 15

the plant balance. The results of the study indicate the customer 16

component of the mains plant is approximately 70%. However, the 17

Company is proposing to maintain its conservative 25% allocation to the 18

customer component and 75% to the demand component for this 19

proceeding. 20

Q. Would you please continue your discussion of the embedded class 21

cost of service study with an explanation of the income statement 22

items in the study? 23

7

A. The allocation of the income statement items starts on Statement 1

K, Schedule K-2, Pages 2, 10, and 18 for the Residential, Firm General, 2

and Interruptible classes, respectively, with the allocation of revenues. As 3

shown, sales and transportation service revenues are directly assigned 4

based on the revenues produced by each rate class. The other revenues 5

are allocated based on the source of the revenue item. Each item is 6

shown along with the allocation factor applied. 7

Operation and maintenance expenses consisting of cost of 8

purchased gas, production, distribution customer accounts, customer 9

service and information, sales and administrative and general expenses 10

are shown starting in Statement K, Schedule K-2, Pages 3, 11, and 19 for 11

the Residential, Firm General, and Interruptible classes, respectively. The 12

cost of purchased gas is directly assigned to each class based on the gas 13

costs included in the Pro Forma revenues. The cost of purchased gas is 14

recovered through the gas cost tracking adjustment and is not recovered 15

through the rates that will be established in this rate case. The remaining 16

operation and maintenance expenses are allocated based on cost 17

causation and typically follow the plant investment previously described in 18

the rate base section. The remainder of the income statement reflects the 19

allocation of depreciation expense, taxes other than income and income 20

taxes as denoted by each line item. Finally, the Pro Forma adjustments 21

are set forth in the Overall Cost of Service section, Statement K, Schedule 22

K-2, Pages 5, 13, and 21 for the Residential, Firm General, and 23

Interruptible classes, respectively. The Pro Forma allocation factors begin 24

8

on Pages 2, 5, and 8 of Statement K, Schedule K-4 for the Residential, 1

Firm General, and Interruptible classes, respectively. The allocation of 2

costs to each rate schedule is presented in the same format as described 3

above for Residential Rate 60. 4

Q. For what purpose has the embedded class cost of service study 5

been used? 6

A. The study results have been used to guide the allocation of the 7

revenue requirement to the various classes as well as the rate designs 8

applicable to each customer class. 9

Q. What methodology did you use to apportion the proposed rate 10

increase among the customer classes? 11

A. As discussed in Ms. Kivisto’s testimony, the core/non-core revenue 12

allocation process authorized in Docket No. 30013-GR-93-47 is proposed 13

to be discontinued in this proceeding. Accordingly, costs were assigned to 14

the interruptible sales and transportation classes in the same manner as 15

the firm classes. 16

I used the embedded class cost study as a guide to allocating the 17

revenue deficiency to the various customer classes. The revenue 18

increase necessary to bring the classes to the overall rate of return ranges 19

from an increase of approximately 10.9 percent for Residential Rate 60 to 20

a reduction of 62.1 percent for Large Interruptible Rate 82. In allocating 21

the revenue increase I first considered the rates of return each class is 22

achieving, as well as the required increases or decreases necessary to 23

move rates to cost of service. The magnitude of the decreases required 24

9

for the interruptible class rates to be based solely on the cost to serve is 1

too substantial and therefore and unreasonable proposition in this case. 2

However, my goal with the allocation of the increase is still to move in that 3

direction. 4

With the overall increase in revenues at 6.96% I wanted to ensure 5

the interruptible classes received a moderate decrease while keeping the 6

impact to the firm classes reasonable in nature and not excessively out of 7

line with the overall increase. This balance was struck by moving the 8

small and large firm classes to cost of service rates while giving the 9

interruptible classes 5% of their respective decreases and allowing the 10

remainder of the increase to the residential class. 11

Q. What is the percentage of the proposed increase by class of 12

customer? 13

A. The proposed increase to each of the classes is shown in the table 14

below: 15

Class Increase Residential 8.41 % Small Firm General 7.76 % Large Firm General 4.32 % Small Interruptible -1.03 % Large Interruptible -3.06 % Overall 6.96 %

16

The greatest increase, 8.4 percent for Residential, is approximately 17

1.2 times the overall increase and compares to the 1.6 times that would be 18

required to achieve cost of service rates for the class. 19

10

Q. What is the total revenue effect of the proposed changes to the 1

Company’s natural gas distribution rates? 2

A. The proposed rates will produce additional revenues of $1,052,167 3

or 6.96 percent annually based on the Pro Forma 2018 throughput. This 4

is different than the revenue deficiency presented in Mr. Jacobson’s 5

testimony due to rounding occurring in the revenue allocation process. 6

Exhibit No. __ (JRH-1) represents a summary of the proposed revenue 7

increase to the firm service customers. The exhibit shows the rate number 8

and a description along with the revenues calculated under the present 9

and proposed rates. The amount and percentage increase is also shown 10

for the proposed revenue increase. 11

Q. Would you please explain Exhibit No. ____(JRH-2)? 12

A. Yes. Exhibit No. ____ (JRH-2) depicts bill comparisons based on 13

typical monthly consumption levels for an annual period for Residential 14

and Firm General Service customers. As shown by the comparisons, the 15

proposed rate structure will result in an average increase, based on final 16

proposed rates, of approximately $3.94 per month for the typical 17

Residential customer using 88 dk on an annual basis. A Small Firm 18

General Service customer (Rate 70 with a meter rated less than 500 cubic 19

feet per hour) would see an increase of approximately $5.59 per month 20

and a Large General Service customer (Rate 70 with a meter rated 500 21

cubic feet per hour or more) would see an increase of approximately 22

$20.59 per month. 23

11

Q. What were the objectives underlying the allocation of the increase 1

and the rates proposed to recover the revenue requirement? 2

A. The embedded class cost of service study and proposed revenue 3

allocation embody several of the recognized ratemaking objectives by 4

their effectiveness in yielding the total revenue requirement under the fair-5

return standard, fairness of the specific rates in the apportionment of the 6

total costs of service among the different consumers, and efficiency of the 7

rate classes. The rate forms proposed also recognize a balanced and 8

gradual move toward meeting the objectives noted above to be cognizant 9

of the rate stability objective. To capture that balance, the proposed rates 10

reflect a move toward cost-based rates but not the full step necessary to 11

price each service to reflect the specific embedded cost components. 12

Q. How are you proposing to collect the allocated increase from each of 13

the rate classes? 14

A. First, I am proposing increases to the Basic Service Charges for the 15

Residential class. The Basic Service Charge under Residential Rate 60 is 16

proposed at $0.64 per day which reflects an average monthly charge of 17

$19.46, an increase of $3.65 per month from the currently effective charge 18

based on the customer related costs identified in the Embedded Class 19

Cost of Service Study provided in Statement K. The Company is not 20

proposing an increase to any of the remaining customer classes. 21

After taking into account any revenue increase associated with the 22

changes in the Basic Service Charge, the remaining increase in revenues 23

is proposed to be reflected through the Distribution Delivery Charge 24

12

components for the Residential class. The entire increase or decrease in 1

revenues assigned to the other rate classes was assigned to the 2

Distribution Deliver Charge. 3

The rate design calculations supporting the final rate levels are 4

included in Statement L, Pages 3-6. A representation of the annual billing 5

impact for the Residential and Firm General Service classes is provided 6

on Pages 7-9 of Statement L. 7

Q. Would you please explain the rationale increasing the Residential 8

Basic Service Charge? 9

A. Aligning fixed and variable rates with the costs they are intended to 10

recover will lead to better and more efficient outcomes for both the 11

Company and its customers by: 12

1. Reducing the volatility in the Company’s revenues due to 13

extreme weather or economic conditions; 14

2. Creating more stable customer bills and sensible price signals 15

for customers seeking to invest in energy efficiency, energy conservation 16

measures or distributed generation; and 17

3. Reducing the cross-subsidies within the class. 18

By increasing the Basic Service Charge the Company is less dependent 19

on sales to recover its fixed costs. Higher fixed charges can reduce the 20

need for frequent rate increases caused by reduced sales, create a more 21

stable customer bill and align rates with costs. 22

Q. Does this conclude your direct testimony? 23

A. Yes, it does. 24

MONTANA-DAKOTA UTILITIES CO.REVENUES UNDER CURRENT AND PROPOSED RATES

GAS UTILITY - WYOMINGPro Forma 2018

Total ProposedPro Forma Proposed Revenue Percent

Customer Class/Rate Customers 1/ Dk 1/ Revenue 1/ Revenue 2/ Increase Increase

Residential - Rate 60 16,577 1,455,905 $9,330,999 $10,115,308 $784,309 8.41%

Firm General Service - Rates 70 & 72 2,465 1,059,697 5,227,862 5,507,981 280,119 5.36%

Small Interruptible 11 209,637 222,222 219,937 (2,285) -1.03%

Large Interruptible 6 2,527,542 325,736 315,760 (9,976) -3.06%

Total Wyoming 19,059 5,252,781 $15,106,819 $16,158,986 $1,052,167 6.96%

1/ Statement F, Schedulle F-2, Page 1. 2/ Statement L, Page 2.

Docket N

o. 30013-351-GR

-19 Exhibit N

o.___(JRH

-1) Page 1 of 1

MONTANA-DAKOTA UTILITIES CO.GAS UTILITY - WYOMING

RATE 60 BILL COMPARISONRESIDENTIAL GAS SERVICE

Present Proposed Amount of %Month Dk Rate Rate Increase Increase

January 15 $79.84 $84.16 $4.32 5.41%February 14 74.03 77.95 3.92 5.30%March 10 58.60 62.72 4.12 7.03%April 8 49.58 53.50 3.92 7.91%May 6 41.61 45.57 3.96 9.52%June 3 28.34 32.06 3.72 13.13%July 2 24.62 28.42 3.80 15.43%August 2 24.62 28.42 3.80 15.43%September 2 24.10 27.78 3.68 15.27%October 5 37.36 41.28 3.92 10.49%November 9 53.83 57.79 3.96 7.36%December 12 67.10 71.30 4.20 6.26%

Total 88 $563.63 $610.95 $47.32 8.40%

Average Increase per Month $3.94

RATE 60 Current 1/ Proposed 2/Basic Delivery Charge $0.52 $0.64Distribution Delivery $0.501 $0.541Cost of Gas $3.747 $3.747

1/ Basic service charge and distribution rates effective with service rendered on and after June 1, 2015, Docket No. 30013-297-GR-14. Current cost of gas and non-core credit effective with service rendered on and after March 1 2019, Docket No. 30013-347-GP-19.2/ Statement L, page 3.

Docket No. 30013.351-GR-19 Exhibit No.___(JRH-2)

Page 1 of 3

MONTANA-DAKOTA UTILITIES CO.GAS UTILITY - WYOMING

RATE 70 BILL COMPARISONFIRM GENERAL GAS SERVICE (< 500 Cubic Feet Per Hour Meters)

Present Proposed Amount of %Month Dk Rate Rate Increase Increase

January 27 $131.77 $143.76 $11.99 9.10%February 25 121.54 132.64 11.10 9.13%March 18 94.77 102.76 7.99 8.43%April 13 73.54 79.32 5.78 7.86%May 8 53.66 57.21 3.55 6.62%June 5 40.66 42.88 2.22 5.46%July 3 33.10 34.44 1.34 4.05%August 2 28.99 29.88 0.89 3.07%September 3 32.43 33.77 1.34 4.13%October 8 53.66 57.21 3.55 6.62%November 16 85.88 92.98 7.10 8.27%December 23 115.32 125.54 10.22 8.86%

Total 151 $865.32 $932.39 $67.07 7.75%

Average Increase per Month $5.59

RATE 70 Current 1/ Proposed 2/Basic Delivery Charge $0.67 $0.67Distribution Delivery $0.364 $0.808Cost of Gas $3.747 $3.747

1/ Basic service charge and distribution rates effective with service rendered on and after June 1, 2015, Docket No. 30013-297-GR-14. Current cost of gas and non-core credit effective with service rendered on and after March 1 2019, Docket No. 30013-347-GP-19.2/ Statement L, page 4.

Docket No. 30013.351-GR-19 Exhibit No.___(JRH-2)

Page 2 of 3

MONTANA-DAKOTA UTILITIES CO.GAS UTILITY - WYOMING

RATE 70 BILL COMPARISONFIRM GENERAL GAS SERVICE ( > 500 Cubic Feet Per Hour Meters)

PRESENT PROPOSED AMOUNT OF %MONTH DK RATE RATE INCREASE INCREASE

January 187 $824.56 $862.14 $37.58 4.56%February 178 782.16 817.94 35.78 4.57%March 138 623.12 650.86 27.74 4.45%April 112 514.43 536.94 22.51 4.38%May 83 397.01 413.70 16.69 4.20%June 52 267.77 278.22 10.45 3.90%July 40 220.24 228.28 8.04 3.65%August 37 207.91 215.34 7.43 3.57%September 43 230.77 239.42 8.65 3.75%October 68 335.35 349.02 13.67 4.08%November 124 563.76 588.69 24.93 4.42%December 167 742.34 775.90 33.56 4.52%

Total 1,229 $5,709.42 $5,956.45 $247.03 4.33%

Average Increase per Month $20.59

RATE 70 Current 1/ Proposed 2/Basic Delivery Charge $1.80 $1.80Distribution Delivery $0.364 $0.565Cost of Gas $3.747 $3.747

1/ Basic service charge and distribution rates effective with service rendered on and after June 1, 2015, Docket No. 30013-297-GR-14. Current cost of gas and non-core credit effective with service rendered on and after March 1 2019, Docket No. 30013-347-GP-19.2/ Statement L, page 4.

Docket No. 30013.351-GR-19 Exhibit No.___(JRH-2)

Page 3 of 3

1

MONTANA-DAKOTA UTILITIES CO.

Before the Wyoming Public Service Commission

Docket No. 30013-351-GR-19

Direct Testimony of

Stephanie Bosch

Q. Would you please state your name and business address? 1

A. My name is Stephanie Bosch and my business address is 400 2

North Fourth Street, Bismarck, North Dakota 58501. 3

Q. What is your position with Montana-Dakota Utilities Co.? 4

A. I am the Regulatory Affairs Manager for Montana-Dakota Utilities 5

Co. (Montana-Dakota). 6

Q. Would you please describe your duties as Regulatory Affairs 7

Manager? 8

A. I am responsible for the proper application of the Company’s gas 9

and electric rates in the Customer Care and Billing System (CC&B), the 10

application of tariffs and the preparation of miscellaneous rate filings. 11

Q. Would you please describe your education and professional 12

background? 13

A. I graduated from the University of North Dakota in 1995 with a 14

Bachelor of Business and Public Administration degree in Banking and 15

Financial Economics. I joined Montana-Dakota in June 1997 as a Rate 16

Clerk in the Regulatory Affairs area and realized positions of increasing 17

responsibility within the Regulatory Affairs Department until 2011 when I 18

2

left the Company. In 2013 I returned to the Company as a Regulatory 1

Analyst before attaining my current position in August of 2015. 2

Q. Have you testified in other proceedings before regulatory bodies? 3

A. Yes. I have previously presented testimony before this Commission 4

and the Public Service Commissions of Montana and North Dakota. 5

Q. What is the purpose of your testimony in this proceeding? 6

A. The purpose of my testimony is present the gas revenues at current 7

rates included in Statement F Schedules F-2 and F-3 of this Application 8

and the changes proposed to the Company’s tariffs provided in Appendix 9

B. 10

Q. What statements and exhibits are you sponsoring in this 11

proceeding? 12

A. I am sponsoring Statement F Schedules F-2 and F-3 and the 13

proposed rate schedules provided in Appendix B to the Application, with 14

the exception of the proposed change to the Purchased Gas Cost 15

Adjustment (PGA) Rate 88 tariff, which is sponsored by Mr. Jacobson. 16

Q. Would you please explain the calculation of revenue at current rates 17

included in Statement F Schedules F-2 and F-3? 18

A. Yes. The Company applied the Basic Service Charges and 19

Distribution Delivery Charges (including the current non-core credit rate) 20

applicable under each rate schedule, and as authorized in Docket No. 21

30013-297-GR-14, to an annualized level of customers and volumes. 22

Interruptible sales and transportation customers were priced at the 23

3

applicable rate schedules’ maximum rate per Dk, unless service is being 1

provided for under a contract rate. The PGA rates are reflective of the 2

March 2019 PGA rates, excluding the current surcharge. 3

Q. Would you please describe changes the Company is proposing to its 4

gas tariffs? 5

A. Yes. The Company is proposing the following changes to the gas 6

tariffs as clearly identified in the legislative copy of the tariffs provided in 7

Appendix B of this Application: 8

• The rates described by Mr. Hatzenbuhler have been incorporated 9

into the proposed tariffs. 10

• Remove the “core” and “non-core” designations included in select 11

rate schedules’ titles. 12

• Revise the Metering Requirements provisions under the 13

Company’s Interruptible Gas Sales Rates 71 and 85 tariffs to 14

recognize that, while most customers are located within the 15

Company’s fixed network system used for meter reading and 16

therefore additional equipment is not needed for their meter data, 17

select customers may still be required to install additional 18

equipment for the transmission of such meter data if located 19

outside the Company’s fixed network communication system. 20

• Clarify the charges included in the determination of a penalty 21

payment as provided for under the Penalty for Failure to Curtail or 22

Interrupt provisions applicable under the Company’s Interruptible 23

4

Gas Sales Rates 71 and 85 and Transportation Rates 81 and 82 1

tariffs. The proposed change clarifies that all charges billed under 2

Rate 70, with the exception of the Basic Service Charge, would be 3

billed a customer in the event of a penalty situation. 4

• Revise the following provisions included in the Conditions of 5

Service Rate 100 tariff to: 6

o Revise the non-residential reconnection fee for seasonal or 7

temporary customers to reduce the seasonal reconnection 8

fee for distribution revenues collected while the customer 9

was in-service for usage above the respective class’ 10

average annual authorized use. 11

o Remove the word “written” from Paragraph 20h 12

(Reconnection after Nonpayment) of the General Terms 13

and Conditions section of Rate 100. The proposed change 14

eliminates the need to have a payment arrangement be in 15

written form. 16

• Other minor wording changes are included throughout the 17

Company’s tariffs to improve the readability of the rate without 18

modifying any conditions. These changes are clearly denoted on 19

the tariff sheets in the legislative format. 20

Q. Is the Company proposing any changes to the Company’s Extension 21

Policies Rate 119 and 120? 22

5

A. Yes. The Company is proposing to update the Levelized Annual 1

Revenue Requirement (LARR) Factor identified on the tariff to reflect the 2

costs and return included in this case. 3

The Company is also proposing to clarify that the cost of the 4

extension shall include all costs from the main, if applicable, up to, and 5

including the riser. All costs after the riser will not be included in the cost 6

of the extension. 7

Q. Does this conclude your testimony? 8

A. Yes. 9