20230601Direct McKenzie.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

OF IDAHO POWER COMPANY FOR AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC SERVICE IN THE STATE OF IDAHO AND FOR
ASSOCIATED REGULATORY ACCOUNTING TREATMENT.
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CASE NO. IPC-E-23-11

IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
ADRIEN M. MCKENZIE, CFA

TABLE OF CONTENTS

I. INTRODUCTION........................................1 A. Overview.......................................1
B. Summary and Conclusions........................4
II. RETURN ON EQUITY FOR IDAHO POWER....................4
A. Importance of Financial Strength...............5 B. Conclusions and Recommendations...............10
III. FUNDAMENTAL ANALYSES...............................11
A. Idaho Power...................................12 B. Outlook for Capital Costs.....................15
IV. COMPARABLE RISK PROXY GROUP........................25 A. Determination of the Proxy Group..............27 B. Relative Risks of the Electric Group and Idaho
Power.........................................28 C. Regulatory Mechanisms.........................37
D. Capital Structure.............................40
V. CAPITAL MARKET ESTIMATES AND ANALYSES..............45 A. Economic Standards............................46 B. Discounted Cash Flow Analysis.................52 C. Capital Asset Pricing Model...................62
D. Empirical Capital Asset Pricing Model.........67 E. Utility Risk Premium..........................72
F. Expected Earnings Approach....................76 G. Flotation Costs...............................80
VI. NON-UTILITY BENCHMARK..............................87

Exhibit Description_______________________

McKenzie, DI 1 Idaho Power Company

I. INTRODUCTION
Q. Please state your name and business address. 1
A. Adrien M. McKenzie, 3907 Red River, Austin, 2
Texas, 78751. 3
Q. In what capacity are you employed? 4
A. I am President of Financial Concepts and 5
Applications, Inc. (“FINCAP”), a firm providing financial, 6
economic, and policy consulting services to business and 7
government. 8
Q. Please describe your educational background and 9
qualifications. 10
A. A description of my background and 11
qualifications, including a resume containing the details of my 12
experience, is attached as Exhibit 7. 13
A. Overview 14
Q. What is the purpose of your testimony in this 15
case? 16
A. The purpose of my testimony is to present to the 17
Idaho Public Utilities Commission (“IPUC” or “Commission”) my 18
independent assessment of the just and reasonable return on 19
equity (“ROE”) for the jurisdictional utility operations of 20
Idaho Power Company (“Idaho Power” or the “Company”). In 21
addition, I also examine the reasonableness of Idaho Power’s 22

McKenzie, DI 2 Idaho Power Company

common equity ratio, considering both the specific risks faced 1
by the Company and other industry guidelines. 2
Q. Please summarize the information and materials 3
you rely on to support the opinions and conclusions contained 4
in your testimony. 5
A. To prepare my testimony, I use information from a 6
variety of sources that would normally be relied upon by a 7
person in my capacity. I am familiar with the organization, 8
finances, and operations of Idaho Power from my involvement in 9
prior proceedings before the IPUC, the Public Utility 10
Commission of Oregon (“OPUC”), and the Federal Energy 11
Regulatory Commission (“FERC”). In connection with this filing, 12
I consider and rely upon corporate disclosures, publicly 13
available financial reports and filings, and other published 14
information relating to Idaho Power. I also review information 15
relating generally to capital market conditions and 16
specifically to investor perceptions, requirements and 17
expectations for utilities. These sources, coupled with my 18
experience in the fields of finance and utility regulation, 19
have given me a working knowledge of the issues relevant to 20
investors’ required return for Idaho Power, and they form the 21
basis of my analyses and conclusions. 22
Q. How is your testimony organized? 23

McKenzie, DI 3 Idaho Power Company

A. First, I summarize my conclusions and 1
recommendations, giving special attention to the importance of 2
financial strength and the implications of regulatory 3
mechanisms and other risk factors. I also comment on the 4
reasonableness of the Company’s proposed capital structure. 5
Next, I briefly review Idaho Power’s operations and 6
finances. I discuss current conditions in the capital markets 7
and their implications in evaluating a just and reasonable 8
return for the Company. I then explain the development of the 9
proxy group of electric utilities used as the basis for my 10
quantitative analyses. With this as a background, I discuss 11
well-accepted quantitative analyses to estimate the current 12
cost of equity for the proxy group of electric utilities. These 13
include the discounted cash flow (“DCF”) model, the Capital 14
Asset Pricing Model (“CAPM”), the empirical CAPM (“ECAPM”), an 15
equity risk premium approach based on allowed ROEs, and 16
reference to expected earned rates of return for electric 17
utilities, which are all methods that are commonly relied on in 18
regulatory proceedings. 19
Based on the results of my analyses, I evaluate a fair 20
ROE for Idaho Power. My evaluation takes into account the 21
specific risks for the Company’s utility operations and Idaho 22
Power’s requirements for financial strength. Further, 23
consistent with the fact that utilities must compete for 24

McKenzie, DI 4 Idaho Power Company

capital with firms outside their own industry, I corroborate my 1
utility quantitative analyses by applying the DCF model to a 2
group of low-risk non-utility firms. 3
B. Summary and Conclusions 4
Q. What is your recommended ROE for Idaho Power? 5
A. I apply the DCF, CAPM, ECAPM, risk premium, and 6
expected earnings analyses to a proxy group of electric 7
utilities, with the results being summarized on Exhibit 8. As 8
shown there, I recommend a cost of equity range for the 9
Company’s electric operations of 10.0 percent to 11.0 percent, 10
or 10.1 percent to 11.1 percent after adjusting for the impact 11
of common equity flotation costs. It is my conclusion that the 12
10.6 percent midpoint of this range represents a just and 13
reasonable ROE that is adequate to compensate Idaho Power’s 14
investors, while maintaining the Company’s financial integrity 15
and ability to attract capital on reasonable terms. 16
II. RETURN ON EQUITY FOR IDAHO POWER
Q. What is the purpose of this section? 17
A. This section presents my conclusions regarding 18
the fair ROE applicable to Idaho Power’s jurisdictional utility 19
operations. I also describe the relationship between ROE and 20
preservation of a utility’s financial integrity and the ability 21
to attract capital. Finally, I discuss the reasonableness of 22
the Company’s capital structure request in this case. 23

McKenzie, DI 5 Idaho Power Company

A. Importance of Financial Strength 1
Q. What is the role of the ROE in setting a 2
utility’s rates? 3
A. The ROE is the cost of attracting and retaining 4
common equity investment in the utility’s physical plant and 5
assets. This investment is necessary to finance the asset base 6
needed to provide utility service. Investors commit capital 7
only if they expect to earn a return on their investment 8
commensurate with returns available from alternative 9
investments with comparable risks. Moreover, a just and 10
reasonable ROE is integral in meeting sound regulatory 11
economics and the standards established by the U.S. Supreme 12
Court. The Bluefield case set the standard against which just 13
and reasonable rates are measured: 14
A public utility is entitled to such rates as will 15 permit it to earn a return on the value of the 16 property which it employs for the convenience of 17
the public equal to that generally being made at 18 the same time and in the same general part of the 19
country on investments in other business 20 undertakings which are attended by corresponding 21 risks and uncertainties. . . . The return should 22
be reasonable, sufficient to assure confidence in 23 the financial soundness of the utility, and should 24
be adequate, under efficient and economical 25 management, to maintain and support its credit and 26 enable it to raise money necessary for the proper 27
discharge of its public duties.1 28

1 Bluefield Water Works & Improvement Co. v. Pub. Serv. Comm'n, 262 U.S. 679 (1923) (“Bluefield”).

McKenzie, DI 6 Idaho Power Company

The Hope case expanded on the guidelines for a reasonable ROE, 1
reemphasizing its findings in Bluefield and establishing that 2
the rate-setting process must produce an end-result that 3
allows the utility a reasonable opportunity to cover its 4
capital costs. The Court stated: 5
From the investor or company point of view it is 6 important that there be enough revenue not only for 7
operating expenses but also for the capital costs 8 of the business. These include service on the debt 9
and dividends on the stock. . . . By that standard, 10 the return to the equity owner should be 11 commensurate with returns on investments in other 12 enterprises having corresponding risks. That 13 return, moreover, should be sufficient to assure 14
confidence in the financial integrity of the 15 enterprise, so as to maintain credit and attract 16 capital.2 17
18 In summary, the Supreme Court’s findings in Hope and Bluefield 19
established that a just and reasonable ROE must be sufficient 20
to 1) fairly compensate the utility’s investors, 2) enable the 21
utility to offer a return adequate to attract new capital on 22
reasonable terms, and 3) maintain the utility’s financial 23
integrity. These standards should allow the utility to fulfill 24
its obligation to provide reliable service while meeting the 25
needs of customers through necessary system replacement and 26
expansion, but the Supreme Court’s requirements can only be 27
met if the utility has a reasonable opportunity to actually 28
earn its allowed ROE. 29

2 Fed. Power Comm'n v. Hope Natural Gas Co., 320 U.S. 591 (1944) (“Hope”).

McKenzie, DI 7 Idaho Power Company

While the Hope and Bluefield decisions did not establish a 1
particular method to be followed in fixing rates (or in 2
determining the allowed ROE),3 these and subsequent cases 3
enshrined the importance of an end result that meets the 4
opportunity cost standard of finance. Under this doctrine, the 5
required return is established by investors in the capital 6
markets based on expected returns available from comparable 7
risk investments. Coupled with modern financial theory, which 8
has led to the development of formal risk-return models (e.g., 9
DCF and CAPM), practical application of the Bluefield and Hope 10
standards involves the independent, case-by-case consideration 11
of capital market data in order to evaluate an ROE that will 12
produce a balanced and fair end result for investors and 13
customers. 14
Q. Throughout your testimony you refer repeatedly to 15
the concepts of “financial strength,” “financial integrity” and 16
“financial flexibility.” Would you briefly describe what you 17
mean by these terms? 18
A. These terms are generally synonymous and refer to 19
the utility’s ability to attract and retain the capital that is 20
necessary to provide service at reasonable cost, consistent 21
with the Supreme Court standards. Idaho Power’s plans call for 22

3 Id. at 602 (finding, “the Commission was not bound to the use of any single formula or combination of formulae in determining rates.” and, “[I]t is not theory but the impact of the rate order which counts.)

McKenzie, DI 8 Idaho Power Company

a continuation of capital investments to preserve and enhance 1
service reliability for its customers. The Company must 2
generate adequate cash flow from operations, together with 3
access to capital from external sources, to fund these 4
requirements and for repayment of maturing debt. 5
Rating agencies and potential debt investors tend to 6
place significant emphasis on maintaining strong financial 7
metrics and credit ratings that support access to debt capital 8
markets under reasonable terms. This emphasis on financial 9
metrics and credit ratings is shared by equity investors who 10
also focus on cash flows, capital structure and liquidity, much 11
like debt investors. Investors understand the important role 12
that a supportive regulatory environment plays in establishing 13
a sound financial profile that will permit the utility access 14
to debt and equity capital markets on reasonable terms in both 15
favorable financial markets and during times of potential 16
disruption and crisis. 17
Q. What part does regulation play in ensuring that 18
Idaho Power has access to capital under reasonable terms and on 19
a sustainable basis? 20
A. Regulatory signals are a major driver of 21
investors’ risk assessment for utilities. Investors recognize 22
that constructive regulation is a key ingredient in supporting 23
utility credit ratings and financial integrity. Security 24

McKenzie, DI 9 Idaho Power Company

analysts study commission orders and regulatory policy 1
statements to advise investors about where to put their money. 2
As Moody’s Investors Service (“Moody’s”) noted, “the regulatory 3
environment is the most important driver of our outlook because 4
it sets the pace for cost recovery.”4 Similarly, S&P Global 5
Ratings (“S&P”) observed that, “Regulatory advantage is the 6
most heavily weighted factor when S&P Global Ratings analyzes a 7
regulated utility’s business risk profile.”5 The Value Line 8
Investment Survey (“Value Line”) summarizes these sentiments: 9
As we often point out, the most important factor 10 in any utility’s success, whether it provides 11
electricity, gas, or water, is the regulatory 12 climate in which it operates. Harsh regulatory 13 conditions can make it nearly impossible for the 14
best run utilities to earn a reasonable return on 15 their investment.6 16
17 In addition, the ROE set by regulators impacts investor 18
confidence in not only the jurisdictional utility, but also in 19
the ultimate parent company that is the entity that actually 20
issues common stock. 21
Q. Do customers benefit from the utility’s financial 22
flexibility? 23

4 Moody’s Investors Service, Regulation Will Keep Cash Flow Stable As Major
Tax Break Ends, Industry Outlook (Feb. 19, 2014).
5 S&P Global Ratings, Assessing U.S. Investors-Owned Utility Regulatory Environments, RatingsExpress (Aug. 10, 2016).
6 Value Line Investment Survey, Water Utility Industry (Jan. 13, 2017) at p. 1780.

McKenzie, DI 10 Idaho Power Company

A. Yes. Providing an ROE sufficient to maintain the 1
Company’s ability to attract capital under reasonable terms, 2
even in times of financial and market stress, is not only 3
consistent with the economic requirements embodied in the U.S. 4
Supreme Court’s Hope and Bluefield decisions, but it is also in 5
customers’ best interests. Customers enjoy the benefits that 6
come from ensuring that the utility has the financial 7
wherewithal to take whatever actions are required to ensure 8
safe and reliable service. 9
B. Conclusions and Recommendations 10
Q. What are your findings regarding the fair ROE for 11
Idaho Power? 12
A. Considering the economic requirements necessary to 13
support continuous access to capital under reasonable terms and 14
the results of my analysis, I recommend a 10.6 percent ROE for 15
Idaho Power’s electric utility operations, which is consistent 16
with the case-specific evidence presented in my testimony. The 17
bases for my conclusion are summarized below: 18
• In order to reflect the risks and prospects 19
associated with Idaho Power’s electric utility 20 operations, my analyses focus on a proxy group 21 of twenty other electric utilities. 22
• Because investors’ required ROE is 23 unobservable and no single method should be 24
viewed in isolation, I apply the DCF, CAPM, 25 ECAPM, and risk premium methods to estimate a 26 just and reasonable ROE for Idaho Power, as 27
well as referencing the expected earnings 28 approach. 29

McKenzie, DI 11 Idaho Power Company

• As summarized on Exhibit 8, considering the 1 results of these analyses, and giving less 2 weight to extremes at the high and low ends of 3 the range, I conclude that the cost of equity 4
for a regulated electric utility is in the 5 10.0% to 11.0% range. 6
• My evaluation of a fair ROE also incorporated 7
an upward adjustment of 10 basis points to 8 account for flotation costs, which are a 9
legitimate cost incurred to raise equity 10 capital supporting Idaho Power’s investment in 11
utility infrastructure. Incorporating this 12 flotation cost adjustment resulted in my 13 recommended ROE range of 10.1% to 11.1%. 14
• My ROE recommendation for Idaho Power’s 15 electric operations is the midpoint of this 16 range, or 10.6%. 17
18
Q. What did the DCF results for your select group of 19
non-utility firms indicate with respect to your evaluation? 20
A. As shown on page 3 of Exhibit 18, average DCF 21
estimates for a low-risk group of firms in the competitive 22
sector of the economy ranged from 10.4 percent to 10.9 percent. 23
While I did not base my recommendations on these results, they 24
confirm that an ROE of 10.6 percent falls in a reasonable range 25
to maintain Idaho Power’s financial integrity, provide a return 26
commensurate with investments of comparable risk, and support 27
the Company’s ability to attract capital. 28
III. FUNDAMENTAL ANALYSES
Q. What is the purpose of this section? 29
A. This section briefly reviews the operations and 30
finances of Idaho Power. As a predicate to my quantitative 31

McKenzie, DI 12 Idaho Power Company

analyses, it examines conditions in the capital markets and the 1
general economy. An understanding of the fundamental factors 2
driving the risks and prospects of electric utilities is 3
essential in developing an informed opinion of investors’ 4
expectations and requirements that are the basis of a fair rate 5
of return. 6
A. Idaho Power 7
Q. Briefly describe Idaho Power and its utility 8
operations. 9
A. Idaho Power is a wholly-owned subsidiary of 10
IDACORP, Inc. (“IDACORP”) and is principally engaged in 11
providing integrated retail electric utility service to 12
approximately 618,000 customers in a 24,000 square mile area in 13
southern Idaho and eastern Oregon. Approximately 95 percent of 14
Idaho Power’s retail revenue is attributable to customers 15
located in Idaho. During 2022, Idaho Power’s energy deliveries 16
totaled 17.1 million megawatt-hours (“MWh”). Sales to 17
residential customers comprised 39 percent of operating 18
revenues, with 21 percent to commercial, 13 percent to 19
industrial end-users, and 10 percent attributable to irrigation 20
pumping. Idaho Power also participates in the wholesale power 21
market, with wholesale energy sales accounting for 4 percent of 22
operating revenues during 2022. At year-end 2022, Idaho Power 23

McKenzie, DI 13 Idaho Power Company

had total assets of $7.4 billion, with total revenues amounting 1
to approximately $1.6 billion. 2
In addition to its three natural gas-fired generating 3
facilities in southern Idaho and interests in two coal-fired 4
plants located in Wyoming and Nevada, Idaho Power’s existing 5
generating units include 17 hydroelectric generating plants 6
located in southern Idaho and eastern Oregon with a nameplate 7
capacity of 1,799 Megawatts (“MW”), or 51.6 percent of Company-8
owned generating capacity. The electrical output of these hydro 9
plants, which has a significant impact on total energy costs, 10
is dependent on stream flows. The Company has experienced 11
prolonged periods of persistent below-normal water conditions, 12
with hydroelectric generation supplying approximately 31 13
percent of total energy needs in 2022, versus an average of 14
about 43 percent over the 2017 to 2021 period. Additionally, 15
Idaho Power has undertaken a substantial capital program for 16
new capacity and energy resources, and in 2022 began 17
construction of two utility-scale battery storage facilities. 18
Idaho Power’s retail electric operations are subject to 19
the jurisdiction of the IPUC and the OPUC, with the interstate 20
jurisdiction regulated by FERC. Additionally, Idaho Power’s 21
hydroelectric facilities are subject to licensing under the 22
Federal Power Act, which is administered by FERC, as well as 23
the Oregon Hydroelectric Act. Relicensing is not automatic 24

McKenzie, DI 14 Idaho Power Company

under federal law, and Idaho Power must demonstrate that it has 1
operated its facilities in the public interest, which includes 2
adequately addressing environmental concerns. 3
Q. What credit ratings have been assigned to Idaho 4
Power? 5
A. Moody’s has assigned the Company an issuer rating 6
of Baa1, while S&P has assigned a corporate credit rating of 7
BBB to Idaho Power. 8
Q. Has Idaho Power made significant capital 9
investments in its system? 10
A. Yes. Idaho Power has made significant new 11
investments to maintain and modernize its utility 12
infrastructure, and to otherwise meet customer demand and 13
provide adequate and reliable service. Since its last rate case 14
in 2011, Idaho Power’s rate base has increased by more than 15
one-third.7 16
Q. Does Idaho Power anticipate the need for capital 17
going forward? 18
A. Yes. The Company must undertake investments for 19
necessary replacement and expansion of its electric utility 20
system as it continues to provide safe and reliable service to 21
its customers. For 2023 to 2027, Idaho Power is estimating 22

7 IDACORP, Inc., Spring 2023 Investor Outreach, Investor Information (February/March 2023) at 6.

McKenzie, DI 15 Idaho Power Company

annual capital expenditures of approximately $650 million.8 1
This represents almost a two-fold increase over the previous 2
five years. In addition, the Company remains obligated to repay 3
maturing long-term debt. Continued support for Idaho Power’s 4
financial integrity and flexibility will be instrumental in 5
attracting the capital necessary to fund these projects in an 6
effective manner. 7
B. Outlook for Capital Costs 8
Q. Please summarize current economic conditions. 9
A. U.S. real GDP contracted 3.4% during 2020, but 10
with the easing of COVID-19 lockdowns, the economic outlook 11
improved significantly in 2021, with GDP growing at a pace of 12
5.7 percent. Regional increases in COVID-19 cases, expiration 13
of government assistance payments, and declines in wholesale 14
trade led GDP to decline in the first two quarters of 2022. 15
More recently, expanding exports and higher consumer spending 16
led real GDP to grow by 3.2 percent and 2.6 percent in the 17
third and fourth quarters of 2022, respectively.9 Meanwhile, 18
indicators of employment remained stable, with the national 19
unemployment rate at 3.5 percent in March 2023.10 20

8 Id. at 5.
9 https://www.bea.gov/news/2023/gross-domestic-product-fourth-quarter-and-year-2022-third-estimate-gdp-industry-and (last visited Apr. 22, 2023).
10 https://www.bls.gov/news.release/pdf/empsit.pdf (last visited Apr. 16, 2023).

McKenzie, DI 16 Idaho Power Company

The underlying risk and price pressures associated with 1
the COVID-19 pandemic were overshadowed by a dramatic increase 2
in geopolitical risks in early 2022. These events have also 3
been accompanied by heightened economic uncertainties as 4
inflationary pressures due to COVID-19 supply chain disruptions 5
were further stoked by sharp increases in global commodity 6
prices. The substantial disruption in the energy economy and 7
dramatic rise in inflation led to sharp declines in global 8
equity markets as investors reacted to the related exposures. 9
S&P concluded that: 10
The balance of risks is firmly on the downside—11 with rapid monetary tightening potentially 12
pushing major economies into recession; growing 13 geopolitical tensions exacerbating Europe’s 14
energy crisis; lingering high prices pressuring 15 costs and eroding households’ purchasing power; 16 and China grappling with structural factors that 17
are undermining its economic growth.11 18
Stimulative monetary and fiscal policies, coupled with 19
economic ramifications stemming from supply-chain disruptions 20
and rapid price rises in the energy and commodities markets, 21
have led to increasing concern that inflation may remain 22
significantly above the Federal Reserve’s longer-run benchmark 23
of 2 percent. In June 2022, inflation, as measured by the 24
Consumer Price Index (“CPI”), peaked at its highest level 25
since November 1981. Since then, CPI inflation has gradually 26

11 S&P Global Ratings, Global Credit Conditions Q4 2022: Darkening Horizons, Comments (Sept. 29, 2022).

McKenzie, DI 17 Idaho Power Company

moderated to 5.0 percent in March 202312 The so-called “core” 1
price index, which excludes more volatile energy and food 2
costs, rose at an annual rate of 5.6 percent in March 2023. 3
Similarly, Personal Consumption Expenditures (“PCE”) inflation 4
rose 5.0 percent in February 2023, or 4.6 percent after 5
excluding more volatile food and energy costs13 As Federal 6
Reserve Chair Powell has noted: 7
Although inflation has moderated recently, it 8
remains too high. The longer the current bout of 9 high inflation continues, the greater the chance 10
that expectations of higher inflation will become 11 entrenched.14 12
More recently, turmoil in the banking sector has shaken 13
investor confidence and increased volatility in bond and 14
equity markets. The Federal Reserve and U.S. Treasury took 15
quick and dramatic action to shore up banks’ liquidity needs 16
and strengthen public confidence in the banking system, but as 17
Moody’s noted, “bank stress has added uncertainty to the 18
outlook.”15 19
Q. How have these developments impacted the Federal 20
Reserve’s monetary policies? 21

12 https://www.bls.gov/news.release/cpi.nr0.htm (last visited Apr. 14, 2023).
13 https://www.bea.gov/news/2023/personal-income-and-outlays-february-2023 (last visited Apr. 14, 2023).
14 Federal Reserve, Transcript of Chair Powell’s Press Conference (Feb. 1,
2023), https://www.federalreserve.gov/mediacenter/files/FOMCpresconf20230201.pdf (last visited Feb. 21, 2023).
15 Moody’s Investors Service, Baseline US macro forecasts unchanged but outlook more uncertain, Sector Comment (Apr. 12. 2023).

McKenzie, DI 18 Idaho Power Company

A. As of its policy meeting in May 2023, the Federal 1
Open Market Committee (“FOMC”) has responded to concerns over 2
accelerating inflation by raising the benchmark range for the 3
federal funds rate by a total of 5.00 percent since March 4
2022.16 In addition to these increases, Chair Powell has 5
surmised that the significant draw-down of its balance sheet 6
holdings that began in June 2022 could be the equivalent of 7
another one quarter percent rate hike over the course of a 8
year.17 Chair Powell noted that, “The process of getting 9
inflation back down to 2 percent has a long way to go and is 10
likely to be bumpy,”18 with the recent banking crisis amply 11
demonstrating these latent risks. 12
Q. What impact do rising inflation expectations have 13
on the return that equity investors require from Idaho Power? 14
A. Implicit in the required rate of return for long-15
term capital—whether debt or common equity—is compensation for 16
expected inflation. This is highlighted in the textbook, 17
Financial Management, Theory and Practice: 18

16 The FOMC is a committee composed of twelve members that serves as the monetary policymaking body of the Federal Reserve System.
17 Federal Reserve, Transcript of Chair Powell’s Press Conference (May 4, 2022), https://www.federalreserve.gov/mediacenter/files/FOMCpresconf20220504.pdf.
18 https://www.federalreserve.gov/mediacenter/files/FOMCpresconf20230322.pdf.

McKenzie, DI 19 Idaho Power Company

The four most fundamental factors affecting the 1
cost of money are (1) production opportunities, 2 (2) time preferences for consumption, (3) risk, 3 and (4) inflation.19 4
In other words, a part of investors’ required return is 5
intended to compensate for the erosion of purchasing power due 6
to rising price levels. This inflation premium is added to the 7
real rate of return (pure risk-free rate plus risk premium) to 8
determine the nominal required return. As a result, higher 9
inflation expectations lead to an increase in the cost of 10
equity capital. 11
Q. Have these developments impacted the risks faced 12
by utilities and their investors? 13
A. Yes. Concerns over weakening credit quality 14
prompted S&P to revise its outlook for the regulated utility 15
industry from “stable” to “negative.”20 As S&P explained: 16
Even before the current downturn and COVID-19, a 17 confluence of factors, including the adverse 18
impacts of tax reform, historically high capital 19 spending, and associated increased debt, resulted 20 in little cushion in ratings for unexpected 21 operating challenges.21 22 23
Meanwhile, rising inflation expectations also pose a challenge 24
for utilities, with S&P recently noting that “the threat of 25

19 Eugene F. Brigham, Louis C. Gapenski, and Michael C. Ehrhardt, Financial Management, Theory and Practice, Ninth Edition (1999) at 126.
20 S&P Global Ratings, COVID-19: The Outlook For North American Regulated Utilities Turns Negative, RatingsDirect (April 2, 2020).
21 S&P Global Ratings, North American Regulated Utilities Face Tough
Financial Policy Tradeoffs To Avoid Ratings Pressure Amid The COVID-19 Pandemic, RatingsDirect (May 11, 2020).

McKenzie, DI 20 Idaho Power Company

inflation comes at a time when credit metrics are already 1
under pressure relative to downside ratings thresholds.”22 S&P 2
noted that “risk will continue to pressure the credit quality 3
of the industry in 2022.”23 As S&P elaborated: 4
Recently, several new credit risks have emerged, 5 including inflation, higher interest rates, and 6
rising commodity prices. Persistent pressure 7 from any of these risks would likely lead to a 8 further weakening of the industry’s credit 9 quality in 2022.24 10 11
Similarly, on November 10, 2022, Moody’s revised its outlook 12
for the regulated utilities sector to “negative” from 13
“stable,” citing “increasingly challenging business and 14
financial conditions stemming from higher natural gas prices, 15
inflation and rising interest rates.”25 16
In affirming its negative outlook on the industry, S&P 17
recently cited weak financial measures, rising energy prices 18
and capital spending, and increased environmental risks as key 19
challenges, noting that, “The industry outlook remains 20
negative and has been negative since early 2020.”26 Value Line 21

22 S&P Global Ratings, Will Rising Inflation Threaten North American Investor-Owned Regulated Utilities’ Credit Quality? (Jul. 20, 2021).
23 S&P Global Ratings, For The First Time Ever, The Median Investor-Owned Utility Ratings Falls To The ‘BBB’ Category, RatingsDirect (Jan. 20, 2022).
24 Id.
25 Moody’s Investors Service, Regulated Gas Utilities--US, 2023 outlook negative due to higher natural gas prices, inflation and rising interest rates, Outlook (Nov. 10, 2022).
26 S&P Global Ratings, North American Regulated Utilities, The industry’s outlook remains negative, Industry Top Trends (Jan. 23, 2023).

McKenzie, DI 21 Idaho Power Company

echoed these sentiments for electric utilities in the Western 1
US, concluding that: 2
The current macroeconomic environment is a 3 challenging period for this group. The main 4 difficulties are wage inflation, higher interest 5
rates, and high commodity prices for raw 6 materials and purchased power.27 7
Q. Do changes in utility company beta values 8
corroborate an increase in industry risk? 9
A. Yes. Beta measures a utility’s stock price 10
volatility relative to the market as a whole and reflects the 11
tendency of a stock’s price to follow changes in the market. 12
A stock that tends to respond less to market movements has a 13
beta less than 1.00, while stocks that tend to move more than 14
the market have betas greater than 1.00. Beta is the only 15
relevant measure of investment risk under modern capital 16
market theory and is widely cited in academics and in the 17
investment industry as a guide to investors’ risk perceptions. 18
As shown later in my testimony in Table 2, the average beta 19
for the Electric Group is 0.89.28 Prior to the pandemic, the 20
average betas for this same group of electric utilities was 21
0.57.29 The significant shift in pre- and post-pandemic beta 22
values for the Electric Group is further exemplified in Figure 23
1 below. As illustrated there, the average beta value for the 24

27 The Value Line Investment Survey, Electric Utility (West) Industry (Apr. 21, 2023).
28 As indicated on Exhibit 13, this is based on data as of March 31, 2023.
29 The Value Line Investment Survey, Summary & Index (Feb. 14, 2020).

McKenzie, DI 22 Idaho Power Company

Electric Group increased significantly with the beginning of 1
the pandemic in March 2020, continued to increase during 2021, 2
and have remained elevated. This dramatic increase in a 3
primary gauge of investors’ risk perceptions is further proof 4
of the rise in the risk of utility common stocks. 5
FIGURE 1 6 ELECTRIC GROUP BETA VALUES 7

Q. Have increased risks and higher inflation 8
resulted in higher capital costs? 9
A. Yes. While the cost of equity is unobservable, 10
yields on long-term bonds provide a widely referenced benchmark 11
for the direction of capital costs, including required returns 12
on common stocks. Table 1 below compares the average yields on 13
Treasury securities and Baa-rated public utility bonds during 14
March 2023 with those prevailing in 2021. 15

McKenzie, DI 23 Idaho Power Company

TABLE 1 1
BOND YIELD TRENDS 2

As shown above, trends in bond yields document a substantial 3
increase in the returns on long-term capital demanded by 4
investors. With respect to utility bond yields—which are the 5
most relevant indicator in gauging the implications for the 6
Company’s common equity investors—average yields are now over 7
230 basis points above the level prevailing during 2021. 8
Q. What implications do these trends have in 9
evaluating a fair ROE for Idaho Power? 10
A. The upward move in interest rates suggests that 11
long-term capital costs—including the cost of equity—have 12
increased significantly. Exposure to rising interest rates, 13
inflation, and capital expenditure requirements also reinforce 14
the importance of buttressing Idaho Power’s credit standing. 15
Considering the potential for financial market instability, 16
competition with other investment alternatives, and investors’ 17
sensitivity to risk exposures in the utility industry, 18

McKenzie, DI 24 Idaho Power Company

maintaining credit strength is a key ingredient in maintaining 1
access to capital at reasonable cost. 2
Q. Would it be reasonable to disregard the 3
implications of current capital market conditions in 4
establishing a fair ROE for Idaho Power? 5
A. No. They reflect the reality in which Idaho Power 6
must attract and retain capital. The standards underlying a 7
fair rate of return require an authorized ROE for the Company 8
that is competitive with other investments of comparable risk 9
and sufficient to preserve its ability to maintain access to 10
capital on reasonable terms. These standards can only be met by 11
considering the requirements of investors over the time period 12
when the rates established in this proceeding will be in 13
effect. If the upward shift in investors’ risk perceptions and 14
required rates of return for long-term capital is not 15
incorporated in the allowed ROE, the results will fail to meet 16
the comparable earnings standard that is fundamental in 17
determining the cost of capital. From a more practical 18
perspective, failing to provide investors with the opportunity 19
to earn a rate of return commensurate with Idaho Power’s risks 20
will weaken its financial integrity, while hampering the 21
Company’s ability to attract the capital necessary to provide 22
safe and reliable service. 23

McKenzie, DI 25 Idaho Power Company

IV. COMPARABLE RISK PROXY GROUP
Q. What is the purpose of this section of your 1
testimony? 2
A. This section explains the basis of the proxy 3
group of publicly traded companies I use to estimate the cost 4
of equity, examines alternative objective indicators of 5
investment risk for these firms, and compares the investment 6
risks applicable to Idaho Power with my reference group. 7
Q. What key principles underpin the evaluation of a 8
proxy group? 9
A. The United States Supreme Court’s Hope and 10
Bluefield decisions30 establish a standard of comparison 11
between a subject utility and other companies of comparable 12
risk in determining a just and reasonable ROE. The generally 13
accepted approach is to select a group of companies that are of 14
similar risk to the subject utility (the “proxy group”), and 15
then to perform various quantitative analyses based on the 16
proxy group to estimate investors’ required returns. The 17
results of these analyses, in turn, are used to evaluate a 18
range of reasonableness and a final recommendation for the ROE 19
attributable to the subject utility. 20

30 Bluefield Water Works & Improvement Co. v. Pub. Serv. Comm'n, 262 U.S. 679 (1923) (Bluefield); Fed. Power Comm'n v. Hope Natural Gas Co., 320 U.S. 591 (1944) (Hope).

McKenzie, DI 26 Idaho Power Company

Q. As an initial matter, does the fact that Idaho 1
Power is wholly owned by IDACORP alter these fundamental 2
standards? 3
A. No. While the Company has no publicly traded 4
common stock and IDACORP is Idaho Power’s only shareholder, 5
this does not change the standards governing the determination 6
of a just and reasonable ROE for the Company. Ultimately, the 7
common equity required to support the utility operations of 8
Idaho Power must be raised in the capital markets, where 9
investors consider the Company’s ability to offer a rate of 10
return that is competitive with other risk-comparable 11
alternatives. Idaho Power must compete with other investment 12
opportunities and unless there is a reasonable expectation that 13
investors will have the opportunity to earn returns 14
commensurate with the underlying risks, capital will be 15
allocated elsewhere, the Company’s financial integrity will be 16
weakened, and investors will demand an even higher rate of 17
return. Idaho Power’s ability to offer a reasonable return on 18
investment is a necessary ingredient to ensure that customers 19
continue to enjoy economical rates and reliable service and, by 20
extension, the preservation of the Company’s ability to attract 21
equity capital. 22

McKenzie, DI 27 Idaho Power Company

A. Determination of the Proxy Group 1
Q. How do you implement quantitative methods to 2
estimate the cost of common equity for Idaho Power? 3
A. Application of quantitative methods to estimate 4
the cost of common equity requires observable capital market 5
data, such as stock prices and beta values. Moreover, even for 6
a firm with publicly traded stock, the cost of common equity 7
can only be estimated. As a result, applying quantitative 8
models using observable market data only produces an estimate 9
that inherently includes some degree of observation error. 10
Thus, the accepted approach to increase confidence in the 11
results is to apply quantitative methods to a proxy group of 12
publicly traded companies that investors regard as risk-13
comparable. The results of the analysis on the sample of 14
companies are relied upon to establish a range of 15
reasonableness for the cost of equity for the specific company 16
at issue. 17
Q. How do you identify the proxy group of electric 18
utilities relied on for your analyses? 19
A. To reflect the risks and prospects associated 20
with Idaho Power’s jurisdictional electric operations, I begin 21
with those companies included in the Electric Utility industry 22

McKenzie, DI 28 Idaho Power Company

groups compiled by Value Line.31 Value Line is one of the most 1
widely available sources of investment advisory information, 2
and its industry groups provide an objective source to identify 3
publicly traded firms that investors would regard to be similar 4
in operations. I then apply the following criteria to identify 5
a proxy group of utilities: 6
1. Corporate credit ratings from Moody’s and S&P 7
within one notch of the Company’s current ratings. 8 For Moody’s, this resulted in a ratings range of 9 Baa2, Baa1, and A3; for S&P the range is BBB-, 10
BBB, and BBB+. 11
2. A Value Line Safety Rank of 1 or 2. 12
3. No cuts in common dividend payments during the 13 past six months and no announcement of a dividend 14 cut since that time. 15
4. No ongoing involvement in a major merger or 16 acquisition that would distort quantitative 17
results. 18
These criteria result in a proxy group composed of twenty 19
companies, which I refer to as the “Electric Group.” 20
B. Relative Risks of the Electric Group and Idaho Power 21
Q. How do you evaluate the risks of the Electric 22
Group relative to Idaho Power? 23
A. My evaluation of relative risk considers four 24
published benchmarks that are widely relied on by investors—25

2 In addition to the companies included in Value Line’s electric utility industry groups, I also considered Algonquin Power & Utilities Company and Emera, Inc, which would both be regarded as comparable utility investment
opportunities by investors. Neither of these companies met my required screening criteria.

McKenzie, DI 29 Idaho Power Company

credit ratings from Moody’s and S&P, along with Value Line’s 1
Safety Rank, Financial Strength Rating, and beta values. 2
Credit ratings are assigned by independent rating agencies for 3
the purpose of providing investors with a broad assessment of 4
the creditworthiness of a firm. Ratings generally extend from 5
triple-A (the highest) to D (in default). Other symbols (e.g., 6
"+" or “-”) are used to show relative standing within a 7
category. Because the rating agencies’ evaluation includes all 8
of the factors normally considered important in assessing a 9
firm’s relative credit standing, corporate credit ratings 10
provide broad, objective measures of overall investment risk 11
that are readily available to investors. Widely cited in the 12
investment community and referenced by investors, credit 13
ratings are also frequently used as a primary risk indicator 14
in establishing proxy groups to estimate the cost of common 15
equity. 16
While credit ratings provide the most widely referenced 17
benchmark for investment risks, other quality rankings 18
published by investment advisory services also provide 19
relative assessments of risks that are considered by investors 20
in forming their expectations for common stocks. Value Line’s 21
primary risk indicator is its Safety Rank, which ranges from 22
“1” (Safest) to “5” (Riskiest). This overall risk measure is 23
intended to capture the total risk of a stock and incorporates 24

McKenzie, DI 30 Idaho Power Company

elements of stock price stability and financial strength. 1
Given that Value Line is perhaps the most widely available 2
source of investment advisory information, its Safety Rank 3
provides useful guidance regarding the risk perceptions of 4
investors. 5
The Financial Strength Rating is designed as a guide to 6
overall financial strength and creditworthiness, with the key 7
inputs including financial leverage, business volatility 8
measures, and company size. Value Line’s Financial Strength 9
Ratings range from “A++” (strongest) down to “C” (weakest) in 10
nine steps. These objective, published indicators incorporate 11
consideration of a broad spectrum of risks, including 12
financial and business position, relative size, and exposure 13
to firm-specific factors. 14
As previously mentioned, beta measures a utility’s 15
stock price volatility relative to the market as a whole and 16
reflects the tendency of a stock’s price to follow changes in 17
the market. 18
Q. How does the overall risk of your proxy group 19
compare to Idaho Power? 20
A. Table 2 compares the Electric Group with the 21
Company across the four key indices of investment risk 22
discussed above. Because Idaho Power has no publicly traded 23

McKenzie, DI 31 Idaho Power Company

common stock, the Value Line risk measures shown reflect those 1
published for its parent, IDACORP. 2
TABLE 2 3 COMPARISON OF RISK INDICATORS 4

Q. What does this comparison indicate regarding 5
investors’ assessment of the relative risks associated with 6
your Electric Group? 7
A. The average S&P credit rating corresponding to 8
the Electric Group is one notch higher than those of Idaho 9
Power, while the average Moody’s credit ratings for the proxy 10
group is one notch lower, indicating about the same amount of 11
risk overall. With respect to Value Line’s Safety Rank, 12
Financial Strength and beta measures, the average values for 13
the Electric Group indicate slightly greater risk than Idaho 14
Power. Considered together, a comparison of these objective 15
measures, which incorporate a broad spectrum of risks, 16
including financial and business position, relative size, and 17
exposure to company specific factors, indicates that investors 18
would likely conclude that the overall investment risks for 19

McKenzie, DI 32 Idaho Power Company

Idaho Power are generally comparable to, or slightly less than 1
those of the firms in the Electric Group. 2
Q. How does Idaho Power’s generating resource mix 3
affect investors’ risk perceptions? 4
A. Because a significant portion of Idaho Power’s 5
total energy requirements are provided by hydroelectric 6
facilities, the Company is exposed to a level of uncertainty 7
not faced by most utilities. While hydropower confers 8
advantages in terms of fuel cost savings and diversity, reduced 9
hydroelectric generation due to below-average water conditions 10
forces the Company to rely more heavily on wholesale power 11
markets or more costly thermal generating capacity to meet its 12
resource needs. As S&P explained: 13
A reduction in hydro generation typically 14
increases an electric utility’s costs by 15 requiring it to buy replacement power or run more 16
expensive generation to serve customer loads. 17 Low hydro generation can also reduce utilities’ 18 opportunity to make off-system sales. At the 19
same time, low hydro years increase regional 20 wholesale power prices, creating potentially a 21
double impact – companies have to buy more power 22 than under normal conditions, paying higher 23 prices.32 24
With respect to Idaho Power specifically, S&P recently 25
observed that: 26

32 Standard & Poor’s Corporation, Pacific Northwest Hydrology And Its Impact On Investor-Owned Utilities’ Credit Quality, RatingsDirect (Jan. 28, 2008).

McKenzie, DI 33 Idaho Power Company

The company relies heavily on hydropower 1
generation and purchased power. Low-cost 2 hydropower provides more than 50% of the 3 company's generation under normal water-level 4
conditions, leading to lower electricity rates. 5 However, when hydroelectric generation is low, 6
the company relies on more expensive purchased 7 power, which exposes the company to the volatile 8 spot power market. Idaho Power saw reduced 9
hydropower generation in both 2021 and 2020 due 10 to precipitation and snow conditions.33 11
Q. Have utilities and their customers recently 12
experienced increased uncertainty in energy markets? 13
A. Yes. The onset of military conflict in Ukraine 14
led to a dramatic rise in energy market volatility. As with 15
major weather events, market conditions that lead to 16
significant spikes in energy prices can place extraordinary 17
pressure on liquidity as utilities seek to fund higher 18
procurement costs and maintain service to customers. With 19
respect to Idaho Power specifically, the Pacific Northwest 20
recently faced a dramatic increase in gas costs. As the Energy 21
Information Administration reported: 22
On December 21, 2022, daily natural gas spot 23 prices at three major trading hubs in the western 24 United States—Pacific Gas & Electric (“PG&E”) 25
Citygate, Sumas on the Canada-Washington border, 26 and Malin, Oregon—settled higher than $50.00 per 27
million British thermal units (“MMBtu”), the 28 highest level of any other market and an average 29

33 S&P Global Ratings, Idaho Power Co., RatingsDirect (May 26, 2022).

McKenzie, DI 34 Idaho Power Company

of $48.12/MMBtu above Henry Hub, the national 1
benchmark natural gas price.34 2
While prices have since moderated, investors recognize 3
that volatile energy markets, unpredictable stream flows, and 4
Idaho Power’s reliance on wholesale purchases to meet a 5
significant portion of its resource needs can expose the 6
Company to the risk of reduced cash flows and unrecovered 7
power supply costs. The Company’s reliance on purchased power 8
to meet shortfalls in hydroelectric generation magnifies the 9
importance of strengthening financial flexibility, which is 10
essential to guarantee access to the cash resources and 11
interim financing required to cover inadequate operating cash 12
flows. 13
Q. How has climate change impacted investors’ 14
assessment of Idaho Power’s risk exposure? 15
A. The risk posed by climate-related weather events 16
has served to magnify concerns over Idaho Power’s exposure to 17
below-average water conditions. S&P concluded that “water-18
intensive assets like power plants [are] especially vulnerable 19
in the absence of adaptation,” and concluded that Idaho Power 20
had the highest exposure to water stress of any U.S. utility.35 21

34 Energy Information Administration, Natural Gas Weekly Update (Dec. 22,
2022). https://www.eia.gov/naturalgas/weekly/archivenew_ngwu/2022/12_22/#itn-tabs-1 (last visited Apr. 25, 2023).
35 S&P Global Ratings, Keeping The Lights On: U.S. Utilities’ Exposure To Physical Climate Risks, RatingsDirect (Sep. 16, 2021).

McKenzie, DI 35 Idaho Power Company

While noting that the risks of such events are generally 1
manageable under recovery mechanisms that allow related costs 2
to be recuperated, S&P also observed that: 3
In the most extreme events, including those of 4 late, utility companies' exposure to acute and 5 chronic climate risks can damage assets or 6
disrupt supplies, which can weaken their 7 financial position and ultimately credit 8
quality.36 9
Q. Do financial pressures associated with Idaho 10
Power’s planned capital expenditures also impact investors’ 11
risk assessment? 12
A. Yes. Idaho Power’s customer growth and regional 13
transmission constraints are driving the need for additional 14
resources to meet projected energy and capacity deficits. As 15
noted earlier, Idaho Power’s capital additions are expected to 16
total approximately $650 million annually over the 2023 to 2027 17
period. This represents a substantial investment given the 18
Company’s current rate base of approximately $3.8 billion. As 19
Value Line recently observed: 20
The company’s system is stressed, and new 21 capacity resources are entering the pipeline and 22
they do not come cheap. . . . All this pressure 23 comes at a time when inflation is still well 24
higher than usual and the interest on borrowings 25 is more punishing to the bottom line.37 26 27

36 Id.
37 The Value Line Investment Survey, IDACORP, Inc. (Apr. 21, 2023).

McKenzie, DI 36 Idaho Power Company

In addition, Idaho Power remains obligated to repay maturing 1
long-term debt. Continued support for the Company’s financial 2
integrity and flexibility will be instrumental in attracting 3
the capital necessary to fund these projects and debt 4
repayments in an effective manner. 5
Q. Do utilities such as Idaho Power continue to face 6
environmental risks? 7
A. Yes. Environmental concerns are leading to a 8
profound transformation in the utility industry. In the 9
electricity sector, the generation segment is undergoing 10
material changes in fuel mix, as natural gas and renewable 11
sources increasingly supplant coal. Over the next decade, 12
renewable sources are widely expected to account for a rising 13
share of the electricity generated in the U.S., including a 14
significant expansion in distributed generation, which will 15
accompany declining costs and increased efficiency of energy 16
storage technologies. Accommodating efforts to decarbonize 17
electric generation will also require significant investment to 18
modernize the transmission grid. And while this disruption 19
offers the potential for growth through increased capital 20
investment, it also conveys higher risks. With respect to Idaho 21
Power, the Company’s carbon emission targets call for achieving 22
100 percent clean electricity by 2045. 23

McKenzie, DI 37 Idaho Power Company

Q. What other consideration is relevant to 1
investors’ risk assessment? 2
A. Rising temperatures and reduced rainfall have led 3
to unusually large and damaging wildfires in the Pacific 4
Northwest. While Idaho Power does not face the same degree of 5
exposure attributed to California utilities due to that state’s 6
inverse condemnation laws, S&P nonetheless classifies the 7
Company as having the second highest exposure to wildfires in 8
the nation.38 9
C. Regulatory Mechanisms 10
Q. What regulatory mechanisms are applicable to 11
Idaho Power’s utility operations? 12
A. In addition to a mechanism that accounts for 13
changes in power supply costs (“PCA”), Idaho Power operates 14
under the Fixed Cost Adjustment mechanism (“FCA”), which is 15
designed to break the link between a utility's revenues and the 16
energy usage of residential and small commercial customers. The 17
IPUC has also authorized a rider to collect most of the 18
Company’s energy efficiency program costs and a deferral 19
account for wildfire resiliency costs. 20
Q. Would investors consider the implications of 21
regulatory mechanisms in evaluating a utility’s relative risks? 22

38 S&P Global Ratings, Keeping The Lights On: U.S. Utilities’ Exposure To Physical Climate Risks, RatingsDirect (Sep. 16, 2021).

McKenzie, DI 38 Idaho Power Company

A. Yes. In response to increasing sensitivity over 1
fluctuations in costs and the importance of advancing other 2
public interest goals such as reliability, energy conservation, 3
and safety, utilities and their regulators have sought to 4
mitigate cost recovery uncertainty and align the interest of 5
utilities and their customers. As a result, decoupling 6
mechanisms, cost trackers, and future test years have been 7
increasingly prevalent in the utility industry in recent years, 8
along with alternatives to traditional ratemaking such as 9
formula rates and multi-year rate plans. S&P Global Market 10
Intelligence, RRA Regulatory Focus concluded in its recent 11
review of adjustment clauses that: 12
More recently and with greater frequency, 13
commissions have approved mechanisms that permit 14 the costs associated with the construction of 15 new generation or delivery infrastructure to be 16
used, effectively including these items in rate 17 base without the need for a full rate case. In 18
some instances, these mechanisms may even 19 provide the utilities a cash return on 20 construction work in progress. 21 . . . [C]ertain types of adjustment clauses are 22 more prevalent than others. For example, those 23
that address electric fuel and gas commodity 24 charges are in place in all jurisdictions. Also, 25
about two-thirds of all utilities have riders in 26 place to recover costs related to energy 27 efficiency programs, and roughly half of the 28
utilities have some type of decoupling mechanism 29 in place.39 30

39 S&P Global Market Intelligence, Adjustment Clause: A state-by-state overview, RRA Regulatory Focus (Jul. 18, 2022).

McKenzie, DI 39 Idaho Power Company

Q. How do the regulatory mechanisms approved for 1
Idaho Power compare to other firms operating in the utility 2
industry? 3
A. A broad array of adjustment mechanisms is also 4
available to the companies in my proxy group of electric 5
utilities. As documented on Exhibit 9, the companies in the 6
Electric Group operate under a wide variety of cost adjustment 7
mechanisms, which encompass revenue decoupling and adjustment 8
clauses designed to address rising capital investment outside 9
of a traditional rate case, increasing costs of environmental 10
compliance measures, as well as riders to address the costs of 11
energy conservation programs, bad debt expenses, certain taxes 12
and fees, post-retirement employee benefit costs, storms, and 13
transmission-related charges. The majority of these proxy 14
firms also operate in regulatory jurisdictions that allow for 15
future test years, formula rates, and multi-year rate plans. 16
Meanwhile, under the PCA that currently governs 17
recovery of electric supply costs for the Company’s Idaho-18
jurisdictional electric utility operations, 95 percent of the 19
difference between actual costs and base level costs are 20
passed through to customers, with 5 percent absorbed/retained 21
by shareholders.40 Thus, in addition to the fact that recovery 22
is deferred when power costs rise above the level included in 23

40 Amounts related to power supplied by Qualifying Facilities are not subject to cost sharing under the PCA.

McKenzie, DI 40 Idaho Power Company

current retail rates, investors recognize that this sharing 1
mechanism exposes the Company to unrecovered electric supply 2
costs. Both of these considerations can adversely affect Idaho 3
Power’s operating cash flow and liquidity. 4
In contrast to many of the specific operating companies 5
associated with the firms in the Utility Group, Idaho Power 6
does not have an approved cost tracking mechanisms to address 7
ongoing investment in new generation capacity. Further, the 8
Idaho jurisdiction has routinely relied on a historical test 9
year approach, which also creates a lag in cost recovery. 10
Thus, while investors would consider Idaho Power’s regulatory 11
mechanisms to be supportive of the Company’s financial 12
integrity, they are more limited than those approved for other 13
firms in the industry. 14
D. Capital Structure 15
Q. Is an evaluation of a utility’s capital structure 16
relevant in assessing its return on equity? 17
A. Yes. Other things equal, a higher debt ratio and 18
lower common equity ratio, translates into increased financial 19
risk for all investors. A greater amount of debt means more 20
investors have a senior claim on available cash flow, thereby 21
reducing the certainty that each will receive their contractual 22
payments. This increases the risks to which lenders are 23
exposed, and they require correspondingly higher rates of 24

McKenzie, DI 41 Idaho Power Company

interest. From common shareholders’ standpoint, a higher debt 1
ratio means that there are proportionately more investors ahead 2
of them, thereby increasing the uncertainty as to the amount of 3
cash flow that will remain. 4
Q. What common equity ratio is implicit in Idaho 5
Power’s capital structure? 6
A. As discussed in the direct testimony of Company 7
Witness Mr. Brian Buckham, the capital structure used to 8
compute the overall rate of return for Idaho Power includes 9
51.0 percent common equity. 10
Q. How does this compare to the average equity 11
ratios maintained by the Electric Group? 12
A. As shown on page 1 of Exhibit 10, common equity 13
ratios for the individual firms in the Electric Group ranged 14
between 33.3 percent and 63.5 percent and averaged 45.0 15
percent. Meanwhile, the three-to-five-year forecasts published 16
by Value Line result in common equity ratios ranging from 33.0 17
percent to 59.5 percent for the Electric Group, with an average 18
of 45.8 percent. 19
Q. Are there other industry benchmarks that are more 20
relevant in evaluating Idaho Power’s capital structure? 21
A. Yes. Because this proceeding focuses on the ROE 22
for the regulated electric utility operations of Idaho Power, 23

McKenzie, DI 42 Idaho Power Company

the capital structures maintained by other operating electric 1
utilities provide a consistent basis of comparison. 2
Q. What capitalization ratios are maintained by 3
comparable utility operating companies? 4
A. Pages 2 and 3 of Exhibit 10 display capital 5
structure data for the group of electric utility operating 6
companies owned by the firms in the Electric Group. As shown 7
there, common equity ratios for these utilities range from 42.8 8
percent to 60.9 percent and average 51.8 percent. This 9
benchmark provides a direct guide to financing policies that 10
are consistent with industry-specific risks and the need to 11
maintain adequate borrowing capacity and financial flexibility. 12
Q. Do ongoing economic and capital market 13
uncertainties also influence the appropriate capital structure 14
for Idaho Power? 15
A. Yes. Financial flexibility plays a crucial role 16
in ensuring the wherewithal of a utility to meet funding needs. 17
Utilities with higher financial leverage may be foreclosed from 18
or have limited access to additional borrowing, especially 19
during times of financial market stress. As Moody’s observed: 20

McKenzie, DI 43 Idaho Power Company

Utilities are among the largest debt issuers in 1
the corporate universe and typically require 2 consistent access to capital markets to assure 3 adequate sources of funding and to maintain 4
financial flexibility. During times of distress 5 and when capital markets are exceedingly 6
volatile and tight, liquidity becomes critically 7 important because access to capital markets may 8 be difficult.41 9
10 S&P recently reiterated these concerns, noting that: 11
Because of the industry’s high capital spending 12
and consistent dividends, negative discretionary 13 cashflow is regularly more than $100 billion 14
annually. To fund this large deficit, the 15 industry requires consistent access to the 16 capital markets. Rising interest rates, 17
decreasing equity prices, and inflation could 18 hamper consistent access to the capital markets, 19
potentially pressuring credit quality.42 20 21 As a result, the Company’s capital structure must maintain 22
adequate equity to preserve the flexibility necessary to 23
maintain continuous access to capital even during times of 24
unfavorable energy or financial market conditions. 25
Q. What other factors do investors consider in their 26
assessment of a company’s capital structure? 27
A. Utilities, including Idaho Power, are facing 28
significant capital investment plans. Coupled with the 29
potential for turmoil in capital markets, this warrants a 30

41 Moody’s Investors Service, FAQ on credit implications of the coronavirus outbreak, Sector Comment (Mar. 26, 2020).
42 S&P Global Ratings. North American Regulated Utilities, The industry’s outlook remains negative, Industry Top Trends (Jan. 23, 2023).

McKenzie, DI 44 Idaho Power Company

stronger balance sheet to deal with an uncertain environment. 1
As S&P recently noted: 2
Under our base case, we expect that by 2024 the 3 industry’s capital spending will exceed $180 4 billion. Because of the industry’s continued 5
robust capital spending, we expect that industry 6 will continue to generate negative discretionary 7 cash flow. This requires that the industry has 8 consistent access to the capital markets to 9 finance capital spending and dividends 10
requirements.43 11 12
In addition, the investment community also considers the 13
impact of other considerations, such as postretirement benefit 14
and asset retirement obligations, in its evaluation of a 15
utility’s financial standing. 16
A conservative financial profile, in the form of a 17
reasonable common equity ratio, is consistent with the need to 18
accommodate these uncertainties and maintain continuous access 19
to capital under reasonable terms that is required to fund 20
operations and necessary system investment, even during times 21
of adverse capital market conditions. 22
Q. What does this evidence suggest with respect to 23
Idaho Power’s proposed capital structure? 24
A. Idaho Power’s ratemaking capital structure falls 25
within the range of capital structure ratios maintained by the 26
proxy group and is consistent with industry benchmarks for 27

43 S&P Global Ratings, For The First Time Ever, The Median Investor-Owned Utility Ratings Falls To The ‘BBB’ Category, RatingsDirect (Jan. 20, 2022).

McKenzie, DI 45 Idaho Power Company

other electric utility operating companies. While industry 1
guidelines provide one benchmark for comparison, each firm must 2
select its capitalization based on the risks and prospects it 3
faces, as well as its specific needs to access the capital 4
markets. Idaho Power’s proposed capital structure reflects the 5
Company’s ongoing efforts to maintain its credit standing and 6
support access to capital on reasonable terms. The 7
reasonableness of the Company’s capital structure is reinforced 8
by the ongoing uncertainties associated with the utility 9
industry and the importance of supporting continued system 10
investment, even during times of adverse industry or market 11
conditions. Based on this evidence, I conclude that the 12
Company’s capital structure represents a reasonable mix of 13
capital sources from which to calculate Idaho Power’s overall 14
rate of return. 15
V. CAPITAL MARKET ESTIMATES AND ANALYSES
Q. What is the purpose of this section of your 16
testimony? 17
A. This section presents capital market estimates of 18
the cost of equity. First, I address the concept of the cost of 19
common equity, along with the risk-return tradeoff principle 20
fundamental to capital markets. Next, I describe the 21
quantitative analyses I conducted to estimate the cost of 22
common equity for the Electric Group. 23

McKenzie, DI 46 Idaho Power Company

A. Economic Standards 1
Q. What fundamental economic principle underlies the 2
cost of equity concept? 3
A. The concept of the cost of equity is based on the 4
tenet that investors are risk averse. In capital markets where 5
relatively risk-free assets are available (e.g., U.S. Treasury 6
securities), investors will hold riskier assets only if they 7
are offered an additional return, or risk premium, above the 8
rate of return on a risk-free asset. Because all assets compete 9
for investor funds, riskier assets must yield a higher expected 10
rate of return than safer assets to induce investors to invest 11
and hold them. 12
Given this risk-return tradeoff, the required rate of 13
return (k) from an asset (i) can generally be expressed as: 14
ki = Rf +RPi 15
where: Rf = Risk-free rate of return, and 16 RPi = Risk premium required to hold asset i. 17
Thus, the required rate of return for a particular asset at 18
any time is a function of: (1) the yield on risk-free assets, 19
and (2) the asset’s relative risk, with investors demanding 20
correspondingly larger risk premiums for bearing greater risk. 21
Q. Is there evidence that the risk-return tradeoff 22
principle actually operates in the capital markets? 23
A. Yes. The risk-return tradeoff can be documented 24
in segments of the capital markets where required rates of 25

McKenzie, DI 47 Idaho Power Company

return can be directly inferred from market data and where 1
generally accepted measures of risk exist. Bond yields, for 2
example, reflect investors’ expected rates of return, and bond 3
ratings measure the risk of individual bond issues. Comparing 4
the observed yields on government securities, which are 5
considered free of default risk, to the yields on bonds of 6
various rating categories demonstrates that the risk-return 7
tradeoff does, in fact, exist. 8
Q. Does the risk-return tradeoff observed with fixed 9
income securities extend to common stocks and other assets? 10
A. It is widely accepted that the risk-return 11
tradeoff evidenced with long-term debt extends to all assets. 12
Documenting the risk-return tradeoff for assets other than 13
fixed income securities, however, is complicated by two 14
factors. First, there is no standard measure of risk applicable 15
to all assets. Second, for most assets—including common stock—16
required rates of return cannot be observed. Yet there is every 17
reason to believe that investors demonstrate risk aversion in 18
deciding whether or not to hold common stocks and other assets, 19
just as when choosing among fixed-income securities. 20
Q. Is this risk-return tradeoff limited to 21
differences between firms? 22
A. No. The risk-return tradeoff principle applies 23
not only to investments in different firms, but also to 24

McKenzie, DI 48 Idaho Power Company

different securities issued by the same firm. The securities 1
issued by a utility vary considerably in risk because they have 2
different characteristics and priorities. As noted earlier, the 3
last investors in line are common shareholders. They share in 4
the net earnings, if any, that remain after all other claimants 5
have been paid. As a result, the rate of return that investors 6
require from a utility’s common stock, the most junior and 7
riskiest of its securities, must be considerably higher than 8
the yield offered by the utility’s senior, long-term debt. 9
Q. What are the challenges in determining a just and 10
reasonable ROE for a utility? 11
A. The actual return investors require is not 12
directly observable. Different methodologies have been 13
developed to estimate investors’ expected return on capital, 14
but these theoretical tools produce a range of estimates, based 15
on different assumptions and inputs. The DCF method, which is 16
frequently referenced and relied on by regulators, is only one 17
theoretical approach to evaluate the return investors require. 18
There are a number of other accepted methodologies for 19
estimating the cost of capital and the ranges produced by these 20
approaches can vary widely. 21
Q. Is it customary to consider the results of 22
multiple methods when evaluating a just and reasonable ROE? 23

McKenzie, DI 49 Idaho Power Company

A. Yes. In my experience, financial analysts and 1
regulators routinely consider the results of alternative 2
approaches in evaluating a fair ROE. No single method can be 3
regarded as failsafe, with all approaches having advantages and 4
shortcomings. As FERC has noted, “[t]he determination of rate 5
of return on equity starts from the premise that there is no 6
single approach or methodology for determining the correct rate 7
of return.”44 Similarly, a publication of the Society of 8
Utility and Regulatory Financial Analysts concluded that: 9
Each model requires the exercise of judgment as 10 to the reasonableness of the underlying 11
assumptions of the methodology and on the 12 reasonableness of the proxies used to validate 13 the theory. Each model has its own way of 14
examining investor behavior, its own premises, 15 and its own set of simplifications of reality. 16
Each method proceeds from different fundamental 17 premises, most of which cannot be validated 18 empirically. Investors clearly do not subscribe 19
to any singular method, nor does the stock price 20 reflect the application of any one single method 21
by investors.45 22 23 As this treatise observed, “no single model is so inherently 24
precise that it can be relied on solely to the exclusion of 25
other theoretically sound models.”46 Similarly, New Regulatory 26
Finance concluded that: 27

44 Northwest Pipeline Co., Opinion No. 396-C, 81 FERC ¶ 61,036 at 4 (1997).
45 David C. Parcell, The Cost of Capital – A Practitioner’s Guide, Society of Utility and Regulatory Financial Analysts (2010) at 84.
46 Id.

McKenzie, DI 50 Idaho Power Company

There is no single model that conclusively 1
determines or estimates the expected return for 2 an individual firm. Each methodology possesses 3 its own way of examining investor behavior, its 4
own premises, and its own set of simplifications 5 of reality. Each method proceeds from different 6
fundamental premises that cannot be validated 7 empirically. Investors do not necessarily 8 subscribe to any one method, nor does the stock 9
price reflect the application of any one single 10 method by the price-setting investor. There is 11
no monopoly as to which method is used by 12 investors. In the absence of any hard evidence 13 as to which method outdoes the other, all 14
relevant evidence should be used and weighted 15 equally, in order to minimize judgmental error, 16
measurement error, and conceptual infirmities.47 17 18 Thus, while the DCF model is a recognized approach, it is not 19
without shortcomings and does not otherwise eliminate the need 20
to ensure that the “end result” is fair. The Indiana Utility 21
Regulatory Commission has recognized this principle: 22
// 23
// 24

47 Roger A. Morin, New Regulatory Finance, Pub. Util. Reports, Inc. (2006) at 429.

McKenzie, DI 51 Idaho Power Company

There are three principal reasons for our 1
unwillingness to place a great deal of weight on 2 the results of any DCF analysis. One is. . . 3 the failure of the DCF model to conform to 4
reality. The second is the undeniable fact that 5 rarely if ever do two expert witnesses agree on 6
the terms of a DCF equation for the same utility 7 – for example, as we shall see in more detail 8 below, projections of future dividend cash flow 9
and anticipated price appreciation of the stock 10 can vary widely. And, the third reason is that 11
the unadjusted DCF result is almost always well 12 below what any informed financial analysis would 13 regard as defensible, and therefore require an 14
upward adjustment based largely on the expert 15 witness’s judgment. In these circumstances, we 16
find it difficult to regard the results of a DCF 17 computation as any more than suggestive.48 18 19 More recently, FERC recognized the potential for any 20
application of the DCF model to produce unreliable results.49 21
As this discussion indicates, consideration of the results of 22
alternative approaches reduces the potential for error 23
associated with any single method. Just as investors inform 24
their decisions through the use of a variety of methodologies, 25
my evaluation of a fair ROE for the Company considered the 26
results of multiple financial models. 27
Q. What does this discussion imply with respect to 28
estimating the ROE for a utility? 29
A. Although the ROE cannot be observed directly, it 30
is a function of the returns available from other alternatives 31

48 Ind. Michigan Power Co., Cause No. 38728, 116 PUR4th, 1, 17-18 (IURC 8/24/1990).
49 Coakley v. Bangor Hydro-Elec. Co., Opinion No. 531, 147 FERC ¶ 61,234 at P 41 (2014).

McKenzie, DI 52 Idaho Power Company

and the risks of the investment. Because it is not readily 1
observable, the ROE for a particular utility must be estimated 2
by analyzing information about capital market conditions 3
generally, assessing the relative risks of the company 4
specifically, and employing alternative quantitative methods 5
that focus on investors’ required rates of return. These 6
methods typically attempt to infer investors’ required rates of 7
return from stock prices, interest rates, or other capital 8
market data. 9
B. Discounted Cash Flow Analysis 10
Q. How is the DCF model used to estimate the cost of 11
common equity? 12
A. DCF models are based on the assumption that the 13
price of a share of common stock is equal to the present value 14
of the expected cash flows (i.e., future dividends and stock 15
price) that will be received while holding the stock, 16
discounted at investors’ required rate of return. Rather than 17
developing annual estimates of cash flows into perpetuity, the 18
DCF model can be simplified to a “constant growth” form:50 19

50 The constant growth DCF model is dependent on a number of strict assumptions, which in practice are never met. These include a constant growth rate for both dividends and earnings; a stable dividend payout ratio; the discount rate exceeds the growth rate; a constant growth rate for book value and price; a constant earned rate of return on book value; no sales of stock at a price above or below book value; a constant price-
earnings ratio; a constant discount rate (i.e., no changes in risk or interest rate levels and a flat yield curve); and all of the above extend to infinity. Nevertheless, the DCF method provides a workable and practical
approach to estimate investors’ required return that is widely referenced in utility ratemaking.

McKenzie, DI 53 Idaho Power Company

1
where: P0 = Current price per share; 2 D1 = Expected dividend per share in coming year; 3
ke = Cost of equity; and, 4 g = Investors’ long-term growth expectations. 5
The cost of common equity (ke) can be isolated by 6
rearranging terms within the equation: 7
8
This constant growth form of the DCF model recognizes 9
that the rate of return to stockholders consists of two parts: 10
1) dividend yield (D1/P0); and 2) growth (g). In other words, 11
investors expect to receive a portion of their total return in 12
the form of current dividends and the remainder through price 13
appreciation. 14
Q. What steps are required to apply the constant 15
growth DCF model? 16
A. The first step in implementing the constant 17
growth DCF model is to determine the expected dividend yield 18
(D1/P0) for the firm in question. This is usually calculated 19
based on an estimate of dividends to be paid in the coming year 20
divided by the current price of the stock. The second, and more 21
controversial, step is to estimate investors’ long-term growth 22
expectations (g) for the firm. The final step is to add the 23
gk
DP
e −=10
gP
Dke +=
0
1

McKenzie, DI 54 Idaho Power Company

firm’s dividend yield and estimated growth rate to arrive at an 1
estimate of its cost of common equity. 2
Q. How do you determine the dividend yields for the 3
utilities in the Electric Group? 4
A. I rely on Value Line’s estimates of dividends to 5
be paid by each of these utilities over the next twelve months 6
as D1. This annual dividend is then divided by a 30-day average 7
stock price for each utility to arrive at the expected dividend 8
yield. The expected dividends, stock prices, and resulting 9
dividend yields for the firms in the Electric Group are 10
presented on page 1 of Exhibit 11. As shown there, dividend 11
yields for the firms in the Electric Group range from 2.5 12
percent to 5.0 percent and averaged 3.9 percent. 13
Q. What is the next step in applying the constant 14
growth DCF model? 15
A. The next step is to evaluate long-term growth 16
expectations, or “g”, for the firm in question. In constant 17
growth DCF theory, earnings, dividends, book value, and market 18
price are all assumed to grow in lockstep, and the growth 19
horizon of the DCF model is infinite. But implementation of the 20
DCF model is more than just a theoretical exercise; it is an 21
attempt to replicate the mechanism investors used to arrive at 22
observable stock prices. A wide variety of techniques can be 23

McKenzie, DI 55 Idaho Power Company

used to derive growth rates, but the only “g” that matters in 1
applying the DCF model is the value that investors expect. 2
Q. What are investors most likely to consider in 3
developing their long-term growth expectations? 4
A. When I implement the DCF model, we are solely 5
concerned with replicating the forward-looking evaluation of 6
real-world investors. In the case of utilities, dividend growth 7
rates are not likely to provide a meaningful guide to 8
investors’ current growth expectations. Utility dividend 9
policies reflect the need to accommodate business risks and 10
investment requirements in the industry, as well as potential 11
uncertainties in the capital markets. As a result, dividend 12
growth in the utility industry generally lags growth in 13
earnings as utilities conserve financial resources. 14
A measure that plays a pivotal role in determining 15
investors’ long-term growth expectations is future trends in 16
earnings per share (“EPS”), which provide the source for 17
future dividends and ultimately support share prices. The 18
importance of earnings in evaluating investors’ expectations 19
and requirements is well accepted in the investment community, 20
and surveys of analytical techniques relied on by professional 21
analysts indicate that growth in earnings is far more 22
influential than trends in dividends per share (“DPS”). 23

McKenzie, DI 56 Idaho Power Company

The availability of projected EPS growth rates is also 1
key to investors relying on this measure as compared to future 2
trends in DPS. Apart from Value Line, investment advisory 3
services do not generally publish comprehensive DPS growth 4
projections, and this scarcity of dividend growth rates 5
relative to the abundance of earnings forecasts attests to 6
their relative influence. The fact that securities analysts 7
focus on EPS growth, and that DPS growth rates are not 8
routinely published, indicates that projected EPS growth rates 9
are likely to provide a superior indicator of the future long-10
term growth expected by investors. 11
Q. Do the growth rate projections of security 12
analysts also consider historical trends? 13
A. Yes. Professional security analysts study 14
historical trends extensively in developing their projections 15
of future earnings. Hence, to the extent there is any useful 16
information in historical patterns, that information is 17
incorporated into analysts’ growth forecasts. 18
Q. What growth rates are security analysts currently 19
projecting for the firms in the proxy group? 20
A. EPS growth projections for each of the firms in 21
the Electric Group reported by Value Line, IBES,51 and Zacks 22

51 Formerly Institutional Brokers Estimate System, IBES growth rates are now compiled and published by Refinitiv.

McKenzie, DI 57 Idaho Power Company

Investment Research (Zacks) are displayed on page 2 of Exhibit 1
11. 2
Q. What other technique can be used to estimate 3
investors’ expectations of future long-term growth when 4
applying the constant growth DCF model? 5
A. In constant growth theory, growth in book equity 6
is equal to the product of the earnings retention ratio (one 7
minus the dividend payout ratio) and the earned rate of return 8
on book equity. Furthermore, if the earned rate of return and 9
the payout ratio are constant, growth in earnings and dividends 10
will be equal to growth in book value. Despite the fact that 11
these conditions are never met in practice, this “sustainable 12
growth” approach may provide a rough guide for evaluating a 13
firm’s growth prospects and is sometimes proposed in regulatory 14
proceedings. 15
The sustainable growth rate is calculated by the 16
formula, g = br+sv, where “b” is the expected retention ratio, 17
“r” is the expected earned return on equity, “s” is the 18
percent of common equity expected to be issued annually as new 19
common stock, and “v” is the equity accretion rate. Under DCF 20
theory, the “sv” factor is a component of the growth rate 21
designed to capture the impact of issuing new common stock at 22
a price above, or below, book value. The sustainable, “br+sv” 23
growth rates for each firm in the proxy group are summarized 24

McKenzie, DI 58 Idaho Power Company

on page 2 of Exhibit 11, with the underlying details being 1
presented on Exhibit 12. 2
The sustainable growth rate analysis shown on Exhibit 3
12 incorporates an “adjustment factor” because Value Line’s 4
reported returns are based on year-end book values. Since 5
earnings is a flow over the year while book value is 6
determined at a given point in time, the measurement of 7
earnings and book value are distinct concepts. It is this 8
fundamental difference between a flow (earnings) and a point 9
estimate (book value) that makes it necessary to adjust to 10
mid-year in calculating the ROE. Given that book value will 11
increase or decrease over the year, using year-end book value 12
(as Value Line does) understates or overstates the average 13
investment that corresponds to the flow of earnings. To 14
address this concern, earnings must be matched with a 15
corresponding measure of book value, or the resulting ROE will 16
be distorted. The adjustment factor determined in Exhibit 12 17
is solely a means of converting Value Line’s end-of-period 18
values to an average return over the year, and the formula for 19
this adjustment is supported in recognized textbooks and has 20
been adopted by other regulators.52 21

52 See, Roger A. Morin, New Regulatory Finance, Pub. Utils. Reports, Inc. (2006) at 305-306; Bangor Hydro-Electric Co. et al., 122 FERC ¶ 61,265 at n.12 (2008).

McKenzie, DI 59 Idaho Power Company

Q. Are there significant shortcomings associated 1
with the “br+sv” growth rate? 2
A. Yes. First, in order to calculate the sustainable 3
growth rate, it is necessary to develop estimates of investors’ 4
expectations for four separate variables; namely, “b”, “r”, 5
“s”, and “v.” Given the inherent difficulty in forecasting each 6
parameter and the difficulty of estimating the expectations of 7
investors, the potential for measurement error is significantly 8
increased when using four variables, as opposed to referencing 9
a direct projection for EPS growth. Second, empirical research 10
in the finance literature indicates that sustainable growth 11
rates are not as significantly correlated to measures of value, 12
such as share prices, as are analysts’ EPS growth forecasts.53 13
The “sustainable growth” approach is included for completeness, 14
but evidence indicates that analysts’ forecasts provide a 15
superior and more direct guide to investors’ growth 16
expectations. Accordingly, I give less weight to cost of equity 17
estimates based on br+sv growth rates in evaluating the results 18
of the DCF model. 19
Q. What cost of common equity estimates are implied 20
for the Electric Group using the DCF model? 21
A. After combining the dividend yields and 22
respective growth projections for each utility, the resulting 23

53 Roger A. Morin, New Regulatory Finance, Pub. Util. Reports, Inc. (2006) at 307.

McKenzie, DI 60 Idaho Power Company

cost of common equity estimates are shown on page 3 of Exhibit 1
11. 2
Q. In evaluating the results of the constant growth 3
DCF model, is it appropriate to eliminate illogical estimates 4
at the extreme low or high end of the range? 5
A. Yes. It is essential that the cost of equity 6
estimates produced by quantitative methods pass fundamental 7
tests of reasonableness and economic logic. Accordingly, DCF 8
estimates that are implausibly low or high should be 9
eliminated. 10
Q. Have other regulators employed such tests? 11
A. Yes. FERC has noted that adjustments are 12
justified where applications of the DCF approach and other 13
methods produce illogical results. FERC evaluates low-end DCF 14
results against observable yields on long-term public utility 15
debt and has recognized that it is appropriate to eliminate 16
estimates that do not sufficiently exceed this threshold.54 17
FERC’s current practice is to exclude low-end cost of estimates 18
that fall below the six-month average yield on Baa-rated 19
utility bonds, plus 20 percent of the CAPM market risk 20
premium.55 In addition, FERC also excludes estimates that are 21
54 See, e.g., Southern California Edison Co., 131 FERC ¶ 61,020 at P 55 (2010).
55 Based on the six-month average yield at March 2023 of 5.75 percent and the 7.8 percent market risk premium shown on Exhibit 13, this implies a current low-end threshold of approximately 7.3 percent.

McKenzie, DI 61 Idaho Power Company

“irrationally or anomalously high.”56 Similarly, the Staff of 1
the Maryland Public Service Commission (”MDPSC”) has also 2
eliminated DCF values where they do not offer a sufficient 3
premium above the cost of debt to be attractive to an equity 4
investor.57 5
Q. Do you exclude any estimates at the low or high 6
end of the range of DCF results? 7
A. Yes. As highlighted on page 3 of Exhibit 11, 8
after considering these benchmarks and the distribution of 9
individual estimates, I eliminate low-end DCF estimates ranging 10
from -7.6 percent to 7.3 percent, as well as a high-end DCF 11
result of 19.8 percent. After removing these illogical values, 12
the lower end of the DCF results is set by a cost of equity 13
estimate of 7.4 percent, while the upper end is established by 14
a cost of equity estimate of 14.9 percent. While a 14.9 percent 15
cost of equity estimate may exceed the other values, low-end 16
DCF estimates in the 7.4 percent to 8.1 percent range are 17
assuredly far below investors’ required rate of return. Taken 18
together and considered along with the balance of the results, 19
the remaining values provide a reasonable basis on which to 20
frame the range of plausible DCF estimates and evaluate 21
investors’ required rate of return. 22

56 Ass’n of Bus. Advocating Tariff Equity v. Midcontinent Indep. Sys. Operator, Inc., 171 FERC ¶ 61,154 at P 152 (2020).
57 See, e.g., Maryland Public Service Commission, Case No. 9670, Direct Testimony and Exhibits of Drew M. McAuliffe (Dec. 2, 2021) at 15-16.

McKenzie, DI 62 Idaho Power Company

Q. What cost of equity estimates are implied by your 1
DCF results for the Electric Group? 2
A. As shown on page 3 of Exhibit 11 and summarized 3
in Table 3, below, after eliminating illogical values, 4
application of the constant growth DCF model resulted in the 5
following ROE estimates: 6
TABLE 3 7
DCF RESULTS – ELECTRIC GROUP 8

C. Capital Asset Pricing Model 9
Q. Please describe the CAPM. 10
A. The CAPM is a theory of market equilibrium that 11
measures risk using the beta coefficient. Assuming investors 12
are fully diversified, the relevant risk of an individual asset 13
(e.g., common stock) is its volatility relative to the market 14
as a whole, with beta reflecting the tendency of a firm’s stock 15
price to follow changes in the market. A stock that tends to 16
respond less to market movements has a beta of less than 1.0, 17
while stocks that tend to move more than the market have betas 18
greater than 1.0. The CAPM is mathematically expressed as: 19

McKenzie, DI 63 Idaho Power Company

Rj = Rf +βj(Rm - Rf) 1
where: Rj = required rate of return for stock j; 2 Rf = risk-free rate; 3
Rm = expected return on the market portfolio; and, 4 βj = beta, or systematic risk, for stock j. 5
Under the CAPM formula above, a stock’s required return 6
is a function of the risk-free rate (Rf), plus a risk premium 7
that is scaled to reflect the relative volatility of a firm’s 8
stock price, as measured by beta (β). Like the DCF model, the 9
CAPM is an ex-ante, or forward-looking model based on 10
expectations of the future. As a result, in order to produce a 11
meaningful estimate of investors’ required rate of return, the 12
CAPM must be applied using estimates that reflect the 13
expectations of actual investors in the market, not with 14
backward-looking, historical data. 15
Q. Why is the CAPM approach relevant when evaluating 16
the cost of equity for Idaho Power? 17
A. The CAPM approach (which also forms the 18
foundation of the ECAPM) generally is considered to be the most 19
widely referenced method for estimating the cost of equity 20
among academicians and professional practitioners, with the 21
pioneering researchers of this method receiving the Nobel Prize 22
in 1990. Because this is the dominant model for estimating the 23
cost of equity outside the regulatory sphere, the CAPM (and 24
ECAPM) provides important insight into investors’ required rate 25
of return for utility stocks. 26

McKenzie, DI 64 Idaho Power Company

Q. How do you apply the CAPM to estimate the ROE? 1
A. Application of the CAPM to the Electric Group 2
based on a forward-looking estimate for investors’ required 3
rate of return from common stocks is presented in Exhibit 13. 4
In order to capture the expectations of today’s investors in 5
current capital markets, the expected market rate of return is 6
estimated by conducting a DCF analysis on the dividend paying 7
firms in the S&P 500. 8
The dividend yield for each firm is obtained from Value 9
Line, and the growth rate is equal to the average of the 10
earnings growth projections for each firm published by IBES, 11
Value Line, and Zacks, with each firm’s dividend yield and 12
growth rate being weighted by its proportionate share of total 13
market value. After removing companies with growth rates that 14
were negative or greater than 20 percent, the weighted average 15
of the projections for the individual firms implies an average 16
growth rate over the next five years of 9.5 percent. Combining 17
this average growth rate with a year-ahead dividend yield of 18
2.1 percent results in a current cost of common equity 19
estimate for the market as a whole (Rm) of 11.6 percent. 20
Subtracting a 3.8 percent risk-free rate based on the average 21
yield on 30-year Treasury bonds for the six-months ending 22
March 2023 produces a market equity risk premium of 7.8 23
percent. 24

McKenzie, DI 65 Idaho Power Company

Q. What is the source of the beta values you use to 1
apply the CAPM? 2
A. I rely on the beta values reported by Value Line, 3
which in my experience Value Line is the most widely referenced 4
source for beta in regulatory proceedings. As noted in New 5
Regulatory Finance: 6
Value Line is the largest and most widely 7
circulated independent investment advisory 8 service, and influences the expectations of a 9 large number of institutional and individual 10
investors. … Value Line betas are computed on a 11 theoretically sound basis using a broadly based 12
market index, and they are adjusted for the 13 regression tendency of betas to converge to 14 1.00.58 15
16 Q. What else should be considered in applying the 17
CAPM? 18
A. Financial research indicates that the CAPM does 19
not fully account for observed differences in rates of return 20
attributable to firm size. Accordingly, a modification is 21
required to account for this size effect. As explained by 22
Morningstar: 23
One of the most remarkable discoveries of 24 modern finance is the finding of a relationship 25 between firm size and return. On average, small 26
companies have higher returns than large ones. 27 . . . The relationship between firm size and 28 return cuts across the entire size spectrum; it 29
is not restricted to the smallest stocks.59 30 31

58 Roger A. Morin, New Regulatory Finance, Pub. Util. Reports, Inc. (2006) at 71.
59 Morningstar, 2015 Ibbotson SBBI Classic Yearbook, at 99.

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According to the CAPM, the expected return on a security 1
should consist of the riskless rate, plus a premium to 2
compensate for the systematic risk of the particular security. 3
The degree of systematic risk is represented by the beta 4
coefficient. The need for the size adjustment arises because 5
differences in investors’ required rates of return that are 6
related to firm size are not fully captured by beta. To 7
account for this, researchers have developed size premiums 8
that need to be added to account for the level of a firm’s 9
market capitalization in determining the CAPM cost of equity.60 10
Accordingly, my CAPM analysis also incorporates an adjustment 11
to recognize the impact of size distinctions, as measured by 12
the market capitalization for the firms in the Electric Group. 13
Q. What is the basis for the size adjustment? 14
The size adjustment required in applying the CAPM is 15
based on the finding that after controlling for risk 16
differences reflected in beta, the CAPM overstates returns to 17
companies with larger market capitalizations and understates 18
returns for relatively smaller firms. The size adjustments 19
utilized in my analysis are sourced from Kroll, who now publish 20
the well-known compilation of capital market series originally 21
developed by Professor Roger G. Ibbotson of the Yale School of 22

60 Originally compiled by Ibbotson Associates and published in their annual yearbook entitled, Stocks, Bonds, Bills and Inflation, these size premia are now developed by Kroll and presented in its Cost of Capital Navigator.

McKenzie, DI 67 Idaho Power Company

Management, and most recently published by Kroll. Calculation 1
of the size adjustments involve the following steps: 2
1. Divide all stocks traded on the NYSE, NYSE 3 MKT, and NASDAQ indices into deciles based on 4 their market capitalization. 5
2. Using the average beta value for each decile, 6 calculate the implied excess return over the 7 risk-free rate using the CAPM. 8 3. Compare the calculated excess returns based 9 on the CAPM to the actual excess returns for 10
each decile, with the difference being the 11 increment of return that is related to firm 12
size, or “size adjustment.” 13
New Regulatory Finance observed that “small market-cap 14
stocks experience higher returns than large market-cap stocks 15
with equivalent betas,” and concluded that “the CAPM 16
understates the risk of smaller utilities, and a cost of 17
equity based purely on a CAPM beta will therefore produce too 18
low an estimate.”61 19
Q. What is the implied ROE for the Electric Group 20
using the CAPM approach? 21
A. As shown on Exhibit 13, after adjusting for the 22
impact of firm size, the CAPM approach implies an average ROE 23
for the Electric Group of 11.2 percent. 24
D. Empirical Capital Asset Pricing Model 25
Q. How does the ECAPM approach differ from 26
traditional applications of the CAPM? 27

61 Roger A. Morin, New Regulatory Finance, Pub. Utils. Reports, Inc. (2006) at 187.

McKenzie, DI 68 Idaho Power Company

A. Empirical tests of the CAPM have shown that low-1
beta securities earn returns somewhat higher than the CAPM 2
would predict, and high-beta securities earn less than 3
predicted. In other words, the CAPM tends to overstate the 4
actual sensitivity of the cost of capital to beta, with low-5
beta stocks tending to have higher returns and high-beta stocks 6
tending to have lower risk returns than predicted by the CAPM. 7
This is illustrated graphically in the figure below: 8
FIGURE 2 9 CAPM – PREDICTED VS. OBSERVED RETURNS 10
11
Because the betas of utility stocks, including those in 12
the Electric Group, are generally less than 1.0, this implies 13
that cost of equity estimates based on the traditional CAPM 14
would understate the cost of equity. This empirical finding is 15

McKenzie, DI 69 Idaho Power Company

widely reported in the finance literature, as summarized in 1
New Regulatory Finance: 2
As discussed in the previous section, several 3 finance scholars have developed refined and 4 expanded versions of the standard CAPM by 5
relaxing the constraints imposed on the CAPM, 6 such as dividend yield, size, and skewness 7 effects. These enhanced CAPMs typically produce 8 a risk-return relationship that is flatter than 9 the CAPM prediction in keeping with the actual 10
observed risk-return relationship. The ECAPM 11 makes use of these empirical relationships.62 12
Based on a review of the empirical evidence, New 13
Regulatory Finance concluded the expected return on a security 14
is represented by the following formula: 15
Rj = Rf + 0.25(Rm - Rf) + 0.75[βj(Rm - Rf)] 16
Like the CAPM formula presented earlier, the ECAPM 17
represents a stock’s required return as a function of the 18
risk-free rate (Rf), plus a risk premium. In the formula above, 19
this risk premium is composed of two parts: (1) the market 20
risk premium (Rm - Rf) weighted by a factor of 25 percent, and 21
(2) a company-specific risk premium based on the stock’s 22
relative volatility [βj(Rm - Rf)] weighted by 75 percent. This 23
ECAPM equation, and its associated weighting factors, 24
recognizes the observed relationship between standard CAPM 25
estimates and the cost of capital documented in the financial 26

62 Roger A. Morin, New Regulatory Finance, Pub. Util. Reports, Inc. (2006) at 189.

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research, and corrects for the understated returns that would 1
otherwise be produced for low beta stocks. 2
Q. Have other regulators relied on the ECAPM? 3
A. Yes. Staff witnesses for the MDPSC have relied on 4
this approach in prior testimony, noting that “the ECAPM model 5
adjusts for the tendency of the CAPM model to underestimate 6
returns for low Beta stocks,” and concluding that, “the ECAPM 7
gives a more realistic measure of the ROE than the CAPM model 8
does.”63 The Staff of the Colorado Public Utilities Commission 9
has recognized that, “The ECAPM is an empirical method that 10
attempts to enhance the CAPM analysis by flattening the risk-11
return relationship,”64 and relied on the same ECAPM equation 12
presented above.65 13
The New York Department of Public Service also 14
routinely incorporates the results of the ECAPM approach, 15
which it refers to as the “zero-beta CAPM.”66 The Regulatory 16
Commission of Alaska has also relied on the ECAPM approach, 17
noting that: 18
Tesoro averaged the results it obtained from CAPM 19
and ECAPM while at the same time providing 20 empirical testimony that the ECAPM results are 21 more accurate then [sic] traditional CAPM 22
63 Direct Testimony and Exhibits of Julie McKenna, Maryland PSC Case No. 9299 (Oct. 12, 2012) at 9.
64 Proceeding No. 13AL-0067G, Answer Testimony and Schedules of Scott
England (July 31, 2013) at 47.
65 Id. at 48.
66 See, e,g., New York Department of Public Service, Cases 19-E-0065 19-G-0066, Prepared Fully Redacted Testimony of Staff Finance Panel (May 2019) at 94-95.

McKenzie, DI 71 Idaho Power Company

results. The reasonable investor would be aware 1
of these empirical results. Therefore, we adjust 2 Tesoro’s recommendation to reflect only the ECAPM 3 result.67 4
The Wyoming Office of Consumer Advocate, an independent 5
division of the Wyoming Public Service Commission, has also 6
relied on this ECAPM formula,68 as has a witness for the Office 7
of Arkansas Attorney General.69 In a 2018 decision, the Montana 8
Public Service Commission determined that “[t]he evidence in 9
this proceeding has convinced the Commission that the [ECAPM] 10
should be the primary method for estimating . . . the cost of 11
equity.”70 12
Q. What cost of equity estimate is indicated by the 13
ECAPM? 14
A. My application of the ECAPM was based on the same 15
forward-looking market rate of return, risk-free rates, and 16
beta values discussed earlier in connections with the CAPM. As 17
shown on Exhibit 14, applying the forward-looking ECAPM 18
approach to the firms in the Electric Group results in an 19
average cost of equity estimate of 11.4 percent, after 20
67 Regulatory Commission of Alaska, Order No. P-97-004(151) (Nov. 27, 2002) at 145.
68 Wyoming Public Service Commission, Docket No. 30011-97-GR-17, Pre-Filed
Direct Testimony of Anthony J. Ornelas (May 1, 2018) at 52-53.
69 Arkansas Public Service Commission, Docket No. 17-071-U, Direct Testimony of Marlon F. Griffing, PH.D. (May 29, 2018) at 33-35.
70 Montana Public Service Commission, Docket No. D2017.9.80, Order No. 7575c (Sep. 26, 2018) at P 114.

McKenzie, DI 72 Idaho Power Company

incorporating the size adjustment corresponding to the market 1
capitalization of the individual utilities. 2
E. Utility Risk Premium 3
Q. Briefly describe the risk premium method. 4
A. The risk premium method extends the risk-return 5
tradeoff observed with bonds to estimate investors’ required 6
rate of return on common stocks. The cost of equity is 7
estimated by first determining the additional return investors 8
require to forgo the relative safety of bonds and to bear the 9
greater risks associated with common stock, and then adding 10
this equity risk premium to the current yield on bonds. Like 11
the DCF model, the risk premium method is capital market 12
oriented. However, unlike DCF models, which indirectly impute 13
the cost of equity, risk premium methods directly estimate 14
investors’ required rate of return by adding an equity risk 15
premium to observable bond yields. 16
Q. Is the risk premium approach a widely accepted 17
method for estimating the cost of equity? 18
A. Yes. The risk premium approach is based on the 19
fundamental risk-return principle that is central to finance, 20
which holds that investors will require a premium in the form 21
of a higher return in order to assume additional risk. This 22
method is routinely referenced by the investment community and 23

McKenzie, DI 73 Idaho Power Company

in academia and regulatory proceedings and provides an 1
important tool in estimating a fair ROE for Idaho Power. 2
Q. How do you implement the risk premium method? 3
A. I estimate equity risk premiums for utilities 4
based on surveys of previously authorized ROEs. Authorized ROEs 5
presumably reflect regulatory commissions’ best estimates of 6
the cost of equity, however determined, at the time they issued 7
their final order. Such ROEs should represent a balanced and 8
impartial outcome that considers the need to maintain a 9
utility’s financial integrity and ability to attract capital. 10
Moreover, allowed returns are an important consideration for 11
investors and have the potential to influence other observable 12
investment parameters, including credit ratings and borrowing 13
costs. When considered in the context of a complete and 14
rigorous analysis, this data provides a logical and frequently 15
referenced basis for estimating equity risk premiums for 16
regulated utilities. 17
Q. How do you calculate the equity risk premiums 18
based on allowed returns? 19
A. The ROEs authorized for electric utilities by 20
regulatory commissions across the U.S. are compiled by S&P 21
Global Market Intelligence and published in its RRA Regulatory 22
Focus report. On page 2 of Exhibit 15, the average yield on 23
public utility bonds is subtracted from the average allowed ROE 24

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for electric utilities to calculate equity risk premiums for 1
each year between 1974 and 2022.71 As shown there, over this 2
period these equity risk premiums for electric utilities 3
average 3.89 percent, and the yields on public utility bonds 4
average 7.83 percent. 5
Q. Is there any capital market relationship that 6
must be considered when implementing the risk premium method? 7
A. Yes. The magnitude of equity risk premiums is not 8
constant and equity risk premiums tend to move inversely with 9
interest rates. In other words, when interest rate levels are 10
relatively high, equity risk premiums narrow, and when interest 11
rates are relatively low, equity risk premiums widen. The 12
implication of this inverse relationship is that the cost of 13
equity does not move as much as, or in lockstep with, interest 14
rates. Accordingly, for a 1 percent increase or decrease in 15
interest rates, the cost of equity may only rise or fall some 16
fraction of 1 percent. When implementing the risk premium 17
method, adjustments are required to incorporate this inverse 18
relationship if the current interest rates is different from 19
the average interest rate over the study period. 20
Current bond yields are lower than those prevailing 21
over the risk premium study period. Given that equity risk 22
premiums move inversely with interest rates, these lower bond 23

71 My analysis encompasses the entire period for which published data is available.

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yields also imply an increase in the equity risk premium. In 1
other words, higher required equity risk premiums partially 2
offset the impact of declining interest rates on the ROE. 3
Q. Is this inverse relationship confirmed by 4
published financial research? 5
A. Yes. There is considerable empirical evidence 6
that when interest rates are relatively high, equity risk 7
premiums narrow, and when interest rates are relatively low, 8
equity risk premiums are greater. This inverse relationship 9
between equity risk premiums and interest rates has been widely 10
reported in the financial literature. As summarized by New 11
Regulatory Finance: 12
Published studies by Brigham, Shome, and Vinson 13
(1985), Harris (1986), Harris and Marston (1992, 14 1993), Carleton, Chambers, and Lakonishok (1983), 15 Morin (2005), and McShane (2005), and others 16
demonstrate that, beginning in 1980, risk 17 premiums varied inversely with the level of 18
interest rates – rising when rates fell and 19 declining when rates rose.72 20 21 Other regulators have also recognized that, while the 22
cost of equity trends in the same direction as interest rates, 23

72 Roger A. Morin, New Regulatory Finance, Pub. Util. Reports, Inc. (2006) at 128.

McKenzie, DI 76 Idaho Power Company

these variables do not move in lock-step.73 This relationship 1
is illustrated in the figure on page 3 of Exhibit 15. 2
Q. What ROE is implied by the risk premium method 3
using surveys of allowed returns? 4
A. Based on the regression output between the 5
interest rates and equity risk premiums displayed on page 3 of 6
Exhibit 15, the equity risk premium for electric utilities 7
increases by approximately 43 basis points for each percentage 8
point drop in the yield on average public utility bonds. As 9
illustrated on page 1 of Exhibit 15 with an average yield on 10
public utility bonds for the six-months ending March 2023 of 11
5.75 percent, this implies a current equity risk premium of 12
4.89 percent for electric utilities. Adding this equity risk 13
premium to the average yield on Baa-rated utility bonds implies 14
a current ROE of 10.64 percent. 15
F. Expected Earnings Approach 16
Q. What other analysis do you conduct to estimate 17
the ROE? 18
A. I also evaluate the ROE using the expected 19
earnings method. Reference to rates of return available from 20
alternative investments of comparable risk can provide an 21

73 See, e.g., California Public Utilities Commission, Decision 08-05-035
(May 29, 2008); Entergy Mississippi Formula Rate Plan FRP-7, https://www.entergy-mississippi.com/userfiles/content/price/tariffs/eml_frp.pdf (last visited
Apr. 25, 2023); Martha Coakley et al. v. Bangor Hydro-Elec. Co. et al., 147 FERC ¶ 61,234 at P 147 (2014).

McKenzie, DI 77 Idaho Power Company

important benchmark in assessing the return necessary to assure 1
confidence in the financial integrity of a firm and its ability 2
to attract capital. This expected earnings approach is 3
consistent with the economic underpinnings for a just and 4
reasonable rate of return established by the U.S. Supreme Court 5
in Bluefield and Hope. Moreover, it avoids the complexities and 6
limitations of capital market methods and instead focuses on 7
the returns earned on book equity, which are readily available 8
to investors. 9
Q. What economic premise serves as the foundation 10
for the expected earnings approach? 11
A. The simple, but powerful concept underlying the 12
expected earnings approach is that investors compare each 13
investment alternative with the next best opportunity. If the 14
utility is unable to offer a return similar to that available 15
from other opportunities of comparable risk, investors will 16
become unwilling to supply the capital on reasonable terms. For 17
existing investors, denying the utility an opportunity to earn 18
what is available from other similar risk alternatives prevents 19
them from earning their opportunity cost of capital. This 20
outcome would violate the Hope and Bluefield standards and 21
undermine the utility’s access to capital on reasonable terms. 22
Q. How is the expected earnings approach typically 23
implemented? 24

McKenzie, DI 78 Idaho Power Company

A. The traditional comparable earnings test 1
identifies a group of companies that are believed to be 2
comparable in risk to the utility. The actual earnings of those 3
companies on the book value of their investment are then 4
compared to the allowed return of the utility. While the 5
traditional comparable earnings test is implemented using 6
historical data taken from the accounting records, it is also 7
common to use projections of returns on book investment, such 8
as those published by recognized investment advisory 9
publications (e.g., Value Line). Because these projected 10
returns on book value equity are analogous to the forward-11
looking allowed ROE on a utility’s rate base, this measure of 12
opportunity costs results in a direct, “apples to apples” 13
comparison. 14
Moreover, regulators do not set the returns that 15
investors earn in the capital markets, which are a function of 16
dividend payments and fluctuations in common stock prices—both 17
of which are outside their control. Regulators can only 18
establish the allowed ROE, which is applied to the book value 19
of a utility’s investment in rate base, as determined from its 20
accounting records. This is analogous to the expected earnings 21
approach, which measures the return that investors expect the 22
utility to earn on book value. As a result, the expected 23
earnings approach provides a meaningful guide to ensure that 24

McKenzie, DI 79 Idaho Power Company

the allowed ROE is similar to what other utilities of 1
comparable risk will earn on invested capital. This expected 2
earnings test does not require theoretical models to 3
indirectly infer investors’ perceptions from stock prices or 4
other market data. As long as the proxy companies are similar 5
in risk, their expected earned returns on invested capital 6
provide a direct benchmark for investors’ opportunity costs 7
that is independent of fluctuating stock prices, market-to-8
book ratios, debates over DCF growth rates, or the limitations 9
inherent in any theoretical model of investor behavior. 10
Q. What ROE is indicated for Idaho Power based on 11
the expected earnings approach? 12
A. For the firms in the Electric Group, the year-end 13
returns on common equity projected by Value Line over its 14
forecast horizon are shown on Exhibit 16. As I explained 15
earlier in my discussion of the br+sv growth rates used in 16
applying the DCF model, Value Line’s returns on common equity 17
are calculated using year-end equity balances, which 18
understates the average return earned over the year.74 19
Accordingly, these year-end values were converted to average 20
returns using the same adjustment factor discussed earlier and 21

74 For example, to compute the annual return on a passbook savings account with a beginning balance of $1,000 and an ending balance of $5,000, the interest income would be divided by the average balance of $3,000. Using
the $5,000 balance at the end of the year would understate the actual return.

McKenzie, DI 80 Idaho Power Company

developed on Exhibit 12. As shown on Exhibit 16, Value Line’s 1
projections for the Electric Group suggest an average ROE of 2
11.0 percent. 3
G. Flotation Costs 4
Q. What other consideration is relevant in setting 5
the return on equity for a utility? 6
A. The common equity used to finance the investment 7
in utility assets is provided from either the sale of stock in 8
the capital markets or from retained earnings not paid out as 9
dividends. When equity is raised through the sale of common 10
stock, there are costs associated with “floating” the new 11
equity securities. These flotation costs include services such 12
as legal, accounting, and printing, as well as the fees and 13
discounts paid to compensate brokers for selling the stock to 14
the public. Also, some argue that the “market pressure” from 15
the additional supply of common stock and other market factors 16
may further reduce the amount of funds a utility nets when it 17
issues common equity. 18
Q. Is there an established mechanism for a utility 19
to recognize equity issuance costs? 20
A. No. While debt flotation costs are recorded on 21
the books of the utility, amortized over the life of the issue, 22
and thus increase the effective cost of debt capital, there is 23
no similar accounting treatment to ensure that equity flotation 24

McKenzie, DI 81 Idaho Power Company

costs are recorded and ultimately recognized. No rate of return 1
is authorized on flotation costs necessarily incurred to obtain 2
a portion of the equity capital used to finance plant. In other 3
words, equity flotation costs are not included in a utility’s 4
rate base because neither that portion of the gross proceeds 5
from the sale of common stock used to pay flotation costs is 6
available to invest in plant and equipment, nor are flotation 7
costs capitalized as an intangible asset. Unless some provision 8
is made to recognize these issuance costs, a utility’s revenue 9
requirements will not fully reflect all of the costs incurred 10
for the use of investors’ funds. Because there is no accounting 11
convention to accumulate the flotation costs associated with 12
equity issues, they must be accounted for indirectly, with an 13
upward adjustment to the cost of equity being the most 14
appropriate mechanism. 15
Q. Is there academic evidence that supports a 16
flotation cost adjustment? 17
A. Yes. The financial literature and evidence in 18
this case provides a sound theoretical and practical basis to 19
include consideration of flotation costs for Idaho Power. An 20
adjustment for flotation costs associated with past sales of 21
common stock is appropriate, even when the utility is not 22
contemplating any new sales of common stock. The need for a 23
flotation cost adjustment to compensate for past common stock 24

McKenzie, DI 82 Idaho Power Company

offerings has been recognized in the financial literature. In a 1
Public Utilities Fortnightly article, for example, Brigham, 2
Aberwald, and Gapenski demonstrated that even if no further 3
stock issues are contemplated, a flotation cost adjustment in 4
all future years is required to keep shareholders whole, and 5
that the flotation cost adjustment must consider total equity, 6
including retained earnings.75 Similarly, New Regulatory 7
Finance contains the following discussion: 8
9 Another controversy is whether the flotation cost 10 allowance should still be applied when the 11
utility is not contemplating an imminent common 12 stock issue. Some argue that flotation costs are 13
real and should be recognized in calculating the 14 fair rate of return on equity, but only at the 15 time when the expenses are incurred. In other 16
words, the flotation cost allowance should not 17 continue indefinitely, but should be made in the 18
year in which the sale of securities occurs, with 19 no need for continuing compensation in future 20 years. This argument implies that the company 21
has already been compensated for these costs 22 and/or the initial contributed capital was 23
obtained freely, devoid of any flotation costs, 24 which is an unlikely assumption, and certainly 25 not applicable to most utilities. … The flotation 26
cost adjustment cannot be strictly forward-27 looking unless all past flotation costs 28
associated with past issues have been recovered.76 29 30

75 E. F. Brigham, D. A. Aberwald, and L. C. Gapenski, Common Equity Flotation Costs and Rate Making, Pub. Util. Fortnightly (May 2, 1985).
76 Roger A. Morin, New Regulatory Finance, Pub. Util. Reports, Inc. (2006) at 335.

McKenzie, DI 83 Idaho Power Company

Q. Can you illustrate why investors will not have 1
the opportunity to earn their required ROE unless a flotation 2
cost adjustment is included? 3
A. Yes. Assume a utility sells $10 worth of common 4
stock at the beginning of year 1. If the utility incurs 5
flotation costs of $0.48 (5 percent of the net proceeds), then 6
only $9.52 is available to invest in rate base. Assume that 7
common shareholders’ required rate of return is 10.5 percent, 8
the expected dividend in year 1 is $0.50 (i.e., a dividend 9
yield of 5 percent), and that growth is expected to be 5.5 10
percent annually. As developed in Table 4 below, if the allowed 11
rate of return on common equity is only equal to the utility’s 12
10.5 percent “bare bones” cost of equity, common stockholders 13
will not earn their required rate of return on their $10 14
investment, since growth will only be 5.25 percent, instead of 15
5.5 percent: 16
TABLE 4 17 NO FLOTATION COST ADJUSTMENT 18

The reason that investors never really earn 10.5 19
percent on their investment in the above example is that the 20
$0.48 in flotation costs initially incurred to raise the 21

McKenzie, DI 84 Idaho Power Company

common stock is not treated like debt issuance costs (i.e., 1
amortized into interest expense and therefore increasing the 2
embedded cost of debt), nor is it included as an asset in rate 3
base. 4
Including a flotation cost adjustment allows investors 5
to be fully compensated for the impact of these costs. One 6
commonly referenced method for calculating the flotation cost 7
adjustment is to multiply the dividend yield by a flotation 8
cost percentage. Thus, with a 5 percent dividend yield and a 5 9
percent flotation cost percentage, the flotation cost 10
adjustment in the above example would be approximately 25 11
basis points. As shown in Table 5 below, by allowing a rate of 12
return on common equity of 10.75 percent (a 10.5 percent cost 13
of equity plus a 25 basis point flotation cost adjustment), 14
investors earn their 10.5 percent required rate of return, 15
since actual growth is now equal to 5.5 percent: 16
TABLE 5 17 INCLUDING FLOTATION COST ADJUSTMENT 18

The only way for investors to be fully compensated for 19
issuance costs is to include an ongoing adjustment to account 20
for past flotation costs when setting the return on common 21

McKenzie, DI 85 Idaho Power Company

equity. This is the case regardless of whether the utility is 1
expected to issue additional shares of common stock in the 2
future. 3
Q. What is the magnitude of the adjustment to the 4
“bare bones” cost of equity to account for issuance costs? 5
A. The most common method used to account for 6
flotation costs in regulatory proceedings is to apply an 7
average flotation-cost percentage to a utility’s dividend 8
yield. In Exhibit 17, I present a survey of recent open-market 9
common stock issues for each company in Value Line’s electric 10
and gas utility industries. For all companies in the electric 11
and gas industries, flotation costs averaged 2.7 percent, or 12
2.6 percent for electric utilities. Applying the average 2.6 13
percent expense percentage for electric utilities to the 14
Electric Group dividend yield of 3.8 percentage produces a 15
flotation cost adjustment on the order of 10 basis points. 16
Q. Have other regulators recognized flotation costs 17
in evaluating a fair and reasonable ROE? 18
A. Yes. For example, In Case No. INT-G-16-02 the 19
IPUC staff noted that applying a flotation cost percentage to 20
the dividend yield “is referred to as the ‘conventional’ 21
approach. Its use in regulatory proceedings is widespread, and 22
the formula is outlined in several corporate finance 23

McKenzie, DI 86 Idaho Power Company

textbooks.”77 In Docket No. UE-991606 the Washington Utilities 1
and Transportation Commission concluded that a flotation cost 2
adjustment of 25 basis points should be included in the allowed 3
return on equity.78 4
More recently, the Wyoming Office of Consumer Advocate, 5
an independent division of the Wyoming Public Service 6
Commission, recommended a 10 basis point flotation cost 7
adjustment.79 Similarly, the South Dakota Public Utilities 8
Commission has recognized the impact of issuance costs, 9
concluding that, “recovery of reasonable flotation costs is 10
appropriate.”80 Another example of a regulator that approves 11
common stock issuance costs is the Mississippi Public Service 12
Commission, which routinely includes a flotation cost 13
adjustment in its Rate Stabilization Adjustment Rider 14
formula.81 The Public Utilities Regulatory Authority of 15
Connecticut82 the Minnesota Public Utilities Commission,83 and 16

77 Idaho Public Utilities Commission, Case No. INT-G-16-02, Direct Testimony of Mark Rogers (Dec. 16, 2016) at 18.
78 Washington Utilities and Transportation Commission Docket No. UE-991606, et al., Third Supplemental Order (September 2000) at 95.
79 Wyoming Public Service Commission, Docket No. 30011-97-GR-17, Pre-Filed
Direct Testimony of Anthony J. Ornelas (May 1, 2018) at 52-53.
80 South Dakota Public Utilities Commission, Northern States Power Co, EL11-019, Final Decision and Order at P 22 (2012).
81 See, e.g., Entergy Mississippi Formula Rate Plan FRP-7, https://cdn.entergy-mississippi.com/userfiles/content/price/tariffs/eml_frp.pdf (last visited
Apr. 25, 2023).
82 See, e.g., The Public Utilities Regulatory Authority of Connecticut, Docket No. 14-05-06, Decision (Dec. 17, 2014) at 133-134.
83 See, e.g., Minnesota Public Utilities Commission, Docket No. E001/GR-10-276, Findings of Fact, Conclusions, and Order at 9.

McKenzie, DI 87 Idaho Power Company

the Virginia State Corporation Commission84 have also 1
recognized that flotation costs are a legitimate expense 2
worthy of consideration in setting a fair and reasonable ROE. 3
VI. NON-UTILITY BENCHMARK
Q. What is the purpose of this section of your 4
testimony? 5
A. This section presents the results of my DCF 6
analysis for a group of low-risk firms in the competitive 7
sector, which I refer to as the “Non-Utility Group.” This 8
analysis is not directly considered to arrive at my recommended 9
ROE range of reasonableness; however, it is my opinion that 10
this is a relevant consideration in evaluating a fair ROE for 11
the Company. 12
Q. Do utilities have to compete with non-regulated 13
firms for capital? 14
A. Yes. The cost of capital is an opportunity cost 15
based on the returns that investors could realize by putting 16
their money in other alternatives. Clearly, the total capital 17
invested in utility stocks is only a small fraction of total 18
common stock investment, and there is a plethora of other 19
alternatives available to investors. Utilities must compete for 20
capital, not just against firms in their own industry, but with 21
other investment opportunities of comparable risk. This 22

84 Virginia State Corporation Commission, Roanoke Gas Company, Case No. PUR-2018-00013, Final Order, (Jan. 24, 2020) at 6.

McKenzie, DI 88 Idaho Power Company

understanding is consistent with modern portfolio theory, which 1
is built on the assumption that rational investors will hold a 2
diverse portfolio of stocks and not just companies in a single 3
industry. 4
Q. Is it consistent with the Bluefield and Hope 5
cases to consider investors’ required ROE for non-utility 6
companies? 7
A. Yes. The cost of equity capital in the 8
competitive sector of the economy forms the very underpinning 9
for utility ROEs because regulation purports to serve as a 10
substitute for the actions of competitive markets. The Supreme 11
Court has recognized that it is the degree of risk, not the 12
nature of the business, which is relevant in evaluating an 13
allowed ROE for a utility. The Bluefield case refers to 14
“business undertakings attended with comparable risks and 15
uncertainties.” It does not restrict consideration to other 16
utilities. Similarly, the Hope case states: 17
By that standard the return to the equity owner 18 should be commensurate with returns on 19
investments in other enterprises having 20 corresponding risks.85 21
22 As in the Bluefield decision, there is nothing to 23
restrict “other enterprises” solely to the utility industry. 24

85 Federal Power Comm’n v. Hope Natural Gas Co., 320 U.S. 391 (1944).

McKenzie, DI 89 Idaho Power Company

Q. Does consideration of the results for the Non-1
Utility Group improve the reliability of DCF results? 2
A. Yes. Growth estimates used in the DCF model 3
depend on analysts’ forecasts. It is possible for utility 4
growth rates to be distorted by short-term trends in the 5
industry, or by the industry falling into favor or disfavor by 6
analysts. Such distortions could result in biased DCF estimates 7
for utilities. Because the Non-Utility Group includes low risk 8
companies from more than one industry, it helps to insulate 9
against any possible distortion that may be present in results 10
for a particular sector. 11
Q. What criteria do you apply to develop the Non-12
Utility Group? 13
A. My comparable risk proxy group was composed of 14
those United States companies followed by Value Line that: 15
1) pay common dividends; 16 2) have a Safety Rank of “1”; 17
3) have a Financial Strength Rating of “A” or greater; 18 4) have a beta of 0.95 or less; and 19 5) have investment grade credit ratings from S&P and 20
Moody’s. 21
Q. How do the overall risks of your Non-Utility 22
Group compare to the proxy group of electric utilities? 23
A. Table 6 compares the Non-Utility Group to the 24
Electric Group and Idaho Power across the four key indices of 25
investment risk discussed earlier. 26

McKenzie, DI 90 Idaho Power Company

TABLE 6 1
COMPARISON OF RISK INDICATORS 2

As shown above, the risk indicators for the Non-Utility 3
Group suggest equivalent or less risk than for the Electric 4
Group and Idaho Power. 5
The companies that make up the Non-Utility Group are 6
representative of the pinnacle of corporate America. These 7
firms, which include household names such as Coca-Cola, 8
Kellogg, Procter & Gamble, and Walmart, have long corporate 9
histories, well-established track records, and conservative 10
risk profiles. Many of these companies pay dividends on a par 11
with utilities, with the average dividend yield for the group 12
at 2.3 percent.86 Moreover, because of their significance and 13
name recognition, these companies receive intense scrutiny by 14
the investment community, which increases confidence that 15
published growth estimates are representative of the consensus 16
expectations reflected in common stock prices. 17

86 Exhibit 18 at page 1.

McKenzie, DI 91 Idaho Power Company

Q. What are the results of your DCF analysis for the 1
Non-Utility Group? 2
A. I apply the DCF model to the Non-Utility Group 3
using the same analysts’ EPS growth projections described 4
earlier for the Electric Group, with the results being 5
presented on page 3 of Exhibit 18. As summarized in Table 7, 6
below, after eliminating illogical values, application of the 7
constant growth DCF model results in the following cost of 8
equity estimates: 9
TABLE 7 10 DCF RESULTS – NON-UTILITY GROUP 11

As discussed earlier, reference to the Non-Utility 12
Group is consistent with established regulatory principles. 13
Required returns for utilities should be in line with those of 14
non-utility firms of comparable risk operating under the 15
constraints of free competition. Because the actual cost of 16
equity is unobservable, and DCF results inherently incorporate 17
a degree of error, cost of equity estimates for the Non-18
Utility Group provide an important benchmark in evaluating a 19
fair ROE for Idaho Power. 20
Q. Does this conclude your direct testimony? 21
A. Yes, it does. 22

McKenzie, DI 92 Idaho Power Company

DECLARATION OF Adrien M. McKenzie, CFA 1
I, Adrien M. Mckenzie, CFA, declare under penalty of 2
perjury under the laws of the state of Idaho: 3
1. My name is Adrien M. McKenzie. I am President of 4
Financial Concepts and Applications, Inc. (“FINCAP”), a firm 5
providing financial, economic, and policy consulting services to 6
business and government. 7
2. On behalf of Idaho Power, I present this pre-8
filed direct testimony in this matter. 9
3. To the best of my knowledge, my pre-filed direct 10
testimony and exhibits are true and accurate. 11
I hereby declare that the above statement is true to the 12
best of my knowledge and belief, and that I understand it is 13
made for use as evidence before the Idaho Public Utilities 14
Commission and is subject to penalty for perjury. 15
SIGNED this 1st day of June 2023, at Austin, Texas. 16
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18 Signed: _______________________ 19
Adrien M. McKenzie 20
21