20040803Vol III Part I.pdf

ORIGINAL.
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF)
AVISTA CORPORATION FOR AUTHORITY
TO INCREASE ITS RATES AND CHARGES
FOR ELECTRI C AND NATURAL GAS
SERVICE TO ELECTRIC AND NATURAL GAS)
CUSTOMERS IN THE STATE OF IDAHO.
I .
HEARING BEFORE
CASE NOS.
AVU-04-
AVU-04-
Idaho Public Utilities Coni mission
Office of the SecretRECEIVED
AUG -1. 2004
Boise. Idaho
COMMISSIONER PAUL KJELLANDER (Presiding)
COMMISSIONER MARSHA H. SMITH
COMMISSIONER DENNIS S. HANSEN
PLACE:Commission Hearing Room
472 West Washington Street
Boise / Idaho
DATE:July 20/ 2004
VOLUME III - Pages 365 - 699
COURT REPORTING
gvw~ tk edIf(/I(UI(/Yfi $,fU 197&
POST OFFICE BOX 578
BOISE, IDAHO 83701
208-336-9208
For the Staff:
For Avista:
For Potlatch:
For Coeur Silver Valley:
For Communi ty Action:
SCOTT WOODBURY / Esq.
and LI SA NORDSTROM / Esq.
Deputy At torneys General
472 West Washington
Bo is e , Idaho 8 3 7 02
DAVID J. MEYER , Esq.
Avista Corporation
Post Office Box 3727
1411 East Mission Avenue
Spokane, Washington 99220-3727
GIVENS PURSLEY LLP
by CONLEY E. WARD , Esq.
601 West Bannock StreetBoise, Idaho 83702
EVANS, KEANE
by CHARLES L. A. COX , Esq.
Post Office Box 659
111 Main StreetKellogg, Idaho 83837
BRAD M. PURDY, Esq.
Attorney at Law
2019 North Seventeenth StreetBoise, Idaho 83702
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID
APPEARANCES
83701
WITNESS EXAMINATION BY PAGE
William E. Avera
(Avista)
Mr. Meyer (Direct)
Prefiled Direct
Prefiled Rebuttal
Ms. Nordstrom (Cross)Mr. Ward (Cross)
Commissioner Hansen
Anthony Yankel
(Coeur Silver Valley)
Mr. Cox (Direct)
Prefiled Direct
Prefiled Rebuttal
Mr. Woodbury (Cross)Mr. Meyer (Cross)
Commissioner Smi
Robert J. Lafferty
(Avista)
Mr. Meyer (Direct)
Prefiled Direct
Prefiled Rebuttal
Mr. Woodbury (Cross)
Mr. Ward (Cross)
NUMBER
365
368
438
485
487
494
496
499
514
524
526
532
533
536
601
634
669
PAGE
For Avista:
Schedules3 .
6 .Schedules 1-
(Confidential - Schedules 4, 7, 9-12,
14 and 15)
7 .Schedules 16-
(Confidential - Schedules 16, 21
and 31)
8 .Schedules 32 -
(Confidential - Schedules 33-35)
Schedule 36
PremarkedAdmitted 485
PremarkedAdmitted 634
premarked
Admi t ted 634
premarked
Admi t ted 634
PremarkedAdmitted 634
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
INDEX
EXHIBITS
24 .Calculation of Loss on Deal B
Gas Sales
PremarkedAdmitted 634
Summary of Savings Obtained by
Selling Fixed Priced Gas
Premar ked
Admi t ted 634
25.
For Potlatch:
Avista Response to Potlatch
Request No.4 (C)
672216.Marked
217.7/9/04 Article:
of Indictment
677Avista Deal Part Mar ked
(Confidential)683218.Marked
219.Avista Response to Potlatch
Request No.4 6 (A)
695Marked
For Coeur Silver Valle
301.Distribution Substation Direct
As s i gnmen t
PremarkedAdmitted 524
302 .Cost of Service Basic Summary Premar ked
Admi t ted 524
303 .Cost of Service Calculation PremarkedAdmitted 524
(Confidential)Premar ked
Admi tted 524
304 .
305.(Conf ident ial Premarked
Admi t ted 524
(Conf ident ial)PremarkedAdmitted 524
306.
307 .Comparison of Proposed Rates for
Schedule 25
PremarkedAdmitted 524
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID
EXHIBITS
83701
BOISE , IDAHO, TUESDAY , JULY 20, 2004, 9:00 A.
WILLIAM E. AVERA
produced as a witness at the instance of Avista, being first
duly sworn , was examined and testified as follows:
HEARING OFFI CER :All right, we'll be back on the
record and welcome to day two.
And, Mr. Meyer, your witness has been sworn in
but officially for the record, would you go ahead and call your
witness?
Dr. Avera.
BY MR.MEYER:
and on whose
MR . MEYER:Thank you.Calling to the stand
DIRECT EXAMINATION
For the record, please state your name and who
behalf are you testifying?
m William E. Avera, and I'm testifying on
behalf of Avista Corporation.
test imony?
And have you prefiled both direct and rebuttal
Yes, Mr. Meyer , I have.
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
AVERA (Di)
Avista
Do you have any changes to make to that?
I have one small change to the direct at page 65.
On line 14 , four word -- five words in , there is "or efficient
thermal generating capaci ty. It should read "or less
efficient thermal generating capacity.So the word less,
S, should be inserted between "or" and "efficient.
Q .I think we have the wrong page reference.
Oh, this may be one of those "printos.The
sect ion is Other Factors, Sect ion D.
Yes, starts on page 65.
And then line 14?Maybe the lines are what
Is the sentence?I t's in that Q and A?
Right.ReducedAnd the sentence is:
hydroelectric generation due to below average water conditions.
COMMISSIONER SMITH:Line 20.
MR . WARD:Starts at 19.
Okay.Take us there, and where isBY MR. MEYER:
your adde
The adder is after "purchase power " between "or"
and "efficient.
Q .Line 21, after "purchase power.Okay.
I apologi ze My computer is not synced with
everyone else '
We I re still not there yet.
The change is to insert the word less.
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HEDRICK COURT REPORTING
O. BOX 578, BOISE , ID
AVERA (Di)
Avista83701
COMMISSIONER SMITH:Less efficient?
THE WITNESS:Less efficient thermal generating
capaci ty.
Well, that was easy.BY MR. MEYER:
If I were to ask you the questions that appeared,
Mr. Avera , in both your direct and your rebuttal, would your
answers be the same?
Yes, they would be.
And are you also sponsoring what has been marked
for identification as Exhibit No.
Yes, sir.
And was that sponsored by you or prepared by you
or under your direction and supervision?
It was.
MR. MEYER:Wi th that, I ask that Dr. Avera '
direct and rebuttal testimony be spread as if read, and move
the admission of Exhibi t No.
COMMISSIONER KJELLANDER:Without obj ection
we 'll spread the testimony of both direct and rebuttal, and
admi t the exhibi
(The following prefiled direct and
rebut tal testimony of Mr. Avera is spread upon the record.
367
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID
AVERA (Di)Avista83701
INTRODUCTION
Please state your name and business address.
William E. Avera, 3907 Red River, Austin, Texas, 78751.
In what capacity are you employed?
I am the President of FINCAP, Inc., a firm providing financial, economic, and
policy consulting services to business and government.
Qualifications
What are your professional qualifications?
I received a B.A. degree with a major in economics from Emory University.
After serving in the United States Navy, I entered the doctoral program in economics at the
University of North Carolina at Chapel Hill. Upon receiving my Ph.D., I joined the faculty at
the University of North Carolina and taught finance in the Graduate School of Business. I
subsequently accepted a position at the University of Texas at Austin where I taught courses
in financial management and investment analysis. I then went to work for International Paper
Company in New York City as Manager of Financial Education, a position in which I had
responsibility for all corporate education programs in finance, accounting, and economics.
In 1977 , I joined the staff of the Public Utility Commission of Texas ("PUCT") as
Director of the Economic Research Division. During my tenure at the PUCT, I managed a
division responsible for financial analysis, cost allocation and rate design, economic and
financial research, and data processing systems, and I testified in cases on a variety
financial and economic issues. Since leaving the PUCT in 1979, I have been engaged as a
consultant. I have participated in a wide range of assignments involving utility-related
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matters on behalf of utilities, industrial customers, municipalities, and regulatory
commissions. I have previously testified before the Federal Energy Regulatory Commission
FERC"), as well as the Federal Communications Commission ("FCC"), the Surface
Transportation Board (and its predecessor, the Interstate Commerce Commission), the
Canadian Radio-Television and Telecommunications Commission, and regulatory agencies,
courts, and legislative committees in 30 states, including the Idaho Public Utilities
Commission (the "Commission" or "IPUC"
I was appointed by the PUCT to the Synchronous Interconnection Committee to
advise the Texas legislature on the costs and benefits of connecting Texas to the national
electric transmission grid.Currently, I serve as an outside director of Georgia System
Operations Corporation, the system operator for electric cooperatives in Georgia.
I have served as Lecturer in the Finance Department at the University of Texas at
Austin and taught in the evening graduate program at St. Edward's University for twenty
years. In addition, I have lectured on economic and regulatory topics in programs sponsored
by universities and industry groups. I have taught in hundreds of educational programs for
financial analysts in programs sponsored by the Association for Investment Management and
Research, the Financial Analysts Review, and local financial analysts societies. These
programs have been presented in Asia, Europe, and North America, including the Financial
Analysts Seminar at Northwestern University. I hold the Chartered Financial Analyst (CFA CID
designation and have served as Vice President for Membership of the Financial Management
Association. I also have served on the Board of Directors of the North Carolina Society of
Financial Analysts. I was elected Vice Chairman of the National Association of Regulatory
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Commissioners ("NARUC") Subcommittee on Economics and appointed to NARUC'
Technical Subcommittee on the National Energy Act. I also have served as an officer of
various other professional organizations and societies. A resume containing the details of my
experience and qualifications is attached as Appendix A.
Overview
What is the purpose of your testimony in this case?
The purpose of my testimony is to present to the Commission my independent
evaluation of Avista Corp.s ("Avista" or "the Company ) current cost of common equity for
its jurisdictional electric utility operations. I conclude that Avista s current cost of equity
significantly exceeds 11.5 percent and endorse strongly the Company s request that this value
be used as the rate of return on common equity ("ROE") for purposes of determining the
weighted average cost of capital.
Please summarize the basis of your knowledge and conclusions
concerning the issues to which you are testifying in this case.
As is common and generally accepted in my field of expertise, I have accessed
and used information from a variety of sources.am familiar with the organization
operations, finances, and operation of Avista from my participation in prior proceedings
before the IPUC, the Washington Utilities and Transportation Commission ("WUTC"), and
the Oregon Public Utility Commission ("OPUC"). In connection with the present filing, I
considered and relied upon corporate disclosures and management discussions, publicly
available financial reports and filings, and other published information relating to Avista. I
also reviewed information relating generally to current capital market conditions and
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specifically to current investor perceptions, requirements, and expectations for vertically
integrated electric utilities. These sources, coupled with my experience in the fields of
finance and utility regulation, have given me a working knowledge of investors' ROE
requirements for Avista as it competes to attract capital, and form the basis of my analyses
and conclusions.
What is the role of ROE in setting a utility s rates?
The rate of return on common equity serves to compensate investors for the
use of their capital to finance the plant and equipment necessary to provide utility service.
Investors only commit money in anticipation of earning a return on their investment
commensurate with that available from other investment alternatives having comparable
risks. Consistent with both sound regulatory economics and the standards specified in the
Bluefieldl and Hope cases, the return on investment allowed a utility should be sufficient to:
1) fairly compensate capital invested in the utility, 2) enable the utility to offer a return
adequate to attract new capital on reasonable terms, and 3) maintain the utility s financial
integrity.
How did you go about developing your conclusions regarding a fair rate
of return for A vista?
first reviewed the operations and finances of Avista and the general
conditions in the electric utility industry and the economy. With this as a background, I
developed the principles underlying the cost of equity concept and then conducted various
Bluefield Water Works Improvement Co. v. Pub. Servo Comm 262 U.S. 679 (1923).
Fed. Power Comm V. Hope Natural Gas Co., 320 U.S. 591 (1944).
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generally accepted quantitative analyses to estimate the Company s current cost of equity.
These included discounted cash flow ("DCF") analyses and risk premium methods applied to
a reference group of electric utilities, as well as reference to earned rates of return expected
for utilities and industrial firms. Based on the cost of equity estimates indicated by my
analyses, the Company s ROE was evaluated taking into account the specific risks and
economic requirements for Avista consistent with restoration and preservation of its financial
integrity.
Summary of Conclusions
What is your conclusion regarding the reasonableness of the 11.5 percent
ROE requested by Avista?
Based on my capital market analyses and the economic requirements for
electric utility operations, I conclude that a 11.5 percent ROE falls below the current required
rate of return for Avista, in light of investors' economic requirements and the Company
specific risks. Results of my quantitative analyses indicated that the cost of common equity
for a benchmark group of electric utilities in the western u.s. is presently in the range of 10.4
to 11.9 percent.The investment risks associated uniquely with Avista, however, are
significantly greater than those of the utilities in the benchmark group and investors require a
higher rate of return to compensate for that risk. Coupled with expectations for higher utility
bond yields going forward, at a minimum these greater risks would suggest a rate of return on
equity at the uppermost end of the range for the proxy group.
The reasonableness of Avista s requested ROE is further reinforced by investors
continued focus on the uncertainties associated with the electric power industry in which
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Avista must operate to meet its energy requirements. Unsettled conditions in western power
markets, Avista reliance on hydrogeneration and purchased power, and regulatory
uncertainties all compound the investment risks associated with the Company s jurisdictional
utility operations. The cost of fully funding the Company s common equity capital is small
relative to the potential benefits that a financially sound utility can have in providing reliable
service at reasonable rates; especially when compared against the burden imposed by a
financially troubled service provider.Considering the importance of ensuring investor
confidence, strengthening Avista s financial standing, and enhancing the Company s ability to
attract the capital necessary to expand utility infrastructure, an 11.5 percent rate of return on
equity is both necessary and reasonable at this juncture.
II.FUNDAMENTAL ANAL YSES
What is the purpose of this section?
As a predicate to my economic and capital market analyses, this section briefly
describes Avista and reviews its operations and finances. This section also examines the risks
and prospects for the electric utility industry as a whole and conditions in the capital markets
and the general economy. An understanding of these fundamental factors, which drive the
risks and prospects of electric utilities, is essential to developing an informed opinion about
current investor expectations and requirements and forms the basis of a fair rate of return on
equity.
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A vista Corporation
A vista Corp.
Briefly describe A vista.
Headquartered in Spokane, Washington, Avista is engaged primarily in the
procurement, transmission, and distribution of electric energy and natural gas, as well as
other energy-related businesses. The Avista Utilities operating division is comprised of state-
regulated utility activities, including retail electric and natural gas distribution and
transmission services and energy generation. In addition to providing electric and natural gas
utility service within a 26,000 square mile area of eastern Washington and northern Idaho,
Avista s utility segment also provides gas distribution service in 4,000 square miles of
northeast and southwest Oregon and in the South Lake Tahoe region of California.
Avista Capital, a wholly owned subsidiary, is the parent company of all non-utility
subsidiaries.Through these companies, Avista is engaged in electric and natural gas
marketing, trading, and resource management, primarily within the eleven Western states
comprising the Western Electricity Coordinating Council, and internet-based specialty billing
and information services. As of September 30,2003, Avista had total assets of approximately
$3.4 billion, with consolidated revenues totaling over $980 million for the 2002 fiscal year.
Please describe Avista's electric utility operations.
Avista provides retail electric service to approximately 321,000 customers,
with principal industries in the area including agriculture, mining, and forestry, as well as
health care, electronic and other manufacturing, and tourism. During the 2002 fiscal year,
Avista s electric deliveries total 9.8 million megawatt hours ("mWh"). Approximately 42
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percent of 2002 retail electric revenues were from residential customers, with 42 percent
from commercial and 16 percent from industrial users and street lighting.
Avista s generating facilities include 8 hydroelectric generating stations located in
Idaho, Montana, and Washington with a combined capacity of approximately 960 megawatts
MW"). In addition, Avista holds a 15 percent interest in the coal-fired Colstrip plant
(approximately 220 MW) and a 50 percent interest in the 280 MW combined cycle natural-
gas fired Coyote Springs 2 facility, which was placed into operation in July 2003. Avista also
owns a wood-fired plant with a generating capacity of approximately 50 MW and has four
natural gas-fired generating facilities used primarily to meet peak demand. Avista anticipates
total capital expenditures for electric utility operations of approximately $230 million for
2004 and 2005.
During 2002 company-owned generation accounted for 55 percent of the electric
energy provided by Avista, with the balance being obtained through purchased power and
exchanges. The electrical output of Avista s hydroelectric plants, which has a significant
impact on total energy costs, is dependent on stream flows, which have fallen significantly
below nonnallevels in recent years. Although Avista estimates that hydroelectric generation
is capable of supplying 50 percent of total system requirements under normal conditions
streamflow conditions for 2003 were approximately 85 percent of normal levels. Avista
expects that below-normal water conditions will continue into 2004.
Avista s transmission system interconnects the Company with other western electric
utilities permitting the interchange, purchase, and sale of power among all major electric
systems in the west. Avista offers firm and non-firm transmission services in the eastern
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Washington, northern Idaho, and western Montana areas of the Pacific Northwest. Avista is
also participating with nine other western utilities in the possible formation of a Regional
Transmission Organization ("RTO"), RTO West. RTO West received limited approval of its
Stage 2 proposal from the FERC in September 2002. Fluctuations in the output of the
Company s hydroelectric generating facilities due to variable water conditions force Avista to
rely more heavily on wholesale power markets to meet its customers' energy needs.
In response to the business and regulatory risks inherent in substantial reliance on
wholesale power markets for electricity supply, and recognizing the continuing uncertainty
concerning the reliability and volatility of such purchases, Avista has proposed a plan to
expand access to additional generating resources and upgrade its electric transmission system.
Avista s Integrated Resource Plan has identified the potential need for the Company to
finance total expenditures for electric facilities of approximately $725 million over the next
ten years.3 The prefen-ed strategy outlined in Avista s 2003 Integrated Resource Plan, which
seeks to reduce exposure to wholesale market volatility, contemplates total expenditures of
$2.4 billion over the plan s 20-year horizon. Considering the Company s weakened credit
standing, enhancing Avista financial integrity and flexibility will be instrumental in
attracting the capital necessary to fund these projects in an effective manner.
Avista is subject to state retail regulation by the IPUC, the WUTC, the OPUC, and the
Public Utilities Commission of the State of California, and at the federal level by FERC.
Additionally, all but one of Avista s hydroelectric facilities are subject to licensing under the
Federal Power Act, which is administered by FERC. After agreeing to institute various
3 Avista Corp., 2003 Integrated Resource Plan at 48.
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protections, mitigation, and enhancement measures in order to address environmental
concerns, Avista received new operating licenses covering its two largest hydroelectric
facilities Cabinet Gorge and Noxon Rapids - in 2000.The license covering fi
hydroelectric plants on the Spokane River expires in August 2007 and the planning and
consultation process with stakeholders is underway. Relicensing is not automatic under
federal law, and Avista must demonstrate that it has operated its facilities in the public
interest, which includes adequately addressing environmental concerns.
How are fluctuations in A vista's operating expenses caused by varying
hydro and power market conditions accommodated in its rates?
Beginning in 1989, Avista implemented a power cost adjustment mechanism
PCA"), under which Idaho jurisdictional rates are adjusted periodically to reflect changes in
variable power production and supply costs. When hydroelectric generation is reduced and
power supply costs rise above those included in base rates, the PCA allows Avista to increase
rates to recover a portion of its additional costs. Conversely, if increased hydroelectric
generation were to lead to lower power supply costs, rates would be reduced. Although the
PCA provides for rates to be adjusted periodically, it applies to 90 percent of the deviation
between actual power supply costs and normalized rates.
What credit ratings have been assigned to Avista?
Like many other utilities in the region, Avista was adversely affected by
volatile and unprecedented energy prices in the western U.S. in 2000 and 2001.
Unprecedented increases in wholesale prices, rate structures that did not capture full costs
acquiring fuel and purchased power led to severe liquidity problems, depressed earnings, and
377 A vera, Di
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debt ratings downgrades. Avista is currently assigned a corporate credit rating of "BB+" by
Standard & Poor s Corporation (S&P), with Avista s senior secured debt being rated "BBB-
Similarly, Moody s Investors Service ("Moody s) has assigned an issuer credit rating of
Bal" Avista, while rating the Company s first mortgage bonds "Baa3". These corporate
credit ratings place Avista in the same category as speculative, or "junk," bond companies
with its senior debt ratings occupying the bottom rung on the ladder of the investment grade
scale.
Electric Power Industry
What are the general conditions in the electric power industry?
The industry is characterized by structural change resulting from market
forces, decontrol initiatives and judicial decisions.
Please describe these structural changes.
At the federal level, the FERC has been an aggressive proponent of regulatory
driven reforms designed to foster greater competition in markets for wholesale power supply.
The National Energy Policy Act of 1992, which reformed the Public Utility Holding
Company Act of 1935, and to a limited extent, the Federal Power Act, greatly increased
prospective competition for the production and sale of power at the wholesale level. In April
1996, FERC adopted Order No. 888, mandating "open access" to the transmission facilities
of jurisdictional electric utilities.FERC also has pushed for the regionalization of
transmission system control, by establishing frameworks for creation of Regional
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Transmission Organizations ("RTOs ) in its Order No. 2000.4 "Open access" has, in the view
of most market observers, resulted in more competition and competitors in wholesale power
markets, but not without the introduction of substantial risks - particularly for utilities (like
Avista) that depend on wholesale power markets for a significant portion of their resource
requirements. On July 31, 2002 FERC issued a notice of proposed rulemaking proposing a
framework to address alleged discrimination in providing interstate transmission services and
in other industry practices.s More recently, on April 28, 2003, FERC issued a White Paper
refining its vision for a wholesale power market platform, taking into account recent
developments in market design and comments filed in response to the earlier SMD NOPR.
Wholesale wheeling provides transmission-dependent electric utilities with additional
energy supply options; but it has also introduced new risks to participants in the wholesale
power markets. Policies affecting competition in the electric power industry vary widely at
the state level, but over 25 jurisdictions have enacted some form of industry restructuring.
This process of industry transition led to the disaggregation of many formerly integrated
electric utilities into three primary components - generation, transmission, and distribution.
Presently, however, Avista is, and is expected to remain, a fully integrated public utility.
Regional Transmission Organizations, Order No. 2000 (Dec. 20, 1999),89 FERC en 61,285.
55 Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity
Market Design, 67 Fed. Reg. 55,451, FERC Slats. & Regs. en 32,563 (2002) ("SMD NOPR"6 FERC White Paper, Wholesale Power Market Platform, April 28, 2003, available at
http://www.fere.govlEleetrieIRTOlMrkt -Stret -eommentslWhite paper. pdt.
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What impact has the western power crisis had on investors' risk
perceptions for firms involved in the electric power industry?
During the course of the last several years, investors have dramatically altered
their assessment of the relative risks associated with the electric power industry. A well-
publicized energy crisis throughout the west has wreaked havoc on the State s customers,
utilities, and policymakers. It also has had dramatic repercussions for western wholesale
power markets and investors and utilities nationwide. Beyond causing state regulators and
legislators to re-evaluate their restructuring initiatives for the retail sector of the electric
industry, the financial implications of the western power crisis experience demonstrated the
risks facing all segments of the electric power industry.
The massive debts owed by California s retail utilities to banks, power producers and
other creditors shattered their financial integrity and the subsequent bankruptcy filing of
Pacific Gas and Electric Company ("PG&E") brought the uncertainties associated with
today s power markets into sharp focus for the investment community. Enron s, and later
Mirant Corporation s, bankruptcies only served to magnify the risks associated with the
power sector and increased investors' reluctance to commit capital in the energy industry, as
former FERC Commissioner Massey succinctly recognized:
Sadly, the tsunami of the western energy crisis, coupled with the collapse of
Enron, have left a devastating wake within the industry. Investor confidence
has been shaken by these events, by a declining national economy, indictments
of energy traders, accounting irregularities, downgrades by rating agencies,
and continuing investigations by the FERC, CFTC, the SEC, and the Justice
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Department. .
. .
The flight of capital from the industry has been severe since
the collapse of Enron.
While the case of California and PG&E represents an extreme example, there is every
indication that investors ' risk perceptions for electric utilities shifted sharply upward as
events in the western U.S. continued to unfold. The resolution is far from over, as even
today, the FERC, federal and state courts, and other agencies debate and examine the
underlying causes of the volatility, high prices and erratic supply patterns characteristic of
western wholesale power markets in 2000 and 2001.
Have these events affected electric utilities' credit standing?
Yes. The last several years have witnessed steady erosion in credit quality
throughout the electric utility industry, both as a result of revised perceptions of the risks in
the industry and the weakened finances of the utilities themselves. For example, during
2002, S&P recorded 182 downgrades in the electric power industry, versus only 15 upgrades,
while Moody s downgraded 109 utility issuers and upgraded one; an acceleration of the trend
in bond rating changes during the previous two years. Moreover, credit quality has continued
to decline. S&P reported an unprecedented 88 ratings downgrades during the first half of
2003 alone,8 and noted that the utility industry "continued its downward credit slope that was
firmly established in early 2000 in this year s third quarter.9 Similarly, Moody s downgraded
51 utilities between January and June 2003, while upgrading only one firm.
Remarks by William L. Massey, Center for Public Utilities Advisory Council
, "
The Santa Fe Conference
(March 17,2003).8 Standard & Poor s Corporation, "Credit Quality For U.S. Utilities Continues Negative Trend,RatingsDirect
(Jul. 24, 2003).9 Standard & Poor s Corporation, "Downgrades Continue to Dominate U.S. Rating Actions in Third Quarter,
RatingsDirect (Oct. 16,2003).10 Moody s Investors Service, Moody s Credit Perspectives (Jul. 14,2003) at 33-34.
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381
What was the impact of these capital and credit market conditions on the
ability of electric utilities to raise funds?
Combined with a stagnant economy and global uncertainties, the dramatic
upward shift in investors' risk perceptions and the weakened financial picture of most
industry participants combined to produce a severe liquidity crunch in the electric power
industry. S&P cited the debilitating impact of these developments on investors' willingness
to provide capital:
The last 24 months have witnessed extraordinary turmoil for power and energy
debt, unprecedented since Samuel Insull's utility empire collapsed during the
1930s. Events ranging from the credit collapse of the California utilities,
through the Enron bankruptcy and subsequent market disruptions for U.
energy merchant companies have destroyed billions of dollars of value for
investors. Wall Street has virtually shut down new investment in this sector. I I
Increasingly constrained capital market access as a result of investor
skepticism over accounting practices and disclosure, more and more federal
and state investigations and subpoenas, audits, and failing confidence in future
financial performance has created a liquidity crisiS.
The challenges faced by electric utilities resulted in reduced financing activity, with
many utilities being forced to rely on bank debt. Access to the commercial paper markets,
long the low-cost staple of high-grade utility credits for meeting working capital needs,
virtually disappeared for certain companies. S&P noted that this falloff in financing activity
was partly attributable to "capital market jitters, especially for those firms that are most in
need of capital market access.13 As a result, at the same time that industry uncertainty and
market volatility increased the importance of financial flexibility, S&P observed that
11 Standard & Poor s Corporation, 2002 Power Energy Credit Conference: Beyond the Crisis (Jun. 12,2002).12 Standard & Poor s Corporation, "S. Power Industry Experiences Precipitous Credit Decline in 2002;
Negative Slope Likely to Continue RatingsDirect (Jan. 15,2003).
13 Id.
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constrained access to capital markets and investor skepticism was contributing to the bleak
credit picture. 14
How has A vista been impacted by the turmoil in the electric power
industry?
The Company s financial integrity has been severely damaged by the turmoil
in the electric power industry. Like others, Avista was swept up in the maelstrom of the
western energy crisis. While a full description of the western power crisis and its effects is
8 .beyond the scope of this testimony, the chaotic market conditions were felt directly and with
full force. Because of Avista s dependence on hydroelectric generation, it has always been
exposed to the uncertainties associated with year-to-year fluctuations in water conditions.
Nevertheless, the degree of price volatility that participants in the western power markets
were forced to assume was unprecedented and variability in short-term market prices bore no
resemblance to fluctuations experienced in the past.
Increased wholesale prices and rate structures that did not capture full costs of
acquiring fuel and purchased power led to depressed earnings. As of December 31, 2001 , for
example, Avista had recorded a regulatory asset of $193 million related primarily to power
cost deferrals resulting from record low hydroelectric generation and higher purchased power
prices. IS Avista was forced to use cash flows from operations, various bank borrowings, and
short- and long-term debt to fund unrecovered energy supply costs. This led to a sharp
deterioration in Avista s financial condition, a severe liquidity crunch, and a dramatic increase
in credit risk. As a result, commercial banks were reticent to extend financing for ongoing
14 Standard & Poor s Corporation, "Credit Quality For U.S. Utilities Continues Negative Trend,RatingsDirect
(Jut. 24, 2003).
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operations or new construction, and the Company s power and natural gas suppliers were
unwilling to transact business absent special credit terms. To varying degrees, utilities
throughout the western U.S. were confronted with the difficult task of maintaining reliable
service and financial integrity in a power market characterized by short supply and
unprecedented price volatility. Municipal utilities in the Northwest were also forced to
approve or propose significant rate increases to recover rising fuel and purchased power
costS.
Even for electric utilities that have permanent fuel and purchased power adjustment
mechanisms in place, there can be a significant lag between the time the utility actually incurs
the expenditure and when it is recovered from ratepayers. One example of this regulatory lag
was noted by The Value Line Investment Survey (Value Line):
A lag in the recovery of sharply higher power costs is hurting Sierra
Pacific Resources. Power prices in the West have soared since the second
quarter of 2000, and until recently, SPR's two utilities lacked a mechanism for
recovering these increases. The Nevada Commission has granted one, but it
won t solve the utilities' problem right away. That's because the mechanism
tracks power costs over a trailing 12-month period and because the amount by
which the utilities can raise rates each month is capped.
Because of record low stream flows available to Avista s hydroelectric facilities in 2001 and
the resulting dependence on wholesale power markets in the west, the chaotic market
conditions were felt directly.
The continuing prospect of further turmoil in western power markets cannot be
discounted.Investors recognIze that volatile markets, unpredictable stream flows, and
15 Avista Corp., Form 10-K Report (2001).
16
Standard Poor s Corporation, Public Power Companies in Northwest Increase Rates Due to Low Water
Skyrocketing Prices , Infrastructure Finance, p. 1 (January 18,2001).
17 The Value Line Investment Survey, p. 1758 (November 17, 2000).
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384
Avista s reliance on wholesale purchases to meet a portion of its resource needs can create a
perfect storm," exposing the Company to the risk of reduced cash flows and unrecovered
power supply costs.In response, Avista s Integrated Resource Plan contemplates an
expansion of the electric utility system, including the construction of additional generating
resources, to insulate customers and the Company from the risks inherent in substantial
reliance on wholesale power markets. Accordingly, strengthening Avista s financial integrity
and flexibility will be instrumental in the Company s ability to attract the capital necessary to
implement this plan in an effective manner. From the standpoint of the capital markets, the
west is risky - and Avista s weakened financial profile and continued exposure to wholesale
electric and natural gas markets in meeting shortfalls in hydroelectric generation and other
variations in resources and loads compound these uncertainties.
What are the implications of the power outages experienced in the upper
Midwest and Northeast during August 2003?
These events underscore the continuing risks inherent in the industry and the
uncertain state of affairs with respect to the industry s structure. The massive blackout,
which stretched from New York to Detroit and from Ohio into Canada, was the largest power
outage in U.S. history. This single event has sharpened the focus of industry stakeholders -
utilities, consumers, regulators, and investors - on the need to improve the nation s electricity
infrastructure, especially in light of the additional stress that deregulated wholesale markets
have placed on the network. The importance of rapidly stimulating investment in electric
power infrastructure has been almost universally cited as the key to ensuring that further
outages are avoided. As FERC Chairman Wood noted:
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If we draw any conclusions from this blackout, it is the urgent need for more
investment in the nation s transmission grid to serve broad regional needs.
Indeed, Avista has committed to expand the scope and reliability of its utility system in order
to provide customers with the benefits of wholesale competition, while attempting to insulate
them from the potential impact of power market anomalies.
Are investors likely to consider the impact of industry uncertainty
assessing their required rate of return for Avista?
Absolutely. While electric utility restructuring has not been actively pursued
in Idaho, Avista continues to face the prospect of FERC driven changes in the transmission
function of their business, as well as more fundamental reforms in how utilities operate to
optimize their assets for the benefit of retail ratepayers.I9 As noted earlier, Avista is an active
participant in the formation of the proposed RTO West, an independent entity that would
operate the transmission grid in seven western states.
Policy evolution in the transmission area has been wide-reaching. Investors' focus on
regulatory change in their assessment of risks and prospects was exemplified by S&P:
The FERC is in the process of changing every aspect of the electric utility
landscape, with industry sages anticipating further transmission and wholesale
market development guidance, which could affect the segment'credit
prospects and quality. .. Significant uncertainty still exists for transmission
companies that may operate under an RTO or ISO structure, which will
significantly impact the full scope of capital expenditures necessary to ensure
18 Statement of Pat Wood, III, Chairman, Federal Energy Regulatory Commission, On the Power Failure in the
S. and Canada, Press Release (Aug. 15, 2003).
19 See, , Remedying Undue Discrimination through Open Access Transmission Service and Standard
Electricity Market Design, 67 Fed. Reg. 55,451, FERC Stats. & Regs. en 32,563 (2002) ("SMD NOPR") and
FERC White Paper, Wholesale Power Market Platform April 28,2003, available at
http://www.fere.govlEleetrieIRTOlMrkt-Stret-eommentslWhi te _paper. pdf.
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reliability and increase capacity in the future. Uncertainty will exist until
operating rules are in place and have stabilized.
Virtually all industry stakeholders have recognized that regulatory uncertainties increase the
risks associated with the electric industry. Former FERC Commissioner Massey has noted
that regulatory uncertainty is "part of the problem" explaining under-investment in electric
utility infrastructure.21 The Department of Energy ("DOE") identified "reducing regulatory
uncertainty" as critical in stimulating increased investment in the power industry and has
noted that lack of clarity in the regulatory structure was inhibiting planning and investment.
The DOE also recognized the impact that this regulatory uncertainty has on investors
required rates of return for electric utilities:
Because transmission assets are long lived, regulatory uncertainty increases
the risks to investors and, therefore, increases the returns they need to justify
transmission system investments.
In remarks before NARUC, a representative of MBIA Insurance Corporation, the world'
largest financial guaranty insurance company, noted the increased risks posed by inconsistent
regulatory decision-making "have made access to the capital markets very difficult and very
expensive.24 Similarly, while the Consumer Energy Council of America recognized that
improvements in electric utility infrastructure are necessary to ensure reliability and support
20 Standard & Poor s Corporation, "Electric Transmission at the Starting Gate RatingsDirect (May 10,2002).21 Massey, William L, "Restoring Confidence in Energy Markets , Remarks at the 9th Annual Spring
Conference for the New England Energy Industry (May 21,2002).22 U.
S. Department of Energy, National Transmission Grid Study (May 2002), at 24 and 31.
23 Id. at 31.
24 Draft Remarks of Kara M. Silva, Vice President, MBIA Insurance Corporation, NARUC Joint Committee on
Electricity, Gas, and Finance and Technology (Feb. 26,2003).
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the economy, they concluded that regulatory uncertainty "has contributed to a fear of
instability for the entire system . 25
The recent blackout has only served to reinforce the importance of regulatory risks for
investors. The Wall Street Journal cited the debilitating impact of an "unsteady regulatory
environment" and the "chaotic combination of regulated and deregulated markets
explaining inhibitions to increased investment in the electric utility system.26 Similarly,
FERC Chairman Wood concluded in his initial comments on the power outages that:
Clearly, we need regulatory certainty and other incentives for investment.
Nevertheless, S&P recently warned investors that the partial reforms presently characterizing
wholesale power markets invites dysfunction and that elevated risks will discourage new
capital
, "
or at least make it more expensive.28 S&P observed:
Investors should not expect that such risk will dissipate any time soon.
Instead, credit risk could actually intensify if the politically charged debate
over refonn continues for years, as it might very well do. And even if policy
makers succeed in crafting a comprehensive solution to the problems of the
nation s energy grid, the regulatory treatment of the costs needed to upgrade
the infrastructure remains uncertain.
Because of potential exposure to wholesale markets, the risks of transmission uncertainties
and potential market volatility are intensified for utilities that depend heavily on purchased
power. Thus, Avista s dependence on purchased power to meet shortfalls in hydroelectric
generation magnifies the importance of maintaining the financial flexibility necessary to fund
25 Consumer Energy Council of America, "Positioning the Consumer for the Future: A Roadmap to an Optimal
Electric Power System" (Apr. 2003) at XVII.
26 Smith, Rebecca, "Overloaded Circuits Blackout Signals Major Weakness in U.S. Power Grid," The Wall
Street Journal (Aug. 18,2003).
27 Statement of Pat Wood, III, Chairman, Federal Energy Regulatory Commission, On the Power Failure in the
S. and Canada, Press Release (Aug. 15, 2003).
28 Standard & Poor s Corporation, "Electric Utility Blackouts Put Spotlight on Political and Regulatory Credit
Risk"RatingsDirect (Aug. 21, 2003).
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an adequate and reliable utility system. At the same time, it also exposes the Company and
its investors to the ongoing regulatory uncertainties and other risks imposed by federal
restructuring of wholesale power markets.
Are these uncertainties the only risks being faced by electric utilities?
No. Apart from these factors, the industry continues to face the normal risks
inherent in operating electric utility systems, including the potential adverse effects of
inflation, interest rate changes, growth, the general economy, and regulatory uncertainty and
lag. Electric utilities are confronting increased environmental pressures that leave them
exposed to uncertainties regarding emissions and potential contamination. S&P recognized
the potential financial challenges posed by such uncertainties:
Pension obligations, environmental liabilities, and serious legal problems
restrict flexibility, apart from the obligations' direct financial implications.
Capital Markets and Economy
What has been the pattern of interest rates over the last decade?
Average long-term public utility bond rates, the monthly average prime rate
and inflation as measured by the consumer price index since 1990 are plotted in the graph
below. After rising to approximately 10 percent in mid-1990, the average yield on long-term
public utility bonds generally fell as economic conditions weakened in the aftermath of the
1991 Gulf war, with rates dipping below 7 percent in late 1993. Yields subsequently rose
again in 1994, before beginning a general decline, with investors requiring approximately 6.4
percent from average public utility bonds in November 2003:
29 Id.
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QJ
.....
Inflation ",
.." . ...,. .. ~ .../'\.. ~ .. '" ,
01
Are investors likely to anticipate any substantial decline in interest rates
going forward?
No. Since early 2001, a great deal of attention has been focused on the actions
of the Federal Reserve as they have moved successively to lower short-term interest rates in
response to weakness in the United States economy. But while interest rates are cuITently at
relatively low levels, investors are unlikely to expect any further significant declines going
forward. The general expectation is that, as economic growth strengthens, interest rates will
begin to rise. For example, the Energy Information Administration ("EIA"), a statistical
agency of the DOE, routinely publishes a 25-year forecast for energy markets and the nation
economy. The most recent forecast, released December 16, 2003, anticipates that the double-
A public utility bond yield will increase from approximately 6.7 percent in 2004 to 7.49
percent over the next five years, with the average being 7.3 percent over the next 10 years.
Similarly, Globallnsight (formerly DRI/WEFA), a widely referenced forecasting service, calls
30 Standard & Poor s Corporation, Corporate Ratings Criteria at 29, available at
www.standardandpoors.comlratings.
31 Energy Information Administration, Annual Energy Outlook 2004, Table 20 (Dec. 16,2003).
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for double-A public utility bond yields to average 7.35 percent over the next ten years, with
yields ranging between 6.70 and 8.02 percent.
How has the market for common equity capital performed?
Between 1990 and early 2000 stock prices pushed steadily higher as the
longest bull market in United States history continued unabated. While the S&P 500 had
increased over four times in value by August 2000, mounting concerns regarding prospects
for future growth, particularly for firms in the high technology and telecommunications
sectors, pushed equity prices lower, in some cases precipitously. While common stock prices
have recovered strongly from recent lows, the market remains volatile, with share values
repeatedly changing in full percentage points during a single day s trading. The graph below
plots the performances of the Dow-Jones Industrial Average, the S&P 500, and the New York
Stock Exchange Utility Index since 1990 (the latter two indices were scaled for
comparability):
16,500
14,500
12,500
10,500
500
500
500
500
500
..,.
. NYSE Utility (x 1 0) ""
32 Globallnsight
, "
The U.S. Economy, The 25-Year Focus , Table 33 (Summer 2003).
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391
What is the outlook for the United States economy?
During the decade through the first quarter of 2001, the United States
economy enjoyed the longest peacetime expansion in history. Monetary and fiscal policies
resulted in modest inflation during this period, with unemployment rates falling to their
lowest levels since the 1960s. A revolution in information technology, rising productivity,
and vibrant international trade all contributed to strong economic growth. However, even
before the events of September 11, 2001, there were increasing signs that the economic
. expansion would not be sustainable. Concerns regarding the slowing pace of economic
activity were exemplified by the Federal Reserve s sequential lowering of interest rates. The
economic picture has brightened more recently, with gross domestic product surging 8.
percent in the third quarter of 2003. Manufacturing activity has rebounded and construction
spending has increased. Nevertheless, businesses have been reluctant to expand hiring and
uncertainties over the durability of the economy recovery continue to be magnified by the
aftermath of war in Iraq, which undermines consumer confidence and contributes to global
economic uncertainty. These factors cause the outlook to remain tenuous, with persistent
stock and bond price volatility providing tangible evidence of the uncertainties faced by the
United States economy.
How do these economic uncertainties affect electric utilities?
Uncertainties over the extent and durability of the economic recovery have
combined to heighten the risks faced by electric utilities. Stagnant economic growth would
undoubtedly mean flat electric sales, while the potential for higher inflation and interest rates
that would likely accompany an economic rebound would place additional pressure on the
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adequacy of existing service rates. While the economy may ultimately return to a path
steady growth and the volatility in the capital and energy markets may abate, the underlying
weaknesses now present cause considerable uncertainties to persist, which increase the risks
faced by the electric utility industry.
III.CAPIT AL MARKET ESTIMATES
What is the purpose of this section?
In this section, capital market estimates of the cost of equity are developed for
a benchmark group of electric utilities. First, I examine the concept of the cost of equity,
along with the risk-return tradeoff principle fundamental to capital markets. Next, DCF and
risk premium analyses are conducted to estimate the cost of equity for a reference group of
electric utilities.
Economic Standards
What role does the rate of return on common equity play in a utility
rates?
The return on common equity is the cost of inducing and retaining investment
in the utility s physical plant and assets. This investment is necessary to finance the asset
base needed to provide utility service.Competition for investor funds is intense and
investors are free to invest their funds wherever they choose. They will commit money to a
particular investment only if they expect it to produce a return commensurate with those from
other investments with comparable risks. Moreover, the return on common equity is integral
in achieving the sound regulatory objectives of rates that are sufficient to: 1) fairly
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compensate capital investment in the utility, 2) enable the utility to offer a return adequate to
attract new capital on reasonable terms, and 3) maintain the utility s financial integrity.
What fundamental economic principle underlies this cost of equity
concept?
Unlike debt capital, there is no contractually guaranteed return on common
equity capital since shareholders are the residual owners of the utility. Nonetheless, common
equity investors still require a return on their investment, with the cost of equity being the
minimum "rent" that must be paid for the use of their money. This cost of equity typically
serves as the starting point for determining a fair rate of return on common equity.
The cost of equity concept is predicated on the notion that investors are risk averse
and willingly bear additional risk only if compensated for doing so. In capital markets where
relatively risk-free assets are available (e.
g.,
S. Treasury securities) investors can be
induced to hold more risky assets only if they are offered a premium, or additional return,
above the rate of return on a risk-free asset. Since all assets - including debt and equity -
compete with each other for scarce investors' funds, more risky assets must yield a higher
expected rate of return than less risky assets in order for investors to be willing to hold them.
Given this risk-return tradeoff, the required rate of return (k) from an asset (i) can be
generally expressed as:
Ki = Rf + RPi
where:Rf = Risk-free rate of return; and
RPi = Risk premium required to hold risky asset i.
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Thus, the required rate of return for a particular asset at any point in time is a function of: 1)
the yield on risk-free assets, and 2) its relative risk, with investors demanding
correspondingly larger risk premiums for assets bearing greater risk.
Does the risk-return tradeoff principle actually operate in the capital
markets?
Yes. The risk-return tradeoff is readily observable in certain segments of the
capital markets where required rates of return can be directly inferred from market data and
generally accepted measures of risk exist. Bond yields, for example, reflect investors
expected rates of return, and bond ratings measure the risk of individual bond issues. The
observed yields on government securities, which are considered free of default risk, and
bonds of various rating categories demonstrate that the risk-return tradeoff does, in fact, exist
in the capital markets.
Does the risk-return tradeoff observed with fixed income securities
extend to common stocks and other assets?
It is generally accepted that the risk-return tradeoff evidenced with long-term
debt extends to all assets. Documenting the risk-return tradeoff for assets other than fixed
income securities is complicated by two factors, however. First, there is no standard measure
of risk applicable to all assets. Second, for most assets - including common stock - required
rates of return cannot be directly observed. Nevertheless, it is a fundamental tenet that
investors exhibit risk aversion in deciding whether or not to hold common stocks and other
assets, just as when choosing among fixed income securities. This has been supported and
demonstrated by considerable empirical research in the field of finance and is confirmed by
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reference to historical earned rates of return, with realized rates of return on common stocks
exceeding those on government and corporate bonds over the long-term.
Is this risk-return tradeoff limited to differences between firms?
No. The risk-return tradeoff principle applies not only to investments in
different firms, but also to different securities issued by the same firm. Debt, preferred stock
and common equity vary considerably in risk because they have different characteristics and
priorities.
When investors loan money to a utility in the form of long-term debt, they enter into a
contract under which the utility agrees to pay a specified amount of interest and to repay the
principal of the loan in full at the maturity date. The bondholders have a senior claim on a
utility s available cash flow for these payments, and if the utility fails to make them
bondholders may force it into bankruptcy and liquidation for settlement of unpaid claims.
Following first mortgage bonds are other debt instruments also holding contractual claims on
the utility s cash flow, such as debentures and notes. Similarly, when a utility sells investors
preferred stock, the utility promises to pay specified dividends and, typically, to retire the
preferred stock on a predetermined schedule.The rights of preferred stockholders to
available cash flow for these payments are junior to creditors, and preferred stockholders
cannot compel bankruptcy, their claims are senior to those of common shareholders.
The last investors in line are common shareholders. They receive only the cash flow
if any, that remains after all other claimants - employees, suppliers, governments, lenders,
have been paid. As a result, the rate of return that investors require from a utility s common
33 See e.g., IbbotsonAssociates, 2003 Yearbook.
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396
stock, the most junior and riskiest of its securities, is considerably higher than the yield on the
utility s long-term debt.
What does the above discussion imply with respect to estimating the cost
of equity?
Although the cost of equity cannot be observed directly, it is a function of the
prospective returns available from other investment alternatives and the risks to which the
equity capital is exposed. Because it is unobservable, the cost of equity for a particular utility
must be estimated by analyzing information about capital market conditions generally,
assessing the relative risks of the company specifically, and employing various quantitative
methods that focus on investors' current required rates of return. These various quantitative
methods typically attempt to infer investors' required rates of return from stock prices,
interest rates, or other capital market data.
Have you relied on a single method to estimate the cost of equity for
A vista ?
No. In my opinion, no single method or model should be relied upon to
determine a utility s cost of equity because no single approach can be regarded as wholly
reliable. As the Federal Communications Commission recognized:
Equity prices are established in highly volatile and uncertain capital markets...
Different forecasting methodologies compete with each other for eminence,
only to be superceded by other methodologies as conditions change... In these
circumstances, we should not restrict ourselves to one methodology, or even a
series of methodologies, that would be applied mechanically. Instead, we
conclude that we should adopt a more accommodating and flexible position.
34 Federal Communications Commission, Report and Order 42-43, CC Docket No. 92-133 (1995).
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Therefore, in addition to the DCF model , I applied the risk premium method based on data
for electric utilities and using forward-looking estimates of required rates of return. In
addition, I also evaluated my results using a comparable earnings approach based on
investors' current expectations in the capital markets. In my opinion, comparing estimates
produced by one method with those produced by other approaches ensures that the estimates
of the cost of equity pass fundamental tests of reasonableness and economic logic.
Discounted Cash Flow Analyses
How are DCF models used to estimate the cost of equity?
The use of DCF models is essentially an attempt to replicate the market
valuation process that sets the price investors are willing to pay for a share of a company
stock. The model rests on the assumption that investors evaluate the risks and expected rates
of return from all securities in the capital markets. Given these expected rates of return, the
price of each stock is adjusted by the market until investors are adequately compensated for
the risks they bear. Therefore, we can look to the market to determine what investors believe
a share of common stock is worth. By estimating the cash flows investors expect to receive
from the stock in the way of future dividends and capital gains, we can calculate their
required rate of return. In other words, the cash flows that investors expect from a stock are
estimated, and given its current market price, we can "back-into" the discount rate, or cost of
equity, that investors presumptively used in bidding the stock to that price.
What market valuation process underlies DCF models?
DCF models are derived from a theory of valuation which assumes that the
price of a share of common stock is equal to the present value of the expected cash flows
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(i., future dividends and stock price) that will be received while holding the stock,
discounted at investors' required rate of return, or the cost of equity. Notationally, the general
form of the DCF model is as follows:
P =
+...+
0 (1+k )1 (1+k )2 (1+k )t (1+k
where:= Current price per share;
= Expected future price per share in period t;
= Expected dividend per share in period t;
= Cost of equity.
That is, the cost of equity is the discount rate that will equate the current price of a share of
stock with the present value of all expected cash flows from the stock.
Has this general form of the DCF model customarily been used to
estimate the cost of equity in rate cases?
No. In an effort to reduce the number of required estimates and computational
difficulties, the general form of the DCF model has been simplified to a "constant growth"
form. But converting the general form of the DCF model to the constant growth DCF model
requires a number of strict assumptions. 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.
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Gi ven these assumptions, the general fonn of the DCF model can be reduced to the more
manageable fonnula of:
p -
0 - ke - 9
where:g = Investors' long-term growth expectations.
The cost of equity (ke) can be isolated by rearranging tenns:
k =-1.+
This constant growth form of the DCF model recognIzes that the rate of return to
stockholders consists of two parts: 1) dividend yield (Dt/Po), and 2) growth (g). In other
words, investors expect to receive a portion of their total return in the fonn of current
dividends and the remainder through price appreciation.
Are the assumptions underlying the constant growth form of the DCF
model always fully met?
In practice, none of the assumptions required to convert the general form of
the DCF model to the constant growth fonn are ever strictly met. Nevertheless, where
earnings are derived from stable activities, and earnings, dividends, and book value track
fairly closely, the constant growth form of the DCF model offers a reasonable working
approximation of stock valuation that provides useful insight as to investors ' required rate of
return.
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How did you implement the DCF model to estimate the cost of equity for
A vista?
Avista s recent financial challenges and weakened credit standing hinder the
application of the DCF model directly to the Company. As an alternative, the cost of equity is
often estimated by applying the DCF model to publicly traded firms engaged in the same
business activity.In order to reflect the risks and prospects associated with Avista
jurisdictional utility operations, my DCF analyses focused on a reference group of other
electric utilities composed of those companies included by Value Line in their Electric
Utilities (West) Industry group. Excluded from my analyses were five firms that do not pay
common dividends or recently cut their payout and two that were rated below investment
grade by S&P (including Avista). Given that these eight utilities are all engaged in electric
utility operations in the western region of the U.S., investors are likely to regard this group as
facing similar market conditions and having comparable risks and prospects. There are
important factors distinguishing western utilities from those located in other regions,
including customer density and the complexities associated with greater reliance on
hydroelectric generation. Indeed, as noted earlier, the ongoing uncertainties associated with
hydroelectric generation and western power markets are important considerations in
evaluating investors' required rate of return for Avista.
What other considerations support the use of a proxy group in estimating
the cost of equity for Avista?
Apart from recognizing the inherent risks and prospects for an electric utility
operating in the west, reference to a proxy group of electric utilities is essential to insulate
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against vagaries that can result when the stochastic process involved in estimating the cost of
equity is applied to a single company. The cost of equity is inherently unobservable and can
only be inferred indirectly by reference to available capital market data. To the extent that the
data used to apply the DCF model does not capture the expectations that investors have
incorporated into current stock prices, the resulting cost of equity estimates will be biased.
For example, the potential for mergers or acquisitions or the announced sale of a major
business segment would undoubtedly influence the price investors would be willing to pay
for a utility s common stock. But because such factors are not typically reflected in the
growth rates used to apply the DCF model, cost of equity estimates for any single company
may fail to reflect investors' required rate of return. Indeed, using even a limited group of
companies increases the potential for error, as the FERC noted in its July 3, 2003 Order on
Initial Decision in Docket No. RPOO-I07-000:
Both Staff and Williston agreed that a proxy group of only three companies
presented problems because "single company will have a magnified
influence on the group results.It was with those changing market dynamics
in mind that witnesses of both Staff and Williston proposed to expand the
group of proxy companies to determine a zone of reasonableness.
A proxy group composed of western electric utilities is consistent not only with the shared
circumstances of electric power markets in the west, but also with the need to ensure against
the potential that a single cost of equity estimate may not reflect investors' required rate of
return.
Regulatory and economic standards require that the allowed rate of return should
reflect what investors expect for a utility of comparable risk.As wi II be descri bed
35 Williston Basin Interstate Pipeline Co.104 FERC en 61,036, at 14-15 (luJ. 3,2003).
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subsequently, Avista s investment risks exceed those of the utilities in the benchmark group.
Accordingly, because investors require a higher rate of return to bear increased risk, this
implies that the Company s cost of equity exceeds that of the proxy group of western electric
utilities.
Why did you excluded from your benchmark group firms that do not pay
common dividends, cut their dividend payout, or have below investment grade bond
ratings?
As discussed earlier, under the DCF approach, observable stock prices are a
function of the cash flows that investors' expected to receive, discounted at their required rate
of return. Because dividend payments are a key parameter required to apply the DCF
method, this hinders application of the DCF model to firms that do not pay common
dividends or have recently cut their payout. Meanwhile, the financial stress and lack of
stability that accompanies below investment grade bond ratings greatly complicates any
determination of investors ' long-term expectations that form the basis for DCF applications
to estimate the cost of equity. It is not practicable to apply the DCF model directly to Avista.
What form of the DCF model did you use?
I applied the constant growth DCF model to estimate the cost of equity for
Avista, which is the form of the model most commonly relied on to establish the cost of
equity for traditional regulated utilities and the method most often referenced by regulators.
Other forms of the general, or non-constant DCF model, such as "two-stage" or
multi-stage" analyses can be used to estimate the cost of equity; however, such approaches
increase the number of inputs that must be estimated and add to the computational
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difficulties. While such methods might be warranted when investors expect a discontinuity
in the operations of a particular firm or industry, they generally require several very specific
assumptions regarding investors' expected cash flows that must occur at given points in the
future. This makes the results of non-constant growth DCF applications sensitive to changes
in assumptions and, therefore, subject to greater controversy in a rate case setting.
Moreover, to the extent that each of these time-specific suppositions about future cash
flows do not reflect what real-world investors actually anticipate, the resulting cost of equity
estimate will be biased. Indeed, the benchmark for growth in a DCF model is what investors
expect when they purchase stock. Unless we replicate investors' thinking, we cannot uncover
their required returns and thus the market cost of equity. In practice, applying a non-constant
DCF model would lead to error if it ignores the requirements of real-world investors.
Are there circumstances where a multi-stage DCF model might be
preferable to the constant growth form?
Yes.The greater complexity of the non-constant growth DCF model is
sometimes warranted when it is evident that investors anticipate a well-defined shift in
growth rates over the horizon of their expectations. For example, in response to structural
reforms introduced in the early 1990s, it was widely anticipated that certain segments of the
electric power industry would transition from fully regulated to competitive businesses.
Because of the difficulty associated with capturing these expectations in the single growth
measure of the constant growth DCF model, many witnesses, including myself, chose to
apply a multi-stage approach. A number of regulatory commissions also departed from the
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simplicity of the constant growth DCF model that they had traditionally favored in order to
recognize the transition to competition that was anticipated by investors.
But acceptance of the multi-stage DCF model was predicated on very specific
assumptions tailored to investors' actual expectations at the time. As discussed earlier,
however, investors are no longer anticipating that such a transition will take place going
forward. Broad-reaching structural changes once anticipated by investors at the state and
federal levels have been largely effectuated to the extent investors expect them to occur. In
the minds of investors, any new initiatives focused on deregulation of the electric utility
industry at the retail level have been indefinitely postponed or abandoned altogether. This is
certainly true in Idaho, where retail deregulation is not being actively pursued.
While the complexity of non-constant DCF models may impart an aura of accuracy,
there is no evidence that investors' current view of electric utilities anticipates a series of
discrete, clearly defined stages. As a result, despite the considerable uncertainties now
confronting the electric utility industry, there is no discernable transition that would support
use of the multi -stage DCF approach.
How is the constant growth form of the DCF model typically used to
estimate the cost of equity?
The first step in implementing the constant growth DCF model is to determine
the expected dividend yield (Dt/Po) for the firm in question. This is usually calculated based
on an estimate of dividends to be paid in the coming year divided by the current price of the
stock. The second, and more controversial, step is to estimate investors' long-term growth
expectations (g) for the firm. Since book value, dividends, earnings, and price are all
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assumed to move in lock-step in the constant growth DCF model, estimates of expected
growth are sometimes derived from historical rates of growth in these variables under the
presumption that investors expect these rates of growth to continue into the future.
Alternatively, a firm s internal growth can be estimated based on the product of its earnings
retention ratio and earned rate of return on equity. This growth estimate may rely on either
historical or projected data, or both. A third approach is to rely on security analysts
projections of growth as proxies for investors' expectations. The final step is to sum the
firm s dividend yield and estimated growth rate to arrive at an estimate of its cost of equity.
How was the dividend yield for the reference group of electric utilities
determined?
Estimates of dividends to be paid by each of these electric utilities over the
next twelve months, obtained from Value Line, served as DI. This annual dividend was then
divided by the corresponding stock price for each utility to arrive at the expected dividend
yield. The expected dividends, stock price, and resulting dividend yields for the firms in the
reference group of electric utilities are presented on Schedule WEA-l. As shown there,
dividend yields for the eight firms in the electric utility proxy group ranged from 2.9 percent
to 5.4 percent, with the average being 4.2 percent.
What are investors most likely to consider in developing their long-term
growth expectations?
In constant growth DCF theory, earnings, dividends, book value, and market
price are all assumed to grow in lockstep and the growth horizon of the DCF model is
infinite. But implementation of the DCF model is more than just a theoretical exercise; it is
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an attempt to replicate the mechanism investors used to arrive at observable stock prices.
Thus, the only "" that matters in applying the DCF model is that which investors expect and
have embodied in current market prices. While the uncertainties inherent with common stock
make estimating investors' growth expectations a difficult task for any company, in the case
of electric utilities, the problem is exacerbated due to the ongoing turmoil in the power
industry. Thus, apart from the fact that investors do not currently expect a clearly-defined
shift in growth rates for electric utilities, these unsettled conditions make the specific
forecasts required to implement the non-constant growth DCF model even more tenuous.
Are dividend growth rates likely to provide a meaningful guide
investors ' growth expectations for electric utilities?
No.Dividend policies for electric utilities have become increasingly
conservative as business risks in the industry have become more accentuated. Thus, while
dividends have remained largely stagnant as utilities conserve financial resources to provide a
hedge against heightened uncertainties, earnings may be expected to grow at a much swifter
pace. Investors' focus has increasingly shifted from dividends to earnings as a measure of
long-term growth, as payout ratios for firms in the electric utility industry have been trending
downward from approximately 80 percent historically to on the order of 60 percent. 36 As a
result, growth in earnings, which ultimately support future dividends and share prices, is
likely to provide a more meaningful guide to investors' long-term growth expectations.
36 See, e.g.The Value Line Investment Survey (Sep. 15, 1995 at 161, Sep. 5,2003 at 154).
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9 .
What other evidence suggests that investors are more apt to consider
trends in earnings in developing growth expectations?
The importance of earnings in evaluating investors' expectations and
requirements is well accepted in the investment community. As noted in Finding Reality in
Reported Earnings published by the Association for Investment Management and Research:
(E)arnings, presumably, are the basis for the investment benefits that we all
seek. "Healthy earnings equal healthy investment benefits" seems a logical
equation, but earnings are also a scorecard by which we compare companies, a
filter through which we assess management, and a crystal ball in which we try
to foretell the future.
Value Line s near-term projections and its Timeliness Rank, which is the principal investment
rating assigned to each individual stock, are also based primarily on various quantitative
analyses of earnings. As Value Line explained:
The future earnings rank accounts for 65% in the determination of relative
price change in the future; the other two variables (current earnings rank and
current price rank) explain 35%.38
The fact that investment advisory services, such as Value Line and IIBIEIS International, Inc.
. ("
IDES"), focus on growth in earnings indicates that the investment community regards this
as a superior indicator of future long-term growth. Indeed, Financial Analysts Journal
reported the results of a survey conducted to determine what analytical techniques investment
analysts actually use.39 Respondents were asked to rank the relative importance of earnings,
dividends, cash flow, and book value in analyzing securities. Of the 297 analysts that
responded, only 3 ranked dividends first while 276 ranked it last. The article concluded:
37 Association for Investment Management and Research, "Finding Reality in Reported Earnings: An
Overview , p. 1 (Dec. 4, 1996).
38
The Value Line Investment Survey, Subscriber s Guide, p. 53.
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Earnings and cash flow are considered far more important than book value and
di vidends.
What are security analysts currently projecting in the way of earnings
growth for the firms in the electric utility proxy group?
The consensus earnings growth projections for each of the firms in the
reference group of electric utilities reported by mES and published in S&P'Earnings Guide
are shown on Schedule WEA-2. Also presented are the earnings growth projections reported
by Value Line, First Call Corporation ("First Call"), and Multex Investor ("Multex ), which
is a service of Reuters. As shown there, with the exception of Value Line s estimates, these
security analysts' projections suggested growth the order of 5.1 to 5.4 percent for the
reference group of electric utilities:
Electric Utility Proxy Grout!,Service Growth Rate
IRES
Value Line 2.4%
First Call
Multex 5.4%
What other earnings growth rates might be relevant in assessing
investors' current expectations for electric utilities?
Short-term projected growth rates may be colored by current uncertainties
regarding the near-term direction of the economy in general and the spate of challenges faced
in the electric power industry specifically. Consider the example of Value Line, which
recently noted that the electric utility industry "is still in a state of flUX,,41 and that:
39 Block, Stanley B., "A Study of Financial Analysts: Practice and Theory Financial Analysts Journal
(July/August 1999).
40 Id. at 88.
41 The Value Line Investment Survey (July 4,2003) at 695.
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. . .
this industry still faces problems. The after-effects of the turbulence in the
power markets still exist, some companies are stressed financially, and even
for traditional utilities, regulatory risk is often a potential problem.
Value Line has also reduced its Timeliness ranking, a relative measure of year-ahead stock
price performance for the 98 industries it covers, for the electric utility industry from 70 to
87.43 While this cautious outlook may explain the fact that Value Line s near-term growth
estimates are out of line with other analysts ' projections, it is not necessarily indicative of
investors ' long-term expectations for the industry.
Given the unsettled conditions in the economy and electric utility industry over the
near-term, historical growth in earnings might also provide a meaningful guide to investors
future expectations. Accordingly, earnings growth rates for the past 10- and 5-year periods
reported by Value Line for the firms in the electric utility group are also presented on
Schedule WEA-2. As shown there, 10-year historical earnings growth rates for the group of
eight electric utilities averaged 7.3 percent, or 8.1 percent over the most recent 5 year period.
How else are investors' expectations of future long-term growth prospects
often estimated for use in the constant growth DCF model?
In constant growth theory, growth in book equity will be equal to the product
of the earnings retention ratio (one minus the dividend payout ratio) and the earned rate of
return on book equity. Furthermore, if the earned rate of return and payout ratio are constant
over time, growth in earnings and dividends will be equal to growth in book value. Although
these conditions are seldom, if ever, met in practice, this approach may provide investors
with a rough guide for evaluating a firm s growth prospects. Accordingly, conventional
42 The Value Line Investment Survey (Aug. 15,2003) at 1776.
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410
applications of the constant growth DCF model often examine the relationships between
retained earnings and earned rates of return as an indication of the growth investors might
expect from the reinvestment of earnings within a firm.
What growth rate does the earnings retention method suggest for the
reference group of electric utilities?
The sustainable, "b x r" growth rates for each firm in the reference group is
shown on Schedule WEA-3. For each firm, the expected retention ratio (b) was calculated
based on Value Line s projected dividends and earnings per share. Likewise, each firm
expected earned rate of return (r) was computed by dividing projected earnings per share by
projected net book value. As shown there, this method resulted in an average expected
growth rate for the group of electric utilities of 4.6 percent.
What did you conclude with respect to investors' growth expectations for
the reference group of electric utilities?
I concluded that investors currently expect growth on the order of 5.0 to 7.
percent for the average firm in the electric utility proxy group. This determination was based
on the growth projections discussed above, but giving little weight to Value Line
projections, which deviated significantly from the more broadly-based consensus growth rate
projections reported by IDES and Multex, as well as past experience.
43 The Value Line Investment Survey (Jan. 2,2004) at 695.
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What cost of equity was implied for the reference group of electric
utilities using the DCF model?
Combining the 4.percent average dividend yield with the 6.percent
midpoint of my representative growth rate range implied a DCF cost of equity for this group
of electric utilities of 10.2 percent.
Risk Premium Analyses
What other analyses did you conduct to estimate the cost of equity?
As I have mentioned previously, because the cost of equity is inherently
unobservable, no single method should be considered a solely reliable guide to investors
required rate of return. Accordingly, I also evaluated the cost of equity for Avista using risk
premium methods.My applications of the risk premium method provide alternative
approaches to measure equity risk premiums that focused specifically on data for electric
utilities and forward-looking estimates of investors' required rates of return.
Briefly describe the risk premium method.
The risk premium method of estimating investors' required rate of return
extends to common stocks the risk-return tradeoff observed with bonds. The cost of equity is
estimated by first determining the additional return investors require to forgo the relative
safety of bonds and to bear the greater risks associated with common stock, and then adding
this equity risk premium to the current yield on bonds. Like the DCF model, the risk
premium method is capital market oriented. However, unlike DCF models, which indirectly
impute the cost of equity, risk premium methods directly estimate investors' required rate of
return by adding an equity risk premium to observable bond yields.
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How did you implement the risk premium method?
The actual measurement of equity risk premiums is complicated by the
inherently unobservable nature of the cost of equity. In other words, like the cost of equity
itself and the growth component of the DCF model, equity risk premiums cannot be
calculated precisely. Therefore, equity risk premiums must be estimated, with adjustments
being required to reflect present capital market conditions and the relative risks of the groups
being evaluated.
I based my estimates of equity risk premiums for electric utilities on (1) surveys of
previously authorized rates of return on common equity for electric utilities, (2) realized rates
of return on electric utility common stocks; and (3) forward-looking applications of the
Capital Asset Pricing Model ("CAPM"). Authorized returns presumably reflect regulatory
commissions' best estimates of the cost of equity, however determined, at the time they
issued their final order, and the returns provide a logical basis for estimating equity risk
premiums. Under the realized-rate-of-return approach, equity risk premiums are calculated
by measuring the rate of return (including dividends, interest, and capital gains and losses)
actually realized on an investment in common stocks and bonds over historical periods. The
realized rate of return on bonds is then subtracted from the return earned on common stocks
to measure equity risk premiums. The CAPM approach measures the market-expected return
for a security as the sum of a risk-free rate and a risk premium based on the portion of a
security s risk that cannot be eliminated by holding a well-diversified portfolio. Under the
CAPM, risk is represented by the beta coefficient (3), which measures the volatility of a
security's price relative to the market at a whole. Even before the widely cited study by
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Eugene F. Fama and Kenneth R. French 44 considerable controversy surrounded the validity
of beta as a relevant measure of a utility s investment risk. Nevertheless, the CAPM is
routinely referenced in the financial literature and in regulatory proceedings.
While these methods are premised on different assumptions, each having their own
strengths and weaknesses, they are widely accepted approaches that have been routinely
referenced in estimating the cost of equity for regulated utilities.
How did you implement the risk premium approach using surveys of
allowed rates of return?
While the purest form of the survey approach would involve queryIng
investors directly, surveys of previously authorized rates of return on common equity are
frequently referenced as the basis for estimating equity risk premiums. The rates of return on
common equity authorized electric utilities by regulatory commissions across the u.s. are
compiled by Regulatory Research Associates ("RRA") and published in its Regulatory Focus
report. In Schedule WEA-4, the average yield on public utility bonds is subtracted from the
average allowed rate of return on common equity for electric utilities to calculate equity risk
premiums for each year between 1974 and 2002. Over this 29-year period, these equity risk
premiums for electric utilities averaged 3.08 percent, and the yield on public utility bonds
averaged 9.81 percent.
44 Fama, Eugene F. and French, Kenneth R., "The Cross-Section of Expected Stock Returns The Journal of
Finance (June 1992).
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Is there any risk premium behavior that needs to be considered when
implementing the risk premium method?
Yes.There is considerable evidence that the magnitude of equity risk
premiums is not constant and that equity risk premiums tend to move inversely with interest
rates. In other words, when interest rate levels are relatively high, equity risk premiums
narrow, and when interest rates are relatively low, equity risk premiums widen. To illustrate,
the graph below plots the yields on public utility bonds (solid line) and equity risk premiums
(shaded line) shown on Schedule WEA-4:
15%
10%
00 0 00 0 00 00 00 00 00 ~
Bond Yield q%wmxec"k""'Equity Risk Premium I
The graph clearly illustrates that the higher the level of interest rates, the lower the equity risk
premium, and vice versa. The implication of this inverse relationship is that the cost of
equity does not move as much as, or in lockstep with, interest rates. Accordingly, for a
percent increase or decrease in interest rates, the cost of equity may only rise or fall, say, 50
basis points. Therefore, when implementing the risk premium method, adjustments may be
required to incorporate this inverse relationship if current interest rate levels have changed
since the equity risk premiums were estimated.
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415
What cost of equity is implied by surveys of allowed rates of return on
equity?
As illustrated above, the inverse relationship between interest rates and equity
risk premiums is evident. Based on the regression output between the interest rates and
equity risk premiums displayed at the bottom of Schedule WEA-, the equity risk premium
for electric utilities increased approximately 43 basis points for each percentage point drop in
the yield on average public utility bonds. As illustrated there, with the yield on public utility
bonds in December 2003 being 345 basis points lower than the average for the study period,
this implied a current equity risk premium of 4.58 percent for electric utilities. Adding this
equity risk premium to the December 2003 yield on triple-B public utility bonds of 6.
percent produces a current cost of equity for the utilities in the benchmark group of
approximately 11.2 percent.
How did you apply the realized-rate-of-return approach?
Widely used in academia, the realized-rate-of-return approach is based on the
assumption that, given sufficiently large number of observations over long historical
periods, average realized market rates of return will converge to investors' required rates of
return. From a more practical perspective, investors may base their expectations for the
future on, or may have come to expect that they will earn, rates of return corresponding to
those realized in the past.45 By focusing on data for electric utilities specifically, my realized
rate of return approach avoided the need to make assumptions regarding relative risk (e.
g.,
beta) that are often embodied in applications of this method.
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Stock price and dividend data for the electric utilities included in the S&P 500
Composite Index ("S&P 500") are available since 1946. Schedule WEA-5 presents annual
realized rates of return for these electric utilities in each year between 1946 and 2002. As
shown there, over this 57-year period realized rates of return for these utilities have exceeded
those on single-A public utility bonds by an average of 4.01 percent. The realized-rate-of-
return method ignores the inverse relationship between equity risk premiums and interest
rates and assumes that equity risk premiums are stationary over time; therefore, no
adjustment for differences between historical and current interest rate levels was made.
Adding this 4.01-percent equity risk premium to the November 2003 yield of 6.61 percent on
triple-B public utility bonds produces a current cost of equity for the electric utility proxy
group of approximately 10.6 percent.
Please describe your application of the CAPM.
The CAPM is a theory of market equilibrium that measures risk using the beta
coefficient. Under the CAPM, investors are assumed to be fully diversified, so the relevant
risk of an individual asset (e.
g.,
common stock) is its volatility relative to the market as a
whole. Beta reflects the tendency of a stocks price to follow changes in the market. A stock
that tends to respond less to market movements has a beta less than 1.00, while stocks that
tend to move more than the market have betas greater than 1.00.The CAPM is
mathematically expressed as:
45 Indeed, average realized rates of return for historical periods are widely reported to investors in the financial
press and by investment advisory services as a guide to future performance.
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41 7
Rj = Rr +3lRm - Rr)
Rj = required rate of return for stockj;
Rr = risk-free rate;
Rm = expected return on the market portfolio; and,
3j = beta, or systematic risk, for stockj.
Where:
Schedule WEA-6 presents an application of the CAPM to the eight companies in the
electric utility proxy group based on a forward-looking estimate for investors' required rates
of return from common stocks. Rather than using historical data, the expected market rate of
return was estimated by conducting a DCF analysis on the firms in the S&P 500. The
dividend yield was obtained from S&P, with the growth rate equal to the average of the
composite earnings growth projections published by ffiES for each firm. As shown there
subtracting a 5.2 percent risk-free rate based on the December 2003 average yield on long-
term government bonds from the 13.7 percent forward-looking rate of return produced a
market equity risk premium of 8.5 percent. Multiplying this risk premium by the average
Value Line beta of 0.77 for the firms in the electric utility group, and then adding the
resulting risk premium to the long-term Treasury bond yield, resulted in a current cost of
equity of approximately 11.7 percent.
Proxy Group Cost of Equity
What did you conclude with respect to the cost of equity for the
benchmark group of electric utilities?
The cost of equity estimates implied by my quantitative analyses are
summarized in the table below:
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Method
DCF
Risk Premium
Authorized Returns
Realized Rates of Return
CAPM
Cost of Eqylly Estimate
10.
11.2%
10.
11.7%
Consistent with the results of my quantitative analyses, I concluded that the cost of equity for
the proxy group is presently in the 10.2 to 11.7 percent range.
What other considerations are relevant in setting the return on equity for
a utility?
The common equity used to finance the investment in utility assets is provided
from either the sale of stock in the capital markets or from retained earnings not paid out as
dividends.When equity is raised through the sale of common stock, there are costs
associated with "floating" the new equity securities. These flotation costs include services
such as legal, accounting, and printing, as well as the fees and discounts paid to compensate
brokers for selling the stock to the public. Also, some argue that the "market pressure" from
the additional supply of common stock and other market factors may further reduce the
amount of funds a utility nets when it issues common equity.
Is there an established mechanism for a utility to recognize equity
issuance costs?
No. While debt flotation costs are recorded on the books of the utility,
amortized over the life of the issue, and thus increase the effective cost of debt capital, there
is no similar accounting treatment to ensure that equity flotation costs are recorded and
ultimately recognized.Alternatively, no rate of return is authorized on flotation costs
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necessarily incurred to obtain a portion of the equity capital used to finance plant. In other
words, equity flotation costs are not included in a utility s rate base because neither that portion
of the gross proceeds from the sale of common stock used to pay flotation costs is available to
invest in plant and equipment, nor are flotation costs capitalized as an intangible asset. Unless
some provision is made to recognize these issuance costs, a utility s revenue requirements will
not fully reflect all of the costs incurred for the use of investors' funds. Because there is no
accounting convention to accumulate the flotation costs associated with equity issues, they must
be accounted for indirectly, with an upward adjustment to the cost of equity being the most
logical mechanism.
What is the magnitude of the adjustment to the "bare bones" cost of
equity to account for issuance costs?
There are any number of ways in which a flotation cost adjustment can be
calculated, and the adjustment can range from just a few basis points to more than a full
percent. One of the most common methods used to account for flotation costs in regulatory
proceedings is to apply an average flotation-cost percentage to a utility s dividend yield.
Based on a review of the finance literature, Roger A. Morin concluded:
The flotation cost allowance requires an estimated adjustment to the return on
equity of approximately 5% to 10%, depending on the size and risk of the
Issue.
Applying these expense percentages to a representative dividend yield for an electric utility of
2 percent implies a flotation cost adjustment on the order of 20 to 40 basis points.
46 Roger A. Morin, Regulatory Finance: Utilities ' Cost of Capital, 1994, at 166.
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What then is your conclusion regarding a fair rate of return on equity for
the companies in your benchmark group?
After incorporating a minimum adjustment for flotation costs of 20 basis
points to my "bare bones" cost of equity range, I concluded that a fair rate of return on equity
for the proxy group of electric utilities is currently in the 10.4 to 11.9 percent range.
RETURN ON EQUITY FOR A VISTA CORP.IV.
What is the purpose of this section?
This section addresses the economic requirements for Avista s return on
equity. It examines other factors properly considered in determining a fair rate of return, such
as market perceptions of Avista s relative investment risks and comparable earnings for
utilities and industrial firms. This section also discusses the relationship between ROE and
preservation of a utility s financial integrity and the ability to attract capital.
Capital structure
Is an evaluation of the capital structure maintained by a utility relevant
in assessing its return on equity?
Yes. Other things equal, a higher debt ratio, or lower common equity ratio,
translates into increased financial risk for all investors. A greater amount of debt means more
investors have a senior claim on available cash flow, thereby reducing the certainty that each
will receive his contractual payments. This increases the risks to which lenders are exposed,
and they require correspondingly higher rates of interest. From common shareholders
standpoint, a higher debt ratio means that there are proportionately more investors ahead of
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them, thereby increasing the uncertainty as to the amount of cash flow, if any, that will
remaIn.
What common equity ratio is implicit in A vista's requested capital
structure?
Avista s capital structure is presented in the testimony of Mr. Malquist. As
summarized in his testimony, the common equity ratio used to compute Avista s overall rate
of return was 44.3 percent in this filing.
How does A vista's common equity ratio compare with those maintained
by the reference group of utilities?
As shown on Schedule WEA- 7, for the eight firms in the Electric Utility
(West) group, common equity ratios at September 30, 2003 ranged from 34.6 percent to 58.
percent and averaged 44.7 percent.
What implication does the increasing risk of the electric power industry
have for the capital structures maintained by utilities?
The challenges imposed by the evolving structural changes in the industry
imply that utilities will be required to incorporate relatively greater amounts of equity in their
capital structures. Moody s noted early on that utilities must adopt a more conservative
financial posture if credit ratings are to be maintained:
The key issue " says the analysts in a recent special comment, "is that the
competitive industries have much lower operating and financial leverage and
47 Puget Energy subsequently announced a sale of common stock, with the net proceeds expected to total
approximately $100 million. Other things equal, considering this stock sale would result in an average equity
ratio for the benchmark group of 45 percent, with only one company (Pinnacle West Capital) having a common
equity ratio below 40 percent.
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that utilities must streamline both in order to be effective competitors.
Analysts say the utilities must do this in order to post stronger financial
indicators and maintain their current ratings leve1.48
As shown on Schedule WEA-7, Value Line expects that the average common equity ratio for
the proxy group of eight western electric utilities will increase to 52.7 percent over the next
three to five years.
The continued decline in credit quality in the electric industry is indicative of the need
for utilities to strengthen financial profiles to deal with an increasingly uncertain and
competitive market. S&P cited the inadequacy of current balance sheets in the electric
industry as one of the key factors explaining this deterioration:
The downward slope in the power industry s credit picture can be traced to
higher debt leverage and overall deterioration in financial profiles, constrained
access to capital markets as a result of investor skepticism over accounting
practices and disclosure, liquidity problems financial insolvency, and
investments outside the traditional regulated utility business, principally
merchant generation facilities and related energy marketing and trading
activities.
more conservative financial profile is consistent with the increasing uncertainties
associated with restructuring and the imperative of maintaining continuous access to capital
even during times of adverse capital market conditions.
How does A vista's capital structure compare with other widely cited
financial benchmarks for electric utilities?
The financial ratio guidelines published by S&P specify a range for a utility
total debt ratio that corresponds to each specific bond rating. Widely cited in the investment
48 Moody
s Investors Service, Credit Risk Commentary, p. 3 (July 29, 1996).
49 Standard & Poor s Corporation, Credit Quality For U.S. Utilities Continues Negative Trend, RatingsDirect,
Jut. 24, 2003.
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423
community, these ratios are viewed in conjunction with a utility business profile ranking,
which ranges from 1 (strong) to 10 (weak) depending on a utility s relative business risks.
Thus, S&P's guideline financial ratios for a given rating category (e.g., triple-B) vary with the
business or operating risk of the utility. In other words, a firm with a business profile of "
(i.e., relatively lower business risk) could presumably employ more financial leverage than a
utility with a business profile assessment of "9" while maintaining the same credit rating.
S&P has assigned A vista a business profile ranking of "
S&P's current capital structure guideline ratios are attached as Schedule WEA-
These capitalization benchmarks are presented in the form of total debt ratios, with the
remainder of capital structure being composed of equity. Consistent with S&P's current
ratings criteria and Avista s S&P business profile ranking of ", as shown on Schedule
WEA-8, a utility would be required to maintain a ratio of total debt to total capital on the
order of 51.0 percent to qualify for a triple-B bond rating. This benchmark equates to a total
equity ratio of 49.0 percent to qualify for a rating at the very bottom of the investment grade
scale.
How do the rating agencies view preferred trust securities and preferred
stock in their assessment of a company s capital structure?
The rating agencies recognize the specific structure of preferred trust securities
and preferred stock in evaluating financial leverage. Depending on the degree of permanence
and other attributes, preferred securities may be considered more "debt-like" and only a
50 Standard & Poor s Corporation, Utilities Perspectives (Dec. 22,2003)
51 Standard & Poor s, Corporate Ratings Criteria 2004 (Nov. 13.2003) at 54, available at
www.standaredandpoors.comlratings.
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portion of the outstanding balance will receive equity treatment in assessing the company
capitalization. As a result, a portion of the preferred trust securities and preferred stock that
Avista has in its capital structure may be treated more as debt than equity in evaluating the
Company s financial risk.
What conclusions can you draw from Avista's proposed capital structure
as to how the rating agencies would view it?
While the rating agencies consider a plethora of factors besides a company
capital structure when determining a credit rating, financial leverage is an important
component of the rating analysis. Considering that only a portion of Avista s preferred trust
securities and preferred stock is likely to receive equity treatment, the total equity ratio
implied by Avista s proposed capital structure would barely meet the targets that S&P expects
for a "BBB" -rated utility.
What other indications confirm the reasonableness of A vista's requested
capital structure?
In the wake of recent turmoil in the electric power industry, bond rating
agencies and investors are continuing to scrutinize debt levels. For those firms with higher
leverage, this intense focus can lead not only to ratings downgrades, but to reduced access to
capital and increased borrowing costs. The Wall Street Journal reported that even firms with
stock prices at recent lows may be forced to issue new common equity in adverse markets
and quoted a credit analyst with Fitch, Inc.
(B)anks are fearful to put more money into the sector" and it is making credit
analysts nervous as well. The smart companies, he says, are the ones that
voluntarily "get their balance sheets in line" and the "let the market know
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they re in charge of their destiny... since the market clearly has the heebie-
jeebies. ,,52
The article went on to note the crucial role that financial flexibility plays in ensuring that the
utility has the wherewithal to meet the needs of customers, especially during times of stress:
All the belt tightening spells bad news for the continued development of the
nation s energy infrastructure. Companies that can borrow more money and
stretch their dollars, quite simply, can build more plants and equipment.
Companies that are increasingly dependent on equity financing - particularly
in a bear market - can do less. 53
What did you conclude with respect to A vista's requested capitalization?
Avista s proposed capital structure is in-line with industry standards, although
its requested equity ratio of 44.3 percent falls slightly below the 44.7 -percent average for the
electric utility benchmark group.Similarly, the total equity ratio implied by Avista
requested capital structure equity ratio would barely meet S&P's published benchmarks for
the lowest investment grade credit rating. The reasonableness of Avista s requested capital
structure is reinforced by the ongoing uncertainties associated with the electric power
industry, the need to support Avista s efforts to strengthen its credit standing, and the
imperative of maintaining continuous access to capital, even during times of adverse industry
and market conditions.
52 Smith, Rebecca, "Rating Agencies Crack Down on Utilities , The Wall Street Journal, p. Cl (December 19,
2001).
53 Id.
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Relative Risks
How does Avista's credit rating compare to those of the reference groups?
The average corporate credit rating for the Electric Utility (West) group used
to estimate the cost of equity is "BBB". As noted earlier, Avista s corporate rating is currently
BB+
" .
What does A vista's credit rating imply with respect to the rate of return
required by investors?
The cost of equity estimates developed earlier for the benchmark group of
electric utilities are predicated on the investment risks associated with the utilities in the
proxy group, which have corporate credit ratings of triple-B or higher. Meanwhile, Avista
below investment grade rating is indicative of an entirely different risk class. Because
investors require a higher rate of return to compensate them for bearing more risk, the greater
investment risk implied by Avista credit ratings suggests that the cost of equity is
correspondingly higher than for the proxy groups.
What is the significance of "investment grade" versus "below investment
grade
The term "investment grade" refers to a security having sufficient quality, or
relatively low risk, to be suitable for certain investment purposes.In discussing this
distinction, S&P noted that:
The term "investment grade" was originally used by various regulatory bodies
to connote obligations eligible for investment by institutions such as banks,
insurance companies, and savings and loan associations. Over time, this term
gained widespread usage throughout the investment community. Issues rated
in the four highest categories, 'AAA'
, '
AA'
, ', '
BBB', are recognized
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10.
being investment grade. Debt rated 'BB' or below generally is referred to as
speculative grade. The term "junk bond" is merely a more irreverent
expression for this category of more risky debt.
There is a precipitous increase in risk associated with moving from investment grade
to below investment grade securities. S&P documented this in its description of the risks
associated with triple-B rated bonds and below investment grade instruments:
An obligation rated 'BBB' exhibits adequate protection parameters. However,
adverse economic conditions or changing circumstances are more likely
lead to a weakened capacity of the obligor to meet its financial commitment
on the obligation. Obligations rated 'BB'
, ', '
CCC', and 'c' are regarded as
having significant speculative characteristics. 'BB' indicates the least degree
of speculation and 'c' the highest. While such obligations will likely have
some quality and protective characteristics, these may be outweighed by large
uncertainties or major exposures to adverse conditions.
A study conducted by Moody s indicated that default rates on double-B rated bonds exceeded
those for triple-B rated debt by a factor of 5.82 times over the period 1970 through 2002.
Thus, bond ratings differences within the investment grade range tend to reflect relatively
modest gradations among fairly secure investments.Meanwhile, moving to below
investment grade implies an altogether different risk plateau - one where the firm is regarded
as a speculative investment.
Is there any direct capital market evidence regarding the amount of the
premium investors require from a firm that is rated double-B, such as Avista?
Although rates of return on equity for below investment grade firms cannot be
directly observed, the observed yields on long-term bonds provide direct evidence of the
additional return that investors require to bear the risks associated with speculative grade
54 Standard & Poor s, Corporate Ratings Criteria at 9, available at www.standaredandpoors.comlratings.
55 ld. at 8.
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credit ratings. While average yields on double-public utility bonds are not routinely
published, Moody s recently reported that the average yield on speculative-grade debt
securities exceeded prevailing yields on long-term government bonds by 387 basis points
during the period 1993 through 1997.Since that time, however, the number of
downgrading actions affecting below investment grade debt accelerated as the economy
weakened and uncertainties increased.As a result, the speculative-grade yield spread
widened sharply to an average of 666 basis points from year-end 1997 through the first
quarter of 2003,58 before narrowing to 403 basis points in December 2003. The table below
calculates the implied risk premium for speculative grade debt based on CUlTent long-term
government and industrial bond yields:
Speculati ve Grade Yield Spread
Dec. 2003 Long-term Govt. Bond Yield
1993-1997-
1997 1 st 0 2003 Dec. 2003
87%66%03%
15%15%15%
02%11.81%18%
04%04%04%
98 %77%14%
Less:
Dec. 2003 Average Industrial Bond Yield
Implied Risk Premium
Based on this evidence, the capital markets would require approximately 3.0 to 5.8 percent in
additional return in order to compensate for the greater risks associated with speculative
grade debt instruments. Investors would undoubtedly require a significantly greater premium
for bearing the higher risk associated with the more junior common stock of a utility with
Avista s below investment grade rating.
56 Moody s Investors Service, "Tracing the Origins of Investment Grade,Special Comment (Jan. 2004) at 6.57 Moody
s Investors Service, Credit Perspectives (JuJ. 14,2003) at 35.
1d.
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429
What does this evidence suggest with respect to Avista's cost of equity
relative to the proxy group of electric utilities?
Because of the additional investment risks associated with Avista s speculative
grade corporate ratings and the Company s weakened credit standing and financial flexibility,
investors' required rate of return on equity for Avista exceeds that of the benchmark group
electric utilities. Considering the evidence presented earlier, a rate of return on equity from
the uppermost end of my 10.4 to 11.9 percent range is justified to support Avista s continued
progress in improving its financial health and flexibility and, ultimately, an investment grade
credit rating. Denying investors the opportunity to earn a return that is commensurate with
Avista s investment risks would perpetuate the Company s anemic credit standing and
hamper its ability to attract capital on reasonable terms.
Implications for Financial Integrity
Why is it important to allow Avista an adequate rate of return on equity?
Given the social and economic importance of the electric utility industry, it is
essential to maintain reliable and economical service to all consumers. While Avista remains
committed to deliver reliable electric service, a utility s ability to fulfill its mandate can be
compromised if it lacks the necessary financial wherewithal.
What lessons can be learned from recent events in the energy industry?
Events in the western U.S. provide a dramatic illustration of the high costs that
all stakeholders must bear when a utility s financial integrity is compromised. California
failed regulatory structure and its impact throughout the west led to unprecedented volatility
in wholesale power costs. For many utilities, recovery of purchased energy costs that they
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were forced to buy to serve their customers was either prevented and/or postponed. As a
result, they were denied the opportunity to earn risk equivalent rates of return and access to
capital was cut off. Regional economies have been jolted and consumers have suffered the
results of higher cost power and reduced reliability. Moreover, while the impact of the
utilities' deteriorating financial condition was felt swiftly, stakeholders have discovered first
hand how difficult and complex it can be to remedy the situation after the fact.
Do you have any personal experience regarding the damage to customers
that can result when a utility s financial integrity deteriorates?
Yes. I was a staff member of the Public Utility Commission of Texas when
the financial condition of EI Paso Electric Company ("EPE") began to suffer in the late
1970s. I later observed first-hand the difficulties in reversing this slide as a consultant to
Asarco Mining, EPE's largest single customer. EPE's ultimate bankruptcy imposed enormous
costs on customers and absorbed an undue amount of the PUCT's resources, as well as those
of the Attorneys General and other state agencies. Now I am serving as a consultant to the
utility as it completes a long struggle to fully recover its financial health. There is no
question that customers and other stakeholders would have been far better off had EPE
avoided bankruptcy by maintaining the utility s financial resilience.
What danger does an inadequate rate of return pose to A vista?
Once lost, investor confidence is difficult to recover and the damage is not
easily reversible. Consider the example of bond ratings. To restore a company s rating to a
previous, higher level, rating agencies generally require the company to maintain its financial
indicators above the minimum levels required for the higher rating over a period of time.
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Given that Avista s corporate credit rating is already below investment grade, the perception
of a lack of regulatory support could lead to further downgrades or, at a minimum, prolong
Avista s efforts to achieve investment grade ratings. Moreover, the negative impact of
declining credit quality on a utility s capital costs and financial flexibility becomes more
pronounced as debt ratings move down the scale from investment to non-investment grade.
At the same time, Avista s long-term plans include significant plant investment to
ensure that the energy needs of its service tenitory are met and that customers and the
Company are insulated from exposure to the vagaries of competitive wholesale markets.
While providing the infrastructure necessary to meet the energy needs of customers is
certainly desirable, it imposes additional financial responsibilities on Avista. To meet these
challenges successfully and economically, it is crucial that Avista receive adequate support to
improve its credit standing.
Other Factors
What else should be considered in evaluating the relative risks of A vista?
Because close to one-half of Avista s total energy requirements are provided
by hydroelectric facilities, the Company is exposed to a level of uncertainty not faced by most
utilities, which are less dependent on hydro generation.While hydropower confers
advantages in terms of fuel cost savings and diversity, investors also associated hydro
facilities with risks that are not encountered with other sources of generation. Reduced
hydroelectric generation due to below-average water conditions forces Avista to rely more
heavily on purchased power or efficient thermal generating capacity to meet its resource
needs. As noted earlier, in the minds of investors, this dependence on wholesale markets
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entails significant risk, especially for a utility located in the west.The ongoing risks
associated with uncertainty in western power markets has been recognized by the
Commission, which voiced its concern "about the unknown water and market conditions that
lie ahead" and noted that "as we have learned over the past two years, there are no guarantees
about future stream flows or market prices.59 Similarly, S&P recently observed that:
Utilities in the Pacific Northwest continue to face a host of challenges. If the
western power crisis left a large number of them, investor-owned as well as
publicly-owned, in dire financial straits, weak economic conditions and the
uncertain hydro situation have hampered recovery prospects.
S&P went on to note the significant potential costs and risks imposed by uncertainty over
fish-conservation measures that might be required to meet federal law and continued
volatility in wholesale power markets, concluding that "managing hydro risk has assumed a
critical importance to credit quality.,,61
What other factors would investors likely consider in evaluating their
required rate of return for A vista?
Investors have clearly recognized that structural change and market evolution
in the electric power industry have led to a significant increase in the risks faced by industry
participants. For a firm caught between expanding wholesale competition in the industry and
the constraints of regulation, as are electric utilities, these risks are further magnified. As
S&P recognized:
Although the move to competition from regulation is obviously negative for
credit quality in general, the transition period can often be worse for
59 Idaho Power granted $256 million deferral, but bond plan denied, Idaho Public Utilities Commission (May
13, 2002).
60 Standard & Poor s Corporation, "Legal Developments Add to Utilities' Disquiet in U.S. Northwest,Utilities
Perspectives (July 21, 2003) at 2-
61 Id.
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bondholders than would be a fully competitive industry. In the interim,
companies can be saddled with many of the disadvantages of being regulated
(e.limits on return on capital and higher costs to comply with regulatory
mandates) while simultaneously being gradually exposed to marketplace
risks.
Similarly, the Wall Street Journal highlighted the risks that investors associate with the
interface between competition and regulation in the power industry:
Now, with the power industry hovering uneasily between regulation and
deregulation, it faces the prospect of a market that combines the worst features
of both: a return to government restrictions, mixed with volatility and price
spikes as companies struggle to meet the nation s energy needs.
Moreover investors recognize that regulation has its own risks.In some
circumstances regulatory uncertainty can eclipse all of the other risk factors facing particular
utilities. Considering the magnitude of the events that have transpired since the third quarter
of 2000, investors sensitivity to market and regulatory uncertainties has increased
dramatically. The sharpened focus on the risks associated with unrecoverable wholesale
power costs, for example, was noted by RRA:
The potential for volatility in wholesale power electricity markets, as
highlighted by the temporary price spikes experienced in the Midwest in June
1999 and, more recently, by the ongoing severe capacity shortage/pricing crisis
in California, has raised investors' level of awareness and concern with regard
to the ability of electric utilities to recover increased wholesale power costs
and fuel expenses from customers.
Investors' required rates of return for utilities are premised on the regulatory compact that
allows the utility an opportunity to recover reasonable and prudently incurred costs. By
sheltering utilities from exposure to extraordinary power cost volatility, ratepayers benefit
62 Standard & Poor s, CreditWeek, Nov. 1,2000, at 31.63
Rebecca Smith, Shock Waves, The Wall Street Journal, Nov. 30,2001, at AI.
64 Regulatory Research Associates, "Recovery of Wholesale Power Costs: Who is at Risk and Who is Not?"
Regulatory Focus, p. 1 (February 28, 2001).
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from lower capital costs than they would otherwise bear. Of course, the corollary implies
that, if investors believe that the utility might face continued exposure to potentially extreme
fluctuations in power supply costs while remaining obligated to provide service at regulated
rates, their required return would be considerably increased. As S&P noted, the August 14th
blackout is unlikely to ease investors' concerns:
Clearly, the blackout has highlighted the complexity of the system, the
diversity of its many stakeholders and the susceptibility of the industry to
political and regulatory risk.65
Conclusions
What is your conclusion regarding the 11.5 percent ROE requested by
A vista in this case?
Based on the capital market research presented earlier, I concluded that a fair
rate of return on equity for the proxy group of electric utilities was in the 10.4 to 11.9 percent
range. In evaluating the rate of return for Avista, it is important to consider investors
continued focus on the unsettled conditions in restructured wholesale power markets, the
Company s ongoing reliance on these markets to purchase a portion of its energy supply, as
well as other risks associated with the power industry, such as heightened exposure to
regulatory uncertainties. In addition, Avista s below-investment grade credit rating implies a
level of investment risk that exceeds that of the proxy group used to estimate the cost of
equity. This suggests that, at a minimum, Avista s required rate of return on equity falls at the
uppermost end of my 10.4 to 11.9 percent range for the firms in the benchmark group of
western electric utilities. Considering the economic requirements and risks discussed above,
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it is my conclusion that the 11.5 percent ROE represents a conservative estimate of investors
required rate of return for Avista in today s capital markets.
How does Avista's requested 11.5 percent return on equity compare with
other benchmarks that investors would consider?
Reference to rates of return available from alternative investments can also
provide a useful guideline in assessing the return necessary to assure confidence in the
financial integrity of a firm and its ability to attract capital. This comparable earnings
approach avoids the complexities and limitations of capital market methods and instead
focuses on the returns earned on book equity, which are readily available to investors.
Value Line s most recent projections indicate that its analysts expect average rates of
return on common equity for the electric utility industry over the next three to five years of
11.0 percent,66 with rates of return for gas distribution utilities expected to average 11.5
percent. 67 Meanwhile, the firms included in Value Line s Composite Index are expected to
earn 16.0 percent on book equity during the 2006-2008 time frame.68 Considering Avista
higher risk profile, these expected earned rates of return confirm the reasonableness of the
Company s request.
Avista s requested rate of return is further supported by the fact that investors are
likely to anticipate increases in utility bond yields going forward. Moreover, an 11.5 percent
rate of return on equity is reasonable at this critical juncture, given the importance of
65 Standard & Poor s Corporation, "Electric Utility Blackout Puts Spotlight on Political and Regulatory Credit
Risk,RatingsDirect (Aug. 21, 2003).66 The Value Line Investment Survey (Jan. 2,2003) at 695.
67 The Value Line Investment Survey (Dec. 19,2003) at 458.
68 The Value Line Investment Survey, Selection Opinion (July 18,2003) at 2857.
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supporting the financial capability of Avista as it prepares to develop and enhance utility
infrastructure. As the summer power failures amply demonstrated, the cost of providing
Avista an adequate return is small relative to the potential benefits that a strong utility can
have in providing reliable service. Considering investors' heightened awareness of the risks
associated with the electric power industry and the damage that results when a utility
financial flexibility is compromised, supportive regulation is perhaps more crucial now than
at any time in the past.
Does this conclude your pre-filed direct testimony?
Yes.
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INTRODUCTION
Please state your name and business address.
William E. Avera, 3907 Red River, Austin, Texas, 78751.
Are you the same William E. Avera that previously submitted direct
testimony in this case?
Yes, I am.
What is the purpose of your rebuttal?
The purpose of my testimony is to respond to the direct testimony of Ms. Terri
Carlock, submitted on behalf of the staff of the Idaho Public Utilities Commission ("IPUC"
In addition, I will also rebut the recommendations contained in the direct testimony of Dr.
Dennis E. Peseau and Mr. John S. Thornton, Jr., on behalf ofPotlach Corporation, concerning
the cost of equity for the jurisdictional utility operations of Avista Corporation. ("Avista
Please summarize the conclusions of your testimony.
With respect to the testimony of Ms. Carlock, I concluded that her
recommendations were biased downward because of her failure to consider the results of
other accepted methods of estimating the cost of equity. Additionally, Ms. Carlock'
assessment of relative risks focused exciusively on Avista s relatively low rates, while
ignoring the substantial uncertainties and higher investment risks that investors must bear to
provide the benefits of lower electricity costs to Avista s customers. Finally, her flotation cost
adjustment understates the costs necessary to raise the equity capital invested in Avista
jurisdictional utility operations in Idaho. At a minimum, considering the results of risk
premium approaches, investors' risk perceptions, and correcting Ms. Carlock's flotation
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adjustment would support a rate of return at the very top of the range of her results, or 11.3
percent.
Meanwhile, Dr. Peseau did not conduct any independent analyses of the cost of equity
to Avista. Instead, his recommendations were based entirely on flawed "updates" and
revisions" to my analyses, which should be rejected in their entirety. Similarly, Mr.
Thornton s recommended 8.5 percent cost of equity is woefully inadequate and, by any
reasonable benchmark, falls well short of investors ' required rate of return from an electric
utility, especially considering Avista s unique risks and weakened credit standing. Mr.
Thornton s recommendations do not "pass the financial end-result test fundamental to
regulation and would preclude Avista from restoring its financial integrity and attracting
capital on reasonable terms.
Would you please summarize the principal shortcomings in the testimony
of Ms. Carlock, Dr. Peseau, and Mr. Thornton that you address in rebuttal?
Yes. The major issues addressed in my rebuttal testimony are as follows:
Ms. Carlock
While the risks premium approach is widely recognized as a meaningful approach
to estimate the cost of equity, Ms. Carlock did not use this method;
. No methodology provides a foolproof guide to investors ' required rate of return
and it is important to consider alternative approaches and evaluate the results of
accepted methods;
The results of risk premium analyses are consistent with a rate of return at the top
of Ms. Carlock's discounted cash flow ("DCF") and comparable earnings ranges;
Ms. Carlock's recommendation does not fully reflect the investment risks
associated with A vista s weakened credit profile and exposure te market
uncertainties;
The pre-tax coverage ratio implied by Ms. Carlock's recommendation is only
marginally above the minimum benchmark for a triple-B bond rating;
Ms. Carlock's flotation cost adjustment is biased downward and she failed to
adjust the results of her comparable earnings approach to incorporate issuance
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439
costs.
Dr. Peseau
Dr. Peseau performed no independent analyses of the cost of equity;
His decision to "update" my DCF analysis by ignoring historical growth trends is
unsupported and contradicts the advise and conclusions of his own sources;
In contrast to Dr. Peseau s allegations, there are no inconsistencies in my risk
premium analyses and his use of single-A bond yields as a benchmark for Avista
investment risks understates investors' required return;
Dr. Peseau did not update my application of the capital asset pricing model
CAPM"); instead, he substituted a market risk premium that does not reflect
expectations in today s capital markets; and
Dr. Peseau ignored Avista s greater investment risks and the need to adjust the
cost of equity to account for flotation costs.
Mr. Thornton
The extreme downward bias of Mr. Thornton s recommended cost of equity is
illustrated when compared against the returns on equity authorized by regulators
including the IPUC;
Mr. Thornton s recommendations are divorced from the requirements of real-
world capital markets and the inputs to his analyses do not reflect the expectations
of investors;
Mr. Thornton s criticisms of my analyses lack any reasonable basis, as does his
rejection of arithmetic mean returns and long-term bond yields in applying the
CAPM;
Like Dr. Peseau, Mr. Thornton ignored Avista s greater investment risks and the
need to adjust the cost of equity to account for flotation costs; and
Correcting Mr. Thornton s flawed calculations results in a coverage ratio that falls
below the minimum guidelines for an investment grade rating and demonstrate
that his recommendations would not allow A vista the opportunity to maintain its
financial integrity.
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II.TERRI CARLOCK
First, does the capital structure proposed by Ms. Carlock provide a
reasonable basis on which to calculate an overall rate of return for Avista?
Yes. Ms. Carlock recommended a capital structure composed of 50.08 percent
long-term debt, 5.57 percent trust preferred securities, 1.76 percent preferred stock, and 42.
percent common equity based on Avista s actual capitalization at December 31 2003. As
discussed in my direct testimony, the average capitalization for the firms in my comparable
group was composed of 44.7 percent common equity. Meanwhile, revised financial guideline
ratios published by Standard & Poor s Corporation ("S&P") imply a total equity ratio in the
range of 42 to 52 percent for Avista to qualify for a triple-B rating. 1 Accordingly, I concluded
that the capital structure used by Ms. Carlock is in-line with industry standards.
How did Ms. Carlock arrive at her 10.4 percent cost of equity
recommendation for Avista?
Ms. Carlock estimated the cost of equity by applying the constant growth DCF
model directly to Avista. She concluded that the results of this single DCF application
indicated a cost of equity in the 8.8 to 11.3 percent range. Ms. Carlock also conducted a
comparable earnings analysis, which resulted in an indicated cost of equity in the 10.0 to 11.
percent range. Based on these two analyses, Ms. Carlock concluded that the cost of equity
was in the 9.5 to 10.9 percent range, selecting lOA percent as her point estimate and
recommendation for Avista.
I Standard & Poor s Corporation
, "
New Business Profile Scores Assigned for U.S. Utility and Power
Companies; Financial Guidelines Revised RatingsDirect (Jun. 2, 2004) at Table 1. For a utility with Avista'
business profile ranking of ", S&P reported a guideline total debt ratio ranging from 58 to 48 percent for a
triple-B rating, which equates to a total equity ratio of 42 to 52 percent.
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441
Did Ms. Carlock apply the risk premium approach to estimate the cost of
equity for Avista?A. No. While Ms. Carlock stated that "much of the theoretical approach" that
she used was consistent with my testimony, Ms. Carlock did not use the risk premium
method to estimate the cost of equity. The risk premium method is widely recognized as a
meaningful approach to estimate investors ' required rate of return. Unlike the comparable
earnings method, which depends on earned returns derived from accounting information, the
risk premium approach is based on capital market data indicative of investors' current
expectations. The IPUC has noted the importance of "evaluating all the methods" and "using
each as a check on the other when setting the allowed rate of return.,,2 This is especially the
case in light of the fact that Ms. Carlock's DCF range was based on the results of a single
company and her comparable earnings approach is not capital market oriented.
Why is the use of multiple methods so important when estimating the cost
of equity?
Investors ' expectations are unobservable , and there is no methodology that
provides a foolproof guide to their required rate of return. Each method provides another
facet of examining investor behavior, with different assumptions and premises. Investors do
not necessarily subscribe to anyone method, and no model can conclusively determine or
estimate the required return for an individual finn. If the cost of equity estimation is
restricted to certain methodologies, while the results of other approaches are ignored, it may
significantly bias the outcome. Rather, all relevant evidence should be weighed and
evaluated in order to minimize the potential for error. The importance of considering the
2 Idaho Public Utilities Commission, Order No. 29505 (May 25 2004) at 38.
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442
results of multiple methods has been widely noted in the financial literature, as evidenced in
this quote from two noted financial scholars:
In practical work, it is often best to use all three methods - CAPM, bond yield
plus risk premium, and DCF - and then apply judgement when the methods
produce different results. People experienced in estimating capital costs
recognize that both careful analysis and some very fine judgements are
required. It would be nice to pretend that these judgements are unnecessary
and to specify an easy, precise way of determining the exact cost of equity
capital. Unfortunately, this is not possible.
Q. Has the IPUC expressed reluctance to consider the results of the Capital
Asset Pricing Model ("CAPM") approach?
Yes. I am aware that the IPUC has continuing concerns over the measurement
and proper use of the beta value necessary to apply the CAPM and has not routinely focused
on the results of this method.4 Nevertheless, the CAPM is a rigorous conceptual framework
at the heart of modern financial theory and it is widely used and referenced in the investment
community. Of course, the CAPM is based on restrictive assumptions and does not describe
security returns perfectly and there are controversies surrounding the measurement of key
variables, such as beta. But then exactly the same could be said for the constant growth DCF
model, which assumes a single, static growth rate into perpetuity that has no observable
proxy in the capital markets.
What cost of equity is implied if the risk premium method is used to
check the results of Ms. Carlock's analyses?A. Application of alternative risk premium approaches based on 1) surveys of
previously authorized rates of return on common equity for electric utilities, 2) realized rates
3 Brigham, E.F. and Gapenski, LC.Financial Management: Theory and Practice 6th ed., Dryden Press (1991)
at 256, as referenced in "Regulatory Finance: Utilities' Cost of Capital" at 239-240.
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of return on electric utility common stocks, and 3) forward-looking applications of the
Capital Asset Pricing Model ("CAPM") were discussed in detail in my direct testimony (pp.
45-52). The results of these analyses, which are not adjusted to incorporate flotation costs
are summarized in the following table:
Risk Premium Method
Authorized Returns
Realized Rates of Return
CAPM
Cost of Eqyj!y Estima~
11.
10.
11. 7%
Taken together, applications of the risk premium approach to estimate the cost of equity for
an electric utility are consistent with ~ rate of return from the top of Ms. Carlock's DCF and
comparable earnings ranges.
What other risk premium evidence confirms that Ms. Carlock'
recommendation is well below investors' required rate of return for Avista?
While the IPUC has expressed concern regarding the assumptions and inputs
necessary to apply certain forms of the risk premium approach (i., beta) it need look no
farther than its recent decision in Case No. IPC-03-13 involving Idaho Power Company
Idaho Power ). In that case, the IPUC approved a cost of equity of 10.25 percent and a
component cost of long-term debt of5.769 percentS Thus, the IPUC's findings imply an
equity risk premium for single-A rated Idaho Power of approximately 4.48 percent. Adding
this equity risk premium to Ms. Carlock's recommended long-term cost of debt of 8.
percent suggests a cost of equity to Avista of 13.16 percent. Alternatively, combining the
48 percent risk premium from the IPUC's May 2004 decision with the average yield on
4 See Order No. 29505 at 38.5 Idaho Public Utilities Commission, Order No. 29505 (May 25, 2004) at 43.
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triple-B public utility bonds for May 2004 of6.75 percent6 results in an implied cost of equity
for a utility with the lowest investment grade credit rating of 11.23 percent. This evidence
confirms the reasonableness of selecting a rate of return from the very top of Ms. Carlock'
DCF and comparable earnings ranges.
What other evidence indicates that a return from the top end of Ms.
Carlock's range of results is warranted?
While Ms. Carlock did not provide the analyses underlying her 10.0 to 11.
percent comparable earnings range, this method is typically implemented based on a review
of historical earned rates of return on book equity for the companies or industry in question.
But earned rates of return based on historical information are not necessarily indicative of
investors' long-run perceptions of risk and expectations for return going forward.
Alternatively, reference to earned rates of return expected from firms of comparable risk can
also provide a useful guide that may better reflect the ongoing returns necessary to assure
financial integrity and attract capital. The most recent projections from the Value Line
Investment Survey (Value Line), which is the largest and most widely circulated independent
investment advisory service, indicate that its analysts expect average earned rates of return on
book equity for the electric and natural gas utility industries over the next three to five years
of 11.0 percent. 7 Based on Value Line s estimates, investors would anticipate a return on
equity from the average electric and gas utility at the top of Ms. Carlock's comparable
eanungs range.
6 Moody s Investors Service Credit Perspectives (Jun. 14 2004) at 49.7 The Value Line Investment Survey, Jun. 4, 2004 at 154, Jun. 18 2004 at 458.
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Do you and Ms. Carlock agree on the benchmark for a fair rate of
return?
Yes. We agree that the authorized rate of return should be competitive with
returns available to investors from investments of corresponding risk, as directed by
landmark Supreme Court decisions. Ms. Carlock also correctly noted that the opportunity to
earn a return at least equal to those expected in the capital markets for comparable
investments is required if a utility is to be able to attract capital. As stated my Ms. Carlock:
. . .
if the return earned by a firm is not equal to the return being earned on .other
investment of similar risk, the flow of funds will be toward those investments
earning the higher returns. Therefore, for a utility to be competitive in the
financial markets, it should be allowed to earn a return on equity equal to the
average return earned by other firms of similar risk.
Ms. Carlock also noted the importance of testing any cost of equity estimate against
applicable standards:
. . .
three standards have evolved for determining a fair and reasonable rate of
return: (1) the Financial Integrity or Credit Maintenance Standard; (2) the
Capital Attraction Standard; and (3) the Comparable Earnings Standard.
This is absolutely correct. If Avista s return on equity does not fully reflect the le~el of
investment risks that investors perceive, it will violate the risk-return tradeoff, breach
applicable standards, and impair Avista s ability to attract necessary capital.
Did Ms. Carlock recognize that the investment risks associated with
electric utilities have increased?
Yes. Ms. Carlock noted that a plethora of changes have impacted investors
risk perceptions, observing that:
8 Carlock Direct at 6 (emphasis added).
Id. at 5.
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The competitive risks for electric utilities have changed with increasing non-
utility generation, deregulation in some states, open transmission access, and
changes in electricity markets.
Ms. Carlock concluded that, because of these greater uncertainties, the difference in the risk
between industrial firms operating in the competitive market and electric utilities "is not as
"l1great as It use to
Did Ms. Carlock consider this increase in risk in her analysis of the cost
of equity for Avista s jurisdictional utility operations?A. No. Ms. Carlock ignored the implications of this trend in investment risks for
utilities, asserting instead that Avista s "competitive risks" are lower because of its "low-cost
source of power and the low retail rates."l2 Ms. Carlock also asserted that the Power Cost
Adjustment Mechanism ("PCA") reduces Avista s risks relative to other electric utilities.
Does this represent an accurate assessment of the investment risks
investors' associate with Avista?
No. While I agree with Ms. Carlock that relatively low rates provide benefits
to customers and may improve Avista s competitive position, this narrow view ignores the
substantial uncertainties that Avista s investors assume to realize these benefits. As explained
in detail in my direct testimony, because a high proportion of Avista s energy needs is
provided by hydroelectric facilities, Avista is exposed to a level of uncertainty not faced by
other utilities, which are less dependent on hydro generation.
Reduced hydroelectric generation due to below-average water conditions forces
Avista to rely on less efficient thermal generating capacity and purchased power to meet its
10 Id. at 8.
11 Id.
12
Id. at 8-
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resource needs. As the IPUC has noted
, "
there are no guarantees about future stream flows or
market prices ,14 and in light of the recent past, this dependence on wholesale markets entails
significant risk in the minds of investors, especially for a utility located in the west. Investors
recognize that volatile markets, unpredictable stream flows, and Avista s dependence on
wholesale purchases to meet the needs of its customers expose Avista to the risk of reduced
cash flows, increased need for financing, and unrecovered power supply costs.
Apart from exposure to market uncertainties, Avista also confronts the complexities
associated with maintaining the necessary licenses to operate its hydroelectric stations. The
process of relicensing is prolonged and involved and often includes the implementation of
various studies and measures to address environmental and stakeholder concerns. For
example, a federal court recently ordered the Federal Energy Regulatory Commission
FERC") to respond to a request for a formal review of Idaho Power Company s ("Idaho
Power ) Hells Canyon hydroelectric complex under the Endangered Species Act. 15 These
measures can impose significant additional costs and/or lead to reduced generating capacity
and flexibility.
Does the fact that Avista has a PCA absolve investors from risk of
volatility in wholesale power markets, as Ms. Carlock seems to imply?
A. No. The fact that Avista had been granted a PCA does not translate into lower
risk vis-a-vis other electric utilities. First, adjustment mechanisms to account for changes in
power supply costs are the rule, rather than the exception, so that Avista s PCA merely moves
13
Id. at9.
14
Idaho Power Granted $256 million deferral, but bond plan denied Idaho Public Utilities Commission (May
, 2002).
448
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its risks closer to those of other utilities. Second, the PCA does not prevent the lag between
the time that Avista actually incurs power supply expenses and when it is actually recovered
from ratepayers. Investors are well aware that the significant reduction in cash flows
associated with mounting deferrals can have a debilitating impact on a utility's financial
position.
Moreover, investors are aware that the PCA does not apply to 100 percent of the
difference between the actual cost of purchased power and the amount collected through
rates, with Avista s shareholders remaining at risk for 10 percent of any discrepancy. Indeed
Avista and its investors have already"experienced the impact that chaotic market conditions
can have when the utility is forced to rely on wholesale purchases to meet the gap in its
resource needs created by reduced hydro generation. Investor~ cannot afford to discount the
continuing prospect of further turmoil in western power markets, with S&P recently
emphasizing the record high wholesale prices for both peak and off-peak power:
For 2003 , record-high wholesale power prices were the defining feature of the
S. merchant power markets. ... Power prices in the western regions were
also the highest on record outside of the 2000-2001 California energy crisis.
... Off-peak prices also rose about 50% across the U.S. and set record highs
along the way in most regions. 16
Is Ms. Carlock's recommended cost of equity compatible with the level of
investment risks associated with Avista?
No. Avista s weakened financial position, as evidenced by its below-
investment grade corporate credit ratings, place it on an altogether differen~ risk plateau. The
15 "Court orders FERC to answer seven-year-old request for study of Idaho dams' fish impact Electric Utility
Week (Jun. 28, 2004) at 14.
16 Standard & Poor s Corporation
, "
Energy Commodity Report: U.S. Power Prices Record High in 2003
RatingsDirect (Jan. 15 2004).
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speculative grade credit rating assigned to Avista confirms that investors perceive its
investment risks to be higher than for the average utility. Investors rely greatly on bond
ratings as a source of information regarding investment risk and bond ratings and the risk of
common stock investment are closely related. Indeed, the higher risk associated with Avista
is mirrored in its Value Line beta of 0.80. As Mr. Thornton recognized:
. . .
the average risk security has a capital asset pricing model beta of 1., while
the average electric utility from my sample has a Value Line beta of ., which
is 28 percent less risky than the average-risk security.
The corollary of Mr. Thornton s conclusion is that Avista s risk is higher than the average
utility and that its expected returns need to be correspondingly greater to attract investment.
Does Ms. Carlock's recommended cost of equity adequately compensate
investors for Avista s greater risks?
No. While Ms. Carlock asserted that her recommendation considered the
risk characteristics for Avista ,18 she failed to look directly at other capital markets data to
assess the level of return investors require to compensate them for Avista s greater investment
uncertainties. Considering the IPUC's recent decision in Case No. IPC-03-13 to authorize
single-A rated Idaho Power a return on equity of 10.25 percent 19 Ms. Carlock's proposed
10.4 percent cost of equity in this case implies an adjustment of 15 basis points to account for
Avista s below-investment grade credit rating. But as discussed in my direct testimony, the
dramatically greater investment risk imposed by a weakened credit standing implies a
significant premium for Avista above the return required for an investment grade utility.
Indeed, reference to bond yield spreads suggests that the capital markets would require a
17 Thornton Direct at 11.
18 Carlock Direct at 14.
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450
minimum of2.8 percent in additional return to compensate for the greater risk associated
with a speculative credit rating.
What are the implications of disregarding Avista s investment risks in
setting the allowed rate of return on equity?A. If the greater risks associated with Avista s speculative grade credit standing
are not incorporated in the allowed rate of return on equity, the results will fail to meet the
comparable earnings standard that Ms. Carlock agrees is fundamental in determining the cost
of capital. From a more practical perspective, failing to provide investors with the
opportunity to earn a rate of return commensurate with Avista s risks will only serve to
perpetuate its impaired financial integrity, while hampering Avista s ability to attract the
capital needed to meet the economic and reliability needs of its service area.
How is a utility's financial integrity typically evaluated?
Bond ratings provide the most objective guide to a utility's financial integrity
and prospects for capital attraction. Bond ratings are assigned by independent agencies, such
as S&P and Moody s Investors Service ("Moody ), for the purpose of providing investors
with an overall assessment of the creditworthiness of a finn. As discussed in my direct
testimony, an investment grade bond rating (i.e. triple-B or above) indicates that a utility has
some measure of financial integrity. A below-investment grade rating, such as the double-
corporate ratings S&P has assigned to Avista, generally evidences a relative lack of
creditworthiness and an inability to attract capital except on more speculative terms.
19 Idaho Public Utilities Commission, Order No. 29505 (May 25, 2004).
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How do the rating agencies decide what ratings to assign to a utility such
as Avista?
The ratings assigned to a utility by the rating agencies are based typically on
an evaluation of the utility's business and financial risks. One of the most important of the
qualitative factors in determining a utility's bond ratings is its pre-tax interest coverage ratio
which is a measure of the protection available to pay interest expense from operational cash
flow. The financial ratio guidelines published by S&P specify a range for a utility s pre-tax
coverage ratio that corresponds to each specific bond rating. Widely cited in the investment
community, applicable ratios are determined by aligning the bond rating with the utility'
business profile ranking, which ranges from 1 (strong) to 10 (weak) depending on a utility'
relative business risks. Thus, S&P's guideline financial ratios for a given rating category
(e.triple-B) vary with the business or operating risk of the utility. A firm with a business
profile of "2" (i.relatively lower business risk) could presumably maintain lower coverage
ratios than a utility with a business profile assessment of "9" while maintaining the same
credit rating. S&P has currently assigned a business profile ranking of "6" to Avista.2o
What pre-tax coverage ratio would Avista require to qualify for the lowest
investment grade bond rating?
Consistent with Avista business profile ranking of "6" and S&P's available
published guidelines, Avista would be required to achieve and maintain a pre-tax interest
coverage ratio in the range of2.6 to 4.0 times to qualify for a triple-B bond rating.
20 Standard & Poor s Corporation
, "
New Business Profile Scores Assigned for U.S. Utility and Power
Companies; Financial Guidelines Revised RatingsDirect (Jun. 2 2004).
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Is it clear that the coverage ratio implied by Ms. Carlocks
recommendations would grant Avista the financial strength necessary to achieve an
investment grade bond rating?A. No. As shown below, the pre-tax interest coverage implied by Ms. Carlock'
recommendations is 2.71 times:
Weighted Pre-tax
Component Percent Cost Rate Cost Cost
Debt 50.08%68%35%35%
Trust Preferred 57%15%0.34%34%
Preferred Stock 76%35%0.13%20%
Equity 42.59%10.40%4.43%89%
100.00%25%11.78%
Pre-tax Interest Coverage
Covera2e
35%
11.78%
71 X
This 2.71 times coverage is only marginally above the very bottom end of the 2.6 to 4.0 times
specified by S&P's financial benchmarks for a triple-B bond rating for a utility with Avista
business risks. To restore a company s rating to a previous, higher level, rating agencies
generally require a company to maintain financial indicators above the minimum levels
required for the higher rating over a period of time. Considering Avista s already weakened
credit standing, it is unlikely that Ms. Carlock's proposed rate of return would be adequate to
allow Avista the opportunity, under efficient and economical management, to restore basic
financial integrity and implies a continuation of its current junk bond ratings.
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What other evidence indicates the importance of reasonable regulatory
decisions on Avista s ability to maintain its financial integrity?
Following the IPUC's decision in Case No. IPC-03-, S&P placed the
utility' credit ratings on CreditWatch , indicating the potential for a future downgrades.21 In
explaining this action, S&P noted:
Standard & Poor s Ratings Services today placed the corporate credit rating
and all long-term ratings on IDACORP Inc. ('/A-) and subsidiary Idaho
Power Co. ('A-/A2') on CreditWatch with negative implications following the
May 25 2004, Idaho Public Utilities Commission (IPUC) ruling authorizing
only a $25.3 million (5.2%) permanent electric base rate increase for the
utility, which had requested an $85.6 million (17.7%) increase. ... Following
the IPUC staff's 3.1 % rate increase recommendation in February 2004
Standard & Poor s said that "a final decision by the commission that adopted a
rate increase akin to that proposed by the staff could have an adverse effect on
bondholder protection measures." The final IPUC ruling is indeed
substantially closer to the staff's position than the company , and will weaken
credit protection measures. 22
Considering the vastly greater investment risks implied by Avista s already weakened credit
profile, the perception of lack of regulatory support would undoubtedly place downward
pressure on current ratings, as is occuning for Idaho Power. Such an outcome would be
inconsistent with the IPUC's stated desire to maintain credit ratings "at or above the current
level,,23 and lends further support for a return on equity at the very top of the range of Ms.
Carlock's results.
21 Standard & Poor s Corporation, "IDACORP Ratings Placed on CreditWatch With Negative Implications
Following IPUC Ruling,RatingsDirect (Jun. 15 2004).
22 Id.
23 Idaho Public Utilities Commission, Order No. 29505 (May 25 2004) at 43.
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Is there evidence regarding the importance of regulatory support in
determining a utility's financial integrity?
Yes. Investment publications and the trade press are replete with examples
that highlight the critical role that a constructive regulatory environment plays in investors
assessment of a utility s credit quality. In discussing the criteria used to establish a
company s bond rating, S&P noted that:
The regulatory relationship can be a benign one - or it can be adversarial. It
affects virtually all corporates to one extent or another, and is obviously
critical in the case of utilities - where it is a factor in all assessments of
business risk.
In light of challenges in the industry, investors have refocused attention on regulatory
policy. An article reporting on investment analysts' comments concerning the prolonged
financial slump in the electric utility industry noted the importance of "evenhanded
regulation " with one analyst concluding "uncertainty is the main obstacle to bolstering
energy utilities ' capital.,,25 Indeed, S&P noted that "one of the major challenges facing the
industry is the daunting task of restoring investor confidence" and recognized the importance
of regulatory support in its assessment of credit quality.26 Accordingly, it is critical to assure
investors' confidence in a balanced approach if reasonable access to capital is to be
maintained.
Did Ms. Carlock consider flotation costs in her DCF analysis?
Yes. Ms. Carlock incorporated flotation costs by increasing the dividend yield
component of her DCF analysis. While Ms. Carlock concluded that direct flotation costs
24 Standard & Poor s Corporation Corporate Ratings Criteria (Nov. 13 2003) at 42.25 Walsh, Campion, "Wall Street Seeks FERC's Help for Power Sector Slump Dow Jones Newswire (January
2003).26 Standard & Poor s Corporation
, "
Regulation and Credit Quality in the U.S. Utility Sector
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would warrant an adjustment equal to 4 percent of the dividend yield component, she reduced
this factor to 2 percent for Avista s jurisdictional utility operations, based on her belief that
all subsidiaries of Avista Corp should be responsible for some of actual flotation costS.,,27
Is there any merit to Ms. Carlock's logic?
No. While I do not disagree with Ms. Carlock that all of Avista s operations
should share the burden of flotation costs incurred to raise equity capital, no adjustment to the
cost factor is required to accomplish this objective. This is because the allowed return on
common equity, including the full 4 percent adjustment for direct flotation costs, is only
applied to the equity used to finance jurisdictional utility operations. Thus, the only flotation
costs that will be considered are those related specifically to the equity required to provide
utility service in Idaho. By adjusting the flotation cost factor downward to 2 percent, Ms.
Carlock is essentially assuming that the costs associated with raising equity invested in Idaho
jurisdictional utility operations are one-half as much as those incurred to finance Avista
other operations. This is clearly not the case and results in a downward bias to Ms. Carlock'
recommendation.
In addition, Ms. Carlock apparently did not adjust the results of her comparable
earnings approach to incorporate flotation costs. Based on Ms. Carlock's representative
dividend yield of 3.4 percent and her 4 percent allowance for flotation costs, this would imply
an upward adjustment of approximately 10 basis points, or a comparable earnings range of
10.1 to 11.1 percent.
27 Carlock Direct at 11.
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In light of the shortfalls in Ms. Carlock's analysis and her failure to
meaningfully address Avista s relative investment risks, what is your conclusion
regarding her recommendations in this case?
In my opinion, Ms. Carlock's recommended 10.4 percent cost of equity falls
well short of the rate of return that investors require from Avista. In order to maintain and
expand utility infrastructure, it is both reasonable and necessary that Avista be provided the
opportunity to strengthen its credit standing and enhance its ability to attract capital. To meet
these challenges successfully and economically, it is crucial that Avista receive adequate
support for its credit standing. Because of shortfalls in her analyses, Ms. Carlock'
recommendation is inadequate to meet this goal.
At the very least, the IPUC should consider the results of risk premium analyses
along with Ms. Carlock's approaches, in evaluating the cost of equity. Ms. Carlock granted
that, in selecting a point estimate from within a range
, "
any point within (the J range is
reasonable.,,28 Coupled with the ongoing risks associated with Avista s continued exposure
to wholesale power markets and its weakened credit standing, this would suggest a minimum
cost of equity from the very top of Ms. Carlock's DCF and comparable earnings ranges.
III.DENNIS E. PESEAU
How did Dr. Peseau evaluate the cost of equity for Avista?
It is important to note that Dr. Peseau s opinions were not based on any
independent analyses of the cost of equity for Avista. Rather, he arrived at his
recommendations based on a purported "update" of my analyses and by making revisions to
my methods.
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What "updates" and modifications did Dr. Peseau make to your cost of
equity analyses?
Apart from conducting no analyses of his own, Dr. Peseau did not simply
update my analyses. Rather, he ignored historical trends in earnings growth in applying the
DCF model, used alternative bond yields to apply my risk premium approaches, and
substituted a lower market return in the CAPM. Finally, Dr. Peseau completely ignored the
flotation cost adjustment supported in my direct testimony.
What was the basis for Dr. Peseau s "revision" to exclude historical
growth rates from his "update" of your DCF analyses?A. In Idaho Power s recent general rate case, Dr. Peseau testified that historical
growth rates should be discarded because he did not approve of the composition of my proxy
groUp.29 Now, Dr. Peseau argues that historical growth rates should be ignored because
investment analysts "have already taken that information into account. ,,30 While I agree with
Dr. Peseau that investment analysts may consider historical growth rates in arriving at their
near-term projections, this fact does not support his argument that such growth measures
should be ignored in applying the DCF model. Rather, the fact that professional analysts
consider historical growth rates in their analyses is strong evidence that such growth rates are
also of relevance to investors in assessing their expectations and required rate of return.
Indeed, Value Line and other investment advisory services routinely report historical growth
rates, along with near-term projections. Ifhistorical rates of growth were not of interest or
relevance to investors, there would be no need to compile such information and present it on
28 Carlock Direct at 14.
29 Direct Testimony of Dennis E. Peseau, Idaho Public Utilities Commission, Case No. IPC-O3-, at 16.30 Peseau Direct at 51.
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an equivalent basis with near-term forecasts. Regulatory Finance: Utilities' Cost of Capital, a
source referenced by Dr. Peseau, concluded that:
Historical growth rates. .. are often used as proxies for investor expectations
in DCF analysis. Investors are certainly influenced to some extent by
historical growth rates in formulating their future growth expectations. In
addition, these historical growth indicators are widely used by analysts
investors, and expert witnesses. ...
Obviously, historical growth rates as well as analysts forecasts provide
relevant information to help the investor with regard to growth expectations.
But instead of heeding the advice of his own source, Dr. Peseau advocates ignoring historical
information altogether and thereby introduces a downward bias to the DCF results.
Q. Is there anything "inexplicable" about your recommended 6.0 percent
growth rate, as Dr. Peseau contends?32
Not at all. The rationale underlying my use of a 6.0 percent growth rate in the
DCF model was fully explained in my testimony (pp. 42-45). As I noted there, based on
analysts' projections and historical growth rates, but giving little weight to Value Line
projections, which deviated from consensus forecasts, I concluded that investors expect
growth in the 5.0 to 7.0 percent range for my proxy group. The 6.0 percent growth rate is the
midpoint of this range. As shown below, my 6.0 percent recommended growth rate is also
equal to the average of the remaining values after excluding Value Line s pessimistic earnings
growth projections:
Source
ffiES
Value Line
First Call
Multex
Growth Rate
5.4%
31 Morin, Roger A.
, "
Regulatory Finance: Utilities Cost of Capital " Public Utility Reports (1994) at 140.32 Peseau Direct at 51.
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Historical 10 Yr.
Historical 5 Yr.
Value Line "bxr
7.3%
00/0Average
Thus, the growth rate developed in my testimony is consistent with the recommendation of
Dr. Peseau s reference source, which notes that "equal weight should be accorded to DCF
results based on history and those based on analysts' forecasts. ,,33
What about Mr. Peseau s contention that your recommendation would
have been lower if you had applied a multi-stage DCF model (p. 53)?
Mr. Peseau s speculation is apparently based on his observation that dividend
growth in the electric utility industry is lagging behind earnings growth. As discussed in my
direct testimony, this observation only serves to illustrate the fact that near-term trends in
dividends are not representative of investors' long-term expectations. In any event, 1
explained why there is presently no compelling arguments in favor of a multi-stage DCF
model and Mr. Peseau presented no evidence to support his remarks and candidly admitted
that "I have not presented such an analysis.,,34
Is there any merit to Dr. Peseau s suggestion that there are inconsistencies
in your risk premium approaches that lead to an upward bias in your results (pp. 54-
56)?
No. The bond yields used in my applications of the risk premium method
were consistent with the underlying data sources used to compute equity risk premiums.
developing risk premiums based on authorized rates of return on equity in Schedule WEA-
I matched allowed rates of return in each year with the average yield on public utility bonds
33 Morin, Roger A.
, "
Regulatory Finance: Utilities Cost of Capital " Public Utility Reports (1994) at 157.34 Peseau Direct at 53.
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reported by Moody s Investors Service ("Moody ). This composite interest rate reflects the
risk profile of the electric utility generally over the 29 years covered by my analysis and there
is simply no basis for Dr. Peseau s insinuation that this somehow results in an upward bias.
Similarly, my analysis of realized rates ofretum reported on Schedule WEA-6 was based on a
consistent set of data, as reported by S&P. Because S&P does not publish an average public
utility bond yield, my analyses relied on the yield on single-A rated issues as a proxy for the
average risk profile of the industry over the study period.
Was it "incorrect" to add the equity risk premium determined in your
studies to the yield on triple-B bonds, as Mr. Peseau claims (p. 54-55)?
No. The exercise at hand is to estimate investors' required rate of return from
Avista s jurisdictional utility operations, not for the average utility. Adding the risk premium
to a triple-B bond yield, as I did, reflects the investment risks of a utility with the lowest
investment grade credit rating.35 Meanwhile, Mr. Peseau derives two of his "updated" risk
premium estimates by adding his revised equity risk premium to the yield on single-A bonds.
As a result, Mr. Peseau s "update" necessarily produces cost of equity estimate that falls
below investors' required rate of return for Avista, which has higher investment risks.
shown in the table below, even accepting Mr. Peseau s flawed "updates " correcting his
calculation to incorporate the May 2004 average yield on triple-B bonds results in the
following cost of equity estimates:
35 In fact, this approach is likely to understate the return on equity because investors in common stock, the most
junior and riskiest of a utility's securities, undoubtedly demand a greater premium to bear the higher risk of a
triple-B bond rating than debtholders.
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Method
Allowed Returns -A Rated
Allowed Returns - BBB Rated
Realized Returns - Arithmetic
Peseau
Updated"
Risk Premium
72%
4.35%
01 %
Implied
Cost of Eqyjtt
11.
11.1 %
10.
Triple- B
Yield
75%
75%
750/0
This restatement clearly confirms the downward bias to the 9.2 to 10.8 percent cost of equity
estimates he recommends based on the same approach:
Is your application of the realized rate of return approach based on the
assumption that "investors typically have holding periods of only one year," as Dr.
Peseau asserts (p. 56)?
No. My application of the risk premium method based on realized rates of
return makes no assumption regarding the holding period of the average investors, and Dr.
Peseau s assertion that the equity risk premium is a function of investors' holding period is
wrong. In estimating the cost of equity, the goal is to replicate what investors expect going
forward, not to measure the average performance of an investment over an assumed holding
period. Under the realized rate of return approach, investors consider the equity risk
premiums in each year independently, with the arithmetic average of these annual results
providing the best estimate of what investors might expect in future periods. Dr. Roger
Morin, who Dr. Peseau referenced in his testimony (p. 51), had this to say:
One major issue relating to the use of realized returns is whether to use the
ordinary average (arithmetic mean) or the geometric mean return. Only
arithmetic means are correct for forecasting purposes and for estimating the
cost of capital. When using historical risk premiums as a surrogate for the
expected market risk premium, the relevant measure of the historical risk
36 Moody s Investors Service Credit Perspectives (Jun. 14 2004) at 49.
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Ldl ~
premium is the arithmetic average of annual risk premiums over a long period
oftime.
Accordingly, Mr. Peseau s risk premium calculations using geometric means are properly
ignored and I have excluded them from the table above.
How did Dr. Peseau "update" your application of the CAPM approach (p.
57)?
Dr. Peseau did not update or otherwise address my CAPM approach. Rather
he ignored it entirely and instead substituted a market risk premium into my analysis that was
based on an entirely different method. As explained in my direct testimony, I applied the
CAPM based on a forward-looking estimate of the market risk premium that relied on
investors' current expectations in the capital markets. Meanwhile , Dr. Peseau simply asserted
that "(a)t this time, the indicated 'current market risk premium and the long-term average
market risk premium are both 7.2%.,,38 But this 7.2 percent risk premium is based on
historical returns back to 1926, not on the forward-looking expectations that drive investors
required rate ofretum in today s capital markets. The end result of Mr. Peseau s calculations
is not an "update" of my approach, but instead a CAPM cost of equity estimate that fails to
reflect investors' current required rate of return.
Did Dr. Peseau address the need to adjust the cost of equity to reflect the
greater investment risks associated with Avista?A. No. Dr. Peseau made no mention of Avista s below-investment grade credit
standing or the additional return investors require to compensate for this greater risk. Rather
he simply observed that investors do not expect to be compensated for "non-market" or
37 Morin, Roger A.
, "
Regulatory Finance: Utilities' Cost of Capital " Public Utility Reports (1994) at 275
(emphasis added).
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463
company-specific" risks.39 While Dr. Peseau s comment may apply under the narrow
strictures of modern portfolio theory, it does not alter a fundamental premise of finance that
investors require higher returns to bear higher risks. The strong link between bond ratings
and equity risk premiums has been well documented, and there is no ambiguity that investors
require substantially higher rates of return to compensate them for the risks of speculative
securities, versus those with investment grade ratings. Moreover, the overall assumption that
investors care only about systemic risk and not company-specific risk is a substantial
simplification of reality. In fact, no investor is perfectly diversified and bondholders
management, and other stakeholders have an intense interest in the fortunes of individual
companies. In the real world both macroeconomic risks (like the general economy) and
specific risks (like purchased power) absolutely factor into investors ' risk perceptions.
What about Dr. Peseau s allegation that such risks are "taken account by
investors" (p. 48)?A. I agree wholeheartedly with Dr. Peseau that investors fully consider the
uncertainties and characteristics of Avista and that the observable share prices in the capital
markets reflect their consensus view of these risks and prospects. But stock prices are only
one component used to estimate investors' required rate of return through quantitative
analyses. To the extent that other assumptions embodied in the analysis (e.market returns,
beta values, or growth rates) do not reflect the expectations that investors incorporated into
observed stock prices, the resulting cost of equity estimates will be flawed. .For example, Dr.
Peseau s "update" of the CAPM is predicated solely on an historical study of equity risk
38 Peseau Direct at 5839 Peseau Direct at 48-49.
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premiums, which does not contain any current market data. As I noted earlier, there is every
indication that the "updates" proposed by Dr. Peseau do not capture real-world expectations
or investors ' requirements for Avista. These flawed approaches and logic do not absolve Dr.
Peseau of the need to consider qualitative indicators of investment risks, including the
business and regulatory uncertainties specific to Avista and the industry in which it operates.
Did Dr. Peseau consider the need to account for past flotation costs?
No. Dr. Peseau did not take issue with my testimony that an adjustment for
flotation costs is reasonable in establishing a fair rate of return for Avista. However, Dr.
Peseau entirely ignored the issue of flotation costs in conducting his "updates" to my
analyses. As discussed in my direct testimony, flotation costs are legitimate and necessary,
and unless an adjustment is made to the cost of equity, investors will not have the opportunity
to earn their fair rate of return.
IV.JOHN S. THORNTON, JR.
Does Mr. Thornton recommend a "fair and reasonable" return on equity,
as his subtitle on page 4 would suggest?
A. No. His 8.50 percent recommendation fails all tests of reasonableness. Mr.
Thornton s claim that his return is adequate to maintain Avista s financial integrity is also
wrong because of mistakes in his coverage calculation presented on Exhibit JST-l and his
reference to the wrong benchmarks to gauge how bond rating agencies evaluate adequacy.
Finally, Mr. Thornton s criticisms of my testimony miss the mark and are simply not credible.
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Do recently authorized returns for electric and gas utilities conclusively
demonstrate the extreme downward bias of Mr. Thornton s 8.5 percent cost of equity
recommendation?
Yes. This recommendation falls far short of the IPUC's recent finding of a
10.25 percent cost of equity for Idaho Power. Further, in contrast to the single-digit cost of
equity estimate proffered by Mr. Thornton, Regulatory Research Associates reported that
authorized rates of return on equity for electric and natural gas utilities averaged 11.0 percent
and 11.1 percent, respectively, for the first quarter of 2004.
What causes Mr. Thornton s analysis to fall so far from a fair and
reasonable result?
In rebutting Mr. Thornton, I will show that his views are contrary to empirical
evidence and common sense and at odds with recent reasoning by the IPUC and the opinions
of investors. The most fatal flaw in Mr. Thornton s approach is that he forgets that the
bottom line test of any rate of return recommendation is whether it is consistent with the
requirements of real world investors. Mr. Thornton s personal views and insights on risk and
return are simply irrelevant if investors don t agree.
Is Mr. Thornton correct on page 31 when he claims that his 8.49 percent
recommended overall rate of return would maintain Avista s financial integrity?
Not at all. First, Mr. Thornton miscalculates the coverage ratio by ignoring the
fact that payments to holders of trust preferred securities are tax deductible. Second, he
compared Avista s projected financial parameters to other utilities actual performance during
2000-2002, a period of unprecedented turmoil in the electric utility industry. Mr. Thornton
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did not compare the projected coverage to the current criteria that the rating agencies apply in
their assessment of credit standing. Indeed, Mr. Thornton criticizes me for not recognizing
the improvements in the industry over the last year (pp. 33-34), yet he measures Avista
prospective performance against those dark days for the industry.
How does impact of Mr.Thornton s recommendations on Avista
financial integrity compare with that implied by Ms. Carlock's proposals?
It is far worse. As shown on below, after properly accounting for the tax
deductibility of Avista s trust preferred securities, his recommendation really translates into a
coverage ratio of 2.52 times:
Weighted Pre-tax
Com onent Percent Cost Rate Cost Cost Covera2e
Debt 48.19%70%19%4.19%4.19%
Trust Preferred 79%01%0.41%0.41%
Preferred Stock 726%34%13%20%
Equity 44.30%50%77%86%
100.00%8.49%10.65%10.65%
Pre-tax Interest Coverage 54 X
This is well below the 2.times minimum threshold specified by S&P for an investment
grade credit rating.A coverage ratio below the minimum guideline specified for a triple-
bond rating is far below the level required to allow Avista to start down the road to rebuild its
creditworthiness. The continuation of junk bond ratings, as will result if Mr. Thornton
recommendations are adopted, would fail to allow Avista an opportunity to maintain its
financial integrity or the ability to attract capital on reasonable terms on a prospective basis.
As a result, Mr. Thornton s proposals are clearly inconsistent with the financial integrity
40 Regulatory Research Associates
, "
Major Rate Case Decisions - January-March 2004"Regulatory Focus
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end-result" test and should be rejected. A speculative grade corporate credit rating does not
permit Avista to maintain its financial integrity or ability to attract capital on other than
speculative terms.
Should it be relevant to this Commission that Mr. Thornton does not
share your "rather gloomy outlook" for electric utilities (p. 33) and has less pessimism
in his own views?
Neither my views nor those of Mr. Thornton are as relevant as the perceptions
of investors and their willingness to provide capital to Avista on reasonable terms. The
headline of the Fitch report included in Exhibit JST-, pp. 20-21 indicates that at the end of
2003 there were finally prospects for stabilization in the industry. Stable is better than
deterioration, to be sure. This Fitch report, which Mr. Thornton referenced on page 34 of his
testimony, confirms that the industry is coming out of a bleak period that left many
participants weakened. Avista, with its double-B corporate rating is a prime example of a
company striving to stabilize its financial circumstances. Were this Commission to send a
disturbing signal, such as adopting an unreasonable return like that recommended by Mr.
Thornton, Avista and its customers would be denied the benefits of stabilization and the
opportunity to regain an investment grade credit rating.
Is Mr. Thornton correct when he claims on page 8 that the arithmetic
mean is "spurious" so that the geometric mean should be the sole measure of average
rate of return?
(Apr. 5, 2004).
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, absolutely not. Both the arithmetic and geometric means are legitimate
measures of average return; they just provide different information. Each may be used
correctly or misused depending upon the inferences being drawn from the numbers. I am
particularly sensitive to Mr. Thornton s cavalier attitude toward these measures since my
Ph.D. dissertation dealt with the proper use of the geometric mean by investors.
The geometric mean of a series of returns measures the constant rate of return that
would yield the same change in the value of an investment over time. The arithmetic mean
measures what the expected return would have to be each period to achieve the realized
change in value over time. The observation on page 10 of Mr. Thornton s Exhibit JST-
recognizes the legitimate role of the arithmetic mean:
Investors can be expected to realize geometric ~etums only over long
periods of time. The average geometric return is always less than the
arithmetic return except when all yearly returns are exactly equal. This
difference is related to the volatility of yearly returns.
As noted earlier in my rebuttal of Mr. Peseau, the arithmetic mean is the preferred
measure when using historical data for rate of return analyses. Yet, Mr. Thornton uses the
geometric mean exclusively and criticizes me for use of the arithmetic mean. One does not
have to get deep into finance theory to see why the arithmetic mean is more consistent with
the facts of this case. The IPUC is not setting a constant return that Avista is guaranteed to
earn over a long period. Rather, the exercise is to set an expected return based on test year
data. In the real world, Avista s yearly return will be volatile, depending on many economic
and weather factors, and investors do not expect to earn the same return each year.
Did Mr. Thornton apply the conventional DCF model used by you, Ms.
Carlock, and Dr. Peseau?
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No. Mr. Thornton used a multi-stage DCF model of his own design.
Although Mr. Thornton discusses his thoughts on why this model makes sense to him, he
presents no evidence that this model replicates the reasoning of real world investors. Mr.
Thornton s discussions of the record of stock market returns going back two centuries and
examination of a number of economic forecasts may be an intellectual exercise of sorts, but it
doesn t inform us of what real world investors expect when they invest in utilities like Avista.
Indeed, it is particularly telling that Mr. Thornton refers to "my growth estimates" on page 18
of his testimony. What matters are investors' estimates. Mr. Thornton gives us no credible
evidence that any investors share his expectations.
Do you agree with Mr. Thornton that dividend growth rates are likely to
provide a superior guide to investors' growth expectations?A. No. Dividend policies in the electric utility industry have become increasingly
conservative as business risks in the industry have become more accentuated. Thus, while
earnings may be expected to grow significantly, dividends have remained largely stagnant as
companies conserve financial resources to provide a hedge against heightened uncertainties.
In this regard, the near-term dividend growth projections understate long-term expectations
for an industry in the midst of turmoil. S&P observed that, while over the past few years
many utilities have frozen dividends or significantly lowered their growth rates" in order to
finance operations and pay down debt
, "
financially stronger companies may reconsider their
,,41IVI en po lcies.
But in contrast to the assumptions Mr. Thornton builds into his DCF model, investors
focus logically shifts from dividends to earnings as a measure of long-term growth as payout
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ratios trend downward. As a result, growth in earnings, which ultimately supports future
dividends and the share price gains anticipated by investors, is likely to provide a more
meaningful guide to investors I long-term growth expectations. The fact that investment
advisory services, such as ffiES and First Call focus on growth in earnings indicates that the
investment community regards this as superior to dividends as an indicator of future long-
term growth. Indeed Financial Analysts Journal reported the results of a survey conducted to
determine what analytical techniques investment analysts actually use.42 Respondents were
asked to rank the relative importance of earnings, dividends, cash flow, and book value in
analyzing securities. Of the 297 analysts that responded, only 3 ranked dividends first while
276 ranked it last. The article concluded:
Earnings and cash flow are considered far more important than book value and
dividends.
Did you err in not using a larger sample of utilities as claimed by Mr.
Thornton at page 34?
No. Mr. Thornton s claim that a larger sample results in "a more efficient
estimator" is contrary to common sense. My selection of these companies was guided by
Value Line s classification of utilities for investors. I chose a sample of western utilities
because there was evidence that investors believe that these utilities share risks that are
unique to the region. Throwing in more utilities from other parts of the country does not
improve information if these companies are not comparable in investors' eyes.
41 Standard & Poor s Corporation Industry Surveys: Electric Utilities (Aug. 7, 2003) at 8.42 Block, Stanley B.
, "
A Study of Financial Analysts: Practice and Theory,Financial Analysts Journal
(July/August 1999).
43 Id. at 88.
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Is there any validity to Mr. Thornton s claim at page 35 that your
dividend yield calculation mismatches price and dividends?
No. The price is observed at the same time as the dividend expectations.
There is no reason to believe that the publication of the Value Line each week causes prices
to move systematically because the information in Value Line Summary Index causes
investors' to alter their expectations, as suggested by Mr. Thornton. If this were the case, then
investors would certainly seek more timely and uniform distribution of Value Line, rather
than relying on weekly deliveries by U.S. mail.
Mr. Thornton argues at page 36 that you unreasonably assume that
companies will "suddenly and forever increase dividends by 6 percent per year" which
is "tremendously optimistic to the point of incredible." Do you make any incredible
assumptions?
No. I am attempting to replicate investor expectations, as reflected in ffiES
and First Call and other publications. First, as explained earlier and in detail in my direct
testimony, investors focus on earnings, not dividends in projecting future growth. This view
is confinned in the writings of Professor Siegal referenced by Mr. Thornton:
It does not matter how much is paid as dividends and how much is reinvested
as long as the firm earns the same return on its retained earnings that
shareholders demand on its stock. The reason for this is that dividends not
paid today are reinvested by the firm and paid as even larger dividends in the
future.
Second, investors do not have an infinite horizon. Their projections of growth go out to the
foreseeable future. Few, if any, real world investors concern themselves with infinitely long
44 Exhibit JST-, p. 11 (emphasis original).
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horizons. As a practical matter, not only is it impossible to predict the distant future, it simply
doesn t matter. In terms of the DCF model, the present value of cash flows in far distant years
- beyond the foreseeable future - is so small as to have little effect on investment decisions
today.
Is Mr. Thornton correct to argue (p. 36) that "one cannot conclude that
investors reasonably expect a 6 percent dividend growth in the near future (through
2009) much less infinity"
No. Investors expect what they expect. Ifpublications like IBES and Value
Line reflect what investors expect, and there is every indication they do, then it is reasonable
to conclude that what you see is what they expect. Mr. Thornton seems to think there is some
absolute benchmark for investor expectations other than what we see revealed in the
marketplace. This view is contrary to that found in Professor Siegal's words on page 10 of
Mr. Thornton s Exhibit JST-
However, the risk and return on stocks and bonds are not physical constants
like the speed of light or gravitational force, waiting to be discovered in the
natural world. Historical values must be tempered with an appreciation of
how investors, attempting to take advantage of the returns from the past, can
alter those very returns in the future.
Please respond to Mr. Thornton s contention that the analysts' growth
projections you used to apply the DCF model are "overly optimistic" (p. 36).
A. First, in contrast to Mr. Thornton s allegations, a study reported in "Analyst
Forecasting Errors: Additional Evidence" found no optimistic bias in earnings projections for
large firms (market capitalization of $500-000 million), with data for the largest firms
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(market capitalization ~ $3 000 million) demonstrating apessimistic bias.45 More
importantly, however, any bias in analysts' forecasts - whether pessimistic or optimistic - is
irrelevant if investors share analysts' views. The continued success of investment services
such as illES, and the fact that projected growth rates from such sources are widely
referenced, provides strong evidence that investors give considerable weight to analysts
earnings projections in forming their expectations for future growth. While the projections of
securities analysts may be proven optimistic or pessimistic in hindsight, this is irrelevant in
assessing the expected growth that investors have incorporated into current stock prices.
an article in Journal of Applied Finarice noted:
There is very little research on the properties of five-year growth forecasts, as
opposed to short-term predictions.
.. .
Analysts' optimism, if any, is not necessarily a problem for the analysis in
this paper. If investors share analysts ' views, our procedures will still yield
unbiased estimates of required returns and risk premia.
Given the importance that investors place on estimates of earnings growth, there is no basis
to support Mr. Thornton s contention that securities analysts' earnings growth projections
should not be used in the DCF model.
Does Mr. Thornton use conventional inputs to apply the CAPM?
No. Mr. Thornton rejects the use of Value Line betas and creates his own
(lower) adjusted betas. Similarly, he follows his own views about the appropriate risk-free
rate and market risk premiums. Again, Mr. Thornton tells us why he has convinced himself
45 Brown, Lawrence D.Analyst Forecasting Errors: Additional Evidence Financial Analysts Journal
(November/December 1997).
46 Harris, Robert S. and Marston, Felicia C., "The Market Risk Premium: Expectational Estimates Using
Analysts' Forecasts Journal of Applied Finance 11 (2001) at 8.
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!~. 7
of the rightness of these inputs, but does not offer any evidence that real world investors
would apply the model his way.
Is there reason for the IPUC to be concerned about Mr. Thornton s low
betas?
Yes. His downward adjustment of the Value Line betas is a major driver of his
low CAPM estimates. In its recent decision in the Idaho Power case the IPUC noted the
concerns about the measurement and proper use ofbeta.47 Mr. Thornton puts great emphasis
on beta not only in his CAPM analysis but as a basis for arguing that utilities have much less
risk than the average stock. To the extent that investors use betas in assessing risk, they are
more likely to reference the published betas in a widely circulated and authoritative source
like Value Line, rather than Mr. Thornton s self-developed adaptations to Value Line. Most
surprising, however, is that buried in Mr. Thornton s discourse on betas is evidence that
validates the IPUC's healthy skepticism.48 The graph of betas presented by Mr. Thornton on
page 26 of his testimony reveals a sharp drop in "OLS betas" in the late 1970s and early
1980s. This was a period of turmoil in the electric utility industry as the second oil embargo
hit along with the Three Mile Island incident. To investors this was a time of great concern
about utilities with resulting dramatic drops in the prices of utility common stocks and
downgrades of utility bond ratings at a time when interest rates and inflation had been soaring
to new highs. As utilities were reeling in the aftermath of these changes, the stock market
generally was strong as inflation and interest rates began to fall and the economy shook off its
47 Idaho Public Utilities Commission, Order No. 29505 (May 25, 2004) at 38.
48 While using the CAPM as his sole risk premium method in the face of the IPUC's reservations about thismethod, Mr. Thornton disparages the comparable earnings method favored by this Commission on page 37
calling it "an inferior approach to estimate a cost of equity.
4 75
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malaise during the early years of President Reagan s administration. While investors almost
certainly regarded electric utilities to be increasing in relative risk, the unadjusted betas were
dropping because utility stock prices were going down while the market was rising. This
period was a statistical artifact that led most observers to understand that historical betas
should be interpreted with a prudent grain of salt.
Are Mr. Thornton s criticisms of your allowed ROE risk premium
approach correct?
, Mr. Thornton s criticisms of the allowed rates of return used in this
approach are without merit. First, he is incorrect to allege that the infonnation regarding
average allowed rates of return in each year is unreliable simply because every item of
possible interest in each rate case is not also presented in my schedule. The allowed rates of
returns are taken ftom a recognized and widely-used publication ftom a firm with a long
history of accumulating and reporting the results of state regulatory commission decisions.
Mr. Thornton questions the potential for "upward bias " depending on the form of the DCF
model considered by regulators or whether they considered results of an "inferior approach
such as the comparable earnings method proposed by Ms. Carlock. But such criticisms miss
the point. Under this approach, it is not necessary to examine the actual tools and techniques
relied on by regulators to set allowed rates of return. Rather, what matters is that, after
reasoned consideration of the evidence presented by all participants to a rate proceeding,
regulators make an infonned determination of investors' required rate of return at the time
they issue their decision. This detennination is embodied in the authorized rates of return on
equity that I used to apply the risk premium approach.
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476
With respect to his theoretical arguments, Mr. Thornton is wrong about the risk
premium in the regression not being an independent variable.49 While the interest rate is
subtracted from the average allowed return each year, bond yields do not appear as an
independent variable in the analysis. Thus, if the risk premium had no association with the
level of interest rates, the regression equation would not show a statistically significant
relationship. In fact, the association found is highly significant using standard statistical
inference. Mr. Thornton also asserts that this study of authorized ROE's does not correct for
changes in industry risk. First, as explained in detail in my direct testimony, there is little
support for Mr. Thornton s contention that the risks associated with the electric power
industry have decreased over the period covered by my study. But irrespective of whether
risk was increasing or decreasing, this would be considered by regulators and captured in the
market data used to establish allowed rates of return. Mr. Thornton is also incorrect to claim
that declines in interest rates would lead to bias in the risk premiums. In fact, the average
interest rates used to apply this approach match the time period used to determine the average
allowed returns. Moreover, interest rates fluctuated considerable over the 29 years covered
by my study, which encompassed periods when interest rates were rising precipitously, as
well as times of moderating rates. And contrary to Mr. Thornton s allegation that my study is
out of step" by "mismatching" allowed ROEs and interest rates, my study specifically
adjusted for the impact of changes in bond yields on the equity risk premium. 50 Mr.
Thornton s suppositions are simply lacking in factual basis.
49 Thornton Direct at fn. 19.
50 Thornton Direct at 38.
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477
Is there any meaningful basis to Mr. Thornton s allegation that your risk
premium analysis based on realized rates of return is biased because it rewards
unsystematic risk" (pp. 39-40)?A. No. First, as I noted earlier in response to Dr. Peseau, the overall assumption
that investors care only about systemic risk and not company-specific risk is a substantial
simplification of reality. No investor is perfectly diversified and in the real world - as
distinct from Mr. Thornton s constructions - both macroeconomic risks and specific risks
affect investors' risk perceptions and return requirements.
Second, the assumption underlying the realized rate of return method is that historical
returns, measured over a sufficiently long time period, provide a surrogate for the forward-
looking rates of return required in the capital markets. This method does not depend on the
strict assumptions of the CAPM and avoids the controversy surrounding beta by looking
directly at returns for electric utilities. Nevertheless, these realized rates of return are a
function of actual prices in the capital markets, which are determined by real-world investors
that have the opportunity to "diversify into other industries.,,51 Thus, following Mr.
Thornton s logic, to the extent that these investors can eliminate risk through diversification
it would not be "priced in the market" or reflected in the values used to compute the realized
rates of return underlying my analysis. In other words, contrary to Mr. Thornton s assertions
the only compensation priced into realized returns would be for systematic risks.
51 Thornton Direct at 39.
52 This can be demonstrated by way of example. Subtracting my 5.2% risk-free rate from my 10.6% cost ofequity based on realized returns results in a risk premium for electric utilities of 5.4%. Dividing this premiumby the average beta of 0.77 for the fmns in my proxy group results in a market risk premium of 7.01 %, whichfalls squarely within the 6.1 to 7.8 percent range advocated by Mr. Thornton (p. 27).
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478
Third, Mr. Thornton again implies that declining risks may lead to an overstatement
of the cost of equity. Apart from the fact that his position is diametrically opposed to the
views of the investment community, as demonstrated in my direct testimony, it is also at odds
with the statistics he cites one paragraph previously, where he notes that the volatility of the
returns to electric utilities exceeded that for the S&P 500 over the 1994 to 2002 period.
Under Mr. Thornton s theoretical paradigm, higher volatility of returns relative to the market
is indicative of higher, not lower, investment risks.
Fourth, as I noted earlier in response to Dr. Peseau, there is no "mismatch" (p. 40) in
using triple-B bond yields to develop a cost of equity estimate for Avista. Adding the risk
premium to a triple-B bond yield, as I did, reflects the investment risks of a utility with the
lowest investment grade credit rating and is more likely to und~rstate, rather than overstate
the returns required by equity investors.
Finally, the single academic study referenced by Mr. Thornton provides no meaningful
information to evaluate the realized rate of return approach or aid the IPUC in its
deliberations. As Mr. Thornton summarized, the final conclusion of this research was that
risk premiums for utilities "should be close to zero.,,54 Of course, no reasonable analyst
would contend that the current risk premium for electric utilities should approach zero and
such a nonsensical result is even inconsistent with the meager returns recommended by Mr.
Thornton himself.
53 Thornton Direct at 39.
54 Thornton Direct at 42.
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479
Q. Is there any reason to believe that the market risk premiums and
expected returns are declining, as Mr. Thornton (p. 40) and Dr. Peseau (p. 58) assert?A. No. Contrary to the assertions of these witnesses, a study reported in the
January/February 2003 edition of Financial Analysts Journal noted that the real risk premium
for U.S. stocks averaged 6.9 percent over the period 1889 through 2000 and concluded that:
Over the long term, the equity risk premium is likely to be similar to what it
has been in the past and returns to investment in equity will continue to
substantially dominate returns to investments in T-bills for investors with a
long planning horizon.
Combining this real risk premium with an inflation rate of 3 percent suggests a market equity
risk premium well above the 8.5 percent used in my CAPM analysis that Mr. Thornton
characterized as "unrealistically high. ,,56
Please respond to Mr. Thornton s criticism of the long-term debt cost you
used to apply the CAPM (p. 43-45).A. I agree with Mr. Thornton that:
The use of a long-term U.S. Treasury bond for the risk-free asset implies a
long-term holding period.
Common equity is a perpetuity and as a result, the return that investors require is predicated
on their expectations for the firm s long-term risks and prospects. This does not mean that
every investor will buy and hold a particular common stock into perpetuity, but even an
investor with a relatively short holding period will consider the long-term because of its
influence on the price that he or she ultimately receives from the stock when it is sold.
Similarly, Mr. Thornton recognized that in applying the DCF model, the analyst must
SS Mehra, Ranjnish
, "
The Equity Premium: Why Is It a Puzzle?Financial Analysts Journal (January/February2003).
S6 Thornton Direct at 46.
57 Thornton Direct at 43.
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consider "the present value of all future dividends expected to be received by a share of
stock ,S8 not just the
dividends to be paid during some shorter (e.two-year), intermediate-
term holding period. Indeed, as Mr. Thornton observed in his Appendix, under the DCF
model "we assume that dividends are paid infinitely (n~oo)."S9
In fact, credible sources unambiguously recognize that long-term Treasury bond yields
provide the preferred basis to compute a long-term cost of capital. Indeed, Roger Ibbotson
whose firm Ibbotson Associates provided data relied on in Mr. Thornton s CAPM
application, made the same conclusion over a decade ago, explaining that while the CAPM
can be applied using short-term bill rates, the appropriate basis for a long-term cost of equity,
especially in the context of rate setting, is the yield on long-term Treasury bonds:
Q. Should the CAPM be used to estimate the short-term or the long-term cost
of capital?
A. The CAPM was originally formulated to measure the short-term cost of
capital, but it may be adapted to measure the long-term cost of capital by using
the expected return on a long-term government bond, instead of the risk risk-
free rate of return, as the riskless rate. ...
Q. When is it appropriate to use the long-term cost of capital?
A. It is necessary to use a long-term cost of capital when discounting cash
flows projected over a long period. Also, regulated ratesetting processes often
specify or suggest that the rate of return should allow the firm to attract and
retain debt and equity capital over the long term. Thus, the long-term cost of
capital is typically the appropriate cost of capital to use in regulated
ratesetting.
58 Thornton Direct at 13 (emphasis added).
59 Thornton Direct at 53.60 Ibbotson, Roger G. and Sinquefield, Rex A., "Stocks, Bonds, Bills, and Inflation: Historical Returns (126-
1987)," Research Foundation of The Institute of Chartered Financial Analysts (1989) at 122-25.
481
Avera, Di - Reb
A vista Corporation
More recently, Ibbotson Associates again emphasized the importance of using long-term bond
yields when applying the CAPM to estimate returns for long-term assets, such as common
stock:
The horizon of the chosen Treasury security should match the horizon of
whatever is being valued. ... Note that the horizon is a function of the
investment, not the investor. If an investor plans to hold a stock in a company
for only five years, the yield on a five-year Treasury note would not be
appropriate since the company will continue to exist beyond those five years.
In applying the CAPM, Ibbotson Associates recognized that the cost of equity is a long-term
cost of capital and the appropriate interest rate to use is a long-term bond yield. Mr.
Thornton s criticism of the long-term bond yields that I used is simply without basis and his
use of a shorter, intermediate term bond yield is similarly unfounded.
Did Mr. Thornton recognize that flotation costs are a necessary expense
that a utility must incur if it is to raise equity capital?
Yes. Mr. Thornton granted (p. 48) that "(f)lotation costs are a necessary cost
of business." Rather than recommend an upward adjustment to account for these costs
however, Mr. Thornton recommended that Avista be allowed to recover flotation costs "as an
expense item" through an accounting treatment.
Do you have any objection to the IPUC adopting an accounting treatment
for the recovery of flotation costs?
No. Allowing recovery of flotation costs as an expense item is certainly one
acceptable way to address this issue going forward. On the other hand, such a treatment
would ignore the costs already incurred in connection with past stock issuances. The only
practicable means available to ensure that Avista has the opportunity to earn investors' cost of
Avera, Di - Reb
A vista Corporation
482
capital is to include an allowance for past flotation costs in arriving at the fair rate of return
as Ms. Carlock and I have recognized. Choosing to ignore a "necessary cost of business" is
yet another reason explaining the extreme downward bias of Mr. Thornton s recommended
cost of equity.
Does financial theory preclude higher returns for higher risk, as Mr.
Thornton implies (p. 49-50)?
Of course not. Bond ratings are a widely recognized proxy for investment
risk. Mr. Thornton apparently is under the impression that investors would not necessarily
require a higher cost of equity from a "D" rated company whose debt is in default because
investors can avoid risk by diversifying.,,63 This shows just how far Mr. Thornton s analysis
departs from common sense in order to justify a below-market return on equity. Lower bond
ratings, such as Avista s double-B corporate credit rating, evidence investors' understanding
that there is greater uncertainties surrounding the firm s ability to successfully meet its
financial obligations, especially during adverse market conditions. In fact, this potential for
greater variability translates into Mr. Thornton s CAPM paradigm, with Avista s beta
exceeding those of the utilities in the proxy groups referenced by Mr. Thornton and me by a
significant margin. Further, while I agree with Mr. Thornton that the interest of bondholders
and stockholders may not always be aligned, the risks of investing in common stocks clearly
exceed those associated with bonds. Thus, reference to yield spreads between bonds of
various ratings is far more likely to understate the risk differential perceived by common
stockholders.
61 Ibbotson Associates 2003 Yearbook (Valuation Edition) at 53.62 Thornton Direct at 48.
Avera, Di - Reb
A vista Corporation
483
Does this conclude your rebuttal testimony?
Yes, it does.
63 Thornton Direct at 49.
484
Avera, Di - Reb
A vista Corporation
(The following proceedings were had in
open hearing.
(Avista Exhibi t No.3, having been
premarked for identification , was admitted into evidence.
COMM IS S lONER KJELLANDER:And I guess we re ready
now for cross-examination.
MR. MEYER:Yes.
COMMISSIONER KJELLANDER:Okay.Thank you.
Let's begin wi th the Counsel for the PUC Staff.
CROSS -EXAMINATION
BY MS. NORDSTROM:
Good morning.
Good morning, Ms. Nordstrom.
Would you agree that there are many
considerations that a Commission looks at when determining what
return on equity point to authorize?
Yes, I would.
On page 7 , line 15, of your rebuttal testimony,
you state that the IPUC findings in Idaho Power case
IPC-03-13 imply an equity risk premium of 4.48 percent for
Idaho Powe r .
Is it possible that other considerations were
part of deciding the 10.25 percent return on equity, and that
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AVERA (X)
Avista
the Commission may not Vlew that Decision as setting a risk
premium applicable to other cases or companies?
Certainly.I am not
- -
I hope I don t mean to
suggest by this discussion that that is the basis of the
Commission I S Decision.My purpose here is merely to show the
implication of the Commission I s finding in Idaho Power relative
to what the interest rate was as it might apply to what the
appropriate finding is for Avista.
Can historical data be used by investors to judge
the reasonableness of expected returns?
Yes, I think that I s one of the sources.
On page 11 , line 7 , of your rebuttal testimony,
you talk about uncertainty regarding the relicensing process.
Are you aware that the Commlssion has established
a mechani sm that allows recovery relicensing costs?
Yes,aware of that,but that still doesn'
ameliorate in investors' eyes the uncertainty surrounding
relicensing since there are environmental and other concerns
that might delay or reduce the amount of capacity and energy
available from the hydro facilities.So I understand that as
to the direct cost there is a mechanism , but from an investor'
perspective, any impairment in the availability of the
hydropower is a concern.
Thank you.MS. NORDSTROM:Staff has no further
questions.
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
AVERA (X)
Avista
Thank you,COMMISSIONER KJELLANDER:
Ms. Nordstrom.
Let I S move now to Mr. Ward.
Thank you.MR . WARD:
CROS S - EXAMINA T I ON
BY MR. WARD:
Dr. Avera , if you would turn to page 44 of your
testimony?Are you the re ?
Yes, sir.
Now , in your prior testimony in the Idaho Power
case and I assume others , you have used the B times R approach
in your DCF analysis as one al ternati ve, have you not?
Yes, sir.
And here again you mention it and summarize it in
just one paragraph , but you don I t list the conclusion
- -
the
ultimate conclusion as to the return on equity indicated.
Isn t it true that that return on equity would be 8.
percent?
That is correct.But my approach , Mr. Con-
Mr. Ward
- -
is to consider the various growth rates that
investors might consider to come up with what an appropriate
growth rate to use, and I don t think investors would consider
only this growth rate in evaluating their expectations of the
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AVERA (X)
Avista
future.
Nevertheless , this is an al ternati ve that you
used in the past and the indicated resul t is 8.8 percent, is
not?
I have used it in the past , Mr. Conley
Mr. Ward
- -
but I have never used it as the sole basis for a
growth rate because I don I t believe that tracks the way
investor expectations are formed.
I understand that.But you don t even list it in
your summary of the resul ts that are derived from your various
analyses.I sn 't that correct?
It's there , it 's in my testimony, I mention it a
number of times.I think itI also mention it in my rebuttal.
lS given the status to which it is due.
If you turn to page 42, in the middle of the page
there, you re discussing the indicated growth rates based on
various analysts I proj ections.Is this correct?
Yes, sir.
And looking at those indicated growth rates , you
have a variation from 2.4 percent to 5.4 percent, but obviously
a heavy grouping at just over five percent?
Yes, Slr.
Now , nevertheless, you come up wi th a six percent
growth rate by adding in the five- and ten-year historical
resul ts.Is that correct?
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AVERA (X)
Avista
And al so adding in the 4. 6 If you I 11 recall
Mr. Ward, ln my rebuttal I point out that if you take out the
2 . 4 percent and add in these remaining numbers pI us the 4. 6,
plus the five- and ten-year historical , you come to the six
percent growth that I used , which , incidentally, is the same
growth rate that Ms. Carlock found.
Okay.I f I took the average of these analyst
estimates here and added it to the existing dividend , wouldn't
that produce an 8.7 percent return on equi ty?
That's the ari thmetic, Mr. Ward, but I don '
believe that's the way investors would approach this data.
And these analysts are well aware of historical
resul ts , are they not?
Yes, they are.
Let 's - - let me ask you even if I threw out the
value line estimate, which is obviously lower than
significantly lower than -- the other analysts, the result
would be a 9.4 percent return on equi ty averaging all the other
analysts I estimates , would it not?
That would be the arithmetic , but I think that
excludes information that investors would reference in
developing their expectations.
And if I take an average of all these estimates,
plus your five and ten percent at -- five- and ten-year
historical results and I averaged all those together and added
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Avista
them to the dividend rate , I got an ROE of 9.8 percent?
That I S right.But you included, I believe, the
4 percent which you said was out of line and which I agree is
out of line with the other estimates.
Yes, but that I s also including the eight-plus
percent historical resul t and the seven percent?
That is correct, Mr. Ward , but I think the way
that investors would use this information is discard the 2.
add the rest, and divide by the number , and they would get the
six percent that I use and Ms. Carlock used.
Okay.Now , just like to briefly discuss the
capi tal asset pricing model wi th you.If you I d turn to your
Schedule WEA-6, page
Yes, sir , I'm there.
In the -- well , would it be fair to say that like
the DCF analysis, the resul ts here are driven in large part by
the estimated growth rate?
I think in terms of the estimated growth rate for
the market, that is the way we develop what investors are
expecting on a forward-looking basis.
Now, if I took this literally, it would suggest
to me that investors on a forward-looking basis are expecting a
13 .7 percent market return.Is that correct?
Yes, sir.
And that's predicated on a 12.1 percent growth
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AVERA (X)
Avista
rate?
Yes, it is.
Now , admi t tedly, companies can grow earnings at
double-digit rates coming out of a recession for a short period
of time if they have had depressed earnings in the first place,
but are you really suggesting that for any appreciable period
of time dividends can grow at 12.1 percent - - I mean , earnings
can grow at 12.
Yes, sir.I think that's what investors expect.
IBM grew earnings at more than 20 percent for 25 years, so I
think investors can expect a significant corporate performance
over time, and that I s the basis on which they re putting their
money down and buying these stocks.
IBM is certainly not a utility, is it?
No, sir , but we are referencing the market
generally here, so this 12.1 percent does not apply to
utilities, it applies to the market generally, companies like
IBM , Microsoft, Dell, and many others
- -
General Electric
that have experienced over the long run significant earnings
growth.
Are you aware that Dr. Jeremy Siegel has a new
edition of his Stocks for the Long Run?
m aware that he 's published many editions.
The re may be a new one out.More recent than the one that I s
Mr. Thornton I s materials?
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AVERA (X)
Avista
I don t know which one Mr. Thornton used, to tell
you the truth.This is the third edition which was published
in 2003, as I recall.Let me read you a quote from Dr. Siegel.
By the way, would you agree, he is a recognized
authority on stock market analysis?
Yes, sir , he is an authority, as much as there
are any in that exciting field.
Fair enough.
Page 114 , he's estimating the potential growth in
earnlngs for the market generally, and he says this:
Now, it is true that real per-share earnlngs
could grow faster or slower than three percent
- -
which he uses
as his estimate of the long-term growth in GDP returning to
the quote
- -
depending on whether firms are net buyers of
shares.
And he goes on to say:Recent evidence suggests
that from 1995 through 2000, corporations have been net
purchasers of shares.The shrinkage of the number of shares
have added between one and one and a half percent annually to
per- share earnings growth.Therefore, wi th the economy growing
at three percent, the upper limit on real long-term per-share
earnings growth , which is the sum of real growth plus the
reduction in the number of shares outstanding, would be four
and a hal f percent.
That I S a far cry from even if we add three
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Avista
percent inflation to make that seven and a half percent nominal
growth , that 's a far cry from 12.1 percent, isn't it?
Yes, sir , for the very long run in terms of
Dr. Siegel 's oplnlon.
I do note on page 5 which is included in
Mr. Thornton I s materials that in 1982 through 1999, investors
enjoyed an after-tax or after-inflation return of 13.6 percent.
So investors may even agree wi th Dr. Siegel for
the very long term , but in terms of any given horizon , they may
expect returns in this order.
And I didn t invent this number.Thi s number
arose from the 500 analysts that are specialists in the
Standard and Poor 500 companies.
And how far forward are they looking with their
estimates?
They re looking five years, which , according to
Mr. Thornton , most investors have a two-year time horizon.
they re looking as far as investors typically look into the
future.
And the ' 82 through '99 results that you just
cited, that stems from the greatest bull market in the history,
did it not?
Yes, that was their experience , but I think
investors can hope and may be expecting those days to return
again, because between ' 99 and 2003, they suffered mightily.
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AVERA (X)
Avista
So investors obviously feel that the very bad times have washed
out and based on these expectations of professional analysts
they expect the foreseeable future to give them a return of
about 13.7 percent.
MR . WARD:That I S all I have.Thank you.
COMM IS S lONER KJELLANDER:Thank you, Mr. Ward.
Mr. Cox.
MR . COX:I have no questions.
COMM IS S lONER KJELLANDER:Mr. Purdy.
MR . PURDY:I have none, thank you.
COMMISSIONER KJELLANDER:Are there questions
from members of the Commission?
COMMISSIONER HANSEN:I do.
COMMISSIONER KJELLANDER:Commissioner Hansen.
EXAMINATION
BY COMMISSIONER HANSEN:
I just had one question l'd like to ask you:
Yesterday in testimony it was pointed out that
Avista had a high-risk premium attached to them , and do you
think that that should be taken into an account of when
recommending a return on equity?
Commissioner , I think that Avista , as it stands
before you , you should consider what is necessary to meet the
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AVERA (Com)Avista
Hope and Bluefield standards:To make its earnings comparable
to similar risk companies, and it lS a relatively high-risk
company; to make the return sufficient so Avista , in its
current low-bond rating situation , can attract capital and
maintain and lmprove , hopefully, its credi t; and I think it I S
necessary to consider what is necessary for this Company to
attract capital.
So I think the risk profile of Avista should
certainly be considered by this Commission in the return that
it allows on equity.
So just to follow up, how much influence should
tha t have , in your mind?
Well, I think the Commission 's judgment as to the
relative risk of Avista should be extremely important.
Now , there are many different measures of
relative risk.The beta is another.The bond rating is one.
The stock ranking is another.Value line has a series of risk
ra t ings And if you look at all of those , what it says
Avista is at the high end of the risk spectrum.It is more
risky than the other Western utilities that Dr. Peseau and
used in our analyses, it is more ri sky than the average uti it y
that Ms. Carlock and Mr. Thornton looked at.
So we re talking about a company that the fact is
it is relatively high risk compared to other utilities, and
believe that should be considered in the Commission I s judgment
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AVERA (Com)Avista
as to what a fair rate of return is.
Thank you.That I S all I have.
COMMISSIONER KJELLANDER:Commissioner Hansen.
I think we re ready now for redirect.
No redirect.Thank you.MR . MEYER:
COMMISSIONER KJELLANDER:Thank you, Mr. Avera.
(The wi tness left the stand.
COMMISSIONER KJELLANDER:And, Mr. Meyer , if you
would like to call your next witness?
MR. MEYER:I m happy to do so.I thought we
were going to go wi th Mr. Yankel.
COMMISSIONER KJELLANDER:You are correct, that
was the plan , and it I S my apologies.So we I 11 go to Mr. Cox.
At this time, we would call Tony Yanke MR . COX:
to the stand.
ANTHONY YANKEL,
produced as a witness at the instance of Coeur Silver Valley,
being first duly sworn , was examined and testified as follows:
DIRECT EXAMINATION
BY MR. COX:
Would you state your name, please?
Anthony J. Yankel.
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HEDRICK COURT REPORTING
O. BOX 578 , BOISE, ID 83701
YANKEL (Di)
Coeur
And on whose behalf are you offering your
test imony?
Coeur Silver Valley.
Have you provided direct testimony and rebuttal
test imony?
Yes, I have.
Do you have any correct ions you need to make to
that testimony?
I have one mlnor correction to my direct
testimony.
And what is that?
Page 11 , line 13, beginning at line starts
"Exhibi t 304 , page 2.That should be corrected to
" Exh bit 3 0 5 . "
Any other correct ions?
None that I m aware of.
Other than that correct ion . if you were asked the
same questions in your direct and your rebuttal, would you give
the same answers?
Yes,would.
Okay.And have
307?
Yes,have.
you sponsored Exhibits 301 to
MR . COX:I d ask that his testimony and exhibits
be admitted.
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YANKEL (Di)
Coeur
COMMISSIONER KJELLANDER:And without objection
we will spread both the direct and rebuttal testimony of
Mr. Yankel across the record as if read, and admit Exhibits 301
through 307.
MR . COX:Thank you.
(The following prefiled direct and
rebuttal testimony of Mr. Yankel is spread upon the record.
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P. O. BOX 578 , BOISE , ID 83701
YANKEL (Di)
Coeur
PLEASE STATE YOUR NAME, ADDRESS, AND EMPLOYMENT.
I am Anthony J. Yanke!. I am President of Yanke 1 and Associates, Inc. My
address is 29814 Lake Road, Bay Village, Ohio, 44140.
WOULD YOU BRIEFLY DESCRIBE YOUR EDUCATIONAL
BACKGROUND AND PROFESSIONAL EXPERIENCE?
I received a Bachelor of Science Degree in Electrical Engineering from Carnegie
Mellon University in 1969 and a Master of Science Degree in Chemical Engineering from the
University of Idaho in 1972. From 1969 through 1972, I was employed by the Air Correction
Division of Universal Oil Products as a product design engineer. My chief responsibilities were
in the areas of design, start-up, and repair of new and existing product lines for coal-fired power
plants. From 1973 through 1977, I was employed by the Bureau of Air Quality for the Idaho
Department of Health & Welfare, Division of Environment. As Chief Engineer of the Bureau
my responsibilities covered a wide range of investigative functions. From 1978 through June
1979, I was employed as the Director of the Idaho Electrical Consumers Office. In that capacity,
I was responsible for all organizational and technical aspects of advocating a variety of positions
before various governmental bodies that represented the interests of the consumers in the State of
Idaho. From July 1979 through October 1980, I was a partner in the firm of Yankel, Eddy, and
Associates. Since that time, I have been in business for myself. I am a registered Professional
Engineer in the states of Ohio and Idaho. I have presented testimony before the Federal Energy
Yankel, DI
Coeur499
Regulatory Commission (FERC), as well as the State Public Utility Commissions of Idaho
Montana, Ohio, Pennsylvania, Utah, and West Virginia.
ON WHOSE BEHALF ARE YOU TESTIFYING?
I am testifying on behalf of Coeur Silver Valley.
WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING?
My testimony will address the cost-of-service for Schedule 25 customers with
emphasis upon directly assigning as opposed to allocating distribution plant to these customers
and the rate design for Schedule 25 in order to properly reflect load factor differences within
Schedule 25.
Q. PLEASE SUMMARIZE YOUR CONCLUSIONS WITH RESPECT TO THE
MANNER IN WHICH COSTS SHOULD BE ASSIGNED TO SCHEDULE 25 CUSTOMERS.
A. After reviewing the Company s cost-of-service study, I have concluded that there are
some problems with respect to the allocation/assignment of Primary related distribution plant
associated with Schedule 25 customers. Basically, the Company is able to (and does properly)
assign the actual costs incurred associated with distribution substations to Schedule 25.
However, after identifying specific substation costs to directly assign, the Company then goes
back to allocation Primary related equipment (between the substations and the customer) in a
500
Yankel, D I
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manner that ignores the fact that these are customers for which specific Primary plant can be
isolated and either directly assigned or simply identified as not existing at all. After correcting
for only these problems (in plant accounts 364-367), the rate of return for Schedule 25 is
significantly increased to the point where it is above the system average rate of return. Based
upon this result, I recommend that Schedule 25 be given the average jurisdictional increase.
I have reviewed the rate design for Schedule 25 in connection with the load and load
factor of Schedule 25 customers. There is no question that Potlatch-Lewiston is a very special
case for Schedule 25 and that rates must be designed with this customer s cost-of-service in
mind. However, Coeur Silver Valley is the next largest customer and it has a significantly higher
load factor than the remaining Schedule 25 customers. The difference in load factors of the
various Schedule 25 customers must be better addressed than in the Company s proposed rate
design. I recommend that rates be established which better reflect this difference in load factor
and thus cost causation.
Q. ARE YOU ADDRESSING ALL ASPECTS OF AVISTA'S CLASS COST-OF-
SERVICE STUDY?
A. No. Due to time constraints, I have not made a complete review of all aspects of the
study, but have focused on those areas where major discrepancies exist between the way costs
are addressed (allocated/assigned) and the actual costs that are incurred. For example, there are
areas such as the change in allocation methodology from the last case that I am aware exists, but
have not reviewed.
501
Yankel, D I
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COST -OF -SERVICE STUDY
Q. WHAT AREAS IN THE COMPANY'S COST-OF-SERVICE STUDY DID YOU
ADDRESS IN DETAIL?
A. My focus was on: 1) distribution Accounts 361-367 as they relate to Schedule 25
customers; and 2) how the rates paid by Schedule 25 customers relate to individual customer
load factors.
Q. IS THE ALLOCATION/ASSIGNMENT OF DISTRIBUTION RELATED PLANT
COSTS THE SAME FOR SCHEDULE 25 AS IT IS FOR ALL OTHER CUSTOMER
CLASSES?
A. No. While most distribution plant was allocated to the various rate schedules
Schedule 25 customers received a mixed bag of allocated and directly assigned plant. Generally
speaking, this may not be unusual except for the pattern of what plant is allocated compared to
what plant is directly assigned.
Direct assignment should be done wherever possible, as it is an accurate reflection of cost
causation, while allocation of costs is only done as a surrogate of cost causation. A vista only has
15 customer~ in its Idaho jurisdiction that are on Schedule 25. These are Avista s largest
customers in Idaho. Appropriately, Avista has directly assigned costs associated with Account
361 (Distribution Substation Structures & Improvements) and Account 362 (Substation
Equipment) to Schedule 25 as can be seen on Exhibit 301. However, costs associated with
1 The main exception to this is Street and Area Lighting customers.
502
Yankel, D I
Coeur
Account 364 (Poles and Towers) and Account 365 (Overhead Conductors & Devices) were then
allocated to Schedule 25 customers as opposed to directly assigned.
Q. WHAT IS WRONG WITH ALLOCATING ACCOUNT 364 AND 365 COSTS TO
SCHEDULE 25 CUSTOMERS?
A. If the costs associated with Accounts 361 and 362 could not have been directly
assigned to Schedule 25 (but had to be allocated), then it may have been appropriate to allocate
costs associated with Accounts 364 and 365 to Schedule 25 customers. However, the Company
was able to isolate and directly assign the costs for Accounts 361 and 362 to Schedule 25, so it is
only appropriate to continue to directly assign the primary lines and towers that originated at
these facilities and carry electricity to these same Schedule 25 customers.
This may be best understood by an illustration using the Lucky Friday Substation that
serves Hecla Mining Company. Starting at the generation level, there is no way to segregate or
directly assign generation plant to Hecla Mining Company, so it must be allocated. Likewise
when that electricity is sent over the transmission system, there is no way to segregate or directly
assign transmission plant to Hecla Mining Company, so it must be allocated. Electricity next
travels through substations. The Lucky Friday Substation is entirely used to serve the Hecla
Mining Company so it is not allocated, but 100% directly assigned to Schedule 25. Coming out
of this substation, these particular Primary lines are 1 121 feet (0.2 Miles) long and are obviously
used to serve only Hecla s Schedule 25 load and should be directly assigned, as was the plant
(Accounts 361 and 362) serving those Primary lines.
2 Including Potlatch's Lewiston facility.
503
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Q. WHAT DISTORTIONS RESULT WHEN POLES, TOWERS, AND OVERHEAD
CONDUCTORS ARE NOT BEING DIRECTLY ASSIGNED TO SCHEDULE 25
CUSTOMERS?
A. Schedule 25 customers are the largest use customers on the system. Collectively,
Schedule 25 customers account for 170 611 kW of non-coincident demand out of610 300 kW
listed for all customers3 or 28%. According to the Company s workpapers4 there are 3 049
circuit miles of Primary lines in Idaho. If all of the Schedule 25 non-coincident usage were used
to allocate this plant, it would mean that 28% or 854 miles of Primary distribution line would be
allocated to these 15 customers or about 60 miles of Primary distribution circuits per Schedule
25 customer.
This would be an absurd result and is partially avoided because the Company correctly
removes the Potlatch-Lewiston load when it is developing its D08 allocator for Primary related
plant. It is my understanding that the Potlatch-Lewiston load is removed because the circuits
behind the substation are not used to serve any customers other than Potlatch and are not even
owned by. A vista.
However, the Company did not go far enough with its assignment of costs to the rest of
the Schedule 25 customers. Instead of being assigned Primary plant, the other 14 Schedule 25
customers are allocated Primary distribution plant based upon their non-coincident peak, which
is set at 49 849 kW out of a total of 489 538 kW , or 10.18% of non-directly assigned Primary
distribution plant. At 10.18% of the circuit miles, this means that 310 miles of Primary lines are
3 See Exhibit 16 Schedule 2 page 31 line 20.
4 Workpapers TLK-43 and TLK-
504
Yankel, DI
Coeur
allocated to these 14 customers or 22 miles for each Schedule 25 customer. Although this is
better than 60 miles of circuit per customer, it is nonetheless absurd.
Q. IS IT POSSIBLE TO SEGREGATE THE PRIMARY DISTRIBUTION SYSTEM
ASSOCIATED WITH ALL OF THE SCHEDULE 25 CUSTOMERS AS IT IS TO
SEGREGATE THE POTLATCH RELATED EQUIPMENT?
A. Data has been provided by the Company6 that lists the number of feet of primary
distribution plant serving each of these Schedule 25 customers. Based upon Exhibit 301 , all of
the substations that are labeled as being 100% assigned to a Schedule 25 customer can easily be
reviewed for direct assignment of Primary distribution plant. For those substations with less than
100% assignment of substation costs, the direct assignment of Primary related plant is still quite
feasible. F or example, if there is I-mile of primary distribution plant between the substation and
a Schedule 25 customer and there are some other customers served off of this same I-mile
stretch, then simply assigning all of the I-mile of plant to the Schedule 25 customer would be a
conservative estimate of the cost responsibility of the Schedule 25 customer.
Q. BASED UPON THE DATA PROVIDED BY THE COMPANY, WHAT
TREATMENT DO YOU RECOMMEND FOR THESE COSTS IN TillS CASE?
A. There is no question that allocating 60 or even 22 miles of Primary plant to each
Schedule 25 customer is inappropriate. According to the Company, there is a total of only 20.
5 See Exhibit 16 Schedule 2 page 31 line 32.
6 Response to Coeur Silver Valley Request 8.
505
Yankel, D I
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miles of Overhead Primary distribution plant and 0.96 miles of Underground Primary
distribution plant used to serve all 15 of the Schedule 25 customers. As opposed to being
directly assigned plant that is actually used, allocation results in approximately 15 times more
Overhead plant and 85 times mores Underground plant being associated with these customers
than is used by Schedule 25 customers.
All Schedule 25 customers must be treated as Potlatch is treated and have Primary
distribution plant directly assigned as opposed to allocated. I recommend using the ratio of the
20 miles of Overhead Primary lines dedicated to Schedule 25 customers divided by the 3 049
miles of Overhead Primary distribution plant in Idaho (0.66%) to allocate/assign Account 364
and 365 to Schedule 25. I recommend using the ratio of the 0.96 miles of Underground Primary
lines dedicated to Schedule 25 divided by the 808 miles of Underground Primary distribution
plant in Idaho (0.12%) to allocate/assign Account 366 and 367 to Schedule 25.
Q. WHAT IMPACT DOES DIRECTLY ASSIGNING THE COSTS OF THESE FOUR
ACCOUNTS HAVE UPON THE RATE OF RETURN FOR SCHEDULE 25?
A. Exhibit 302 is a summary sheet from a cost of service run made where the costs for
these four distribution accounts were directly assigned to Schedule 25. Contrary to the
Company s filed rate of return for Schedule 25 that was only 25% of the jurisdictional average
the rate of return for Schedule 25 (when using direct assignment) turns out to be 1.03 greater
than the jurisdictional average.
7 10.18% / 0.66% = 15.48 10.18% / 0.12% = 84.
Yankel, DI
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Q. ARE THERE CONCERNS RAISED BY THE COMPANY REGARDING THE
DIRECT ASSIGNMENT OF THESE COSTS?
A. Yes. First, the Company is concerned that using the relative length of primary
distribution does not capture the relative cost of the primary trunk lines necessary to meet the
capacity needs for extra large industrial customers. Although there may be some differences in
cost of serving different capacity loads, those costs should be contained within a relatively
narrow range for the Company s 13 , and 34 kv lines-not in the range of 15-85 times greater
as is suggested by the Company s choice of allocation factors compared to direct assignment.
Additionally, the age of the Primary lines serving Schedule 25 customers would suggest that they
would be relatively cheaper than the cost of lines being installed today and may be cheaper than
the average cost of Primary lines. Basically, the argument should not be accepted that the costs
of these facilities are higher until actual cost data is provided which demonstrates this to be the
case.
Second, the Company contends that the estimates it used for the circuit mileage
associated with individual customers may be slightly inaccurate. Be that as it may. I assume the
Company did an acceptable job of measuring, but the potential for error always exists. In order
to alleviate any concerns in this regard, I conducted another cost of service run using 1.5 times
the amount of Primary lines that the Company measured. r assume that the Company s accuracy
is well within this factor of 1.5. Exhibit 303 contains a summary of the results assuming that 30
miles of Overhead and 1.5 miles of Underground Primary distribution should be directly
assigned to Schedule 25. The resulting rate of return was still above the jurisdictional average
rate of return.
Yanke!, Dr
Coeur507
RATE DESIGN
Q. THE PRESENT RATE DESIGN FOR SCHEDULE 25 FEATURES A FLAT
ENERGY CHARGE AND A DEMAND CHARGE (ABOVE THE MINIMUM) THAT IS
FLAT. DOES THIS RATE DESIGN ADEQUATELY REFLECT COSTS FOR SCHEDULE
25 CUSTOMERS?
A. Although there are often good reasons for using rate structures that are flat, this does
not insure that the resulting charges will be reflective of cost causation. The Company readily
recognizes this phenomenon in this case where it proposes a declining block rate structure for
both Schedule 21 and Schedule 25 customers. As stated in Mr. Hirschkom s direct testimony at
page 22:
Generally, larger use customers under the Schedule are less costly to serve than
smaller use customers on a cost per kWh basis, as some fixed costs are spread
over a larger base of usage. Therefore, a lower incremental/average rate for
service to larger use customers under a Schedule generally is supportable on a
cost of service basis...
Based upon the above, A vista is proposing the introduction of a declining block energy charge
for Schedule 25 customers.
Q. HOW DOES THE SIZE (USAGE) AND LOAD FACTOR VARY WITHIN
SCHEDULE 25?
A. Potlatch-Lewiston is a new addition to Schedule 25 and is approximately three times
larger than the rest of Schedule 25 put together. Its load factor is also significantly higher than
other customers on this schedule. It appears that the addition of a customer as large as Potlatch-
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Lewiston to the Schedule 25 customer group is why a separate designation was made for this
customer in the Company s cost-of-service study as well as why the Company is proposing a
declining block energy rate structure for Schedule 25.
After Potlatch-Lewiston, Coeur Silver Valley is the largest of the remaining 14 customers
on Schedule 25. Exhibit 304 page 1 is a listing of test year montWy energy and billing demand
for each Schedule 25 customer . As can be seen from that exhibit, Coeur Silver Valley s energy
consumption is about 1.5 times that of the closest Schedule 25 customers, while its billing
demand is the third highest of all Schedule 25 customers. The smallest Schedule 25 customer is
J. D. Lumber Co. with energy consumptions about 20% that ofCoeur Silver Valley and about
% the size of Potlatch Lewiston.
Additionally, Coeur Silver Valley is not only the largest Schedule 25 customer
(excluding the new Potlatch- Lewiston load), but it also has the highest load factor of the group.
Exhibit 304 page 2 lists the annual consumption as well as annual billing demands for each of
these customers in order to calculate an average monthly load factorlO for each customer. As can
be seen from that exhibit, Coeur Silver Valley has the highest average load factor of 71 %, while
D. Lumber has the lowest at 33%. As a group (excluding Potlatch Lewiston) the average load
factor for Schedule 25 is only 53%.
Q. WHAT IMPLICATION DOES THIS DIFFERENCE IN LOAD FACTOR HAVE
ON COST OF SERVICE AND RATE DESIGN?
9 Data provided as a workpaper in response to Staff Request 29.
10 (annual energy) / (total billing demands) / (730 MS. per month)
Yankel, DI
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A. All things being equal, higher load factor customers are generally much cheaper to
serve than lower load factor customers. The fact that the Coeur Silver Valley load has an
average load factor that is over 2 times the worst average load factor on the rate schedule in
which it frnds itself means that there are large differences in meeting demand obligations
between Coeur Silver Valley and the other Schedule 25 customers. If Coeur Silver Valley is
going to pay rates that are reflective of its cost causation, then the design of the rates within
Schedule 25 must be such that higher load factor customers on the rate schedule are rewarded
with lower rates.
Q. DOES THE PRESENT SCHEDULE 25 RATE FULLY REFLECT THE
DIFFERENCE IN DEMAND RELATED COSTS FOR MEMBERS OF THIS RATE
SCHEDULE?
A. Although there is some recognition in the existing rate schedule of the impacts of load
factor, that recognition is minimal. Present rates have a minimum charge of $7 500 for the first
000 kW of demand and a $2.25 per kW charge for usage over 3 000 kV A. Assuming more
than the minimum, at a 71 % load factor, this translates into 0.434 cents per kWhll, which
amounts to a 15% addition to the energy charge of2.874 cents per kWh. At the Schedule 25
average load factor of 53% the demand charge translates into 0.582 cents per kWh, which is only
a 20% addition over the energy cost. The effective rate for usage over 3 000 kV A per month is:
L. F.Mills / kWh
33.
34.
71%
53%
510
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Although there is a 4.5% difference in the rates paid between these two load factors, this
differential is not a strong price signal to reflect the difference in cost causation between the two
different load factors.
I will use the ratio of the demand charge to the energy charge as a gauge of the relative
dependence placed upon the demand component compared to the energy component of the rate.
In this particular case with a demand charge of$2.25 per kW and an energy charge of2.874
cents per kWh the ratio would be 78 (2.25 /0.02874 = 78.3).
Q. HAS THE COMPANY FILED DATA THAT WOULD SUGGEST A
SIGNIFICANTLY DIFFERENT LEVEL OF DEMAND CHARGES FOR SCHEDULE 25?
A. Yes. On Exhibit 16, Schedule 2, page 3, line 6 the Company calculated the demand
related costs for serving Schedule 25 customers at current level of Return as $7.02 per kW per
month. Although I do not agree that this calculation should be taken literally as the basis for
setting demand charges, the fact that present demand charges for Schedule 25 are approximately
1/3rd of this level suggests that the demand charges may be too low.
Q. DOES THE COMPANY'S PROPOSED SCHEDULE 25 RATE FULLY REFLECT
THE DIFFERENCE IN COST CAUSATION FOR MEMBERS OF TillS RATE SCHEDULE?
A. No. The Company s proposed Schedule 25 rates do little to help the load factor
diversity that I am addressing. I assume (but do not know) that the new declining block energy
11 $2.25 / 730 ills / 0.71 = $0.00434
Yankel, DJ
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511
rate appropriately sets a revenue requirement for the Potlatch- Lewiston load that matches its
cost-of-service. However, it does little to address the load factor differentials for the rest of the
Schedule 25 customers.
The proposed rates have a $2.75 per kW charge for usage over 3 000 kV A. At Coeur
Silver Valley s average load factor of71 % this translates into 0.531 cents per kWh while at a
530/0 load factor it translates into 0.711 cents per kWh. With the proposed tail block energy rate
of 3.420 cents per kWh, the effective rate for usage over 3 000 kV A per month is:
L. F.Mills / kWh
39.
41.31
71%
53%
Once again, the difference in the rates between these two load factors (4.6%) is not significant
enough to reflect the difference in cost causation. In this case the proposed ratio of the demand
to energy rate is 80 (2.75 /0.03420 = 80.4) or not much of a change.
Q. IS THERE ANOTHER UTILITY TO WHICH THE COMMISSION COULD TURN
THAT PLACES MORE EMPHASIS UPON DEMAND RELATED CHARGES?
A. Yes. This Commission recently concluded a major rate case with Idaho Power.
Idaho Power s Schedule 19 serves customers in a similar size range to that of Avista's Schedule
25. It is interesting to note, that the present energy rates for Idaho Power s Schedule 19 have
been set at 2.8486 cents per kWh, which is almost the same as Avista's present energy rate of
8740 cents per kWh for its Schedule 25 customers. In contrast to the closeness of these energy
rates, Idaho Power s demand charge for Schedule 19 is $3.21 / kW, while Avista's demand
charge for Schedule 25 is $2.25 / kW (for usage greater than 3 000 kW). The ratio of the
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Yankel, DI
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demand to energy rate for Idaho Power s Schedule 19 is now set at 113 (3.21 / .028486 = 112.7).
Additionally, Idaho Power s Schedule 19 has a "Basic Load Capacity" rate that increases the
demand charge and thus this ratio even higher.
Idaho Power s rates for Schedule 24 (Irrigation Pumping) now has a demand charge of
$4.00 per kW and an energy charge of 3.244 cents per kWh. The ratio of demand to energy
charges in this case is 123 (4.00/ .03244 = 123.3). In spite of the fact that it is important to keep
this ratio for Irrigation customers as low as possible because Irrigators have effectively no
discretion regarding their demand levels, this ratio is significantly above the 78 calculated for
Avista's Schedule 25.
Q. HOW CAN 1HIS PROBLEM BE CORRECTED?
A. There are two ways to correct this problem of not assigning enough costs to low load
factor customers. The first way is to increase the demand charge and lower the energy charge ( s).
The second method is to develop a declining block energy rate that is load factor dependent, i.
the first so many kWh per kW are priced at one rate while usage above that level is priced at a
lower rate. I do not have a preference as to which method the Commission should adopt. I do
recommend that whatever method the Commission uses, it should target a ratio of demand to
energy charges of at least 120 for Schedule 25.
Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
A. Yes.
Yankel, DI
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PLEASE STATE YOUR NAME, ADDRESS, AND EMPLOYMENT.
I am Anthony J. Yanke!. I am President of Yanke I and Associates, Inc. My
address is 29814 Lake Road, Bay Village, Ohio, 44140.
ARE YOU THE SAME ANTHONY 1. Y ANKEL THAT HAS PROVIDED
DIRECT TESTIMONY IN THIS CASE?
Yes.
WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY?
I address certain issues brought up by the Staff with respect to Schedule 25.
Q. PLEASE SUMMARIZE YOUR CONCLUSIONS WITH RESPECT TO THE
ASSIGNMENT OF COSTS TO SCHEDULE 25 CUSTOMERS AS WELL AS THE RATE
DESIGN FOR THAT CUSTOMER CLASS.
A. The Staff's cost-of-seIVice study (like the Company s) fails to properly address the
assignment/allocation of certain primary distribution related costs to Schedule 25. If data is
utilized that is more reflective of cost causation, the rate of return for Schedule 25 comes out to
be above the jurisdictional average.
514
Yankel, DI
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Although the Staff's rate design is somewhat of an improvement over that proposed by
the Company with respect to recognizing the benefits of load factor for Schedule 25 customers
there is still a good deal of room for improvement. I develop a rate design for Schedule 25
customers that is similar to that recently approved on the Idaho Power system, which far better
reflects a rate differential between high and low load factor customers.
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COST -OF -SERVICE STUDY
Q. DO YOU AGREE WITH THE STAFF'S COST-OF-SERVICE ANALYSIS?
A. No. The cost-of service study used by the Staffis simply the Company s cost study
with the inclusion of the Staff's (as opposed to the Company s) revenue requirement numbers.
Basically, the Staff did not challenge any of the Company s methodology. Admittedly, I did not
challenge a great deal of the study either, but my review was limited to only one group of 14
customers with very specific characteristics.
In 1994, the summer peak was only 88% of the winter peak! while in the 2002 test year
data used in this case, the summer peak is approximately 4% higher than the winter peak2
Primarily, this change has been brought about by an increase in air-conditioning load, which has
prompted the Company to begin including cooling degree values in its load normalization
calculations. It is my understanding that the load research data used in this case was gathered
over 10 years ago, during a time when this system was winter peaking. I mention this because
the Company s load research data impacts the residential class The Company s cost-of-service
study lists the Residential class (like Schedule 25) as being significantly below cost-of-service.
A lot of the disparity that the Company s cost-or-service study is showing for the Residential
class could simply be an artifact of the outdated data being used by the Company that reflects a
very different load profile. Like Schedule 25, a lot more review should go into the data used to
develop cost-or-service studies before they are used to disproportionately raise rates for anyone
class of customers.
1 July 1994
peak was 1 270 MW while the December peak was 1 436 MW.2 Page TLK-78 of the workpapers provided by Tara L. Knox.3 It does not impact the cost-of-service for Schedule 25 as they are all measured hourly.
Yankel, D I
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516
Q. HAS THE STAFF DISAGREED WITH YOUR POSITION WITH RESPECT TO
DEVELOPING MORE OF A DIRECT ASSIGNMENT FOR CERTAIN DISTRIBUTION
COSTS TO THE SCHEDULE 25 CUSTOMERS?
A. No, I assume that the lack of inclusion of direct assignment data for these distribution
costs associated with Schedule 25 was more of an oversight or lack of data, than a deliberate
disagreement with the treatment. Most rate analysts would agree that it is far more
appropriate/accurate to directly assign costs than it is to allocate costs.
Q. CAN DISTORTIONS IN COST-OF-SERVICE RESULT IF DIRECT
ASSIGNMENTS ARE NOT MADE?
A. Yes, significant distortions can occur if direct assignments are not made. Potlatch-
Lewiston is a good example. This is by far the largest customer on the system and is three times
the size of all Schedule 25 customers combined. The Company either allocates distribution plant
on the basis of Non-Coincident Peak (NCP) or it is directly assigned. Potlatch-Lewiston s share
of the Idaho NCP is 20%4, Potlatch-Lewiston is directly assigned only $70 921 of Account 361
costs (Structures and Improvements), but if these costs were to be simply allocated on the basis
ofNCP, Potlatch-Lewiston would be allocated $519 8835 or over 7-times the actual cost
incurred. Potlatch-Lewiston does not even use any Account 364 (poles, Towers & Fixtures), but
4 Exhibit 16 Schedule 2 page 31 line21.
5 $2 627 000 times 19.79% equals $519 883.
Yankel, D I
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517
an allocation based upon NCP would place a burden upon this facility of$11 283 269 . Simply
put, it is inappropriate to allocate costs to large customers on the basis ofNCP when it is possible
to directly assign or more accurately define cost causation.
Q. IS THE DATA YOU USED TO ASSIGN/ALLOCATE COSTS TO SCHEUDLE 25
A TRUE DIRECT ASSIGNMENT?
A. No. A true direct assignment would assign only costs. As a surrogate for cost
causation, I chose to use the actual miles of primary distribution line used to serve these
customers and the assumption that costs per circuit mile average out to be the same. If the
Company can produce actual cost figures for the 21 miles of the primary distribution lines that is
used to serve all Schedule 25 customers7 (compared to 3 857 total primary miles in Idaho), then
this data should be substituted.
There should be no question that using actual miles of primary distribution line is far
more accurate for this customer group than the simple choice of using NCP data to allocate these
costs. The NCP data would suggest that an average of 60 miles of primary distribution line was
associated with each of the Schedule 25 customers (including Potlatch-Lewiston) when in fact
there is only 21 miles of primary distribution (overhead plus underground) that is used to serve
all Schedule 25 customers (including Potlatch-Lewiston).
Q. SHOULD SCHEDULE 25 BE SINGLED OUT TO GET MORE THAN THE
AVERAGE RATE INCREASE?
6 $57 015 000 times 19.79% equals $11 283 269.7 See Exhibit 306.
Yankel, DI
Coeur518
A. No. The difference in the choice of reflecting the relative number of miles of primary
circuits compared to the simplistic application ofNCP is the sole difference that pegs the rate
return for Schedule 25 at significantly below average cost-of-service, versus slightly above
average cost -of-service. It is this difference that should have been recognized in the Company
cost study, before recommendations were made to disproportionately increase rates for Schedule
25. A fluke in the cost -of-service study or the lack of quality data should not be the cause of a
disproportionate increase to any class-especially, when better data is available.
Yanke!, DI
Coeur519
RATE DESIGN
Q. DO YOU AGREE WITH THE STAFF'S OVERALL POSITION WITH RESPECT
TO RATE DESIGN FOR SCHEDULE 257
A. I have some concerns with some of the comments made by the Staff regarding the
rate design for Schedule 25 customers. Specifically, I disagree with Mr. Schunke s proposal for
the next case to gather additional information so that the Company can provide "a proposal to
eliminate the declining block rates in Schedules 21 and 25,,Although I welcome the
development of additional data, I do not believe that its intended purpose should be the
elimination of the declining block rates The data should be allowed to speak for itself and if
the data suggests that there should be more declining blocks or steeper declining blocks, then so
be it.
Q. DO YOU AGREE WITH THE RATE DESIGN DEVELOPED BY THE STAFF
FOR SCHEDULE 257
A. No. At the outset, I should say that I agree with Dr. Peseau s assessment that
Potlatch-Lewiston should not be included in the Schedule 25 rates. This facility should be
treated separately as there are no other customers that have load characteristics that are remotely
similar. My comments will address rate design for only 14 customers-all but the Potlatch-
Lewiston load.
8 Schunke s direct testimony at page 4 lines 13 and 14.
Yanke!, DI
Coeur520
My primary disagreement with the Staff's proposed rate design for Schedule 25 is that in
spite of the inclusion of a declining block energy rate, it still places very little reward (via lower
rates) for higher load factor usage. In my direct testimony, I attempted to address this concern in
a general way. Now that a more probable revenue requirement is being addressed, it is possible
to put a numerical value to the rate design concepts I proposed in order to provide some reward
to higher load factor customers.
Q. HOW WOULD YOU DEVELOP A RATE DESIGN FOR SCHEDULE 25 THAT
BETTER REWARDS lllGH LOAD FACTOR CUSTOMERS?
A. In my direct testimony, I proposed a ratio between demand costs and tail block energy
costs of at least 120: 1 in order to be somewhat consistent with the rate design for similar
customers in the Idaho Power service area as recently adopted by this Commission. As you may
recall, I calculated a ratio of 78: 1 for the existing Schedule 25 rates and a ratio of 80: 1 for the
Company proposed Schedule 25 rates. The Staff proposal of a second demand block rate of
$2.75 per kW and 3.268 cents per kWh for the tail block energy rate produces a ratio of84:
some improvement, but still a far cry from the rate design on the Idaho Power system.
Instead of the Staff's proposal of $9 000 for the first 3 000 kW and $2.75 per kW for each
additional kW, I propose that the initial 3 000 kW be priced at $10 500 and that each additional
kW be priced at $3.25 per kW. This demand charge is still less than half of the demand cost
calculated by the Company of $7.02 per kW per month for Schedule 25 customers and it serves
several purposes: 1) It is a rate that is similar9 to the rate being charged to Idaho Power Schedule
9 Idaho Power s Schedule 19 rate has a $3.21 demand charge in the summer and a $2.64 demand charge in
the winter, but additionally has a Basic Load Capacity charge of an additional $0.37 per kW of annual peak
Yankel, DI
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521
19 customers of$3.21 perkW; 2) It places more charges on the demand component so that
higher load factor customers will receive more of a benefit; and 3) It allows a ratio of the demand
charge to the tail block energy rate to be sufficiently larger without forcing the tail block energy
rate itself to be significantly reduced. The net impact of this rate design would be to place
approximately half of the increase upon the demand component.
The Staff's tail block energy rate is 3.268 cents per kWh. Using the ratio I previously
recommended between demand and tail block energy rates of 120, my proposed tail block energy
rate becomes 2.710 cents per kWh. Although there is not a huge difference between these two
tail block rates, there is sufficient difference to cause the ratio of demand to energy charges (120)
to be similar to the emphasis that is placed upon load factor in the Idaho Power system. This
proposed tail block rate is about 6%10 below the current energy rate for Schedule 25-meaning
that the tail block rate would have a slight decrease. If desired, a higher tail block could be
developed, but in order to maintain the ratio of demand to tail block energy rate of 120, this
would entail raising the demand charge further. It cannot be forgotten that all customers will pay
the demand rate as well as the initial and tail block energy rate, so just because one proportion of
the rate is going down, it does not mean that the overall bill is being reduced-just the price
signals will be arranged differently.
The last rate component to be addressed is the initial energy block. The last rate
component must do two things: 1) it must make sense; and 2) it must result in a rate such that
when taken in total, all of the rate components produce the revenue requirement for the schedule.
I have targeted the average rate increase calculated by the Staff of 15.78% because I believe that
demand that that effectively increases both the demand an winter demand charges by more than $0.37 per
monthly billing demand-depending upon the difference between the monthly billing demand and annual
demand.
710 cents divided by 2.874 cents equals 94.3%.
Yankel, DI
Coeur522
Schedule 25 should get no more than the average rate increase. In order to get this percentage
increase from Schedule 25 with the above proposed rate components, an initial energy block rate
of 4.33 cents per kWh is required. This rate is well within the realm of reason and is 12% greater
than the initial block rate proposed by the Staff.
Q. PLEASE SUMMARIZE YOUR RATE DESIGN FOR SCHEDULE 25 AND WHY
YOU BELIEVE THAT IT IS BETTER THAN THAT PROPOSED BY EITHER THE
COMPANY OR THE STAFF.
A. There is hardly any reward under the present Schedule 25 rate design for high load
factor customers. The days of the energy constrained utility in Idaho are numbered. More
emphasis should be placed upon demand charges in the A vista service territory compared to the
past. I believe that Idaho Power s new rates can serve as a model for rate design in the A vista
service area. The demand charge that I have proposed is essentially the same as that for Idaho
Power s Schedule 19 and the tail block energy rate is designed to hit a target ratio that is
representative of rate design on the Idaho Power system. In some respects, the proposal I am
making may seem radical, but the perceived change is more a result of where we have been as
opposed to where we should be going-the historical rate design was greatly lacking in its ability
to reward high load factor customers.
Q. DOES TIllS CONCLUDE YOUR REBUTTAL TESTIMONY?
A. Yes.
Yankel, D I
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(The following proceedings were had in
open hearing.
(Coeur Exhibit Nos. 301 through 307,
having been premarked for identification , were admitted into
evidence.
And we re ready now toCOMM IS S lONER KJELLANDER:
tender Mr. Yankel for cross.Let I S begin wi th Mr. Ward.
No questions, thank you.MR. WARD:
COMMISSIONER KJELLANDER:Go to Mr. Purdy.
MR . PURDY:I have none.
COMMISSIONER KJELLANDER:No quest ions
Mr. Purdy?
MR . PURDY:No.m sorry.
COMM IS S lONER KJELLANDER:Mr. Woodbury.
MR . WOODBURY:Thank you, Mr. Cha i rman .
CROS S - EXAMINA T I ON
BY MR. WOODBURY:
Good mornlng, Tony.
Good morning.
Coeur Silver Valley in this case recommends
direct assignment of primary related distribution plant , and
that I s the plant between substations and the customer which
think is Account 364 poles and towers, 365 overhead conductors
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HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
YANKEL (X)
Coeur
and devices, and much of that plant is largely depreciated, and
so I look at your recommendation as sort of one of a vintaged
allocation.Would that be correct?
No, I do not believe.My direct assignment or
allocation is really based on the number of miles.It really
has nothing to do wi th the age of the plant.There was no data
provided to me that the Company had apparently readily
available - - I I m not saying it I S not available someplace , but
certainly readily available
- -
in this case that would address
the vintage or the age or the cost of that particular plant.
So my procedure methodology was simply based upon the number of
miles of plant for underground and overhead primary
distribution.
And it is not an assignment direct on depreciated
value?
, it is not, although I do believe in
conversations and just my experience from , you know
unfortunately many years ago up in the Silver Valley that
probably a lot of that plant is fairly old and probably fairly
well depreciated.There was no attempt to incorporate that
information.
If that
- -
if that plant required replacement at
today I s dollars, then it's not Coeur Silver I s recommendation
that there be a direct assignment of that cost to the
Schedule 25 customers?
525
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID
YANKEL (X)
Coeur83701
It would be my recommendation if the data
fully available for all the customers to use whatever cost data
is available.So if there would be new plant installed, then,
yes, the new plant costs would be utilized.
Okay.Thank you.
MR. WOODBURY:Staff has no further questions.
COMMISSIONER KJELLANDER:Thank you,
Mr. Woodbury.
Let I S move to Mr. Meyer.
MR. MEYER:Thank you.
CROSS - EXAMINATION
BY MR. MEYER:
Good mornlng, Mr. Yankel.
Good morning.
Your direct assignment of primary distribution
costs, as I think you just testified to a moment ago, was based
on a number of
- -
it was mileage based , essentially, wasn '
it?
Yes.
Now , does that flat mileage-based allocation
assume that the maj or feeder lines for Schedule 25 customers
all have the same cost per mile as, let I s say,
simple single-phased circuits serving residential
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YANKEL (X)
Coeur83701
neighborhoods?
The assumption is that they have the average , not
necessarily the same, but that they would average out to be the
average for the system.The difference between a three-phase
and a single-phase in a residential neighborhood, I assume that
difference would be relatively small.If one looks at the
number of conductors, it's still going to take a ground wire
and two wires for a single phase.The three-phase would just
to be put in and installation costs wouldrequlreone more Wlre
be very similar same wi th poles,pole height,and whatnot.
would assume that residential single phase would shade
cheaper, but not that much cheaper.
That's a simplifying assumption that you made in
your analysis.Correct?
Yes.
All right.Now, isn't it also true that your
line mile measurement looked only at the most direct route from
the closest substation to the customer?
Yes.
Is it also true that some of these customers in
Schedule 25 may also receive power from an alternative route or
from other substations by means of backup?
I believe that I s probably true, certainly not
true for all of them, but for some of them.But in that case
also the substations and lines that would be the direct route
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could also be used as backup, say, for interruptions for people
in other sides of the line as well , so it could kind of go both
directions.
But, again, that is another simplifying
assumption that you made in your analysis?
Well, if I was to make the more complicated
analysis that you re suggesting, I would have to also certainly
add some plant from the other direction but I would have to
subtract some plant out that ve added ln or used because
there would be outages and whatnot going the other direction as
we 11 .
Right.But you don'know how that nets out?
No,don '
Okay.Do you understand that the Company I s
proposal on rebuttal would be to essentially meet you half way
with your proposal and assign one-half the difference between
the Company I s base case cost of service study and the amounts
that you have allocated, at least pending any further study?
Yes.I actually very much appreciate that, you
know
, "
offer," for lack of a better term.I don t necessarily
agree that 50 percent is enough , but, I mean , I do think that
it I S a nlce compromise.
And lacking more sophisticated costing data, does
that strike you as a sensible accommodation for purposes of
thi s case?
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Not really.Again , if I look , just for example,
a t the underground ine - - and the underground ine always
costs a whole lot more than overhead
- -
if I look at the
distribution of underground used by Schedule 25 versus that
which is out there on the entire system , I find that the
difference is approximately 85 times as much if I just use
assume the average cost that Schedule 25 gets about 85 times
more than they would normally get if it was a straight mileage
base.Splitting the difference in half , splitting the baby in
half , would get me down to about 40 to one or whatever.
don t think that I s a fair compromise.I think it I S moving the
right direction , I just don t think it adequately covers the
concern.
You were in the hearing room yesterday, were you
not, when witness Knox testified on behalf of the Company?
Yes, I was.
And did you hear her testify that her proposal to
meet you halfway on this issue served to materially increase
the rate of return for Schedule 25 customers from a .25 in the
base case that had been filed , all the way up to .62?
I think it was 67 , but, yes, it was a large
increase, yes.
Do you have in front of you Mr. Hirschkorn '
rebuttal testimony in this case?
I can get it.
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MR . MEYER:May I approach the witness?I have
it readily available.
COMMI S S lONER KJELLANDER:Yes.
MR . MEYER:For the record, I've handed the
witness Mr. Hirschkorn 's prefiled Exhibit 30 , directing him to
page 4.
BY MR. MEYER:Now, you assert
- -
if you I 11 keep
that in front of you for a minute
- -
you assert that Coeur
Silver Valley has the highest energy usage and the highest load
factor of customers served under Schedule 25 except for
Potlatch?
Yes.
All right.Isn't it true, Mr. Yankel , that of
all the customers served under Schedule 25 as shown in that
rebuttal Exhibit 30, that your client, Coeur Silver Valley,
would receive the lowest increase, an increase of 10. 3
percent?
Yes.
And isn t that 10.3 percent increase, in fact,
significantly less than the overall increase for Schedule 25 of
13 .1 percent also shown on that page?
I would agree that it I S certainly different.
Whether it I s significantly different, I think I would really
take exception to that.It I S less than three percent
difference, so it 's not that significant.
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Again, the point of my testimony was not so much
disagreeing with some of the direction that the Company was
going in.I believe that the Company I s direction was proper.
I also thought that Mr. Hirschkorn I s testimony indicated that
more movement was needed, and I m suggesting more movement
towards more reflection of load factor in rates.
Lastly, isn I t the percentage increase of
10.3 percent for your client considerably less than the 1 7
nearly 19 percent increases for other customers in that
schedule, including certain forest product companies?
I don't know about certain forest product
companles, but, yes, it I S certainly different.I think the
highest is 18.9 percent.So it 's close to, but not quite half
of, at least one of the clients
- -
one of the customers
- -
Schedule 25 would receive.
MR. MEYER:Thank you.That's all the cross.
COMMI S S lONER KJELLANDER:Thank you, Mr. Meye r .
Are there questions from members of the
Commission?Commissioner Smi th.
COMMISSIONER SMITH:Just kind of a generlc
question.
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EXAMINATION
BY COMMISSIONER SMITH:
You talk a lot about load factors.I n your
estimation , what's a high load factor?
Hundred percent.
Yeah?
Actually,Potlatch was surprised in looking at
the data , it was very high.It was well over
- -
I believe over
So there are people out there that have very high90 percent.
load factors.Tha t'Coeur Silver Valley has 71 percent.
actually qui te high.Fifty percent is fairly high.
Fifty?
Fifty percent is fairly high.
COMMISSIONER SMITH:Thank you.
COMMISSIONER KJELLANDER:Redirect.
MR . COX:None.
COMMISSIONER KJELLANDER:No redirect?
MR. COX:Right.
COMM IS S lONER KJELLANDER:Thank you, Mr. Yanke 1 .
THE WITNESS:Thank you.
COMMISSIONER KJELLANDER:And is it your intent
to have your wi tness excused at the end of the day?
MR . COX:Yes.
COMMISSIONER KJELLANDER:Okay.Thank you.
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