200403121st Response of Micron to ID Power.pdf

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Conley E. Ward (ISB No. 1683)
GIVENS PURSLEY LLP
601 W. Bannock Street
O. Box 2720
Boise, ID 83701-2720
Telephone No. [phone]
Fax No. [phone]
cew~givenspursley .com
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LJT \L \T1ES' COf'Ir1\SSION
Attorneys for Micron Technology, Inc.
S:\CLIENTS\4489\17\Micron Rsp to IPC 1st Disc Req,DOC
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICA nON
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS INTERIM
AND BASE RATES AND CHARGES FOR
ELECTRIC SERVCE.
Case No. IPC-03-
MICRON TECHNOLOGY, INc.'
RESPONSES TO IDAHO POWER
COMP ANY'S FIRST
INTERROGATORIES AND
PRODUCTION REQUEST
COMES NOW Micron Technology, Inc., by and through its attorneys of record, Givens
Pursley LLP, and hereby responds to Idaho Power Company s First Interrogatories and
Production Request to Micron Technology, Inc. as follows:
REQUEST NO. I: Please provide copies of any testimony and exhibits Dr. Peseau has
filed with any utility regulatory agency or public utility commission during 2000-2003 in which
Dr. Peseau discusses utility rate of return.
RESPONSE: Please see the documents attached hereto as Exhibit A.
OR\G\NAl
MICRON TECHNOLOGY, INc.'S ANSWERS AND RESPONSES TO IDAHO POWER COMPANY'
FIRST INTERROGATORIES AND PRODUCTION REQUEST -
REQUEST NO.2: Please provide Dr. Peseau s supporting documentation for the
revenue growth rate of 4.06% assumed on page 6 of Dr. Peseau s testimony. If this supporting
information is contained in an exhibit or work papers, please specify the location of such data by
page and line.
RESPONSE: Please see the documents attached hereto as Exhibit B.
DATED this 11 th day of March 2004,
UJ t'lv..
Conley E.
GIVENS PURSLEY LLP
Attorneys for Micron Technology, Inc.
MICRON TECHNOLOGY, INc.'S ANSWERS AND RESPONSES TO IDAHO POWER COMPANY'
FIRST INTERROGATORIES AND PRODUCTION REQUEST - 2
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 11th day of March 2004, I caused to be served a true
and correct copy of the foregoing by the method indicated below, and addressed to the following:
Jean Jewell
Idaho Public Utilities Commission
472 W. Washington Street
O. Box 83720
Boise, ID 83720-0074
Lisa Nordstrom
Weldon Stutzman
Deputy Attorney Generals
Idaho Public Utilities Commission
472 W. Washington Street
O. Box 83720
Boise, ID 83720-0074
S. Mail
Hand Delivered
Overnight Mail
Facsimile
Mail
S. Mail
Hand Delivered
Overnight Mail
Facsimile
Mail
u.S. Mail
Hand Delivered
Overnight Mail
Facsimile
Mail
S. Mail
Hand Delivered
Overnight Mail
Facsimile
Mail
Barton L. Kline
Monica B. Moen
Idaho Power Company
O. Box 70
Boise, ID 83707
John R. Gale
Vice President Regulatory Affairs
Idaho Power Company
O. Box 70
Boise, ID 83707
Peter 1. Richardson
Richardson & O'Leary
99 E. State Street, Ste. 200
O. Box 1849
Eagle, ID 83616
u.S. Mail
Hand Delivered
Overnight Mail
Facsimile
Mail
Don Reading
Ben Johnson Associates
6070 Hill Road
Boise, ID 83703
S. Mail
Hand Delivered
Overnight Mail
Facsimile
Mail
MICRON TECHNOLOGY, INc.'S ANSWERS AND RESPONSES TO IDAHO POWER COMPANY'
FIRST INTERROGATORIES AND PRODUCTION REQUEST -
Randall C. Budge u.S. Mail
Eric L. Olsen Hand Delivered
Racine, Olson, Nye, Budge, Bailey Overnight Mail
201 E. Center Facsimile
O. Box 1391 Mail
Pocatello, ID 83204-1391
Anthony Yankel S. Mail
29814 Lake Road Hand Delivered
Bay Village, OH 44140 Overnight Mail
Facsimile
Mail
Lawrence A. Gollomp S. Mail
Assistant General Counsel Hand Delivered
S. Department of Energy Overnight Mail
1000 Independence Ave. SW Facsimile
Washington, DC 20585 Mail
Dennis Goins S. Mail
Potomac Management Group Hand Delivered
5801 Westchester Street Overnight Mail
Alexandria, VA 22310-1149 Facsimile
Mail
Dean J. Miller S. Mail
McDevitt & Miller Hand Delivered
420 W. Bannock Street Overnight Mail
O. Box 2564 Facsimile
Boise, ID 83701 Mail
Jeremiah J. Healy u.S. Mail
United Water Idaho Inc.Hand Delivered
8248 W. Victory Road Overnight Mail
O. Box 190420 Facsimile
Boise, ID 83719-0420 Mail
William M. Eddie S. Mail
Advocates for the West Hand Delivered
1320 W. Franklin Street Overnight Mail
O. Box 1612 Facsimile
Boise, ID 83701 Mail
MICRON TECHNOLOGY, INc.'S ANSWERS AND RESPONSES TO IDAHO POWER COMPANY'
FIRST INTERROGATORIES AND PRODUCTION REQUEST - 4
Nancy Hirsh u.S. Mail
NW Energy Coalition Hand Delivered
219 First Ave. South, Ste. 100 Overnight Mail
Seattle, W A 98104 Facsimile
Mail
Dennis E. Peseau, Ph.S. Mail
Utility Resources, Inc.Hand Delivered
1500 Liberty Street SE, Ste. 250 Overnight Mail
Salem, OR 97302 Facsimile
Mail
Brad M. Purdy S. Mail
Attorney at Law Hand Delivered
2019 N. 1 ih Street Overnight Mail
Boise, ID 83702 Facsimile
Mail
Michael Karp S. Mail
147 Appaloosa Lane Hand Delivered
Bellingham, W A 98229 Overnight Mail
Facsimile
Mail
Michael L. Kurtz S. Mail
Kurt J. Boehm Hand Delivered
Boehm, Kurtz & Lowry Overnight Mail
36 E. Seventh Street, Ste. 2110 Facsimile
Cincinnati, OH 45202 Mail
Thomas M. Power S. Mail
Economics Department Hand Delivered
Liberal Arts Building 407 Overnight Mail
University of Montana Facsimile
32 Campus Drive Mail
Missoula, MT 59812
MICRON TECHNOLOGY, INc.'S ANSWERS AND RESPONSES TO IDAHO POWER COMPANY'
FIRST INTERROGATORIES AND PRODUCTION REQUEST - 5
EXHIBIT A
In the fall of 2000 Dr. Peseau prepared a cost of capital study for Edgewood
Water Company in Lake Tahoe , Nevada , Docket No. 00-8036. This case was
eventually settled by stipulation. There is no record in files that actual pre-
filed rate of return testimony was ever filed by Dr. Peseau.
Enclosed is Dr. Peseau s prefiled testimony in:
Nevada Docket No. 01-1002
Nevada Docket No. 01-10001
Nevada Docket No. 03-10001
Hale Lane et al 141 00203/10/04 10: 11 FAX [phone]
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BEFORE TijE PUBLIC SERVICE COMMISSION OFtNEVAtW i
g~
t9;:~UIS$tGU!N CITy
; ,
C2 JAN 22 M'fl/: ~ 5
In Re Application ofNEV ADAr POWER
COMPANY fur arnhority to md~~e
annual revenue requirement for~genera1 rates
charged to all cl~ses of electric customers
and for relief properly related ~~reto.
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Docket No.: 01-10002
Docket No.: 01-10001
In Re Application ofNEV AD~ POWER
7 COMPANY for approval of new and
revised depreciation rates.
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PREPARED TESTIMONY OF.
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DENNIS E. PESEAU
Submitted by:
Fred Schmidt
Hale Lane Peek Dennison Howard and Anderson
777 E. William, Suite 200
Carson City, Nevada 89701
Attorney for
SOUTHERN NEVADA WATER AUTIIORITY
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03/10/04 10: 12 FAX [phone] Hale Lane et al .. PESEAU
~ Docket No. 01-10001
Tf1~timony of Dennis E. Peseau
on behalf 0
re Southern Nevada Water
Authority
I Ire: PhrIse I - Cost of Capital Issues
I i: January 22 , 2002
PLEAS E S1 A 1E Y~~R NAME AND BUSINESS ADDRESS.
My name is Dennis E. Peseau, My business address is Suite 250, 1500
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Liberty Street, S., ~+Iem, Oregon 97302,
BY WHOM AND IN HAT CAP AC ITV ARE YOU EMPLOYED?
I am President of utill~ Resources , Inc. My firm consults on a number of
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economiC, InanCla ii engineerIng ma ers or varIous pnva e an pu
entities,
I ~DOES YOUR A T
1tCHMENT
1 ACCURATELY DESCRIBE YOUR
BACKGROUND AND! EXPERIENCE?
Yes.
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ON WHOSE BEHAL I ARE YOU TESTIFYING IN THIS PROCEEDING?
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I am testifying on beh61f of the Southern Nevada Water Authority~
WHAT IS THE PURP~SE OF YOUR DIRECT TESTIMONY?
These proceedings, ~ocket No. 01-10001; provide for a number of distinct
issues with different dates set for the filing of testimony and hearing of each
issue. The subject ofjthis testimony is the general issue of Nevada Power's
cost of capital, as set fprth in the November 2001 prehearing conference. The
purpose of my testim:ony here is to focus on but two of the several issues
potentially involved in determining an overall weighted cost of capital: the
appropriate rate of re~urn to be granted on Nevada Power's common equity
! .
(referred hereinafter ~s "ROE") and the appropriate capital structure to adopt
for weighting the costs of debt, preferred and common equity. For purposes
of the record in these proceedings, the SNWA takes no specific position on the
methods used to com:pute the costs of debt and preferred stock.
The capital structure issue I raise pertains to a very important deferred
taxes issue here that has implications for cost of capital, revenue requirement
:j.
and the deferred energy proceedings. Both the ROE and the capital structure
issues are doubly i~portant because they affect not only the revenue
requirement set in thlse proceedings , but also the huge carrying charges
being sought in the reJently filed deferred energy proceedings, Docket No. 01-
11029. If an ROE aJ excessive at that proposed by Nevada Power in this
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docket is used in setting the rate of return, and that rate of return is adopted
as the carrying charge in the deferred docket, customers will pay significant
amounts of excess profits for the next several years.
WHA T CONCLUSIONS HAVE YOU REACHED WITH RESPECT TO AN
APPROPRIATE ROE AND CAPITAL STRUCTURE FOR NEVADA POWER
IN THESE PROCEEDINGS?
I conclude that:
The present fair and reasonable ROE for Nevada Power is 10.5%, not
the 12.25% requested by the Company. This ROE, the capital
structure I propose, and other capital costs result in an overall cost of
capital of 8.47%.
The appropriate and most reflective capital structure in this case for
purposes of setting rates is 40% common equity, 6.5% preferred equity
and 53.5% debt.
The level of $325 million of deferred taxes associated with the deferred
energy cost balances must be included either as a zero cost capital
component in the capital structure, or be used to reduce carrying costs
on the deferred energy balances.
DO YOUR COST OF CAPITAL RECOMMENDATIONS HAVE AN IMPACT
NEV ADA POWER'REVENUECERTIFICATIONFILING
REQUIREMENT REQUEST OF $22.7 MilLION?
Yes, each of these two adjustments reduces Nevada Power's revenue
requirement recommendation:
Hale Lane et al ~00603/10/04 10: 13 FAX [phone]
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My recommended ROE reduction to 10.5% reduces Nevada Power
Certification filing revenue requirement by $ 24.8 million.
My recommended reduction in the equity from 42.59% to 40% reduces
Nevada Power s revenue requirement by an additional $ 2.7 million.
Including the zero cost capital derived from the deferred taxes on the
deferred energy balances results in an overall weighted cost of capital
of 7.73%.
RATE OF RETURN ON COMMON EQUITY
WHAT GENERAL APPROACH HAVE YOU FOLLOWED IN DETERMINING
APPROPRIATE ESTIMATES OF NEVADA POWER'S FAIR RATE
RETURN ON COMMON EQUITY IN THESE PROCEEDINGS?
I expect, given the importance of this issue, that there will be a number of
other parties developing testimony and exhibits on this issue. Therefore,
rather than my developing an entirely independent analysis of this issue, I
have chosen to follow Nevada Power witness Dr. Morin s methods as closely
as possible. I do so in order to demonstrate that just a few key updates and
more relevant samples of comparable companies result in significantly lower
estimates of Nevada Power s required return on common equity.
WHAT METHODS HAVE YOU USED TO ESTIMATE NEVADA POWER'
COST OF COMMON EQUITY?
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Hale Lane et al 14100703/10/04 10: 13 FAX [phone] .. PESEAU
On pages 4 and 5 of Dr. Morin s prefiled testimony, he explains that he used
two versions of the Capital Asset Pricing Model (the "CAPM" and "ECAPM"
Risk Premium and Discounted Cash Flow ("DCFn) methods. Again , I use each
of these same methods below with minimal modifications so as to draw
attention to the major and , in my opinion faulty assumptions in Dr. Morin
analysis.
GENERALLY, WHAT ARE THE FAULTY ASSUMPTIONS USED IN DR.
MORIN'S TESTIMONY?
Three principal assumptions used by Dr. Morin have the result of exaggerating
the estimated return on equity (ROE) for Nevada Power:
(1 )The sample of companies selected by Dr. Morin and used by him to
compare to Nevada Power is unrepresentative of the risks in the
electric utility industry. The sample is comprised of entities having
considerable business operations in unregulated markets and, in some
instances, no involvement in providing electric utility services.
(2)The estimate of dividend growth rates in Dr. Morin s DCF model is
considerably higher than expected by investors and financial analysts.
The DCF dividend growth estimates used by Dr. Morin are based solely
03/10/04 10: 13 FAX [phone] Hale Lane et al .. PESEAU 141 008
on growth rates for earnings per share and do not account for slower
near-term dividend growth.
(3)The estimate of the level of market risk ("beta ) for Nevada Power in Dr.
Morin s CAPM and ECAPM analyses is much higher than is
representative of the electric utility industry. In estimating market risk
or beta, Dr. Morin ignores published beta estimates specific to the
electric utility companies and instead selects betas for oil and gas
exploration and production companies, betas for"interstate natural gas
pipelines and betas for natural gas distribution companies.
In my analyses , I use Dr. Morin s methods, but with assumptions
specific to and appropriate for electric utilities. In a couple of instances, I make
" '"
minor updating adjustments to Dr. Morin s data. These changes result in a
range of ROE estimates for Nevada Power of 9.5%11.0%. Each of the three
methods used by Dr. Morin is separately discussed below.
DISCOUNTED CASH FLOW METHOD:
HAVE YOU REVIEWED DR. MORIN'S DCF EQUITY COST ESTIMATES
FOR ELECTRIC UTILITIES?
Yes. Dr. Morin prepared discounted cash flow ("DCF") estimates of the cost
of equity for a .sample of Moody s electric utilities (Exhibit RAM-5) and a
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sample of 32 vertically integrated electric utilities (Exhibit RAM-6) and found
the cost of equity fell within a range of 12.1 % to 13.3%.
HAVE YOU PREPARED MORE REALISTIC DCF ESTIMATES OF THE
COST OF EQUITY FOR THOSE TWO SAMPLES OF ELECTRIC UTILITIES?
Yes. I have prepared two DCF estimates of the cost of equity that are based
on those samples and data reported by Dr. Morin. In preparing my DCF equity
cost estimates , I revised Dr, Morin s estimates by making two changes but in
all other respects have adopted Dr. Morin s \Cimples, earnings per share
EPS") growth forecasts and dividend yields. The changes I have made are
(1) I have limited companies in the samples to those that had at least 70% of
their revenues from electric operations and (2) I have recognized that investors
expect near-term growth in dividends per share (!l OPS") to be slower than
growth in EPS. To make the revisions, I have relied upon data on the
percentage of electric revenues reported by C. A. Turner Utility Reports for
November 2001 and Value Line forecasts of near-term growth in dividends per
share.
WHA T ARE THE RESULTS OF YOUR ANALYSES?
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Based on Dr. Morin s samples and data and the additional data from C. A.
Turner Utility Reports and Value Line I find the cost of equity for an electric
utility falls in a range of 10.3% to 11.0%.
PLEASE EXPLAIN THE DCF METHOD OF ESTIMATING THE COST OF
EQUITY.
The constant growth DCF model computes the cost of equity as the sum of an
expected dividend yield ("/PO ) and expected dividend growth ("). The
expected dividend yield is computed as the ratio of next period's expected
dividend ("0/') divided by the current stock price (U ). Generally, the constant
growth model is computed with formula (1) or (2):
(1 )
(2)
Equity Cost DoIPo x (1 + g) + 9
Equity Cost D/P + 9
where DalPo is the current dividend yield and JPo is found by increasing the
current yield by the growth rate.Dr. Morin relies upon this constant growth
model to make his DCF equity cost estimates and assumes estimates of EPS
growth provide a useful measure of DPS growth required in the model.
ARE THERE PROBLEMS WITH HIS APPROACH?
Yes. The constant growth DCF model is derived from the valuation model
shown in equation 3 below:
03/10/04 10: 14 FAX [phone],"-Hale Lane et al 141 011.. PESEAU
(3)D/(1+k) + Di(1+k)2 + . . . + OJ(1+k)"',
, alternatively,
(3A)D/(1+k) + DJ(1+k)2 + Oi(1+k)3 + (04 + P )! (1+k)4
where k is the cost of equity; Po is the stock price paid today, 01, 021 . . . 0- are
the cash flows expected to be received in periods 1 , 2, . . . 00, respectively; and
P 4 is the price the investor expects to receive at the end of period number "
(be it a sale price or the price offered in merger). Dividends (0" O2, . . . etc.
are all assumed to grow at the same rate of 1 +g in air periods. Thus in any
period "" the dividend in the next period (IC n+111) can be determined by the
formula On+1 = On X (1 +g).
While EPS growth may provide a useful approximation of average DPS
growth for some industries, at this time, forecasted EPS growth will overstate
average DPS growth expected by investors for electric utilities. As a result, Dr.
Morin s sale reliance on EPS growth to make his DCF equity cost estimates will
overstate the cost of equity for a typical electric utility.
WHY IS THAT THE CASE?
, ,
Available evidence discussed below indicates investors expect DPS growth to
be slower than EPS growth for the next. several years, Investors are aware
that many electric utilities have been and will attempt to improve their financial
strength by cutting dividends or holding back on increases in dividends.
Hale Lane et a1 14101203/10/04 10: 14 FAX [phone] .. PESEAU
Investors also have access to Value Line forecasts of DPS growth which show
DPS growth for most electric utilities is expected to be slower than EPS growth
for the next several years. As a result, Dr. Morin s assumption that investors
expect electric utilities to have the same growth in DPS in the next few years
as the growth in EPS is not realistic. Even if investors expect EPS growth
reported by Dr. Morin to materialize, they would not assume such growth will
occur in DPS until some time in the future.
The DCF model says the price an investor pays for a share of stock is '
based on expected future cash flows. Near-term, those cash flows are from
DPS , not EPS.
ARE THERE FORECASTS OF DPS GROWTH THAT ARE READILY
AVAILABLE TO INVESTORS?
Yes. Value Line, one of the sources of data Dr. Morin relies upon in his DCF
analysis presents DPS forecasts as well as EPS forecasts. In my restatement
of Dr. Morin s equity cost estimates, I use the Value Line forecasts of DPS for
the years they are available and use Dr. Morin s forecasts of EPS growth for
years that follow. To make the analysis, I use the equivalent of equation (3A)
above, the Value Line forecasts of DPS growth to determine expected
dividends for the next five years (011 O2, . . .etc) , then I apply Dr. Morin
forecasts of EPS growth to determine future growth and solve for the value of
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the cost of equity (k). The lower DPS growth rates predicted by the investment
community reflect the capital needs of electric utilities today in coping with
changes caused by deregulation and volatile electric markets. Analysts call this
DCF approach a two-stage DCF model because it is based upon 2 different
growth rates.
HAVE YOU MADE ANY OTHER CORRECTIONS TO DR. MORIN'
CALCULATIONS?
Yes. A. Turner Utility Reports lists the percentage of electric revenues for
each of the companies Dr. Morin has used in the samples of companies he
reports in Exhibits RAM-5 and RAM-6. I have revised those samples to include
only those companies that have at least 70% electric revenues. This screen
eliminates those companies with significant unregulated operating revenues.
WHAT ARE SOME OF THE SPECIFIC COMPANIES CONTAINED IN DR.
MORIN'S SAMPLES THAT ARE NOT REPRESENTATIVE OF THE RISK
AND ROES OF ELECTRIC UTILITIES?
Four of those companies are PPL Corporation , aGE Energy, Reliant Energy
and TECO Energy. PPL Corporation is heavily involved in wholesale power
markets and C. A. Turner Utility Reports lists its percentage of electric,revenues
at 59%.Value Line states that PPL Corporation s regulated Pennsylvania
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03/10/04 10: 15 FAX [phone] Hale Lane et al .. PESEAU ~014
distribution business will likely generate but 5% of corporate profits next year.
OGE Energy is a holding company that C. A. Turner Utility Reports states has
revenues from sales of electricity of but 40%. OGE Energy s subsidiary,
Enogex, produces natural gas liquids that Value Une reports has increased
aGE's risk in recent periods. OGE Energy s Transok is a gatherer, processor
and transporter of natural gas. Investors would take the risk of those business
activities into account when pricing aGE Energy s stock. Reliant Energy was
also include in Dr. Morin s sample. C. A. Turner Utility Reports lists its
percentage of electric revenues at just 14%. Reliant has an 80% interest in
Reliant Resources, a subsidiary that is in the process of purchasing Orion
Power, an independent power producer. It has interstate pipelines and
,....
operations in Europe and Latin America. Value Une reports Reliant Energy is
in the process of spinning off some non-regulated businesses. TECO Energy
has also been included by Dr. Morin. It is a holding company for Tampa
Electric but also mines coal, develops unregulated power projects, is involved
with coal-bed methane-gas production and owns real estate. C. A. Turner
Utility Reports lists its revenues from electric operations at 60%.
At Exhibit RAM-5 page 1 , Dr. Morin reports his estimates of the costs of
equity for these four companies. The average of those equity cost estimates
is 14.0%. By including these companies with relatively small percentages of
revenues from electric utility operations, Dr. Morin increases his average
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03/10/04 10: 15 FAX [phone] Hale Lane et al ~015.. PESEAU
estimate of the cost of equity underlying his recommended return for Nevada
Power. The risks and required returns for these companies are not indicative
of traditional electric utility operations and should not be included in such an
average.
WHERE DO YOU REPORT THE REVISED SAMPLES AND DATA YOU
HAVE USED IN YOUR ANALYSIS?
Those data are reported in Exhibit DP-1 and Exhibit DP-Exhibit DP-
reports the electric utilities in Moody s sample that have at least 70% of their
revenues from electric operations as well as the Value Line forecasts of near-
term DPS growth. Exhibit DP-2 shows the same information for the vertically
integrated electric utilities that pass the percentage of electric revenues screen
and the DPS growth forecasts.
WHERE DO YOU REPORT THE RESULTS OF REVISING DR. MORIN'S DCF
ANALYSES FOR THE ELECTRIC UTILITIES?
The revised equity cost estimates of 10.33% for the sample in Exhibit RAM'-5
and 10.96% for the sample shown in Exhibit RAM-6 are shown in Exhibit DP-
Also, Exhibit DP-3 shows that investors would expect, on average, growth in
1 Excelon passes the revenue percentage filter but is not included in either sample because
Value Line does not provide forecasts of either DPS or EPS for the company.
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the range of 5.5% to 5.9% (see line 7 of Exhibit DP-3) instead of growth of
5% to 6.8% (see line 6 of Exhibit DP-3) implied by Dr. Morin s approach.
DR. MORIN ALSO RELIES UPON DCF EQUITY COSTS FOR NA JURAL
GAS DISTRIBUTION UTILITIES.HAVE YOU REVISED THOSE
ESTIMA TES?
Yes. In Exhibit RAM-7 Dr. Morin uses the data for the natural gas distribution
companies to make other astimates of the cost of equity he believes are
relevant for Nevada Power. His equity cost estimates for these unrelated
companies fall in a range of 12.5% to 15.4%. I do not agree that a sample of
gas distribution companies should be relied upon to determine Nevada Powers
cost of equity. I have, however, revised Dr. Morin s DCF equity cost estimates
for that sample of utilities and find it also supports my recommended ROE. I
have revised his analysis by recognizing near-term growth in DPS and requiring
that a company have at least 70% of its revenues from gas operations to be
included in the sample. With those two changes and Dr. Morin s data, I find a
cost of equity of 10.8%.
WHERE DO YOU PRESENT THIS ANALYSIS?
Exhibit DP-4 shows the natural gas distribution companies that pass the
percentage of revenues screen and the Value Line forecasts of near-term DPS
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growth. Exhibit DP-5 shows the DCF analysis and derivation ofthe 10.8% cost
of equity estimate.
CAPITAL ASSET PRICING MODEL AND RISK PREMIUM STUDIES
HAVE YOU ALSO REVIEWED DR. MORIN'S CAPM AND OTHER RISK
PREMIUM STUDIES?
Yes. Dr. Morin presents equity costs based on two versions of the capital asset
pricing model (CAPM and ECAPM) and two historical risk premium studies and
one study based on differences in authorized ROEs and interest rates. Based
on those five studies, he estimates the cost of equity for an electric utility falls
in a range of 10.8% to 11.6%.
HAVE YOU CORRECTED AND REVISED HIS ESTIMATES TO BE MORE
APPROPRIATE?
Yes , I have. Based on my revisions and corrections, the cost of equity implied
by the approaches Dr. Morin has presented falls in a range of 9.5% to 10.9%.
WHAT IS THE PRIMARY PROBLEM WITH HIS CAPM APPROACHES?
The primary problem is the beta estimate he has constructed. There are readily
available estimates of betas for the electric utilities. If investors are concerned
with the issues Dr. Morin raises at pages 19-21 of his prefiled testimony, the
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03/10/04 10: 16 FAX [phone] Hale Lane et a1 .. PESEAU 141 018
concerns would already be reflected in market data and revealed in the
estimated betas. Exhibit DP-6 shows the Value Line betas that are available
and an average of those betas for the 32 vertically integrated electric utility
companies he has relied upon in his Exhibit RAM-6. The average beta is .
and no beta is larger than .65. Such direct measures of beta are totally
inconsistent with the beta of.7 Dr. Morin uses in his CAPM analyses
HAVE YOU MADE ANY OTHER CHANGES IN YOUR REVISIONS OF HIS
CAPM ANALYSES?
Yes. At page 24 of his testimony, Dr. Morin averages together a market risk
premium ("MRP") of 7.3% he derives from data published by Ibbotson
I I Associates and a MRP of 7.7% that he estimates to determine his MRP of
5%. Table 9-2 of Ibbotson Associates 2001 Yearbook reports a MRP of large
company stocks minus long-term Treasury income returns of7., not 7.3%.
For purposes of my restatement of Dr. Morin CAPM analyses, I have
averaged together the 7.8% reported by Ibbotson Associates and Dr. Morin
other estimate of the MRP of 7.7%. Thus , for my revision and update I have
used a value of 7.8% for the MRP instead of the 7.5% adopted by Dr. Morin.
2 The average beta for the vertically integrated electric utilities I presented in Exhibit DP-2 is
also .52.
16-
Hale Lane et al 141 01903/10/04 10: 16 FAX [phone]
.L.
.. PESEAU
WHAT CONCEPT HAS DR. MORIN CHOSEN TO CALCULA TE THE
MARKET RISK PREMIUM?
The market risk premium used by Dr. Morin from the Ibbotson Associates' study
is an "arithmetic mean" of historical market risk premiums.
IS THERE SOME DEBATE IN FINANCIAL LITERATURE AS TO WHETHER
THE ARITHMETIC MEAN IS THE BEST ESTIMATOR OF FORWARD
LOOKING MARKET RISK PREMIUMS?
Yes. While, for the sake of remaining as close as possible to -Dr. Morin
approach I simply adopt his arithmetic mean calculation of the market risk
premium , I note that a large body of literature exists that debates the merits of
using a geometric mean, an arithmetic mean or some weighted average of the
two in calculating the market risk premium here. I also note that of the various
methods of computing the market risk premium , the arithmetic mean method
produces the highest estimate of this premium. I take no position here and
instead use the arithmetic mean used by Dr. Morin.
Also , in response to BCP 2-17 Supplemental, Dr. Morin indicated he
relied upon the yield on 30-year Treasury bonds as a proxy for the risk-free
rate. At the time he performed his study in the fall of 2001 that rate was 5.
which Dr. Morin used in his study. At the present time , the yield on 30-year
Treasury securities is approximately 5.4%. The more recent 5.4% yield is used
here to update Dr. Morin s risk premium analyses.
17-
Hale Lane et a1 141 02003/10/04 10: 17 FAX [phone]
J 1
.. PESEAU
WHAT IS YOUR UPDATE AND REVISION OF DR. MORIN'S ESTIMATE OF
THE COST OF EQUITY MADE WITH THE TRADITIONAL CAPM?
At page 270f his prefiled testimony, Dr. Morin provides his equity cost estimate
of 10.8% made with the traditional model; it was found as 5.5% + .70 x 7.
= 10.8%. With my revised value for RF, beta and the MRP, the revised and
updated CAPM estimate is 5.4% + .52 x 7.8% = 9.5%.
WHAT IS YOUR UPDATE AND REVISION OF DR. MORIN'S ESTIMATE OF
THE COST OF EQUITY MADE WITH THE MODEL HE CALLS THE ECAPM?
Atthe bottom of page 27, Dr. Morin presents the formula of the ECAPM and his
estimate of the cost of equity of 11.3%. Substituting my update of the RF
5.4% and estimates of the beta of .52 and MRP of 7.8% in the formula
displayed at page 27 of Dr. Morin s testimony, my update and revision of the
ECAPM is 10.4%.
HAVE YOU REVISED AND UPDATED HIS HISTORICAL RISK PREMIUM
ANALYSIS BASED ON DATA FOR THE ELECTRIC UTILIITES?
Yes. Dr. Morin presents his analysis at page 28 of his testimony. I have made
one conceptual change and updated the RF to revise his estimate of 11.1 %.
The conceptual change is that I have computed risk premiums using the
method presented by Ibbotson Associates in Table 9-2 of the 2001 SBBI
18-
Hale Lane et al ~00203/10/04 10: 18 FAX [phone]
'-rl"
.. PESEAU
Yearbook that I discussed above. I have also updated the RF to 5.4%. In the
case of the electric utility study, the estimate average risk premium remains at
6% and thus the updated risk premium is 5.4% + 5.6% = 11,0%. I have
attached the results of my updated and revised analysis as Exhibit DP-
HAVE YOU CORRECTED, REVISED AND UPDATED DR. MORIN'
HISTORICAL RISK PREMIUM ANALYSIS BASED ON DATA FOR THE
NATURAL GAS DISTRIBUTION INDUSTRY?
Yes, I have revised the study but recommend it be given very little weight in the
consideration of the cost aT equity of an electric utility. Dr. Morin presents his
study at page 31 of his testimony. Based on his analysis, the average risk
premium is 6.1 % and the equity cost estimate is 11.6%. In making my revision
I have used corrected data for dividends that are consistent with data Dr. Morin
used in his risk premium analysis for the electric utilities and have again made
a conceptual change to compute risk premiums as the difference between total
returns on stocks and income returns for Treasury securities as is done by
Ibbotson Associates. With the correction, revision and the updated RF r the
historical risk premium study for the natural gas distribution companies implies
an equity cost of 5.4% + 5.5% = 10.9%. I have attached the results of my
analysis as Exhibit DP-
19-
Hale Lane et al 14100303/10/04 10: 19 FAX [phone]
-..i.
.. PESEAU
DID YOU ALSO UPDATE DR. MORIN'S RISK PREMIUM STUDY BASED ON
AUTHORIZED ROE'S FOR ELECTRIC UTILITIES?
Yes. Dr. Morin describes his study at pages 32-34. Based on the regression
results he presents at page 33 and a value for RF of 5.5%, he estimates a risk
premium of 5.4% and a cost of equity of 10.9%. With my updated RF of 5.4%
and his regression results, the implied cost of equity is 10.8%.
PLEASE SUMMARIZE YOUR DCF AND RISK PREMIUM ESTIMATES OF
THE COST OF EQUITY FOR A TYPICAL ELECTRICAL UTILITY.
I have prepared such a summary in Exhibit DP-9. My updates and revisions of
Dr.' Morin s risk premium estimates fall within a range of 9.5% to 11.0%. My
updates and revisions of his DCF equity cost estimates fall within a range of
10.3% to 11.0%. I conclude that a fair and reasonable rate of return on Nevada
Power's common equity in these proceedings is 10.
SNWA PROPOSED CAPITAL STRUCTURE FOR NEVADA POWER
--,
WHAT IS THE ISSUE WITH RESPECT TO THE NEVADA POWER CAPITAL
STRUCTURE TO BE USED FOR RA TEMAKING PURPOSES?
The capital structure , or percentage of debt, equity or other sources of capital
determined in these proceedings will be used to weight the respective costs of
each source of capital in computing a final overall weighted cost of capital.
20-
Hale Lane et al 141 00403/10/04 10: 19 FAX [phone]
'T1
.. PESEAU
In Nevada Power s Statement F, Pages 1 and 2 of 2, both May 31 2001
ending and pro forma September 30 2001 capital structures are summarized.
In its Certification filing, Schedule F, the Company summarizes its actual
September 30, 2001 capital structure. Because of the importance of the
percentage of common equity, or "equity ratio" used for weighting purposes in
the capital structure, I focus on the changes proposed by Nevada Power.
PLEASE EXPLAIN THE CHANGES TO THE EQUITY RATIO CONTAINED IN
NEVADA POWER'S ORIGINAL AND CERTIFICATION FILING.
The Company reports equity ratios of 32.36% and 42.59% in its Schedule F
page 2 of 2 and its Certification Schedule F page 1 of 1 , respectively.
WHAT OVERALL WEIGHTED COST OF CAPITAL DOES NEVADA POWER
PROPOSE BE USED FOR RA TEMAKING PURPOSES IN THESE
PROCEEDINGS?
The Company proposes that the Commission adopt the figure of 9.30%.
WHAT IS THE BASIS FOR THE COMPANY RAISING ITS ESTIMATE OF IT5
COMMON EQUITY RATIO FROM 32.36% AS OF MAY 31, 2001 TO 42.59%
AS OF SEPTEMBER 30, 2001?
As explained in the direct testimony of Nevada Power witness Mr. Atkinson
Page 9, Sierra Pacific Resources , the parent, infused a common equity
21-
Hale Lane et al ~00503/10/04 10: 19 FAX [phone] .. PESEAU
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contribution to Nevada Power of approximated $340 million in the months of
August and September 2001. This infusion, later revised to $351 million, plus
estimated retained earnings of $112 million, raised its estimate of the common
equity ratio to 42.59%.
DO YOU AGREE THAT THE BEST ESTIMATE OF THE CAPITAL
STRUCTURE IN THESE PROCEEDINGS IS 42.59%?
No, not for ratemaking purposes. While Nevada Power is to be commended
for raising its common equity component of capital, the 42.59% is not likely to
represent a normal or actual capital structure for the Company.
WHY?
The 42.59% common equity ratio is unlikely to be representative for two
reasons: 1) Nevada Power and its parent SPR regularly transfer equity to and
from each other and , 2) Nevada Power is proposing a $258 million off-balance
sheet debt financing through its Contract Price Adjustment.
PLEASE EXPLAIN THE SIGNIFICANCE OF WHAT YOU CHARACTERIZE
, AS REGULAR TRANSFERS OF EQUITY BETWEEN NEVADA POWER AND
SPR.
22-
Hale Lane et al 141 00603/10/04 10: 20 FAX [phone] .. PESEAU,-----,,
-,-1
,----.
If equity is transferred regularly between parent and subsidiary, then equity
balances of Nevada Power at any single point in time may not be
representative of a normal or average equity ratio. In this case, SPR made a
substantial equity contribution at the end of the certification period which raised
the common equity ratio by more than 32%. If Nevada Power transfers equity
back to SPR, then this snapshot equity ratio will overstate a normal ratio for
ratemaking purposes, and the overall rate of return will be higher that it should
be. By contrast, a permanent issuance of common stock by a company not
wholly owned would not be subject to these equity ratio fluctuations, because
no 'such transfers could take place.
DO NEVADA POWER AND SPR REGULARLY TRANSFER EQUITY TO AND
FROM EACH OTHER?
Yes. Information provided by Nevada Power in financing applications and
responses to data requests shows regular equity transfers between the
Company and SPR. The response to data request BCP 2-, included here as
my Exhibit _(DEP-10) shows such recent transfers.
PLEASE ADDRESS YOUR CONCERN THAT THE PROPOSED CAPITAL
STRUCTURE DOES NOT REFLECT ADDITIONAL DEBT FROM THE
CONTRACT PRICE ADJUSTMENT.
23-
Hale Lane et al ~00703/10/04 10: 20 FAX [phone] .. PESEAU
'-..--
----l
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As further evidence that the snapshot capital structure proposed by Nevada
Power is not likely to be a normalized capital structure, I reference Mr.
Oldham s direct testimony regarding the Contract Price Adjustment. Nevada
Power Exhibit E-, Page 4 of 5, Line 18, shows that the Company is proposing
an off-balance sheet financing of $258 727 230, possibly up to $300 million , for
the Contract Price Adjustment
I do not propose to add this proposed debt financing into the capital
structure used for ratemaking purposes, I simply use this information to
demonstrate that the normalized capital structure for Nevada Power will have
a lower equity ratio than proposed by the Company.
WHAT CAPITAL STRUCTURE DO YOU RECOMMEND BE USED FOR
RA TEMAKING PURPOSES IN THESE PROCEEDINGS?
I conclude that percentages of 40%, 6.5% and 53.5% be adopted for common
equity, preferred equity and debt, respectively.
WHAT IS THE OVERALL WEIGHTED COST OF CAPITAL FOR NEVADA
POWER?
My 10.5% ROE recommendation and the other capital costs and capital
structure used by the Company result in an overall weighted cost of capital of
8.47%, on my Exhibit (DEP-11).
24-
Hale Lane et al 141 00803/10/04 10: 20 FAX [phone]"---'4 PESEAU
CAPITAL STRUCTURE AND DEFERRED TAXES IN DEFERRED ENERGY
WHAT IS THE ISSUE WITH RESPECT TO THE CAPITAL STRUCTURE AND
DEFERRED TAXES?
Under more typical ratemaking for deferred energy, there does not arise a
timing issue with respect to deferred taxes associated with energy cost
deferrals and ratemaking in general rate cases. However, the enormity of the
pending deferred energy balances , the level of associated deferred taxes and
the proposed three year amortization period gives rise to an important new
issue. This issue could be addressed in either the cost of capital or revenue
requirement phases of Docket No. 01-10001 , or in the pending deferred energy
Docket No. 01-11029. I raise this issue in this phase in order to alert the
Commission of the need to address this new, important issue.
PLEASE EXPLAIN.
Under previous deferred energy rate making, annual deferred energy cases and
relatively low DEAA positive or negative balances to be accounted for, the issue
of the timing and disposition of deferred energy-related deferred taxes was not
a very significant issue.
The issue is just how to account for a $ 325 million in deferred taxes that
are associated with the $ 922 million of deferred energy balances. This figure
of $ 325 million was taken from the Company s most recent 1 O-Q filed with the
25-
Hale Lane et a1 141 00903/10/04 10: 20 FAX [phone], \..-/,----,,.. PESEAU
SEC for the period ending September 30 , 2001. Due to the tax savings
realized by Nevada Power this year from these deferred taxes, the Company
will have had $ 325 million of zero cost capital at its disposal to use or to
otherwise offset the carrying costs of the $ 922 million deferral. This issue can
be addressed in either of two ways:
1. As an element in this phase s capital structure, with a $325 million
capital component at zero cost, or;
2. An offset to the total deferred energy balances for which carrying
charges are computed in the deferred energy docket.
The SNWA takes no position on whether this issue is most properly considered
here or in the deferred case, so long as customers receive due recognition for
this capital.
WHAT OVERALL WEIGHTED COST OF CAPITAL RESULTS FROM
INCLUDING DEFERRED TAXES AS AN ELEMENT OF THE COMPANY'
CAPITAL STRUCTURE IN THIS DOCKET?
The overall cost of capital becomes 7.73%, as shown in my Exhibt (DEP-12).
DOES THIS CONCLUDE YOUR DIRECT TESTIMONY ON THE ISSUE OF
COST OF CAPITAL?
Yes.
26-
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03/10/04 10: 22 FAX [phone] Hale Lane ~t al'--'
Exhibit DP-
Value Line Beta Estimates for Firms
in RAM-6 Sample
Full Screened
Sample Sample
1 Allegheny
2 Alliant
3 American Electric Pwr
4 Ameren
5 Cinergy
6 Gleco
7 Constellation
8 DPL, Inc
9 DTE
10 Dominion
1 Dynegy
12 Exelon
13 FPL Group 0.40 DAD
14 FirstEnergy
15 Hawiian Electric
----------
16 IDACORP
17 Great Plains Energy
18 NiSource 0.45
19 aGE 0.45
20 PPL Corp
21 Pinnacle West 0.45
22 Public Service Enter
23 RGS Energy
24 SCANA 0.45
25 Southern Go.
26 TECO Energy
27 TXU
28 UtiliCorp United
29 Vectren
30 WPS Resources
31 Wisconsin
32 Xcel Energy
Average
Maxium Beta
Morin s Beta
"--....-.
Source and notes:
Source: Value Line beta estimates as of 11/23/01.
al Screen is based on 70% or greater electric revenues as reported by
by Co A. Turner Utility Reoprts.
b! Value Line reports there is no meaningful figure for beta.
.. PESEAU (41015
03/10/04 10: 22 FAX [phone] Hale Lane et a1 .. PESEAU 141 016
Exhibit DP-
"---'
page 1 of 2
Risk Premium Analysis
Comparison of Returns on Moody s Electric Utility Stock Index
and Long-Term Treasury Securities
Moody
Long Electric
Term Utility Total
Treasury Stock Index Dividend Stock Risk
Yield Index c/ Dividend Gain/loss Yield Retum Premium
1931 07%43.
1932 15%39.42 81 %08%73%80%
1933 36%28.27.12%95%22.17%25.32%
1934 93%21.06'26.70%57%21.13%24.49%
1935 76%36.71.23%27%77.49%56%
1936 55%41.1.48 15.36%10%19.47%16.71 %
1937 73%24.41.73%18%37.55%40,10%
1938 52%27.13.66%19%19.84%17.11%
1939 26%28.1.48 72%37%10.09%57%
1940 94%22.22,98%34%17.64%19.90%
1941 04%13.45 39.47%6.48%32.99%34.93%
1942 2.46%14.25%37%15.61 %13.57%
1943 2.48%21.47,03%96%55.98%53.52%
1944 2.46%21.38%24%62%14%
"",,
1945 99%31.47.65%16%53.82%51.36%
1946 12%32.04%59%63%64%
1947 2.43%25.21.74%77%16.97%19.09%
1948 37%26.34%25%59%16%
1949 09%30.16.68%34%23.02%20.65%
1950 24%30.79%76%54%45%
1951 69%33.87%10%15.97%13.73%
1952 79%37.11.82%64%17.46%14.77%
1953 74%39.65%31%96%17%
1954 72%47.20.07%38%25.45%22.71%
1955 95%49.76%65%41%69%
1956 3.45%48.79%70%91%96%
1957 23%50.74%96%70%25%
1958 82%66.31,95%97%36.92%33,69%
1959 4.47%65.90%93%03%79%
1960 80%76.16.80%07%20.88%16.41%
1961 15%99.29.29%66%32.95%29.15%
1962 95%96.85%99%14%01 %
1963 17%102.03%33%36%41%
1964 23%115.3.43 12.93%35%16.28%12.11%
1965 50%114.59%34%75%1.48%
1966 55%105.72%58%14%64%
1967 56%98.36%09%26%81%
1968 98%104.96%58%10,54%98%
,-----"
1969 87%84.18.67%43%14.23%20.21 %
03/10/04 10: 22 FAX [phone] Hale Lane et al ... PESEAU 141017"----'
Exhibit DP- 7
Page 2
Moody
Long Electric
Term Utility Total
Treasury Stock Index Dividend Stock Risk
Yield Index c/ Dividend Gain/loss Yield Return Premium
1970 6.48%88.69%55%10.25%38%
1971 97%85.3.42%38%96%52%
1972 99%83.28%69%3.41 %56%
1973 26%60.27.20%99%21.21%27,20%
1974 60%41.32.36%93%24.43%31.69%
1975 05%55.35.20%12.07%47.27%39,67%
1976 21%66.290 19.10%31%28.40%20.35%
1977 03%68.87%36%11.22%01%
1978 98%59.12.38%52%86%11.89%
1979 10.12%56.41 59%10.41%82%16%
1980 11.99%54.42 '53%11.66%14%98%
1981 13.34%57.11%12,84%17.95%96%
1982 10.95%70.7.43 22.83%12.99%35.82%22.48%
1983 11 .97%72.52%11.20%13.72%77%
1984 11.70%80.11.29%11.47%22.75%10.78%
1985 56%94_18.49%10.74%29.23%17.53%
1986 89%113.19.67%36%29,03%19.47%
"---""
1987 20%94.17.09%02%06%16.95%
1988 18%100.11%9.41%16.52%32%
1989 16%122,21.38%74%30,12%20.94%
1990 44%117.88%17%30%-4.86%
1991 30%144.22.29%60%29.89%21.45%
1992 7.26%141.06%28%4.23%07% '
1993 54%146.00%37%10.37%11%
1994 99%115.21.27%11%15.16%21.70%
1995 03%142.23.72%81%31.53%23.54%
1996 73%136.-4.83%34%51%-4,52%
1997 02%155.14.51%66%21.17%14.44%
1998 5.42%181.44 16.51 %79%22.29%16.27%
1999 82%136.24.60%96%19.64%25.06%
2000 58%218.9.28 59.52%78%66.31%59.49%
Average Risk Premium 62%
Treasury Equity
Rate Cost
Equity Cost Estimate 5.40%11.
Sources and Notes:
a/ Table A-, Ibbotson Associates, SBBI 2001 Yearbook
b/ Computed
'----'"
cI Mergent. Moody s 2000 Public Utility Manual with updates from News Reports.
03/10/04 Hale Lane et al10: 23 FAX [phone]
Exhibit DP-
"'--""
Risk Premium Analysis
Comparison of Retums on Moodys Natural Gas Stock Index
and Long-Term Treasury SecuriUes
Moody
Long Gas
Term Utility Total
Treasury Stock Index Dividend Stock Risk
Yield Index cJ Dividend cJ Gain/loss Yield Return Premium
1954 72%26.
1955 95%26.16%99%11,14%42%
1956 45%28,1.43 46%09%55%60%
1957 23%25.1.49 68%28%3.40%85%
1958 82%38,50.16%93%56,09%52,86%
1959 47%39.27%21%6.48%66%
1960 80%48.21.77%52%26,29%21,82%
1961 15%64.34.74%96%38,71%34.91%
1962 95%59.05%09%-4.96%11%
1963 17%64.13 19%57%11.75%80%
1964 23%68,60%51%11%94%
1965 50%64,2.4 76%52%24%6.47%
1966 55%53,16,81%28%12.53%17.03%
1967 56%50,63%99%64%19%
1968 98%53,56%53%12,08%52%
1969 87%43,18,44%35%13.09%19.07%
1970 6.48%52.19.26%77%26,03%19.16%
1971 97%47,54%85%69%17%
1972 99%53,11,87%6.48%18.35%12.38%
1973 26%43.43 18.88%00%12.89%18.88%
1974 50%29,31.59%62%23,97%31,23%
1975 05%38,3.43 28.88%11.54%40.42%32,82%
1976 21%51,35,28%53%44.82%36,77%
1977 03%50,78%43%66%55%
,--
1978 98%45.65%00%-1,65%68%
1979 10.12%53,16,38%42%25.80%16.82%
1980 11.99%56,81%58%14.39%27%
1981 13,34%53.49%74%25%74%
1982 10.95%50,38%87%49%85%
1983 11.97%55,5.45 10.21%10.77%20.98%10.03%
1984 11,70%69.24,93%10,23%35.17%23.20%
1985 56%76.87%69%18,57%87%
1986 89%90.18.69%42%26,10%16,54%
1987 20%77.15,01%45%56%16,45%
1986 18%86,12.31%96%20.27%11.07%
1989 16%117,34:91%43%42.35%33,17%
1990 8.44%108.00%72%27%43%
1991 30%124.14.20%38%20.58%12,14%
1992 26%138,11.64%69%17.33%10.03%
1993 54%154.11.00%21%16.21%95%
1994 99%126.17.59%78%12.81%19.35%
1995 03%155.22,83%89%28.72%73%
1996 73%166,86%14%12.00%97%
1997 02%191.14,64%79%19.44%12.71%
199!!42%177.22%26%97%99%
1999 82%178.44%64%08%-0,34%
2000 58%219,23.50%62%28.12%21.30%
46%
Treasury Equity
Rate Cost
Equity Cost Estimate 5.40%10.
""----'"
Sources and Notes;
a! Table A-, Ibbotson Associates, SBBI 2001 Yearbook
b/ Computed
cJ Mergen!, Moody s 2000 Public Utility Manual with upclates from News Reports,
.. PESEAU ~018
03/10/04 10: 23 FAX [phone] Hale Lane et al .. PESEAU
Exhibit DP-
Summary of Updates and Revisions of
Dr. Morin s Equity Cost Estimates
Dr. Morin
Dr. Morin Estimated Revised and
Proposed Equity Updated
ROE Cost Equity Cost
Risk Premium Studies
CAPM 11.10.
ECAPM 11.11.10.4%
Historical RP-Electric Utilities ' 11.11.11.
'---/
Historical RP-Natural Gas Utilities 12.11.10.
Allowed Risk Premium- Electric 11.4%10.10.
Discounted Cash Flow
Moody s Electric Uilities
IBES growth 12.12.
Value Line Growth 13.12.
Average 12.4%10.
Vertically Integrated Electrics
IBES growth 12.12.4%
Value Line Growth 13.13.
Average 12.11.
Natural Gas Distribution Utilities
IBES growth 13.12.
Value Line Growth 15.4%15.4%
Average 14.10.
"--.,,/f4I 019
03/10/04 10: 23 FAX [phone] Hale Lane et al .. PESEAU 141020- '
Exhibit - (DEP-1 0)
'--"
NEVADA POWER COMPANY
RESPONSE TO INFORMATION REQUEST
DOCKET NO.01-10001 REQUEST DATE:10-12-
REQUEST NO.BCP 2-08 WITNESS:R. Atkinson
REQUESTER:BCP -RESPONDER:K. Langley
REQUEST:
Please provide a schedule showing all dividends paid to Sierra Pacific Resources by
Nevada Power, and all equity infusions by Sierra Pacific Resources into Nevada Power
fer the period 1998 to present
RESPONSE:
Dividends paid to SPR by NPC.
11/1/1999 $48M
2/112000 $24M
5/112000 $24M
8/1/2000 $24M
11/1/2000 $16M
9/112001 $33M
"-...
Equity Infusions by SPR Into NPC*
11/1/1999 $18M
2/112000 $14M
5/112000 $114M
8/112000 $9M
6/112001 $21.
8/1/2001 $260M
9/1/2001 $113M
(M = mil/ions)
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03/10/04 10: 24 FAX [phone] Hale Lane et a1 .. PESEAU ~023/' -
'. 1 -
Attachment 1
Page 1 of 3
"--../ '
STATEMENT OF OCCUPATIONAL AND
EDUCATIONAL HISTORY AND QUALIFICATIONS
DENNIS E. PESEAU
Dr. Peseau has conducted economic and financial studies for regulated
industries for the past twenty-eight years. In 1972, he was employed by Southern
California Edison Company as Associate Economic Analyst, and later as Economic
Analyst. His responsibilities included review of financial testimony, incremental cost
studies , rate design, econometric estimation of demand elasticities and various areas
in the field of energy and economic growth. Also, he was asked by Edison Electrical
Institute to study and evaluate several prominent energy models as part of the Ad
Hoc Committee on Economic Growth and Energy Pricing.
From 1974 to 1978, Dr. Peseau was employed by the Public Utility
Commissioner of Oregon as Senior Economist. There he conducted a number of
economic and financial studies and prepared testimony pertaining to public utilities.
In 1978 Dr. Peseau established the Northwest office of Zinder
Companies, Inc. He has since submitted testimony on economic and financial
matters before state regulatory commissions in Alaska, California, Idaho, Maryland
Minnesota, Montana, Nevada, Washington, Wyoming, the District of Columbia, the
Bonneville Power Administration and the Public Utilities Board of Alberta on over one
,,------,.
03/10/04 10: 24 FAX [phone] Hale Lane et al .., PESEAU 141 024" '
Attachment 1
Page 2 of 3
...........
hundred occasions. He has conducted marginal cost and rate design studies and
prepared testimony on these matters in Alaska , California , Idaho , Maryland
Minnesota, Nevada, Oregon, Washington and in the District of Columbia. He has
also conducted cost and rate studies regarding PURPA issues in the states
Alaska California, Idaho, Montana, Nevada, New York, Washington, and
Washington, D.
Dr. Peseau holds the B., M.A. and Ph.D. degrees in economics.
" He has co-authored a book in the field of industrial organization entitled
Size. Profits and Executive Comcensation in the Large Corcoration,which devotes
,----",
a chapter to regulated industries.
Dr. Peseau has published articles in the following professional journals:
Review of Economics and Statistics Atlantic Economic Journal Journal of Financial
Manaaement , and Journal of Reg ~mal Science. His articles have been read before
the Econometric Society, the Western Economic Association, the Financial
Management Association , the Regional Science Association and universities in the
United Kingdom as well as in the United States.
He has guest lectured on marginal costing methods in seminars in New
Jersey and California for the Center of Professional Advancement. He has also
guest lectured on cost of capital for the public utility industry before the Pacific Coast
'------' '
03/10/04 10: 25 FAX [phone] Hale Lane et al .. PESEAU 141 025
. 1
Attachment 1
Page 3 of 3
-......-
Gas and Electric Association , and for the Executive Seminar at the Colgate Darden
Graduate School of Business, University of Virginia.
Dr. Peseau and his firm have participated with and been members ofthe
American Economic Association , the American Financial Association , the Western
Economic Association, the Atlantic Economic Association and the Financial
Management Association. fie was formerly a member of the Staff Subcommittee on
Economics of the National Association of Regulatory Utility Commissioners.
Dr. Peseau has been President of Utility Resources, Inc. since 1985.
---..-"----,,,
03/10/04 10: 25 FAX [phone]'--.-/,-----,,'-..../Hale Lane et al ~026.. PESEAU
AFFIRMATION
, Dennis E. Peseau , pursuant to NAC 703.710 hereby affirm that the
foregoing prepared testimony was prepared by me or under my direction and is
correct to the best of my knowledge.
Signed 12- '
Dated
/~
,;/d. :J!-
03110/04- ;;, . '--.-/'
....J
10: 25 FAX [phone] Hale Lane et al .. PESEAU
Alaina Burtenshaw
Public Utilities ConuIDssion
101 Convention Center Drive, Suite 250
Las Vegas, NV 89109
DATED this 22nd day of January, 2002.
141 028
C'k/1 lto
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
.' ..' ". -.,." -
Application ofNEV ADA POWER COMPANY for authority
to increase its annual revenue requirement for general rates
charged to all classes of electric customers and for properly
related thereto.
, I:.I r
;:.
1 !
: ~
't ..i'-.j. I 0
, .
Application ofNEV ADA POWER COMPANY for approval
Of new and revised depreciation and amortization rates.
Docket No. 03-10001
Docket No. 03-10002
PREPARED TESTIMONY OF
DENNIS E. PESEAU
Phase One - Cost of Capital
Submitted by:
:;;~
Fred Schmidt
Hale Lane Peek Dennison and Howard
777 East William Street, Suite 200
Carson City, NV 89701
[phone]
Attorneys for
SOUTHERN NEVADA WATER AUTHORITY
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Docket No. 03-10001
Direct Testimony of
Dennis E. Peseau
on behalf of
Southern Nevada Water Authority
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
My name is Dennis E. Peseau. My business address is Suite 250 , 1500
Liberty Street, S.E., Salem, Oregon 97302.
BY WHOM AND IN WHAT CAPACITY ARE YOU EMPLOYED?
I am President of Utility Resources, Inc. My firm consults on a number of
economic, financial and engineering matters for various private and public
entities.
ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?
I am testifying on behalf of the Southern Nevada Water Authority (SNWA).
DOES ATTACHMENT ACCURATELY DESCRIBE YOUR
BACKGROUND AND EXPE~ENCE?
Yes.
WHAT IS THE PURPOSE OF YOUR TESTIMONY?
The purpose of my testimony in this cost of capital phase in these
proceedings is to offer the Commission an update of rate of return on
equity estimates ("ROE") for Nevada Power Company ("Nevada Power
using the same essential methods used by Dr. Avera in his direct
testimony.I limit my testimony and analyses to Dr. Avera s methods to
demonstrate a couple of points. First, simple updates to data, and use of
internally consistent data employed within Dr. Avera s ROE methods
dramatically lower his ROE estimate below the 11.2% he sponsors.
Second, these updates and consistencies further reveal that no formal
capital markets methods used by Dr. Avera, nor by others in my opinion,
could possibly generate the 14% ROE Dr. Avera refers to by adding other
ad hoc adjustments to his initial 11.2% ROE.
A further purpose of my testimony is to set squarely before this
Commission the request by Nevada Power for compensation in the form of
1n previous rate cases, and I expect the same to be true here, numerous other parties offer ROE
estimates based on slightly to significantly different methods and assumptions. As a simple check for this
Commission I only update and make consistent Dr. Avera s methods.
adjustments of the allowed ROE that is over and above a risk-adjusted
return set in open and competitive equity markets , as argued by Dr. Avera.
WHAT DO YOU CONCLUDE FROM YOUR MODIFICATIONS TO DR.
AVERA'S METHODS FOR ESTIMATING EQUITY RETURNS?
I conclude that consistent application of the discounted cash flow (DCF)
and risk premium methods used by Dr. Avera reduces his
recommendations as follows:
ROE Method Avera Estimate Peseau Estimate
DCF 10.
Risk Premium I 11.10.
Risk Premium II 11.0 - 9.
CAPM 11.10.
I conclude that the range of 9.3 - 10.1 % is reasonable for purposes of
setting equity return in these proceedings.Although I generally
recommend the midpoint of the equity return range, 9.7% in this case , I
testify below that any authorized return in the range of 9.7%-10.1 % is fair
and reasonable.
WHAT GENERAL COMMENTS DO YOU HAVE REGARDING THE
TESTIMONY AND ANALYSES OFFERED BY DR. AVERA?
See Avera Pages 65 - 87 for his plea for above market returns.
Dr. Avera offers 87 pages of testimony covering a number of topics.
Twenty-six of these pages cover the quantitative equity return methods and
estimates commonly considered by this Commission. The rest of the
testimony is concerned with general and fundamental economic and
financial topics which are normally and efficiently taken into account by
investors when bidding on and purchasing common stock and other assets.
Financial institutions and investors know the financial and operational
characteristics of Nevada Power every bit as well as Dr. Avera and use this
information to make formal investment decisions. A well-known financial
principle is that investors are not normally, nor do they expect to be,
compensated for nonmarket or company-specific risks that are not
systematic. These risks are diversifiable and do not, and should not form
the basis of rate of return "adders. n The methods of determining cost of
equity used by Dr. Avera and others in this case measure returns that are
commensurate with similar risk-adjusted investments and should once
again form the basis for this Commission s authorized return on equity in
these proceedings.
PLEASE TURN TO YOUR COMMENTS ABOUT DR. AVERA'
TESTIMONY. WHAT IS THE BASIS FOR HIS SUPPORT OF AN EQUITY
RETURN FOR THE COMPANY?
Dr. Avera presents four quantitative analyses of the cost of equity for
reference electric utilities and analyses from which he derives an 11.
cost of equity estimate. Based on that information and additional premiums
he adds for risk specific to Nevada Power, he recommends a 14% return.
Then for reasons that are not quite clear to me, a final return of 12.4% on
equity is used to actually compute the weighted cost of capital.
WHAT ARE THE QUANTITATIVE STUDIES?
Dr. Avera presents a discounted cash flow ("DCF") analysis for a
benchmark group of electric utilities in the western U. S., two risk premium
approaches and an estimate based on the capital asset pricing model
CAPM"
).
From his DCF analysis, he estimates that a benchmark sample
of western electric utilities requires a return on equity of 10.8% (page 56).
Based on two risk premium models, he concludes that the cost of equity for
the respective reference samples of electric utilities are 11.5% (page 62)
and 11.1 % (page 63). And , from his CAPM approach, he derives a cost of
equity estimate for the western electric utilities of 11.7% (page 64).
Combined , he concludes that the costs of equity for his sample of electric
utilities in the western U. S. is on the order of 11.2% (page 7).
HOW DOES HE REACH THE CONCLUSION THAT NEVADA POWER
SHOULD BE AUTHORIZED AN EQUITY RETURN IN EXCESS OF
11.2%?
Dr. Avera presents lengthy discussions of company-specific risks that he
contends are faced by Nevada Power and should be recognized in setting
the authorized return. That analysis of unique risks is the basis for his
contention that the Company requires an equity return higher than the
11.2% he estimates is required by other western electric utilities and higher
than the Company s request of 12.4%.
DO YOU HAVE ANY COMMENTS ABOUT HIS DCF ANALYSIS?
Yes. Recall that the DCF method under standard financial assumptions
reduces to the equation:
ROE = D/Po + g
where ROE =required equity return
first period dividend rate
today s stock price
growth rate
Dr. Avera s estimate of 10.8% return results from his estimate of the DCF
components:
10.8% = 4.8% (yield) + 6.0% (growth)
I focus my modifications on the 6.0% growth rate and update his dividend
yield. The growth rate g is that expected in the future by investors. It is by
nature forward looking. But I noted that on Dr. Avera s Schedule WEA-
he used not only the typical benchmark for expected growth , as reported by
the investor institutions IBES , Value Line, First Call and Multex Investor , but
historical rates of earnings growth for both five and ten year past periods:
Ave. Expected
Growth Rate
Dr. Avera s Ex ected Growth Rates
Value First
IBES Line Call Multex
5.4
Past
10 Yr.
Past
5 Yr.
While the simple average of these growth rates is 5.6%, Dr. Avera uses the
0% figure to develop his 10.8%.
IN YOUR OPINION, IS DR. AVERA'S USE OF THE HISTORICAL
GROWTH RATES IN HIS AVERAGE AN APPROPRIATE BASIS FOR
ESTIMATING THE DCF REQUIRED FUTURE EXPECTED GROWTH
RATE?
No. To the extent that past growth might be of any importance to investors
the analysts' forecasts Dr. Avera reports for IBES , Value Line , First Call and
. ~
Multex have already taken that information into account. David A. Gordon,
Myron J. Gordon and Lawrence 1. Gould, (Choice Among Methods of
Estimating Share Yield Journal of Portfolio Management (Spring 1989), pp.
50-55) did a study that found analysts' forecasts of growth provide a better
explanation of stock prices than three backward-looking measures of
growth. They explain that their findings make sense because analysts
would take into account past growth as well as any new information when
they form their forecasts. Roger Morin reports the results of other empirical
studies and concludes analysts' forecasts
. . . "
are more accurate than
forecasts based on historical growth" (Regulatory Finance: Utilities Cost
Capital page 154).My restatement of Dr. Avera s DCF analysis
recognizes all of the forecasts of growth that Dr. Avera relied upon but
gives no weight to the measures of past growth Dr. Avera reported.
HOW HAVE YOU MODIFIED DR. AVERA'S DCF EXPECTED GROWTH
RATE VARIABLE TO REMOVE THE EFFECTS OF HISTORICAL
GROWTH?
My Exhibit DEP-1 is a restatement of Dr. Avera s analysis of the growth
rate.
To determine an updated or consistent estimate for the DCF
expected growth rate for each of the utilities in Dr. Avera s sample , I adopt
his reported estimates of investor institution projections in Schedule WEA-
as well as his estimate of sustainable BR growth in his Schedule WEA-
My Exhibit DEP-1 shows that the correct average for the projected or
expected growth rate is 4.78%, not the range of 5% to 7% argued by Dr.
Avera.
Q. . BASED ON YOUR UPDATES AND UTILIZATION OF ONLY THE
FORWARD-LOOKING GROWTH RATES REPORTED BY DR. AVERA
WHAT IS YOUR RESTATEMENT OF DR. AVERA'S DCF RESULTS?
Based on his sample and the restatements discussed above, the indicated
average cost of equity for the western electric utilities is 9.3% (4.5 + 4.8%)
at this time, 150 basis points less than the 10.8% estimated by Dr. Avera.
DO YOU HAVE OTHER CONCERNS WITH DR. AVERA'S DCF
ANALYSIS?
0r. Avera used stock prices as of August 22, 2003, a time of depressed prices. Any update to stock
prices to current level would reduce significantly the estimate he uses for dividend yield.
Yes. The DCF method he proposes is inefficient. At page 40, Dr. Avera
presents the general form of the DCF model. It clearly shows that expected
dividends per share (DPS) are the cash flows that are of interest to
investors. He adopts Value Line forecasts of dividends for the next year
but ignores Value Line forecasts of dividends for other future years. His
DCF approach is inefficient because it does not incorporate all of the
information on dividend growth that investors consider when they price the
shares of common stock in his sample. Had Dr. Avera made his DCF
estimates with a multi-stage DCF model that recognized that dividend
growth is expected to be less than half as rapid as forecasted earnings and
sustainable growth for the period 2004 to 2008 , the DCF equity cost
estimate would be less than 9.3% (closer to 9.0%). But because I limit my
testimony to a restatement of the methods Dr. Avera has relied upon, I
have not presented such an analysis.
UPDATE TO DR. AVERA'S RISK PREMIUM APPROACHES
WHAT IS A RISK PREMIUM APPROACH TO ESTIMATING A UTILITY'
REQUIRED RETURN ON EQUITY?
Whereas the DCF method adds estimates of dividend yield to expected
growth rate to get equity cost estimates, risk premium methods recognize
10-
that over time common stock is riskier than most debt securities (bonds)
and therefore requires a premium , or adder, over and above the return on
bonds. This adder is often termed a risk premium. As yields on bonds are
generally directly observable and measurable, equity cost estimates may
be derived if reliable risk premiums can be determined.
HOW DOES DR. AVERA UTILIZE THE RISK PREMIUM METHOD?
Dr. Avera uses a risk premium method based on authorized equity returns
another based on actual or realized returns and finally, the more
academically rigorous risk premium method , the Capital Asset Pricing
Model (CAPM).
WHAT EQUITY RETURN DOES DR. AVERA ESTIMATE USING HIS
AUTHORIZED RETURN RISK PREMIUM METHOD?
11.5%. He derives this by adding an August 2003 bond yield of 7.07% to a
risk premium estimate of 4.39% that is derived in his Schedule WEA-
Schedule WEA-4 uses regression analysis to attempt to determine the
historical relationship between allowed equity returns , bond yields , and the
difference between the two - the risk premium. The theory is that if the
regression analysis can determine the relationship between the bond yield
and the appropriate risk premium , then one can observe today s bond yield
11-
add to it the estimate of risk premium appropriate for the bond yield and
add the two to get an equity return estimate. From Schedule WEA-, Dr.
Avera estimates the relationship as:
(ROE - Bond Yield) = .07 + (-.435 Bond Yield)
While I have no quarrel with the basic methodology, Dr. Avera uses interest
rates or bond yields that are internally inconsistent in his method.
PLEASE EXPLAIN.
Dr. Avera uses a low yield bond to compute his historical risk premium.
Use of this low bond yield when subtracted from allowed equity returns
produces an exaggerated or higher risk premium than if a consistent bond
rate is used. The bond yield used by Dr. Avera , shown on Schedule WEA-
4 is an average of MA, AA, A and BBB rated bonds. Since the highly
rated bonds MA, AA and A will have the lowest interest rates, the
composite rate used by Dr. Avera is low. Subtracting a low interest rate
from an authorized return yields an artificially high risk premium. Then , on
Page 62 , Line 7, he adds this high risk premium to the highest bond yield
that of a triple-B bond. This mixing of different bonds for the regression
analysis and for computing the equity return biases upward Dr. Avera
estimate of an equity return.
12-
HAVE YOU ATTEMPTED REMOVE DR.AVERA'
INCONSISTENCY?
Yes. An appropriate calculation would use the same measure of bond
rating in the regression analysis as in the recommended equity return. In
making my restatement, I have used A-rated utility bonds to compute the
risk premiums, to run the regressions and to estimate the equity cost.
chose the A-rated utility bond rates because Dr. Avera relies on A-rated
bonds in Schedule WEA-5. Also, current quotations for A-rated utility bond
rates are widely available and published by Value Line every week. I also
used triple-B rates, as a second approach, in another regression as well
because that is what Dr. Avera uses on his Page 62. The results of the
revised analysis are shown in my Exhibit DEP-, pages 1 and 2 of 2.
Combining the revised regression result with a recent quotation of
86% for A-rated utili.ty bond rates gives an indicated cost of equity for the
benchmark electric utilities of 10.68%, 82 basis points lower than Dr.
Avera s estimate of 11.5%. Using the triple-B regressions with the current
triple-B rate of 6.21 % as of December 19, 2003 gives a cost of equity
estimate of 10.73%.
ARE NEVADA POWER AND SIERRA PACIFIC EITHER A-RATED OR
TRIPLE-B RATED?
13-
No. The credit ratings for each vary with the type of security, but are in the
B8" to "8+" range. As Dr. Avera points out, the difficulty in attaching
authorized equity returns to such ratings is that because the equity risk
premium computed is inversely related to the bond yield , no such analysis
can be done, nor can the relationship even be estimated reliably for these
ratings, under such circumstances.
DO YOU HAVE ANY COMMENTS ABOUT DR. AVERA RISK
PREMIUM APPROACH BASED ON THE REALIZED-RATE-OF-RETURN
APPROACH THAT HE PRESENTED IN SCHEDULE WEA-
Yes. First, as he did with his other risk premium approach , Dr. Avera used
one type of bond to determine the average risk premium and then
incorrectly added that risk premium to a triple-B public utility bond rate.
this analysis the risk premium was established as the average difference
between annual returns on stocks and A-rated bonds and thus the risk
premium will be larger than if the premium were established for triple-
bonds. To make Dr. Avera I s approach internally consistent, I added the
current A-rated bond to the premium for A-rated bonds. This change alone
reduces Dr. Avera s equity cost estimate to 9.9%. See Exhibit DEP-
My other observation is that Dr. Avera I s approach assumes that
investors typically have holding periods of only one-year, when investors
14-
probably expect to hold shares of utility stocks for longer periods.
investors have very long holding periods , a risk premium based on
differences in geometric average returns would be the appropriate risk
premium.If, for example, investors have 57-year holding periods , the
correct estimate of the risk premium would be 3.11 % instead of 4.01 %.
See Exhibit DEP-3. I expect that investors typically have holding periods
longer than one-year but much shorter than 57 years. In such a case this
approach would indicate the cost of equity would be between 9.9% and
0% but closer to 9.9%.
DO YOU HAVE ANY COMMENTS ABOUT DR. AVERA'S CAPITAL
ASSET PRICING MODEL EQUITY COST ESTIMATE?
Yes.Although the CAPM's derivation is steeped in a good deal of
financial theory and mathematical determination , the final specification, like
the DCF method, is fairly straightforward:
Equity Cost = Risk Free Rate + Beta x Market Risk Premium
There are a number of different ways the CAPM can be implemented and a
number of ways that estimates of the risk free rate and market risk premium
can be derived. I limit my comments to an update of Dr. Avera I s risk free
15-
rate and his estimate of the market risk premium (MRP). I will not contest
his measure of market risk, "beta.
WHAT IS THE RISK-FREE RATE USED BY DR. AVERA?
Dr. Avera uses as a measure of the risk-free rate the average yield on
twenty year government bonds. He indicates that this measure of the risk-
free rate as of August 2003 was 5.39%.
WHAT IS THE RECENT YIELD ON TWENTY YEAR GOVERNMENT
BONDS?
The recent yield is 5.11 %.I use that rate in my update.
HOW DOES DR. AVERA ESTIMATE THE MARKET RISK PREMIUM
(MRP)?
While I do not agree entirely with his method of estimating the market risk
premium, I use his method here with a simple update.
Dr. Avera derives a forecast of the total average market return for
the stock market of 14.24%, then, to estimate the market premium he
subtracts off the existing risk free rate of 5.39%, which results in an 8.85%
MRP.
16-
WHAT UPDATE HAVE YOU MADE TO DR. AVERA'S MARKET RISK
PREMIUM, MRP?
Whereas the twenty year government bond rate is directly observable and
is set in competitive markets, the other component of the risk premium
approach used by Dr. Avera, the projected market return , is not directly
observable or measurable.The projected market return is simply the
opinion about the future made by different investor institutions and can
change frequently. Use of a projected market return of 14.24%, as of a
single point in time therefore, makes the prediction of total market return
highly variable , as I now show. For reference, the long-term market risk
premium is 7.0%, not the 8.85% used by Dr. Avera.
Dr. Avera s total market return was measured prior to the substantial
stock market recovery that occurred this fall and winter. With the run-up of
the market, investors now understand that such a large short-term gain as
14.24% is no longer realistic. For example, the Value Line forward-looking
total market return for the 1700 stocks it follows, as of December 19 , 2003
was 11.7%, not the 14.24% used by Dr. Avera. This huge potential for
variation in these estimates makes rate of return setting for regulatory
purposes difficult.
17-
Nevertheless, using the updated market return forecast of 11.7%,
the implied MRP is 6.60% (11.7% - 5.11 %), not the 8.85% used by Dr. Avera.
Assuming, to be conservative, that investors require a risk premium
that falls in the range of the long-term average MRP of 7% and the
indicated current MRP of 6.6%, an update of Dr. Avera I s CAPM equity cost
estimate falls in a range of 9.8% to 10.1 % as shown below:
Equity cost = RF + beta x MRP
Equity cost = 5.11% + .71 x 7.0% = 10.
Equity cost = 5.11% + .71 x 6.6% = 9.
SUMMARY
PLEASE SUMMARIZE YOUR UPDATES AND RESTATEMENTS OF DR.
AVERA'S QUANTITATIVE ESTIMATES OF THE COST OF EQUITY FOR
BENCHMARK ELECTRIC UTILITIES.
I updated and restated Dr. Avera I s four quantitative estimates of the cost
of equity. As I indicated above, the 10.7% equity return estimate was
derived by observing from other jurisdictions what regulatory commissions
were authorizing. While the method is useful to some extent, there is
obviously the problem of comparability to Nevada. There is, for example,
no means of normalizing out differences among different authorized equity
18-
returns for actual versus hypothetical capital structures, incentive or
punitive adjustments to equity returns, performance-based ratemaking,
construction work in progress in or out of rate base, among other possible
differences.
The 9.0% was the bottom of the range derived from Dr. Averas realized-
return approach to the risk premium. This 9.0% is associated with a very
long common stock holding period and may not represent a best estimate
of how investors hold and trade stock. I conclude, then, that a range of
3% -10.1% return on equity is fair and reasonable. To be conservative, I
recommend that the Commission authorize a return from the mid- to the
upper end of my range, that is, 9.7% to 10.1%. My Exhibit DEP-4 shows
that a 9.7% equity return, with Nevada Power's capital structure, results in
an 8.95% overall weighted rate of return.
WHAT CONSIDERATIONS WEIGH IN YOUR RECOMMENDING THE
MID- TO UPPER END OF YOUR EQUITY RETURN RANGE?
I normally recommend the midpoint of a range of equity returns. In this
case, due to the improvement in capital markets and associated reduction
in capital costs since the Nevada Power 2001 general rate case, the 9.
is reasonable. On the other hand, the 9.7% equity return is lower than that
now authorized. Given the financial rocky road experienced recently by
Nevada Power, the Commission may consider not lowering the presently
19-
. 15
authorized equity return below the present level to send a more positive
message to the financial community.
HOW DOES YOUR RECOMMENDED RATE OF RETURN ON EQUITY
COMPARE WITH THAT AUTHORIZED BY THE COMMISSION IN THE
NEVADA POWER GENERAL RATE CASE?
The top of my recommended range, 10.1 %, is essentially the same rate on
equity as authorized by the Commission in 2001.
DO THE DIRECTIONS IN TRENDS OF FINANCIAL MARKET CAPITAL
COSTS SINCE THE 2001 GENERAL RATE CASE SUPPORT YOUR
RECOMMENDATIONS?
Yes. My Exhibit DEP-5 plots monthly interest rate data for 10-year Treasury
bonds and for Baa corporate bonds for the period October 2001 through
December 2003. Generally, rates for government bonds have decreased
somewhat, while rates on corporate bonds have decreased significantly. I
conclude that a range of 9.7%-10.1 % return on equity for Nevada Power,
given the drop in capital costs, is fair and reasonable.
DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
Yes.
20-
Attachment 1
Page 1 of 3
STATEMENT OF OCCUPATIONAL AND
EDUCATIONAL HISTORY AND QUALIFICATIONS
DENNIS E. PESEAU
Dr. Peseau has conducted economic and financial studies for regulated
industries for the past twenty-eight years. In 1972 , he was employed by Southern
California Edison Company as Associate Economic Analyst, and later as Economic
Analyst. His responsibilities included review of financial testimony, incremental cost
studies , rate design, econometric estimation of demand elasticities and various areas
in the field of energy and economic growth. Also, he was asked by Edison Electrical
Institute to study and evaluate several prominent energy models as part of the Ad
Hoc Committee on Economic Growth and Energy Pricing.
From 1974 to 1978 , Dr. Peseau was employed by the Public Utility
Commissioner of Oregon as Senior Economist. There he conducted a number of
economic and financial studies and prepared testimony pertaining to public utilities.
In 1978 Dr. Peseau established the Northwest office of Zinder
Companies, Inc. He has since submitted testimony on economic and financial
matters before state regulatory commissions in Alaska, California, Idaho, Maryland
Minnesota, Montana, Nevada, Washington, Wyoming, the District of Columbia, the
Bonneville Power Administration and the Public Utilities Board of Alberta on over one
AUCiGnmem I
Page 2 of 3
hundred occasions. He has conducted marginal cost and rate design studies and
prepared testimony on these matters in Alaska, California , Idaho, Maryland
Minnesota, Nevada, Oregon, Washington and in the District of Columbia. He has
also conducted cost and rate studies regarding PURPA issues in the states of
Alaska , California , Idaho, Montana , Nevada, New York, Washington, and
Washington, D.
Dr. Peseau holds the B., M.A. and Ph.D. degrees in economics.
He has co-authored a book in the field of industrial organization entitled,
Size. Profits and Executive Compensation in the Large Corporation , which devotes
a chapter to regulated industries.
Dr. Peseau has published articles in the following professional journals:
Review of Economics and Statistics Atlantic Economic Journal Journal of Financial
Manaqement, and Journal of Reqional Science. His articles have been read before
the Econometric Society, the Western Economic Association, the Financial
Management Association, the Regional Science Association and universities in the
United Kingdom as well as in the United States.
He has guest lectured on marginal costing methods in seminars in New
Jersey and California for the Center of Professional Advancement. He has also
guest lectured on cost of capital for the public utility industry before the Pacific Coast
Attachment 1
Page 3 of 3
Gas and Electric Association , and for the Executive Seminar at the Colgate Darden
Graduate School of Business, University of Virginia.
Dr. Peseau and his firm have participated with and been members of the
American Economic Association, the American Financial Association, the Western
Economic Association, the Atlantic Economic Association and the Financial
Management Association. He was formerly a member ofthe Staff Subcommittee on
Economics of the National Association of Regulatory Utility Commissioners.
Dr. Peseau has been President of Utility Resources, Inc. since 1985.
~.l~.U.1.JJ.1..1. 1J~J..-.1.
Revised Computation of Dr. Avera s DCF Estimates
Average of
Estimated Growth Rate Updated
Dividends Projections Equity
for Reported by Cost
Price-20O4-Yield Dr. Avera-Estimate
Black Hills Corp $31.$1.97%94%91%
Hawaiian Electric $41.$2.48 96%98%94%
IDACORP lnc $23.$1.03%53%10.56%
MDU Resources Group-$21.48 $0.26%66%92%
PNM Resources Group $26.$0.64%40%04%
Pinnacle West $33.$1.5.48%52%00%
Puget Energy, Inc.$21.$1.71%16%87%
Sempra Energy $28.$1.55%74%10.29%
Xcel Energy $14.42 $0.34%05%39%
Average 55%78%32%
Notes and Sources
a/ As reported by Dr. Avera, Schedule WEA-1 page 1 of 1, with recent splits.
bl November 14, 2003 Value line forecast of DPS growth for 2004.
cI Average of four projecrted growth rates and projected BR growth reported by
Dr. Avera in Schedules WEA-2 and 3.
d! Adjusted for stock split of 3:2.
12/29/03
EXHIBIT DEP-
Page 1 of 2
Revised Computation of Dr. Avera s Schedule WEA-4
Based on A-rated Public Utility Bond Rates
A-rated
Allowed Public Utility Risk
Year ROE Bond Yield Premium
1974 13.100k 50%60%
1975 13.20%10.09%11%
1976 13.10%29%81%
1977 13.30%61%69%
1978 13.20%29%91%
1979 13.50%10.49%01%
1980 14.23%13.34%89%
1981 15.22%15.95%-0.73%
1982 15.78%15.86%-0.08%
1983 15.36%13.000A.70%
1984 15.32%14.03%29%
1985 15.20%12.47%73%
1986 13.93%58%35%
1987 12.99%10.10%89%
1988 12.79%10.49%30%
1989 12.97%77%20%
1990 12.70%86%84%
1991 12.55%36%19%
1992 12.09%69%3.40%
1993 11.41%59%82%
1994 11.34%31%03%
1995 11.55%89%66%
1996 11.39%75%64%
1997 11.40%60%80%
1998 11.66%04%62%
1999 10.77%62%15%
2000 11.43%24%19%
2001 11.08%78%30%
2002 11.16%36%80%
Average 92%97%
Regression OUtput
Constant
Std ErrofY Est
R Squared
No. of Observations
Degrees of Freedom
Current Equity Risk Premium
0749
0057
8053
Average Yield over Study Period
Dec. 2003 A-rated ubTIty bond yield
Change in Yield
92%
- 5.86%
==-
-4.06%
X Coefficient(s) -0,4559
Std Err of Coef. 0.0431t-statistic -10.
Risk premiumfmterest rate relationship
Adjustment to Average Risk Premium
-45.59",(,
85%
Average risk premium over Study Period
Adjusted risk premium
Current Equity Cost Estimate
82%
10.68%
12129103
b- ~ r.
,.....
1- w...
If.Q7. -to
~Xtll.J:HT 1J~.t"-
Page 2 of 2
Revised Computation of Dr. Avera s Schedule WEA-4
Based on Baa-rated Public Utility Bond Rates
Baa-rated
Allowed Public Utility Risk
Year ROE Bond Yield Premium
1974 13.10%84%26%
1975 13.20%10.96%24%
1976 13.10%820h 28%
1977 13.30%06%24%
1978 13.20%62%58%
1979 13.50%10.96%54%
1980 14.23%13.95%28%
1981 15.22%16.60%38%
1982 15.78%16.45%-0.67%
1983 15.36%14.20%16%
1984 15.32%14.53%79%
1985 15.20%12.96%24%
1986 13.93%10.00%93%
1987 12.99%10.53%2.46%
1988 12.79%11.00%79%
1989 12.97%97%00%
1990 12.70%10.06%64%
1991 12.55%55%00%
1992 12.09%86%23%
1993 11.41%91%50%
1994 11.34%63%71%
1995 11.55%29%26%
1996 11.39%17%22%
1997 11.40%95%3.45%
1998 11.66%26%4.40%
1999 10.77%88%89%
2000 11.43%36%07%
2001 11.08%8.02%06%
2002 11.16%8.02%14%
Average 10.32%56%
Regression Output CUrrent Equity Risk Premium
Constant
Std Err ofY Est
R Squared
No. of Observations
Degrees of Freedom
0747
0057
8306
Average Yield over Study Period
Dec. 2003 Baa-rated util'dy bond yield
Change In Yield
10.32%
21%
-4.11%
x Coefficient(s:
Std Err of Coef
t-statistic
-0.4755
0413
11.
Risk premiumJinterest rate relationship
Adjustment to Average Risk Premium
-47.55%
96%
Average risk premium over Study Perioc
Adjusted risk premium
Current Equity Cost Estimate
56%
52%
10.73%
12/29103
.c.AI1J.DJ. J. u.c.J:: - J \.\-.;;;
Revised Computation of Dr. Averas Schedule WEA-5
S&P Electric companies
Year Return Index
1945 000
1946 -0.49%0.995
1947 12.17%874
1948 47%887
1949 24.49%104
1950 527%162
1951 1725%363
1952 19.66%631
1953 19%780
1954 23.46%198
1955 12.33%469
1956 83%539
1957 10.29%800
1958 38.35%874
1959 77%059
1960 21.84%946
1961 28.89%374
1962 70%483
1963 1029%150
1964 15.36%8248
1965 2.99%495
1966 -4.34%126
1967 67%909
1968 66%594
1969 13.42%441
1970 12.59%377
1971 226%567
1972 19%926
1973 18.71%7256
1974 25.35%5.416
1975 50.39%145
1976 23.53%10.061
1977 921%10.988
1978 -3.78%10.572
1979 51%10.626
1980 86%11.355
1981 20.45%13.677
1982 35.59%18.545
1983 13.36%21.023
1984 24.72%26219
1985 25.34%32.863
1986 28.06%42.085
1987 31%39.008
1988 17.16%45.702
1989 31.48%60.089
1990 06%61.327
1991 28.91%79.057
1992 45%83.365
1993 12.56%93.836
1994 13.17%81.478
1995 30.15%106.043
1996 -0.32%105.704
1997 25.03%132.161
1998 15.04%152.038
1999 18.93%123258
2000 51.67%186.945
2001 14.78%159.314
2002 14.41%136.357
Averages 1028%01%
Premiums
Current A-rated utility bond
Equity cost
12/29/03
A-Rated Utility bondsReturn Index
000
029
004
033
125
134
077
124
145
1216
1209
112
194
151
158
1240
1292
414
439
513
500
432
1.364
374
1276
1.383
607
725
794
747
850
2261
353
361
2268
2222
2210
135
349
922
026
6228
6266
937
056
634
10.016
11.195
12.054
13.179
15287
17.157
19.408
20.931
19.757
21.093
22.738
26.185
2.91%
41%
86%
93%
75%
-5.03%
37%
93%
18%
-0.61%
-8.01%
39%
-3.61%
60%
06%
425%
9.39%
82%
10%
-0.82%
-4.55%
-4.78%
75%
11%
8.34%
1622%
7.37%
98%
63%
89%
2221%
08%
36%
-3.94%
05%
-0.54%
41.86%
83%
17.11%
28.16%
23.90%
61%
10.71%
16.13%
18%
16.01%
11.77%
67%
33%
16.00%
1223%
13.12%
85%
-5.61%
76%
80%
15.16%
627%
( ,
5.90%
'" ... ~.tl4:- I ~ 0).-
Q..Arithmetic Geometric L""01% 3.11% c:r-9% 5.9% 9.
,,-1 ~
~()
IO."l.i'"
EXHIBIT DEP-
NEVADA POWER COMPANY
CORPORATE STRUCTURE
WEIGHTED COST OF CAPITAL
FOR THE TEST PERIOD ENDING MAY 31,3003
FOR THE CERTIFICATION PERIOD ENDING SEPTEMBER 30, 2003
(IN THOUSANDS)
Capital Capital Weighted
Amounts Proforma amount Capital Cost of Cost of
Descri tion 5/31/03 Adjustments 9/30/03 Ratio%Capital%Capital%
Debt
Short-Term Debt 00%00%00%
Customer Deposits 22,361 457 818 72%10%01%
Long-Term Debt 783,835 783 835 56.05%61%83%
Total Debt 806,196 457 806 653 56.77%52%83%
Equite
Preferred Equity 194,713 194,713 12%38%51%
Common Equity 101,985 79,331 181,316 37.12%70%60%
Total Equity 296,698 79,331 376,029 43.23%11%
Total Capital 102 894 79,788 182 682 100.00%95%
.....~.....~............... .............. ....
Percent
f\.) ~
())----'-~ ~
: i
---c--1..
~ ~
r-+
0'"
~ ~.....
I\)\9'
0 ~
c::
~ ~
---c
(J)
.......
0'"::J :;u! i
.....
: en I\)P+-
i i
(J)
L___u .
AFFIRMATION
, Dennis E. Peseau, pursuant to NAG 703.710 hereby affirm that the
foregoing prepared testimony was prepared by me or under my direction and is
correct to the best of my knowledge.
Signed .2.:
~,
Dated
BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Application ofNEV ADA POWER COMPANY for authority
to increase its annual revenue requirement for general rates
charged to all classes of electric customers and for properly
related thereto.
Application ofNEV ADA POWER COMPANY for approval
Of new and revised depreciation and amortization rates.
PREPARED TESTIMONY OF
DENNIS E. PESEAU
Phase One - Cost of Capital
Work Papers
Docket No. 03-10001
Docket No. 03-10002
e-...~
-~.iiiiiceH "t.l:J RAllO I:J. I \Mediati: 13.DJ PIE RATIO au YLD
15.2! 17.192 24.3 27.9 26.5 46.1 58.5 36.9 33.
1\.8, 13.152 17.5 20.7 20.3 20.4 26,0 18.3 21.
DL"'\l1\ nlLL" \lunr. NYSE.BKH
TIMElINESS 4 lOW8l!d I1m03 ti~: 21.51 18.
SAFElY 3 lawered8l1s.~ ~~ENDS'5.91 146
1 3B I DIYiIenas t
TECHNICAL Raised ""WI .
. .. = ~
"'rest P.t.
BETA .80 11.00. MalbI) 3-1or.2 $pili 3I92nr.. Suer.;-:.
200&-08 PR E TlON
~~
~18
AM:' Tolal Shaaea 'rea.
""""
'=.-011Price Gain Return !IigII 40 (+25%) 9%low 30 (-5%) 3%
Insider DecisionsDJFUAUJJ'" .h"'IoBuy 0 0 0 0 0 0 0 0 0 . 10 .0pIi0IJ0 0100DOOOO """
10 Sol. 1 1 0 0 ~ 0 0 0 0 ! 'IoTOtRETURN1D1O3 7.5Institutional Decisions "1IIS ~URmLIO2OIIZ 1Q2003 2Q2OI3 PelCent 18 S1OCIt INOE110 Buy 71 78 94 shares 12 1 yr, 27.8 45.510 Sol 45 45 35 1raded 6 I-
,. . . .
. 3 yr, 15.3 26.6IK1I1ICO113301218715915 t-
'--:::..",""
,",'hlilolllll"'II,,'1 I I iSyr.SO.64.8
198711988119891199011991 1992 1993,1994 1995 1996 1997 1998 1999 2000 2001 200212003 2004; oYAWELBlEPUB..1NC.
5.98 13.' 5.6.22j 6.501 6.59 6.51: 6.;: 6.92 7.50 14,45 31.48 37.05 69.69 57.96 15.64'42.15 4U5!Revenuespersh 57.48 1.51 1.53 1.601 1.69 82 182' 192 2.09 2.45 2.52 2.n 2.88 3.68 5:27 4.90 (75 5J5:"CashAow persh f.OO97 1.02 1.07 1.121 1.11 1.15 \.11 1.11 1.19 1.40 1.49 1.60 1.70 2.37 142 2.33 ua ZJO !Eamingsperlh" 2.75.55 .62 .68 .731 .78 .!3 85: !8 . .89 .92 .95 1.00 1.04 1.08 1.12 1.16 1.20 1J4IDi'1'dDed'dpersh8. US65 .65 .49 1.08 I 1.25 I 1.251 1.88. ~:t 2.40 1.13 .98 1.18 4.89 5.79 14.07 8.60 3.40 160 ICap1 Spending per sh 1.505.38 5.86 6.21 6.60 I 6.921 7.261 7.85 a 13 8.43 8.91 9.46 9.58 10.14 11.95 18.95 19.54 I 21.22.55 iBook Value perlh C 26.50
20.48 20,51 20.51 20.51 i 20.51 i 20.551 21.40 21.53 21.64 21.68 21.70 21.581 21.37 23.30 26.89 27.10 I 32251 32.5Q:CGmmOllShsOlllsfg 33.25105 11.4 11,3 11.11 14.4 i 162 , 15.3~ 12.: 13.1 11,110 14.13.6 10.9 11.12.5 . -1igIPa- AvgAnn1PlERaIio fz.5.95 .861 .821 92; .981 9". 91 .881 75 .75 .11 ,78 .71 .58 .68 1'~U1e ,RNtivePIERatio ..154% 5.3% 5.6% 5.9".; 4 ! 4 : 5.00. e.. 5.. i 5.4.9% 4.2% I 45% 4.2"io 2.9% 4.00.0;
~ '
AvgAnn1D1v'dfaeki U%
CAPITAL STRUCTURE BS oUI3O1O3 139.4 1~5.149.8! 162.6 3117 679.791.9 1623.8 1558.6 423.9 i 1360 f575;Rewnues(SmiII) fnoTotal Debt S851.4 mill Due In SYrs S3B3.7 mill. 22.9 23.! 25.30.3 32.4 34.36.5 52.8 88.63.2 70.0 71DINetProfit 90.0LTOebtS825.5mi1l LTlnterestS40.6miIL 0'-
",
31""' 30.7% ""- .8% 36.5% 36.5% 31.9"'..' 35.D% 34.~'Income" Dol. (IT interest eamed: 4.Ox) .1 , .
, -.
v. I .v" ""'.... I "u"",,, ....v..Leases.Uncap/lalizedNone J.2"......!.E i', 22.9'12"'A .6"10 .3.3% 3.8.5% 18.2'!'0 f.O% us :AFUDC'foJoNetPlolit (0%
Pension Assets.121D2 $32.4 mitt ObRg. S5D.9 33,7". 42., J7.~ i 46.0% 44.3% 43.9~ 42.6% 52.1% I 44.7% I 53.6% I 56.0% 58.DS !Long-Term DeblRatio 55.0%mill 66.3"-. : 57.52.3"', 54.0"'. 55.7% 56.1% 57,4~ 47.2"'.0 54,7"'.. 45.9'\ i un 42.0%.Common Ratio 45.D%Pld StockSS.5 mill Pld Div d S.2mlll. 253.4 ;304:3 348.41 357.9 368.8 368.7 311.3 589.931.0 1154.0 i 1585 1755:ToIaICapiIaI(SmlU) f965~~q~:~~=~;7
::~
~ 288.7~ 363
~.
393.3 400.401.1 389,484.2 794.311238.2 1476.3 i 1635 1160 ,Net Plant Smal) 244Q
men div'ds on a tufty convened basis, 10.6":0, 9.3". 9.2"'. 110.4\ 10.6% 11~ 11.4% 10.6\ 10.6% 6.6~ I I ur. :Re1um on Total Cap1 6.5%
Common 5tock32.107.619 shs. 13.6".; 13.5'. 14,00-'1'5.15.8% 16.7% 16.8% 18.7%! 17.1% 11.8%! 10.0" I fm RelumonShr.EquiIy fD.5%Isof7131/03 13.6"'., 13.6'. 14.0".! 15.7"'.. 15.8% 16.7% 16.8% 19.0% 17.2% 11~ I 10.0% fO.:Re1umonComE . E fO.5%
MARKET CAP: S1.0 billion (Mid Cap) 3.1 ' 28'3.4'101 5.3"k 5.8%6~ 6.4% 10,5~.111.6"!. 6.0041 U"! or.,RetalnedJoComEq 5.0%
ELECTRIC OPERATING STATISTICS 77".. :'9', ;OS'.. I 66'.. 63% 63% I 62% 45"'-0 I 33"'.. I 50"..1 54" I 53"'.. :ADDiv'dstoNetProf 5f~
" C!iarq! Re!aii Sa!fs
~ 2~l 2
~~~
2~f~ BUSINESS: BlaCk H,ns Corporation is a holding for Bladt & gas. Black tfdls FibelCom is a le!ecom joint venture. Acq'd Wick-
~tQQ.IiSeILl\'l1il 11335 11062 9516 HdIs Powa and light which provides eledricity \0 60.000 custom- lord Energy MaIke1ing 719!: Mallon Resources 3'03. Fuel costs:
~Gmt.Reos.De!KWI'.fc! 'us 4.72 4.93 ers III SOUIh Dakota. Wyoming, and Montana. EIecCric revenue 15% 01 revs. '02 clepr. rale: 16%. Has 840 employees. 16.000==~,j.1
~~ ~ ~~
bre~down. ")2: residential. 23%: commen:ial. m.: i1dusIriaJ. com. stockholders. CIumn. & CEO: Daniel P. LandguIh. Pres. ~
~lQJFmr.NA NA NA 12"..: O1her. 36'. Generatng sources. '02; coal 50"~ oil & gas. COO: Everett E. Hoyllnc.: SD. AdIhss: P.O. Box 1400. Rapid
\~CosDne!si;r-er.:!1 + 1,5 +1.+12 39"..: purchase!!. 11'.. Mines coal and explores lor & produces oil City. SD 57709. Tel.: [phone]. Web: www.blac:khillscorp.com.
fimI~'AI~~ 376 418 241 Black Hills has received a payment by $0.07, however. We haven t adjusted
ANNUAL RATES Past Past Esl'd'Oo.'Q2 for tenninating its contract with AI- our 2004 earnings estimate of $2.30 a
clcIIange(persni IDYl$. SYrs. 10'05-'08 legheny Energy. 1\vo years ago, Black share because the company expects that
Revenues , 22.0~. 38.00-. 0% Hills built a gas-fired plant near Las share net for 2003 and 2004 will approxi-
"Cas:h Flow ' 10.5~. 14.~ 4.Vegas and signed a 15-year agreement mate the 2002 tally. (Our 2003 estimate is
5:g~ 1tg~ N.~ with Allegheny. which was to supply the a bit lower because we ve included some
Book Value 9.5"10 13-5~. fuel for the facility and market its output. charges that management has excluded
Cat- QUARTERLY REVENUES (S mill) F II Since then. Allegheny has become finan- from its guidance.) Net income is up in
endar Mar.31 Jun.30 Sep.30 ~.311 Y~ar cially weak and the pact became unattrac- 2003 thanks to higher gas production and
2000 2479 3370 4532 5857 16238 tive for Allegheny, so it benefited both prices and a reduced loss at Black Hills
2001 561:7 419:1 302:4 275:4 11558:6 parties to end the deal. Black Hills is look- telecommunications joint vent~e.
2002 95.8 105.4 112.6 110.1 1423.9 mg for another counterparty, but beca~e The c;ompany has been active WIth fl.
2003 290 290.410.9 368.1360 future cash flows from the project are like- nancU1g moves recently. In April, Black
2004 375 375 425 400 f575 Iy to be lower under any new agreement, Hills sold $118 million (4.6 million shares)Cal EARNINGSPERSHARfA Full the company recorded a net impairment in common stock. In May, it issued $250
end~r Mar.31 Jun.30 Sep.30 Dec.31 Year charge of $0.06 a share in the September million of 10-year notes. In August, the
2000 .42 .38 .71 .83 2.37 qua~er.. We have treated this as a nonre- co~pany reached an agr~ement ~or a ~?15
2001 1.37 1.34 .61 .18 3.42 curnng It!!m. ~Illion, three-year revolvIng credit facility.
2002 -55 .54 .64 .60 2,33 !3lack HIlls has completed the sale of Finanees are adequate, but there is room
2003 .62 .48 ,60 50 2.20 Its hydro .assets. Because these plants for improvement; for instance, the fixed-2004 .55 60 63 .52 30 are located 1!1 the East, they are not a good charge coverage is only average.
Cal QUARTERlYDMOENDSPAloe. Full fit geographIcally. The proceeds were $186 This untimely stock's yield is a bit be.
end~r Mar,31 Jun.30 Se .30 Dee.31 Year mill~on. and Black Hills recorded a nonre- low the in~ustry average. For the 3- to26 26 26 26 104 curnng gaIn of $0.14 a share on the sale. 5-year penod, annual dividend growth
~~~O '27 '27 27 27 l OS The company used $91 million to payoff should continue. but with the stock now
2001 28 28 .28 ,28 112 relat~d debt and interest-rate swaps, and trading within our 2006-2008 Target Price
2002 .29 .29 .29 .29 1:16 it mIght use the rest to retire additional Range, total-return potential is unexciting.
2003 .30 .30 .30 debt. The !;ale will dilute annual share net Paul E. Debbas, CFA November 14, 2003
(A) Diluted EPS. ExcJ. nonrecurnng ga,n report due eany ~eo. 16) J,1cencs histoncally (D) 'n mill" adj. lor stock splits. (E) Rate base: Companys financial Strength (losses!: '98. ((IC!: '99. 3c net: '02. IEc) nel: paid in early Marcn. ..ne. SeDI.. and Dec. Net orig. cost Rale allowed on com. sq. in '99: Slack's Price Slabllily '03, (3c) net. '00 & '01 EPS conl add d~e 10 . Divd re,nvest!1'en:
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change In shares outstanding. Next earnings I deferred charges. . -
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: E "",;1.. S4.121sh. 12.0~'.. Regulatory Cninate: Above Average. Elrnings Predictability
0 2003, Value line Pvbbstung, Int. Ail "9n~ ",e""'d. Factual Jna'.enaJ ~ '::z.:~ ..,: 30"-":,, CO"ved 10 be "haole ard IS ~ed w~houI wa.anne, at any kmcl.'!"HE PUBLISHER IS NOr;~ESPO!~S'eLE FOR A~V ERRORS OR CMISSIC'
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HAWAIIAN ELECTRIC NYSE-HE 1780
RECENT PIE Tiding: 16.G\ RELA1IYE DlV'OPRICE . RAllO . Median: 1101 PIE RATIO YLO
TlMEUNESS 5 lNe'Ed&20"O3 High: I 44.6 39.8 39.5 41.5 42.40.5 37.41.3 49.Target Price RanLow:! 34.8 32.1 33.3 32.9 36.4 28.1 27.7 33,6 34.2006SAFETY 2 na.se-J21~U2 LEGENDS 2007 !2008- 1.011 DivIderds P $IITECHNICAl 3 ~1I1~O3
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10 Bur 94 B6 82 shares I yr. 1.4 45.510 Sd 65 74 76 traded 3 yr, 67.0 26.HlIf" 11422 11450 11364 I, "II 11,.1 , I III II I I 5". 53.7 64.81987: 198e 198911990 199111992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 oYALUELlNEPU8.
INC.36.28, 35.43 ~1.s7 ~ 46.12 45.41, 41.65 41.27 .41.48 43.53 45.72 45.90 4624 47.29 52.11 48.52 44,93 46.15 4U5 ReYenuespersh I 54.7504: 4.78 5.29 i 4.43 4,74 i 5.02 4.46 5.05 5.45 5.62 6.01 6,46 6.70 6.17 6.67 7.04 US 7ofS "CashFlow"persh I 707585 : 2.90 3.06! 2.02 2.40 I 2.54 2.38 2.60 2.66 2.60 2.76 2.96 2.89 2.54 3.19 324 UD US EarnIngs penh" 10083 , 1.95 2.07 . 2.17 2.21 2.25 2.29 2.33 2.37 2.41 2.44 2.0\8 2.48 2.48 2.48 2.0\8 148 2.48 DiY'd Decl'd per sh . .2.4878 j 5,88. 6.90 6.50 6.831 8.06 8.11 00 6.54 6.66 .4.62 5.19 4.17 4.DB 3.55 3.48 5.00 5.50 Cap1$pendinjpersh . 3.2519., 21.95. 23.18 23.29 24.36 22.12 2324 23.80 24.51 25.05 25.54 25.75 26.31 25.43 26.11 28.43 29,fS 3O.fO SookVWepersh c 33.DD17.50 I 20.68: 2127. 21.92 23.87 24.76 27.68 28.66 29.77 30.85 31.90 32.12 32.21 32.99 35.60 36.81 38.00 38.25 CoaImonShsOutst'
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39.0010.3 : 10.3 , 10.9 i 162 142 15.3 15.5 12.5 13.5 13.7 132 13.4 12.1 12.9 11.8 13.5 WI .. Avg Ann1P1E Ratio f2.5691 .86' .83, 1.20 .91 .93 .92 .82 .90 .86 .76 .70 .69 .84 .60 .74 I.JrJe Re!ativePJERatio I 6.2".: 6.5': 6.2".! 6.6% 6.5" 5.8~ 6.2"t. 7.2"1. 6.6"10 6.8% 6.7% 6.8 .1% 7.5% 6.6"10 5.7% AvgAnn'DiY'dYield I f.7r.
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1142.2 1188.5 1295.9 1410.6 1464.14852 1523.3 1719.0 1727.3 1653.7 f7BD 188D IImnues (SmDI) 2r35682 802 84,4 B52 103.3 1132 111.1 84.6 109.8 1202 ros no NetPlUlil
.'
120LTDebtSI263.5rM1. LTlnterest$82.JmiB. 40.8% 39.8% 39.8% 39.8 34.9% 33.5% 33.9% 41.670 34.670 34.6"10 36.OS 35.rI. Income Tax Rate 37.or.Incf.S200miLS=.obbg.pfd.secur.ofbuslsubsid. 15.9% 16.3% 18.1% 20.7% 16.5% 14.8 6.1% 9.11% 5.9% 4.8% I.OS "OS AAJDC%IDNetProfil I(L T interest earned: 3.0x)
Pension AsseIs-121D2S589.1 miD. Obfig. $728.48.6% 48.1% 48.1% 48.5% 43.4% 44.7% 47.2'1. 58.4% 56.9% 52.0% sr.o. 5f.OS Long-TermDebtRatio I 48.OSmin. 44.8% 45.7% 46.2"1. 46.3% 44.0% 43.1% 41.4% 39.9% 41.6"10 46.5~ U.or. of7.5S Common 'Ratio ; SD.SSPld Stock S34.4 mill Pld Oiv d $2.0 mill. 1435.9 1493.5 1578.1 16702 1851.3 1918.9 2049.5 21012 2235.8 2251.0 23SD 2420 Total Capital (SmIIQ 25SD114.657shs.4"'~1O5V.%,S2Opar.calLS20to 1543.1677.8 18082 1941.8 2019.2093.4 20662 2091.3 2067.5 2079.3 2nS 2f6D NelPIant SmID) 2O5DS21: 260.000 shS. S'.IO S!..%. 5100 par. call.
S101: Sinking fund ends 2O1S. Exd.preferred 6.4% 7.0% 7.0% 6.7% 7.0% 7.4% 6.S% 5.9% 6.7% 7.3% f.DS f.5% ReturnonToIaICap' f.5%stock due within 1 year. 9.2"1. 10.3'/, 10.3% 9.9'!. 9,S% 10.7% 10.3'/, 9.7% 11.4% 11.1% ,.0. r.ss ReturnonShr.Equi1y iDSCommon Stock 37.410.715 sh5.ls of 811103 9.6% 10.7% 10.6% 10.2"1. 10.6% 11.4~ 11.0% 9.8% 11.6% 11.3% ,.0. r.ss Return on Com . ,.or.MARKET CAP: SI.7 billion IMid Cap) .4% 1.1% 1.1% 3.0% 3.0% 1.8% 1.5% 1.7% 4.4% 4.3% US !OS Relalned1DComEq I 3.DSELECTRIC OPERATING STATISTICS 96'J(, 91% 90% m 76% 88'J(, 84% 63% 63% ARDiv'dsIoNelProl I
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BUSINESS: Hawaiian Electric Industries, Inc. is the parent c:ompa- iI '01. EIecIric rev. breakdown. '02: residential, 34%; convnelCial.i.'f1lCs Uso!rol,/o'. 6686 6679 6659 "I 01 Hawaiian Electric Co~ (HECO) & American Savings 34%; Iatge ight & power, 31%; OIlIer. I%. GeneIating sourteS, '02:ki': 1!J'.s!. AM. 9 ~'
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11.29 11.27 10.70 Sank lASS). HECO & lis SIbs., Mati Electric Co. (MECO) & Hawai oil. 62%; purch., 38%. Fuel COS1s: 39% of revs. '02 reported depr.~3IYail'll:!"" ~~ m~ mg Electric lIght~. (HaCO). eIecIricity 10 410,000 rate (uIiIiIy): 3.9%. Has 3.200 empls.. 38,400 com. stockholders.t~~.:;~ 73.7 72.72.8 on Oahu, Mall, LfoIokaI. Lanai. & HawaIi. Operating cas. systems Pres. & CEO: Robert F. Clarke. Inc.: HL Addiess: P.O. Sox 730,iR.;:CIaImo:3:.:-:-.: +1.3 + 1.3 +1.are not iIten:onneded. Discontinued iltemationaJ power subsidiaIy HonoIUu. HI968Q8.0730. Tel.: [phone]. Web: www.hei.com.
F:J;:IC/!a't1;c.- '234 259 289 Hawaiian Electric Industries' earn. pacity continues to be held up. So far
'....
51 ings will likely decline in 2003. The HELCO has spent $83 million to add a~=~::S I
:VIS. f~ Es ~O2 single biggest reason for the sharp decline much-needed plant on the Big Island. ButRevenues" 1.00'. 1.5% 0% is a $16 million aftertax swing in pension various intervenor groups have thwartedCash FIow- 3.5: 3.0% 2.5% costs, from $4 million in income in 2002 to the utility's plan, so far. HELCO will pur-5~Jd~s fg.;~ 2
~~ :
a $12 million expense ' this year. In addi- sue various avenues to complete the facil-Book Value 1:5~~ 1.5% 3.5';' tion, HErs American Savings Bank (ASB) ity, including litigation, talks with inter-Clio OUARTERLYREVENUES(Smilll Full s,!bsi~ary is in~g costs ass~ated veno~, and ~ request f~r rezoning.endar Mar.31 Jun.30 Se .30 Dec.31 Year WJ~ Its transfonna~on from a u:aditional ASB 18 faCIng a notice of tax assess-2000 4010 4131 4459 4581 17190 thrift to a full-semce commerCIal bank. ment from the state Department of2001 433:3 427:4 447:3 419:3 1727J ~o, Its interest-rate sp~ead h~ shrunk ~~on. I~ is being assessed $17.~ mi!-2002 409.431.6 435.7 1653.slightly. Not ~very trend IS negative; ~B lion, Inclu~g Interest,. for credits It2003 424.6 448.8 453.452.9 f780 has lowered Its loan-loss reserve and In- booked dunng the penod frDm 19992004 455 465 475 485 1880 creased its fee income. Nevertheless, the through mid.2003. H the ruling is unfavor-I- EARNINGS PER SHARE" F II negative factors outweigh the positive able and the company can no longer record
~ar Mar.31 Jun,30 Se .30 Dec.31 Y~ar ones
, .
so we expect share n~t to decline these cr~~ts, net income would be reduced90 59 67 37 2.54 14% m 2003. HEI stock IS ranked 5 by $4 million annually. Our estimates and
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83 .78 '85 '73 319 (Lowest) for Timeliness. projections will include the credits as long2002 '75 '87 '91 '72 314 We estimate just a slight earnings in. as ASH is still booking them.2003 :66 :69 :81 :64 2.80 crease in 2004, based on 2.2% kilowatt- This stock's ~e)d is more than one2004 .67 70 83 .65 2.85 hour sales growth. flat pension costs, and percentage pOInt above the averageCal- QUARTERLY DIVIDENDS PAID B. Full moderate gro~h o . J.!3B. O?T estimate for electric utility; stocks ~ a ~oup,endar Mar.31 Jun,30 Se .30 Dec.31 Year could prove \?ptimiS?C If pension expense That has attracted mcome-onented l~ve~-1999 62 .62 .62 .62 2.48 worse~s, as IS possible under .a ~ange of tors to such an extent that the quotation IS2000 .62 62 62 62 248 scenanos that HEI presented In Its 10-Q now higher than our 3- to 5-year Target2001 :62 :62 :62 :62 2:48 form f~!" June 30~. Pric~ Range. As ~ re~ult, total-return po-2002 .62 .62 ,62 .62 2.48 Hawall Electric Light Co11!pany's tentlal over that tIme IS poor.2003 .62 .62 .62 (HELCO) plan to add generatmg ca. Paul E. Debbas, CFA November 2003(A) Diluted EPS. EKcl. gain /lossesl from dis. Nell ~mings ~rt due lale Jan. (B) Div'ds OIig. cost Rale. allowed on com. eq. iI '95: Company's Ananctal Strength cant. ops.
: .
92. 153.02): .93. (SOc): '98, (31 C) hlSloncaUy paId 1'\ early Mar.. June, Sept. and HECO. 11.4%: 111 '01: HElCO, 11.5%: In '99: Stock's Price Slability 100net .99, 12c: .00.ISI.12): '01, (71C): '03. Dec.. Div'd reinvesL plan avail. (C)lncl intan- MECO, 10,94%: earned on avg. com. eq., '02: Price Growth Persistence (lOci. .00 & .02 egs. dont add due 10 rounding. g. In '02: $5,521sh. (0) In mill. IE) Rale base: 12.0%. RegulalOry Climate: loJJave Average. earnings Predictability I) 2003, Value Lllle Publoshong. loe, All rights reserved. FaauaJ melonal is Ob!ained from SOUit95 bebved 10 be reliable and IS provided without wanantJes of any kind.THE PUBUSHEA IS ~,()T nOSPONSIBLE tOR ANY ERRORS OR OMISSIONS HEREIN. This ~,on IS stnC1ly lor Subscribe(s own. non-ccmmen:iaL iIIomal",e. No pari0 ~ "'" ~, r=o-",-,: !E;::, S!0f20 ,. lI,nSIlIlII1,1 " any DM!e4 elednil1lC or OIlIer Iorm. or IJsed lor gerJelilling or ma""lIng any pnn1ed or elearono:: 1II.IJ/IcatJon. seNU or pItIducI.
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TIMEUNESS 3 Rmo 11 ~~O3 : I 2 33.0! 30.6 30.0 34.3 37,8: 38.1 36.5 53.49.4 41.0 ' 27.Target Price Ran27.3' 21.8 23.4 27.3 28.5' 29.9 26,0 25,9. 33.6 20.9 20.2006 2SAFETY 3 LOI',aealQ3 LEGENDS 7 12008'06 I u""'enosD so
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0&-1)811.61: 12.: 14.60 '3.E8 "22! 13.761 14.57 14.45 1451 15.38 19.90129.83117.50 27.150.10 24.22.50 24.60 Revenuespersh 30,79! 2.e.t 3.~3 ::3 3.26: 3.16! 3.53' 3.39 3.89 4.05 4.22: 4.691 50 5.63 5.63 4.081 3.601 4.601"CashFlow persh i 5,30' 132 .,37 1 31 156; 155; 1.97, 1.801 2.101 2.21 2.32; 2.37: 2.43 3.501 35 1.631 10M I I.BOEamingspershA '1.80 1.80. :03. 'as 1.86, 1.86: 1 1.86 1.86 1.86 1.86; 1,861 86 1.8SI 1.86 1.8S1 1.701 f.20Divdl)e(;l'dperShB.1.201.15 ! 1.64 . 1 78 - -- 3.94 i 326 i 3.32 i 2.94 2.23 2.49 2.51 I 2:37! 2.95 I 3.73 4.78 3.53 . 3~! 5.65 Capl 5pending per sh 5.751729, :6.81. 17 35. ,;~O 17C6 17.28! 17.86' 17,91 18.15 18.47 18.931 19.42i 20,02121.82 23.15 23.01 22.35122.95 BookYaluepershC 24.9033.98: 33.981 33.38 ;3J!---33.9B. 35.191 37.09; 37.61 37.61 37.6t 37.61' 37.61137.37.61 37.63 38.02 38.201 38.20 CommanShsOutsl'go, 38.2019.2,17.1 , to.9. '3~ '6.8, 17.0i 15.4; 13.12.4 13.7 13.6i 14.4! 12.7 10.9 11.4 18.BofdliWa... AvgAnn'IPIERatio I 15.51.28.1.42, 83 ::0 ")7, 1031
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1 .83 .8S .781 751 72 .~t .5~! 1.03 ...1w!1Jne ReIative~~~atio 7.2',. 8.0",. 710 71'; 1.0 6.1,. 7.4.. 7.2%! 6.1% 5.9% i S.~ ! 6.0% 4.~ 4,~1 6,""'*t"" AvgAnnIO,vdYield 4.1%
~~:e~~~~~~~ ~~::~~: $398.4 mdl.
540.4: 543.7 l 545.6 '5785 748.5 11122.0 I 658.3/1019.5648,0 928.8 I 860 HO Revenue
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LT Debt 5923.7 11'111. LT Interest 558.2 mill. 78.2; 74.86.9 90.6 92.3 I 94.8 96.9 i 137.6 130.0 66.40.0! 70.0 I Net ProfitlSmlDt 75.
LT interest nOI ea.'Ik."!IJ 31.800 ' 31.4"'35.80/, 365% 33.5% 1 32.0% i 32.0". i 32.1':0 33.3'-.. .. 33.0% 310% IIncome Tax Rate I 33~
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6".. 1.7% .4% .6%: 1.3'1, 1 3~ ! 3.6% 3.1% 00:" I 3.0% 3.0% IAFUDC%toNetPlOfit ' 3.Pension Assets-121O2 5202.: mill Obiig.5294.5 45.6', . 46~ i 45.2% I 48.0% 48.2% I 49.4':0 I 48.~ i 48,3% 48.4% 49.2'.~ I 49.0%: 4B.5% !long-Term Debt Ratio i 46.5%mill 44., 44,9".. I 45.9% I 45.1% 48.8% I 44.2"., 144.8":. i 45.9% 47., 47.9"., I 48.0% I 4B.5% ICommon EauiIv Ratio 51.0%1488 9 i 14995 I 1487.1540.1522.2 11652.3 : 1680.3 ! 1790.0 1818.0 1826.9 I 17751 1BOO IToial Capital (SmID) 18751616.4, 1656.6 i 1672.9.1694.6 1716.9117115 11745.7 ! 1805.0 1886.0 19065 I 19551 20651NetPlan\lSmIDI ! 23506~' 7.6% 7.8%! 7.3%17...19.2% 8,7":0 5.1"/m1 Return on Total Capl 18:, 9,3~; I 10.11.3% 11.:r"'11.~! 11~ i 14~ 13~ 7.5~! 7.5'/0 Re\umcnShr.Equ~ i 7.5%Common Stock 38.196.28i ;;!IS. 10.9', 10.0"... 11.6":0 11.9% 12.2% 12.2"., i 12.10, 116.0"~ 14.4'1;, 0"., 4.5%, 1.0% Retumon Ccm Eauitv E 7.5%MARKETCAP:S1blllion(MidCap) :"'1 NMF' 1.3'1011.9'10 2.4%! 2.6% 2.9"..: 75% 6.3% NMFi NI.fF; 2.5%iRetainedtoComEq i 3.0%ELECTRIC DPERATING STATlsncs 940 ' 1~,90"~ I 86% 82% I 80"'.. 78~; I 55% 58% 11:F.1 NMF! 6S% !AJI Div'ds to Net Prof 65'"
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~OJ'.~ 2?1 BUSINESS: IDACOAP, Inc. is 1he holding company for Idaho pcwer cost 30% cf '02 rev.; estimated labor COSIs: 9,7~.. 200220B43 i!0074 28071 Power. a hydtoelectric uIiii1y that partly owns three coal plants and depreciation rate: 3.0~.. Fuet sources: hydro. 450.: thermal. 55~...
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markelS natural gas through 1rading operations. Also has interests Has 1.942 employees, 20.088 common stockholders. Chairman:2219 2570 29i3 11 a patented fuel ceU sys1em. Sells electricity in Idaho (97% cI Jon H. MIller. CEO & Pres.: Jan B. Packwood. Incorporated: Idaho.;~A NA NA revs.) and Dregon (3%1. Revenue breakdown: residential 35'/': Addr.: 1221 W. Idaho SL, Boise, Idaho 83702. Tel.: [phone].~ T 0 +2,commercial. 230,: mustrial 20%: other. 22%, Fuel and purchased Internet www.idacorpmc.com.
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"tedC"...-,.::c. " .129 295 115 IDACORP's nonutility businesses will went on line in 2001. Recoupment of the
ANNUAL RATES Past Pasl Est'd '00-'02 probably post a loss this year. To put plants' operating costs will be made
ofcha:1OelDE'S!"' IOYrs. 5Yrs. 10'06-'08 an end to deficits in energy marketing op- through the power cost-adjustment me-Revenues 17.. 32.
. -
14.erations, management agreed to sell its chanism. The filing includes a request forCash Flow" 4., 5,Nil book of wholesale electric trading con- $20 million in immediate interim rateEarrungs 5., 5.
Divi~ends
- - -.
-8.0". tracts to Sempra. The transaction was relief. A regulatory order on the applica-Book Value 3.0'. 4.0".. 1.5.finalized in September. Elsewhere, IDA's tion is due next May.Cal- OUARTERLYREVENUES(SnulLl I Full patented f~el cell SJ:s~m .that conv~rts We look for a sharp eamings decline
endar Mar.31 Jun.30 Sep 30 Dec.31 Year hydrogen mto electriCIty IS undergomg in 2003. In addition to nonutility losses.
2000 166.3 254.6 :!-j'
:~
277.5 1019.field t~ts and will likely record a small the settlement of a power contract and the
2001 133 1579 2115 821.0 5648.l?s~ thIs year. To?, ldawest E!1e~. a sub- absence of last years tax law benefits will
2002 239.6 209.8 2S9.c 219.8 928.sJdlary ~hat ha~ Investments In mne 5T!1all shave earnings by $0.64 a share. Thus,2003 '211 9 200.2391 208.860 generating projects, and the commumca. despite an expected 0%-5'k increase in
2004 230 220 260 230 940 tions division would do well to break even retail energy sales, we estimate 2003 earn-Cal- EARNINGS PER SHARE A Full in. 2003. The onl~ probab~e noncore c~n- ings will fall almost 40%, to $1.00 a share.
endar Mar 31 Jun.30 Sep 30 Dec 31 Year tnbutor to net this year 'IS the financIal An expected increase in rates on the afore-2000 ~ S" . ; 1 ~3 ' 350 arm. which receives tax credits for its in- mentioned request suggests an earnings2001 93 .~1 :55 I 3:35 vestments in afforda~17 hous~g. Overall. rebound in 2004.2002 .66 j8 38 d.09 I 1 63 we expect the nDnutility busmess- es to The annual dividend was reduced2003 d OS J.02 ao .14 1.00 lose about $0.30 a share in 2003. from $1,86, to $1.20 a share, effective
2004 .30 .20 1.05 .25 80 The company has filed a general rate with the December payment. The actiontal. OUARTERLYOIYIOENOSPAIDB. I Full case. T~e petition asks for an $86 million was taken because profits didn't cover the
endar Mar.31 Jun.30 SeD,30 Oec.31 i Year annual. Increase. based on an 11.2% return disbursement in 2002 and probably won1999 ~65 .465 .;65 .465 t8G on equIty, up from the ~urrent ll,O'k.. It this year or next. Since the reduction was
2000 ~65 .465 46: -165 1 86 seeks recovery of expen~tures to plant In- widely expected. it had minimal effect on
2001 ~65 465 ~1)5 J65' 1 86 frnstructure, demand-s~de m~agement share price, At the stock's recent quote,2002 . ~G= ~65 ;.;: ;65 ;85 costs. and the $50 mill1Dn capl~al outlay IDACORP is an average electric utility.
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!"!1 cost. Rale allowed on com. eq. in Idaho in Company s Financl~1 Strength 87, 33c: 93. 1&: ~2c. ~", ~6c. NEXI egs. ,May laiC Aug.. and late Nov. . DlVd reinvest. 95: 11.0%. Earned on 02 avg. system com. Stock s Price Stability 'PI. due late Jan, '~9 ;;aleS J~ ",I ,m;' 'lading I plan a';311. (C) Incl. deferred debits. In '02: eq.: 7.1%. Regul. Clim.: Above Average. Price Growth Persistence Ievs. Beg'n. CO; 'nc! ';I::i!'; ~ '.~..;a' .a';;; ; $12.68:sn. (0) In mill. (E) Rate Base: Net ortgi- Earnings Predictability ;2003.Va.'ueLV'-eP",-",
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64: .70 .83 ,96 1.01 1.20 1.47 '.23 60 1.60 Eamlngspersh .42 ' ,42 I .44 i .42 .43 .43 .44 : .47 i .48 I .49 I 50 .52 .55 I .57 ,60 .63 .66 70 Oiv'd Qecl'd per Sh B. .8232. .69! .41i -66 .70 1.1 161: 1.271 1.31! 1.75 1.77 1.22 1,94 116T 2.03! 2.49 3.20 Cap Spendin9persh 3.25~13; 4.37; 4.48' 4,48! 4.63 4.7: 4.96' 5.10! 5261 5.47 6.10 6.92 7.82 9,03' 10.60; 11.56 12.55! 13.60 BookYaluepershC 17.2561.84 i 64.07 64.07' 64.07 64.07 64.07. 64.07: 64.07: 64.07 i 64.07 63.32 79,55 85.56 97.54 1O4.67! 111.06 114.00 117.00 Common Shs 0utst'9 D 126.15.0: 10.4j 10.7: 11.3 11.1' 13.5. IS.! 118
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7! 13.9 13.4 16,6 15,13.2 13.14.Boldfigjltesoro Av9Ann IPIERalio 13,1.00 : .86! .81 ' .84 .71 . .82 .89 ! .
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bIS~38.6 mi
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7',; 9.1~! 8.6!'6% 9.4%/8.8% 8.2",(, 8.4% 9.2%7.3% 5%18.00" RetumonTotalCapas 01 816103 11.6'. i 11.6\ ' 11.8~. . 12.4% 13,6% 13.0% 12.3% 12.4~~ 113% 10.1% 12.5% I 11.5% Return on Shr. Equity 11.0%(Adlustedfor3-lor-2splijpaid101301D3.) 12.0".~11.9~ 12..112.7% 13.9% 13.12.4% 12.5% 13.4"10 10.2% 12.5%i11.S%Re\umonComEquftvE: 11.MARKET CAP: 52.6 billion (Mid Cap) 2.9".! 2.8% 0".. j 3.8% 5.5% 5.9% 5.7% 6.5% 7,9% 7.5% I 6.5% Retained 10 Com Eq 6.ELECTRIC OPERATING STATISTICS 76'.; 77".. 76'... I 71% 61% 56% 55% 49",(, 41% 52% 42% I 44% All Oiv'ds 10 Net Prof i 43%::-,?~SaiesiXWrij ~~~ 2
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BUSINESS: MDU Resources Group, Inc. is a diveroified energy gas production, aggregates mining, constructian materials produc-J ~....s:.l!se~lWri, 933 947 999 company. Mantana-Oakota Utilities sells gas & electricity to tion, ulifity line construction & maintenance.'indep. power produc-: =fo?/S.~J(VIHIt: 4.55 4.66 4.67 294.000 customers in North Dakota. Montana. South Dakota. Wyrr lion. '02 depree. rate; 5.2%. Has 7.000 employees. 14.000 stock.5~;~~M.;
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rev. breakdown; '02: residential, 37'1'0; holders. Chairman, President & CEO:Marlin A. WMe. Inc.: DE. Ad-~.,.. .;.;:G-j;acc," 55.0 53.0 54,commeraal. 38r.: Industrial, 10%: other. 15r.. Genera,,!,!! sources, dress: Schuchart Bldg., 918 East D,vide Ave. P.O. Bo. 5650, BIS....~:.str;-..asll...' +9 +.2 +'02: coal. 71%: oil & gas, 1~'.; purch.. 28%. Also: gas plpeUne, o~ & marek, NO 58506-5650. Tel.: [phone]. Web: www.mdu.com,"=~"3.,.~'I.I':: 397 506 441 MDU Resources is on track to post lion (9.1%) electric rate increase in North
Past Est'd 00-'02 large earnings increase in 2003. The Dakota and reached settlements for gas~~~~ ;:,~~ 1
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5 YIS. 10 '06-'08 biggest reason for the improvement is tariff hikes totaling $2.4 million in Sol1thReven~es 13,5% 18,5% 4.5~. sharply higher oil and gas prices, along Dakota and Minnesota. The gas transmis-Cash Flow" 8,S~ 8.5% 0~ with a likely 10%-12% rise in production. sion segment should see throughput rise5~~'~~Js g:g~t 1
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~:~!: But MDU is more than just a commodity 25% since a large pipeline project will goBook Value 8,5% 13,
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0~ play. The company's COnstruction mate- into service in the fourth quarter of 2003.Cal- QUARTERLY REVENUES (SmilLj Full rials division is also fari,ng well, ~hanks to Finally, the utility.services division ?aendar Mar.31 Jun.30 Sep.30 Dee.31 Year the ~ffects of a federal ~g~way bill, a good had ~wo c.onsecu~lve tough years, but It IS2000 372.0 3630 530 8 6079 18737 housing market, acqwsltions, and favor- shoWIng SIgnS of Improvement.2001 6412 546:4 551:7 484j 2223:6 able .weathe~ condi~ons. Our $1 60 share- The board ?f, directors boosted the2002 3545 4802 6124 5570 2004 I earnings estImate IS near the high end of quarterly diVJdend by one cent a2003 467:8 5482 716:' m9 2310 MDU's target, which it raised moderately share (6.25%) in August, We had expect-2004 490 595 765 640 2490 in September to $1.47-$1.63. (Note: All ed a slightly smaller increase. The moveCal EARNINGS PER SHARE A F II per-share data have been adjusted for a 3. continued MDU's long track record of an.end~r Mar31 Jun.30 Seo,30 Dee31 Y~ar for.2 stock split paid October 30th.nual dividend increases, which it should2000 15 23 ~2 :i7 120 We estimate flat earnings in 2004. be able to maintain over the 3- to 5-year2001 33 37 '49 '28 1 47 That's in line with MDU'6 guidance of period and beyond, The company s fi-2002 '07 23 'SO '42 123 $1,50-$1.63. We look for a decline in oil nances are in excellent shape, and earn-2003 :25 :39 :57 :39 60 and gas profits, assuming that realized gas ings growth over that time-frame should2004 .20 ,40 .60 .40 1.60 prices Iwhile higher than historical levels) give it the wherewithal to continue raisingC I QUARTERlYDMOENOSPAlOB. F II are somewhat below the lofty level of 2003. the disbursement.~~r Mar.31 Jun.30 Seo 30 Dee.31 Y~ar On the ot~er hand, the other divisions This high-,uality stock's yiel~ is €?om-133 .14 .54 ought to pI~k up t~e slack. The cons!ruc- P3!~~le WIth that of most dl~ers1fjed
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:14 .147 .57 tlon matenals ~uslness sho~d continue utJhtles. At the current quotatu:m, total-2001 :,47 .147 .147 .153 59 th~. moment~ It gathered In 2003. The return I?~tentlal to 2006-2008 IS a cut2002 .153 ,153 .153 .16 .62 utihty operatIons should benefit from rate above ubhty nonns.2003 .16 .16 .17 relief, as MDU has requested a $7.8 mil- Paul E. DeMas. CFA November 14, 2003IA) Diluted EPS. Excl. nonIecumng gaInS
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Iepon due late Jan. (B) Dividends historically adj. for splits. IE) Rale base: varies. Rales al- Company s Financial Strength lIosses): '93. 9c: '98. IS2e), 01, 6c: '02. 1Sc: paid III early Jan., Apr.. July, and Oct. . Oivi- lowed on util. com. eq.: 11.4%-13.0%: earned Slock's Price Stability 03. 17c). '00 EPS don . add due '0 change In dena Ielnvestmenl plan available. (C) Incl. de. on avg. com. eq., '02; I I .2%. Regulalory Price Growth Perslslence hares out: '02 due to rounding, NeX! earnings lerred charges: In '02; $3.31/sh. (D) In mill.. CUmale: N0, MT, Avg.; SO, Above Average. EarningS Predictability I) 2003. Value Lme Publishing. Inc. Ab I19hts ,esOJY~. FaC1ua' malenal IS oblallleO lrom sources be".Wd 10 be ref:able and IS P/OVIded W11I1ouf wallant'es 01 any Iund.THE PUBLISHER IS NOT RESPONSiBLE FOR ANY ERRORS Oq OMISSIONS HEREIN. ThIs PublICa""" is slriellY 101 sUOSCriber's own. non-commOltiaI. JlJ!Bmal use. No pan
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Pfd Stock 512.8 mil. Pfd Div'd S.6 rnia. 1596.4 I 1450.5 11444.5 11481.0 115312 1896.19012 1891.3 11978.7 1966.9! 2030! 2065 iTofaf CapitallSmiII) 2180 128.oooSI1S.4.58~,S100parw/omandatOl)' 1703.9; 1696.7; 1574.411552.7115732 1593.8 1582.1617.3; 1781.0 1867.3' 1915! 1945INe1Plant(Smm\ 2015redemption. Sinking fund began 211184. 5.9":,: H'!-.! 6.2':,! 6...! 6-7"-' 6.9",(, 5.,," r 6'i. I 9.50,;. 4.7", I 4.5% 0'10 !Return on Total Cap
~ 110.7'~! 8.5"5% i 9.7% 11.8% 8.8~.! 9.9% i 15.3% 6.5~ I 6.5%7.0% I Return on5hr. EquIty Common Stock 40239294 shs. Is of 8/1/03 9.2'. : 11.0'.! 7.9'~ 9.5% I lI"k 12.1% 8.8% i 10,0".. I 15.4%! 6.5% I 6.5% ~ 7.0:; I Return on Com EquiNE 0!,MARKET CAP: 51.1 bOnon (Mid Cap) 9.2'.. ! 11.0'., 7.9'9 i 7.6% I 6.5% 8.4% 5.2".. I 6.5'- '2.3~3.D"4 I 3.5% !Retained to Com Eq 0-..ELECTRIC OPERATING STATISTICS 11'!O ! 8'
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a.. i 21~,! 34% 31% 42'rt I 35~2D'k 53%; sr:.! 52% !AD Diyds to Net Prof 54'
\~IIe!aiSo!!sIK'Mij ~ ~2~1 ~~~ BUSINESS: PNM Resowces. parent of PubDc Service Company 01 coal, 68%; nuclear. 31~: 9as/oit, 1'... Fuel COS!$: 47~, 01 re,:;.
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~h1:stuseM\llI 4163 4252 5186 New Mexico. sells electricity (77% of revenues), gas (23%). other labor COS1S: 16'
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02 jjepreciation rate: 3:4'~. Est'd plant age: 13 !A,y. tWtfie4 oeri\\H(c) 5.16 5.16 5.16 less 1I1an (1'..j i1 nor1h-cenual New Mexico (population: 1.300.000). years. Has 2.656 employees, 15.046 stockhOlders. Chairman. Ch.ef ICaiIaorr~Piai:1521 1521 1742 Lalgest CUStOmer: City of Albuquerque. E1edIic revenue break. Executive OffICer & President Jeffry E. StertJa. 1ncoIp.: New Mex~ I
=~r/ 1J36 ~:Wl ~4.fl c2own: residen1Jal, 35':.: commercial. 43'10; Industrial, 14%; other, co. Address: 414 SilveI Avenue, South West. AlbuquefQ~e. ~ew \~Cus:oaJ!l5I)1i111j +2.0 +2.4 +1.8~. Area's mimry eslablistvnents Ire major customers: Fuels: Mexico 87103. Telephone; 505-241-2477. Internet www.prvn.COrT'.
FixedCl3geCov 1'01 268 481 177 PNM Resources is expanding its the higher rates until next spring. the
ANNUAlAATES Past Past Est'OO-'02 who~esale mark~t~g operations. compromise. was r~jected. As a result. the I
of change (persh) 10YIS. SYIS. Io'O&-W DespIte a sharp decline In wholesale ener- company wJlI continue to earn under 39'r Revenues 8.0% 14.0% .5,. gy prices in the western region since late on its gas utility investment. Management~Cash Flow" 1
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g1~ -f.N- 2001, PNM has done well in this area. It may seek a revised settlement or may turn i
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20 0% 4.5% currently obtains 20% of its revenues from to the courts for relief. Book Value 4.0% 6:S'Yo 3./no this sector, and customers are continually We look for higher earnings in 2003. II- QUAImRLYREYENUES (S l11li1.) being added. Earlier this year, PNM con- Pluses include a retail sales gain of 2w,~r Mar,31 JunJO Se0.30 Dec.31 ~::~ tracted to sen 80 megawatts (mw) annual- higher margins on wholesale operations
2000 321.3 329.0 499.5 461.5 1611.3 ly. for two y~ars to the U.S. Navy in S~ and a .Iower payroll, resulting from 2002:s2001 736.5 6661 6219 3276 2352.1 DIego and WIll suppl:r Overton Powt:r DlS- reduction In headcount. But these POSI- 2002 314.0 264:6 289:4 3O1~ 1169.0 trict in Nevada with 15 mw to 25 mw lives will be partly offset by a $O.24-a-2003 387.3402 385.2 376.9 1490 yearly through 2007. Overall, wholesale share charge in the third quarter for the I2004 400 35S 400 390 1545 sales have i~cr~ased by ~50 mw in 2003. cost of the call premium on retir~d debt. Cal- EARNINGS PER SHARf" F II To meet exIstIng commItments and to All told, we estImate a 9~ rise In 2003 .endar Mar,31 Jun.30 Seo.30 Dec.31 V:ar serve expected rising demand, PNM earnings, to $1.75 a share. Further gains i2000 55 45 ~7 35 2.32 recently began operating three combustion in energy sales point to improved results
2001 60 124 .88 20 392 turbines y,ith a total capacity of 215 mw, in 2004. For now, the stock is untimely.
2002 :63 .28 .45 .25 1:61 and. it is buying 200 mw of wind power ca- The yield. is a full percentage point be- !
2003 .53 .44 .41 .37 1,75 paClty for 25 years from F?L Group. low th~ l~dustry norm. But based on i2004 ,55 .45 .sO .35 1.85 The regulators have rejected the com- our projectIOn of eanlings gains to 2006- :Cal- QUAllTERLYDMDEHDSPAlO Iloo Full pany's gas. rate agreem~n~ with .inter- 2008 and a low payout ratio, di~ojdcnd !
enIIar Mar.31 Jun,30 SeD.30 Dec,31 Vear ested .p~rti~s. The commISSIon denIal of B growth prospects over the same pencd ex- :1999 .20 .20 .20 .20 .80 $22 million mcrease was based on concern ceed those of the group. StilI. the )'2000 .20 20 .20 .20 80 that high natural gas prices in the corning that time y,illlikely remain below the uti1- i2001 .20 20 .2D .20 :So months would increase customers' heating ity average. At the stock's recent price, to- 2002 .20 22 .22 22 .86 bills this winter. Though PNM offered to tal returns are unexciting.
2003 .22 .23 .23 .23 defer collection of the residential portion of Arthur H- Medalie Not,ember 14, 200.
(A) EPS diluted. Next egs rept due late JaIl. 21c: '01. fISc): '03, 69c. fB) Div'ds hlStorically
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base: net O"g, cost Elect. ROE allow. In '90: Company s Financial Strength BOoExd. nonrecur. gains (losses): '88, (S4.81); '90. paid i1 mid-Feb.. mid-May. rnld-Aug.. and mid- 12.52%: earned on avg. com. eq, '02: 6.6~,. Stock's Price Stability (55e); '92. (S3.42): '93, ($2.85); '94, 11c: '95. Nov. oDiv'd remyeSl plan avail. (C) lnet, in- Regul. CIim.: Avg. Price Growth Persistence net: 35c: '97. 4e: '98, net (24e); '99. Be: '00. tang. in '02: S9.34!sh. (D) In mill. (E) Rate EamingS Predictability
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INC.106-0815.26 24.11 17.39 18,38 16.'9.391 19.66! 19,28' 19.08120.77 23.52 25.12128.57 43.50 53,66 28.9O! 32.95 33.85RevenuespershF '36.10 3.45 3.27 dl,39 4.701 5.25! 5.O9! 5.161 90 7.12 7.73 7.99 8.72 7.01! 7.40 8.00 Cash F1ow" persh 3.211 2.15 1.441 ,81 113.90 731 1.95 i 1.99 I 2.22 "47 2.76 2,85 3.18 3.35 3.88 2.53! 2.55 3.00 Eamingspersh A 2.781 3.20 .801 .-. '-
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1 .201 .83' .93 1.03 1.13 1.23 1.33 1.43 1.53 1.63! 1,73 f.83 Div dDecl'dpershB. 2.13961 3.06 3.461 2.98 2.10 I 2.571 2.69; 2.92; 3.38, 2.95 3.63 3.76 4.05 7.76 12.27 9.81: 10 5.20 CapISpendingpersh 26.621 23.46 16,31 I 17.40 15.23 I 17.00 i 18.87 i 20.32 I 21.49! 22.51 23.90 25.50 26.00 28.09 29,46 29.44 i 30.25 31,Book Value per sh c I 34.86.Q8 I 86.72 86.72, 86.871 87.011 87,161 87,42: 87.43' 87.52! 87.52 84.83 84.83 84.83 84.83 84.83 91.261 91,30 91.30 CommonShsOUlsl'91.! 10.8 8.7! 16.31 IO,8! 115! 9.61 10.8' 11.8 11.8 15.2 11.9 11.3 12.0 14.41-n~re..", AvgAnn IP/ERatio T f2.563 ,90 .1.21/ -- .661 .681 631 .72! ,74 .68 .79 .68 .73 ,61 ,79! Lm RelativePIERaUo ,9.2% 13,7% 6.4%
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.9'.. I 4.,! 3.9% i 3.5% 3.5% 2.B% 35% 3.8% 3.5% 4.5~i I --r'"' Avg Ann' Div'd Yield , 5.1%CAPITAL STRUCTURE IS 016130103 17185 i 1685.4 11669.8 I 1817.8 1995.0 I 2130.6 12423.4 3690.2 4551.4 2637.3: 3010 3090 I Revenues (Sm/o) F 3330Total Debt$3434.5 miLOue in SYrs $1366.4 mill, 200.81 198,8! 194.4: 198.3 248.7 252.6 i 270.8 283,312.2 215.2 i t35 27SiNeiProfitlSmllli 300&-~btS
~~~; 9X~Tlnterest$181.1 miD. 42.5'
o! 38.2', ! 39.7'. I 39,3~. 37.7'1. 39.5% 38.3% 44,1% 40.6% 39.1%! 39.0% 39.0% Income Tax Rate 39,eres
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3,2A..! 4.7',: 7.2~: 7.4%, 65% 7.4% 4.3% 7,6% 15.3% 20.5% 1 7.D'!. 0% AFUDC"1.toNeIProfrt 1 Pension Assets-121O2 5720.8 min. Oblig. $1.07 56.. I 55.9". ! 53.9~. I 52.0% 50.5% 47.6% 50.0'10 45.1% S1.7% 51.8~.! 53.0% ! 50.5% ILong-Tenn DebtR~o I 47.bill 35.. ; 38., ! 40.
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Pfd Stock None 4674.3 ; 4633.5 ! 4660.4 I 4561.1 4442.9 4307.6 4411,4337.8 5172.4 5557.9 j 586Q mo Tota' Capital (SmRl) 60904601.3: 4624.11 4647.1 ; J655.1 4677.6 mo.6 47785 5133.2 5907,6479.4' mo 6800 NetPlantl$m~n 6930~ 6.,: 6...; 6.2% 7.4% 7.6% 7.9% 8.1% 7.6% 5.4% I 5.5% 0'!. Retum on Total Cap 6.5%8~.! 9.7', i 9.0'.; 9.1% 11.3% 11.2% 12.3'k 11.9% 12.5% 8.0% I 1.5% 9.5% Rewm onShr. Equity 5',(,Common Stock 91.271.421 shs. as 01 8112/03 12.2~1 9.1 9.3~.; 9.2% 11.6% 11.2% 1m 11.9% 12.5% 8.0%! 6.5% 9.5% RetumonComEauitvE 9.5%LlARKETCAP:S3.4 billion (Mid Cap) 11.,: 5.7',! 5.0'., 4.6% 6.9% 6.1% 6.8% 7.3% 2.9%! 2.5% 3.5% RetainedtoComEq "3.5%ELECTRIC OPERATING STATISTICS 9'.. i 49'., 51'. I 54% 44% 45% 42% 43% 41"1. 64%! 68'!. 61% IAII Div'ds to Net Prot 65%
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BUSINESS: Pinnacle West Capital Cotporation (parent of Arizona 24%; nuclear. 18"1.; gas. & olller. 8%: purch. power. 5O"k. Has~ilfJst.UseIIol'llHI 1363 1354 1350 Public Servlcel supplies eJec1r1city 10 appro"- 1 780,000 people i1 6,100 employees: 36,876 stockholders. Aeponed '02 depreciationAvg.Rlistllevs.llenilllHCI 5.82 5.49 5.57 11 of 15 Arizona counties. Electric revenue sources: residential, rate: 3.6%. Esfd plant age: 8 years. Chairman & CEO: WiRiam J.
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FiledO1ameCov.384 375 274 Pinnacle We~t has filed its first gener- the common eq~ty ratio, but th~t ratio
ANNUAL RATES Past Past Est'd 'O()-'02 at rate case In 13 years. It seeks a $175 still exceeds the mdustry norm. Since noDf change (per Shl 10Vrs. 5Yrs. 10'06-'08 million increase in electric revenues, based new plant will be built for a while afterRevenues 8.. 14.5% .2.0"'0 on an allowed return on equity of 11., completion of a 425-mw unit in 2004, con-Cas,h Flow" 13.0 5.5% 2.(P,i, up from the current 11.25%. A major com- struction costs will soon be down sharply.
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~:g~t 5:~~ ponent of the request is inclusion in the That should help boost the common equityBook Value 6.00.. 5.0% 0!'. rate base of five plants built since 1999 by ratio and make borrowing less costly.Ca~ QUARTERLYREVENUES(SmiD) F II PNW's unregulated Pinnacle West Energy Earnings may show no progress inendar Mar.31 Jun.30 Seo.30 Dec.31 V:ar IP'Y~! su~sidiary. If authorized, these 200~. Pluses include the absence of last2000 4881 758.5 1607 836 6 36902 facIlities wIll be transferred from PWE to year s charges of $0.77 a share for the can-2001 938:8 1294 1574 744:6 4551.4 the regulated utility. The app~ication also celation of two plants and a subsidiary's2002 501 6184 8730 644.4 2637.asks for recovery of restructunng and com- loss of two contracts for nuclear fuel casks.2003 604:0 758~ 946:6 700.3010 pliance costs associated with electric com- But these positives will be offset by the2004 630 14() 910 750 3090 petition rules, $234 million written off in a dilutive effect of a late 2002 offering of 6.Cal EARNINGSPERSKARfA F II settlement agreement, and inclusion in million common shares and a lengthy out-end;r Ma~31 Jun.30 Seo.30 Dec.31 v:ar rates of 5.800 miles of recently built trans- age at the Chona coal-fired station. In all,2000 ~2 1 06 1 3- 50 335 mission and distribution lines. The campa. we estimate near-flat earnings of $2,55 a2001 :70 :79 1:77 :42 3:68 ny has requested an o~der by -!uly 1,2004, share this yea~. An o~der on the rece~t2002 .63 .89 1.19 d.18 2.53 the d~y a rate morato?um expIre~,rate request pomts to Improved. results In2003 .28 .61 1.20 .46 2.551 DespIte heavy capItal spending over 2004, Currently, the stock is untimely.2004 .40 ,10 35 .55 00 1 the last three years. finances remain Dividends are growing at a healthyC I QUARTERLY DMDENDS PAID a. Full i strong. Since 1999. PWE has added 1,700 clip. A low payout ratio and our projection~;r Ma~ 31 Jun 30 Sen30 Dec.31 Year i megawatts (mw, of generation at a cost of of steady earnings gains from their pres-1999 325 325 325 35 I 1 $1.4 billion. Because cash flow did not ent level to 2006-2008 indicate above-2000 '35 '35 '35 '3751 1 43 ~nver all of these outlays, the company average dividend hikes over that2001 '375 '375 '375 :40 1.53 I Issued long-tenD debt and equity to bridge timeframe. Utility investors might consid-2002 :40 :4D :40 .425 : 63 I the shortfall, The ratio of offerings re- er these high-quality shares.2003 .425 .425 425 ! suited in a six-percentage-point drop in Arthur H. Medalie November 2003(A) Diiu1ed egs. Excl. nonrecuI.
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S7. I~C: 89. : .S! 9;). 'OG. 22c. Nell egs. rpl. aue late Jan. (0) In mill, (E) Rate base: Fail value. Rate alrd Company s Financial Strength ($2.10): '91. i54.681: '93. 22c: '94. 31c: 95. .~ell B) D:v ds h'slOncally pa,a ,n eany Mar.. early on com. eq. in '96: 11.25'10; earn. on avg, com. Stock's Price Stability 6e: '99, ($1.20): '02, (77cJ: excl. diSCont.: ,~9, I ~~ne. ~art' Sa-OL and eany De(:. . Reinvest. eq. in '02: 8.3%. Aegu!. Cum.: Avg. (F) Excl. Price Growth Persis~ence ($7.80); '90, 31c: '91, 51.76: 92. 7c: 99. tPlan a.,altIC)ir.cl. del. chgs. In '02: S3.9O1sh, sales lax begin. '94, Earnings Predictability 02003 Value une PubltShlno. 'oc. A~ 'chIS res.,.,eo, -
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PUGET ENERGY, INC. NYSE.PSD I~~lr 22.60 1~1ThJ 13.7a~:~~1U)I~k~~ 721~~ 4%1111786TlMEUNESS 4 RaJSed 1Q.~liO3 High: I 27.9 29,8 24,9 24.26.0' 302: 30.3; 28.4' 28.0: 27.8; 23.6; 24.4 !Target Price RangeLow: I 23.9 23.5 16.5 20,1 22.1; 23.5 I. 24.1; 18.6 i 19.1: 18.5 i 16,6 i 18.2006 2007 '2008SAFETY LMredIO1I9.1!1 LEGENOS - oeszOMdenosps/1
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Puget Sound Energy (PSE) was formed 1993 1994 1995 199611997 :1998 11999 !200~02 200312004 !'JVALUEUlIEPU8..INC, '06-08through the merger of Puget Sound Power 17.~9 18.76 18.53 r 18.84 19.83: 22.56 i 24.34 ; 40.06: 38.25.55 24,S0 25.90 i Revenues per sh 32.75&. Light and Washington Energy effective 3.73 3.46 3.58 3.60 3.19; 3.81; 3.98; 4.52: 3.78 3,80 3.90 4.50 Cash Flow- persh 5.00~ebruary11,1997.ShareholdersofWash- 2.00 1.64 1,89 1.89. 1.28i 1.851 1.91: 2.16j l.22 1.24 1.35; 1.7S Earnin9spershA 2.00Ington Energy receIVed .86 of a share of 1.83 1.84 1.84 1.84 1.84; 1.84; 1 84; 1.84; 1.84 1.21 1.00 i 00 : Divd Decrd per sh B. 1.f2PugetSoundP&LstockforeachWashing- 3.50 3.94 2.12 1,90' 3., 4.05' 3.96: 3.56~ 3,1'1 2.3.40'Cap "i"SpendlngpeTSh -rooton Energy share. Data prior to 1997 are for 18.65 18.43 18.48 18.53. '16.06116,00; 16.24: 16,611 15,66i 16.27116.90. 17.70lBookValuepershc 20.50Puget SOund P&L and are not direcUy com- 63.63 63.64 63,64 63.64' '84.56 I 84.56 i 84.92: 85.90 I 87.02 i 93,64! 99.00' 99.5fJ 'Common Shs Outsrg Jj~parable with PSE data. PSE ~anged its 13.6 12.6 11.7 12.6 20.14.6' 12.3: 10.8 ~ 19.1 17-'.! Bordlig!ns- 'AvgAnn'P/ERatio-name to Puget Energy when it formed a .80 .83 .78 .79. 1.18
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76 i .70: .70: .98 ,931 VoIwjUle iRelaOveP/ERalio .80holding company at the start of 2001. 6.7':. 8.9% 8.3% i 7.7', 7.1~: 6." 7.8", : 7.9"..: 7.9'. 5.~ I ~res ,Av9 Ann J Divd Yield 4.5!.CAPITA.lSTRUCTURE as 01 &I30IO3 1112.9 1194.1179.3 1198.8: 1676.9 : 1907.3 ~ 2066.6 ~ 3441.7 i 3374.2392.3 I 2425: 2S75 iRmnues (SmUl) 3300TotaIDeblS2610.3mjll.Dueln5YrsSS36.4~1I. 138.3 120.1 135.7; 135,4 125.7; 169.6' 173.3: 193.8: 113.61 117.130j 175,NetProfit(SmilIL ' 200~DeJ~~:~e=S1~1.37.6% 40.1% 37.9% 38.3~,: 33.2'., 140.0"-.. ! 37.8~, ! 39.5'!o ~ 4O.! 32.7':, 34.0%' 38.0'-llncomeTaxRale . 38,0';0 Mth Intereslrates 018.231'", and 8.
:~ s 6.7% m 4.8%, 3.6'.0 , 4., i 4.,. 6., , 6.2',. 6.3~,; 3.9'.;5.0% O~ iAFUDC ..10 Nel ~r~~I
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(lTinIeres1eamed:2.1x) . 42.6% 41~ 39.8~ 37.1~ ' 46., 147.6'.. 152.6~, ! 59.5'1. I 62.2'"..! 60.1% 59.
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6o.S~ ilong-TermD~btR~o 55,S!.leases. UncapitarlZed Annual rentals S182 miD. 48.8% 49.9'4 SO.9% 53.3~0 ' 44.6~, ! 43.7'.~ I 4O,7'-~ ; 37.. ; 34.9'.. I 37.4% I 40.5% I 39.5'.. :Common Equity Ratio 44,5~..Pension AsseIs-121O2 5344 mill. Obfig. S370 RIIll 2430.23S2.3 2310.2212.5: 3043.4 : 3095.7 I 3387.9 I 3815.6 ! 3900.4 4076.7 / 4155, 4460 I Total Capital (Smill) 4625
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~~~c~~~4 :,~~~~r,~om:~r. call- 2153.2 2266.2282.0 2291 ': 3250.5 ~ 3430.9 :~9 :3838.4: 3888~~ 3916.2; 3950: ~~NetPlant(S~_able 5101 105105.17;2.400.000 shares 7.45%, 7.4% 6.8% 7.5%7,,' 5.6..! 7.1.., 7.I,! 7Jl'..j 5.2"4.9%5.5%: 0" !Returnon Total Cap I Sloo par. All shares cumutalive. 9.9% 8.6% 9.8% 9.7'..; 7.7'., 110.5'1. 110.8', ! 12.5', i 7.7':' 7.2'io 0% lo.0~ jReturnonShr.Equity 9.5!,Common Slock94.03I.408 shs. 10.3% 8.9'4 10.2% 10.2'1.: 7.9~, i 11.6'.. ; 11.8', ! 13.0'~; 7.7\. 7.2% I 7.5% i lo.D"~ !Return on Com MARKET CAP: S2.1 bDiion IMld Cap) .9% NMF .3% .3~,: NMF! .' 1.0'..: 3.6".! NMF 1.3'.~ 2.0%, 4.~RetainedlocomEq ; ElECTRIC OPERATING STAT1ST1CS 92% 111% 98% 98"-,' NMF: 99',; 92',; 74', ~ 125'1. 83'.. 76%' 58'" All Div ds 10 Net Prof : m2000 2001 2002 BUSINESS' P I Ene Inc.. h llii """""'nv tor uget 1lia17"'oIhe 9" G ti~ - t2' '1'" hytl
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r. ,.. enera_.source.. 'coa,. ,,. , roo ,.A~iU.Use~ 919 6:i3 358 Sound Enetgy IPSE), which seUs elec1ricity and gas to 1.3 million oil & gas. 4'10; purch.. 74";". Fuel costs: 42', of revs. '02 reponedA'1 h1IS.koerK\\!Uc, 7.39 1120 49 customers in a 6.0D0-sq.-ml region in western Washington. Merged depr, rates: 2.9~" electric, 3... gas, Has 4.700 emplOyees. 45.200~a!Ymrdllll\ 4917 4970 4577 willi Washington Energy 2/97. Earnings breakdown. '02: utility, stodd1olden;, Chairman: Douglas Beig!~e. Presidenr & CEO:
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8~.: other, ~". EJec. Stephen P. Reynolds. Inc.: WA. Addre~: P.O. Bo~ 97034. Belle.,CnangeClmoelsl)TftJ +1.8 +1.+1.9 Iri: rev. breakdown, '02: residential. 45,.: commercial. 39,,; K1dus- we. WA 98009-9734. Tel: [phone]~. Inlemel: www.pse.com.
FaalCi1aI9! CoY. r.! 244 178 172 Puge~ ~ergy has _announc~d the first cially for i~s fa;;t-growing gas scrvice !lrea,ANNUAl RATES Past Past Est'd '00-'02 ~p m Its, plan to ~~crease Its generaL. and to raIse. Its common-eqwty ratIo toofcnange(persh) IDYlS. SYIS 10'0&-'08 mg capacity. Its utility has agreed to ac- 45% from an Imputed 40'" currcntly. It ex-Revenues 7.5% 13.0% ,1.0% quire just under 50~, or 137 megawatts, of peets to seek an 11% return on equity. TheCash Flow" ..5%
~~
the Frederickson gas-fired plant for $80 percentage rate increases to be requested
~~
:i~ :is% ~O"" million. Puget Sound Energy IPSE) will fi- are likely to wind up in the single digits.Book Value -5% .2.0% 4:0% Dance the deal with short-term debt and Earnings should improve significantlyCaJ. OIIARTERLYREYEHUES(Smllt) Full has filed to rt;cover the cost t~ough its in 2004. .In 2003, three f~ctors hu~ theendar Mar.31 Jun.30 Sep.30 Dec.31 Year power~st ~dJustment mechanism. The bottom hne; ~e ~bsorptJon of , hlgh~r2000 647.2 538.8 979.0 1276.3441.7 transaction IS expected to close br the end ~ower costs (which IS capped at $40. mll-2001 119.9 935.4 619.7 699.0 3374,0 of the first quarter of 2004, contlng~nt on li~n under the power-cost rnechamsmJ;2002 7390 5408 458.5 6540 2392.3 a favorable order from the Washington mild weather In the first quarter: and a2003 676:0 557~ 515.675.6 2425 comuussion. The utility will need addi- disappointing showing from InfrastruX, a2004 750 600 525 700 2575 tional capacity, so it intends to acquire 50 utility-construction business. hurt by unfa-I- EARNINGS PER SHARP, Full megawatts of wind power and 300 mega- vorable weather conditions and weak de-~ar l.Iar.31 Jun.30 Sep.30 Dec.31 Year watts of thermal capacity in 2~05. It pla~s mand. Power costs will be passed through2 00 89 .29 .20 78 2.16 to finance these purchases wIth a combl- to customers next year. and we assume~01 '98 .20 d03 '07 1.22 nation of debt and equity, which could in- nonnaI weather. Talks \\ith InfrastruX'
2002 2a .34 :07 ~5 1.24 elude permanent financing for Frederick- customers suggest that this unit should2003 .45 .22 .10 .58 1.35 son. PSE would also seek recovery of the fare much better in 2004. If it doesn2004 .75 .25 10 65 1.75 costs of these generating assets through rebound as expected, thell Pugel EnergyCal- OUARtERLYDMDENDSPAlDB. FuU its power-cost mechanism. will decide whether to divest it.endar Mar.31 Jun.30 SeD.30 Dec.31 Year The utility pla,ns ~o ide a general rate Untimely. Puget Enea:g)' stock o~f~rs a1999 46 46 46 46 1 84 case, The applicatIon would be for both decent YIeld. We project some dIVIdend46 '46 '46 '46 1 84 electricity and gas and would be made in growth by the 2006-200::1 period. This
~~~ '
46 '46 '46 '46 1 84 the first quarter, in time for an order by should produce an annual total return a I2002 '46 2s 25 2s 121 the start of 2005. PSE wants to place addi- bit above average by utility standards. 2003 2s .25 .25 .25 tionaI investment into the rate base, espe- Paul E. Debbas. CFA NoL'cmbcr 14, 2003 (A) Diluled EPS. ExcI, nonrecurring gain Ooss): IB) Dividends historically paid in mid-February"miD. (E) Rate base: Nel anginal cost Rate al. Company . Financial Strength 99. 15c; '01, (Bc) net; Joss on discontinued op- May. August. and November, . Dividend rein- lowed on com. eq. In '02; 11.0%: earned on Slock's Price Stabllhy Brauons; '97. 3c, Incl. merger costs: '97. 43c, vestment plan available. (C) Incl. deterred avg. com. eq.. '02: 7.6%. Regulatory Cnmate: Price Growth Persistence Next earnings report due mid-February, charges, In '02: S690.4 miU., S7.37/sh. ID) In Average. EarningS Predictability C 2003. Value IJne Pi.cJIJshnQ, Inc. AJ! I\9hIS resOlVed. Factual malerial is obtained 110m SOU!Ces beb...d 10 co reIlaoIe ono IS plOVIdea ...""nbes of any kine!. ntE PU8l1SHER IS NOT RESPoNSI8lE FOR ANY ERRORS OR OMISSIONS HEREIN. This publicalJon IS s-.nctly lor StJbstnoer"s...'I1. non-commeltlall1lemal use. No pan
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, I I, I I . ,01 ~ "'" be resold. SiOIed 01 nl\SllJJlled .. 8/\y pIII1ed, eIectOIic or oC1er Ixm. or used lor generaong Dr maJ1lebng any PMIed or eIeCIronJc
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SEMPRA ENERGY NYSE-SRE 1787 -
TlMEUNESS 3 'O.!fe(ll':'~J High:' 25.0! 27.LoVl: 21,1' 23,~AFETY 2 L':oE'~2;~: LEGENDS!!)(I~eoa.o." I
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Sempra Energy was formed through the ' 1993 1994 1995: 1996 i 1997 ! 1998 ! 1999 12000 2001. 2002 . 2003 I 2004 I to VALUE UNE PUUjC, 06-08merger 01 Enova Corp. ami Pacific Enter-16.g9 'H! :6,05: 17,09 I 1951 i 23.31 . 22.89! 35,38 I 39.27! 29.38: 33.75; 32.70 I Revenues persh . 32.25poses cn June 26.1998. Enova stock, ;95 ~c: J33 4 83; 5.27\ 5.16. 5.36; 4.91, 5.39, 5.71, 5.651 5.50i"CashFiow persh holders recer/ed one Sempra snare lor I '81 . ', 3-1 1.98 I 2.20 i 1.1.66 i 2.06 I 2.55 2.79; 20 2.651 Earnings per sh A
each Encvashare. ana Pacmc Enterprises I :.:0 ';2 ':6 1.56! 1561 156: 156: 1.CD, 1.00 : 1.COi 1.00; 1.00 I Div'd Decl'dpersh I. 1.0051ockholders received 1.5038 SempraI3~G-- n=-;:ag~ 1.79 1.74 85 2.4Bi 3.76! 5.221 5,92: 5.25! 5.70 CapISpendin9persh
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directly comparable to Sempra Energy data, -""""!J3-ii.6--".2, 11.3 10.8 21,1: 12.8, 9.4 9.8.2~BoldligjlteS8re AvgAnn IPIERatio 11.5
CAPITAL STRUCTURE as 01 6I30Jt13 .84 77. .75' .62 1.10! .1 .61 .50 .45! \fol,,"!1Jne !RelaUvePIERilliO .
TOlaIDebtS4929.0m;u.Dueinsvrss2448,OmiJl. 5.7', H', 7.2'".' 7.6.6% 6.0~, 1 7.~, 5.2% I 4,1% 1 4.4% I _es ;Avg Ann'I Div d Yield ! 2.9%IT Debt $4414.0 ~a. IT Interest 5263.0 moD. 1960.1 19a2.0 '870.7' 1993.5 2217.0 I 5525.0 I 5435.0 ! 7143.ao29.0 '6020.0 i 7700 7450 I Revenues (SmUt) 1200Ind.S200rr~IJ.CumU1.0trty1I1COmePfd.Sec. "0' 335 2375 258.2 060 4400 5340 850 685 615 N tPofit Smn 805!lTimeresteamed:3.3xl ~:___
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Leases, Uncapitalized Alll'uaI rentals S94.0 null. i J',JS 6', 36." 385'i I 36.8% I 31.1":' i 30.7', ! 38.0~, I 28.8% ! 19.9%; 19.5j;,! 20.0% IIncome Tax Rate 35.0%PensionAssets-12J02S1.~ebilLOblig.S229bHI. I 1(1,1'. ~3', J.O', , 3.9% 2.9'to I 3.6% I 2.2"'., I 3.0:i I 3.2%: 10,
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0%: 10.0".. AFUOC'iOIoNetProfrt 0'10Pf~SloCkS203.0miD~ ,,!dDivdS~1.0m':J. , r ~3;; . ;~.
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751=, . J6.~ i 55.1~. I 47.3~, i 47.6".i ! 56.2~ ! 55.7"..; 58.6':0 i 53.11%; 52.0% iLong-TermDebtRatio 39.0'10~73.i70 S.'IS. ~.40 .5. CUll. S2C par. :all., 'Q~' ::...~. =;)9'-' 498" 1421% 493'" 490'. 4040' 41.2'i. I 386" 45.0" 450% Common Equi Ratio ' 59.5%202s,""2~0"OOsnsSI-
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can. 2 es,2U. ;- mill. sit... S !.7S25 cum.:' ~o par: I :;v46.~9331 2938.6' 3152.5 ! 3730.9 I 5912.0 ! 6092.0 ,6166.0 I E532.0 ! 7312.0: 839O! 9020 I Total Capital (Smml 10600
caiL 25 ~- subj, !:) mind. redem: BOO.COO shs I 1..I.3ioo.2 ' 3074 4 I 293~1 5441~? 5394 0! 5726.0 ! 621;;? I 6832.0 ~ 7565, 822! I Net Plant(Smlll)9950S430-S4..,CI:.'1I.. 1'10 par, ca:1. 1 OC. hll 50. B11.166 , 3,, 9.. 8., 8.,; 8.,; 9.0"'., I 10..", 9.8~, 10.0'-.., 5"iRetumonTotalCa~1 ,shs.6':,cum.S25pcr. ! ~3.4', '
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, 14 ; ~4.2~, 115.4% 9.8% 112.7"', 116.3% I 18.4~,119.3"'1 17.5~; 14.0~ !RetumonShr.Equity 12.5':0Common Stock 20B,i~.4~2 shs. zs 017/31/03 i ';.
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2 ~', ~4 " 14., : 16.0".. ' 10.1~i i 13.2", i 17.2'1 I 19.4% i 20.4~, i 18.0"!.: 14.5% I Return on Com Equ' E: 12.5%MARKETCAP:S5.8bdhonlLargeCap) ~i5i
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3.0'.0 : 3.1~, 4.6~'NMF! .9".. i 7.4"1. 111.9-.. 13.1% i 12.5%; 0"..lRetainedloComEq 1.5%ELECTRIC OPERATING ~~~~TlC
iOOl 2002 :!2" . ~", !1', i 79%! 72'~ 110% S4'I 58%: 4O~'! 37'"..! 33~,! 39~ IAII Divds to Net Prol 34%
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5~ +1.6 I BUSINESS: Sempra Energy is I holding company lor San Diego 41":0: commercial. 41%; Uldustrial 10%: other. 6'.. GeneratUlg\;~;.;s; ~:-.
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"rsb "GoIS 1\ tJf!C1~C Co.. which sells electricity IICId gas mainly in San sources.O2; nuclear. 23%: purchased, 77':.. PO\'ier COSlS: 28~. of
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AF ~1vIF NMF ::!~G ec:d'otji 8. Southern California Gas Co.. which distributes gas revenues. '02 deprec. ~te: 4.3%. Has 122CO em;Jlcyees. 175.000
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t~MF NMF NMF':o mC'"..1 01 ScutMm Car~omoa. Customers: 1.3 million eleCDic. 6.1 common stock.'1oldelO. Ct.airman, President 8. CEO: Stephen LMr"a
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Tn,IF NMF NMF i :r.Qocn 9'ls. t-ias v'Yes!ed ~s generabon. Has 6 noOlMrty subsicf~ Baum. Inc.: CA. Address: 101 Ash SI.. San Oiago. CA 92101,3017,
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earrungsl. EIec, rev, breakdown. '02: reSldenlial. Tel.: [phone].lnlemet www.sempra.torn.
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309 2~~ 249 I Scmpra Energy sold some stock last Our 2003 earnings estimate requires
ANNUAL RATES Past Past Esrd 'Oo-'02! month. The company issued 16.5 million an explanation, The CPUC has finallyc!;:'-ooI1?-'CS',," lUes. SYIt-- to O6-"Da ; ..hart!" at $28 each, shortly after a rating granted SDG&E pennissirm to record S65
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l:g:: : :lgCII.c' 11I re~ its credit ratings ,Sempra million iaft tax~S! of Prf!fits it made onEamln~ 3., 4 . 3.I 1$,;11 :-:111 Investment gr!l e. e com- e sa e 0 e ectnclty unng t e westernI Dividends .35", -8.NIl : pany II:-:cd most of the proceeds to retire power crisis in 2001. We have includedBook Value :.
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. 'WO :-:hnrt-ll'rm debt. The sale win have little this $0.31 a share in our September-
Cal, I QUARTERLY REVENUES IS mi!L) ! Full! !!Jli-ct un ~amings in 200~ be~ause it came q,uarter presentation and our fu1l-year es-enclar I Mar.31 Jun.30 Sep.30 0ec.31 Vear. lutl! 11\ the year, but it WIll dilute 2004 re- timate. On the other hand. we have ex.
2000 ,~~60 1530 1832 2321 7!J3Coi :mlt... ;\ccordingly. we have cut our 2004 eluded a $47 million aftertax writedown of
2001 :3242 :!.'OO :510 :377 8029.:; "han!-IIl't estimate by $0.15, to $2.65. assets and a $37 million aftertax charge2002 !:40\1 ~428 1384 ~683 6020,00 T~~,t"s lIl'ar the low end of Sempra s target for litigation and losses associated with a2003 i:923 !64ii 2O5e 1879 ,7700. III ::::!.
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:S2.90. sublease of part of the SoCalGas head-2004 i lS50 1750 200G IS50 7450 I 'I\\'() rate cases are pending. San Diego quarters building. Fina1ly, our estimate re-Cal-' EARNINGSPERStlAREA Full i lia~ .. F.luctric is requesting an electric fleets the full $40 million of income thatendar ! Mar.31 Jun.30 Se .30 Dec,31! Vear! !ann hi!,;\! II! $59 million 12.5%/ and a gas Sempra expects to book from its synthetic2000: 4~ .55 .55 ~7 2.Cti' ":111' IIIcrease of $22 million 19,1%1. fuels investments this year, although the
2001 : .78 ,60 .59 52 2.5E I :-'~Iuthl'r!) Cali!ornia Gas is seeking a rate IRS is auditing these projects,2002 il 70 .73 .D5 ~-: luk!. III )SlaO million 18.5%1. Between them, This stock has fared well in 2003. The2003 .:6 .55 1.39 70 3.20 t ~\I' uII lilies also want to be granted opera- upholding of Sempra contract to sell2004 I 60 .60 .SO 65 2.65 I t !llIIul IIIcentive awards totaling $33.5 mil- power to the state, the good performance
Cal- I OUARTERLYDMDENDSPAIDBI Full' hull.. On the other hand. the California of its nonutility operations, and its obtain-
endar Mar,31 Jun.30 Se .30 OecJ1 Year I~uhhc. Utilities CommissiDns (CPUC) Of. ing of permits for two liquefied natural gas
1999
' .
39 .39 .39 ,39 , 55 hc!!..1 Ratepayer Advocates and two con- facilities have beerl well received by the2000 39 .25 25 25 ! ~~ :-'lInll'r groups are prDposing rate decreases market. By utility standards, however. the2001 .25 .25 2~
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III::: H;:.! million and $266 million, respec- yield is below average, but 3- to 5.year2002 I 25 .25 25 .2~ , tI\"I'I~'. An IIrder shDuld CDme in the first total-retun1 potential is above average,, 2003 I 25 25 25 25 IllIarJl'r flf 2004. Paul E. Debbas, CFA Novemba 14.2003
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O;"dend re,n. cost. Rate allowed on com. ea.: SOG&E in '03. Company s Financial Strength 8+-+:)' ,3~; ~~.: .~ :.~, '~~c': 3;,) ~O.J,':" ,~,,: . '
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:; IC) '"CI .mang'bles.1n 10.9~.: SoC.iGas in '03. 10.82',: earned on Stock's Price Stability mergercos:s "0:'~~'I;am:~s:"c;n,
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- IOI;-:nJl!.,a~J.tor avo. com. eO.,02:20,eo.,. Reijulatory Ciim.te: Price Growth Persistence 25
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Xcel Energy was formed through the merger 1993 11994 ; 1995 1996 1997 11998 1999 2000 2001 I 2002 2003! 2004 I ~ VALUE UNE PU8.INC, : O600B
01 Northern S'.ates Power and New Century 17 97: :B.59 18,64 I 19.22 : 16.321 18.46 I 16.42: 3-1.11 i 43.56! 23.18.35, 1135lRevenuesaersh 19.75Energies on Augus! 21. 2000, NSP stock- 352 , 4.!JO. 4 30 I "33, 3.92: 4.20! 4.13: 4.12! 5,09' 3.14 41J 3.3D
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Cash Flow" persh
holdersreceivedoneshareolXcellorevery 151;:';3 1.96: 1.91~ 1.51! 1.641 '43: 6G 2271 .42! 1.45 1.25:Earnin9spershA l.50NSPshare.andNCEstockholdel'5received :.' 1.31. 1.34: 1.37; 1.40: 1.43i 1.45; H6: 150. 1,13; .75 .77:DivdDetrdpershB., 1.55 shares 01 Xcel for each NCE share. 2.70: 3.06 2.94; 2.99: 2.90 I 2.99 : 11B7 i 363: 7.40' 6.0.: 2.20 2.80 Czp l Spendin9pe~--.1:ooData prior to 2000 reflect NSP or. a stand- a66 14.17: 14,87 1625 I 1b.42 :6.37; 17.95 ~ 11.70: 12.55 13.10 ookValuepersh
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alone basis and are not compai3ble with 133,76' 133.84 : 136.35 ! 138.131149.24 152.70 1155.73 1339,;'9 ,345.39~71 ! 425.00: 42500 ,C~~~OutS!9 0 . 4-I3.Xceldata. 14 iU, 11.6 12.5 15.5 I 15.2 16.'43: 12.4' 'Bo'dligllte..,. AII9Ann1PlERatio 12,0 i
CAPITAL STRUCTURE IS 016130103 .88 , .BI .78 ; .78 . .89 i ,79: .9$; .93: .64' NMi=: VoI"'.uJo iRelati'le PIE Ratio 80
ToIaIDebIS6757.9m1U.DuefnSYrsS2EBC.0Il1lll, 5.7',; 6.2~. 5...; 5.;0.. ~ 5... I 5.1~ ~ 6.1"', i 5., 5.3'.. 6..AIma'.. .Av!lAnn1Di~dYi~ld 0".
~~~~S::S i.~~:~~:~\ 240-:.0: 2.:86.5 : 2566.6 12854.2 ! 2733.7 12819.2 ! 2869.0 : 1!5~1 : 15O2f: 9524.t. 7800 7Boo'RevenueslSmill) 8775 !
Origina\9d Preferred Securide!. !oouidalJOn val 21'7' 243.5, 215.8: 274.5' 251.8 I 29a.1 , 240,1 i 545.6: 784.7: !iI.605 550 Net Profit jSmil1) 640
S25Is/lare; 7.760.000 ShareS 60'
,.
cumulative. 38.2'.. : 35 4', : 35,6". I 34.. I 27.8'.. I 26.0'.. I 21.6~, ! 35.. : 29.2", ~ 32.7'; ~- F; 3f.:lncOiii T..x Rate
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par. 5100 mill 7.85'..I3.~-ded;;CIJble Trust Prete 6.0'. 5.' 6.2"-.i i 6.9'"..! 6.6". 3'-.0 i 2.5~. . 4.. 7.1', ; 46.;0,0"." 4.!AFUDC '10 Net Profit O~'Securities. 38.5... 4v,6:" 40.5~, I 4:).1~, . 40.4~.. 39.9".. I 5-I.~ i 58., , 66.7". : 59.6:, : Sto'53.0~. ilontTerm-bt Ratio ~o-.~"IInlerest not earned) 54.4'.0 ; 52.;0. ' 53.2'.0 I 53.8% I 51.G~. : 53.5~i I 40.5~, i 40., : 32.B'~ ! 3~.5~, ! 45.4&.5'. ,Common EquiN Ra~o 50.5'!'o Leases. Uncapl1alizedAnruJalremaliiS6S.0mill.
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Pension Asse1s-121O2 52.64 b,n. Oblig. 52.51 hilt 3359.B: 36r0.8 : 3810.3968.9 4650.9 ~ 4637.6316.2 i 13m: 18911 11815! 1tS5O' USBS :Tolal CapitaIISmll') 13000
Ptd Siock 5105.3 mill. Pld Div'd S42 mill. 4214.1 : I 4310.3 ,4337! 4361; C395; 14451
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6.5'!"-..IRetumonTolalCapl .5'!8pal. callable 5102.00 10 5103.75. 10.2'.; 11.
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Common Slock398.751.621 SM. as 017,'31103 10., I 122 , : 13.0% 112.3~.. 9,, 111.2".. . 8.6"" 9.7'. 12.6, 3.7', 1t.O. : lo.O tum on Co
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MARKET CAP: $6.5 billion (large Cap) :::I - 6';; I 3.0~., 4.2'.. I 3.6".io I 1.2';0 2.5% i NMF! .; 4.3', NMF i 5.0':0 ~Relained to Com Eq 0~,
ELECTRIC OPERATING STATISTICS ~ 77',69'.. i 72'..: ea'
..
19".. I 10000i; 91'60~,: NMF i 53'..! 60'
..
IAn Divclslo Net Pro! 62'" I2000 2001 2002~ii!!3!S2:!s1KWH! +6.0 +.1 +1.BUSINESS:)(ee1 Energy Inc. is !he parent of Northern States erating sourceii, '02: coal. 50'-.: nUCf".ar. 13'.: 93" & 0:1. 10'~;.C&:I~"5!M""'~ 4 ~~ 5 t~. 4
:~
Power. v.11icI1 supplies power 10 MN. WI. ND. SO. MI. & gas 10 MI. Qther. 2'".,: purchased. 25~,. Fuel CO$!; 46', of revs. '02 reported I~~~~KWI!", NA 9462 NA WI. ND. MI & J.Z:. P.s. 01 Colorado. which supplies power & gas" depree. rate: 3.4%. Has 14 500 e.'"*-reES, 300.000 com. s1ock- i
r$kuZ:. Sww 1\,\;" 7936 8344 8259 CO & Wi: & SouthweS1em P.S.. which supplies power 10 TX. OK. holders. Cha'nnan & CEO: Wirfne H, ilrunelb. PIesidenl & COO: !
AIr.I;IU20Ftt'!:',' F 60.52.2 NA NM. & KS. Customers: 3.3 mill elec.. 1.7 miD. gas. Elec. rev, Richard C. KeUy. Inc: MN. Ac:dress: 6QIj I-ocoIteI Mar., MlMeapc!is :c.~Cm!m'I'-e'-J, .1.8 + 1.3 +.breakdown, '02: res'!. 31%: comm1 & rol51'!',; other. 16%. Gen- !.IN 55402. Tel.: [phone]. ln1emet ",y.'W.xcelenergy..om. '
;os:~Cct ,217 221 125 Xcel Energy is on track to have NRG since Xcel is almost entirely a regulated '
ANNUAL RATES Pm Pasl Est'd '00-'02 Energy's .Chapter 11 bankruptcy reo- electric and gas utilit),~cna.~lpersh, 10Yrs. SYrs. 1o'G6-'18 solved by December 15th. Creditors The board of directors plans to eval-
B6ve
~~~" ~:~~
1~:~~ :ll~ were scheduled to vote on November 12th uate the dividend polic~' next June, Ea~ .5"" -4.5.~ 0""; on an agreement that would provide them assuming that the final payment to NRG'Dividends 1.5% .0!. with $350 million in cash in late 2003, $50 creditors has been made by then. (Note:Book Value 2.0'" .5~. million at the start of 2004, and $352 mil- The dividend planned for ' eady in the
Cal- QUARTERtY REYENUES (SmiILI Full lion later in 2004 from a tax refund that fourth qunrter has been delayed because
enclar Mar.31 Jun.30 Se.30 Dec.31 Year Xcel expects to receive stemming from the retained earnings are negative. The com-2000 2322 2460 3115 3694 11591 write-off of its investment in NRG. (If the pany intends to resume payment in De-2001 4231 3698 3763 3336 15028 bankruptcy proceedings aren t concluded cember, when it expects retained earnings 2002 2371 22Z7 2473 2453 9524.4 by December 15th, then Xcel won't get its to return to the black.' The company s cur-2003 2147 1771 2058 1824 7800 refund until 2005, which is why the De- rent $O.75-a-share dividend would put the I
2004 2000 1800 2100 '900 7800 cember 15th date is significant.) The stock payout ratio at about 60'h based on esti-
~~r Mar.3~~:;o ~~RE
~ec.31 1 :~~ ~::r ~~e ~t::s d~~~~:s ~~J~: r;a~:;O
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~~:
2000 45 016 29 .40 1.60 the NRG mess behind it. NRG has already forecast a modest dh'idE'nd hike at thE' I2001 .61 .49 .79 .2.27 been deconsolidated from Xcel's financial board meeting next June. The movE'. would 2002 .27 23 .41 d.42 .42 statements. come less than two years afl-er thE'. direc- .2003 .30 d.71 G .69 '.f4 US Operations earning power appears to tors halved the dividend. We project that 2004 .35 .20 .sO .20 1.25 be in the $1.15-$1.25 a share range, dividend growth will continue through the Cal- OUARTERlYDMDENDS,AIDB. Full management's target for 2004. It assumes 2006-2008 period.endar Llar.31 Jun.30 Se.30 Dec.31 Year that NRG's bankruptcy is concluded in This stock's yield is about half a per- .
1999 .:b7 .357 .363 .363 1.44 2003, the utilities earn close to their aI- centage point above the industry2000 .363 .363 .368 .375 1.47 lowed returns on equity. and nonregulated average, Even assuminl! some dividend I2001 .375 .375 375 .375 1.50 operations ias a group) cut their modest ~owth throu~h 2006-2008. total-return I2002 .375 .375 ,375 .188 1.31 loss. Beyond 2004. we project low-sin~le' potcntil'll i1': just aV(,Tage for a utility. 1.:.2003 I .168 .188 :es digit average nnnunl earnings growth. Paul E. LJ('hba.r.f:4 NOI'l'lI/hC'r 14. 200:J
...
(A) D,luted EPS. ExcI, ex1rao~. gain flosses': mgs report due lal~ Jan. (8) Div'ds historically Rate allowed on COOl. eo.: MN '92.11.47',: WI I Companys Finantizl Strength 6 I
00 /6CI:3;:"O2.(S6.2;! ga;n 0.' dlS::. Daldl!1mi(J..la~.~r.Ju!y,andOc\..Div'1 '95 11.3~i:CO'03:e!gt;.1075":TX'Stock'sPriceSlabllily 50 I
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0 2003. Value Lo1o \:!c. AJ: riIIhts resefVeG, Fac:.oaJ ...te'... 1$ """rood ..'"' ~"Ces belwed to ~ roIIatle and oS WJI/I(JIJ MlnantJeS of any klJ1d
';HE PiJBUSH:R ;S I;:). nESP:JI'::)iB'E ~OR AllY ERQoqS O~ ()I~'5SJc.':. 'iEnEIN TI'4;r~ 1$ SIr.wy "" .._, s 0W"0. non-co""",r:.a' ""e"."" CS! No oart
01 c rray 00 """":!!:coo
,~
..,.." c' n-....-.J;ie.:! " any prroon t'!:r= " 0"'.1 Di"I. IX "'""0 ~, 9""O"bny Co". IT.oUr=-:; ar,y Po"""" '" .,i!O'C'!'C """"""'" ,.r.'OU '" o;CC'.I:;I.
Selected Yields
Months YearRecent Ago Ago
(12/11/03) (9/11/03) (12/12/02)
Months YearRecent Ago Ago
(12/11/03) (9/11/03) (12/12/02)
TAXABLE
Market Rates
Discount Rate
Federal Funds
Prime Rate
30-day CP (Al!PU
3-month LlBOR
Bank CDs
6-month
year
year
US. Treasury Securities
3-month
&-month
year
year
10-year
3D-year
3D-year Zero
1.00 1.00
1.05 1.04
1.17 1.14
89 0.98 1.1.33 . 1.3.21 3.
5.2027 5.
Treasury Security Yield Curve50%
50%-1 , ;
50% ~
50%.
1.50%-1
'"
: -Curr"nt
- \'colr-Ago !"-00
... .
~ 3
:1.1,,". ~ .011"'
1.25
1.32
1.41
1.14
1.20
1.2&
1.48
Mortgage-Backed Securities
GNMA 6.
FHLMC &.5% (Gold)
FNMA &.
FNMA ARM
Corporate Bonds
Financial (1O-year) A 5.47
Industrial (25/30-year) A &.21
Utility (25/30-year) A
(TID'Utility (25/3O-year) Baa/BBB 6.
Foreign Bonds nO.Year)
Canada
Gennany
Japan 1.33 1.49 . 1.
United Kingdom
Preferred Stocks
Utility A
Financial A
Financial Adjustable A
TAX-EXEMPT
Bond Buyer Indexes
20-Bond Index (GOs)
25-Bond Index (Revs)
General Obligation Bonds (GOs)
year Aaa 1.05 1.18
year A 1.28 1.3&
year Aaa
year A
10-year Aaa 354
10-year A
25/30-year Aaa
25/3O-year A 5.12
Revenue Bonds (Revs) (25/3O-Year)
Education
Electric
Housing
Hospital
Toll Road Aaa
Federal Reserve Data
BANK RESERVES
(Two-Week Period; in Millions, Not Seasonafly Adjusted)
Recent Levels11/26/03 Change150& -18756 -1450 -1&7
Excess Reserves
Borrowed Reserves
Net Free/Borrowed Reserves
12/10/03
1319.
1283
Average Levels Over the Last...
12 Wks. 26 Wks. 52 Wks.1465 1980 18&2109 15& 1011356 1824 17&2
MONEY SUPPLY
(One-Week Period; in Billions, Seasonally Adjusted)
Recent Levels11/24/03 Change
1280.7 -lOA
6057.8 -
8854.0 -11.0
Ml (Currency+demand deposits)
M2 (Ml +savings+small time deposits)
M3 (M2+large time deposits)
12/1/03
1270.
6055.
8843.
Growth Rates Over the Last...3 Mas. 6 Mos. 12 Mos.2.1% 1.5% 5.0% 1.1% 4.8% 2.5% 3.
~d~~~~ ~!i~~g~iI1: BQ O~B~'
~:~
OA~.C 2003. Value Line Publishing. Inc. M rights reserwd. Factual material is obIained from sources belie.'ed to be reiable and is plO'Med without wananties of any kV1d. THE PUBlISHER
IS NOT RESPONSIBLE FOR Air( EROORS OR OMISSIONS HERBN. This publication is StIidIy lor s\lbsai)e(s O'M\, I\OIKOfMM!rciaI, i'llemal use. No part of it may be reproduced.
resold. stored or IransmmeO In any prin1ed. electronic or other lorm. or usee for generating or marketing any printed or electronic pubncation, seNice or product.
c, , ' 'UE LINE
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ary ,. AI'
;;:;~ & '
binder. Last week's
Summary & IndexInvestment ~Urv~~" Index should be removed,
' ..,.,
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, ~" '. '' ,~ :":' -- -
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December 19, 2003
\f', TABLE'OF'SUMMARY'& INDEX.CONTENTS
,. ~'-.
Summary & Indexc:"
'!".:":""-";!;'' ';'"
Page, Number
Industries, 'In alphabeti~ order ........
....................................,...............................................:................................;;;.
.:.t, '
.. -,
' Stocks, In al~habeticaJ order '
..._...........~......:.........,....................................;...,...'-;:....
~.......................................... 2-2~' NoteWorthy
. ~,
k ~,hanges """""
:~::"",:"""""""""",:""""",~""""""",,","-.,~........................................................." ,
24,
" ,~. ,;;~'
SCRE;E:N~
':'" ", ,
Industries..in order of TImeliness Rank '
:..::...::~';._
~4_,,~, Stocks with, Lowest PIEs ..,..........
~..........:~.:;:~;;.-~'
:35, Timely Stocks in Timely'lndustries ;~................., 25--2P; - Stocks with 'Highest PIEs'
, :"'-:"".~........................
::.... 35:; Tamely St~ (1 & 2, (or Perfonnanqe) ...........~. 27~29 ' Stocks W!th H!ghest ~nuaJ Total ~etums .;.
:...:-...
: 36 :
' '
Conservative Stocks,(1.& 2-for,Safety) .-.......-. ,~3l S~ocks WIth Hlghest,3- to 5-year DIvidend YIeld,
"'" ,-:"'; ,
Highest DiVIdend Yieldil19 Stocks .r;;;..
~"':::........,
;;~.... 32'
..,' ,
Hag!) Retums Eamed on Total Capital;;...........
~;;;~..
. :3-1 '
- ,
, S!ocks with Highest 3-: 10 5-yearPr\ce P~~entiaU"" ~~
" ~~
" Barpairi Bas~ment Stocks'
"""
;"""""""""""""i'37 :::'
' "
Blgg~ "Free Row" Cash ~enerators .
~......
~;....... 33 ,
;,
l)!\timety ~?Cks, (5 for .P~rfonnan~e) """""""'~~'" 3"~~. :
""'--"
Best Perfonning StockS Ia$t 13 Weeks ......
~...:.:;.._.. ,
33. '
;;,
: H!ghestOIVldentJ Yielding Non-utility Stocks.........., 38 :. - WofSt Pe!fonning St()cks last ~3 We~ks :'
~;,.......
J~.... 53;, ,..- H.I9hest Gro~ St~ "
"-'.';"-':~:"""""""";;""""""~!' ., '
WidestDlSCOUl'ltsfromBook,Value""
""""-""",
~,,, 34 "
:, , '., p,",. '
" d''I'
' , , -~ '' :' '.. -, , ' '.. ' "" " '-- "..
t ' , "
,: . .. '.. ", " : '
The Median of Estimat~d:
:\
,;:-' The Me~lan'~t'EStimated" '
. "
TheEStimated Median:pri~"
:~:, "(~'
~~~~:!~\f
;: _
(n~_"'
; . ,
~!=fro~
~':~;'" :'
18~5!"
~~~'
t::::t '
~:~,
;: fr ~~8;
: ~:, ;: ,
45%'~25fE2)~:"
.. "
26,Weeks: Minket,Low ':Market H~i\ ' '
::: ,
:26 Wee~ Martc~n.ow Market High
' '
: 26 Weeks
: :
Market Low '~efti1gh. '
' -
" Ago'
" -
, 9-21-01 - '
:, '
4-16-O2c~ _..
~ ~ ,
Ago"'
-:-:
'1;i ,9-21~l ,4-16-0Z' "
: ,
Ag~ "
;:-",,
9-21001".::;._, 4-1~,
. ".- ,
16:8 ,15.4 "20:.9 ~;:2.0%~~:, ~h
~;" ,
:~Q% ,
::"
105%
:--:'
55%;
,:~~:.. " ,~~,
r~~.
~~~:~,~:.:. ~,:, ':, ,-, ";,\,.. ,!:.;,.. ,
;J-.:'J
.':':~::, '
" ANALYSES OF1NDUSTRIES IN ,ALPHABETICAL ORDER WITH PAGE NUMBER;;~:;r~: '
:~: "'::, "
' Numeral in parentheSIs aftet.tti&~indtist1Y,!s:rank for probable~pert'orri1ance,~next 12 moritbs)::
, ~:, '\;' .-,::":, :\:', "
, PAGE'~;.~:::t' ,
'j~;;" ~~~::
~;~' PAGE);; '
~~; ,. : '
PAGe '
::~'' ~;::' .,--/;:;~;.. '
pAGEAdvertising (&3) :
..
1923.:- , EduCaIiOOaI ~ (3f.:~.
;,:,,
"1584' ';:Irisurance (P.roptCas.) (47) '~586 RaIlroad (82) -;;;-~;;;..;;.~.
:....- "','
~~e (76).-
-";:'.
m, .'EJedr!caI EquipineIit (58h...
~~;
1001., : Internet (2);;';'--",:- 2229 REJ.T. ,(9.1) ..
::', ~'. :..~: ~~
JJ77 ,11.:,
AirT~rt(32)
, ""
253 BedricUtil.(CentraI)(B6l--,-:69S'lnvestmentCo.(~)-;......_960 R~~(62)__
, '
1841
' '
~Apparel(68) 11651
, :
EJeCb!C Ulil'1ty(Eas1) (98r::---::-,154
" ,
~Co.(Foreigrt)~12l-16:4 ReStawant(36) _!t:::i.:
:.'~:-_,-
AiIIoUIII:k(44) 1Ot:-..8ediicUb1ity.(Wes!)(84)-1775..
~(~) . -
1331.. RetailBuilcingSupply(24) __881-, Auto Parts (38)
~--=--
795 BecIronics (42
. ,
1024.. Manu!. ~YJjO) 1554 R$D (~I,inesH20),_~.... 110:4, Bank
" - "..
2101,EnIeitainmei1I r 1~ "Marilime(11r~;.
--,.....
278 :' Retail StOre (13)
: ,,; .
,- 1669
, "'
Bank CanaIian) (5S), 1570 EMeIfainmenI ech (18) '.:.:1.-.. 1598 .-Medical SeMces (6)-
....
62k;'Securities Brokeiage (23) ,
:-..
.:1424 ;:;;,. Bank (77)' -.....::....:::... 613 ' EnvironmenIaI (33)
: '
353, Medical~'(16) :':-:-"'178'" Seri1iconduclor'(14P'
~':;:"':'_.
1051 ,'Beverage
,~ __..
1m:~, F~~,(Div.).(31L-21~,- Metal fabncatiqg 19.1
\ """"
~" ~EquipJ591 ,,;",,
.,_..
1091 ,
::,:, =~ __..
~t,
~),;,,
==i~
...:,
~=J~eraJ)(~)~;:..;;r
::.
~~~;r;
, , '
Materials (72) , ...:-.:-.. 851:..: Foresgn, ~1h~ ,1~1 ... ~Nal!Jra! Ga$ (Oiv..)(48l. ~.,.;.:;..-, 431 Sleediniegrated) ,(94J -:~:1414
;::'
C8b1e1V(34),
~:., ,: ';:, .
828:."fDreign':relecorl!-(?),~;I 768:,
,~.
Ne~(60)-,
;. ,.. ...
1909:,Telecom..Equipmerit(5)\145 !"'i*Cana!ian EneIgy (81) __M.. 428 FurnMome Furnishings (95) -.. 895 'OffICe EquiplSupplies (49)
---
1137 Telecom. (29) ,.;...0......,;,.; ~1.9,
Ceme!!t & (45) --.. 888 Grocery (73 1m .oilfield ~qUtp.. (88) ..-.-...: ~943 'T e~ne (51) ----_M_'" 1664 '
.' =~~~:~:.
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:, =~Ia
--- .. -~: *
~:::~=(:i.
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~e~(21) _.1106 HousehoidProduCls(71) _....,941 PharmaCYSeMCeS!4) -'_M.183 Trucking(30) ~_.._.,......._..2~...CQmputer So1tWareJSvcS (2S) M...2172 ' Human R~ (61)
~..
1289' -, Power'(57f
"";".'.?::
::,LL.... 91F Water U\J1ity (90) ~ L:.:.:t;...;.
...:..:.
: 1420 '
. ~, '
DiVeISified Co. (78)
--.-..
1377 Ind~ se~ (75)' '~::323' ,~Prec!~ Metals (54). -:...L:.!2..;..:1219 --WifeleSS :Nelwoiliii1lj (15)"=.!_
.;;..
:S11 ", ' ' Drug (39) -..-. 1246 lnIonnation SelVices (8)
-..
379 PrecISIon Instnment (67) --. 124
' "-+:,
E~ (17) , '
- -
-;... 1434' "'lnSurance :lUfe)(46)'" ,_..
.0-- -; 1205" 'Pubfishing (BOr ":-"'::.:~..:. '" . 1895' ,.. '_,n -'*Re.feiYed iRiiiis week'siSSiie~ '1-"
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!--StartFragment--~10/200211/2002 5.12/2002 5.01/2003 5.02/2003 4.03/2003 4.04/2003 4.OS/2003 4.52 06/2003 4.07/2003 4.08/2003 5.39 . or-09/2003 5.21 cI,JJ-10/2003 5. 21 . Q11/2003 5.12/2003 5.11
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http://www.federalreserve.gov/releaseslhI5/datalm/tcm2Oy.txt 1/14/04
Schedule DP-ROE-
Revised Computation of Dr. Averas DCF Estimates
Average of
Estimated Growth Rate Updated
DivIdends Projections Equity
for Reported by Cost
Price-2004-111 Yield Dr. Avem:-Estimate
Black HUIs Corp $31.20 $1.24 3.97%94%9.91%
Hawafian EIecbic $41.62 $2.5.96%1.98%7.94%
IDACORP, Inc $23.$1.20 03%53%10.56%
MOO Resources Group-$21.$0.3.26%66%92%
PNM Resources Group $26.$0.95 64%40%04%
Pinnacle West $33.$1.83 48%52%00%
puget Energy,lnc.$21.25 $1.71%16%87%
Sempra Energy $28.$1.3.55%74%10.29%
XceI Energy $14.$0.5.34%05%8.39')(,
Average 55%78%32%
Notes and Sources
aJ ks reported by Dr. Avera, Schedule WEA-1 page 1 of 1, with recent sprlts.
bI November 14, 2003 Value Une forecast of DPS growth for 2004.
cI Average of four projecrted growth rates and projected BR growth reported by
Dr. Avera In Schedules WEA-2 and 3.
dJ AcIjusted for stocIc split of 3:2.
12/29/03
IBES VL 1stcal Multex BR8 0.5.20 2.3 3.1 1.6 2.6 7.5 6.6.25 3.4 0.5 4.8 3.6 4.5 4.6 4.5 7.6.4 9.3 1.4 3.
444 2.667 5.7 5.144 4.367
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ROE
Avg Util prem
bond yld
1974 13.10% 9.27%
1975 13.20% 9.88%
1976 13.10% 9.17%
1977 13.30% 8.58%
1978 13.20% 9.22%
1979 13.50% 10.39%
1980 14.23% 13.15%
1981 15.22% 15.62%
1982 15.78% 15.33%
1983 15.36% 13.31%
1984 15.32% 14.03%
1985 15.20% 12.29%
1986 13.93% 9.46%
1987 12.99% 9.98%
1988 12.79% 10.45%
1989 12.97% 9.66%
1990 12.70% 9.76%
1991 12.55% 9.21 %
1992 12.09% 8.57%
1993 11.41% 7.56%
1994 11.34% 8.30%
1995 11.55% 7.91%
1996 11.39% 7.74%
1997 11.40% 7.63%
1998 11.66% 7.00%
1999 10.77% 7.55%
2000 11.43% 8.09%
2001 11.08% 7.72%
2002 11.16% 7.53%
83%
32%
93%
72%
98%
11%
08%
-0.40%
0.45%
05%
29%
91%
4.47%
01%
34%
31%
94%
34%
52%
85%
04%
64%
65%
77%
66%
22%
34%
36%
63%
Regression Output:Constant 0.0734Std Err of Y Est 0.0058R Squared 0.774No. of Observations
Degrees of Freedom
X Coefficient(s)
Std Err of Coef.
-0.435
0452
t-statistic 616
average 81% 3.08%
beta mrp
11%00%10.
11%60%
80% yld73% grwth
98% D1/Po
11.71% 60% MRP
PROOF OF SERVICE
I hereby certify that I mailed the foregoing Prefiled Testimony of Dennis E.
Peseau in Dockets 03-10001 and 03-10002 by delivering to the U.S. Post Office copies
thereof, properly addressed for mailing to the following persons:
Kathleen Drakulich
Nevada Power Company
O. Box 10100
Reno, NY 89520
Alaina Burtenshaw
Public Utilities Commission
1150 E. Williams Street
Carson City, NV 89701
Dale Swan
Exeter Associates
5565 Sterrett Place, #310
Columbia :MD 21044
Scott Craigie
Alms Consulting
6005 Plumas Street, St. 301
Reno, NY 89509
Patrick Fagan
O. Box 646
Carson City, NV 89703
Bill Kockenmeister
6005 Plumas Street, Suite 301
Reno, NY 89509
Mike Pinnau
Chemical Lime Company
O. Box 985004
Fort Worth, Texas 76185-5004
Dan Reaser
Lionel Sawyer Collins
50 West Liberty Street
Reno, NY 89501
Michael Kostrinsky
harrah's Operating Company, Inc.
One Harrah's Court
Las Vegas, NY 89119-4132
Mark Russell
Mirage Hotel and Casino
3400 Las Vegas Blvd. South
Las Vegas, NY 89109
Martha Ashcraft
Lewis & Roca LLP
3993 Howard Hughes Parkway
Las Vegas, NY 89109
Tim Hay
Bureau of Consumer Protection
1000 E. William Street, Suite 200
Carson City, NY 89701-3117
Lawrence Gollomp
S. Department of Energy
1000 Independence Avenue, S.
Washm~on, D.C. 20585
Doris Knesek
Utility Shareholders Association
2554 Nye Lane
Minden, NY 89423
Robert Crowell
Crowell, Susich Owen & Tackes
O. Box 1000
Carson City, NY 89702
Michael. Kurtz
Boehm Kurtz & Lowry
36 E. Seventh Street, S1. 2110
Cincinnati, OH 45202
Eric Witkoski
Office ofthe Attorney General ofNV
555 East Washington Street, #3900
Las Vegas, NY 89101
Dated: January 16, 2004
ploy, of HALE LANE PEEK
ENNISON AND HOWARD
777 E. William Street, Suite 200
Carson City, Nevada 89701
- O~~_/O4 ~~:~~':\X 6~L?OO!_-- Hale Lane tet ,) PESK\r l4J 003---
Application Of
Central Nevada Utilities Comp31lY
For.An Increase In Water
And S ewer Rates
WON&;'" ~WYER& COI.I.IN.~,,""""N=::;;"T LAW,,""" ......1( OF """",c:.o.
::0 w.::.... I.ISB"TY :::T-
~";-'
Inre:
A.2
BEFORE 'IHE PUBLIC UTILITIES COMMISSION
OF THE STATE OF NEV ADA
00000
Docket No. 00~
PRE FILED DIRECT TESTIMONY OF
DENNIS E. PESEAU
ON BEHALF OF CENTRAL NEVADA UTILITIES COMPANY
1. Introduction
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
My name is Depnis E. Peseau. My business address is Suite 250, 1500 Liberty Street, S .
Salem, Oregon 97302.
BY WHOM AND IN WHAT CAPACITY ARE YOU EMPLOYED?
I am President. of Utility Resources, Inc. My firm consults on a number of eCOllOlnlC
financial and engineering matters for various private and public entities-
ON WHOSE BEHALF ARE YOU TESTIFYING IN TillS PROCEEDING?
I am testifying on behalf of the Cenhal Nevada Utilities Compauy ("CNUC" Of :he
Company
Hale Lane et al 141 00401/20/04 14: 42 FAX 775 684 ~001 .. PESEAU,-,-
UON~~AWYERaCOI.I..IN,a
...TTO"N~'" AT """W
1100 !SANIC CF" """CI'II~"PV='W W':= uIJERTY =-vn~n
A.4
DOES ExinBIT DEP-l ACCURATELY DESclUBE YOUR BACKGROUl'.'D AND
EXPERIENCE?
Yes.
I discuss two distinct subj eets. name1y: (1) CNUC' s fair rate of retwn; and, (ii) the rate design
W1IAT SUBJECTS DOES THIS TESTIMONY ADDRESS?
proposed by CNUC based on my cost of service study. In the context of discussing a fair
rate ofretum that CNUC should earn, I also discuss the Company s cost of commOI1 equity,
its cost of debt, its capital strocture and, finally, its weighted cost of capital.
WHAT CONCLUSIONS DO YOU REACH'?
I conclude that:
The weighted cost of capital and fair rate of return. for CNUC is 11.62 percent.
The fair rate erratum on C"NlJC common equity is 12.90 percent.
The cost ofCNUC's debt is 10.50percent.
A conservative estimate ofCNUC' s test year capital structure is 47.20 percent equity,
52.80 percent debt.
- .
01120/04 14: 42 FAX [phone] . __Hale ane et al .. PESEAU !4J 005
UONt:;L. SAWYERa, COUJN""
A"I'TO""=--AT L.AW1 tOO 9AI'K 01'" A""""';"
P1--"%A
""
-~'t L""crry .,,-.iiY"-
Based on the cost of service and other policy considerations, the Company should
recover the increase in its annual water revenue requirement of$343,
930.00 through
a combination of increases in service charges and an increase in the
commodity
charge, which will be divided into peak and off.peak seasons as follows: '
~~~f~;:~V~ ~~" ~~t~~ni(;
:i ~ ~~~:'
;;; ~'%:;
~t:~~j:
~~:
A~~~~~~
::;,:;:::"','
f~';;':'Y:
~" :
;'I::"'i:;~~:~r:~?,
':..~", ";:,' '~:"' ,~:.:::
SE~C&d'HA.ltGES,'~f~, 1f."
~:"
~I:~ji:;'
:.' :::?,';"
~I:"
" "~;:
'.C;
..': ",. ,.'"""" "~ " :'" ':, '' : ' , " " " , '.' ..~"
Size Description Current Cbarge Proposed Charge
5/8"AU se~ce connections $6,$9_
3/4"Domestic semcc connections $6.$9,
3/4"All service coDIlcctions except Domestic $9.$13.50
Domestic service connections $6.$9.
All service coDIlections except Domestic $14.$21.00
lW'Domestic seIVice connecdons $9.$13.
An service connections $41.00 $6l.50
All service connections $80.$120.
All service COI1D.ections
$33.$49.
All service COI1D.cctions
$63.$94.
All service cou,nections $99.S 148.
10"All service connections $141.20 $211.80
12"An service connections $195.$292,
14"An service coDJJ.ections $195.$292,
~)i~~:
-"'i':",'
,--,, , '. -
,I,
" ""~', ", ".."", '"
CoL\1Monti;:, CHAAGES
:~';' ,~~:
:,L/~:~
~ :".., "' -..--' ..,
7-:: :
"" ..,
-7" ,,:'
!:,, -
' '/J,. c;
.. . "
Period Charge Per Billing Unit (per 1000 gaUons)
Curren!Proposed
Winter Periodl
Summer Perlod~
" 2
The Winter season rate will be in effect from November through April.
The Sununer season rate will be in effect from May through October,
01/20/04 14:43 FAX [phone] Hale Lanc" c;L al-. --- ----- ------
UON~L..-WYER"" c:o'-LIN9ATTO"NEYS AT LAW, '00 ".N~ 0" ."'CA'C...
= w,,-= w.,e",..,. AT.1"""0,N""ADA _so I
i'~:SI:.CQO06
The Company proposes to recover the necessary increase in its ,1illl.lilt sc'.v::r reVCr1Ll~
requirement of$438 243.00 by increasing monthly service charges to all customers
. : ';~"~:"~~~;.~; .: :';: /,)\~;,: :(~~~~::~,
'~i::":~~~;il)~~~f.
se~;\~~~~~thly~.~c~;9~:u:~es
Service Charge Current "Proposed
Charb'e Charge
Ingle Family Residence Connection $15.30\$29.
rnplex SeTVice Connection $12.45 $24_lill
1ultiple Units over cwo Service Connection Sl5.S29.5~
win\ming Pools:
10.000 Gallons Pool Cauacitv 34,
~O.OOO Gallons Pool CapacitY S4.00i 70,
000 Gallons Pool CapacitY $4.$i.
. -~~~
:;i
2S follows:
5 '
V\JV ,",u,.UU= .L uu.....", ..."u
000 Gal1ons Pool Ca acitv
000 Gallons Pool Ca aci
100,000 Gallons Pool Ca acity
150,000 Gallo.as Pool Ca
000 Gal1ons Pool Ca aci
000 Gallons Pool C aci
OOO and above Gallons Pool Ca aci
railer Courts, Trailer Estates:
er Trailer- Service COI1I1ection - Trailer Courts
or Each Mobile Home S~IVic:e Connection - Trailer Estates
chools and Churche.~:
or Each Classroom in Schools
aT Each P!\lmbing Fixmre in Schools, in Addition to Mcmrhlv Servic~ Char e
or Service Connection in Churchcs
01' Each Plumbin F1xture in Churches, in Addition to Mo%J.thl Service Charge
usiness and Otner eratlons:
or Each Plumbin FixtUre in Cafes and Taverns
or Each Plumbin Fixture in Business and Other 0 eratioIl, not O~herwisc Desi nard
edical Clinics:
or Each Plumbin Fixture in Medical Clinics
aundromats:
or Each Washing Machine in Laundromat
oreis and Motels:
or Each Roam in Hotel/Morcl
or Each Plumbing FixtUre in Hote1JMotel
231
~ - 2,
$12,
$12.
$42.
.1;62.
580.
5386.
$92.
$4,
$4.
$9_
$4.
$20.
$4,
$8.
$8.
S3_
$4,
$4,
$4_
);~$~~
$23.20'
$& 1.0,
$119,
$151)4':-
$166.
$177_
S7.
$8.
$7.
$38.
S7.
WHAT !S THE BASIS FOR YOUR CONCLUSIONS REGARDING CNUC'S FAIR
RATE OF RETUR..~ ON EQUITY?
26
Using a number of market-bas en estimates of return on equity, J find that larger, publiciy-
traded water companies have 2D. equity return. range of 11.40 percem to 11.fiO percent.
--- 11 /u4 ~~~.!~~2 ~!!,!Q.9_L_- __-1lJ!le- Lane et ---
uONE:L 5AW'fSR""'IOIIooI.1NS..-n CRN=~ AT .,00BM'Coc",......,.,e:R"'"
I'LA%A."""'C'T u._,.... "T.nn,n
) PESE,\l'(4J 007
Financial principles and empirical studies indicate that smaller w~ter companies
h~ve a
distinct and significantly larger degree a frisk thw do larger water companies. This greaTer
risk of small water companies justifies an additional 140 basis point increase for the
Company.
ll. Pumose of Testimonv. Principles. Summary and Conc1usions
HOW IS YOUR TESTIMONY ORGANIZED?
In this section, the concept of a fair rate of return and summary of my analysis is presented.
In Section ill of my testimony, the risk oflarge and small water utility cornmon stocks and
differences in risk of water utilities is discussed. In Section IV of my pre filed direct
testimony, I discuss specific additional risks faced by CNUC and explain why CNUC' s cost
of equity exceeds the cost of equity oflarger publicly-traded water utilities. Section V 0 f
testimony reports my discounted cash flow CDCF") equity cost estimates for a sample of
publicly-traded water utilities. Section VI of my prefi.led direct testimony presents equiTy
cost estimates based on two risk premium approaches. Section VB of my testimony
addresses the cost of debt cfwater companies in general and c~ruc in particular. Sectiop
VITI. of my pre filed direct testimony discusses CNUC's capital structure. Fmal1y. Section IX
of my testimony sets forth the rate structure proposed by CNUC for recovering the water
division s and sewer division s annual revenue requirements.
PLEASE DISCUSS WHAT IS MEANT BY A FAIR RATE OF RETURN.
A fair rate of remm is achieved wheI1 a Utility is permitted to set rates for service at keels
where the expected return over expenses provides common stock investors a reasonable
. opportUnity to earn the cost of common equity. Because operating expenses and interest on
. .. .
l'-l/':U/U4 14: H t:L\ 775 684 600J -- -__._
_d-_-H"I;,L:Hli.:,~I " ". '~~; nOli------,- ---- ----,,---, , ..-" - - ----
UoNr;;~ "'AWYERa. Cg~N'"ATTORN,""" AT .....'"
"00:0 SA"'" or A"'~Ale...
Pt,AZIo,"0 -""'T ..,........... :rr..._n_
debt take precedence over payments to common stock holders, it is the common equity
shareholder of the company who bears the greatest risk of actual returns taIling short of
expected returns. The courts recognized this principle many years ago and cast: many of the
tests and burden of regulatory perfonnance in terms of the end result the common equity
shareholder could expect.
In 1923, the U.S. Supreme Court set forth the following standards in the Bluefield
Waterworks de:cision:
A public utility is entitled to such rates as wi 11 pennit h to BaIIl a ret,rrn on the
value of tile property which it employs for the convenience of tht: public
equal to that generally being made at the same time and in the same general
part ofthfi: country on investn:ents in otherbus:nessundertaki..lgs which arc
attended by corresponding risks and uncertainties; but it has no constinuional
right to profits such as are realized or anticipated in highly profitable
enterprises or speculative ventures. The return should be reasonably
sufficient to assure confidence in the financial soundness of the utility, and
should be adequate, under efficient and economic management, to maintain
and support its credit and enable it to raise the money necessary for the
proper discharge of its public duties. A rate of return may be reasonable at
one time and become too high or roo low by changes affecting opp ortunities
for investment, the money market, and business conditions generally. 262
S. 679 692-93 (1923).
In the Hope Natural Gas Company decision, issued in 1944, the Court stated the following
regarding the rerum to O\~/Ilers of a company:
(TJhe return to the equity owner should be commensurate ",irb. retnffis on
investments in other enterprises having corresponding risks. That rerum,
moreover, should be sufficient to assure confidence in the financial integrity
of the enterprise, sO as to maintain its credi~ and to attracT. capitaL 320 U.
591,603 (1944).
In 1989, the Supreme Court reaffmned the principles set forth in the Hop~ decision in
Duquesne Light Co. v Barasch but also recognized two important economic concepts- First
6- .
v~/~u/u't L't;'t't rrlA ,,~ OO~ OUUI
2? II
WaNE!. SAWYER8. COu.JN;;"""'O"NIOY""'T........1 100 DAN" aPAMI:""CA
........,..
"" "",,5"1'
.....~.......-
"'"'ill
Hale Lan~~ et al ____2-PESE.-\("l4J 009
it found that regulatory commissions may need to adjust the risk premium element of the
rate of rerum on equity to provide a fair return. The Court wrote:
(W1hether a particular rate is 'I unjust" or "umeasonable" will depend to some
extent on what is a fair rate of return given the risks under a particular -rate
setting system. . . . 488 u.S. 299, 310 (1989).
Second, the Court found that the cost of common stock was "... the reTUrn required to sell
such stock upon reasonable terms in the market"
Id.at 310 , n 7. But, the source of ti.mds
that would be used to buy such shares, does not change that cost of equity. Owners o:tlle
utility ~ould be individuals who bought stock on margin or bought it with 100 percent of
their own funds. Owners could also be a partnership, a developer, a holding company or
some other type of owner. Knowledge about ownership, in short, does not change lhe
underlying cost of equity and thus is irrelevant to a dete.rrnination of the cost of equity and
fair rate of rot urn. For companies that have no publicly-traded common stock, lik= C1'\TUC
as well as those that do, the Court found the test of a fair rate of return is tied to the issuance
of new shares of common stock.
Belo-..y,l eh--plai.... thr..t sroall firms are more risky than larger finns. In the case of CNUC, it
is appropriate to recognize that small firms have higher equity costs and t.~\.lS the return
required to sell common stock for such smail firms on reasonable terms wo uld be higher than
the retl1In investors require to buy shares oflarger, less risky finns-
IO 'VHAT ARE THE IMPLICATIONS OF THE PRINCIPLES THE U. S. SUPREME
COURT LAID OUT IN HOPE, BLUEFIELD, AND DUQUESNE IN THE
DETERMINATION OF A FAIR RATE OF RETURN FOR CNUC?
lO' The U. S. Supreme Court's principles are important to debt holders, ratepayers and. equll)'
UlI;':U/U4 14: 44 FAX [phone] Hale Lane et ai---- --' PES;:.l4J 010
24:
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owners of CJ\TUC. From the perspeccive of debt holders, author.zed rates need to be
sufficient to assure current and prospective debt holders that Cl'\'UC will have interest
coverage comparable to other utilities having similar risk. Othervrise, the acceptance of
CNUC debts will decline and debt costs increase. Such increases in debt costs will require
rate increases and disadvantage ratepayers as well as debt halder-s. This is especially
important if a company s source of extemallong-term financing is limited to the less form~l
markets, as is the case with CNUC.
From the perspective of ratepayers and equity owners, the U.S. Supreme Court s principles
require rates which provide a. reasonable opportunity to earn a return for its owners that is
cOII1II1ensurate ~ith the return earned on investments in other enterprises having
COlTesponding risks. Rates, in addition, must be set at a 1evel sufficient to allow Cl\1'lJC to
attract capital on Te~asonable terms. From the perspective of ratepayers, the rates they pay
should provide a reasonable oppOItunit'j for CNUC to earn that fair rate of retlU11. That level
- the one that provides shareholders a fair rate ofretum on common equity ,- is the cos~ of
common equity.
ID. Risks of Water UtilitY Stocks
AS A PRELIMINARYMA TTER, PLEASE DISCUSS THE SAMPLE OF UTILITIES
YOU HAVE USED IN YODR DCF ANALYSIS.
Acquisitions and buyouts now in progress have substantial1yrcduced the number ofpublicJy-
traded water utilities available to make forward-looking estimates of the cost of equity.
Also, there are a limited number of water m:ilities for which there are analysts ' foreca.':;ts
futuTe earnings, dividends and future earned returns OD equity, the prefc;:rred data for a DCF
, .
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141011
analysis. Combined) these two limiting factors reduce the water utility sample to only rour
companies for which useful data are available to construct a benchr1.lark return on equity
ROE"
HOW DID yOU DETERMINE THE SAMPLE OF LARGE PUBLICLY-TRADED
WATER UTILITIES TO MAKE YOUR DCF BENCHMARK EQUITY COST
ESTIMATES'?
My sample oflarge publicly traded-water utilities is composed of American States Water
American WaterWorks, California Water Service andPhiladelphiaSnburbIDCorp.3 To my
knowledge, these four companies are not in the process of being acquired. As explained
below) the fact that a firm is in the process ora merger or acquisition often distorts the firm
share price and, therefore, provides incorrect signals about investors' expectations. In
addition, Value Line forecasts of expected futuIe dividends, earnings and ROEs for these
companies, the elements necessary to make DCF equity cost estimates, are available for the
benchmark companies. Finally, the benchmark companies are also listed in C. A Turner
Utility Reports and have at least one bond rating from Moody s or S&P that is siHg1e-A or
higher and have at least 75 percent of revenues derived from water utility operations. Exhibit
DEP-2 lists operating revenues and net plant for these four companies.
HOW IS RISK TYPICALLY MEASURED AMONG UTILITIES?
Beta" risk is the most frequently used measure of"bottom~line" risk. Beta risk quantifies
:;
Value Line reports data for six large water utilities. However, E'town Corp is being
acquired by Thames Water p1c and United Water Resources is being acquired by SUC7. Lyo.DJ\;Jise
des Eaux. As a result, those companies are not included in the forward-looking DCF analysis fo~
water 'utilities.
-9- .
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and therefore gives the degrees of risk differentia~ faced by eq'Jity o \vners offLlTlS, thereby \
determining differences in required returns on equity.
14 WHAT IS "BETA" RISK?
A.14 The risk measure caned '"beta CWl is the measure of risk in the Capitd Asset Prici:::lJ?,
Model ("CAPM")- Beta is a measure of relative risk. An average ::isk stock has a beta of 1.
and stocks that are less risky tha.Tl average have betas less than 1.0. If tWo utilities have the
same beta, CAPM predicts the utilities have the same "bottom-line" risk and required return,
The CAPM is written as:
Equity cost = RF (p x market risk premium)
or as
Equity cost = RF Company risk premium
where RF is a return on a risk-free asset (usually assumed to be a Treasury s:::ctL.-ity), c..!d the
beta times the market risk -premium pro"\.ides a measure ofllie company risk premium-
HAVE YOU COMPARED THE BETA RISK OF WATER A-"ND ELEC1'PJC
UTILITIES?
Yes. Exhibit DEP-3 reports Value Line betas for the sample offour large water utilities used
to make DCF equity cost benchmark estimates. Based on those statistic~l estimates, the
average water utilit'J is slightly more risky than the average electric utility and thus, the
average large) publicly-traded water utility bas a stightly higher cost of equity than the
average electric Utility.
10~
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, .
IV. Specific Additional Risk Faced by CNUC
16 IS CNUC MORE RISKY THAN LARGER PUBLICLY~TRADED WATER
UTll.-ITIES?
Yes. The Company is more risky thal1larger, publicly-traded water for a number of reasons.
The Company is more risky because it is smaller than the benchmark companies
Additionally, the Company is notpublicIy-tradcd. These facts mean that CNLJC is more risky
than the benchmark companies and, therefore, requires an t:quity cost risk prerniurn greateI
than the equity cost risk premium detennined fOT the 'benchmark companies in order to
provide CNUC a reasonable opportunity to earn a fair -rate ofretum.
17 ARE SMALL WATER mD..ITIES MORE OR LESS RISKY THAN LARGER
PUBUCLY-TRADED UTILITIES?
Small water utilities are more risky than larger ones and require higher equity retums tn
compensate fOT higher risk even when they have above-average common equity ratios.
EJdllbit DEP-2 shows CNUC has net plant and operating revenues that are less than .
percent as large as the average net plant and operating revenues of the average of four
benchmark water utilities I use to make equity costs.
18 IS THERE EVIDENCE THAT SHOWS SIZE HASANIlVIPACTONTHE COST OF
EQUITY?
18 Yes, evidence for companies in general, and water utilities in particular, indicates smalier
companies have higher costs of equity. Formal academic studies have addressed ~he issue
of company size ard risk and have found mat, in general, small~r firms are more risky,
Eugene Fama and Kenneth French ("Industry Costs of Equity,Journal oj Financial
11-
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11 I
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---' PES!':.~'jO14
Economics 43 (1997) 'J1. 153-93) conducted empirical studies that show that when beta nsk
Another study by Ibbotson Associates found similar results, Tables from the 2000 Ibbotson
Associates study are reproduced here as Exhibits DEP-4 and DEP-5 ,"' 11105': tables show
that, in general, sraaller companies have more beta risk than larger compZinies, Those tables
also show that, even if:..wo companies have the same beta risk, but one company is smal1er
than the other) fue smaller company requires a higher rerum on equity than the larger one.
is the same for companies, smaller companies are generally more risky than larger one~,
IbbotsonAssociates' estimates ofnumerica1 differences in equitycosrs are shown in Exhibir
DEP-S. This table shows the different expected risk premiums due to the size of companies
Assuming CNUC common shares would trade at a market-la-book ratio similar to publicly-
traded water utilities, the market value of CNUC would fall into the Micro-cap category.
Larger publicly-traded water utilities typically have market capitalizations that would put
them in the Low.Cap size category. 'With such market valuations, the Ibbotson Associates
study indicates a size risk premium in excess of the cost of equity for larger publicly-traded
water utilities of no less than 137 basis points for CNUC.
HAVE ANY REGULATORY COMMISSIONS STUDIED THE DIFFERENCES IN
RISK OF SMALL AND LARGE WATER UTILITIES?
Yes, the California Public Utilities CoII1..mission ("CPVC") has made su~h a stUdy of water
utilities. The CPUC found that smaller water utilities (Class C and Class D) required
Ibbotson Associatc::s, Stocks. Bonds. Bills and Inflation. 2000 Yearbook.Tables 7-
and 7-6 are reproduced as Exhibits DEP-4 and DEP-5.
12-
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equity retum higher than the l~ger Class A water utiliries even though those small water
utilities were financed with 100 percent comm.on equity. Even Class A water utilities have
as the size of a finn decreases. This increase in business risk more tban offsets the lo\ver
a sroa1l capitalization compared with the Ibbotson Associates' study. Business 11Sk increases
financial risk that would accompany 100 pcrceDt common equity. Staff Report on IssuE's
Related to Small Water Utilities (iss. June 10 , 1991); also CPUC Decision 92-03-093-
Also relevant to this proceeding is the CPUC's detennination that a small Class A water
utility, Park Water Company, had greater overall risk than larger, publicly-traded water
In a subsequent proceeding, the CPUC also found that smaller Class C and D water utili ty
required a higher ROE than the larger Class A water utilities.
utilities. In Decision 99-03-032 in Application 98-03-024, the CPUC concluded:
27. \\!hUe 'Park's slightly higher equity ratio than the average ofRRB'
comparable" group serves to somewhat lessen its financial risk, this is IDem:
than offset by Park's small size, limited financial flexibility, demonstrated
higher costs to borrow, and greater vulnerability to the risks of catastrophi('.
events which produce significantly higher business risks, leading to our
finding that Park presents an overall higher risk as perceived by investors, so
that the ROE expected m an acljusted quantitative analysis for the RRB
comparabJe" group should serve as a floor above which Park should be
compensated-
The CPUC further found that "Park's greater overall risk to investors represents an additional
30 basis points.
20 HAVE YOU CONDUCTED ANY NE'W STUDmS WHICH SHOW Sl\1ALL WATER
UTILITIES HAVE IDGHER COSTS OF EQUITY THAN LARGER ONES?
A.20 . Yes. Market information is required to estimate equity costs. It is generally difficult to find
13.
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useful market information for small water utilities because many ofllie small finns, such as
CNUC, are not publicly traded. Market data required to make DCF equity cost estimates
for four water utilities 1.1. California, however. were available to conduct such an analysis-
My study compared average equity costs of the two 5wallerwaterutilities, Domingul;:zWater
Company and SJW Corporation (San Jose Water), with equity costs ror the two larger
companies, California Water Service and American States Water, for the period 1987 to
1997. The results of my analysis are provided in Exhibit DEP-6. It shows that the smaller
water utilities had a cost of equity that, on average, was 97 basis point3 higher than the
average cost of equity for the larger water utilities.
This market information provides an estimate ofpart of the risk premium required by C1\:'UC.
Exhibit DEP-2 shows CNUC is less than .50 percent as large as the water utilities I use to
detennine benchmark DCF equity cost estimates and thus CJ\'UC has a higher cost of equity.
Based on the measures of size in Exhibit DEP-, CNUC falls well below the size of SJW
Corp and Dominguez Water Company. Thus, an appropriate risk premium foT C1'-;uC is
greater than the 97 basis point risk premium as well as risk premiums required to compensate
the Company for other company-specific risks.
21 DO THESE COl\'IPANY-SPEClFIC RISKS INCREASE CNUC'S COST OF
EQUITY?
Yes. Evidence I presented above shows that because CNUC is smaller than the benchmark
Basing the study on companies in the same state or geographic region reduces
concerns about the study results being dependent upon differences in regulatory risks or geographic
risks. .
14-
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companies, it requires a greater than 97 basispoi.otriskpremium. I conclude CNUC requires I
an eq1lity cost risk premium above the benchmark cost of equity estimates for larger water
and electric utilities of no less than 140 basis points at this time.
V. DCF Estimates of the Benthmark Cost of Eauity.
. Q.22 PLEASE TURN TO YOUR DISCOUNTED CASH FLOW EQUITY COST
ESTIMATES. "WHY HAVE YOU USED SAlVIPLES OF LARGE \V ATER i
UTILITIES TO DETERNfINE BENCHMARK EQUITY COSTS?
22 An ROE for CNUC, which is fair-to ratepayers, allows CNUC to attract capital on reasonabl~
terms, and maintain its financial integrity. This ROE is CNUC's cost of equity. That cost
should be commensurate with returns investors expect to ean1 on investments of co mp arab Ie
risk. To estimate that cost of equity, the analyst requires market data that reveals investors
required remms. but such data are not available for CNUC. There is no "pure play
company that is perfectly comparable to CNUC. The larger water utilities iI1 Exhibit DEP-
however, are providing the same service and thus provide a useful benchmark to d"-termine
a floor under CNUC's cost of equity.
.As discussed above, CNUC is more risk-y than the large utiliti~s in the sample in Exhibit
DEP-2. In this section of my testimony, I determine equity cost benchmarks using the DCF
model to establish a floor under the risk-adjusted ROE required to fairly compensate CNUC
Z2 PLEASE EXPLAIN TIlE DCF METHOD OF ESTIMATING THE COST OF
EQUITY.
The discounted cash flow model computes the cost of equity as the sum of an expected
- dividend yield CD/P ) and expected dividend growth (g). The expected dividend yield
15-
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computed as the ratio of next period's expected dividend (Dl) divided by the cuhent stock
price (Po)' Generally, the single period model is computed with formula (1) or (2):
(1)
(2)
Equity Cost DdPo x (1+
g) + "'"
D/PoEquity Cost
"'"
where DJP 0 is the current dividend yield and DlP 0 is found by increasing the current YldJ
by the gro'\vthrate. The DCF model is derived from the valuation model ShO\VTl in e;qll,ll:on
3 below:
(3)D/(1+k) + D/(l+k)2 +.. . + D)(l+k)",
, alternatively,
(3 A)D/(1+k) + CD:/. + P,)I (1+k),
where k is the cost of equity; Po is the stock price paid on the ex-dividend date, Dl' D 2' . .
.. are the cash tlow~ expected to be received in periods 1, 2
, . . , ""
, respectivdy; ~'1d Pl is
the price the investor expects to receive at the end of period number "2" (be it a sale price
or the price offered in merger).
23 WHAT WATER UTILITY SAMPLE DATA HAVE YOU USED TO :MAKE YOUR
BENCHMARK DCF EQIDTY COST ESTIMATES?
A.23 The relevant financial data for American States Water, American Water Works
Califoroia W 2.tcr Service and Phil~delphia Suburban Corp have been used to make
the DCF equity cost benchmark estimates. These four companies are an of the
water compaDies for which Value Line makes projections of future dividends per
share ("DPS"), earnings per share ("EPS") and ROEs, and which are not being
27
16.
lI"-V/V't ~~~~_.!1S4 __,_- IIale t.il/I(' (:t ,1;P;':'1:..~~O19
acquired.6 I did not include companies that were being acquired because, during
acquisitions, stock prices and thus dividend yields reflect investor expectations
related to when and if the buyout will OCCllI and the price, or stock price equival ent
they will receive. Thus, it is difficult to detennin~ investors' views about the
underlying cost of common equity when a company is involved in an 2.Gquisition.
24 HOW DID YOu COMPUTE CURRENT DIVIDEND YIELDS?
2811
'::OWNS~~A'M'=RNIO'nI"T LAW"OOBAN",Ol"AMIiRICA
Pt.A:t.OJ"'" w=r ,"'BERTY lIfT.ReNO.
The current dividend yield (Da ) is computed as the average of the highest and
lowest dividend yields during two periods ending in August 2000. The value for
o is computed as the sum of the cUITent indicated quarterly dividend and the three
prior quarterly divider-ds for each stock. The high and low prices used to compute
the dividend yie1ds are round from data for the 3-month and 12-month periods
ending in August 2000. Estimates of dividend yields (i.e, in equation 1 , D
are reponed in Exhibit DEP- 7, As of the end of August 2000, the 3-month average
dividend yield is 3.96 percept and the 12-month average dividend yield is 3.
percent for the sample of four water utilities.
HOW DID YOU ESTIMATE GROWTH RATES?
In estimating growtb1 I asSUl"U.e investors rely upon analysts' forecasts of future
sustainable growth :md forecasts of future EPS gro\Vth when they form th~ir
opinions about future growth prospects, To the e~tQlt that past DPS and EPS
6 E'Town and United Walar Resources are in the process of being ac;quired by Thames
Water and Suez Lyonnaise des Eaux, respectively.
17-
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growth provide an indic.ation of future growth prospects, I assume the walysts
have taken such past iDformation into account when they formed their forecasts
the future.
Once such growth estimates are made, investors buy or sell shares of the stocks
until the ex"pE:cted return from the dividend yields pIus the growth projections equal
the investors' discount rate.
26 WHAT DO YOU MEAN BY AN "INVESTORS' DISCOUNT RATE"?
An investors' discount rate for a particular stock is the discount rate for a marginal
inves1or 8 that \\rill make the present value of all expected future cash distributions
to that investor equal td the market price for a share of stock. That discount rate
is also the cost of equity. It is the discolUlt rate where the supply of shares of the
stock equal the demand for shares of the stock.
This assumption is consistent with an empirical study conducted by David A. Gordon
Myron J. Gordon and Lawrence L Gould "Choice AInong Methods of Share Yield JOtlnla! of
Porifolio Management (Spring 1989), pp. 50-55. They found that a consensus of analysts' forecasTs
of earnings per share for the next five years provides a. more accurate estimate of groVlth requilt:d
in the DCF model than 3 different historical measures of growth- They explain that this result makes
sense because analysts would take into account such past growth as indicators of future gro\.vrh aswell as any new information. As a result, one should expecT analysts' forecasts of gro'h'th to be
superior measures of growth required by the DCF model.
The marginal investor is the investor who last bought or sold shares of the stock.
Other investors, not on the margin, may have higher discouut rates and (thus do not buy the stock)
or lower discount rates and thus retain their positions in the stock-
Hi.
. .
-'-- -:~,::::'_-=-:" .." '~~_.i._0 q J) U U Hcll!~ Lan!' c-I ai FLS!.:Q 021
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~ o;CL..LINS"'TTO..,,~yS AT LAW'CQa_",O""""""CA
r I..AZA&0 W",= u"""TY ST.R~NCo. .
27 ARE THERE OTHER INDICATORS OF FUlliRE GRO\"VTH TRAT
INVESTORS MAY RELY UPON'\VHEN PRICING SILL\RES OF \VA TER
UTILITY COMMON STOCKS?
A.27 Yes.Other estimates \If forward-looking growth - at least for the near - teI11J c.::-e
analysts' forecasts of future EPS gro-wth. Exhibit DEP-8 shows estimates of l'J.ture
EPS grO\vth rates reported by the S&P Earnings Guide for a consensus 0 f aDf..lysls
and Value Line August 2000 forecasts crEPS grov,i.h for the four compc.ni::3 in
the water utility sample. The average of analysts' forecasts of growth j" ! .
percent.
28 HOW DID YOU UTILIZE TillS INFORI\1-t\TION ON DIVIDEND YIELDS
M"D ESTIMATED FUTURE GROWTH TO MAKE YOUR BENCHMARK
DCF ESTIMATES?
I adopted a growth rate range to compute the DCF equity cost estimates for the
sample of water utilitic~ of 7.14 percent 9 to 7.31 percent and the 'L2.Ilge of CLlm~nt
dividend yields in Exhibit DEP- 7 to estimate this bencbma.;-k equity cost rang'"',
Exhibit DEP-9 shows the estimated DCF range of 11.40 percent to 11.60 ~crcent
for the average utility in the sample of four publicly-traded water utilities- Ir is
derived from the dividend yield data and this ra..'"lge of growth rates.
This benchmark range does not however, account for the additional risk faced by
CI\!"UC. It only provides an estimate of tho floor under the fair rate of re-:Drn on
common equity for C!\JUC. In Section IV above, I concluded the additional eq-c..ity
The 7.14 percent figure was derived from a sample of 17 electric utilities, which
generally are less risky than water utilities.
19-
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--; PESEAr ~O22
return required by ewc is at least 140 basis points. Recognizing this size risk
premium, the benchmF.rk DCF equity cost floor indicates the cost of equity for
CNUC falls in a range of 12.80 percent to 13.00 percent.
VI. Risk Premium Estimates ofthe Benchmark Cost ofEquitv
. Q.29 IS THERE THEORETICAL SUPPORT FOR ESTIMATING THE COST OF
EQUITY WITH A RISK PREMITJM MODEL?
Yes. The capital assehricing model discussed above provides theoretical support
and justifies the finance principle that common stocks are generally more risky than
bonds.
Q.30 DO yOU EXPECT RISK PREMIUMS TO BE CONSTANT?
A.30 No. The theoretical work of Gordon and Halpern lo and numerous ernpirical
studies, including a 1993 study by the Staff of the Virginia Srate Corporation
Commission, indicate: that risk premiums change in the opposite direction to
changes in interest rates. Thus changf;s in the cost of equity, while moving in the
same direction as changes in interest rates, are generally smaller than associated
changes in Treasury rates. In the past, our firm conducted en:lpirical studies for
gas utiliti~s telecommUJ.1.ications companies, and electric utilities which
corroboTate the Gordon and Halpern theory.
10 Bond Share Yield Spreads Under Uncertain Inflation American Economic Review,
664 (September 1976) 559-565.
20-
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ARE THERE DATA AVAILABLE TO ESTIMATE HO\Y RISK
PREMIUMS CHANGE WITH CHA~GES IN INTEREST RATES?
Yes. The least controversial source of data for such an analysis are past deCisions
by regulatory commissions,
One should expect authorized ROEs for investor-owned utilities, which were not
detennined as a part of a settlement, to provide an unbiased measure of th::) cust
equity at the time the case was heard. Such commission detenni.natio~s \-vould Lake
into account the various stakeholders in a contested proceeding and, th1:.s, the
adoptc:d ROEs would be expected to be high enough to provide companies the
ability to attract capital on reasonable terms and maintain financial integrity, but
would take ratepayers' inter~sts into account and not authorize more than a fair rate
9fretum. The ROE that balances the interests of both ratepayers and investors is
the cost of equity. Every commission decisio~ will not provide every company iIS
cost of equity, but given the goals and r~sponsibilities of regulatory commissions,
one should expect that, on average, the cost of equity is awarded and thus the
various commission determinations provide an unbiased source of data to conduct
the risk premium analysis.
There are 485 past ,::ommission detenninations of ROEs that are available to
estimate risk premiu..-rns fOT electric utilities for the period 1983 !O 1999 and thus
another benchmark for consideration in the determination of the fair ROE for
CNUc. Exhibit DEP-IO shows annual averages of the ROEs authorized by the
21-
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ATTORNlrl'5 AT LA'"IIOO"ANKO......,IiRlCA
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RI!!NO,
various commissions for each of the years in the period as well as the number of
decisions, associated rates on IQ-year Treasury securities and derived risk
premiums at the different points in time. Figure 1 plots those annual average risk
premiums compared to the average Treasury yields. My quantitative analysis in
Exhibit DEP-IO is based on the 485 individual decisions o~dered by the
commissions and not the annual averages. The annual averages do : ho'1,,'evcr
support the same conclusion that risk premiums vary inversely with the !eyel of
Treasury rates.
32 WHAT MODEL IS USED TO MAKE THE RISK PREMIUM ESTIMATES?
A32
Q.33
A.33
I used the following model:
RPj =(AI X RFj
where RP, is the risk premium computed by subtracting the measure of the risk-
free rate (RFj) from the authorized ROE for the particular commission decision,
and Ao and AI are the parameters estimated with the statistical regression. If--
as expected -- risk premiums increase when the risk-free rates fall, the estimated
slope: (Le., A ) will be negative.
WHAT INTEREST RATE HAVE YOU USED AS RF?
I have adopted the IO-year Treasury rate as the measure of the risk-free rate.
Generally, Treasury rates are adopted as such risk-free rates. Blue Chip Financial
Forecasts collects, collates, and publishes averages and ranges of interest rate
forecasts :made by many financial institutions every month. In its March 2000
22-
. ., .
U.L/~U/U4 I 4 : 50 tAX 775 684 600 - PESL\i
13
LION EL.. SAWYC:'"& COLUN'O
ATTORNr'(:: IH LAW ::O
:::/.;;~:::"
RENO.
Hale Lane et 8.1 l4J 025
edition, Blue Chip asked those financial institutions "Should the 1 a-year Tre2.sury
note now be considered the 'benchmark' Treasury bor:d?"86 F:".rcell~ of the
respondents answered "yes," This market consensus provides a basis to adopt the
1 a-year Treasury instead of the rate OD some other Treasury security for this
analysis.
34 \VHATWERE THE RES'CLTS OF YOUR RISK-PREMIUM ANALYSIS'
A.34 The results of my analysis are shown iT'. Exhibit DEP-11. The -37 value for tile
slope (i.) means iliar as 1 a-year Treasury rates fall, t:.l1e risk premiuI:l goes up.
Another way of interpreting that result is that ifthe 1 a-year Treasury rate drops by
100 basis points, the cost ofequiry will drop by only 63 basIs points. The large t-
statistic of -21.6 indicates the Gordon "Hid Halpern theory is supported by the dati:)
and thus costs of equity are not expected to change as much as cl1angc;s in interest
rates.
35 WHAT IS THE COST OF EQUITY PREDICTED WITH YOL'R. RISK
PREMIUM APPROACH?
The cost of equity predictions are also shown in Exhibit DEP-ll. Blue Chip
Financial Forecasts reports consensus forecasts of 1 a-year Treasury yields as well
as the average of the top 10 percent and bottom 10 percent of forecasts being made
by the various financial instihltions being polled. Based on this range of forecasts
for the first quarter 0)2001 , the risk premium approach indicates another cost of
equity benchmark range of 11.10 percen: to 11.60 percent. With a 140 basis point
23-
01/20/04 J 4: 52 FAX [phone] !I!l1(~ Lint' (~t ,, PESI':.l?J (J 0::
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9 '
10 I
11 I
15
WONI!:L.3A.WYER:01 I;QUoINS"~YORH~9 AT LAWooD""I(OP.",,~I"'..
= W"-"T U,"crn- :;T.-. R
~~__.
risk premium range to reflect the additional risk of CNUC, the results of tbs
analysis indicate an equi~ cost range fot CNUC of12.50 percent to 13.00 percen!-
36 HAVE YOU PREPARED AN ADDITIONALRISKPREMIUl\1 ESTThL~TE
THAT IS BASED ON INFORMATION FOR THE LARGE WATER
UTILITIES?
A36 Yes. An estimate of the benchmark cost of equity based on the capital asse:tpricmg
model is also made. Above, I discussed "beta " the measure of risk provided by the
capital asset pricing model. The CAPM provides another method to cstimat~ :b.:::
benchmark cost of equity with a different type of risk premium model. CAPM
estimates can be made if there are estimates of the risk free rate, beta and :cJ.arket
risk premium. I used the overall consensus forecast of 1 O-year Tr~asuries of 6.
percent reported by Blue Chip for the first quarter of2001 as the measure of the
risk free rate, adopted Value Line estimaTes of betas reported in Exhibit DEP-3 as
the measure of beta risk for the large water utilities and adopted a range of
estiIDates for the current market risk premium to make my estimates,
37 WHAT IS YOURFIRST ESTllVIATE OF THE MARKETRISKPREMID\1?
My first estimate of the cun-ent market risk premiwll is the long-tenn average
rnarket risk premium far the period 1926-1999 of8.50pcrcentreported by Ibbotson
Associates. In adapti.r~g this long-term average, I assume the past provides a use'r:.ll
approximation of the fl.lture risk premium investors now req uire for an average risk
stock.
26
28;2L1.
. .\ .
OJ / ~O/O4 14: 53 FAX [phone]J JlCli!' L;,,;eo :':'-;'0 4; 003,- - u-o_---o_-_o ,-
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5\1
Q.39
22
L.ION;:I. ~AWYER... C:O~IN'"
A"'.,RN!:Y" AT L.AW: , 00 "..No; QF ,,""'Rlc.o.
""""'~
"" wt::!lT ueeRTY 8"T.R~N"
Q.38 IS IT POSSIBLE TO ESTII\1A TE A CURRENT - AS OPPOSED TO A
LONG-TERM AVERAGE - EXPECTED MARKET rUSK PREMnnyf'?
Yes. To be useful, thee:;Umate of the expected market risk premiUlI1 must be
estimate that is relevant today. A measure ofth~ long-term average cEff~rcnce iI"
returnS from stocks and Treasury securities based on data fro:n 1926-199'), (:l" ;;ume
other period, provides some perspectiyc about what investors n,,-,-)" CoPT, in the
future (based em the past), but it is not as usef1l1 as evid~ce about the currenL risk
premium required by investors. As discussed above, that CcrTent risk prerniUIE is
expected to increase a~ interest rates fall. It is also expected to i:1creasc \v:lel1
investors expect produc-.tivity in the economy to increase and if investors expect
stock markets to be more volatile-
IS IT REASOKABLE TO ASSUME I~VESTORS EXPECT ABOVE
AVERAGE MARKET VOLATll..ITY AT TillS TIME?
A.39 Yes. With the exception of 1987, the stock market in 1998 was more volatile 1na11
in any year since 1933 - Volatility in 1999 dropped a little , but j t is back up ag2.:~
in the year 2000. I expect investors recognize this risk and, all else equal, are
demanding higher than average ITIillket risk premiums.
Q.40 'WIIA T IS YOUR OTHER ESTL1VIA'fE OF THE CURRE~T l\1..tillKET
RISK PREMIl.;'"
A.40 I htve based this estiMate on an analysis of data Value Line reports from time-to-
time for the Industrial Composite- In ValLIe. Line July 2000 reporT.., the In(lustrial
Composite consisted :Jf785 industrial, retail and transportation comparies. Over
25-
. 0
. .
01/20/04 14:53 FAX 775 61S ~~~J_,-__.!1qlc:LaJH; '21 (\1--- ,- '---- ---- .-,-- ----' -
~ I
AAI
16
20 I
UONEL SAWYER'" c:oU-lN!J
....,.,....RHGV8 AT""'W1100 ....."K ,,"..."'BRI"'"
SO W=T U"~IOTT =.ItItNO-
' rESEAl'l4J 004
the years, I have collected eighteen of these reports from 1984 to the present. In
each of the reports, financial data and stock market values are pooled as if they all
belong to one giant cong10merate.In the earlier reports for the Industrial
Composite, companies from the same industry groups were pooled to provide data
but different numbers of companies were included.
HOW DID YOU MAKE THIS ESTIMATE OF THE CURRENT MARKET
RISK PREMIUM?
I followed a tbree step process. First, for each report available, I estimated a DCF
equity cost for the Industrial Composite using the model discussed above and
concepts consistent with the Value Line data-II In this analysis, the equirj cost:
estimates are based on reponed dividend yields and my estimates of sustainable
growth. These data and the a.nnual DCF equity cost estimates are repU):1cd at the
top of Exhibit DEP-12- Second, I computed risk premiums above 10 -year Treasury
rates and ran a. regression similar to the one presented in Exlllbit DEP-12 to
determine the relationghip between risk premiums and two independent variables
the IO-year. Treasury rate and a variable that represents differences betw~en
productivity in the period 1984-1995 and 1996 to the present.J2 The results of that
11 To be coDservl.tive, I have assumed the reported dividends in the dividend yields fur
the Industrial Composite are estimates ofD I from equation 2 and do not increase them by the po-,""1h I
~,
l2 Robert McTeer of the Dallas Federal Reserve Bank, who is also on the Open Market
Conunittee of the Federal Reserve, noted that productivity through 1995 was about 1.1 percent.
McTeer also noted that productivity from 1996 through 1999 more than doubled to 2.3 percent 311d
that he expected it to go even higher in th~ future. My analysis assumes investors also expect
productivity of2.3 percent or higher in the future.
26-
01/20/04- ----, -
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281
26\
LION"'", $AWVERa. C:O~N$
"'TTQI'N~:;; AT u..w""0 "AN...O""Mt;R"""
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1 ~ : 53 FAX [phone] Jlalt~ ~;-ii'"
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statistical analysis are alfo shown in Exj,ibit DEP-12. Third, I estim3.~ecl a currelJt
risk premium for the Ind~1strial Composite of 10.30 pe:rcen"'.:. asswning tb'C' lO-yea:-
Treasury note has a yield of 6-00percent. Available evidence indicate::; the hem fo~
the Industrial Composit~ is less iliarll,OO and thus ioplied market r:sk pr8:ni'.lID
for the full market is above 10.30 percent. To be cons:;:rvac1vc, hG\';cver, 1 adopt
the 10.30 percent risk premium for the Industrial Composire as my csumate 0::' the
current market risk premium.
Q.42 'WHAT WERE THE RESULTS OF YOUR CAPlY! RISK PREyIIL;M
ANALYSIS?
A.42 Based on this model and the consensus forecast ofRF, beta and the range of market
risk premium ("MRP") estimates, the benchmark equity cost for a large public!y-
traded water utility is estimated as feliows:
Equity cost fAR? )
Equity cost 00 percent (.61 8.50 percent)
Equity cost
"'"
00 perrellI 1 0.30 percent)
Equity cost range 11.20 percent to 12.30 pt'Tcent
The equity cost range for cr"TUC based on thi:; CA.PM analysis is 12.60 percent to
13.70 percent- This range is found by again adding 140 basis points to the
benchmark equity cost range of 11.20 percent to 12.30 percent for rat: large
publicly-traded water companies.
27-
- .. ,
01/20/04 14: 54 FAX [phone] . PESf.:\l"--_._---,---------'--'_.,' ---.-Hal e Law., t: l ii -- 0
.'.
l4.i 006
44 WHAT EQUITY RETURN DO YOU RECOMMEND THE COMMISSION
APPROVE FOR CNUC?
A.45
18
10N;;:L. :!;AWYe:1II
'" ",OL."""'"
...TTO"N='" AT LA'"00 ""NOt 0.. "'M!:ft'CA
)O"'I:";~':"T'1'::or.R"'..O
I recommend the Commission authorize 8..."1 equity retum of 12,90 percent, the
midpoint of a 12.80 percent to 13.0p percent range using primarily the water
company DCF model.
The fair rate ofretum for C~T(JC should be detennined by recognizing that CJ:\;UC
is considerably smaller in terms of operating revenues and net plant ThaD the
publicly-traded water companies I have relied upon to determine equity costs. I
presented evidence that smaller companies in general. and small water comparlles
in particular, have higher costs of equity than larger companies.
vll. CNUC'S Cost of Debt
PLEASE DISCUSS YOUR ESTIMATES OF CNUC'S COST OF DEBT.
Detenninmg the cost of a utility s debt for use in estimating a weighted to~al cost
of capital is generally a straightforward process fOT large utilities. Cred:r rating
agencies and formal underwriting entities pro...ide rather fluid and structme~-
markets for debt issuance by larger utilities, at ascertainable temlS.
For CNUC, howevEI, the quantifying of debt costs is somewhat less
straightforward. As noted in the CNUC brief, this filing is treating pareJ.i:
contributions to C~,;uC. that is, funds "due to PEC or Affiliates" as CNUC debt.
This approach is a conservative ant: because, under certain ciIcumstances, ~uch
contributions might be treated as equity investments. From the books of C:NLJC
28-
, ., ,
01/20/04 14: 54 FAX [phone]
, .
IIa 1(: L:!",'i: 007
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121
UONEL. :;"WYI:"
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,,'-=-'
.... W1IQT "'.""'TT :iT-R"NO,
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A.46
debt balances are consid~red to be $2 743 922., or 52.80 percent of total capital
structure for the test year.
A true market-based rate of interest must be inieITcd to set a fa;, anc re:asoD.8.o 1 e
cost of debt in dUs instance. Accordingly, I have refem;d to ouTs;rj:;, C'1;j~~::t!\'e
measures of debt cost. I note that our firm' s experienc~ in estimating ,ieD! Co;'L for
smaller water and similar utilities is that debt capital is somei:imcs difficul~ to
obtain. Such companies often cannot access national markets for debt and must
resort to financing through commercial banks and, if large enough, insurance
companies. Debt needs as small as those of CNUC simply do nor justify the t:ntry
costs to national markets.
WHAT lVIEASURE OF DEBT COSTS DO YOU ADOPT IN YOUR
TESTIMONY?
Commercial bank loans are often tied to the prevailing prime rate. The pfevailing
prime rate has been 9.50 percent for quite some time.
I estimate that CNUC might have access to commercial bank debt at teITrlS of
betWeen 100 and 200 basis points above prime. This would place its deb: costs
betWeen 10.50 percent and 11.50 perc~nt at this rime. I have adopted the mor.::
conservative estimatt: of debt costs of 10.50 percent for purposes of setting rates
in these proceedings.
29-
01/20/04 14: 55 FAX [phone] _,Ba19 Lane ~l 3i
---' ----,--- __
--__n_--- --'--' - _.
13,
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, PESE.i4!oos
VllI. CNUC'S Capital Structure
47 PLEASE DISCUSS YOUR ESTIMATES FOR CNUC'S CAPITAL
STRUCTURE.
A. 47 My estimates ofCNUC' 5 percentages of debt and equi ty in its capital structure are
summarized in my Exhibit DEP-13. There present~d: the allocated levels of debI
and equity are $2,743 922.00 and $2,466 590., respectively. This r~s1.llts in an
actual" capital structure of 52.80 percent debt and 47.20 percent e4uity.
48 IS THE ACTUAL CAPITAL STRUCTURE THE BEST MEASURE FOR
SETTING RATES OF RETURN IN THIS PROCEEDING?
Under the circumstances of this proceeding, yes. First, as stated in the brief
supponing the application, the Commission has expressed a preference for using
a utility's actual capital structUre, Second, CNLJC has adopted a conser,:ative
approach in calculating its actual capital srructUre, treating contributions from its
parent corporation as debt. Third, financial principles develop the fact that the true
cost of capital of a utility is a direct fimction of, among other things, the degree or
debt (referred to a.c:: leverage) in the capital structure. The more highly leveraged
the capital structure, the higher the cost of common equity and, therefore, the
overaIl cost of capital. As explain~d below, CNUC's actUal capital structUre falls
within a range ofreasonable capital structures.
49 IS CNUC'S CAPITAL STRUCTURE TOO HIGHLY LEVERAGED?
A.49 No. CNUC's common equity ratio falls within what I consider to be a reasonable
range-
30.
- ., .
OJ /20/04 14: 56 FAX [phone] lIall~ L:iI!'" ,, i FI'S, "l8: f) 0 9
, ---,,----'-- --' ,-"-
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:::,
rrER
.., O::OLJ.-IN9 """'cnrcr:"f~ AT LAW
"OXo841"oc""-AMCUCA pu.v.DO weST """'F\TY ~.
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19 \
50 WHAT IS THE BASIS FOR YOUR CONCLUSIOl'\ TlL;\.T C1\LJC'
CAPITAL STRUCTURE FALLS 'WITHIN A REASONABLE RAt'lGL OF
CAPIT AL STRUCTURES?
A.50 MyExhibitDEP-14 contains a copy Of~0 excerpt from the December 2000 C. .4,
Turner Utility Reports, indicating that larger water companies haviEg an
approximate A-rating from Standard (L"1d Poor s or Moody s bond r8t1n,g sel\i:.~:;
average a 45 pefcent equity ratio, In general, I believe that an c,:'i.iiry EI\10 01
between 40 percent and 50 percent is considered healthy.
CNUC's equity ratio falls well within t:.1lls range. Indeed, CNUC's actual capltd
strUcture is very similar to that of an A-rated water company, Villile I base my
final recommendations on the acmal equity ratio of52-80 percent debt and 47.
percent equity, I also include weighted cost of capital figures b2.sed upon 40
percent and 45 percent common equity nltios for consideration by 1:he COI1l-TJ1:SSiOIl-
Q.51 BASED UPON YOUR RECOMMENDED COST OF EQUITY /u"i("D DEBT
Ai."ID YOUR ALTERNATIVE CAPITAL STRUCTURES, \VHAi:
WEIGHTED COST OF CAPIT AL DO YOU RECOM.l\1END7
As shown on Exhibit DEP-, the 12,90 percent cost of equity, 10.50 percent cost
of debt and actual capital structure, the weighted cost of capital is 11.62 percem.
Alternatively, these capital cost componerlts combir~ed vrith either 2. 45 percent OT
40 percent equity ratLo derive we:ghlecI capital costs of 11.58 per~e;1t aiid IIAn
percent, respectively
31-
01/20/04 14: 56 FAX [phone] Hale Lane (~t. a 1 -, PESE..l.l'I4J 0 I (j
-_.- ---. .-------,- ,----.--..- - ,-----,-' -------"
I.IONE:L 9"WYERIX COLLJNS
"-r-ro....= AT L.AW'00 C,,"'OC O~""'Z:RIC:'".-.....zA'c W=T U.,I:RTT "'T.R6"'Q, .
IX. CNUCTS Proposed R..'\te Desi~n
52 WHAT IS THE I:.~CREA.SE IN CNUC'S ANNUAL REVENUE
REQUIREMENT FOR WATER SERVICES?
A.52 The required ioc:rease in CNUC's annual revenue requirement for water services is
$343,903.00.
53 HOW DOES THE COMPANY PROPOSE TO RECOVER ITS A1~NUAL
REVENUE REQUIREME~1?
A.53 CNUC proposes to rec':Iver approximately 60 percent of the Company s alIDual
revenue requirement from water services through a base commodity charge-
CNUC proposes to recover the remaining 40 percent of the Company's annual
revenue requiren1ent from water services through an increase in the monthly
service charge collected from all customers and through an increased seasonal ratt:.
Specifically. the Company proposes to add a seasonal commodity charge to the
base commodity charge to produce a total summer season comrnoc!1ty charge that
recovers approximately 20 percent of system capacity costs. C:t-.ruc limited tb~
portion of capacity costs recovered through the seasonal commodity charge to 20
percent to accommodate rate continuIty and stability because this type of charge
is new. The remaining 80 percent of capacity costs are recovered by increasing all
monthly per meter fixed charges on a uniform percentage basis.
5d IS THE RATE
REASONABLE?
DESIGN PROPOSED BY CNUC FAIR M'D
Yes. As explained below, allocating and recovering cost of service in the manIler
32-
01/20/04 14 : 56 FAX [phone] HalpL:!f;.:'1'" c: i: \:4.i (j 11-- n
------------------ ,-- -_.,---- -'
131
15 I
L.lQN~9A.WYER"'C;:O'-'-'N'"ATTOltNr1"" AT LAW100 SANK QF """""CAPI.A~= w"~T ~'BERTY "T-
_._-~!"~_.
described above is a fair, simple and straight forward way to recover costs of
~erJice from customer. The proposed rate design, in addition, m2...l(~s C'J.stomers
aware of the components of cost and the relationship of those costs to US??,'::
particularly the time of use,The rate 5trUcture proposed by the Compal1Y,
therefore, will encOUIag~ the efficient consumption of water.
55 WI-IY IS THE BASE COMMODITY RATE PROPOSED BY CI\'1TC FAIR
AJ'j"'D REASONABLE?
ASS Th~ cost to supply water to customers consists of the cost of acquiring the W~Icr
necessary to supply customer demands and building, operating and m2.intaining ,he
facilities to treat and deliver the water to customers when they dema,jc. it. For
designiJ:J.grates, these costs can be classified into three major components, the base
commodity component, the maximum capacity component and the custo:ner
component. The base commodity componcnt includes the costs of acquiring water
to meet customer requirements and the cost of facilities nec~ssary to deliver base
water demands to customers. Base water d~mands :r1c1ude the portion 0 r customer
demands that tends to be relatively stable throughout the year. The rna.'dmum
capacity component includes the COST of the facilities necessary to deliver to
customers sufficient 'vater to meet their maximum OT peak requirements. The
customer component of costs includes the costs of metering, billing, collecting and
accounting for customers usage and revenues-For water utilities, this CDS1
component tends to bf; relatively small compared 1:0 the other cost components,
281 33-
01/20/04 14:57 F..
\.\
i75 68~.,,001
- __,_
l~1it~:- Lap.f'.":'l ~;l-,.----,---'--' -- ---
13;
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, I'ESL-\I IfjO12
The most straight forward way to apportion costs to the base commodity
~omponeI1t is to utilize: the system load factor. The load factor represents me ratio
of average demand throughout the year to peak demand during the year. As such
it is an indication of the level of facilities necessary deliver water to Cl,lStomers
demand did not vary by time of use. For CNUC, the ratio of average day demand
to average daily demand during the peak momh is approximately 60 percent.
Therefore, for rate design purposes, I propose thai 60 percent of the Company
annual water revenue requirement should be recovered in a base commodity
component to be charged to and recovered from all customers connected to the
main system on the basis of water usage throughout the year.
Q.56 PLEASE EXPLAIN WHY THE SEASONAL CHARGE Al\'D THE
INCREASE IN THE MONTHLY SERVICE CHARGES ARE
REASONABLE?
c:r-.-ruc, of course~ is entitled to recover its annual revenue requirement. A portion
oBhe cost of service incurred by a water utility relates to the delivery peak capacity
requirements and demand to customers. Some of1hese costs are related to ability
to call on system cap'icity even if it is never utilized and some of these coSt are
related to actual usage attimes of system maximum demand. System facilities are
designed to deliver this amount of demand to customers.
Typically these types of costs are recovered from customers in one of two ways.
First, since these costs are largely fixed.. they can be recovered on the basis of
declining block commodity rates, with rates for sub-marginal usage desi!?;I1ed to
34-
01/20104 1 4 : 5 fAX [phone]-- -. ..- -,- - - ,-- ---_._-----'------'--"-'
261
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;,"
recover capacity costs. This method of revenue recovery, however, does not
necessarily encourage the efficient consumption of water. Second, because meter
:_~ ;~ - ","-~-..~~ ~
... +1-.~ ~~.~~,;,,1 f",..,~ """",,...p ,,(. ~,'o:tpT"'"1 r""....."...i", thPo:e ~~n~r1tv;:,!"'~!.;)... U."'GJ.,:ILU'" V.L ~..~ t'~L"U'L-' .-. ..__.
~- -- -.;------ ----..-. --".' .
charges can be recovered from customers on the basis affixed monthly charges per
meter which vary by meter size- N ei thc:r 0 f these methods camp 1 et el y rel ate::; costs
to demand at the time of system peak which the Syst(:ffi isdesigued for. Fu:c this
reason, CNUC proposes a seasonal rate
PLEASE EXPLAIN THE BENEFITS OF A SEASONAL RI\. TE.
Most water systems experience distinct seasonal peaks, due to weather-sensitive
demand and supply. Seasonal pricing reeD gnizes Lhe cost variance between s er,ring
peak and off-peak demands. Seasonal rate:; provide price signals to consumers
the actual cost savings That can result from changing usage patterns, Of, conversely,
the costs incurred by ConSU.I.'11ers not changing consumption patterns.For
consumers who arewilJing and capable of modifying usage pe.ttems, seasonal rates
also provide a means for reducing water bills. In contrast, uniform rat~ ovel- time
induce unnecessary c2pacity expansion,
The benefits of seasonal rates include increased operation efficiency, through
capacity utilization imp:rovements-In addition, seasonal rates reduce peak
demands. Reducing maximum demands can extend available water supplies and
postpone, and in some situations eliminate, the pressures for capacity expansion.
35-
. ,
01120/04 14: 58 FAX [phone] ____- _al~~LarJ~_er~__.-
r.tO~EL~WYER
~ - ,--..--
"""O""'~"A't....W1100 8ANK OF AMIO"IICA
..~
.... ~'f' U8ERTY 8T.R"NO.
....vA"" AQ,...o,
) PESEAF 141 016
main system. Michael L. J ohIlson explains in J:1j s testimony the costs of serving the
Class 2 Irrigation customer, which yield a rate of $.17 per 1000 gallons plus a
monthly service charge of$131.00.
61 WHAT IS THE COMP M'Y'S Al\'NUAL REVENUE REQUIREMENT FOR
SEWER SERVICE AND HOW nOES CNUC PROPOSE TO RECOVER
THAT REVENUE?
The Company's annual revenue requirement foT sewer service is $438,409.00-
CNUC proposes to recover that increase by allocating tho increase pro rata to
customers based upon the type of service. The increase to each customer will be
approximately 93 percent per month.
62 DOES TillS CONCLUDE YOUR TESTIMONY?
62 Yes.
38-
. .. .
---1I zu/ u -=~~~~ l'A.oI14~~~ -. _.___!la lC:La~e,- 'L._, n --,_YESEAU fgJO17
AFFI RMA TION
I, Dennis E. Peseau, pursuant to NAG 703.710 hereby affirm that HIs
foregoing prepared testimony was prepared by me or under my direction and is
correct to the best of my knowledge.
Dated
c: g~,M.-
-..12
. -
...&. 2 ;(" QJ
Signed
. -. .
vv~v/v't .1't:;HI 1'1\A "DO'! DUUJ _- Hal La~et ~L____'pE~EAU 141018
Exhibit (DEP. 1)
Page 1 of 3
STATEMENT OF OCCUPATIONAL AND
EDUCATIONAL HISTORY AND QUALIFICATIONS
DENNIS E. PESEAU
Dr. Peseau has conducted economic and financial studies for regulated
industries for the past twenty.eight years. In 1972, he was employed by Southern
California Edison Company as Associate Economic Anaiyst, and later as Economic
Analyst. His responsibilities included review of financial testimony, Incremental cost
studies, rate design, econometric estimation of demand elasticities and various areas
in the field of energy and economic growth. Also, he was asked by Edison Electrical
Institute to study and evaluate several prominent energy models as part of the Ad
Hoc Committee on Economic Growth and Energy Pricing.
From 1974 to 1978 , Dr. Peseau was employed by the Public Utility
Commissioner of Oregon as Senior Economist. There he conducted a number of
economic and financial studies and prepared testimony pertaining to public utilities.
In 1978 Dr. Peseau established the Northwest office of Zinder
Companies, Inc. He has since submitted testimony on economic and financial
matters before state regulatory commissions in Alaska, California, Idaho, Maryland
Minnesota, Montana, Nevada, Washington, Wyoming, the District of Columbia , the
Bonneville Power Administration and the Public Utilities Board of Alberta on over one
hundred occasions. He has conducted marginal cost and rate design studies and
v U ~v, V""L"". v v L'a"- I '" UU" UUU t1a ~Lane 1:)1.1.11.,,---.. t't;:;hAl'~O19
Exhibit (DEP-1)
Page 2 of 3
prepared testimony ' on these matters in Alaska, California, Idaho , Maryland
Minnesota, Nevada, Oregon , Washington and in the District of Columbia. He has
also conducted cost and rate studies regarding PURPA issues in the states of
Alaska, California, Idaho, Montana, Nevada, New York, Washington, and
Washington, D.
Dr. Peseau holds the B.A., M.A. and Ph.D. degrees in economics.
He has co-authored a book in the field of industrial organization entitled
Size. Profits and Executive Compensation in the Large Corporation, which devotes
a chapter to regulated industries.
Dr. Peseau has published articles in the following professional journals:
Review of Economics and Statistics. Atlantic Economic Journal. Journal of Financia!
Management, and Journal of Reoional Science . His articles have been read before
the Econometric Society, the Western Economic Association , the Financial
Management Association , the Regional Science Association and universities in the
United Kingdom as well as in the United States.
He has guest lectured on marginal costing methods in seminars in New
Jersey and California for the Center of Professional Advancement. He has a!sc
guest lectured on cost of capital for the public utility industry before the Pacific Coast
Gas and Electric Association, and for the Executive Seminar at the Colgate Darden
Graduate School of Business , University of Virginia.
. ., .
,~.vv ",.. "v UU" UUV' lldlC L,Ule Cl. ill. .. t';)hAIJ--- --------.---'-.---.---- ._--------,-' ,--,-l4J 020
Exhibit - (DEP-
Page 3 of 3
Dr. Peseau and his firm have participated with and been members of the
American Economic Associa1ion , the American Financial Association, the Western
Economic Association , the Atlantic Economic Association and the Financial
Management Association. He Wd,S formerly a member of the Staff Subcommittee on
Economics of the National Association of Regulatory Utility Commissioners.
Dr. Peseau has been President of Utility Resources , Inc. since 1985.
Vii ,,"VI V" .tv. vv r;1.A I I J 00'+ DUUl --Hale -,-'l!,~~~!!.L,---,-,__'m ., PESEAU ~O2t
Exhibit - (DEP-2)
Central Nevada Utilities Company
Table 1: Comparison of the Size of
Four Water Utilities ~ and CNUC
Operating Net
Revenues Plant
($ millions)($ millions)
American States Water $179.$424.
American Water Works 318.836.
California Water Service $219.$513.
Phil. Suburban Corp.$265.4 062.4
Average $495.$1.709.
CNUC $1.$5.
CNUC as a
Percentage of Average
Source: !L C.A. Turner Utility Reports , September, 2000.
, ,
VL"'V' V""',"""~"""UUUL 'late L.1U~_t-':..!:,~~.!c__._,,--'--'-".' .---_.'.., n:;)/:.,\U
Central Nevada Utilities Company
Table 2: Comparison of Value Line
Estimates of Beta Risk for Water Utilities
December 2000
Water Utilities:
1 American States Water
2 American Water Works
3 California Water Service
4 Philadelphia Suburban
Average
Source: Value Line Summary and Index, December 22 2000.
\ .. .\ ,If!:J Ull
Exb1.b1t. (DEP-3)
~~~-=--~ ~~~~~-~~ ~------- !11l1 e Li!L_--___-~ PESEAU ~O23
Exhibit ---(DEP-4)
Centra! Nevada Utilities Company
Table 3: Table 7-
Published by Ibbotson Associates
Table 7-Size~Decile Portfolios
of the NYSE
Bounds, Size
and Composition
From 1926 to 1999
ecentHistoricQI Average Recent Decile Market RecentPercentage of Number of CCipitalb:alion Percentage ofDedleTotal Cgpitalization Companies lin thousands)Total CcIpitolizationlargest65.27%186 537,187 0.53 76.27%1.4 45%182 115,150,71B 11 .28%61%185 497.7'27 909 0.4%59"10 183 274,796 124 78%00%18.5 17.4 953,833 77%02%183 118 014 701 1.1 9%37%184 78,066 231 79%90%184 129 702 51%55%18..t 506,709lO.Smcllesr 25%185 297,279 09%
Mid-Cap 3-5 15. 1 553Low.Cop ~8 4.29% .551Micro-Cop 9-1 0 0 80% 369
Source; Ct:'TIta' for Rm47't:h in Se:cuP"iry Pric~:. Univnrity of Chicago.
Hinorial 2Vef'lge pcrc:en~c orwt;1 capitalization shows the avc:ragc. the: last 74 years, of the decile marker va.luc:s~ a percerU::I&' of th" roul NYSE calc:ula.ted om yeu. Number of comp:mies in dec:ilc:s. recent marker =pila1iZ;lrion ofdec:ilc:.s ac.d rc=r perC1'mage of rotal capiQj~tion arc as of September 30. 1999.
9.17 .177,866
24!.6,21 0 634-
803,988
59%
2.49%
36%
D~ca~
Recent Murket
Capitoli;r.Qtian
(in thousands)
5369 722 21,4
10,498 796
221,601
203 671
304 131
872,220
577 778
381 ,830
214 640
97,914
Com ny Name
General Electric: Co.
Ul'li~ Corp.
ReQders Digest Association Inc.
Sterling SoHware lnc,
Steris Corp.
Unovc Inc:.
T remmell Crow Co.
ransadion Network Services Inc.
Donno Karan Intemotionollne.
DeJro Finandol Corp.
l'lorgesl
1 a-Smallest
Snur(e: Ca/r~,. .fe,. Rem.,.c/' i... S~C'.Jriry Pri",. Vnivmiry of Chicago.
Mar~r capi~izaciQn Oll1d Mme oflolrgcst company in c:acl1 deci!e ~ cfSc:ptt:I?~er 30.1999.
Source: Ibbotson Associates 58812000 Yearbook, Page 140.
U~I ':'VI V..01. V~ I't\.A I I;) DO'! DUU l .!!ale ~i!.I!I~__~ ,--------.-... PESEAU 141024
Exhibit~(DEP-5 )
Central Ntwada Utilities Company
Table 4: Table 7-
Published by Ibbotson Associates
Table 7-6 Size-Decile POrtfoliO5 of the NYSE:
long-Term Returns in Excess of CAPM
From 1926 tc 1999
Arithmetit Actual Return CAPM Return Siz;e PremiumMeclliin b:ce55 of in Excess of (Return inDecileBeta"Return Riskless Rote"Risldess Rate--Excess of CAPMJ
Q~90 12,13%93%7.28%-0.35%
13,8.36 --0.13.92 -0.1.12 14,0.281.15 15.10.06
15.44 1024 9.49
15.10.
1.27 16,11.10.1.381.33 17.12.10.1.61
-'.
'13 20.73 15.11.57
Mid-Cop, 3-5 14.
Low-Cop, 6--B 15.10.60Micro-CcQ, ;-10 18.40 13.19 10.2.21
Note
Difference between low-cap and micro-cap is 1.37%.
Source: Ibbotson Associates 8881 2000 Yearbook , Page 142.
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Exhibi t--- (DEP- 7)
Central Nevada Utilities Company
Table 6: Average Dividend Yields
Average
High LO'
Stock Stock
Price-Price-
Do/Po Do-(1999)(1999)
$1.$39.$25.
$0.$30.$18.9'1
4.25 $1.$32..$21 .
$0.$24.$16.
95%
Based on 12 Months of Prices
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4 Philadelphia Suburban
Average
Month Month
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Stock Stock
Dc/Po Do-Price-P rice-
$1.28 $31.$25.
$0.$26.$23.
$1.$26.$22.
$0.$24.$20.
96%
Based on 3 Months of Prices
1 American States Water
2 American Water Works
3 California Water Service
4 Philadelphia Suburban
Notes:
aJ Dividends paid during the 12 month period ending August 2000.
b/ Price range for tIle 12 month period ending August 2000.
c/ Daily Prices reported by Yahoo! for June to August 2000,
- .-----.----- '-, .vv ':VI V4 1;): U~ l'A.17';) 1:i84 I:iO O! ---_J:l_f!J-_~~ape~,t.al .. PESEAU 141 027
Exhibit (DEP-8)
Central Nevada Utilities Company
Table 7: Forecasts
of Future Earnings Growth
S&P
Earnings Value
Guide-Line-Average
1 American States 00%50%-75%2 American Water Works 00%50%25%3 California Water Service 50%50%4 Phil. Suburban Corp.11.00%50%75%
Average of Column 31%
Notes:
a/ S&P Earnings Guide for September 2000.
hI Forecasts made August 4 , 2000.
cl No forecast reported.
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01/20/04 15: 02 FAX [phone]-----JI_ale '1nc~Ull ... PESEAU 141 029
Exhibit (Dt:P-1D)
Page 1 Of2
Central Nevada Utilities Company
Table 9; Annual Averages of
Authorized ROEs , 10-Year Treasury Rates
and Average Risk Premiums for Electric Utilities
1983-1999
Average Average Average
Number Authorized TreasuJY Risk
Year of Orders ROE Yield-Premium
1983 15.11.
1984 15.11.
1985 15.12.
1986 13.
1987 12.5.4%
1988 12.
1989 12.
1990 12.4.4%
1991 12.50/0 2%1
1992 12.4.4%
1993 11.
1994 11.
1995 11.
1996 11.
1997 11.
1998 11.4%
1999 10.
NOt8S
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9
01/20/04 15: 05 FAX [phone] Hale Lane ct al .. PESEAU 141031
.. ...
Central Nevada Utilities Company Exhibit--- (DEP-ll)
Table 10: Risk Premiums Computed as Difference
Between Authorized ROEs and 10-Year
Treasury Yields ~ During the Period 1983-1999
Regression Output:
Constant ("
Std Err of Y Est
R Squared
No. of Observations
Degrees of Freedom
075
009
0.491
485
483
Slope (~A, "
Std Err of Coat.
t~statistic
-0.
017
-21.
Predicted
Equity Cost Risk TreasuryEstimatePremiumRate-
Top
;;;;
Bottom 11.
Formula: Risk Premium = Ao + (A1 x Treasury Rate)-c/
Sources and Notes:
aJ Source of Data: Oregon PUG Response to NW Natural Datarequest in UG 132 updated with data in Phillip Cross, Rate of Return: Stillan Issue at PUGs Public Utilities Fortnightly, December 1998 and decisonsreported by Regulatory Research Associates for 1999.
hI Blue Chip Financial Forecasts. Top and bottom ten percen~ consensus forecasts for 1st quarter 2001 as reported in September 2000.
cl 8-month lag between order date and Treasury yield adopted
based on the results of an Oregon PUG Staff study.
. .
--....01/20/04 15: 06 FAX [phone] Hale Lane et al .. PESEAU 141 035 . ". .. - :
C. A. Turner
Utility Reports
"the lnve8fDrl:! edge
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Electric Comprmies
Natural GtIS Companies
Telephone Companies
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DBCEMBER 2000
PahUIlb.cd by C.A. 1'1uncr Utility Repaas
o. &x lOSe, Moo~wa, NJ 08OS7.10S0
(~Ii) ~4-92QO, Exr.caaion. 400
A.tIAUS CaasuhMlII CompcmY
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01120/04 15: 06 ~AX 775 6M4 6001 Hale Lane et al ---PESE , ":;'---'---,. .:~- ----
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