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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC SERVICE
TO ELECTRIC CUSTOMERS IN THE STATEOF IDAHO.
CASE NO. IPC-O7-
IDAHO POWER COMPANY
DIRECT TESTIMONY
STEVEN R. KEEN
Would you state your name , address and
present occupation?
My name is Steven R. Keen and my business
address is 1221 West Idaho Street, Boise, Idaho.I am
employed by Idaho Power Company as Vice President and
Treasurer.
What is your educational background?
I graduated with high honors in 1981 from
Idaho State University, Pocatello , Idaho, receiving a
Bachelor of Business Administration degree in Accounting.
have also attended numerous seminars and conferences on
accounting and finance issues related to the utility
indus try.I am a Certified Public Accountant licensed in
the State of Idaho.
Would you please describe your business
experience with Idaho Power Company?
I joined Idaho Power Company (Idaho Power or
the Company) in September, 1982 , in the Property Accounting
Department.In March , 1983, I transferred to the Tax
Department as a Tax Accountant.From that time through
December, 1998, I advanced through every position in the Tax
Department including Property Tax Representative, Tax
Research Coordinator and finally Corporate Tax Director.
January, 1999 I became President of IDACORP Financial
Services.In June of 2006 I accepted the position of Vice
STEVEN R. KEEN, DI
Idaho Power Company
President and Treasurer of Idaho Power Company and IDACORP
Inc.
In the course of my duties with Idaho Power
Company, I have presented tax testimony to the Internal
Revenue Service.I have also provided tax and/or
capi talization rate testimony to the Departments of Revenue
and Taxation for Idaho, Oregon, Wyoming and Nevada.
What are your duties as Vice President and
Treasurer of Idaho Power as they relate to this proceeding?
I oversee the direct financial planning,
procurement, and investment of funds for Idaho Power , as
well as superVlse corporate liquidity management.
My duties and responsibilities include
varlous aspects of all the Company s financings and other
financial matters.Wi th respect to long-term financings,
sale of bonds and equity, my duties include development of
financial plans with senior officers, meeting with
representatives of investment banking firms that are
interested in underwriting Idaho Power securities,
discussions with rating agencies, assisting in preparation
of financial material including Registration Statements
filed wi th the Securities and Exchange Commission,
representing the Company at information meetings for
investment banking firms, reviewing information relative to
the Company s financings and recommending disposition of net
STEVEN R. KEEN, DI
Idaho Power Company
proceeds.Wi th respect to short-term financings, these
duties and responsibilities include negotiation of lines of
credi t with commercial banks and arranging for the sale of
commercial paper.
Do your responsibilities include
communication with members of the financial communi ty?
I am in continuous contact withYes.
individuals representing investment and commercial banking
firms , rating agencies, insurance companies, institutional
investment firms, and other organizations interested in
publicly traded securities that actively follow IDACORP and
Idaho Power Company.In association with the Company
Chief Financial Officer and the Director of Investor
Relations, my responsibilities include keeping these persons
informed of the Company s financial condition , arranglng
meetings with these people and Idaho Power s senior
executive management, and visiting with financial
representatives in their respective offices.Some of these
members of the investment community have followed the
electric utility industry for an extended period of time and
have a great deal of expertise in the financial problems and
prospects of utili ties.
Through my continual contact wi th the
financial community and review of investment banking
analytical reports and articles issued by these firms and
STEVEN R. KEEN, DI
Idaho Power Company
the rating agencies, I am able to keep informed on trends,
interest rates, financing costs, security ratings, and other
financial developments in the public utility industry.
Are you a member of any professional
societies or associations?
Yes.I am a current member and past board
President of the Idaho Society of Certified Public
Accountants.I am a current member of and past Council
member of the American Institute of Certified Public
Accountants.I am a current member and past board Chairman
of the Associated Taxpayers of Idaho.I am also a current
member of the board of the Idaho Tax Foundation and a member
of the Idaho Association for Financial Professionals.
I also receive information from attendance at
conferences and seminars of these and other utility
professional groups such as the Edison Electric Institute.
Through participation in these events, I gain additional
insights into the financial developments affecting Idaho
Power Company as well as the electric utility industry.
What is the purpose of your testimony in this
proceeding?
I am sponsoring testimony as to the point
estimate for Idaho Power Company s rate of return on common
equi ty and the embedded cost of long-term debt, risk factors
tha t are unique to Idaho Power Company, the use of a
STEVEN R. KEEN, DI
Idaho Power Company
forecasted year-end 2007 capital structure, and the
resultant overall cost of capital used to compute the
Company s revenue requirement.
What exhibi ts are you sponsoring?
I am sponsoring Exhibits numbered 10 through
15.
What return on equity are you recommending in
this proceeding?
I have selected 11.5 percent as the minimum
reasonable cost of equi ty for the Company.
Could you briefly outline what conditions
require a return on common equi ty of 11.5 percent?
As I will discuss in greater detail later in
my testimony, in addition to the reasons advanced by Mr.
Avera, I believe that, at a minimum, an 11.5 percent return
on equity is required to properly account for the risks
confronting Idaho Power Company, namely:( 1 ) a predominately
hydroelectric generating base subject to the uncertainties
of weather and water;(2) the effects of pricing changes in
a volatile wholesale power supply market in the Western
Uni ted States and specifically the Northwest , coupled with
the Idaho Commission Order No. 30215 on the load growth
adjustment rate in the Power Cost Adjustment (PCA);( 3) the
re-emergence of water issues in Idaho,(4) the renewal of
federal licenses for the Company s hydroelectric proj ects,
STEVEN R. KEEN, DI
Idaho Power Company
primarily the Hells Canyon Complex which provides 40 percent
of the Company s total generating capacity and particularly
the significant cost of re-licensing that project;( 5) the
impact of QF related expenditures, and (6) the inability of
the Company to recover the significant capital investment
required for present and growing electrical requirements and
service reliabili ty for its customers on a timely basis.
Are some of these risk conditions the same
risk conditions that have been raised in past Idaho Power
ra te proceedings?
However, I believe those riskYes.
condi tions have only grown worse with the passage of time.
please describe the risks specific to Idaho
Power s predominately hydroelectric generating base which is
subj ect to the uncertainties of weather and water.
Idaho Power Company and its customers have
historically enj oyed the benefits of a hydroelectric-based
utili ty.The availability of hydroelectric power depends on
the amount of snow pack in the mountains upstream of Idaho
Power s hydroelectric facilities, reservoir storage,
springtime snow pack run-off, rainfall and other weather and
stream flow management considerations.During low water
years, when stream flows into Idaho Power s hydroelectric
proj ects are reduced , Idaho Power s hydroelectric generation
is reduced.Extreme temperatures increase demand for power
STEVEN R. KEEN, DI
Idaho Power Company
by customers who use electricity for cooling and heating,
and moderate temperatures decrease demand for power.
precipi tation or the lack thereof also directly affects the
Company s irrigation load.Wea ther and hydro-production are
inextricably linked.Reduced hydroelectric generation
resulting from below normal water flows requires the Company
to use more expensive thermal generation and/or purchased
power to meet the electrical needs of its customers.
Does the Company s PCA remove this risk?
Not entirely.Al though the Idaho Commission
grants recovery for the maj ori ty of the variations in power
supply expense through the Company s PCA, the recovery is
less than 100 percent.Al though originally viewed by the
Company as an earnings stability mechanism, the PCA has
provided less stabili ty than anticipated.The risks
associated with the Idaho jurisdictional 10 percent of
variations in power supply expenses (the portion the
Company s shareholders are required to absorb) are having an
increasingly significant adverse financial impact on the
earnings capabili ty of the Company.Actual results no
longer provide the level of earnings stability originally
contemplated by the Company.
Why have the earnings stability benefi ts of
the PCA to the Company declined?
While I do not profess to be an expert on the
STEVEN R. KEEN, DI
Idaho Power Company
details of the PCA mechanism , from a financial perspective a
significant factor affecting the PCA has changed.
Please elaborate.
The Commission authorized1993 PCA
mechanism with the principal parts being fuel expenses,
deduction for surplus sales, purchased power expenses and an
adjustment to compensate for the difference between actual
load and the load used to establish base rates.
At the time the PCA was established in 1993
there fundamen tal relationship between FERCwas
jurisdictional rates for purchases and sales and Idaho Power
retail rates.All of the prices or rates were cost-based.
In 1997 , FERC determined that it would permit
market-based rates as opposed to cost-based rates.While
Idaho retail rates remained cost based,FERC jurisdictional
rates for sales and purchases became market based.The cost
or price for both FERC jurisdictional power purchases and
sales attributable to Idaho Power increased significantly.
This enormouscrea ted difference between the monetary
for purchased and surpl us sales that theamoun t s power
parties considered in 1992 and 1993 when the PCA methodology
established,and the costs and prices experienced inwas
recent years.This volumetric change is truly monumental
when you consider the financial size of Idaho Power.Mr.
Said informed me that average Idaho Power purchases for the
STEVEN R. KEEN, DI
Idaho Power Company
period average expense1993though1996were
$22 389,000 per year.For the period 1997 through 2006 the
average Idaho Power purchases were at an average expense of
$214 840,000.surplus sales for the period 1993Likewise,
through 1996 were at an average revenue of $42,000,000.For
the period 1997 through 2006,the average sales were at an
average revenue of $190,592 000.
Did you ask Mr. Said to provide you wi
information as to the decline in PCA earnings stability
benefits since the inception of the PCA due to increased
prices?
Mr. Said has informed me that at theYes.
time of the inception of the PCA , the Company, interested
parties and the Commission envisioned power supply expenses
would vary $120 million from a high-water scenario to a low-
water scenario.With base rates set at the mean of the
range and 90 percent sharing by customers, the Company
exposure to adverse water power supply expenses was $
million (1/2 * $120 million * 10 percent = $6 million)
In Mr. Said's testimony in this case, he
states that the range of power supply expenses from a high-
water scenario to a low-water scenario is now $330 million.
Using a similar computation , the Company s exposure to
adverse water is now $16.5 million (1/2 * $330 million * 10
The risk exposure today is 2.75 times as great aspercent) .
STEVEN R. KEEN, DI
Idaho Power Company
it was at the time the PCA was adopted.This increased
amount that is at risk should be recognized in the Company
return on equity in light of FERC market-based rates and how
those purchase power costs are calculated and treated in the
Idaho PCA mechanism.
Does your recommended 11.5 percent return on
equi ty reflect this increased risk to the Company based upon
the expanding range of power supply expense possibilities?
I allowed for a modest upward adjustment to
reflect the increased volatili ty in the markets.If market
changes limit the upside opportuni ty from the PCA mechanism,
then an additional return on equity would be required.
essence, if the predominant outcome of the PCA is now for
the shareowner to absorb some portion of additional costs,
my recommended return on equi ty is too low.
On January 9, 2007, the Commission issued
Order No. 30215 concerning the load growth adjustment rate
in the PCA mechanism.Are you aware of that order?
Yes.
How was that Order received by the financial
communi ty?
It heightened their concern that the Company
will be unable to earn its allowed rate of return.A. G.
Edwards & Sons, Inc. issued a research report on February
16,2007 stating,The revised LGAR mechanism and use of the
STEVEN R. KEEN, DI
Idaho Power Company
historical test years in rate cases makes it difficult for
IDA to earn its allowed ROE in periods of strong customer
and rate base growth.A similar report from Wachovia
Capi tal Markets, LLC on February 15, 2007 states,With the
resulting regulatory lag and reduced prospects for Idaho
Power to recover its authorized return on equi ty, in our
vlew, the decision reduces confidence in the regulatory
backdrop, especially as the Company begins to enter a new
baseload build cycle.Moreover , more frequent rate case
filings equate to more cost, more time, and more
uncertainty. "
In that Order, did the Commission discuss the
relationship between the load growth adjustment and the
return on equi ty?
Yes.In that Order the Commission stated:
" (B) ecause this process (the adjustment of load growth
recovery) puts the Company at some business and financial
risk , it is awarded a commensurate equity return.Order
No. 30215 at p. 10).
What does the Commission s statement mean to
you?
It communicates to me that the additional
risks borne by the Company due to the denial of load growth
costs are to be offset by a commensurate equi ty return.
the load growth adjustment rate increases, the return on
STEVEN R. KEEN, DI
Idaho Power Company
equi ty component must also increase.
Did you request from Mr. Said, as a result of
Order No. 30215, a quantification of the cost attributable
the increase
$16.per MWh?
Yes.I asked Mr. Said to provide me with the
the PCA load growth adjustment from
reduced expense recovery due to the removal of additional
load growth-related power costs from the PCA if the load
growth adjustment rate was increased from $16.84 per MWh.
Mr. Said provided me wi th three calculations.
One calculation indicated that a change from $16.84 MWh to
$29.41 MWh , as adjusted when Order No. 30215 was issued,
would remove an addi tional $3.4 million of expense and
require a 21 basis point increase to my ROE recommendation.
He also provided the calculations for the required change
based on his proposed rate of $29.16 MWh and the results
were nearly identical with approximately $3.4 million
removed from expense and a required 21 basis points
correlative adjustment to ROE.
A final calculation was included using a rate
of $71.58 MWh which Mr. Said evidently obtained from a
literal interpretation of the provisions of the load growth
calculation contained in Order No. 30215.This adjustment
removes an additional $15 million of revenue requirement and
would require a correlative increase to ROE of 91 basis
STEVEN R. KEEN, DI
Idaho Power Company
points.
Does your rate of return recommendation
reflect the calculations for the load growth adjustment Mr.
Said provided you?
My rate of return would not require
modification if the change approximates Mr. Said's $29.
per MWh load growth adjustment proposal.My recommended
rate of return of common equity 11.5 percent has increased
from the Company s prior rate of return and the changes to
load growth-related power costs contributed to that
increase.If the load growth adjustment rate is increased
above $29.16 per MWh , the return on common equity must
increase.For instance, if further reduced cost recovery
attributable to the load growth adjustment is $15 million
(using a load growth adjustment rate of 71.58 MWh), my rate
of return recommendation would need to be increased to 12.
percent which would be an increase of 70 basis points.
Are there any other water or weather-related
risks of the Company that you would like to comment on?
Yes.Comments from rating agencies and
analysts have expressed concern about the potential impacts
from aquifer recharge and water rights in general.While it
is difficult to quantify potential exposures, the heightened
level of discussions and disagreements on these issues have
increased the Company s risk profile in the financial
STEVEN R. KEEN, DI
Idaho Power Company
communi ty .
Please describe the risks regarding the
renewal of federal licenses for the Company s hydroelectric
proj ects .
Idaho Power Company is the only investor-
owned electric utility in the United States with 55 percent
of its generation derived from hydro generating facili ties
under normal water conditions.Wi th such a large portion of
the Company s generation resources based on hydro
facilities, a negative economic impact resulting from
renewing the federal licenses of these facilities could have
a significant financial impact on the Company and the prices
its consumers pay for electricity.As part of this process,
the Company has filed and will continue to file applications
wi th the FERC for new licenses for its hydro generating
capac i ty .
What are the associated financial risks to the
Company from re-licensing its hydro generating capacity?
Once an application is filed , the time frame to
actually receive an order from the FERC is unknown. This
uncertainty combined with the potential loss of generation
capabili ty due to operational changes, and the magnitude of
the financial impact of unknown Protection, Mi tigation, and
Enhancement (PM&E) costs are financial risks to the Company.
Are there other hydro re-licensing-based
STEVEN R. KEEN, DI
Idaho Power Company
financial risks considered by the investment community?
Yes. For any particular generating facility, the
worst possible outcome would be the loss of the license to a
competing party.Along with the uncertainty as to the
eventual receipt of licenses and the costs involved in
preparing for the license applications, costs of PM&E
related to these proj ects are also difficult to quantify.
The potential financial magni tude of these PM&E and their
effect on the Company s low-cost hydrogeneration resources
threaten the financial stability of a company the size of
Idaho Power and the ultimate rates it must charge its
cus tomers .These amounts will vary between each facili ty,
but in all cases they can be significant due to lost
generation capacity, generation at a higher cost, and the
decreased ability of the Company to time and control water
releases.
If the Company cannot generate when it is
most advantageous for the system, then some of the economic
value of the generation has been lost , even if the amount of
total generation does not change.In addi tion to the hydro
re-licensing risk, the Company continually faces significant
capi tal, operating and other costs relating to compliance
with current environmental statutes, rules and regulations.
These costs may be even higher in the future as a result of,
among other factors, changes in legislation and enforcement
STEVEN R. KEEN, DI
Idaho Power Company
policies and the potential addi tional requirements imposed
in connection with the re-licensing of the Company
hydroelectric proj ects .
Please address the risk associated with the
Company s re-licensing effort before the FERC for the Hells
Canyon generating facilities.
The Hells Canyon generating facilities
comprised of Hells Canyon , Oxbow, and Brownlee dams make up
67 percent of the Company s hydro generation capacity and 40
percent of its total generation capacity. The Hells Canyon
license application was filed in July, 2003, and accepted by
the FERC for filing in December, 2003.The FERC process
moves at a slow and deliberate pace due to the large number
of interested parties involved in evaluating the
application, thus the timing of the issuance of a new Hells
Canyon facilities license remains uncertain.
Historically, FERC has given the Company an annual license
renewal (under the existing old license) until the formal
new license is issued.It is difficult to predict the
ultimate financial impact of the re-license until the new
FERC license is issued and all of the re-license conditions
are known.
Please comment on the re-licensing efforts
tha t the Company has already undertaken.
As part of the FERC re-licensing regulations
STEVEN R. KEEN, DI
Idaho Power Company
and pursuant to the Federal Power Act, the Company is
required to conduct numerous studies and evaluations
concerning botanical issues , land management issues,
hydraulic issues, flow modeling issues, sedimentary issues,
water quality issues, aquatic issues, recreation issues,
cultural resource issues and fish and wildlife issues.
How does the Company account for the cost
these proj ects?
As provided by FERC and state accounting
requirements, the proj ect costs are booked to Construction
Work in Progress (CWIP) since they are part of the re-
licensing process. While the costs are included in CWIP , the
Company accrues a capitalization charge commonly referred to
as an allowance for funds used during construction (AFUDC).
When the new license is issued, those costs will be
transferred to electric plant in service and AFUDC will
cease.
Does the Company combine the FERC re-
licensing proj ects for accounting purposes?
Periodically the costs of re-licensing
proj ects are transferred from individual proj ects to a
rollup proj ect for the particular FERC license.
Just addressing the FERC rollup projects for
Brownlee, Oregon and Hells Canyon , for purposes of
illustration , what were the rollup amounts as of December
STEVEN R. KEEN, DI
Idaho Power Company
, 2006?
As of that date , the rollup costs for the
Hells Canyon re-licensing were:
Brownlee $34 742 257
$23,814 989Hells Canyon
Oxbow $10,907 067
Again , for purposes of illustration , for the
year 2006 what was the total amount of AFUDC attributable to
the Hells Canyon re-license?
Including not only rollup but all Hells
Canyon projects , the total amount of AFUDC was $4,776,138.
Is thi s amount inc uded in the Company
earnings?
Yes.AFUDC is a non-cash i tern that
represents the cost of financing construction proj ects wi
borrowed funds and equi ty funds.The component for AFUDC
attributable to borrowed funds is included as a reduction to
interest expense, while the equity component is included in
other income.The total amount of AFUDC is charged to CWIP.
Will the amounts be larger at the end of
calendar year 2007?
Yes, CWIP for the Hells Canyon proj ect re-
licensing which includes AFUDC of 4,858,000 for the year
2007 is forecasted to be $97 544,000.
What will occur when the Company receives a
STEVEN R. KEEN, DI
Idaho Power Company
new license for the Hells Canyon facilities?
The amounts in CWIP will be transferred to
plant in service and the accumulation of AFUDC will cease.
The result will be a large increase in rate base with
earnings of the Company declining since there will be no
AFUDC .Because this is a re-license of an existing hydro
facility, there will be no increase (if not a decrease due
to operational changes) in the generation of power and thus
no increase in sales revenues.The financial industry sees
this as a risk that confronts the Company which can be
summarized as follows:upon receipt of a re-license,(1)
the Company s earning will go down (no AFUDC) (2) the
Company s rate base will go up (transfer from CWIP), and (3)
no additional sales revenues (same plant but new license)
Does the regulatory treatment of energy
purchases the Company makes from PURPA Qualifying Facilities
(QFs) lncrease the financial risk to Idaho Power?
Yes, the regulatory treatment of QF
expendi tures provides for a one-for-one recovery of dollars
expended , but does not provide for a return to compensate
the Company for this acti vi ty.The Company is, in effect,
buying and selling energy pursuant to a legal mandate,
wi thout any compensation for providing this service.
Simplistically, this regulatory treatment is similar to
requiring a person operating a business to buy a product at
STEVEN R. KEEN, DI
Idaho Power Company
the same price it must be sold.The mere dollar-for-dollar
recovery of QF expenditures, but no return for the use of
the Company s balance sheet and liquidity in managing QF
programs, is viewed as a significant risk by the rating
agencies.They are not making a judgment related to the
appropriateness of QF energy purchase programs, but merely
pointing out the cost of the financial risk (s) arising from
a QF transaction , and that this risk should be reflected in
a higher return on equi ty to credit the Company for its QF
contracts.
Has the Commission previously considered a
proposal to compensate the Company for its management of QF
programs?
Yes.In determining the appropriate rates to
be paid for power and energy sold to Idaho Power pursuant to
section 210 of the PURPA Act of 1978, the Commission through
Order 18190 at page 21 indicated:
In another context, Staff witness
Drummond proposed that Idaho Power be
given a management fee amounting to five
percent of the gross paYments made to
CSPP'(QFs). The Commission will do
all in its power to encourage Idaho
Power to manage such proj ects in anorderly fashion. Orderly management
includes adequate staffing and clear
lines of authority among personnel
assigned to deal with CSPPs; good faith
negotiating of contracts and expedi tious
processing of worthy applications; and,
above all , a showing that the Company
has integrated cogeneration and small
power resources into its own planning,
STEVEN R. KEEN, DI
Idaho Power Company
construction and financing programs.
When orderly management is demonstrated,
the Commission will reconsider the
question of an appropriate management
fee or an equity adjustment.
The current expected normalized cost for QF
purchases is approximately $93 million.A five percent
management fee on these normalized QF costs would result in
a payment to the Company of approximately $4.65 million.
Using the same methodology as provided to me by Mr. Said
relating to changes in the load growth adjustment, this
$4.65 million increase would correlate to an addi tional 28
basis points of ROE that would increase my recommended ROE
to 11.78 percent.
Do the rating agencies recognize the
financial costs of QF-related transactions?
Yes.Like other electric utili ties, when the
Company adds to its rate base, it must use some portion of
shareholder equity to fund the investment.The Company mus
maintain its equity component above a certain level as it
continues this investment process.If it does not, the debt
level increases and the Company will face the threat of a
bond rating downgrade.Conversely, when the Company enters
into a QF contract for purchased power, an obligation not
reflected in its financial statements , an increase in equity
is needed to maintain credi t quali ty.Unless an equi ty
component is provided to offset the debt-like obligation of
STEVEN R. KEEN, DI
Idaho Power Company
long-term QF purchase power contracts, the Company faces
off-balance sheet financial risk. For financial commitments
that do not appear on the balance sheet, credit rating
analysts impute the debt and interest equivalents on the
financial statements of the Company to achieve a more
accurate picture of the risk associated wi th their
investment.The added equity needed to offset this imputed
debt and interest represents the effect that long-term
purchased power commitments have on the cost of capital. Any
increase in the long-term obligation of a utili ty related to
its capacity and energy resources will have to be backed by
an appropriate amount of equi ty in the eyes of the
investment community.
In reviewing its evaluation of the credi
implications of QF-related expenditures, S&P in May of 2003,
noted that such agreements are "debt-like in nature " and
that the increased financial risk must be considered in
evaluating a utility s credit risks.
Standard & Poor s Ratings Services views
electric utility purchased-poweragreements (PPA) as debt-like in nature
and has historically capitalized these
obligations on a sliding scale known asa "risk spectrum.Standard & Poor
applies a 0% to 100% "risk factor " tothe net present value (NPV) of the PPA
capaci ty paYments, and designates this
amount as the debt equivalent.
* * *
Standard & Poor s evaluates the benefits
STEVEN R. KEEN, DI
Idaho Power Company
and risks of purchased power by
adjusting a purchasing utility
reported financial statements to allow
for more meaningful comparisons withutili ties that build generation.Utili ties that build typically finance
construction with a mix of debt and
equity. A utility that leases a power
plant has entered into a debt
transaction for that facility; a capital
lease appears on the utility s balance
sheet as debt. A PPA is a similar fixed
commi tment. When a utility enters into
a long-term PPA with a fixed-costcomponent, it takes on financial risk.
Furthermore, utili ties are typically not
financially compensated for the risks
they assume in purchasing power , as
purchased power is usually recovereddollar-for-dollar as an operatingexpense.
Please describe the risks relative to the
Company s ability to recover significant capi tal investment
required for present and growing electrical requirements.
As the Company s generation and transmission
systems age and customer electrical requirements increase
addi tional investment is required to meet reliabili
standards and the additional demand on its electrical
infrastructure.The Company s latest forecast requires
construction budgets of approximately $266 million in 2008
and $815 million for 2008 through 2010 combined.
Construction investments of this magnitude introduce two
elements of risk: first, the ability of the Company to
attract the required capital and , secondly, the recovery of
these investments is on a deferred basis and subj ect to the
STEVEN R. KEEN, DI
Idaho Power Company
regulatory process.
Has the Company been able to earn its
authorized return on equity during recent years?
No.In fact , the Company s actual return on
equi ty has been less than 9 percent for the last four years.
What has prevented the Company from earning
its authorized or allowed return on equity?
I have previously addressed in my testimony
several issues which I believe adversely impact the
Company s ability to earn its authorized return.However
in my opinion, it is the use of a historical test year that
is the primary reason the Company fails to earn its
authorized or allowed return on equity at this time.
believe this opinion is universally held by financial
analysts that follow Idaho Power/IDACORP.Idaho Power
Company is in a consistent position of always recovering its
costs on a historical basis when its costs are constantly
increasing on a prospective basis.As a result, there is a
consistent recovery lag.As long as Idaho Power is
obligated to continue a large construction program to
accommodate growth and increased consumer demand, it can
never "catch-
What effect does growth have on the use of
historical data?
Growth inherently worsens the effects.
STEVEN R. KEEN, DI
Idaho Power Company
Operation & Maintenance (O&M) expenses typically rise faster
than inflation as new facilities and personnel are added to
meet growing cus tomer demands.Yet recovery is based on
lower historical amounts from a prior period.theLikewise,
allowed rate of return is applied to a rate base from a
prior historical period and new plant addi tions suffer some
period of zero percent return awaiting eventual rate base
trea tmen t
What is the status of Idaho Power Company
credit ratings?
Idaho Power Company s credit ratings as of
June 1, 2007 are as follows:
S&P Moody'Fi tch
Corporate Credit Rating BBB+Baa None
Senior Secured Debt
Senior Unsecured Debt BBB (prelim)Baa BBB+
Short -Term Tax-Exempt BBB/A-Baa 1/VMIG-NoneDebt
Commercial Paper
Credi t Facility None Baa None
Rating Outlook Negative Stable Stable
Standard & Poor s has continued to place the
Company on a "negative outlook"What prompted this action?
Per the Standard & Poor s May 11, 2007
Research Update,their Credit Analyst gave the following
reason:
The negative outlook reflects the
potential for weakened financial metrics
in accordance with expected large
capi tal expenditures and increase (dJ
STEVEN R. KEEN, DI
Idaho Power Company
generation cost. Also the uncertainty
of the effect of the recharge programs
under the stipulation agreement and
uncertainty regarding the IRS'
assessment of a $45 million taxliabili ty are factors.
A downward rating action could occur if
IPC is unable to achieve its proj ectedfinancial metrics. Conversely, an
outlook or a rating improvement will
depend on the restoration of adequate
financial performance, with modest
reliance on power cost deferrals, and
minimal or no ultimate financial
consequences from the aquifer rechargeprogram.
Do you believe that the current credit
ratings of Idaho Power Company are adequate?
Other utilities with the same credit ratings
as Idaho Power Company are able to raise capital in today
markets. However, these new debt/bond issues are at a higher
cost than if these utili ties had a higher credit rating (the
higher the credit rating, the lower the cost). This results
in passing on higher interest costs to the customer over the
life of the bonds.
The biggest threat to Idaho Power Company
current ratings is unforeseen risk. Should an unforeseen
event cause Idaho Power Company s short-term credit ratings
to be lowered , Idaho Power Company would no longer be able
to issue commercial paper. This would cause Idaho Power
Company to draw on the more expensive credi t lines,
resul ting in passing on higher interest costs to the
STEVEN R. KEEN, DI
Idaho Power Company
customer.
Would you please describe Exhibit No. 10?
Exhibi t No. 10 details the calculation of the
Idaho Power Company capital structure for long-term debt,
and the common equity balance resulting from the Company
forecasted year-end 2007 capital structure as provided to me
by Ms. Lori Smith, and the resulting overall rate of return
tha t I am recommending.
The capi tal structure presented on Exhibit
No. 10 incorporates changes to the Company s financial
reporting of its capital structure.Could you please
discuss the rationale for the variance?
For financial reporting purposes, the
American Falls Bond Guarantee and the Milner Dam Note
Guarantee are included in the long-term debt portion of the
capi tal structure.For ratemaking purposes, the interest
costs associated wi th both the American Falls and the Milner
debt securities are covered as O&M expenses.Even wi th
these exclusions the capital structure presented in my
Exhibit No. 10 is reasonable in light of industry and rating
agency cri teria.
Would you please comment on Exhibit No. II?
Exhibi t No. 11 details the calculation of the
cost of debt used in the estimated year-end 2007 capital
structure.The cost of debt is 5.591 percent. please note
STEVEN R. KEEN, DI
Idaho Power Company
that two forecasted bond issuances of $153 million and $80
million respectively appear on lines 10 and 11 respectively.
The $153 million issue will be used to redeem outstanding
short term Commercial Paper as well as financing ongoing
capi tal expenditures. The $80 million issue will be used to
retire the 7.38 percent First Mortgage Bonds and is
forecasted to have a coupon of 6.20 percent. The interest
rates for these issuances were derived with the following
methodology.First, the Company assumed a maturity on the
bonds for 30 years. Second, Idaho Power s current credit
spread on 3 O-year issues is 110 bps (basis points). Third,
the Company contacted Bank of America to obtain the
indicative forward Treasury rates as of July 2, 2007 and
December 3, 2007. The Indicative Forward Treasury Rate plus
Idaho Power s credit spread equals the forecasted interest
rate. Exhibit II, notes (e) and (d) show this calculation.
Does the Company utilize variable rate
securi ties in its long-term capitalization?
Yes.The Company currently utilizes several
variable rate securities in its long-term capitalization.
These securities are the County of Sweetwater (Bridger)
Pollution Control Revenue Bonds Variable Rate Series 2006
($116.3 million), the Port of Morrow (Boardman) Pollution
Control Revenue Bonds Variable Rate Series 2000 ($4.
million), and the Humboldt County (Valmy) Pollution Control
STEVEN R. KEEN, DI
Idaho Power Company
Revenue Bonds Variable Rate Series 2003 ($49.8 million)
These securities are listed on lines 13, 14 , 15, and 16 on
Exhibit No. 11.
Would you please describe the variable rate
nature of these pollution control bonds?
These variable rate pollution control bonds,
al though considered long-term securi ties, have features that
allow the Company to take advantage of rates applicable to
short-term securi ties.The County of Sweetwater Pollution
Control Variable Rate Bonds Series 2006 (Bridger Variable
Rate Bonds) and the Port of Morrow Pollution Control
Variable Rate Bonds Series 2000 (Boardman Variable Rate
Bonds) reset their interest rate on a weekly basis.The
Humboldt Pollution Control Variable Rate Bonds Series 2003
(Valmy Variable Rate Bonds) reset their interest rate every
35 days.
The Bridger Variable Rate Bonds reset their
interest rate every 7 days via a Dutch auction process
(lowest bid received by an Auction Agent that covers the
bonds outstanding) to reflect the current market condi tions.
On a weekly basis, the Boardman Variable Rate Bond's weekly
interest rate is determined the first day of a weekly period
by a Remarketing Agent.The Remarketing Agent examines tax-
exempt obligations comparable to the Boardman Variable Bonds
known to have been priced or traded under the then-
STEVEN R. KEEN, DI
Idaho Power Company
prevailing market conditions and finds the lowest rate which
would enable sale of the Boardman Variable Rate Bonds.The
Valmy Variable Rate Bonds reset their interest rate every
days via a Dutch auction process (lowest bid received by an
Auction Agent that covers the bonds outstanding) to reflect
the current market conditions.
Please comment on the derivation of the
effective cost of the interest rates for the Pollution
Control Bonds listed on lines 13, 14 , 15, and 16 of Exhibit
No. 12.
Exhibi t No. 12 is a chart that depicts the
Securi ties Industry and Financial Markets Municipal Swap
Index ( S IFMA Index)(formerly The Bond Market Association
(BMA) Swap Index) for the last five years dating from March
, 2007.The SIFMA Index , produced by Municipal Market Data
(MMD), is a 7-day high-grade market index comprised of tax-
exempt Variable Rate Demand Obligations (VRDO's) from MMD'
extensive database.The Index was created in response to
industry participants I demand for a short-term index to
accurately reflect activity in the VRDO market.
Please describe Exhibit 13.
Exhibi t No. 13 shows the Company s average
spreads (difference of the Company s actual variable rate,
plus or minus , when compared to the SIFMA Index during the
same time period) over the SIFMA Index for the Bridger
STEVEN R. KEEN, DI
Idaho Power Company
Variable Rate Bonds, the Boardman Variable Rate Bonds, and
the Valmy Variable Rate Bonds over the last five years.
please note that the Valmy and Bridger Variable Rate Bonds
do not have five years of data since each were issued in
October , 2003 and October , 2006, respectively.
In light of the historic lows of short-term
interest rates during the last five years , it was determined
that the methodology used in the last rate case (Order No.
29505) utilizing the average of the last five years of the
SIFMA Index, plus an average of the Company s spreads over
that same five-year period of these variable rate bonds,
would produce an erroneous implicit coupon rate for variable
rate debt.Simply put, this method would produce an
implici t coupon rate well below current market rates and an
unreasonable result. Therefore, the Company used a forward
market based approach. This methodology will produce a
forecasted implici t coupon rate for variable rate debt that
more accurately reflects near-term market conditions.
please describe Exhibi t 14.
Currently, there is no forward market curve
directly applicable to variable rate bonds. However, Bank of
America (BofA) Investments has developed an intrinsic
forward curve for the SIFMA Index.Exhibi t No. 14 is a
graph of this curve.
An analysis is performed to calculate each
STEVEN R. KEEN, DI
Idaho Power Company
variable rate bond's historic spread over/under the SIFMA
Index. An average of BofA's intrinsic forward curve for 2007
is also calculated. This average plus each variable rate
bond's historic spread over/under the SIFMA Index serves as
the basis for calculating the forecasted 2007 implicit
coupon rate for Idaho Power s variable rate debt.
Please describe Exhibi t 15.
The average of BofA's intrinsic forward curve
for 2007 is 3.58 percent, the average five-year Company
spreads for the Bridger Variable Rate Bond Series 2006 is
07 percent , the Boardman Variable Rate Bond is 0.
percent, and the Valmy Variable Rate Bonds is -07 percent.
These calculations are summarized in Exhibi t No. 15 and are
also presented in Exhibit 11 , column (11), line nos.(13) -
(15) .
The Effective Cost in Exhibit 11, column (13)
is calculated by taking Net Proceeds Received column (10)
di vided by Annual Interest Requirements column (12) times
100.
What is the overall cost of capi tal for Idaho
Power Company?
As shown on Exhibit 10, using the forecasted
year-end 2007 capital structure provided to me by Ms. Smith
the cost of capital presented in my testimony, and
incorporating the 11.5 percent cost of equity, the resultant
STEVEN R. KEEN, DI
Idaho Power Company
overall cost
percent.
this case?
of capital for Idaho Power Company is 8.561
Does this conclude your direct testimony in
Yes, it does.
STEVEN R. KEEN, DI
Idaho Power Company
IDAHO POWER COMPANY
COMPOSITE COST OF CAPITAL
AT ALLOWED RATE OF RETURN - SUMMARIZED
Forecasted December 31 2007 Capitalization
(1 )(2)(3)(4)(5)
Capitalization Structure Embedded Weighted
Amount Percent Cost Cost
108,460 000 49.737%591 %781%
120 188,586 50.263%11.500% *780%
228 648 586 100.000%561%
Line
1 Long-term Debt
2 Common Equity
Total Capitalization
Note:
* Requested rate of return 2007 Idaho PUC rate case.
Exhibit No.1 0
Case No. IPC-O7-
S. Keen , IPC
Page 1 of 1
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2
IDAHO POWER COMPANY FORECASTED 2007 IMPLICIT COUPON RATE FOR VARIABLE RATE
DEBT
As of 3/7/2007
(1)(2)(1) + (2) = (3)
Forecasted SIFMA
Average Spread over SIFMA*Forward Rate 2007 Foreca:;ted 2007
Instrument Index Last Years Average Implicit Coupon Rate
Port of Morrow 2000 (Boardman)
(1)(2)(1) + (2) = (3)
Forecasted SIFMA*
verage Spread over SIFMA Forward Rate 2007 Forecasted 2007
Instrument Index Last Years Average Implicit Coupon Rate
Humboldt 2003 (Valmy)
(1)(2)(1) + (2) = (3)
Forecasted SIFMA
verage Spread over SIFMA Forward Rate 2007 Forecasted 2007
Instrument Index Last Months Average Implicit Coupon Rate
Sweetwater 2006 (Bridger)
NOTE: The Securities Industry And Financial Markets Municipal Swap Index
NOTE: Calculation for the Forecasted SIFMA Forward Rate - 2007 Average
Date BotA Intrinsic FolWard Curve
3/20/2007 3.412
6/22/2007 694
9/24/2007 659
12/24/2007 571
Average for 2007 584
Exhibit No, 15
Case No, IPC-O7-
S, Keen, IPC
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