20080919Williams Direct.pdf

RECEIVED
ZlIlSEP .19 AM 19= 50
IDAHO PUBLIC
UTILITIES COMMISSiON
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE )
APPLICATION OF ROCKY )
MOUNTAIN POWER FOR )
APPROVAL OF CHANGES TO ITS )
ELECTRIC SERVICE SCHEDULES )
AND A PRICE INCREASE OF $5.9 )
MILLION, OR 4.0 PERCENT )
CASE NO. PAC-E-08-07
Direct Testimony of Bruce N. Wilams
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-08-07
September 2008
1 Q.
2
3 A.
Please state your name, business address and present position with Rocky
Mountain Power (the Company), a division of PacifCorp.
My name is Bruce N. Wiliams. My business address is 825 NE Multnomah,
4 Suite 1900, Portland, Oregon 97232. I am the Vice President and Treasurer of
5 PacifiCorp.
6 Qualifications
7 Q.
8 A.
9
10
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13
14
15
16 Q.
17 A.
18
19
20
Briefly describe your educational and professional background.
I received a Bachelor of Science degree in Business Administration with a
concentration in Finance from Oregon State University in June 1980. I also
received the Chartered Financial Analyst designation upon passing the
examination in September 1986. I have been employed by the Company for 23
years. My business experience has included financing of the Company's electric
operations and non-utility activities, responsibility for the investment
management of the company's qualified and non-qualified retirement plan assets,
and investor relations
What are your responsibilties as Vice President and Treasurer?
I am responsible for the Company's treasury, credit risk management, pension
and other investment management activities. In this proceeding, I am responsible
for the preparation of Rocky Mountain Power's embedded cost of debt and
preferred equity and the testimony related to capital structure.
21 Purpose of Testimony
22 Q.
23 A.
What is the purpose of your testimony in this proceeding?
I wil first present a financing overview of the Company. Next, I wil discuss the
Wiliams, Di - 1
Rocky Mountain Power
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7 Q.
8 A.
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15 Q.
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17 A.
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planned amounts of common equity, debt, and preferred stock to be included in
the Company's planned capital structure. I wil then analyze the embedded cost
of debt and preferred stock supporting Rocky Mountain Power's electrc
operations in the state of Idaho for the test period. This analysis includes the use
of forward interest rates, historical relationship of security trading patterns, and
known and measurable changes to the debt and preferred stock portfolios.
What time period does your analyses cover?
The test perod in this proceeding is the twelve months ending December 31,
2007, with known and measurable changes through December 2008. The capital
structure and costs of debt and preferred applied in this case are the average of
those measures at December 31, 2007, and December 31, 2008. The
determination of the embedded cost of debt and preferred stock was conducted
using the Company's actual costs at June 30,2008, adjusted for changes as I later
detail in my testimony.
Please explain Rocky Mountain Power's requirements to generate new
capital?
To address the load growth challenges outlined in Mr. A. Richard Walje's
testimony, the Company is adding significant new generation, transmission and
local distrbution facilities as well as investment in environmental resources. This
new investment wil require the Company to raise approximately $3.7 bilion of
new long-term debt in the capital markets over the next thee years while also
receiving new capital contributions from its parent company and continuing to
retain all earnings during this period. To date, the Company's owners have
Wiliams, Di - 2
Rocky Mountain Power
1 contributed $615 milion in additional capital to the business. Also, no dividends
2 have been paid by the Company to its owners. The cumulative impact of the
3 equity contributions and the reinvestment of earnings totals approximately $1.4
4 bilion.
5 Capital Structure Recommendation
6 Q.How does the Company finance its electric utility operations?
7 A.The Company finances its regulated utility operations utilizing roughly a
8 50%/50% mix of debt and common equity capital. During periods immediately
9 prior to and during significant capital expenditues, the Company may allow the
10 common equity component of the capital structure to increase, which provides
11 more predictable access to the capital markets, a more competitive cost of debt,
12 and over the long-run, more stable credit ratings, all of which assist in financing
13 such expenditures.
14 Q.What is the overall cost of capital that you are proposing in this proceeding?
15 A.Rocky Mountain Power is proposing an overall cost of capital of 8.49 percent.
16 This cost includes the Return on Equity recommendation from Dr. Samuel C.
17 Hadaway and the following capital structure and costs:
Wiliams, Di - 3
Rocky Mountain Power
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7 Q.
8
9 A.
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12 Q.
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14 A.
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Percent of %Weighted
Component Total Cost Average
Long Term Debt 49.2%6.20%3.05%
Preferred Stock 0.4%5.41%0.02%
Common Stock Equity 50.4%10.75%5.42%
Total 100.0%8.49%
How does this capital structure compare to the Company's actual capital
structure at June 30, 2008?
The actual capital structure at June 30, 2008 is approximately 52.3 percent
common equity, the same percentage of preferred stock and 47.3 percent long-
term debt.
Do you believe the proposed capital structure is a reasonable capital
structure for the purpose of setting rates in this Docket?
Yes. Although the common equity component of the proposed capital strcture
for ratemaking purposes is lower than the actual common equity component at
June 30, 2008, the actual common equity component wil vary over time with
financing activity and capital expenditures. In recognition of this, I believe the
proposed capital structure to be a fair and reasonable reflection of the structure
that wil exist, on average, during the period the rates in this case are in effect.
20 Financing Overview
21 Q.
22
23 A.
What types of securities does the Company employ in the long-term debt and
preferred stock components of its capital structure?
The Company relies on a mix of first mortgage bonds, other secured debt, tax
Wiliams, Di - 4
Rocky Mountain Power
1 exempt debt, unsecured debt and traditional perpetual cumulative preferred stock
2 to build the long-term debt and preferred stock components of its capital structure.
3 The Company has concluded the majority of its long-term financing
4 utilizing secured first mortgage bonds issued under the Mortgage Indenture dated
5 January 9, 1989. Exhibit No.7 shows that, as of December 31,2008, the
6 Company is projected to have approximately $4.8 bilion of first mortgage bonds
7 outstanding, with an average cost of 6.49 percent and average remaining maturty
8 of 18 years. Presently, all outstanding first mortgage bonds bear interest at fixed
9 rates. Proceeds from the issuance ofthe first mortgage bonds (and other financing
10 instruments) are used to finance the combined utility operation.
11 Another important source of financing has been the tax-exempt financing
12 associated with certain qualifyng equipment at power generation plants. Under
13 arrangements with local counties and other tax-exempt entities, these entities
14 issue securities and the Company, in turn, borrows the proceeds of those issuances
15 from the entities and contractually commits to make timely payments of principal
16 and interest on these bonds in order to take advantage of their tax-exempt status in
17 financings. As of December 31,2008, the Company's tax-exempt portfolio is
18 projected to be $738 milion in principal amount with an average cost of 4.1 0
19 percent (which includes the cost of issuance and credit enhancement).
Wiliams, Di - 5
Rocky Mountain Power
1 Planned Capital Structure
2 Q.
3
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5 A.
6
7
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15 Q.
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17 A.
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22 Q.
23 A.
How did you determine the amount of common equity, long-term debt, and
preferred stock to be included in Rocky Mountain Power's planned capital
structure?
As a regulated utilty, Rocky Mountain Power has a duty and an obligation to
provide safe, adequate and reliable service to customers while balancing cost and
risk. Significant capital expenditues for new generation, transmission and
distribution plant investment, operating and maintenance costs for new and
existing utility plant assets, and clean air investments are required for Rocky
Mountain Power to fulfill this obligation. Through its planning process, the
Company determined the amount of necessary new financing including capital
contributions needed to support these activities and calculated the required equity
and debt ratios required to maintain our current 'A-' credit rating for senior
secured debt.
Has the Company previously received capital contributions and does it
expect future contributions as well?
Yes. Following the acquisition by MidAmerican Energy Holdings Company
(MEHC) on March 21,2006, the Company has received a total of$615 milion of
cash capital contributions from MEHC via its direct parent company, PPW
Holdings, LLC. Similarly, the Company's planing includes additional cash
equity contributions before the end of2008.
Why is there the need for additional amounts of equity?
The cost increases in this case, coupled with the credit rating agencies
Wiliams, Di - 6
Rocky Mountain Power
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8 Q.
9
10 A.
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expectations for credit metrics and balance sheet strength, mean that additional
equity will be required along with improved business results and other
considerations to support our current 'A-' credit rating from Standard & Poor's
Ratings Service ("S&P"), 'A3' rating from Moody's Investors Service
("Moody's"), and 'A-'from Fitch Ratings. The Company canot finance itself
solely with debt. It is employing a mix of both new debt and equity to help
maintain a balanced capital structure.
Please describe the changes to the Company's levels of debt financing that
wil occur during 2008.
Over the period ending December 31, 2008, the balance of the outstanding long-
term debt wil change through maturities, principal amortization and sinking fund
requirements, and issuance of new securities. Based upon the long-term debt
series outstanding at June 30, 2008, I have calculated the reduction to the
outstanding balances for maturities, principal amortization and sinking fund
requirements, which are scheduled to occur prior to December 31, 2008. The
total long-term debt maturities and principal amortized over this period is $212.4
million. Then I added $800 milion of long-term debt issuances that occurred in
July 2008 that are necessary to fund our operations and to refinance maturing
debt. This new debt financing is balanced by the projected increase in equity
provided through the cash contributions from our parent company, as discussed
above, as well as increased retained earnings.
Wiliams, Di - 7
Rocky Mountain Power
1 Q.
2
3 A.
4
5
6
7 Q.
8
9 A.
10
1 1
12 Q.
13 A.
14
15
16
17
18 Q.
19 A.
20
21
22
23
How does this projected capital structure compare to comparable electric
utilties?
The projected capital structure is in-line with the comparable group that Dr.
Hadaway has selected in his estimate of Return on Equity. Both the Company
and the group of comparable companies show a similar percentage of common
equity in their capital structures.
Is the proposed capital structure consistent with the Company's current
credit rating?
Yes. This capital structure is intended to enable the Company to deliver its
required capital expenditures while achieving credit ratios that support the
continuance of our current' A-' credit rating.
How does maintenance of a strong credit rating benefit customers?
The credit rating given to a utility has a direct impact on the price that a utility
pays to attract the capital necessary to support its current and future operating
needs. A strong credit rating directly benefits customers by reducing immediate
and future borrowing costs related to the financing needed to support regulatory
operations.
Are there other benefits?
Yes. During periods of capital market disruptions, higher-rated companies are
more likely to have ongoing, uninterrpted access to capitaL. This is not always
the case with lower-rated companies, which during such periods find themselves
either unable to secure capital or able to attract capital only on unfavorable ters
and conditions. In addition, higher-rated companies have greater access to the
Wiliams, Di - 8
Rocky Mountain Power
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6 Q.
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8 A.
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16 Q.
17 A.
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long-term markets for power purchases and sales. Such access provides these
companies with more alternatives when attempting to meet the current and future
load requirements of their customers. Finally, a company with strong ratings wil
often avoid having to meet costly collateral requirements that are typically
imposed on lower-rated companies when securing power in these markets.
Is the Company subject to rating agency debt imputation associated with
Purchase Power Agreements?
Yes. Rating agencies and financial analysts consider Purchase Power Agreements
(PPAs) to be debt-like and wil impute debt and related interest when calculating
financial ratios. For example, S&P wil adjust the Company's published financial
results and add debt and interest implied by PP As when assessing
creditworthiness. They do so in order to obtain a more accurate assessment of a
company's financial commitments and fixed payments. Exhibit NO.8 is the May
12,2003, publication by S&P detailing its view of the debt aspects ofPPAs which
was refined in the March 30, 2007, publication (Exhibit No.9).
How does this impact the Company?
During a recent ratings review, S&P evaluated the Company's PPAs and other
related long-term commitments. The impact ofPPAs resulted in approximately
$450 milion of additional debt being imputed to the balance sheet and related
interest expense being added to the Company's income statement. These, in turn,
impacted the Company's debt and coverage tests.
Wiliams, Di - 9
Rocky Mountain Power
1 Q.
2
3 A.
How would the inclusion of this PPA related debt affect the Company's
capital structure?
By including the $450 milion imputed debt resulting from PPAs, the Company's
4 capital strcture would have a lower equity component as a corollar to the higher
5 debt component.
6 Financing Cost Calculations
7 Q.
8
9 A.
10
11 Q.
12 A.
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18
19
20
21
22
How did you calculate the Company's embedded costs of long-term debt and
preferred stock?
I calculated the embedded costs of debt and preferred stock using the
methodology relied upon in the Company's previous Idaho rate cases.
Please explain the cost of debt calculation.
I calculated the cost of debt by issue, based on each debt series' interest rate and
net proceeds at the issuance date, to produce a bond yield to maturity for each
series of debt. It should be noted that in the event a bond was issued to refinance
a higher cost bond, the pre-tax premium and unamortized costs, if any, associated
with the refinancing were subtracted from the net proceeds of the bonds that were
issued. The bond yield was then multiplied by the principal amount outstanding
of each debt issue, resulting in an annualized cost of each debt issue. Aggregating
the annual cost of each debt issue produces the total anualized cost of debt.
Dividing the total anualized cost of debt by the net proceeds of debt outstanding
produces the weighted average cost for all debt issues. This is the Company's
embedded cost of long-term debt.
Wiliams, Di - 10
Rocky Mountain Power
1 Q.
2 A.
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11 Q.
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13 A.
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How did you calculate the embedded cost of preferred stock?
The embedded cost of preferred stock was calculated by first determining the cost
of money for each issue. This is the result of dividing the annual dividend rate by
the per share net proceeds for each series of preferred stock. The cost associated
with each series was multiplied by the total par or stated value outstanding for
each issue to yield the annualized cost for each issue. The sum of annualized
costs for each issue produces the total anual cost for the entire preferred stock
portfolio. I then divided the total anual cost by the total amount of preferred
stock outstanding to produce the weighted average cost of all issues. This is the
Company's embedded cost of preferred stock.
A portion of the Company's debt portolio bears variable coupon rates.
What is the basis for the projected interest rates used by the Company?
The majority of the Company's varable rate debt is in the form oftax-exempt
debt. Exhibit NO.1 0 shows that these securities on average had been trading at
approximately 82 percent ofthe 30-day LIB OR (London Inter Bank Offer Rate)
for the period January 2000 through July 2008. Therefore, the Company has
applied a factor of 82 percent to the forward 30-day LIBOR Rate at December 31,
2008, and then added the respective credit enhancement and remarketing fees for
each floating rate tax-exempt bond. Credit enhancement and remarketing fees are
included in the interest component because these are costs which contribute
directly to the interest rate on the securities.
Wiliams, Di - 1 1
Rocky Mountain Power
1 Embedded Cost of Long-Term Debt
2 Q.What is the Company's embedded cost of long-term debt?
3 A.The embedded cost oflong-term debt is 6.20 percent. This represents the costs
4 for the test period divided by the average long-term debt outstanding at December
5 31, 2007, and December 31, 2008, as shown in Exhibit NO.7.
6 Embedded Cost of Preferred Stock
7 Q.What is the Company's embedded cost of preferred stock?
8 A.Exhibit NO.1 1 shows the embedded cost of preferred stock at December 31,
9 2007, and also December 31,2008, to be 5.41 percent.
10 Q.Does this conclude your testimony?
1 1 A.Yes.
Willams, Di - 12
Rocky Mountain Power
2fØ8SEP l 9 AM 10: 50
IDAHO PUBliC'
UTILITIES COMMIŠSION
Case No. PAC-E-08-07
Exhibit NO.7
Witness: Bruce N. Wiliams
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Bruce N. Wiliams
Cost of Long Term Debt
September 2008
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ZOfl SEP 19 AM .10: 50
IDAHO PUBLIC
UTILITIES COMMISSION
Case No. PAC-E-08-07
Exhibit NO.8
Witness: Bruce N. Wiliams
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Bruce N. Wiliams
Standard & Poors - Utilities & Perspectives
September 2008
.';
'\... ,."l.
t..
Last Week's Rating
Reviews and Activity . . . . . 10
Did You Know?
World Energy Consumption
and Regional Carbon Dioxide
Emissions in 2001. . .. .. . . .. 10
Last Week's
Financing Activity
Duke Energy's $700 Millon
Senior Notes Are Rated 'A-' . . . 11
Wisconsin Electric Power's
$635 Milion Debt Issue Is
RatedA-' .................11
North Carolina Eastern
Municipal Power's Bonds
Are RatedBBB' ............ 12
Medco Energi's Proposed
$200 Millon Notes Are
Rated8+'.................12
Utility Credit Rankings
Electric/Gas/Water. . . . . . . . . 14
Telecommunications. . . . . . . . 17
International. . . . . . . . . . . . . . 18
Key Contacts .. .. . . .. .. .. 19
STANDARD
&POOltS
Rocy Mountain Power
Exhibit NO.8 Page 1 of 4
Feature Article
"Buy Versus Build": Debt Aspects of
Purchased-Power Agreements ..................................2
Utilty Spotlight
High Commodity Prices Bode Well For Stone
Energy's Cash Flow ...............................................5
Special Report
Survey of State Regulators Reveals Focus
on U.S. Utilities' Financial Strength ..... . . . . . . . . . . . . . . . . . . . . . . . .6
News Comments
Laclede Group's and Unit's Ratings Are Lowered; Outlook Stable ....................7
Sierra Pacific Power's Water Facilities Bond Rating Is Raised to 'BB'. . . . . . . . . . . . . . . . .7
Empresa Electrica Guacolda Ratings Are Affirmed; Off Watch ......................7
Spanish Utilities Gas Natural, lberdrola Ratings Are Affirmed; Off Watch .............8
Enel's and Subs' Ratings Are Affirmed; Off Watch, Outlook Negative .. . . . . . . . . . . . . . . .8
Petrozuata Finance Ratings Is Affirmed; Off Watch . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9
.-"
..l .!
J ,
r ,. Feature Article
Rocky Mountain Power
Exhibit NO.8 Page 2 of 4
Case No. PAC-E-08-o7
Witness: Bruce N. Willall
"Buy Versus Build": Debt Aspects of Purchased-Power Agreements
Standard & Poor's Ratings Services views electric utilitypurchased-poer agreements (PPA) as debt-like in
nature, and has historically capitalized these obligations on
a sliding scale known as a "risk sperum: Standard &
Poor's applies a 0% to 100% .risk factor" to the net present
value (NPV) of the PPA capacity payments, and designates
this amount as the debt equivalent.
While determination of the appropriate risk factor takes
several variables into consideration, including the econom-
ics of the power and regulatory treatment, the overwhelm-
ing factor in selecting a risk factor has been a distinction in
the likelihood of payment by the buyer. Speifically,
Standard & Poor's has divided the PPA universe into two
broad categories: take-or-pay contracts (TOP; hell or high
water) and take-and-pay contracts (TAP; performance
based). To date, TAP contracts have been treated far more
leniently le.g., a lower risk factor is applied) than TOP con-
tracts since failure of the seller to deliver energy, or per-
for, results in an attendant reduction in payment by the
buyer. Thus, TAP contracts were deemed substntially les
debt-like. In fact, the risk factor used for many TAP obliga-
tions has been as low as 5% or 10% as opposed to TOPs,
which have been typically at least 50.
Standard & Poor's originally published its purchased-
power criteria in 1990, and updted it in 199. Ovr the past
decade, the industry underwent significant changes related
to deregulation and acquire a history with regard to the
performance and reliability of third-part generators. In gen-
erL, independent generation has perfrmed well; the likeli-
hood of nondelivrynd thus release from the payment
obligation-is low. As a result, Standard & Poor's believes
that the distinction between TOPs and TAPs is minimaL, the
result being that the risk factor for TAPs wil become more
stringent. This article reiterates Standard & Poor's views on
purchased powr as a fixed obligation, how to quantify this
risk, and the credit raifications of purchasing power in
light of update observtions.
Why Capitalize PPAs?
Standard & Poor's evaluates the benefits and risks of pur-
chased pow by adjusting a purchasing utility's reported
financial sttements to allow for more meaningul compar-
isons with utilities that build generation. Utilities that build
typically finance construion with a mix of debt and equity.
A utilit that leases a power plant has entered into a debt
transaction for that facilit; a capital lease appears on the
utilty's balance sheet as debt A PPA is a similar fixed com-
mitment. When a utilit enters into a long-term PPA with a
fixed-cost component, it takes on financial risk. Furthermore,
utilities are typically not financially compensated for the risks
.. Back to
"' Table of Contents
Next Page ~Page 2 May 12, 203
they assume in purchasing po, as purchad po is usu-
ally revered dollar-for-dollar as an operating exe.
As electricity deregulation has progressed in some coun-
tries, states. and regions, the line has blurred betw tra-
ditional utilities, vertically integrated utilties, and merchant
energy companies, all of which are in the generation busi-
ness. A common contract that has emerged is the tollng
agreement, which gives an energy merchant copany the
right to purchase powr from a speific power plant. (see
"Evaluating Debt Aspec of Powe Tollng Agreements:
published Aug. 26, 2002). The energ mehant, or tol, is
typically responsible for procuring and delivering gas to the
plant when it wants the plant to generate power. The power
plant operator must maintain plant availability and prduc
electricity at a contractual heat rate. Thus, tollng contacts
exhibit characteristics of both PPAs and leases. Howeve,
toilers are typiclly unregulated entities competing in a
competitive marketplace. Standard & Poor's has determined
that a 70% risk factor should be applied to the NPV of the
fixed tollng payments, reflecting its assessment of the risks
borne by the toller, which are:
. Fixed payments that cover debt financing of power plant
(typically highly leveraged at about 70%),
. Commodity price of inputs,
. Energ sales (price and volume). and
. Counterpart risk.
Determining the Risk Factor for PPAs
Altematively, most entities entring into longterm PPAs, as
an altemative to building and owing power plant, continue
to be regulated utilitie. Observtions over time inicate the
high likelihood of performance on TAP commitments and,
thus, the high likelihoo that utilities must make fixe pay-
ments. However, Standard & Poor's believes that vertlly
integrated, regulated utilties are affored greater protecion
in the recovery of PPAs, compared with the recov of fixed
tollng charges by merchant generaor. There are tw re-
sons for this. Firs, tariff are tyally set by regulators to
recover costs. Second, most vertically integrate utilties c0
tinue to have captive customers and an obligation to serve. At
a minimum, purchased pow, similar to capital costs and ful
co, is included in tariff as a cost of serice.
As a generic guideline for utilitis with PPAs included as
an operating expense in base tari, Standard & Poor's
believes that a 50% risk factor is approprate for longter
commitments (e.g. tenors greter thn three yers). This risk
factor assumes adequate regulator treent, incuding
recognition of the PPA in tari; othse a highe risk factor
could be adoed to indicate grater risk of reery.
Standard & Poor's will apply a 50% risk fator to the capacity
Standard & Poor's Utilites & Perspectives
".~
-: ,t
. .
~r.. Feature Article
component of both TAP and TOP PPAs. Where the capacity
component is not broken out separately, we will assume tha
50% of the payment is the capacity payment. Furtermor.
Standard & Poor's wil take counterpart risk into account
when considering the risk factor. If a utilit relies on any indio
vidual seller for a material portion of its energ needs, the
risk of nondeliver will be assessed. To the extent that energy
is not delivered, the utility will be expse to replacing this
power, potentially at market rates that could be higher than
contracted raes and potentially not reoverable in tariff.
Standard & Poor's continues to view the reovry of
purchased-power costs via a fuel-adjustment clause, as
opposed to base tariffs, as a material risk mitigant. A month
ly or quarterly adjustment mechanism would ensure dollar-
for-dollar recovery of fixed payments without having to
receive approval from regulators for changes in fuel cost.
This is superior to base tariff treatment, where variations in
volume sales could result in under-recovery if demand is
sluggish or contracting. For utilties in supportive reulatory
jurisdictions with a precedent for timely and full cost recov-
ery of fuel and purchased-poer costs, a risk factor of as low
as 30% could be used. In cein cases, Standard & Poor's
may consider a lower risk factor of 10% to 20% for distribu-
tion utilities where recovery of certin costs, including
stranded assets, has been legislated. Qualifying facilties
that are blesse by overarching federal legislation may also
fall into this category. This situation would be more typical of
a utlity that is transitioning from a vertically integrated to a
disaggregated distribution company. Stil, it is unlikely that
Table 1
ABC Utility Co. Adjusbnent to Capital Structure
Rocky Mountain Power
Exhibit NO.8 Page 3 of 4
Case No. PAC-E-08-Q7
Witness: Bruce N. Willams
no portion of a PPA would be capitalized (zer risk fa)
under any circumstnces.
The previous scenarios address ho purchased por is
quantified for a vertically integrated utility with a bundled
tariff. However. as the industry transitions to disaggregtion
and deregulation, various hybrid models hav emerged. For
example. a utilty can have a deregulated merchant energy
subsidiary, which bus power and off-sells it to th regulat-
ed utility. The utilit in turn passes this power through to
customers via a fuel-adjustment mechanism. For the mer-
chant entit, a 70% risk factor would likely be applied to
such a TAP or tollng scheme. But for the utilit, a 30% risk
factor would be used. What would be the appropriate treat-
ment here? In part. the decision would be driven by th rat-
ings methodolog for the family of copanies. Starting from
a consolidated perspective, Standard & Poor's would use a
30% risk factor to calculate one debt equivalent on the con
solidated balance sheet given that for the consolidated
entity the risk of recovery would ultimately be throug th
utility's tariff. However. if the mercant energy compay
were deemed noncore and its rating was more a reflecion
of its stand-alone creditortiness, Standrd & Poor's
would impute a debt equivalent using a 70% risk factor to
its balance sheet. as well as a 30% risk-adjusted deb
equivalent to the utilty. Indeed, this is ho the purchases
would be refleced for both companies if there were no
ownership relationship. This examle is perhps ovrly
simplistic because there wil be many variations on this
theme. However, Standard & Poor's will apply this logic as
Original capitl stnctre
%
54
Adjustd capital strure$ %1,40 48327 11200 71,00 342,92 100
Deb
Adjustment to debt
Preferred stock
Common equity
Total capitalization
$
1,400
200
1,000
2,60
8
38
100
Table 2
ABC Utilty Co. Adjustent to Pretax Interest Coverage
Original pre
interest coverage
Adjusd pr
intere covrage
Net incme 120
Incom taxes 65 300
Interest expnse 115 115 =2.6x
Prta available 30
..Backto"i Table of Contents
Nex Page~Page 3 May 12, 2003
(30331
(115+331 =2.3x
Standard & Poors Utilties & Perspectves
/...
-: t. .
'r' Feature Article
a starting point, and modify the analysis case-by-case. com-
mensurate wi the risk to the various participants.
.
Adjusting Financial Ratios
Standard & Poor's begins by taking the NPV of the annual
capacity payments over the life of the contract. The ratio-
nale for not capitalizing the energy component eve though
it is also a nondiscretionary fixed paent. is to equate the
comparison between utilities that buy versus build-.e.,
Standard & Poor's does not capitalize utility fuel contracts.
In cases where the capacity and energy components of the
fixed payment are not specified, half of the fixed payment is
used as a proxy for the capacity payment. The discount rate
is 10%. To determine the debt equivalent. the NPV is multi-
plied by the risk factor. The resulting amount is added to a
utilty's reported debt to calculate adjusted debt. Similarl,
Standard & Poor's imputes an associated interest expense
equivalent of 10%-10% of the debt equivalent is added to
reported interest expense to calculate adjusted interest cov-
erage ratios. Key ratios affected include debt as a percent-
age of total capital, funds from operations (FFO) to debt.
pretax interest coverage, and FfO interest coverage. Clearly,
the higher the risk factor, the greater the effec on adjusted
financial ratios. When analyzing forecasts, the NPV of the
PPA wil tyically decrease as the maturity of the contrct
approaches.
Utilty Company Example
To ilustrate some of the financial adjustments, consider the
simple example of ABC Utilty Co. buying power from XYL
Independent Power Co. Under the terms of the contct,
annual payments made by ABC Utilty start at $9 millon in
2003 and rise 5% per year through the contract's expiration
in 2023. The NPV of these obligations ovr the life of the
contract discounted at 10% is $1.09 billon. In ABC's case,
Standard & Poor's chose a 30% risk factor, which when mul-
tiplied by the obligation results in $327 milion. Table 1 iIus.
trates the adjustent to ABC's capitl structre, whre the
$327 milion debt equivalent is added as debt, causing
ABC's total debt to capitalization to rise to 59% frm 54%
(48 plus 11). Table 2 shows that ABC's pretax interest cover-
.. Back to
~ Table of Contents
Next Page ~Page 4 May 12, 20
Rocky Mountain Power
Exhibit NO.8 Page 4 of 4
Case No. PAC-E-08-07
Witness: Bruce N. Wiliams
age was 2.6x, without adjusting for off-balance-she oblig-
ations. To adjust for the x:Z capacity payments, th $327
millon debt adjustent is multiplied by a 10% interest rate
to arrve at about $33 millon. When this amount is added to
both the numerator and the denominator, adjust pretax
interest coverge falls to 2.3x.
Creit Implications
The credit implications of the updated criteria are that
Standard & Poor's now believes that historical risk facors
applied to TAP contracts with favorable recvery mecha-
nisms are insuffcient to capture the financial risk of these
fixed obligations. Indeed. in many cases where 5% and 10%
risk factors were applied, the chang in adjusted financial
raios (from unadjusted) was negligible and had no efec on
ratings. Standard & Poor's views the high probabilty of
energy delivery and attendnt paym warrants reogition
of a higher debt equivalent when capitalizing PPAs.
Standard & Poor's wil attempt to identify utilties that lire
more vulnerable to modifications in purchased-power
adjustments. Utilties can offset these financial adjustments
by recognizing purchased powr as a debt equivalent, and
incorporating more common equity in their capital str-
tures. However. Standard & Poor's is aware that utilties
have been reluctant to take this action beause many regu-
lators wil not recognize the necessity for. and authorize a
retum on, this additional wedge of common equity.
Alternatively, regulators could authorize higher return on
existing common equity or proide an incentive return mech-
anism for economic purchases. Notwithstanding unsupport-
ive regulators, the burden wil stil fall on utilties to offset
the financial risk associated with purchases by either quali-
tative or quantitative means. -
Jeffey Wolinsky, CFA
New Yor (11212 438.2117
Dimiti Nikas
New Yor (1) 212-48-7807
Antony Flinto
london (44) 20-7826-3874
Laurence Conheady
Melbourne (61) 3-9631-2036
Standard & Poor's Utilties & Perspectives
i- SEP 19 AM ro: 51
IDAHO PUBLIC
UTILlTIESCOMM1SSION
Case No. PAC-E-08-07
Exhibit NO.9
Witness: Bruce N. Wiliams
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Bruce N. Wiliams
Standard & Poors - Ratings Direct
September 2008
pO-Mar-2007) Credit FAQ: Imputed Debt Calculation For U.S. Utilties' Power Purchase...
Rocky Mountain Power
Exhibit NO.9 Page 1 of 4
Case No. PAC-E-08-07
Witness: Bruce N. Wiliams
RESEARCH
Credit FAQ:
Imputed Debt Calculation For U.S. Utilities' Power
Purchase Agreements
publication date: 3o-ar-2007
Primary Credit Analysts: David Bodek, New York (1) 212-438-7969;david_bodek~standardandpors.com
Ricnrd WCortright, Jr., New York (1) 212-438-7665;
ncard_cortht~stndardndpoors.com
Solomon B Samson, New York (1) 212-438-7653;
soLsamson~standardandpoor.co
In November 2006, Standard & Poor's Ratings Services invited members of
the U.S. electric industr and
interested parties to provide us with comments on our proposal to incorporte evergreen treatmnt in th
debt equivalents we calculate to reflec the fixed obligations created by power purchase agreements
(PPAs). Evergreen treatment would, for analytcal purposes, assume an extension of the life of someshort- and intermediate-term PPAs, so as to achieve coparabilty in the financial metrics of companies
with supply arrangements of varying durations.
We received Comments from every sector of the power industry-utiities, independent power produrs,
trde organizations, consultants, investors, and regulators. Based on the comments received, we have
reached a number of coclusions regarding the application of evergreen treatmnt to PPAs in our analsis.
We have also made a number of clarifications and refinements to our rating methodology. This discussion
supplements our Nov. 1, 2006 article "Request for Comments: Imputng Debt to Purchased Power
Obligations: which is available on RatingsDirect.
.Frequently Asked Questions
How is evergreen treatment applied in Standard & Poor's credit analysis?
Standard & Poor's adjusts reported financial metrics to capitalize portons of the costs of PPAs. The intent
of these adjustments is to capture fixed PPA obligtions that have debt-like attributes because thy fund
the recovery of third-part power suppliers' capitl investments in generation assets. These fixed
obligations merit inclusion in a utilit's financial metrics as though they are part of a utlity's permanent
capital structure. Evergreen treatment would extend the tenor of short- and intermediate-term contrcts to
reflect the long-term obligation of elecc utilites to meet their customers' demand for elecici.
We have concluded that there is a limited pool of utlites whose portolios of existing and projeced PPAs
do not meaningfully correspond to long-term load serving obligatins. Although evergreen treatmnt wil be
applied selectively in those cases where the portlio of existing and projectd PP As is inconsistent with
long-term load-serving obligations, a blanket application of evergreen treatmnt is not warranted.
The net present value (NPV) of the fixed obligations associated wit a portolio of short-term or
intermediate-term contrcts can lead
"to distortons in a utilit's financial profle relative to the NPV of the
fixed obligations of a utilit wit a portolio of PPAs that is made up of longer-term commitments. Where
there is the potential for such distortons, rating commitees wil consider evergreen treatment of existing
PPA obligations as a scenario for inclusion in the rating analysis.
What are the mechanics of PPA debt imputation and evergreen treatment?
A starting point for calculating the debt to be imputed for PPA-related fixed obligations can be found
among the .commitments and contingencies" in the notes to a utilit's financiai statements. An NPV is
calculated for the stream of capacity payments associated with the outstanding contracts included in the
https:llww.ratingsdirec.com/AppslR/controller/ Article?id=570 164&type=&o utputTyp... 3/30/2007
pO-Mar-2007) Credit FAQ: Imputed Debt Calculation For U.S. Utilties' Power Purchase...
Rocky Mountain Power
Exhibit NO.9 Page 2 of 4
Case No. PAC-E-08-07
Witness: Brue N. Williams
financial statements. The notes to the financial statements report capaci payments for the succin
five years and a '''ereaftet' period.
While we have aCcess to proprietary forecasts that show the detail underlying the costs that are
amalgamated beyond the five-year horizon, others, for purposes
of calculating an NPV, can. divide th
amount reported as "lhereaftet' by the average of the capacity payments in the preceding five years to
derive an approximate tenor of the amounts combined as the sum of the
obligations beyond the fift year.
In calculating debt equivalents, we also include new contrct that wil commence during the forecast
period and aren't reflected in the notes to the financial statements. For this group of contracts, debt
imputtion wil not commence until the year that energy deliveries are to begin under the anticipated
contrct.
How is NPV calculated?
The NPV is caiculated using a discount rate equivalent to th company's average cost of debt, net of
securitization debt. Once we arnve at the NPV, we apply a risk factor to reflect the benefits of regulatory or
legislative cost recovery mechanisms (see "Request for Comments: Imputing Debt to Purchased Power
Obligatns." (cited above) for a discussin of rik factor).
How does ever9reen treatment alter the PPA debt adjustment?
If evergreen treatment is warranted, we would extend the expiration of existing contract and those
tht
are slated to commence during the five-year horizon. Based on our analysis of several companie, we
have determined that any evergreen extension of the tenor of existing contract and anticipated contrct
should extend those contract to 12 years beyond th relevant forecast year.
To decide whether to apply evergreen treatmnt. we would start with an examination of actu al capacity
payments scheduled during the five-year horizon and the period represented as the thereaftr period in the
financial statements. If we conclude that the duration of PPAs is short relatie to our targeted tenor, we
would then add capacity payments until the targeted tenor is achieved. The price for the capaci tht we
add wil be derived from new peaker entr economics.
We use empirical data to establish the cost of developing new peaking capacity and wil reflect regional
differences in our analysis. The cost of new capacity is trnslated into a dollars-per-kilowatt-year figure
using a proxy weighted average cost of capital and a proxy capital recovery period.
Does customer choice curb the need for evergreen treatment?
Several comments submitted to us observed that over the long term there is the potential that customers
may switch to third-part providers. thereby undermining the rationale for an evergreen adjustment We
acknowledge that the introduction of customer migration would alter the long-term obligation to serve. At
the same time, it must be noted that our rating methodology already addresses this concern. Customer
choice typically goes hand in hand with the transformation of a utilit into a pure transmission and
distrbution system. We have previously
stated that we won't impute debt for those utilites whose role-as
a result of either regulatory orders or legislation-is limited to that of a conduit between suppliers and retail
customers. Therefore, utilties whose customers have retail choice aren't generally exposed to debt
imputtion and, in tum, we won't apply evergreen treatmnt to their supply obligations.
Have there been revisions to the analytical treatment of short-trm PPAs?
For many years, Standard & Poor's didn't calculate debt equivalents fo the fixed costs of power supply
arrangements whose tenor was three years or less. We recently announced our abandonment of this
exception to our debt imputation criteria. However, we understand that there are some utilties tht use
short-term PPAs of approximately one year or less as gap fillers pending either the constrcton of new
capaci or the execution of long-term PPA contract. To the extent that such short-term supply
arrangements represent a nominal percentage of demand and serve the purposes descrbed above, we
wil neiter impute debt for such contract nor provide evergreen treatmnt to such contract.
Are accommodations made for PP As that are treated as leases in the financial statements?
Several utilities have reported that their accountant dictte that certin PPAs need to be treated as leases
for accounting purposes due to the tenor of the PPA or the residual value of the asset upon the PPA's
expiration. We have consistently taken the position that companies should identify those capac charges
httPS:llwww.ratingsdirect.com/AppslR/controller/ Article?id=570 164&type=&outputTyp... 3/3012007
Rocky Mountain Power
(30-Mar-2007) Credit F AQ: Imputed Debt Calculation For U.S. Utilties' Power Purchase... Exhibit NO.9 Page 3 of 4Case No. PAC-E-08-07
Witness: Bruce N. Wiliams
that are subject to lease treatment in the financial statements so that we can accord PPA tre atment to
those obligations. in lieu of lease treatment. That is, PPAs that receive lease treatment for accuntg
purpses won't be subject to a 100% risk factor for analytcal purpses as though they were leases.
Rather, the NPV of the stream of capaci payments associated with these PPAs wil be reduced by the
risk factor that is applied to the utility's other PPA commitents.
How is the depreciation expense related to PPAs calculated?
We noted in our November artcle that we now add an implied depreciation expense to funds from
operations (FFO) to align the analytical treatment of PPAs wih the concpt of purchased power asa
substiMe for se If-build. We observed that we calculate imputed depreciatin expense in conformity wi
the methodoiogy used for calculating a depreciation adjustment as an offet to debt equivalents created by
leases.
The imputed depreciation expense is calculated for any given year by taking the scheduled fixed capaci
payment commitment for tht year and subtracting frm It the implied interest expense calculated frm th
NPV of the stream of capacity payment associated with that year. The calculted depreiation pry is
added to FFO in the numeraor as part of the calculation of both the FFO-to-interest and FFO-to-ebt
ratios.
What adjustmen ts are made for tollng contracts? .
We will assign a 100% risk factor when imputing debt to an unregulated energy company that has entered
into a tollng agreement for a power planls output This is done because of the absence of a
regul
mechanism for the recovery of the fied costs presented by th tollng arrngement
Are transmission contracts treated diferently than PPAs?
In recent years, some utilties have entered into long-term transmission contrct in lieu of building
generation. In some cases, these transmission contrcts provide accss to specifc power plants, while
other transmission arrangements provide accss to competitive wholesale electricit markets. We have
concluded that these types of transmission arrangements represent extensions of the power plants to
which they are connected or the markets that they serve. Irrespective of whether these transmissin lines
are integral to the delivery of power from a specifc plant or are conduits to wholesale markets, we view
these arrangements as exhibiting very strong parallels to PPAs as a substitute for investment in power
plants. Consequently, we will impute debt for the fixed costs associated wit long-term transmission
contracts.
Additional Contacts:Arhur F Simonson, New York (.1) 212-438-2094;
arthur_simonson~standardandpoors.com
Arleen Spangler. New York (1) 212-438-2098;
arleen_spangler~standardandpoors.com
Scott Taylor, New Yor (1) 212-438-2057;
scott_taylor~standardandpoors.com
John WWhitock, New York (1) 212-438-7678;
john_whitlock~standardandpoors.com
Analyic seivs provided by Standard & Poos Ratings servce (Ratings Services) are th reul of separate acl
designed to preserve the independence and objeciv of ratins opinions. The credit ratings and observatons contain herein
are solely statements of opinion and not statement of fact or recommendations to purcase, hold. or sell any securies or make
any other instment decisions. Accrdingly. any user of the infonnation contained herein shld not rely on any crit rat or
othr opinion containe herein in making any investment deciion. Ratings are based on inftio received by Rati
Serv. Other divisions of Standard & Poor's may have infonnatio that is not available to Ratings Serices. Standar & Poor's
has establishe policies and procedurs to maintain the confdentialit of non-ublic infonation reve during the raproc.
Ratings Sece reciVS compensation for its ratings. Suc compensation is nonnaliy paid either by the issuers of su
securitie or thir parties participating in marketing the securities. While Standard & Poors reserves th riht to dis the
rating, it receives no payment for doing so, except for subscrptions to it publications. Additonal information about our ratings
fes is availabl at ww.standardandpoors.comlusatingsfees.
https:/Iwww.ratingsdirect.com/AppsI/controller/ Article?id=5 70 164&type=&outputTyp... 3/3012007
pO-MaT-2007) Credit FAQ: Imputed Debt Calculation For U.S. Utilities' Power Purchase...
Rocky Mountain Power
Exhibit NO.9 Page 4 of 4
Case No. PAC-E-08-7
Witness: Bruce N. Willams
COpyriht e 2007 Standard & Poor's, a division ofThe McGraw.HiI comani. All
Rights Reserved. Privacy Notiæ
rt:e McGraw'Hil CompanIe ~'
https:/ Iwww.ratingsdiTect.com/AppsI/controller/ ArticJe?id=S70 164&type=&outputTyp... 3/3012007
iMSEP \ 9 lM \0: 5 ,
UT\tR~~R t~JAA\~S\ON
Case No. P AC-E-08-07
Exhibit No. 10
Witness: Bruce N. Wiliams
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Bruce N. Wiliams
PCRB Varable Rates
September 2008
Indicative Forward PCRB Variable Rates
For December 31, 2008
Jan-OO
Feb-OO
Mar-OO
Apr-OO
May-OO
Jun-OO
Jul-00
Aug-oO
sep-oo
Oct-OO
Nov-OO
Dec-OO
Jan-Ol
Feb-Ol
Mar-Ol
Apr-Ol
May-Ol
Jun-Ol
Jul-0l
Aug-Ol
Sep-Ol
Oct-Ol
Nov-Ol
Dec-Ol
Jan-02
Feb-02
Mar-02
Apr-02
May-02
Jun-02
Jul-02
Aug-02
Sep-02
Oct-02
Nov-02
Dec-02
Jan-03
Feb-03
Mar-03
Apr-03
May-03
Jun-03
Jul-03
30 Day LmOR
Daily Ave
(a)
Floating Rate PCRBs
Daily Ave
(b)
5.81%
5.89%
6.05%
6.16%
6.54%
6.65%
6.63%
6.62%
6.62%
6.62%
6.63%
6.68%
5.88%
5.53%
5.13%
4.82%
4.16%
3.92%
3.82%
3.64%
3.17%
2.48%
2.13%
1.96%
1.81%
1.85%
1.89%
1.86%
1.84%
1.84%
1.83%
1.80%
1.82%
1.81%
1.44%
1.42%
1.36%
1.34%
1.1%
1.31%
1.1%
1.6%
1.1%
3.33%
3.62%
3.68%
4.02%
4.89%
4.35%
3.99%
4.09%
4.50%
4.36%
4.33%
4.14%
3.10%
3.59%
3.18%
3.72%
3.38%
3.03%
2.65%
2.36%
2.42%
2.18%
1.79%
1.64%
1.49%
1.9%
1.46%
1.8%
1.67%
1.58%
1.49%
1.49%
1.69%
1.84%
1.66%
1.57%
1.40%
1.43%
1.45%
1.52%
1.56%
1.8%
1.2%
PCRB/LmOR
(b)/(a)
57%
62%
61%
65%
75%
65%
60%
62%
68%
66%
65%
62%
53%
65%
62%
77%
81%
77%
69%
65%
76%
88%
84%
84%
82%
75%
77%
85%
91%
86%
81%
83%
93%
102%
115%
110010
103%
107%
111%
115%
119%
119%
102%
Rocky Mountain Power
Exhibit No. 10 Page 1 of 3
Case No. PAC-E-OS-o7
Witness: Brue N. WiUiams
Indicative Forward PCRB Variable Rates
For December 31, 2008
Aug-03
Sep-03
Oct-03
Nov-03
Dec-03
Jan-04
Feb-04
Mar-04
Apr-04
May-04
Jun-04
Ju1-04
Aug-04
Sep-04
Oct-04
Nov-04
Dec-04
Jan-OS
Feb-OS
Mar-OS
Apr-OS
May-OS
Jun-OS
Ju1-0S
Aug-OS
Sep-OS
Oct-OS
Nov-OS
Dec-OS
Jan-06
Feb-06
Mar-06
Apr-06
May-06
Jun-06
Ju1-06
Aug-06
Sep-06
Oct-06
Nov-06
Dec-06
Jan-07
Feb-07
30 DayLIBOR
Daily Ave
(a)
Floating Rate PCRBs
Daily Ave
(b)
1.1%
1.2%
1.2%
1.3%
1.S%
1.1%
1.0%
1.09%
1.0%
1.0%
1.2S%
1.41%
1.60%
1.78%
1.90%
2.19%
2.39%
2.49%
2.61%
2.81%
2.97%
3.09%
3.2S%
3.43%
3.69%
3.78%
3.99%
4.1S%
4.36%
4.48%
4.S8%
4.76%
4.92%
S.08%
S.24%
S.37%
S.3S%
S.33%
S.32%
S.32%
S.3S%
S.32%
S.32%
1.6%
1.24%
1.24%
1.6%
1.32%
1.21%
1.7%
1.20%
1.27%
1.29%
1.28%
1.26%
1.40%
1.49%
1.72%
1.6S%
1.67%
1.78%
1.88%
1.9S%
2.50010
2.93%
2.39%
2.28%
2.44%
2.S5%
2.66%
2.93%
3.10%
3.02%
3.13%
3.11%
3.4S%
3.S2%
3.74%
3.60%
3.S3%
3.61%
3.57%
3.62%
3.70%
3.64%
3.63%
PCRBI LffOR
(b)/(a)
104%
111%
111%
121%
114%
110%
107%
110%
l1S%
117%
102%
89%
88%
83%
91%
7S%
70%
72%
72%
69%
84%
9S%
74%
67%
66%
68%
67%
71%
71%
67%
68%
6S%
70%
69%
71%
67%
66%
68%
67%
68%
69%
68%
68%
Rock Mountain Power
Exhibit No. 10 Page 2 of 3
Case No. PAC-E-OS-o7
Witness: Bruce N. Wiliams
Indicative Forward PCRB Variable Rates
For December 31,2008
Mar-07
Apr-07
May-07
Joo-07
Jul-07
Aug-07
Sep-07
Oct-07
Nov-07
Dec-07
Jan-08
Feb-08
Mar-08
Apr-08
May-08
Joo-08
Jul-08
Average
12/31/2008
30 Day LIBOR
Daily Ave
(a)
Floating Rate PCRBs
Daily Ave
(b)
PCRB1 LIBOR
(b)/(a)
68%
71%
73%
71%
69%
68%
70%
72%
74%
65%
76%
91%
135%
80%
73%
107%
133%
82%
5.32%
5.32%
5.32%
5.32%
5.32%
5.52%
5.48%
4.98%
4.75%
5.00%
3.95%
3.14%
2.80%
2.79%
2.63%
2.47%
2.46%
3.64%
3.79%
3.90010
3.76%
3.66%
3.76%
3.84%
3.56%
3.53%
3.25%
3.02%
2.86%
3.79%
2.22%
1.93%
2.63%
3.28%
Forward 30 Day
LIBOR*
(1)
Histoncai l'oating
Rate PCRB 1 30 Day
LIBOR
(2)
3.54%82%
* Source: Bloomberg L.P.
Forecast Floating
RatePCRB
(1) * (2)
2.90%
Rocky Mountain Powe
Exhibit No. 10 Page 3 of 3
Case No. PAC-E-08-o7
Witness: Bruce N. Willams
iøSEP 19 1"19= 51
IDAHO PUBUÇ
UTILITIES COMMisSION
Case No. PAC-E-08-07
Exhibit No. 11
Witness: Bruce N. Wiliams
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Bruce N. Wiliams
Cost of Preferred Stock
September 2008
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