20101220Vol III Technical Hearing pp 311-579.pdf

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OR I GI NAL
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF PACI FICORP DBA ROCKY MOUNTAIN
POWER FOR APPROVAL OF CHANGES TO
ITS ELECTRIC SERVICE SCHEDULES
HEARING BEFORE
CASE NO.
PAC-E-10-07
TECHNICAL HEARING
COMMISSIONER MARSHA H. SMITH (Presiding)
COMMISSIONER MACK A. REDFORD
COMMISSIONER JIM D. KEMPTON
PLACE:Commission Hearing Room
472 West Washington Street
Boise, Idaho
DATE:November 30, 2010
VOLUME III - Pages 311 - 579
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HEDRICK
COURT REPORTING
POST OFFICE BOX 578
BOISE. IDAHO 83701
208-336-9208
s'eI-V th ~ eolf(J/~ oSlÍt 19
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1 APPEARANCES
2 For the Staff:
3
4
5
6
For PacifiCorp
dba Rocky Mountain Power
(RMP) :
SCOTT WOODBURY, Esq.
and NEIL PRICE, Esq.
Deputy Attorneys General
472 West Washington
Boise, Idaho 83702
HICKEY & EVANS, LLP
by PAUL J. HICKEY, Esq.
Post Office Box 467
Cheyenne, Wyoming 82003
-and-
DANIEL E. SOLANDER, Esq.
ROCKY MOUNTAIN POWER
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
RACINE, OLSON, NYE, BUDGE
& BAILEY
by RANDALL C. BUDGE, Esq.
Post Office Box 1391
Pocatello, Idaho 83204-1391
RACINE, OLSON, NYE, BUDGE
by ERIC L. OLSEN, Esq.
Post Office Box 1391
Pocatello, Idaho 83204-1391
BENJAMIN J. OTTO, Esq.
IDAHO CONSERVATION LEAGUE
710 North Sixth Street
Boise, Idaho 83702
WILLIAMS BRADBURY, PC
by RONALD L. WILLIAMS, Esq.
1015 West Hays Street
Boise, Idaho 83702
-and-
DAVI SON VAN CLEVE, PC
by MELINDA J. DAVISON, Esq.
333 Southwest Taylor, Suite 400
Portland, Oregon 97204
BRAD M. PURDY, Esq.
Attorney at Law
2019 North Seventeenth Street
Boise, Idaho 83702
7
8
9
10
For Monsanto:
11
12
13
14
For Idaho Irrigation
Pumpers Association (IIPA):
15
16 For Idaho Conservation
League (ICL):
17
For PacifiCorp Idaho
Industrial Customers (PIIC):
For Community Action
Partnership Association
of Idaho (CAPAI):
APPEARANCESHEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
INDEX
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24
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1 EXHIBITS
2
NUMBER PAGE
3
4
For PacifiCorp Idaho Industrial Customers:
547
548
549
616 PIIC Data Request 150 Marked
5
617 OPUC Order 10-414, Case UM 1355, 2 pgs Marked
6
618
7
OPUC Order 07-446, Case UE 191, 2 pgs Marked
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9
10
11
12
13
14
15
16
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
EXHIBITS
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1 BOISE, IDAHO, TUESDAY, NOVEMBER 30, 2010
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3
4 COMMISSIONER SMITH: Back to you, Mr. Hickey.
5 MR. HICKEY: We would call as our next witness
6 Bruce Williams.
7
8 BRUCE WILLIAMS,
9 produced as a witness at the instance of Rocky Mountain Power,
10 being first duly sworn, was examined and testified as follows:
11
12 DIRECT EXAMINATION
13
14 BY MR. HICKEY:
15 Q.Good afternoon, Mr. Williams.
16 A.Good afternoon.
17 Q.For the record, would you please state your name
18 and spell it?
19 A.My name is Bruce Williams: B-R-U-C-E,
20 W-I-L-L-I-A-M-S.
21 Q.And by whom are you employed and in what capacity
22 are you employed?
23 A.l'm employed by PacifiCorp, and I am the vice
24 president and treasurer of PacifiCorp.
25 Q.And are you the same Bruce Williams that has
311
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WILLIAMS (Di)
RMP
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1 filed direct testimony in this case on the 28th of May, 2010,
2 and prepared exhibits numbered 5 through 9?
3 A.Yes, I am.
4 Q.And did you also file rebuttal testimony on
5 November 16th of this year?
6 A.Yes, I did.
7 Q.Do you have any additions or corrections that you
8 wish to make to any of your testimony or exhibits?
9 A.Yes, I have a couple slight revisions to my
10 rebuttal testimony.
11 Q.Okay. Would you like to give us those
12 references, please?
13 A.Yes, just get my reading glasses on.
14 On page 2, line 12, strike the word "no" and
15 replace it with "yes."
16 Further on that line
18
Q.
here?
A.
Q.
A.
Q.
A.
"yes. "
Strike the word "no" and replace it with the word
19 Okay.
So the page reference in your rebuttal again?
Page 2 of my rebuttal testimony, line 12.
Okay.
Following that line, strike the word "although,"
312
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WILLIAMS (Di)
RMP
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1 so the sentence begins with the word "the."
2 On line 13, before the words "the resulting
3 overall cost," insert the word "with."
4 And, further, on line 13, delete the word
5 "remains. "
6 That concludes my corrections.
7 Q.Okay.
8 COMMISSIONER SMITH: Could you just please read
9 the sentence as it is now constituted?
10 THE WITNESS: Certainly. Beginning on line 12,
11 the response to the question would be: Yes. The Company
12 accepts Ms. Carlock i s proposed cost of debt and preferred
13 stock, with the resulting overall cost of capital at 8.34
14 percent.
15 MR. HICKEY: Okay. Madam Chair, I would move
16 that the prefiled direct and rebuttal testimony of Mr. Williams
17 be spread upon the record as if it were read, and that
18 Exhibi ts 5 through 9 be marked for identification at this
19 point.
20 COMMISSIONER SMITH: Hearing no obj ection, the
21 prefiled testimony of Mr. Williams will be spread upon the
22 record as if read, and Exhibits 5 through 9 will be marked for
23 identification.
24 (The following prefiled direct and
25 rebuttal testimony of Mr. Williams is spread upon the record.)
313
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WILLIAMS (Di)
RMP
.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.
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16 Q.
17 A.
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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 Charered Financial Analyst designation upon passing the
examnation in September 1986. I have been employed by the Company for 24
years. My business experience has included financing of the Company's electric
operations and non-utilty 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 maagement, pension
18 and other investment management activities. In this proceeding, I am responsible
19 for the preparation of Rocky Mountain Power's embedded cost of debt and
.20 preferred equity and the testimony related to capital structue.
21 Purpose of Testimony
22 Q.What is the purpose of your testimony in this proceeding?
A.I wil first present a financing overview of the Company. Next, I wil discuss the
314 Wiliams, Direct - 1
Rocky Mountan Power
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planned amounts of common equity, debt, and preferred stock to be included in
the Company's planned capital structue. I wil then analyze the embedded cost
of debt and preferred stock supporting Rocky Mountain Power's electric
operations in the state of Idaho for the test period. This analysis includes the use
of forward interest rates, historical relationship of securty trading patterns, and
known and measurable changes to the debt and preferred stock portolios.
What time period does your analyses cover?
The test period in this proceeding is the twelve months ending December 31,
2009, with known and measurable changes though December 2010. The capita
structure and cost of debt and preferred stock applied in this case were determned
using an average of the five quarer ending balances from the quarer ending
December 31, 2009, through the quarer ending December 31, 2010.
What is the overall cost of capital that you are proposing in this proceeding?
Rocky Mountain Power is proposing an overall cost of capital of 8.36 percent.
This cost includes the Return on Equity recommendation from Dr. Samuel C.
Hadaway and the following capital structue and costs:
Component
Long Term Debt
Preferred Stock
Common Stock Equity
Total
Percent of
Total
47.6%
0.3%
52.1%
100.0%
Weighted
Average
2.82%
0.02%
5.52%
8.36%
%
Cost
5.92%
5.41%
10.60%
Financing Overview
Q. Please explain the Company's requirements to generate new capital.
A. As described in Company witness Mr. A. Richard Walje's diect testimony, the
Company continues to make ongoing investment in infrastrctue includig
315 Wiliams, Direct - 2
Rocky Mountain Power
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investment in generation, transmission and distrbution. These and futu capital
additions and investments wil require the Company to raise funds by issuing
significant amounts of new long-term debt in the capital makets and obtaining
new capital contributions from its parent company. Funds wil also be made
available by the continued absence of any dividends or distrbutions by
PacifiCorp to its parent company durng the period. Since the acquisition of
PacifiCorp by MidAmerican Energy Holdings Company ("MEHC") in March
2006, there have been no common stock dividends or distrbutions, PacifiCorp
has received $990 millon in additional cash equity contributions from MEHC,
and $1.7 billion of earings have been retained in PacifiCorp. These actions help
ensure that PacifCorp remains well-positioned to support the additional
investments that have been and wil continue to be made in the system.
How does the Company finance its electric utilty operations?
The Company finances its regulated utilty operations utilizing a blend of debt and
common equity capita. Immediately prior to. and durg periods of significant
capital expenditures such as the curent situation, the Company's requirement for
more common equity as a component of the capital structure wil increase. This
provides more flexibility regarding the type and timing of debt financing, better
access to the capital markets, a more competitive cost of debt, and over the long-
run, more stable credit ratings; all of which assist in financing such expenditues.
In fact, the Company's equity component is expected to remain in excess of 50
percent for the next several years to faciltate the financings necessar for the
investments in system reliabilty and infrastrcture.
316 Wiliams, Direct - .3
Rocky Mountain Power
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In addition, all else being equal, the Company wil need to have a greater
common equity component to offset varous adjustments that rating agencies
make to the debt component of the Company's published financial statements. I
wil discuss these adjustments in greater detail later in ths testimony.
Do you believe the proposed capita structure is a reaonable capital
structure for the purpose of setting rates in this Cocket?
Yes. While the capital strctue wil var due to financing activity and capital
expenditures, I believe the proposed capital structure to be a fai and reasonable
reflection of the structue.
Q. What types of securities does the Company employ in the long-term debt and
preferred stock components of its capital structure?
A. The Company relies on a mix of first mortgage bonds, other secured debt, tax-
exempt debt, unsecured debt and preferred stock to meet its long-term financing
requirements. These securties employ varous maturities in order to provide
flexibilty and mitigate refinancing risks.
The Company has completed the majority of its long-term financing
utilzing secured first mortgage bonds issued under the Mortgage Indenture dated
Januar 9, 1989. Exhibit NO.5 shows that, for the twelve months ending
December 31,2010, the Company is projected to have approximately $5.6 bilion
of first mortgage bonds outstandig, with an average cost of 6.38 percent.
Presently, all outstanding first mortgage bonds bear interest at fixed rates.
Proceeds from the issuance of the first mortgage bonds (and other financing
instrments) are used to finance the combined utilty operation.
317 Wiliams, Direct - 4
Rocky Mountain Power
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Another importt soure of financing has been the tax-exempt financing
associated with certin qualifying equipment at power generation plants. Under
3 arangements with local counties and other tax -exempt entities, the Company
4 borrows the proceeds and guarantees the repayment of the long-term debt in order
5 to take advantage of their tax-exempt status in financings. Durng the twelve
6 months ending December 31, 2010, the Company's tax-exempt portolio is
7 projected to be $738 millon in principal amount with an average cost of 2.44
8 percent (including the cost of issuance and credit enhancement.)
9 . Planned Capital Structure
10 Q.
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18 A.
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How did you determine the capital structure proposd in this proceeding?
The Company used an average of the five quarer ending balances durng the time
period ending December 31, 2010, to calculate its proposed capital strctue.
This approach smoothes volatilty in the capital strcture which wil fluctuate as
the Company expends capital, issues or retires debt, retains earings and receives
infusions of new equity.
How does the Company determine the amount of common equity, long-term
debt, and preferred stock to be included in its 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 utilty plant assets, and clean ai investments are required for Rocky
Mountain Power to fulfil this obligation. Through its planning process, the
318 Wiliams, Direct - 5
Rocky Mountain Power
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Company determned the amount of necessar new financing including capital
contributions needed to support these activities and calculated the required equity
and debt ratios required to maintain continued access to the financial markets.
Has the Company previously received capital contributions from MEHC and
does it expect future contributions as well?
Yes. Since the acquisition by MEHC on March 21,2006, the Company has
received a total of $990 millon of cash capital contrbutions from MEHC via its
diect parent company, .PPW Holdings, LLC. The Company expects additional
cash equity contributions of $100 millon before the end of 2010.
Why is there the need for additional amounts of equity?
The Company's capital structue reflects the cost increases described in this case,
including investment in infrastrctue and power costs. These cost increases,
coupled with the credt rating agencies' expectations for credit metrcs and
balance sheet strength, mean that the Company cannot finance itself solely with
new debt. Additional equity is reuied along with improved business results and
other considerations to support PacifiCorp's curent senior secur 'A' credit
rating from Stadard & Poor's ("S&P"), 'A2' rating from Moody's Investors
Service ("Moody's"), and 'A-'from Fitch Ratings.
Please describe the changes to the amount of outstanding long-term debt.
Durng the period ending December 31,2010, the balance of the outstading
long-term debt wil change through matuties and principal amortation. Based
upon the long-term debt series outstanding at December 31,2009, I have
calculated the reduction to the outstanding balances for maturities and pricipal
319 Wiliams, Direct - 6
Rocky Mountan Power
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amortizations totaling $14.6 millon that are scheduled to occur durg the period
ending December 31, 2010.
Is the proposed capital structure consistent with the Company's current
credit rating?
Yes. This capital strctue is intended to enable the Company to deliver its
required capital expenditures while achieving credit ratios that are expected to
support the continuance of PacifiCorp' s curent credit ratings.
How does maintenance of a strong credit rating benefit customers?
The credt rating given to a utility has a direct impact on the price that a utilty
pays to attract the capital necessar to support its current and futue operating
needs. A solid credit rating diectly benefits customers by reducing immediate
and future borrowing costs related to the financing needed to support regulatory
operations.
Are there other benefits?
Yes. Durng periods of capital market disruptions, higher-rated companies are
more likely to have ongoing, uninterrpted access to capita and access at lower
costs. Ths is not always the case with lower-rated companies, which find
themselves either unable to secure capital or able to secure capital only on
unfavorable terms and conditions durng such periods.
In addition, higher-rated companies have greater access to the long-term
markets for power purchases and sales. Such access provides these companies
with more alternatives when attempting to meet the curent and futue load
requirements of their customers.
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Rocky Mountain Power
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Finaly, a company with strong ratings wil often avoid having to meet
costly collateral requirements that are typicaly imposed on lower-rated
companies when securig power in these markets.
Did S&P "and Moody's change the Company's credit ratings in 2009?
Yes. S&P upgraded PacifiCorp's senior secured debt to 'A' while it downgraded
PacifiCorp's short-term debt rating to 'A-2'. Simlarly, Moody's upgraded
PacifiCorp's senior secured debt to 'A2'.
Please explain these rating changes.
The upgrade to PacifiCorp's senior secured debt merely reflects a change in
S&P's methodology rather than a change in PacifiCorp's credit quality or
financial metrcs. S&P changed its approach to estimating the amount of
collateral available to senior secured debt holders in the event of a default by
PacifiCorp on its first mortgage bonds.
S&P continues to be cautious about PacifiCorp's credit metrcs and has
stated it views the Company's credit metrcs on a stand-alone basis as more
consistent with a 'BBB' rating. Indeed, in downgrading the Company's short-
term debt rating, S&P cited a need to take a firmer view on linkng PacifiCorp
short-term ratings to stand-alone credit quality. S&P sustained its current 'A-'
corporate credit rating based on its expectation "that management wil achieve
cash flow metrics more consistent with an 'A' rating over the next several years."i
Moody's upgrade of PacifiCorp' s senior debt was par of an industr-wide
action in which the majority of senior secured debt ratings of investment-grade
. 1 Standar & Poor's RatingsDirect April 1,200, and reiterated in the RatingsDirt of Apri 30, 2010.
321 Wiliams, Direct - 8
Rocky Mountain Power
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regulated utilities were upgraded by one leveL. The action was a result of an
analysis of the history of regulated utilty defaults and was not specific or unique
to the Company.
Do these rating agency actions change the Company's need to add equity to
its capital structure and improve its rmancial metrics?
No. Without continued improvement in financial metrics along with supportive
state regulatory outcomes in rate cases, the ratings direction is likely to be lower
rather than higher for PacifiCorp.
Do S&P's recent credit reports on PacifCorp underline S&P's expectation
that PacifiCorp improve its financial metrics in order to maintan its current
credit rating?
Yes. In its latest report, S&P made several references to the need for PacifiCorp
to improve its stand-alone financial metrics, noting that PacifiCorp had an
"aggressive financial risk profile that reflects a large capita program and the need
to shore up cash flow metrcs." S&P also stated that "(G)iven the recent tuoil
in both the liquidity and capital markets, we have taken a firer view on the need
to link the PacifiCorp short-term ratings to its stand-alone credit quality, which
supports an 'A-2' short-term rating.,,2 S&P also reiterated its credit views,
including that "supportive rate case outcomes reman key to maintaining and
improving upon the Company's financial performnce.,,3 Exhbit No.6 is the
April 30,2010 S&P RátingsDirect publication.
2 Standar & Poor's RatingsDirect April 30, 2010
3 ¡d.
322 Willams, Dirct - 9
Rocky Mountan Power
.1 Purchase Power Agreements
2 Q.Is the Company subject to rating agency debt imputation associated with
3 Purchase Power Agreements?
4 A.Yes. Rating agencies and financial analysts consider purchase power agreements
5 ("PPAs") to be debt-lie and wil impute debt and related interest when
6 calculating financial ratios. For example, S&P wil adjust the Company's
7 published financial results and impute debt balances and interest expense resulting
8 from PP As when assessing creditworthiness. It does so in order to obtan a more
9 accurate assessment of a company's financial commtments and fixed payments.
10 Exhibit NO.7 is the May 7, 2007, publication by S&P detailng its view of the
11 debt aspects of PP As..12 Q.How does this impact the Company?
13 A.In its April 30, 2010, RatingsDirect report cited above, S&P stated that
14 approximately $395 millon of additional debt and related interest expense were
15 added to the Company's debt and coverage tests solely as a result of PPAs. There
16 were also other adjustments made by S&P that together resulted in total
17 imputations of approximately $1 bilion of debt and $78 millon of interest being
18 added into the calculation of PacifiCorp's credit ratios. These adjustments are
19 detailed by S&P in its April 30, 2010, Ratings Direct report (Exhibit No.6)
20 Q.How would the inclusion of this PPA-related debt affect the Company's
21 capital structure?
22 A.Negatively. By including the imputed debt resulting from PPAs and these other
23 adjustments, the Company's capital structure has a lower equity component as a.
323 Wiliams, Direct - 10
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corollar to the higher debt component, lower coverage ratios and reduced
financial flexibilty than what might otherwise appear to be the case from a
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3 review of the book value capital strctu. For example, if one were to add the $1
4 bilion of debt adjustments that S&P makes to the Company's capital structue in
5 this case, the resulting common equity percentage would declie from 52.1
6 percent to 48.5 percent. The table below shows the proposed capital strctue and
7 how the S&P adjustments impact the components when viewed by the rating
8 agency.
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Illustration of Rating Agency Adjustments to PacifiCorp's Capital Structure
($ in milions)
Book Values /Rating Agency Adjusted Book Values
Ratios Adjustments / Ratios
Long-Term Debt 6,369/47.6%$1,000 7,369/51.2%
Preferred Stock 41/0.3%0 41/0.3%
Common Equity 6,984/52.1 %0 6,984/48.5%
Totals $13,394/100.0%$1,000 $14,394/1 00.0%
9 Financing Cost Calculations
10 Q.
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12 A.
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15 Q.
16 A..17
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 rate cases in Idaho and other
jursdictions.
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
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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. Aggrgating
the annual cost of each debt issue produces the total annualized cost of debt.
Dividing the total annualized 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.
How did you calculate the embedded cost of preferred stok?
The embedded cost of preferred stock was calculated by first determing 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 annual cost for the entire preferred stock
portfolio. I then divided the tota annual 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 portfolio 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 of tax -exempt
debt. Exhibit No.8 shows that these securties on average had been trading at
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.1 approximately 91 percent of the 30-day LIBOR (London Inter Ban Offer Rate)
2 for the period Januar 2000 through December 2009. Therefore, the Company
3 has applied a factor of 91 percent to the forward 30-day LIDOR Rates durng the
4 period ending December 31, 2010, and then added the respective credit
5 enhancement and remaketing fees for each floating rate tax-exempt bond. Credit
6 enhancement and remarketing fees are included in the interest component because
7 these are costs which contrbute directly to the interest rate on the securties and
8 are reognized in interest expense.
9 Embedded Cost of Long- Term Debt
10 Q.What is the Company's embedded cost of long-term debt?
11 A.The embedded cost of long-term debt is 5.92 percent as shown in Exhibit NO.5..12 Embedded Cost of Preferred Stock
13 Q.Whatis the Company's embedded cost of preferred stock?
14 A.Exhibit NO.9 shows the embedded cost of preferred stock at December 31,
15 2010, to be 5.41 percent
16 Q.Does this conclude your testimony?
17 A.Yes.
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326 Wiliams, Direct - 13
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1 Introduction and Summary of Rebuttal Testimony
2 Q.
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16
17
Are you the same BruceN. Wiliams that provided direct testimony in this
proceeding?
Yes, I am.
What is the purpose of your rebuttal testimony?
The purose of my rebuttal testimony is to respond to the capital strctue
recommendations offered by Monsanto Company ("Monsanto") witness Mr.
Michael P. Gorman and the adjustment to pension expense proposed by Idaho'
Public Utilties Commssion ("IPUC") Staff witness Mr. Donn English.
In my analysis, I demonstrate that Mr. Gorman's recommendations
unreasonably propose the use of a hypothetical capital strcture without a clear
and compelling justification for disregarding PacifiCorp' s actual capital strctue.
PacifiCorp's proposed 52.1 percent equity component remains well supported by
the updated cost of capital summar presented in my testimony. Adoption of
PacifiCorp's actual capital structue wil allow the Company a fai opportnity to
maintain its credit rating and attract capital on reasonable terms.
My rebuttal testimony also responds to Monsanto's ~verall rate of return
18 recommendations and shows how this recommendation, if adopted, would
19 negatively impact PacifiCorp' s financial integrity.
20 Review of Staff and Monsanto Recommendations
21 Q.
22 A.
23
What are Monsanto's and IPUC's recommendations on cost of capital?
Mr. Gorman recommends a hypothetical capital structure that reduces the equity
component from PacifiCorp's actual equity share of 52.1 percent to 49.7 percent.
327
Willams, Di-Reb -1
Rocky Mountain Power
.1
2
3
4
5 Q.
6
7 A.
8
9
IPUC witness Ms. Terr Carlock proposes slight changes to the Company's cost
of long-term debt and preferred stock. Both Monsanto and IPUC propose
reductions to the Company's proposed retu on equity which Dr. Samuel C.
Hadaway wil discuss in his rebuttal testimony.
Are there items concerning the cost of capital in your direct testimony with
which the parties agreed?
Yes, Ms. Carlock accepts the Company's proposed capital structue and Mr.
Gorman accepts the Company's proposed cost oflong-term debt and preferred
stock.
10 Company's Overall Cost of Capital
11 Q..12 A.
13
14
15
16
17
18
19
20
21
22
.
Are you proposing a new overall cost of capital in this proceeding?
No. Although the Company accepts Ms. Carlock's proposed cost of debt and
preferred stock, the resulting overall cost of capital remains at 8.34 percent. The
table below shows the Company's cost of capital adjusted for Ms. Carlock's
proposed changes:
Overall Cost of Capital
Percent of %Weighted
Component Total Cost Average
Long Term Debt 47.6%5.88%2.80%
Preferred Stock 0.3%5.42%0.02%
Common Stock Equity 52.1%10.60%5.52%
Total 100.0%8.34%
328
Wiliams, Di-Reb - 2
Rocky Mountain Power
.1 Q.
2 A.
3
4
5
6
7
8
9
10
11
.12
13 Q.
14 A.
15
16
17
18
19
20
21
22
.23
What is the Company's actual capital structure?
At September 30,2010, the capital structu was:
Long Term Debt 47.0%
Preferred Stock 0.3%
Common Stock Equity 52.7%
As the table above shows, the Company's actual equity component at the end of
September is in excess of the 52.1 percent in the proposed capital strctue. In
addition, the common equity component wil increase through the end of the year
as the Company continues to retain all earings. Finally, it should be noted that
since acquisition by MidAmerican Energy Holdings Company in 2006,
PacifiCorp's common equity component has averaged 50.6 percent of total
capitalization.
Please explain the benefits of the Company's actual capital structure.
The Company's actual capital Structure is intended to maintain current credt
ratings. As I discussed in my direct testimony, maintenance of the Company's
credit ratings benefits customers by reducing immediate and futue borrowing
costs. In addition, higher rated companies ar more likely to have on going,
uninterrpted access to capital and access at lower costs. Furer, higher rated
companies have greater access to the long-term markets for power purchases and
sales which provides more alternatives to meet the current and future load
requirements of customers. Also, higher rated companies can often avoid or
reduce the amount of costly collateral requirements that are typically imposed on
lower-rated companies when transacting in the wholesale energy markets.
329
Wiliams, Di-Reb - 3
Rocky Mountain Power
.1 Reply to Monsanto Witness Mr. Gorman
2 Hypothetical Capital Structure
3 Q.What is your general response to Mr. Gorman's capital structure
4 recommendations?
5 A.Mr. Gorman proposes a series of adjustments to PacifiCorp's actual capital
6 strctue to produce a hypothetical capital structure with a common equity
7 component of 49.7 percent. Mr. Gormn has failed to provide a clear and
8 compellng justification for his hypothetical capital structue. Mr. Gorman's
9 adjustments are arbitrar and without a financial basis. Furter, he uses a time
10 period for his common equity analysis which is inconsistent with the rate case test
11 period and his attempts to prove the recommended equity strcture is supportive
.12 of the Company's credit rating are in error.
13 Q Please explain Mr. Gorman's adjustments to the Company's actual common
14 equity component.
15 A.Mr. Gorman proposes to remove special deposits, short-term investments, and the
16 difference in affiliate notes receivable and payable. The most significant of these
17 is the adjustment for short term investments of $196 millon. Mr. Gorman
18 believes his capital structure "is more reasonable for setting rates because it
19 reflects the actual common equity capita RMP relied on to invest in utility
20 plant."i
21 Q.Please identify the fundamental problems in Mr. Gorman's analysis.
22 A.First, as of September 30, 2010, the Company had exhausted its temporar cash
.1 Gorman Direct Testimony page 14 lines 4 and 5.
330
Wiliams, Di-Reb - 4
Rocky Mountain Power
.1
2
3
4
5
6
7 Q.
8
9
10
11 A;
12
13
14
15
16
17 Q.
18
19 A.
20
21
22
.
investments, effectively eliminating this aspect of Mr. Gormn's adjustments.
Additionally, in general financial treatment, short term investments are
often netted against long term debt to determne what is known as "net debt". Net
debt is used as a financial metric to reflect the company's net obligation to its
bondholders. Nowhere in general finance is there support for Mr. Gormn's
novel proposal to net common equity with cash to derive net common equity.
Mr. Gorman states that it is reasonable to believe that these short-term cash
investments simply represent a placeholder for all the earnings RMP is
retaining until needed to fund utilty plant investment.2 Do you agree with
him?
No. All of the Company's net cash from operations since acquisition by MEHC
has been re-invested in the business. The fact is that PacifiCorp is investing more
into its business than the amount of cash flow generated by operations. For
example during the first six months of 2010, the Company has invested $876
milion into capital expenditures while generating only $779 millon of net cash
flow from operations. These facts show that Mr. Gorman's position is unfounded.
Did Mr. Gorman use the same period of time as the Company to determine
his hypothetical capital structure?
No, based on Exhibit No. 202 (MPG-l) Mr. Gorman is using a period oftime
from June 30, 2009, though June 30, 2010. However, the Company's capital
strcture was determned as the average durng the twelve months ending
December 31,2010. Therefore, as the Company expects to retain all earings.2 Gorman Direct Testimony page 14 line 24 though page 15 line 2.
331
Wiliams, Di-Reb - 5
Rocky Mountain Power
.;1
2
3
4 Q.
5
6
7 A.
8
9
10
11.
.
during 2010 to finance necessa capital expenditures to serve its customers, Mr.
Gorman would naturally have a lower common equity percentage than what the
Company calculated.
Do you agree with Mr. Gorman's statement that the Company's capital
structure at June 30, 2010, is 52.2 percent and is very close to that projected
by the Company for year-end 2010 of 52.1 percent?3
Yes, Mr. Gorman has correctly stated the Company's actual common equity level
of 52.2 percent at June 30, 2010. However, the 52.1 percent he cites is the
expected average.durg the calendar year and the common equity component
wil be higher at year end 2010. This higher ratio wil permt maintenance of the
Company's credit rating and allow the Company to attract additional capital to
12 meet constrction needs.
13 Credit Metric Analysis
14 Q.
15
16 A.
17
18
19
20
21
Please comment on Mr. Gorman's discussion concerning financial integrity
and his credit metric analysis.
I disagree with Mr. Gorman's analysis and conclusions for four reasons:
· First, Mr. Gorm's calculations did not properly reflect the adjustments that
rating agencies make when calculating their credit metrcs. For instance, my
direct testimony stated that S&P adds nearly $1 bilion of additional debt and
$73 millon of interest to PacifiCorp' s reported results.4 While Mr. Gorman
did attempt to include the adjustments, he unfortnately only included a
3 Gorman Direct Testimony page 13 lines 20 though 21.4 Begmnmg with their Apri30, 2010 repor S&P now imputes $78.2 millon of mterest while the debt
amount is approximately the same. This increase, while not material to the discussion above, would fuer
weaken Mr. Gorman's credit metrcs had he included the updated adjustments.
332
Willams, Di-Reb - 6
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10
11.12
13
14
15
16
17 Q.
18
19 A.
20
21
portion of the total adjustments and not the entire amounts. He includes less
than half of the total debt adjustments ($432 milion vs. $998.2 millon) and
only $28.1 millon of the $73 millon of additional interest.5
· Second, even the portion of the adjustments he included is incorrectly stated
as Mr. Gorman further reduces the amount by mis-matching an Idaho
allocation percentage to a total company capital strctue. This furer
reduces the impact of the already too low adjustments.
· Third, Mr. Gorman's model also excludes a significant amount of interest
expense that the Company reports on its financial statements such as interest
expense on customer deposits, interest on capital leases, regulatory liabilties
and others.
· Four, Mr. Gorman ignores the rating agencies published expectations for
PacifiCorp and instead measures the flawed results of his model against the
general utilty industry. Had Mr. Gorman used the Company specific targets
from the rating agencies, his already over-stated results stil would not have
supported the Company's curent ratings.
Was Mr. Gorman aware of these rating agency published expectations for
the Company?
Yes, Mr. Gorman cites them in his testimony on page 10 for Standard & Poor's
and page 11 for Moody's. It is not clear why he ignored them for puroses of his
credit metrcs.
.5 Monsanto Company Exhibit No. 218 (MPG-17) lines 6 and 9.
333
Wiliams, Di-Reb - 7
Rocky Mountain Power
.1 Q.
2
3
4 A.
5
6
7 Q.
8 A.
9
10
11
12.13
14
15
16
Should the Commision disregard Mr. Gorman's statements that his
recommended return on equity and proposed capital structure are
supportive of the Company's current bond rating?
Yes, for reasons outlned above, the Commssion should disregard Mr. Gorm's
statements that his recommended retu on equity and proposed capital strctue
are supportive of the Company's current bond rating.
Are there other inaccuracies in Mr. Gorman's testimony?
Yes. There are certain errors in Mr. Gorman's testimony that, while not essential
to determning the cost of capital, should be corrected for the record in this case.
For example on page nine of his testimony, Mr. Gorman states that RMP is a
subsidiar of PacifiCorp and that PacifiCorp issues debt and equity on behalf of
RMP. The fact is that RMP is not a subsidiar of PacifiCorp. RMP is a division
of PacifiCorp and is the trade name under which PacifiCorp delivers electrcity to
customers in Idaho, Utah and Wyoming. Further, PacifiCorp is the financing
entity and issues debt and equity to fund its overal needs including those of the
operating divisions such as RMP and its other sister operating divisions.
17 Reply to IPUC Witness Mr. English
18 Q.
19
20 A.
21
22
.
Please describe the adjustment that Mr. English is proposing to the
Company's pension expense.
Mr. English is proposing to average the projected contributions to the pension
plan for the period of 2010 though 2014. This averaging results in a proposed
reduction to pension expense of $20.9 milion.
334
Wiliams, Di-Reb - 8
Rocky Mountain Power
.1 Q.
2 A.
3
4
5
6
7
8
9
10 Q.
11 A.
12
13 Q.
14 A.
15
16
17
18
19
20
21
.
22
.23
Do you agree with Mr. English's proposed reduction to pension expense?
No. It is my understanding that historically this Commssion has used cash
contributions for the test period to set rates. The Company continues to believe
that recovery of 2010 cash contributions is the most appropriate outcome. As
discussed in Mr. Steven R. McDougal's testimony, the Company does not believe
it is appropriate for parties to flp back and fort between approaches depending
on what wil give the lowest result. The Company's filng included expected cash
contrbutions of $104.8 millon durng 2010 and this is the level that the
Commssion should include in determning revenue requirement.
What was the actual level of cash contributions during 2010?
The Company's cash contribution to fund its pension plan in 2010 was $112.8
milion.
Why did the Company contribute $112.8 milion in 2010 to its pension plan?
The Company made an additional $8 milion contrbution during 2010 in order to
help improve the funded status of the pension plan. While the Company was
scheduled to contrbute $104.8 millon to the pension plan durng 2010 to meet
minimum funding requirements, the resulting funded ratio would have been 79.45
percent. Plans with funded ratios below 80 percent are subject to restrctions
including limts on lump sum distribution of benefits and plar amendments that
would increase.benefits. In addition, the plan would be put in "at risk" status as
of Januar 1,2011, causing a significant increase in the 2011 minimum funding
requirements. By makng an additional $8 millon contribution (for a total of
$112.8 millon) the plan increased its expected funded status to 80.14 percent
335
Wiliams, Di-Reb - 9
Rocky Mountan Power
.
.
.
1
2
3
4 Q.
5
6 A.
7
8
9 Q.
10 A.
11
12
13
14
15
16
17
18
19
20
21
thereby avoiding benefit restrctions and "at risk" status, including the required
notifications to plan parcipants, the Pension Benefit Guaranty Corporation, and
any labor organizations representing plan paricipants.
Has any party proposed that the Company should not be allowed to recover
year average proposal it would assure under recovery of 60 to 80 percent of the
2010 contributions depending on the timing of the Company's next rate case.
Is there an alternative method that the Commission could consider?
It is my understanding that the Commssion has traditionally preferred historical
data with adjustments for known and measurable changes. As such, the use of a
historical average, updated for actual 2010 contrbutions, would be appropriate. If
the Commssion wished to consider an alternative to the Company's proposed
2010 cash contrbutions, the Company would suggest a thee-year average of
historical contrbutions. In addition, the Company would recommend updating
the 2010 contrbution to the actual contribution amount of $112.8 millon. This
approach would smooth the impact of the pension contrbutions while providig
the Company an opportnity to recover its actual pension contrbutions.
However, if the Commssion were to adopt the use of a historical average
of cash contrbutions, the Company respectfully requests that this be made as a
policy decision to ensure consistency and is applied in all futue rate cases. The
6 Ths treatment in effect becomes a forecasted revenue requirement item in the case basd on information
beyond the test penod and is a mismatch with the test penod convention followed by the Company in its
Application.
336
Wiliams, Di-Reb - 10
Rocky Mountain Power
.1 use of a historical average, if adopted and consistently followed, should ensure
2 that over time the Company collects an amount equal to its contrbutions.
3 Q.What have been the actual contributions over the historical three year
4 period?
5 A.The contrbutions and the resulting average are as follows:
6 Cash Contrbutions
7 2010 $112.8 millon
8 2009 49.6 millon
9 2008 65.6 millon
10 Average $76.0 millon
11 Q.Would use of a historical average allay the concerns that Mr. English cited in.12 his direct testimony?
13 A.Yes. Mr. English expressed a concern that including the 2010 contrbution
14 amount in rates that go into effect in 2011 and potentially remaining in effect for
15 several years could allow the Company to collect significantly more in revenue
16 than necessary to meet its pension obligations.7
17 Q.What is the resulting adjustment if the Commission adopts a three-year
18 average of historical contributions?
19 A.The result of the three-year historical average would be a reduction of $19.11
20 milion from the total Company 0 & M expense in the Company's diect case or
21 $1.03 millon to Idaho. Company witness Mr. McDougal details how the
22 adjustment was calculated in his testimony. However, such an adjustment would.7 English direct testimony page 9 lines 17 though 21.
337
Wiliams, Di-Reb - 11
Rocky Mountain Power
.1
2
3
4
5 Q.
6 A.
.
.
only be appropriate if it is accompanied by a policy decision by the Commssion
that consistently applies this treatment in future rate case proceedings so that the
Company has a reasonable opportnity to collect its pension contrbutions over
time.
Does that conclude your rebuttal testimony?
Yes.
338 Wiliams, Di-Reb - 12
Rocky Mountan Power
.
.
.
1 (The following proceedings were had in
2 open hear ing . )
3 BY MR. HICKEY: And I think to be complete, I doQ.
4 need to state into the record if I were to ask you all of the
5 questions set forth in both the prefiled and rebuttal
6 testimony, would your answers be the same as you published in
7 those two testimonies, Mr. Williams?
8 A.Yes, they would be.
9 Okay. Mr. Williams, if I may, there were someQ.
10 understandable -- questions raised about the relationship
11 between Rocky Mountain Power, PacifiCorp, MidAerican Energy
12 Holdings Company, and, ultimately, Berkshire Hathaway. As the
13 treasurer of the Company, do you have a general understanding
14 of those relationships?
15 A.Yes, I do.
16 Could you address them for us, please, andQ.
17 explain where Rocky Mountain Power fits within those corporate
18 structures?
19 Certainly. Rocky Mountain Power is an operatingA.
20 division of PacifiCorp, which is a legal entity onto itself.
21 Its other operation divisions are Pacific Power and PacifiCorp
22 Energy. Those, again, are divisions of PacifiCorp, the
23 corporation. And I think as we mentioned earlier, PacifiCorp 's
24 common stock is entirely owned by MidAerican Energy Holdings
25 Company; and then MidAmerican Energy Holdings Company is
339
HEDRICK COURT REPORTING
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RMP
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.
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1 largely owned by Berkshire Hathaway, the ultimate parent
2 company to PacifiCorp.
3 Q.There were references both in questions as well
4 as in responses from Mr. Walj e to the concept of ring fencing
5 as it relates to Rocky Mountain Power. Can you, first of all,
6 tell us your understanding of ring fencing, and then relate
7 that to how that concept applies to both MidAerica Energy
8 Holdings Company and Berkshire Hathaway?
9 Certainly. Ring fencing is a -- I guess aA.
10 financial term that i s often used by investors as well as rating
11 agencies, and it refers to measures that are put in place at
12 subsidiaries to protect them from events that happen further up
13 the organizational chart. So in PacifiCorp i s perspective, it
14 protects us or Rocky Mountain Power from things -- adverse
15 things -- that might happen at MidAmerican Energy Holdings
16 Company or even Berkshire Hathaway. So it i S a way of giving us
17 the benefit of ownership from those entities, but also not
18 exposing us to their financial problems if they had those, if
19 those events were to happen. And these ring-fencing provisions
20 were part of the acquisition commitments that were put in place
21 at the time PacifiCorp was acquired by MidAerican in 2006.
22 There was also some conversation in examinationQ.
23 of Mr. Walj e about the dividend policy of Rocky Mountain Power
24 and PacifiCorp in relationship to MidAmerica Energy Holdings
25 Company. Do you know what that dividend policy is and how it 's
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HEDRICK COURT REPORTING
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RMP
.
.
.
1 been viewed by regulatory agencies?
2 A. Yeah, the dividend policy I think is pretty
3 simple. PacifiCorp has not paid any dividends to MidAerican
4 Energy since the acquisition in 2006, doesn't expect to pay any
5 dividends through the balance of this year and next year as
6 well. I think that policy has been widely seen as a posi ti ve
7 attribute of the ownership now by MidAmerican and Berkshire
8 Hathaway, in contrast to previous ownership where there was a
9 need by that owner to have regular quarterly dividends coming
10 out of PacifiCorp to help meet their investor expectations and
11 also their quarterly earnings targets and financial targets
12 that they put forth to their investors. So I think that's been
13 a big benefit to the Company PacifiCorp and Rocky Mountain
14 Power -- that we i re not managed quarter to quarter such as
15 other companies or perhaps the Company had been managed
16 previously by prior owners. So we have the benefit of having
17 perhaps more of a longer-term perspective on investments in the
18 Company and the need to retain capital to invest in the
19 business.
20 Q.As the treasurer of the Company, do you have any
21 opinions or observations about whether or not customers have
22 any benefit from that dividend policy?
23 A. Oh, yeah, I think it i S been a strong benefit to
24 the customers. It i S allowed the Company to continue with the
25 investments that Mr. Walj e talked about that will provide
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RMP
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.
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1 benefi t now and also into the future.
2 It i S also allowed us to access the capital
3 markets at times when other companies couldn 't, and I can give
4 you examples of that during 2008 or 2009 because of market
5 condi tions.
6 I think it's also allowed the Company to borrow
7 at rates more favorable than similar companies with the same
8 credi t ratings we have. Because of the ownership by Berkshire
9 Hathaway, we have the benefit of what i s called the "Berkshire
10 halo," and investors are willing to put confidence in
11 Berkshire's management and ownership of the Company.
12 Lastly, Mr. Williams, there were several timesQ.
13 that I believe Mr. Walj e had deferred or at least referred to
14 you as the treasurer of the Company. If I haven i t addressed
15 the areas that were referred to you, at this time would you
16 make any additional comments regarding the subject matter of
17 your expertise that was asked of Mr. Walj e?
18 I think there were some questions about capitalA.
19 structure and the cost of debt and common equity. I would be
20 happy to get into those if --
21 Q.Please.
22 Okay. I know there's some questions about theA.
23 cost of debt in the case, and as I mentioned, we have adjusted
24 the cost of debt down to 5.88 percent from 5.92. But I think
25 it i S important to remember that what helps drive that cost of
342
HEDRICK COURT REPORTING
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WILLIAMS (Di)~p
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1 debt is the capital structure and the ratings, and the Company,
2 when it does its capital plan and its financings, seeks to come
3 up with a financial ratios and metrics that would support the
4 current credit ratings; and we believe that i s beneficial to the
5 customers because that provides both a good balance in the cost
6 of debt and the equity and the overall rate of return, but it
7 also allows us to finance the business through all different
8 economic and business cycles.
9 And as I mentioned earlier, there were times in
10 2008 when other utili ties couldn i t access the long-term debt
11 markets, but this company was, partly because of the ratings,
12 because of the ownership by Berkshire Hathaway and MidAmerican,
13 and also the capital structure and the way that we finance the
14 Company. So we were able to finance ourselves during, you
15 know, the worst financial environment I i ve seen in my 25 years
16 with the Company, and I think that i s a benefit, you know, not
17 only to the cost of debt, but it allows us to maintain
18 stability for the long term.
19 MR. HICKEY: Madam Chair, Mr. Williams is
20 available for cross-examination.
21 COMMISSIONER SMITH: Thank you.
22 Mr. Budge, do you have questions?
23 MR. BUDGE: Thank you. Just a few questions.
24
25
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RMP
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1 CROS S - EXAMINAT I ON
2
3 BY MR. BUDGE:
4 Q.Mr. Williams, I believe you provided testimony
5 concerning the Company 's capital structure. Is that right?
6 A.That is correct.
7 Q.In looking at your table on the bottom of page 2
8 of your rebuttal, you have a chart that reflects these overall
9 costs, I believe.
10 A.Correct.
11 Q.And so the long-term debt you i re showing there is
12 in the 5.88 percent range, and you have common equity in there
13 at 10.6, which is what i s sought by the Company in this case?
14 A.Yes.
15 Q.And if I understand your overall thrust of your
16 rebuttal testimony is you seek to challenge the recommendation
17 of the Staff witness and also the Monsanto witness that seek to
18 reduce the common equity component of your capital structure to
19 about 49.7 percent. Correct?
20
21
A.No, that i s not correct.
Q.Okay. What is your understanding of what Staff
22 and Monsanto witnesses propose with respect to capital
23 structure?
24
25
A.I believe Staff witness Ms. Carlock accepted our
capi tal structure as proposed. The Monsanto witness Mr. Gorman
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RMP
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1 though has proposed adjustments, as you have mentioned. But
2 just to be clear, Staff witness Carlock has accepted our
3 capital structure as filed.
4 Q.And the capital structure approved in the last
5 Order of this Commission in 2007, Order 30482, approved an
6 equi ty structure with 50.4 percent of common equity. Is that
7 correct?
8 A.I don i t have that Order in front of me. It
9 sounds reasonable, but I i II take your word on that.
10 Q.Okay. Subj ect to check?
11 A.Yes.
12 Q.I think the Order is there if you need to check
13 it.
14 And the recommendation of the Company is that
15 that capital structure for equity be increased above that
16 number last approved by the Commission, above the 50.4?
17 A.Yes, we i re asking for 52.1 percent in this case.
18 Q.And the Company, in fact, has been operating at a
19 common equity level ever since the 2007 Order that is above the
20 50.4 percent number that was authorized by the Commission?
21 A.I don i t think that i s the case. I think there
22 have been periods of time when we probably have been below that
23 number. Those would be periods of time when we have done large
24 debt financings. I would say on average though, the capital
25 structure has been above that level -- at that level or above.
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RMP
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1 Look at Exhibit 238 that should be there,Q.
2 available to you. Do you have that available, Mr. Williams?
3 A.Yes, l'm looking at it now.
4 Looking at line 6, that deals with common equity.Q.
5 Would you agree that the percentage in the years 2008, 2009,
6 and 2010 through -23 are above the 50.4 percent common equity
7 level approved by the Commission in 2007?
8 Yeah, i would say these numbers are above thatA.
9 level. It I S unclear to me whether these are averages during
10 the year, and if they I re averages, however they were
11 determined; or if they I re end points. But subj ect to check on
12 that, i will agree, these numbers are above that level.
13 The source on Exhibit 238 is FERC Form I?Q.
14 i see that. It says various dates though, soA.
15 doesn I t really help me.
16 When we talk about return on common equity andQ.
17 the Company requesting in this case 10 ~ 6 percent, it is my
18 understanding when you view that from the perspective of what
19 it actually costs a ratepayer, that that number would be
20 grossed up to the extent of taxes that also must be recovered
21 off the top?
22 A.Correct.
23 What type of a percentage would that be grossedQ.
24 up by if ten percent -- 10.6 is the authorized rate?
25 Approximately what kind of a gross-up percentage would the
346
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WILLIAMS (X)
RMP
.
.
.
1 ratepayers have to pay in order to achieve the 10.6 sought by
2 the Company?
3 Subj ect to confirmation by Mr. McDougal who willA.
4 testify later, I believe it i S one minus the tax rate.
5 And then with respect to the debt financing, isQ.
6 it true that because the interest rate paid on debt is a
7 deductible expense for tax purposes, that that number would be
8 grossed down or reduced?
9 Yeah, there would be a tax benefit or tax shieldA.
10 on the debt cost.
11 And that would increase the differential betweenQ.
12 the cost of debt and cost of equity from the perspective of the
13 ratepayers that pay the cost?
14 A.Yes.
15 So is it true then that when the Company seeks asQ.
16 they are here to increase the common equity, does that act in
17 the best interests of the shareholders, Berkshire Hathaway, and
18 contrary to the best interests of the ratepayers?
19 I don i t think so. I will defer to Dr. HadawayA.
20 for the determination of the return on equity or how he
21 developed that. I would say I think it i S in the interest of
22 the ratepayers to have a heal thy, strong utility that can meet
23 its financial commitments and obligations and have access to
24 capi tal.
25 But since the Company has already increased theQ.
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WILLIAMS (X)
RMP
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1 common equity above what i s been authorized, wouldn i t you agree
2 that it apparently has a financial incentive to have, as a part
3 of its capital structure, more money in common stock than it
4 would in debt?
5 I don i t think so. If you look at the actualA.
6 earnings that the Company has had on its common equity, which I
7 believe are around six percent, it i S not much different than
8 the debt cost, so that wouldn i t really lead me to believe your
9 argument that the Company would increase the common equity
10 component to increase its earnings. I mean, really, the reason
11 the common equity component is increasing, as I touch on in my
12 testimony, is to maintain the credit ratings; and to maintain
13 the credit ratings in the build cycle that we i re in and also
14 because of the debt adjustments that the rating agencies make,
15 we need a higher equity component to offset those factors.
16 That i s the Company
i s perspective, but from theQ.
17 ratepayers i perspective, it costs us more in rates that we must
18 pay to the Company to support a higher capital structure
19 invol ving more equity and less debt. Wouldn i t you agree?
20 Well, I would -- I mean, all things being equal,A.
21 yes, the equity is more expensive than the debt. But it i shard
22 to say all things being equal, because there i s an
23 interrelationship between those two costs.
24 Appreciate that. Thank you very much for yourQ.
25 testimony.
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WILLIAMS (X)
RMP
.
.
.
1 MR. BUDGE: Nothing further.
2 COMMISSIONER SMITH: Thank you, Mr. Budge.
3 Mr. Purdy.
4 MR. PURDY: No. Thank you.
5 COMMISSIONER SMITH: Ms. Davison.
6 MS. DAVISON: I just have -- thank you. I just
7 have one quick question.
8
9 CROSS-EXAMINATION
10
11 BY MS. DAVISON:
12 Q.Mr. Williams, you were touting earlier on the
13 wi tness stand the benefits of the current owner 's dividend
14 policy, and you gave that as an example of benefits to
15 customers. Is it your testimony that Rocky Mountain Power does
16 not have any earnings pressure from its current owners?
17 Well, first, I don i t want to give the impressionA.
18 I was touting the dividend policy. I was trying to, I guess,
19 explain what I understand the policy to be.
20 I would say that the Company, like all companies
21 that has investors, has certain expectations by them; and I
22 think our investors, when they choose to invest in Rocky
23 Mountain Power or PacifiCorp, expect a reasonable opportunity
24 to earn a return commencement with the risks of that business
25 as an equity owner perspective.
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WILLIAMS (X)
RMP
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1 Q.Excuse me. I don i t want to be rude, but my
2 question is very narrowly focused, and my question was is it
3 your testimony that Rocky Mountain Power does not have any
4 earnings pressure from its current owners? I i m not talking
5 broadly about capital structure.
6 A.I understand that. I was trying to respond to
7 your question.
8 Q.It i S "yes" or "no."
9 MR. HICKEY: Well, Madam Chair, I think he's
10 enti tled to give an answer, whether or not Counsel likes it.
11 MS. DAVISON: Well, he could attention "yes" or
12 "no" and then explain, but l'm trying to get him to answer the
13 question directly before he then goes off on a tangent.
14 MR. HICKEY: I understand. I i II withdraw the
15 obj ection with that understanding.
16 COMMISSIONER SMITH: Does the witness understand
17 the question?
18 THE WITNESS: Could you repeat the question,
19 please?
20 BY MS. DAVISON: All right, I i II try ita thirdQ.
21 time.
22 Earlier on the witness stand, you were touting
23 the benefits of the dividend policy of the current owners to
24 customers. My question to you is is it your testimony that
25 Rocky Mountain Power does not have any earnings pressure from
350
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WILLIAMS (X)
RMP
.
.
.
1 its current owners?
2 A. l'm not sure whether to give you a "yes" or "no"
3 answer. Let me try to answer the question as best as I can.
4 Rocky Mountain Power has earning pressure on it
5 by its investors. The expectation is that we will achieve our
6 budgets, and those budgets are developed in part with the
7 expectation that we i II have a reasonable opportunity to earn a
8 return on the investment by our investors.
9 Q.Thank you.
10 MS. DAVISON: No further questions.
11 COMMISSIONER SMITH: Thank you. Mr. Olsen.
12 MR. OLSEN: No questions, Madam Chair.
13 COMMISSIONER SMITH: Mr. Otto.
14 MR. OTTO: Nothing, Madam Chair.
15 COMMISSIONER SMITH: Mr. Woodbury.
16 MR. WOODBURY: Thank you, Madam Chair.
17
18 CROSS-EXAMINATION
19
20 BY MR. WOODBURY:
21 Q.Mr. Williams, referring to your direct testimony
22 on pages -- page 6, I guess, and looking at your Exhibit --
23 S&P , Exhibit 6, page 3 --
24
25
A.Could you give me just a minute to catch up with
you, please?
351
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WILLIAMS (X)
RMP
.
.
.
23
1 Q.Sure.
A.I'm sorry,page 6?
Q.Yeah,page 6,around line 4.
The S&P --does S&P indicate that the Utility has
no right to cause MEHC to make an equity contribution?
2
3
4
5
6 A.Yes.
7 Q.They state that. And then in your testimony, you
8 expect additional cash equity contribution of $ 100 million and
9 for the end of year 2010.
10 Now, does that come from when S&P speaks of MEHC,
11 are they speaking of money that you have received from PPW
12 Holdings? Do they equate the two of those?
13 Yeah, the money comes directly from PPW Holdings.A.
14 That i s the intermediate that owns us. It gets its funding
15 though from MEHC, so if you trace the funds back, it comes from
16 MEHC.
17 Q. Well, this testimony was filed quite a while ago,
18 I guess. Has the Company received that cash infusion?
19 A. Yes, it was received in June of this year.
20 Q. And looking at your direct testimony on page 10,
21 you i re speaking of purchase power Agreements and also how
22 they' re perceived by rating agencies?
A.Yes.
24 And they say that -- you say, and it i S myQ.
25 understanding also, that rating agencies and financial analysts
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HEDRICK COURT REPORTING
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WILLIAMS (X)
RMP
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.
.
1 consider power purchase Agreements to be debt-like, and will
2 impute debt and related interests when calculating financial
3 ratios.
4 Why don i t rating agencies also impute revenue to
5 offset the debt and interest, you know, the other side of the
6 ledger?
7 I think it i S because the obligation to purchaseA.
8 and pay for the power that under the Agreements are referring
9 to is, you know, absolute and unconditional. So they know
10 you i re going to be making those payments; it i S a debt-like
11 obligation much like you have to pay interest and principal on
12 your debt. So they i re picking that up on, say, the liability
13 side.
14 On the revenue side, I guess there i s no
15 assurance, you know, you can sell the power or recover it,
16 things like that. To the extent you do and it i S in your
17 historical financials, you know, you are getting credit for it
18 that way.
19 Do the rating agencies make a distinction betweenQ.
20 PURPA Agreements, which are mandatory purchases of the Utility,
21 and voluntary purchases?
22 In my experience, they have not.A.
23 Is it your understanding that in Idaho, throughQ.
24 the Company i s ECAM, that it recovers 100 percent of its
25 PURPA-related costs?
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WILLIAMS (X)
RMP
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1 I i m not familiar with all of the mechanics of theA.
2 Idaho ECAM, but I will accept that.
3 And if that were, do you know whether that, IQ.
4 guess, regulatory mechanism is given any weight in the -- a
5 rating agency' s assessment of power purchase Agreements?
6 Yes, it is. The agencies -- S&P, when they doA.
7 their calculation as to amount of debt they impute, they have
8 what they call a risk factor, and the stronger the regulatory
9 mechanisms are to recover your purchase power costs, they will
10 reduce that risk factor, which has a result then of reducing
11 the amount of debt and interest that gets imputed. The Company
12 has been fortunate in that we i ve gotten S&P to reduce that risk
13 factor, which has lowered the amount of debt and interest, and
14 we i ve been able to reduce it because of the regulatory
15 mechanisms like the Idaho ECAM and other mechanisms in other
16 states as well.
17 So, in answer to your question, yes, that has
18 been helpful, and it has reduced that debt and interest impact.
19 That i S helpful.Q.
20 MR. WOODBURY: Thank you, Madam Chair. No
21 further questions.
22 COMMISSIONER SMITH: Thank you. Are there
23 questions from the Commissioners? Commissioner Redford.
24 COMMISSIONER REDFORD: I just have a couple of
25 questions maybe.
354
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WILLIAMS (X)
RMP
.
.
.
20
1 EXAMINATION
2
3 BY COMMISSIONER REDFORD:
4 Q.Earlier, Mr. Walj e was asked as to whether Rocky
5 Mountain Power pays for its Wall Street analysts. Do you know
6 the answer?
7 A.Yes. I think the question was do we pay the
8 rating agencies.
9 Q.Excuse me.
10 A.Yes, the answer is, yes, we pay each of the three
11 rating agencies an annual fee. I i d rather not say exactly how
12 much for competi ti ve reasons, but we do pay each of them a fee.
13 Q.That i s fine. So, I think your later testimony
14 was that you felt that what the rating analysts do is more
15 beneficial to the ratepayer than to the shareholder. Is that
16 what your testimony
17 A.No, I think the question was does the ratings
18 benefit customers as well as the shareholders.
19 Q.Yes, that was the question.
A.Okay. And I think my answer to that was, yes, I
21 think it benefits both of those parties perhaps for different
22 reasons, but there i s a benefit, I think, to each of them.
23 Q. Would you say that the benefit to the shareholder
24 outweighs the benefit to the customer?
25 A.It i S hard for me to quantify. I think they each
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RMP
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1 get different benefits maybe in different degrees.
2 Q.Well, I guess my ultimate question is since you
3 pay for the analysts and -- or, the rating agencies -- and to a
4 great extent their reports determine whether or not you i re able
5 to obtain financing and your ratings, wouldn i t you say that
6 it i S pretty obvious that the biggest benefit is to the
7 shareholders -- shareholder or owner?
8 A.I i m not sure. I i m not sure. I think there i s
9 certainly benefit to the shareholder and owner. There i s also
10 benefi t to the debt holder, the debt investor.
11 I want to come back to the benefit to the
12 customers, because -- because of the ratings and assuming, you
13 know, they rated us properly and at a level we would agree
14 with, hopefully that will reduce the debt cost to the
15 customers, which the customers pay. You know, in this case
16 it i s the 5.88 percent.
17 The other benefit I tried to explain
18 Q.Let 's -- go ahead. l'm sorry.
19 A.Okay. The other benefit I tried to explain is,
20 you know, the ratings will allow the Company to access capital
21 or borrow at times when perhaps lower-rated companies can 't,
22 and an example I keep coming back to is 2008-2009 during the
23 financial crisis, that I think -- let me go through a scenario,
24 say, where we couldn i t have borrowed and so then we have to
25 start canceling capital proj ects. And I don i t know where that
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WILLIAMS (Com)
RMP
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.
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1 would lead to, but clearly it would likely be issues with
2 service and quality and maintenance and things like that.
3 Q.I think we would both agree that that i s not the
4 case as far as Rocky Mountain Power and its relationship with
5 its owners.
6 A.Well, it has not been the case, I would agree
7 with that, yes.
8 Q.So any residual benefit -- maybe this is just me
9 testifying, but any residual benefit would be far outweighed by
10 its benefit to the shareholders? And you can say -- you can
11 answer that or not.
12 A.I want to try to answer your question. I 'm just
13 kind of struggling to see the benefit to the shareholders.
14 They i re putting their money in, they're taking the equity risk,
15 they i re taking the opportunities to earn a return on their
16 investment. The the rating agencies are rating the debt
17 that we i re going to be issuing and people are going to be
18 investing, and that i s a different class of investors. So, I
19 think, you know, the ratings will help attract the debt
20 capital, which will go along with the equity to fund the
21 Company.
22 And, yeah, I think there i s benefits to the
23 shareholders; there i s also benefits to the debt investors; and
24 because we can borrow hopefully more cheaply and at times
25 perhaps when other people can 't, there i s also benefit to the
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WILLIAMS (Com)
RMP
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.
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1 customers.
2 Q.Well, your given the parties -- that is,
3 Berkshire and its owners I think that the -- I hope you 're
4 not paying too much to the analysts.
5 A.I don i t think we are. With the help of
6 MidAmerican, we i ve been pretty successful in reducing the fees.
7 I think, as Mr. Walj e talked about earlier, the Company is very
8 cost conscious, and this is yet another one of the costs that
9 we keep a pretty close eye on.
10 Q.What -- in addition to your being the treasurer,
11 do you hold any other positions or are you on any other
12 committees or any other departments?
13 A.I have responsibilities with the pension
14 investments. l'm the chairman of the pension committee.
15 I i m also involved in the credit risk management.
16 And I am treasurer to the foundation that
17 Mr. Walj e touched upon earlier.
18 I don i t serve on any other committees.
19 Are you involved in the analysis of capitalQ.
20 investments?
21
22
A.No, I 'm -- largely, am not.
Q.Okay. So, Mr. Walj e i s testimony that they have
23 done a spectacular job -- I don i t know if that was the word or
24 not -- in evaluating capital investments, you had no say in
25 that at all?
358
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WILLIAMS (Com)
RMP
.
.
.
1 MR. HICKEY: Madam Chairman, could I ask
2 Commissioner Redford to speak up a little bit?
3 COMMISSIONER REDFORD: Oh, I i m sorry.
4 MR. HICKEY: l'm at that age where I don't pick
5 up everything.
6 COMMISSIONER REDFORD: Well, let me turn this up
7 a little bit. Can you hear me good now?
8 MR. HICKEY: I think so. I don't think I I malone
9 here. I think some of the back of the room was also not
10 getting all of your questions. Thank you very much.
11 COMMISSIONER REDFORD: Could I ask the reporter
12 to read back that last question?
13 (Whereupon, the requested portion of the
14 record was read by the court reporter.)
15 Q.BY COMMISSIONER REDFORD: Do you understand the
16 question?
17 A.I do.
18 I would agree with you that I have not had a job
19 evaluating those capital investments. I would also agree with
20 Mr. Walj e that based on what I see of that analysis and the
21 decisions and the budgets and plans that are put together, I
22 would agree with him that I think the Company does a very
23 outstanding, good, thorough -- whatever adj ecti ve you want to
24 use -- job in analyzing the different investment opportunities.
25 Q.Do you -- does the Company, Rocky Mountain Power,
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HEDRICK COURT REPORTING
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WILLIAMS (Com)
RMP
.
.
.
20
21
1 also have a chief financial officer?
2 A.Yes, PacifiCorp does.
3 Q.Thank you. I have no further questions.
4 COMMISSIONER REDFORD: Thank you, Madam Chairman.
5 COMMISSIONER SMITH: Thank you, Commissioner
6 Redford.
7 Any redirect?
8 MR. HICKEY: No redirect. We would ask that
9 Mr. Williams be excused.
10 COMMISSIONER SMITH: Is there any objection to
11 excusing Mr. Williams?
12 Seeing none, you may be excused, and thank you
13 for your help.
14 THE WITNESS: Thank you.
15 (The witness left the stand.)
16 COMMISSIONER SMITH: Okay, I want to take an
17 off-the-record, two-minute reassessment of how late people can
18 go, starting with Wendy, who i s the most important person.
19 (Discussion off the record.)
COMMISSIONER SMITH: Go back on the record then.
MR. HICKEY: Dr. Hadaway is ready to be sworn,
22 Madam Chair.
23
24
25
360
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WILLIAMS (Com)
RMP
.
.
.
1 SAMUEL HADAWAY,
2 produced as a witness at the instance of Rocky Mountain Power,
3 being first duly sworn, was examined and testified as follows:
4
5 DIRECT EXAMINATION
6
7 BY MR. HICKEY:
8 Q.Good afternoon, Dr. Hadaway.
9 A.Good afternoon, Mr. Hickey.
10 Q.For the record, could you please state your name
11 and spell it?
12 A.Yes. My name is Samuel C. Hadaway: S-A-M-U-E-L;
13 middle initial C, as in Charles; Hadaway, H-A-D-A-W-A-Y.
14 Q.And by whom are you employed and what is your
15 capaci ty with that organization?
16 A.I am here as a consultant for the Company, but
17 l'm employed by the financial analysis consulting firm Financo,
18 Inc., of Austin, Texas, and I i m an owner in that firm.
19 And, Dr. Hadaway, did you file direct testimonyQ.
20 on the 28th of May and attach to it an Appendix A and Exhibits
21 10 through 14?
22 A.Yes, sir, I did.
23 And did you also have an opportunity to fileQ.
24 rebuttal testimony on the 16th of November of this year and
25 attach to it Exhibits 57 through 60?
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HADAWAY (Di)
RMP
.
.
.
20
21
22
23
24
25
i A.Yes, sir.
2 Q.Do you have any changes or corrections to any of
3 that testimony or those exhibits?
4 A.No, I do not.
5 Q.If I were to ask you the questions set out in
6 both the prefiled and direct testimony -- excuse me, the
7 prefiled direct testimony and rebuttal testimony -- would your
8 answers be the same?
9 A.Yes, they would.
10 MR. HICKEY: Madam Chair, I would move that the
11 prefiled direct and rebuttal testimony of Dr. Samuel Hadaway be
12 spread onto the record as if it was read; and that Appendix A,
13 Exhibits 10 through 14, and 57 through 60 be marked for
14 identification.
15 COMMISSIONER SMITH: Seeing no obj ection, it is
16 so ordered.
17 (The following prefiled direct and
18 rebuttal testimony of Mr. Hadaway is spread upon the record.)
19
362
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
HADAWAY (Di)
RMP
.1 Q.
2 A.
3
4 Q.
5 A.
6 Q.
7 A.
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22
.23
Please state your name, occupation, and business address.
My name is Samuel C. Hadaway. I am a Principal in FINANCO, Inc., Financial
Analysis Consultants, 3520 Executive Center Drive, Austin, Texas 78731.
On whose behalf are you testifying?
I am testifying on behalf of Rocky Mountain Power (RM or the Company).
Briefly describe your educational and professional background.
I have a Bachelor's degree in economics from Southern Methodist University, as
well as MBA and Ph.D. degrees with concentrations in finance and economics
from the University of Texas at Austin (UT Austin). I am an owner and full-time
employee of FINANCO, Inc. FINANCO provides financial research concerning
the cost of capital and financial condition for regulated companies as well as
financial modeling and other economic studies in litigation support. In addition to
my work at FINANCO, I have served as an adjunct professor in the McCombs
School of Business at UT Austin and in what is now the McCoy College of
Business at Texas State University. In my prior academic work, I taught
economics and finance courses and I conducted research and diected graduate
students in the areas of investments and capital market research. I was previously
Director of the Economic Research Division at the Public Utilty Commssion
(Texas Commssion) of Texas where I supervised the Texas Commssion's
finance, economics, and accounting staff, and served as the Texas Commssion's
chief financial witness in electrc and telephone rate cases. I have taught courses
at varous utilty conferences on cost of capital, capital strcture, utility fiancial
condition, and cost allocation and rate design issues. I have made presentations
363 Hadaway, Di- 1
Rocky Mountain Power
.1
2
before the New York Society of Securty Analysts, the National Rate of Return
Analysts Forum, and varous other professional and legislative groups. I have
3 served as a vice president and on the board of dictors of the Financial
4 Management Association.
5 A list of my publications and testimony that I have given before varous
6 regulatory bodies and in state and federal cours is contained in my resume, which
7 is included as Appendix A.
8 Purpose and Summary of Testimony
9 Q.
10 A.
11.12 Q.
13
14 A.
15
16
17
18
19
20
21
22
.
What is the purpose of your testimony?
The purpose of my testimony is to estimate the market required rate of retu on
equity capital (ROE) for the Company.
Please state your ROE recommendation and summarize the results of your
cost of equity studies.
Iestimate the cost of equity for RMP to be 10.6 percent. My discounted cash
flow (DCF) analysis indicates that a range of 10.3 percent to 10.8 percent is
appropriate. My risk premium analysis indicates an ROE range of 10.39 percent
to 10.59 percent. Based on these quantitative results and my fuer review of
other economic data, I recommend a point estiate of 10.6 percent. As I wil
discuss in more detail later in this testimony, given the continuing market
tubulence that exists, the estimates of ROE produced by the traditional DCF and
risk premium models are modest. As such, my recommended 10.6 percent ROE
is a conservative estimate of RMP' s cost of equity capita.
364 Hadaway, Di- 2
Rocky Mountain Power
.1 Q.
2
3
4
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22
23.
How is your analysis structured?
In my DCF analysis, I apply a comparable company approach. RMP's cost of
equity cannot be estimated directly from its own market data because it is a
wholly-owned subsidiar of MidAmerican Energy Holdings Company. As such,
the Company does not have publicly traded common stock or other independent
market data that would be required to estimate its cost of equity diectly. I begin
my comparable company review with all the electrc utilities that are included in
the Value Line Investors Survey (Value Line). Value Line is a widely-followed,
reputable source of financial data that is often used by professional regulatory
economists. To improve the proxy group's comparabilty with the Company, I
restrcted the group to companies with senior secured bondratings of at least "A-"
by Standard & Poor's (S&P) or "A3" by Moody's Investors Service (Moody's). I
also required the comparable companies to derive at least 70 percent of revenues
from regulated utility sales, to have consistent financial records not affected by
recent mergers or restructuring, and to have a consistent dividend record, with no
dividend cuts or resumptions in the past two year, as required by the DCF modeL.
The fundamental characteristics and bond ratings of the 22 companies in my
comparable group are presented in Exhibit No. 10.
In my risk premium analysis, I relied on curent and projected single-A
utilty bond interest rates. These interest rates are consistent with the Company's
senior secured bond ratings of "A" from S&P and "A2" from Moody's. As I wil
explain in more detail later in this testimony, under curent market conditions the
DCF and risk premium models appear to provide extremely conservative
365
Hadaway, Di- 3
Rocky Mountain Power
.1
2
3
4 Q.
5 A.
6
7
8
9
10
11.12
13
14 A.
15
16
17
18
19
20 Q.
21
22 A.
23.
estimates of the Company's cost of equity capitaL. The data sources and the
details of my cost of equity studies are contaned in Exhibit No. 10 though
Exhibit No. 14.
How is the remainder of your testimony organized?
My testimony is divided into thee additional sections. Following this
introduction, I review various methods for estimating the cost of equity. In this
section, I discuss comparable earings methods, risk premium methods, and the
discounted cash flow modeL. In the following section, I review genera capital
market costs and conditions and discuss recent developments in the electrc utility
industry that may affect the cost of capital. In the final section, I discuss the
details of my cost of equity studies and summarze my ROE recommendations.
Estimating the Cost of Equity Capital
Q. What is the purpose of this section of your testimony?
The purpose of this section is to present a general defmition of the cost of equity
capital and to compare the strengths and weakesses of several of the most widely
used methods for estimating the cost of equity. Estimating the cost of equity is
fundamentally a matter of informed judgment. The varous models provide a
concrete link to actual capita market data and assist with defining the varous
relationships that underlie the ROE estimation process.
Please define the term "cost of equity capital" and provide an overview of
the cost estimation process.
The cost of equity capital is the rate of return that equity investors expect given
the risks of an individual security. Conceptually it is no different than the cost of
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debt or the cost of preferred stock. The cost of equity is the rate of retu that
common stockholders expect, just as interest on bonds and dividends on preferred
stock are the returns that investors in those seurties expect. Equity investors
expect a retu on their capita commensurate with the risks they take and
consistent with retus that are available from other simlar investments. Unlike
retus from debt and preferred stocks, however, the equity retu is not diectly
observable in advance and, therefore, it must be estimated or inferred from capital
market data and trading activity.
An example helps to ilustrate the cost of equity concept. Assume that an
investor buys a share of common stock for $20 per share. If the stock's expected
dividend is $1.00, the expected dividend yield is 5.0 percent ($1.00 / $20 = 5.0
percent). If the stock price is also expected to increase to $21.20 after one year,
this one dollar and 20 cent expected gain adds an additional 6.0 percent to the
expected total rate of return ($1.20/ $20 =6.0 percent). Therefore, buying the
stock at $20 per share, the investor expects a total retu of 11.0 percent: 5.0
percent dividend yield, plus 6.0 percent price appreciation. In this example, the
total expected rate of retu of 11.0 percent is the appropriate measure of the cost
of equity capital, because it is this rate of return that caused the investor to
commt the $20 of equity capital in the first place. If the stock were riskier, or if
expected returns from other investments were higher, investors would have
required a higher rate of retu from the stock, which would have resulted in a
lower initial purchase price in market trading.
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Each day market prices change to reflect new investor expectations and
requirements. Changes in maket prices, al else equal, imply changes in investor
required rates of retu. For example, when interest rates on bonds and savings
accounts rise, utilty stock prices usually fall. This is tre, at least in par, because
higher interest rates on these alternative investments mae utilty stocks relatively
less attractive, which causes utilty stock prices to decline in maket trading. This
competitive maket adjustment process is quick and continuous, so that market
prices generally reflect investor expectations and the relative attractiveness of one
investment versus another. In this context, to estimate the cost of equity one must
apply informed judgment about the relative risk of the company in question and
knowledge about the risk and expected rate of retu characteristics of other
available investments as welL.
How does the market account for risk differences among various
investments?
Risk-return tradeoffs among capital market investments have been the subject of
extensive financial research. Literaly dozens of textbooks and hundreds of
academic aricles have addressed the issue. Generally, such research confirs the
common sense conclusion that investors wil take additional risks only if they
expect to receive a higher rate of return. Empircal tests consistently show that
returns from low risk securties, such as U.S. Treasury bils, are the lowest; that
retus from longer-term Treasury bonds and corporate bonds are increasingly
higher as risks increase; and generally, retus from common stocks and other
more risky investments are even higher. These observations provide a sound
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theoretical foundation for both the DCF and risk premium methods for estimating
the cost of equity capital. These methods attempt to captue the well founded
risk-retu principle and explicitly measure investors' rate of retu requirements.
Can you ilustrate the capital market risk-return principle that you just
described?
Yes. The following graph depicts the risk-return relationship that has become
widely known as the Capital Market Line (CML). The CML offers a graphical
representation of the capita market risk-retu principle. The graph is not meant
to ilustrate the actual expected rate of return for any parcular investment, but
merely to ilustrate in a general way the risk-return relationship.
Risk-Return Tradeoffs
c..::20%-
Q)a:-0
15%Q)-
Cda:
"0 10%Q)Õ
Q)a.5%xil
The Capital Market Line
Common
Stocks
Investment
Grade Bonds
Higher Risk ..
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As a continuum, the CML can be viewed as an available opportnity set for
investors. Those investors with low risk tolerance or investment objectives that.
mandate a low risk profile should invest in assets depicted in the lower left-hand
portion of the graph. Investments in this area, such as Treasury bils and short-
matuty, high quality corporate commercial paper, offer a high degree of investor
certinty. In nominal term (before considering the potential effects of inflation),
such assets are virally risk-free.
Investment risks increase as one moves up and to the right along the CML.
A higher degree of uncertainty exists about the level of investment value at any
point in time and about the level of income payments that may be received.
Among these investments, long-term bonds and preferred stocks, which offer
priority claims to assets and income payments, are relatively low risk, but they are
not risk-free. The market value of long-term bonds, even those issued by the U.S.
Treasur, often fluctuates widely when governent policies or other factors cause
interest rates to change.
Farher up the CML continuum, common stocks are exposed to even more
risk, depending on the nature of the underlying business and the financial strength
of the issuing corporation. Common stock risks include market-wide factors,
such as general changes in capital costs, as well as industr and company specific
elements that may add fuer to the volatilty of a given company's performance.
As I wil ilustrate in my risk premium analysis, common stocks typically are
more volatile (have higher risk) than high quality bond investments and,
therefore, they reside above and to the right of bonds on the CML graph. Other
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more speculative investments, such as stock options and commodity futues
contracts, contan higher risks (but offer higher potential retus). The CML's
depiction of the risk-retu tradeoffs available in the capital makets provides a
useful perspective for estimating investors' required rates of return.
How is the fair rate of return in the regulatory process related to the
estimated cost of equity capital?
The regulatory process is guided by fai rate of return principles established in the
U.S. Supreme Court cases, Bluefield Water Works and Hope Natural Gas:
A public utilty is entitled to such rates as wil permt it to ear a
return on the value of the property which it employs for the
convenience of the public equal to that generally being made at the
same time and in the same general par of the countr on
investments in other business undertngs which are attended by
corresponding risks and uncertainties; but it has no constitutional
right to profits such as are realized or anticipated in highly
profitable enterprises or speculative ventures. Bluefield Water
Works & Improvement Company v. Public Service Commission of
West Virginia, 262 U.S. 679, 692-693 (1923).
From the investor or company point of view, it is important that
there be enough revenue not only for operating expenses, but also
for the capital costs of the business. These include service on the
debt and dividends on the stock. By that standad the retu to the
equity owner should be commensurate with retus on investments
in other enterprises having corresponding risks. That retu,
moreover, should be sufficient to assure confidence in the financial
integrity of the enterprise, so as to maintain its credit and to attract
capitaL. Federal Power Commission v. Hope Natural Gas Co., 320
U.S. 591, 603 (1944).
Based on these principles, the fai rate of return should closely paralel investor
opportnity costs as discussed above. If a utilty ears its market cost of equity,
neither its stockholders nor its customers should be disadvantaged.
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What specific methods and capita market data are used to evaluate the cost
of equity?
Techniques for estimating the cost of equity normally fall into thee groups:
comparable earings methods, risk premium methods, and DCF methods. The
first set of estimation techniques, the comparable earings methods, has evolved
over time. The original comparable earngs methods were based on book
accounting retus. This approach developed ROE estimates by reviewing
accountig returns for unregulated companies thought to have risks similar to
those of the regulated company in question. These methods have generally been
rejected because they assume that the unregulated group is earing its actual cost
of capital, and that its equity book value is the same as its market value. In most
situations these assumptions are not valid, and, therefore, accounting-based
methods do not generally provide reliable cost of equity estimates.
More recent comparable earings methods are based on historical stock
market returns rather than book accounting retus. While this approach has
some merit, it too has been criticized because there can be no assurance that
historical returns actually reflect current or future market requirements. Also, in
practical application, eared market returns tend to fluctuate widely from year to
year. For these reasons, a currnt cost of equity estimate (based on the DCF
model or a risk premium analysis) is usually required.
The second set of estimation techniques is grouped under the heading of
risk premium methods. These methods begin with curently observable market
retus, such as yields on government or corporate bonds, and add an increment to
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account for the additional equity risk. The capital asset pricing model (CAPM)
and arbitrage pricing theory (APT) model are more sophisticated risk premium
approaches. The CAPM and APT methods estimate the cost of equity diectly by
combining the "risk-free" government bond rate with explicit risk measures to
determne the risk premium required by the maket. Although these methods are
widely used in academic cost of capital research, their additional data
requirements and their potentially questionable underlying assumptions have
detracted from their use in most regulatory jursdictions. The basic equity risk
premium methods provide a useful parallel approach with the DCF model and
assures consistency with other capital market data in the equity cost estimation
process.
The third set of estimation techniques, based on the DCF model, is the
most widely used regulatory cost of equity estimation method. Like the risk
premium approach, the DCF model has a sound basis in theory, and many argue
that it has the additional advantage of simplicity. I wil describe the DCF model
in detail below, but in essence its estimate of ROE is simply the sum of the
expected dividend yield and the expected long-term dividend, earings, or price
growth rate (all of which are assumed to grow at the same rate). While dividend
yields are easy to obtain, estimating long-term growth is more difficult. Because
the constant growth DCF model also requires very long-term growth estimates
(technically to infity), some argue that its application is too speculative to
provide reliable results, leading to a preference for the multistage growth DCF
analysis.
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Of the three estimation methods, which do you believe provides the most
reliable results?
From my experience, a combination of DCF and basic equity risk premium
methods provides the most reliable approach. While the caveat about estimating
long-term growth must be observed, the DCF model's other inputs are readily
obtainable, and the model's results typically are consistent with capital market
behavior. The basic risk premium methods provide a good paralel approach to
the DCF model and fuer ensure that curent market conditions are accurately
reflected in the cost of equity estimate.
Please explain the DCF model.
The DCF model is predicated on the concept that stock prices represent the
present value or discounted value of all futue dividends that investors expect to
receive. In the most general form, the DCF model is expressed in the following
formula:
Po = D¡/(1+k) + DiI(1+k)2 +... + Doo(l+k)"" (1)
where Po is today's stock price; Di, D2, etc. are all futue dividends and k is the
discount rate, or the investor's required rate of return on equity. Equation (1) is a
routine present value calculation based on the assumption that the stock's price is
the present value of all dividends expected to be paid in the futue.
Under the additional assumptions that dividends are expected to grow at a
constant rate "g" and that k is strictly greater than g, equation (1) can be solved for
k and rearanged into the simple form:
k=DilPo+ g (2)
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Equation (2) is the famliar constant growth DCF model for cost of equity
estimation, where DilPo is the expected dividend yield and g is the long-term
expected dividend growth rate.
Under circumstances when growth rates are expected to fluctuate or when
future growth rates are highly uncertain, the constant growth model may not give
reliable results. Although the DCF model itself is stil valid (equation 1 is
mathematically correct), under such circumstances the simplified form of the
model must be modified to capture market expectations accurately.
Recent events and current maket conditions in the electrc utilty industr
as discussed later appear to challenge the constant growth assumption of the
traditional DCF modeL. Since the mid-1990s, dividend growth expectations for
many electric utilties have fluctuated widely. In fact, over one-third of the
electrc utilties in the U.S. have reduced or elimiated their common dividends
over this time period. Some of these companies have reestablished their
dividends, producing exceptionally high growth rates. Under these
circumstances, long-term growth rate estimates may be highly uncertain, and
estimating a reliable "constant" growth rate for many companies is often dicult.
Can the DCF model be applied when the constant growth assumption is
violated?
Yes. When growth expectations are uncertain, the morè general version of the
model represented in equation (1) should be solved explicitly over a finite
"transition" period while uncertainty prevails. The constant growth version of the
model can then be applied after the transition period, under the assumption that
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more stable conditions wil prevail in the future. There are two alternatives for
dealing with the nonconstant growth transition period.
Under the "termnal price" nonconstant growth approach, equation (1) is
written ina slightly different form:
Po = DiI(l+k) + DiI(1+k)z + ..~ + PT/(I+kl (3)
where the varables are the same as in equation (1) except that PTis the estimated
stock price at the end of the transition period T. Under the assumption that
norml growth resumes after the transition period, the price PT is then expected to
be based on constant growth assumptions. With the termnal price approach, the
estimated cost of equity, k, is just the rate of retu that investors would expect to
ear if they bought the stock at today's maket price, held it and received
dividends through the transition period (until period T), and then sold it for price
PT. In this approach, the analyst's task is to estimate the rate of return that
investors expect to receive given the current level of market prices they are
willng to pay.
Under the "multistage" nonconstant growth approach, equation (1) is
simply expanded to incorporate two or more growth rate periods, with the
assumption that a permanent constat growth rate can be estimated for some point
in the future:
20 R = Do(1+g1) + + Do(1+g2)n +o (l+k) ... (l+k)n ... +
(DOC i+gT) (T+l)i
(k-gT)
(l+k)T (4)
21 where the variables are the same as in equation (1), but gi represents the growth.22 rate for the first period, gz for a second period, and gT for the period from year T
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(the end of the transition period) to infinity. The first two growth rates are simpiy
estimates for fluctuating growth over "n" years (typically 5 or 10 years) and gT is
a constant growth rate assumed to prevail forever after year T.The difficult task
for analysts in the multistage approach is determning the varous growth rates for
each period.
Although less convenient for exposition puroses, the nonconstant growth
models are based on the same valid capital maket assumptions as the constant
growth version. The nonconstant growth approach simply requires more explicit
data inputs and more work to solve for the discount rate, k.Fortnately, the
required data are available from investment and economic forecasting services,
and computer algorithms can easily produce the required solutions. Both constant
and nonconstant growth DCF analyses are presented in a subsequent section of
my testimony.
Please explain the risk premium methodology.
Risk premium methods are based on the assumption that equity securities are
riskier than debt and, therefore, that equity investors require a higher rate of
return. This basic premise is well supported by legal and economic distinctions
between debt and equity securities, and it is widely accepted as a fundamental
capital market principle. For example, debt holders' claims to the earings and
assets of the borrower have priority over all claims of equity investors. The
contractual interest on mortgage debt must be paid in full before any dividends
can be paid to shareholders, and secured mortgage claims must be fully satisfied
before any assets can be distrbuted to shareholders in banptcy. Also the
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fixed-income nature of interest payments makes year-to-year retus from bonds
typically more stable than capital gains and dividend payments on stocks. All
these factors demonstrate the more risky position of stockholders and support the
equity risk premium concept.
Are risk premium estimates of the cost of equity consistent with other
current capital market costs?
Yes. The risk premium approach is useful because it is founded on current
market interest rates, which are directly observable. This featu assures that risk
premium estimates of the cost of equity begin with a sound basis, which is tied
directly to current capital maket costs.
Is there consensus about how risk premium data should be employed?
No. In regulatory practice there is often considerable debate about how risk
premium data should be interpreted and used. Since the analyst's basic task is to
gauge investors' required retus on long-term investments, some argue that the
estimated equity risk premium should be based on the longest possible time
period. Others argue that market relationships between debt and equity from
several decades ago are irelevant and that only recent debt-equity observations
should be given any weight in estimating investor requirements. There is no
consensus on this issue. Since analysts cannot observe or measure investors'
expectations diectly, it is not possible to know exactly how such expectations are
formed or, therefore, to know exactly what time period is most appropriate in a
risk premium analysis.
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The important point is to answer the following question: "What rate of
return should equity investors reasonably expect relative to retus that are
curently available from long-term bonds?" The risk premium studies and
analyses I discuss later address this question. My risk premium recommendation
is based on an intermediate position that avoids some of the problems and
concerns that have been expressed about both very long and very short periods of
analysis with the risk premium modeL.
Please summarize your discussion of cost of equity estimation techniques.
Estimating the cost of equity is one of the most controversial issues in utilty
ratemakng. Because actual investor requirements are not diectly observable,
several methods have been developed to assist in the estimation process. The
comparable earings method is the oldest but perhaps least reliable. Its use of
accounting rates of retu, or even historical market returns, mayor may not
reflect current investor requirements. Differences in accounting methods among
companies and issues of comparabilty also detract from this approach.
The DCF and risk premium methods have become the most widely
accepted in regulatory practice. In my professional judgment, a combination of
the DCF model and a review of risk premium data provides the most reliable cost
of equity estimate. While the DCF model does require judgment about futue
growth rates, the dividend yield is straightforward, and the model's results are
generally consistent with actual capital market behavior. For these reasons, I wil
rely on a combination of the DCF model and a risk premium analysis in the cost
of equity studies that follow.
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1 Fundamental Factors That Affect the Cost of Equity
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What is the purpose of this section of your testimony?
In this section, I review recent capital maket conditions and industr factors that
should be reflected in the cost of capital estimate.
What hasbeen the experience in the U.S. capital markets for the past several
years?
In Exhibit No. 11, page 1, I provide a review of annual interest rates and rates of
inflation in the U.S. economy over the past ten years. During that time inflation
and fixed income maket costs declined and, generally, have been lower than rates
that prevailed in the previous decade. Inflation, as measured by the Consumer
Price Index (CPI), was zero percent in 2008 but increased to about a 3 percent
annual rate in 2009. Over the past decade, the CPI has averaged 2.6 percent. This
is lower than its long-run average of 3.5 percent to 4.0 percent.
Durng the period from mid-2004 until mid-2006, the Federal Reserve
System increased the short-term Federal Funds interest rate 17 times (the Federal
Funds rate is the rate bans charge each other to borrow reserves overnight),
raising it from 1 percent to 5.25 percent. In late 2007, in response to the early
tubulence in the sub-prime credit markets, the Federal Reserve Open Market
Commttee began aggressively reducing the Federal Funds rate. Since September
2007, the rate has been lowered eleven times to its curent target level of between
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zero and one-quarer percent. While governmental policies and "flght to safety" 1
issues have drven down interest rates on higher quality debt securties, the cost of
equity for utilties has not declined to the same extent.
Has the recent extreme turbulence in the capital markets increased the cost
of capital for utilties?
Yes. At varous times since late 2008, the capital markets in the U.S. have been
more turbulent than at any time since the 1930s. This period has seen frequent
large daily moves in the stock market2 and conditions in the corporate debt market
that, in late 2008 and pars of early 2009, could best be characterized as near-
chaos. The S&P 500 and the Dow Jones Industrial Average have fluctuated by 50
percent since November 2007. In this environment, many large financial
institutions such as Countrywide Financial, Washington Mutual, the Federal
Home Loan Mortgage Association, the Federal National Mortgage Association,
Wachovia, Bear Sterns, and Merrll Lynch were unable to surive as independent
institutions. Lehman Brothers was forced to fie for banptcy. Other surviving
institutions such as Citigroup, Goldman Sachs, American International Group,
Morgan Stanley and others have required multibilion dollar capital infusions.
1 The term "flght to safety" refers to the tendency for investors, dunng periods of market
tubulence, to remove money from more riky investments, such as corporate bonds and stocks,
and to put the money into government securities such as Treasur bils and bonds. The effect
causes a reduction in the supply of funds to corprations and an increase in funds invested in
government secunties. The result is wider "spreads" between corprate bond and government
bond interest rates and higher capital costs for corpraions.
2 On May 6, 2010, the Dow Jones Industral Average (Dow) opened at approximately 10,860, fell
to a low of 9,940 - nearly a 920 point drop or about 8.5%, most of which came in a matter of just
a few minutes - and then rallied to close at approximately 10,520. On May 10,2010, the Dow
rose 405 points, or approximately 3.9% to close at 10,785; but on May 20,2010, the Dow lost
3.6% or 379 points to close at 10,068.
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Since October 2008, the Federal government has enacted emergency
legislation and taken other steps to stabilze the economy. As par of that effort
the government increased federal deposit insurnce for bans, lent bilions of
dollars to financial institutions, purchased hundreds of bilions of dollars in
iliquid securities, guaranteed loans between financial institutions, and purchased
equity in bans. There is no question that the economic and financial
uncertainties generated by the credt crisis have significantly impacted the risks
surrounding public utilty company cost of capital.
Can you be more specific regarding the impact of the credit crisis on the cost
of capital of public utilties?
Yes. In Exhibit No. 11, page 2, I provide data that ilustrate the volatilty that has
occurred in the debt markets. The schedule shows that durng the past two years,
single- A spreads for utilty companies were at times more than thee times
previously existing levels. The month-by-month interest rates paid by single-A
rated utilties and the U.S. Treasury since Januar 2008 are presented in Exhbit
No. 11, page 2. These interest rate data are summarzed in Table 1 below.
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.Table 1
Long- Term Inerest Rate Trend
Sinle-A 30-Year Sinle-A
Month Utilty Rate Treasur Rate Utilty Spread
Jan-08 6.02 4.33 1.69
Feb-08 6.21 4.52 1.69
Mar-08 6.21 4.39 1.82
Apr-08 6.29 4.44 1.85
May-08 6.28 4.60 1.68
Jun-08 6.38 4.69 1.69
Jul-08 6.40 4.57 1.83
Aug-08 6.37 4.50 1.87
Sep-08 6.49 4.27 2.22
Oct-08 7.56 4.17 3.39
Nov-08 7.60 4.00 3.60
Dec-08 6.52 2.87 3.65
Jan-09 6.39 3.13 3.26
Feb-09 6.30 3.59 2.71
Mar-09 6.42 3.64 2.78.Apr-09 6.48 3.76 2.72
May-09 6.49 4.23 2.26
Jun-09 6.20 4.52 1.68
Jul-09 5.97 4.41 1.56
Aug-09 5.71 4.37 1.34
Sep-09 5.53 4.19 1.34
Oct-09 5.55 4.19 1.36
Nov-09 5.64 4.31 1.33
Dec-09 5.79 4.49 1.30
Jan-09 5.77 4.60 1.17
Feb-l0 5.87 4.62 1.25
Mar-l0 5.84 4.64 1.20
Apr-l0 5.81 :4.69 1.12
3-MoAvg 5.84 4.65 1.19
12-MoAvg 5.85 4.44 1.41
Mergent Bond Record (Utility Rates); ww.federaleserv.gov(Treasur Raes).
Thee-month average is for February though Apil20lO.
Twelve-month average is for May 2009 through Apil20l0.
1 The data in Table 1 vividly ilustrate the market tuoil that has occured. In fact,.2 increased risk aversion and continuing maket volatilty have resulted in ongoing
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dificulties for many corporations. The on-going effects of the maket's
turbulence is not easily captued in financial models for estimating the required
rate of return that assume equilbrium conditions. However, these continuing
effects and the elevated level of risk aversion should be considered in estiating
the cost of equity capitaL.
Do the smaller spreads between single-A utilty bond yields and U.S.
Treasury bonds mean that the markets have completely recovered from the
economic turmoil that resulted from the financial crisis?
No. While markets have attempted to stabilze relative to the near-chaotic
conditions that existed in late 2008, investors remain concerned about high
unemployment, the large federal government deficits that are being created, and
the potential for furter fallout from housing foreclosures and other remnants of
the financial crisis. Although it is dificult to measure these effects directly, the
data in Table 2 provide some perspective for the ongoing impacts.
384
Hadaway, Di- 22
Rocky Mountain Power
.Table 2
Utilty Bond Inerest Rate Spreads
Column 1 2 3
Aa Baa Baa minus
Month Utilty Utilty Aa
Apr-07 5.83 6.24 0.41
May-07 5.86 6.23 0.37
Jun-07 6.18 6.54 0.36
JuI-07 6.11 6.49 0.38
Aug-07 6.11 6.51 0.40
.Sep-07 6.10 6.45 0.35
Oct-07 6.04 6.36 0.32
Nov-07 5.87 6.27 0.40
Dec-07 6.03 6.51 0.48
Jan-08 5.87 6.35 0.48
Feb-08 6.04 6.60 0.56
Mar-08 5.99 6.68 0.69
Apr-08 5.99 6.81 0.82
May-08 6.07 6.79 0.72
Jun-08 6.19 6.93 0.74
Jul-08 6.13 6.97 0.84
Aug-08 6.09 6.98 0.89
Sep-08 6.13 7.15 1.02
Oct-08 6.95 8.58 1.63
Nov-08 6.83 8.98 2.15
Dec-08 5.92 8.11 2.19
Jan-09 6.01 7.90 1.89
Feb-09 6.11 7.74 1.63
Mar-09 6.14 8.00 1.86
Apr-09 6.19 8.03 1.84
May-09 6.23 7.76 1.53
Jun-09 6.13 7.31 1.18
JuI-09 5.63 6.87 1.24
Aug-09 5.33 6.36 1.03
Sep-09 5.15 6.12 0.97
Oct-09 5.23 6.14 0.91
Nov-09 5.33 6.18 0.85
Dec-09 5.52 6.26 0.74
Jan-l0 5.55 6.16 0.61
Feb-lO 5.69 6.25 0.56
Mar-lO 5.64 6.22 0.58
Apr-lO 5.62 6.19 0.57
3.Mo Avg 5.65 6.22 0.57
Source: Mergent Bond Record.
Thee-month averair is for Februarv thou!! Aur2010.
385
.
.
Hadaway, Di- 23
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10 Q.
11.12 A.
13
14
15
16
17
18
19
20
21
22
.23
The spreads between the highest quality Aa utilty bond interest rates and Baa
rates remain almost twice as wide as those that existed in 2007 before the
financial crisis began. Like the Treasur bond yield spreads shown in Table 1, the
Baa - Aa spreads have narowed since late 2008 and early 2009, but they have not
returned to the lower levels that existed in early 2007. The unsettling volatity in
the stock market documented above along with these continuing wider spreads
between the highest quality utilty Aa bonds and minimum investment grade Baa
bonds are an indication of heightened investor uncertainty and risk aversion
caused by the continuing effects of the financial tuoiL.
What do forecasts for the economy and interest rates show for the coming
year?
Expectations are beginning to move toward higher interest rates during the
coming year. On Februar 18,2010, the Federal Reserve (Fed) raised the
Discount Rate from 0.50 percent to 0.75 percent. All members of the 12 Federal
Reserve bans supported the decision. This is the first increase in any of the
government admnistered interest rates since the Fed began its efforts to revive the
economy in 2008.
Additional economic data and projections from S&P also point to higher
rates. S&P's most recent Trends & Projections publication for April 2010 is
presented in Exhibit No. 11, page 3. The S&P data reflect signifcant economic
contraction durng 2009. S&P indicates that real gross domestic product (ODP)
declined by 2.4 percent during that year. However, ODP growth resumed in the _
3rd Quarer of 2009, and for all of 2010, S&P expects real ODP to increase by 3.0
386 Hadaway, Di- 24
Rocky Mountain Power
.1
2
percent.
S&P also forecasts that long-term government and high grade corporate
3 interest rates wil rise somewhat from reent levels. The summar interest rate
4 data are presented in Table 3 below:
5.6
7
8
9
10
11
12
13
14 Q.
15 A.
16.17
Table 3
Standard & Poor's Interest Rate Forecast(a) (b) (c)
Average Average Average
Apr. 2010 2009 2010 Est.Treasury Bils 0.2% 0.2% 0.4%10-Yr. T-Bonds 3.9% 3.3% 4.1%30-Yr. T-Bonds 4.7% 4.1% 5.0%Aaa Corporate Bonds 5.3% 5.3% 5.7%
Sources: Column (a) from: www.federalreserve.gov, (Current Rates).
Columns (b) and (c) from: Standard & Poor's Trends & Projections,
April 2010, page 8 (Projected Rates).
The data in Table 3 show that long-term Treasur interest rates during 2010 are
projected to increase by 30 basis points from curent levels. Rates on highest
grade Aaa corporate bonds are expected to increase by 40 basis points. Although
in the recently turbulent market environment it has been difficult to project
interest rates, investors recognize that as the economy improves, the demand for
loanable funds wil rise. These market forces wil generally lead to higher
interests rates, consistent with the market data and foreasts shown on Exhibit No.
11 Page 3 of 3. As such, the information on that exhibit offers perspective for
judging the cost of capital in the present case.
How have utilty stocks performed during the past several years?
Utilty stock prices have fluctuated widely. After reaching a level of over 400 in
2000, the Dow Jones Utilty Average (DJUA) dropped to about 200 by October
2002. From late 2002 until 2008, the DJUA trended upward. However, utilty
387 Hadaway, Di- 25
Rocky Mountain Power
.
.
1
2
3
4
5
6
7
8
9
10 Q.
11
12 A..13
stock prices dropped materially with the overall market decline of 2008 and early
2009. The current level for the Dru A is over 25 percent below the highest levels
attained in 2007. The wider fluctuations in more recent years are vividly
ilustrated in Graph 1, which depicts DJUA prices over the past 25 years.
Graph 1
Dow Jones Utilty Average
1986-2010
600
500
400
300
200
100
o
t2$' t2"''b t2(lC?~ t2(lC?ti t2(lcl t2(lC?fò t2(lC?'b t2~~ t2~ti t2!' t2" ~~'b t2(l"'~
Over the last decade, utilty stock prices have become much more volatile than
they previously were. In this environment, investors' return expectations and
requirements for providing capital to the utility industr are higher than they were
relative to the longer-term traditional view of the utility industry.
How have utilty stocks performed relative to the overall market recovery
experienced during the past year?
Utilty stock prices have lagged significantly behind the overall maket recovery.
Graph 2 shows the monthly levels for the DJUA versus the broader maket S&P
388 Hadaway, Di- 26
Rocky Mountain Power
.
.
.
1 500 index since the market lows that occured in Februar and Marh of 2009.
Graph 2
Dow Jones Utilty Average
vs. S&P 500
Mar. 2009 - Apr. 2010
r.....---....................................................................................................._........................-I. ~~~.I . "" -~~""'~~"l #'....~........v:1i ~"'''''~-'~. S&P 500
$"''''''
I
IDJUA I..
~QJ
~t§
~QJ
~o~
..~§
")'l
..~
~~~
~QJ
~,ç
~QJ
")~
91
C:0~
1400.00
1200.00
1000.00
800.00
600.00
400.00
200.00
0.00
2 While the S&P 500 has increased significantly durng the past year, utility prices
3 have remained relatively flat. This result is a furer indication that the cost of
4 equity for utilty companies has not declined to the same extent that interest rates
5 have fallen or to the same extent that the cost of equity may have come down for
6 the broader equity maket. The relatively lower prices for utilty shares indicate
7 that the cost of capital for utilities is higher.
8 Graph 3 further ilustrates this result by showing the cumulative
9 percentage change in the two equity indexes since the March 2009 lows.
389 Hadaway, Di- 27
Rocky Mountain Power
.
.1
2
3
4
5 Q.
6 A.
7
8
9
10
11.12
Graph 3
Dow Jones Utility Average
vs. S&P500
Cumulative % Change
Mar. 2009 - Apr. 2010
70.00% ...........................................................................................................................................................
::.::: =--==mmmmm_:m.......~1
40.00%..........................................................~..~~~~:::."..........................................."..................¡
I S&P 500 I P'~~'~'" !30.00% ......................................."'''............................................"".............................."""....."....................,~::::~=~~
i¡OJ i¡OJ . ~OJ i¡OJ i¡OJ ..1; ..~~~ ~tf ~v fb0~ ~o-4 ~fl($ ~fl"
While the S&P 500 has recovered over 60 percent (61.43%) from its March 2009
lows, utilty stock prices have increased by less than one-third that amount
(19.75%). This result again suggests the market difficulties that utilties face and
the continuing relatively higher cost of equity for utility companies.
What is the industry's current fundaental position?
The industr has seen signifcant volatilty both in terms of fundamenta operating
characteristics and the effects of the economy. While many companies have
refocused their businesses on more traditional utilty service, the effects of
deregulation of the wholesale power markets and continuing fuel price
uncertainties remain prominent. The economic crisis has also reduced sales
volumes and increased the difficulty of planning for future load requirements.
S&P reflects this volatilty in its most recent Electrc Utiity Industry Survey:
390 Hadaway, Di- 28
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21.22
23
24
25
26
27
28
29
30
31
32
33
34 Q.
35.36 A.
Standard & Poor's Industry Surveys
The S&P Electrc Utilties subindex was down 0.5% in 2009,
compared with a 23.5% increase for the benchmark S&P 500
Composite stock index and a 24.3% increase for the broader S&P
1500 SuperComposite. This followed a strong decline of 28.1 % in
2008 for the S&P Electrc Utilties subindex, versus declines of
38.5% and 38.2% for the S&P 500 and the S&P 1500,
respectively. We believe the underperformance of electrc utilty
stocks in 2009 reflected both the downturn in the economy and the
weakess in power markets, as well as the impact on earings from
abnormlly mid summer weather.
We expect the performance of both the electrc utilty sector and
the individual companies withìn the sector to remain relatively
volatile over the next several years. However, assuming that the
housing, financial, and credit markets begin to stabilze, we believe
the stocks wil be less volatile in 2010 than they were in 2008 and
2009, or during the fist few years of this decade.... *** The
performance of the sector, however, wil remain sensitive to the
macroeconomic environment and market forces surrounding it.
(Standard & Poor's Industry Surveys, Electric Utilities Februar
25,2010, page 6).
Value Line also comments on the industry's relatively poor stock price
performance:
Value Line Investment Survey
The Value Line Utilty Average underperforred the Value Line
Geometric Average by a wide margin in 2009. Things haven't
changed so far in 2010. The broad-based Value Line Geometrìc
Average is up 8%, while the Value Line Utilty Average is where it
"vas at tbe star of the year. (Value Line Investment Survey, Electrc
Utilty (Central) Industr, March 26, 2010, page 901.)
Credit maket gyrations and the volatilty of utilty shares demonstrate the
increased uncertainties that utilty investors face. These uncertainties translate
into a higher cost of capital for utilties than has been experienced in recent year.
Do utilties continue to face the operating and financial risks that existed
prior to the recent financial crisis?
Yes. Prior to the recent financial crisis, the greatest consideration for utilty
391 Hadaway, Di- 29
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.1
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5
6
7
8
9
10
11.12
13
14
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17
18
19
20
21
22
.23
investors was the industr's continuing transition to more open market conditions
and competition. With the passage of the Energy Policy Act (EPACT) in 1992
and the Federal Energy Regulatory Commssion's (FERC) Order 888 in 1996, the
stage was set for vastly increased competition in the electric utiity industry.
EPACT's mandate for open access to the transmission grid and PERC's
implementation though Order 888 effectively opened the market for wholesale
electricity to competition. Previously protected utilty service terrtory and lack of
transmission access in some pars of the countr had limited the availabilty of
competitive bulk power prices. EPACT and Order 888 have essentially
eliminated such constraints for incremental power needs.
In addition to wholesale issues at the federal level, may states
implemented retail access and opened their retail makets to competition. Prior to
the Western energy crisis, investors' concerns had focused principally on
appropriate transition mechanisms and the recovery of stranded costs.' More
recently, however, provisions for dealing with power cost adjustments have
become a larger concern.
Concern is also beginning to develop around pending clite change
legislation including the recent passage by the House of Representatives of H.R.
2454 - the American Clean Energy and Security Act of 2009, also referred to as
the Waxman-Markey bil, which has been followed by the introduction in the U.S.
Senate on May 12,2010, of the American Power Act, also called the Kerr-
Lieberman bilL. It appears increasingly likely that in the foreseeable future
climate change initiatives wil require utilities to balance a diverse set of supply-
392 Hadaway, Di- 30
Rocky Mountain Power
.1
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3
4
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21 Q.
22
.23 A.
side and demand-side resources. In paricular, utilities with significant coal-fired
generation would have the added risk of addressing a reduction in greenhouse gas
(GHGs) emissions by needing to make costly changes to existing generation fleets
such as retirng existig coal plants in favor of lower-emission alternatives,
operating higher cost supply options, purchasing domestic and/or foreign carbon
offsets, or purchasing more expensive low-or-zero emission power. In addition,
climate change legislation may require investment in a mandated percentage of
renewable energy options, whether or not the investment appears to be economic,
and would likely place added pressure on utilties to offer additional demand-side
alternatives, including energy efficiency programs, that wil reduce customers'
demand for power. Moreover, electrc utilties must continue to manage the
uncertainty of addressing sulfur dioxide, nitrogen oxides and mercury, Finally,
the Environmental Protection Agency has proposed rules in May 2010 regardig
coal combustion residue and new permt requirements for best available control
technology for GHGs.
As expected, the opening of previously protected utilty markets to
competition, the uncertnty created by the removal of regulatory protection,
continuing fuel price volatilty and concerns about the impact of climate change
legislation have raised the level of uncertinty about investment returns across the
entire industry.
Is RMP affected by these same uncertinties and increasing utilty capital
costs?
Yes. To some extent all electrc utilities are being affected by the industry's
393 Hadaway, Di- 31
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9 Q.
10
11 A..12
13
14
15
16
17
18
19
20
21
22
23.
tralsition to competition and the emphasis on protecting the environment.
Although deregulation has not occurrd in the state of Idaho, the Company's
power costs and other operating activities have been signifcantly affected by
transition and restructuring events around the countr. In fact, the uncertainty
associated with the changes that are transformng the utiity industr as a whole,
as viewed from the perspective of the investor, remain a factor in assessing any
utilty's required ROE, including the ROE from the Company's operations in
Idaho.
How do capital market concerns and financial risk perceptions affect the cost
of equity capital?
As I discussed previously, equity investors respond to changing assessments of
risk and financial prospects by changing the price they are wiling to pay for a
given securty. When the risk perceptions increase or financial prospects declie,
investors refuse to pay the previously existing market price for a company's
securities and market supply and demand forces then establish a new lower price.
The lower market price typically translates into a higher cost of capital through a
higher dividend yield requirement as well as the potential for increased capital
gains if prospects improve. In addition to market losses for prior shareholders,
the higher cost of capital is transmitted diectly to the company by the need to
ear a higher cost of capital on existing and new investment just to maintain the
stock's new lower price level and the reality that the firm must issue more shares
to raise any given amount of capital for future investment. The additional shares
also impose additional futue dividend requirments and may reduce future
394 Hadaway, Di- 32
Rocky Mountain Power
.1
2
3 Q.
4
5 A.
6
7
Table 4
Authorize Electric Utilty Equity Returns
2006 2007 2008 2009
1st Quarer 10.38%10.27%10.45%10.29%
2nd Quarer 10.68%10.27%10.57%10.55%
3rd Quarter 10.06%10.02%10.47%10.46%
4thOuarer 10.39%10.56%10.33%10.54%
Full Year Average 10.36%10.36%10.46%10.48%.Average Utilty
Debt Cost 6.08%6.11%6.65%6.28%
Indicated Average
Risk Premium 4.28%4.25%3.81%4.20%
.
earings per share growth prospects if the proceeds of the share issuance are
unable to earn their expected rate of retu.
How have regulatory commissions responded to these changing market and
industry conditions?
Over the past five years, average allowed equity returns have fluctuated in a
relatively narrow range. Table 4 provides a quarer-by-quarer summar of the
results:
2010
10.66%
10.66%
5.88%
4.78%
Source: Regulatory Focus, Regulatory Research Associates, Inc., Major Rate Case
Decisions, April 1, 2010. Utilty debt costs are the "average" public utility bond
yields as reported by Moody's.
8 Since 2006, equity risk premiums (the difference between allowed equity retus
9 and utilty interest rates) have ranged from 3.81 percent to 4.78 percent.
10 Cost of Equity Capital for RMP
11 Q.
12 A.
What is the purpose of this section of your testimony?
The purose of this section is to present my quantitative studies of the cost of
13 equity capital for the Company and to discuss the details and results of my
14 analysis.
395 Hadaway, Di- 33
. Rocky Mountain Power
.1 Q.
2 A.
3
4
5
6
7 Q.
8 A.
9
10
11.12
13
14
15
16
17
18
19
20
21
22
23.
How are your studies organized?
In the first par of my analysis, I apply thee versions of the DCF model to a 22-
company group of electric utilties base on the selection criteria discussed
previously. In the second par of my analysis, I present my risk premium analysis
and review projected economic conditions and projected capita costs for the
coming year.
Please describe your DCF analysis.
My DCF analysis is based on thee versions of the DCF modeL. In the first
version of the DCF model, I use the constat growt format with long-term
expected growth based on analysts'. estimates of five-year utilty earings growth.
While I continue to use a longer-term growth estimation approach based on
growth in overall gross domestic product, I also rely on the DCF results with
analysts' growth rates because this is the approach that has traditionally been used
by many regulators. Because the analysts' growt estimates are objective,
verifiable forecasts provided by independent third pares, this approach can
minimize disputes among the paries about the appropriate inputs to and
application of the modeL.
In the second version of the DCF model, again a constat growth format,
for the estimated growth rate I use the estimated long-term ODP growth rate. In
the third version of the DCF model, I use a two-stage growth approach, with stage
one based on Value Line's thee-to-five-year dividend projections and stage two
based on long-term projected growth in ODP. The dividend yields in all thee of
the annual models are from Value Line's projections of dividends for the coming
396 Hadaway, Di- 34
Rocky Mountain Power
.1
2
3
4 Q.
5
6 A.
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30.31
32
year and stock prices are from the thee-month average for the months that
correspond to the Value Line editions from which the underlying financial data
are taken.
Why do you use the long-term GDP growth rate to estimate long-term
growth expectations in the DCF model?
Growth in nominal GDP (real GDP plus inflation) is the most general measure of
economic growth in the U.S. economy. For long time periods, such as those used
in the Morningstar/lbotson Associates rate of return data, GDP growth has
averaged between 5 percent and 8 percent per year. From this observation,
Professors Brigham and Houston offer the following observation concerning the
appropriate long-term growth rate in the DCF Model:
Expected growth rates var somewhat among companies, but
dividends for matue firs are often expected to grow in the future
at about the same rate as nominal gross domestic product (real
GDP plus inflation). On this basis, one might expect the dividend
of an average, or "normal," company to grow at a rate of 5 to 8
percent a year. (Eugene F. Brigham and Joel F. Houston,
Fundamentals of Financial Management, 11th Ed. 2007, page
298.)
Other academic research on corporate growth rates offers similar conclusions
about GDP growth as well as concerns about the long-term adequacy of analysts'
forecasts:
Our estimated median growth rate is reasonable when compared to
the overall economy's growth rate. On average over the sample
period, the median growth rate over 10 years for income before
extraordinar items is about 10 percent for all firs... After
deducting the dividend yield (the median yield is 2.5 percent per
year), as well as inflation (which averages 4 percent per year over
the sample period), the growth in real income before extraordinar
items is roughly 3.5 percent per year. This is consistent with the
historical growth rate in real gross domestic product, which has
averaged about 3.4 percent per year over the period 1950-1998.
397 Hadaway, Di- 35
Rocky Mountain Power
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3
4
5
6
7
8
9
10
11
12
13
14
15.16 Q.
17 A.
18
19
20
21
22
23
24
25
26
.
(Louis K. C. Chan, Jason Karceski, and Josef Lakonishok, "The
Level and Persistence of Growth Rates," The Joural of Finance,
April 2003, p. 649)
IBES long-term growth estimates are associated with realized
growth in the imediate short-term future. Over long horions,
however, there is little forecastability in earngs, and analysts'
estimates tend to be overly optimistic... On the whole, the absence
of predictabilty in growth fits in with the economic intuition that
competitive pressures ultimately work to correct excessively high
or excessively low profitabilty growth. (Ibid, page 683)
These findings support the notion that long-term growth expectations are more
closely predicted by broader measures of economic growth than by near-term
analysts' estimates. Especially for the very long-term growth rate requirements of
the DCF model, the growth in nominal GDP should be considered an important
input.
How did you estimate the expected long-run GDP growth rate?
I developed my long-term GDP growth forecast from nominal GDP data
contained in the St. Louis Federal Reserve Ban data base. That data for the
period 1949 though 2009 are summarzed in my Exhibit No. 12. As shown at the
bottom of that exhibit, the overall average for the period was 6.9 percent. The
data also show, however, that in the more recent years since 1980, lower infation
has resulted in lower overall GDP growth. For this reason I gave more weight to
the more recent years in my GDP forecast. This approach is consistent with the
concept that more recent data should have a greater effect on expectations. Based
on this approach, my overall forecast for long-term GDP growth is 90 basis points
lower than the long-term average, at a level of 6.0 percent.
398 Hadaway, Di- 36
Rocky Mountain Power
.1 Q.
2
3
4 A.
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22.23
The DCF model requires an estimate of investors' long-term growth rate
expectations. Why do you believe your forecast of GDP growth based on
long-term historical data is appropriate?
There are at least thee reasons. First, most econometrc forecasts are derived
from the trending of historical data or the use of weighted averages. This is the
approach I have taen in Exhibit No. 12. The long-run historical average ODP
growth rate is 6.9 percent, but my estimate of long-term expected growth is only
6.0 percent. My forecast is lower because my forecasting method gives much
more weight to the more recent 10- and 20-year periods.
Second, some curently lower ODP growth forecasts likely understate very
long growth rate expectations that are required in the DCF modeL. Many of those
forecasts are curently low because they are based on the assumption of
permnently low inflation rates, in the range of 2 percent. As shown in my
Exhibit No. 12, the average long-term inflation rate has been over 3 percent in all
but the most recent 20 years.
Finally, the current economic tuoil maes it even more importt to
consider longer-term economic data in the growth rate estimate. As discussed in
the previous section, current near-term forecasts for both real ODP and inflation
are severely depressed. To the extent that the longer-term outlooks of
professional economists are also depressed, their forecasts may be understated.
Under these circumstances, a longer-term view is even more important. For all
these reasons, while I am also presenting other growth rate approaches based on
analysts' estimates in this testimony, I believe it is appropriate also to consider
399 Hadaway, Di- 37
Rocky Mountain Power
.1
2 Q.
3 A.
4
5
6
7
8
9
10
11.12
13 Q.
14 A.
15
16
17
18
19
20
21
22
.
long-term GDPgrowth in estimating the DCF growth rate.
Please summarize the results of your DCF analyses.
The DCF results for my comparable company group are presented in Exhibit No.
13. As shown in the fist column of page 1 of that exhibit, the trditional constant
growth model indicates an ROE of 10.3 percent to 10.5 percent. In the second
column of page 1, I recalculate the constant growth results with the growth rate
based on long-term forecasted growth in GDP. With the GDP growth rate, the
cOnstant growth model indicates an ROE range of 10.7 percent to 10.8 percent.
Finally, in the third colum of page 1, I present the results from the multistage
DCF modeL. The multistage model indicates an ROE of 10.6 percent. The results
from the DCF model, therefore, indicate a reasonable ROE range of 10.3 percent
to 10.8 percent.
What are the results of your equity risk premium studies?
The details and results of my equity risk premium studies are shown in Exhibit
No. 14. These studies indicate an ROE range of 10.39 percent to 10.59 percent.
The Federal Reserve System's continuing "easy money" policies have provided
renewed liquidity in the credit makets that is reflected in these lower yields.
These results are slightly below the average DCF results, which continues to
demonstrate the equity market risk aversion that is reflected in contiuing
volatilty and relatively low stock prices for utilty shares. These circumstaces
indicate that the cost of equity capital has not declined to the same extent as the
yields on utilty debt.
400
Hadaway, Di- 38
Rocky Mountain Power
.1 Q.
2 A.
3
4
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22
23.
How are your equity rik premium studies structured?
My equity risk premium studies are divided into two parts. First, I compare
electric utility authorized ROEs for the period 1980-2009 to contemporaneous
long-term utilty interest rates. The differences between the average authorized
ROEs and the average interest rate for the year is the indicated equity risk
premium. I then add the indicated equity risk premium to the forecasted and
current single-A utilty bond interest rate to estimate ROE. Because there is a
strong inverse relationship between equity risk premiums and interest rates (when
interest rates are high, risk premiums are low and vice versa), fuer analysis is
required to estimate the curent equity risk premium leveL.
The inverse relationship between equity risk premiums and interest rate
levels is well documented in numerous, well-respected academic studies. These
studies typically use regression analysis or other statistical methods to predict or
measure the equity risk premium relationship under varing interest rate
conditions. On page 3 of Exhibit No. 14, I provide regression analyses of the
allowed annual equity risk premiums relative to interest rate levels. The negative
and statistically significant regression coeffcients confir the inverse relationship
between equity risk premiums and interest rates. Ths means that when interest
rates rise by one percentage point, the cost of equity increases, but by a smaller
amount. Similarly, when interest rates decline by one percentage point, the cost
of equity declines by less than one percentage point. I use this negative interest
rate change coefficient in conjunction with current interest rates to establish the
appropriate current equity risk premium.
401 Hadaway, Di- 39
Rocky Mountain Power
.1 Q.Please summarize the results of your cost of equity analysis.
2 A.My results are summarzed in Table 5 below:
TableS
Summary of Cost of Equity Estimates
DCF Analysis Indicated Cost
Constant Growth (Analysts' Growth)10.3%-10.5%
Constant Growth (GDP Growth)10.7%-10.8%
Multistage Growth Model 10.6%
Reasonable DCF Range 10.3%-10,8%
Equity Risk Premium Analysis Indicated Cost
Projected Utiity Debt Yield + Equity Risk Premium
Equity Risk Premium ROE (6.19% + 4.40%)10.59%
Curent Utilty Debt + Equity Risk Premium
Equity Risk Premium ROE (5.84% + 4.55%)10.39%
RMP Estimated ROE 10.6%
3 Q.How should these results be interprete to determine the fair cost of equity.4 for the Company?
5 A.The recent maket tuoil and the continuing effects on capital market conditions
6 make it difficult to strictly interpret quantitative model estimates for the cost of
7 equity. While corporate interest rates have dropped from the levels that existed in
8 late 2008, the DCF results, based on continuing relatively low utility stock prices,
9 show that the cost of equity has not declined as much as utilty bond yields.
10 Under these conditions, use of a lower DCF range or equity risk premium
11 estimates based strictly on historical risk premium relationships likely understate
12 the cost of equity. From this perspective, and with consideration of the
13 Company's on-going capital requirements, I estimate the fair and reasonable cost
14 of equity capital to be at least at the approximate mid-point of my DCF range and.15 at the upper end of my risk premium range. This leads to a point estimate of 10.6
402
Hadaway, Di- 40
Rocky Mountain Power
.
.
.
1
2 Q.
3 A.
percent as the market required ROE for the Company.
Does this conclude your testimony?
Yes, it does.
403
Hadaway, Di- 41
Rocky Mountain Power
.1 Introduction and Purpose of Testimony
2 Q. Are you the same Samuel C. Hadaway who submitted direct testimony in this
3 proceeding?
4 A.Yes.
5 Q.What is the purpose of your rebuttal testimony?
6 A.The purose of my rebuttl testimony is to respond to the rate of retu on equity
7 ("ROE") recommendations offered by Idaho Public Utilities Commission Staff
8 witness Ms. Terr Carlock and Monsanto witness Mr. Michael P. Gorman. In my
9 analysis, I wil demonstrate that their rate of return recommendations are not
10 consistent with the ongoing equity market volatility or the continuing financial
11 distress that the u.s. economy is undergoing. I wil also respond to the other.12 witnesses' comments on the methodology I used in my direct testimony to
13 estimate Rocky Mountain Power's cost of equity and I will update my ROE
14 analysis for curent market costs and conditions.
15 Review of Other Parties' Recommendations
16 Q.
17 A.
18
19
20
21
22.23
What are the parties' ROE recommendations?
Ms. Carlock recommends a 10.0 percent ROE and Mr. Gorman recommends an
ROE of 9.5 percent. As I wil explain in my updated ROE analysis, the
Company's initially requested 10.6 percent ROE remains well supported by my
updated DCF analysis. Although my risk premium results are lower, I discount
those results due to the ongoing equity market tuoil and the artificially low
interest rates that have resulted from the governent's expansionary monetary
policy, which I will discuss later in this testimony.
Hadaway, Di-Reb - 1
404 Rocky Mountain Power
.1 Q.What is your general asessment of the other parties' ROE
2 recommendations?
3 A.Their recommendations are well below Rocky Mountain Power's cost of equity.
4 By comparison, their recommendations are much lower than recently allowed
5 ROEs for other integrated electrc utilities around the countr. I will show that
6 their analyses and recommendations are faulty because they use negatively biased
7 model inputs and they fail to reasonably consider the ongoing effects of the recent
8 financial crisis. Additionally, I will provide updated data and analysis, which
9 shows that Rocky Mountain Power's current cost of equity is in the range of 10.3
10 percent to 10.8 percent. These factors demonstrate the uneasonably low natue
11 ofthe other partes' recommendations..12 Q.Why are their recommendations not consistent with current capital market
13 costs and conditions?
14 A.Contrary to the other parties' apparent beliefs, the cost of equity cannot be
15 measured by simply extrapolating artificially low, governent policy induced
16 interest rates to ROE. A more realistic view of curent market conditions and
17 more plausible input assumptions show that the other parties' recommendations
18 are well below the reasnable range. Relative to the downward trend in
19 Treasures and high grade utility bond yields, the cost of equity has not declined
20 as much.
21 Ms. Carlock and Mr. Gorman appear to believe that the cost of equity has
22 dropped in lockstep with declining interest rates. This contention is simply.23 wrong.The most recently reported data from Regulatory Research Associates
Hadaway, Di-Reb - 2
405 Rocky Mountain Power
.
.
.
1 shows that for the first nine months of201O, the average allowed ROE for electrc
utilities was 10.36 percent.1 The most recently allowed ROE in Idaho has been2
3 10.5 percent (Avista Corp., Case No. A VU-E-09-01, decided July 17,2009 and
4 Idaho Power, Case No. IPC-E-08-lO, decided January 30,2009).
5 Economic and Market Conditions
6 Q.In your direct testimony, you provided data to ilustrate interest rate trends
7 and the spreads between U.S. Treasury bond and single-A rated utilty
8 bonds. Have you updated that information?
9 A.Yes. I provide that data in Exhibit No. 57, page 1. Table 1 below sumarizes the
10 results.
1 Regulatory Focus, Regulatory Research Associates, October 4,2010.
406
Hadaway, Di-Reb - 3
Rocky Mountain Power
.
.
Month
Jan-08
Feb-08
Mar-08
Apr-08
May-08
Joo-08
Jul-08
Aug-08
Sep-08
Oct-08
Nov-08
Dec-08
Jan-09
Feb-09
Mar-09
Apr-09
May-09
Joo-09
Jul-09
Aug-09
Sep-09
Oct-09
Nov-09
Dec-09
Jan-1O
Feb-1O
Mar-1O
Apr-1O
May-l0
Joo-1O
Jul-1O
Aug-1O
Sep-1O
Oct-1O
3-Mo Avg
12-Mo Avg
Table 1
Long-Term Inerest Rate Trends
Single-A
Util Rate
6.02
6.21
6.21
6.29
6.28
6.38
6.40
6.37
6.49
7.56
7.60
6.52
6.39
6.30
6.42
6.48
6.49
6.20
5.97
5.71
5.53
5.55
5.64
5.79
5.77
5.87
5.84
5.81
5.50
5.46
5.26
5.01
5.01
5.10
5.04
5.51
30-Year
Treasur Rate
4.33
4.52
4.39
4.44
4.60
4.69
4.57
4.50
4.27
4.17
4.00
2.87
3.13
3.59
3.64
3.76
4.23
4.52
4.41
4.37
4.19
4.19
4.31
4.49
4.60
4.62
4.64
4.69
4.29
4.13
3.99
3.80
3.77
3.87
3.81
4.27
Single-A
Util Spread
1.69
1.69
1.82
1.85
1.68
1.69
1.83
1.87
2.22
3.39
3.60
3.65
3.26
2.71
2.78
2.72
2.26
1.68
1.56
1.34
1.34
1.36
1.33
1.30
1. 17
1.25
1.20
1.12
1.21
1.33
1.27
1.21
1.24
1.23
1.23
1.24
Soures: Mergent Bond Record (Util Rates); ww.federalrsere.gov (Treasur Rates).
The month average is for Augt 2010 - October 2010.
Twelve mont average is for November 2009 - October 2010..Hadaway, Di-Reb - 4
407 Rocky Mountain Power
.1
2
3
4
5
6
7
8
9 Q.
10
11.12 A.
13
14
15
16
17 Q.
18 A.
19
20
21
22
.23
The data in Table 1 vividly ilustrate the market turmoil that has occured. Over
the past two years, interest rates have fluctuated widely. The Federal Reserve's
effort to reduce borrowing costs for banks (the Fed Funds rate) and lower the
yields on U.S. Treasur bonds have now extended to high quality corporate
borrowers as welL. While the effects of market tubulence may not be easily
captued in financial models for estimatig the rate of return, equity market
tubulence and continuing elevated risk aversion. should be considered explicitly
in estimates of the cost of equity capitaL.
Do the smaller spreads between yields on single-A utilty bonds and U.S.
Treasury bonds mean that the markets have fully recovered from the
economic turmoil that resulted from the financial crisis?
No. While markets have stabilized from the near-chaotic conditions that existed
in late 2008, investors remain concerned about high unemployment, large federal
deficits, and the potential for further fallout from foreclosures and other effects of
the financial, crisis. Although it is diffcult to measure these factors directly, they
should not be ignored as Ms. Carlock and Mr. Gorman have done.
What do economic and interest rate forecasts show for the coming year?
In Exhibit No. 57, page 2, I provide Standard and Poor's (S&P) most recent
economic forecast from its Trends & Projections publication for October 2010.
The S&P forecast reflects the significant economic contraction that occurred in
2009, with a drop in real GDP of2.6 percent. For all of2010 and 201 1, S&P
forecasts that real GDP will increase by 2.7 percent and 2.5 percent, respectively.
While this forecast does not reflect a full "double-dip" recession for the remainder
Hadaway, Di-Reb - 5
408 Rocky Mountain Power
of 20 I 0 and into 2011, the lack of further expansion in 2011 is a more pessimistic
outlook than S&P had previously provided. The S&P forecast now delays the
resumption of more robust growth until the 3rd and 4th Quarters of2011.
Consistent with S&P's pessimistic outlook for the economy, its long-term
interest rate forecasts have also declined. Table 2 below summarizes the interest
rate forecasts:
Table 2
Standard & Poor's Interest Rate Forecast
Oct. 20 I 0 Average Average
Average 20 I 0 Est. 20 I 1 Est.Treasur Bils 0.1 % 0.1 % 0.3%lO-Yr. T-Bonds 2.5% 3.1% 2.5%30-Yr. T-Bonds 3.9% 4.1% 3.5%Aaa Corporate Bonds 4.7% 4.8% 4.3%
Sources: www.federalreserve.gov, (Current Rates). Standard & Poor's
Trends & Projections, October 2010, page 8 (Projected Rates).
The data in Table 2 shows that S&P expects, durng 2011, that long-term
Treasury interest rates will drop an additional 40 basis points from their recent
(October 2010) low levels. Although in the tubulent market environment it is
diffcult to project interest rates, a much slower economic recovery and
continuing governent "easy money" policies are reflected in the S&P
projections.
Have you updated the graph from your direct testimony that shows how
utilty stocks have performed during the past several years?
Yes. Utility stock prices have remained volatile and have recovered less, relative
to the broader market indices, from the March 2009 low point. The wider utility
stock price fluctuations in the more recent years are vividly ilustrated in the
Hadaway, Di-Reb - 6
409 Rocky Mountain Power
.I
2
.
3
4
5
6
7 Q.
8
9 A.
10.11
Graph 1 below, which depicts the Dow Jones Utility Average (DJUA) over the
past 25 years.
Graph 1
Dow Jones Utilty Average
1986-2010
600
500
400
300
200
100
o
tpfòdf /~~lfo lfClri ""cl _~'öo d 0-
!b""OJ
0(3 d-i~ o#'~ o~ ¿l'ö 0#''l df..~
In this environment, investors' retu expectations and requirements for providing
capital to the utility industr remain high relative to the longer-term, traditional
view ofthe utility industr. Increased market volatility for utility shares causes
investors to require a higher rate of return.
How have utilty stocks performed relative to the overall market recovery
since March 2009?
Utility stock prices have lagged behind the overall market as well. Graph 2 shows
the monthly levels for the DJUA versus the broader market S&P 500 index since
the market lows that occurred in February and March of 2009.
Hadaway, Di-Reb - 7
410 Rocky Mountain Power
.
.
.
Graph 2
Dow Jones Utilty Average
vS.S&P500
Mar. 2009 -Oct. 2010
1400.00
~"~ #~..~. . .... ~"....~~..~.. ~ ..."'~.. ~~....~'S -~ ~~ _: ~~ I I~~"~. S&P 500
1200.00
1000.00
800.00
600.00
400.00
¡~
..
IDJUA I 200.00
0.00
r;~ r;~ r;~ r;~ _r;~ ~~ ~~ ~~ ~~ M..t)~~ ')~(: 't~Cb el Qrt ~# ~~ ')~(l ~cs of;r
1 While the S&P 500 has increased significantly since its lowest level in March
2 2009, utility prices have increased less than one-half as much. This result is a
3 fuher indication that the cost of equity for utility companies has not declined to
4 the same extent that interest rates have fallen or to the same extent that the cost of
5 equity may have come down for the broader equity market. The relatively lower
6 prices for utility shares indicate that the cost of capital for utilities is higher.
7 Graph 3 further ilustrates this result by showing the cumulative
8 percentage change in the two equity indexes since the March 2009 lows.
411
Hadaway, Di-Reb - 8
Rocky Mountain Power
.
1.2
3
4
5 Q.
6
7
8 A.
9
10
.
Graph 3
Dow Jones Utilty Average
vs. S&P 500
Cumulative % Change
Mar. 2009 - Oct. 2010
I'.................................................................................................................................................
,'§~/
#'~'~
............
t"
~ ~Çj l'Cl _# c?Cl "i. ~..I.~ ')'S ~ (J (;6 ~JI ~..i. ..i. ..i.," ,.. _R'')~~ ,.~Cf (J
70.00%
60.00%
50.00%
40.00%
30.00%
20.00%
10.00%
0.00%
While the S&P 500 has recovered over 60 percent (60.97%) from its March 2009
lows, utility stock prices have increased by only about 25 percent (24.97%). This
result again points out the market difficulties that utilities face and the continuing
relatively higher cost of equity for utility companies.
How do the other parties' ROE recommendations in this case compare to the
rates of return authorized by other state utilty commissions around the
country?
They are substantially lower. Over the past five years, quarterly average allowed
ROEs have generally been in the 10.4 percent to 10.5 percent range. Recently
allowed average rates for integrated electric utilities have been approximately
412
Hadaway, Di-Reb - 9
Rocky Mountain Power
.
. 20
.
1 10.4 percent,2 Table 3 below sumarizes the ROE data, including both delivery
2 and fully integrated companies:3 Table 3
4 Authorized Electrc Utility Equity Retus5 2006 2007 2008
6 1st Quarter 10.38% 10.27% 10.45%
7 2nd Quarter 10.68% 10.27% 10.57%
8 3rd Quarter 10.06% 10.02% 10.47%
9 4th Quarter 10.39% 10.56% 10.33%
10 Full Year Average 10.36% 10.36% 10.46%
I 1 Average Utility
12 Debt Cost 6.08% 6. 11 % 6.65%
13 Indicated Average
14 Risk Premium 4.28% 4.25% 3.81 %
15
16 Source: Regulatory Focus, Regulatory Research Associates, Inc., Major Rate
17 Case Decisions, October 4,2010. Utility debt costs are the "average" public
18 utility bond yields as reported by Moody's.
2009 2010
10.29%10.66%
10.55%10.08%
10.46%10.27%
10.54%
10.48%10.36%
6.28%5.59%
4.20%4.77%
19 The 10.0 percent ROE recommended by Ms. Carlock is below the national
averages and the 9.5 percent ROE recommended by Mr. Gorman is in stark
21 contrast to the cost of equity capital deemed appropriate by state regulators
22 around the countr.
23 Current Deficiencies of the CAPM and Other Equity Rik Premium Models
24 Q.Mr. Gorman uses the CAPM to estimate ROE. Can you explain why the
25 CAPM currently understates ROE and why CAPM estimates should not
26 currently be included?
27 A.Yes. The CAPM requires three inputs to estimate ROE:
28 1) the risk-free interest rate (Rr);
29 2) the market risk premium for stocks relative to the risk-free rate (Rm - Rr); and
2 See Exhibit No. 57, page 3.
413
Hadaway, Di-Reb - 10
Rocky Mountain Power
.1
2
3) a measure of market-related, or nondiversifiable, risk (ß or beta).
The CAPM estimate of ROE is calculated from the following equation:
3 ROE = Rf + ß(Rm - Rf)
4 Under present market conditions, and as applied by the other partes in their
5 CAPM analyses, all three of the CAPM inputs tend to understate ROE. The risk-
6 free rate, Rf, is understated because, due to the governent's easy money policies
7 and investors' flight to safety, the U.S. Treasur yields used for Rf are artificially
8 low. The second input, the market risk premium (Rm - Rr) is also understated.
9 This is the case because Mr. Gorman bases his market risk premium estimates on
10 historical data and prior academic studies that cannot possibly reflect the recent
11 market turmoiL. While there is no objective source for measurng the widening.12
13
equity risk premium phenomenon, the volatility of utility stock prices
demonstrated in the graphs above are indicative of the effect. Finally, the
14 CAPM's market risk factor, ß, is depressed by the relatively poor market
15
16
17 Q.
18
19 A.
20
21
22.23
performance that utilities have provided. In this envionment, CAPM and other
equity risk premium estimates of ROE understate the cost of equity.
Do many of these same issues affect traditional bond-yield plus equity-risk
premium estimates of ROE?
Yes. Governent and utility bond interest rates are tyically the foundation for
traditional equity risk premium models. To the extent that such rates are
artficially reduced by the governent's expansionary monetary policy, risk
premium estimates of ROE wil be understated. The wide divergence between
DCF model results and equity risk premium results is a reflection of this
Hadaway, Di-Reb - 11
4 14 Rocky Mountain Power
condition. While there is no widely accepted model to measure the wider equity
risk premiums required to balance this anomaly, it is clear that both the CAPM
and traditional equity risk premium models curently understate the cost of equity
capitaL.
This anomaly is similar in natue to why cost of equity analysts exclude
companies that are involved in a merger or acquisition from their proxy groups.
The stock prices of such companies will move towards the trnsaction price per
share as the likelihood of the transaction occurng increases. Thus a DCF or
CAPM analysis will be distorted because the stock price of the utility (and the
resulting beta) is responding to the terms of the merger agreement, not to the
fudamentals of investor expectations. In an analogous manner, when the Federal
Reserve manipulates interest rates, bond yields respond to the Federal Reserve's
actions, not investor expectations and the yields of fixed income securities are
distorted.
Rebuttal of Staff Witness Carlock
16 Q.
17 A
18
19
20
21
22.23
What is the basis for Ms. Carlock's 10.0 percent ROE?
Ms. Carlock uses the traditional constant growth DCF model and a comparable
earnings (CE) approach. She fids the reasonable ROE range to be 9.5 percent to
10.5 percent. She selects the midpoint of that range, 10.0 percent, as her final
ROE recommendation (Carlock Direct at 2, line 25 to 3, line I). From her
analysis, she finds a DCF estimate of9.3 percent (Carlock Direct at 20, lines 3-4).
She states that her CE approach provides a range of 8.6 percent to 9 percent for
western utilities and about 10.5 percent for Value Line electrc utilities with
Hadaway, Di-Reb - 12
415 Rocky Mountain Power
.1
2
3 Q.
4 A.
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
.
.
financial strength of "A." From these results she concludes that the CE range
should be 9.0 percent to 10.5 percent.
What is your general impression of Ms. Carlock's testimony?
A DCF approach with a CE test of reasonableness at times may be adequate, as
noted above. However, Ms. Carlock should have given more consideration to
recent economic conditions and her ROE estimate should have been higher. The
10.5 percent expected earnings rate for the Value Line electrcs with financial
strength of "A," which she notes in her CE analysis (Carlock Direct at 18, lines 5-
7), is more like the allowed rates of retu for other utilities around the countr
and it is more consistent with investors' expectations for integrated electrc
utilities like RMP.
The much lower earned retu for her western utility group appear to be
anomalous. This point is made clear upon a review of Ms. Carlock's workpapers.
Here, it is seen that the 2009 earned retu data for her western group includes
returns as low as 3.2 percent (PNM Resources), 5.7 percent (N Energy), and 5.8
percent (Hawa;iian Electrc). These returns are near, and in the case ofPNM
Resources, even below the curent cost of single-A debt, making them completely
unsuitable for consideration in a reasonable cost of equity analysis. Finally, the
8.6 percent to 9.0 percent range she finds for the western group is far below any
allowed ROE for any integrated electrc utility in the U.S.
Begining on page 17, line 25, Ms. Carlock states:
"Authoried retus by State Commissions for electrc utilities
durng the last quarter of2009 and 2010 to date, range from 9.4%
416
Hadaway, Di-Reb - 13
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10
11
12.13
14
15
16
17
18
19
20
21
.
in Connecticut to 11.0% in Michigan. Many of the decisions
authorized aretu on equity between 10% and 10.25%."
These data bear further explanation. The lowest allowed ROE (9.4%) that Ms.
Carlock cites from Connecticut is not representative because it is for a
distrbution-only company. Distrbution-only companies are believed by the
rating agencies to have lower operating risks than integrated utilities and, as a
group, they have received lower allowed ROEs. As shown in the detailed data
from Regulatory Research Associates which support page 3 of Exhibit No. 57, for
vertically-integrated utilities, like RMP, there have been 42 rate cases durg the
time frame referred to by Ms. Carlock and the average allowed ROE has been
10.48 percent. 3 Many more decisions have resulted in authorized ROEs at or
above 10.25 percent (31 cases), than below 10.25 percent (11 cases). While a few
decisions have been around 10.0 percent, the majority of decisions have been
above 10.25 percent rather than in the 10.0 percent to 10.25 percent range
mentioned by Ms. Carlock.
Her DCF results are also questionable. The growth rates in that analysis
are low because she uses only Value Line growth rate data, which indicates' a
growth rate of only 4.4 percent. Also, for one of her two dividend yields, she uses
Value Line's projected yields for 3-5 years in the futue, which are lower than
current actual dividend yields and are not likely consistent with investors' curent
yield requirements given the recently depressed levels of utility stock prices.
3 See page 14 of the proprietar version of Dr. Hadaway's rebuttl workpaper.
417
Hadaway, Di-Reb - 14
Rocky Mountain Power
.1 With more consideration for these factors, Ms. Carlock could have found an ROE
2 well above 10.0 percent.
3 Q.You criticize the other parties' lack of cOlÌsideration for current economic
4 conditions. What does Ms. Carlock say about the economy?
5 A.On page 15, she offers a brief discussion of interest rates and stock market levels.
6 She says that interest rates have been low durng 2010. She also notes that the
7 Dow Jones Industral Average reached a peak of over 14,000 in 2007 and as of
8 October 4,2010 was at a level of 10,751. She does not acknowledge that this
9 weak stock market performance implies a higher cost of equity. Although, due to
10 governent expansionary monetary policy, interest rates have declined to their
11 lowest levels in many years, stock market investors remain highly risk averse. In.12 this environment, the equity market's required risk premium is larger, not lower.
13 Ms. Carlock might have reached a higher conclusion about RMP's cost of equity
14 if she had taken a broader view of market conditions.
15 Q.How does Ms. Carlock determine the growth rate in her DCF model?
16 A.For her growth, she uses Value Line's projected growth rates in cash flow,
17 earnings, dividends, and book value. Although the calculation is not shown in her
18 testimony, in her work papers she shows the average result to be 4.4 percent (see
19 the average of growt rates in colum I of the DCF tab in the "P AC-E-l 0-
20 7 _TCarlock_ Workpapers.xls" workpaper fie provided by Ms. Carlock).
21 Q.Would Ms. Carlock have found a higher growth rate if she had considered
22 other growth rate sources?.23 A.Yes. There are at least three areas that should be considered in evaluating Ms.
Hadaway, Di-Reb - 15
418 Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22
.
Carlock's DCF growth rate estimate. First, several of her growt rate
observations are lower than any investor would expect for long-term growth in the
DCF modeL. For example, Value Line's average projection for dividend growth
for her 15-company "A" group is only 3.68 percent, and for seven of her
companies that grwth rate is less than 3 percent. Such low relatively near-term
growth rate projections are not consistent with the long-term, steady-state growth
rates required in the DCF modeL.
As a second issue, other analysts' growth rate projections, beyond those
provided by Value Line, are readily available on-line at no cost. In my updated
DCF analysis in Exhibit No. 59, page 2, I average Value Line's projected earnings
growth with similar estimates from Zacks and Thomson FinanciaL. That average
for my comparable group of single-A rated companies is 5.52 percent. Had Ms.
Carlock included other analysts' growth estimates in her calculations, she would
have found higher average growth, which would have produced a ~ubstantially
higher ROE estimate.
Finally, many regulatory economists are now also including more broadly-
based growth rate sources, such as the projected growth rate in gross domestic
product (GDP). The FERC has used this growth rate, along with analysts' growth
projections, for many years in gas pipeline cases. While we disagree on the level,
Mr. Gorman and I have routinely used GDP growth as one of our long-term
growth estimates for the past several years. My estimate of the expected GDP
long-term growth rate (6.0%) is shown in my Direct Testimony Exhibit No. 12.
Hadaway, Di-Reb - 16
4 19 Rocky Mountain Power
.1
2
3 Q.
4
5 A.
6
7
8
9
10
11.12
13
14 Q.
15
16
17
18 A.
19
20
21
22.
Ms. Carlock's DCF growth rate and her DCF ROE estimates would have been
higher if she had included a broader-based growth rate assessment.
Why do you disagree with Ms. Carlock's using a 3,;5 year future dividend
yield in her analysis?
The projected yield from Value Line's 3-5 year forecast is lower than current
market yields because it is based on utility stock prices that Value Line projects
for the 2013-2015 time period. For her group, the dividend yield based on 2009
data is 4.95 percent, but the 2013-2015 yield is only 4.39 percent. The 4.39
percent yield is not consistent with what investors are curently payig for utility
stocks and, therefore, it is not representative of the current cost of equity capitaL.
For my comparable group, as shown in Exhibit No. 59, the updated dividend yield
with stock prices through September is 4.8 percent to 4.9 percent, about the same
as Ms. Carlock's 2009 dividend yield.
What would Ms. Carlock's DCF analysis have indicated if she used only her
2009 dividend yield (4.95 %) or your average 2010 dividend yield (4.77 % )
with the 5.52 percent average of analysts' growth projections from your
Exhibit No. 59?
Her DCF range would have been 10.29 percent to 10.47 percent (4.77% yield +
5.52% growth = 10.29% ROE and 4.95% yield + 5.52% growth = 10.47% ROE).
This range would have been much closer to the 10.5 percent CE check of
reasonableness that Ms. Carlock found for her "A" fmancial strength Value Line
electrc utility group.
Hadaway, Di-Reb - 17
420 Rocky Mountain Power
.
.
.
1 Q.Please summarize your rebuttal of Ms. Carlock?
2 A.Ms. Carlock's 10.0 percent ROE recommendation does not adequately consider
3 the ongoing equity market effects that have lingered from the recent financial
4 crisis. She seems to base her recommendation on a belief that much lower
5 governent-induced interest rates should translate directly to a lower cost of
6 equity. While equity costs have declined somewhat from the near-chaotic
7 conditions that existed in late 2008 and early 2009, they have not dropped in
8 lockstep with interest rates. Ms. Carlock's limited DCF growt rate analysis and
9 use of one dividend yield from the 2013-20 I 5 time period should be reconsidered
10 and her CE check of reasonableness for the "A" financial strength Value Line
11 electrc utility group should be given more weight.
12 Rebuttal of Monsanto Witness Gorman
13 Q. What is the basis for Mr. Gorman's 9.5 percent ROE recommendation?
14 A.Mr. Gorman's results are sumarized on page 37 of his testimony. Based on two
15 constant growth and one multi-stage growth DCF models, a risk premium
16 analysis, and the CAPM, he concludes that the reasonable ROE range is 9.1
17 percent to 9.9 percent with a midpoint of9.5 percent.
18 Q.What is your genera assessment of Mr. Gorman's ROE testimony and
19 recommendation?
20 A.Mr. Gorman's recommendation is far below RMP's cost of equity. His
21 recommendation is understated because he employs negatively biased model
22 inputs and he includes the results from one model, the CAPM, that are curently
23 uneliable. In addition, even ifthere were no Federal Reserve activity distortng
Hadaway, Di-Reb - 18
421 Rocky Mountain Power
.I
2
3
4
5
6 Q.
7 A.
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22.
fixed income yields, his equity risk premium analysis is flawed because he rejects
the well-documented fact that equity risk premium increase when interest rates
are low (as they are now) and decrease when interest rates are higher. I will show
that, but for these deficiencies, Mr. Gorman's analysis should have supported an
ROE of 10.21 percent.
What are your specific areas of disagreement with Mr. Gorman's analysis?
Mr. Gorman and I disagree strongly on the pricipal inputs to two of his three
models and we disagree on the curent reliability of the CAPM. In his analysis,
he consistently applies inputs that are negatively biased and produce the lowest
ROE results. In one of his constant growth DCF models, he sumaries the data
in a way that skews the results downward. In his multi-stage DCF model, which
is similar to mine, he agrees with me that GDP growth is an appropriate input, but
he uses short-term GDP growth rate forecasts that are significantly dominated by
recently low inflation rates. The inflation rates in his GDP forecast are almost a
full percentage point lower than the longer-term historical averages. This
approach is inconsistent with the long-term growth rate requirement of the DCF
modeL.
In his equity risk premium analysis, he selects data that are not consistent
with the recent risk premiums allowed by regulators and he fails to include the
well documented inverse relationship that exists between equity risk premiums
and interest rates, i.e., equity risk premiums tend to increase when interest rates
are low and decrease when interest rates are high. With this omission, in the
Hadaway, Di-Reb - 19
422 Rocky Mountain Power
.1
2
3
4
5
6
7
8
9 Q.
10
11 A.
12
13
14
15
16
17
18
19
20
21
22
.
.
curently low interest rate environment, his equity risk premium are significantly
understated and, therefore, his equity risk premium estimates of ROE are too low.
His CAPM estimates are even lower. From that analysis, his ROE
estimate is only 8.80 percent. This result is far below the next lowest number in
the summary shown in his Table 4 on page 37. This low result is simply a
confirmation ofthe CAPM's curent artificially low input problems that I
discussed earlier. The CAPM estimate is clearly an outlier that should have been
discarded.
Can you demonstrate what Mr. Gorman's results would have been if he had
used more reasonable input assumptions?
Yes. I have redone one of Mr. Gorman's constant growth DCF models with one
correction and I have redone his multi-stage model with a more reasonable long-
term GDP growth rate input. In Mr. Gorman's "sustainable growth" DCF
analysis, the result for DPL, Inc. is 19.14 percent, which he correctly considers to
be an outlier. Rather than simply eliminating DPL, Inc. from his group, however,
Mr. Gorman uses the group median, rather than average and median, to
sumarize all of his results. A more logical approach would have been simply to
remove DPL, Inc. from the analysis. When that is done, as I show in Exhibit No.
58, page 2, the group average is 9.48 percent, as compared to Mr. Gorman's
group median (including DPL) of9.14 percent. Although not a large effect when
applied to all three of Mr. Gorman's models, his reporting of only the median
results in his sumary table produces a slightly lower overall DCF estimate.
423
Hadaway, Di-Reb - 20
Rocky Mountain Power
.1 Q.What is your specific disagreement with Mr. Gormn's multi-stage DCF
2 analysis?
3 A.In that analysis, Mr. Gorman uses analysts' growth rate forecasts in the first five
4 years and a GDP growth rate forecast for years 11 and later. In the intermediate
5 years, years six through 10, he interpolates growth in a linear fashion between the
6 first and third stages. I disagree with his final result because it is dominated by an
7 estimate of future GDP growth that is far too low. He uses GDP growth forecast
8 from the Blue Chip Financial Forecast service, which are for five and 1O-year
9 periods. The curent Blue Chip GDP consensus forecasts are low because. they
10 are dominated by low expected real growth in the economy and the assumed long-
11 term inflation rate is only about 2.0 percent. As shown in the GDP forecast in my.12 Direct Testimony Exhibit No. 12, these inflation rates are lower than for any 10-
13 year period in the last 60 years. The nominal 4.9 percent growth rate that Mr.
14 Gorman uses is itself lower than nominal GDP growth in any 10-year period,
15 other than the most recent 10-years, which is obviously dominated by the low
16 growth rates experienced in 2008 and 2009 and that are curently expected
17 through 2011. For Mr. Gorman to base his long-term DCF growth estimate on
18 currently depressed near-term GDP expectations is unrealistic and it creates an
19 unrealistically low estimate of ROE.
20 Q.If Mr. Gorman had used your updated GDP growth rate, what would the
21 results of his multi-stage DCF analysis have been?
22 A.In Exhibit No. 58, page 3, I have reproduced Mr. Gorman's multi-stage analysis.23 from his Exhibit No. 210 (MPG-9) with my 6.0 percent GDP growth forecast
Hadaway, Di-Reb - 21
424 Rocky Mountain Power
.
.
.
1
2
3 Q.
4 A.
5
6
7
8
9
10
11
12 Q.
13 A.
14
15
16
17
18
19
20
21
22
substituted for his grwth rates in years 11 and later. From that analysis, the
average ROE is 10.70 percent and the median is 10.94 percent.
Please comment on Mr. Gorman's equity risk premium analysis.
In his equity risk premium analysis, Mr. Gorman fails to include the well-
documented tendency for equity risk premiums to increase when interest rates are
low and decrease when interest rates are higher. In the risk premium analysis
frm my Direct Testimony, I provide a detailed regression ofthe past 30 years of
data to document this fact. Mr. Gorman ignores that relationship altogether.
When his analysis is modified to properly reflect wider equity risk premium that
are appropriate in the curent low interest rate environment, his equity risk
premium is much higher.
Please elaborate.
Mr. Gorman presents his equity risk premium data in Exhibit Nos. 212-213
(MPG-ll through MPG-12). He discusses that analysis on pages 28-32 of his
testimony. The analysis consists of two part. In one approach, he adds equity
risk premiums based on governent bond interest rates of 4.40 percent to 6.08
percent to a projected Treasur bond yield of 4.70 percent. This analysis
produces an ROE range of9.l0 percent to 10.78. In his second approach he adds
equity risk premiums of 3.03 percent to 4.59 percent over utility bond yields to
the recent "A" utility bond yield of 5. I 7 percent. This analysis produces an ROE
range of 8.20 percent to 9.76 percent, with a midpoint estimate of8.98 percent.
Prom these two results, he concludes that an ROE of 9.46 percent is appropriate.
425
Hadaway, Di-Reb - 22
Rocky Mountain Power
.I Q.
2
3 A.
4
5
6
7
8
9
10
11 Q..12
13 A.
What does Mr. Gorman's equity risk premium data indicate when your
regression analysis approach is included?
In Exhibit No. 58, pages 4-7, I have applied the standard regression analysis to
calculate "interest rate adjustment" factors for his two equity risk premium
studies. This approach properly takes into account the inverse relationship
between equity risk premiums and interest rates. With this adjustment, Mr.
Gorman's Treasury bond equity risk premium analysis indicates an ROE of 10.57
percent, as shown in pages 4-5 of Exhibit No. 58. His utility bond equity risk
premium analysis indicates an ROE of9.91 percent (pages 6-7). The midpoint of
these revised risk premium results is 10.23 percent.
Please summarize the results of your adjustments to Mr. Gorman's ROE
analysis.
My adjustments are sumarized in Table 4 below:
Table 4
Sunry of Updated Gormn ROE Results
DCFModels
Constant Growth DCF (Analysts' Growth)
Constant Growth DCF (Sustainable Growth)
Multi-Stage DCF
DCF
Risk Premium Average
CAPM
Recommended ROE
Summa of Results
Gorman
Initial
ROE
10.50%
9.14%
9.90%
9.85%
9.46%
8.80%
9.50%
Updated
ROE
10.50%
9.11%
10.94%
10.18%
10.24%
NA
10.21%
14 His constant growth DCF result at 10.50 percent is within the reasonable range..15 As discussed above, removing DPL, Inc. frm the analysis altogether (rather than
Hadaway, Di-Reb - 23
426 Rocky Mountain Power
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.
1
2
3
4
5
6
7
8
9
10
11 Q.
12
13 A.
14
15
16
17
18 Q.
19
20
21 A.
22.23
just relying on the median), changes his sustainable growth constant growth result
to 9. I 1 percent, relative to a group average of 9,48 percent. The inclusion of a
more realistic long-term GDP growth rate of6.0 percent in his multi-stage DCF
analysis increases that result to 10.94 percent. Factoring in the observed inverse
relationship between interest rates and equity risk premiums, increases the equity
risk premium average to 10.24 percent. I also excluded his unreasonably low
CAPM result altogether. As shown above, the average of the adjusted DCF and
risk premium results is an ROE of 10.21 percent. Had Mr. Gorman considered
these more reasonable inputs, his ROE estimates would have been well above the
9.5 percent ROE he recommends.
On pages 42-51, Mr. Gorman criticizes various aspects of your ROE analysis.
What is your general response to his criticisms?
His criticisms are not accurate. They are principally focused on my use of the
GDP growth rate in my DCF model and his mistaken view that the cost of equity
for utilities has declined as much as interest rates. His characterization of my
GDP growth forecast is misplaced and his contention that equity costs have
declined significantly is simply wrong.
On pages 44-45, Mr. Gorman criticizes your GDP growth forecast by saying
that it is based on historical GDP data. Is it accurate to say that your
forecast is a "historical input"?
No. The GDP growth rate that I use is a forecast based on general economic
conditions that investors may expect for utilities in the very long ru, as is
required in the DCF modeL. While I develop my forecast from the St. Louis
Hadaway, Di-Reb - 24
427 Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10
11
.12 Q.
13
14 A.
15
16
17
18
19
20
21
22
.23
Federal Reserve Bank data base that covers the past 60 years, my forecast is not a
simple average or an extrapolation of the historical data. As is done in most
econometrc forecasts, I use the long-run historical relationships to project what
investors may reasonably expect for the long-term futue. I also give more weight
to more recent observations by applying weighted averages that give about five
times as much weight to the most recent 10 years as compared to the earliest 10
years. Giving more weight to the more recent data lowers the overall growth rate
forecast. For example, my current forecast is 6.0 percent whereas the annual
average ofthe growtrate data is 6.9 percent. In this context, Mr. Gorman's
criticism of my growth forecast is unwarranted and his comparison of my
approach to forecasted earnings growth rates is misplaced.
How do you respond to Mr. Gorman's criticisms of your equity risk
premium analysis?
I find Mr. Gorman's comments about my equity risk premium analysis surrising
since he has relied on the same data in his equity risk premium analysis. He
adopts my commission-authorized ROEs as the basis to estimate risk premium
and then he applies those risk premium, as I do, to both projected and curent
interest rates. The primary differences between our approaches is that my
historical time frame is longer (my data goes back to 1980, Mr. Gorman's to 1986)
and I take into account the inverse relationship between interest rates and equity
risk premium. As I demonstrated previously, had Mr. Gorman included this
fudamental relationship in his analysis, his equity risk premium analysis would
have produced an ROE above 10 percent.
Hadaway, Di-Reb - 25
428 Rocky Mountain Power
.1 Update of ROE Estimates
2 Q.Have you updated your ROE analysis to take into account recent data and
3 the current conditions in the capital markets?
4 A.Yes. Consistent with my customary practice, I have updated my ROE analysis for
5 curent conditions using the same methodologies that I employed in my direct
6 testimony.
7 Q.What are the results of your updated DCF analyses?
8 A.My updated DCF results are shown in Exhibit No. 59. The indicated DCF range
9 is 10.3 percent to 10.8 percent, with a midpoint of 10.55 percent.
10 Q.What are the results of your updated bond yield plus equity risk premium
11 analysis?.12 A.My equity risk premium studies are shown in Exhibit No. 60.These studies
13 indicate an ROE range of9.73 percent to 9.91 percent. Under current market
14 conditions, I discount these results because current utility bond yields are
15 artificially depressed by governent monetary policy and investors' continuing
16 flght to safety away from the ongoing turbulence in the equity capital market.
17 Q.What do you conclude from your updated ROE analyses?
18 A.My updated DCF analysis shows that Rocky Mountain Power's current cost of
19 equity capital is in the range of 10.3 percent to 10.8 percent. These results show
20 that the Company's requested ROE of 10.6 percent is reasonable and that the
21 recommendations of Ms. Carlock and Mr. Gorman, as discussed herein, are
22 uneasonably low.
.Hadaway, Di-Reb - 26
429 Rocky Mountain Power
.1 Q.Are you providing aCAPM analysis in your ROE update?
2 A.No. As I explained previously, governent monetary policies and recent flight to
3 safety issues have pushed Treasur bond interest rates to artficially low levels. In
4 this environment, CAPM estimates understate the market cost of equity capitaL.
5 For this reason, I do not include CAPM estimates in my ROE analysis and any
6 results from a CAPM analysis should be disregarded.
7 Q.Does this conclude your rebuttl testimony?
8 A.Yes.
.
.
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Rocky Mountain Power
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20
21
1 (The following proceedings were had in
2 open hearing.)
3 MR. HICKEY: Thank you.
4 Q.BY MR. HICKEY: Dr. Hadaway, were there any items
5 that were deferred to you over the course of Mr. Walj e i s
6 examination this morning?
7 A.I don i t recall any specific ones. I think
8 Mr. Williams probably answered the questions that were related
9 to my testimony.
10 MR. HICKEY: Madam Chair, Dr. Hadaway is
11 available for cross-examination.
12 COMMISSIONER SMITH: Mr. Budge.
13 MR. BUDGE: Thank you, Madam Chair.
14
15 CROSS- EXAMINAT ION
16
17 BY MR. BUDGE:
18 Q.Dr. Hadaway, I believe your recommendation in the
19 case is a return on common equity of 10.6 percent.
A.That i S right.
Q.Is that correct?
22 How many rate cases have you testified in in your
23 career where you i ve made a recommendation of return on
24 equi ty?
25 A.Probably 250.
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1 And how many of those would be PacifiCorp rateQ.
2 cases?
3 I i ve worked for them for at least the last tenA.
4 years, maybe a little longer than that, so maybe 20 of those
5 cases or -- no, more than that. I really don i t know,
6 Mr. Budge; I hadn i t thought about that.
7 I assume in that period you i ve testified beforeQ.
8 Commissions in all six states where PacifiCorp does business?
9 I don i t believe I i ve appeared in California but IA.
10 have filed testimony where the case has settled, but I believe
11 I have appeared in each of the other jurisdictions.
12 And in all of those cases you refer to, wereQ.
13 those in cases where you were advocating a rate of return for
14 the Utility?
15 A.Yes.
16 Q.And of those --
17 Excuse me, Mr. Budge, I i m sorry. I have alsoA.
18 testified recently in a Utah and Wyoming ECAM case, but that
19 didn't involve rate of return.
20 So of those cases where you testified in favor ofQ.
21 a return on equity for the Company or a utility, of those that
22 went to hearing in a contested fashion and were decided by the
23 Commissions, how many of those times did a Commission ever
24 adopt your recommendation?
25 A.One.
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1 MR. BUDGE: No further questions.
2 COMMISSIONER SMITH: Thank you.
3 Mr. Purdy.
4 MR. PURDY: I have no questions.
5 COMMISSIONER SMITH: Ms. -- no questions.
6 Mr. Olsen.
7 MR. OLSEN: No questions, Madam Chair.
8 COMMISSIONER SMITH: Mr. Otto.
9 MR. OTTO: None, Madam Chair.
10 COMMISSIONER SMITH: Mr. Woodbury.
11 MR. WOODBURY: Thank you, Madam Chair.
12
13 CROSS-EXAMINATION
14
15 BY MR. WOODBURY:
16 Q.Dr. Hadaway, how are you?
17 A.Fine, Mr. Woodbury. How are you?
18 Q.I have, you know -- starting on page 28 and
19 continuing through 31, I guess, you cite just a number of, I
20 guess, instances or factors that increase risk?
21
22
23
24
25
A.Excuse me. On my direct or my rebuttal?
Q.Direct.
A.And which page, please?
Q.Starting at about page 28 and continuing through
31. And I can -- you speak of dereg of wholesale power
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1 markets, fuel price uncertainties, reduced sales volumes,
2 increased difficulty of planning for future load requirements,
3 climate change legislation, ECAM. You note that PacifiCorp 's
4 utility with significant coal-fired generation would have added
5 risk with respect to reduction of greenhouse gases; and
6 renewable energy options, DSM al ternati ves. All of those are
7 factors that you believe contribute to the perception of
8 increased risk and requirement of a higher return by investors?
9 A.I think this testimony is a little broader than
10 that. It's generally what you see in Value Line or in the
11 rating agency reports about the risks, and, you know, so that i s
12 why I i m discussing them here. These are things that investors
13 are concerned about. Depending on how they i re treated -- for
14 example, the ECAM may be a risk-reducing mechanism depending on
15 the nature of the power supply, those kinds of things -- these
16 things can cut both ways.
17 Q.Okay. But the factors that you cite are more
18 generic as opposed to Company specific?
19 A.Well, in the part that you've cited. l've
20 quoted, i believe, from Standard and Poor I s and from Value Line
21 and the other sources like that.
22 Q.And, you know, in citing the coal-fired
23 generation and pollution control equipment, i think that the
24 Company has another witness, Teply, who in his direct on
25 page 2, line 4, states that this will -- intended to enhance
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1 overall generation capability and cycling efficiency.
2 So there are posi ti ve aspects of the
3 requirements?
4 A.There certainly may be. I i m talking about the
5 legislation and so far that the Congress has not passed, and
6 here i s I describe that legislation very briefly.
7 Q. And on page 31, on line 7, you talk about there
8 may be a requirement of a greater percentage of renewable
9 energy options.
10 Are you referencing renewable portfolio standards
11 or PURPA or what?
12 A.Portfolio standards in many states.
13 Q.And in talking about added pressure to offer
14 addi tional DSM al ternati ves, you know, is that posi ti ve or
15 negative?
16 It depends on how it affects the load and howA.
17 that i s treated in the rate-making process.
18 So all of these can be assessed in a way byQ.
19 PacifiCorp that will not be negatively perceived by rating
20 agencies and investors?
21 Yes. It depends on how the regulator deals withA.
22 those things.
23 Okay. And, you know, on your rebuttal testimonyQ.
24 on page 5, you talk about Standard and Poor i s forecast reflects
25 significant economic contraction that occurred in 2009 with a
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1 drop in the GDP.
2 And "economic contraction," is that, you know,
3 the terms that they i re using, is that like quanti tati ve easing?
4 Is that the printing of money?
5 A.No, l'm talking about -- it i S in, I believe, for
6 the rebuttal part, Exhibit 57.
7 Q.Uh-huh.
8 A.And in there, there i s a page from Standard and
~ Poor i s that shows what happened during 2009, what they think
10 for 2010, and that contraction is the 2.6 percent drop in --
11 A VOICE:(Via telephone) We i re sorry, your
12 conference is ending now. Please hang up.
13 THE WITNESS: l'm not talking about monetary
14 easing there at all. I i m talking about the reduction in the
15 growth rate in gross domestic product.
16 BY MR. WOODBURY: Now, S&P is talking aboutQ.
17 forecast increases. In 2010, you cited 2.7 percent; in 2011,
18 of 2.5. But in page 6, line 4, you state that S&P has a
19 pessimistic outlook for the economy.
20 Are they interpreting those increases as lower
21 than they should be?
22 A. They' re lower than they were from them a few
23 months ago. That i s what I mean there.
24 Q. And, all right, I guess on page 15, line 9, you
25 talk about government i s expansionary monetary policy. That
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1 refers to quanti tati ve easing?
2 A.As it i S been called a lot of different things,
3 but the Federal Reserve system repurchasing -- the most recent
4 thing is its new program to continue repurchasing long-term
5 government bonds. In addition to its earlier actions to reduce
6 short-term interest rates, it i S continuing to pump money into
7 the economy to keep all interest rates down.
8 Q.Thank you.
9 MR. WOODBURY: Madam Chair, I have no further
10 questions.
11 COMMISSIONER SMITH: Are there questions from the
12 Commissioners?
13 COMMISSIONER REDFORD: No.
14 COMMISSIONER KEMPTON: None.
15 COMMISSIONER SMITH: Nor I.
16 Redirect?
17 MR. HICKEY: No redirect, and we'd ask that
18 Dr. Hadaway be excused, please, Madam Chairman.
COMMISSIONER SMITH: Is there any obj ection to
20 excusing Dr. Hadaway?
21 Seeing none, he is excused.
22
23
24
25
THE WITNESS: Thank you, your Honor.
(The witness left the stand.)
COMMISSIONER SMITH: Speeding right along.
MR. HICKEY: Mr. Solander will be calling our
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1 next witness. Daniel.
2 MR. SOLANDER: Thank you. Rocky Mountain Power
3 would call Mark Tallman as its next witness.
4
5 MARK TALLMAN,
6 produced as a witness at the instance of Rocky Mountain Power,
7 being first duly sworn, was examined and testified as follows:
8
9 DIRECT EXAMINATION
10
11 BY MR.SOLANDER:
Q.Good afternoon,Mr.Tallman.
A.Good afternoon.
Q.Could you please state your name and then spell
it for the record?
12
13
14
15
16 A.Mark R. Tallman: M-A-R-K, R, T-A-L-L-M-A-N.
17 Q.And by whom are you employed and in what
18 capacity?
19 A.PacifiCorp. Specifically, I work for PacifiCorp
20 Energy, operating division of PacifiCorp, and l'm the vice
21 president of renewable resource acquisition.
22
23
24
25
Q.Could you move the mic a little closer?
A.How i s that? Okay?
Q.And are you the same Mark Tallman that filed
direct testimony on May 28th and prepared Exhibits Nos. 20
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1 through 32?
2 A.Yes.
3 Q.And did you also file rebuttal testimony on
4 November 16, 2010, and with that testimony file Exhibit Nos. 61
5 through 63?
6 A.Yes.
7 Q.And do you have any corrections or changes to
8 your testimony or exhibits at this time?
9 A.No.
10 Q.So if I were to ask you the questions set forth
11 in your prefiled testimony, your answers would be the same
12 today?
13 A.Yes.
14 MR. SOLANDER: I would now move, Madam Chair,
15 that the prefiled direct and rebuttal testimony of Mark Tallman
16 be spread upon the record as if read, and that Exhibits 20
17 through 32 and Exhibits 61 through 63 be marked for
18 identification.
19 COMMISSIONER SMITH: If there is no objection, it
20 is so ordered.
21 (The following prefiled direct and
22 rebuttal testimony of Mr. Tallman is spread upon the record.)
23
24
25
439
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
TALLMAN (Di)
RMP
.1 Q.Please state your name, business address and presént position with Rocky
2 Mountain Power ("Company").
3 A.My name is Mark R. Tallman. My business address is 825 NE Multnomah, Suite
4 2000, Portand, Oregon 97232. My present position is Vice President of
5 Renewable Resource Acquisition.
6 Qualifications
7 Q.
8 A.
9
10
11.12
13
14
15
16
Please describe your educational and professional background.
I have a Bachelor of Science Degree in Electrcal Engineering from Orgon State
University and a Masters of Business Administration from City University of
Seattle. I am also a Registered Professional Engineer in the states of Oregon and
Washington. I have been the Vice President of Renewable Resource Acquisition
since December 2007. Pror to that, I was Managing Director of Renewable
Resource Acquisition from April 2006 to December 2007. I have worked at the
Company for more than 24 years in a varety of positions of increasing
responsibilty, including the commercial and trading organization; the
Company's engineering organization; the retail distrbution organization; and five
17 years as a District Manager.
18 Purpose and Overview of Testimony
19 Q.What is the purpose of your testimony?
20 A.The purpose of my testimony is to demonstrate the prudence of the Seven Mile
21 Hil, Glenrock, Rollng Hils, Seven Mile Hil II, Glenrock III, High Plains and
22 McFadden Ridge I wind-powered generation resources (collectively the "Wind
.23 Resources" and individually a "Wind Resource"). The Company is also adding
440 Talman, Di - 1
Rocky Mountain Power
.1 the Dunlap I wind-powered generation resource that is addressed in the testimony
2 of Mr. Stefan A. Bir.
3 Q.Please summarize your testimony.
4 A.I star by describing the Company's integrated resource plan ("IRP") and how it is
5 utilzed to identify and quantify the need and timing of new supply-side resources.
6 I also provide an overview of the relevant MidAerican Energy Holdigs
7 Company ("MEHC") transaction commtments related to acquisition of renewable
8 resources. Finally, I provide a description of the Wind Resources, the decision-
9 makng process leading to their acquisition and a description of updated
10 information for each Wind Resource.
11 Q.What were the commercial operation dates for each Wind Resource?.12 A.Each Wind Resource is in sèrvice. As shown in the table below, the commercial
13 operation date ("COD") vares by Wind Resource.
Wind Resource COD
Wind
Resource COD
Seven Mile Hill December 31, 2008
Glenrock December 31, 2008
Rollinii Hils Januar 17, 2009
Seven Mile Hil II December 31, 2008
Glenrock II Januar 17, 200
High Plais September 13,200
McFadden Ridiie I September 29, 200
14 Q.Please summarize each Wind Resource.
15 A.The table below summarzes each Wind Resource, its location and its associated
16 investment.
.
441 Tallman, Di - 2
Rocky Mountain Power
.in esource ummarv
Wind
Resource MW Location Investment COD
Seven Mile Hil 99.0 Medicine Bow, WY $206,070,352 1213112008
Glenrock 99.0 Glenrck. WY $217,015,087 1213112008
Rolling Hils 99.0 Glenrk, WY $200,234,936 1117/2009
Seven Mile Hil II 19.5 Medicine Bow, WY $41,304,822 12/3112008
Glenrock II 39.0 Glenrock, WY $86,84,843 1117/200
High Plains 99.0 McFadden, WY $232,518,676 9/13/200
McFadden Ridge I 28.5 McFadden, WY . $56,511,031 9/29/200
W. dR s
1 Integrated Resource Plan
Please briefly describe the IRP proess.
The IRP is a strategic planning tool that presents a framework for resource
acquisitions to ensure the Company continues to provide reliable, low-cost service
with manageable and reasonable risk to customers. The IRP builds on the
Company's prior resource planning efforts and reflects significant advancements
in portfolio modeling and risk analysis.
What is the main purpose of the IRP?
The mandate for an IRP is to ensure that the Company has, on a long-term basis,
an adequate and reliable electrcity supply at the lowest reasonable cost and to
ensure that such supply is provided or fulfilled in a timely and planned manner
consistent with the long-term public interest. The IRP serves as a strategic
roadmap to assist the Company in determning and implementing its long-term
resource strategy. In doing so, the IRP accounts for state specific IRP
requirements, expected customer resource needs, the currnt planning
environment, corporate business goals and certain commtments made by the
Company as par of MEHC' s acquisition of PacifiCorp, including the acquisition
of renewable resources.
442 Tallman, Di - 3
Rocky Mountain Power
.1 Q.
2 A.
3
4
5
6
7 Q.
8 A.
9
10
11.12
13
14
15
16
17
18
19
20
21
.
What is the outcome of the IRP process?
The outcome of the IRP process is a preferred portfolio that represents a balance
of resource additions that meet futue customer needs, minimize cost, balance
diverse staeholder interests and address envionmental concerns. The
Company's IRP includes an action plan that is intended to inform and provide
guidance for the Company's resource procurement activities.
How do the most recent IRPs address renewable resources?
The 2004 IRP was fied with the Idao Public Utilties Commssion
("Commssion") on Januar 21, 2005, and the Commssion acknowledged the
2004 IRP on August 26,2005. The 2007 IRP was fied with the Commssion on
May 30, 2007, and the Commssion acknowledged the 2007 IRP on October 15,
2007. The 2008 IRP was filed with the Commssion on May 29, 2009, and the
Commssion acknowledged the 2008 IRP on September 15,2009.
Each of these IRPs identifies a need to acquire 1,400 megawatts ("MW")
or more of cost-effective renewable resources.! Indeed, the acquisition of
renewable resources is the first action item listed for each such IRP. For example,
the 2007 IRP identifies over 2,000 MW of cost-effective renewable resources to
be acquired by 2013 and the 2008 IR targets to acquire an incremental 1 ,400
MW by 2018, which is consistent with the taget contained in the 2007 IR. By
2018, acquisition of renewable resources reaches 2,540 MW in the 2008 IRP,
which includes over 1,400 MW of resources added from 2009 through 2018.
1 Wind-powered generation resources served as the proxy resource in each IRP.
443 Tallman, Di - 4
Rocky Mountain Power
.1 Q.Do the referenced IRPs address the procurement process for renewable
2 resources?
3 A.Yes. Generally, each IRP outlines a resource procurement strtegy as par of the
4 IRP action plan? The Company procures resources in accordance with the then-
5 curent law, rules, and/or guidelines in each of the states in which PacifiCorp
6 operates. Meaning that if a jursdiction has a requirement to issue a request for
7 proposal ("RF") then the Company would comply with the requirement.
8 Specifically, the Company has relied on periodic issuance of RFs and pursuit of
9 opportnities though bilateral negotiations, contracting with Qualifying Facilities
10 defined by the Public Utilties Regulatory Policies Act of 1978and self-
11 development for the addition of renewable resources to its portfolio. Reliance on.12 multiple procurement approaches enables the Company to achieve regulatory
13 compliance and react effectively to market developments.
14 Q.Have other state commisions acknowledged the referenced IRPs and their
15 associated action plan on renewable resource acquisition?
16 A.Yes. The commssions in Washington, Oregon, and Utah have acknowledged the
17 2008 IRP. The Wyoming Public Service Commssion adopted Rule 253 in 2009,
18 which requires the Company to file an IRP but does not include an
19 acknowledgment proceeding. In California, the Comp;my provides its IRPon an
20 informational basis and is not required to seek acknowledgement. Each state
21 commssion acknowledged the earlier IRPs referenced, with the exception of the
, 22 Utah commssion for only the 2007 IRP..2 See 2004 IRP chapter 9,2007 IRP chapter 8 and 2008 IRP chapter 9.
444
Tallman, Di - 5
Rocky Mountain Power
.1 Q.In its acknowledgement of the 200, 2007 and 2008 IRPs, did the
2 Commission object to the acquisition of renewable resources?
3 A.No. In fact, the Commssion noted Staffs support for acquisition of cost-
4 effective renewable resources in the Commssion's 2007 IRP Acceptance of
5 Filng.
6 MEHC Transaction Commitments
7 Q.
8
9 A.
10
11
12.13
14
Please provide an overview of the MEHC transaction commitments related
to the acquisition of renewable resources.
As par of the regulatory approvals related to the acquisition of the Company,
MEHC and the Company commtted to:
. Bring at least 100 MW of cost-effective wind resources in service withn one
year of the close of the transaction;
. Have 400 MW of cost-effective new renewable resources in the Company's
generation portfolio by December 31, 2007; and
15 . Reafir the Company's commtment to acquire 1,400 MW of cost-effective
16 new renewable generation resources.
17 Each of the Wind Resources was acquired consistent with these commtments
18 and, in parcular, in support of the commtment to have 1,400 MW of cost-
19 effective new renewable resources in the portfolio.
20 Wind Resource Acquisitions
21 Q.Please generally describe the Wind Resources.
22 A.Each Wind Resource is an individual project consisting of wind turbine
23 generators ("WTGs" or a "WTG"), an electrcal collector system, access roads,
24 and required communication and control facilties (e.g., meterig, hardwar,
. 25 software, and associated communication circuits). In the case of Seven Mile Hi,
445
Tallman, Di - 6
Rocky Mountain Power
.1
2
3
4
5
6
7
8 Q.
9 A.
10
.
11 Q.
12 A.
13
14
15
16
17.
Glenrock and High Plains, the project also included an operations/maintenance
("O&M") buildig, collector substation and interconnection facilties. While
Rollng Hils required its own collector substation, Seven Mile Hil II, Glenrock
III and McFadden Ridge I did not. Finally, Rollng Hils, Seven Mile Hil II,
Glenrock III, High Plains and McFadden Ridge I did not require the constrction
of a new interconnection substation; respectively utilizing the Freezeout, Windstar
or Foote Creek substations instead.
What WTG do the Wind Resources utilze?
The General Electrc Company ("G.E.") 1.5 MW model SLE WTG. The number
of WTGs at each Wind Resource is shown in the table below.
Wind Resource WTGs
G.E.
Wind 1.5MW
Resource WTGs
Seven Mile Hil 66
Glenrock 66
Rolling Hils 66
Seven Mile Hil II 13
Glenrock II 26
High Plais 66
McFadden Ridge I 19
Who owns the land where the Wind Resources reside?
The Company is leasing land from private entities and the state of Wyoming for
each Wind Resource with the exception of Glenrock, Rollng Hils and Glenrock
III. Facilities associated with Glenrock, Rollng Hils and Glenrock III are
primarly located on land owned by the Company that was previously use to
support coal mining activities. Minor levels of facilties are located on state of
Wyoming lands.
446 Talan, Di - 7
Rocky Mountain Power
.1 Q.Please elaborate on the Company-owned land.
2 A.The Glenrock, Rollng Hils and Glenrock III resources are all located on propert
3 owned by the Company that includes the location of the Company's now
4 reclaimed Dave Johnston coal mine. Mining operations took place from
5 approximately 1958 though September of 2000. After mining operations ceased,
6 the Company reclaimed the land pursuant to its Wyomig admnistered Federal
7 mining permt. The siting of these renewable resources at this location serves as a
8 testimonial to environmental stewardship and continued asset utilzation for the
9 benefit of customers. This is the only instance I am aware of in the western
10 United States where wind projects have been located at the site of a reclaimed
11 coal mine..12 Q.What factors does the Company consider before acquiring new resources?
13 A.The decision as to whether it is in the best interests of customers for the Company
14 to acquire a resource is made after reviewing a detailed overview of the project
15 including the contract support and counterpary guarantees, the risks, the need as
16 established by the IRP, the financial assessment, and the justification of the
17 project.
18 Q.Did the Company follow this general proces in the acquiition of each Wind
19 Resource?
20 A.Yes. The Company followed this process in determning that each Wind
21 Resource is prudent and in the public interest to pursue.
.
447
Tallman, Di - 8
Rocky Mountan Power
.1 Q.. Was the decision to acquire the Wind Resources consistent with the decision
2 making process the Company has used in adding other renewable resources
3 that have been before this Commission?
4 A.Yes. Some of the renewable resources that have previously been before this
5 Commssion include the Leaning Juniper I, Marengo, Goodnoe Hils and
6 Marengo II wind-powered generation resources.
7 Q.Did the Company perform an evaluation of the wind potential for each Wind
8 Resource?
9 A.Yes. The Company commssioned a third-par to perform an evaluation of the
10 wind potential for each Wind Resource. The Company's decision to acquire each
11 Wind Resource took into account the technical wind study. 3.12 Q.What other factors did the Company take into consideration when making
13 the decision to acquire each Wind Resource?
14 A.The Company took into account both quantitative and qualitative factors.The
15 quantitative factors included an economic analysis of the resource.See
16 Confidential Exhibit Nos. 20 through 26.
17 Q.Were the economics of each Wind Resource in line with the alternative
18 undifferentiated power market?
19 A.Yes. Each Wind Resource compares favorably with the expected non-
20 differentiated power market. See economic analysis results contained in
21 Confidential Exhibit Nos. 20 through 26.
.3 The decision to proeed with Seven Mile Hil II was informed by the wind study associated with Seven
Mile Hil and the decision to proceed with Glenrock II was informed by the wind studies associated with
Glenrock and Rollng Hills.
448
Tallman, Di - 9
Rocky Mountan Power
.1
2
3
4
5
6
7
8
9
10 Q.
11 A..12
13
14
15
16
17 Q.
18
19 A.
20 Q.
21 A.
22.23
resource and, as such, the Company is able to further utilze certin infrastrctue
that was necessar for the Seven Mile Hil resource. Likewise, similar synergies
exist with the Rollng Hils and Glenrock III resources (being adjacent to the
Glenrock resource) and the McFadden Ridge I resource being adjacent to the
High Plains Wind Resource. This fuer utilzed infrastrctue includes
transmission interconnection substations (Freezeout, Windsta and Foote Creek)
as well as project transmission assets from High Plains to Foote Creek and from .
Glenrock to Windstar. In addition, O&M buildings, land rights and roads are
furher utilized.
What independent benefit will the Windstar substation have?
In constrcting the Windstar substation, the Company was able to establish a key
point of interconnection that can be used for numerous other third pary requests
for interconnection (generation and other). In addition, the Windstar substation
now represents the key staring point in Wyoming for the Company's multibillon
dollar Energy Gateway transmission project that wil, among other things,
facilitate further integration of renewable and non-renewable resources.
Wil the Company receive production tax credits ("PTCs") and RECs from
each Wind Resource?
Yes.
Did the Company benefit from any Wyoming specific tax benefits?
Yes. The Company benefited from a Wyoming sales tax exemption for each
Wind Resource. The benefit was in the form of an avoided cost. The Wyoming
sales tax exemption sunsets December 31, 2011.
450
Tallman, Di - 11
Rocky Mountai Power
.1 Q.
2
3 A.
Has the Company obtained a Certifcate of Public Convenience and Necessity
("CPCN") for each Wind Resource?
Yes. The Company obtained a CPCN for each Wind Resource from the
4 Wyoming Public Service Commssion. Because each Wind Resource is in
5 Wyoming, application for a lie certificate in Idao was not required.
6 Update for MostRecent Capacity Factor Projections
7 Q.
8
9
10 A.
11.12
13
14 Q.
15
16 A.
17
18
19
20
21
22.
In completing the construction process, did the Company obtain third-party
technical studies updating the capacity factor estimates for each Wind
Resource?
Confidential Exhibit Nos. 27, 28, 29, 30 and 31 are the final build design energy
projections for the Seven Mile Hil, Glenrock, Rollng Hils, Seven Mile Hil II
and Glenrock III resources, respectively. A final build design energy projection
has yet to be completed for the High Plains and McFadden Ridge I resources.
Please summarize the final. build design energy projections for these
resources.
The table below provides a summar of the final build design energy projection
estimate ("FBDE") for each Wind Resource as well as the projection at the time
the decision was made to acquire the resource. The summar shows estimated
annual capacity factor ("CF") at the probabilty fifty (P50) level and megawatt-
hours ("MW"). Because actual CF is dependent on the weather and other
factors, a P50 estimate means that the actual production in any given year can be
expected to be higher or lower over the life of the resource.
451
Tallman, Di - 12
Rocky Mountain Power
.
1 Q.
2
3 A..4
5 Q.
6 A.
7
8
9 Q.
10
11
12 A.
13
.
Wind Resource FBDE
Acquisition Acquisition Updte Update
Decision Decision wlFBDE wlFDE
Resource (CF)(MWh)(CF)(MWh)
Seven Mile Hil 41.3%358,170 40.3%349,948
Glenrock 38.6%334,755 37.4%324,348
Rollng Hils 31.0%268,844 33.8%293,127
Seven Mile Hil II 39.3%67,132 40.3%68,840
Glenrock II 31.0%105,908 36.4%124,357
TotalMW 1,134,810 1,160,170
Averae CF 36.2%37.6%
High Plais 35.7%309,605 n/a
McFadden Ridge I 34.5%86,133 n/a
TotalMW 1,530,547 1,555,907
Average CF 35.9%36.9%
Is it unusual for capacity factor estimates to vary over time as the
construction of wind-powered generation facilties progress?
No. As more information is acquired, it is not unusual for capacity factor
estimates to be updated.
Why were the estimated capacity factors of these resources updated?
The update in estimated capacity factor reflects normal changes that resulted in
the final construction design of the resources, as well as additional information on
wind climatology for the sites.
Is the average capacity factor of the Wind Resources in line with the average
capacity factor for the Company's Wyoming power purchase contracts with
wind-powered generation resources?
Yes. The average capacity factor for the Company's Wyoming power purchase
contracts with wind-powered generation resources is approxiately 32.0 percent.
452
Tallman, Di - 13
Rocky Mountain Power
.1 Q.Is the average capacity factor predicted for the Wind Resources in line with
2 the proxy capacity factor assumed for Wyoming wind resources in the
3 Company's IRP?
4 A.Yes. The Company's 2007 IRP and 2008 IRP used a 35 percent4 capacity factor
5 to model proxy wind projects for building the Company's portfolio of renewable
6 energy resoures. In reality, some renewable resources wil have capacity factors
7 above 35 percent and others wil be lower than 35 percent.
8 Q.Does the Company currently have wind resources or contracts with wind
9 resources in its portfolio with capacity factors below 35 percent?
10 A.Yes, excluding any of the Wind Resources, the Company curently has 21 such
11 resources with projected annual capacity factors below 35 percent. These.12 resources are located inside and outside of Wyoming. See Confidential Exhibit
13 No. 32.
14 Q.Does the net power cost study in this case include the FBDE?
15 A.Yes. The Company believes the most recent capacity factor projection is
16 appropriate to use for setting rates and, as such, the Company included the FBDE
17 updates in the net power cost study sponsored by Company witness Dr. Hui Shu
18 in this case.
19 Q.Has the Company included the value of PTCs and RECs in its filing?
20 A.Yes. The value of PTCs, RECs or other known tax-related benefits and burdens
21 for each Wind Resource are included in the Company's filng.
.4 35% is in line with the proxy wind assumptions used in the 200 IR.
453
Tallman, Di - 14
Rocky Mountain Power
.1 Q.
2
3
4 A.
Did the Company acquire the Wind Resources for the purpose of complying
with renewable portfolio standards in Oregon, Washington, California or to
meet the requirements of carbon reduction legislation in Utah?
No, each Wind Resource was acquired on the basis of its economics, other
5 quantitative factors and qualitative factors.
6 Conclusion
7 Q.
8 A.
9
10
11.12
13
14
15
16
17 Q.
18 A.
19
20
21
22.23
What are the overall benefits of Wind Resources to Idaho customers?
Customers benefit from the Wind Resources because they represent cost effective
renewable resources. The 2004, 2007 and 2008 IRPs specify that cost effective
renewable resources (using wind-powered generation resources as a proxy)
should be steadily added to the system. The Wind Resources benefit customers as
their acquisitions were both cost effective and consistent with the Company's
robust long-term planning efforts though the IRP process. Customers fuer
benefit from these renewable resources because they provide a zero incremental
cost fuel soure, thus reducing exposure to potentially volatile commodity and/or
fuel risks.
Are there other benefits the Commission should consider?
Yes. The Wind Resources are multi-shafted generation resources that diversify
the impact of individual generator failures and provide the Company with
continued ownership and operational experience with utilty-scale wind projects.
Each Wind Resource utilzes G .E. wind turbines, thus complementing the
Company's operating experience with other G.E. based projects, spare
optimization and procurement of O&M services.
454
Tallman, Di - 15
Rocky Mountain Power
.1 Q.Was each Wind Resource acquired consistent with the Company's then-
2 current IRP and does it represent the least cost/risk option available for the
3 long-term benefit of customers?
4 A.Yes
5 Q.Was each Wind Resource prudently acquired, in the public interest and is
6 each Wind Resource used and useful?
7 A.Yes
8 Q.Does this conclude your direct testimony?
9 A.Yes.
.
.
455
Tallman, Di - 16
Rocky Mountain Power
.1 Q.Please state your name, business address and present position with
2 PacifiCorp (the "Company").
3 A.My name is Mark R. Tallman. My business address is 825 NE Multnoma, Suite
4 2000, Portand, Oregon 97232. My present position is Vice President of
5 Renewable Resource Acquisition.
6 Q.Are you the same Mark R. Tallman that submitted direct testimony in this
7 proceeding?
8 A.Yes.
9 Q.What is the purpose of your testimony?
10 A.The purose of my testimony is to rebut the testimony of Mr. Joe Leckie of the
11 Idao Public Utilties Commssion (the "Commssion") Staff as it relates to rate
.12 base associated with the Dunlap wind project and operations and maintenance
13 ("O&M") costs associated with wind administration and the High Plains,
14 McFadden Ridge I, and Dunlap wind projects.
15 Dunlap Wind Project
16 Q.Please summarize Staff's position as it relates to the Dunlap wind project.
17 A.Staff is proposing a $1.0 millon (system) rate base reduction for the Dunlap wind
18 project. Specifically, Staf is proposing a rate base reduction in association with
19 the purchase cost to acquie the Dunlap Ranch property; which comprises the
20 majority of the critical property rights necessar to constrct the Dunlap wind
21 project.
22 Q.What is the stated reason for Staffs proposed reduction?.23 A.Staf testified that "it appears to Staff that some of the land purchased is not
456 Tallman, Di-Reb - 1
Rocky Mountan Power
.1 currently used and useful in providing utilty service."
2 Q.Does the Company agree with Stafls contention that a portion of the Dunlap
3 Ranch property is not used and useful?
4 A.No, the entirety of the Dunlap Ranch is used and useful because it was used,
5 useful and necessar to effectuate a cost effective and environmentally respectful
6 wind project.
7 Q.Does Staff recognize not all property is equally suitable for placement of
8 wind generation?
9 A.Yes, in their testimony Staf states:"Staff recognizes that not all property wil be
10 equally suitable for the placement of wind generation, and that there may be other
11 restrctions on the property that would curail the number of wind generation
.12 sites."
13 Q.What was Stafls reasoning in determining their proposed reduction?
14 A.Notwithstanding Staf s acknowledgement regardig the blanket suitabilty of
15 property for wind development, Staff s reasoning was based on their after-the-fact
16 observance of the as-built placement of wind tubine generator ("WTG") towers
17 and transmission facility towers. Staff concluded that if a section of deeded land,
18 or portion of a section, within the Dunlap Ranch property did not ultimately house
19 a WTG tower or a transmission tower then the pro-rata costs associated with such
20 land should be arbitrly declared "not curently used and useful".
21 Q.Was there any other reasoning associated with Stas determination?
22 A.No, Staffs work papers clearly demonstrate the sole reasoning behind their.23 determnation was a simple counting of land sections that did not have an
457 Tallan, Di-Reb - 2
Rocky Mountain Power
.
.
.
1
2 Q.
3 A.
4
5
6
7
8
9
10
11
12
13
14
15 Q.
16 A.
17
18
19
20
21
22 Q.
23 A.
outcome of housing WTG towers or trnsmission towers.
Does Stas reasoning and simplistic approach overlook important facts?
Yes, Staff's approach of focusing only on WTG and transmission tower
placement overlooks several important facts. First, the propert was not offered
piecemeal; the Company had to purchase the entire ranch. Second, WTG or
transmission towers could not be placed in some areas due to restrctions I wil
discuss later. Third, purchase of the propert is less expensive than leasing. In
addition, three of the propert sections Staff declares as "not curently used and
useful" in fact housed meteorological towers that were used, useful and critical in
determning the placement of WTGs upon the site. This meteorological tower
information was utilzed to optimally site WTGs; subject to constraints identified
after the purchase of the property. Finally, the Company is receiving revenue
from an agricultural lease associated with the Dunlap Ranch property. I address
each of these issues later in my testimony.
What do you conclude from Staff's determination?
I conclude that Staff is inappropriately basing their assessment of what constitutes
"used and useful" on a few arbitrar criteria of where the Company constrcted
WTG and transmission towers. The appropriate criteria should be what the
Company knew at the time the Dunlap Ranch was purchased and the overall
benefit of the Dunlap Ranch to customers. Determnation on this latter basis is
the most appropriate view and consistent with established regulatory principle.
Was the Dunlap Ranch property being offered for sale piecemeal?
No. The Dunlap Ranch was being offered for sale in its entirety. The alternative
458 Tallman, Di-Reb - 3
Rocky Mountain Power
.1
2
3
4
5
6 Q.
7
8 A.
9
10
11.12
13
14
15
16
17 Q.
18
19 A.
20
21
22.23
of buying the property piecemeal was not being offered in the market. Because
the Dunlap Ranch property comprises the majority of the property rights
necessar for the development of the Dunlap wind project, the entie ranch
property was vital and was necessar in successfully developing a prudent and
cost effective generation resource that is indeed the Dunlap wind project.
Why was the entire ranch property necessary for developing the Dunlap
wind project?
The development and ultimate placement of WTGs and other facilities associated
with a wind project is a highly technical, time consuming and iterative process
that cannot be determned without a number of environmental, engineering and
technical wind studies. In addition, it is necessar to have multiple consultative
sessions with agencies who are pary to applicable permtting processes (i.e., the
Wyoming Game and Fish Deparent) and agencies who the Company may have
interaction with following the permtting process (i.e., the United States Fish &
Wildlife Service). The purose of the studies and consultations is to identify the
restrictions associated with the wind project site.
Do you have an exhibit showing the Dunlap Ranch property in the context of
the overall Dunlap wind project?
Yes, Exhibit No. 61 identifies the Dunlap Ranch property in the context of the
overall property rights necessar for the Dunlap wind project. It also ilustrates
the critical natue of the Dunlap Ranch propert relative to the overall property
rights required. Absent the Dunlap Ranch property, the Company could not have
constrcted the Dunlap wind project.
459 Tallman, Di-Reb - 4
Rocky Mountain Power
.1 Exhibit No. 61 also identifies the environmenta restrctions that resulted
2 in agency consultations and permt requirements that took place after the
3 Company acquired the ranch property and demonstrates why it is necessar to
4 have adequate propert rights when developing a wind project. While the site
5 restrctions associated with the Dunlap wind project were many, the adequate size
6 of the Dunlap Ranch property to accommodate the restrctions was a critical and
7 necessar factor in constructing a generation resource in the best interest of
8 customers.
9 Q.How should the used and usefulness of a wind site property be assessed?
10 A.Because of the iterative natue of developing a wind project, it is impossible to
11 have a complete foreknowledge about a piece of property at the time a.12 commtment to acquire the wind site property rights must be made. The iterative
13 natue of wind project development underscores the inappropriateness of judging
14 used and usefulness of wind site property on the basis of outcome. The used and
15 usefulness of wind site propert is most appropriately based on what the
16 Company knew at the time it acquired the property rights and the benefit to
17 customers in the overall context of a prudent and cost effective supply side
18 generation resource.
19 Q.Does Staff question the prudence of, or otherwise propose a rate base
20 reduction associated with, any aspect of the Dunlap Wind project other than
21 the Dunlap Ranch property?
22 A.No.
.
460 Tallman, Di-Reb - 5
Rocky Mountain Power
.1 in terms of wake effects from potential futue adjacent wind projects, important
2 buffer property to respect the environment and the potential for continued public
3 access to the property. These additional customer and public interest benefits are
4 diectly associated with those sections of land that Staff has identified as being
5 "not curently used and useful" and additionally demonstrte that those portions
6 of the ranch are indee used, useful and in the public interest.
7 Wind O&M Costs
8 Q.Please summarize Staffs position as it relates to O&M costs for wind
9 administration and the High Plains, McFadden Ridge I and Dunlap wind
10 projects.
11 A.Staff is proposing a $488,000 (system) reduction in the expense increase.12 requested by the Company for O&M costs associated with the High Plains,
13 McFadden Ridge I and Dunlap wind projects, and a $174,119 (system) reduction
14 in expense associated with wind administration O&M costs.The total reduction
15 proposed by Staff is $662,119 (system).
16 Q.What was the intent behind the O&M expense increase requested by the
17 Company for wind administration and the High Plains, McFadden Ridge I
18 and Dunlap wind projects?
19 A.Staff describes the intent, and the Company agrees, as: "These increases are
20 intended to captue the increase in costs to operate these facilities that were
21 recently placed in service."
22 Q.What is the stated reason for Staff's proposed reductions?.23 A.Staf testified that "The Company has not shown that the 2009 test year expenses
463 Tallman, Di-Reb - 8
Rocky Mountain Power
.1 are insufficient to cover these costs:"
2 Q.What was the basis for Stafrs determination?
3 A.Staff determed that expected costs associated with 2010 contractual expenses
4 are acceptable known and measurable increases to the test year expenses but that
5 2010 expenses budgeted for labor, employee expense and electrcal pars,
6 breakers, fuses fiters, gaskets, gear oils, propane etc. are not sufficiently known
7 and measurable and should not be included in the Company's test year expenses.
8 Q.Does the Company agree with Stafrs contention that the budgeted expenses
9 associated with wind administration and the High Plains, McFadden Ridge I
10 and Dunlap wind projects are not suffciently known and measurable?
11 A.No, the costs that Staff is targeting are costs typically associated with any of the.12 Company's owned wind plants and are the type of costs the Company has indeed
13 experienced in association with fewer wind projects that were operating for the
14 entirety of 2009. Because adding three wind projects at two different sites is
15 indeed known and measurable, it is unreasonable for Staff to declare such
16 expenses associated with the addition of those operating wind projects as not
17 known and therefore unrecoverable.
18 Q.Is there a practical reason the Company doe not have historical expenses
19 associated with the referenced "budgeted expenses"?
20 A.Yes, as my diect testimony described, the High Plains and McFadden Ridge I
21 wind projects reached their commercial operation date ("COD") durng
22 September 2009. In addition, the Dunlap wind project reached its COD on.23 October 1,2010.As a result, actual 2009 expenses largely do not reflect expenses
464 Tallman, Di-Reb ~ 9
Rocky Mountan Power
.1 associated with these paricular wind projects because they were either operating
2 for a very short period of time durng 2009 or not at all (in the case of Dunlap).
3 Q.Did the Company provide Staff with any information regarding expenses the
4 Company incurred during 2009 for other wind projects?
5 A.Yes, in response to data request IPUC 109 the Company itemized actual expenses
6 associated with five wind projects located at two Wyoming sites (Seven Mile Hil,
7 Seven Mile Hil II, Glenrock, Rolling Hils and Glenrock III). These expenses are
8 similar in type to the expenses Staffs has taken issue with. In so doing, the
9 Company demonstrated that the expenses associated with the thee new Wyoming
10 projects (High Plains, McFadden Ridge I and Dunlap) are reasonable and known
11 and measurable on a dollar per site basis as compared with those incured durng.12 2009. Specifically, the Company is seking an additional $488,000 (system) in
13 O&M expenses which amounts to $244,000 per new site. This can be compared
14 to the actual 2009 expense of approximately $319,000 per existing site. When
15 viewed on this basis, the expected costs for 2010 are reasonable as compared to
16 the known and measurable 2009 average cost per site. See Exhibit No. 62.
17 Q.Did the Company provide Staff information regarding expected wind
18 administration costs for 2010 compared to actual costs for 2009?
19 A.Yes, in response to data request IPUC 319 the Company itemized actual wind
20 administration costs for 2009 associated with five sites in the system (Wyoming,
21 Oregon and Washington) as compared to wind administration costs for 2010
22 associated with seven sites in the system (two new sites added in Wyoming). In.23 so doing, the Company demonstrated the reasonableness of its wind
465 Tallman, Di-Reb - 10
Rocky Mountan Power
.
.
1
2
3
4
5
6
7
8 Q.
9
10 A.
11
admnistration costs and the known and measurable nature of the 2010 expenses
on a per site basis. Specifically, the Company is seeking an additional $174,119
(system) which amounts to approximately $262,000 per site within the
Company's portolio (7 total sites in 2010). This can be compared to the actual
2009 expense of approximately $332,000 per site (5 total sites in 2009). When
viewed on this basis, the expected costs for 2010 are reasonable as compared to
the known and measurable 2009 average cost per site. See Exhibit No. 63.
Is Stafls recommended wind administration reduction reasonable given the
information the Company provided Staff in IPUC 319?
No. By recommending a $174,119 (system) reduction in expense associated with
wind administration O&M costs, Staff is expecting the Company to absorb the
12 added admnistration costs associated with thee new wind projects.
13 Conclusion
14 Q.
15
16 A.
17
18
19
20
21
22
.
What conclusion do you have regarding Staff's proposal to reduce the
Dunlap wind project rate base by $1.0 milion (system)?
I conclude that the Dunlap wind project is a very cost effective resource that wil
benefit customers for many years. Staff is inappropriately reviewing the used and
usefulness of the Dunlap Ranch property on the basis of actual WTG and
transmission tower placement. Instead, Staf should have viewed the used and
usefulness of the Dunlap Ranch property on the basis of what the Company knew
at the time the propert was purchased, the cost benefit the property brings
customers (i.e., perpetually avoided lease costs) and the ongoing benefit the
466 Tallman, Di-Reb - 11
Rocky Mountain Power
.1 propert brigs customers (e.g., revenues from the agricultural lease) as well as
2 the overall public interest.
3 Q.What are the policy implications of Staff's rate base reduction
4 recommendation?
5 A.From a policy perspective, accepting Staff's proposal sends a signal that land
6 right acquisitions for wind project sites should not be governed by what is in the
7 overall cost effective interest of customers, but rather based on how many of the
8 propert sections wil house WTG or transmission towers. Such an approach
9 does not constitute a least cost approach to generation development and is
10 contrar to the best Înterest of customers. The Company maintans that
11 acquisition of the Dunlap Ranch in its entirety was its only option, it was not.12 available piecemeal, and that the acquisition was indeed prudent, in the best
13 interest of customers, and constitutes a used and useful asset in the public interest.
14 Q.What recommendation do you have for the Commission regarding Staff's
15 proposed Dunlap wind project rate base reduction?
16 A.I recommend the Commssion reject Staff's proposed $1.0 millon adjustment
17 associated with the Dunlap Ranch property and reject Staff s recommendation to
18 have $1.0 millon associated with the Dunlap Ranch property put into Account
19 105 (property held for futue use).
.
467 Tallman, Di-Reb - 12
Rocky Mountain Power
.
468 Tallman, Di-Reb - 13
Rocky Mountain Power
.
.
.
1 (The following proceedings were had in
2 open hear ing . )
3 Q.BY MR. SQLANDER: And, Mr. Tallman, are you also
4 adopting the testimony and exhibits of any other witness in
5 this proceeding?
6 A.I am.
7 Q.And would that be the direct testimony filed by
8 Stefan Bird on May 28th, and his accompanying Exhibits 15A
9 through 19?
10 A.Yes.
11 Q.And do you have any corrections or changes to
12 Mr. Bird i s testimony or exhibits?
13 A.No.
14 MR. SOLANDER: I would now move, Madam Chair,
15 that the prefiled direct testimony of Stefan Bird be spread
16 upon the record as if read, and Exhibits 15A through 19 be
17 marked for identification.
18 COMMISSIONER SMITH: Is there any objection?
19 Seeing none, that is so ordered.
20 (The following prefiled direct testimony
21 of Mr. Bird is spread upon the record.)
22
23
24
25
469
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
TALLMAN (Di)
RMP
.1 Q.Please state your name, business address and present position with Rocky
2 Mountain Power ("Company").
3 A.My name is Stefan A. Bird. My business address is 825 NE Multnomah, Suite
4 600, Portland, Oregon 97232. My present position is Senior Vice President of
5 Commercial and Trading.
6 Qualifications
7 Q.
8 A.
9
10
11.12
13
14
15
16
17
18
19
20
21
22
23.
Please describe your educational and professional background.
I hold a B.S. in mechanical engineering from Kansas State University. Ijoined
PacifiCorp Energy and assumed my curent position in Januar 2007. From 2003
to 2006, I served as president of CalEnergy Generation U.S., an owner and
operator of Qualifying Facility and merchant generation assets, including
geothermal and natual gas-fired cogeneration projects across the United States.
Prom 1999 to 2003, I was vice president of acquisitions and development for
MidAmerican Energy Holdings Company. From 1989 to 1997, I held multiple
positions at Koch Industries, Inc., including energy trading, financial trading,
acquisitions, project engineering and maintenance planning in the United States,
Latin America and Europe.
In my current position I oversee the Company's Commercial and Trading
organization which is responsible for electricity and natural gas wholesale
activities, dispatch of all of the Company's owned and contracted generation
resources, and wholesale purchases and sales to balance the Company's load and
resources. My organization is also responsible for the Company's load and
revenue forecast, integrated resource plan ("IRP") and net power costs ("NPC")
470
Bird, Di - 1
Rocky Mountain Power
.1 modeling. Most relevant to this case, I am responsible for acquisition of power
2 resources for utilzation in the Company's east and west balancing authorities (the
3 "System") by means that include the nègotiation of power purchase agreements
4 ("PP As") and the acquisition of generation resoures through the requests for
5 proposals ("RF") process.
6 Purpose and Overview of Testimony
7 Q.
8 A.
9
10
11.12
13
14
15
16
17
18
19
20
21
22.23
What is the purpose of your testimony?
The purpose of my testimony is to demonstrate the prudence of the Three Buttes
Windpower LLC ("Three Buttes") PPA, the Top of the World Wind Energy, LLC
("Top of the World") PPA, and the Dunlap I wind-powered generation resource
("Dunlap I") for which the Company is seeking cost recovery in this proceedig.
In addition, my testimony describes the 2010 renewable energy credit ("REC")
sales revenue included in this proceeding and includes discussion of REC sales
volume, price and revenue uncertainty. Specifically, my testimony:
. Describes the procedural history of the 2008R RFP;
. Provides a description of Thee Buttes, and describes the economic
analysis and selection of Thee Buttes as a resource for the Company;
. Describes the procedural history of the 2008R -1 RFP;
. Provides a description of Top of the World and describes the economic
analysis and selection of Top of the World as a resource for the Company;
. Describes the procedural history of the 2009R RF;
. Provides a description of Dunlap I and describes the economic analysis
and selection of Dunlap I as a resource for the Company; and
471 Bird, Di - 2
Rocky Mountain Power
.1
2
3 Q.
4 A.
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22.23
. Provides a description of 2010 REC sales revenue and a description of
forecast REC sales volume, price and revenue uncertainty.
Please summarize your testimony.
The Three Buttes PPA, the Top of the World PPA and Dunlap I resources are
prudent acquisitions that contrbute to PacifiCorp's diverse and cost-effective
portfolio of resources. The Three Buttes PPA was acquired as a result of a fai,
transparent and robust competitive solicitation process, the 2008R RFP, that
solicited bids for renewable resources less than 100 megawatts ("MW") or any
size with contract term less than five years. The Top of the World and the Dunlap
I projects were also both acquired though fai, transparent and robust competitive
bidding processes, namely the 2008R-l RFP and the 2009R RFP, which were
both overseen by an independent evaluator ("IE"). I discuss each resource in
sequence by first providing a general overview of the 2008R RF, 2008R-l RF
and 2009R RFP. I then provide a description of the economic analysis and
selection of the Initial Shortlist and Final Shortlist in each RFP. Last I describe
the negotiation and ultimate selection of each resource.
In addition to the thee renewable resources, I discuss PacifiCorp's 2010
REC sales revenues included in this proceeding, which is $91.8 milion. A large
portion of the 2010 REC sales revenue is based on known and measurable
transactions. However, actual 2010 REC sales revenue wil be higher or lower
due to uncertainty in REC market prices and due to uncertnty in actual 2010
REC production which could be higher or lower due primaly to weather
uncertinty. Forecasting REC sales revenue beyond 2010 is highly speculative
472 Bird, Di - 3
Rocky Mountain Power
.1
2
and could var by tens of millons of dollars per year given the one-off natue of
high value REC trasactions in 2010, lack of REC market transparency and
3 liquidity ~ uncertain REC market regulatory environment, uncertain REC market
4 prices, uncertain REC production, uncertain legislative renewable compliance
5 requirements, and potential requirement for carbon offsets to comply with carbon
6 legislation, which could potentially reduce REC sales revenue to zero.
7 The 2008R RFP
8 Q.
9
10 A.
11.12
13
14
15 Q.
16
17 A.
18
19
20
21
22
23.
Did the Company issue a renewable Request for Proposals (õ2008R RI"P") in
2008?
Yes. The 2008R RFP was issued on Januar 31, 2008, and solicited renewable
resources less than 100 MW or any size with contract term less than five years.
Bids under the 2008RRFP were due and received on March 31, 2008. The 2008R
RFP is posted on the Company wehsiteat
http://www.pacificorp.comlsup/rfpsIr2rr.htmL
Why did the Company issue the W08R RFP without seeking certin state
Commission approval in contrast to the 2008R~1 RFP and 2009R RFP?
As of January 2008 the production tax credit had not been extended beyond the
end of 2009 and renewal of the production tax credit was uncertain. The
Company determined it had a short window to issue a request for proposals,
receive bids, evaluate, negotiate and execute cost-effective transaction(s) that
could he constructed and achieve commercial operation prior to the expiration of
the production tax credit. The Company limted bids to less than 100 lvfW or any
size with contract term less than five years to comply with Oregon Public Utilty
473 Bird, Di - 4
Rocky Mountain Power
.1
2
3
4
5
6
7
8 Q.
9
10 A.
11
.12
13 Q.
14 A.
15 Q.
16 A.
17
18
19
20
21
22 Q.
23 A..
Commission (Oregon Commission) and Public Service Commission of Utah
(Utah Commission) procurement guidelines. \Vithout the resource size limitation,
maintaining compliance with the Oregon Commission and Utah Commission
procurement guidelines would have otherwise required a more protracted
procurement timeframe and put at iisk the abilty to acquire cost effective
renewable resource(s) through a competitive solicitation before the production tax
credit expired.
Is the 2008R Rl"P consistent with regubitory guidelines for resource
procurement?
Yes. The 2008R RFP is consistent with regulatory guidelines for resource
procurement as stipulated by the Oregon and Utah Commissions. TIie Idaho
Commission does not have specific resource procurement guidelines.
Please descrihe the market response to the2008R RFI).
PacifiCorp received. 29 proposals from 11 different bidders.
Please describe the evaluation process for the W08R RFP.
The economic analysis for the 2008R RFP was completed in two steps. The
Initial Shortlist evaluation was a screening process that evaluated proposals on
price (70%) and non-price (30%) considerations. This initial screening was
followed by the Final Shortlist evaluation which usedthe IR Planing and Risk
("PaR") model consistent with the Company's renewable resource valuation
methodology, the alternative cost for compliance ("ACC").
Explain the evaluation which resulted in the Initial Shortlist.
The Initial Short List resulted from a screening process that ranked the proposals
4 74
Bird, Di - 5
Rocky Mountain Power
on price and non-price factors. The price factors were determed using
PacifiCorp's Structuring and Pricing RFP Base Model to develop a comparson
metrc that projected net present value revenue requirement (net PVRR) per
kîlowatt month (net PVRRW-mo) for each bid. The net PVRR component
combines the positive value of energy and capacity with negative offsetting costs.
The net PVRRW-mo metrc is the levelized annuity value which, when applied
to the nominal kîlowatts on a monthly basis and present-valued, wil result in the
net PVRR. The non-price factors included evaluation of positive or negative
conformty to 2008R RFP bid requirements including the draft PPA or build own
transfer documents, transmission availabilty and interconnection status,
development status of the resource, bidder experience, bidder creditwortiness
and performance guarantees. Of the 29 proposals received, five proposals had a
positive net present value and were placed on the Initial Short List.
Please describe the Final Short List evaluation in the 2008RRFP.
PacifiCorp used the IRP PaR model to complete an ACC calculation for each of
the five proposals on the Initial Short List to determne the Final Shortlist.
What is the ACC method?
The ACC method uses the Company's IRP production cost simulation model and
its Forward Price Curve to generate a market-based alternative cost comparson of
bid resources. To establish the market-based alternative, the Company firt runs
the IRP production cost simulation model (the Planning and Risk, or PaR model)
in stochastic mode using the then curent IRP preferred portolio. The IR PaR
model is then run a second time with the uncommtted futue renewable resources
475
Bird, Di - 6
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10
11 Q..12 A.
13
14
15
16 Q.
17
18 A.
19
20
21
22
23.
removed from the preferred portolio. The difference between the two runs
establishes the maket-based alternative cost. Costs and benefits of the specific
bid resources being considered are compared agaist the IRP PaR model market-
based alternative. The resulting comparson metrc is an ACC value for each
resource bid, which represents the resource cost over the life of the project that
yields a zero net PVRR difference with respect to the IRP PaR model's maket-
based resource alternative. A negative ACC value, expressed in dollars-per-
MWh, indicates that the bid resource compares favorably to the market-based
alternative, whereas a positive ACC value indicates that the bid resource
compares unfavorably to the market-based alternative.
Please describe the results of' the 2008R RFP Final Short List~
The Final Short List resulted in three proposals with favorable ACC values. All
thee P!ojects were located in Wyoming. Two of the thee proposals were
substantially more favorable than the third. Therefore, PacifiCorp elected to
engage the two more favorable bids in negotiations for a PP A.
Please describe the result~ ofthe negotiations 'With the 2008R RFP Final
Sbort List bidders.
PacifiCorp entered into negotiations with two of the bidders included on the Final
Short List in early summer 2008. The first bidder's project was a 49.5 megawatt
project located in Wyoming. PacifCorp termated negotiations with this
counterpary in late 2008 after several months of negotiations because the
counterpary was unwiling to agree to terms and conditions in the PP A that
would provide adequate protection to customers consistent with terms and
476 Bird, Di-7
Rocky Mountain Power
.1
2
3
4
5
6
7 Q.
8
9 A.
10
11.12
13
14
15
16
17
18
19
20
21
.
cònditions in other PacifiCorp executed wind PP As. The second bidder's project
is a 99 megawatt project located in Wyomig. Following successful negotiations
that were held in parallel with the negotiations with the other bidder described
above, PacifiCorp executed a PPA with this bidder on September 5,2008. This
bidder is identified as Three Buttes Windpower LLC, an entity owned by Duke
Energy Corp.
Please describe the basic terms of'the transaction with Three Buttes
\Vindpower LLC.
The transaction is a 99 megawatt PP A with Thee Buttes Windpower LLC. The
transaction allows PacifiCorp to purchase all of the output and RECs of the 99
megawatt project for a term of 20 years. PacifiCorp has the option to purchase
the facilty at fai market value at the conclusion of the initial 20 year term. The
project reached commercial operation on December 1, 2009. The project is
located in Natrona and Converse counties in Wyoming. The project utilzes 66
General Electric 1.5 megawatt sle (model) wind turbine generators. The terms
and conditions included in the PP A are consistent with other PacifiCorp wind
PP As. The 2008R RFP resulted in acquisition of a cost-effective 99 megawatt
wind resource in Wyoming. Confidential Exhibit No. 15 is a copy of the PPA
with Three Buttes Windpower LLC.1 The contract was included in the
Company's net power cost analysis, for a summar of the net power cost please
refer to Company witness Dr. Hui Shu's testimony.
i Due to the large size of the exhibits attached to the PPA with Th Buttes Windpower lLC, only the
contract is attached hereto. The Company wil be pleased to provide copies of the exhibits upon request.
477 Bird, Di - 8
Rocky Mountain Power
.1 The 2008R-l RFP
2 Q.Please describe the 2008R-l RFP procedural history.
3 A.The Company fied its initial application for the 2008R-l RF on March 4, 2008.
4 The purose of the 2008R-l RFP was to request and evaluate proposals to fulfill a
5 portion of the renewable resource generation identified in the Company's 2007
6 Integrated Resource Plan ("2007 IRP"). To that end, the 2008R-l RFP solicited
7 System-wide renewable resources that would enable the Company to meet its
8 service obligations. The 2008R-l RFP targeted acquisition of up to 500 MW of
9 renewable resources with commercial operation dates prior to December 31, 2011
10 and with a lîmit of 300 MW per resource.2 The 2008R-l RFP was issued to the
11 market on October 6, 2008, with proposals due December 22, 2008..12 Q.Did the Idaho Commission approve the 2008R-l RFP?
13 A.The Idaho Commssion does not require approval of Company RFPs.
14 Q.Was the 2008R-l RFP approved by a commission in another state?
15 A.Yes, on September 23,2008, the Oregon Commssion approved the 2008R-l
16 RFP, with certain conditions that were all satisfied by the Company.3
17 Q.Was an independent evaluator hired to oversee the 2008R-l RFP?
18 A.Yes, the Oregon Commssion hired and the Company contracted with Boston
19 Pacific to be the IE.
20 Q.Describe the market response to the 200R-l RFP.
21 A.The Company received 37 bids from 20 bidders on December 22, 2008.
.2 300 MW is the upper limt permtted by Utah Senate Bil 202. Qualfying Facilities that are at least 10
MW were eligible, pursuant to Guideline 6 in Order No. 06-44.3 See Order No. 08-476.
478 Bird, Di - 9
Rocky Mountain Power
.1 Q.Did the Company re-issue the 200R-l RFP after receipt of proposals on
2 December 22, 2008?
3 A.Yes. Because the acquisition of a successful resource under the 2008R-l RF
4 would not occur until 2009, the Company was required to amend and reissue the
5 2008R-l RFP to accommodate Utah's resource procurement law.4
6 Q.What were the changes to the Amended 2008R-l RFP?
7 A.The Amended 2008R-l RFP included three changes: (1) it allowed the original
8 bidders to update their proposals; (2) it provided new bidders the opportnity to
9 bid into the Amended 2008R -1 RF; and (3) it modified the schedule to allow for
10 updated and new proposals.
11 Q.Was the Amended 2008R-l RFP approved by a commission in another sta~?.12 A.Yes. The OregotlCommssion approved the Amended 2008R-l RFP on Januar
13 21,2009.5 The Company issued the Amended 2008R-l RF to the maket on
14 Januar 26,2009, with proposals due Februar 27,2009.
15 Q.Describe the market response to the Amended 2008R-l RFP.
16 A.The Company received 50 bids from 22 bidders on Februar 27,2009.
17 Q.Please describe the Amended 2008R-l RFP Initial Shortlist selection process.
18 A.The Company's analysis of the Amended 2008R-l RFP proposals focused on
19 determing which resources would provide the best value to customers on a
20 System-wide planning basis to meet customer requirements at the least cost, on a
21 risk-adjusted basis. To achieve these objectives, the Company evaluated
22 alternatives in a two step process. First, the Company selected thee Initial
.4 See Utah Code Ann. 54-17-502(2) (a) (i).
5 See Order No. 09-017.
479 Bird, Di - 10
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22
.
Shortlists: (a) west wind; (b) east wind; and (c) all other renewable resources.
The purose of first selecting three separate Initial Shortlists was to capture
location resource diversity and the different sources of renewable resources.
To select groups of proposals to comprise each of the thee Initial
Shortlists, the IE agreed with the Company's goals to: (1) select the proposals
with the greatest net benefit in term of price and non-price benefits; (2) select a
diversity of bidders and projects; (3) select a mix ofPPA and build-own-transfer
("BOTs") alternatives; (4) determne a relatively clear split between the score of
the last proposal evaluated and the next proposal that was not selected; and (5)
achieve the RFP goal that each category contain up to 500 MW or 5 proposals.6
Each proposal received up to a maximum of 100 points. The thee Initial
Shortists were comprised of the highest scorig proposals in each of the thee
respective segments, based on price (up to 70 points) and non-price factors (up to
30 points). The price factor was derived by using the PacifiCorp Structuring and
Pricing RFP base model, which determnes the top-performng proposals on the
basis of the net pPVRRW-mo. The Net PVRR component views the value of
the energy and càpacity as a positive and the offsetting costs of the proposal as a
negative. The more positive the Net PVRR, the more valuable a given resource is
to the Company's customers.
The non-price factors evaluated were negative or positive based on the
following criteria: (a) conformty with Amended 2008R-l RFP proposal
requirements; (b) conformty with the pro form PPA or BOT documents and/or
6 See The Oregon Independent Evaluator's Final Closing Report on PacifiCorp's 2008R-l/Renewables RF
(MayI5, 2(09) at p. 13, (Exhibit No. 16).
480
Bird, Di - 11
Rocky Mountain Power
.1 Asset Acquisition and Sale Agreement, attched as exhibits to the Amended
2 2008R-l RFP; (c) feasibilty of the proposal; (d) site control or permtting of the
3 proposal; and (e) operational viabilty of the proposal. Based on the application
4 of the price and non-price factors, the Company selected proposals to comprise
5 the Initial Shortlists.
6 Q.Please describe the Amended 2008R-l RFP Final Shortlist selection process.
7 A.After the Company selected the thee Initial Shortlists, it moved to step two of the
8 evaluation process - selection of the Final Shortlist. To select the Final Shortlist,
9 the Company applied its ACC analysis methodology for renewable resources to
10 each of the three Initial Shortlists. Ths resource-specific analysis allows the
11 Company to compare a resource against the potential next highest alternative cost.12 for renewable resource compliance. In essence, the result of the ACC analysis
13 shows how the resource compares to the undifferentiated power market. The
14 ACC analysis also incorporates a resource's risk-adjusted system benefit, using
15 the Company's IRP stochastic production cost modeL. A negative ACC indicates
16 that the resource is valued below undifferentiated market alternatives; whereas a
17 positive ACC indicates that the resource is valued above undifferentiated maket
18 alternatives. Upon completion of the ACC analysis and the PVRR (d) analysis,
19 the Company selected four alternatives for inclusion in the Final Shortlist, one of
20 which was Top of the World.
21 Q.Did the IE concur with the Amended 2008R-l Final Shortlist and
22 recommend acknowledgment?
23 A.Yes. The IE concured with the selection of the Final Shortlist and reommended.
481 Bird, Di - 12
Rocky Mountain Power
.1
2
3
4
5 Q.
6
7 A.
8
9
10
11.12
13
14
15
16
17
18 Q.
19
20 A.
21
22
23
24.
its acknowledgment by the Oregon Commssion. See The Oregon Independent
Evaluator's Final Closing Report on PacifiCorp's 2008R-l Renewables RFP
(May 15, 2009) ("2008 R-l Final Report"), attched as Confidential Exhibit No.
16.7
Please explain the basis of the IE's recommendation, as outlined in the IE's
2008 R-IFinal Report.
The IE based its recommendation to acknowledge the Amended 2008R-l RF
Final Shortlist on six key points. First, the selected proposals represented the
resources with the greatest net benefits to customers as determed by the ACe.
Second, the proposals represented the top options from a competitive process.
Thir, the IE's analysis confired that the selected proposals represent the lowest
cost alternatives for customers, with an accounting for risk. Four, the shortlist
provided a diversity of projects, bidders, and transaction types for negotiations
going forward. Fifth, the Amended 2008R-l RFP aligned with the Company's
IRP process. Sixth, the Company agreed to conduct an analysis at the time it
made its procurement decision to show how the accuracy of output projections
and asset life were reflected in the final decision.
Did the IE determine that the Amended 2008R-l RFP process was fair and
transparent?
Yes. On page 14, the 2008 R-l Final Report states:
(Thoughout the 2008R-l process the IE was) in constant contact
with the Company and had multiple discussions on dozens of
issues. The IE believes the quality of the effort is reflected in the
excellent response to the RFP. All of this work has led to what we
7 Due to the large size of the exhibits included in the 2008 R - 1 Final Report, only the report itself is
attached hereto. The Company wil be pleased to prvide copies of the exhibits upon request.
482
Bird, Di - 13
Rocky Mountain Power
.1 believe was a fai and transparent process which complies with
2 Commssion guidelines and wil, we hope, lead to a positive result
3 with the supply of new renewable resources for the ratepayers.. .
4 Q.Did the IE conclude that the negotiation phase of the RFP was conducted in a
5 fair and reasonable manner?
6 A.Yes. The IE concluded that the negotiation phase of the Amended 2008R-l RF
7 process was cared out in a fai and reasonable manner. See Boston Pacifc
8 report of the Independent Evaluators on negotiations in PacifiCorp 2008R -IRFP
9 (September 18,2009) at p. 1, attched as Confidential Exhibit No. 17.8
10 Q.Did the IE's report on the negotiation phase of the RFP conclude that Top of
11 the World was the best choice of projects from the fina shortlist?
12 A.Yes. The IE considered price, technology and wilingness to meet the
.13 requirements of the RFP in reaching this conclusion.
14 Q.Does the record developed in the RFP process show that Top of the World is
15 a prudent and cost-effective resource?
16 A.Yes. Additionally, the acquisition of Top of the Wodd is consistent with
17 PacifiCorp's IRP action plan and PacifiCorp's renewable resource commtments
18 resulting from the MidAmerican Energy Holdings Company acquisition. These
19 are generally discussed in the direct testimony of Company witness Mr. Mark R.
20 Tallman in this Application.
21 Q.Please describe the Top of the World PPA.
22 A.Top of the World is a 20-year PPA for 200.2 MW and associated renewable
23 energy credits. The Company wil purchase all of the output associated with the
.8 Due to the large size of the exhibits in the Boston Pacific report of the hidependent Evaluators on
negotiations in PacifiCorp 2008 R-IRFP (September, 2009), only the report is attached hereto. The
Company wil be pleased to provide copies of the exhibits upon request.
483 Bird, Di - 14
Rocky Mountain Power
project. PacifCorp has the option to purchase the facilty at fai market value at1.the conclusion of the initial 20-year term. The Top of the World project is2
3 comprised of 66 General Electrc tubines (each capable of producing 1.5 MW)
4 and 44 Siemens Energy, Inc. tubines (each capable of producing 2.3 MW). The
5 project is located near Casper, Wyoming and is expected to reach commercial
6 operation on or before November 1, 2010. The terms and conditions of the PP A
7 are consistent with other wind PP As entered into by the Company. Confidential
8 Exhibit No. 15 also contains a copy of the PPA with Top of the World.9 The
9 contract was included in the Company's net power cost analysis, for a summ
10 of the net power cost please refer to Company witness Dr. Shu's testimony.
11 The 2009R RFP.12 Q.
13 A.
14
15
16
17
18
19
20
Please describe the 209R RFP.
The 2009RRFP targeted acquisition of up to 500 MW of System-wide renewable
resources with commercial operation dates between 2010 and 2012 and where no
single resource exceeding 300 MW10 would be acquired. Eligible resources were
also required to: (1) meet an expected annual output of at least 25,000 megawatt-
hours ("MW") after accounting for planned and unplanned outages; (2) include
associated renewable energy credits ("RECs"); and (3) comply with renewable
portfolio standard ("RPS") requirements in the Company's six-state service area.
The 2009R RFP also allowed for the submission of a Company Benchmak.
9 Due to the large size of the exhibits attached to the PPA with Top of the World, only the contract is
attached hereto. The Company wil be pleased to provide copies of the exhibits upon request.10 300 MW is the upper limit permtted by Uta Code Ann. § 54-17-502. Qualfying Facilities that are at
least 10 MW are eligible, puruant to Guideline 6 in Order No. 05-44.
484
.
Bird, Di - 15
Rocky Mountain Power
.1
2
3
4
5
6
7 Q.
8
9 A.
10
11
.12
13
14
15
16
17 Q.
18
19 A.
20
21
22
23.
conversations with the Company's generation personneL. The IE's stated prima
concern was the potential omission of capita costs. Accordingly, the IE focuse
on ensurng that appropriate capital costs were included in the Company
Benchmark. As an additional check, the IE compared the Company Benchmark
capital costs and estimated capacity factors to proposals from the 2008R -1 RFP
the IE considered comparable.
What did the Benchmark Memo conclude with respect to the inclusion of
capital costs in the Benchmark?
The Benchmark Memo concluded that all capital costs were properly included
and that the level of the Company Benchmark's estimated capital costs were
appropriate. The IE also found that the Company Benchmak capital costs were
within the range of comparable costs as indicated by proposals in the 2008R-l
RFP. Finally, the IE found that the estimated annual Benchmark capacity factor,
while in the high range compared to all proposals in the 2008R-l RFP, was within
the range of capacity factors from proposals associated with potential resources in
the nearby vicinity.
11
Why did the Company submit a Company Renchmark and what role did it
play in the RFP process?
The Company's Benchmark played an important role in the 2009R RF process
by providing a cost-based alternative for the benefit of customers. The Company
received proposals in the 2009R RFP under a multitude of strctues with varing
terms and conditions that served as alternatives to the Company Benchmark
including PP As, and BOTs. Including a Benchmak provides a benefit for
11 See Benchmark Memo at p. 11-12, (Exhibit No. 18).
486
Bird, Di - 17
Rocky Mountain Power
.1
2
3
4 Q.
5 A.
6
7
8
9
10
11
.12
13
14
15
16
17
18
19
20
21
22
customers because it serves as a check on market-based proposals, it provides a
resource alternative that the Company is prepared to undertake, and it shields
customers from 100 percent market exposure.
Please describe the 2009R RFP Initial Shortlist selection process.
The Company's analysis of the 2009R RFP proposals focused on determning
which resources would provide the best value to customers on a System-wide
planning basis to meet customer requirements at the least cost, on a risk adjusted
basis. To achieve these objectives, the Company evaluated alternatives in a two
step process. First, the Company selected three Initial Shortlists: (a) west wind;
(b) east wind; and (c) all other renewable resources. The purpose of first selecting
three separate Initial Shortlists was to captue location resource diversity and the
different sources of renewable resources.
To select groups of proposals to comprise each of the thre Initial
Shortlists, the IE agreed with the Company's goal to: (a) select the proposals with
the greatest net benefit in terms of price and non-price benefits; (b) select a
diversity of proposals and projects; (c) select a mix ofPPAs and BOTs; (d)
determe a relatively clear split between the score of the last proposal priced and
the next proposal that was not selected; and (e) achieve the RF goal that each
category contain up to 500 MW or five proposals. See The Oregon Independent
Evaluator's Final Closing Report on PacifiCorp's 2009R Renewables RFP
(November 5,2009) ("2009R Final Report") at p. 12. The 2009R Final Report is
attached as Confidential Exhibit No. 19.12
.12 Due to the large size of the exhibits to the 200R Final Report, only the report itself is attached hereto.
The Company wil be pleased to provide copies of the exhibits upon request.
487
Bird, Di - 18
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20 Q.
21
22 A.
.
Each proposal received up to a maximum of 100 points. The three Initial
Shortlists were comprised of the highest scoring proposals in each of the thee
respective segments, based on price (up to 70 points) and non-price factors (up to
30 points). The price factor was derived by using the PacifiCorp Strcturig and
Pricing RFP base model, which determnes the top performng proposals on the
basis of the Net PVRRW-mo. The Net PVRR component views the value of
the energy and capacity as a positive and the offsetting costs of the proposal as a
negative. The more positive the Net PVRR, the more valuable a given resoure is
to the Company's customers.
The non-price factors evaluated were negative or positive based on the
following criteria: (a) conformty with 2009R RFP proposal requirements;'(b)
conformty with the pro forma PPA or BOT documents and/or Asset Acquisition
and Sale Agreement attached as exhibits to the 2009R RFP; (c) feasibilty of the
proposal; (d) site control or permtting of the proposal; and (e) operational
viabilty of the proposaL. Based on the application of the price and non-price
factors, the Company selected proposals to comprise the Initial Shortlists. The
Initial Shortlist contained a total of 14 resource alternatives (13 proposals from
the market and the Company Benchmark). The 14 alternatives contained five east
wind resources, four west wind resources and five other renewable resources.
Did the IE agree with the Company's selection of alternatives contained in
the three Initial Shortlists?
Yes. The IE agreed with the Company's selection of the three Initial Shortlists.13
13 See 2009R Final Report at pp. 11-14, (Exhibit No. 19).
488
Bird, Di - 19
Rocky Mountain Power
.1
2
3
4 Q.
5 A.
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22
.
23
24
25
26
27
28
in a location recently designated as a Greater Sage-Grouse Core Area.
Wyoming's Greater Sage-Grouse Core Area is discussed in more detail later in
my testimony.
What did the IE conclude in its 2009R Final Report on the Final Shortlit?
The IE based its recommendations to acknowledge the Final Shortlist on six key
points. First, the selected alternatives represented the resources with the greatest
net benefits to customers as determned by the ACe. Second, the alternatives
represented the top options from a competitive process where the Company
received proposals from 26 suppliers offering a total of 39 projects. Some of
these projects offered multiple options for a total of 82 proposal options and over
9,400 MW. Third, the IE's report states:
independent analysis confired that the selected bids
represent the lowest cost alternatives for ratepayers, with an
accounting for risk. Our independent analysis included the
creation of our own cost annuity models for each bid
option, a review of PacifiCorp' s models, and a thorough
review of the terms and condition of each bid.
14
Fourth, The RFP aligns with the Company's IRP process. The Initial and Final
Shortlist analyses used curent assumptions from the IRP. In addition, the ACC
analysis uses a model from the Company's IR process to calculate the benefit of
renewable resources. Fifth, the Company Benchmark is included in the Final
Shortlist and the IE took special care to confir that selection, noting:
(w)e confired the accuracy of the Benchmark costs and
scoring and provided the Commssion with a complete
review of all costs of the project prior to bid reeipt. We
also confired the Benchmak's status by; (a) reviewing
the project's initial and final shortlist scores and models,
(b) independently scoring the project's non-price
14 ¡d. at p. 3.
490 Bird, Di - 21
Rocky Mountain Power
.1
2
3
characteristics, (c) comparng the cost and output of the
project to recent thd-pary bids, and (d) evaluating the bid
costs in our own cost modei.15
4 Sixth, while there were two bids targeted for acquisition the' shortlist also includes
5 two 'back- up' bids which provides some assurance that, should negotiations fall
6 though with a bidder, the RFP may stil result in a winner in addition to the
7 Benchmark. 16
8 Dunlap I
9 Q.
10 A.
11
12.13
14
15
16 Q.
17 A.
18
19
20 Q.
21 A.
22
23
.
Please describe Dunlap I.
Dunlap I is alII MW wind project consisting of 74 wind turbine generators, an
electrcal collector system, a 34.5 to 230 kV collector substation (known as the
Dunlap substation), a 230 kV transmission line (approximately 11 miles in
length), 230 kV breakers, access roads, an operations & mantenance building and
required communication and control facilities (e.g., metering, hardware, software,
and associated communication circuits and other equipment).
Where wil Dunlap I be located?
Dunlap I wil be located approximately eight miles nort of Medicine Bow,
Wyoming in Carbon County on property consisting of approximately 16,500
acres (the "Site").
Why is the Site an appropriate place to construct Dunlap I?
The Site is appropriate for Dunlap I for thee primary reasons: (1) studies indicate
the Site wil result in a desirable wind resource; (2) the Site is located in close
proximity to the Company's transmission system and another Company-owned
15 2009R Final Report at p. 3, (Exhibit No. 19).
16 ¡d. at p. 4.
491 Bird, Di - 22
Rocky Mountain Power
.1 wind project; and (3) the Company owns the majority of the Site land, thereby
2 avoiding third-par royalty payments at a benefit to customers.
3 Q.Please explain the division of land ownership within the Site.
4 A.The Company owns the vast majority of the Site land. The Burau of Land
5 Management ("BLM") owns two sections, the state of Wyoming owns
6 approximately two and one half sections and one section is held by a private a
7 third pary.
8 Q.Please explain if any of the Dunlap I facilities wil be located on land not
9 owned by the Company.
10 A.The Company has no rights at this time to use the BLM land and no plans to place
11 facilties on BLM lands. The Company holds a lease for the state lands and.12 intends to cross one section with a 230 kV transmission line. At this time,
13 placement of wind turbine generators ("WTGs") on the state lands is not planned
14 for Dunlap i. Although the Company plans to install electrical facilities on the
15 third-pary lands, there are no plans for the placement of Dunlap I WTGson such
16 lands at this time. Finally, the Company holds a lease to an additional state
17 section that the transmission line from the Site to the point of interconnection with
18 the Company's transmission system wil cross. The remainder of the transmission
19 right-of-way is on land leased from a private entity.
20 Q.Has the Company performed an evaluation of the wind potential at the Site?
21 A.Yes. Wind potential studies were performed by the Company's consultant as par
22 of the Company's Benchmark submittal. In addition, as par of the 2009R RF
23 process, the Company retained a separate independent consultant to perform an.
492 Bird, Di - 23
Rocky Mountain Power
493 Bird, Di - 24
Rocky Mountain Power
.1 Q.Is Dunlap I in the Greater Sage-Grouse Core area?
2 A.No. The Dunlap I facilities, including the 230 kV transmission line, are not
3 located in the Greater Sage-Grouse Core Area.
4 Q.What is the projected commercial operation date for Dunlap I?
5 A.The projected commercial operation date for Dunlap I is November 1,2010.
6 Q.What investment related to the Dunlap I resource is included in the revenue
7 requirement in this case?
8 A.The Company has included $261.2 millon for Dunlap I in this case.This amount
9 is consistent with the amount utilzed in the evaluation and selection of the 2009R
10 RFP Final Shortlist and reviewed by the IE. The operation and maintenance costs
11 included in this case associated with Dunlap I are $2.4 millon for WTG.12 maintenance, permttng obligations, local levy tax, and land use payments. The
13 testimony of Company witness Mr. Steven R. McDougal includes the revenue
14 requirement calculations with the inclusion of this resource. Dunlap I was
15 included in the Company's net power cost analysis, for a summar of the net
16 power cost please refer to Company witness Dr. Shu's testimony.
17 Q.Does the record developed in the RFP process show that Dunlap I is a
18 prudent and cost-effective resource?
19 A.Yes. Additionally, the acquisition of Dunlap I is consistent with PacifiCorp's IRP
20 action plan and PacifiCorp's renewable resource commtments resulting from the
21 MEHC acquisition.
.
494 Bird, Di - 25
Rocky Mountain Power
.1 2010 Renewable Energy Credit sales revenue
2 Q. What is PacifiCorp's 2010 REC sales revenue in this proceeding?
3 A.PacifiCorp's 2010 REC sales revenue in this proceeding is $91.8 milion. The
4 testimony of Company Witness Mr. McDougal includes the revenue requirement
impacts of the 2010 REC sales revenue. Page 3.6.3 of Mr. McDougal's Exhibit
NO.2 provides the detai behind the 2010 REC salès revenue.
Is there uncertainty in the 2010 REC sales revenue?
Yes. Although a large portion of the 2010 REC sales revenue is based on known
and measurable transactions, actual 2010 REC sales wil be higher or lower due to
speculation related to unkown REC transactions given the uncertain REC market
regulatory environment, uncertain REC market prices and uncertain REC
production volume due primay to weather uncertainty.
Is it reasonable to use 2010 REC sales revenue as a proxy for future REC
sales?
No. The 2010 REC sales revenue is extraordinar due to several high value one-
off transactions that were executed during a unique window of oppòrtnity in a
highly iliquid market. Curent regulatory uncertainty in California regarding
eligible REC transactions prevents the abilty to execute incrementa comparable
transactions with the investor owned utilties in California. PacifiCorp's abilty to
execute comparable high value REC sales transactions with other counterparies is
limited by market demand, counterpary resource eligibilty and transmission
delivery restrctions.
495 Bird, Di - 26
Rocky Mountain Power
.1 Q.Could REC sales revenue beyond 2010 vary by tens of milons of dollars and
2 potentially fall to zero?
3 A.Yes. PacifiCorp has executed certain high value REC transactions that extend
4 through 2012, so those revenues are known and measurable assuming the RECs
5 supporting these sales are produced. However, REC sales that have not been
6 executed are highly speculative due to the uncertain REC market regulatory
7 environment, uncertin REC market prices, uncertain legislative renewable
8 compliance standads and potential need for carbon offsets. PacifiCorp's annual
9 REC sales revenue beyond 2010 could var by tens of millons of dollars based
10 on REC price uncertainty alone. REC sales beyond 2012 could potentially fall to
11 zero if RECs are needed for renewable portfolio standard compliance or as carbon.12 offsets to satisfy potential new carbon legislation.
13 Q.Due to the uncertainty of REC sales revenue what treatment is the Company
14 proposing?
15 A.The Company is proposing REC sales should be included in the ECAM. Mr.
16 McDougal describes this proposal in his testimony.
17 Q.Does this conclude your direct testimony?
18 A.Yes.
.
496 Bird, Di - 27
Rocky Mountain Power
.
.
.
20
1 (The following proceedings were had in
2 open hearing.)
3 Q.BY MR. SOLANDER: And, Mr. Tallman, are you aware
4 of any issues that have been directed to you during the
5 examination of Mr. Walj e this morning or afternoon?
6 A.I don i t think so. I think I got off clean.
7 MR. SOLANDER: Madam Chair, Mr. Tallman would be
8 available for cross-examination.
9 COMMISSIONER SMITH: Thank you.
10 Mr. Budge.
11 MR. BUDGE: No questions, thank you.
12 COMMISSIONER SMITH: Mr. Purdy.
13 MR. PURDY: I have none.
14 COMMISSIONER SMITH: Questions? Mr. Olsen?
15 MR. OLSEN: Yes, I have a few questions --
16 COMMISSIONER SMITH: Please.
17 MR. OLSEN: -- Madam Chair.
18
19 CROSS-EXAMINATION
21 BY MR. OLSEN:
22 Q.Mr. Tallman, on page 3 of your rebuttal
23 testimony, lines 18 through 20, and then also on page 5,
24 line 17, approximately, you talk about the criteria that should
25 be applied under the used and useful standard as it relates to
497
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
TALLMAN (X)
RMP
.
.
.
1 Intervenors i and Staff i s issues they have raised about the
2 Dunlap Ranch. Is that correct?
3 A. Could you give me the second reference again,
4 please?
5 Q.Second reference? First is page 3, lines 18
6 through 20.
7 A.Correct. And the second reference?
8 Q.Page 5, line 17, approximately, 16 through 18.
9 A.Okay. I i ve got them.
10 Q.Okay. And what you say there, the principle that
11 should be used is that should be judged on what Rocky Mountain
12 Power knew at the time the Dunlap Ranch was purchased and the
13 overall benefit of Dunlap Ranch to Rocky Mountain i s customers.
14 Is that correct?
15 A.Correct.
16 Q.Okay. Should this criteria for used and useful
17 be used in all cases of resources or when that question comes
18 up?
19 A.Well, I wouldn i t really consider myself a
20 regulatory expert on this particular area. My testimony and my
21 rebuttal testimony is specific to the Dunlap Ranch and the
22 assessment that Staff performed in their review of the outcome
23 of the Dunlap wind project. So my testimony is specific to
24 wind projects, and I try to go into detail as to why I believe
25 that to be the case.
498
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
TALLMAN (X)
RMP
.
.
.
1 I think I probably would have to look for some
2 other Company witness if they wanted to address that issue on a
3 broad policy basis. In general, I would say if a asset
4 provided a benefit to customers, then, yes, it should be
5 determined to be used and useful.
6 Q.At the time that that decision was made or later
7 on?
8 A.Well, depending on -- the premise I was referring
9 is, indeed, the premise that from a prudence perspective, the
10 Company should be judged based on what it knew at the time it
11 made the decision, and that i s that particular reference.
12 I also included a reference to the benefit to
13 customers, and indeed the Dunlap Ranch provides significant
14 benefi t to customers. I layout several examples of that in my
15 testimony, and in particular, the savings and lease expenses
16 alone was dramatic, and it was a dramatic and very long-lasting
17 benefi t for the customers.
18 Q. And I 'm -- I guess I i m looking at a policies
19 perspecti ve. You clarified that you i re looking at Dunlap Ranch
20 indi vidually, but if you were looking at a demand-side resource
21 that was acquired at time X, sometime in the past, and now
22 you i re looking at time Y, would that criteria for used and
23 useful be applicable to that type of resource as well?
24 A.I really wouldn i t consider myself an expert on
25 demand-side management investments and the regulatory policy in
499
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
TALLMAN (X)
RMP
.
.
.
1 terms of used and usefulness.
2 MR. OLSEN: No further questions, Madam Chair.
3 COMMISSIONER SMITH: Thank you, Mr. Olsen.
4 Mr. Otto.
5 MR. OTTO: I do have a few questions, and l'm
6 not -- actually, I have a good line of sight, so I i II stay
7 seated.
8
9 CROS S - EXAMINAT I ON
10
11 BY MR. OTTO:
12 Mr. Tallman, you refer on -- lost my page here, IQ.
13 apologize. We i re on page 2 of your rebuttal testimony, and
14 lines 2 through about 6. Part of the used and useful of the
15 whole ranch you refer to as to effectuate a cost-effective and
16 environmentally-respectful wind proj ect.
17 And then on Exhibit 61 is a map that shows some
18 of the restrictions that were placed on the ranch in building
19 the proj ect .
20 Would it be fair to characterize some of those
21 environmental restrictions as part of the project, part of the
22 permi tting process, for example?
23 A.Yes, that would be a correct statement. In
24 permitting the Dunlap wind project, part and parcel of that
25 process was going before the State of Wyoming through their
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
TALLMAN (X)
RMP
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.
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1 State permitting process, and a key commenter in that process
2 is the State Department of Wildlife. And then, ultimately, the
3 decision to issue the permit is issued by a board that i s called
4 the Industrial Siting Council, and part and parcel to that
5 permi t issuance is the wildlife restrictions associated with
6 the property.
7 And did you participate in the permittingQ.
8 process?
9 A.Yes.
10 And during that process, did the wildlife agencyQ.
11 ask for the Company to perform any mitigation measures or
12 impact offsets on other parts of the Dunlap Ranch from impacts
13 that were caused by where the wind towers were located?
14 A. There i s a number of criteria that i s embedded in
15 our permit. Conservation offsets, if that was the nature of
16 your question, was not one of the items that we were asked to
17 perform, but we were asked to perform a number of other
18 environmentally-sound and prudent type actions, some involving
19 wildlife studies and some involving some ongoing assessments of
20 bird mortality rates. And we also had technical advisory
21 committees that we interact with for some period of time during
22 the operation phase of the proj ect.
23 So would you say it 's -- maybe I already askedQ.
24 this, but we'll see:
25 Would it be fair to say that the whole ranch is
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
TALLMAN (X)
RMP
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.
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1 part of the project? In the permitting process, they looked at
2 the context of the entire ranch, the impacts on the ground
3 where wind towers will be located, and that i s where you
4 choose -- that i s where you made the decision to use what ended
5 up being just portions for the actual wind towers, but at all
6 times the proj ect was considered as the whole ranch?
7 A.Yes, that i s correct. When you submit your
8 Application, you have to define a site boundary, and the site
9 boundary defines the specific area that i s being looked at
10 environmentally, and indeed the boundary of the ranch was that
11 site boundary.
12 And you can see that by looking at the exhibit.
13 You can see the number of different types of environmental
14 si tuations that were encountered on the ranch. One example
15 might be setbacks associated with avian nests, and, therefore,
16 that reduced the area that we had available to us to optimally
1 7 site certain assets.
18 Q.All right. When you went out and bought the
19 ranch, were you aware of the specific areas that were going to
20 be restricted, or did that come later during the permitting
21 process?
22 A.That came later after purchasing the ranch, but
23 prior to submitting our permit Application.
24 The process usually goes along the lines of an
25 ini tial due diligence assessment on a piece of property, which
502
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
TALLMAN (X)
RMP
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.
.
1 we did perform on the ranch, kind of a fatal flaw analysis, if
2 you will. And then move into a much more intensive, iterative
3 study phase once we purchase the ranch. And then, ultimately,
4 through multiple consultations with wildlife agencies,
5 technical consultants, we arrive at a proposal that we put in
6 front of the industrial siting council for, ultimately,
7 permi tting.
8 Q.Thanks very much. That i s all I have.
9 COMMISSIONER SMITH: Mr. Woodbury, do you have
10 any questions?
11 MR. WOODBURY: Thank you, Madam Chair. Not for
12 Mr. Tallman i s testimony, but for Mr. Bird 's.
13
14 CROS S - EXAMINAT I ON
15
16 BY MR. WOODBURY:
17 Q.You have adopted Mr. Bird i s testimony?
18 A.Oh, yes, sir.
19 Q.Put on your other hat. Mr. Bird on page 3,
20 line 4, recites that the Company is trying to establish a
21 prudence of three projects that it had purchased -- Three
22 Buttes, Top of the World, and Dunlap I -- all through an RFP
23 process. And are you aware whether -- I think he relates upon
24 an Oregon approval in the Top of the World.
25 Were all three of these proj ects, did the Company
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1 submi t them for approval as RFPs in states other than Idaho?
2 A.First of all, could you give me the lines that
3 you i re referring to? I just want to make sure I 'm --
4 Q.Page 3, line 4.
5 A.So what the testimony is outlining is that there
6 were three separate and distinct Requests for Proposal
7 processes, not a single process --
8 Q.Yes.
9 A.-- so just to clarify that point.
10 Two of the RFP processes were submitted and
11 reviewed by the Oregon Commission.
12 Q.Which two were those?
13 A.Those would have been RFP 2008R-1 and 2009R.
14 And then to answer the balance of your question,
15 none of the RFPs were submitted to any other Commission because
16 there was not a requirement to do so. However, I believe the
17 Utah Commission retained a consultant in at least two of them;
18 however, I i d need to double-check that fact.
19 Q.As I read through Mr. Bird i s testimony, it
20 appeared and he cited on page 17, starting around line 17
21 he i s talking about benchmark memo, and he cites the reasons the
22 Company submitted a benchmark in the Dunlap I, which is the
23 2009 RFP, and all of the reasons that he cited were very good.
24 And could you indicate why the Company elected
25 not to have a benchmark in the other RFPs, or did it?
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1 A.No, the Company did not in the other two RFPs,
2 because simply we didn i t have an al ternati ve available. The
3 Company believes strongly that when we can put forth a
4 cost-based al ternati ve in RFP process, it i S a good thing for
5 customers to do that; and we believe that because what we i re
6 really putting forth is something that i s literally at cost,
7 whereas, the market does not do that. The market puts forth
8 something that, of course, is designed to maximize their income
9 of revenue.
10 So to answer your question, in the case of 2009R,
11 we did have a benchmark alternative. That was a positive
12 situation and it also meshed with one of our commitments, which
13 I believe was to this commitment -- this Commission to have
14 benchmark alternatives. In the previous RFP, we just didn't
15 have one ready.
16 Q.On page 5 of Mr. Bird i s testimony, at line 11, he
17 notes that the Idaho Commission does not have specific resource
18 procurement guidelines.
19 Is it your understanding that, essentially i in an
20 Idaho Power case where we were dealing with RFP guidelines,
21 that Rocky Mountain Power filed testimony -- not testimony, but
22 filed comments in that case stating its position that for Rocky
23 Mountain Power, such guidelines were not required because of
24 the guidelines that it follows in other states as -- that i sit?
25 A.So you i re on lines 10 through 12, is that
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1 correct, page 5?
2 Q.Yeah, I had line 11, so it would be: That 's
3 between 10 and 12.
4 A.Well, I i m not familiar with the specific
5 testimony you i re referencing.
6 Q.It wouldn i t be testimony. I think they were only
7 comments, and it might even have been in the context but it was
8 the Company i s position. You would -- would you accept that?
9 A.Well, I i II accept that you i re fairly representing
10 it. lIm not familiar with that particular piece of submittal,
11 but I would say that because of our multistate status and
12 because generation is an allocated resource, that we -- it
13 doesn i t really matter where we i re building a generation asset
14 or adding a resource. If the procurement process of a state
15 such as Oregon applies, then we i II follow it to be compliant.
16 So that i s why you will see that if we i re adding a resource
17 that i s greater than 100 megawatts, we will indeed follow a
18 Commission-approved RFP process that i s -- follows the rules of
19 Oregon; and if we i re above another threshold, we i d follow the
20 rules of Utah.
21 Q.One other area of Mr. Bird i s testimony, and
22 that i s on page 27, line 15, and it i S a recommendation of his
23 that the Company is proposing that REC sales -- removable
24 energy credits -- be included in the ECAM.
25 And wouldn i t you agree that this is perhaps the
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1 wrong forum for such a proposal by the Company, and that should
2 be a separate proposal or Application?
3 A.Well, no, I wouldn't agree with that.
4 Q.You wouldn 't?
5 A.I believe what I would state is that Mr. McDougal
6 describes the Company i s proposal, and l'm sure he can elaborate
7 on why we believe this is the right forum.
8 I would go on though to comment that renewable
9 energy credits have been a very unexpected and pleasant upside
10 benefi t of adding these types of resources to our portfolio.
11 The Company has been able to enter into some very high-value
12 transactions on a very opportunistic basis. That opportunity
13 wouldn i t have been there if we hadn i t have been assertive in
14 this arena. And I believe the testimony cites more than
15 $90 million of value to the benefit of customers that are
16 really at issue here.
17 And, again, I would defer to Mr. McDougal if you
18 would like to ask more.
19 Q.Would you accept that, strangely in Idaho, we
20 have a regulatory procedure which requires Applications,
21 foundation, and Notice, to provide parties with Notice? Do you
22 think that we have captured all of the interested parties in
23 your rate case that might have an interest in this change in
24 your ECAM?
25 A.I really don't know. I i d let Mr. McDougal
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1 address that issue.
2 Q.Thank you. Mr. Tallman, I have no further
3 questions of you.
4 MR. WOODBURY: Madam Chair, I tender him back.
5 COMMISSIONER SMITH: Thank you.
6 Do we have questions from the Commissioners?
7 COMMISSIONER REDFORD: No.
8 COMMISSIONER KEMPTON: Commissioner, I have one
9 question.
10
11 EXAMINATION
12
13 BY COMMISSIONER KEMPTON:
14 Q.Mr. Tallman, just to clarify for me a little bit,
15 looking at the map and the size of this project, and the
16 comparisons and the benefits between leasing the property which
17 apparently was very high and purchasing the entire property
18 recognizing that you i ve got a lot of surplus property left
19 over, how do you make a determination -- I mean, you talk about
20 what you say between those two comparisons, but as a matter of
21 fact, if the first comparison is too high, it may be
22 outrageously too high, and yet you could still save a
23 difference between outrageously too high and purchasing the
24 property which is still too high.
25 And so I guess my question is how do you make the
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1 determination that the purchase price or the lease price,
2 whichever one you i re making -- using as a comparative or
3 principle to compare your number on the high side, how do you
4 make a determine that -- determination that -- that i s
5 reasonable to begin with?
6 A.Well, first and foremost, what we i re looking at
7 is the overall generation project. I mean, we judge the
8 economics of a generation resource in its totality. So, the
9 first thing we i re looking to do is bring forth an economic
10 generation supply side resource. That i s the overall premise.
11 When you get down to the detailed level of trying
12 to secure a piece of property, we do have a number of wind
13 proj ects that were brought to us by developers that were on
14 leased land. We do have two particular sites where the Company
15 owns the land, and that is a very unusual situation where the
16 owner of the asset would actually own the piece of property.
17 To answer your question most directly, you know,
18 if we were faced with a lease versus purchase opportunity --
19 which is typically not the case, but if we were -- we i d use the
20 sum total of our knowledge of the lease market at that current
21 time to try to assess whether or not, you know, one i s better
22 versus the other.
23 In this particular case, the property is being
24 offered for sale, it i S being offered for sale at an attractive
25 price. We endeavored to purchase the property at a cost that
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1 was in line with really the value of that type of property in
2 that current market for nonwind uses. We made that
3 determination based on our understanding of the then-current
4 lease market.
5 And I wouldn i t say that leasing property and
6 installing a wind proj ect on it would result in an outrageously
7 expensive situation. It i s just in our experience, this
8 situation was more cost effective; and that i s what we were
9 going for, the lowest-cost al ternati ve.
10 Q.And so you i re leasing out the excess property for
11 agriculture purposes?
12 A.We do. We have a agricultural lease with a third
13 party. It i S modest in the income it brings to the Company, but
14 it i S large in terms of the value it brings to the Company
15 because it brings a number of things that we i d probably have to
16 pay a third party to do. Provides us with an on-site
17 caretaker, provides us with somebody who can monitor whether or
18 not trespassing is taking place; provides us with somebody that
19 can regulate access to the property whether it i S for
20 recreational purposes or other purposes; repairs; those sort of
21 things. So it provides a lot of benefits to the Company. It
22 provides an incremental ongoing revenue stream to the Company.
23 But its highest and best value is kind of a
24 totali ty of everything it brings that we just can i t have
25 somebody out there at all points of time. Usually you have a
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1 landowner, you know, that i s on site, and since we are the
2 landowner, this is our way of having a direct presence.
3 Q.Is the property irrigated?
4 A.Pardon?
5 Q.Is the property irrigated?
6 A.There is irrigation water available, and when
7 it i S available, one of the duties of the caretaker is to
8 irrigate the property to the best the availability of the --
9 Q.Are they deep wells?
10 A.I don i t know.
11 Q.Who maintains ownership of all of the capital
12 assets on the property the wells, the roads -- that maybe
13 have to be maintained? I don i t know if they' re gravel or not,
14 I don i t know what kind of roads are coming out of that, but
15 just the equipment on the place and the equipment that i s
16 required for the agricultural process, who owns that?
17 A.The lessee would own anything that i s related to
18 agriculture, but it i S ranching activities is what it is, so
19 it i S not growing a crop. It i S basically grazing. So the
20 capital or the tangible equipment is just related to grazing.
21 Q.So there i s the agriculture product is actually a
22 pasture product for the entire ranch?
23 A.We call it an agricultural lease, but it i s
24 basically we i re leasing the property for grazing purposes to
25 the extent it doesn i t interfere with our operations.
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21
22
23
24
25
1 COMMISSIONER KEMPTON: I don i t have any further
2 questions.
3 COMMISSIONER SMITH: Thank you.
4 Do you have redirect
5 MR. SOLANDER: No redirect.
6 COMMISSIONER SMITH: -- Mr. Hickey -- or, sorry,
7 Mr. Solander?
8 MR. SOLANDER: No redirect, thank you.
9 COMMISSIONER SMITH: Thank you.
10 MR. SOLANDER: And we would ask that Mr. Tallman
11 be excused for the remainder of the proceeding.
12 COMMISSIONER SMITH: Is there any obj ection to
13 excusing Mr. Tallman?
14 Seeing none, you are excused. Thank you for your
15 help.
16 (The witness left the stand.)
17 MR. SOLANDER: Rocky Mountain Power calls
18 Chad Teply as its next witness.
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1 CHAD TEPLY,
2 produced as a witness at the instance of Rocky Mountain Power,
3 being first duly sworn, was examined and testified as follows:
4
5 DIRECT EXAMINATION
6
7 BY MR. SOLANDER:
8 Q.Good afternoon, Mr. Teply.
9 A.Good afternoon.
10 Could you please state and spell your name forQ.
11 the record?
12 A.My name is Chad Teply: C-H-A-D, T-E-P-L-Y.
13 And whom are you employed by and in whatQ.
14 capaci ty?
15 I i m employed by PacifiCorp Energy, and myA.
16 capacity is vice president of resource development and
17 construction.
18 And are you the same Chad Teply that filed directQ.
19 testimony on May 28, 2010, in this proceeding?
20 A.I am.
21 And did you also file rebuttal testimony onQ.
22 November 16, 2010?
23 A.I did.
24 And do you have any corrections or changes toQ.
25 your testimony at this time?
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1 I have two minor corrections to my rebuttalA.
2 testimony:
3 First item is on page 3, line 11. The word
4 "completing" should be "competing."
5 And then the second item is on page 6, line 10.
6 The reference to line 31 above should be -- should refer to
7 page 2, line 9.
8 And with those two exceptions, if I were to askQ.
9 you the same questions set out in your direct and rebuttal
10 testimony, would your answers be the same today?
11 A.They would.
12 MR. SOLANDER: Madam Chair, I would now move that
13 the prefiled direct and rebuttal testimony of Chad Teply be
14 spread upon the record as if read.
15 COMMISSIONER SMITH: If there i s no obj ection, it
16 is so ordered.
17 (The following prefiled direct and
18 rebuttal testimony of Mr. Teply is spread upon the record.)
19
20
21
22
23
24
25
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2
3 A.
4
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22
.23
Pleas state your name, business address and poition with PacifiCorp
("Company").
My name is Chad A. Teply. My business address is 1407 West Nort Temple,
Suite 210, Salt Lake City, Utah. My present position is Vice President of
Resource Development and Constrction for PacifiCorp Energy. I report to the
President ofPacifiCorp Energy. Both Rocky Mountan Power and PacifiCorp
Energy are divisions of PacifiCorp.
Qualifications
Q.. Please describe your education and business experience.
A. I have a Bachelor of Science Degre in Mechanìcal Engineering from South
Dakota State University. I am a Registered Professional Engineer in the state of
Iowa. I joined MidAmerican Energy Company in November 1999 and held
positions of increasing responsibilty within the generation organìzation,
including the role of project manager for the 790- megawatt Walter Scott Energy
Center Unit 4 completed in June 2007. In April 2008, I moved to Nortern
Natual Gas Company as senior diector of engineering. In Februar 2009, I
joined the PacifiCorp team as Vice President of Resource Development and
Constrction, at PacifiCorp Energy. In my curent role, I have responsibilty for
development and execution of major resource additions and major envionmenta
projects.
Q. What is the purpose of your testimony?
A. The purpose of my testimony is to provide the Commssion and paries with
information supporting the prudence of pollution control equipment and
515 Teply, Di - 1
Rocky Mountain Power
.1
2
additional generation plant capital investments being placed in service durng the
test period.
3 Background
.
4 Q.
5
6
7 A.
8
9
10
11
12
13
Please provide a general description of desired outcomes from the pollution
control equipment and generation plant capital investments being placed in
service.
The pollution control equipment investments contemplated in this case primaly
result in the reduction of sulfur dioxide ("SOi"), nitrogen oxides ("NOx"), and
pariculate matter ("PM") emissions from the retrofitted facilties. The tubine
upgrade investments are intended to enhance the Company's overall generation
capabilty and cycle efficiency for the large therml units being provided with this
equipment. The repai and replacement capital investments are intended to
support generation asset reliabilty via reduced risk of equipment/component
14 failures.
15 Description of Pollution Control Investments
16 Q.
17
18 A.
19
20
21
22
23.
Please describe the Dave Johnston Unit 3 pollution control project and
associated equipment.
The pollution control project at the Dave Johnston Unit 3 power plant is being
completed in conjunction with the Dave Johnston Unit 4 pollution control project
that wil be placed in service in 2012. The Dave Johnston Unit 3 pollution control
project wil upgrde and improve the unit's PM controls and install SOi controls.
The capital expenditure for the project during the test period is $300 millon.
Constrction began in 2008, and the project wil be operational by May 31, 2010.
516 Teply, Di - 2
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10
11.12
13
14
15 Q.
16
17 A.
18
19
20
21
22
23.
The new pollution control equipment is being tied into the existing unit durng a
scheduled plant maintenance outage. The project wil install a dr flue gas
desulfuzation ("DFOD") system with fabric fùter. A DFOD system injects lime
slurr in the top of an absorber vessel (scrubber) with a rapidly rotating atomizer
wheeL. The rapid rotation of the atomizer wheel causes the lime slurr to separate
into very fine droplets that interm with the flue gas. The SOi in the flue gas
reacts with the calcium in the lime slurr to form calcium sulfate in the form of
dr PM. The dr PM is then captued in the downstream baghouse along with fly
ash from the boiler. The DFOD system wil produce a nonhazardous dr waste
product suitable for landfil disposal. Other equipment to be installed as par of
the project includes induced draft fans, boiler reinforcement, new ductwork, lime
slurr reagent preparation systems, waste material handling systems, electrcal
infrastructue, controls, and other miscellaneous appurenances and support
systems.
Wil the Dave Johnston Unit 4 pollution control projec also be placed in
service during the test period contemplated in this case?
No. The Dave Johnston Unit 4 pollution control project, which is being
constructed concurently with the Dave Johnston Unit 3 pollution control project,
wil be placed in service during the next planned major maintenance outage for
that unit. The planned major maintenance outages for the Company's generation
assets are scheduled ona control area basis, considerig optimal frequency
between overhauls and to minimize the number of major units off line at anyone
time. The Company's Dave Johnston Unit 4 completed its most recent overhaul
517 Teply, Di - 3
Rocky Mountain Power
.1 in 2009 and is scheduled for its next overhaul in the spring of 2012. The
2 Company's intent in establishing the tie-in schedules for the Dave Johnston Unit 3
3 and Dave Johnston Unit 4 pollution control equipment was to balance the
4 aggregated constrction costs and schedules for the pollution control equipment
5 projects against the established planned maintenance overhaul schedules, work
6 plans, and budgets for the respective units.
7 Q.Are costs specific to Dave Johnston Unit 4 pollution control equipment
8 included in this case?
9 A.No. Costs contemplated in this case include only those costs that are specific to
10 Dave Johnston Unit 3 as well as the cost of all common facilities that are required
11 to be placed in service to allow prudent operation of either unit's new emission.12 control system. Common facilties include reagent preparation, waste disposal,
13 electrical supply, and ancilar utilty systems, as well as site preparation and the
14 chimney. In the event one of the subject units is retired in the futue, these
15 common facilities would not be retired since they must remain in servce for the
16 remaining unit to operate.
17 Q.Please describe the emissions improvements that wil be achieved with the
18 Dave Johnston Unit 3 pollution control project.
19 A.The Dave Johnston Unit 3 DFOD system and baghouse wil reduce SOiemissions
20 from the unit by approximately 90 percent, or approximately 6,600 tons per year.
21 In addition to reducing SOi emissions, the baghouse wil reduce the emissions of
22 PM. The PM emission limit wil be reduced from 0.20 pounds per millon British
23 Thermal Units to 0.015 pounds per millon British Thermal Units..
518 Teply, Di - 4
. Rocky Mountain Power
.1 Q.Please desribe the other major pollution control projects and associated
2 equipment contemplated in this case.
3 A.The other major pollution control projects undertaken by PacifiCorp in 2010
4 include: (1) the Huntington Unit 1 electrostatic precipitator to baghouse
5 conversion project; (2) the Huntington Unit 1 scrubber upgrade project; (3) the
6 Huntington Unit 1 low NOx burners instalation project; (4) the Dave Johnston
7 Unit 3 low NOx burers installation project; (5) the Jim Bridger Unit 1 scrubber
8 upgrade project; and (6) the Jim Bridger Unit 1 low NOx burers installation
9 project. The Huntington baghouse installation project wil replace the existing
10 electrostatic pr~ipitator with a fabric fiter to captue dr PM from the flue gas
11 stream. The scope of work for this project also includes converting the existing.12 stack to wet operation to enable the scrubber bypass dampers to be removed. The
13 Huntington Unit 1 scrubber upgrade wil allow treatment of all the flue gas from
14 the unit. The project wil also provide new waste handling equipment to maage
15 the increase in waste product from the higher removal efficiency of the scrubber.
16 The Jim Bridger Unit 1 scrubber upgrade wil replace internal scrubber parts
17 (trays, piping and nozzles). This work wil improve SOz removal efficiency while
18 enabling the bypass dampers to bypass less flue gas. The low NOx burers
19 projects referenced above wil install new burers that utilze improved
20 combustion characteristics and a separated over-fire air supply to the boiler to
21 reduce NOx emissions.
22 Q.Do Huntington Unit 1 and Jim Bridger Unit 1 currently have scrubbers?
23 A.Yes. The scrubber upgrade projects priarly include the upgrade and.
519
Teply, Di - 5
Rocky Mounta Power
.1 replacement of existing pumps, spray headers, trays, and ancilar equipment to
2 improve the control' of SOz emissions from the affected units.
3 Q.Please describe the emissions improvements that wil be achieved with the
4 pollution control projects described above.
5 A.The pollution control equipment investments described above support the
6 Company's ongoing commtment to reduce SOz emissions from its generation
7 fleet by approximately 50 percent compared to 2005 levels. In addition to
8 reducing SOz emissions, the projects support the Company's ongoing
9 commtment to reduce NOx emissions from its generation fleet by approximately
10 40 percent compared to 2005 levels.
11 Q.Have the costs of the projects been prudently managed?.12 A.Yes. The scrubber and baghouse projects have been contracted under lump-sum
13 turney engineer, procure and constrct (EPC) contrct terms which resulted from
14 competitive bidding processes. The burner replacement projects have been
15 contracted under multiple lump-sum contracts which resulted from competitive
16 bidding processes. PacifiCorp management continues to provide oversight of the
17 projects and closely manages any project execution plan changes or potential
18 contract scope changes.
19 Q.Are there additional operating costs that wil be incurred as a result of the
20 installation of the pollution control equipment?
21 A.Yes. Operation of the new pollution control equipment wil result in increased
22 operation and maintenance costs of $1.5 milion associated with reagent, waste.23 disposal, and equipment maintenance. These costs are summarzed on page 4.6 in
520
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Rocky Mountain Power
.1
2 Q.
3
4 A.
5
Exhibit 2 of Mr. Steven McDougal's Direct Testiony.
How are the pollution control investment costs and associated operating costs
being treated in the revenue requirement?
The costs for the pollution control equipment have been included in this case as
explained in the revenue requirement testimony of Mr. McDougal.
6 Justification of Pollution Control Investments
7 Q.
8 A.
9
10
11.12
13
14
15
16
17
18
19
20
21
22.23
What is the basis for these investments?
These investments were identified as par of the Company's response to
environmental regulations that govern the plants' operations. Though the 1977
amendments to the Clean Air Act, Congress set a national goal for visibilty to
remedy impaient from manmade emissions in designated national parks and
wilderness areas; this goal resulted in development of the Regional Haze Rules,
adopted in 2005 by the Environmenta Protection Agency. The first phase of
these rules trigger Best Available Retrofit Technology ("BART") reviews for al
coal-fired generation facilities built between 1962 and 1977 that emit at least 250
tons of visibility-impairng pollution per year. The units provided with the
pollution control equipment investments discussed above are subject to BART
reviews. BART reviews of the units have been completed and submitted to the
respective state deparents of environmental quality for final disposition.
The respective state deparments of environmental quality for the units
have incorporated the results of the above mentioned BART analyses into the
construction permts and approval orders for the pollution control equipment
contemplated by this case.
521 Teply, Di-7
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
With respect to the Dave Johnston Unit 3 and Jim Bridger Unit 1 projects,
the Wyoming Deparment of Environmental Quality ("WY DEQ") issued BART
permts for those units on December 31, 2009, incorporating the equipment and
instalation schedules recommended via the BART review and contemplated in
this case. The conditions of the BART permts wil be incorporated into the
Wyoming State Implementation Plan ("SIP") for Regional Haze in support of its
goals to reduce visibilty impairng emissions. The Wyoming SIP is subject to
U.S. Environmental Protection Agency ("EPA") review and approvaL. The WY
DEQ has also issued constrction permts for the Dave Johnston Unit 3 and Jim
Bridger Unit 1 environmental improvement projects.
With respect to the Huntington Unit 1 project, the Utah Deparment of
Environmental Quality has incorporated the results of a BART review completed
for that facility into the Utah SIP. The Utah SIP is subject to EPA review and
approval. The state of Uta has also issued an Approval Order (i.e. a permt to
constrct) for the Huntington Unit 1 environmental improvement project.
In addition to the BART requirements, increasingly more stringent
National Ambient Air Quality Standads have been and are being adopted for
criteria pollutants, including S02, nitrogen dioxide, ozone and PM.
Implementation of these projects assists in avoiding nonattainment of these
standads. The environmental compliance activities discussed above form the
basis for these investments.
.
522 Teply, Di - 8
Rocky Mountain Power
.1 Q.
2
3 A.
4
5
6
7
8
9
10
11.12
13
14
15-
16
17
18
19
.
What factors does the Company consider when determining which capita
investments to make in environmenta equipment retrofit projects?
The Company takes several factors into consideration when makng pollution
control equipment investments includig: evaluation of state and federal
environmental regulatory requirements and associated compliance deadlines;
review of emerging environmental regulations and rulemakng; and analyses of
alternate compliance options. As par of the BART review of each facilty, the
Company evaluated several technologies on their abilty to economically achieve
compliance and support an integrated approach to control criteria pollutants (e.g.
SOi, NOx, and PM for the facility), if it were to continue to operate and to bur
coal. The BART analyses reviewed available retrofit emission control
technologies and their associated performnce and cost metrcs. Each of the
technologies was reviewed against its abilty to meet a presumptive BART
emission limit based on technology and fuel characteristics. The BART analyses
outlned the available emission control technologies, the cost for each and the
projected improvement in visibilty which can be expected by the installation of
the respective technology. Once the preferred BART technology was identified,
the Company moved forward with its competitive bidding process to evaluate and
ultimately select the preferred provider for the projects.
523 Teply, Di - 9
Rocky Mountan Power
.1 Q.
2
3
4
5 A.
6
7
8
9
10
11.
.
12
13
14 A.
Would the Company's decision to make this incremental investment in
environmental controls at these units change if limitations were placed on
carbon dioxide emissions, such as in the Waxman-Markey bil in the U.S.
House of Representatives or the Kerry-Lieberman bil in the U.S. Senate?
No. The Company is currntly engaged in assessing its existing generation
resources, its planned supply and demand-side resources and its 1O-year capital
budget regarding the impact of carbon dioxide emissions restrctions. While
planned investments in other units may change, the Company's plans regarding
these investments would not change due to carbon-emission restrctions. The
units have depreciation lives for ratemag purposes that provide sufficient
remaining time to depreciate the investments in the pollution controls.
Timing of Investment
Q. Why is PacifiCorp installing pollution control equipment at this tie?
As discussed above, the Company is installng the pollution control equipment at
15 this time primarly to ensure compliance with Regional Haze Rules, but also in
16 response to a more strngent National Ambient Air Quality Standads and a
17 varety of existing and emerging emission reduction requirements. Final
18 instalation activities and tie-in of the pollution control equipment described
19 above can only be accomplished when the units are off-line. Meetig the timing
20 requirements of constrction permts/approval orders and reducing plant outage
21 time necessitated completion of final installation activities and tie-in of the
22 pollution control equipment durng the scheduled overhauls within this test
23 period. Installation of the pollution control equipment and associated systems
524
Teply, Di - 10
Rocky Mountain Power
.1
2
contemplated in this case represent a significant step for PacifiCorp's coal-fueled
power plant fleet toward meeting the SOz and NOx reductions required by the
3 Regional Haze Rules and established by the respective states' emissions reduction
4 miestones.
5 Customer Considerations
6 Q.
7
8
9 A.
10
11.12
13
14
15
16
17
18
19
20
21
22
.
What are the benefits to customers of installng the pollution control
equipment and why should Rocky Mountain Power's customers pay the costs
related to this project?
Customers directly benefit from the continued availabilty of low-cost generation
produced at the facilities while also achieving environmenta improvements from
these resources, resulting in cleaner ai. In addition, the tie-in of these necessar
. controls is being accomplished durng planed maintenance outages, as opposed
to scheduling separate outages for this work, which reduces replacement power
costs. The Company has ten BART-eligible units in Wyoming and four in Uta.
The BART controls for each of these units must be installed as expeditiously as
possible, but no later than five years from the date the respective SIPs are
approved and prior to the compliance dates specified in the permts Postponing
instalation on these units to later planned maintenance outages would make it
virally impossible for the Company to effectively ensure that all of its affected
units meet compliance deadlines and would place the Company at risk of not
having access to necessar capital, materials, and labor while attempting to
perform these major equipment installations in a compressed timeframe.
525
Teply, Di - 11
Rocky Mountain Power
.1 Description of Turbine Upgrade Investments
2 Q. Please desribe the turbine upgrade projects.
3 A.
4
5
6
7
8
9
10
11 Q..12
13 A.
14
15
16
17
18
19
20
21
.
The Company has thee turbine upgrade projects totaing approximately $129
milion that wil be completed durng the test period. The projects include: (1) the
Hunter Unit 1 high pressure (HP)/intermediate pressure (IP)llow pressure (LP)
turbine sections replacement; (2) the Huntington Unit 1 HPIIILP tubine sections
replacement; and (3) the Jim Bridger Unit 1 HPII tubine sections replacement.
The revenue requirement impact of this investment has been included in Exhbit
NO.2 of Mr. McDougal's Direct Testimony and the investment is summarzed on
page 8.6.2 of such exhibit.
Please describe the effciency improvements that will be achieved with the
turbine upgrade projects described above.
The Company expects the Hunter Unit 1 turbine upgrade to allow more efficient
turbine performance without increasing emissions, such that an additional 15
megawatts of capacity can to be generated by the unit. The same principles apply
to the Huntington Unit 1 tubine upgrade and Jim Bridger Unit 1 turbine
upgrades, which are expected to provide efficiency improvements, without
increasing emissions, resulting in an additional 18 megawatts and an additional
four megawatts, respectively, of capacity to be generated by the units. Dr. Hui
Shu has annualized the incrementa changes to these thee units in her net power
cost analysis in her Direct Testimony.
526
Teply, Di - 12
Rocky Mountan Power
.
.
.
1
2
3 A.
4
5
6
7
8
9 Q.
10
11 A.
12
13
14 Q.
15 A.
Justification of Turbine Upgrade Investments
Q. What is the basis for these investments?
As par of the Company's efforts to meet the growing demand for generation, and
given the advancing technological improvements in steam tubine design and
manufactug, the Company has initiated a tubine upgrade initiative. This
tubine upgrade initiative is intended to furter enhance PacifiCorp's overall
generation capabilty and cycle efficiency for the large thermal units being
provided with this equipment.
What other generation plant capital investments are included in this
application?
Repair and replacement investments are the remaning projects contemplated in
this case. The projects fall within four major categories: (1) boiler section
replacements; (2) controls upgrades; (3) generator rewind; and (4) other.
How wil customers benefit from these capita expenditures?
These capita expenditures enable the Company to mantain overall reliabilty of
16 the aging fleet. The Company's plants produce energy at costs lower than market
17 prices, enabling the Company to serve its customers at some of the lowest retail
18 electrcity prices in the United States. Investment in the Company's existing
19 generating units increases the probability of continued safe and reliable operation
20 of these lòw-cost resources.
21 Conclusion
22 Q.
23
Please summarize your testimony.
A.Investment in pollution control equipment is required to meet the Regional Haze
527
Teply, Di - 13
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10
11.12 Q.
13 A.
.
Rules enacted in 2005 by the EPA, and the resultig BART reviews and
permtting process. The Company's decision to install this pollution control
equipment would not change due to the enactment of carbon dioxide emission
reduction legislation. The investment allows for the continued operation of low-
cost coal-fired generation facilities while achieving significant environmental
improvements to ai quality and regional haze issues.
Also, the Company is makng other prudent capita expenditues in its
existing generation fleet that wil benefit customers by mantaining safe, reliable,
efficient, cost-effective generating resources. The investments during the test
period are reasonable and prudent, and the Company should be granted full cost
recovery for these investments.
Does this conclude your direct testimony?
Yes.
528
Teply, Di - 14
Rocky Mountain Power
.1 Introduction
2 Q.Please state your name and business address.
3 A.My name is Chad A. Teply. My business address is 1407 West North Temple,
4 Suite 210, Salt Lake City, Utah.
5 Q.Are you the same Chad A. Teply who submitted pre-filed direct testimony in
6 this proceeding?
7 A.Yes.
8 Purpose of Testimony
9 Q.What is the purpose of your rebuttal testimony in this proceeding?
10 A.My testimony wil respond to the dict testimony of Mr. Randall J. Falkenberg
11 on behalf of the PacifiCorp Idaho Industrial Customers ("PUC") regarding the.12 Company's management and financial modeling of unplanned therm unit
13 outages and wil also respond to the diect testimony of Mr. Don Reading on
14 behalf of the Idaho Conservation League ("ICL") regarding prudence of the
15 Company's pollution control expenditures for coal-fired power generation plants.
16 Q.Please summarize Mr. Falkenberg's concerns regarding the Company's
17 management and financial treatment of planned and unplanned thermal unit
18 outages and his recommended adjustments 6 and 7.
19 A.Mr. Falkenberg's concerns are primarly two-fold. First, Mr. Falkenberg is
20 concerned with the Company's prudence regarding management of two outage
21 events. Second, Mr. Falenberg is concerned with the Company's utiization of
22 the calculated four-year average outage rate for the therml units in question. Mr.
.
529
Teply, Di-Reb - 1
Rocky Mountain Power
.
.
.
1
2
3 Q.
4
5 A.
6 Q.
7
8
9 A.
10
11
12
13
14
15
16
17
18
19
Falenberg's recommendation is to cap the allowable outage durations for the two
outage events to 28 days in outage rate calculations.
Does the Company believe that the planned and unplanned thermal unit
outages in question were prudently managed?
Yes.
Are the costs for the extended planned and unplanned outage durations in
the four-year averaging period representative of the costs expected in the
prescribed test period?
Yes. The Company has appropriately applied the accepted outage rate averaging
methodology to the specific units referenced. When reviewed in isolation, the
Company recognizes that the individual outage rates referenced are, on average,
higher than those units that did not experience extended planned or unplanned
outages durng the four-year averaging period; however, considering the size and
age of the Company's generation fleet, individual units do experience significant
events that result in extended outages during prescribed test periods. If significant
events are not calculated into the Company's outage rates, due to their anomalous
characteristics, said omission arificially affects the historical, and therefore,
forecasted availability of the fleet. As such, the outage rate averaging
methodology applied by the Company for individual units, when reviewed in
20 context with the Company's aggregated outage rates, accurately represents costs
21 incurred by the Company associated with unit outages in the prescribed test
22 period and provides an accurate forecast for expected outage costs for the
23 Company's generation fleet on a forward-looking basis.
530
Teply, Di-Reb - 2
Rocky Mountain Power
.1 Q.Are the Company's calculated four-year average outage rates for the thermal
2 units in question reasonable?
3 A.Yes. Using the four-year average outage rate for the Company's therml units is
4 reasonable and should be included in rates.
5 Q.Why should the Commission reject Mr. Falkenberg's proposal to cap
6 extended outages at 28 days in the outage rate calculations utilzed as the
7 basis for this case?
8 A.The cap approach proposed by the Company in OPUC docket, UM 1355, and
9 referenced by Mr. Falenberg in his testimony beginning on line 23. was par of a
10 larger proposal that has not been accepted by regulators. As noted in Mr.
11 Falenberg's testimony, there are several completing alternatives in the docket.12 referenced and a decision is pending. The Company has submitted extensive
13 testimony and exhibits in OPUC docket, UM 1355, which can be referenced but
14 wil not be re-presented herein.
15 Q.Was the Company's management of the Lake Side unplanned outage
,
16 referenced in Mr. Falkenberg's testimony prudent and reasonable?
17 A.Yes. On August 16, 2009, the Lake Side steam turbine generator tripped
18 following a three phase electrical fault which resulted in catastrophic damge to
19 the stato~ windings. There were no operational or other monitoring equipment
20 indications of a problem prior to the trip and no history of problems on the unit.
21 Following the fault, the generator field was removed allowing access for visual
22 examnation and testing. Inspections by Siemens (the original equipment.23 manufactuer), the Company and an independent generator expert revealed the
531
Teply, Di-Reb - 3
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10
11.12
13 Q.
14
15 A.
16
17
18
19
20
21
22.23
stator core was beyond repair, and that stator replacement was the only option to
retu the unit to servce. A suitable replacement stator was located, purchased
and delivered. Contamination from the stator fault necessitated field
refubishment. Work to ship the replacement stator, remove the failed stator, and
refurbishment of the field occured simultaeously. With a new stator and
refurbished rotor installed, the manufactuers' recommend tests were performed
prior to returning the unit to service on November 15,2009. Considering the
natue of the catastrophic damage incurred and the typical lead time to specify,
procure and manufacture replacement equipment of the type needed in this
instance, the schedule achieved to locate, purchase, and install a replacement
stator at Lake Side and return the unit to service for the benefit of customers was
commendable.
Was the Company's management of the Colstrip Unit 4 planned outage
referenced in Mr. Falkenberg's testimony prudent and reasonable?
Yes. Prior to 2009, Colstrip Unit 4 experienced a sudden, massive condenser tube
leak that caused cracks in the L-O stages of the main turbine's low-pressure
rotors. These cracks were discovered durng a scheduled spring 2009 inspection.
The tubine manufactuer determned that the rotors could not be returned to
service in their as-found condition. The rotors were sent to the tubine
manufacturer's facilities for removal of the damaged rotor wheels and weld-repai
and machining of new wheels. During the initial repai sequence, non-destrctive
examination completed by the manufactuer as part of its quality assurance
process found significant defects in the weld material which had been utilzed for
532
Teply, Di-Reb - 4
Rocky Mountan Power
.1
2
3
4
5
6
7
8
9 Q.
10
11.12 A.
13
14
15
16
17
18 Q.
19
20 A.
21
22.23
repai of the new wheels. This material had to be removed and the wheels re-
welded. Final quality assurce testing showed that the second batch of weld
material was sound. The wheels were machined, blades installed, and the unit
was retued to service in late 2009. Although the required rotor repais and need
for re-work resulted in extended outage duration, adherence to manufactuer
recommendations for turbine rotor repairs and utilization of its repai facilties
was the prudent and reasonable approach to management of that outage critical
path.
Please summarize Mr. Falkenberg's concerns regarding the Company's
management and financial treatment of the Naughton Unit 3 outage and his
recommended adjustment 9.
Mr. Falenberg's concerns are primarly two-fold. First, Mr. Falenberg is
concerned with the Company's prudence regarding management of the referenced
outage event. Second, Mr. Falkenberg is concerned with the Company's
calculation of the outage rate for the thermal unit in question. Mr. Falkenberg's
recommendation is to adjust the planned and forced outage rates calculated for the
thermal unit in question in this case.
Does the Company believe that the Naughton Unit 3 outage in question was
prudently managed?
Yes. The Company prudently negotiated a liquidated damages clause with the
contractor before the star of repais. The Company prudently exercised that
clause when poor subcontractor performance negatively impacted outage
completion. The liquidated dage payment was credited to customers.
533
Teply, Di-Reb - 5
Rocky Mountain Power
.1
2
3
4
5
6 Q.
7
8
9
10 A.
11 Q..12
13 A.
14
15
16 Q.
17
18 A.
19
20
21
22.23
The collection of liquidated damages from the outage repai does not
displace the need to recover appropriate outage costs and reflect appropriate
outage durations in the four-year average outage rate for the therm unit in
question. As noted in Mr. Falkenberg's testimony, the liquidated damges
collected did not result in full compensation for costs associated with this event.
Does including extended planned and unplanned outage durations in the
four-year averaging period for cost recovery for specific units appropriately
represent costs incurred by the Company associated with outages in the
prescribed period?
Yes. Please refer to my testimony beginning on line 31 above.
Is it your opinion that the calculated four-year average outage rate for the
thermal unit in question should be included in rates?
Yes. In my opinion, the Company has appropriately applied the accepted outage
rate averaging methodology to the specific units referenced, and therefore that
rate should be included in rates.
Pleas summarize Mr. Reading's concernsregardiìig prudence of the
Company's pollution control expenditures contemplated in this case.
Mr. Reading's concerns regarding prudence of the pollution control expenditures
for which the Company is seeking recovery in this case are primarly three-fold.
First, Mr. Reading is concerned that the Company is instaling certain pollution
control equipment to meet "a presumptive BART emission limit". Mr. Reading is
concerned that the Company is makng these investments before it receives a final
decision on whether the equipment is sufficient to meet federal pollution control
534
Teply, Di-Reb - 6
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10
11.12
13
14
standards.
Second, Mr. Reading is concerned that the Company is installng certain
pollution control equipment in accordace with state issued permt requirements,
but without final U.S. Environmenta Protection Agency ("EPA") review and
approval of the respective state implementation plans. Mr. Reading's concern is
that the EPA may ultimately require more stringent controls and more expensive
equipment to be installed on the generating units contemplated in this case.
Third, Mr. Reading testifies that if futue stricter regulations are enacted,
the projects contemplated in this case may not be suffcient to achieve
compliance. Mr. Reading has asked that the Company justify any futue pollution
expenditures in two ways. First, expenditures would be analyzed not only based
on the effectiveness of the control equipment, but also with respect to compliance
with existing federal pollution control laws. Second, a risk assessment of meeting
realistic assumptions for futue strcter environmental requirements would be
15 completed.
16 Company Response to Concerns
17 Q.
18
19
20 A.
21
22
.
Please clarfy the definition of "a presumptive Best Available Retrofit
Technology ("BART") emision limit" as it pertains to established federal
pollution control standards.
The use of the term "presumptive" in the instance cited refers to presumptive
emission rates that are discussed in the Regional Haze Rule, Code of Federal
Regulations (CFR), Title 40, Sections 51.300 through 51.309, and Appendix Y.
535
Teply, Di-Reb-7
Rocky Mountain Power
.
.
.
1 Electronic copies of the referenced Code of Federal Regulations can be found at
2 the following link:
3 http://www.access.gpo.gov/naralcfr/waisidx 09/40cfr51 09.htm
4 The term "presumptive" comes from Appendix Y cited above, and the
5 presumptive rates are defined by the EPA. States use the presumptive rates
6 defined by the EPA to assist in determning if a BART-eligible facilty has met
7 the requirement to install best available retrofit technology. For example, if the
8 installation of 10w-NOx burers on a BART-eligible facility with cell-burers
9 firng sub-bituminous coal achieves an emission rate of 0.28 IbIMBtu, which is
10 below the EPA presumptive BART rate of 0.45 Ib/mmtu (the presumptive rate
11 for a cell-burer unit burning sub-bituminous coal), it can be presumed that the
12 installation of low- NOx burners on this unit meets federal best available retrofit
13 requirements with respect to NOx control, and no additional controls would be
14 required. With respect to S02 control, the EPA had defined the presumptive S02
15 emissions rate as 0.15 Ib/mmtu or 90% removaL. Here again, if the instalation of
16 pollution control equipment on a BART-eligible facilty achieves an emission rate
17 less than that presumptive limit, it can be presumed that the installation meets
18 federal best available retrofit requirements and no additional controls wil be
19 required.
536
Teply, Di-Reb - 8
Rocky Mountain Power
.1 Q.
2
3
4
5 A.
6
7
8
9
10 Q.
11.12
13 A.
14
15
16
17
18
19
20
21
22.23
Is the Company obligated to instal pollution controls required by state
permits, regardless of whether final U.S. Environmental Protection Agency
review and approval of the respective state implementation plans remains
pending?
Yes. The BART permts and constrction permts issued by the respective state
agencies for the pollution control investments contemplated in this case include
stand-alone requirements enforceable by the laws of the respective states. These
requirements are enforceable independent of whether EPA has approved the
respective state implementation plans.
Does the Company anticipate that final U.S. EPA approval of the respective
state implementation plans will. require alternate pollution control equipment
to be installed, making the equipment contemplated in this case obsolete?
No. The pollution control technology selections completed to date apply best
available retrofit technology, comply with existing state and federal regulations,
and support Regional Haze Rule objectives. The Company also incorporates into
its pollution control equipment contract specifications design considerations
intended to provide appropriate levels of operating margin, equipment
redundancy, and system maintainabilty and reliabilty provisions to support an
expected range of process inputs, operating conditions, and system performance.
Although the Company cannot predict futue pollution control regulations and
associated emissions limts, the Company does tae steps to procure a prudent
level of design flexibility to accommodate potential changes in system
performance requirements, where practicaL.
537
Teply, Di-Reb - 9
Rocky Mountain Power
.1
2
3
4
5
6 Q.
7
8
9 A.
10
11.12
13
14
15
16
17
18
19
20
.
proceed with investments to control emissions other than GHGs. As stated on
page 10 of my diect testimony, the Company's plans regarding these investments
would not change due to carbon-emission restrctions. The units have
depreciation lives for rate mang purposes that provide sufficient remaining time
to depreciate the investments in the pollution controls.
Starting at line 20 on page 45 of his testimony, Mr. Reading refers to other
states that are evaluating whether to invest in environmental control
equipment or retire existing coal units. How do you respond?
PacifiCorp and its parent closely monitor environmental activities in other states,
including nearly all Western states. PacifiCorp is a paricipant in the Oregon
proceedings regarding Portland General Electric's Boardman plant. I would
correct Mr. Reading's statement regarding that proceeding, in that no decision has
yet been made to retie that plant before the end of the depreciation life used for
ratemakng. That is merely one of several options under consideration.
PacifiCorp and its parent are also closely following proceedings in
Colorado. As Mr. Reading correctly notes, the curent activity in Colorado relates
to the implementation of a statute enacted in 2010. That statute primaly focused
on reductions in nitrogen oxides and faciltated the conversion of 1000 MW of
coal-fired generation to natural gas generation. The regulatory proceeding is stil
pending.
539
Teply, Di-Reb - 11
Rocky Mountain Power
.1 Q.
2
3
4
5 A.
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22.23
Is the Company undertking reasonable effort to ensure that environmental
regulators consider the uncertanty create by requiring investments in
certain emisions controls prior to knowing the nature and extent of controls
on other emissions?
Yes. The Company appealed Regional Haze requirements in Wyoming for this
exact reason. Wyoming was the first state to make the determnation that best
available retrofit technology (BART) required the installation of selective
catalytic reduction ("SCR") controls for nitrogen oxides. The Company disagreed
with that determnation and asserted that Appendix Y of 40 CFR Par 51 did not
contemplate the installation of post-combustion controls. Additionally, the
Company was concerned that other environmental laws and/or regulations could
impact the Company's facilities affected by Wyoming's BART determnations.
These requirements not only include greenhouse gas reduction requirements, but
also a host of regulatory initiatives underway by the EPA, including the outcome
of pending coal combustion residual regulations and maximum achievable control
technology standards for mercur and non-mercur hazardous air pollutants. Due
to the uncertainty associated with the potential impact of these rules on the
Company's facilities, the Company appealed the BART permts issued by the
Wyoming Deparment of Environmental Quality to ensure that these and other
issues were considered in the agency's decision and, to the extent these issues had
an impact on long-term viabilty of the facilities, the economic analysis of adding
emission reduction equipment was properly reflected. The Company's appeal is
stil pending before the Wyoming Environmenta Qualty CounciL. Since the time
540 Teply, Di-Reb - 12
Rocky Mountain Power
.1 that the Company fied its appeal, the EPA has issued a BART determnation for
2 the Four Corners Power Plant, requirng the installation of SCR at all five units
3 operated by Arzona Public Service within a five-year period, without regard to
4 other environmental requirements or their associated uncertinties.
5 Q.In this rate case, the investments in environmental controls have already
6 occurred. What process is in place by which Mr. Reading's concern are
7 explored prior to investments being made?
8 A.The integrated resource planning (IRP) proceedings conducted in all six of the
9 states served by the Company provides the process to address Mr. Reading's
10 concerns. Future IRP proceedings wil more and more focus upon the increasing
11 complexity in balancing factors such as (1) pending environmental regulations.12 and requirements to reduce emissions, (2) avoidance of excessive reliance on any
13 one technology, (3) cost of energy efficiency and demand response programs, (4)
14 cost of supporting reasonable state economic development efforts, (5) cost of
15 additional transmission investment to increase effciency and reliabilty of the
16 integrated transmission system, (6) all while tring to maintain rates as affordable
17 as possible.
18 Q.Does this conclude your rebuttal testimony?
19 A.Yes.
.
541
Teply, Di-Reb - 13
Rocky Mountain Power
.
.
.
1 (The following proceedings were had in
2 open hearing.)
3 MR. SOLANDER: And Mr. Teply is available for
4 cross-examination.
5 COMMISSIONER SMITH: Thank you.
6 Mr. Budge, do you have questions?
7 MR. BUDGE: Briefly, if I may.
8
9 CROSS-EXAMINATION
10
11 BY MR. BUDGE:
12 Q.Mr. Teply, would you agree that Siemens i
13 performance on the Naughton 3 turbine overhaul was imprudent?
14 A.Yes, we would.
15 Q.And did the Company, in fact, receive a $500,000
16 liquidated damage payment from Siemens because they imprudently
17 performed the overhaul contract?
18 A.Yes, we did.
19 Q.And so would you agree that the length of the
20 outage was abnormally long due to the imprudent action of
21 Siemens?
22
23
A.We would agree that it was abnormally long, yes.
Q.Is it normal regulatory practice to allow
24 recovery of imprudent action or abnormal events?
25 A.No, it is not.
542
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
TEPLY (X)
RMP
.
.
.
1 Q.And do you believe it i S reasonable for the
2 Company to collect liquidated damage payments for an outage
3 from a vendor and then recover the cost of the outage from
4 customers by including the outage in the net power costs?
5 A.In this instance, the circumstances that are
6 being discussed here, although there was an extremely long
7 outage as a result of a subcontractor i s poor performance,
8 overall, the Company i s position is that the Company did not
9 imprudently manage that outage effort, took steps to actually
10 negotiate liquidated damages into the contract to protect not
11 only the Company but the Company i s customers obviously; but in
12 this instance, the subcontractor failed to perform, so we did
13 pursue the liquidated damages against that contract.
14 Q.Okay, I can appreciate that. I i m not sure that
15 was responsive to the question I had.
16 My question was is it reasonable for the Company
17 to collect the liquidated damage payment for the outage, and
18 then recover that same cost from the customers by including
19 that outage in the net power costs?
20 A.Maybe I misunderstood your question initially.
21 The LDs that were collected as part of that outage were
22 actually applied towards the purchase power costs of the
23 Company, technically crediting back to the customers on a net
24 power cost perspective.
25 Q.So you i re claiming the two net each other out?
543
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
TEPLY (X)
RMP
.
.
.
20
1 A.They netted out.
2 MR. BUDGE: No further questions. Thank you.
3 COMMISSIONER SMITH: Thank you.
4 Mr. Purdy.
5 MR. PURDY: I have no questions.
6 COMMISSIONER SMITH: Ms. Davison or
7 Mr. Williams.
8 MS. DAVISON: Yes, Madam Chair, I have a couple
9 questions.
10
11 CROSS-EXAMINATION
12
13 BY MS. DAVISON:
14 Q.Good afternoon, Mr. Teply.
15 A.Good afternoon.
16 Q.Mr. Falkenberg proposes an adj ustment related to
17 the Naughton outage that Mr. Budge was just asking you about.
18 Is that correct?
19 A.He does.
Q.And is it correct that you oppose
21 Mr. Falkenberg i s adjustment on the Naughton outage?
22
23
A.We do.
Q.Is your reason for opposing Mr. Falkenberg 's
24 Naughton outage adjustment because -- and I i II quote your
25 testimony -- poor subcontractor performance negatively impacted
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1 outage completion?
2 I i II refer you to your rebuttal, page 5, lines 21
3 through 23. Is that accurate?
4 A. That i s not the reason that we i re objecting to the
5 adj ustment to the outage duration.
6 Q.And why are you obj ecting to Mr.. Falkenberg 's
7 adj ustment then?
8 A.The intent of the testimony and the rebuttal
9 testimony was to identify the fact that there were actually
10 three separate outage events that Mr. Falkenberg addressed.
11 Each of the three were longer than we would have anticipated
12 going into an event like that.
13 However, what the intent of my rebuttal testimony
14 was intended to communicate is that if we take our fleet in
15 aggregate and we look at anomalous events like the three that
16 are described in Mr. Falkenberg i s testimony and then aggregate
17 them against other units that are actually performing well or
18 are maybe running actually improved rates, when we aggregate
19 that and look at that four-year outage cycle over time, the
20 three outages in question here did not skew that data
21 negatively.
22 Q.So it i S your testimony that we should look at
23 this in aggregate and not based on an individual outage?
24 A.That i S correct.
25 Q.Thank you. Did PacifiCorp receive liquidated
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1 damages payment associated with the Naughton outage?
2 A.Yes, as previously testified to, we did.
3 Q.And could you turn to your rebuttal testimony at
4 page 5, line 23, and do you state that the liquidated damages
5 payment was credited to customers?
6 A.Yes, I do.
7 Q.And is a correct statement?
8 A.The intent there is that the liquidated damage
9 payment was actually credited to our purchase power expense
10 accounting category; therefore, figuring into our net power
11 costs as a company.
12 Q.Well, let me ask the question a little more
13 clearly and a little more directly:
14 Is it your testimony that the liquidated damages
15 payment was credited to customers in this rate case?
16 A.No, not in this rate case. Actually, the timing
17 of this event preceded the ECAM that was -- actually, the first
18 ECAM, I believe, in the state of Idaho. The timing of this
19 event actually preceded that test period for the ECAM, so the
20 credit that you i re referring to here from the Idaho customers i
21 perspecti ve did not become part of that case.
22 Q.So is your testimony as written actually
23 incorrect?
24
25
A.If you were to take it from a just a Idaho
customer 's perspective. I would say from a proceedings
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1 perspecti ve, that would be correct.
2 Q.So, actually, your testimony you should say that
3 Idaho customers did not receive credit for the liquidated
4 damages payment. Correct?
5 A.That would be correct.
6 Q.And I i d like to hand you a document that we have
7 premarked as Exhibit 616. This is a PacifiCorp Response to
8 PIIC Data Response 150. Could you take a look at that
9 document, please?
10 (PIIC Exhibit No. 616 was marked for
11 identification.)
12 Q.BY MS. DAVISON: You see that?
13 A.Uh-huh.
14 Q.And this Response to the Data Request confirms
15 that Idaho ratepayers did not receive credit for the liquidated
16 damages payment?
17 A.Correct.
18 Q.Thank you.
19 Mr. Teply, does your testimony respond to
20 Mr. Falkenberg i s proposal to cap the allowable outage durations
21 in the Company i s four-year forced outage rates Mr. Falkenberg i s
22 recommending at 28 days? Do you respond to that?
23 A. Yes, with the same response that I previously
24 testified to: We see that as more of an aggregated statistic
and do not support the 28-day cap.
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1 Q.Does your rebuttal testimony recognize that
2 PacifiCorp has a 28-day cap in Oregon?
3 A.We speak to that topic. However, my
4 understanding and I wasn i t directly involved in that
5 proceeding -- but my understanding is that 28-day cap has not
6 yet been agreed to in that proceeding.
7 Q.Well, let me -- let me hand out for you a
8 document that I i ve premarked as Exhibit 617. I think that will
9 address that issue for you.
10 ( PIIC Exhibit No. 617 was marked for
11 identification.)
12 Q.BY MS. DAVISON: And I would assume from your
13 answer that you i re not aware that the Oregon Commission issued
14 an Order in that proceeding that you i re referring to on
15 October 22, 2010?
16 A.I am not.
17 Q.If you turn to page 5 of the Oregon Order, the
18 exhibi t marked 617, would you agree that the Oregon
19 Commission i s Final Order concluded that PacifiCorp' s historic
20 average forced outage rate should have the length of anyone
21 forced outage capped at 28 days?
22 A.I see that as an Item No. 5 here. Yes, I do see
23 that text.
24
25
Q.Thank you. And if you turn to page 21 of this
Order, do you see that the Oregon Commission
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1 MR. SOLANDER: l'm sorry, i donlt have a page 21.
2 THE WITNESS: I don I t have 21. I only have a few
3 pages here.
4 Q.BY MS. DAVISON: Oh, l'm sorry. I see it. That
5 is a different --
6 l'm trying to move along fast. I got a little
7 ahead of myself.
8 COMMISSIONER SMITH: It I s okay.
9 Q.BY MS. DAVI SON: I I m handing you what I s been
10 marked Exhibit 618, Mr. Teply.
11 (PIIC Exhibit No. 618 was marked for
12 identification. )
13 Q.BY MS. DAVISON: And are you familiar with this
14 Oregon Commission Order that was issued on October 17, 2007?
15 A.No, I am not.
16 Q.And if you turn to page 21, which is the second
17 page of this Order, do you see that the Oregon Commission caps
18 outages at 28 days because, quote: An outage of that duration,
19 no matter what the cause, is anomalous and raises issues
20 regarding its inclusion in normalized rates.
21 Do you see that?
22
23
24
25
A.I do see that quote, yes.
Q.And do you disagree with that conclusion?
A.Not knowing all the facts of this case, I really
can I t speak to that.
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1 MS. DAVISON: I have no further questions. Thank
2 you.
3 COMMISSIONER SMITH: Thank you.
4 Mr. Olsen.
5 MR. OLSEN: No questions, Madam Chair.
6 COMMISSIONER SMITH: Mr. Otto.
7 MR. OTTO: I do have a few, Madam Chair.
8
9 CROSS-EXAMINATION
10
11 BY MR. OTTO:
12 Q.There you are. Good evening, Mr. Teply. I have
13 a couple questions about the pollution control equipment --
14 A.Okay.
15 Q.-- just to narrow it down.
16 Now, I think this might have been in
17 Mr. McDougal i s testimony, but are you aware -- well, let i s
18 start off with this:
19 You i re in charge of engineering and pollution
20 controls at your coal plants. Is that part of your job
21 portfolio?
22 A.Yeah, part of my team iS responsibilities is to
23 construct the environmental retrofit proj ects that we are
24 discussing today.
25 Q.Are you -- do you know the amount of money the --
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1 that Rocky Mountain Power is requesting in this rate case for
2 pollution controls?
3 A.Not right off the top of my head, but I 'm
4 familiar with the proj ects.
5 Q.Okay. Well, I i II just say it i s -- Mr. McDougal
6 says it 's $475 million. Does that sound about correct for this
7 test year?
8 A.Yes, it does.
9 Q.In the ballpark?
10 A.Uh-huh.
11 Q.So, thank you. Do you have final approval from
12 the person who gives final approval for the type of technology
13 that i S being installed?
14 The regulator, excuse me, the regulator?
15 A.I i m not sure of your question there.
16 Okay. We have permits to construct the proj ects
17 that are contemplated here from the respective states that
18 we i re building the equipment in.
19 Q.All right. And these requirements are required
20 by the Clean Air Act. Is that correct?
21 A.Yes, the proj ects, the environmental control
22 proj ects that we i re contemplating here, are part in -- are
23 being completed in response to regional haze rules in the
24 states of Wyoming and Utah.
25 Q.And you testified that the -- the Federal
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i Environmental Protection Agency will review the State permits
2 and give a final approval?
3 A.No, that i s not the case.
4 Q.Oh, that i s not the case?
5 A.The way the process works, the EPA actually has
6 final review and approval over the State implementation plans
7 that each state submits. Part of that State implementation
8 plan is the individual permits and individual proj ects that the
9 states have required. They assemble those projects into a
10 cohesive plan, submit that ultimately for EPA review and
11 approval.
12 Q.So is it fair to say that the proj ects Rocky
13 Mountain Power is proposing and its specific technologies that
14 they i re proposing are an integral part of the State
15 implementation plans?
16 A.Yes, I would say that would be fair to say.
17 Q.And so if the EPA decided that they do not
18 approve the State implementation plans, could it be the case
19 that the result would be different requirements for Rocky
20 Mountain Power?
A.No, that i s very unlikely. The states actually --
22 the EPA actually participates in the permitting process during
23 the public commenting period for the individual BART permits,
24 which is a Best Available Retrofit Technology permit that
25 allows you to construct these proj ects. The EPA actually
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1 participates in that process, so they are very much aware of
2 the proj ects that we have proposed and that the states
3 ultimately proposed as part of their State implementation plan.
4 Q.All right. So on page 12 of your rebuttal
5 testimony, you discuss that Wyoming was the first state -- this
6 is on lines 6 through 9 -- Wyoming was the first state to make
7 the determination that BART required specific technology, and
8 that i s called selective catalytic reduction controls.
9 And correct me if I i m wrong, but that i s not the
10 technology that Rocky Mountain Power has chosen for the
11 specific projects in this case?
12 A.Yeah, for the specific proj ect in this case,
13 selecti ve catalytic -- none of the proj ects we i ve talked about
14 today have selective catalytic reduction equipment being
15 installed.
16 Q.Correct. So then continuing on page 12, on lines
17 18 through 22, it appears that you appealed the BART permits
18 because you disagreed that states should require the selective
19 catalytic reduction?
20 A.Yeah, and at the time of filing this testimony,
21 that appeal was active. We i ve since closed that appeal.
22 Q.What were the results of that closure?
23 A.The results of the closure is that we have agreed
24 with the State that we will be installing SCR. They will
25 continue to carry SCR in their permits in their State
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1 implementation plans and for Jim Bridger and for Naughton
2 Jim Bridger Units 1 through 4 and Naughton Unit 3 -- over time.
3 Q.Did that Agreement include dates that you would
4 install that equipment?
5 A.Yes, there are compliance dates set up and
6 part -- negotiated as part of that Settlement.
7 Q.Do you know what those dates are, or the year?
8 A.Naughton Unit 3 SCR would be placed in service in
9 2014; Jim Bridger Units 3 and 4 would be placed in service in
10 2015 and 2016; and then the SCRs for Jim Bridger 1 and 2 would
11 be in i 21 and '22, I believe -- 2021 and 2022.
12 Q.So in less than ten years, you i II be installing
13 more expensive pollution control equipment?
14 A.There will be additional controls expected to be
15 installed on those -- on those facilities.
16 Q.All right. And then turning to, let i s see, it i s
17 page 12, it i S continuing on page 12 at the bottom and then over
18 onto page 13, you talk of the Four Corners power plant and the
19 Arizona Public Service Commission, and that the EPA has
20 required this technology immediately on that plant?
21
22
A.Right. That is correct.
Q.Do you foresee the EPA doing a similar thing in
23 Wyoming?
24
25
A.That is always a risk. As you carry these
projects through the ultimate approval process, including the
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1 State implementation plan review processes, that i s very much a
2 part of why we sit down with the states of Utah and Wyoming for
3 our thermal fleet, for example, and spend a lot of time
4 developing schedules that integrate into our outage planning
5 and into our ten-year planning process, to basically align
6 oursel ves with the State environmental quality boards such that
7 when there are concerns raised by the EPA regarding timing, we
8 have at least an Agreement at the State level that we are
9 prudently approaching -- or, prudently applying the control
10 technologies in a timely fashion.
11 Q.All right. But, again, it i s the EPA who gets to
12 make the final decision?
13 A.Yeah, ultimately, the EPA does approve the State
14 implementation plans.
15 Q.And they i ve not done that yet in Wyoming?
16 A.Not in Wyoming, nor in Utah.
17 Q.Or nor in Utah. And those are the states that
18 you i re asking for recovery in this case?
19 A.Obviously not for the SCR proj ects
20 Q.But pollution?
21 A.-- but we are talking about facilities in both
22 Utah and Wyoming.
23 Q.Right. And so I guess that begs the question,
24 who carries the risk of the EPA requiring better pollution
25 control if you i ve already sought recovery for Wyoming and Utah
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1 without getting final approval about what that technology
2 should be?
3 A.Well, I think you i re mixing two -- two topics
4 here, one being that the projects that we i re actually
5 requesting recovery on now, those proj ects, there i s very little
6 risk that the EPA will change -- very little, if any, risk that
7 the EPA will change those requirements because they have
8 actually been involved in the permitting process.
9 I think your question is is there a risk with
10 respect to additional control proj ects that will be required
11 ultimately by EPA when they review the State implementation
12 plans of Wyoming and Utah. There is that risk. The Company i s
13 taking prudent steps to try to avoid that acceleration of
14 addi tional proj ects via things like appealing the BART permits
15 for the SCRs in Wyoming; and also, obviously, watching closely
16 the other states i State implementation plan reviews that are
17 ongoing via the EPA at this point.
18 So, I think that -- l'm not sure that your
19 question can be dovetailed into one answer because I think
20 there i s two steps here along the way, one of which the EPA is
21 fully well aware of, the second of which becomes a risk to the
22 Company from a cost and planning perspective, but, ultimately,
23 none of those costs have been committed yet.
24 Q.That i S a fair answer. I appreciate that
25 clarification. One last question:
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21
22
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24
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1 In Arizona, was the EPA involved in the
2 permi tting process in that state, commenting on the State plan,
3 and then --
4 A.Having not participated directly, I i m not sure if
5 they would have submitted public comments or not during the
6 process. I really can i t speak to that.
7 MR. OTTO: Thank you. That's all.
8 COMMISSIONER SMITH: Mr. Woodbury, do you have
9 questions?
10 MR. WOODBURY: Madam Chair, Staff has no
11 questions. Thank you.
12 COMMISSIONER SMITH: And I i II tell you, it does
13 no good to look at the clock.
14 (Laughter)
15 MR. WOODBURY: I can i t see the clock from here.
16 COMMISSIONER SMITH: Are there questions from the
17 Commissioners?
18 COMMISSIONER REDFORD: No.
COMMISSIONER KEMPTON: No.
COMMISSIONER SMITH: Nor I.
Do you have redirect, Mr. Solander?
MR. SOLANDER: No redirect, thank you.
COMMISSIONER SMITH: Okay.
MR. SOLANDER: And I would ask that Mr. Teply
also be excused from the remainder of the proceeding.
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1 COMMISSIONER SMITH: Is there any obj ection to
2 excusing Mr. Teply?
3 Seeing none, he i s excused.
4 (The witness left the stand.)
5 MR. SOLANDER: Madam Chair, Rocky Mountain Power
6 calls Carol Hunter -- I i m sorry, calls Brian Hedman as its next
7 witness.
8 MR. HEDMAN: Carol can go first if she wants.
9
10 BRIAN HEDMAN,
11 produced as a witness at the instance of Rocky Mountain Power,
12 being first duly sworn, was examined and testified as follows:
13
14 DIRECT EXAMINATION
15
16 BY MR. SOLANDER:
17 Q.Good afternoon.
18 A.Good afternoon.
19 Q.Could you please state and spell your name for
20 the record?
21
22
A.My name is Brian Hedman: B-R-I-A-N, H-E-D-M-A-N.
Q.And by who are you employed and in what
23 capacity?
24
25
A.I am employed by the Cadmus Group. I am here on
behalf of the Company. I am a principal with that
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23
24
25
1 organization.
2 Q.And are you the same Brian Hedman who filed
3 supplemental testimony on August 6, 2010, in this proceeding?
4 A.I am.
5 Q.And do you have any corrections or changes to
6 that testimony at this time?
7 A.No.
8 Q.If I were to ask you the same questions set forth
9 in your testimony, would your answers be the same today?
10 A.Yes.
11 MR. SOLANDER: I would move the Commission that
12 the prefiled supplemental testimony of Brian Hedman be spread
13 upon the record as if read.
14 COMMISSIONER SMITH: Is there any obj ection?
15 Seeing none, it is so ordered.
16 (The following prefiled supplemental
17 testimony of Mr. Hedman is spread upon the record.)
18
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Please state your name, business and business' address.
My name is Brian K. Hedman: I am employed by The Cadmus Group, Inc, at 720
S.W. Washington, Suite 400, Portland, Oregon, 97205.
4 Qualifications
5 Q.What is your current position at The Cadmus Group (Cadmus) and your
6 employment history?
7 A.I joined Cadmus (then Quatec, LLC) in 2002 and hold the position of PrincipaL.
8 Prior to joining Cadmus I was employed by PacifiCorp for 20 years in a variety of
9 positions. My last position at PacifiCorp was Manager of DSM Policy. In tht
10 role I was responsible for preparng and filing the Company's Integrted Res6urce
11 Plan and energy efficiency programs in Oregon, Washigton, Idao, Californa,.12 Uta and Wyoming.
13 Q.What are your responsibilties at Cadmus?
14 A.I am responsible for designg and evaluating energy effciency and low income
15 program, supportg integrted resource plang and preparng testimony in
16 support of utility cost of service, rate design and energy efficiency taff fiings.
17 Q.What is your educational backgound?
18 A.I hold a Bachelor's degree in business from the University of Washington and a
19 Master's degree in economics from Portand State University.
20 Q.What other jurisdictions do you work in?
21 A.In addition to PacifiCorp, I curently support clients in Oregon, Washigton,
22 Californa. Uta, Iowa. Missour, Arona Colorao, Kaas, Nebraska. New
.
560 Hedan, Supp - 1
Rocky Mountan Power
. 561 Hedman,Supp - 2
Rocky Mounta Power
562 Hedman, Supp - 3
Rocky Mountan Power
563 Hedman,. Supp - 4
Rocky Mountain Power
565 Hedan, Supp - 6
Rocky Mounta Power
.1
2
3
4
5
6
7
8
9
10
11.12
13
14 Q.
15 A.
16
17
18
19 Q.
20 A.
21
22
23.
program, what would have happened? In most instances, DSM programs provide
information and incentives to customers to encourage the purchase or adoption of
energy effciency measures and practices. Absent the program, some of these
customers would have purchased the measures or underten the practices on
their own accord. It would not be appropriate to credt the progr with changig
these customers' behavior. If they receive an incentive from the progr for
these actions, absent program influence, they are considered "free-riders". In
other words, it was not necessary for the utility to provide these customers with an
incentive and the utility should not get credit for their actions. Energy savings
from free-riders are not included in the tota program energy savings for the
puroses of cost-effectiveness determination and customer costs associated with
free-:riders are not included in the program costs. Any payments by the utility to
the customer are included as costs of the program, however.
How is free-ridership quantied?
Free-ridership is expressed as a net-to-gross factor that combines the impacts of
the frèe-ridership (incentive recipients tht would have purchased the energy
effciency measure with no incentive) and spilover (additional purchaes
influenced by the progrm but for which no incentive is paid).
How are net-to-gross factors estimated?
In the planng phase net-to-gross assumptions ate derived from sources such as
prior evaluations of the Company's programs and the Data Base of Energy
Effciency Resources (DEER), which contain the results of hundreds of progr
evaluations. These are tyically the factors used in progr filings. Net-to-gross
566 Hedman, Supp - 7
Rocky Mountan Power
.1 factors are estimated through post implementation evaluation of programs.
2 Customer interviews and market analysis are used to estimate the free-ridership
3 and spilover.
4 Q.Is Rocky Mountain Power's process for determining annual savings and cost
5 effectiveness consistent with the process used by utilties in other
6 jurisdictions?
7 A.Yes. The process used by Rocky Mountain Power in its annual report is
8 consistent with that used by other utilities. The costs reflect the actul
9 expenditures incured by the company while the savings are based on an estimate
10 derived from the planing assumptions. Rocky Mountain Power reviews program
11 costs and participation thoughout the progr year and adjusts the programs to.12 reflect changes that occur. In addition, Rocky Mountain Power performs thrd
13 pary process and impact evaluations of the programs consistent with the terms of
14 the MOD. These evaluations help the Company fuer refine the progrs to
15 increase parcipation, increase energy savings acquisitions and maintan or
16 improve their cost effectiveness on an ongoing basis.
17 Q.How do Rocky Mountai Power's Idaho programs compare to other
18 programs Cadmus has assessed cost effectveness of or evaluated?
19 A.Cadmus has evaluated and assessed the cost effectiveness of hundreds of
20 progrs implemented by utilities nationwide, including PacifiCorp's. The
21 Company's progrs are designed using widely accepte practices that aim to
22 maxiz parcipation while miniing utility costs and rate impacts. Mid-
23 coure adjusents to the progrs are noted in the anual reports and indicate.
567 Hedm, Supp - 8
Rocky Mounta Power
568 Hedman, Supp - 9
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10
11.12
13
14
15
16
17
18 Q.
19 A.
20
21
22
.
combined (load management and energy effciency, excluding NEEA costs and
savings) is 3.7, with a net TRC benefit to customers of over $32 million (Exhibit
No. 56, Table 2). The TRC and UCT cost for the load management programs
were $ 14.53/kW-yr and $43.24/kW-yr, respectively, and can be compared against
utilty avoided costs of $67 .05/kW -yr (Exhibit No. 56, Table 3). The levelized
TRC and UCT cost of the energy efficiency programs were 6.5 cents and 4.4
cents per kWh, respectively, compared against utility avoided costs of 8.8 cents
(Exhibit No. 56, Table 3). Though allowed by the California cost effectiveness
formulations, the benefit-to-cost ratios do not include non-energy benefits or other
fuel benefits and are calculated utilizing net savings, i.e., inclusive ofthe impacts
of free-ridership and spilover. This presents a conservative estimate of the
program's cost effectiveness. As an overall portolio, the DSM investments were
also cost-effective from both a Rate Impact Test (RI and Parcipant Cost Test
(PCT) perspective with benefit-to-cost ratios of 1.372 and 11.436, respectively
(Exhibit No. 56, Table 2). The energy effciency portfolio was cost-effective
under all cost tests except the RI test where the benefit-to-cost ratio was .68
(Exhbit No. 56, Tables 4 and 5).
Are the process and impact evaluation of these programs complete?
No. The process and impact evaluations are in varous stages of completion.
Field work, sureys and data anlysis are largely complete and the quality
assurce process is underway. I expect the results to be fialized by the end of
the yea.
569 Hedman, Supp - 10
Rocky Mountain Power
.1 Q.Please summarize your conclusions.
2 A.The Company's expenditues of Schedule 191 revenue (and the fuds utilized for
3 irrgation load control participation credits) have been reasonable and prudent. A
4 portfolio of programs covering all customer classes has been offered with total
5 savings of over 258 MW of annual load control available and total energy savings
6 of over 25 GWh (including NEEA) over the 2008 and 2009 calenda periods. A
7 levelized utility cost per saved kilowatt hour of 4.4 cents has been achieved. The
8 levelized avoided costs over the same period were 8.8 cents per kWh. From a
9 conservative UCT perspective, the cost per kW for load management investments
.10 was $43.24/kW-yr against the Company's avoided cost of$67.05/kW-yr. Based
11 on program performance, anual reports already filed with the Commission and.12 the analysis provided in Exhibit No. 56, the 2008 and 2009 progr costs were
13 prudently incured.
14 Q.Does this conclude your testimony?
15 A.Yes.
.
570 Hedman, Supp - 11
Rocky Mounta Power
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.
.
18
19
1 (The following proceedings were had in
2 open hearing.)
3 MR. SOLANDER: And Mr. Hedman is available for
4 cross-examination.
5 COMMISSIONER SMITH: Mr. Budge.
6 MR. BUDGE: No questions.
7 COMMISSIONER SMITH: Mr. Purdy.
8 MR. PURDY: No questions.
9 COMMISSIONER SMITH: No questions there.
10 Mr. Olsen?
11 MR. OLSEN: No questions, Madam Chairman.
12 COMMISSIONER SMITH: Mr. Otto.
13 MR. OTTO: No questions, Madam Chair.
14 COMMISSIONER SMITH: Mr. Woodbury.
15 MR. WOODBURY: Wow. Thank you, Madam Chair.
16 Just one question.
17
CROSS-EXAMINATION
20 BY MR. WOODBURY:
21 Q.On page 3, I think, line -- go beyond 13. You
22 speak of the DSM programs, the eight programs that the Company
23 has, and you state that in addition to those, the Company i s
24 Idaho portion of the Northwest Energy Efficiency Alliance
25 sponsorship is funded through the revenues collected from
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1 Schedule 191.
2 Are you able to articulate the Idaho benefits
3 that are received by customers through the Company 's
4 participation in NEEA?
5 A.In what sense? In a monetary sense or in the
6 sense of what NEEA i S function is? I should just add, for the
7 record, that I was a board member of the NEEA organization for
8 the first five years of its existence, so I i m generally
9 familiar with what they do.
10 But they operate upstream. They don i t provide
11 incentives directly to customers. So it i S a little bit more
12 difficul t to attribute the actual impacts of their programs to
13 any specific customer across the Northwest.
14 Q.Is it your understanding because of a prior
15 Commission Order with respect to Schedule 191 that the Company
16 is proposing to eliminate its participation in NEEA?
17 A.I i m not familiar with that Order.
18 Q.On page 10 of your testimony, you speak of
19 process and impact evaluations of the DSM programs, and you
20 said that you expect the results to be finalized by the end of
21 the year?
22 A.That i S correct.
Q.This is almost December. Have those results been
24 finalized?
25 A.No, they have not.
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1 Q.Okay. Do you still expect that they will be
2 finalized by the end of the year?
3 A.Yes, actually, I do.
4 Q.Thank you.
5 MR. WOODBURY: Madam Chair, I have no further
6 questions.
7 COMMISSIONER SMITH: Do we have questions from
8 the Commissioners?
9 COMMISSIONER REDFORD: No.
10 COMMISSIONER KEMPTON: No.
11 COMMISSIONER SMITH: Nor I.
12 Any redirect?
13 MR. SOLANDER: No redirect.
14 COMMISSIONER SMITH: No redirect.
15 MR. SOLANDER: And we would also ask that
16 Mr. Hedman be excused.
17 COMMISSIONER SMITH: Is there any objection to
18 excusing Mr. Hedman?
19 Seeing none, you i re excused. Thank you for being
20 here, appreciate your help.
21 (The witness left the stand.)
22 COMMISSIONER SMITH: We have reached the limit of
23 my endurance, so it is my intention to recess briefly and have
24 the Commissioners have a small caucus on the issue of
25 surrebuttal and come back and give you our issues with regard
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1 to that, so, if you i II all just sit tight for a couple of
2 minutes--
3 And it was also my intention to start in the
4 morning at about 8: 35. Does anybody have any problem with
5 that?
6 MR. HICKEY: None at all.
7 COMMISSIONER SMITH: We i II be off the record for
8 a few minutes.
9 (Discussion off the record.)
10 COMMISSIONER SMITH: We have surrebuttal
11 testimony proposed by three parties: Mr. Olsen, Ms. Davison
12 and Mr. Williams, and Mr. Budge. Is that correct? Do I have
13 all of them?
14 Wi th regard to Mr. Budge i s proposed surrebuttal,
15 the Commission would not accept the surrebuttal testimony of
16 James Smith. We believe that Mr. Budge i s cross-examination
17 covered aptly all of the areas that are in this surrebuttal,
18 and there i s no need for what is essentially a restatement of
19 the questions that have already been asked of Mr. Walje and
20 responded to. So we believe at this time, that would be
21 unnecessary and potentially prej udicial to the Company.
22 Wi th regard to the testimony of -- proposed
23 surrebuttal of Kevin Lawrence, we think that Mr. Budge 's
24 cross-exam also very expertly explored the extent of
25 Mr. Walj e i s knowledge regarding Chinese electric rates and
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1 Monsanto i S operation, and the Commission is very able to
2 determine what weight to give Mr. Walj e i s testimony on those
3 issues, which, frankly, we see as not being central to the rate
4 case. So we would not accept filing of surrebuttal of
5 Mr. Lawrence.
6 And with regard to the surrebuttal testimony of
7 Mr. Gorman, I would just note that the witnesses he 's
8 surrebutting have already appeared and been excused from the
9 hearing, and we also believe that that i s unnecessary and would
10 not accept it.
11 With regard to the surrebuttal testimony proposed
12 of Dr. Peseau and Mr. Widmer, I would ask the Company to review
13 it and determine if it i S really necessary to oppose this at
14 this time. These witnesses are still to appear. It may help
15 the smooth proceeding of the case to have that there, and so I
16 would ask that you take a look at that.
17 MR. HICKEY: We will.
18 COMMISSIONER SMITH: And I would ask the same
19 thing with regard to Mr. Falkenberg on behalf of the Industrial
20 Customers. It i S getting late.
21 With regard to Mr. Olsen i s proposed surrebuttal,
22 which actually was filed here yesterday and I had the
23 opportunity to read, I think that that should be admitted. I
24 think the Company should take the opportunity to respond to
25 what I see as essentially a customer suggestion with regard to
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1 the irrigation load control program, and I think it would be
2 beneficial to do that.
3 So, that would be our disposition of the
4 surrebuttal, which means we will address this again in the
5 morning with regard to the three that I i ve asked you to take
6 particular note of.
7 Mr. Budge.
8 MR. BUDGE: Just one matter unrelated: On the
9 Motion to Strike that the Commission Chair I believe is going
10 to review tonight --
11 COMMISSIONER SMITH: Yes. Yes.
12 MR. BUDGE: -- whether it be deferred, and I
13 think the Motion was to strike, but then Counsel i s argument, as
14 I understood it, would be to identify what might be deferred to
15 the second phase; and, obviously, the Commission can discern
16 what to look at and what not to look at.
17 The only thing I would make mention of is we saw
18 the line and page identified for the first time this morning,
19 which I haven i t had a chance to look at even though the Motion
20 was filed weeks ago. So, if some of that is identified to be
21 deferred, then the Company in its rebuttal testimony many times
22 referred to that testimony as well, and so that similar
23 testimony of the Company is trying to rebut something they
24 don i t like, Monsanto i s would have to similarly be deferred, and
25 I can i t identify that without knowing the ruling on the other.
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1 COMMISSIONER SMITH: Well, I only received it
2 this morning also, so I haven i t had time to look at the page
3 and line references. But I would certainly have hoped that you
4 did not ask to strike something that you rebutted, but I don i t
5 know that because I haven i t had time to look at it.
6 So, I guess my question is do you want me,
7 tonight, to look at your pages and line references with an eye
8 towards something that needs to be stricken, or do you just
9 want to generally ask the Commission not to delve into the
10 issues that we i re going to cover at the February hearing?
11 MR. HICKEY: Well, I think it i s the latter, and
12 that i s why --
13 COMMISSIONER SMITH: Is your mic on?
14 MR. HICKEY: It i s the latter, Chairman Smith.
15 COMMISSIONER SMITH: Okay.
16 MR. HICKEY: And the reason it is, is the
17 practical observation that we i re not really striking because we
18 have a second phase of the hearing.
19 COMMISSIONER SMITH: Okay.
20 MR. HICKEY: But--
21 COMMISSIONER SMITH: I take that as a Motion, as
22 you withdrawing your Motion to Strike and merely asking the
23 Commission to note that wherever there are references or
24 testimony that may relate more to the economic valuation of
25 Monsanto 's interruptibili ty, that those not be considered
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1 during this phase of the hearing, but, rather, they will be
2 fully explored in the later hearings.
3 MR. HICKEY: That is a fair summary of my
4 practical offer to try to work us all through this, with one
5 significant exception, and that i s Mr. Collins. Mr. Collins
6 should not be allowed to testify in this phase of the case for
7 the reason that his whole purpose as a witness, as you will
8 recall, was to rebut Mr. Clements. His testimony was actually
9 prepared and filed when we were all gathering around the
10 argument on that Motion of the timeliness of the Clements
11 testimony that led to your October 22nd Order. So we would
12 certainly ask that Mr. Collins be deferred as well to this
13 second phase for the reason that we shouldn i t have to hear
14 these things twice. All of our time, but most importantly the
15 Commission i s time, is limited significantly for this case, and
16 there is no purpose in calling him at this point.
17 COMMISSIONER SMITH: Mr. Budge.
18 MR. BUDGE: I won i t respond. I think the Chair,
19 as you make the review, can make the determination with respect
20 to all testimony.
21 COMMISSIONER SMITH: So that means you i re going
22 to present Mr. Collins.
23 MR. BUDGE: Correct.
24 COMMISSIONER SMITH: All right.
25 MR. HICKEY: Well, we will I guess take it up
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1 when he gets presented, but it just -- I i ve said all that I
2 think I need to.
3 COMMISSIONER SMITH: Okay. Thank you.
4 Thank you, everyone, for helping us get as far as
5 we have today. I don i t know if it i s still snowing outside.
6 Plan to start at 8: 35 and hope that we all can be here at that
7 time. Until then, enj oy your evening. We i II see you in the
8 morning.
9 MR. HICKEY: Thank you.
10 (The hearing was adj ourned at 6: 01 p.m.)
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