20101220Vol V Technical Hearing, pp 821-1036.pdf

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ORIGINAL
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF PACIFICORP 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:December 1, 2010
VOLUME V - Pages 821 - 1036
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HEDRICK
COURT REPORTING
POST OFFICE BOX 578
BOISE, IDAHO 83701
208-336-9208
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24.25
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
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For Monsanto:
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For Idaho Irrigation
Pumpers Association (IIPA):
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16 For Idaho Conservation
League (ICL):
For PacifiCorp Idaho
Industrial Customers (PIIC):
For Community Action
Partnership Association
of Idaho (CAPAI):
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
APPEARANCES
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1 I N D E X
2
WITNESS EXAMINATION BY PAGE
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Erich Wilson
(RMP)
822
824
843
846
Mr. Hickey (Direct)
Prefiled Rebuttal
Mr. Woodbury (Cross)
Commissioner Kempton5
6 Michael Gorman
(Monsanto)
Mr. Budge (Direct)
Prefiled Direct
Prefiled RebuttalMr. Hickey (Cross)
850
854
905
911
7
8
9
Hui Shu
(RMP)
914
921
936
985
986
988
1001
1006
1008
Mr. Hickey (Direct)
Prefiled Direct
Prefiled Rebuttal
Mr. Otto (Cross)
Mr. Olsen (Cross)
Ms. Davison (Cross)
Mr. Woodbury Cross)
Mr. Budge (Cros s)
Mr. Hickey (Redirect)
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Gregory Duvall
(RMP)
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1012
1021
1034
1035
Mr. Hickey (Direct)
Prefiled Rebuttal
Mr. Budge (Cross)
Commissioner Smith
Mr. Hickey (Redirect)
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17 EXHIBITS
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NUMBER PAGE
For PacifiCorp Idaho Industrial Customers:
620 PIIC Data Request 156 Marked 999
621 PIIC Data Request 155 Marked 1000
For Monsanto:
248 PacifiCorp 2008 Integrated Resource
Plan, 11 pgs
Marked 1022
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
INDEX
EXHIBITS
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1 BOISE, IDAHO, WEDNESDAY, DECEMBER 1, 2010, 1:31 P.M.
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3
4 COMMISSIONER SMITH: I believe we're ready to go
5 back on the record, and although we kind of left Mr. Gerrard
6 hanging at the end, I see he has left the stand.
7 (Laughter. )
8 MR. HICKEY: And would appreciate being excused,
9 Madam Chairman.
10 COMMISSIONER SMITH: Is there any objection to
11 excusing Mr. Gerrard?
12 Seeing none, he's excused.
13 Mr. Budge, does your witness need to go now?
14 MR. BUDGE: No, he needs to be able to leave here
15 by 4: 30, and I checked with the other parties and most of the
16 parties appear not to have any cross for him other than the
17 Company would have some, and so --
18 COMMISSIONER SMITH: So wouldn't it be prudent to
19 take him now?
20 Or, Mr. Hickey, I guess I'd defer to you. It's
21 your case and I don't like to interrupt it.
22 MR. HICKEY: Sure. He could certainly go now if
23 you want. I do want -- we're trying to reduce and/or eliminate
24 any cross on our part and the people I need to confer with
25 aren't back here yet, so --
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
COLLOQUY
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1 COMMISSIONER SMITH: Well, let's start with I
2 assume Mr. Wilson and see how far we get.
3 MR. HICKEY: Yeah, we certainly will accommodate
4 that need.
5 COMMISSIONER SMITH: What I don't like to do is
6 be in the middle of a witness if we can avoid it.
7 MR. HICKEY: I assure you.
8
9 ERICH WILSON,
10 produced as a witness at the instance of Rocky Mountain Power,
11 being first duly sworn, was examined and testified as follows:
12
13 DIRECT EXAMINATION
14
15 BY MR. HICKEY:
16 Q.Good afternoon, Mr. Wilson.
17 A.Good afternoon.
18 Q.For the record, would you please state and spell
19 your name?
20 A.Sure. My name is Erich D. Wilson: E-R-I-C-H,
21 W-I-L-S-O-N.
22 Q.And by whom are you employed and in what
23 capacity?
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A.I'm employed by PacifiCorp as the director of
human resources.
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WILSON (Di)
RMP
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1 Q.And did you have an opportunity to file rebuttal
2 testimony on November 16th of this year, and attach to that
3 testimony Exhibits 68 through 70?
4 A.I have.
5 Q.Do you have any additions or corrections to that
6 testimony, Mr. Wilson?
7 A.Not at this time.
8 Q.If I were to ask you the questions set out in
9 your rebuttal testimony, would your answers be the same
10 today?
11 A.They would be.
12 MR. HICKEY: I would move that the prefiled
13 rebuttal testimony of Erich Wilson be spread onto the record as
14 if read, and that Exhibits 68 through 70 be marked for
15 identification.
16 COMMISSIONER SMITH: If there's no obj ection, it
17 is so ordered.
18 (The following prefiled rebuttal testimony
19 of Mr. Wilson is spread upon the record.)
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WILSON (Di)
RMP
.1 Q.Please state your name, business address and present position with
2 PacifiCorp dba Rocky Mountain Power (the "Company").
3 A.My name is Erich D. Wilson. My business address is 825 NE Multnoma, Suite
4 1800, Portland, Oregon 97232~My present position is Director, Human
5 Resources.
6 Q.Have you riled direct testimony in this ca?
7 A.No.
8 Qualifications
9 Q.
10 A.
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20 Q.
21 A.
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Please briefly describe your education and business experience.
I have been employed as the Director of Human Resources since March 2006.
From March 2001 to March 2006, I was the Director of Compensation for the
Company. Prior to coming to the Company, I held varous positions within the
area of human resources (operations, benefits and stafing), but for the majority of
my career I have diected the design and admnistration of compensation
programs. I received a Bachelor's degree in Economics (Business) from the
University of California, San Diego in 1992. In addition, I achieved the Certified
Compensation Professional status from the American Compensation Association
in 1999 and have kept this certification curent though attending varous
educational programs and seminars.
Please describe your present duties.
My prima responsibilties include managing the Company's human resource
function, including compensation, benefits, compliance, staffing, training and
development, employee and labor relations, and payrolL. I focus on assisting the r
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Wilson, Di-Reb - 1
Rocky Mountain Power
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Company in attracting, retaning, and motivating qualified employees along with
the admnistrtion of all associated human resource programs and employee
3 experiences.
4 Purpose and Overview of Rebuttal Testimony
5 Q.
6 A.
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What is the purpose of your rebuttl testimony?
The purose of my rebuttal testimony is to demonstrate why the Commssion
should reject certain labor related adjustments proposed by PacifiCorp Idaho
Industrial Customers witness Mr. Greg R. Meyer and Idaho Public Utilties
Commssion Staff witness Mr. Donn English. Specifically, I address the
following:
· The Company's incentive program is not a "bonus", is strctued to provide
benefits to customers consistent with Commssion precedent, and is par of the
Company's total market-based compensation package. The removal of
incentive expense would therefore result in below-maket compensation.
· 2009 and 2010 base wage expense is reasonable and consistent with the
competitive market in which the Company competes in for labor.
· Supplemental Executive Retirement Plan ("SERP") expense is related to a
market competitive benefit offering.
Please briefly describe the Company's compensation philosophy.
The Company's primar objective in establishing employee compensation is to
provide pay at the maket average. Compensation at the market average
(competitive level) is critical to attacting and retaining qualified employees to
support the business and our customers.
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Rocky Mountain Power
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In order to encourage superior performance, a certin percentage of each
employee's maket compensation must be "at risk." The Company's Annual
Incentive Plan is strctured so that each employee has the opportnity to receive
total compensation at the market average, so long as the employee performs at an
acceptable leveL. In exceptional performance years, an employee's incentive may
be more than target and in low performance years may be below target, but on
average, the incentive is generally at the guideline leveL. If the individual fails to
ear the full guideline incentive, that individual wil be paid less than the
competitive total cash compensation in the marketplace for that year. Central to
the Company's approach to total compensation is that, while certain employees
may be paid more than or less than market in a given year as a result of the
incentive portion of compensation, on an overall basis the base compensation and
incentive wil result in a level of compensation commensurate with the market.
Stated another way, in the unlikely event every employee performed at exactly the
same level, each employee would be paid only at the market average.
Has the Company made changes to the Annual Incentive Plan in response to
Commission feedback?
Yes. In 2006, the Company adjusted its Anual Incentive Plan in response to
feedback from the Commssions that represent our customers. Prior to that time,
the Company sought recovery of all awards made to employees under the plan,
whether or not those awards resulted in tota employee compensation that was
above a target (competitive market) leveL. Under the curent plan, the Company
is only seeking recovery of incentive awards that, in tota, result in employee
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Rocky Mountain Power
.1 compensation at the competitive maket leveL.
2 Total Compensation
3 Q.
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How doe the Company determine the total cash compensation package for
each position?
At least annually, the Company collects market data for comparable jobs and
calculates the average data point for total cash compensation by position. To do
so, we use a varety of compensation studies put out by varous
experts/organizations, including Hewitt Associates, Towers Watson, and Mercer.
In addition, the Company also uses an on-line tool called MarketPay.com.
MarketPay.com provides electronic accss to all of the compensation studies we
have trditionally used and some additional sureys, allowing us to more
efficiently perform information searches and job and pay comparsons.
After the Company determnes the appropriate level of total cash
compensation for a position, it then determnes the porton of that compensation
that wil constitute the "at-risk" portion that is, the "taget" incentive pay. The
Company sets the "at-risk" portion by reviewing market compensation using the
varous compensation studies described above. The "at-risk" portion is typically
in the 10-25 percent range; however, incentive pay for a few employees is set as
high as 75 percent. Generally speakng, the higher the position is within the
Company, the higher the percentage of target incentive pay. The remaining
percentage of total compensation is referred to as "base compensation."
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Rocky Mountain Power
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1 Annual Incentive Plan
2 Q. What is the objective of the Annual Incentive Plan?
3 A.The objective of the Annual Incentive Plan is to provide employees with incentive
4 to perform at an above-average leveL. This is achieved by putting a percentage of
5 the competitive total compensation "at risk." If an employee performs at an
6 acceptable level for the position, the employee wil receive the target incentive
7 amount which wil allow the employee to earn compensation comparable to
8 similar positions in the market. If an employee fails to perform at an acceptable
9 level, the employee wil receive less than the target incentive or no incentive at
10 alL. When this situation occurs, the employee wil be paid less than the
11 comparable total cash compensation in the marketplace for that year. Conversely,
for exceptional performance, an employee may receive above his or her taget
incentive leveL.
The abilty to earn a higher-than-target incentive payment provides the
employee with an incentive to exceed average performance. This opportnity is
an essential counterbalance to the risk the employee faces that his or her
performance in a paricular year wil be less than acceptable, with the
consequence that total compensation wil be less than market in that year. The
symmetr of the incentive element provides the Company with the financial tool
to encourage exceptional performance and discourage less than acceptable
performance. As would be expected from a well-designed, symmetrcal plan, the
average incentive element is approximately at the target incentive leveL.
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Rocky Mountain Power
.1 Q.IS incentive compensation a greater benefit to customers than compensation
2 consisting solely of base compensation?
3 A.Yes. In the Company's experience, a higher level of overall employee
4 performance is achieved when a portion of pay is "at risk." In addition, the
5 Company's incentive compensation plan enables the Company to attract and
6 retain talented employees in the increasingly competitive market for skilled labor.
7 Therefore, while the total cost of the Company's base plus incentive
8 compensation program is equal to market average total cash compensation Gust as
9 a salar-only program would be) the benefit to customers is greater.
10 Q.How is the incentive compensation plan implemented?
11 A.The Company's Annual Incentive Plan provides incentive awards based on the.12 following: (1) the employee's performce against individual goals; (2) the
13 employee's performance against group goals including safety goals; and (3)
14 success in addressing new issues and opportnities that may arse durng the
15 course ofthe year.
16 Q.What are the individual goals and how are they set?
17 A.Individual employee goals star with the goals set for the Company as a whole.
18 Each year, the Company President, in conjunction with MidAmerican Energy
19 Holdings Company, sets the overall goals for the Company. All of these goals
20 focus on delivering safe and reliable electrc service and providing excellent
21 customer service. Goals include safety goals such as reducing lost time,
22 recordable, preventable, and restricted duty incidents. Customer service related.23 goals include implementing local and regional customer service improvements,
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Rocky Mountain Power
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improving visibility and relations with industral customers and consumer
associations, and improving overall customer satisfaction. Some goals relate to
operating within established budgets, including maintaining operating costs,
controllng the cost of capital expenditues, and achieving operational efficiencies
that allow the Company to remain a low-cost utility. Other key goals relate to
operational performance, major project delivery, organizational planning and
development, and quality of service and regulatory commtments. The
achievement of each and every one of these goals wil serve to benefit our
customers.
How do the Company goals relate to individual employee goals?
These Company-wide goals serve as the foundation for the goals set for each
individual employee. Thus, when an individual employee sets his or her own
individual goals for the year, they are set by reference to how that employee's
position can advance the overall goals of the Company. The employee's
performance on individual goals accounts for approximately 70 percent of his or
her overall evaluation.
What are the group goals?
In addition to performance against individual goals, all employees are evaluated
against six common or "group" goals. These group goals describe the
characteristics the Company believes are important to the success of all
employees, i.e., customer focus, job knowledge, planning and decision makng,
productivity, building relationships and leadership. The employee's performance
with respect to these group goals accounts for approximately 30 percent of the
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Rocky Mountain Power
.1 employee's overall evaluation.
2 Q.Explain the third category.
3 A.In the course of anyone year, challenges wil arse that were not contemplated by
4 the goals set at the beginning of the year. For instace, the Company may
5 become involved in a significant transaction, such as a purchase or sale, or the
6 Company may contend with unexpected outage conditions. In these cases, some
7 percentage of the employee's evaluation may reflect his or her performance under
8 these unforeseen conditions.
9 Q.Are any of the employees judged on the financial performance of the
10 Company?
11 A.No. Whle all employees are expected to operate within applicable budgets,.12 corporate financial performance and retus are not a factor in determning the
13 amount of incentive compensation awarded under the plan. The Company does
14 maintain a separate Long-Term Incentive Plan, ("LTIP"), for executives that
15 awards bonuses based on overall corporate performance; however, the Company
16 does not seek recovery of the costs of the L TIP from our customers.
17 Q.What level of incentive compensation does the Company expect to payout on
18 a year on year basis?
19 A.The Company expects to payout, on a year after year basis, the taget level of
20 incentive compensation. The Company's pay philosophy is to provide total
21 compensation at the market average. Absent incentive compensation, each
22 employee's compensation would be significantly less than market average.
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Wilson, Di-Reb - 8
Rocky Mountan Power
.1 Q.Does the Company recommend the full target level of incentive compensation
2 plus base compensation be included in rates?
3 A.Yes, for several reasons. First, customers should fully support the cost of
4 incentive compensation because, as I previously mentioned, it is an essential
5 component of an overall market-based competitive compensation program.
6 Reducing customer support for incentive pay would result in under-maket
7 salares, makng it impossible for the Company to recrut and maintain a qualified
8 labor force, which would in tu mae it impossible for the Company to provide
9 safe and reliable service. Moreover, the goals of the plan are designed to
10 encourage superior performance on the par of our employees to pursue the goals
11 that diectly benefit our customers-safety, reliabilty, and customer service. This
.12 is precisely the type of prudently designed incentive plan that provides direct
13 benefits to customers.
14 Q.Wil allowing recovery of the entire Incentive Plan expense result in .
15 ratepayers bearing the cost of a compensation plan that provides employees
16 higher than average market pay?
17 A.No. Overall, total employee base pay plus incentives is equal to market average
18 pay. Employees who excel may earn more and employees who underperform
19 may ear less, but most employees wil ear market average pay and the total
20 expense,. including incentive pay, wil be equivalent to maket average pay for all
21 employees.
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Rocky Mountain Power
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Over the past few years, there has been a significant shift by companies to
deliver compensation in the form of both base pay and incentive. This
compensation strctue allows the company to place emphasis on employee
performance in areas critical to employees and customers such as safety,
reliabilty, and customer service. Customers clearly benefit when employees are
incentivized to focus on these activities.
It is critical to understand the "at risk" portion of total compensation is not
a bonus. A bonus is something unexpected. The "at risk" compensation is not
unexpected-in fact, it is the opposite. The "at risk" portion of total
compensation is expected by the employee but only if the employee performs at
or above an acceptable leveL. Any reduction beyond the competitive target
incentive level would place the Company in a position of not being able to offer
competitive pay levels and placing operational and customer objectives at risk.
Mr. Meyer claims that the group goals are ineffective because they do not
provide employees with the quantitative goals to assess their performnce
and provide for subjective evaluation by the manager. Do you agree with
these criticisni?
No. First, let me emphasize that every employee has individual goals, not just
goals for the group to which the employee belongs. Second, shared group goals
are effective and quantifiable, such as goals related to safety or customer service.
For example, Exhibit No. 68 shows the 2009 objectives of an Engineer. One of
these objectives includes "OSHA Incident Rate - Maitan a safe work
environment for employees - Ensure Hydro Resources has 3 or less incidents in
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Rocky Mountain Power
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2009, which wil allow Hydro to achieve an incident rate of 1.6 or less." Clearly,
achievement of this goal can be measured based on the number of incidents that
occur at hydro resources. Not every indicia of performance, however, is
quantifiable. For example, Exhibit No. 68 also shows as one of this employee's
goals "Coordnate all work that has any potential environmental impacts with the
area environmental analyst. Consider any impact as far as oil spils, fish
(ramping, minimum flow), PBC, asbestos, or any other related environmental
issues in advance for all the overhaul projects and make the appropriate paries
aware." This goal, although not quantifiable, is designed to motivate employee
behavior that wil provide benefits to customers. Mr. Meyer's "quantifiable"
argument should be disregarded. Moreover, PacifiCorp has found that, as long as
goals are specific, concrete, and observable, allowing for some management
discretion in makng awards creates a more powerfl motivator for superior
performance.
Mr. Meyer appears to argue that the fact that not all goals are quantifiable
wil result in employees not understanding the goals. Do you agree?
No. In fact, imposing a "quantifiable" requirement on some employee goals
would result in confusion for employees who have goals that are inerently
unquantifiable.
How do you respond to Mr. Meyer's argument that some of the Company's
performance factors should be classifed as job requirements?
Mr. Meyer misperceives the "at risk" portion of total compensation as a bonus.
As I have explained, it is not. Recognizing this, Mr. Meyer's criticism is, in fact,
835 Wilson, Di-Reb - 12
Rocky Mountain Power
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an acknowledgement that the Company has designed its total compensation .
correctly. Only by performng the job requirments at acceptable levels can the
employee achieve total compensation at the market average.
As I have explained, because the Company's compensation strctue
includes incentive payments as par of market compensation, employees meeting
their goals should receive a level of base and incentive compensation consistent
with market compensation. It is logical, then, that the employee's goals wil set
forth what acceptable job performance is for that employee. Employees
exceeding these goals should receive additional incentive compensation to
encourage exemplar performance.
Mr. Meyer also criticizes the Company's incentive program on the basis that
it improves shareholder value. Has the Company tailored its goals to benefit
shareholders?
No. On the contrar, the Company's focus in setting goals is to improve
operational efficiency, improve customer service, and promote safety, all of
which benefit customers. The annual goal setting process begins with discussions
between the manager and employee in order to ensure that the employee
establishes goals that align with the business and operational objectives and focus
on specific areas of where the employee can improve or develop for the year. The
goals are then documented with assigned measurements. The goals do include
controllng expenses, because employees can reasonably be expected to control
costs, which benefits customers. The goals associated with this compensation do
not include net income or revenues for most employees because most employees
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Rocky Mountain Power
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are not in a position to impact revenues. The Company's L TIP contains goals
related to net income and revenue for those employees' best in a position to
impact those elements. The Company does not include costs of LTIP in its rate
requests.
Has the Incentive Plan been successful?
Yes. Since placing a portion of total compensation at risk, the Company has sen
improvements in safety, customer service standads, and operational output.
These outcomes demonstrate that the Company's approach has been successful in
motivating employees in a way that results in customer benefits. While these
achievements may provide indiect benefits to the shareholder, that is not the
guiding principle in how the program is designed.
Can you provide examples that ilustrate how goals are aligned with
customer benefits?
Yes. Exhibit No. 69 contains copies of 2009 objectives for six actual employees
classified from analyst to manager leveL. (The group includes a Dispatch
Supervisor, Manager of Engineering and Environmental Services, Regulatory
Analyst, Engineer, Metering Admnistrator, and Finance/Accounting Analyst).
The names have been redacted to protect employee privacy. As you can see, each
employee has between one and five key objectives that serve as goals for the year.
Each objective is described in detaiL. Next, each objective is assigned a set of
concrete goals by which they wil be measured and a weighting for that paricular
objective. All of the employees' goals focus on objective outcomes that are ve.ry..
closely tied to safety, reliabilty and customer service. None of them are tied to
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Rocky Mountain Power
.1 financial outcomes. Moreover, each goal sheet reflects the significant attention
2 and effort that goes into tailoring these for each employee.
3 Q.Do you have any further observations about Mr. Meyer's criticism of the
4 Company's goals?
5 A.Yes. Mr. Meyer's arguments are narowly focused on one element of an
6 individual's performce, that being the performnce against the six defined
7 common goals. It is important to note that these six goals comprise only
8 30 percent of employees overall evaluation. Mr. Meyer's criticisms of a small
9 proportion of employee goals should not be accepted as a valid basis for
10 disallowing any incentive plan expense.
11 Q.Do you believe that Mr. Meyer has presented any basis for disalowing any.12 portion of the Company's incentive progrm?
13 A.No. The Company has developed an incentive program that is diectly tied to
14 customer goals, has provided demonstrable benefits to customers, and is par of an
15 overall compensation package that is commensurate with the market. The
16 Company requests that the Commssion reject Mr. Meyer's proposed adjustment.
17 Q.Please describe Mr. English's proposed adjustment to the incentive portion
18 of PacifiCorp's total compensation package.
19 A.Mr. English proposes to remove 100 percent of the incentive portion of the
20 compensation package, resulting in a $1.3 millon disallowance on an Idaho-
21 allocated basis.
22 Q.Do you agree with Mr. English's proposed adjustment?.23 A.No. Mr. English's adjustment is not based on quantifable labor market data
838
Wilson, Di-Reb - 15
Rocky Mountai Power
.
.
.
1
2
3
4
5
6 Q.
7
8 A.
9
10
11
12
13 Q.
14 A.
15
16
17
18
19
20
21
22
23
related to our workforce requirements but is based on maket generalizations. Mr.
English categorizes the incentive payment as a bonus; however, as I explained in
the opening, incentive pay is not "extra pay" but actually an essential element of
the compensation provided to our employees that enables them to achieve a
market competitive level of compensation.
Are there additional arguments Mr. English makes in pointing to disallowing
the company's incentive compensation expense?
Yes. Mr. English also states that from his assessment of the incentive plan, it is a
complex plan and is tied to individual performance and therefore impossible to
determe if the goals and incentive compensation benefits the customer or the
shareholder. He also then takes the view that operating budget goals tie to
shareholder benefit and therefore must be disallowed.
Do you agree with the additional arguments made by Mr. English?
No. Again, as I state in the opening of my rebuttal as to how our compensation is
strctued and delivered, our incentive is based on quantifiable goals that are
established between the maager and employee and are set to deliver operational
efficiency and improvements for our customers.
I also disagree with the position Mr. English takes that operating budget
goals, if used as an individual goal, should not be borne by the customer as it
diectly benefits the shareholder. Ou operating budget goals are set to drve and
deliver on the requirements of our business being able to provide and deliver safe
and reliable service to our customers. These goals are a diect benefit to our
customer and are set with that as the sole focus.
839
Wilson, Di-Reb - 16
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10
11 Q..12 A.
13
14
15
16 Q.
17 A.
18
19
20
21
22.23
The last argument made by Mr. English is that given the economic crisis
and financial challenges facing individuals in the U.S., the company should either
not seek rate increases or mitigate the increase by elimating incentive payments
made to its employees. Again, I can't stress the importance of my point enough
that the compensation provided to our employees is set to deliver compensation at
the competitive market average level and this is done by blending it though both
base and incentive pay. Deliverig pay below that level would set compensation
below market and in tu place risk on the customers of the company not being
able to attract and retain labor to provide the safe and reliable service expected
and required.
Does Mr. English propose any further adjustments to compenstion?
Yes. Mr. English takes the position that all wage increases during 2009 and 2010
should be disallowed, as again, he views the economic crisis and financial
challenges facing individuals across the company as his key support for this
position.
Do you agree with Mr. English's further adjustments and position?
No. First, the wage increase levels set for our union population are set as par of
the collective bargaining process typically covering multiple years and are a par
of many considerations such as work rules, benefits and retirement. These
varables together deliver a competitive set of benefits and compensation to the
union employee workgroup. These wage levels are par of contracts that were
prudently entered into by management and are known and measurable in the test
period and should be provided full cost recovery.
840
Wilson, Di-Reb - 17
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10 Q.
11.12 A.
13
14
15
16
17 Q.
18
19 A.
20
21
22.23
Second, the non-represented population levels for 2009 and 2010 are set,
as is tre for each plan year, by reviewing maket data for labor wage adjustments
and positioned at the market average. For 2009, the level of 3.5 percent was
market competitive. The 2010 wage increases for non-represented employees
were again based on a detailed market analysis of the actions being taken in the
labor market. From this assessment, and also factoring in the economic crisis and
conditions facing our customers, the Company implemented 2010 wage increases
slightly below market practices and only those employees who received a base
compensation below $100,000 were eligible for an increase.
How does the Company's 3.5 percent wage adjustment for 209 compare to
the market in which it competes for labor?
As I have noted, the company annually does a thorough assessment of the market
and reviews practices being undertaken by its competitors in the area of planned
wage increases. Exhibit No. 70 shows the analysis completed and that the results
for the 2009 plan year was an average increase of 3.75 percent as compared to the
company's wage adjustment of 3.5 percent.
Please describe Mr. English's proposed adjustment to PacifiCorp's SERP
benefits expense.
Mr. English recommends that 100 percent of the SERP expense be removed from
this filing as these benefits are above and beyond those covered in more
conventional retirement plans. Mr. English also argues that an executive's salar
is aleady higher than the typical employee and is aleady receiving a larger .
benefit than the other employees.
841
Wilson, Di-Reb - 18
Rocky Mountain Power
.1 Q.Do you agree with Mr. English's assessment and proposed adjustment to the
2 Supplemental Executive Retirement Plan (SERP) expense in this filing?
3 A.No. These are not extra, unnecessar or excessive benefits. Our pay and benefits
4 philosophy continues to remain the same in that we provide programs/plans at the
5 market average (no better and no worse). The Company no longer offers the
6 SERP benefit to new paricipants and the expenses sought are related to one
7 active paricipant and past paricipants who, during their employment, delivered
8 value to the then curent customers while also shaping the Company to benefit
9 futue (currnt) customers. The Company honors its commtment to continue to
10 fund SERP expenses. The SERP expense is a form of retiement/pension simlar
11 to the frozen benefit expense of the non-union employee population who shifted.12 on June 1,2007 to a cash balance. Both of these changes in plan offering were
13 taken to address futue volatilty and competitiveness thereby reducing long term
14 expense to our customers, the expense in this filng is again based on no new
15 growth in expense.
16 Q.Does this conclude your rebuttal testimony?
17 A.Yes.
.
842
Wilson, Di-Reb - 19
Rocky Mountain Power
.
.
.
1 (The following proceedings were had in
2 open hearing.)
3 Q.BY MR. HICKEY: Do you have any questions that
4 were deferred to you by Mr. Walje?
5 A.No, I do not.
6 MR. HICKEY: Mr. Wilson is available for
7 cross-examination.
8 COMMISSIONER SMITH: Thank you.
9 Mr. Otto. Mr. Olsen.
10 MR. OLSEN: I have no questions, Madam Chair.
11 COMMISSIONER SMITH: Ms. Davison. Mr. Purdy.
12 MR. PURDY: No questions.
13 COMMISSIONER SMITH: Mr. Woodbury.
14 MR. WOODBURY: Thank you, Madam Chair.
15
16 CROSS-EXAMINATION
17
18 BY MR. WOODBURY:
19
20
Q.Mr. Wilson, with respect to the Company's
incenti ve plan, you make an you hold a portion back, but
21 then you make an assessment regarding their level of
22 performance, and do you ever -- are employees ever fired for
23 less than acceptable performance?
24
25
A.Yes, we do terminate employees if they do not
perform their responsibilities as outlined for their job.
843
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WILSON (X)
RMP
.
.
.
1 Q.Do you have an annual turnover percentage as
2 those that how many fall into that category every year?
3 A.I don't know the answer to that.
4 Q.So there are consequences other than just not
5 receiving the full benefit package?
6 A.The full compensation package, that's correct.
7 Q.And the competitive market that you look to for
8 the average level of salary for employees, how large is that
9 market, just the Northwest or --
10 A.No, it's a national market that we look at.
11 Q.Okay. And do you think that's unique to gauge
12 your salaries of employees on a national market?
13 A.No, I do not believe that that's unique.
14 COMMISSIONER SMITH: I think there was a
15 disconnect there between the question and the answer. Maybe
16 you ought to try that again.
17 Q.BY MR. WOODBURY: I asked the question as to
18 whether the Company found it necessary or believed it was
19 necessary to use a national average, I guess, for -- of
20 salaries for your employees, and you said it was not unique
21 or--
22 A.Thank you for raising that. That's not how I
23 interpreted the question.
24 It is the Company's belief that it is appropriate
25 to look at national data for salary purposes in setting for our
844
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WILSON (X)
RMP
.
.
.
18
1 employees.
2 Q.DO you use subsets of data of the Northwest?
3 A.We do, and we also look at industry-specific
4 data.
5 Q.Do you use Idaho only?
6 A.NO, we do not use Idaho only.
7 Q.RMP only, the states -- the three states that you
8 operate in?
9 A.No. We'll look at if anything other than
10 national will be the Northwest as a cut that will be inclusive
11 of five of our six terri tory states.
12 Q.You know, on page 17, you state that the deli very
13 of pay below the competi ti ve market average level would affect
14 the Company's ability to provide safe and reliable service.
15 You're not intending to imply that the Company's
16 employees are motivated only by money.
17 A.Would you please restate the question?
Q.You're not intending by that language to say that
19 the type of performance of the Company's employees is
20
21
22
essentially motivated they are only motivated by money?
A.No, not at all.
Q.You know, because some choose to -- there are
23 other factors as to whether or not they would want to work in
24 Idaho?
25 A.Or anywhere else wi thin our organization. Pay is
845
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WILSON (X)
RMP
.
.
.
1 one element of the employment experience that we offer.
2 Q.Okay.
3 MR. WOODBURY: Thank you. I have no further
4 questions, Madam Chair.
5 COMMISSIONER SMITH: Thank you, Mr. Woodbury.
6 Mr. Budge, do you have questions?
7 MR. BUDGE: No questions, thank you.
8 COMMISSIONER SMITH: Mr. Otto. Questions from
9 the Commissioners.
10 MR. OTTO: No, Madam Chairman, I don't.
11 COMMISSIONER REDFORD: No.
12 COMMISSIONER SMITH: Commissioner Kempton.
13 COMMISSIONER KEMPTON: I had a couple.
14
15 EXAMINATION
16
17 BY COMMISSIONER KEMPTON:
18 Q.Mr. Wilson, could you explain what you mean by
19 on page 2 of your rebuttal on lines 21, what you mean by
20 "market average" and how it is determined? It's somewhat the
21 same question Mr. Woodbury asked.
22 A.Sure. What we do on an annual basis is we
23 evaluate each and every position within our organization and we
24 take the position and match it to third-party salary survey
25 sources, and wi thin that match, we match our positions to
846
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WILSON (Com)
RMP
.
.
.
1 what's defined as the market average or more oftentimes
2 referred to as the 50th percentile. So, we establish the pay
3 for each and everyone of our positions at the average that
4 implies that there are employers that provide higher levels of
5 compensation and employers that provide lower levels of
6 compensation, but we've established both our pay and benefit
7 programs at the market average.
8 Q.And this is a market average of pay scales and
9 not of a scale of incentive pay?
10 A.It's an evaluation of total compensation.
11 Q.So -- and I'm talking about your national
12 comparison now.
13 A.Okay.
14 Q.So incentive pays are mixed up in the regular
15 base pay scale. Is that right?
16 A.They're a component of total compensation, base
17 plus.
18 Q.You don't have those separated?
19 A.We do not. Base plus incentive delivers total
20 compensation.
21 Q.I was thinking -- it may be some other witness.
22 I was thinking that there was a chart that you had in here and
23 it indicated that -- that when you were looking at incentive
24 pay, the way you made your comparison was across a level of
25 incenti ve pay adj ustments, as averse to just simply the
847
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WILSON (Com)
RMP
.
.
.
1 incenti ve pay incorporated wi thin the body of the regular pay.
2 That's not true?
3 A.No, I'm not sure I'm clear on what that number
4 is.
5 Q.Do you have any kind of matrix in here that
6 showed--
7 Let me put it this way: Since I can't identify
8 it, I'm going to withdraw that question.
9 COMMISSIONER KEMPTON: So, Madam Chairman, I
10 don't have any more questions.
11 COMMISSIONER SMITH: Possibly Exhibit 70?
12 COMMISSIONER KEMPTON: Yes, I think that's it.
13 Thank you.
14 THE WITNESS: So if you'd like, I would be more
15 than happy to explain this exhibit.
16 Q.BY COMMISSIONER KEMPTON: Okay. And my question
17 pertains to the fact that you have these all broken out in
18 terms of merit, and then you have the 209 projected merit
19 increases, and that was basically what I was getting to. Thank
20 you, Madam Chairman.
2 i So, go ahead and explain.
22 A.Okay. This is -- this table is representation.
23 What we do on an annual basis is we go to the market and -- the
24 labor market, that is -- to identify what our competi ti ve
25 organizations are providing as a base wage adjustment on an
848
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WILSON (Com)
RMP
.
.
.
1 annual basis. You may call this merit base pay adjustment,
2 annual adj ustment to base pay only.
3 And the purpose of this is to depict for 2009,
4 for example, that the average projected merit increase provided
5 by our competitors as defined here is 3. 75 percent, and that
6 compares to the actual Company's merit providing opportunity
7 that we shared with our employees of 3.5 percent in 2009. And
8 we did 3.5 rather than 3. 75 in reflection of the market
9 condi tions that our both customers and employees were facing.
10 Q.When you make the comparisons on the merit pay,
11 do you make it on the basis of just Rocky Mountain Power, or
12 the entire Company structure?
13 A.This is Company-wide. This is all of PacifiCorp,
14 all three business units.
15 Q.And your average in this rate case was what?
16 A.For 2009, it was 3.5 percent, as a comparison to
17 the market average of 3. 75.
18 COMMISSIONER KEMPTON: Okay. No further
19 questions, Madam Chairman.
20 COMMISSIONER SMITH: I don't know if the record
21 is clear, but I would just like to reflect that the previous
22 conversation dealt with Exhibit No. 70.
23 THE WITNESS: Seventy.
24 COMMISSIONER SMITH: Any redirect?
25 MR. HICKEY: I have no redirect. Thank you.
849
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WILSON (Com)
RMP
.
.
.
1 COMMISSIONER SMITH: Thank you for your help,
2 Mr. Wilson.
3 THE WITNESS: Thank you.
4 (The witness left the stand.)
5 MR. HICKEY: Madam Chair, in the interest of
6 making sure that we don't have any -- in the interest of making
7 sure we don't have any witness on the stand at a difficult time
8 of the day for Mr. Gorman's schedule, I would suggest to my
9 friend Mr. Budge that now would be a chance to get his witness
10 accommodated if he wants to.
11 MR. BUDGE: Thank you. That would be fine.
12 Appreciate the courtesy from the Company and others.
13 We'd call Mike Gorman.
14
15 MICHAEL GORMAN,
16 produced as a witness at the instance of Monsanto, being first
17 duly sworn, was examined and testified as follows:
18
19 DIRECT EXAMINATION
20
21 BY MR. BUDGE:
22 Would you state your complete name and businessQ.
23 address for the record?
24 My name is Michael Gorman. My business addressA.
25 is 16690 Swingley Ridge Road, Chesterfield, Missouri.
850
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
GORMAN (Di)
Monsanto
.
.
.
1 MR. HICKEY: Mr. Budge, if you would allow me to
2 interrupt you and I apologize for doing it, but I again forgot
3 to ask if we could have Mr. Wilson excused, Madam Chairman.
4 COMMISSIONER SMITH: Is there any obj ection to
5 excusing Mr. Wilson?
6 If not, he's free to come or go as he chooses.
7 MR. HICKEY: Thank you.
8 Q.BY MR. BUDGE: Mr. Gorman, did you file direct
9 testimony on behalf of Monsanto Company under date of
10 October 14, 2010?
11 A.Yes.
12 Q.And did you also file rebuttal testimony on
13 behalf of Monsanto Company under date of November 16, 2010?
14 A.I did.
15 Q.Did you also submit in conj unction with that
16 testimony Exhibit Nos. 202 through 220?
17 A.Yes.
18 Q.And also Exhibits 232 through 233?
19 A.Yes.
20 Do you have any corrections you wish to make toQ.
21 either your testimony or exhibits?
22 I have one correction in my rebuttal testimony onA.
23 page Gorman DI-REB-5, line 17. Number "9.6 percent" should be
24 struck and the number "9.5 percent" should be inserted.
25 Q.Any further?
851
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
GORMAN (Di)
Monsanto
.
.
.25
1 A.That's all the corrections.
2 Q.Mr. Gorman, if I were to ask you today the same
3 questions as contained in your prefiled direct and rebuttal
4 testimony, would your answers be the same?
5 A.Yes.
6 MR. BUDGE: All right, hearing that, we would
7 move to spread the testimony of Mr. Gorman as described,
8 together with Exhibits 202 through 220, and 232 through 233,
9 and tender him for cross-examination.
10 COMMISSIONER SMITH: If there's no objection, the
11 prefiled direct and surrebuttal testimony will be spread upon
12 the record as if read, and the exhibits are identified.
13 Mr. Budge.
14 MR. BUDGE: One initial question: The
15 surrebuttal testimony I think that was submitted yesterday was
16 not accepted by the Commission.
17 COMMISSIONER SMITH: Oh, okay. It was not, so
18 just rebuttal.
19 MR. BUDGE: The Chair had mentioned surrebuttal,
20 so it would just be rebuttal.
21 COMMISSIONER SMITH: I get it. I saw it said
22 "rebuttal" and I didn't believe it, but it really is rebuttal,
23 so--
24 MR. BUDGE: Correct.
(The following prefiled direct and
852
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
GORMAN (Di)
Monsanto
.1 rebuttal testimony of Mr.Gorman is spread upon the record.)
2
3
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5
6
7
8
9
10
11
12.13
14
15
16
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24.25
853
HEDRICK COURT REPORTING GORMAN (Di)
P. O.BOX 578,BOISE,ID 83701 Monsanto
.PACIFICORP dba ROCKY MOUNTAIN POWER
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. PAC-E-10-07
Direct Testimony of Michael P. Gorman
1 Q PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
2 A Michael P. Gorman. My business address is 16690 Swingley Ridge Road, Suite 140,
3 Chesterfield, MO 63017.
4 Q WHAT IS YOUR OCCUPATION?
5 A i am a consultant in the field of public utilty regulation and a managing principal of
6 Brubaker & Associates, Inc., energy, economic and regulatory consultants..
7 Q PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND EXPERIENCE.
8 A This information is included in Appendix A to my testimony.
9 Q ON WHOSE BEHALF ARE YOU APPEARING IN THIS PROCEEDING?
10 A i am appearing on behalf of Monsanto Company, a special contract customer of
11 RMP.
12 Q WHAT IS THE SUBJECT OF YOUR TESTIMONY?
13 A i will recommend a fair return on common equity and overall rate of return for Rocky
14 Mountain Power ("RMP" or "Company").
.
854 Gorman, Di - 1
Monsanto Company
.1 Q
2 TESTIMONY?
ARE YOU SPONSORING ANY EXHIBITS IN CONNECTION WITH YOUR
3 A
4 These exhibits were prepared either by me or under my supervision and direction.
Yes. I am sponsoring Exhibit No. 202 (MPG-1) through Exhibit No. 220 (MPG-19).
5 Summary
6 Q
7 A
8
9
10
11.12
13
14
15
16
17
18
19 Q
20 A
PLEASE SUMMARIZE YOUR RETURN ON EQUITY RECOMMENDATIONS.
I recommend the Idaho Public Utilties Commission ("Commission") award RMP a
return on common equity of 9.5%, which is the midpoint of my estimated range of
9.1 % to 9.9%,1 propose adjustments to the Company's proposed capital structure to
exclude common equit supporting assets not devoted to utilty operations. Based on
my recommended return on equity and capital structure, i recommend an overall rate
of return of 7.70% for RMP, as shown on Exhibit No. 202 (MPG-1), page 1 of 2. As
set forth in this testimony, my recommended return on equity and capital structure wil
support RMP's financial integrity, and provide fair compensation for the risk of utilty
operations.
i wil also respond to RMP witness Dr. Samuel Hadaway's proposed return on
equity of 10.6%. For the reasons discussed below, Dr. Hadaway'S recommended
return on equity for RMP is excessive and should be rejected.
HOW DID YOU ESTIMATE RMP'S CURRENT MARKET COST OF EQUITY?
21 utility companies that have investment risk similar to RMP. i then performed three
i did this by development of a comparable proxy investment group of publicly traded
22 versions of the Discounted Cash Flow ("DCF") model, Risk Premium ("RP") study,
23 and Capital Asset Pricing Model ("CAPM") analysis. Based on these assessments,.
855 Gorman, Di - 2
Monsanto Company
.
.
.
1 and as discussed in more detail below, i estimate RMP's current market cost of equity
2 to be 9.5%.
3 Q HOW DID YOU ADJUST RMP'S PROPOSED CAPITAL STRUCTURE?
4 A RMP's balance sheet includes short-term assets which are not included in utilty plant
5 in-service or utilty rate base. These short-term cash assets are primarily attributable
6 to PacifiCorp's decision to retain all earnings in the utilty and build up its common
7 equity balance. I recommend that the common equity supporting these short-term
8 assets be excluded from the capital structure used to estimate the rate of return on
9 RMP's utilty rate base. As such, i adjusted RMP's capital structure to remove
10 common equity not supporting utilty rate base investments, and thereby estimating
11 the capital structure relative weights that are currently supporting utilty rate base.
12 Q WHAT IS THE REVENUE REQUIREMENT IMPACT OF YOUR RETURN ON
13 EQUITY AND CAPITAL STRUCTURE ADJUSTMENTS?
14 A The revenue impact from reducing RMP's return on equity from 10.6% down to 9.5%
15 and reducing the common equity ratio of the forecasted test year capital structure
16 from 52.1 % to 49.7% lowers its claimed Idaho jurisdictional revenue deficiency by
17 $7.7 millon.
18 Rate of Retu m
19 Q PLEASE SUMMARIZE THIS SECTION OF YOUR TESTIMONY.
20 A In this section of my testimony:
21 1. I wil review the current electric utilty industry market outlook.
22 2. i wil review the investment risk of RMP.
856 Gorman, Di - 3
Monsanto Company
.
2
3
4
5
6
7
8 Q
9 A
10
11
12
13.
14 Q
15 A
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30.31
3. I wil propose a capital structure that wil maintain RMP's financial integrity.
4. I wil estimate a fair return on equity for RMP.
5. I wil show that my recommended rate of return will support RMP's financial
integrity and investment grade bond rating.
6. Finally, I will respond to RMP witness Dr. Hadaway'S recommended return on
equity of 10.6% and explain why it is excessive and unreasonable.
Electric Utilty Industry Market Outlook
PLEASE DESCRIBE THIS SECTION OF YOUR TESTIMONY.
I review the credit rating and investment return performance of the electric utilty
industry. Based on the assessments below, i find the credit rating outlook of the
industry to be strong and supportive of the industry's financial integrity. Further,
electric utilties' stocks have exhibited strong return performance and are again
characterized as a safe investment.
PLEASE DESCRIBE THE ELECTRIC UTILITIES' CREDIT RATING OUTLOOK.
Electric utilties' credit rating outlook is improving over the recent past. Standard &
Poor's ("S&P") recently provided an assessment of the credit rating of U.S. electric
utilties for the second quarter of 2010. S&P's commentary included the following:
The past three months witnessed several outlook changes, most of
which were positive or revisions to stable from negative. The principal
drivers for the positive outlooks were constructive rate decisions,
overall improving business risk profiles, and stronger measures of
bondholder protection.
* * *
The universe of U.S. electric utilties is relatively highly rated, certainly
compared with the average 'B' category for U.S. industrial companies.
This is due to the large percentage of firms carrying 'excellent' (84%)
and 'strong' (13%) business risk profiles. ...What typically distinguishes
one utilty's business profile score from another is the quality of the
regulatory climate and management's commitment to credit quality and
financial policies. We consider the financial risk profile for most electric
companies to be 'aggressive' ...
857 Gorman, Oi - 4
Monsanto Company
.
1
2
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4
5
6
7
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9
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25
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27
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31
32
33
34
35
36
37
38
39
40
41
42
.
The ratings distribution for electric utilities in the U.S. remains solidly
entrenched in investment grade. Approximately 67% of the industry
carries a 'BBB' category corporate credit rating ('BB8+', 'BBB', and
'BBB-'), nearly 29% 'A-'and above, and about 4% below investment
grade ('BB+' and below). Some 86% of all domestic electric utilty
companies carry a stable outlook, so the number of rating changes is
expected to remain moderate in the near to intermediate term. Ratings
stabilty for the electric sector continues to be based in large part on
the following expectations:
. Generally responsive rate orders, including mechanisms or
automatic provisions that allow that for the timely recovery of
commodity prices, environmental compliance costs, and other
expenses;
. Receptive capital markets. access to liquidity, and manageable
debt maturity schedules;
. Moderation in growth and expansion capital expenditures; and
. Credit-supportive actions by utilty management.1
From an economic standpoint, S&P stated the following:
Effects On Ratings
Regulated electric utilties have been, and are expected to continue,
weathering the difficult economy with little lasting effect on the
collective financial risk profile of the industry, and we assess ratings
and outlooks based on our stable view of industry and company-
specific factors. Outlooks and ratings should remain predominantly
unchanged, even if industry conditions worsen in the near term, as
described in our pessimistic scenario (see table 1). However, if lack of
economic growth persists for an extended period, regulatory risk could
rise if concerns about the plight of ratepayers leads to resistance to
rate increases.
* * *
Solid Industry Fundamentals Support Stable Outlook
Throughout 2009, U.S. electric utilities performed well with continued
favorable access to capital compared to most corporate issuers.
Despite diffcult market conditions last year, external financing activity
for the U.S. regulated electric utilty industry was about $49.8 bilion,
roughly matching 2008 activity. Many companies have proactively pre-
financed issuance well in advance of their debt maturities, taking
advantage of investor appetite and favorable spreads. Investor
appetite for first-mortgage bonds remained healthy, and deals
remained oversubscribed. Credit fundamentals indicate that most, if
not all, electric utilties should continue to have ample access to capital
markets and credit. Banking syndicates are also expressing
1Standard & Poor's RatingsDirect on the Global Credit Portal: "Ratings Roundup: Strongly
Positive Rating Changes In U.S. Electric Utility Sector In Second-Quarter 2010; No Downgrades,"
July 15, 2010, emphasis added.
858 Gorman, Oi - 5
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1
2
wilingness to renegotiate credit facilties, although at more demanding
terms than in the previous years.2
3 Moody's also acknowledges the following for the electric utilty industry in its report:
4
5
6
7
8
9
10
11
12
Overview
The fundamental credit outlook for the U.S. investor':owned electric
utilty sector remains stable, thanks to a supportive regulatory
framework that provides good transparency into operating cost and
capital investment recovery; adequate liquidity profiles; relatively
unfettered access to the capital markets; and reasonably stable
financial credit metrics. The investor-owned utility business model
remains well positioned within its investment-grade rating category for
2010 and at least the first half of 2011.3
13 Similarly, Fitch states:
14
15
16
17
18
19
20
Overview
The U.S. Utilties, Power, and Gas (UPG) sector 2010 outlook is
framed in the context of Fitch Ratings' outlook for a slow U.S.
economic recovery in 2010, with stable outlooks for most of the
business segments within the UPG universe except for negative 2010
credit outlook for competitive generators and retail propane
distributors.
21 * * *
22
23
24
25
26
27
28
Resilent Peñormance in 2009
Companies in the UPG sector weathered the recession and financial
crisis of 2008-2009 with considerably less pain than sectors such as
financial institutions, cyclical industrials, and retailers. The absence of
significant defaults in the sector is in stark contrast to the upswing in
defaults and bankruptcy filngs across the rest of the U.S. economy,
consistent with the defensive reputation of the sector. '
29
30
31
32
In general, companies in the UPG sector entered 2009 in reasonably
sound financial condition; some drew down their bank credit facilties
during the banking crisis in late 2008 and repaid the loans as the bank
and financial markets stabilzed during 2009.4
33 As noted by S&P, Moody's and Fitch above, the regulated electric utilty
34 industry is maintaining strong investment grade credit and is well positioned to
2Standard & Poor's RatingsDirect on the Global Credit Portal: "Industry Economic And
Ratings Outlook: Slightly Positive Outlook For U.S. Regulated Electric Utilities Supports Rating
Stability," February 2,2010, emphasis added.3Moody's Investors Service Industry Outlook: "U,S. Electric Utilities Face Challenges Beyond
Near-Term," January 2010, emphasis added.4Fitch Ratings: "U.S. Utilities, Power and Gas 2010 Outlook," December 4,2009.
859 Gorman, Di - 6
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1 weather the recent economic downturn. Therefore, reasonable and rational
2 adjustments to RMP's rates would be appropriate to provide fair compensation, but
3 not excessive compensation, in an effort to improve RMP's competitive position and
4 support its credit quality.
5 Q PLEASE DESCRIBE ELECTRIC UTILITY STOCK PRICE PERFORMANCE OVER
6 THE LAST FIVE YEARS.
7 A As shown in Figure 1 below, the Edison Electric Institute ("EEl") has recorded electric
8 utilty stock price performance compared to the market. The EEl data shows that its
9 Electric Utilty Index has outperformed the market over the last five years
10 (2004-2008). Again, this strong stock performance indicates commission-authorized
12
11 returns on equity over the last several years have been positively received by. the
market.
FIGURE 1
30.00
20.00
10.00c..:i..GIii
(10.00)..c8 (20.00)..GIa.
(30.00)
(40.00)
(50.00)
Index Comparison
-+EEllndex
_S&P500
2004 2005 2008 2009 Q2201020062007
Source: EEl Q2 2010 Stock Performance Financial Update, at Page 1.
860 Gorman, Oi - 7
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During 2009 and the first half of 2010, the EEl Index underperformed the market,
2 which is not unusual for stocks that are considered "safe havens" during periods of
3 market turbulence. The EEl states the following:
4
5
6
7
8
9
10
11
12
13
14
Given the explosive market rally that began in March, the EEl Index's
underperformance of the major averages is not surprising. Defensive
stocks typically lag early in market rebounds coming out of recessions,
and the EEl Index surpassed broad market returns in each year from
2004 through 2008. Five years is a long stretch of outperformance for
any industry but especially so for the traditionally staid and
conservative utilties, who spent much of the middle years of the past
decade rebuilding balance sheets and refocusing business strategies
on basic regulated distribution and generation after the turbulence and
missteps into non-core businesses that followed deregulation in the
late 1990s.
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
Utilties a Winner for the Decade
Indeed, the industry's return to its roots in the traditional power
business proved a winning strategy for long-term growth of
shareholder value during the decade that just ended. From January 1,
2000 through December 31, 2009, the EEl Index returned 134%,
substantially outperforming the Dow Jones Industrials 14% return, the
S&P 500's -9% return, and the Nasdaq's 44% decline. The
tech-heavy Nasdaq never fully retraced the ground lost after the tech
bubble collapsed in 2001, and the S&P 500 was also heavily weighted
with technology at the decade's start, which accounts in part for its
negative showing. The financial crisis and "Great Recession" (the
popular label for our current economic malaise) capped the ten-year
stretch, producing severe losses in financial stocks and a new round of
weakness for the Nasdaq. All in all, conservative, plodding utilities
were the tortoise that outran the hare, demonstrating that sound
regulation, financial stabilty, operational and service excellence and
good investment returns can all coexist, and in fact be mutually
reinforcing.
33 * * *
34
35
36
37
38
39
40
Fundamentals Remain Solid
While the changed economic landscape since mid-2008 has
diminished the industry's near-term earnings prospects, industry
analysts continue to believe that many companies offer potential for a
return to reasonably strong earnings growth - supported by rate base
growth and rate relief from cases decided in recent months - as the
economy recovers from recession and enters a new expansion phase.
41 * * *
42
43
In fact, the industry's generally. strong balance sheets and credit
ratings, and its strategic focus on predictable regulatory treatment
861 Gorman, Di - 8
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12
13
14
15
16.17
18
19
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23
24
25
26
27
28
29
30
31
32
33
34
.
1
2
3
4
5
6
7
8
9
10
(such as pre-approval of major projects and construction work-in-
progress rate treatment in several states) were key factors that enable
companies to access capital throughout the credit crisis of late
2008/early 2009. The industry's positive long-term fundamental outlook
and attractive dividend yields wil likely continue to appeal to investors
looking for stable investments in today's diffcult economic
environment. As the year came to an end, a number of analysts
remarked on the relative undervaluation of regulated utility stocks
relative to the broad market, and sug~ested that the underperformance
in 2009 was unlikely to be sustained.
RMP Investment Risk
Q PLEASE PROVIDE A BRIEF OVERVIEW OF RMP AND ITS INVESTMENT
CHARACTERISTICS.
A RMP is a subsidiary of PacifiCorp, which is owned by MidAmerican Energy Holdings
Company ("MEHC"). PacifiCorp issues debt and equity on behalf of RMP.
PacifiCorp's current senior secured bond ratings from S&P and Moody's are "A" and
"A2," respectively.6 PacifiCorp's corporate credit ratings from S&P and Moody's are
"A-" and "Baa1 ," respectively.7
Specifically, S&P states the following:
Rationale
The 'A-' corporate credit rating (CCR) on PacifiCorp reflects its
"excellent" business risk profile, evidenced by a diverse and growing
service territory, and "aggressive" financial risk profile that reflects a
large capital program and the need to shore up its cash flow metrics.
While the ring-fenced utilty's credit metrics are more consistent on a
stand-alone basis with a 'BBB' category rating, Standard & Poor's
Ratings Servces expects that management wil achieve cash flow
metrics more consistent with an 'A' category rating over the next
several years. PacifiCorp is owned by MidAmerican Energy Holdings
Co. (MEHC; BBB+/Stable/--).
* * *
Outlook
The stable outlook on the PacifiCorp ratings incorporates our
expectation that MEHC wil continue to support the utilty by
5EEi 04 2009 Financial Update, emphasis added.
~illams Direct at 6.7PacifiCorp, FERC Form 3-Q as of June 30,2010 at 109.10.
862 Gorman, Di - 9
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2
3
4
5
6
7
8
9
10
11
12
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14
15
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18
19
20
21.22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
.
contributing equity sufficient to ensure that our fully adjusted debt to
total capitalization is managed over the next few years to an adjusted
level of closer to 50% and that FFO to total debt and FFO interest
coverage wil be 20% or better and in the range of 4.0x-4.5x,
respectively. Given that PacifiCorp's financial risk profile is weak for
the current ratings, we do not expect near-term upward ratings
momentum for the utilty. PacifiCorp's regulatory and structural
insulation shields the utility from some MEHC credit deterioration, to an
extent. Specifically, our criteria provide that the PacifiCorp CCR can
be no more than three notches above the MEHC consolidated credit
rating. The company is comfortably within this range, so we do not
see significant prospects for the utilty rating to fall as a result of
adverse rating changes on MEHC, which also enjoys a stable outlook.8
Similarly, Moody's confirms PacifiCorp's supportive regulatory treatment:
Rating Rationale
PacifiCorp's Baa1 rating for its senior unsecured obligations is driven
by the stability of its regulated cash flows, the geographically diverse
and relatively constructive regulatory environments in which it
operates, the diversification of its generation portfolio, financial credit
metrics that are within the ranges demonstrated by U.S. integrated
electric utilties rated Baa, and its position as the largest subsidiary of
MEHC. The rating also considers PacifiCorp's plans for significant
capital investment in generation and transmission and for
environmental compliance. The stable outlook incorporates Moody's
expectation that PacifiCorp wil continue to receive generally
supportive regulatory treatment to recover its increased costs and that
capital expenditures wil be financed in a manner that is consistent with
its current credit profile.
* * *
Reasonably Supportive Regulatory Environment
PacifiCorp's rating recognizes that the regulated nature of its
businesses and acknowledges the relative stabilty and predictabilty of
cash flows associated with these operations. The rating also
considers PacifiCorp's specific regulatory relationships. In 2007,
approximately 72% of PacifiCorp's retail revenues were subject to
regulatory oversight in Utah and Oregon which Moody's generally
ranks as average among U.S. regulatory jurisdictions in terms of
framework development, consistency and predictabilty of decisions,
and expectation of timely recovery of costs and investments. In
Oregon, California and Wyoming (44% of 2007 revenues) regulators
have authorized adjustment mechanisms to recover changes in the
costs of fuel and purchased power. Such provisions add adjustment
8Standard & Poor's RatingsDirect Summary: "PacifiCorp," October 30, 2009 (emphasis
added).
863 Gorman, Di -10
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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 Q
29
30 A
31
32
.
mechanisms to recover changes in the costs of fuel and purchased
power. Such provisions add predictabilty to utility returns and reduce
implementation lag. In an attempt to minimize regulatory lag and earn
its allowed ROEs, PacifiCorp is filing more frequent rate cases in all its
jurisdictions.
* * *
Existence of Ring-Fencing Provisions
PacifiCorp is ring-fenced via a special purpose entity structure, which
preserves its credit profile as an independent operating company,
separate from its ultimate parent company. The structure includes
typical ring-fencing provisions such as an independent director,
separate books and records, restrictions on affliate transactions (arm's
length), prohibitions on collateralizing or guaranteeing affliate debt,
and restrictions on dividend distributions. PacifiCorp's dividend
distributions are subject to compliance with certain financial tests,
including a minimum interest coverage ratio of 2.5 times and minimum
equity ratio in the range of 44-48.25%.
Financial Metrics
PacifiCorp's cash flow metrics are expected to remain fairly stable over
the near-to-medium term as the company continues with its significant
capital expenditure program. Moody's anticipates the company wil
proactively seek additional rate recovery for increased costs and
investments, and that dividend policy will continue to be established in
a manner that is supportive of the company's current credit profile.
Over the next few years, Moody's anticipates PacifiCorp's ratio of CFO
pre-W/C to Debt will remain in the range of 17-19% and that its interest
coverage ratio wil be in a range of 4.0-5.0 times. 9
WHAT DO YOU RECOMMEND THE COMMISSION TAKE FROM THIS CREDIT
REPORT REVIEW OF THE REGULATORY TREATMENT RMP IS RECEIVING?
Credit analysts consider the regulatory treatment for RMP to be constructive and
supportive of RMP's excellent business risk profile and stable investment grade credit
standing.
9Moody's Investors Service Credit Opinion: "PacifiCorp," October 17,2008 (emphasis added).
864 Gorman, Oi - 11
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.1 RMP's Proposed Capital Structure
2 Q WHAT CAPITAL STRUCTURE IS THE COMPANY REQUESTING TO USE TO
3 DEVELOP ITS OVERALL RATE OF RETURN FOR ELECTRIC OPERATIONS IN
4 THIS PROCEEDING?
5 A RMP's 2010 forecasted capital structure, as supported by RMP witness Mr. Bruce N.
6 Wiliams, is shown below in Table 1.
TABLE 1
RMP's Proposed Capital Structure
(December 31, 2010)
Descnption
Percent of
Total Capital
.Long-Term Debt
Preferred Stock
Common Equity
Total Capital Structure
47.6%
0.3%
52.1%
100.0%
Source: Williams Direct at 2.
7 Q
8 A
9
10
11
12
13
14
15
16.
DO YOU HAVE ANY ISSUES WITH RMP'S PROPOSED CAPITAL STRUCTURE?
Yes. RMP's proposed capital structure reflects a substantial increase in its common
equity ratio over the last several years. Indeed, based on its Federal Energy
Regulatory Commission financial statements, RM~ has not paid dividends to its
parent company over at least the last three years and has received $990 milion of
equity infusions since its acquisition by MEHC.10 As a result, RMP's common equity
ratio has increased from approximately 49.4% in 2007, up to 52.2% by June 30,
2010.
The concern I have with RMP's capital structure, is that while it has retained
all earnings in the Company, those earnings have not been completely invested in
10Williams Direct at 6.
865 Gorman, Oi -12
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14
15
16
17
18
19
20
21
22
23
24.
1 utility plant and equipment in the test year, or through 2010. Indeed, the Company's
2 books and records show that the Company has a substantial investment in special
3 deposits, temporary cash investments, and notes receivable from affilate companies
4 (together short-term asset investments). The five quarter average of the short-term
5 asset investment totals over $200 milion. RMP is using its retained earnings in part
6 to invest in these short-term assets.
7 I recommend the common equity supporting these short-term assets
8 investments not be included in the capital structure used to recover RMP's cost of
9 capital for utilty operations. RMP's common equity that is not used to support
10 investments in utilty plant should not be included in its utilty cost of capitaL. As a
11 result, RMP's ratemaking capital structure should be adjusted to remove the common
12 equity supporting short-term cash investments and, thus, excluded from the
13 development of an overall rate of return applied to RMP's utilty plant investment.
Q PLEASE DESCRIBE YOUR PROPOSED ADJUSTMENT TO RMP'S CAPITAL
STRUCTURE.
A RMP is proposing a 2009 test year, with known and measurable adjustments through
year-end 2010. However, actual data is only available for the post-test year through
June 30, 2010. Therefore, i relied on RMP's most recent five quarters of data ending
June 30, 2010 to develop an average capital structure ending June 30, 2010.11
RMP's capital structure at June 30, 2010is 52.2%, and is very close to that projected
by RMP for year-end 2010 of 52.1%.
i propose to remove the common equity capital supporting the following
non-utility assets: (1) special deposits, (2) short-term investments, and (3) the
difference between notes receivable from affliate companies and notes payable to
11Data for the last two quarters of 2010 were not available.
866 Gorman, Oi -13
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1 affliate companies. This wil reduce the five quarter average common equity amount
2 by approximately $200 millon, and lower the common equity ratio from 52.1 % down
3 to 49.7%.
4 I believe this capital structure is more reasonable for setting rates because it
5 reflects the actual common equity capital RMP relied on to invest in utilty plant. The
6 primary difference between my capital structure and that proposed by RMP, is that
7 the Company is proposing to reflect the cost of common equity capital that has not
8 been used to support investments in utilty plant. In contrast, my capital structure
9 reflects the actual capital structure mix supporting its investment in utilty plant.
10 Therefore, i believe my capital structure produces a more reasonable estimate of
11 RMP's actual cost of capital supporting its utilty plant investment.
12 Q DOES RMP HAVE AN ACQUISITION ADJUSTMENT RECORDED ON ITS
13 BALANCE SHEET THAT IS SUPPORTED BY COMMON EQUITY CAPITAL?
14 A Yes. However, RMP's schedules in this case indicate that a portion of this acquisition
15 adjustment is included in its Idaho rate base. Therefore, I did not remove the
16 common equity supporting this acquisition asset from the capital structure supporting
17 rate base. However, if this acquisition adjustment is removed from the Idaho rate
18 base, then the common equity supporting the acquisition adjustment should also be
19 removed from utility capital structure.
20 Q IS IT POSSIBLE THAT RMP'S DEBT CAPITAL COULD HAVE BEEN USED TO
21 FUND INVESTMENTS IN THESE SHORT-TERM CASH ASSETS?
22 A No. RMP's long-term embedded debt cost is 5.92%, and is more expensive than the
23 short-term interest earnings it produces on these short-term cash investments.
24 Therefore, it is reasonable to believe that these short-term cash investments simply
867 Gorman, Oi -14
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2 needed to fund utilty plant investment.
represent a placeholder for all the earnings RMP is retaining in its Company unti
3 Q
4 A
5 Q
WHAT IS YOUR PROPOSED CAPITAL STRUCTURE IN THIS PROCEEDING?
My proposed capital structure is shown below in Table 2.
TABLE 2
Adjusted Capital Structure
(ActuaI5-Quarter average, ending June 2010)
Description
Percent of
Total Capital
Long-Term Debt
Preferred Stock
Common Equity
Total Capital Structure
50.0%
0.3%
49.7%
100.0%
Source: Exhibit No. 202 (MPG-1) at 1.
IS YOUR PROPOSED CAPITAL STRUCTURE GENERALLY CONSISTENT WITH
6 RMP'S TARGET CAPITAL STRUCTURE FOR UTILITY OPERATIONS?
7 A
8 utility operations of 50%/50% debt/equity. The capital structure outlned in Table 2
Yes. In previous proceedings, Mr. Willams has stated a capital structure target for
9 approximates this targeted utilty capitalization mix.
10 Q WILL YOUR PROPOSED CAPITAL STRUCTURE SUPPORT RMP'S FINANCIAL
11 INTEGRITY AND CREDIT RATING?
12 A
13 consistent with RMP's current credit rating and wil support RMP's financial integrity.
Yes. As i will discuss later in my testimony, my proposed capital structure is
868 Gorman, Oi - 15
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1 Return on Common Equity
2 Q PLEASE DESCRIBE WHAT IS MEANT BY A "UTILITY'S COST OF COMMON
3 EQUITY."
4 A
5 make an investment. Investors expect to achieve their return requirement from
A utilty's cost of common equity is the return investors expect, or require, in order to
6 receiving dividends and stock price appreciation.
7 Q
8
9 A
10
11.12
13
14
15
16
17
18 Q
PLEASE DESCRIBE THE FRAMEWORK FOR DETERMINING A REGULATED
UTILITY'S COST OF COMMON EQUITY.
In general, determining a fair cost of common equity for a regulated utilty has been
framed by two decisions of the U.S. Supreme Court: Bluefield Water Works &
Improvement Co. v. Public Servo Commission of West Virginia, 262 U.S. 679 (1923)
and Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591 (1944).
These decisions identify the general standards to be considered in
establishing the cost of common equity for a public utility. Those general standards
provide that the authorized return should: (1) be suffcient to maintain financial
integrity; (2) attract capital under reasonable terms; and (3) be commensurate with
returns investors could earn by investing in other enterprises of comparable risk.
PLEASE DESCRIBE THE METHODS YOU HAVE USED TO ESTIMATE THE COST
19 OF COMMON EQUITY FOR RMP.
20 A
21 common equity. These models are: (1) a constant growth Discounted Cash Flow
I have used several models based on financial theory to estimate RMP's cost of
22 ("DCF") model; (2) a sustainable growth DCF model; (3) a multi-stage growth DCF
23 model; (4) a Risk Premium model; and (5) a Capital Asset Pricing Model ("CAPM"). I.
869 Gorman, Di -16
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1 have applied these models to a group of publicly traded utilties that I have
2 determined reflect investment risk similar to RMP.
3 Q HOW DID YOU SELECT A PROXY GROUP OF UTILITIES SIMILAR IN
4 INVESTMENT RISK TO RMP TO ESTIMATE ITS CURRENT MARKET COST OF
5 EQUITY?
6 A I relied on the same proxy group used by RMP witness Dr. Hadaway to estimate
7 RMP's return on equity.
8 Q HOW DOES THIS PROXY GROUP'S INVESTMENT RISK COMPARE TO THE
9 INVESTMENT RISK OF RMP?
10 A The proxy group is shown on Exhibit No. 203 (MPG-2). This proxy group has an
11 average senior secured credit rating from S&P of "A-," which is comparable to RMP's
12 senior secured credit rating from S&P of "A." The proxy group's senior secured credit
13 rating from Moody's is "A2," which is identical to RMP's senior secured credit rating
14 from Moody's. Therefore, my proxy group has comparable total investment risk to
15 RMP.
16 The proxy group has an average common equity ratio of 46.9% (including
17 short-term debt) from AUS and 48.1 % (excluding short-term debt) from Value Line in
18 2009. This proxy group's common equity ratio is lower than my proposed common
19 equity ratio for RMP of 49.7%. A comparable common equity ratio demonstrates that
20 RMP's financial risks are comparable to or lower than my proxy group.
21 I also compared RMP's business risk to the business risk of my proxy group
22 based on S&P's ranking methodology. RMP has a business risk profile of "Excellent,"
23 which is identical to the risk profile of my proxy group. S&P's profile score
24 methodology is discussed later in my testimony.
870 Gorman, Di - 17
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1 Discounted Cash Flow Model
2 Q
3 A
4
5
6
7
8
9
10
11
12
13.14
15
16
17
18
19
20 Q
21 A
PLEASE DESCRIBE THE DCF MODEL.
The DCF model posits that a stock price is valued by summing the present value of
expected future cash flows discounted at the investor's required rate of return or cost
of capitaL. This model is expressed mathematically as follows:
Po= ~ + D2 Dw h_ were (Equation 1)
(1+K)1 (1+K)2 (1+Kf
Po = Current stock price
D = Dividends in periods 1 - 00
K = Investor's required return
This model can be rearranged in order to estimate the discount rate or investor
required return, "K." If it is reasonable to assume that earnings and dividends wil
grow at a constant rate, then Equation 1 can be rearranged as follows:
K = D1/PO + G (Equation 2)
K = Investor's required return
D1 = Dividend in first year
Po = Current stock price
G = Expected constant dividend growth rate
Equation 2 is referred to as the annual"constant growth" DCF modeL.
PLEASE DESCRIBE THE INPUTS TO YOUR CONSTANT GROWTH DCF MODEL.
22 expected dividend, and expected growth rate in dividends.
As shown under Equation 2 above, the DCF model requires a current stock price,
.
871 Gorman, Di -18
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1
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3
4
5
6
7
8
9
10
11
12.13
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Q WHAT STOCK PRICE AND DIVIDEND HAVE YOU RELIED ON IN YOUR
CONSTANT GROWTH DCF MODEL?
A I relied on the average of the weekly high and low stock prices over a 13-week period
ended September 10, 2010. An average stock price is less susceptible to market
price variations than a spot price. Therefore, an average stock price is less
susceptible to aberrant market price movements, which may not be reflective of the
stock's long-term value.
A 13-week average stock price is stil short enough to contain data that
reasonably reflect current market expectations, but is not so short a period as to be
susceptible to market price variations that may not be reflective of the security's
iong-term value. In my judgment, a 13-week average stock price is a reasonable
balance between the need to reflect current market expectations and the need to
capture sufficient data to smooth out aberrant market movements.
i used the most recently paid quarterly dividend, as reported in The Value Line
Investment Survey. This dividend was annualized (multiplied by 4) and adjusted for
next year's growth to produce the D1 factor for use in Equation 2 above.
17 Q WHAT DIVIDEND GROWTH RATES HAVE YOU USED IN YOUR CONSTANT
18 GROWTH DCF MODEL?
19 A There are several methods one can use in order to estimate the expected growth in
20 dividends. However, for purposes of determining the market required return on
21 common equity, one must attempt to estimate investors' consensus about what the
22 dividend or earnings growth rate wil be, and not what an individual investor or analyst
23 may use to form individual investment decisions.
24 Security analysts' growth estimates have been shown to be more accurate
25 predictors of future returns than growth rates derived from historical data because
872 Gorman, Di -19
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2
3
4
5
6
7
8
9
10
11
12.13
14
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they are more reliable estimates. 12 Assuming the market generally makes rational
investment decisions, analysts' growth projections are more likely the growth
estimates considered by the market that influence observable stock prices than are
growth rates derived from only historical data.
For my constant growth DCF analysis, I have relied on a consensus, or mean,
of professional security analysts' earnings growth estimates as a proxy for the
investor consensus dividend growth rate expectations. i used the average of three
sources of analysts' growth rate estimates: Zacks, SNL Financial and Reuters. All
consensus analysts' projections used were available on September 15, 2010, as
reported online.
Each consensus growth rate projection is based on a survey of security
analysts. The consensus estimate is a simple arithmetic average, or mean, of
surveyed analysts' earnings growth forecasts. A simple average of the growth
forecasts gives equal weight to all surveyed analysts' projections. It is problematic as
to whether any particular analyst's forecast is more representative of general market
expectations. Therefore, a simple average, or arithmetic mean, of analyst forecasts is
a good proxy for market consensus expectations.
18 Q WHAT IS THE GROWTH RATE YOU USED IN YOUR CONSTANT GROWTH DCF
19 MODEL?
20 A The growth rates I used in my DCF analysis are shown in Exhibit No. 204 (MPG-3).
21 The average and median growth rates for my proxy group are 5.67% and 5.45%,
22 respectively.
.12See, !U, David Gordon, Myron Gordon, and Lawrence Gould, "Choice Among Methods of
Estimating Share Yield," The Journal of Portolio Management, Spring 1989.
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1 Q WHAT ARE THE RESULTS OF YOUR CONSTANT GROWTH DCF MODEL?
2 A As shown in Exhibit No. 205 (MPG-4), the average and median constant growth DCF
3 returns for the proxy group are 10.45% and 10.50%, respectively.
4 Q DO YOU HAVE ANY COMMENTS CONCERNING THE RESULTS OF YOUR
5 CONSTANT GROWTH DCF ANALYSIS?
6 A Yes. The three- to five-year growth rate exceeds a long-term sustainable growth rate
7 as required by the constant growth DCF modeL.
8 Q WHY DO YOU BELIEVE THE PROXY GROUP'S THREE- TO FIVE-YEAR
9 GROWTH RATE IS IN EXCESS OF A LONG-TERM SUSTAINABLE GROWTH?
10 A The three- to five-year growth rate of the proxy group exceeds the growth rate of the
11 overall U.S. economy. As developed below, the consensus of published economists'
12 projects is that the U.S. Gross Domestic Product ("GDP") wil grow at a rate of no
13 more than 5.1% and 4.9% over the next 5 and 10 years, respectively. A company
14 cannot grow, indefinitely, at a faster rate than the market in which it sells its products.
15 The U.S, economy, or GDP, growth projection represents a ceilng, or high-end,
16 sustainable growth rate for a utility over an indefinite period of time.
17 Q WHY IS THE GDP GROWTH PROJECTION CONSIDERED A CEILING GROWTH
18 RATE FOR A UTILITY?
19 A Utilities cannot indefinitely sustain a growth rate that exceeds the growth rate of the
20 overall economy. Utilties' earnings/dividend growth is created by increased utilty
21 investment or rate base. Utilty plant investment, in turn, is driven by service area
22 economic growth and demand for utilty service. In other words, utilities invest in
23 plant to meet sales demand growth, and sales growth in turn is tied to economic
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1 growth in their service areas. The Energy Information Administration ("EIA") has
2 observed that utilty sales growth is less than U.S. GOP growth, as shown in Exhibit
3 No. 206 (MPG-5). Utilty sales growth has lagged behind GOP growth. Hence,
4 nominal GOP growth is a very conservative, albeit overstated, proxy for electric utilty
5 sales growth, rate base growth, and earnings growth. Therefore, GOP growth is a
6 reasonable proxy for the highest sustainable long-term growth rate of a utilty.
Q IS THERE RESEARCH THAT SUPPORTS YOUR POSITION THAT, OVER THE
LONG TERM, A COMPANY'S EARNINGS AND DIVIDENDS CANNOT GROW AT
A RATE GREATER THAN THE GROWTH OF THE U.S. GDP?
A Yes. This concept is supported in both published analyst literature and academic
work. Specifically, in a textbook entitled "Fundamentals of Financial Management,"
published by Eugene Brigham and Joel F. Houston, the authors state as follows:
The constant growth model is most appropriate for mature companies
with a stable history of growth and stable future expectations.
Expected growth rates vary somewhat among companies, but
dividends for mature firms are often expected to grow in the future at
about the same rate as nominal gross domestic product (real GOP
plus inflation).
13
Also, Morningstar's Stocks, Bonds, Bíls and Inflation 2009 Yearbook
Valuation Edition tracked dividends of the stock market in comparison to GOP growth
over the period 1926 through the end of 2008.14 Based on that study, the authors
found that earnings and dividends for the market have historically grown in tandem
with the overall economy. It is important to note that the growth of companies
included in the overall market will normally be higher than that of utilty companies.
These non-utilty companies achieve a higher level of growth because they retain a
13"Fundamentals of Financial Management," Eugene F. Brigham and Joel F. Houston,
Eleventh Edition 2007, Thomson South-Western, a Division of Thomson Corporation at 298.14Stocks, Bonds, Bils and Inflation 2009 Yearbook Valuation Edition (Morningstar, Inc.) at 67.
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1 larger percentage of their earnings and payout a much smaller percentage of their
2 earnings as dividends. Retaining higher percentages of total earnings fuels stronger
3 growth for these non-utilty companies. Since the market in general grows at the
4 overall GOP growth rate, it is very conservative to assume that utilty companies could
5 achieve this same level of sustained growth without a material reduction in their
6 dividend payout ratios. As such, using the GOP as a maximum sustainable growth
7 rate is a very conservative and high-end estimate for utilty companies.
Q HAVE ANALYSTS RECOGNIZED THAT SHORT-TERM GROWTH OUTLOOKS
WILL SLOW OVER TIME?
A Yes. Value Line recognized that dividend growth wil likely slow from short-term
growth patterns. Value Line stated as follows:
Dividends have been increasing at a rapid pace since 2002, reflecting
relatively healthy balance sheets throughout the industry. In fact, last
year 61% of electric utilties raised their dividend, 33% reported no
change, 2% reinstated theirs, 2% lowered them, and only 2% are not
paying them at all. In any industry these statistics would be viewed as
quite favorable. But 2008 actually marked the slowing of a trend for
the electric utilty industry, in which the percentage of dividend
increases declined. The reversal is attributable to deteriorating
economic conditions, elevated capital spending, and higher debt-to-
capitalization ratios. Despite this, many utilties are stil sporting
attractive yields. 15
23 Sustainable Growth DCF
24 Q PLEASE DESCRIBE HOW YOU ESTIMATE A SUSTAINABLE LONG-TERM
25 GROWTH RATE FOR YOUR SUSTAINABLE GROWTH DCF MODEL.
26 A A sustainable growth rate is based on the percentage of the utilty's earnings that are
27 retained and reinvested in utilty plant and equipment. These reinvested earnings
15Value Line Investment Survey, May 29,2009, emphasis added.
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increase the earnings base (rate base) and wil grow earnings when the reinvested
earnings investment is put into service, and the Company is allowed to earn its
authorized return on the additional rate base investment.
The internal growth methodology is tied to the percentage of earnings retained
in the company and not paid out as dividends. The earnings retention ratio is 1 minus
the dividend payout ratio. As the payout ratio declines, the earnings retention ratio
increases. An increased earnings retention ratio will fuel stronger growth because
the business funds more investments with retained earnings. As shown ¡nExhibit No.
207 (MPG-6), Value Line projects the proxy group to have a declining dividend
payout ratio over the next three to five years. These dividend payout ratios and
earnings retention ratios can then be used to develop a sustainable long-term
earnings retention growth rate to help gauge whether analysts' current three- to five-
year growth rate projections can be sustained over an indefinite period of time.
The data used to estimate the long-term sustainable growth rate is based on
the Company's current market to book ratio, and Value Line's three- to-five year
projections per earnings, dividends, earned return on book equity, and projected
stock issuances.
As shown in Exhibit No. 208 (MPG-7), page 1 of 2, the average and median
sustainable growth rates for the proxy group using this internal growth rate model are
5.16% and 5.03%, respectively.
21 Q WHAT IS THE CONSTANT GROWTH DCF ESTIMATE USING THIS
22 SUSTAINABLE LONG-TERM GROWTH RATE?
23 A A DCF estimate based on this sustainable growth rate is developed in Exhibit No. 209
24 (MPG-8). As shown there, a sustainable growth DCF analysis produces a group.25 average and median DCF result of 9.92% and 9.14%, respectively.
877 Gorman, Di - 24
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2 produces a return on equity of 19.14%. Excluding DPL Inc., the proxy group's
The average result is skewed due to a significant outler - DPL Inc., which
3 average DCF would be 9.48%. Therefore, I conclude that the median result of 9.14%
4 better represents the central tendency of my proxy group. Hence, I wil rely on the
5 median DCF result.
6 The sustainable growth DCF result is based on the dividend and price data
7 used in my constant growth DCF study (using analyst growth rates) and the
8 sustainable growth rate discussed above and developed in Exhibit No. 208 (MPG-7).
9 Multi-Stage Growth DCF Model
10 Q
11 A.12
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18 Q
19 A
HAVE YOU CONDUCTED ANY OTHER DCF STUDIES?
Yes. My first constant growth DCF is based on consensus analysts' growth rate
projections, so it is a reasonable reflection of rational investment expectations over
the next three to five years. The limitation on the constant growth DCF model is that
it cannot reflect a rational expectation that a period of high/low short-term growth can
be followed by a change in growth to a rate that is more reflective of long-term
sustainable growth. Hence, I performed a multi-stage growth DCF analysis to reflect
this outlook of changing growth expectations.
PLEASE DESCRIBE YOUR MULTI-STAGE GROWTH DCF MODEL.
The multi-stage growth DCF model reflects the possibilty of non-constant growth for
20 a company over time. The multi-stage growth DCF model reflects three growth
21 periods: (1) a short-term growth period, which consists of the first five years; (2) a
22 transition period, which consists of the next five years (6 through 10); and (3) a
23 long-term growth period, starting in year 11 through perpetuity..
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For the short-term growth period, i relied on the consensus analysts' growth
2 projections described above in relationship to my constant growth OCF modeL. For
3 the transition period, the growth rates were reduced or increased by an equal factor,
4 which reflects the difference between the analysts' growth rates and the GOP growth
5 rate. For the long-term growth period, i assumed each company's growth would
6 converge to the maximum sustainable growth rate for a utilty company as proxied by
7 the consensus analysts' projected growth for the U.S. GOP of 4.9%.
Q WHAT DO YOU BELIEVE IS A REASONABLE SUSTAINABLE LONG-TERM
GROWTH RATE?
A A reasonable growth rate that can be sustained in the long run should be based on
consensus analysts' projections. Blue Chip Financial Forecasts publishes consensus
GOP growth projections twice a year. Based on its latest issue, the consensus
economists' published 5- to 10-year GOP growth rate outlook is 5.1% to 4.9%,
respectively. 16
Therefore, i propose to use the consensus economists' projected 10-year
GOP consensus growth rate of 4.9%, as published by Blue Chip Financial Forecasts,
as an estimate of sustainable long-term growth. This consensus GOP growth
forecast represents the most likely views of market participants because it is based
on published economist projections.
20 Q WHAT STOCK PRICE, DIVIDEND AND GROWTH RATES DID YOU USE IN YOUR
MULTI-STAGE GROWTH DCF ANALYSIS?21
22 A I relied on the same 13-week stock price and the most recent quarterly dividend
23 payment discussed above. For stage one growth, I used the consensus analysts'
16Blue Chip Financial Forecasts, June 1, 2010 at 14.
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1 growth rate projections discussed above in my constant growth DCF modeL. The
2 transition period begins in year 6 and ends in year 10. For the long-term sustainable
3 growth rate starting in year 11, I used 4.9%, the consensus economists' 10-year
4 projected nominal GDP growth rate.
5 Q WHAT ARE THE RESULTS OF YOUR MULTI-STAGE GROWTH DCF MODEL?
6 A As shown in Exhibit No. 210 (MPG-9), the average and median multi-stage growth
7 DCF return on equity for the proxy group are 9.87% and 9.90%, respectively.
8 Q PLEASE SUMMARIZE THE RESULTS FROM YOUR DCF ANALYSES.
9 A The results from my DCF analyses are summarized in Table 3:
TABLE 3
Summary of DCF Results
Description Proxy Group
Constant Growth DCF Model (Analysts' Growth)
Constant Growth DCF Model (Sustainable Growth)
Multi-Stage Growth DCF Model
Average DCF Return
10.50%
9.14%
9.90%
9.85%
10 For reasons set forth above, i believe my constant growth DCF model based
11 on analysts' growth is inflated because short-term analyst growth rate projections are
12 not reasonable estimates of long-term sustainable growth. Therefore, the DCF model
13 based on analysts' growth rate estimates should not be used on a stand-alone basis.
14 I recommend it be averaged with my other DCF estimates to produce a reasonable
15 DCF point estimate that can be used to derive RMP's return on equity. The constant
16 growth DCF model based on the sustainable growth approach is based on a growth
17 rate that is sustainable in the long term in comparison to GDP growth, but may not
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reflect analysts' short-term growth outlooks. The multi-stage growth DCF model
return reflects the expectation of changing growth rates over time. Even though I
have strong concerns about the accuracy of the constant growth DCF at this time, i
included all estimates in my DCF return of approximately 9.85%.
Risk Premium Model
PLEASE DESCRIBE YOUR BOND YIELD PLUS RISK PREMIUM MODEL.
This model is based on the principle that investors require a higher return to assume
greater risk. Common equity investments have greater risk than bonds because
bonds have more security of payment in bankruptcy proceedings than common equity
and the coupon payments on bonds represent contractual obligations. In contrast,
companies are not required to pay dividends on common equity, or to guarantee
returns on common equity investments. Therefore, common equity securities are
considered to be more risky than bond securities.
This risk premium model is based on two estimates of an equity risk premium.
First, i estimated the difference between the required return on utilty common equity
investments and Treasury bonds. The difference between the required return on
common equity and the bond yield is the risk premium. i estimated the risk premium
on an annual basis for each year over the period 1986 through June 2010. The
common equity required returns were based on regulatory commission-authorized
returns for electric utilty companies. Authorized returns are typically based on expert
witnesses' estimates of the contemporary investor required return.
The second equity risk premium method is based on the difference between
regulatory commission-authorized returns on common equity and contemporary
"An rated utilty bond yields. This time period was selected because over the period
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1986 through June 2010, public utilty stocks have consistently traded at a premium
to book value. This is ilustrated in Exhibit No. 211 (MPG-10), where the market to
book ratio since 1986 for the electric utilty industry was consistently above 1.0. Over
this time period, regulatory authorized returns were sufficient to support market prices
that at least exceeded book value. This is an indication that regulatory authorized
returns on common equity supported a utilty's ability to issue additional common
stock, without diluting existing shares. It further demonstrates that utilties were able
to access equity markets without a detrimental impact on current shareholders.
Based on this analysis, as shown in Exhibit No. 212 (MPG-11), the average
indicated equity risk premium over U.S. Treasury bond yields has been 5.19%. .Of
the 25 observations, 19 indicated risk premiums fall in the range of 4.40% to 6.08%.
Since the risk premium can vary depending upon market conditions and changing
investor risk perceptions, i believe using an estimated range of risk premiums
provides the best method to measure the current return on common equity using this
methodology.
As shown in Exhibit No. 213 (MPG-12), the average indicated equity risk
premium over contemporary Moody's utility bond yields was 3.75% over the period
1986 through June 2010. The indicated equity risk premium estimates based on this
analysis primarily fall in the range of 3.03% to 4.59% over this time period.
20 Q DO YOU BELIEVE THAT THIS RISK PREMIUM IS BASED ON A TIME PERIOD
21 THAT IS TOO LONG OR TOO SHORT TO DRAW ACCURATE RESULTS
22 CONCERNING CONTEMPORARY MARKET CONDITIONS?
23 A No. Contemporary market conditions can change dramatically during the period that
24 rates determined in this proceeding wil be in effect. Therefore, relying on a relatively.25 long period of time where stock valuations reflect premiums to book value is an
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indication that the authorized returns on equity and the corresponding equity risk
premiums were supportive of investors' return expectations and provided utilties
access to the equity markets under reasonable terms and conditions. Further, this
time period is long enough to smooth abnormal market movement that might distort
equity risk premiums. While market conditions and risk premiums do vary over time,
this historical time period is a reasonable period to estimate contemporary risk
premiums.
The time period I use in this risk premium is a generally accepted period to
develop a risk premium study using "expectational" data. Conversely, studies have
recommended that use of "actual achieved return data" should be based on very long
historical time periods. The studies find that achieved returns over short time periods
may not reflect investors' expected returns due to unexpected and abnormal stock
price performance. However, these short-term abnormal actual returns would be
smoothed over time and the achieved actual returns over long time periods would
approximate investors' expected returns. Therefore, it is reasonable to assume that
averages of annual achieved returns over long time periods wil generally converge
on the investors' expected returns.
My risk premium study is based on expectational data, not actual returns, and,
thus, need not encompass very long time periods.
20 Q BASED ON HISTORICAL DATA, WHAT RISK PREMIUM HAVE YOU USED TO
ESTIMATE RMP'S COST OF EQUITY IN THIS PROCEEDING?21
22 A The equity risk premium should reflect the relative market perception of risk in the
23 utilty industry today. i have gauged investor perceptions in utilty risk today in Exhibit
24 No. 214 (MPG-13). On that exhibit, i show the yield spread between utilty bonds and.25 Treasury bonds over the last 30 years. As shown in this exhibit, the 2008 utilty bond
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yield spreads over Treasury bonds for "A" rated and "Baa" rated utilty bonds are
2.25% and 2.97%, respectively. The utility bond spreads over Treasury bonds for "A"
and "Baa" rated utilty bonds for 2009 are 1.96% and 2.98%, respectively. These
utilty bond yield spreads over Treasury bond yields are much higher than the 30-year
average spreads of 1.60% and 2.00%, respectively.
While the yield spreads for 2008 and 2009 reflect unusually large spreads, the
market has started to improve and these spreads have started to decline. For
example, the 13-week average "A" rated utilty bond yield has subsided relative to the
end of 2008 and 2009, down to around 5.17%. This utiity bond yield when compared
to the current Treasury bond yield of 3.92% as shown on Exhibit No. 215 (MPG-14),
page 1 of 3, implies a yield spread of around 1.25%, which is lower than the 30-year
average spread for "A" utilty bonds of 1.60%. The same is true for the "Baa" utility
yields and spreads.
Q HOW DID YOU ESTIMATE RMP'S COST OF COMMON EQUITY WITH THIS RISK
PREMIUM MODEL?
A i added a projected long-term Treasury bond yield to my estimated equity risk
premium over Treasury yields. The 13-week average 30-year Treasury bond yield,
ending September 10, 2010 was 3.92%, as shown on Exhibit No. 215 (MPG-14).
Blue Chip Financial Forecasts projects the 30-year Treasury bond yield to be 4.7%,
and a 10-year Treasury bond yield to be 3.8%.1 Using the projected 30-year bond
yield of 4.70%, and a Treasury bond risk premium of 4.40% to 6.08%, as developed
above, produces an estimated common equity return in the range of 9.10% (4.70% +
4.40%) to 10.78% (4.70% + 6.08%), with a midpoint of 9.94%.
17 Blue Chip Financial Forecasts, September 1, 2010 at 2.
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2 13-week average yield on "A" rated utilty bonds for the period ending September 10,
I next added my equity risk premium over utilty bond yields to a current
3 2010 of 5.17%. Exhibit No. 215 (MPG-14), page 1 of 3. Adding the utiity equity risk
4 premium of 3.03% to 4.59%, as developed above, to an "A" rated bond yield of
5 5.40%, produces a cost of equity in the range of 8.20% to 9.76%, with a midpoint of
6 8.98%.
7 My risk premium analyses produce a return estimate in the range of 8.98% to
8 9.94%, with a midpoint estimate of 9.46%.
9 Capital Asset Pricing Model ("CAPM")
10 Q
11 A.12
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25.
PLEASE DESCRIBE THE CAPM.
The CAPM method of analysis is based upon the theory that the market required rate
of return for a security is equal to the risk-free rate, plus a risk premium associated
with the specific security. This relationship between risk and return can be expressed
mathematically as follows:
R¡ = Rf + B¡ x (Rm - Rf) where:
R¡ = Required return for stock i
Rf = Risk-free rate
Rm = Expected return for the market portfolio
B¡ = Beta - Measure of the risk for stock
The stock-specific risk term in the above equation is beta. Beta represents
the investment risk that cannot be diversified away when the security is held in a
diversified portfolio. When stocks are held in a diversified portfolio, firm-specific risks
can be eliminated by balancing the portfolio with securities that react in the opposite
direction to firm-specific risk factors (e.g., business cycle, competition, product mix,
and production limitations).
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2 nondiversifiable risks. Nondiversifiable risks are related to the market in general and
The risks that cannot be eliminated when held in a diversified portfolio are
3 are referred to as systematic risks. Risks that can be eliminated by diversification are
4 regarded as non-systematic risks. In a broad sense, systematic risks are market
5 risks, and non-systematic risks are business risks. The CAPM theory suggests that
6 the market wil not compensate investors for assuming risks that can be diversified
7 away. Therefore, the only risk that investors will be compensated for are systematic
8 or non-diversifiable risks. The beta is a measure of the systematic or
9 non-diversifiable risks.
1D Q
11 A.12
13 Q
14 A
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16
17 Q
PLEASE DESCRIBE THE INPUTS TO YOUR CAPM.
The CAPM requires an estimate of the market risk-free rate, the company's beta, and
the market risk premium.
WHAT DID YOU USE AS AN ESTIMATE OF THE MARKET RISK-FREE RATE?
As previously noted, Blue Chip Financial Forecasts' projected 3D-year Treasury bond
yield is 4.7%.18 The current 3D-year bond yield is 4.4%. I used Blue Chip Financial
Forecasts' projected 3D-year Treasury bond yield of 4.7% for my CAPM analysis.
WHY DID YOU USE LONG-TERM TREASURY BOND YIELDS AS AN ESTIMATE
18 OF THE RISK-FREE RATE?
19 A
2D
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22.
Treasury securities are backed by the full faith and credit of the United States
government. Therefore, long-term Treasury bonds are considered to have negligible
credit risk. Also, long-term Treasury bonds have an investment horizon similar to that
of common stock. As a result, investor-anticipated long-run inflation expectations are
18Blue Chip Financial Forecasts, September 1, 2010 at 2.
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1 reflected in both common stock required returns and long-term bond yields.
2 Therefore, the nominal risk-free rate (or expected inflation rate and real risk-free rate)
3 included in a long-term bond yield is a reasonable estimate of the nominal risk-free
4 rate included in common stock returns.
5 Treasury bond yields, however, do include risk premiums related to
6 unanticipated future inflation and interest rates. A Treasury bond yield is not a
7 risk-free rate. Risk premiums related to unanticipated inflation and interest rates are
8 systematic or market risks. Consequently, for companies with betas less than 1.0,
9 using the Treasury bond yield as a proxy for the risk-free rate in the CAPM analysis
10 can produce an overstated estimate of the CAPM return.
11 Q.12 A
WHAT BETA DID YOU USE IN YOUR ANALYSIS?
As shown in Exhibit No. 216 (MPG-15), the proxy group average Value Line beta
13 estimate is 0.69.
14 Q
15 A
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HOW DID YOU DERIVE YOUR MARKET RISK PREMIUM ESTIMATE?
i derived two market risk premium estimates, a forward-looking estimate and one
based on a long-term historical average.
The forward-looking estimate was derived by estimating the expected return
on the market (as represented by the S&P 500) and subtracting the risk-free rate from
this estimate. i estimated the expected return on the S&P 500 by adding an expected
inflation rate to the long-term historical arithmetic average real return on the market.
The real return on the market represents the achieved return above the rate of
inflation.
Morningstar's Stocks, Bonds, Bils and Inflation 2010 Yearbook publication
estimates the historical arithmetic average real market return over the period 1926 to
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2009 as 8.6%.19 A current consensus analysts' inflation projection, as measured by
the Consumer Price Index, is 1.9%.20 Using these estimates, the expected market
return is 10.66%.21 The market premium then is the difference between the 10.66%3
4 expected market return, and my 4.7% risk-free rate estimate, or 5.96%.
5 The historical estimate of the market risk premium was also estimated by
6 Morningstar in Stocks, Bonds, Bils and Inflation 2010 Yearbook. Over the period
7 1926 through 2009, Morningstar's study estimated that the arithmetic average of the
achieved total return on the S&P 500 was 11.80%,22 and the total return on long-term8
9 Treasury bonds was 5.8%.2 The indicated equity risk premium is 6.0% (11.80% -
10 5.8% = 6.00%).
Q HOW DOES YOUR ESTIMATED MARKET RISK PREMIUM RANGE COMPARE TO
THAT ESTIMATED BY MORNINGSTAR?
A Morningstar estimates a forward-looking market risk premium based on actual
achieved data from the historical period of 1926 through year-end 2009. Using this
data, Morningstar estimates a market risk premium derived from the total return on
large company stocks (S&P 500), less the income return on Treasury bonds. The
total return includes capital appreciation, dividend or coupon reinvestment returns,
and annual yields received from coupons and/or dividend payments. The income
return, in contrast, only reflects the income return received from dividend payments or
coupon yields. Morningstar argues that the income return is the only true risk-free
rate associated with the Treasury bond and is the best approximation of a truly
risk-free rate. I disagree with this assessment from Morningstar, because it does not
19Morningstar, Inc. Ibbotson SBBI 2010 Classic Yearbook at 82.
2°Blue Chip Financial Forecasts, July 1,2010 at 2.
21~ ((1 + 0.086) * (1 + 0.019))-1 n * 100.
22Morningstar, Inc. Ibbotson SBBI 2010 Classic Yearbook at 82.
231d.
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1 reflect a true investment option available to the marketplace and therefore does not
2 produce a legitimate estimate of the expected premium of investing in the stock
3 market versus that of Treasury bonds. Nevertheless, I wil use Morningstar's
4 conclusion to show the reasonableness of my market risk premium estimates.
5 Morningstar's analysis indicates that a market risk premium falls somewhere
6 in the range of 5.2% to 6.7%. This range is based on several methodologies. First,
7 Morningstar estimates a market risk premium of 6.7% based on the difference
8 between the total market return on common stocks (S&P 500) less the income return
9 on Treasury bond investments. Second, Morningstar found that if the New York
10 Stock Exchange (the "NYSE") was used as the market index rather than the
11 S&P 500, that the market risk premium would be 6.4% and not 6.7%. Third, if only
12 the two deciles of the largest companies included in the NYSE were considered, the
13 market risk premium would be 5.9%.24
14 Finally, Morningstar found that the 6.7% market risk premium based on the
15 S&P 500 was impacted by an abnormal expansion of price-to-earnings ("PIE") ratios
16 relative to earnings and dividend growth during the period 1980 through 2001.
17 Morningstar believes this abnormal PIE expansion is not sustainable. Therefore,
18 Morningstar adjusted this market risk premium estimate to normalize the growth in the
19 PIE ratio to be more in line with the growth in dividends and earnings. Based on this
20 alternative methodology, Morningstar published a long-horizon supply-side market
risk premium of 5.2%.2521
22 Thus, based on all of Morningstar's estimates, the market risk premium falls
23 somewhere in the range of 5.2% to 6.7%.
24Morningstar observes that the S&P 500 and the NYSE Decile 1-2 are both large
capitalization benchmarks. Morningstar, Inc. Ibbotson SBBI2009 Valuation Yearbook at 54.
251d. at 66.
889 Gorman, Di - 36
Monsanto Company
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.
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1 Q WHAT ARE THE RESULTS OF YOUR CAPM ANALYSIS?
2 A As shown in Exhibit No. 217 (MPG-16), based on my low-end market risk premium of
3 5.2%, high-end market risk premium of 6.7%, a risk-free rate of 4.7%, and a beta of
4 0.69, my CAPM analysis produces a return in the range of 8.28% to 9.31%, with a
5 midpoint of 8.80%.
6 Return on Equity Summary
7 Q BASED ON THE RESULTS OF YOUR RATE OF RETURN ON COMMON EQUITY
8 ANALYSES DESCRIBED ABOVE, WHAT RETURN ON COMMON EQUITY DO
9 YOU RECOMMEND FOR RMP?
10 A Based on my analyses, i estimate RMP's current market cost of equit to be 9.5%.
TABLE 4
Return on Common Equity Summary
Description Results
DCF
Risk Premium
CAPM
9.85%
9.46%
8.80%
11 My recommended return on equity range is 9.10% to 9.90%. My low end is
12 based on the average of my CAPM and risk premium return estimates and my high
13 end is based on my DCF analysis.
890 Gorman, Di - 37
Monsanto Company
.
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22
.
1 Financial Integrity
2 Q WILL YOUR RECOMMENDED OVERALL RATE OF RETURN SUPPORT AN
3 INVESTMENT GRADE BOND RATING FOR RMP?
4 A Yes. I have reached this conclusion by comparing the key credit rating financial
5 ratios for RMP at my proposed capital structure, and my return on equity to S&P's
6 benchmark financial ratios using S&P's new credit metric ranges.
Q PLEASE DESCRIBE THE MOST RECENT S&P FINANCIAL RATIO CREDIT
METRIC METHODOLOGY.
A S&P publishes a matrix of financial ratios that correspond to its assessment of the
business risk of the utilty company and related bond rating. S&P updated its credit
metric guidelines on November 30, 2007, and incorporated utiity metric benchmarks
with the general corporate rating metrics. However, the effect of integrating the utility
metrics with that of general corporate bonds, resulted in a reduction to the
transparency in S&P's credit metric guideline for utilties. Most recently, on May 27,
2009 S&P expanded its matrix criteria and included an additional business and
financial risk category. Based on S&P's most recent credit matrix, the business risk
profile categories are "Excellent," "Strong," "Satisfactory," "Fair," "Weak," and
"Vulnerable." Most electric utilties have a business risk profile of "Excellent" or
"Strong." The financial risk profile categories are "Minimal," "Modest," "Intermediate,"
"Significant," "Aggressive," and "Highly Leveraged." Most of the electric utilties have
a financial risk profile of "Aggressive." RMP has an "Excellent" business risk profile
and a "Significant" financial risk profile.
891 Gorman, Oi - 38
Monsanto Company
.
Q
2
3 A
4
5
6
7
8
9
10
11 Q.12
13 A
PLEASE DESCRIBE S&P'S USE OF THE FINANCIAL BENCHMARK RATIOS IN
ITS CREDIT RATING REVIEW.
S&P evaluates a utility's credit rating based on an assessment of its financial and
business risks. A combination of financial and business risks equates to the overall
assessment of RMP's total credit risk exposure. S&P publishes a matrix of financial
ratios that defines the level of financial risk as a function of the level of business risk.
S&P publishes ranges for three primary financial ratios that it uses as
guidance in its credit review for utilty companies. The three primary financial ratio
benchmarks it relies on in its credit rating process include: (1) debt to EBITDA,
(2) funds from operations ("FFO") to total debt, and (3) total debt to total capitaL.
HOW DID YOU APPLY S&P'S FINANCIAL RATIOS TO TEST THE
REASONABLENESS OF YOUR RATE OF RETURN RECOMMENDATIONS?
i calculated each of S&P's financial ratios based on RMP's cost of service for retail
14 operations. While S&P would normally look at total consolidated financial ratios in its
15 credit review process, my investigation in this proceeding is to judge the
16 reasonableness of my proposed cost of capital for rate-setting in RMP's Idaho utilty
17 operations. Hence, i am attempting to determine whether the rate of return and cash
18 flow generation opportunity reflected in my proposed utilty rates for RMP in Idaho wil
19 support its investment grade bond ratings and financial integrity.
20 Q
21 A
DID YOU INCLUDE ANY OFF-BALANCE SHEET DEBT?
Yes. As shown in Exhibit No. 218 (MPG-17), page 4 of 4, i estimated an Idaho
22 allocation of PacifiCorp total off-balance sheet debt, imputed interest and amortized
23 expenses for operating leases and purchased power agreements ("PPAs"). These.
892 Gorman, Oi - 39
Monsanto Company
.off-balance sheet obligations were used to estimate RMP credit metrics at my
2 proposed rate of return.
3 Q
4 A
5
6
7
8
9
10
11.12
13
14
15 Q
HOW DID YOU ESTIMATE RMP'S OFF-BALANCE SHEET DEBT?
The off-balance sheet debt is shown on Exhibit No. 218 (MPG-17), page 4 of 4. First,
I developed an Idaho allocator, which is the ratio of RMP's Idaho rate base as of
December 2009 divided by total Company rate base at the same time.
Second, i obtained RMP's total Company lease and purchased power
off-balance sheet debt and associated imputed interest and amortization expenses
from the S&P report (Williams Exhibit No. 60, page 6 of 10). These factors were used
to estimate the Idaho allocated portion of the total Company off-balance sheet lease
and purchased power imputed debt, interest and amortization expense. The
off-balance sheet impact on RMP's total capital structure weights was used to
develop the RMP debt ratio for Idaho operations including total Company off-balance
sheet PPA and operating lease debt equivalents.
PLEASE DESCRIBE THE RESULTS OF THIS CREDIT METRIC ANALYSIS FOR
16 RMP.
17 A
18 (MPG-17), page 1 of 4.
The S&P financial metric calculations for RMP are developed on Exhibit No. 218
19 As shown on Exhibit No. 218 (MPG-17), page 1 of 4, column 1, based on an
20 equity return of 9.50%, RMP wil be provided an opportunity to produce a debt to
21 EBITDA ratio of 3.3x. This is within the S&P's "Significant" financial risk guideline
.
893 Gorman, Oi - 40
Monsanto Company
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1
2
3
4
5
6
7
8
9
10
11
.12
13
14
15
16
17
18
19
20
21
22
23
.
range of3.0x to 4.0x and above (stronger) than the "Aggressive" risk profile.26 This
ratio supports an investment grade credit rating.
RMP's retail operations FFO to total debt coverage at a 9.50% equity return
would be 26%, which is within the "Significant" metric guideline range of 20% to 30%
and above the "Aggressive" profile range. The FFO/total debt ratio wil support an
investment grade bond rating.
Finally, RMP's total debt ratio to total capital is 52%. This is within the
"Aggressive" profile guidance range of 50% to 60%. This total debt ratio wil support
PacifiCorp's investment grade bond rating.
At my recommended return on equity and my proposed capital structure, the
Company's financial credit metrics are supportive of its current" A" utilty bond rating.
Q DO YOU BELIEVE THIS CREDIT METRIC EVALUATION OF RMP AT YOUR
PROPOSED RETURN ON EQUITY PROVIDES MEANINGFUL INFORMATION TO
HELP THE COMMISSION DETERMINE THE APPROPRIATENESS OF YOUR
RECOMMENDATION?
A Yes. While S&P calculates these credit metrics based on total Company operations,
and not the retail operations of RMP as I have performed in this study, it stil provides
meaningful information on the proposed rate of return for RMP in this case and how it
wil contribute and help support consolidated operations credit standing. Further,
while credit rating agencies also consider other financial metrics and qualitative
considerations, these metrics are largely driven by the cost of service items of
depreciation expense and return on equity. Hence, to the extent these important
aspects of cost of service impact RMP's internal cash flows, the relative impact on
26Standard & Poor's RatingsDirect: "Criteria Methodology: Business Risk/Financial Risk
Matrix Expanded," May 27, 2009.
894 Gorman, Oi - 41
Monsanto Company
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1 RMP wil be measured by these credit metrics. As ilustrated above, an authorized
2 return on equity of 9.50% wil support internal cash flows that wil be adequate to
3 maintain RMP's current investment grade bond rating.
4 Response to RMP Witness Dr. Samuel Hadaway
5 Q WHAT RETURN ON COMMON EQUITY IS RMP PROPOSING FOR THIS
6 PROCEEDING?
7 A RMP is proposing to set rates based on a return on equity of 10.6%. RMP's return on
8 equity proposal is based on the analysis and judgment of Dr. Samuel Hadaway.
9 Dr. Hadaway's results are summarized at page 40 of his direct testimony.
10 Q DO DR. HADAWAY'S METHODOLOGIES SUPPORT HIS 10.6% RETURN ON
11 EQUITY FOR HIS PROXY GROUP?
12 A No. As discussed in detail below, reflecting current market data and properly
13 applying his models, Dr. Hadaway's own analyses would support a return on equity in
14 the range of 9.1% to 9.9%.
15 Q PLEASE DESCRIBE THE METHODOLOGY SUPPORTING DR. HADAWAY'S
16 RETURN ON COMMON EQUITY RECOMMENDATION.
17 A Dr. Hadaway develops his return on common equity recommendation using three
18 versions of the DCF model, and two utilty risk premium analyses. i have summarized
19 Dr. Hadaway's results below in Table 5 under column 1. Under column 2, i show the
20 results of Dr. Hadaway's analyses adjusted for updated data and more reasonable
21 application of the models.
895 Gorman, Di - 42
Monsanto Company
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2
As shown below in Table 5, using consensus economists' projection of GDP
growth rather than Dr. Hadaway's inflated GDP growth estimates, his own DCF
3 analyses would support a return on equity for RMP in the range of 9.1% to 9.9%.
TABLES
Summary of Dr. Hadaway's ROE Estimate
Description
Hadaway
Results
(1 )
DCF Analysis
Constant Growth (Analysts' Growth)
Constant Growth (GDP Growth)
Multi-Stage Growth Model
Reasonable DCF Range
10.3% - 10.5%
10.7% - 10.8%
10.6%
10.3% - 10.8%
Risk Premium Analysis
Forecasted Utility Debt + Equity Risk Premium
Current Utilty Debt + Equity Risk Premium
Risk Premium Estimate
10.59%
10.39%
10.84%
Recommended ROE
Adjusted ROE
10.6%
Sources:
lHadaway Direct at 40.
2Exhibit No. 219 (MPG-18).
Adjusted
Hadawa¥
Results
(2)
10.3% - 10.5%
9.6% - 9.7%
9.6% - 9.7%
9.8% - 10.0%
Reject
8.1% - 9.75%
9.56%
9.1% - 9.9%
4 Q
5 A
PLEASE DESCRIBE DR. HADAWAY'S CONSTANT GROWTH DCF ANALYSIS. .
Dr. Hadaway's adjusted constant growth DCF analysis is shown in Exhibit No. 219
6 (MPG-18). As shown on that exhibit, Dr. Hadaway's constant growth DCF analysis is
8 growth rates: (1) Value Line; (2) Zacks; and (3) Thomson.
7 based on a recent stock price, an annualized dividend and an average of three
896 Gorman, Oi - 43
Monsanto Company
.
1 Q
2 A
3
4
5
6
7
8
9
10
11
ARE DR. HADAWAY'S DCF ESTIMATES RELIABLE?
No, for at least two reasons. First, Dr. Hadaway's constant growth OCF based on
analyst growth rates produces excessive return estimates for the same reasons
discussed above concerning my OCF studies. That is, Dr. Hadaway's analyst growth
OCF study is based on an abnormally high dividend yield in the range of 4.78% to
4.86% and growth rate of 5.50%. The growth rate used in this OCF study is too high
to be a reasonable estimate of a sustainable long-run growth rate.
Second, his OCF studies that use a GOP growth rate are overstated, because
his GOP growth rate used in his constant growth and multi-stage growth models is
based on an inflated GOP growth rate of 6.0%. This GOP growth is excessive and
not reflective of current market expectations.
.12 Q HOW DID DR. HADAWAY DEVELOP HIS GOP GROWTH RATE?
13 A He states that the GOP growth rate is based on the achieved GOP growth over the
14 last 10,20, 30, 40, 50, and 6o-year periods. Dr. Hadaway's projected GOP growth
15 rate is unreasonable. Historical GOP growth over the last 20 and 40-year periods
16 was strongly influenced by the actual inflation rate experienced over that time period.
17 Q WHY IS DR. HADAWAY'S DCF ESTIMATE EXCESSIVE IN COMPARISON TO
18 THAT OF PUBLISHED MARKET ANALYSTS?
19 A The consensus economists' projected GOP growth rate is much lower than the GOP
20 growth rate used by Dr. Hadaway in his OCF analysis. A comparison of
21 Dr. Hadaway's GOP growth rate and consensus economists' projected GOP growth
22 over the next five and ten years is shown below in Table 6. As shown in this table,
23 Dr. Hadaway's GOP rate of 6.0% reflects real GOP of 3.1% and an inflation adjusted.24 GOP of 2.9%. However, consensus economists' projections of nominal GOP include
897 Gorman, Di - 44
Monsanto Company
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.
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GOP inflation projections over the next five and ten years of 2.1 %, and 2.2%,
2 respectively.
27
3 As is clearly evident in the table below, Or. Hadaway's historical GOP growth
4 reflects historical inflation, which is much higher than, and not representative of,
5 consensus market expected forward-looking inflation.
TABLE 6
GOP Projections
Descnption
GOP
Inflation
Real Nominal
GOP GOP
2.9%6.0%
2.9%5.1%
2.6%4.9%
Or. Hadaway
Consensus 5- Year Projection
Consensus 10- Year Projection
3.1%
2.1%
2.2%
Source: Blue Chip Financial Forecasts, June 1, 2010, at 14.
6 As such, Or. Hadaway's 6.0% nominal GOP growth rate is not reflective of consensus
7 market expectations and should be rejected.
8 Q HOW WOULD OR. HADAWAY'S DCF ANALYSES CHANGE IF CURRENT
9 MARKET-BASED GOP GROWTH RATE PROJECTIONS ARE INCLUDED IN HIS
10 ANALYSIS RATHER THAN HIS EXCESSIVE GOP GROWTH RATE?
11 A As shown in Exhibit No. 219 (MPG-18), i updated Or. Hadaway's OCF analyses using
12 more recent market data and a GOP growth rate of 4.9%. This GOP growth rate is
13 the consensus economists' 10-year projected growth rate of the GOP as published in
14 the Blue Chip Financial Forecasts on June 1, 2010. As shown in Exhibit No. 219
27 Blue Chip Financial Forecasts, June 1, 2010, at 14.
898 Gorman, Oi - 45
Monsanto Company
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.
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1 (MPG-18), using this consensus economists' projected GDP growth rate, reduces
2 Dr. Hadaway's DCF results from 10.6% to 9.9%.
3 Q PLEASE SUMMARIZE YOUR UPDATE AND ADJUSTMENTS TO
4 DR. HADAWAY'S DCF STUDIES.
5 A Updating the price and dividend yield information and growth rates in Dr. Hadaway's
6 study, and modifying them for a more reasonable GDP growth rate, reduces the
7 average DCF result produced by Dr. Hadaway's studies from 10.6% down to 9.9%.
8 Dr. Hadaway's original estimates, and these updated and adjusted results are shown
9 below in Table 7.
TABLE 7
Adjusted Hadaway DCF
Range Average
Description Hadaway DCF Adjusted DCF
Constant Growth (Analysts' Growth)
Constant Growth (GDP Growth)
Multi-Stage Growth Model
Average
10.4%
9.7%
9.7%
9.9%
10.4%
10.8%
10.6%
10.6%
10 As shown above in Table 7, using a consensus economists' GDP forecast, rather
11 than the GDP forecast derived by Dr. Hadaway, would support a return on equity for
12 RMP of 9.9%.
13 Q PLEASE DESCRIBE DR. HADAWAY'S UTILITY RISK PREMIUM ANALYSIS.
14 A Dr. Hadaway's utilty bond yield versus authorized return on common equity risk
15 premium is shown in his Exhibit No. 14. As shown in this exhibit, Dr. Hadaway
16 estimated an annual equity risk premium by subtracting Moody'S average bond yield
899 Gorman, Di - 46
Monsanto Company
.
1
2 over the period 1980 through 2009. Based on this analysis, Dr. Hadaway estimates
from the electric utility regulatory commission authorized return on common equity
3 an average indicated equity risk premium over current utility bond yields of 3.23%.
4 Dr. Hadaway then adjusts this average equity risk premium using a regression
5 analysis based on an expectation that there is an ongoing inverse relationship
6 between interest rates and equity risk premiums. Based on this regression analysis,
7 Dr. Hadaway increases his equity risk premium from 3.23%, up to 4.40% and 4.55%
8 relative to projected and current "A" bond yield of 6. i 9% and 5.84%, respectively. He
9 then adds these inflated equity risk premiums to a projected and the current "An rated
10 utilty bond yield of 6.19% and 5.84% to produce a return on equity of 10.59% and
11 10.39%, respectively.
.12 Q
13 A
14
15
16
17
18
19
20 Q
21
22 A
ARE DR. HADAWAY'S UTILITY RISK PREMIUM ANALYSES REASONABLE?
No. Dr. Hadaway develops a forward-looking risk premium model, relying on
forecasted interest rates and volatile utilty spreads, which are highly uncertain and
produce inaccurate results. Further, Dr. Hadaway adjusts his equity nsk premium of
3.23% to reflect the inverse relationship between interest rates and utilty risk
premiums. This adjustment is inappropriate and not consistent with academic
literature that finds that this relationship should change with risk changes and not
simply changes to nominal interest rates.
DOES DR. HADAWAY'S RISK PREMIUM ANALYSIS SUPPORT A RETURN ON
EQUITY IN THE RANGE OF 10.59% TO 10.39%?
No. His equity risk premium estimates of 4.40% and 4.55% are overstated. The
.24
23 common equity risk premium over the period 1986 to 2010 is approximately 3.75% as
shown in Exhibit No. 213 (MPG-12).
900 Gorman, Oi - 47
Monsanto Company
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1 Q DO YOU HAVE ANY COMMENTS CONCERNING DR. HADAWAY'S
2 FORECASTED UTILITY YIELD OF 6.19%?
3 A Yes. Dr. Hadaway develops his forecasted utilty yield based on the 3-month
4 historical spread of "A" rated utility bond yields and 3D-year Treasury yields of 1.19%
5 added to his projected long-term Treasury yield of 5.0%. This approach is
6 unreasonable because Dr. Hadaway relies on projected interest rates. The accuracy
7 of his projections are highly problematic. Indeed, while interest rates have been
8 projected to increase over the last several years, those increased interest rate
9 projections have turned out to be wrong.
10 Q WHY DO YOU BELIEVE THAT THE ACCURACY OF FORECASTED INTEREST
11 RATES IS HIGHLY PROBLEMATIC?
12 A This is clearly evident by a review of projected changes to interest rates made over
13 the last several years, in comparison to how accurate these projections turned out to
14 be. This analysis clearly ilustrates that observable interest rates today are as
15 accurate as are economists' consensus projections of future interest rates.
16 An analysis supporting this conclusion is ilustrated in Exhibit No. 220
17 (MPG-19). On this exhibit, under Columns 1 and 2, i show the actual market yield at
18 the time a projection is made for Treasury bond yields two years in the future. In
19 Column 1, I show the actual Treasury yield and, in Column 2, i show the projected
20 yield two years out.
21 As shown in Columns 1 and 2, over the last several years, Treasury yields
22 were projected to increase relative to the actual Treasury yields at the time of the
23 projection. In Column 4, I show what the Treasury yield actually turned out to be two
24 years after the forecast. Under Column 5, i show the actual yield change at the time
25 of the projections relative to the projected yield change.
901 Gorman, Oi - 48
Monsanto Company
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1
2
3
4
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22
.
As shown in this exhibit, over the last several years, economists have been
consistently projecting increases to interest rates. However, as demonstrated under
Column 5, those yield projections have turned out to be overstated in virtually every
case. Indeed, actual Treasury yields have decreased or remained flat over the last
five years, rather than increase as the economists' projections indicated.
This review of the experience with projected interest rates clearly ilustrates
that interest rate projection accuracy is highly problematic. Indeed, current
observable interest rates are just as likely a reasonable projection of future interest
rates as are economists' projections.
Q WHY IS DR. HADAWAY'S USE OF A SIMPLE INVERSE RELATIONSHIP
BETWEEN INTEREST RATES AND EQUITY RISK PREMIUMS NOT
REASONABLE?
A Dr. Hadaway'S belief that there is a simplistic inverse relationship between equity risk
premiums and interest rates is not supported by academic research. While academic
studies have shown that, in the past, there has been an inverse relationship with
these variables, researchers have found that the relationship changes over time and
is influenced by changes in perception of the risk of bond investments relative to
equity investments, and not simply changes to interest rates. 28
In the 1980s, equity risk premiums were inversely related to interest rates, but
that was likely attributable to the interest rate volatilty that existed at that time.
Interest rate volatility currently is much lower than it was ilT the 1980s.29 As such,
when interest rates were more volatile, the relative perception of bond investment risk
28"The Market Risk Premium: Expectational Estimates Using Analysts' Forecasts," Robert S.
Harris and Felicia C. Marston, Journal of Applied Finance, Volume 11, No.1, 2001 and "The Risk
Premium Approach to Measuring a Utility's Cost of Equity," Eugene F. Brigham, Dilip K. Shome, and
Steve R. Vinson, Financial Management, Spring 1985.29Morningstar SBBI, 2009 Yearbook at 95-96.
902 Gorman, Di - 49
Monsanto Company
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1 increased relative to the investment risk of equities. This changing investment risk
2 perception caused changes in equity risk premiums.
3 In today's marketplace, interest rate variabilty is not as extreme as it was
4 during the 1980s. Nevertheless, changes in the perceived risk of bond investments
5 relative to equity investments stil drive changes in equity premiums. However, a
6 relative investment risk differential cannot be measured simply by observing nominal
7 interest rates. Changes in nominal interest rates are highly influenced by changes to
8 inflation outlooks, which also change equity return expectations. As such, the
9 relevant factor needed to explain changes in equity risk premiums is the relative
10 changes to the risk of equity versus debt securities investments, not simply changes
11 to interest rates.
12 Importantly, Dr. Hadaway's analysis simply ignores investment risk
13 differentials. He bases his adjustment to the equity risk premium exclusively on
14 changes in nominal interest rates. This is a flawed methodology and does not
15 produce accurate or reliable risk premium estimates. His results should be rejected
16 by the Commission.
17 Q CAN DR. HADAWAY'S RISK PREMIUM ANALYSES BASED ON CURRENT AND
18 PROJECTED YIELDS BE MODIFIED TO PRODUCE MORE REASONABLE
19 RESULTS?
20 A Yes. Eliminating the inverse relationship adjustment to the equity risk premium of
21 3.23% and relying on Dr. Hadaway's current "An rated utility yield of 5.84% will result
22 in a return on equity risk premium of 9.07%. Using Dr. Hadaway'S 2009 equity risk
23 premium of 4.20% as shown in his Exhibit No. 14 and his current "An rated utilty yield
24 of 5.84% will result in a return of 10.04%. Therefore, Dr. Hadaway'S risk premium will
25 be in the range of 9.07% to 10.04%, with a midpoint of 9.56%.
903 Gorman, Oi - 50
Monsanto Company
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Q DOES THE "A" RATED BOND YIELD USED BY DR. HADAWAY REFLECT
2 CURRENT "An RATED UTILITY BOND YIELDS?
3 A No. The "A" rated utilty bond yield of 5.84% used by Dr. Hadaway represents a
4 three-month average time period ending April 10, 2010 (Direct at 21). As shown on
5 my Exhibit No. 215 (MPG-14), the current "A" rated utilty bond yield is approximately
6 5.17%, rounded to 5.2%. Using the current "A" rated utility bond yield, and a risk
7 premium in the range of 3.2% to 4.55%, would suggest a return on equity in the range
8 of 8.4% to 9.75%, with a midpoint of 9.1%. Again, more current interest rates clearly
9 show a very significant decline in capital market costs relative to RMP's last rate case
10 and even the time Dr. Hadaway performed his return on equity study.
11 Q DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
12 A Yes, it does.
904 Gorman, Oi - 51
Monsanto Company
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1 Q
2 A
REef r;
PACIFICORP dba ROCKY MOUNTAIN POWER iata NOV 16 h'g..
#in. S8
UT/.l/iDT1~ltP... i LitL)BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. PAC-E-10-07
Rebuttal Testimony of MichaelP. Gorman
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
Michael P. Gorman. My business address is 16690 Swingley Ridge Road, Suite 140,
3 Chesterfeld, MO 63017.
4 Q ARE YOU THE SAME MICHAEL P. GORMAN WHO PREVIOUSLY FILED
5 TESTIMONY IN THIS PROCEEDING?
6 A Yes.
7 Q
8 A
ON WHOSE BEHALF ARE YOU APPEARING IN THIS PROCEEDING?
I am appearing on behalf of Monsanto Company, a special contract customer of
9 Rocky Mountain Power ("RMP" or "Company").
10 Q ARE YOU SPONSORING ANY EXHIBITS IN CONNECTION WITH YOUR
12 A
11 REBUTTAL TESTIMONY?
13 Q
Yes, Exhibit No. 232 (MPG-20) and Exhibit No. 233 (MPG-21).
WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY IN THIS
15 A
14 PROCEEDING?
i wil respond and comment on the rate of return recommendation of Idaho Public
16 Utilties Commission Staff witness Terri Carlock.
90S Gorman, Oi-Reb - 1
Monsanto Company
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13
14
15
16
17
18
19
20
21
22.23
1 Q PLEASE OUTLINE THE RECOMMENDATIONS MADE BY STAFF WITNESS
2 CARLOCK TO WHICH YOU WILL RESPOND.
3 A Ms. Carlock supports the Company's proposed capital structure, and recommends a
4 return on equity of 10%, which is at the midpoint of her recommended range of 9.5%
5 to 10.5%.
6 Q WHAT REASONS DID MS. CARLOCK GIVE TO SUPPORT THE COMPANY'S
7 PROPOSED CAPITAL STRUCTURE IN THIS PROCEEDING?
8 A Ms. Carlock provided no support or rationale for why she concludes that the
9 Company's proposed capital structure is reasonable for setting rates. For the
10 reasons set forth in my testimony, it is important that the Commission carefully review
11 the Company's capital structure to ensure that it is reasonable, and will minimize the
12 Company's cost of capital, while maintaining its financial integrity and credit standing.
Q HOW DID MS. CARLOCK DEVELOP HER RECOMMENDED RETURN ON EQUITY
IN THE RANGE OF 9.5% TO 10.5%?
A Ms. Carlock performed both a comparable earnings analysis and a discounted cash
flow ("DCFn) return estimate. Ms. Carlock's comparable earnings analysis was based
on earned return on equity for electric utilties followed by The Value Line Investment
Survey, with a financial strength rating of "A.n There, she found that the return on
equity for these companies falls in the range of 9.0% to 1 0.5%. (Carlock at 18).
However, she does not identify the year of the expected earned return on equity, nor
does she show any schedules supporting her findings. Further, Ms. Carlock's
comparable earnings analysis indicates that the return for electric utiity companies in
the West region of the United States, including Idaho utilities, is around 8.6% to 9.0%.
906 Gorman, Oi-Reb - 2
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.
.
1 Based on this comparable earnings assessment, she concludes that a fair return on
2 equity for PacifiCorp would be in the range of 9.0% to 10.5%.
3 Ms. Carlock also performed a DCF analysis. Based on her DCF analysis, she
4 found that a fair return on common equity would be in the range of 8.8% to 9.3%, with
5 a recommended point estimate at 9.3%. (Carlock at 19-20).
6 Based on these results, Ms. Carlock estimated a return on equity for
7 PacifiCorp in the range of 9.5% to 10.5%. (ld. at 21).
8 Q DO YOU BELIEVE MS. CARLOCK'S COMPARABLE EARNINGS ANALYSIS
9 PRODUCES A FAIR RETURN ON EQUITY FOR RMP IN THIS CASE?
10 A No. Earned return on equity for the publicly traded companies followed by The Value
11 Line Investment Survey does not accurately identify what a fair return on equity for
12 PacifiCorp's investment in regulated utilty operations in Idaho would be in today's
13 marketplace. This is true for several reasons. First, the comparable earnings
14 analysis measures an accounting return and not an investor-required return. To the
15 extent the accounting earned return on equity is higher or lower than the
16 investor-required return, then the value of the Company's security would trade at a
17 premium or discount to its underlying book value. Hence, the earned return does not
18 represent fair compensation based on current capital market costs.
19 Further, the companies relied on by Ms. Carlock to measure her comparable
20 earned return on equity of 10.5% are on average trading at a significant premium to
21 book value. For example, as shown on my Exhibit No. 232 (MPG-20), the average
22 market-to-book ratio for the companies followed by The Value Line Investment
23 Survey that have a financial strength rating in the "A" category, had a median return
24 on equity for 2009 of 10.5%, and a median market-to-book ratio of 141%. In
25 significant contrast, the median earned return for the utilties followed by The Value
907 Gorman, Oi-Reb - 3
Monsanto Company
.
8
9
10
11.12
13
14
15
16
17
18
19
20
.
1 Line Investment Survey in the West District portion of the U.S. had a median return
2 on equity of 8.6%, and a median market-to-book ratio of 121%. This evidence clearly
3 suggests that a 10.5% return on equity exceeds the current market's required return
4 on equity, because the price of security was bid up in response to this above-market
5 earnings opportunity. Therefore, her earned return on equity estimate exceeds the
6 required return on investment by the market, and a 10.5% return on equity is
7 unreasonably high in today's very low capital market cost.
Q ARE THERE OTHER CONCERNS WITH THE COMPARABLE EARNINGS
ANALYSIS USED BY MS. CARLOCK TO ESTIMATE A FAIR RETURN FOR RMP
IN THIS PROCEEDING?
A Yes. Many of the companies included in the group of Value Line companies with a
financial strength rating of "A," include companies that have subsidiaries in merchant
generation and other commodity-related businesses. Indeed, these companies
demonstrate the highest earned return on equity during 2009. For example, Entergy
Corp. had a return on equity of 14.3%, Exelon Corp. had a return on equity of 22.5%,
and Sempra Energy had a return on equity of 13.1 %. These companies in particular
had very high earned returns on equity, which may have largely been driven by their
merchant generation affilates. Earnings on merchant generation activities or other
non-regulated businesses are not reasonable risk proxies for PacifiCorp and do not
produce a fair return on equity estimate to use to set rates.
21 Q DOES MS. CARLOCK'S DCF RETURN ESTIMATE SUFFER FROM THE SAME
22 SHORTCOMINGS AS HER COMPARABLE EARNINGS ANALYSIS?
23 A No. A DCF return does measure the investor-required return, but wil increase and
24 decrease based on markets' demand for higher compensation for assuming the risk
908 Gorman, Di-Reb - 4
Monsanto Company
.
5
6
7
8
9
10
11.12
13
14
15
16
17
.
1 of investment, or for changes in market capital costs that are driven by changes in
2 underlying security valuations. Hence, the DCF return estimate does measure the
3 correct return, and that is the return investors are currently requiring in order to
4 assume the underlying investment risk of a company.
Q SETTING ASIDE YOUR CONCERN WITH THE VALIDITY OF A COMPARABLE
EARNINGS ANALYSIS, WOULD A COMPARABLE EARNINGS ANALYSIS OF
THE VALUE LINE COMPANIES WITH A FINANCIAL STRENGTH OF "A"
SUPPORT A 10.5% RETURN BASED ON 2010 DATA?
A No. As shown on Exhibit No. 233 (MPG-21), while the earned return on equity for
companies followed by The Value Line Investment Survey in 2009 was at a median
10.5%, using the same data in 2010 suggests a return on equity of 10.0% for these
same companies. Using this more recent data, and reflecting current expected
earned returns on equity, Ms. Carlock's return on equity range would top out at 10%,
rather than the 10.5% she estimated. Further, if the low-end is set at her 9.3% DCF
return, then the adjusted Carlock range would be 9.3% to 10.0%, with a midpoint of
9.65%. This adjusted point estimate is comparable to my recommended return on
equity for RMP in this case of 9.6%.
18 Q DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY?
19 A Yes, it does.
IIHueylShareslPLDocslSDVV9210\T estimony . BA11187189.docx
909 Gorman, Di-Reb - 5
Monsanto Company
.
.
.
1 (The following proceedings were had in
2 open hearing.)
3 Q.BY MR. BUDGE: Just one question: Would you
4 provide a brief summary of your testimony?
5 A.I will. In my testimony, I respond to the
6 Company's estimate of a fair return on equity and overall rate
7 of return. I find that a fair return on equity is 9.5 percent,
8 which is the midpoint in my estimated range of a fair return on
9 equi ty for PacifiCorp and Rocky Mountain Power in this
10 proceeding of 9.1 to 9.9 percent.
11 I reviewed the analyses supporting Dr. Hadaway's
12 estimated return on equity of 10.6 percent and found several
13 reasons why I believe he has significantly overstated a fair
14 return on equity for PacifiCorp in this case.
15 MR. HICKEY: Madam Chairman, I'm going to object
16 on the basis that this is exactly what's in the testimony, and
17 as has been obj ected in other instances, it seems like we're
18 just restating what's already spread into the record.
19 COMMISSIONER SMITH: Mr. Budge.
20 MR. BUDGE: That's correct. I just want him to
21 do the quick summary as Mr. Walj e and some other witnesses have
22 done. If there's an objection, we'll move right along and
23 tender him for examination.
24 COMMISSIONER SMITH: I think the Commissioners
25 have read the testimony. We appreciate the summary. If you're
910
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
GORMAN (Di)
Monsanto
.
.
.
20
21
22
1 ready to move on, we are too.
2 MR. BUDGE: Yes.
3 COMMISSIONER SMITH: Mr. Otto.
4 MR. OTTO: No questions, Madam Chairman.
5 COMMISSIONER SMITH: Mr. Olsen.
6 MR. OLSEN: No questions, Madam Chair.
7 COMMISSIONER SMITH: Ms. Davison.
8 MS. DAVISON: No.
9 COMMISSIONER SMITH: Mr. Purdy.
10 MR. PURDY: No questions.
11 COMMISSIONER SMITH: Mr. Woodbury.
12 MR. WOODBURY: No questions.
13 COMMISSIONER SMITH: That leaves you.
14 MR. HICKEY: Thank you, Madam Chairman, just a
15 few.
16
17 CROSS-EXAMINATION
18
19 BY MR. HICKEY:
Q.Good afternoon, Mr. Gorman.
A.Good afternoon.
Q.Is it fair to say that you have testified in
23 opposi tion to the Company's position on return on equity in
24 many dockets throughout the six-state territory?
25 A.Yes.
911
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
GORMAN (X)
Monsanto
.
.
.
1 Q.Can you give us an approximation of how many
2 times you've appeared in rate case proceedings for the purpose
3 of contradicting the testimony offered by the Company on a
4 reasonable rate of return on equity?
5 A.Well, when you say, "contradicting the Company,"
6 my testimony generally attempts to measure what is a reasonable
7 and fair return on equity, and if I find the Company's
8 recommendation for return on equity to be excessive, then
9 I will provide a rebuttal and explain why I find it to be
10 excessive.
11 Q.Well, let me ask it this way, Mr. Gorman: Have
12 you ever agreed with Dr. Hadaway in any of the cases that
13 you've appeared that involved the issue of setting just and
14 reasonable rates for Rocky Mountain Power?
15 A.I have not, mostly because Dr. Hadaway relies on
16 inputs to his models, which I think inflate a fair return on
17 equity.
18 Q.That wasn't the question, Mr. Gorman.
19 COMMISSIONER SMITH: Mr. Hickey, we need to let
20 the witness finish his answer. I think he's done.
21 Q.BY MR. HICKEY: Can we agree at least on this,
22 Mr. Gorman, that you have been, in many cases, in many states,
23 offering testimony that is in contradiction to testimony
24 offered by the Company to support its case? Can we at least
25 agree on that?
912
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
GORMAN (X)
Monsanto
.
.
.
1 A.And can you read that question back?
2 Q.We can certainly have it read back, yes.
3 A.Make sure I heard it correctly.
4 (Whereupon, the requested portion of the
5 record was read by the court reporter.)
6 THE WITNESS: Saying the testimony I filed
7 concerning PacifiCorp, I can't recall a case where I didn't
8 find that their recommended rate of return was reasonable.
9 Every case I can remember, I believe I did recommend a
10 reasonable rate of return in the rej ection of the Company's
11 inflated rate of return.
12 Q.BY MR. HICKEY: Thank you. It sounds like we
13 were in agreement then. Is that right?
14 With the description I offered, if you're askingA.
15 me if I found the Company's recommendation to be reasonable, I
16 can't remember a case where I did.
17 MR. HICKEY: I have no further questions,
18 Madam Chair.
19 COMMISSIONER SMITH: Do we have questions from
20 the Commissioners?
21
22
23
24
25
COMMISSIONER REDFORD: No.
COMMISSIONER SMITH: Nor I.
Redirect, Mr. Budge.
MR. BUDGE: No questions, Madam Chairman.
COMMISSIONER SMITH: Thank you.
913
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
GORMAN (X)
Monsanto
.
.
.
20
21
22
1 MR. BUDGE: We would ask this witness be excused,
2 and thank the Company and Chair for accommodating the
3 scheduling problem there.
4 COMMISSIONER SMITH: Is there any objection?
5 Seeing none, Mr. Gorman is excused.
6 Thank you for being here.
7 THE WITNESS: Thank you.
8 (The witness left the stand.)
9 COMMISSIONER SMITH: Back to you, Mr. Hickey.
10 MR. HICKEY: Yes. We'd like to call Dr. Hui Shu
11 as our next witness.
12
13 HUI SHU,
14 produced as a witness at the instance of Rocky Mountain Power,
15 being first duly sworn, was examined and testified as follows:
16
17 DIRECT EXAMINATION
18
19 BY MR. HICKEY:
Q.Good afternoon, Dr. Shu.
A.Good afternoon.
Q.For the record, could you please state and spell
23 your name?
24
25
A.My name is Hui Shu: H-U-I, S-H-U.
Q.And by whom are you employed and in what
914
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
SHU (Di)
RMP
.
.
.
18
19
1 capacity?
2 A.I am employed by PacifiCorp as a manager of net
3 power cost.
4 COMMISSIONER SMITH: I think Dr. Shu is going to
5 have to get closer to the mic.
6 MR. HICKEY: I was just going to have the same
7 request. Thank you, Chairman Smith.
8 Q.BY MR. HICKEY: I don't know how close that mic
9 will come to you, but I think some other witnesses had a
10 problem with getting it to -- you might just get in the habit
11 of leaning towards it, Hui.
12 A.Okay.
13 Q.Yeah, it would be good to stay closer to it.
14 Thank you.
15 Are you the same Hui Shu that filed direct
16 testimony on May 28th of this year and attached to it Exhibit
17 40?
A.Yes.
Q.And did you also file rebuttal testimony on
20 November 16th of 2010 and attach to your rebuttal testimony
21 Exhibits 71 through 75?
22
23
A.Yes.
Q.Do you have any changes or corrections to your
24 testimony or exhibits?
25 A.Yes, I do. I would like to make two comments:
915
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
SHU (Di)
RMP
.
.
.
20
21
22
1 The first one is related to a errata filing of my
2 testimony -- my rebuttal testimony -- on November 24th, and
3 that errata corrected three printing errors, at least that's
4 what I thought. In reviewing the errata testimony, I noticed
5 that two of the three printing errors were not quite corrected.
6 May I assume Commissioners have my errata
7 testimony?
8 COMMISSIONER SMITH: Your rebuttal?
9 THE WITNESS: Yeah, errata rebuttal.
10 COMMISSIONER SMITH: Yes, we have it.
11 THE WITNESS: Okay. I'm sorry. The errata
12 mentioned on page 35, line 2, there need to be text inserted on
13 that line.
14 Q.BY MR. HICKEY: Let's just slow down a little
15 bi t, Hui, and let the Commissioners get to the point you've
16 referenced them to.
17 A.Okay.
18 Q.The page again, please?
19 A.Page 35.
Q.And what line on page 35?
Of your rebuttal. Correct?
A.Correct. Page 35, and line 2. And in the errata
23 filing, that portion of the testimony has been corrected, which
24 is to insert the text after "that is," so that finish that
25 paragraph, which now reads as: That is, for a unit with a
916
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
SHU (Di)
RMP
.
.
.
1 capaci ty of 100 megawatts, when GRID dispatches the unit at
2 70 megawatts, it does not matter whether the unit has been
3 derated by 20 percent or not. The Commission should reject
4 PIIC' s adjustment.
5 And, also, inserted is the text currently on
6 page 36 of the same testimony beginning on line 11, so that
7 portion of the text has been correctly inserted on page 35, and
8 line 11 through 19 of page 36 should be deleted.
9 Q.And then am I correct --
10 MS. DAVISON: I'm sorry, Mr. Hickey. I got
11 completely lost. I think this is dealing with her testimony,
12 so I'm trying to understand. I apologize for the interruption,
13 but are we dealing with the rebuttal testimony?
14 MR. SOLANDER: The errata.
15 MS. DAVISON: The errata. I don't have an
16 errata.
17 COMMISSIONER SMITH: Let's go off the record for
18 a few minutes while we make sure everybody has the right
19 testimony.
20 (Discussion off the record.)
21 COMMISSIONER SMITH: Let's go back on the record.
22 Q.BY MR. HICKEY: So the date that this errata was
23 filed, so the record is clear, was the 28th of November, is
24 that correct, or 24th? You'll have to tell me: I don't have
25 it in front of me.
917
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
SHU (Di)
RMP
.
.
.
1 A.The letter attached to the errata filing is
2 November 24th.
3 Q.Okay. So the 24th of November, an errata was
4 filed. And tell us then as succinct as possible succinctly
5 as possible -- Dr. Shu, why was the errata filed?
6 A.The errata was filed because of the -- my
7 rebuttal testimony wasn't printed correctly. It's -- at this
8 point, it seems like some of the lines were dropped and some of
9 the paragraphs are concatenated.
10 Q.Sure. My words, not yours: There was a computer
11 gli tch of some kind that what you had on your screen didn't get
12 printed correctly as part of the rebuttal testimony. Is that a
13 fair summary of what caused the errata?
14 A.It's fair.
15 Q.And so the errata was simply to complete and
16 clean up some of these word-processing glitches. Correct?
17 A.Correct.
18 Q.Okay.
19 MR. HICKEY: Now, with that said, I would ask
20 that the prefiled direct and rebuttal testimony of Dr. Shu,
21 together with the errata that was filed on the 24th of
22 November, be spread upon the record as if read, and that
23 Exhibits 40, and 71 through 75, be marked for identification.
24
25
COMMISSIONER SMITH: I just want to clarify that
the only change we needed to make if we had the errata was
918
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
SHU (Di)
RMP
.
.
.
19
20
1 striking the testimony on page 36, lines 11 through 19.
2 THE WITNESS: Sorry.
3 COMMISSIONER SMITH: Yes, go ahead.
4 THE WITNESS: There's another one, which is on
5 page 46.
6 COMMISSIONER SMITH: All right, let's do that
7 one.
8 THE WITNESS: Line 17. Oh, sorry. Excuse me,
9 it's page 45. Page 45, line 17. At the very end of that line,
10 it started with "Staff, PIIC," and basically starting from
11 "Staff," that word, to the end of that paragraph should be
12 deleted.
13 COMMISSIONER SMITH: Deleted?
14 THE WITNESS: Correct. That's it.
15 COMMISSIONER SMITH: So beginning on line 17 with
16 the word "Staff" and continuing through the end of line 19
17 should be stricken.
18 THE WITNESS: Correct.
COMMISSIONER SMITH: Okay , with those changes
Q.BY MR. HICKEY: Are there any other additions or
21 corrections, Dr. Shu?
22 A. No.
23 COMMISSIONER SMITH: Is there any objection to
24 spreading the prefiled direct and rebuttal testimony of Dr. Shu
25 on the record? Any questions lingering?
919
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
SHU (Di)
RMP
.1 If not,we will spread the testimony on the
2 record as if read with the corrections that have just been
3 identified.
4 (The following prefiled direct and
5 rebuttal testimony of Dr.Shu is spread upon the record.)
6
7
8
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
920
HEDRICK COURT REPORTING SHU (Di)
P.O.BOX 578,BOISE,ID 83701 RMP
.1 Q.
2
3 A.
Please state your name, business address and present position with
PacifiCorp ("Company").
My name is Hui Shu, my business addrss is 825 N.E. Multnoma, Suite 600,
4 Portland, Oregon 97232. My present position is Manager of Net Power Costs.
5 Qualifications
6 Q.
7 A.
8
9
10
11.12
13 Q.
14 A.
15
16
17
Briefly describe your educational and profesional background.
I received an undergraduate degree in Electrcal Engineering and finished training
in the program for a Masters in Business Administration from University of
Shanghai for Science and Technology. I received a PhD degree in Systems
Science with a focus on Econometrcs from Portland State University. I have
worked for PacifiCorp since 1992 and have held positions in the commercial and
trading and regulatory areas. I accepted my curent position in Februar 2008.
Please describe your current duties.
I am responsible for the coordination and preparation of net power cost studies
and related analyses used in retail price filngs. In addition, I represent the
Company on varous net power cost related issues with intervenor and regulatory
groups associated with the six state regulatory commssions to whose jurisdiction
18 the Company is subject.
19 Purpoe of Testimony
20 Q.
21 A.
22
.23
What is the purpose of your testimony in this proceeding?
I present the Company's net power costs for the 12-month period ending
December 2010. Specifically, my testimony:
. Sponsors the GRID model net power cost report that supports this fiing;
921 Shu, Di - 1
Rocky Mountan Power
.1
2
. Describes the primar drvers of the increase in the Company's net power
costs;
3 . Describes modeling enhancements addressing hydro resources; and
4 . Discusses the wind integration charge included in the Company's filing.
5 Net Power Cost Results
6 Q.
7 A.
8
9
10
11.12 Q.
13
14 A.
15
16
17 Q.
18
19 A.
20
21
22.23
What are the normalized net power costs for the test period?
The normalized net power costs ("NP") for the twelve months ending December
2010 are approximately $69.2 millon on an Idaho allocated basis, or $1.07 bilion
system-wide as presented in confidential Exhibit No. 40. The allocation of total
Company NPC to Idaho is presented in Exhibit NO.2 in Company witness Mr.
Steven R. McDougal's diect testimony.
How wil the normalized NPC approved by the Commission in this
proceeding be used for setting retail rates in Idaho?
They wil set the new base NPC for puroses of the Energy Cost Adjustment
Mechanism ("ECAM") and wil be trued-up to actual NPC consistent with the
mechanics of the ECAM.
How do proposed NPC compare with the NPC that the Commission
authorized in the Company's last general rate case, Case No. PAC-E-08-07?
The NPC authorized in Case No. PAC-E-08-07 were $982 millon on a total
Company basis or $66.1 millon on an Idaho allocated basis. On a total Company
basis, NPC have increased approximately $87.7 millon from $982 miion to
$1.07 bilion. Idaho's allocated portion of NPC in the current filing is
approximately $3.1 millon higher than the NPC curently included in customers'
922
Shu, Di - 2
Rocky Mountain Power
.1 rates, which is the combined result of increases in the total Company NPC and
2 decreases in Idaho's allocation factor.
3 Primary Drivers Increàsing Net Power Costs
923 Shu, Di - 3
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10
11 Q..12 A.
13
14
15
16
17 Q.
18 A.
19
20
21
22
23.
transfer ("FPT") wheeling contracts with the Bonnevile Power Admnistration
("BP A"). As these FPT contracts expire, they are being replaced with new
wheeling contracts with BPA that are higher-priced point-to-point ("PTP") and
network-integration ("NT") contracts. The increases also include expenses for
additional contracts to wheel generation from the Chehalis gas-fired plant and the
Goodnoe Hils wind plant to the Company's load areas. Also, Idao Power
Company has adjusted its wheeling rate for the contrcts with the Company
associated with delivering generation from the Jim Bridger plant to the
Company's load areas. These changes to wheeling expenses increase NPC by
approximately $16.5 millon on a total Company basis.
Are the BPA wind integration charges included in the wheeling expenses?
Yes. The BPA wind integration charges are recorded in the Company's wheeling
expense account. These expenses were included in the Company's total wind
integration charges in the last case. In addition, BP A has increased its wind
integration charge from $0.68 per kW-month to $1.29 per kW-month based on the
results of BPA's 2010-'2011 transmission rate case.
How do expiring power purchase and sales contracts impact net power costs?
The cost of the replacement power for expirng purchase contracts could be higher
or lower, depending on whether the price of the expired power purchase contract
was below or above curent maket prices. Likewise, the revenue credits of
additional wholesale sales could be lower or higher, depending on whether the
price of the expired power sales contract was above or below curent market
prices.
924
Shu, Di - 4
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9 Q.
10 A.
11
.12
13
14
15
16
17
18
19
20 Q.
21 A.
22
23.
significantly below curent market prices, and accordingly, expiration of the
contract increased NPC in the test period due to higher costs of the replacement
power. The cost increase from the replacement of this contract is mitigated
somewhat by the increase in revenues from the Reasonable Portion of the contract
with Grant PUD. The expiration of the Meaningful Priority from Grant PUD also
reduces NPC because it was priced at the then-maket price plus a premium. The
net impact of these changes reduces NPC by approximately $3.4 millon on a total
Company basis.
How does decreased hydro generation impact the Company's NPC?
Because hydro generation is a zero cost resource in the NPC calculations, the
reduction in hydro causes the NPC to increase. Ths filing reflects a decrease in
hydro generation of 0.1 millon megawatt hours, or 2.9 percent, when compared
to the amount included in the Company's last rate filing. The reduction in hydro
generation increases NPC by approximately $4.9 millon on a total Company
basis. I wil discuss the changes in hydro generation later in my testimony. All
things being equal, reduced hydro generation wil require the Company to re-
dispatch the system utiizing additional higher cost thermal resources and by
makng additional wholesale market purchases and reduced wholesale market
sales.
Have the wind integration costs increased?
Yes. In the current fiing, the Company uses $6.50 per megawatt-hour, which
was authorized by the Commssion in Case No. PAC-E-09-07, to calculate the
costs of integrating the wind generation into the Company's system. In the
926 Shu, Di - 6
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10 Q.
11 A.
.12 Q.
13 A.
14
15
16
17 Q.
18
19 A.
20
21
22
23.
Company's 2008 general rate case, the wind integration charge was based on the
results from the Company's 2007 Integrated Resource Plan (IRP) at $1.14 per
megawatt-hour for all wind generation. Also, in that case the wind integration
costs for the generation from the Leaning Juniper and Goodnoe Hils located in
the BP A's control area were calculated using the same rate at $1.14 per
megawatt-hour, except the last two months in the test period when BPA added a
wind integration charge in its trnsmission taff rates at $0.68 per kW-month. I
wil discuss furer later in my testimony about the Company's wind integration
costs, and the application of the $6.50 per megawatt-hour in this filing.
Are there other factors decreasing some of these NPC increas?
Yes. System load is lower and the wind gen.eration is higher in the curent fiing.
How much has the Company's system load decreased?
The system load in the curent filing is about 0.5 millon megawatt-hours
(approximately one percent) lower than what was in the 2008 general rate case,
which reduces the NPC by approximately $20.6 millon on a total Company basis.
Dr. Peter C. Eelkema's direct testimony explains the changes in system load.
How much additiomíl wind generation is included in the.test period as
compared with what was in Case No. PAC-E-OS-07?
The NPC in the current filing includes approximately 1.9 millon megawatt-hours
additional wind generation from eight Company-owned wind projects since the
Company's last general rate case. This NPC study includes generation from the
99-megawatt Glenrock, 39-megawatt Glenrock III, 99-megawatt High Plains, 99-
megawatt Rollng Hils, 99-megawatt Seven Mile Hil, 19.5-megawatt Seven Mile
927 Shu, Di-7
Rocky Mountai Power
.1 Hil II and 28.5-megawatt McFadden Ridge I wind projects that are all located in
2 Wyoming. Please refer to the diect testimony of Mr. Mark R. Tallman for
3 additional detal about these resources. The NPC also includes the III-megawatt
4 Dunlap project located in Wyoming that wil be in service in November 2010 but
5 assumed to be in-service for a full twelve months for the curent fiing. Please
6 refer to the diect testimony of Mr. Bird for additional detal about the Dunlap
7 project. For the Company-owned wind facilities, the varable cost is the costs to
8 integrate the intermttent wind generation into the Company's resource portolio.
9 Q.Did the Company adjust for startup costs related to the gas-fired units?
10 A.Yes. Because the GRID model does not capture the starp costs of the gas-fired
11 units that are not included in any other Federal Energy Regulatory Commssion
12 accounts, a line item is added to the NPC report to capture the starp fuel costs of.13 the gas-fired units.
14 Q.Has the Company changed its topology modeled in GRID?
15 A.Yes. To reflect the transmission constraints in the Wyoming area and to ensure
16 the reliability of the transmission network in the area governed by the Western
17 Electricity Coordinating Council ("WECC"), the constrint in the cut plane
18 named Tot 4A in Wyoming has been redefined by PacifiCorp Transmission
19 deparment and approved by WECC. As a result, the previously modeled
20 transmission area of "Wyoming" in GRID has been recefmed.
21 Q.Did the Company model the impact of the new transmission addition
22 between Populus and Terminal?
23 A.Yes. The addition of the Populus to Termal line increases the transmission.
928 Shu, Di - 8
Rocky Mountan Power
.1 capacity across Path C from southeast Idao to nortern Utah by approximately
2 780 megawatts. The additional transmission capacity makes it possible to better
3 utilize the market price differentials between the east and west sides of the
4 Company's system, reduces reliance on additional purchases of transmission from
5 third paries, and improves reliabilty. For fuer detas, please refer to the diect
6 testimony of Company witnesses Mr. John A. Cupparo and Mr. Darell T.
7 Gerrard.
8 Determination of NPC and Model Inputs and Outputs
9 Q.Please explain NPC.
10 A.NPC are defined as the sum of fuel expenses, wholesale purchase power expenses
11 and wheeling expenses, less wholesale sales revenue.
12 Q.Please explain how the Company calculates NPC..13 A.NPC are calculated using the Generation and Regulation Initiative Decision
14 model ("GRID"). GRID is a production cost model that simulates the operation
15 of the Company's power system on an hourly basis.
16 Q.IS the Company's general approach to the calculation of NPC using the
17 GRID model the same in this ca as in previous caes?
18 A.Yes. The Company used the GRID model in its last rate filing in Idaho.
19 Q.IS the Company using the same version of the GRID model as used in Case
20 No. PAC-E-08-07?
21 A.Yes.
22 Q.What inputs were updated for this filing?
23 A.The system load, wholesale sales and purchase contracts for electrcity, natural.
929 Shu, Di - 9
Rocky Mountain Power
.1
2
3
4 Q.
5 A.
6
7
8 Q.
9 A.
10
11
12.13 Q.
14 A.
15
16
17 Q.
18
19 A.
20
21
22
23.
gas and wheeling, market prices for electrcity and natu gas, fuel expenses,
characteristics of the Company's generation facilities, planned outages and forced
outages of the Company's generation resources ar updated for this filng.
Was the transmission topology al updated for this filing?
Yes. The transfer capabilities of the transmission paths have been updated. In
addition, as I mentioned above, the transfer capabilty of Path C to Utah has
reflected the impact of the transmission line from Populus to Termnal.
What reports does the GRID model produce?
The major output from the GRID model is the NPC report. This is attached to my
testimony as confidential Exhibit No. 40. Additional data with more detailed
analyses are also available in hourly, daily, monthly and annual formats by heavy~
load hours and light-load hours.
Has the Company changed its modeling of normalized hydro generation?
No. As in the 2008 general rate case, the normalized hydro generation is
produced by the Vista model, except the enhancement that I wil discuss later in
my testimony.
Are the inputs to Vista prepared in the same way as in the Company's 2008
general rate case?
The historical informtion used as the basis of the normized generation
continues to include all available years, except for the Bear River system. The
Bear River system data excludes flood control years, which is an unlikely event.
The Company is, however, currently in the process of reviewing patterns of
weather and stream flow changes for hydro generation in the context of changes
930 Shu, Di-1O
Rocky Mountan Power
.1 in climate, both globally and in the region. Based on this review, the Company
2 may propose changes to its modeling of normalized hydro generation in future
3 proceedings.
4 Q.Do you believe that the GRID model appropriately reflects the Company's
5 system operations in its operating environment?
6 A.Yes. The use of the GRID model as described in my testimony reasonably
7 simulates the operation of the Company's system consistent with the Company's
8 operation of the system, including operating constraints and requirements.
9 Q.Does the Company propose to update its filing in its rebuttal testimony for
10 material chauges in uet power costs, such as new contracts, fuel costs and the
11 Official Forward Prce Curve, irrespective of whether these changes increase
12 or decrease net power costs?.13 A.Yes. This ensures that the Commssion has the most accurate and current
14 information available to it in setting rates for the test period.
15 Enhancements to the Hydro Modeling
16 Q.Please describe the enhancements to the hydro inputs the Company made in
17 the filing.
18 A.There are two enhancements to the hydro inputs of the GRID modeL. The first
19 enhancement is to apply single-year medan hydro generation. The second
20 enhancement is to explicitly model th reduced generation related to operating the
21 hydro units for reserve purposes that causes "motorig" and efficiency losses.
.
931
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Rocky Mountan Power
.1 average daily or weekly shape and median annual volume of the available
2 historical inflow data, which can range from about 40years to about 90 year
3 depending on the river system.
4 Q.Please explain the reduction in hydro generation due to motoring for
5 spinning reserves.
6 A.In order to meet spinning reserve requirements, the Company must keep
7 generating resources connected to the transmission grid and be responsive to
8 automatic generation control. One option for providing spinning reserves is to
9 "motot' a unit which means the unit is connected to the grid and spinning with
10 electrcal energy rather than with water. At the Swift plant, the normal amount of
11 energy required to motor a unit is about two megawatts. Motoring the unit with.12 two megawatts of energy provides spinning reserve for the full range of unit
13 output. To spin the unit at minimum load with water would require a flow
14 though the turbine of about 350 cubic feet per second, which is extremely
15 inefficient and would consume the equivalent of about 10 megawatts. Even
16 though motoring consumes energy, it is more efficient and cost-effective than
17 spinning a unit with water.
18 Q.What are the efficiency losses the Company proposes to capture in its hydro
19 modeling?
20 A.To provide load following and system regulating requirements, the dispatchable
21 hydro units at the Swift and Yale plants from time to time operate significantly
22 below peak effciency. However, the forecasted hydro generation data from the
.23 Vista model is optimized at peak efficiency. The cumulative effect of load
933
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Rocky Mountan Power
.1
2
3
4 Q.
5 A.
6
7
following with hydro units is less efficient operations. In other words, less energy
is generated with the same amount of water than would have been generated at
peak efficiency.
How does the Company adjust for the lost generation?
The lost generation from the Company's LewisRiver is deducted from its
optimized generation. The amount of the adjustment is based on 2009 historical
information.
8 Wind Integration Charges
9 Q.
10 A.
11.12
13
14
15
16
17
18
19 Q.
20
21 A.
22
23.
What has the Company included for wind integration charges in thi filing?
As discussed previously, the Company used $6.50 per megawatt-hour as the rate
of the wind integration charge for the wind generation located in its control areas.
This rate has been authorized by the Commssion in Case No. PAC-E-09-07 for
the purpose of setting avoided costs. For the two wind projects located in the
BPA's control area, Leaning Juniper and Goodnoe Hils, the wind integration
charge is based on BPA' s tarff rate at $1.29 per kW -month beginning in October
2009 for varations in the wind generation within 30 minutes. This charge is
approximately $5.89 per megawatt-hour based on a 30 percent capacity factor for
the wind resource.
Has the Company updated its wind integration charge since its last general
rate case?
Yes. As par of its 2008 IR filed with the Commssion on May 29,2009, the
Company performed studies on the impact of integrating the generation from the
wind projects into its system.
934 Shu, Di - 14
Rocky Mountain Power
.1 Q.Why doesn't the Company use the wind integration costs from its 2008 IRP?
2 A.To minimize controversy, the Company uses the same wind integration charge
3 that has been approved by the Commssion for setting avoided costs in Idaho. In
4 addition, the Company is in the process of updating the wind integration study as
5 par of its 2011 IRP.
6 Conclusion
T Q.IS the normalized system. wide net power costs for the 12.month period
8 ending December 2010 reflective of costs that the Company wil incur on
9 behalf of its customers and should it be included in rates?
10 A.Yes. The Company's normalized net power costs in the amount of $1.07 bilion
11 on a total Company basis, and $69.2 millon allocated to Idaho is what the.12 Company expects to incur on behalf of its customers. This level of NPC, as
13 updated by the ECAM, is in the public interest and should be included in Idaho
14 rates for recovery by the Company.
15 Q.Does this conclude your direct testimony?
16 A.Yes.
.
935
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Rocky Mountain Power
.
.
.
Q.
2
3 A.
4
5 Q.
6
7 A.
8 Q.
9 A.
10
11
12
13
14
Please state your name, business address and present position with
PacifiCorp dba Rocky Mountain Power (the "Company").
My name is Hui Shu, my business address is 825 NE Multnomah, Suite 600,
Portland, Oregon 97232. My present position is Manager of Net Power Costs.
Are you the same Hui Shu that submitted direct testimony in this
proceeding?
Yes.
What is the purpose of your rebuttal testimony?
The purose of my rebuttal testimony is to respond to the adjustments proposed
by intervening parties to the Company's fied net power costs ("NPC") in the
current proceeding. These adjustments are proposed by Mr. Bryan Lanspery of
the Idaho Public Utilties Commission Staff ("Staff'), Mr. Randall J. Falkenberg
of the PacifiCorp Idaho Industrial Customers ("PIIC"), and Mr. Mark T. Widmer
of Monsanto. In addition to my testimony, Company's witnesses Mr. Chad A.
15 Teply addresses the adjustments proposed by Mr. Falkenberg and Mr. Widmer
16 regarding the Lake Side outage, Colstrip outage and Naughton outages, and Ms.
17 Cindy A. Crane addresses adjustment proposed by Mr. Falkenberg regarding the
18 Jim Bridger fuel quality.
19 Recommendation for Company's Net Power Costs
20 Q.
21 A.
22
Has the Company made changes to its originally fied NPC?
Yes. The Company's system NPC has decreased from $1.07 bilion in the
original fiing to $1.063 bilion.
936
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.1 Q.
2 A.
3
4 Q.
5 A.
6
7
8 Q.
9
10 A.
11.12
13
14
15
16
17
18
19
20
21
22
23.
What are the reasons why the Company's NPC decreased?
This decrease of$6.5 milion reflects corrections and the Company's acceptance
of certain adjustments proposed by Staff, PIIC and Monsanto.
Please summarize the changes in NPC from your direct testimony.
Exhibit No. 71 summarizes the cost impact of the corrections and adopted
adjustments that result in an NPC of approximately $1.063 billon on a total
Company basis, which is $69.0 milion on an Idaho-allocated basis.
Do you have a general comment regarding the level of NPC that the
Company has calculated and the adjustments proposed by other parties?
Yes. NPC and its components are volatile and inherently difficult to forecast.
Actual operation lacks the same certinty and perfect foresight as the optimization
model used to forecast NPC in regards to the variables and constraints, such as
hourly load and market prices, availability of generation and transmission
facilities, and weather conditions that impact the amount of hydro and wind
generation. As a result, the actual operation/dispatch of the Company's resources
may not necessarily achieve what the optimization model projects. That is, the
model optimized NPC tends to understate the actual NPC that would be incurred
for the same period. The Company's net power costs have increased significantly
in recent years. With known changes in the Company's resource portfolio in the
rate effective period, the normalized NPC in a historical test period fuher
understates the costs that the Company prudently incurs to serve its customers. In
the last general rate case, Case No. PAC-E-08-07, the Company agreed to NPC of
$982 milion, given the design of the test period. However, the actual NPC
Shu, Di-Reb - 2
937 Rocky Mountain Power
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9
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13 Q.
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16 A.
17
18
19
20
21
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23
.
during 2008, which was the test period in that case, was $ 1.121 bilion, and the
actual NPC during 2009 when the rates were in effect was $1.022 bilion. In the
curent case, the Company proposed NPC of $ 1,070 milion that would be in
effect during 2011. The Company's recent fiing in Oregon Docket No. VE 216
has shown that the projected NPC in 201 I would be approximately $1,289
milion. The preliminary results indicate that the Company's actual NPC through
September are at approximately $859 milion, or $ I. i 29 bilion for the 12-month
period ended September 20 i O. Given the significant differences between what
the Company proposed in this case and expected actual NPC in the rate effective
period, it is unreasonable to make further adjustments to reduce the modeled NPC
that wil be used to set base rates beginning January 1,2011, especially when the
adjustments are as significant as the ones proposed by Staff, PIIC and Monsanto.
The Commission has authorized an Energy Cost Adjustment Mechanism
("ECAM") for the Company. Doesn't the implementation of ECAM resolve
the under-recovery risks of NPC?
No. As noted by Mr. Widmer the "review and determination of the appropriate
NPC is very important because it represents one of the Company's single largest
revenue requirement components and establishes the ECAM baseline." i The
amount that the Company is authorized to recover under the ECAM is based on
the differences between actual NPC and the base NPC included in rates durg
that period. Curently the Company's ECAM has a 90/10 sharng band. Because
of the sharing band the Company is effectively limited to not recover all of the
prudently incurred NPC in the rate effective period when actual NPC are.i Direct testimony of Mark T Widmer page io lines 14-16.
938
Shu, Di-Reb - 3
Rocky Mountain Power
.1 projected to be higher than what the Company proposes in the current case.
2 Company Responses to Specific Adjustments - Overview
3 Q.
4
5 A.
How have you organized your responses to the parties' modeling adjustments
to NPC?
I have grouped the parties' proposed NPC modeling adjustments into three
6 categories. First, there are adjustments to which the Company has agreed in
7 whole. Second, there are adjustments to which the Company has agreed in part,
8 or in response to which the Company has proposed a different position. Third,
9 there are proposed modeling adjustments that the Company disputes as
i 0 inaccurate, unsubstantiated, or inconsistent with normalized ratemaking.
1 1 Corrections and Adjustments Accepted in Whole.12 Q.
13 A.
14
15
16
17
18
19
20
21
22
.
Has the Company made any corrections since its initial fiing?
Yes. After the initial fiing, the Company has identified and provided in response
to a Monsanto data discovery (Monsanto Data Request 2.33) three corrections:
. Dunlap was modeled without reserve requirements;
. STF transmission from southeast Idaho to northern Uta was not removed
after the inclusion of the Populus to Terminal transmission line addition;
and
. The UAMPS Use of Facilities wheeling expense should have been
excluded
Correcting these three items increases the Company's system NPC by
approximately $0.1 milion.
939
Shu, Di-Reb - 4
Rocky Mountain Power
.I Q.Has the Company accepted any adjustments proposed by Staff, PIle or
2 Monsanto?
3 A.Yes.The Company has accepted the following proposed adjustments:
4 .Commitment Logic Screens (PILC Adjustment I): As proposed by PIlC,
5 the Company agrees to modify its daily screens consistent with the
6 methodology set fort in the parties' stipulation in Oregon Docket UE
7 216. This change results in a decrease to system NPC of approximately
8 $ 1.7 milion. As discussed later in my testimony, the Company does not
9 agree that this adjustment changes incremental O&M expenses included in
10 the test year, as these expenses were not included in the test year.
11 .Inter-hour Wind Integration Costs of Non-Owned Resources (corrected.12 PILC Adjustment 4, and portion of Staff wind integration costs adjustment
13 and portion of Monsanto Adjustment 2): The Company agrees to remove
14 inter-hour wind integration costs associated with the wind projects that are
15 located in the Company's balancing areas but do not deliver generation to
16 the Company's system.PIlC's inter-hour wind integration adjustment
17 needs to be corrected by removing the wind generation that the Company
18 receives under contract with Seattle City and Light ("SCL"). This
19 adjustment results in a decrease to system NPC of approximately
20 $1.4 milion.
21 .Colstrip Planned Outages (Monsanto Adjustment 8). The Company
22 agrees to this adjustment that moves the timing of planned outages of the
23 two Colstrp units from fall to spring. This reduces the system NPC by.Shu, Di-Reb - 5
940 Rocky Mountain Power
.
.
.
I approximately $0.2 milion.
2 .Modeling of Mona Market (Monsanto Adjustment 14). The Company
3 does not agree to the concept and logic of this adjustment. However,
4 given the complexity around modeling all market caps in GRID, rather
5 than selectively making adjustments to only one market for the selected
6 time periods, the Company accepts the amount of adjustment proposed by
7 Monsanto in the curent case and wil review the overall modeling of
8 market caps in the futue. This reduces the system NPC by approximately
9 $0.4 milion.
10 Adjustments Accepted in Part
11 APS Supplemental Adjustment (Staff's APS Supplemental Adjustment, Monsanto
12 Adjustment 1)
13 Q. Please explain the issue raised by Staff and Monsanto with respect to the
14 APS Supplemental contract.
15 A.Staff and Monsanto state that the Company's modeling of the APS Supplemental
16 contract causes uneconomic dispatch of the contract, and the contract should be
17 removed. The proposed adjustment would reduce system NPC by $1.9 millon.
18 Q.Does the Company agree with the proposal?
19 A.No. Contrary to what Staff indicates as an inconsistency, the Company's
20 modeling consistently reflects the fact that the Company has historically
21 purchased energy from APS under the terms of the contract. It is not reasonable
22 to arbitrarily remove this contract simply based on modeling results.
941
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Rocky Mountain Power
.
.
.
I Q.
2 A.
3
4
5
6
7
8
9
10
11
12 Q.
13
14 A.
15
16
Please describe the APS Supplemental contract.
The Company executed the Supplemental contract in 1990 with the Arizona
Public Service Company ("APS") and has included it in NPC in Idaho since that
time. Under the contract, APS makes available to the Company two categories of
supplemental firm energy, coal ("APS Coal") and other ("APS Other"). At
present, per the terms of contract, APS is obligated to offer the Company 219,000
megawatt-hours of firm energy on an annual basis priced at its incremental cost of
coal generation, and 876,000 megawatt-hours of firm energy from other sources
that are primarily natual gas-fired resources. The two categories of firm energy
cannot be offered at the same time. APS is obligated to offer the energy, but the
Company only takes the energy when it is economical to do so.
Has the Company modified the modeling of the APS Supplemental contract
in the current rebuttal filing?
Yes. The new approach to modeling this contract eliminates the increases to NPC
when the contract is dispatched. The Company has aligned the timing and pricing
of the deliveries with historic experience, rather than aligning the volume of
i 7 deliveries with historic volumes, GRID now exercises the call option on the
18 available energy when it is economical to do so. This change reduces the
19 Company's fied system NPC by approximately $2.6 millon.
20 Non-firm Transmission (Staff NF Transmission Adjustment, Monsanto Adjustment 3)
21 Q.
22
23 A.
Please explain Staff's and Monsanto's positions on the modeling of non-firm
transmission.
Staff and Monsanto recommend that the Company should include non-finn
942
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Rocky Mountain Power
.
2
3
4
5
6 Q.
7 A.
8
9
10
11.12
13 Q.
14
15 A.
16
17
18
19
20
21
22
23.
transmission in GRID. Staff and Monsanto modeled non-firm transmission using
a four-year historical average to adjust the capacity of link in the GRID model
topology and using a dollar per megawatt-hour energy charge to calculate
expenses. Staff's and Monsanto's proposed adjustments would reduce system
NPC by $2.5 milion and $2.4 milion, respectively.
What is the Company's response to Staff's and Monsanto's proposal?
The Company agrees to model non-firm transmission in GRID. However, ifnon-
firm transmission is included in the model, it should be included on the same
basis as short-term firm transmission. There is no basis for using a different
method for non-firm transmission than for short-terni transmission. Both types of
transmission should be modeled using a four-year average to adjust the capacity
link in the GRID model topology and the most current year of expenses.
Please explain why non-firm transmission should be modeled the same as
short-term firm transmission.
In the process of reviewing how the Company has utilized non-firm transmission,
it is clear that the Company purchases and uses short-term firm and non-firm
transmission in the same way. The transmission providers offer certain amount of
transmission capacity as firm products, and the rest as non-firm. The only
difference between the two products is that non-firm transmission wil be cut first
for reliability of the transmission system. For both short-term firm transmission
and non-firm trnsmission, the wheeling expenses are incured whether the
transmission capacity purchased is fully utilized or not. As a result, the Company
has modeled the non-firm transmission capability based on a four-year average of
943
Shu, Di-Reb - 8
Rocky Mountain Power
.
2
3 Q.
4 A.
the historical purchases of non- firm transmission, and the expenses estimated
based on what was incurred in the base period of the current filing.
What is the impact on NPC of including non-firm transmission in GRID?
Including non-firm transmission using an approach that is consistent with the
5 modeling of short-term firm transmission decreases system NPC by
6 approximately $ 1.2 milion.
7 Top of the World Wind (Monsanto 6)
8 Q.
9
10 A.
11.12
13
14 Q.
15 A.
16
17
18
19
20
.
Please describe the adjustment proposed by Monsanto for the power
purchase contract with Top ofthe World Wind.
Monsanto proposes to reflect the actual in-service date of the contract, which is
one month earlier than what the Company has included in its original fiing, but
exclude the wind integration costs related to the wind generation. This
adjustment would increase system NPC by $ 1.6 milion.
Does the Company agree with this adjustment?
Partially. In addition to the impact of additional purchase expenses, the additional
wind generation would lead to additional wind integration costs, which is a
subject that I wil discuss later. Applying the same methodology as the Company
applied for all other wind generation, the additional energy purchased from Top
of the World Wind increases system NPC by approximate $1.9 millon, including
additional wind integration costs.
944
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Rocky Mountain Power
. 1 Company Responses to Contested Adjustments
2 Wind Integration Costs (Staff Wind Integration Costs Adjustment, PIIC
3 Adjustment 5, Monsanto Adjustment 2, 2a and 2b)
4 Q.
5
6
7 A.
8
9
10
11
12.13
14
15
16
17
18
19
20
21 Q.
22
23 A..
What have Staff, PIIC and Monsanto proposed with respect to the overall
wind integration costs and the wind integration costs of the OA TT
customers?
Staff s proposal is to remove the entire amount of wind integration costs from the
Company's filing, which would reduce the Company's system NPC by
approximately $34.2 milion. PIlC proposes to remove the intra-hour wind
integration costs associated with integrating non-owned wind projects that are
interconnected to the Company's transmission system, which would decrease the
Company's system NPC by approximately $4.3 milion. Monsanto proposes
various versions of adjustments to the Company's wind integration costs,
including the same proposal as the Staff to remove the $34.2 milion of the total
wind integration costs, a similar proposal to PIIC is to remove the wind
integration costs of the non-owned wind projects that would reduce the
Company's system NPC by approximately $6.4 milion, or to include the wind
integration costs for the portion of the test period that incorporated the actual
wholesale transactions and reduce the Company's system NPC by approximately
$2.6 milion.
Do you see any basis to the proposals made by Staff and Monsanto to exclude
the entire wind integration costs?
No. The proposals seem to be made based on three general arguments. First, the
945
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7 A.
8
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19
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21
22
.
wind integration charge that the Company used is for setting avoided costs rates
and not for setting retail rates. Second, the wind integration costs "are neither
paid under contract or to any other utility." Third, the costs should be captued in
the Company's ECAM. Their arguments to support their adjustments are
contradictory and ilogicaL.
Please explain.
In Case No. PAC-E-09-07, after considering the Company's proposed wind
integration costs and parties' positions on such costs, the Commission adopted a
wind integration charge that was lower than what the Company proposed and
authorized the Company to use $6.50 per megawatt-hour charge in determining its
avoided costs for wind qualifying facilities in Idaho. Neither Staff nor Monsanto
provides any evidence that would explain why this charge is appropriate to apply
to wind qualifying facilities, but not appropriate to apply to Company-owned
facilties or non-qualifying facilty purchased power agreements. It is also unclear
whether Staff or Monsanto is suggesting that by applying this charge, the prices
for wind qualifyng facilities located in Idaho are understated and whether the
retail customers should pay more for the two qualifying facility contracts that are
listed in Mr. Lanspery's testimony. While implying that the Company's wind
integration costs are not real ("neither paid under contract or to any other utility"),
Staff states that the Company's wind integration costs are captured in actual test
period expenses and reflected in a number of accounts. 2 In addition, if the
proposal of removing the wind integration costs from the Company's filing is
.2 Staffs testimony onpage 5, lines 20 through 22 suggest that the reference to 2009 may need to be 2010.
Otherwise, the discussion on a 2009 test period would be irrelevant in the curent proceeding.
Shu, Di-Reb - I I
94 6 Rocky Mountain Power
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7 Q.
8
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10 A.
11
12
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21
22
23
.
.
based on the fact that the wind integration costs are of significant size, difficult to
calculate, and the Company may capture such costs in its ECAM filings, then the
same argument may be made to the wholesale sales revenues: the Company's
wholesale revenues are large, the actual amount of revenues in a year never
matches the amount that has been projected, and as a result, the Company could
use the ECAM fiings to capture such revenues.
Staff indicates that in the testimony requesting the ECAM, the Company
stated that the ECAM was designed to capture the volatilty, including the
wind variabilty. How do you respond?
It is correct that the ECAM is designed to capture the volatilty in NPC that
occurs in relation to a properly set base NPC. However, the wind integration
costs are not the same as the vanation in NPC that the ECAM is designed to
capture. Instead of addressing the variation between normlized and actual wind
generation as the ECAM is designed for, wind integration costs are costs incured
due to additional reserve requirements to integrate the intermittent generation
from the wind projects into the Company's portfolio of resources. The additional
reserve requirements include regulating services that deal with wind varability in
ten-minute interval, and load following services that deal with wind varability
over hourly time intervals. Both services should respond to the up and down
vanations inherent in wind facilities. That is, the additional reserve requirements
to integrate wind generation into the Company's resource portfolio takes on the
forms of regulation up, regulation down, load following up and load following
down.
947
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.
.
In proposing to remove the wind integration costs, Staff never explained
why such costs, which are reflected in a number of accounts, simply should not be
part of the normalized studies, or at least not "explicitly". The Company could
have modeled the wind integration costs "implicitly" by incorporating the
additional reserve requirements in GRID, which would certainly lead to a value
that is higher than $6.50 per megawatt-hour. The Company applied a simplified
calculation using a Commission-authorized value that is lower than what the
Company believes it to be in an attempt to minimize the controversy. In addition,
since the ECAM is designed to capture the differences between actual NPC and
the baseNPC, the base NPC should reasonably account for all components,
including the wind integration costs.
Staff stated that the Commission has never expressly approved wind
integration costs in any utilty's general rate case. Do you believe that this is
a precedent to follow?
No. The fact that the Commission has never expressly approved such costs does
not mean that the costs do not exist or are not prudently incurred. The Company's
wind resources have increased significantly in recent years. The subject of wind
integration costs has received more and more attention in recent years. The
Company is not the only utility that has recognized the cost impact of integrating
wind generation into its resource portfolio. By allowing the wind integration
costs charged by the Bonnevile Power Administration ("BP A"), Staff and
Monsanto agree that the Company prudently incured wind integration costs in
serving its customers at approximately $5.89 per megawatt-hour.
948
Shu, Di-Reb - 13
Rocky Mountain Power
.1 Q.One of Monsanto's arguments for removing wind integration costs seems to
2 be the fact that the Company is unable to calculate its actual wind
3 integration costs, and without knowing the actual costs "it is very diffcult to
4 determine the reasonableness of Company's requested recovery." How do
5 you respond?
6 A.First of all, as Mr. Widmer is aware, the Company operates its resource portfolio
7 to serve all its obligations, and does not differentiate what resources are used for
8 serving which obligations. As such, the Company can only estimate the impact of
9 wind integration costs. Second, if Mr. Widmer is looking for references to check
10 if the Company's wind integration costs are within reasonableness, he only needs
11 to look at the wind integration charge that BP A imposes, the wind integration.12 study that the Company used in proposing wind integration costs for avoided
13 costs, wind integration costs that he quoted in his testimony from the Company's
14 last Integrated Resource Plan ("IRP"), and the wind integration costs of $6.63 per
15 megawatt-hour that were approved by the Public Service Commission of Utah in
16 the Company's last general rate case Docket No. 09-035-23.
17 Q.Why do PIIC and Monsanto propose disallowing intra-hour wind integration
18 charges associated with non-owned wind facilties in the Company's
19 balancing areas?
20 A.PIIC argues that the Company should not include the wind integration costs
21 incurred by providing wind integration services to the non-owned wind projects
22 because the Company does not have a transmission tariff to recover the costs from
23 those customers.The proposal would reduce system NPC by $4.3 millon.. As a.Shu, Di-Reb - 14
949 Rocky Mountain Power
secondary proposal, Monsanto also proposed the same adjustment, which would
reduce system NPC by $6.4 millon.
Are there any errors in the adjustments by PIIC and Monsanto?
Yes. The adjustments proposed by PIlC and Monsanto are both incorrectly
calculated because, in addition to generation from the non-owned wind projects,
their adjustments exclude the generation under the contract between the Company
and SCL. Per the terms of the contract, the Company receives wind generation
from the portion of the Stateline wind project owned by SCL and then returns
firm and shaped energy to SCL. In addition, Monsanto's adjustment also includes
an adjustment for inter-hour wind integration for the wind projects that are located
in the Company's balancing areas that the Company has interconnected.
Why doesn't the Company charge wind generators for wind integration costs
that are located in the Company's balancing areas but do not provide
generation to the Company?
The Company could not charge wholesale transmission customers for this tye of
service without FERC approval of a rate application proposing a new wind
integration charge. The Company is required by federal law to interconnect with
new facilities under the terms of its Open Access Transmission Tariff ("OA IT").
Once the Company interconnects a new facility to its transmission system, it is
responsible for integrating it into the system.
Are there barriers to charging non-owned wind facilties for wind integration
costs?
Yes. Modifying the Company's OATT to impose wind integration charges on
Shu, Di-Reb - 15
950 Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10
11
12
13
14
15 Q.
16 A.
17
18
19
20
21
22
23
.
.
only non-owned wind facilities would violate the federal statutory mandate that
the Company treat all transmission customers, affiiated and non-affiiated, on a
not unduly discriminatory basis. In addition, there is little regulatory guidance
from FERC in this area with respect to what FERC wil ultimately consider to be
an adequate proposal for a wind integration charge. Although FERC
conditionally accepted a proposal by We star to add a new Schedule 3A charge,
whereby all variable generators located within Westar's balancing area pay a
regulatory service fee for power exported outside of the balancing area, recently,
FERC rejected Puget Sound Energy's proposed revision to its OATT to add a new
charge applicable to all wind generators for wind integration within-hour
generation following service. In each case, wind industry advocates vigorously
protested the proposed tariff revisions because, among other issues, the proposed
charges constituted significantly higher regulatory service fees to intermittent
resources than for dispatchable resources.
Does the Company plan to raise this issue in its next FERC rate case?
Yes. The Company plans to fie a rate case with FERC no later than June 1, 2011,
in which the Company wil include a proposed wind integration charge in its
trnsmission tariff rates pending any FERC guidance on the issue. The Company
completed a wind integration study in conjunction with its 2010 Integrated
Resource Plan and is in the process of reviewing comments from parties regarding
the study. It is hoped that the study can be used in the development of a wind
integration charge proposed to be added to the OATT, however, no determination
has yet been made. The Company is closely tracking all developments at FERC
951
Shu, Di-Reb - 16
Rocky Mountain Power
.1
2
3 Q.
4 A.
5
6
7
8
9
10
11
12 Q.
13
14 A.
15
16
17
18
19
20
21
22
.
.
related to wind integration and is bound to follow any guidance FERC may issue
in this regard.
Are the costs associated with wind integration a prudent expense?
Yes. As a balancing area authority, the Company must operate its balancing areas
by matching system resources to actual load and generation fluctuations on a
moment-to-moment basis through automatic generation control. Maintaining
system balance is one of the key fuctions of a balancing area authority who is
required to maintain system reliability, including maintaining system frequency.
Load fluctuations, outages, and generation output fluctuations all contribute to the
need for balancing resources. The addition of renewable resources such as wind
has the tendency to increase the need for balancing resources.
What are the benefits to the Company's retail customers of providing such
services to the non-owned generation?
As a balancing area authority, the Company owns and operates an extensive
transmission network that it is required to operate safely and reliably for all of its
customers, keeping all resources and loads in balance on a moment-to-moment
basis. By providing wind integration services in addition to other transmission
related services as a balancing area authority, the Company ensures that its
customers are served by a reliable system with diverse resources. Moreover, any
transmission revenues received from non-owned generation, which pays wheeling
to the Company, are credited against retail rates and therefore have the effect of
lowering retail rates.
952
Shu, Di-Reb - 17
Rocky Mountain Power
.1 Q.
2
3 A.
4
5
6
7
8
9
10
11
12 Q.
13 A.
14
15
16
17
18
19
20
21
22
23
.
.
What adjustment does Monsanto propose to the Company's inter-hour wind
integration costs?
If the Commission does not agree with Monsanto's proposal to remove the entire
wind integration costs from the Company's filing then Monsanto proposes a
secondary adjustment. Monsanto claims that the inter-hour wind integration costs
for balancing purposes have already been included in the Company's fiing
through the inclusion of actual short term firm transactions, and by calculating the
inter-hour wind integration costs for the period from January 1 to May 4, 2010,
the Company double counted the wind integration costs. The adjustment would
reduce Company's system NPC by $2.6 millon for inter-hour wind integration
costs from Januar to ApriL.
What is your response to the proposal?
I don't agree with the proposal. Monsanto's own arguments present
contradictions. On one hand, Mr. Widmer claims that the inter-hour wind
integration costs have been included for the first four months of the test period
because the Company has included actual short term firm transactions though
that period. Then on the other hand, Mr. Widmer also agrees that "(t)he Company
has a variety of options for balancing," and these options include redispatch of all
flexible resources, firm and non-finn wholesale contracts, generation and wind
curtailment. The Company has included actual short term firm transactions in its
filing. However, those transactions are only a small portion, if any, of the
resources that the Company utilzes to integrate generation from wind facilities
into its system. In its fiing, the Company has included wind generation at the
953
Shu, Di-Reb - 18
Rocky Mountain Power
.expected level that lacks the significant varability as in actual generation. As
2 such, the generation from all other flexible resources is also at the level that does
3 not reflect the impact of the significant variability in actual wind generation and
4 the costs of integrating such generation into its system.
5 Q.Are there other problems with Monsanto's proposal?
6 A.Yes. While not accepting the Company's wind integration costs at $6.50 per
7 megawatt-hour, Mr. Widmer uses the Company's wind integration at $6.92 per
8 megawatt-hour as a reasonable approximation to split the intra-hour and inter-
9 hour wind integration costs. In addition, it is unclear what Mr. Widmer implies
10 by stating that further adjustment could be made to what he has proposed in
11 relation to various other means. Ifthe reference were to the flexible resource
12 indicated above, the Company's NPC in the proceeding has not considered the.13 impact of significant fluctuation in wind generation on other resources because
14 they are all modeled on a normalized basis. If the reference were to the additional
15 sales transactions that the Company could make, Mr. Widmer would be double
16 counting the presumed impact that he calculated based on short term firm
17 transactions, which would have included both sales and purchases.
18 Q.What do you recommend the Commission do regarding various proposals to
19 remove all or portion of the wind integration costs that the Company has
20 included in the case?
21 A.With the exception of inter-hour wind integration costs discussed earlier in my
22 testimony that the Company agrees to remove, the Commission should reject all
23 other adjustments proposed by Staff, PILC and Monsanto..Shu, Di-Reb - 19
954 Rocky Mountain Power
.Bear River Hydro Normalization (Staff Bear River Hydro Generation Adjustment,
2 Monsanto Adjustment 12)
3 Q.
4 A.
5
6
7
8
9
10 Q.
11 A..12
13
14
15
16 Q.
17
18 A.
19
20
21
22
23.
What was the issue on the Bear River normalization?
The Company modeled the normalized generation from the Bear River system
based on history, excluding the flood control years. Staff and Monsanto argued
that the Company should not have reduced hydro generation from the Bear River
system based on long-term drought conditions on the Bear River, and recommend
using the historical average generation from the Bear River system. The
adjustments would reduce the Company's system NPC by $2.2 milion.
Does the Company agree with Staff and Monsanto's argument?
No. The water available for generation at the Bear River facilities is dependent
on contractually specified irrigation and flood control releases from Bear Lake.
Flood control on the Bear River is an operational constraint and releases of
water
for flood control have not been available to the Company since 2001. The usual
manner of normalizing hydro requires adjustments for operating constraints.
Please explain the contractual controls over discharges of water from Bear
Lake.
Those contractual controls include: (1) The 1958 Bear River Compact approved
by the United States Congress which prohibits the release of water from Bear
Lake solely for power generation below the irrgation reserve level of elevation
5,914.61 feet; (2) the 2000 "Operations Agreement for PacifiCorp's Bear River
System," which requires that the Company operate Bear Lake primarily for
irrigation and flood control. This agreement was required by Idaho, Wyoming,
955
Shu, Di-Reb - 20
Rocky Mountain Power
.
2
3
4
5
6
7
8
9
10 Q.
11.12 A.
13
14
15
16
17
18
19
20
21
22
23.
and Utah as a condition for approving MidAmerican Energy Holdings Company's
acquisition ofPacifiCoip; and (3) recently, the Company began modeling the
impact of the new operating constraints required by the 2003 license for FERC
Project #20, including the Grace Plant on the Bear River system, which mandates
increased bypass flows below Grace dam for ameliorating fisheries and aquatic
issues and to provide recreation opportnities (e.g., white water boating). Water
released into the river channel below the dam bypasses the turbine and cannot be
used for generation. This alone reduces total generation available from the Bear
River by an estimated i 9,000 megawatt-hours.
Please provide background on how the Company modeled Bear River
generation in the last case.
The dams on the Bear River have three potential sources of water for generation:
natural inflow, water withdrawn from Bear Lake to supply downstream irrigators,
and water withdrawn from Bear Lake for flood control puiposes. The Company's
operating agreements for the Bear River system referred to above prohibit the
Company from withdrawing water from Bear Lake for generation and flood
control puiposes unless the lake elevation exceeds a certain leveL. For the past 10
years, and for the foreseeable futue assuming median streamflow into Bear Lake,
this operational constraint has and wil prevent the Company from operating the
Bear River system with flood control releases. The lake elevation is projected to
drop to about 5,910 feet at present, which is 11 feet below the 5,921 feet elevation
level that allows the Company to release flood control storage.
The Company previously modeled the Bear River system using historical
Shu, Di-Reb - 21
956 Rocky Mountain Power
.
.
.
1
2
3
4
5
6
7
8
9 Q.
10
11 A.
12
13
14
15
16
normalized hydro generation for all three operational modes that included water
supply from natural run-off, irrgation deliveries, and flood control releases,
without considerig the operational constraints around flood control operations.
After a careful review, the Company concluded that the flood control mode of
operation has now effectively become unavailable, and the Company has begun
accounting for this operational constraint in its rate filings and operations
planning by excluding the generation using the flood control water in its
normalized hydro generation.
What has been the generation from the Bear River system in the recent
history?
Figure 1 below shows the actual generation from the Bear River system from
1979 to 2009 water year (October of the previous calendar year to September of
the current year), which is the base period applied in the current proceeding. The
unshaded bars identify the flood control years. It is clear that the generation
during the flood control years is significantly higher than the non-flood control
years. The actual generation through 20 lOis also added to the Figure.
957
Shu, Di-Reb - 22
Rocky Mountain Power
.
.
.
1
2 Q.
3
4 A.
5
6
7
8
9
Figure 1 Actual Generation from Bear River
800,000
700,000
600,000
500,000
400,000
300,000
200,000
100,000
o
r--
___H_'__,___"__'H_'.__._------------
-i -
ilJ
I~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~
September 2010 is preliminary.
How does the normalized hydro generation from the Bear River system
compare with actual generation?
Figure 2 below shows the comparison of historical generation that is unadjusted
for any known and measurable changes, such as rules and regulations, over the
years, normalized generation in the current proceeding as proposed by the
Company and by Staff and Monsanto, and the most recent actual generation. It is
clear that the normalized generation in the Company's fiing is more
representative of the expected generation from the Bear River system.
958
Shu, Di-Reb - 23
Rocky Mountain Power
.1 Figure 2 Bear River Generation Comparison
.2 Q.
3
4 A.
350,000
300,000
250,000
.s 200,000
~
:E 150,000
100,000
50,000
L
o
1979-2008 1979-2008 1979.2008
Average Median Median, w/o
Flood Control
IOGRC Staff and
Monsanto
Water Year Water Year I
2009 Actu.i 2010 Actu.i J
September 2010 is preliminary.
What then is the consequence of adopting Staff and Monsanto's proposed
adjustment for Bear River normalization?
Adopting Staff and Monsanto's proposal would lead to overstating hydro
5 generation, and understating NPC as a result of not incorporating this operational
6 constraint in normalizing historical generation. I recommend the Commission
9 Q.
10 A.
11
12
13.
7 reject the adjustment proposed by Staff and Monsanto.
8 Start Up Energy (PILC Adjustment 2)
Please explain PIlC's proposal for the value of start-up energy.
PILC proposed that the Company include the energy associated with starting up
Currant Creek, Lake Side, and Chehalis in NPC because the fuel costs of star-ups
are included in NPC. The adjustment would decrease the Company's system
NPC by $1.7 milion.
Shu, Di-Reb - 24
959 Rocky Mountain Power
.Q.
2 A.
3
4
5
6
7
8
9 Q.
10 A.
11
12
13
14
15
16
17
18
19
20
.
.
What other costs are incurred when starting up the gas-fired plants?
Start-up costs are not limited to fueL. In order to accommodate the start-ups of a
500 to 600-megawatt gas unit, the Company must re-dispatch the system. In
doing so, the Company incurs costs beyond what it would have incurred had the
star-ups not occurred. These costs could result from ramping down the lower-
costs hydro and thermal units to lower effciency levels, and increasing generation
from higher-cost units prior to when they are needed. None of these costs are
included in GRID.
Did PIIC's proposal contain technical errors?
Yes. In calculating the value for the start-up energy, PIIC violated the
requirement of the minimum down time required for units to stay offine before
returning to service. This is due to the fact that GRID allows units to sta
instantaneously. However, if start-up energy is to be considered, the multi-hour
start-up sequence must also be considered. The end result is that the units would
need to stay offine and be unavailable for a longer time in order for PIIC's
adjustment to be even applicable. The prolonged downtime would lead to
increases in NPC by approximately $4.7 milion from what the Company included
in its original fiing on a total Company basis, which offsets the $1.7 milion
assumed value of the start-up energy. As a result, I recommend the Commission
reject PIlC's adjustment.
960
Shu, Di-Reb - 25
Rocky Mountain Power
.1 Normalization of Call Option Contracts (PIIC Adjustment 3, Monsanto Adjustment
2 13)
3 Q.
4
5
6 A.
7
8
9
10
11 Q..12 A.
13
14
15
16
17
18
19
20
21
22
23.
What were the adjustments that PIIC proposes to the modeling of the SMUD
sales contract and Monsanto proposes to the modeling of the Black Hils sales
contract?
PIIC proposes to substitute actual data for normalized data for the sales contract
with the Sacramento Municipal Utility District ("SMUD"), and Monsanto
proposes similar adjustment for the sales contrct with Black Hils Power ("Black
Hils"). The adjustments would reduce the Company's system NPC by $1.6
milion and $1.3 millon, respectively.
Do you have any general comments about the two proposals?
Yes. For normalized purposes, the GRID assumes that the counterparties - who
control the call options on these two contracts - will maximize the value of the
contracts and tae power at the most economical time. GRID assumes
optimization of all flexible resources, while PIlC's and Monsanto's proposals
embody an approach of optimizing flexible resources when it lowers NPC and not
optimizing flexible resources when it raises NPC. It was based on the assumption
that the Company acts rationally and other companies act irrationally. PIlC's and
Monsanto's proposals vi.olate any reasonable principles of consistency and
fairness. . If NPC are to be set using an optimization model, then all resources and
contracts that are subject to being optimized should be optimized. This is the same
argument used by Staff and Monsanto in their proposed treatment of the APS
Supplemental contract where they propose that actual historic energy take under
Shu, Di-Reb - 26
961 Rocky Mountain Power
.the contract should be rejected in favor of optimizing the contract in GRID.
2 Q.Please explain.
3 A.The proposed adjustments depart from modeling power costs on a normalized
4 basis. If this tye of modeling adjustments were adopted, then consistency and
5 fairness require its application to all other flexible purchase or sale contracts that
6 are modeled in a similar fashion to the SMUD and Black Hils contracts. For that
7 matter, it should also be applied to flexible generating resources. Optimization of
8 the Company's system operations decreases NPC on a net basis. PILC and
9 Monsanto have not proposed "de-optimization" across the board, which would
10 increase NPC. Nor have PIlC and Monsanto provided any justification for
II selective "de-optimization" of only two call option sales contracts, rather than all
12 purchase and sale contracts and flexible generating units..13 Q.Why is it important to treat third party contracts the same whether the
14 Company is sellng or purchasing energy?
15 A.Use of any delivery patterns other than the optimized delivery patterns wil
16 always lower net power costs for wholesale sales contracts with flexibility such as
17 the SMUD and Black Hils contracts. The opposite is true for purchased power
18 contracts that give the Company flexibility in how the power is taken. It is not
19 fair or consistent to normalize different contracts using different rules.
.
962
Shu, Di-Reb - 27
Rocky Mountain Power
.1 Q.
2
3
4
5 A.
6
7
8
9
10
11
12
13
14
i 5
16
17
18
19
20
21
.
.
How do you respond to the arguments made by PIIC and Monsanto that
flexible wholesale sales contracts should not be optimized because the
Company has not modeled any of the loads, constraints, or forward price
curves used by the counterparties?
It is correct that the Company does not model the counterparties' systems due to
the impossibility of obtaining the data that are proprietary to those counterparties.
However, given that the Company is only one of the many participants in the
market, the only assumption is to assume that all the participants in the same
market are rational and wil exercise their rights to the flexible contract to lower
their costs. This is confirmed by Black Hils as presented on page 2 of Exhibit
No. 72, which was an exhibit to Mr. Falkenberg's testimony in the Company's
2009 Wyoming general rate case, Docket No. 20000-352-ER-093, where it states:
"BHP wil captue the maximum contract value by taking delivery of the contract
energy to serve load or faciltate market sales." This is exactly what the
Company's method of optimization captures, and what is demonstrted in Exhibit
Nos. 73-75. Exhibit No. 73 shows the actual delivery taken as a whole, and that
the pattern of this energy delivery may appear to be flat. However, looking at the
same data, but by HLH and LLH and by location where the energy was delivered
in Exhibit Nos. 74 and 75, it is clear that Black Hils exercised their rights based
on price signals from the market, taking more energy when and where market
prices were relatively higher.
3 Both Mr. Falkenberg and Mr. Widmer were consultants to Wyoming Industral Energy Consumers
("WIEC") in that proceeding.
963
Shu, Di-Reb - 28
Rocky Mountain Power
.
.
.
Q.
2 A.
3
4
5
6
7 Q.
8
9 A.
10
11
12
13
14
15
16
17
How is the SMUD contract structured?
In addition to the firm energy component that is modeled in GRID explicitly,
SMUD also has the right to take provisional power from the Company under the
terms of the same contract, which wil be returned in full to the Company next
year. For the normalized calculation, the Company assumes the take and return of
the provisional power are equal and matching in the test period.
Does the historical data display SMUD's preference on when to take energy
under the contract?
Yes. When both ofthese are taken together, it is clear that SMUD intends to take
energy with preferences by season. Figure 3 below shows the monthly pattern of
the total firm and provisional sales in a four-year period. Based on the historical
pattern, it would be reasonable to assume that without the flexibility of the
provisional portion of the contract, SMUD would shape their take of the firm
portion with a similar seasonal pattern. PIlC's proposal only considers the firm
portion of the contract, and suggests that SMUD would take more energy in
spring than in fall as if SMUD would not have considered their rights to the
provisional energy.
964
Shu, Di-Reb - 29
Rocky Mountain Power
.I Figure 3 Historical Shape of Energy Take by SMUD
-
--..-------..........-_..__..----......----_..----_..-----------------------------_..----_....---..----_....---_.._-_....--_....---
------------------_......---------
80,000
70,000
60,000
50,000
40,000
~30,000:¡
20,000
10,000
0.
2 Q.
3 A.
4
5
6
7
8
9
10
11.
~~""~§?t ?t9:ic:a c:a c:a c:a.!.!.!.!
I II Finn . Provisional I
Does the Company model any contracts based on actual historical data?
Yes. The Company models non-flexible contracts, such as the ones with GP
Camas, Biomass, and small purchases, based on historical information because
none of these contracts provide the Company the kind of flexibilities that are
provided for under the terms of the call option sales contracts. Based on the
principle of known and measurable information, the only information known to
the Company is the history of those contracts. I recommend the Commission
reject the adjustments proposed by PIIC and Monsanto on the basis that the
adjustments violate the fairness in the optimization of all flexible resources to
reduce NPC.
965
Shu, Di-Reb - 30
Rocky Mountain Power
.
2 Q.
3 A.
4
5
6 Q.
7 A.
8
9
10 Q.
11 A.
12.13
14
15
16
17 Q.
18 A.
19
20
21
22
23.
Heat Rate Deration (PIIC Adjustment 10)
What does PIIC's propose in this adjustment?
PIIC claims that the Company's application of outages biases the availability and
average heat rates of the units. The adjustment proposed by PIIC would reduce
Company's system NPC by $1.8 milion.
How does the Company apply the deration method?
The Company's approach derates the maximum capacity of the unit in every hour
of the year by an equal percent based on historic forced outage rates, which
constitutes a "haircut" in unit availability.
How would PIIC's discussion change this method?
The discussion presented by PIIC would alter thermal units' heat rate curves to
artificially increase their effciency as compared with the heat rate cures that are
developed from actual plant operating data. The discussion on the "other aspect"
of the problem that PIIC presents is to reduce thermal plant minimum generation
levels so GRID can run thermal units at levels they are physically incapable of
reaching.
Would PIIC's method significantly understate the heat rates?
Yes. The only time when the derate adjustment to the heat rate may be applicable
is when the unit is dispatched at one particular level of generation - its derated
maximum capacity, with the assumption that the unit may be dispatched at its
stated maximum capacity in GRID ifthere were not the availabilty "haircut".
When the unit is dispatched at any level below its derated maximum capacity,
GRID has made the optimal decision to dispatch that unit at a lower and less
Shu, Di-Reb - 31
966 Rocky Mountain Power
.
.
.
1 effcient generation level, whether it has been derated or not. Therefore, derating
2 the entire heat rate curve overstates the effciency of the unit and understates the
3 heat inputs.
4 Figure 4 and Figure 5 below show the heat rate cures that would be under
5 the methods modeled by the Company and modeled by Mr. Falkenberg in the
6 Company's previous cases in other jurisdictions for a coal-fired unit and gas-fired
7 unit, from minimum to maximum generation level, with the assumed generation
8 levels superimposed on the heat rate curves that would be dispatched under the
9 Company's methods. The graphs clearly demonstrate that heat input required for
10 various levels of generation is understated using the derate-adjusted heat rate. In
11 both cases, there are many hours of dispatch below the derated maximum
12 capacity, which are the generating levels at which PIlC's proposal would
13 understate the heat rate, and subsequently understate NPC.
967
Shu, Di-Reb - 32
Rocky Mountain Power
.
.
.
2
Figure 4 Heat Rate Curve (Coal Unit)
I
i/o;m,me,-
Heat Rate Curve
¡-::a-S
'l..%
L~
1- "a~
/ i '
PIIC Adjusted Htt Rate Curve
Derated Capacity
Maximum capac,\
\j
i
Generation Level
Figure 5 Heat Rate Curve (Gas Unit)
Heat Rate cule!
"
;a-S:%
l¡
/1
Derated Capacity !
i
Maximum Ca aci
/' ~PIIC Adjusted Heat ~
Rate Curve ~'---
.~.,__ I-~
Minimum Capacity ¡ ____! --
¡
Generation Level
968
Shu, Di-Reb - 33
Rocky Mountain Power
.
1 Q.Hasn't the Company agreed to adjust the heat rates at least to the derated
2 maximum capacities of the units as claimed by PIIC?
3 A.No. The Company believes that the only adjustment that may be valid is at units'
4 derated maximum, assuming that the unit could generate at a slightly more
5 effcient level, but the Company does not believe such adjustment should be
6 made. After the Company's application of the "haircut," the units' capacities are
7 stil at relatively effcient levels. In actual operations, a unit can be derated to any
8 level between its minimum and maximum capacities, and from Figure 4 and
9 Figure 5, the heat rate at lower levels are significantly less effcient than at the
10 derated maximum.
11 Q.Do you agree with PIIC's discussion that the minimum generation level.12 should be derated because the maximum generating level is derated?
13 A.No. The purose of the "haircut" to the maximum generating capability is to
14 reflect the amount of generation no longer available due to outages. That is fully
15 accomplished through the "haircut" to the maximum generating capacity.
16 Q.PIIC relates the proposal of making duration adjustment to the Company's
17 modeling of fractionally owned units. Do you have comments on that?
18 A.Yes. PIlC seems to suggest that the portion of the units that would not be
19 available due to outages may be considered to be owned by other entities. Such
20 concept would require the modeling of all aspects of the units in the same manner,
21 including the reserve capabilities of the units. In addition, in the case of outages,
22 it is not correct to assume that another entity owns the portion of the units that are
23 forced out. When GRID determines certain amount of generation from a unit, it.Shu, Di-Reb - 34
969 Rocky Mountain Power
.1 does not make the decision based on whether or how much the unit has been
2 derated. That is, for a unit with a capacity of 100 megawatts, when GRID
3 dispatches the unit at 70 megawatts, it does not matter whether the unit has been
4 derated by 20 percent or not. The Commission should reject PIIC's adjustment.
5 Existing Long Term Contracts (PIIC Adjustments 11 and 13 regarding DC Intertie
6 Costs, and Idaho Power PTP Contract)
7 Q.
8
9 A.
io
11
12.13
14 Q.
15 A.
16
17
18
19
20
21
22
23.
Please explain PIIC's proposed adjustment to costs associated with the DC
Intertie.
PIIC argues that costs associated with the DC Intertie and Network Transmission
Agreement between BPA and the Company should be removed from NPC on the
basis that no purchases are modeled at the Nevada-Oregon Border ("NOB"), the
point from which the agreement provides wheeling. The two adjustments
proposed by PIIC would result in a $4.8 milion decrease to system NPC.
Please provide some background on the DC Intertie contract.
The DC Intertie contract was executed 16 years ago on May 26, 1994, to provide
deliveries of 200 megawatts of power from Southern California Edison at NOB
under Amendment 1 to the Winter Power Sales Agreement ("WPSA"). The
WPSA was executed on December 14,1993 and provided up to 422 MW of
power to be delivered to the Company's west control area. At the time the WPSA
was executed, the Company had suffcient transmission rights to import 222
megawatts of power into the west control area. The agreement provided that if the
Company procured additional transmission rights by June 1, i 993, then it could
import the remaining 200 megawatts to its system. The Company secured the
Shu, Di-Reb - 35
970 Rocky Mountain Power
.1
2
3
4 Q.
5 A.
remaining 200 megawatts of transmission rights by acquiring 200 megawatts of
transmission capacity on the DC intertie. The Company terminated the WPSA
effective January 1, 2002, but kept its 200 megawatts of DC Intertie import rights.
How does the DC Intertie contract benefit the Company's customers today?
The agreement takes advantage of the load diversity between summer-peaking
6 California and the winter-peaking Pacific Northwest. The contract provides a
7 valuable means of securing capacity and energy from California entities to meet
8 retail loads. Loads in California are relatively low in the winter when loads in the
9 Company's west control area and the rest of the Pacific Northwest are at their
10 highest.
i i Existing Long Term Contracts (PIIC Adjustments 11 and 13 regarding DC Intertie.i 2 Costs, and Idaho Power PTP Contract)
13 Q.
14
15 A.
16
17
18
19
20 Q.
21 A.
22
23.
Please explain PIIC's proposed adjustment to costs associated with the DC
Intertie.
PIlC argues that costs associated with the DC Intertie and Network Transmission
Agreement between BP A and the Company should be removed from NPC on the
basis that no purchases are modeled at the NOB, the point from which the
agreement provides wheeling. The two adjustments proposed by PILC would
result in a $4.8 milion decrease to NPC.
How should the Commission judge the prudence of this contract?
Prudence should always be judged based on the information that was known at
the time the contract was executed. It would not be reasonable to judge a 16-year
old contract based on information that is available today that was not available 16
Shu, Di-Reb - 36
971 Rocky Mountain Power
.I years ago.
2 Q.But there are no transactions modeled at NOB in the test period in this
3 proceeding. Why is it appropriate to include costs related to the DC Intertie
4 agreement in this proceeding?
5 A.In making their proposal, PIIC focuses on energy deliveries under the contract
6 rather than the capacity and diversity benefits of the contract. It would be
7 inappropriate to penalize the Company for prudently acquiring transmission rights
8 16 years ago by disallowing costs today based on hindsight and only looking at
9 the energy value of a resource that can facilitate the delivery of both capacity and
10 energy. By purchasing these transmission rights, the Company has purchased
11 assurance that it can reliability serve its load obligations. PIIC's proposals based
12 on the limited energy-only view of this contract is similar to arguing that the.13 Company should only be able to recover insurance premiums when it receives
14 proceeds under an insurance policy. The costs associated with this contract are
15 modest in light of the benefit to the Company's overall transmission strategy and
16 hedge against changes in the market.
17 Q.What does PIIC propose to adjust for the expenses of the contract between
18 the Company and the Idaho Power Company ("IPC")?
19 A.PIIC claims that the contract that the Company has with IPC would no longer be
20 needed after the Populus to Terminal section of transmission line goes into
21 service. As a result, the expenses related to the contract should be removed,
22 which would reduce the Company's system NPC by $0.8 milion.
.
972
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Rocky Mountain Power
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.
.
1 Q.Why does the Company disagree with this adjustment?
2 A.The notion that an existing contract should be terminated simply because a new
3 resource may replace the function of that contract is unfounded. The referenced
4 contract is a two-year contract that the Company entered into in 2009 to serve
5 retail load, given the information at the time about the resources available to the
6 Company to meet its obligation in the next two years. This contract is not the
7 same as the short term firm contracts that the Company enters into from time to
8 time and for a short duration, such as the ones listed as a correction earlier in my
9 testimony. The capability of those short term firm transmission is modeled in
10 GRID at the assumed level based on what the Company has experienced
11 historically, and the assumption should be modified when the Populus to Terminal
12 line can provide the needed transmission capacity. The Company entered into
13 that particular contract based on expected in-service date of the Populus to
14 Terminal line and with the option of annual contracts only. As the result, the
15 terms of the contract could not perfectly match the in-service date of the new
i 6 transmission line, and the Company should not be required to time the contract
17 terms precisely with resources that become available subsequently. Had the
18 Company entered into a shorter contract, there would have been a potential gap
i 9 prior to the new transmission line being in service to the detrment of customers.
20 I recommend the Commission reject PIlC's adjustment.
21 Reserve Shutdown (Monsanto Adjustment 5)
22 Q.Please describe Monsanto's adjustment for reserve shutdowns.
23 A.Monsanto claims that the Company's forced outage rates and the rates used in
973
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.
2
3
4
5 Q.
6 A.
7
8
9
10 Q.
11 A.
12.13
14
15
16
17
18
19
20
21
22
23.
GRID are calculated inconsistently and proposes that reserve shutdown hours
should be added to the denominator of the forced outage rate calculations. The
proposed adjustnient would reduce the Company's system NPC about $0.8
milion.
Do you agree with this adjustment?
No. This adjustment has the effect of arificially lowering the forced outage rates
by stating that the units would be available 100 percent of the time if they were to
be called upon to run durng the hours when they were on reserve shutdown for
economic reasons.
Please explain.
Contrar to what Monsanto claims, the Company's calculation of forced outage
rates is consistent with how GRID applies them. Monsanto agrees that the
planned outage hours should be excluded from the denominator in the calculation
of forced outages. Removing the reserve shutdown hours are based on the same
fact that no forced outage events are collected during either the planned outage
hours or the reserve shutdown hours. Monsanto's proposal is the same as stating
that if the units were to ru during the hours when they were shutdown for
economic reason, the units would not encounter any forced outage events. The
proposal is not supported by logical or analytical reasoning. In addition, given th.e
fact that GRID models reserve shutdowns, the rates are only applied to the hours
when they are scheduled to run, which is a fact even supported by Mr. Widmer in
his testimony stating that "(t)he Company's daily screen modeling in GRID
specifically identifies when CCCTs are available but are not economic to ru and
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974 Rocky Mountain Power
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2
3
4
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
.
essentially placed them on reserve shutdown so they cannot run." I recommend
the Commission reject Monsanto's proposaL.
Cal iso (Monsanto Adjustment 7)
Q. Please describe Monsanto's adjustment to the Cal iso Fees.
A. Monsanto recommends removal of the Cal iso fees that are based on 2009 actual
costs incurred by the Company, and replace them with a lower amount.
Monsanto's recommendation is based on the assumption that a significant portion
of the fees are not matched by electricity transactions that the Company included
in the case and could incur the fees. This adjustment results in a $4.0 milion
decrease to the Company's system NPC.
Q. How do you respond to this adjustment?
A. i urge the Commission to reject this adjustment. Cal iso fees are incurred for
transactions at market points ofSP15, NP15, and when the Cal iso is the
counterpart.4 The bulk of these trnsactions are short term transactions made
close to the time of delivery. Cal iso is a major counterpar in the Company's
activities to balance its system, which is a fact that Monsanto doesn't dispute
according to Mr. Widmer's testimony stating "(h)istorical records reveal that most
of the transactions with the Cal iso as a counter par are incurred shortly before
or on the actual day of delivery." Such activities are reflected in GRID as part of
the system balancing sales and purchases, which are transactions computed by
4 Mr. Widmer quoted an excerpt presumably from the testimony by Company's witness Mr. Duvall from
the Wyoming Docket No. 20000-352-ER-09. Mr. Duvall's testimony in that case did not contain the
quoted excerpt. However, Mr. Duvall did testify to content similar to the excerpt as the Second
Supplemental testimony in the Company's Utah general rate case Docket No. 08-035-38, where the
discussion was about the reason why the Company entered into transactions that had delivery points in
SP 15 when it did not have firm transmission rights.
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Rocky Mountain Power
.1
2
3
4
5
6
7 Q.
8
9 A.
10
ii
12
13
14
15
16 Q.
17
18 A.
19
20
21
22
.
.
GRID representing the types of transactions that would be consummated shortly
before or on the actual day of delivery. The Company continues to do business
with the Cal iso and continues to incur Cal iso fees. There is no reason to
arbitrarily eliminate expenses that are required to be incurred when doing
business with the Cal iso simply because the data in the Company's fiing does
not explicitly include those applicable transactions.
Would removing the Cal iso as a counterparty affect the operations ofthe
Company's power system?
Yes. The Company enters into transactions with the Cal iso in order to
economically balance the system. In doing so, the Company incurs Cal iso fees.
Not allowing the Cal iso fees is the same as making the assumption that the
Company would not do business with the Cal iso. Removing Cal iso as
counterpart would limit the options that the Company may use to balance its
system economically. As a result, NPC would go up due to those limitations and
constraints.
Does the Company expect that it wil continue to do business with the Cal
iso in 2010?
Yes. The Company expects to do business with the Cal iso in 2010 and the
future and incur various fees in the markets governed by the Cal iso. Costs such
as wheeling costs are tyically quantified for ratemaking purposes by using the
most recent historic data, absent any known and measurable changes. This is
exactly how the Company has normalized Cal iso costs in this proceeding.
976
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Rocky Mountain Power
.Q.
2 A.
3
4
5
6
7
8
9
10
11
12
13
14
15
16
.
Do you see other problems in Monsanto's proposal?
Yes. Despite the fact that the Company requested Monsanto to provide all
workpapers supporting their adjustments, the workpapers for this adjustment is
among the ones that do not support the amount of the adjustments. Given the
magnitude of the adjustment, it seems that Monsanto proposes to remove the
entire amount of the Cal iso fees that the Company included in the case,
replacing it with only a fraction of the actual Cal iso fees that the Company has
incured during the period that is claimed to match the actual short term firm
transactions that the Company included in the case. However, through September
2010, the Company has incurred approximately $3.2 milion of Cal iso fees, both
wheeling fees and service fees, which are only $66,265, lower than what the
Company included in the fiing for the corresponding period. Accordingly, the
Commission should reject Monsanto's argument that the Company would not
incur Cal iSO fees in the test period, as well as rejecting the proposed adjustment,
which would replace what the Company has included in the case with a fraction
of the actual fees.
17 Cholla 4 Capacity (Monsanto Adjustment 10)
18 Q.
19 A.
20
21
22
23.
What was the issue regarding the capacity of Cholla unit 4?
As the result of a major overhaul in 2008 the capacity at Cholla Unit 4 was
upgraded. However, due to transmission constraints, the generation from the
Cholla unit 4 to the Company's system has remained at the previous leveL.
Monsanto argues that the upgrade should be reflected in GRID. The adjustment
would reduce the Company's system NPC by $1.1 millon.
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977 Rocky Mountain Power
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10
11
12.13
14
15
16
17
18
19
20
21
22
23.
1 Q.Do you agree with Monsanto's argument?
2 A.No. First, the argument ignores the physical transmission constraints on delivery
3 of power from Cholla. Second, Monsanto has increased transmission capacity to
4 accommodate the increased generation from Cholla unit 4 without increasing any
5 other costs related to that capacity. Third, the purpose of derating the units for
6 forced outages is to capture the lost generation due to such outages, while
7 Monsanto's proposal would suggest the lost generation due to outages could be
8 supplemented by the possible generation from the unit that cannot be delivered to
9 the system.
Morgan Stanley Call Premiums (Monsanto Adjustment 11)
Q. Please explain the Monsanto's proposed adjustment.
A. Monsanto proposes to remove the capacity payments related to two of the
Company's call option contracts because those contracts are not dispatched during
the test period. The adjustment would reduce the Company's system NPC by
$3. i milion.
Q. Do you agree with Monsanto's proposed adjustment?
A. No. Monsanto is seeking to disallow the capacity payments that the Company
pays on call option contracts without demonstrating the imprudence of these
costs. The Company executed these call option contracts to meet demand and
ensure reliable service by providing physical delivery of energy durng periods of
increased demand and/or transmission constraints when prices are higher. So
even if the contracts are not dispatched in GRID, they can provide customers a
real benefit in the event of a change in the Company's system.
978
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Rocky Mountain Power
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10
I I.12
13
14
15
16
17
18
19
20
21
22
.
1 Q.What would you recommend the Commission do in the current case?
2 A.The Commission should reject Monsanto's proposal to remove the capacity
3 payment of the call option contracts. As stated above, the contracts were entered
4 into to meet demand and ensure reliable service by providing physical delivery of
5 energy during periods of increased demand and/or transmission constraints when
6 prices are higher. Monsanto's adjustment is similar to requesting a refund of your
7 auto insurance payment every year when you have not been involved in an
8 accident.
9 Other Proposals
Combined Cycle O&M Adjustment (PIIC Adjustment 14)
Q. Please explain PIIC's adjustment to O&M costs of combined cycle plants.
A. PILC states that the proposed daily screening adjustment reduces the O&M costs
associated with combined cycle plants.
Q. What is the basis for PIIC's adjustment?
A. Based on Mr. Falkenberg's testimony on this issue in prior cases and the reference
to Mr. Steven R. McDougal's exhibit, PILC seems to be referring to the O&M that
the Company might have added to fixed O&M for each star-up of a combined
cycle plant.
Q. Is PIIC's adjustment reasonable?
A. No. The Company has not included any incremental O&M to reflect the
additional costs of combined cycle plant sta-ups. Therefore, there are no costs
to remove.
979
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Rocky Mountain Power
.1 Q.Do both Staff and Monsanto oppose updates to the Company's fied NPC?
2 A.Yes. The Company believes that updated information would provide the
3 Commission with the most recent and more accurate information for the test
4 period. While opposing updates to the Company's NPC, Monsanto proposes to
5 selectively update components of the NPC, such as the recommendation to
6 replace the Cal iso fees that the Company included in the fiing with actual Cal
7 iso fees that the Company has incurred for period prior to May 4,2010.If the
8 Company were to update the NPC to reflect all actual information that is available
9 for the test period through September, the NPC for the twelve-month period
10 ending December 2010 would be approximately $53.7 milion higher than what
11 was contained in the Company's original fiing. If the Company were to update
12 all NPC for actual information though May 4, 2010, as Monsanto recommended.13 for the Cal iso fees, the test period NPC would be $25.0 milion higher than
14 fied.
15 Q.Has the Company updated its NPC in this rebuttal?
16 A.No. However the Company believes updates improve the accuracy ofNPC
17 forecasts and reserves the right to propose updates in future fiings Staff, PIIC and
18 Monsanto proposed and the Company accepts adjustments to NPC, which total to
19 an approximate $6.5 milion reduction from what the Company originally fied.
20 Q.Please summarize your testimony.
21 A.In its direct fiing, the Company proposed NPC of$1.07 bilion on a total
22 Company basis for the 12-month test period ending December 2010. In this
23 current fiing, the Company has revised its projected NPC to $ I .063 billon on a.Shu, Di-Reb - 45
980 Rocky Mountain Power
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.
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1 total Company basis. The revised NPC incorporate corrections and positions that
2 Staff, PIlC and Monsanto proposed and the Company accepts, which total to an
3 approximate $6.5 milion reduction from what the Company originally fied. For
4 the adjustments that the Company does not agree with, I have provided
5 explanations and evidence to support the Company's positions. I believe the
6 revised NPC has reflected more accurate information and presented a reasonable
7 compromise to positions proposed by Staff, PIlC and Monsanto.
8 Q.Does this conclude your rebuttal testimony?
9 A.Yes, it does.
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.
.
1 (The following proceedings were had in
2 open hearing.)
3 MR. HICKEY: And so the record -- thank you,
4 Chairman Smith.
5 Q.BY MR. HICKEY: For the record, if I were to ask
6 you all the questions in both the direct and rebuttal, your
7 answers would be the same as you published wi thin those
8 documents. Isn't that correct?
9 A. Correct.
10 Q. Now, were you here when questions were asked this
11 morning of Cindy Crane?
12 A.Yes, I was.
13 Q.And do you recall that one of the questions that
14 was asked of Ms. Crane related to an adjustment to net power
15 costs that had been suggested in testimony by Mr. Falkenberg?
16 A.Yes, I remember that.
17 Q.As the person responsible for net power costs on
18 behalf of the Company in the case, did you have rebuttal to
19 that statement or that -- excuse me, to that proposed
20 adjustment?
21 MS. DAVISON: Madam Chair, I object to that on
22 the basis that my questions were extremely -- I assume that --
23 he hasn't laid the foundation. I think he must be asking about
24 my questions. But my questions were extremely narrow and they
25 were focused on coal costs.
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1 MR. HICKEY: I can certainly lay more foundation,
2 Madam Chairman, if that's necessary.
3 MS. DAVISON: Well, I obj ect on the basis that my
4 questions were not about net power costs. My questions were
5 about coal costs, and they were very narrow.
6 COMMISSIONER SMITH: Mr. Hickey.
7 MR. HICKEY: The reality is, whether Ms. Davison
8 wants to accept it or not, is the whole reason she asked the
9 question is because her witness is sponsoring a proposed
10 adj ustment to net power costs; and if I were allowed, Dr. Shu
11 would be able to explain her background with that particular
12 issue, and it's in the spirit of the rebuttal testimony that I
13 understood we have the opportunity to present.
14 COMMISSIONER SMITH: Ms. Davison, the Company
15 does have the burden of proof in this case and the opportunity
16 to present rebuttal, and it's chosen to do both direct and
17 rebuttal at the same time. So it may seem a little out of
18 order, but it's certainly allowed.
19 MS. DAVISON: Thank you.
20 MR. HICKEY: Thank you.
21 BY MR. HICKEY: So by way of additionalQ.
22 background and foundation, the question that was posed was, in
23 fact, the question asked by Ms. Davison that related to fuel,
24 and she inquired of Cindy Crane regarding that proposed
25 adj ustment offered by Mr. Falkenberg. Do you remember that
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1 question?
2 A.I do.
3 Q.What was the question?
4 A.The question, in my own words, seems to say
5 whether the coal quality at Bridger is at normal or one time
6 instance, and whether it will last and it will appear in the
7 future.
8 Q.And what is your response to the question and the
9 answer given by Ms. Crane?
10 The coal quality at Bridger is reflected in theA.
11 availability of the Bridger plant, and it's the same as any
12 other plants would normalize the availability or the outages of
13 those units. And we did not do anything different for the
14 Bridger plant.
15 And it is correct, as Cindy Crane mentioned, the
16 Company is dealing with a problem in the well installed
17 equipments, necessary equipments, to facilitate the coal mixing
18 process. However, until the equipments are installed and
19 tested and -- we can't -- we cannot make arbitrary adj ustments
20 to remove what has been based on historical record. And this
21 kind of a normalization is the same as I mentioned for outages
22 and for heat rates.
23 The Company has installed scrubbers on several of
24 our units. The Company elected not to degradate the heat rate
25 of those units because, again, we don't know how much of an
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1 impact it will be. So we will wait until it's tested and
2 reflected in the actual results will reflect the impact.
3 Q.Thank you, Dr. Shu.
4 MR. HICKEY: At this point, Madam Chair and
5 members of the Commission, Dr. Shu is ready for examination by
6 the parties and the Commission.
7 COMMISSIONER SMITH: Thank you, Mr. Hickey.
8 Mr. Otto, do you have questions?
9 MR. OTTO: I do, Madam Chairman. I have two
10 questions.
11
12 CROSS-EXAMINATION
13
14 BY MR. OTTO:
15 Dr. Shu, are renewable energy credits part of theQ.
16 net power supply cost calculation?
17 A.No.
18 Q.Oh, they're not. Okay.
19 MR. OTTO: Actually, I have no further questions.
COMMISSIONER SMITH: Excellent. Mr. Olsen.
21 MR. OLSEN: Yeah, I just have one -- a couple of
22 questions.
23
24
25
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2
3 BY MR. OLSEN:
4 Ms. Shu, could you turn to page 43 of yourQ.
5 rebuttal testimony, starting on line 7?
6 Now, in this portion of the testimony, lines 7
7 through 14, you talk about an adjustment to Monsanto is called
8 out for disallowing some capacity payments for some call option
9 contracts that were entered into to meet demand and reliability
10 service of the, I guess, PacifiCorp system. Is that correct?
11 Excuse me. I have to interrupt. Which -- youA.
12 are referring to rebuttal testimony or the errata?
13 Yes, rebuttal testimony, page 43.Q.
14 Or the errata? You say rebuttal?A.
15 Q.Yes, rebuttal.
16 Could you mention the line numbers again?A.
17 Yes. Lines 7 through 14.Q.
18 Yes, I have it.A.
19 Okay. And don't you discuss in there a proposedQ.
20 adjustment that Monsanto is seeking to make on disallowing
21 payments for two call option contracts? Is that correct?
22 A.Correct.
23 Now, with respect to your answer there, you stateQ.
24 that those contracts were entered into to meet demand and
25 reliability in service for PacifiCorp' s system. Is that
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1 correct?
2 A.Correct.
3 Q.Okay. Now, then you make a comparison that to
4 these type of contracts or looking for that adjustment there,
5 that they were like an insurance contract. Is that correct?
6 A.Correct.
7 Q.Okay. And that making this adjustment would be
8 like I guess asking for part of the premium back because you
9 didn't use the insurance. Is that correct?
10 A.Correct.
11 Q.Now, are you familiar with the demand-side
12 management program, specifically the irrigation load management
13 program?
14 A.No. I know the name, but I'm not very familiar
15 wi th the programs.
16 Q.Okay. But are you aware that basically when
17 PacifiCorp has a curtailment, they are able to take down a
18 certain amount of megawatts off the system? Is that correct?
A.I do believe the program allows the Company to
20 interrupt the load.
21 Q.Okay. Is that similar to just adding supply on
22 the other side like these option contracts, on the supply
23 side?
24
25
A.In theory, it resembles that, because it reduces
load.
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1 Q.Okay. So, you could have DSM that is out there
2 and ready to be used and not used and -- but that doesn't mean
3 that the payment for that program would be imprudent or
4 unnecessary, would it?
5 A.Again, I'm not familiar with the DSM programs. I
6 do not know how the payments were made or designed.
7 MR. OLSEN: No further questions.
8 COMMISSIONER SMITH: Thank you.
9 Ms. Davison.
10 MS. DAVISON: Thank you, Madam Chair.
11
12 CROSS-EXAMINATION
13
14 BY MS. DAVISON:
15 Q.Good afternoon, Dr. Shu.
16 A.Good afternoon.
17 Q.I'd like to go back to the testimony that you
18 provided on the stand this afternoon in response to some
19 questions I asked Ms. Crane.
20 Are you an expert on coal quality issues?
21
22
A.I am not.
Q.Is Ms. Crane the expert on coal quality issues
23 for the Company?
24
25
A.Correct.
Q.Is it your testimony that no matter how poor the
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1 quality of the coal is, that you will simply normalize any
2 outages associated with the coal plants?
3 A.I don't believe that's what I said. First off, I
4 don't believe the coal quality issue at Bridger is abnormal;
5 therefore, as a regular regular course of business would
6 treat all those outages or derates the same whether it's due to
7 coal quality or due to some other breakage of equipments.
8 Q.Isn't it true that Ms. Crane did, in fact, admit
9 today on the witness stand, as well as through a Data Response,
10 that the coal quality at Bridger is abnormal and that the
11 Company is in the process of trying to improve it?
12 A.I don't believe she mentioned that word,
13 "abnormal. "
14 Q.Well, isn't it, in fact, true that the Company is
15 trying to improve the coal quality at Bridger?
16 A.It's true. Company -- I will think the Company
17 would continue to improve insufficiency of all its resources.
18 Q.But it's your position that regardless of the
19 quality of the coal, you'll just simply normalize the
20 outages?
21 A.No, I did not say that. It's -- again, we don't
22 believe those coal qualities are abnormal, which is why we
23 would normalize the outage rates the same way as for all other
24 outages.
25 MS. DAVISON: Sorry, I didn't know she was going
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1 to deal with Ms. Crane's testimony, so let me grab my notebook.
2 Q.BY MS. DAVISON: And did you see the Response to
3 PIIC Data Request 141?
4 A. I don't recall that.
5 Q. Do you recall me asking Ms. Crane a question
6 about that? This was handed to Ms. Crane as premarked Exhibit
7 619. Did you take a look at that?
8 A.No, I haven't.
9 Q.And would you accept, subj ect to check, that the
10 Company responded that the Bridger Coal Company has initiated
11 efforts to reduce delivered coal quality variability?
12 COMMISSIONER SMITH: Would you like the reporter
13 to provide her with a copy of that exhibit?
14 MS. DAVISON: I'm simply trying to -- I think I'm
15 done with this. I'm just trying to highlight that her
16 testimony is at odds with Ms. Crane's on this issue of the
17 quali ty of the coal.
18 MR. HICKEY: I have the exhibit in my hand and it
19 seems like it would be appropriate for the witness to have it.
COMMISSIONER SMITH: Let's provide a copy of the
21 exhibit to the witness, and then she can confirm what it
22 says.
23
24
25
THE WITNESS: Yes, I have it.
Q.BY MS. DAVISON: So do you disagree with the
answer to this Data Request?
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1 A.No, I don't.
2 Q.Okay.
3 A.This Data Request merely indicate the Company is
4 initiated effort to improve its process.
5 Q.Well , it's to improve the quality of the coal, as
6 Ms. Crane admitted today on the witness stand. Isn't that
7 correct?
8 A.It is correct.
9 Q.Thank you. I'd like to turn to your rebuttal
10 testimony, Dr. Shu. Does your rebuttal testimony on page 14,
11 line 17, through page 19 address the issue -- and I'll try to
12 be careful on how I say this -- of intrahour wind integration
13 charges associated with nonCompany-owned wind facilities?
14 A.Again, I have to ask, this is the prefiled
15 rebuttal not the redacted rebuttal?
16 Q.I was working from your rebuttal testimony that
17 I -- the only copy I had with me, so --
18 MR. HICKEY: What page?
Q.BY MS. DAVISON: That was on page 14 through page
20 19. It's a wide range of pages.
21
22
A.Yes.
Q.And are these nonPacifiCorp wind facilities
23 wholesale transmission customers?
24
25
A.They are transmission customers.
Q.Are they wholesale transmission customers?
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1 A.Actually, I don't know how to define it. All I
2 know is they are customers of the Company's transmission
3 system, transmission function.
4 Q. You understand the difference between wholesale
5 and retail. Correct?
6 A. Yes.
7 Q. And if you look at your rebuttal testimony at
8 page 15, lines 12 through 17, I believe you talk about this
9 issue.
10 A.Yes.
11 Q.And just to be clear for the record, this is
12 wholesale customers. Correct?
13 A.Right.
14 Q.Thank you. Does your testimony dispute that
15 these wholesale transmission customers are the entities causing
16 PacifiCorp to incur these intrahour wind integration costs?
17 A.No, they are not the ones causing this cost.
18 This wind integration cost is, no matter how old the generators
19 are, the wind integration costs exist.
20 Q.So it's your testimony on the witness stand today
21 that these wholesale transmission customers are not causing
22 these costs, these wind integration costs?
23 A.They incur part of the total wind integration
24 cost, but they are not the ones -- only ones -- incurring that
25 cost.
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1 Q.My question is who's causing the costs, and I'm
2 talking again let me finish, I'm sorry.
3 Just so we're clear, I'm talking about intrawind
4 integration costs, and I think we've established that that's
5 wholesale customers. Correct?
6 A.Yes.
7 Q.And so my question is I don't believe that you
8 dispute that these wholesale transmission customers are the
9 enti ties causing PacifiCorp to incur these intrahour wind
10 integration costs.
11 A.I do agree they incur intrahour wind integration.
12 I just want to make sure to say they are not the only ones
13 causing the intrahour wind integration costs.
14 Q.Again, I don't want to beat a dead horse, but I'm
15 asking not who's incurring it. Who's causing the costs? And I
16 believe that if you look at your testimony, at your rebuttal
17 testimony page 16, lines 16 through -- or, 15 through 17, you
18 admit that point?
19 A.Right, I do agree these generators do incur
20 costs, and I just want to make sure wind integration intrahour
21 cost is not a concept for those customers only. So, they are
22 not the one causing the cost; they do incur a cost.
23 Q.So you're saying these wholesale wind integration
24 customers are not causing you integration costs?
25 A.They do incur wind integration costs.
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1 Q.Are they causing the costs, not incurring?
2 A.I don't draw the distinction. "Causing," to me,
3 that word means they are the one they are the only one
4 incurring this cost. That's why it causes some problem or -- I
5 don't really know how to -- how to distinguish those two since,
6 to me, the causing -- "causing," the word, meaning they started
7 the problem. I'm just trying merely to say they are not the
8 only ones incurring this cost.
9 Q.That's not the question I'm asking you. I'm not
10 asking you if they're the only ones that are --
11 MS. DAVISON: I'm sorry, Scott, we can't look at
12 each other.
13 MS. CARLOCK: She wants you out of the way to see
14 a face.
15 MR. WOODBURY: Sorry.
16 MS. DAVISON: Thank you.
17 Q.BY MS. DAVISON: Dr. Shu, I'm not asking you to
18 say that they're the only entity on PacifiCorp' s system that's
19 causing these costs. I'm just merely trying to establish a
20 foundation that I believe you have admitted in your rebuttal
21 testimony that they are causing you to have wind integration
22 costs.
23
24
25
A.Okay. Correct.
Q.Thank you. And, therefore, do you agree that
PacifiCorp will propose that nonCompany-owned wind facilities
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1 that are its wholesale transmission customers will pay at least
2 a portion of these intrahour wind integration costs?
3 A.The Company will propose that.
4 Q.Thank you.
5 A.And I'm not sure if this is a appropriate place.
6 I, in my testimony, beginning on line 16, the
7 response is: The Company plans to file a rate case with FERC
8 no later than June 2011.
9 However, after the testimony has been filed, the
10 FERC -- Federal Energy Regulatory Commission -- issued a Notice
11 of Proposed Rulemaking, and that rulemaking is about
12 integrating the variable energy resources. And in that
13 Proposed Rulemaking, FERC made several requirements. Among
14 them is that it would require transmission providers to offer
15 intrahour transmission scheduling at a 15-minute interval.
16 And also it requires the transmission customers,
17 whose resources are variable energy resources, to provide
18 transmission providers the necessary data so the transmission
19 providers will be able to forecast their production. And as a
20 resul t of that, the Company --
21 And also in the requirement, the FERC required if
22 any transmission provider is to file a rate case, the rate case
23 should be supported by actual data from one -- from one year
24 after the implementation of the intrahour operation.
25 And as a result, the statement would need to be
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1 changed here. The Company will file a rate case with FERC no
2 later than June 2011; however, the wind integration tariff will
3 not be part Of it just because it's the impossibility of having
4 one year of actual data from this date on to June 2011.
5 Q.So, Dr. Shu, when you did your errata or when you
6 were sitting on the witness stand earlier today, why did you
7 not correct your testimony?
8 A.It's not an error. It's this is a new
9 information. I'm just stating the Company's expected activity
10 will change.
11 Q.So but this concept of an intrahour
12 integration cost is not new, is it?
13 A.No, it is not.
14 Q.And has PacifiCorp previously filed with FERC a
15 rate case for these charges?
16 A.No, the PacifiCorp has not filed. However,
17 PacifiCorp has been tracking the acti vi ties in the field, and
18 the PacifiCorp was planning to have a solid support for its
19 Application and even before this FERC NOPR, and there weren't
20 very many successful Applications with FERC.
21 Q.But there's no legal impediment preventing you
22 from filing this type of rate case at FERC, was there?
23 MR. HICKEY: Madam Chair, if I may, I think
24 there's just a misunderstanding. The rate case is going to be
25 filed.
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1 MS. DAVISON: Excuse me, I don't believe that
2 it's appropriate for Mr. Hickey to testify for Dr. Shu. She's
3 certainly more than capable of representing her position.
4 MR. HICKEY: I would whole-heartedly agree.
5 COMMISSIONER SMITH: I would agree with that, and
6 I think your question does ask though for a legal conclusion
7 and I don't believe that Dr. Shu is a lawyer. So, I think you
8 ought to rephrase it or move on.
9 MS. DAVISON: Okay. Thank you.
10 Q.BY MS. DAVISON: Has there been any impediment
11 that you're aware of that has prevented you from filing a rate
12 case at FERC for these wholesale wind integration charges?
13 A.I'm not aware of those.
14 Q.Under the Company's proposed rate case here today
15 or that we're here today about, are Idaho retail ratepayers
16 subsidizing wholesale transmission wind customers?
17 A.I don't believe so. The Company has a
18 significant transmission network and that transmission network
19 benefi t our retail customers, and the wind integration is only
20 a small portion of the entire cost of the transmission network.
21 And because of this transmission network, the Company has
22 collected revenues from the transmission customers and those
23 revenues are all credited back to the retail customers.
24 But didn't we just establish that the Company isQ.
25 not charging these wholesale wind customers the wind
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1 integration charges?
2 A.That's correct.
3 Q.And so if there is, in fact, and you admitted on
4 the witness stand that you are collecting data on how much this
5 wind integration is costing the Company and you're not charging
6 the wholesale wind farms for that, then by definition, doesn't
7 that leave your retail customers as the entity who is paying
8 for these costs?
9 A.Again, the transmission system, there are
10 multiple costs, there are other costs, and the Company are paid
11 to -- by the transmission customers and all those revenues are
12 credi ted back. It is correct, this is one of the costs present
13 the Company is not recovering from those customers.
14 Q.And you are seeking to recover those from the
15 retail customers at the moment. Correct?
16 A.Yes.
17 Thank you. Let's change topics and I'll referQ.
18 you to pages 2 and 3 of your rebuttal testimony. You raise
19 some general comments at the area about the level of net power
20 costs that the Company is seeking to recover in this
21 proceeding. Is that correct?
22 A. Yes.
23 Q. And is it correct that you testify that the
24 actual expected net power costs will be allegedly higher than
25 the normalized historic test period costs?
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1 You are referring to a specific number or theA.
2 general concept?
3 Q.General concept.
4 A.In general, yes.
5 And have you performed any analysis or providedQ.
6 any evidence to demonstrate the prudence of the actual net
7 power costs that you reference in your rebuttal testimony on
8 those two pages?
9 I have not done a prudence review because IA.
10 believe the Company incurred those costs prudently.
11 And, Dr. Shu, I'd like to hand you what I haveQ.
12 premarked as Exhibit 620.
13 (PIIC Exhibit No. 620 was marked for
14 identification.)
15 BY MS. DAVISON: And do you recognize this DataQ.
16 Response?
17 A.Yes.
18 And is it correct that this Data Response statesQ.
19 that you did not do a prudence analysis?
20 A.Correct.
21 Thank you. Have you performed any analysis ofQ.
22 the actual net power costs referred to in your rebuttal
23 testimony that have been impacted by load variations, hydro and
24 wind generation deviations, or any other similar factors?
25 A.No.
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22
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24
25
1 Q.And I'd like to hand you what we have premarked
2 as Exhibit 621.
3 (PIIC Exhibit No. 621 was marked for
4 identification. )
5 Q.BY MS. DAVISON: And do you recognize this Data
6 Response?
7 A.Yes.
8 Q.And this is simply in written form confirming
9 that you have not done that analysis. Is that correct?
10 A.Correct.
11 Q.So do you believe that the Company has the burden
12 to demonstrate that each component of its power costs are
13 prudent?
14 A.I believe the Company has the burden to
15 demonstrate the net power cost is prudent, not every single
16 component.
17 MS. DAVISON: Thank you. I have no further
18 questions, Madam Chair.
19 COMMISSIONER SMITH: Thank you.
Mr. Purdy.
MR. PURDY: No questions.
COMMISSIONER SMITH: Mr. Woodbury.
MR. WOODBURY: Thank you, Madam Chair.
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1 CROSS-EXAMINATION
2
3 BY MR. WOODBURY:
4 Q.Dr. Shu, I have some questions on -- regarding
5 the wind integration costs that the Company incurs. And if I
6 understand your testimony , it's that wind integration and all
7 that entails from an operation standpoint for the Company does
8 not lend itself to a precise dollar and cent number, but can
9 only be estimated?
10 A.Correct.
Q.And is it for --can your GRID model be modified
in such a way that it does produce that number?
A.It could.
Q.And has the Company attempted to do that in its
11
12
13
14
15 preparation of the wind study -- wind integration study -- as
16 part of the 2000 -- the current IRP?
17 A.Correct. As part of the Company's 2010 IRP, the
18 Company performed a wind integration study, and in the study,
19 as part of the study, it identified the additional reserve
20 requirements due to integrating wind into our system. And as a
2 1 result, a GRID can take the additional reserve requirement as
22 an input and a model wind integration cost in the GRID.
23
24
25
Q.So it's possible to do?
A.It's possible.
Q.On page -- in your rebuttal testimony on page 11,
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1 around line 18, you state that: While implying that the
2 Company's wind integration costs are not real, neither paid
3 under contract or to any other utility, Staff states the
4 Company's costs are captured in the actual test period expenses
5 and reflected in a number of accounts.
6 As I look at the language
7 And we're talking about Mr. Lanspery' s
8 testimony.
9 A.Okay.
10 Q.Correct?
11 A.Yes.
12 Q.Yes. On page 5, line 12, of his direct, he
13 states well, the question was: Do you believe Rocky
14 Mountain Power should include wind integration charge as a
15 variable cost to its own wind facilities and power purchase
16 contracts?
17 And he says: No. First of all, these are
18 internal costs that are neither paid under contract or to
19 another utility.
20 That in -- well, other than BPA, don't you pay
21 them for some wind integration?
22 A.The Company does pay BPA for wind integration for
23 two of its projects.
Q.But, otherwise, that statement would be true?
A.The reason why I don't believe that statement is
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1 true is that it seems, to me, my interpretation of that is, it
2 has to be
3 Q.Yes, well --
4 A.Excuse me.
5 Q.Let me first back up a little bit. Staff -- I
6 mean, you're implying from that Staff statement that Staff's
7 intention is to say that wind integration costs are not real.
8 Now--
9 COMMISSIONER SMITH: Would you confirm that
10 that's actually what she implied?
11 MR. WOODBURY: No, this is what she -- she says
12 in her testimony on page 11, line 18: While implying that the
13 Company's wind integration costs are not real.
14 COMMISSIONER SMITH: All right.
15 MR. WOODBURY: With the statement: Nei ther paid
16 under contract or to another utility.
17 COMMISSIONER SMITH: Gotcha.
18 Q.BY MR. WOODBURY: Is it your understanding in
19 interacting -- the Company interacting with Staff in some of
20 the dockets that we've had on wind integration costs that Staff
21 has ever taken the position that wind integration costs are not
22 real?
23
24
25
A.That's the impression when I read this paragraph.
Q.Did you discuss this language with anybody wi thin
the Company to maybe ascertain as to whether this was
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1 Commission Staff' s position?
2 A.Yes.
3 Q.And they indicated to you that we had previously
4 indicated that wind integration costs are not real?
5 A.Not previously, just from this paragraph of the
6 testimony.
7 Well, the fact that this says "neither paid underQ.
8 contract or to any other utility," I mean, if we talk about our
9 ini tial discussion, it was that, essentially, this doesn't lend
10 itself to a dollar-and-cent calculation and has to be -- and
11 has to be estimated, and contracts are generally for services
12 rendered and establish a dollar amount. Correct?
13 Correct. But in the model, there are otherA.
14 things which would lead to this, like, for example, the Company
15 has to follow the load. So that one has exactly the same
16 nature as the following the wind.
17 And I don't -- I don't disagree with the CompanyQ.
18 as far as, you know, yes, there are wind integration costs and
19 you do attempt to define those, I guess, on page 12 around
20 line 11 or following. You state that wind integration costs
21 are costs incurred due to additional reserve requirements, and
22 then indicate what you do as far as following load and stuff
23 like that.
24 But it's very difficult to define, you know, for
25 purposes of this rate case, I mean, because Staff had indicated
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1 and I think you stated on the prior page, 10, that the
2 proposals -- you're summarizing the proposals of the parties,
3 and you state the wind integration charge used is for setting
4 avoided cost rates and not for setting retail rates. And the
5 wind integration charge you're talking about there is the six
6 fifty per month --
7 A.Correct.
8 Q.-- as presently authorized?
9 And you would agree that that charge was
10 developed for setting published avoided cost rates?
11 A.Yes.
12 Q.And not for setting retail rates?
13 A.Correct. That's my understanding.
14 Q.You agree with that. Okay.
15 And that with respect to proposal of some that
16 these costs are captured in the ECAM, is your objection there
17 that because of the 90/10 split, the Company doesn't recover
18 all of its costs or that -- well, stop. Start there.
19 A.The main obj ection is, I believe, the function of
20 ECAM is to capture the difference between the actual cost and
21 the baseline, so
22 Q.If there was no 90/10 split, would the costs be
23 recovered in the ECAM?
A.They would.
Q.They would? Okay. The wind integration costs
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1 would if there wasn't that percentage split?
2 A.I believe that would be correct with a delay, the
3 delay in the recovery.
4 Q.So there may be indefinable, but nevertheless
5 encompassed or assumed in the numbers that flow through the
6 models?
7 A.Correct.
8 Q.Okay. Dr. Shu, I thank you.
9 MR. WOODBURY: Madam Chair, no further questions.
10 COMMISSIONER SMITH: Mr. Budge.
11 MR. BUDGE: Thank you, just briefly.
12
13 CROSS-EXAMINATION
14
15 BY MR. BUDGE:
16 Q.Dr. Shu, I just need to clarify concerning a
17 question I had regarding when that Top of the World wind
18 proj ect actually went into service.
19 A.October 1 of this year.
Q.Okay. When the Company originally filed, they
21 had indicated it was going to go into place November 1.
22 Correct?
23
24
25
A.Correct.
Q.And then Monsanto submitted a Data Request 2.33,
and the Company responded and said that it changed from
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1 November 1 to October 1. Correct?
2 A.I believe that was the case. Not -- I don't
3 qui te remember which Data Response or which one.
4 Q.Subj ect to check --
5 A.Subj ect to check.
6 Q.-- it was Data Request 2.33, and I'm happy to
7 hand it to you if you like.
8 A.That's all right.
9 Q.Okay. So that being the case, I assume that you
10 agree with the adj ustment made by Mr. Widmer that proposed to
11 move the in-service date of Top of the Wind (sic) from the
12 November 1st date of the original filing to the new date of
13 October 1?
14 A.I do agree with that adjustment. However,
15 Mr. Widmer's adj ustment is not complete because of the wind
16 integration cost.
17 Q.Okay. When you filed your errata testimony on
18 November 21st, were you aware that Company witness Mr. Duvall
19 had filed testimony recently in the Wyoming case indicating
20 that the Top of the World contract start date had moved the
21 other way, now back to December 1?
22
23
A.I don't remember December 1, that date.
Q.You're not aware of his testimony in Wyoming
24 moving the start date back to December 1 from October 1?
25 A.I don't think he moved it to December 1.
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1 Q.Okay. Well, I'll take that up with him next.
2 But if, in fact, that were the case, would you
3 agree, subj ect to check, that this would reduce your proposed
4 rebuttal net power supply cost by approximately five million?
5 A.I have not done that study, but I do remember
6 that it would increase the net power cost. I do not know by
7 how much.
8 MR. BUDGE: Thank you. No further questions.
9 COMMISSIONER SMITH: Do we have questions from
10 the Commissioners?
11 COMMISSIONER REDFORD: No.
12 COMMISSIONER KEMPTON: No.
13 COMMISSIONER SMITH: Nor I.
14 Redirect?
15 MR. HICKEY: Just very limited redirect, thank
16 you, Chairman Smith.
17
18 REDIRECT EXAMINATION
19
20 BY MR. HICKEY:
21 Q.You were asked some questions by Ms. Davison on a
22 couple of different Data Responses, and I'm going to refer you
23 to No. 620, if you remember Exhibit 620 that addressed the
24 issue of prudence.
25 A.Yes.
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1 Q.Let me ask you this: Is it your understanding
2 that prudency reviews are undertaken by utilities or by Public
3 Utili ty Commissions, Dr. Shu?
4 A.My understanding is by Commissions.
5 Q.Do you know whether or not the Company engages in
6 a due diligence process before it adds additional resources to
7 its portfolio of generation resources?
8 A.Yes.
9 Q.And do you know whether or not it would engage in
10 a due diligence process before it would acquire any other form
11 of energy or power?
12 A.Yes.
13 MR. HICKEY: That's all I have, Madam Chairman.
14 COMMISSIONER SMITH: Thank you, Mr. Hickey, and
15 thank you, Dr. Shu, for your testimony.
16 MR. HICKEY: Yes, would you please -- may Dr. Shu
17 please be excused?
18 COMMISSIONER SMITH: If there's no obj ection,
19 Dr. Shu is excused.
20 (The witness left the stand.)
21 MR. HICKEY: And we're ready to call Greg Duvall
22 as our next witness.
23
24
25
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25
1 GREG DUVALL,
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, Mr. Duvall.
9 A.Good afternoon.
10 Q.Would you please state and spell your name for
11 the record?
12 A.Yeah, my name is Gregory N. Duvall. That's
13 G-R-E-G-O-R-Y, middle initial N, Duvall is D-U-V-A-L-L.
14 Q.And by whom are you employed and what is your
15 capaci ty with the Company?
16 I'm employed by PacifiCorp, and I'm the directorA.
17 of long-range planning and net power costs.
18 And did you have an opportunity, Mr. Duvall, toQ.
19 file rebuttal testimony on November 16th of this year?
20 A.Yes, I did.
21 Do you have any corrections or changes to yourQ.
22 rebuttal testimony?
A.No, I do not.
Q.If I were to ask you the same questions set forth
in the prefiled rebuttal, would your answers be the same
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22
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1 today?
2 A.Yes, they would.
3 MR. HICKEY: I would ask, Madam Chair, that the
4 prefiled rebuttal testimony of Mr. Duvall be spread upon the
5 record as if read.
6 COMMISSIONER SMITH: If there's no objection, it
7 is so ordered.
8 (The following prefiled rebuttal testimony
9 of Mr. Duvall is spread upon the record.)
10
11
12
13
14
15
16
17
18
19
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3 A.
4
Please state your name, business addres and present position with Rocky
Mountain Power Company (the Company), a division ofPacifiCorp.
My name is Gregory N. DuvalL. My business address is 825 NE Multnomah, Suite
600, Portand, Oregon, 97232. My present position is Director, Long Range
5 Planning and Net Power Costs.
6 Qualifications
7 Q.Briefly describe your education and business experience.
8 A.I received a degree in Mathematics from University of Washington in 1976 and a
9 Masters of Business Administration from University of Portland in 1979. I was
10 first employed by PacifiCorp in 1976 and have held various positions in resource
11 and transmission planning, regulation, resource acquisitions and trading. From.12 1997 though 2000 I lived in Australia where I managed the Energy Trading
13 Deparment for Powercor, a PacifiCorp subsidiar at that time. After retuing to
14 Portland, I was involved in diect access issues in Oregon and was responsible for
15 directing the analytical effort for the Multi-State Process ("MSP"). Curently, I
16 direct the work of the integrated resource planning group, the load forecasting
17 group, the net power cost group, and the renewable compliance area.
18 Q.Did you file direct testimony is this proceeing?
19 A.No.
20 Summary of Testimony
21 Q.What is the purpose of your rebuttal testimony?
22 A.I wil respond to Mr. Brian Collns and Ms. Kathn Iverson's testimony that was
.23 fied on behalf of Monsanto. Specifically my testimony wil rebut:
1012 Duval, Di-Reb - 1
Rocky Mountai Power
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2
. Mr. Collns 'comments regarding the tratment of Monsanto's load and
interrptible products in the Company's Integrated Resource Planning (IRP);
3 . Ms. Iverson's comments regarding the interrptible natue of Monsanto's
4 load; and
5 . The appropriate regulatory treatment of Monsanto.
6 IRP treatment of Monsanto
7 Q.
8
9 A.
10
11.12
13
14
15
16 Q.
17
18
19 A.
20
21
22.
Is it true that Rocky Mountain Power models Monsanto's load as non-firm
for integrated resource planning purposes?
No. Monsanto's load is treated as firm load and their interrptible products are
treated as firm resources. If Monsanto's interrptible products were no longer
economic, the Company would find other means to meet its firm load obligations
and would have an obligation to serve Monsanto's entire load. If Monsanto's load
were non-firm, the Company would be able to interrpt it at any time for any
reason with no limitations, and would only provided power on an as, if and when
available basis.
Mr. Collns states that Rocky Mountain Power is now deducting 157
megawattsl of Monsanto's interrptible load for purposes of determining its
planning reserve obligation. Is this correct?
No. The Company conducted a review of the Monsanto contrct for peak
capacity planning purposes subsequent to the 2008 IRP Update. Based on that
review for the 2011 IRP, the Company IRP plans on 116 MW of the 162
megawatts total fuace capacity wil be avaiable on a fir basis at the time of
1 Collins, dirct page 3 lines 23-24 and page 4 lines 1-11.
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2
3
4
5
6
7
8
9
10
11
12
13.14 Q.
15 A.
16
17
18
19
20
21 Q.
22
23 A.
the annual system coincident peak, and thus serves as a resource for peak capacity
planning puroses. These 116 megawatts are composed of 67 megawatts for the
economic curailment porton of the contract, plus 49 megawatts of non-spin
reserves. The remaining 47 megawatts of the 162 megawatt total interrptible
product are not considered to be available as a firm resource durng the system
peak because this capacity can only be called upon during a double contingency
event. This planning assumption was highlighted on slide 44 of the slide
presentation2 that was discussed at the October 5,2010, IRP public input meeting,
which included the following bullet:
"Modeling change to Monsanto curailment/reserves contract: 47 MW
reduction in non-spin contingency reserves available for the peak hour;
this amount now assumed to be non-fir (available only in the event of
double-contingency outages)"
What do you mean by a double contingency event?
As defined in the energy service agreement a double contingency event is the
forced outage of two or more PacifiCorp generatig units totaling 500 megawatts
or more of capacity. To qualify these outages must have occurred within fort-
eight hours of each other and must overlap for at least one hour. It would not be
reasonable to assume that a double contingency would occur at the time of the
Company's system coincident peak for planning puroses.
Does the Company include Monsanto in its load requirements when making
long term capacity planning decisions?
Yes. The IRP uses a peak load forecast that includes Monsanto's full load,
.2 The slide prsentation from the October 5, 2010, IRP public input meeting can be found on the
Company's website at http://www.pacificorp.comles/ir/pip.htm.
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.1
2
3 Q.
4
5 A.
6
7
8
9 Q.
10
11.12
13
14 A.
15
16
17
18
19
20
21
.
including the portion of this load that is interrptible on a fir basis durg the
annual system coincident peak load hour.
If the Company ha a contract allowing interruption of Monsanto why doe
the Company include that load in the IRP.
For resource planning and dispatch it is necessar to include Monsanto's full
energy and demad in the IRP otherwise their interrptible capacity would be
double counted since the interrptible products are included as a fir system
resource.
Ms. Iverson makes the following comment in her testimony findings and
conclusions; "The concept of forcing a non-firm customer to rirst "buy all-
firm" and then "sell a product" back to the utilty is neither reaonable nor
fair and in fact is a fiction that does not reflect reality.,,3 What is your
response to this statement?
Ms. Iverson's claim is nonsensical, the concept that Rocky Mountain Power is
forcing Monsanto to do anything is a fiction and does not reflect reality. The
Company provides Monsanto fir electrc service, the same service quality as any
other customer on the electric system. Monsanto has offered to allow the
Company to interrpt that service and in retu the Company has compensated
Monsanto for the right not to serve them under specific prices, terms and
conditions. These arangements are contractual and represent mutually agreeable
arangements to which both Monsanto and the Company have chosen to accept.
3 Iverson direct page 3 lines 11 thugh 13, bold underline added for emphasis.
1015 Duvall, Di-Reb - 4
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.1 Q.
2
3
4 A.
5
6
7
8
9 Q.
10 A.
11.12
13
14
15
16
17
18
19
20
Do you agree with Ms. Iverson statement that: "The fundamental principle is
that non-firm customers receive a lower quality service than the firm
customers do.,,4
No. Once power enters the electric grd there is no distinction or difference to that
power. There is no distinction between green or brown power just as there is no
difference between fir or non-fir power; the service is the same. Ms.
Iverson's claim that Mo~santo's loads are served at a lower quality of service is
not based on any facts.
What percent of Monsanto's load is interruptible?
Ms. Iverson claims that 95 percent5 of Monsanto's load is interrptible by
comparng nine megawatts of finn load to a tota of 182 megawatts, which is a
correct mathematical statement given the numbers she used, but one that only
provides a single perspective and uses incorrect assumptions6. Looking at this
ratio from a different perspective, the current energy service agreement between
Rocky Mountain Power and Monsanto allows interrption for a maimum of
1,050 hours out of 8,760 total hours in a year, which is less than 12 percent. On a
megawatt-hour basis, Monsanto receives approximately 1,385,000 megawatt
hours7 per year and the curent contract allows for only approximately 76,754
hours of curailment for a maximum of 5.5 percent interrptible service from
Monsanto.
.4 Iveron direct page 7 lines 18 thugh 19, page 10 lines 3 though 4.
5 Iverson, direct page 4 line 14.6 If Ms. Iverson had used the 2011 IRP assumption that 116 megawatts are intenuptible, her
percentage of load that is intenuptible would change from 95 percent to 64 percent.7 Company witness Grfith Exhibit No. 50 line 16.
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.1 Regulatory Treatment of Monsanto
2 Q.Has the Idaho Public Utilties Commision previously ruled on Ms. Iverson
3 proposal of a "non-firm" approach to both jurisdictional and class
4 allocations?
5 A.Yes. In Case No. PAC-E-01-16 Monsanto argued that they should only pay a
6 single net energy rate. The Commssion rejected this proposal and ordered
7 Monsanto to pay a capacity and energy charge for all of Monsanto's service;
8 "The Commission does support separate pricing components. The
9 Commssion finds that the contract for Monsanto should specify
10 separate rate components for firm service and for the
11 interrptibilty discount. The fixed costs of service to Monsanto
12 should not be buried in an energy only rate, payable only if
13 energy is used and possibly not recovered in full, but should be
14 captued in a fixed customer charge and demand charge.
15 Recovering fixed charges in this manner is consistent with.16 rates formulated for other customer clases and recognizes the
17 fact that PacifiCorp continues to incur charges and is required
18 to be ready to serve even when Monsanto is idle."a
19 On December 18, 2006 in Order No. 30197 the Commssion ruled on the
20 appropriate jurisdictional treatment of Monsanto:
21 "The transition of Monsanto from contract to taff standard
22 customer, we find, wil facilitate futue rate adjustments and
23 should serve to keep Monsanto's rates better aligned with its
24 cost of service. .. While tarff rates may present Monsanto with
25 new challenges, we perceive the regulatory result to be positive
26 and one of greater equity. Under the submitted Agreement
27 Monsanto's futue rates after Januar 1,2008 wil be adjusted
28 using the same process as all other customers."g
29 Q.Does the Company have a proposed solution for this issue?
30 A.Yes. The Company follows a "customer indifference" approach when valuing
.8 Final Orer No. 29157, page 4 lines 12-22, emphasis added.
9 Order No. 30197 page 9 lines 1 - 8, bold underline added for emphasis.
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2
interrptible products offered by industrial customers. In other words, the
Company seeks to pay industral customers who can offer interrptible products
3 the same price the Company would otherwise pay if it were to acquire those same
4 products from other sources, such as the maket or its own resources.
5 Conclusions
6 Q.
7 A.
8
9
10
11 Q..12 A.
.
Please summarize your testimony.
Monsanto's full load is included as fir load in the IRP for resource planning
purposes and should be include for allocation purposes. The Company has
appropriately treated Monsanto's load for jursdictional allocation purposes
consistent with previous Commssion orders.
Does this conclude your testimony?
Yes.
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1 (The following proceedings were had in
2 open hearing.)
3 Q.BY MR. HICKEY: Mr. Duvall, were you here
4 yesterday when Mr. Teply testified?
5 A.Yes, I was.
6 Q.And do you recall cross-examination of him that
7 related to an Order, I believe it was the UM- 1355 Order?
8 A.Yes, I have.
9 Q.And from what jurisdiction was that Order
10 entered?
11 A.That was from Oregon.
12 Q.Are you familiar with that Order?
13 A.Yes, I was the Company's primary witness in that
14 case, and I'm familiar with that Order.
15 Q.To put some context for the questions that I have
16 to ask you, what do you recall from yesterday's examination of
17 Mr. Teply the question was regarding that particular Order?
18 A.Yes, this was the cross-examination Exhibit
19 No. 617 that was handed out by Ms. Davison, and she had pointed
20 him to some language. There's one page out of the Order, it's
21 page 5 out of the Order, where it talks about a length of any
22 one forced outage being capped at 28 days. And I think
23 Mr. Teply said that that's what the Order said, and he wasn't
24 familiar with this docket.
25 Q.So with the familiarity that you have with the
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1 Order, having been the Company's witness in that docket, can
2 you explain or further address what the Order held, from your
3 perspective?
4 A.Yeah. The Oregon Commission, they spent about
5 three years working on forced outage rates, and this is their
6 Final Order that came out of the Docket UM-1355. And in this
7 case, Mr. Falkenberg has proposed using a cap of 28 days on the
8 four-year historic average that the Company has proposed for
9 forced outages. The 28-day reference in the UM-1355 Order is a
10 cap on 20-year historic averaged data. So what happened in the
11 Oregon case and what Mr. Falkenberg proposed here are pretty
12 much apples and oranges.
13 Q.What's the what's the significance of this?
14 What would the result be in terms of net power costs under what
15 Mr. Falkenberg has contended as opposed to what you're
16 suggesting the appropriate read of that Order is?
17 A.Well, Mr. Falkenberg's adjustment reduces net
18 power cost, but we are in the position of just finishing up our
19 compliance filing in Oregon implementing this full Order, which
20 actually uses a collar on the four-year average using NERC coal
21 unit data, and then we replaced with the 20-year average. It's
22 all spelled out in this exhibit, all the different steps, but
23 it's completely different. But the end result is that the
24 forced outage -- the impact on net power cost is pretty much
25 de minimis as compared to just using the four-year rolling
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1 average.
2 MR. HICKEY: Madam Chairman, Mr. Duvall is
3 available for examination by the Commission and parties.
4 COMMISSIONER SMITH: Thank you.
5 Mr. Otto, do you have questions?
6 MR. OTTO: I have no questions, Madam Chair.
7 COMMISSIONER SMITH: Mr. Olsen.
8 MR. OLSEN: No questions, Madam Chair.
9 COMMISSIONER SMITH: Ms. Davison.
10 MS. DAVISON: No.
11 COMMISSIONER SMITH: Mr. Purdy.
12 MR. PURDY: No.
13 COMMISSIONER SMITH: Mr. Price.
14 MR. PRICE: No questions, Madam Chair.
15 COMMISSIONER SMITH: Mr. Budge.
16 MR. BUDGE: I have some, thank you.
17
18 CROSS-EXAMINATION
20 BY MR. BUDGE:
21 Q.Mr. Duvall, did you file testimony in the Wyoming
22 case recently, indicating that the Top of the World contract
23 had been moved back to December 1?
24.25
A.I filed testimony recently in the Wyoming general
rate case, but I'm pretty sure that the Top of the World was
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1 October 1. I haven't had a chance to check that since you
2 asked the question to Dr. Shu, but I know of no reason why it
3 would have been moved to December 1.
4 Q.Handing you what's been marked as Exhibit 248,
5 and that exhibit should consist of the 2008 integrated resource
6 plan is the first part of it, and then towards the end is the
7 2008 update that has a date in the bottom, left corner of
8 March 31, 2010.
9 COMMISSIONER SMITH: Mr. Budge, do you want to
10 reflect these are selected pages and not the entire plan?
11 MR. BUDGE: Yes. Yes, thank you. It consists of
12 the cover page under date of May 28, 2009, of the 2008
13 integrated resource plan, which is a long document, so I
14 selected pages 86 through 91.
15 And then following that, with respect to the
16 update under date of March 31, 2010, we have included selected
17 pages 33, 34, and 35.
18 COMMISSIONER SMITH: Thanks.
19 (Monsanto Exhibit No. 248 was marked for
20 identification. )
21 Q.BY MR. BUDGE: And I believe, if I understand
22 your rebuttal testimony correctly, you direct the work of the
23 integrated resource planning group. Would that be correct?
24 A.That is correct.
25 Q.And if you'd turn, please, to the second page in
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1 on Exhibit 248, there's a topic heading that says Load and
2 Resource Balance Components?
3 A.I've got it.
4 Q.And then under that, under the caption where the
5 existing resources are being described and then you go through
6 a description of the various resources, if you turn to page 87,
7 there's a description of the interruptible resources?
8 A.Correct.
9 Q.And you identify there the three on the east
10 side -- Monsanto, MagCorp, and Nucor -- and those total 237
11 megawatts of load interruption capability. Correct?
12 A.Correct.
13 Q.And the last sentence, it says: Interruptible
14 resources directly curtail load and thus planning reserves are
15 not held for them.
16 Could you just explain what is meant by that
17 statement?
18 A.Well, that's -- well, if they're -- they're
19 actually providing curtailment services.
20 Q.And so does that mean the Company is not planning
21 any resources to serve that interruptible load?
22 A.Well, it is -- it is planning resources. I think
23 the charts that are in here look at the hour of system peak.
24 That's just a portion of the integrated resource planning. We.25 look at all of the needs throughout the year: All of the
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1 energy needs, as well as capacity needs.
2 Q.I may not have understood your answer. Let me
3 rephrase the question differently.
4 Aren't you simply saying for planning purposes
5 that you don't plan to have a production resource available to
6 serve this interruptible load, because they can be interrupted
7 by the Company when it wants?
8 A.Well, for planning -- planning purposes, we
9 include the full Monsanto load in our firm load requirements.
10 We also include the Monsanto interruptible products as a
11 resource in our resource stack. Certainly, that's -- you know,
12 we have a contract with Monsanto through February right now,
13 and what's beyond February is still up in the air. And it's in
14 our plans as a proxy, as part of the other interruptible
15 customers, as are the irrigation load controls. If those don't
16 come through, we will replace them with whatever is cost
17 effecti ve.
18 Q.Regarding your statement, you said you include
19 the Monsanto full load. So that would be 182 megawatts.
20 Correct?
21 A.That's correct.
22 Q.And then you deduct back out the interruptible
23 load of 170 or -72 megawatts. Correct?
24 A.We include in the resource stack in our most
25 recent resource planning, we include the interruptible products
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1 as a resource. The current plan, the 2011 IRP, we include 116
2 megawatts, as indicated on page 2 of my rebuttal.
3 Q. You simply repeated the same answer you gave me
4 before. My question was I'm talking about for planning
5 purposes, let's assume we have an A minus B equals C, and I
6 think you just said A is we include the firm load of Monsanto,
7 which would be 180 megawatts. Correct?
8 A.That's right.
9 Q.And then minus B would be you say you include the
10 full interruptible load, then B would be the minus 170
11 interruptible load. Correct?
12 A.The 116 megawatts
13 Q.Okay.
14 A.is what we have as a resource. Again, that's
15 included as a as a resource.
16 Q. SO after you include the firm load and you take
17 out the interruptible load, what you have left is whatever is
18 left of Monsanto's firm load, which would normally be the nine
19 megawatts?
20 A.No.
21 Q.Simply because you're not including the full 170
22 megawatts that is the interruptible portion?
23 A.Yeah, as I explained in my testimony, we've
24 included 116 megawatts because the difference between that and
25 the full what you would call interruptible in the Monsanto
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1 contract is only available if there's a double contingency,
2 which means you have two major plants out of 500 megawatts or
3 more and they're overlapping. That's explained in my testimony
4 as well.
5 Q.So, turn to the March 31, 2010, update, Table
6 3.9, and you'll see the seventh line down under the Resources
7 in the East part, you'll see the category Interruptible.
8 A.Correct.
9 Q.And that's the same 327 megawatts we identified
10 earlier?
11 A.Right.
12 Q.And so you show that as being a resource out
13 through year 2019 for planning purposes. Correct?
14 A.Yes, it's a planning assumption, correct. And as
15 I indicate in my testimony --
16 Q.So what you're -- so for planning purposes --
17 MR. HICKEY: Wait. Wait, Randy. I don't think
18 he finished his response for you.
19 Q.BY MR. BUDGE: Excuse me?
A.Yeah, as I indicated in my testimony, the 327
21 that was in the 2008 update has a number that is too high for
22 Monsanto, so that number 327 in the current IRP is a lower
23 number because Monsanto is at 116 megawatts instead of the 162
24 megawatts I believe that was in this prior planning document.
25 Q.So, basically what you're saying, that with
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1 respect to that interruptible load you describe for Monsanto,
2 the Company is planning that as an available resource to meet
3 peak load through 2019 under the current integrated resource
4 plan, Exhibit 248?
5 A.Yeah, as a planning assumption we hope that
6 happens, but it is a planning assumption.
7 Q.So the only load that the Company must plan to
8 serve for Monsanto would be the firm load?
9 A.Well, all of Monsanto's load is firm load, and
10 actually this is why I put my testimony in here is because
11 Monsanto morphed from interruptible load to calling that
12 nonfirm load, and that's really the reason I've put my
13 testimony in is it's not nonfirm. Nonfirm is as if and when.
14 An available can be interrupted anytime, as it would have a
15 lower priority of service. We do have nonfirm service in the
16 wholesale world, but -- and alls that means is that it's there,
17 but the first thing to get cut is the nonfirm service, and
18 that's not what Monsanto takes.
19 Q.So do you use the term "interruptible" and
20 "curtailment" interchangeably?
21 A.I would say that's a fair use of those words.
22 Q.But you don't use the word "nonfirm"
23 interchangeably?
24
25
A.No, I do not.
Q.Turn to page 4, if you would, line 18 and 19.
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1 A.Okay.
2 Q.Actually, beginning on line 17 you have a
3 sentence that says: Monsanto has offered to allow the Company
4 to interrupt that service.
5 Are you referring to the current contract that's
6 in place and offer to interrupt, or is this something different
7 than the current contract?
8 A.No, that's the current contract.
9 Q.So "offer to interrupt" would be an incorrect
10 reference to the contract right that the Company has to
11 interrupt?
12 A.Well, maybe we're just mixed up on semantics, but
13 through the contract, Monsanto is offering to allow the Company
14 to interrupt it.
15 Q.And then you go on at the end of that sentence on
16 19 and you say this right to interrupt is: In return, the
17 Company has compensated Monsanto for the right not to serve.
18 "Compensate" is at least defined in Black's Law
19 Dictionary "to pay," so if your statement suggests that
20 Monsanto writes a check or, excuse me, the Company writes
21 some check periodically to Monsanto to pay them for this right,
22 that wouldn't be accurate, would it? The Company never writes
23 any checks out to Monsanto; they simply send a bill at the end
24 of the month for whatever the cost is Monsanto owes and
25 Monsanto pays the Company, not the other way around?
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1 MR. HICKEY: I'll object to the form of the
2 question: It mischaracterizes the testimony of Mr. Duvall.
3 COMMISSIONER SMITH: Mr. Budge.
4 MR. BUDGE: Well, his testimony is what I was
5 trying to cross-examine him on.
6 MR. HICKEY: Well, if you're ask- --
7 MR. BUDGE: Let me rephrase.
8 COMMISSIONER SMITH: Thank you.
9 Q.BY MR. BUDGE: You say the Company has
10 compensated Monsanto.
11 Isn't it a fact, Mr. Duvall, the Company never
12 pays anything to Monsanto on a month-to-month basis?
13 A.The Company provides Monsanto a significant
14 credi t to their service each month, so I think technically, I
15 don't exactly know how the arrangements go between the Company
16 and Monsanto, but there is a credit that is given Monsanto
17 that's through the contract.
18 Q.Well, have you ever looked at the bill? You say
19 there's a credit on the bill. Are you suggesting that on the
20 bill there is a credit?
21 A.I have not looked at the bill. My understanding
22 is that Monsanto gets a credit -- I don't know if the number is
23 confidential, but a substantial credit -- for providing the
24 interruptible services.
25 Q.Well, let's get a bill, Mr. Duvall.
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1 MR. BUDGE: If he could be handed, please,
2 Monsanto Exhibit --
3 MR. WOODBURY: 242.
4 MR. BUDGE: Oh, yeah, 242.
5 (Whereupon, the court reporter handed the
6 witness Exhibit No. 242.)
7 Q.BY MR. BUDGE: Looking at Exhibit 242, now do you
8 see that Monsanto is charged for firm demand on nine megawatts?
9 A.I do.
10 Q.And do you see that they're charged for
11 interruptible demand on 178?
12 A.On my copy, that's blacked out. I have no idea
13 what those numbers are.
14 Q.Okay. Do you see that they're also charged for
15 firm energy and for interruptible energy?
16 A.Yes, I do.
17 Q.Do you see any credits on this bill at all coming
18 from PacifiCorp to Monsanto as you suggest is the case?
19 A. Well, my testimony is not from a perspective of
20 an accountant. And, you know, I'm not familiar with the bill;
21 Mr. Clements is and I don't know if any other people are. But
22 I am pretty sure that Monsanto does not provide the services
23 they provide for free.
24 And the point of the testimony, if it's not
25 clear, was to indicate that those -- that Monsanto is
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1 compensated in some way, shape, or form, for providing those
2 services to the tune of a number that, like I said, I don't
3 know: It's confidential for now.
4 Q.Fair enough. So to clarify your testimony, when
5 you say "compensate," you do admit that the Company doesn't
6 write a check out to Monsanto on a monthly basis?
7 A.Yeah, I don't know that for sure, but I'LL take
8 that subject to check.
9 Q.And based upon your review of the billing
10 statement, Exhibit 242, would you correct your prior statement
11 that you thought Monsanto received a credit?
12 A.Again, I guess I did say a "credit" on the bill,
13 and I do say I would correct that.
14 Q.Okay. You had some criticism in your rebuttal
15 testimony of the use of the term "quality of service" by
16 wi tness Iverson. Do you recall that, generally?
17 A.I do.
18 Q.And if, in the proper context, Mrs. Iverson's
19 testimony "quality of service" refers to additional hours of
20 interruption, would you agree then that an interruptible
21 customer that is limited to 100 hours of interruption per year
22 could be said to have a higher-quality service than one
23 interruptible customer who can be interrupted a thousand hours
24 per year?
25 A.Well, I was looking at "quality of service" in
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1 terms of the firmness of the product, what is delivered to
2 Monsanto when the Company is delivering power to meet the load,
3 and that's the exact same level of service as any other retail
4 customer.
5 Q.So you're basically saying the electrons are the
6 same?
7 A.Right. And as I described earlier, in the
8 wholesale world, the nonfirm designation in wholesale power
9 means it gets cut first. And so in the retail for Monsanto,
10 Monsanto doesn't get cut first as compared to any other
11 customer, other than through the terms of its contract.
12 Q.When you suggest that Monsanto receives the same
13 service as any other customer, would you agree that as an
14 interruptible customer, Monsanto risks, during periods of
15 interruptions taken by the Company, lost production
16 opportunity?
17 A.I have no idea.
18 Q.You don't have an idea if the furnaces are shut
19 down that they don't lose some production?
20 A.I don't know that.
21 Q.And would you believe that when a curtailment
22 occurs, that Monsanto has a risk of potential damage to
23 equipment such as during icing periods we have now, the cold?
24 A.I have no idea. I mean, these contracts, I've
25 seen them with aluminum companies as well, and they're just
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1 shutting off the pot lines for a certain amount of time. The
2 company who is on the manufacturing side needs to specify the
3 terms and conditions so they don't run into those sorts of
4 damage conditions, but that's not something the Utility is
5 responsible for.
6 Q.One other risk that they would have based on
7 their quality of service that might be different from every
8 other customer would also be the additional cost of buy-through
9 energy should they choose to do that during a period of
10 curtailment. Do you agree that's a risk of business?
11 A. It's a risk to Monsanto?
12 Q. Yes.
13 A.It's a financial sort of pricing issue as far as
14 I could see. It would result in a higher price to Monsanto at
15 certain times than it would have if they didn't have the
16 buy-through conditions.
17 Q.And despite those obvious risks, you would still
18 contend that Monsanto has exactly the same service as any other
19 customer?
20 A.When they're being delivered power. I mean, if
21 Monsanto's interrupted, they are interrupted; but even during
22 times of buy-through, the quality of electricity coming to
23 Monsanto is the same as if there weren't any buy-through.
24 Q.Again, that's the electrons and electrons?
25 A.That's right.
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1 Q.No further questions. Thank you, Mr. Duvall.
2 A.You're welcome.
3 COMMISSIONER SMITH: Thank you, Mr. Budge.
4 Do we have questions from the Commission?
5 COMMISSIONER REDFORD: No.
6 COMMISSIONER KEMPTON: No.
7
8 EXAMINATION
9
10 BY COMMISSIONER SMITH:
11 Q.I guess just one: I guess your testimony on the
12 top of page 5 about what is service quality, I guess that's one
13 thing that bothered me yesterday in some dialogue that I think
14 Mr. Budge had with one of the witnesses, and I guess in my
15 usual construction of the words "service quality" in this
16 industry is voltage sags, momentary outages, or other things
17 that are measured by SAIDI and SAIFI. Is that your
18 understanding also?
19 A.Boy, I don't know anything about that. This was
20 really comparing between Monsanto and other retail customers.
21 Q.Okay. I'll ask Ms. Iverson that question. Thank
22 you.
23
24
25
A.All right.
COMMISSIONER SMITH: Any redirect?
MR. HICKEY: Just a couple very quick ones.
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1 REDIRECT EXAMINATION
2
3 BY MR. HICKEY:
4 Q.I'm going to refer you to an exhibit that is yet
5 to be sponsored by Mr. Griffith who is a witness we'll be
6 calling later in the case, but I have in front of me for the
7 reference of anyone who wants to follow Exhibit 52, and I'm at
8 page 26 of Mr. Griffith's Exhibit 52.
9 And my question, if I may approach the witness,
10 Madam Chair
11 COMMISSIONER SMITH: You may.
12 Q.BY MR. HICKEY: -- is do you know whether or not
13 there is a tariff associated with Monsanto's special
14 contract?
15 COMMISSIONER SMITH: It's Exhibit 52.
16 Q.BY MR. HICKEY: The question, Mr. Duvall, is do
17 you know whether or not there is a tariff associated with the
18 Monsanto special contract?
19 A.I don't know that, but what you've handed me
20 looks like a tariff to me.
21 Q.Well, I'm going to save that question for
22 Mr . Griffith.
23 COMMISSIONER SMITH: Yeah, you quit while you're
24 ahead.
25 MR. HICKEY: I have no questions on redirect.
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1 COMMISSIONER SMITH: Thank you, Mr. Duvall, for
2 your help in the case.
3 THE WITNESS: You're welcome.
4 MR. SOLANDER: Rocky Mountain Power calls
5 Barb Coughlin as its next witness.
6 COMMISSIONER SMITH: No, no, no.
7 MR. SOLANDER: No?
8 COMMISSIONER SMITH: Before the next witness,
9 we're going to take a ten-minute break.
10 I was waiting to see if you wanted Mr. Duvall
11 excused.
12 MR. HICKEY: Yes.
13 COMMISSIONER SMITH: If there's no obj ection,
14 he's excused.
15 (The witness left the stand.)16 (Recess. )
17
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