20101220Vol VI Technical Hearing, pp 1037-1279.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
CASE NO.
PAC-E-I0-07
TECHNICAL HEARING
HEARING BEFORE
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 VI - Pages 1037 - 1279
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HEDRICK
POST OFFICE BOX 578
BOISE, IDAHO 83701
208-336-9208
COURT REPORTING
s'et1f tk ~ M/fI(Jlt¡ ß'iree 198
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1 APPEARANCES
2 For the Staff:
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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
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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 IrrigationPumpers Association (IIPA):
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16 For Idaho Conservation
League (ICL):
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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
.1 I N D E X
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WITNESS EXAMINATION BY PAGE
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Barbara Coughlin Mr.Solander ( Direct)1037
4 (RMP)Prefiled Rebuttal 1039
Mr.Purdy (Cross)1065
5 Mr.Price (Cross)1088
Commissioner Smith 1090
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Peter Eelkema Mr.Solander ( Direct)1092
7 (RMP)Prefiled Direct 1094
Prefiled Rebuttal 1105
8 Mr.Otto (Cross)1116
Mr.Olsen (Cross)1117
9 Commissioner Kempton 1126
10 Steven McDougal Mr.Hickey (Direct)1130
(RMP)Prefiled Direct 1133
11 Prefiled Rebuttal 1169
Prefiled Direct ( Fuller)1227
12 Mr.Otto (Cross)1238
Mr.Olsen (Cross)1240.13 Ms.Davison (Cross)1246
Mr.Price (Cross)1256
14 Mr.Budge (Cross)1260
Commissioner Smith 1267
15 Mr.Hickey (Redirect)1269
Mr.Budge (Recross)1272
16 Commissioner Redford 1274
Commissioner Smith 1276
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18 EXHIBITS
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NUMBER PAGE
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For PacifiCorp Idaho Industrial Customers:
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622 PIIC Data Request 186,2 pgs Marked 1246
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23 For Monsanto:
24 249 Monsanto Data Request 10.1 Marked 1265.25
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
INDEX
EXHIBITS
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1 BOISE, IDAHO, WEDNESDAY, DECEMBER 1, 2010
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4 COMMISSIONER SMITH: We i II go back on the record.
5 Are you ready for your next witness?
6 MR. SOLANDER: We are. Rocky Mountain Power
7 calls Barb Coughlin as our next witness.
8
9 BARBARA COUGHLIN,
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. SOLANDER:
16 Q.Good afternoon, Ms. Coughlin.
17 A.Good afternoon.
Q.Could you please state your name and spell your
19 last name for the record?
20 A.Yes. My name is Barbara Coughlin. It i s
21 B-A-R-B-A-R-A, C-O-U-G-H-L-I-N.
22 Q.And by whom are you employed and in what
23 capacity?
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A.lIm employed by PacifiCorp, and lIm the director
of customer and regulatory liaison.
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701 COUGHLIN (Di)
RMP
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1 Q.And are you the same Barbara Coughlin that filed
2 rebuttal testimony on November 16, 2010, as well as preparing
3 Exhibits No. 76 and 77?
4 A.Yes, I am.
5 Q.Do you have any corrections or changes to your
6 testimony or exhibits?
7 A.No, I do not.
8 Q.If I were to ask you the questions set forth in
9 your prefiled testimony, would your answers be the same
10 today?
11 A.Yes.
12 MR. SOLANDER: With that, I would move that the
13 prefiled rebuttal testimony of Barbara Coughlin be spread upon
14 the record as if read, and Exhibits 76 through 77 be marked for
15 identification.
16 COMMISSIONER SMITH: If there is no obj ection, it
17 is so ordered.
18 (The following prefiled rebuttal testimony
19 of Ms. Coughlin is spread upon the record.)
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1038
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
COUGHLIN (Di)
RMP
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Please state your name, business address and present position with
PacifiCorp dba Rocky Mountain Power (the "Company")?
My name ìs Barbara A. Coughlìn, 825 NE Multnomah, Portland, OR 97232. My
4 present posìtìon ìs Dìrector, Customer and Regulatory Lìaìson.
5 Qualifications
6 Q.
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Please desribe your educational and professional background?
I have worked ìn the gas and electrc ìndustr sìnce 1978. I receìved a Legal
Assìstant Certìficate from Marcrest College ìn 1991. From 1978 to 1997, I held
varous posìtìons ìn ìncreasìng levels of responsìbìlty wìthìn the legalregulatory
deparent of lowa-lllinoìs Gas and Electrc Company, a predecessor company to
MìdAmerican Energy Company. In 1997, I was promoted to a customer servìces
supervìsor and ìn 1999 was promoted to customer servìces manager at
MìdAmerican Energy Company. I worked as manager of regulatory projects at
PacìfìCorp from 2006 though 2008, when I was promoted to my current posìtìon
15 of Dìrector of Customer and Regulatory Lìaìson.
16 Purpose of Rebuttal Testimony
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18 A.
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What is the purpose of your rebuttal testimony?
. The purpose of my rebuttal testìmony ìs to respond to testìmony of Ms. Marlyn
Parker and Mr. Curtìs Thaden of Idaho Public Utìltìes Commssìon Staff
("Staff') and respond to testìmony of Ms. Teri Ottens representìng Communìty
Actìon Parnershìp Assocìatìon of Idaho ("CAPAI"). Specìfìcally I wìl address
the followìng ìssues raìsed by these parìes:
· Landlord Interim Bìlìng and Lìnk Programs;
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. Red Flag Rules;
. Rebìling;
. Customer notication for rebillìng;
. Unbìled usage;
· Meter upgrade;
· Moratorium and winter payment plan communications;
. Lend-A-Hand contrbutìons;
. Energy conversatìon education;
. Low income weatherization funding; and,
. Low income weatherization matching funds.
Landlord Programs
Q. Please explain the Company's landlord programs.
A. Rocky Mountaìn Power offers two landlord programs to mae it easier for
customer to do business with the Company. These programs provide resources
for landlords, property owners, and tenants. The first program is known as the
Landlord Interim Biling Agreement, and the second program is known as the
Landlord Link program.
Q. What is a Landlord Interim Biling Agreement program?
A. A Landlord Interim Biling Agreement is a contractual agreement that ensures the
continuance of electrc service between tenants for rental properties. Any
propert owner, landlord or a property management company that has a sìte or
multiple sites is elìgible.
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Please explain how a landlord participates in this program.
A Ladlord Interim Bìling Agreement form is completed and signed by the
landlord. Once the completed form is returned to the Company, the interi
bìling is set up within our customer service system.
How does the program work?
When the tenant applìes for electric service at a rental property where there is a
signed Landlord Interim Billìg Agreement, the Company transfers responsibìlty
for the biling from the landlord's name into the tenant's name. When the tenant
later moves out and closes theìr account, the bìling responsibìlty is automatically
transferred back into the landlord's name.
After the Company sets up the interim biling designation within its customer
service system, does it retain the agreement signed by the landlord?
Yes, the Company retains the Landlord Interim Bìling Agreement for six years.
Please explain the Landlord Link program?
The Landlord Lìnk program allows the Company to work together with propert
owners, landlords or property managers to effcìently handle requests by tenants
for service when they move in and out of rental unìts. Paricìpation by the
landlord in the Landlord Interim Billng Agreement program is a prerequisite to
paricipate in the Landlord Lìnk program.
This Landlord Lìnk program was originally piloted a number of years ago
in a university town to make the annual move-in process with students more
efficient. The pilot program was well received by the particìpating landlords and
was made avaìlable throughout all of the Company's service terrtories in 2003.
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While program paricipation is relatìvely small, 17 landlords with a total of 452
renta units in Idaho, we belìeve those landlords who paricipate are please with
the program.
How does a landlord participate in the Landlord Link program?
Information regarding the Landlord Link program is found on the Company's
websìte. A landlord who is interested in paricipatìng contacts the Company via
emaìl or by telephone. A small group of specìally trained call center agents
respond to landlords by telephone to explain all aspects of the program. This
ensures the landlord has a thorough understanding of theìr responsibìlties as
paricìpants, which includes reading the meter as a tenant move il and out,
securing the appropriate electrc service applìcation information, and verifyirg the
identification of a prospectìve tenant/customer.
How does Landlord Link work when tenants move in and out of a premise?
A parcipatìg landlord wìl work with theìr tenant by providing them a Landlord
Lìnk Applìcation to be completed and signed by the tenant, along with the renta
unit's meter reading. This applìcatìon form requìres the same ìnformtion any
other prospectìve Rocky Mountaìn Power customer would provide to secure
electric service. The form is then sent to the Company via facsimle.
Alternatively, the tenant or landlord may submit the same applìcant information
via an onlìne form found on the Company's websìte. The onlìne applìcatìon also
includes a field that captues whether it is the tenant or landlord providing the
informatìon.
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Rocky Mountain Power
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How long does the Company retain the faxed Landlord Link Application and
the information gathered through the online Landlord Link Application?
The Company retains the faxed applications and onlìne information for six years.
Ms. Parker states she has concerns with the Company accepting applications
for service from third parties and is also concerned that the Company may
not have adequate checks and balance in place to meet the requirements of
the Federal Trade Commission's Red Flag Rule. Do you believe these
concerns are warranted?
No, I do not. As I indicated earlìer, the customer information provided to the
Company, whether ìt comes via fax on the Landlord Link Applìcatìon or though
the onlìne Landlord Link Applìcation, is the same as that requìred from any other
prospective customer requesting electric service from the Company. As a
paricipant in the program, landlords are asked to verify the information on the
form and check the tenant's identification.
Red Flag Rule
Q. Does the Company have a process to address the proposed "Red Flag Rule"?
A. Yes. In October 200S, in antìcipation of the passage of the Red Flag Rule, the
Company implemented a new process to review all new customer accounts for the
protection of personal identìties. All new customer records are sent though a
nightly electronic fie process to Equifax for verificatìon of the customer
identification. This includes accounts that were created via.the phone, onlìne, or
through the Landlord Link program. Equifax returns a fie to the Company
indicatìng potentìal and probable discrepancìes in personal identifying
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informatìon provided by the customer. These discrepancies are then investìgated
by a specìally traÌned team of specialists to follow-up with customers to correct
any errors or take other appropriate actìon.
Has the Company made any changes to its Red Flag process since the 200
implementation?
Yes. Since 200S the Company has continued to review and refine the process to
ensure ìt meets the intent of the rule and provides appropriate protections for our
customers. As par of Customer Service's ongoing process improvement efforts,
early in 2010, a Customer Services review was conducted by personnel not par of
the daÌly work flow. As a result of this review, recommendatìons for addìtional
account documentation and a trackìng mechanism were made and have been
implemented. In additìon, mid-year 2010, the Company's internal auditors
reviewed the process as par of theìr ongoing complìance review of Company
practìces. If any fìndìngs are identìied, corrective actions wì1 be implemented
15 accordingly.
16 Rebiling
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Ms. Parker states she identifed some concerns in her investigation of the
Company's rebiling procedures under Rule 204 (UCRR) and indicates that
the Company does not follow an objective or independent verifiable
methodology when preparing estimated bils. What methodology does the
Company utilze to estimate bils when a meter is not read during the
monthly meter reading window?
The Company utìlzes system logic for estimatìng regular monthly bìls. I wìl
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Rocky MountaÌn Power
.1 describe the detaìls of the system logic later in my testimony.
2 Q.What methodology does the Company utilze to rebil a customer when a
3 meter malfunctions or fails, when the meter equipment was incorrectly
4 installed or programmed, or when bils were inaccurately prepared?
5 A.For all the conditions described above, the rebìled amounts are manually
6 calculated; system generated estimates are not used. The method used to
7 calculate the bìlìng adjustment for each condition referenced above vares.
8 Q.Please provide a sample of the method used to calculate the usage for a meter
9 that has been unregistering consumption for a specifed period of time?
10 A.As an example, if a meter was tested and the results reflect a ninety-two percent
11 accuracy rate, the amount of the adjustment to the customer's monthly bìl would.12 be eight percent of the usage in the allowed months for backbiling. Another
13 example would be if the meter was tested and the results reflect a 107 percent
14 accuracy rate, the amount of the adjustment would be a seven percent credit of the
15 usage in the allowed months for backbìling.
16 Q.How does the Company rebil a customer in the situation where the
17 customer's meter stopped functioning?
18 A.A bìling adjustment in the situation of a stopped meter is based on a manual
19 calculation of historical usage of the site, using a per day average. If there is no
20 avaìlable usage for the site to base the manual per day usage calculation, after the
21 Company sets the new meter, a specìal meter reading is obtained in order to
22 determne an average per day usage for the allowed months of backbiling.
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calculated by using actual usage, yet allows for schedulìng constraìnts such as
weather-related issues, trainìng, or personnel on vacation or ì1.
Has the Company investigated or contemplated a change to its system logic
for estimation of monthly bils?
No. Because of very limted customer feedback, a continued decline ìn the
number of estimated reads, the fact that the Company is an electric only utìlty, .
and electricìty is typically not the primar heat source for the majority of our
customers, the Company has not found it necessar to investigate other estimation
methodologies.
Should the Company's current methodology be changed?
No. We believe our curent methodology is reliable as it is specific to the
individual customer's premise and lifestyle. The Company belìeves that the cost
to develop a more complex estìmating routine that would brig additional costs to
our customers to develop and maìntaìn, is not ìn the best ìnterest of our customers.
15 Also our current estimating logic is strightforward and easy for customers to
16 understand.
17 Notification of Rebiling
18 Q.
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Ms. Parker, on page 11 of her testimony also raised concerns about
communications with customers whose meters malfunctioned and were
rebiled. How does the Company notify a customer when it is necessary to
rebil?
When a billing adjustment is made to a customer's account, the customer is
provided notification on theìr next regular bilL.
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.1 Q.What does the notification on the customer's next regular bil include?
2 A.The adjustment section on the bìl wil include the month of the adjustment,
3 reason for adjustment, dates of service, and the amount of the adjustment.
4 Documentatìon is added to the customer's account providing detals of the biling
5 adjustment including the reason for the biling adjustment, in the event the
6 customer contacts the Company to discuss the adjustment.
7 Q.Is there any other notification that the customer receives?
8 A.For complex biling adjustments such as corrections due to crossed meters,
9 adjustments associated with guarantee requests (which are a result of a customer-
10 initiated contact), adjustments greater than $10,000, and adjustments for managed
11 accounts, the customer is notified of the adjustment dìrectly, either by phone or by.12 mail usìng the Company's biling adjustment letters. These contacts ar made
13 prior to the customer receiving the adjusted bil. The letter sent to the customer
14 notifyìng them of a biling adjustment advises the customer of theìr optìon of an
15 interest free payment plan. Upon request of the customer, the Company also
16 provides the customer a spreadsheet with the details of the biling adjustment.
17 Q.What is a guarantee request?
18 A.When a customer has made a contact with us concerning a biling inquir or to
19 investigate a meter problem, the Company is committed to investìgate under ìts
20 customer guarantee program these concerns and to respond within ten working
21 days, with a full report of the investìgation. When the Company has the results, a
22 Company representative wìl call and inform the customer. If the Company's.23 representatìve was not able to reach the customer via phone, a letter is sent to the
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1 customer with the results and any necessar billng adjustment.
2 Q.Ms. Parker recommends that the threshold of $10,000 should be much lower
3 when it comes to calling a customer if the adjustment amount exceeds
4 $10,000. Do you support thi recommendation?
5 A.Because of the categories of biling adjustments that currently receive telephone
6 calls or letters as outlned above (complex adjustments, customer-initiated
7 adjustment known as guarantee reviews, adjustments of $10,000, and managed
8 accounts), we fìnd the curent process meets the expectations of the majority of
9 customers. However, the Company is agreeable to changing the threshold for
10 sending letters for billng adjustment of $5,000 or more, rather than $10,000 for
11 customers receiving an adjustment that is not covered in one of the other
12 categories outlined above. And, the Company wil continue to send spreadsheets
13 to those customers requesting the bìling adjustment informtion in that format.
14 Unbiled Usage Due to Leaving Service Connected
15 Q.Ms. Parker states that the Company's policy allowing service to remain
16 connected between customers does not save time, mileage or costs and the
17 Company loses a considerable amount of revenue for electricity that went
18 unbiled. She states that the presumed net benefit of the policy may be more
19 myth than fact. Do you agree with Ms. Parker's determination?
20 A.No, the Company believes its currnt process is cost-effective.
21 Q.~ Please explain.
22 A.In 2009, there were 12,701 disconnect read orders generated as reflected ìn
23 response to Staff's Data Request IPUC 129. Of that 12,701 disconnect read
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orders created, there were a total of 7,837 customer-initìated account closures
where a new customer had not already taken responsibilty for the usage at a site
at the time account closure was requested. Not all customer-requested
disconnections ultimately result in the need for an order to be generated for the
fìeld to disconnect service. Of the 7,837 accounts closed, there were only 835
instances where field orders to disconnect service were generated for unbiled
usage of 1,000 kWh or greater.
What happens once a field order is generated for a disconnection of service?
A field metering specialist (referred to as a "collectot') is dispatched to the site to
leave a notìce of impending disconnection or disconnect service depending upon
the immediate cìrcumstances such as weather and occupancy.
For the 835 instances in 2009 where field orders were generated, how were
these accounts handled?
Of these 835 instances, approximately forty-two percent of the orders resulted in a
customer takng responsibìlty for the unbìled usage after receivìng a notice of
disconnectìon or havìng the service disconnected.
How many field orders to disconnect unbiled usage were completed in 2oo9?
In 2009, the Company completed approximately forty-seven percent of the field
orders disconnecting power to premises without an active customer.
Can you quantify the amount of revenue that was lost as a result of the
remaining sites where unbiled usage was not recovered?
Yes. The unbiled usage for 2009 was 798,319 kWh. Based on an average of
eight cents per kWh, the unbìled revenue would be approximately $63,866.
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.1 Q.Please describe the financial impact to the Company if it were to change its
process and follow Ms. Parker's recommendation to disconnect electric2
3 service between tenants.
4 A.Agaìn, using the same period as a baseline, there were a total of 7,837 customer-
5 inìtiated account closures where a new customer had not aleady taen
6 responsibilty for the usage at a site. Following Ms. Parker's recommendation,
7 the Company would need to dispatch an employee to disconnect the service.
8 Based on curent activity rates of the personnel needed to disconnect electrc
9 service, the approximate cost for completing the 7,837 requests would be
10 $ 1 78,183. Then, when a customer signs for service at the sìte, the Company
11 would agaìn need to dispatch personnel to connect the service at the site. This.12 would increase the costs to $356,366.
13 Q.How does this compare to the costs incurred by following the current
14 process?
15 A.Assuming all 7,837 customer requests for disconnectìon (identìfìed above)
16 requìred a closing read and an openìng read, the total approximate operational
17 costs would be $110,621. This is based on a calculation of .16 hours to read the
18 meter at a meter reader's activìty rate of $44.11 for each of the 7,837 requests.
19 Q.Does that account for the unbiled usge?
20 A.No. If you add the unbìled usage to the operational costs, the total cost for the
21 current process is approximately $180,621.
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.1 Q.Would all 7,837 requests require a meter reader to obtain a closing or
2 opening read?
3 A.No. If a meter is scheduled to be read within five days of the customer's request,
4 or if it has been read in the five days prior to the customer's request, the Company
5 would use the actual meter reading taken and prorate the bil based on a per day
6 usage to allow for the one to fìve day addition or reduction in the biling.
7 Q.What is the main reason for the difference in costs?
8 A.The cost differences are priarly due to the type of personnel requìred to work
9 the request and the length of time requìred to perform the work. A disconnection
10 and reconnection of service requìres a field metering specialist, and in cases
11 where the site has 3-phase service a journeyman linema is needed. However,.12 opening and closing meter reads can be performed by a meter reader, which has a
13 lower activity rate cost. The average time to disconnect or connect a service,
14 including travel, is 0.42 hours (approximately 25 minutes), while the average time
15 for an opening or closing read takes 0.16 hours (approximately 10 minutes).
16 Q.Please describe the difference in the work classifcations of meter reader and
17 collector.
18 A.A meter reader's training and focus is to accurately read the meters to ensure each
19 meter is read at regular monthly intervals. In the majority of cases, meter readers
20 are not electrcally trined to disconnect and connect meters. Many meter readers
21 walk theìr routes and they would not have the necessar tools and personal
22 protective equipment with them in order to disconnect or connect a meter..23 A collector has specific training and is electrcally traìned to remove or
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.1 install a meter to disconnect or connect power. Personal protective equipment
2 must by worn by anyone disconnecting or connectìng a meter. Collectors drve
3 from site to site and have tools and safety equipment readily avaiable to them.
4 The collector's work is assigned by priority and is workedmapped geographically
5 by the collector each day in order to complete as many orders as possible. The
6 work performed by the collector includes collectìon of past due bìls, customer- .
7 requested or company initiated disconnection of service, connection of service,
8 reconnection of service, and postìng past due notice or other disconnection of
9 service notice.
10 Q.Has the Company looked at ways to reduce the amount of unbiled usage?
11 A.The Company continually looks for ways to reduce unbìled usage. In 2007, the.12 Company conducted a pilot in six cities within its six-state service terrtory. In
13 that pilot the Company left door hangers notifying the occupant of the impending
14 disconnection of service. Durng that pilot forty-eight percent of occupants who
15 received a notice became customers within three to four days, and were back-
16 bìled to the date of their occupancy for the previously unbìled service. In
17 addition to back-bìling for the previous unbìled service, past due balances from
18 old accounts were also being collected. The pilot was determned to be successful
19 and the process was updated accordingly and expanded throughout all of the
20 Company's service terrtory.
21 Q.What changes to the Company's processes have been implemented since
22 2009?
.23 A.In early 2010, a change was made to better enable the Company to track the aging
1055
Coughlin, Di - Reb - 17
Rocky Mountan Power
.1
2
3
4
5 Q.
6 A.
7
8 Q.
9
10 A.
11.12
13
14 Q.
15
16 A.
17
18
19
20
.
of the orders tìed to unbìled usage. In addition, management dìrectives and goals
were establìshed to set and work priority orders. While the lost energy use has
been identified as a risk of this process, it is continually being reviewed and
managed.
How would the Company recover the additional costs outlined above?
The Company would need to recover these costs through customer's rates and/or
fees.
Does the Company have other concerns with increasing the number of
service disconnections in between customers?
Yes. Fìrst and foremost there are inherent safety risks every time a field metering
specìalist disconnects or connects a meter. Also it would requìre addìtional
manpower, could cause customer dissatisfaction, and could increase the number
of customer guarantee failures.
Ms. Parker recommends a $20 initiation fee. What is the Company's
position on this?
The Company does not belìeve adding a $20 ìnìtiation fee is appropriate at this
time. The Company belìeves it is effectively managing the unbiled usage orders,
and is working to continue to improve on those statistìcs. In addìtion, based on
the figures provided for 2009, a $20 fee would not have recovered the costs
incurred by disconnectìng between tenants.
1056
Coughlìn, Di-Reb - 18
Rocky Mountan Power
.1 Q.Ms. Parker believes the Company is sending mixed signals to customers
2 when it encourages conservation but leaves service connected when there is
3 no customer. Please address this comment.
4 A.The Company does not believe mixed signals are sent.In most cases the energy
5 used between customers is far less expensive than what would be ìncurred to
6 connect and disconnect the meter. One of the Company's goals is to educate our
7 customers on varous ways to reduce theìr electrcal usage and save energy. This
8 results in a lower bìl for our customers and decreases the need to build more
9 power plants or purchase power on the open market. While the Company does
10 agree that efforts to reduce costs and strengthen accuracy should always be
11 explored and implemented as appropriate, the costs of disconnecting the power at.12 all premises outweigh the benefits.
13 Q.Ms. Parker also mentioned that the Company has no plans to upgrade
14 meters to allow for remote reading or remote disconnection and reconnection
15 of service. Do you agree?
16 A.The Company actively researches new technologies and their cost-effectiveness.
17 At this time, the Company does not belìeve that upgrading to new technology
18 meters in its Idao service terrtory is cost-effective.
19 Q.What recommendations did Mr. Thaden include in his tetimony?
20 A.Mr. Thaden recommends the Commssion accept the following recommendatìons:
21 .Dìrect Rocky MountaÌn Power to communicate informatìon regarding the
22 Idaho Moratorium and the Winter Payment Plan though revisions to the.23 annual Customer Informatìon brochure and by attaching bìl inserts to
1057
Coughlìn, Di-Reb - 19
Rocky Mountan Power
.1
2
3
4
5
6
disconnection notìces;
.Encourage the Company to increase funding for the Lend-A-Hand
program through changes to the way customers can contrbute;
.Dìrect Commssion staff to convene a workshop to examne how best to
provide energy conservation educatìon to low income customers; and
.Provide no additìonal funding for low ìncome energy conservation
7 educatìon at this tìme.
8 Moratorium and Winter Payment Plan Communications
9 Q.
10
11.12 A.
13
14
15
16
17
18 Q.
19
20 A.
21
22.23
Does the Company accept Mr. Thaden's recommendation to increase
communications related to the Idaho Moratorium and the Winter Payment
Plan by revising the Customer Information brochure?
Yes. The Consumer Information brochure distrbuted in residential bms annually
includes a paragraph on the Winter Payment Plan and information related to the
winter moratorium is included under the "Disconnectìon Notices" setìon. This
brochure is included as Exhibìt No. 76. The Company wm revise the brochureìn
an effort to make these two topics more promìent. These changes wìl be
incorporated in the next version that wm be printed in late 2010.
Does the Company accept Mr. Thaden's recommendation to attach bil
inserts to disconnection notices?
No. The Company's disconnect notìce includes a paragraph describìng the winter
moratorium. Refer to Exhibit No. 77. The Company wil look ìnto a redesign of
the notice that wil include Winter Payment Plan information. The Company's
preference is to include this additional informtìon prominently on the notìce as
1058
Coughlìn, Di-Reb - 20
Rocky MountaÌn Power
.1 an alternative to creating and attachìng a new bìl ìnsert. The Company curntly
2 has a new supply of disconnectìon notices but wil complete a redesign for use in
3 the fall of 201 1.
4 Lend-A-Hand program
5 Q.
6
7
8 A.
9
10
11.12
13
14 Q.
15
16
17 A.
18
19
20
21
22.23
What comments do you offer with respect to Mr. Thaden's recommendation
that the Company implement additional ways that customers can contribute
to the Lend-A-Hand program?
The Company promotes the benefits. of the Lend-A-Hand program and provides
the opportnity for customers to donate regularly. This is accomplished through
three donation envelope distributions in bìls durng the months of November,
Februar and June as well as through the inclusion of program information on the
Company's home webpage, on-line payment webpage, in customer newsletters
and press releases.
Please refer to Mr. Thaden's Exhibit No. 120. Does the Company support
the changes to this envelope as suggested by Mr. Thaden on page 15 of his
testimony?
No, the Company is not supportive of changing the mailng address for
contrbutions to the Idaho Lend-A-Hand Program, as the address used goes
dìrectly to the Company's central cash remittace operation center where the
donations are processed and funds are forwarded monthly to our parerig
agencies. However, the Company wil change the name on the envelope from
"Lend A Hand" to "Idaho Lend-A-Hand" which may make it more evident that
the donations wìl be directed entìely to assist households in Idaho.
1059
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Rocky Mountain Power
.1 Q.What other ways does the Company promote contributions to the Idao
2 Lend-A-Hand?
3 A.The Company appreciates Mr. Thaden's posìtive feedback on our maketìng of
4 the Lend-A-Hand program. We also promote the Fixed Donation component that
5 allows customers to contrbute a designated amount monthly on their bil, through
6 aricles in the Company's Voices customer newsletter and press releases. The
7 Company does not have the abì1ty to include a check box on bìling statements
8 due to the lìmitations of our customer servce system and remittance processing
9 machines. However, as an alternative, we wil include the Fixed Donatìon details
10 on a tear away flap on payment remittance envelopes durng a monthly bìl
11 distrbution in early 2011. Customers interested in paricipatìng in the Fixed.12 Donation program wìl be able to designate theìr monthly contrbution amount
13 and enroll by including the tear away portion, also called a bangtail, in the
14 envelope with theìr payment. If this proves to be an effective means of obtaÌning
15 contrbutions, we wìl distrbute the bangtaÌI envelopes annually and expand theìr
16 use to our other state fuel funds.
17 Q.What comments do you offer regarding Mr. Thaden's statement on page 10
18 of his testimony in which he mentions that state funding is not available in
19 Idaho?
20 A.To obtan additional funding to help customers pay theìr energy bìls, the
21 Company belìeves the answers may be found in the Idaho legislatue rather than
22 at the utìlty..
1060
Coughlìn, Di-Reb - 22
Rocky MountaÌn Power
.
.
.
1 Energy Conservation Education
2 Q.
3
4
5 A.
6
7
S
9
10
11 Q.
12
13 A.
14
15
16
17
is
19 Q.
20 A.
21
22
23
Does the Company agree with Mr. Thaden's recommendation regarding a
workshop on providing energy conservation education to low-income
households?
Yes. The Company belìeves it would be wortwhile for Commssion staff to lead
a workshop with attendees representing electrc and gas utiìties as well as staf
from the local agencies that work with limted ìncome households on a daÌly
basis. It is importnt for gas supplìers to parcipate and provide funding for this
effort as a large.percentage of our residential customers' heatìng source is natural
gas.
Does the Company support Mr. Thaden's recommendation related to the
funding of low income energy conservation education.
Yes. We appreciate that Mr. Thaden recognizes that Rocky Mountain Power staff
has worked with CAP AI staff in developìng a program plan and goals in an effort
to implement this project. Rocky MountaÌn Power made a one-time commtment
of $50,000 to fund low income energy conservation education in Februar 2009
though a Stipulatìon in Case No. PAC-E-OS-07. Those funds have yet to be used
by CAP AI for this effort.
What recommendations from Ms. Ottens will you be addressing?
Ms. Ottens recommends the Commssion accept the following recommendatìons:
.Rocky Mountaìn Power should increase funding of theìr Low Income
Weatherizatìon Program to reflect a per customer level equal to that of
A VISTA; and,
1061
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Rocky MountaÌn Power
.1
2
.Remove the matchìng requìrement where seventy-fìve percent of each
dollar of fundìg comes from a non-utilty source such as U.S. Deparent
3 of Energy LIHEAP funds.
4 Low Income Weatherization Funding
5 Q.
6
7 A.
8
9
10
11.12
13
Does the Company support Ms. Ottens recommendation to increase Low
Income Weatherization Progrm funding toequal that of Avista?
No. The Company's funding of the Low Income Weatherization Program
(Schedule 21) cannot be diectly compared wìth other utilties. For example,
A vista provides both electric and natual gas service in portons of Idaho, and the
Company provides electrc service only. A greater percentage of the Company's
residentìal customers use natural gas as a heating source. Since the largest
opportnity for energy savings is often related to heating effìcìencies, it would be
necessar to include funding from the natural gas supplìer serving the Company's
14 customers in a funding comparson.
15 Low Income Weatherization Matching Funds
16 Q.
17
18
19 A.
20
21
22.23
What comments does the Company offer with respect to Ms. Ottens
recommendation to remove the seventy-five percent funding match
requirement in the Company's Low Income Weatherization Program?
Ms. Ottens misstates the matching requìrement in effect though the Company's
Low Income Weatherizatìon Program (Schedule 21) on page 2 of her testìony.
Funding from the Company is avaÌlable to cover seventy-five percent of the cost
of the installation of efficiency measures, and our parnerig agencies use just
twenty-five percent of fundìng from other government sources to cover theìr
1062
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Rocky Mounta Power
.1
2
3
4
5
6
7
8
9
10
11
12.13
14
15
16
17 Q.
18
19 A.
20
21
22
.23
costs. The Company belìeves it is appropriate for our customers to obtain benefits
from these federal funds as they pay taxes that support these programs. This is
accomplished by leveraging a portion, just twenty-five percent of these funds with
those obtaÌned though the surharge to the Company's customers.
We appreciate Ms. Ottens reference to the program as a cost effective
DSM program. A program evaluation is currently in progress by an external fir.
We anticipate this evaluation that wil include a cost effectiveness analysis wìl be
completed in Februar 2011. Order No. 30239 in Case No. PAC-E-06-1O
requìres Rocky MountaÌn Power to conduct a study to determne the cost-
effectiveness of ìts Weatherization Program after March 31, 2009. The Company
initìated the evaluation process in 2010 in order to allow for more completions to
be studied under the curent program guidelìnes which were effective April 1,
2007. A year or more of post consumption paricìpation data wil be included in
the analysis. The Company believes it is appropriate for paries to review the
results of this evaluatìon before progra changes, including funding revisions ar
implemented.
Is it appropriate to make changes to the Low-Income Weatherization
Program (Schedule 21) at this time?
No. The Company recommends that the program continue to operate under the
curent tarff, including approved funding levels. Program evaluation results can
be reviewed by the Company, staff and interested pares once avaÌlable. This
information wil be useful in determning if there are beneficial changes that could
be fied for the Commssion' s consideration.
1063
Coughlìn, Di-Reb - 25
Rocky MountaÌn Power
.
.
.
1 Q.
2 A.
Does this conclude your testimony?
Yes.
1064
Coughlìn, Di-Reb - 26
Rocky MountaÌ Power
.
~l.
:~.
18
19
20
1 (The following proceedings were had in
2 open hearing.)
3 MR. SOLANDER: And with that, Ms. Coughlin would
4 be available for examination by the Commissioners or parties.
5 COMMISSIONER SMITH: Thank you.
6 Mr. Otto.
7
'/'\:~''¡,,mNo questions, Madam Chairmari:,'MR. OTTO:
8 COMMISSIONER SMITH: Mr. Olsen.
9 MR. OLSEN:No questions, Madam Chair.,
COMMISSIONER SMITH: Ms. Davison? Mr. Purdy?10
11 MR. PURDY: I do.
12 ~.,"
13 CROSS-EXAMINATION
14
15 BY MR. PURDY:
16 Q.Good afternoon.
17 A.Good afternoon.
Q.We meet at last.-...~
A.Right.
Q.First, I want to ask you a couple que'stions about
21 Communi ty Action iS -- I i m sorry, Rocky Mountain iS èqnseEvation
22 education program.
23
24
25
A.Yes.
Q.And if you need a reference, lIm referring to
page 23 of your rebuttal testimony.
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1 A.Thank you.
2 Q.And on page 23, you address Staff witness
3 Curtis Thaden's testimony concerning this program, do you
4 not?
5 A.Yes, I do.
6 Q.And in your rebuttal, you characterize the
7 conservation education program as a one-time commitment --
8 A.Yes.
9 Q.-- by Rocky Mountain. Is that correct?
10 A.Yes, that i s correct.
11 Q.Am I to assume then that the Company does not
12 intend to fund this on an ongoing annual basis?
13 A.The commitment right now is a one-time, and
14 that i s the only commitment that is out there.
15 Q.All right. And in taking this position, you
16 refer to a Stipulation executed in Case PAC-E-08-07 for
17 support. Is that right?
18 A. That's correct.
19 Q. Without -- hopefully without having to drag out
20 the Stipulation, is your -- is your position that this is a
21 one-time commitment specifically set forth in that
22 Stipulation?
23
24
25
A.Paragraph 8.
Q.Paragraph 8. And do you happen to have the
language to which you rely?
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1 A.Yes, I do.
2 Q.Would you read that, please?
3 A.The parties agree that the demand-side management
4 programs proposed by Rocky Mountain Power in Docket PAC-E-08-01
5 are prudent.
6 Further, the parties agree that a total of
7 $50,000 of demand-side management program funds will be made
8 available to Southeastern Idaho Community Action Agency and
9 Eastern Idaho Community Action Partnership to be used to
10 support conservation education as a component of Rocky Mountain
11 Power i s low-income weatherization program, Schedule 21.
12 Q.All right. Now, what I heard you just read, I
13 guess from my perspective, it did not say anywhere that it was
14 a one-time-only commitment. Would you disagree with that?
15 A.It says, "a total."
16 Q.lIm sorry?
17 A.A total of $50,000.
18 Q.It does characterize the program as a, quote,
19 component, end quote, of the Company's low-income
20 weatherization program. Is that right? Do you see the word
21 "component" used?
22
23
A.Yes.
Q.And isn't it true that the low-income
24 weatherization program is an ongoing annual program?
25 A.Yes, it is.
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20
1 Q.Does it make sense for the Company to
2 characterize it as a component of an ongoing program, yet only
3 be a one-time commitment?
4 A.It is a total of $50,000 commitment.
5 Q.Could a reasonable person construe that as a
6 total annual $50,000 commitment?
7 A.It is a total $50, 000 commitment.
8 Q.All right. And do you know whether, when this
9 Settlement Stipulation was executed, either Avista and/or
10 Rocky -- I'm sorry, Idaho Power had in place a similar
11 conservation education program?
12 A.I am not aware. I was not a part of the
13 Stipulation negotiations.
14 Q.All right. So you were in no way involved in the
15 process that led to the Stipulation?
16 A.No, I was not.
17 Q.All right. If you would, would you please turn
18 to page 24 of your rebuttal?
A.Okay.
Q.And there you address Ms. Ottens' testimony
21 regarding low-income weatherization funding. Is that right?
22
23
A.Yes.
Q.Now, if I am to paraphrase the Company iS position
24 in this case as not proposing any changes to low-income
25 weatherization, would that be a fair characterization?
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18
19
1 A.That would be a fair characterization, yes.
2 Q.And, currently, funding for that program is
3 capped at $150,000 per year, is it not?
4 A.That is correct.
5 Q.So, potentially, the Company could invest less
6 than that amount?
7 A.It could.
8 Q.All right. Do you know when -- I i m sorry.
9 Do you know in what year the $150,000 cap was
10 imposed?
11 A.I believe, subj ect to check, I i m going to say
12 2007. I don i t have the tariff in my book here with me.
13 Q.That i S fair enough. Do you know what the funding
14 level was prior to that?
15 A.No, I do not.
16 Q.All right. So we i ve been operating at that level
17 cap of 150,000 for roughly three years?
A.Correct.
Q.All right. And beginning on line 7 at page 24
20 through line 14, correct me if lIm wrong, but that seems to be
21 the totality of your discussion regarding low-income
22 weatherization funding, just the funding?
23 A.Just the funding piece? Yes, in this testimony,
24 that is correct.
25 Q.All right. And if you would look at and if you
1069
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1 would, please, would you read lines 7 -- I i m sorry, 7 through
2 10?
3 A.No. The Company i s funding of the low- income
4 weatherization program, Schedule 21, cannot be directly
5 compared with other utilities. For example, Avista provides
6 both electric and natural gas service in portions of Idaho, and
7 the Company provides electric service only.
8 Q.All right. Now, you made that statement in
9 response to Ms. Ottens i comparison of Rocky Mountain IS
10 low-income funding to Avista and Idaho Power, did you not?
11 A.Yes, I did.
12 Q.All right. And do you know whether, under the
13 communi ty action agencies for which Community Action
14 Partnership is the umbrella organization, whether the contract
15 between those agencies and Rocky Mountain Power allows
16 customers to receive low-income weatherization program IS
17 benefits who do not use electricity as their primary heat
18 source?
19 A. I do not know about the contracts of the other
20 companies. I would only be able to speak to Rocky Mountain
21 Power.
22 Q.All right, that i s what lIm asking you to do.
23 A.It would have to be measures that would be --
24 provide benefit, electric-specific benefit.
25 Q.All right, let me take another shot at that:
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1 Do you know if the existing contract between the
2 two community action agencies operating in Rocky Mountain IS
3 service terri tory requires that for a participant in the
4 low-income weatherization program to be a participant and
5 recei ve funding, that person must use electricity as their
6 primary heating source, not gas?
7 A.If it were to be for measures that had to do with
8 heating, it would need to be electric as a primary heating
9 source; however, there are other measures -- weatherization
10 measures -- that may be taken that are not directly the heat
11 source.
12 MR. PURDY: Excuse me one second, Madam Chair.
13 Q.BY MR. PURDY: When Ms. Ottens makes a comparison
14 of Rocky Mountain's funding level to Avista' s, is it your
15 understanding that she attempted to compare the Avista
16 customers who were electric, primarily -- electric heaters
17 only?
18 A.No.
19 Q.All right. If she compared Rocky Mountain to
20 Avista' s electric heaters only, would that be a fair
21 comparison, in your mind?
22 A.I still would have concern that you i re making
23 comparisons across the utilities when the utilities'
24 weatherization programs, the measures, vary across the
25 utilities. So I would not say that was a fair comparison.
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1 Q.Aren i t the weatherization measures that are
2 implemented by the community action agencies largely dictated
3 by the United States Department of Energy?
4 A.My understanding is the measures of the different
5 companies, each company has their own measures that they
6 install through their program and they do vary.
7 Q.Do you know to what extent the Department of
8 Energy's standards or Rules or Regulations apply at all?
9 A.I can speak to Rocky Mountain Power's in that
10 Rocky Mountain Power in 2007 changed their program -- this
11 current program -- to adopt some of the DOE standards so that
12 it would allow more flexibility and measures that can be taken
13 for Rocky Mountain Power customers.
14 Q.Now, is it fair to characterize your rebuttal
15 testimony as suggesting that any type of comparison of Rocky
16 Mountain i s low-income weatherization funding to any other
17 utilityl s similar programs is not appropriate without bringing
18 the local natural gas supplier to the table as well?
19 A.Yes, I think that would be appropriate.
Q.Who is the primary natural gas supplier in Rocky
21 Mountain i s part of Idaho?
22 A.As far as our service terri tory, it's my
23 understanding it's Intermountain Gas.
24
25
Q.All right. Now, I i m not asking for legal
opinion, but do you know if the Commission iS authority to force
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1 a natural gas company utility such as Intermountain Gas to
2 implement weatherization measures is compared to an electric
3 utility IS?
4 A.I can i t answer that question.
5 Q.All right. And regardless, do you disagree with
6 Ms. Ottens i premise that it i S desirable to have some kind of
7 parody or equal treatment by Rocky Mountain, Avista, and
8 Idaho Power with respect to their low-income weatherization
9 programs?
10 A.I don i t disagree in the sense that everything is
11 looked at not in general terms but in specific terms. So to
12 make a broad characterization that it needs to be equal, I do
13 not agree with it; but if it was looked at it in specific
14 terms, I would be more willing to entertain that idea of
15 looking at it from that parody perspective.
16 Q.What do you mean by more "specific terms"?
17 A.Well, as I mentioned before, measures differ
18 between company programs. The service -- electric and gas
19 service -- differ between the company programs. And so I am
20 not willing to take and make a general statement, as I said
21 before. It would have to be very specific, looking at the
22 indi vidual programs to see if anything can be drawn as far as a
23 comparison.
24 Q.Have you reviewed Staff witness Beverly Barker iS
testimony in that regard?
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1 A.Yes, I have.
2 Q.And in her testimony, does she suggest some type
3 of a collaoorati ve effort or workshop proceeding to sit down
4 and try to compare the three utili ties?
5
8
A.
Q.
A.
that.
Q.
A.
I would be in agreement with
Yes, I recall that.
6 What do you think of the testimony?
7 I think that that
11 workshop and working towards that end.
12 Q.Thank you.
13 MR. PURDY: Excuse me, Madam Chairman.
14 Q.BY MR. PURDY: All right, I took a shot at two
15 other Company witnesses on this line of questioning, and I
16 guess, tag, you're it, so --
17 A.Okay.
18 Q.-- I i II take another run here.
19 Were you present for Mr. Walj e i s testimony and
20 cross-examination -- I i m sorry, cross-examination testimony
21 yesterday and Ms. Hunter's today?
22
23
A.Yes, I was.
Q.All right. And do you agree with Ms. Hunter IS
24 testimony that you are an integral part of the team that puts
25 together Rocky Mountain's position on low-income weatherization
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1 funding program designs?
2 A.Yes.
3 Q.All right. How would you define your role on
4 that team?
5 A.The low-income program manager that Ms. Hunter
6 referred to is a direct report to me, and as a direct report,
7 all the program operations are reviewed by me and in
8 conj unction with me; and we also reach out to, as Ms. Hunter
9 relaid, we reach out to the DSM group for technical support.
10 Q.Who is the low-income manager you referred to?
11 A.Becky Eberle. I believe you're familiar with
12 Becky.
13 Q.I do know Becky, thank you.
14 And so I don i t know if I'm going beyond what you
15 just testified to, but at the end of the day, does the buck
16 stop with you in making the final Company proposal regarding
17 low-income weatherization?
18 A.No, the buck does not stop with me. We would
19 make a recommendation to, as Ms. Hunter stated, to my bossi
20 would be Karen Gilmore, the vice president of customer service.
21
22
Q.Does the buck stop with her?
A.That i S her determination as to her protocol with
23 Mr. Walje.
24
25
Q.Is that a "yes," a "no," or you don't know?
A.That i s -- it i S her decision whether she takes
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1 that to Mr. Walj e.
2 Q.All right. And do you know from past experience
3 that she does that all the time or occasionally?
4 A.Are you asking specific to these low-income
5 assistance programs or --
6 Q.lIm asking with respect to the low-income
7 weatherization assistance program, who, at the end of the day,
8 says, Look at, weI re going into a general rate case in Boise,
9 Idaho, starting next Tuesday, and here is our formal final
10 position on low-income weatherization funding program design,
11 every other aspect? Who is that person?
12 A.If Becky were to make a recommendation to me and
13 it was a decision that was going to be a significant change, I
14 would take that recommendation to Ms. Gilmore for her review.
15 Q.All right. And did you hear both Mr. Walj e and
16 Ms. Hunter I s testimony that they consider the low-income
17 weatherization program to be a prudent, cost-effective
18 program?
19 A.Yes.
Q.And I assume that you agree with them?
A.I will agree
Q.And, I'm sorry, for Idaho only?
A.For Idaho only, I would say that with regard to
24 this current program, it has been in place since 2007. We are
25 currently in the process of having an evaluation of the program
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1 completed, so to the best of our knowledge it i s cost effective,
2 but that will be proven out with the evaluation that will be
3 completed in February, as Ms. Hunter provided this morning.
4 Q.Well, the program has been in place longer than
5 since 2007, has it not?
6 A.But there were changes to the program in 2007
7 which would have a dramatic change to the cost effectiveness of
8 the program.
9 Q.All right. But in one form or another, how long
10 has the program been in place, do you know?
11 A.No, I don't know. I know the program that's in
12 place now has been in place since 2007 and there was a radical
13 change in the program, and the cost-effectiveness test needs to
14 be completed before any changes will be recommended.
15 Q.What i s the name of the entity conducting the
16 evaluation?
17 A.Cadmus. I believe Ms. Hunter mentioned that this
18 morning.
Q.Does Cadmus have any affiliation or association
20 with an organization known as Quantec?
21 A.I do not know the makeup of Cadmus, I'm sorry. I
22 can't answer that question.
23 Q.And by the way, Quantec is Q-U-A-N-T-E-C as I
24 refer to it.
25 Have you heard of Quantec before.
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1 A.I i ve heard of it, but I do not know the
2 relationship there. I can i t answer your question.
3 Q.All right. And you have, I assume, reviewed
4 clearly, you've read through the testimony of Ms. Ottens, but
5 both Ms. Barker and Mr. Thaden on behalf of Commission Staff as
6 well, have you not?
7 A.Yes.
8 Q.Are you familiar with their various testimonies
9 about the need for low-income weatherization versus the
10 resources for that program?
11 A.Yes.
12 Q.And do you agree with me that all three of them
13 come to the conclusion that need substantially exceeds
14 resources as they now exist?
15 A.I agree that's what they all stated in their
16 testimony.
17 Q.And as the person responsible for making the
18 final recommendation to Ms. Gilmore, do you take into account
19 the need, available resources, and the disparity between those
20 two?
21 A. We take into account the need, available
22 resources. We also take into account the impact on all our
23 ratepaying customers in the state, as well as the evaluation
24 results that we receive.
25 Q.And is the Cadmus evaluation going to take that
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1 into account as well?
2 A.The Cadmus evaluation I have not seen and I
3 cannot speak to that.
4 Q.Well, you are conditioning -- strike that,
5 please.
6 You are taking the position, are you not, in your
7 rebuttal that no changes should be made to low-income
8 weatherization pending the final outcome of that evaluation?
9 Is that right?
10 A.Yes, that's true, but I i ve also just said that we
11 would take into consider all the other factors I just listed
12 when we make a recommendation.
13 Q.Well, because you condition any change to -- and
14 I i II call it LIWA -- because you condition any change to LIWA
15 on the outcome of the evaluation, certainly you must have in
16 mind some type of data that that evaluation is going to provide
17 to the Commission that is relevant in making -- proposed in
18 making changes to LIWA?
19 A.I don't know how else to state it that we will
20 take into consideration the results of that evaluation, what it
21 provides to us, what we i ve heard from the other parties, as
22 well as the impact on all of our ratepayers.
23 Q.You will provide -- I i m sorry, could you repeat
24 that?
25 A.We will base our recommendation on all the items
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1 that I have previously mentioned.
2 Q.Right. But lIm asking about the evaluation, that
3 you condition a change to LIWA on that evaluation. What is it
4 about the evaluation that is significant to you?
5 A.The cost-effectiveness test would be first and
6 foremost as to whether it i S getting the results that were
7 intended.
8 Q.Well, we've just had two witnesses, including
9 Rocky Mountain's president, testify in the last two days that
10 it i S a prudent and cost effective program as is.
11 A.And I stated when I first took the stand that as
12 we know it today, it is, but we have a current evaluation in
13 place, and we believe that before any changes are recommended
14 that it would be the prudent thing to do to get the results of
19
20
21
22
15 that study.
17
Q.
stemmed from
right?
A.
Q.
A.
30239.
Q.
a Settlement Agreement in a prior case. Am I
Yes, that's what the testimony says.
What case was that?
That, I believe, was PAC-E-06-10, Order No.
24 between, among other parties, Rocky Mountain Power and
25
18
Communi ty Action. Is that right?
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1 A.Yes, I believe it does.
2 Q.And pursuant to the Stipulation that was executed
3 in that case, wasn't it agreed that Community Action would not
4 propose any changes to low-income weatherization for roughly a
5 two-year period, from the spring of 2007 till 2009, and among
6 other things in return, the Company was going to conduct a
7 study sometime after March of 2009 regarding the evaluating the
8 low-income weatherization program?
9 A.Right.
10 Q.All right. And, now, here we are. It's, as of
11 today, December of 2010. When is the evaluation expected to be
12 released?
13 A.I believe I i ve already testified to that.
14 Q.Well, all right. I heard Ms. Hunter testify this
15 morning that it might, hopefully, be released in February or
16 March, yet I think I saw in your testimony you said February.
17 Do you really know when it's going to be released?
18 A.I was told by Cadmus February.
19 Q.All right. And has the Company made any
20 commitment in terms of what it intends to do once it has that
21 report in its hand?
22 A.I believe that I stated in my testimony that it
23 would be appropriate to review it with the parties once we have
24 received it, and that would be our intention: To entertain
25 discussions at that point once we have the evaluation and have
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1 the appropriate information to entertain discussions.
2 Q. I appreciate that it's appropriate and it i S your
3 intention. Do you have any concrete plan of action regarding
4 the evaluation and what you i re going to do with it once it i s
5 completed?
6 A.I believe this morning Ms. Hunter did indicate
7 that it would be included in the annual report. And also the
8 Company is, at the desire of the parties, very willing to
9 entertain conversations. Other than that, I have nothing more
10 specific to offer to you today in response to that.
11
12
Q.
answer?
A.
Q.
report?
A.
Q.
A.
Q.I'LL restate the question. You testified that
Sorry. Are you done? Is that the end of your
13 Yes.
14 It's going to be included in what annual
15
16 The DSM programs she indicated.
17 I i m sorry, could you repeat that?
18 The DSM programs.
19
20 the results of the evaluation will be included in the annual
21 report. Which annual report are you referring to?
22 A. I said the annual report of DSM programs.
23
24
25
Q.All right. When is that due?
A.I do not know.
Q.You don i t know. Well, if you don i t know when
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1 that annual report is going to be published or provided to
2 anyone, then what assurance do we have that Rocky Mountain
3 Power is really going to do anything at all with this
4 evaluation other than its stated general intent that it would
5 be appropriate to discuss with other parties?
6 A.I have stated that the Rocky Mountain Power is
7 very willing to sit down with the parties and discuss the
8 resul ts of the report, Mr. Purdy, and we would very much be
9 willing to do that.
10 Q.Would the Company commit to some type of a formal
11 filing deadline by which it would bring the report to the
12 Commission to the attention and review and allow all interested
13 parties to comment?
14 A.If the Commission believes that appropriate, of
15 course, we would comply with a ruling that they made. If they
16 believe it's important to meet with the parties in informal
17 discussions, we would willingly comply with that also. We i re
18 very willing to bring the information to the parties for
19 discussion. There's no hesitation on our part to do that.
20 This is the best interests of our customers.
21 Q.You testified concerning the matching issue. And
22 by "matching," I mean with respect to any low-income
23 weatherization project for Rocky Mountain Power, there has to
24 be at least 25 percent Federal funding included. Is that
25 right?
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1 A.That i S correct.
2 Q.All right. The same questions I'm going to ask
3 you about parody involve low-income weatherization between
4 Idaho Power, Avista, and Rocky Mountain Power, given -- apply
5 here.
6 Gi ven that neither Idaho Power nor Avista require
7 a 25-percent Federal matching, why should Rocky Mountain Power
8 insist on that?
9 A.Rocky Mountain Power wants to serve as many
10 low-income customers, income-eligible customers, with
11 weatherization services as possible, and in having that
12 matching provision, that allows the dollars that are collected
13 by all ratepayers to stretch further to offer more services to
14 the customer.
15 It also serves another function: When these
16 low-income programs are evaluated for cost effectiveness, it
17 will help us achieve that cost effectiveness threshold that i s
18 necessary.
19 Q.So you're saying that the Company iS LIWA program
20 on its own is not cost effective?
21 A.There is that potential that if it was done
22 strictly on Rocky Mountain Power dollars that it would not be
23 cost effective based on the information from -- that I had
24 received yesterday from our low-income or from our DSM folks.
25 Q.Are you aware that Avista does not require any
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1 matching Federal funds with respect to its program?
2 A. I'm speaking to Rocky Mountain Power i s program.
3 Q. i i m sorry, could you repeat that?
4 A. lIm speaking about Rocky Mountain Power's
5 programs. I cannot speak to Avista i s programs.
6 Q. Well, do you know what their matching requirement
7 is, if they have one?
8 A.No.
9 Q.Do you know what Idaho Power i s requirement is, if
10 they have one?
11 A.I believe Idaho Power i s is 85 percent. I don It
12 recall Avista iS.
13 Q.So that would be 15 percent Federal funds
14 required for any given weatherization proj ect?
15 A.Yes.
16 Q.And what is it, again, that i s unique about Rocky
17 Mountain Power? I i m sorry, strike that, please.
18 Of the rationale you provided for the 75/25
19 matching, why wouldn't that same rationale apply for Idaho
20 Power and Avista?
21 A.I can't speak to their programs. I can speak to
22 Rocky Mountain Power's program.
23 Q.Are you aware of any distinctions in terms of how
24 those utilities receive and manage Federal moneys --
25 A.No, I'm not.
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1 Q.-- for weatherization?
2 A.No, lIm not.
3 MR. PURDY: If i might just have one minute.
4 Q.BY MR. PURDY: i wanted to follow up one point i
5 brought up earlier about the evaluation and the fact that
6 it I s it was to be conducted sometime after March 31st of
7 2009 and now we're looking at sometime, i guess, in the spring
8 of 2011 and possibly included in some annual report, we don I t
9 know what the date of that is. Why did it take so long?
10 A.Wi th the program change that i spoke to before
11 where we went to the 75/25 matching with the 25 percent being
12 the Federal dollars, we also made a change so that the measures
13 would line up better with the DOE measures. So, the onset of
14 the new program that started in April of that year was not a
15 calendar year. It would have started April 1, 2007. There
16 were only 52 homes that were weatherized, and in order to have
17 the proper evaluation done we need to have the postevaluation.
18 So it was necessary to wait until there were enough homes
19 evaluated and had that postevaluation -- postevaluation
20 information available before the study could be conducted.
21 Q.Then you had another year -- 2009 -- to work with
22 data, and now you have another year after that, 2010 data?
23 A.i believe that for any DSM program -- this is
24 subject to check and perhaps Ms. Hunter would have the answer
25 to that but any DSM program has a three-year evaluation for
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1 its cost effectiveness, that to evaluate a program immediately
2 after it i S imposed does not provide the proper data.
3 Q.So, meanwhile, Community Action stayed out from
4 any type of seeking any type of change to low-income
5 weatherization for two years. Rocky Mountain Power still
6 hasn i t completed its study; we still don i t know when it's going
7 to come out; we still don't know what it's going to say; and
8 you can't point to anything in that study that i s even of
9 significance or relevance here. Isn't that true?
10 MR. SOLANDER: I i m sorry, I'm going to obj ect:
11 Is there a question in that statement?
12 COMMISSIONER SMITH: I think, Mr. Solander,
13 perhaps the objection would be that it i S argumentative, and
14 that would be sustained.
15 MR. SOLANDER: Thank you.
16 MR. PURDY: Madam Chair, IIll withdraw the
17 question. Thank you.
18 I have nothing further. Thank you.
19 THE WITNESS: You're welcome.
COMMISSIONER SMITH: Mr. Budge, are you weighing
21 in on this?
22
23
24
25
MR. BUDGE: No questions.
COMMISSIONER SMITH: Mr. Price.
MR. PRI CE : I do.
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1 CROSS-EXAMINATION
2
3 BY MR. PRICE:
4 Q.I think Mr. Purdy plowed most of the ground here,
5 but I do have a couple questions really quick.
6 A.Okay.
7 Q.How many residential customers does Rocky
8 Mountain Power have in its Idaho service terri tory?
9 That i s Schedule 1 and Schedule 36 combined.
10 A.I believe I had that number here, if you i II be
11 patient with me. My recall was it was approximately 54,000
12 customers, somewhere.
13 Q.My recollection is 57,000, so that i s the
14 ballpark?
15 A.Fifty-seven, yeah.
16 Q.How many of those residential customers -- again,
17 Schedule 1 and Schedule 36 combined -- rely upon electricity as
18 their sole source of heat?
19 A.I have my number here. 56,430 is what I had.
20 Our last survey indicated 31 percent.
21
22
23
Q.Thirty-one percent?
A.Right.
Q.So doing the quick math in my head, that's
24 roughly, a third of 57,000, let's say 18,000. Does that sound
25 about right, 19,000?
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1 A.Çlose enough.
2 Q.I think 19 is right, yeah.
3 So a substantial number of Rocky Mountain Power IS
4 residential customers rely upon electricity as their sole
5 source of heat?
6 A.I believe I stated 31 percent.
7 Q.Okay. And, again, I don i t want to plow some of
8 the same ground, but going back to that 2009 Stipulation that
9 arose out of PacifiCorp i s last rate case that was PAC-E-08-07,
10 there was nothing in that Stipulation that prevented the
11 Company from awarding or funding its energy conservation
12 education programs on an annual basis. Correct?
13 A.My testimony remains the same, that this was a
14 Stipulation for a total of $50,000.
15 Q.Okay. But there i s no prohibition to make it
16 annual?
17 A.Not that I'm aware of, but I -- I have before me
18 Paragraph 8.
19
20
21
22
23
24
25
Q.Okay.
MR. PRICE: That's all I have.
COMMISSIONER SMITH: Thank you, Mr. Price.
Do we have questions from the Commissioners?
COMMISSIONER REDFORD: No.
COMMISSIONER KEMPTON: No.
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i EXAMINATION
2
3 BY COMMISSIONER SMITH:
4 Q.I just had one on page 24.
5 A.Okay.
6 Q.I got confused on line 10. There's a sentence
7 that says: A greater percentage of the Company i s residential
8 customers use natural gas as a heating source.
9 Greater than what? Greater than Avista or
10 Idaho Power, or greater than --
11 A.Greater than the Rocky Mountain Power customers.
12 Q.So maybe the confusion is over the -- your
13 Company?
14 A.Could --
15 Q.This sentence makes no -- I can i t figure it out,
16 so help me.
17 A.A larger percentage of the Rocky Mountain Power
18 customers use natural gas for heating purposes than electricity
19 for heating purposes.
20 Q.Ah, that's totally different. So it's not a
21 comparison with Avista or Idaho Power?
22
23
24
25
A.No.
Q.You i re just saying you Ire 31 percent?
A.Right, that's correct.
Q.So that means 60-some percent use something
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1 besides electricity?
2 A.Right. Not necessarily all natural gas. There
3 could be propane or oil or --
4 Q.Well, I would suspect that there are very -- I
5 would think that less than 31 percent would use natural gas,
6 given my knowledge of the availability of natural gas in
7 Southeastern Idaho, so that i s why it confused me.
8 A.Okay.
9 Q.So you don't know that they use natural gas; you
10 just know that they don't use electricity?
11 A.Right. We know that about 31 percent of them use
12 electrici ty.
13 Q.And we don't know how many percent use natural
14 gas?
15 A.Right. I do not have that in here.
16 Q.That clears that up.
17 COMMISSIONER SMITH: Any redirect?
18 MR. SOLANDER: No redirect, thank you.
COMMISSIONER SMITH: Thank you for your help,
20 Ms. Coughlin.
21
22
THE WITNESS: You i re welcome.
MR. SOLANDER: We would also ask that
23 Ms. Coughlin be excused.
24
25
COMMISSIONER SMITH: Is there any obj ection to
excusing Ms. Coughlin?
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1 Seeing none, she i s excused.
2 (The witness left the stand.)
3 MR. SOLANDER: Rocky Mountain would like to call
4 Peter Eelkema as its next witness.
5 MR. HICKEY: Eelkema.
6
7 PETER EELKEMA,
8 produced as a witness at the instance of Rocky Mountain Power,
9 being first duly sworn, was examined and testified as follows:
10
11 DIRECT EXAMINATION
12
13 BY MR. SOLANDER:
14 Q.Good afternoon.
15 A.Good afternoon, Mr. Solander.
16 Q.Could you please state your name and spell your
17 last name for the record?
A.Sure. Peter Eelkema, and the last name is
19 spelled E-E-L-K-E-M-A.
20 Q.And whom are you employed by and in what
21 capacity?
22 A.l'm employed by PacifiCorp as a senior consultant
23 in their load and revenue forecasting department.
24
25
Q.Are you the same Peter Eelkema that filed direct
testimony on May 28, 2010?
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1 A.Yes.
2 Q.And did you also file rebuttal testimony on
3 November 16, 2010?
4 A.Yes.
5 Q.Do you have any corrections or changes to your
6 testimony at this time?
7 A.Yes, I do:
8 On page 2 of my rebuttal testimony, lines 7 and
9 8, the sentence that starts with "Mr. Steven McDougal addresses
10 the jurisdictional impacts of Mr. Yankel i s proposal," that
11 should be deleted.
12 Q.Do you have any other additional changes to your
13 testimony?
14 A.No, I do not.
15 Q.And if I were to ask you the questions set out in
16 your prefiled direct and rebuttal testimony today, would your
17 answers be the same?
18 A.Yes, they would.
19 MR. SOLANDER: I would now move that the pre filed
20 direct and rebuttal testimony of Peter Eelkema be spread upon
21 the record as if read.
22 COMMISSIONER SMITH: If there is no objection, it
23 is so ordered.
24 (The following prefiled direct and
25 rebuttal testimony of Dr. Eelkema is spread upon the record.)
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2
3 A.
Please state your name, business addres and present position with Rocky
Mountain Power ("Compay").
My name is Peter C. Eelkema, my business address is 825 N.E. Multnomah, Suite
4 600, Portand, Oregon 97232, and my present posìtion is Lead/Senior Consultant,
5 Load and Revenue Forecasting.
6 Qualifications
7 Q.
8 A.
9
10
11.12
13
14
15
16
17
18
19
20 Q.
21 A.
22
23.
Briefly describe your educational and professional background.
I received an undergraduate degree in Economics from San Jose State University
in San Jose, California. I also received a PhD in Economics from the University
of Kansas.
From September 1989 to October 1993, I was a Managing Research
Economist at the Kansas Corporation Commssion. From October 1993 to March
1996, I was an Economist at the Nevada Office of Advocate for Customers of
Publìc Utilìties. From March 1996 to March 1998, I was a Senior Economist,
Forecastìng, at Sierra Pacìfic Power/Nevada Power Company, and from March
1998 to Januar 2005, I was a Staff Economist, Forecasting at Sierra Pacìfic
Power/Nevada Power Company. From January 2005 to May 2008, I was a
Consultant, Load and Revenue Forecastìng at PacifCorp. I was promoted to my
curent positìon in May 2008.
Please describe your current duties.
I am the senior consultant of the Load and Revenue Forecasting group. The Load
and Revenue Forecastìng group is responsible for the development of the test year
kilowatt-hour ("kWh") sales, number of customers, system loads, and system
1094 Eelkema, Di - 1
Rocky Mountain Power
.1
2 Q.
3 A.
peaks for the Company's six retail jurisdictions.
Have you previously testified before a regulatory commission?
Yes. I have testìfied before the Utah, Wyoming, and Nevada Public Service
4 Commssions, and the Kansas Corporation Commssion.
5 Purpose and Summary of Testimony
6 Q.
7 A.
8
9
10
11.12
13
14
15 Q.
16
17 A.
18
19
20
21
22
23.
Please explain the purpose of your testimony in this proceeding.
I describe how PacìfiCorp developed the test year number of customers and bìls,
kWh sales at the meter ("sales"), and system loads and system peak loads at the
system input level ("loads") for the 12-months ending December 31,2010. The
Company produces test year sales and peak for all six states in which the
Company serves retail customers which are necessar for the development of
jursdictional allocatìon factors, test year revenues, and test year net power costs.
In addition to the test year bìls and sales at the class level, the Company has
developed test year bìls and kWh sales by rate schedule for Idaho.
How were 2010 test year sales utilzed in preparation of this general rate
case?
Test year loads for Idaho for the twelve-months endìg December 31,2010, were
used to calculate net power costs, and also used by Company witness Mr. Steven
R. McDougal to calculate the revenue requirement and jursdictional allocatìon
factors. Additìonally, test year sales by rate schedule are used by Company
witnesses Mr. Willam R. Griffth and Mr. C. Craig PaÌce to allocate costs between
customer classes and to design rates which correctly reflect the cost of service.
The sum of energy by rate schedule tìes to test year energy by customer class.
1095
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.1 Q.
2
3 A.
4
5
6
7
S
9
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Pleas explain why this Commission should rely on a 2010 test year sales
instead of 2009 actual sales and peak as the basis for the rate case?
Idaho's 2009 sales were unusual for at least two reasons. Fìrst, 2009 industral
sales were abnormally low. Second, an unusually wet sprig resulted in a
decrease ìn ìrgation sales. The usage from these two customer classes decrease
approximately 20 to 21 percent from 2007 and 200S level, reducìng Idaho's 2009
tota sales approximately 12 to 13 percent from 2007 or 200S levels. Table 1
provides a comparison of weather normalized sales for the past thee years and
the test year for the Idao jursdiction.
Table 1 - Idaho Historical Weather Normalized and Test Year Sales (MWh)
Idaho
2007 2008 2009 2010
Actual Actual Actual Test Year
Residential 703,206 707,545 701,865 708,442
Commercial 395,197 394,786 432,685 402,252
Industrial 1,667,149 1,642,706 1,301,528 1,645,256
Irgation .636,390 619,643 519,126 545,290
Lighting 2,215 2,488 2,556 2,560
Total 3,404,156 3,367,168 2,957,760 3,303,800
11 Table 1 shows Idaho test period sales are 11.7 percent higher than weather
12 normalized sales in 2009, but in lìne with 2007 and 200S data. Below, Table 2
13 provides the same view at a total Company leveL.
1096 Eelkema, Di - 3
Rocky Mountain Power
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1 Table 2 - Company Historical Weather Normalizd and Test Year Sales (MWh)
.
Tota Company
2007 2008 2009 2010
Actual Actual Actual Test Year
Residential 15,553,797 15,746,851 15,614,657 15,852,572
Commercial 15,788,129 15,956,997 16,084,321 16,104,632
Industrial 19,396,932 20,124,653 18,711,760 18,959,206
Irgation 1,398,259 1,366,554 1,240,038 1,285,620
Public Authority 428,141 447,396 437,218 436,640
Lighting 136,080 141,122 144,765 141,150
Total 52,701,339 53,783,573 52,232,759 52,779,820
2 Table 2 shows total Company sales for the test period are 1.0 percent higher than
3 weather normalized sales ìn 2009.
4 Q.
5 A.
How is your testimony organized?
My testimony explains how I developed the normalìzed load used in this case. I
6 wìl address thee man areas: (l) I describe the process for developing test year
7 sales for residentìal, commercìal, ìrgation, lìghtìng, and industral customer
8 classes; (2) I describe the process of adding lìne losses and then spreading the
9 load to each hour of the test year; and (3) I describe the process of developing test
10 year sales and bìls by rate schedule.
11 Summary of Development of Test Year Loads
12 Q.Please provide a general overview of the methodology to develop test year
13 sales and peak.
14 A.In summar, this methodology consists of usìng monthly actual sales by customer
15 class in a model which fìts sales to weather and economic drvers. Then using
16 economic drvers, the model yields monthly test year sales by customer class. In
1097 Eelkema, Di - 4
Rocky Mountan Power
.1 a separate analysis, the model uses sales and peak data along with weather
2 varables to yield jursdictional test year peaks. Test year monthly sales become
3 the basis of test year loads by adding lìne losses, i.e., kWh sales levels are
4 grossed-up to a generatìon or "input" leveL. The monthly loads are then spread
5 out to each hour based on the test period peaks and actual hourly load.
6 Test Year Sales for Non-Industrial Customer Classes
.1 modelìng concepts with traditional regression analysis techniques. Major drvers
2 of the SAE-based residentìal model are heatìng and cooling related variables,
3 equipment shares, satuatìon levels and efficiency trends, and economic drvers
4 such as household size, income and energy price.
5 For the commercial class, the Company develops test year sales per
6 customer using regression analysis techniques wìth employment used as the major
7 economic drver in addìtion to weather-related varables.
8 For other classes, the Company develops test year sales per customer
9 though regression analysis techniques using time trend varables.
10 Test Year Industrial Class Sales
11 Q..12
13 A.
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22.23
How does the Company develop test year sales for the industrial customer
class?
The industrial customers are separated into thee categòries: (l)existing
customers that are monitored by the Customer Community Managers ("CCMs");
(2) new large customers or expansions by existìng large customers; and (3)
industrial customers that are not assigned CCMs. Customers are assigned CCMs
if they have a peak load of one megawatt or more at a single site.
The Company develops test year sales for the fìrst two categories though
the data gathered by the CCMs assigned to each customer. The CCMs have
ongoing diect contact with large customers and are ìn the best position to know
about the customer's plans for changes in business processes, which might impact
their energy consumption.
The Company develops the porton of test year industral sales related to
1099 Eelkema, Di - 6
Rocky MountaÌn Power
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new large customers and expansion by existing large customers based on direct
input of the customers, load factors, and the probabìlty of the project occurrence.
Smaller industral customers, i.e., under one megawatt, are more homogeneous
and are modeled using regression analysis with trend and economic varables.
Employmentis used as the major economic drver.
The Company develops the total test year industral sales by aggregating
test year sales for the thee industral customer categories.
Why does the Company develop test year industrial sales using a different
methodology than the methodology used for the other customer classes?
The Company relìes on a different methodology because of the diverse makeup of
the customers within the class. In the industral class, there is no "typical"
customer. Large customers have very diverse usage patterns and power
requìrements. It is not unusual for the entire class to be strongly influenced by the
behavior of one customer or a small group of customers.
The non-industral customer classes are generally composed of many
smaller customers that have simiar behaviors and usage patterns. No small group
of customers, or single customer, influences the movement of the entìre class.
This difference requìres the diferent processes for developing test year sales.
19 Development of Test Year Hourly Loads
20 Q.
21 A.
22
23
Please outlne the development of test year hourly loads.
After the Company develops test year monthly energy sales by customer class,
test year hourly loads is developed in two steps:
Fìrst, monthly and seasonal peaks for each state are developed. The
1100 Eelkema, Di - 7
Rocky Mountaìn Power
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monthly peak model uses historic peak-producing weather for each state, and
incorporates the impact of weather on peak loads though several weather
varables which drve heating and cooling usage. These weather varables include.
the average temperatue on the peak day and lagged average temperatues. Test
year peaks based on average monthly historical peak-producing weather for the
period 1990-2009.
Second, the Company obtains test year hourly loads for each state from
hourly load models using state-specific hourly load data and daly weather
varables. The Company develops hourly loads using a model that incorporates
the twenty-year average temperatues, a typical annual weather pattern, and day-
type varables such as weekends and holìdays. The hourly loads are calìbrated to
match the monthly and seasonal peaks from the first step above. Also, the hourly
loads are calibrated so that the monthly sum of hourly loads equals monthly sales
plus line losses.
How are monthly system coincident peaks derived?
After the test year hourly loads are developed for each state, hourly loads are
aggregated to the total system leveL. The system coincìdent peaks can then be
18 identifìed as well as the contrbution of each jurisdictìon to those monthly peaks.
19 Curtilment Adjustments
20 Q.
21
22 A.
.23
Please describe test year curtalment and how it is reflected in the model
driven results?
Test year curtaÌlment is developed for industral sales and peak ìn Idao and Utah.
Industral curtailment consists of interrption and buy-thr. Test year curtilment
1101 Eelkema, Di - 8
Rocky Mountain Power
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is developed for ìrgatìon peak in Idaho and Utah. Irgatìon curaìlment consists
of only interrption. Test year residential air conditioning curailment is
developed for Uta.
Test year sales are gross of buy-th, but net of interrptìon. That is, the
model drven test year sales are drven by historic sales data which contains both
retail sales and buy-th.
The historical monthly peak data is also gross of buy-th, but net of
interrption. Monthly historical peaks have been adjusted to reflect the
interrption which occured at that hour; therefore, the model drven peaks is
gross of interrption and buy-thr.
Why didn't you make one adjustment to reflect curtailment in the model
driven results?
As mentioned earlìer, test year sales and peak are used by diferent groups and
each group treats curlment differently. Therefore, it is necessar for each group
to make an adjustment for curailment specific to how they use curilment.
Please desribe the method used to develop test year curtailment.
Test year sales is not adjusted to reflect the effects of the ìrgation program
because the Company is assuming 100 percent tae-back. Irgators knowing they
may be curtailed durng the 2:00 p.m. to 6:00 p.m. window wil ìrgate around
the curilment hours. As a result, energy wìl be shifted away from curtilment
hours, but the daìly energy wìl not change apprecìably. Also, the Utah residential
aì conditioner program is energy neutral.
Test year peak curaìlment to reflect the effects of the ìrgation programs
1102 Eelkema, Di - 9
Rocky Mountain Power
.1 in both Idao and Utah are calculated as the ratio of class usage at the tìme of
2 coincìdent peak to maximum class usage times the maximum curtaìlment from
3 the program.
4 Test year peak and sales curaiment to reflect the effects of the Idaho and
5 Utah industral programs is estimated based on a 5-year average historical
6 monthly interrption and buy-th. In 2010, there is an increase ìn Idaho
7 industrial potentìal curtilment which is not reflected in the historical data. It is
8 assumed that the customer wìl buy-ththese additional hours.
9 Test Year Rate Schedule Sales
10 Q.Why does the Company develop test year rate schedule sales?
11 A.To perform the class cost of service and rate design analysis, two additional.12 projections that are based on test year kWh sales and test year number of
13 customers are required. Once the test year kWh sales are complete, it must be
14 applìed to individual rate schedules to develop test year kWh sales by rate
15 schedule. In addition, test year number of customers must be expressed in
16 number of bìls.
17 Q.How are test year rate schedule level sales projected?
18 A.This process is cared out in two steps. Fìrst, the Company projects each rate
19 schedule's share of the customer class sales. Second, the Company multìplìes the
20 projected rate schedule share by the test year customer class sales to project sales
21 by rate schedule.
22 Q.How is the number of test year bills for each schedule developed?
.23 A.Simiar to the test year rate schedule sales, the test year rate schedule bìls is
1103
Eelkema, Di - 10
Rocky Mountain Power
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cared out in several steps. Fìrst, the Company calculates the ratio of bils to
sales by rate schedule to bìls by customer class. Second, this ratìo is projected
3 for the test period based on the regression results. Thìrd, the ratio is multìplìed by
4 the customer class bìls to produce the bìls by rate schedule.
5 Conclusion
6 Q.
7 A.
8
9 Q.
10 A.
Do you consider the test year sales and loads to be reasonable?
Yes. Actual 2010 sales have an equal probabìlty of being more than or less than
test year sales.
Does this conclude your testimony?
Yes.
1104
Eelkema, Di - 11
Rocky Mountaìn Power
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Please state your name, business address and present position with
PacifiCorp dba Rocky Mountain Power (the "Company").
My name is Peter C. Eelkema. My business address is 825 NE Multnoma, Suite
600, Portand, Oregon 97232. My present position is Senior Consultant in the
Load Forecasting Deparent.
Are you the same Peter C. Eelkema who submitted direct testimony in this
proceeding?
Yes.
What is the purpose of your testimony?
My testimony in this case rebuts the testimony of Idaho Irgatìon Pumpers'
Association ("lIP A") wìtness Mr. Anthony J. Yanel and the testìmony of the
PacuiCorp Idaho Industrial Customers ("PIIC") wÍtness Mr. Greg A. Meyer:
· I wìl explaìn why this Commssion should not accept Mr. Yanel's
adjustment to ìrgation sales.
.I wìl also point out why this Commssion should not accept Mr. Meyer's
16 proposed residential revenue adjustment.
17 Irrigation Sales Adjustment
18 Q.
19 A.
Please summarize Mr. Yankel's testimony and the isues you are rebutting.
Mr. Yankel is recommending an increase in test year ìrgation sales to 662,167
20 MWh. The Company's annual ìrgation sales included in the test year are
21 545,290 MW. Mr. Yankel's recommendatìon increases ìrgation sales revenues
22 by approximately $7,049,436. This adjustment should be rejected by the
23 Commssion.
1105
Eelkema, Di-Reb - 1
Rocky Mountan Power
.1 Q.Please explain.
2 A.Fìrst, Mr. Yankel did not recognize that there was a distinct change in weather
3 normalized ìrgatìon sales staring in 2002. Second, Mr. Yankel did not make a
4 compensating adjustment to reflect the increase ìn power costs associated with the
5 addìtional energy requìrements which would increase net power cost by
6 $6,119,173. And fìnally, Mr. Yankel does not make an adjustment for
7 jursdictional or class cost of service demand factors. Mr. Steven R. McDougal
8 addresses the jursdictional impacts of Mr. YankeI's proposal.
9 Q.Is there a statistical test of whether there is a change in the rate of irrigation
10 growth?
11 A.Yes. While the Company cannot be certaìn of the cause, our analysis.12 demonstrates to more than a 95 percent confident level, that there has been a
13 statistically significant decrease in the rate of growth.
14 Q.Is Mr. Yankel's conclusion that there is an upward trend in Idaho irrigation
15 weather normalized sales correct?
16 A.No. Mr. Yankel used a simple tìme trend from 1998 to 2008 to estimate the
17 change in ìrgation sales for that period. The result of Mr. Yankel' s specìfìcatìon
18 is an upward trend in ìrgation sales. However, this specìfìcation does not reflect
19 a change in the rate of ìrgation sales growth around 2002. As shown in Figure 1
20 below, a time trend varable that is fìt to annual weather normalized data from
21 1998 though 2009 indicates that since 2002 ìrgation sales have been declining
22 instead of increasing as concluded by Mr. YankeL..
1106
Eelkema, Di-Reb - 2 .
Rocky Mountaìn Power
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r.....................................................................................................................................................................................................................ìI Figure 1 I
I Normalized Irrigation Sales 1998 to 2010 I
I 700,000 ................................................................................................................................................................. Ii ¡ ,. l
I 650,000 1..............................................................................................................¡.............................~......... ¡
Iil 600,000 ..I..................................................................................................................~....................:.......... II.. ¡ . . .
! ~ 550,000 ¡..................................... ....................................................................................................:.$......... ii ¡ · it
Ii, 500,000 ..1"................. . ............................................................................................................................... I450,000 .1'........................................................................................................................................................I ~
I 400,000 ,=~~~~~~~~~;~-~~~~;~~~;:~~~-:~;~~"
ì . Weather Normalized .á Company Test Year 0 Mr. Yanke I ProposedL.______.__._......._..._ ....._......._......__....__ _.__..._~..._
What is your estimate of 2010 irrigation sales based simply on a 1998-2009
trend line which allows for a change in the rate of irrigation growth?
Test year 2010 ìrgatìon sales would be 574,609 MWh instead of 662,167 as
proposed by Mr. YankeL. 2010 ìrgatìon sales based on the time trend is much
closer to the sales amount included in the Company's filìng.
Should the Commission adopt 574,609 MWh as test year irrigation sales?
No. The Commssion should adopt the Company's original test year sales of
545,290 MWh. A trend line based on annual sales is an oversimplifìed method to
develop test year sales and highly influenced by the period of tìme chosen for
analysis. A better approach is to model monthly ìrgation sales though a
structued model which allows more flexibìlty. An example of the increased
flexibilty is the ability to recognize a change in the trend. The Company has used
this approach to develop test year sales.
1107
Eelkema, Di-Reb - 3
Rocky Mountaìn Power
.1 Q.What other observations can you glean from Figue I?
2 A.Firt, as noted earlìer, there is a slight downward trend to the data in recent years.
3 Second, Mr. Yankel's recommended sales level is above even the highest level of
4 weather normalized sales and clearly not consistent with recent experience.
5 Q.Are there other reasons that irrigation sales have been decreaing?
6 A.Yes. The Company has an energy efficìency program tageted to Idaho ìrgators.
7 The Company has a program encouraging the installatìon of varable frequency
8 drve ("VFD") pumps. These pumps allow ìrgators to use electric energy more
9 efficiently by better controllng the amount of water being pumped.
10 Q.Is there an upward trend in Idaho irrigation number of customers as
11 concluded by Mr. Yankel?.12 A.Yes. Fìrst, I would also note that what the Company tracks and labels
13 "customers" are actually sites or points of service.One customer may be takìg
14 service at more than one sìte.
15 Q.Please explain why the number of sites is increasing.
16 A.As mentioned earlìer, a customer may have multiple sìtes serving the same
17 acreage. A customer may have one meter for the pump to bring water to the
18 surface and another meter for the pivot ìrgatìon system. If a customer installs a
19 pivot system on land which previously had a wheel line, the number of sites may
20 increase even though the amount of land being ìrgated has not increased. So the
21 upward trend in the number of sìtes is not an indicator of increasing ìrgation
22 sales..
1108
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Rocky MountaÌ Power
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How can changing irrgation of land from wheel line to pivot system not
increase irrigation sales?
There ar a number of reasons. For example, as farers convert theìr ìrgation
systems, they may upgrade to more effìcient VFD pumps and pivot systems that
apply water much more effciently. Therefore, the change from wheel lines to a
pivot system wil likely reduce ìrgation energy sales because the pivot system
applìes water more efficìently. Looking only at the growth in sites, while
ignoring these other factors, is over-simplìfied and an inaccurate approach. The
increased number of sites with vìrally no change in the amount of land being
ìrgated is not a legìtimate indicator of increasing ìrgation sales.
Has there been a change in the amount of agricultural land in the Company's
service territory?
No. Although the Company has not been able to find statistìcs on the amount of
land under ìrgation in the service terrtory, discussions wìth the county
agricultural extension agents and a representative of the Idao Deparment of
Water Resources, indicate there is vìrally no new land being ìrgated.
Mr. Yankel states that weather normalized 2009 sales volume is an outlier
base.on his time trend. Is Mr. Yankel correct that 2009 weather normalized
sales are an outlier?
No. Once Mr. Yanel's regression time period is changed to reflect the shift in
sales, 2009 weather normalized ìrgation sales are not an outler. In fact, with the
corrected time period, as I note above, Mr. Yankel's test year sales are the outler
that does not fit into the trend lìne as shown in Figure 1.
1109
Eelkema, Di-Reb - 5
Rocky Mountaìn Power
.1 Q.Please describe the Company's methodology for weather normlization.
2 A.The Company performs several steps in developìng Idaho ìrgatìon weather
3 normalizatìon. Fìrst, the Company uses a model to identify the relatìonship
4 between weather and ìrgation sales. The Company utìlìzes load research data
5 for this modeling because it provides a view of the relationship between sales and
6 weather on a daily basis. Based on fìve years of data this provides approximately
7 525 observatìons (daìly observations for five summers) of this relatìonship. From
8 load research data, the Company analyzes the sensitivities of sales at different
9 temperatue levels to see if there are any breakoìnts or changes in this
10 sales/weather relationship. Also, the Company can analyze which weather
11 varable best explains varations in ìrgation sales..12 The Company then uses the identìfcation of the weather varable that
13 provides the best fit in the monthly modeL. This is done by properly matchìng the
14 temperature variable to the biling cycles and estimating monthly sensitivity of
15 ìrgation sales to weather. The weather normalization adjustment is the estimated
16 coeffìcient which reflects weather sensitivity multiplied by the difference between
17 actual and normal weather.
18 Q.Why ~oesn't the Company include precipitation as the weather driver in its
19 model?
20 A.The Company has chosen temperature as measured by Cooling Degree Days with
21 a base of 50 degrees ("CDD50") as its weather drver. The Company recognized
22 that CDD50 is a better indicator of ìrgation need than other varables such as.23 precipitation, humidity, wìnd speed, and cloud cover. One of the maìn reasons is
1110
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Rocky Mountan Power
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have discussed and should be rejected by the Commssion.
Please summarize Mr. Yankel's criticism regarding the Company's test year
residential sales.
Mr. Yankel is not recommending an adjustment, but he belìeves that the
Company's test year residential sales are understated.
Do you agree with Mr. Yankel's statement on Yankel DI.12, lines 6.7 that the
Company's test year forecast for residential sales are too low?
No. Mr. Yankel relìed on a comparson of weather normalized residentìal sales
Januar 2010-June 2010 on a cycle month basis (388,366 MWhs) agaìnst the
Company's fied residential sales forecast Januar 2010-June 2010 (365,652
MWhs) which is on calendar month basis. The correct comparson using
weather-normalized actual sales on a calendar basis (as shown in Table 1)
demonstrates that the Company's residential sales forecast for the first six months
of test year is very reasonable.
Table 1
Residential Sales in MWH: Jan 2010.Jun 2010
PacifiCorpls Forecast 365,652
Weather Normalized Actuals.
Calendar Basis 365,288
Difference 364
% Difference 0.1%
16 Residential Sales Adjustment
17 Q.Please summarize PUC's poition on the Company's propos level of
18 residential revenues.
19 A.Mr. Meyer recommends that the level of residential revenues be increased by
1112
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Rocky Mountan Power
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approximately $1.2 millon. He claims that the Company's test year temperatue
normlized usage per bil of 12,309 kWh, is too low when compared to the
average actual residential use per bìl of 12,675 kWh as measured over the five-
year period 2005 through 2009. To compute the higher residential use per bil,
Mr. Meyer makes two changes to the Company's fìlìng. Fìrst, he removes the
temperatue normalìzation adjustment from the historical data. Second, he
averages five years (2005-2009) of data to calculate the test year use per bilL.
Have you quantified the impact of these changes?
Yes. Table 2 identìfies the cumulatìve effect of the two changes proposed by Mr.
Meyer.
Table 2.Increase from Use per Bil
Company (milions) (kWh) Description
NA
$0.68
$1.2
12 Q.
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14 A.
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16
17 Q.
18.19 A.
12,309
12,518
12,675
Company proposal
Use 5-year avera~e instead of 2010 test period
Remove temperatue normalìzation
Is it reasonable to remove the Company's temperature normalization of
residential loads?
No. Mr. Meyer's proposal implicitly assumes that residential loads ìn Idao are
not affected by temperatue. Mr. Meyer provides no rationale as to why it is
appropriate to ignore temperature normlìzation for the residential class.
Would Mr. Meyer's adjustment reduce the accuracy of the residential load
forecast?
Yes. Removing the Company's temperatu normization of residential loads
1113
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Rocky Mountaìn Power
.1 would decrease the accuracy of the forecast.
2 Q.Doesn't use of a five-year average account for temperature fluctuations?
3 A.No. Obviously a five-year average is not an appropriate surogate for weather
4 normalìzation. The Company's weather normalization is based on 20-year
5 average weather period. Furtermore, a five-year average mixes the effect of
6 weather, effìcìency, growth, and changes in habit. An integrated model such as
7 the Company uses to develop test year sales accounts for these effects in a more
8 comprehensive framework.
9 Q.How do you respond to the other aspects of Mr. Meyer's proposal?
10 A.Mr. Meyer presents no evidence, rationale or precedent for using a fìve-year
11 average rather than the Company's more robust approach of using an integrated.12 model to develop test year sales. The Commssion has traditionally weather-
13 normlized sales by using a long-term definìtion for norm temperatures. In
14 contrast, Mr. Meyer's proposal uses a simple average of actual sales over a much
15 shorter tìme period of fìve years.
16 Q.Are there other errors in the adjustment proposed by Mr. Meyer?
17 A.Yes. While he attempted to account for the NPC effect, Mr. Meyer's over-
18 simplìfied approach was inaccurate. Mr. Meyer also ignored the impact these
19 increased sales would have on jursdictìonal allocatìon factors. Mr. McDougal
20 discusses these to errors in his testimony and demonstrates that if they were
21 correctly modeled Mr. Meyer's proposed adjustment is essentially negated.
22 Q.Please summarize your rebuttal testimony..23 A.Mr. Yankel' s adjustment for ìrgation sales ignores the change in ìrgation sales
1114
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stang about 2002. The Commssion should reject this adjustment.
In addition, Mr. Meyer is recommending an adjustment for residential
sales volume which should not be adopted. Mr. Meyer's adjustment is based on a
simple five-year average and does not recognize weather or other drvers of the
change in residential sales.
Does this conclude your testimony?
Yes.
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Rocky Mountaìn Power
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1 (The following proceedings were had in
2 open hearing.)
3 MR. SOLANDER: And Mr. Eelkema would be available
4 for the examination by the Commissioners and parties.
5 COMMISSIONER SMITH: Thank you.
6 Mr. Otto, do you have questions?
7
8 CROSS-EXAMINATION
9
10 BY MR. OTTO:
11 Q.I do have one or two questions for you. I'm
12 going to refer to page 4 of your rebuttal testimony, and you
13 may have -- were you here when I spoke with Ms. Hunter this
14 morning?
15 A.Yes, I was.
16 Q.Okay. And I asked her about the difference
17 between irrigation sites and customers?
18 A.Yes.
Q.And one of the proposals is to reduce to
20 50 horsepower, and Mr. Mickelsen says that will
21 Have you reviewed Mr. Mickelsen's rebuttal
22 testimony filed by the Irrigation Pumpers?
23
24
25
A.I have read it briefly.
Q.Briefly. Are you familiar with the section where
he says that reducing the eligibility to 50 horsepower would
1116
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1 reduce participating sites by 25 percent?
2 A.i do recall reading that, yes.
3 Q.Do you have any indication of how many customers
4 that would impact?
5 A.No, I do not.
6 MR. OTTO: That i s all I have.
7 COMMISSIONER SMITH: Mr. Olsen.
8 MR. OLSEN: Thank you, Madam Chair.
9
10 CROSS-EXAMINATION
11
12 BY MR. OLSEN:
13 Q.Good afternoon, Mr. Eelkema.
14 A.Good afternoon, Mr. Olsen.
15 Q.Okay. I'd like you -- my understanding is that
16 in your capacity as the consultant for load revenue
17 forecasting, that you fill out these load revenue numbers for
18 this case; and part of the special consideration you talk about
19 initially in your direct testimony on page 3, lines 3 through
20 5, was that there was an unusually wet spring in 2009. Is that
21 correct?
22
23
A.Yes, that is correct.
Q.And this wet spring affected the irrigation sales
24 and also the industrial sales as well. Is that correct?
25 A.Yes, that the wet spring affected the irrigation
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1 sales. I don i t believe I said that it affects industrial.
2 Q.And I apologize, I didn i t mean to combine that,
3 but you did say that industrial sales were down as well?
4 A.Yes.
5 Q.Okay. If we could turn to page 2 of your
6 rebuttal testimony, beginning on line 1, you take issue with
7 the adj ustment which Mr. Yankel has proposed in this case
8 relating to the normalized irrigation sales, and specifically,
9 you say: Number one, he didn i t recognize the distinct change
10 in 2002; and then, number two, he didn't make a compensating
11 adjustment that would be required from an increase in the sales
12 for the net power cost.
13 Is that correct?
14 A.Yes, that is correct. And also I said that there
15 was no adj ustment for changes in the jurisdictional allocation.
16 Q.Okay. Correct, no change in the jurisdictional
17 allocation.
18 I i d like to focus just on the net power costs
19 number. You cite a number there on line 6 of 6,119,173. Is
20 that correct?
21 A.Yes, that is correct.
22 Q.But you don't run that number through the
23 jurisdictional allocation model to come up with Idaho's share,
24 do you?
25 A.lIm sorry, I donlt understand the question.
1118
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1 Q.Well, that i s -- that is a gross number as far as
2 the effect of the net power supply cost. Correct?
3 A.Yeah.
4 Q.I mean, that i s not Idaho i s share of the change in
5 net power supply costs, is it?
6 A.That is correct. That would be the change in net
7 power costs that would be attributable to this change in
8 irrigation sales.
9 Q.Okay. But what lIm saying then, how does that
10 trickle down to Idaho i s allocation of those net power supply
11 costs?
12 A.Well, that would have to be broken out to the
13 hourly level, and then that will affect peak and energy that
14 will have to be put into the jurisdictional allocation model,
15 and then the result will be a change in the cost to Idaho.
16 Q.Okay. And, roughly, that i s usually about five
17 percent of those costs, isnlt it?
18
19
A.I -- I can i t speak to that.
Q.So you didn i t follow that analysis through like
20 you accuse Mr. Yankel of not doing. Correct?
21 A.That is correct. And I want to make it clear
22 that I am not recommending this change to the Commission. I
23 was just trying to get the Commission an idea of the change in
24 net power cost.
25 To do it properly, you would have to, as
1119
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1 suggested by Mr. Olsen, run it through the models to get a
2 proper number.
3 Q.The other change other than the net power supply
4 cost you talk about is a distinct change in weather normalized
5 irrigation sales back in 2002. And then I would like to direct
6 you to page 3 of your rebuttal testimony, Exhibit 1, and you
7 have what I understand to be a regression analysis up there
8 that you propose more properly reflects this distinct change.
9 Is that a fair characterization of your testimony?
10 A.I would characterize this as a very crude
11 regression model, yes. It's based on annual data rather than
12 the Company i s model, which is based on monthly data.
13 Q.Okay. Now, you point to this -- well, I guess
14 your chart here is pretty interesting. I see a kind of an
15 elbow or a bend in that chart. And am I to take away that this
16 is in recognition of your testimony back on page 2, lines 9
17 through 13, that there i s a 95 percent confidence level that
18 there's some significant event that happened in 2002?
19 A.Just based on the numbers, we can say with 95
20 with more than 95 percent confidence that there is a change in
21 the rate of growth.
22 Q.Okay. Now, when did you know that this change in
23 the rate of growth took place?
24 A.This was brought up by Mr. Yankel' s testimony
25 that -- we started looking at this closer and then developed
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1 this curve then that reflects this change in growth.
2 Q.Well, this crude regression analysis that you
3 point out here in Figure 1, you know, looks rather odd. Most
4 regression analyses that I understand of, and hearkening back
5 to my collegiate days or whatnot, you know, don't have a
6 distinct bend.
7 How was this figure derived? Is there just a
8 point through 2002 for the first five data points, and then the
9 next seven data points there's a different point? How do you
10 get the bend like that?
11 A.This regression analysis might be referred as
12 piecewise linear regressions. I think it's a very common
13 technique.
14 Q.Now, would you repeat your answer again? You
15 said piece by?
16 A.I'm sorry. Piecewise linear regression.
17 Q.Okay, piecewise. Explain that to me.
18 A.What it does is it allows if you know the point
19 where you suspect that there might be a change in the linear
20 regression, it allows through the use of a simple variable the
21 testing of whether you are confident that there is a change in
22 this regression, and then estimates the regression based on the
23 idea that the two points must meet up.
24
25
Q.Well, correct me if I i m wrong, but continuing
there on page 3 of your testimony, line -- beginning on line 8,
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1 you know, you talk about Mr. Yankel' s trend line, his
2 oversimplified method to develop the test year, and it i s highly
3 influenced by the period of time chosen for the analysis.
4 Doesn i t this pieceline regression do the same
5 thing by you focusing on test year data for 2002 for the data
6 point?
7 A.Yes. I would agree that it is also influenced by
8 the choice of the point at which you believe that there i s a
9 change. Also, it i S influenced by the total number of points
10 that you want to include.
11 Q.So, for example, if we redid your Figure 2 and
12 focused on 2001, it's really low. What would happen to your
13 line there? Wouldn i t the slope of it go up quite a bit, if I
14 understand it correctly?
15 A.If I understand what you i re suggesting is that
16 instead of ignoring the obvious 2002 break point, you move to a
17 2001?
18 Q.Yes, which is way lower. It looks like it i S down
19 there significantly lower. You go from 600,000 down to just a
20 li ttle bit over 500,000. If you chose that as your break point
21 linear regression analysis, what would happen to the line in
22 general?
23 A.I think that the closer we move to the same
24 starting point that Mr. Yankel used, the more this regression
25 line would look like Mr. Yankel' s.
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1 Q.But I guess for your purposes, the further you
2 move away from his starting point, the less it looks like
3 Mr. Yankel i s?
4 A.With a break point at 2002, the obvious kink
5 there in the curve.
6 Q.Okay. Now, you say that, you know, this was just
7 discovered when you started looking at Mr. Yankel i s testimony.
8 Is that a correct characterization of your prior testimony?
9 A.Yes, that is.
10 Q.Okay. So, for example, if I were to refer you,
11 subj ect to check, to the prior integrated resource plans for
12 2004 and 2007 -- which I will represent, subject to check, that
13 show that there's slight growth in the irrigation class over
14 the going-forward time frames -- you would have no reason to
15 say that that i s not correct for the IRP?
16 A.In fact, I believe that that is correct, that
17 there is, in the IRP, a slight increase in irrigation sales
18 that we model.
19 Q.So you i re saying that the IRP was wrong and that
20 you i re more correct, given your elbow point here in 2002?
21 A.Looking at the annual data here, I think it's
22 obvious that there is a change in the rate of growth at about
23 2002, and that this is a more correct representation of the
24 growth rate.
25 Q.Well, I would refer you, subj ect to check, to the
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1 most recent update. The 2009 update for the IRP has the
2 irrigation load being flat, no growth, or not a decline either.
3 So, I just point that out here for the record.
4 A couple other questions I have here, if you i II
5 just bear with me a moment:
6 If we could turn to page 6 of your rebuttal
7 testimony, I believe you talk about the methodology that you
8 have used for weather normalization of the irrigation sales,
9 and it i S your position that you don i t think precipitation is a
10 good indicator or a factor in your normalization process. Is
11 that correct?
12 A.What lIm saying here is that if you include
13 precipitation in the model, you i re going to have problems.
14 You i re going to have -- that i s going to lead to a biased
15 estimate, which obviously is a bad thing, and that --
16 Q.What do you mean -- I i m sorry, I didn i t mean to
17 interrupt.
18 A.So here you have a choice whether you want to
19 include a temperature variable or a precipitation variable, or
20 al ternati vely, try and find a precipitation variable that is
21 not correlated with the temperature. But -- so given a choice
22 between the temperature variable and the precipitation
23 variable, you i re much better off choosing the temperature
24 variable, because if you can imagine a weather station such as
25 Pocatello, a single weather station, especially in the
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1 summertime, you can have a thunderstorm move over the top of
2 the weather station, you can have a large amount of
3 precipi tation at that one site, but not precipitation in the
4 service territory. So if -- there 's -- using precipitation
5 leads to a poor measure of kind of spatial geographically.
6 Q.However, didn i t Mr. Yankel point out in his
7 testimony that Idaho Power uses a defined precipitation and
8 temperature normalization approach?
9 A.Yes, I did read that in Mr. Yankel i s testimony.
10 Q.But it i S your testimony that that i s not
11 necessarily a better approach, it i s just one approach?
12 A.I believe that's a inferior approach, that it
13 could very well lead to a biased estimate.
14 Q.Thank you, Mr. Eelkema. I have no further
15 questions.
16 A.You're welcome.
17 COMMISSIONER SMITH: Any questions?
18 MS. DAVISON: No, Madam Chair.
19 COMMISSIONER SMITH: Mr. Purdy, do you have
20 questions?
21
22
MR. PURDY: No questions, thank you.
COMMISSIONER SMITH: Do you have questions,
23 Mr. Budge?
24
25
MR. BUDGE: No questions.
MR. PRICE: No questions.
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1 COMMISSIONER SMITH: Questions from the
2 Commission?
3 COMMISSIONER REDFORD: No.
4 COMMISSIONER SMITH: Commissioner Kempton.
5 COMMISSIONER KEMPTON: Chairman, I have one.
6
7 EXAMINATION
8
9 BY COMMISSIONER KEMPTON:
10 Q.Mr. Eelkema, looking at the Figure 1 that was
11 addressed just a minute ago, you used this as an explanation on
12 all of page 3 and a little bit of page 4. At the bottom, you
13 talk about a better approach is to model monthly irrigation
14 sales through a structured model, which allows more
15 flexibili ty. An example of the increased flexibility is the
16 ability to recognize a change in the trend. The Company has
17 used this approach to develop test year sales.
18 Well, I'll return to that particular statement in
19 just a second, but why did you use a broken stick model with
20 two separate linear regressions rather than use Excel and just
21 simply do an exponential curve; and if you started with the
22 very bottom one, you can almost eyeball that and see that it
23 occurred below the point that you've identified in 2002 as a
24 break point, and, in fact, that curve may actually go up a
25 little bit?
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1 A.And I guess we never tried any type of
2 exponential smoothing model for this. Instead, the Company
3 relied on a monthly model because it gives the more granular
4 view. We just feel that it provides more information, more
5 degrees of freedom.
6 Q.I do too. And so why wasn i t there an exhibit on
7 that?
8 A.I'm sorry, that probably is my oversight. I
9 should have included that.
10 Q.So -- and that notwithstanding, does your more
11 sophisticated model actually still indicate a decrease that is
12 as significant as what you had here in the broken stick
13 model?
14 A.No, it actually in- -- the model that was used by
15 the Company for irrigation indicates a slight upward trend in
16 irrigation sales than not without the kink there in the curve.
17 Q.And I i d like to address about the same thing back
18 in your direct, okay. And going back to the more sophisticated
19 one, that gives you your 95 percent confidence level, right,
20 because the broken stick certainly doesn i t do it. So, your
21 more sophisticated model is the one you're talking about a 95
22 percent confidence level. Is that correct?
23 A.No, I i m sorry. When I said 95 percent confidence
24 level, I believe you i re referring to my rebuttal testimony
25 where lIm indicating the confidence level that we have there,
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1 that there is a change in the rate of growth, that there is a
2 kink there in that curve.
3 Q.Okay. A break point?
4 A.Yes.
5 Q.So looking at page 5 on your direct testimony,
6 you use a narrative to test your sales for nonindustrial
7 customers and you separate the two because of the number of
8 data points that you get in the two cases, and then you mention
9 that you use the test year number of customers using regression
10 models based on January '97 to January 2010 time frame.
11 And then is one of the inputs to that in the next
12 sentence where it says the Company also used the most reliable
13 available economic drivers from the IHS Global Insights which
14 was released in December 2009 -- how does that fit into your
15 regression analysis?
16 A.The regression analysis varies between the
17 different customer classes. For the residential and commercial
18 customer classes, we use data from IHS Global Insight as the
19 driver of the forecast.
20 For the irrigation and street lighting, it's more
21 static and there we don't use any economic data.
22 Q.What do you mean by "the driver"? The economic
23 driver for the model?
24 A.It's -- it i S used in the model as an input as a
25 explanatory variable in the model, and then the 2010 number is
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21
22
1 also input into the model so that it -- based on the
2 coefficients of the -- the estimated coefficients from the
3 model times the 2010 number, that then yields the 2010
4 estimate.
5 Q.Okay. Do you know what the confidence level was
6 in that calculation?
7 A.I'm sorry, I can get that information, but I
8 don't have that with me.
9 Q.Would you consider it to be a statistically
10 significant figure as far as the accuracy of the
11 determination?
12 A.I would -- I i m going out on a limb here subj ect
13 to check. I would say that we i re more than 98 percent
14 confident.
15 Q.Okay. Well, that i s better than flipping a
16 nickel. So I don't have any more questions on this section.
17 COMMISSIONER SMITH: Are you done?
18 COMMISSIONER KEMPTON: Yeah.
19 COMMISSIONER SMITH: Any redirect?
MR. SOLANDER: No, thank you.
COMMISSIONER SMITH: Thank you for your help.
MR. SOLANDER: Could Mr. Eelkema be excused from
23 the remainder of this proceeding?
24
25
COMMISSIONER SMITH: If there is no objection, we
will excuse Mr. Eelkema.
1129
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1 Seeing none, he's excused.
2 (The witness left the stand.)
3 COMMISSIONER SMITH: Let i s take a seven-minute
4 stretch.
5 (Recess.)
6 COMMISSIONER SMITH: All right, I see your
7 exci ted, smiling faces ready to go back to work. Okay, so some
8 faces are less excited than others. I think we're ready for
9 the Company's next witness.
10 MR. HICKEY: Our next witness, Chairman Smith, is
11 Steve McDougal.
12
13 STEVEN McDOUGAL,
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
19 BY MR. HICKEY:
20
21
22
Q.Good afternoon, Mr. McDougal.
A.Good afternoon.
Q.Could you please state and spell your name for
23 the record?
24
25
A.Yes. My name is Steven R. McDougal: S-T-E-V-N
(sic), middle initial R, M-C-D-O-U-G-A-L.
1130
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1 Q.By whom are you employed and what is your
2 posi tion with the Company?
3 A.I'm employed by PacifiCorp and Rocky Mountain
4 Power as director of revenue requirement.
5 Q.Okay. And did you have an occasion to file
6 direct testimony in support of this Application and this docket
7 on the 28th of May of this year, and attach to it Exhibits No.
8 1 through 4?
9 A.Yes, I did.
10 Q.And, similarly, did you have a chance to file
11 rebuttal testimony on November 16th of this year, and attach to
12 your rebuttal Exhibits 78 through 80?
13 A.Yes, I did.
14 Q.Do you have any additions or corrections to
15 either of those prefiled testimonies, Mr. McDougal?
16 A.I do have one quick correction to my rebuttal
17 testimony.
18 Q.Okay.
19 A.If we get my rebuttal testimony and turn to
20 page 29 --
21
22
Q.All right. Gi ve us a moment, please.
A.Okay. On line -- excuse -- yeah, page 29,
23 line 20, it says --
24
25
Q.Page 21 or 29?
A.Twenty-nine.
1131
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21
22
23
24
25
1 Q.Twenty-nine, okay.
2 A.Line 20, the year "2005" should be "2006."
3 Q.Is that the only addition or correction that you
4 have, sir?
5 A.That is the only change.
6 Q.If I were to ask you each of the questions that
7 are set forth in both your direct and rebuttal testimony, would
8 your answers be the same?
9 A.Yes, they would.
10 MR. HICKEY: I would move that the prefiled
11 direct and rebuttal testimony of Mr. Steven McDougal be spread
12 upon the record as if read, and that Exhibits 1 through 4 and
13 Exhibi ts 78 through 80 be marked for identification, Chairman
14 Smith.
15 COMMISSIONER SMITH: If there's no obj ection, it
16 is so ordered.
17 (The following prefiled direct and
18 rebuttal testimony of Mr. McDougal is spread upon the record.)
1132
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.1 Q.Please state your name, business address and present position with Rocky
2 Mountain Power ("Company"), a division of PacifiCorp.
3 A.My name is Steven R. McDougal, and my busìness address is 201 South Maì,
4 Suite 2300, Salt Lae City, Utah, 84111. I am curently employed as the diector
5 of revenue requìrements for the Company.
6 Qualifications
7 Q.Briefly describe your educational and professional background.
8 A.I received a Master of Accountancy from Brigham Young University with an
9 emphasis in Management Advisory Services ìn 1983 and a Bachelor of Science
10 degree in Accountìng from Brigham Young University in 1982. In additìon to my
11 formal education, I have also attended varous educational, professional, and.12 electrc industr-related seminars. I have been employed by Rocky MountaÌn
13 Power or its predecessor companies since 1983. My experience at Rocky
14 Mountain Power includes various positions within regulation, finance, resource
15 planning, and internal audit.
16 Q.What are your responsibilties as director of revenue requirements?
17 A.My primar responsibìlties include overseeing the calculatìon and reportng of
18 the Company's regulated earings or revenue requìrement, assuring that the inter-
19 jurisdictional cost allocatìon methodology is correctly applìed, and explaining
20 those calculatìons to regulators in the jurisdictions in which the Company
21 operates.
22 Q.Have you testified in previous regulatory proceedings?
.23 A.Yes. I have provided testimony before the Utah Publìc Service Commssion, the
1133 McDougal, Di - 1
Rocky Mountaì Power
.1 Washington Utìlties and Transportatìon Commssion, the California Publìc
2 Utìlties Commssion, the Idaho Publìc Utìlitìes Commssion, the Wyoming
3 Publìc Service Commssion, and the Utah State Tax Commssion.
4 Purpose and Overview of Testimony
5 Q.
6 A.
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22.23
What is the purpose of your testimony in this proceeing?
My diect testìmony addresses the calculation of the Company's Idao-allocated
revenue requirement and the revenue increase requested in the Company's filìg.
I describe the major assumptions use by the Company to compute revenue
requìrement and present the calculation of the requested price increase.
Specifìcally, I provide testìmony on the following:
· The $27.7 millon retaìl revenue increase requested in this case
representìng the increase over curnt rates required for the Company to
recover the costs incurred to serve Idao customers;
· A description of the test period proposed in this case, includìg the
treatment of rate base and jurisdictional loads;
· Inter-jursdictional allocations, including tratment of ìrgatìon demand
side management ("DSM") costs and specìal contracts with ancìlar
services;
. Treatment of revenue from the sale of renewable energy credits ("RECs");
. The detailed results of operatìon for the test period, demonstratìng that
under current rates the Company wìl ear an overall retu on equìty
("ROE") in Idaho of 5.7 percent, which is signifìcantly below the retu
on equity requested in this case and the curent authorized retu; and
1134 McDougal, Di - 2
Rocky Mountain Power
.1
2
. Calculation of the Load Growth Adjustment Rate ("LGAR") based on
costs in this fiing for use in the Energy Cost Adjustment Mechanism
3 ("ECAM").
4 Revenue Increase
5 Q.
6 A.
7
8
9
10
11.12
13
14
15 Q.
16
17 A.
18
19
20
.
What revenue increase is the Company seeking in this case?
The Company's application supports an overall revenue increase of $27.7 millon,
or 13.7 percent. Exhibìt NO.1 provides a summar of the Company's Idaho-
allocated results of operatìons for the test period. At curent rate levels, Rocky
Mountain Power wìl ear an overall ROE in Idaho of 5.7 percent durng the test
period. This return is significantly less than the most recently approved ROE of
10.25 percent included in the stipulation approved by the Commssion in Case
No. PAC-E-07-05 (the "2007 general rate case"), and is less than the 10.6 percent
retu recommended by Company wìtness Dr. Samuel C. Hadaway in this
proceeding.
Is the Company requesting the full $27.7 millon as a change to customer
rates at this time?
Yes. The Company's current applìcation requests that rates for all customers,
including the tarf contract customers whose rate plans expìre December 31,
2010, be adjusted effective Januar 1,2011, to reflect customers' true cost of
service based on the test period data.
1135 McDougal, Di - 3
Rocky Mountain Power
.1 Test Period
2 Q.What test period did the Company use to determine revenue requirement in
3 thi case?
4 A.Revenue requìrement in the Company's applìcatìon is based on the historical
5 twelve-month period ending December 31,2009, adjusted for known and
6 measurable changes though December 31,2010 (the "Test Period").
7 Q.Is the Test Period in this case consistent with test period used by the
8 Company in previous Idaho general rate cass?
9 A.The Test Period is prepared in a maner consistent with the Company's general
10 rate cases fied previously in Idao. Later in my testimony I provide additional
11 support for major decìsions made in the Test Period preparation, including.12 treatment of rate base, normalìzation of jurisdictional loads, and treatment of
13 renewable energy credit sales. I also describe the process employed by the
14 Company to prepare revenue requìrement, and provide brief descriptions of each
15 normalìúng adjustment made to revenue, net power costs, depreciatìon, taxes,
16 rate base, and operations and maìntenance ("O&M") expense.
17 Q.What over-riding principle guided the Company's development of the Test
18 Period in this case?
19 A.The primar objective in determning a test period is to develop normalized
20 results of operations which best reflect the operatìng conditions during the time
21 the new rates wìl be in effect ("rate effectìve period"). Multiple factors must be
22 considered to determne which test period best reflects these conditions.
23 Ultimately this is best accomplìshed with a forecast test period that coincides with.
1136 McDougal, Di - 4
Rocky MountaÌn Power
.1
2
3
4
5 Q.
6
7 A.
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22
23.
the rate effective period. However, since this method has not been previously
allowed by the Commssion, the Company has relìed on historical data with
normalìûng adjustments made though December 2010 to reflect as closely as
possible the rate effectìve period.
Why is it important that the Test Period and the rate effective period be
aligned as closely as posible?
In an envìronment of rapidly expanding rate base and ìncreasing net power costs a
test period that is not alìgned with the rate effective period cannot adequately
capture the conditìons that the Company wìl experience while rates are in effect.
When a utìlty is in a significant investment cycle and experiencing other cost
increases, a pure historical test period constraÌns the utilty to chronically under-
recover the true cost of service. The Company wìl continue to place needed
assets into service during the rate effective period. These assets wìl immediately
provide benefits to the Company's customers in Idao, but the Company wìl no
longer be able to defer the cost of fìnancìng such assets in the form of allowance
for funds used durng construction ("AFUDC") and wìl begin to incur
deprecìation expense as soon as the asset is in service. Due to the current
regulatory framework in Idaho, rates cannot be adjusted to adequately recover the
cost of these assets untìl a future rate case whose historical test period captures
these plant additions. The ECAM mitigates the under recovery on increased fuel
costs related to new assets, but it can also work agaÌnst the Company by passing
through the benefìts of zero-cost energy from new wind faciltìes while the fixed
costs of these same faciltìes go unrecovered until they can be ìncorporated into a
1137
McDougal, Di - 5
Rocky Mounta Power
.1 general rate case. i
2 Q.What has the Company done in this case to better align the Test Period with
3 the rate effective period?
4 A.A signifìcant cost drver in this applicatìon is the capital investment the Company
5 has incurred to serve its retaÌI customers. The Company has calculated rate base
6 on an end-of-period basis, including actual rate base at December 31,2009, plus
7 major capital addìtions that wìl be in service by December 31,2010, reflected at
S the additions' full cost. The Company also proposed this treatment for rate base
9 in PAC-E-OS-07 (the "200S general rate case"). This treatment better aligns the
10 case with the level of investment that wìl be used and useful during the rate
11 effective period, and sets the customer rates at a more appropriate leveL. All of.12 the capìtal additions in this case wil be ìn service prior to the anticipated date of
13 the price change. Expense and revenue items related to new capital additìons,
14 including net power cost impacts, are annualized so that a full year of the cost or
15 benefit is included in the Test Period. Absent this treatment, customers would
16 receive the full benefit of capital additions such as the Dunlap wind facìlty
17 through the ECAM without paying the full capìtal cost of the resource.
is Q.Has the Company treated any revenue requirement components in this cae
19 different from its past cases in Idaho?
20 A.Yes. The historical 2009 load has been normalized to remove abnormal operating
21 condìtions that occurred. Jursdictìonal load dìrectly impacts thee maÌn
22 components of the Company's revenue requìrement: retaÌI revenue, system net
.1 The curent ECAM includes an adjustment mechanism designed to counteract this effect for select wind
facilities, but ths mechanism wil expire once rates from this case are effective.
1138
McDougal, Di - 6
Rocky Mountan Power
.
.
.
1
2
3 A.
4
5
6
7
8
9
10
11
12
13
14
15
power costs, and inter-jursdictìonal allocation factors.
Q.Why is the use of the Company's normalized load necessary in this case?
As the Company examned the historical 2009 load, it found anomalous results
that, if left unchanged, would materially distort the revenue requìrement
calculation for the Test Period. During 2009, sales to ìrgation customers and
Monsanto were signifìcantly below levels experienced over the previous fìve
years. The table below ilustrates the dramatic reduction ìn energy sales for these
customers in 2009.
Table 1: Tariff Contract and Irrigation Sales
Year MWh
2004 1,969,495
1,855,452
1;SS4~¡75
2005
200:6
2:007 1,996..641
1,952.49.520u:B
Average2ûi: - 2003 1,945,651
20C0:1,526,683
TestPerlcd 1,9û839D
The Company typically adjusts residentìal and commercial historical loads in
general rate cases to normalize varatìon due to atypical temperatus. However,
the shar reductìon seen in taff contract load ìn 2009 was not weather drven and
would not be normized with the Company's traditional adjustment. A more
comprehensive adjustment to loads is needed to reflect energy usage for these
customers at a level expected durng the Test Period, as well as load across the
Company's system. Company witness Dr. Peter C. Eelkema's testimony explaìs
1139 McDougal, Di - 7
Rocky MountaÌn Power
.1
2
3 Q.
4
5 A.
6
7
8
9
.
.
10
11
12
13
how the Company's loads were developed and provides support for the projected
energy usage by customers in Idaho during 2010.
What is the impact of the anomalous historical load on the inter-
jurisdictional alloction factors?
The reduced load ìn Idao durng 2009 causes a notable drop in Idaho's System
Generation ("SG"i allocation factor, which allocates the majority of system-wide
costs among the Company's six jursdictions. The following table shows Idao's
SO factor since fiscal year 2004 for previous years compared to the factor
computed using 2009 historical loads and the Company's 2010 forecasted loads.
Table 2:: 56 Alla-aUon Fador
Year
FY2ÛG4
Idaho %
639%
r:'200S 6~46%-
P""20lJ6 6.2S%
CY2C-û6 6,31%
6,05%.CY2007*
C'l2oo8 .5,81%
CY2009 .s~Q:S%
:C.Y20:1u:5~:51%
~ ,C,ese N:Q. P.AC-E-C:ß-C:7
Note: FY denotes a fiscal year ending on March 31, and CY denotes
a calendar year ending December 31 of the given years.
This significant drop in the SG factor from one year to the next is not typical, and
highlìghts not only that the load in Idaho declìned, but that ìt was inconsistent
with changes in other states' load, causing a reduction in the ratìo of Idao load
compared to system load. The Company does not expect the drop in Idaho load
2 The SG factor measures each state's contnbution to system demand and energy. Demand is weighted
75% and energy is weighted 25%.
1140 McDougal, Di - 8
Rocky MountaÌn Power
.1
2
durng 2009 to contìnue into 2010, and setting rates in this case based on the 2009
trough would not be appropriate. Using the 2010 normized load ìn this case
3 results in an SG factor more in lìne with historical trend in Idaho and is supported
4 by the Company's forecasting process that accounts for known changes ìn
5 customer load as explained by Dr. Eelkema.
6 Inter-Jurisdictional Allocation
7 Q.
8
9 A.
10
11.12 Q.
13
14 A.
15
16
17
18
19
20
21
22
23.
You previously mentioned the Revised Protocol. Has the Company applied
that allocation method in thi case?
Yes. As approved by the Commssion in Case No. PAC-E-02-03, the Idao
jursdictional revenue requìrement in this case is computed using the Revised
Protocol allocation methodology.
Please briefly describe the history of inter-jurisdictional allocations and the
Revised Protocol.
The first effort to achieve a multi-state agreement followed the merger of Pacifìc
Power and Light Company and Uta Power and Light in 1989. The PacìfCorp
Inter-Jursdictìonal Task Force on Allocations ("PITA") was formed which
included Company personnel, regulatory agency representatives from each state
jurisdiction in which PacìfiCorp serves (including Idao), and other interested
paries. Two main issues were at the forefront of the PITA process: PacìfìCorp's
integrated system operatìons and the equìtable sharng of operatìonal costs and
benefìts.
The fìrst agreement reached in March 1990 was called the Consensus
Allocation Method. Furer methods were developed and implemented over time
1141 McDougal, Di - 9
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
.
to address emergìng issues, including the PIT A Accord in Januar 1993 and the
Modified Accord in June 1997. In April 1998, Uta chose not to follow the PITA
agreements, adopting another method of allocation, the Rolled In method. After
Utah's depare from the PITA agreements, other states began to question the
sustaÌnabìlty of the PITA process, and the group held its last meetìng in April
2000.
On December 1, 2000, due in par to the breakdown of the PITA process,
the Company fied an applìcation seeking approval to restrcture into six separate
state electrc companies, a generation company, and a service company. As a
result of strong opposition to the Company's proposal, interested paries began
discussions about the need for a common method of allocatìng costs, benefits and
risks. On March 7, 2002, the Company fied applìcatìons in five states requesting
the initiation of an investigation of inter-jursdictional issues. Monthly multi-day
meetings ensued for the next 18 months. In September 2003, the Company
initiated proceedings in Uta, Oregon, Wyomig, and Idaho seeking ratification
of an Inter-Jursdictional Cost Allocation Protocol ("Protocol,,).3
Subsequent to the filng of the Protocol, substantìal discusscÌons occurred
among ìnterested paries in the context of what has been referred to as the MSP.
As a result of discussions among the MSP paries, the Company developed the
Revised Protocol which was ultimately approved in Uta, Oregon, Wyoming, and
Idaho and has been used (although not offìcìally approved) in Calìforna.
3 The Company's Protocol filings were docketed as 02-035-04 in Utah, UM 1050 in Orgon, 20üOEI-02-
183 in Wyoming, and PAC-E-02-3 in Idaho.
1142 McDougal, Di - 10
Rocky Mountain Power
.1
2 Q.
3
4 A.
5
6
7
8
9
10
11
12
13
.14 Q.
15
16 A.
17
18
19
20
21
22
23
24
.
Protocol.
Does the Revised Protocol prescribe the treatment of state-specific demand
side management programs?
Yes. As described in Section iv, Subpar C of the Revised Protocol, demand-side
management programs are assigned to the State Resources category. According
to the Revised Protocol:
"Costs assocìated with Demand-Side Management Programs wil
be assigned on a situs basis to the State in which the ìnvestment is
made. Benefits from these programs, in the form of reduced
consumption, wìl be reflected though time in the Load-Based
Dynamic Allocation Factors."
U sìng this allocation, there is consistency between the cost and benefìt assocìated
with demand-side management programs as described below.
Have you.treated the Idao Irrigation Load Control Program as a demand-
side management program as contained in the Revised Protocol?
Yes. As described by Dr; Eelkema, the Company's loads used to compute the
inter-jurisdictìonal allocation factors have been adjusted to reflect peak
curtailment durng 2010. Consequently, Idao's contrbution to the system
coincìdent peak and the resulting rate for allocatìng system-wide costs are
reduced. The program costs recovered through base rates, namely the incentive
payments made to paricipatìng customers, are situs assigned to Idao. This is
consistent with the Company's fiings in previous Idaho rate cases using Revised
Protocol, as well as cases in the Company's other states utìlzing the Revised
Protocol.
1144
McDougal, Di - 12
Rocky MountaÌn Power
.1 Q.
2
3 A.
4
5
6
7
8 Q.
9
10 A.
11.12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
.
Do any other jurisdictions served by PacifiCorp have similar programs, and
are those programs treated in a similar manner in this case?
Yes. The Company operates programs to control ìrgation and central ai
conditioning load in ìts Uta service terrtory. Both of these programs are treated
in a similar manner as the Idaho ìrgation program, i.e. the Utah load used to
compute ìnter-jurisdictìonal allocatìon factors is reduced to reflect program
paricìpation and the program costs are dìrect assigned to Utah.
Does the Revised Protocol prescribe the treatment of special contracts with
ancilary services?
Yes. Appendi D of the Revised Protocol describes the treatment of specìal
contracts, including those with and wìthout ancilar service contract attrbutes.
Specìfìcally, the Revised Protocol states:
"For allocatìon purposes Special Contracts with Ancìlar Service
Contract attrbutes are viewed as two transactions. PacìfiCorp sells
the customer electrcity at the retal service rate and then buys the
electrcìty back durng the interrptìon period at the Ancìlar
Service Contract rate. Loads of Specìal Contract customers wil be
included in all Load-Based Dynamc Allocatìon Factors. When
interrptìons of a Special Contract customer's service occur, the
host jursdiction's Load-Based Dynamic Allocation Factors and
the retail service revenue are calculated as though the interrption
did not occur. Revenues received from Specìal Contract customer,
before any discounts for Customer Ancìlar Service attrbutes of
the Special Contract, wìl be assigned to the State where the
Special Contract customer is located. Discounts from tarff prices
provided for in Special Contracts that recognize the Customer
Ancìlar Service Contract attbutes of the Contract, and payments
to retail customers for Customer Ancìlar Services wìl be
allocated among States on the same basis as System Resources."
1145 McDougal, Di - 13
Rocky Mountan Power
.1 Q.Have you treated the Company's agreement with Monsanto as a special
2 contract with ancillary service contract attributes, as desribed in Appendix
3 D of the Revised Protocol?
4 A.Yes. In the Company's calculation ofIdaho revenue requirment, Monsanto's
5 load is ìncluded in the load-based dynamc allocatìon factors, and the retaÌI
6 revenue is calculated as if there is no interrptìon and is dìect assigned to Idaho.
7 In addition, the cost of the ancìlar services is allocated among all states on the
8 same basis as other system resoures. The net power cost study sponsored by
9 Company wìtness Dr. Hui Shu includes the payment to Monsanto based on the
10 terms of the specìal contract for 2010.
11 REC Sales Revenue
Please explain how revenue from the sale of RECs has been treated in this
case?
Revenue from the sale of renewable energy credìts is treated as a revenue offset in
the revenue requìrement computatìon. This case includes a total of $91.8 millon
in revenue from the sale of RECs for the Test Period. Adjustment 3.6 of Exhibìt
NO.2 provides the detaÌled calculation of revenue in the Test Period as well as the
inter-jurisdictional allocation of such revenue. Adjustment 3.6 is made up of two
main components: (1) adjusting the total Company revenue to the level expected
durng the Test Period; and (2) reallocating revenue to avoid assigning a portion
to states for which the Company is currntly not sellng RECs in order to comply
with curent or futue requirements related to renewable energy.
1146 McDougal, Di - 14
Rocky Mountain Power
.1 Q.Please explain the computation of total REC sales revenue for the Test
2 Period.
3 A.To compute the level of REC revenue expected in the Test Period, the Company
4 must calculate the volume of wind-related RECs expected to be avaÌlable for sale.
5 This calculation begins wìth the total wind generatìon from the net power cost
6 study for which the Company has the right to sell RECs. Then, in order to
7 comply with curent and futue restrctions related to renewable energy in
S Calìfornia and Oregon, the Company assumes that those states' allocated share of
9 RECs are banked, or go unsold, durg the Test Period. Next, based on market
10 conditions and Company polìcy designed to mitìgate the risks described by
11 Company wìtness Mr. Stefan Bìrd, the Company assumes ìt wìl be able to sell 75.12 percent of un-banked RECs. Sale transactìons known at the tìme the rate case
13 was prepared, for both wind and non-wind-related RECs, are included at theìr
14 contractual volume and price. Known wind transactions are then compared to the
15 available wind generation after the adjustments described above, and any Test
16 Period RECs remaÌning available are assumed to be sold.
17 Q.Please explain the reallocation of revenue to avoid assigning revenue to states
lS for which the Company is currently not sellng RECs.
19 A.Revenue from REC sales is ìnìtially allocated system-wide in the Company's
20 results. However, because the Company curently banks the share of RECs
21 allocated to Oregon and California, those states should not receive an a1ocatìon
22 of the revenue generated from the sale of the remainìng RECs. To appropriately
23 allocate the sales revenue to the remaining four states, an adjustment is made to.
1147 McDougal, Di - 15
Rocky Mountaìn Power
.1
2
3
4 Q.
5
6 A.
7
8
9
10
11
.12
13
reverse Oregon and California share of the initial system alocatìon, and this
amount is spread ratably to the remaning states. Details ar provided on pages
3.6.1 and 3.6.2 in Exhibit NO.2.
Is the Company proposing specifc changes to the ratemaking treatment for
REC sales in this application?
Yes. In additìon to including the expected revenue from REC sales as a credt to
customers in this case, the Company believes actual REC sales revenue should be
tracked similar to net power costs and included as a component of the ECAM
calculation. The Company proposes that the curent rate case serve to set the base
level of REC sales to which actual sales would be compared. Varations from the
base REC sales revenue would be deferred and recovered or refunded on a dollar
for dollar basis by way of subsequent ECAM proceedings. Company witness Mr.
Bìrd provides testimony describing the volatile nature of these transactìons
14 supportingìnclusion ìn the ECAM.
15 Idaho Results of Operations
16 Q.
17
18 A.
19
20
21
22
23.
Please explain how the Company developed the revenue requirement for the
Test Period.
Revenue requirement preparatìon began with historical accounting ìnformtìon; in
this case the Company used the 12 months ended December 31,2009. The
revenue requìrement components in that historical period were analyzed to
determne if an adjustment was waranted to reflect normal operatìng conditions.
The historical informatìon was adjusted to recognize known, measurable and
anticìpated events and to include previous Commssion-ordered adjustments.
1148
McDougal, Di - 16
Rocky MountaÌn Power
.1
2
3
4
5
6
7
8
9
10
11.12 Q.
13 A.
14
15
16
17
18
19
20 Q.
21 A.
22
23.
Historical rate base is calculated using end-of-period balances as of
December 31,2009. Major capital additions planned to go into service by
December 31,2010, are added based on the full cost expected to be placed into
service. In order to synchronize other components of the revenue requirement,
costs and benefits related to these major plant additions are included in revenue
requìrement on an annualized level regardless of the date the resource wìl go into
service. For example, the Dunlap I wind plant wìl be placed ìnto service in
November 2010. The capital cost of the project is included ìn this case at the full
amount,. an annual level of operatìon and maÌntenance expense is added, and the
net power cost study assumes generation from that project was available for a full
12 months.
Please describe Exhibit No.2.
Exhibit NO.2 is Rocky MountaÌn Power's Idao results of operations report (the
"Report"). The historical period for the Report is the 12 months ended December
31,2009, which has been adjusted for known and measurable changes though
December 31,2010. The Report provides totals for revenue, expenses, net power
costs, deprecìatìon, taxes, rate base and loads in the Test Period. The Report
presents operatìng results for the period in terms of both return on rate base and
ROE.
Please describe how Exhibit No~ 2 is organiz.
The Report is organized into sections marked with tabs as follows:
. Tab 1 Summar contaÌns a summ of normalized Idaho-allocated
results of operatìons.
1149 McDougal, Di - 17
Rocky Mountan Power
.1
2
3
4
5
6
7
8
9
10
11.12
13
14
15
16
17
18
. Tab 2 Results of Operations detaÌls the Company's overall revenue
requìrement, showing unadjusted costs for the year ended December
2009 and fully normlìzed results of operatìons for the Test Period by
FERC account.
. Tabs 3 through 8 provide supporting documentation for the
normalizing adjustments requìred to reflect on-going costs of the
Company. Each of these sections begins with a numerical summar
that identìfies each adjustment made to the 2009 actual results and the
adjustment's impact on the case. Each column has a numerical
reference to a corresponding page in Exhibìt No.2, which contains a
lead sheet showing the adjusted PERC account(s),allocation factor,
dollar amount and a brief description of the adjustment. The specìfìc
adjustments included in each of these tab sections are described ìn
more detaÌI below.
. Tab 9 is Tab 2 restated with the Idaho allocation based on the Rolled
In allocatìon method.
. Tab 10 contaÌns the calculation of the Revised Protocol allocation
factors.
19 Tab 3 - Revenue Adjustments
20 Q.
21 A.
22.23
Please desribe the adjustments made to revenue in Tab 3.
Temperature Normlization (page 3.1) - This adjustment recalculates Idaho
revenue based on temperatue normalized historical load assuming average
temperature patterns.
1150 McDougal, Di - 18
Rocky MountaÌn Power
.1
2
3
4
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22.23
Revenue Normalization (page 3.2) - This adjustment normlizes base year
revenue by removing items that should not be included to determne retaÌI rates,
such as credits from the Bonnevìle Power Admnistration ("BP A") for the
Residential Exchange Program. The expense side of the BPA credit is removed in
adjustment 5.2.
. Effective Price Change (page. 3.3) - This adjustment reflects the $4.38 millon
revenue increase which became effective on April 18, 2009, in the 2008 general
rate case. Ths adjustment also normalizes the pro forma effects for the special
contract price changes effective Januar 1,2010 as determned in the 2007
general rate case.
Forecast Price Change (page 3.4) - This adjustment reflects the revenue effects
of using the normalìzed Idaho loads supported by Dr. Eelkema for the Test Period
ending December 2010.
SÛ2 Emission Allowances (page 3.5) - Consistent with Case No. PAC-E-06-04,
. this adjustment removes the sulfur dioxide ("S02") sales occurrng prior to June
30,2009, and amortizes those sales over a 15-year period. S02 sales occurrng
after June 30, 2009, are captured as par of the ECAM.
Green Tag Revenue or RECs (page 3.6) - In order to help meet jurisdiction
specìfìc renewable portfolio stadads, a market for green tags or RECs is
developing where the tag or green traìts of qualìfyìng power production facìlties
can be detached and sold separately from the power ìtself. Generally, wind, solar,
geothermal and some other resources qualify as renewable resources, although
each state may have a slìghtly different definition. Curently, Calìfornia and
1151 McDougal, Di - 19
Rocky Mountan Power
.1
2
3
4
5
6
7
S
9
10
11.12
13
14
15
16
17
is
19
.
Oregon have renewable portfolio standards that limit the Company's abilty to sell
green tags. As I described earlier ìn my testìony, this adjustment adds ìnto
results an incremental amount of 2010 REC revenues over and above the 2009
level, and correctly allocates the REC revenue among states to account for
banng in California and Oregon. The Company also proposes that REC
revenues be dealt with as par of the Company' sECAM proceeding due to the
volatìlìty described ìn the testimony of Mr. Bìrd.
Wheeling Revenue (page 3.7) - Durng 2009 there were varous transactìons
resultìng in wheelìng revenue that the Company does not expect to occur in the
Test Period. These transactìons relate to varous prior period adjustments and
contract termnations. This adjustment also ìncludes pro forma wheeling revenue
for the Test Period.
Tab 4 - O&M Adjustments
Q. Has the Company made considerable effort to control its operating costs?
A. Yes. As par of the Mid American Energy Holdìngs Company ("MEHC") merger
commtments in Case No. PAC-E-05-0S, commtment 131, the Company agreed
to reduce its admnistrative and general expense below $222.S millon annually,
adjusted for inflatìon. As shown in Exhibit No.2, Page 2.2, the Company's actual
December 2009 A&G level is $162.6 millon, far below the merger commtment.
1152 McDougal, Di - 20
Rocky Mountan Power
.
.
15
16
17
18
19
20
21
22
.23
1 Normalizing Adjustments
2 Q. Pleas describe the adjustments made to O&M expense in Tab 4 of Exhibit
3 No.2.
4 A.Miscellaneous General Expense (page 4.1) - Tils adjustment removes certain
5 miscellaneous expenses that should have been charged below-the-lìne to non-
6 regulated expenses. This adjustment also corrects the allocation of Utah related
7 sales tax refunds.
8 Wage & Employee Benefit Adjustments (page 4.2 and 4.3) - This adjustment
9 is used to compute labor-related costs for the Test Period. Labor-related costs are
10 computed by adjustìng salaries, incentives, benefìts and costs assocìated with F AS
11 87 (pension), FAS 106 (post retìrement benefits) and FAS 112 (post employment
12 benefits) for changes expected beyond the actual costs experienced in 2009. Page
13 4.3.4 is a numerical summary staring with actual labor costs ìn 2009 and
14 summarizing the adjustments made to reflect the Test Period level of expense.
This summary is followed by the detailed worksheets used to adjust the labor
costs forward to the Test Period.
The fìrst step to adjust labor is to annualìze salar increases that occured
durig 2009. This was done by identìfying actual wages by labor group by month
along with the date each labor group received wage increases. The next step is to
apply the wage increases though the end of the Test Period to the annualized
2009 salares. The Company used union contract agreements to escalate union
labor group wages, while increases for non-union and exempt employees were
based on actual increases. This calculation is detailed on pages 4.3.5 through
1153 McDougal, Di - 21
Rocky MountaÌn Power
.1
2
3
4
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22
23.
4.3.6. Payroll taxes were updated to captue the impact of the changes to
employee salares.
An adjustment is also made to incentìve compensation, pension expenses,
and other employee benefìt costs expected to be incured in 2010. The Company
utìlzes an ìncentive compensatìon program as par of ìts philosophy of delìverig
market coinpetitìve pay structured in a manner that benefìts customers with safe,
adequate and relìable electrc service at a reasonable cost.
MEHC Transition Savings (page 4.4) - The Company elìmìated many
positions in our labor force as a result of the MEHC transactìon. These savings
were made possible by the payment of change-In-control severance, which is
currently being amortized over a thee year period as authorized in Case Nos.
PAC-E-06-11 and PAC-E-07-05. Since the amortizatìon wil end December 31,
2010, this adjustment removes the amortization from results.
Irrigation Load Control Program (page 4.5) - Incentive payments made to
Idaho customers paricìpating in the ìrgation load control program were system
allocated in unadjusted data. This adjustment corrects that allocation and assigns
these costs dìrectly to Idao consistent with other DSM progras. This
adjustment also recognizes a $261,233 increase in total incentìve payments baséd
on program paricipatìon ìn the Test Period. An offsettìng adjustment was made
to reduce the jursdictional load used to develop allocatìon factors to reflect load
paricipating in the program durng the Test Period ìrgation season. This load
adjustment reduces Idaho load used to compute inter-jurisdictìonal allocatìon
factors and consequently the level of system-wide costs allocated to Idao.
1154 McDougal, Di - 22
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DetaÌls supporting the incremental adjustment are provided on pages 4.5.2 and
10.13.
Incrementa Generation O&M (page 4.6) - This adjustment adds incremental
O&M expense for the High PlaÌns, McFadden Ridge I, and the Dunlap I wind
generating plants, as well as the Dave Johnston coal plant scrubber, all of which
were placed ìnto service durg 2009 or wil be durng the Test Period.
Consistent with the end-of-period rate base treatment, this adjustment includes a
full year of O&M for the Dave Johnston scrubber and the Dunlap I wind plant,
even though they wìl be placed into service part way though the year. The net
power cost study sponsored by Company witness Dr. Shu also includes the full
year impact (cost or benefìt) from these resources.
Remove Non Recurring Entries (page 4.7) - Varous accountìng entres were
made during 2009 that were non-recurng in natue or relate to a prior period.
This adjustment removes these items reducing total Company operating expense
by $ 1.3 millon.
MEHC Affliate Management Fee (page 4.8) - This adjustment complìes with
the MEHC acquisìtion commtment US, which states:
"MEHC and PacìfìCorp wil hold customers haress for increases in
costs retained by PacifCorp that were previously assigned to affilates
relating to management fees... This commtment is off settable to the
extent PacifiCorp demonstrates to the Commssion' s satisfaction, in the
context of a general rate case the following:
i) Corporate allocations from MEHC to PacifiCorp included in
PacifìCorp's rates are less than $7.3 millon..."
This adjustment lìmits the MEHC corporate charge to PacìfiCorp to $7.3 millon.
Intervenor Funding (page 4.9) - This adjustment increases amortization expense
on previously deferred intervenor funding by the expected amortzation amount
1155 McDougal, Di - 23
Rocky MountaÌn Power
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though the Test Period and rate base is adjusted to reflect all balances as of
December 2010.
Generation Overhaul Expense (page 4.10) - Ths adjustment normlizes
generation overhaul costs using a four year average methodology. Actual
overhaul expenses from 2006 - 2008 are escalated to 2009 dollars using escalatìon
indices and then those escalated expenses are averaged over four years. For the
Currant Creek, Lake Side and Chehalis generating units, the four year average is
comprised of the overhaul expense projected during the first four full years these
plants are operational. The adjustment is calculated by subtracting the actual
overhaul costs from the four year averages.
Memberships and Subscriptions (page 4.11) - This adjustment removes
expenses in excess ofCommssion polìcy as stated in Order No. 29505. National
and regional trade organizations are recognized at 75 percent and dues for
membership in Western Electrc Coordinating Council ("WECC") and Nortern
Tier Transmission Group are included at 1 00 percent. All other membership dues
are removed.
Postretirement Measurement Date Change (page 4.12) - This adjustment
removes the Idao situs assigned expense related to a change in the measurment
date for postretìrement benefìts.
Cash Basis Idaho Pension Expense (page 4.13) - This adjustment replaces the
actuarially determned pension expense for the Test Period with the actual amount
funded (cash basis). This adjustment is consistent with the Idao Commssion's
orders number 29838 and 29871 referrg to a United Water case, and with the
1156
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Rocky MountaÌn Power
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Company's 2007 genera ratecase, Case No. PAC-E-07-05, and the Company's
200S general rate case, Case No. PAC-E-OS-07.
Insurance Expense (page 4.14) - This adjustment normlìes injury and daage
expenses to reflect a three-year average of gross expense minus insurance
proceeds. This adjustment also examnes the level of captive ìnsurnce expense
which continues to remaÌn below $7.4 millon as agreed to by the Company as
par of the MEHC transaction in Case No. PAC- E-05-0S, commtment 129.
DSM Removal (page 4.15) - Idaho allows for recovery of DSM expenses
though the customer efficiency services rate adjustment (Schedule 191). This
adjustment removes Idaho DSM costs ìn order to prevent a double recovery
through base rates and Schedule 191.
Wyoming Advertising (page 4.16) - This adjustment removes from results
certin advertising costs that the Company was ordered to incur by the Wyoming
Publìc Service Commssion. These costs wìl be charged situs to Wyoming
customers.
Avian Settlement (page 4.17) - In 2009 the Company and the U.S. Attorney for
Wyoming reached an agreement assocìated with increasing protection for wildlife
habitat in and around the Company's transmission and distrbution assets. Under
the terms of the agreement, the Company is providing funds to varous wildlife
agencìes in Wyoming as well as Idaho, Uta and Montana to support
improvements to design and the constrction of avian-safe power lìnes. This
adjustment removes the April 2009 reversal of a December 200S entr. Also, this
adjustment includes capital improvements of existing power lines that wìl benefit
1157 McDougal, Di - 25
Rocky Mountain Power
.1 customers by protectìg wild life habitat and reducìng avian related outages.
2 Tab 5 - Net Power Cost Adjustments
3 Q.
4 A.
5
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Please describe the adjustments included in Tab 5.
Net Power Cost Study (page 5.1) - The net power cost study adjustment
presents normalized Test Period steam and hydro power generation, fuel,
purchased power, wheelìng expense and sales for resale based on the Company's
GRID modeL. It also normalìzes hydro, weather conditìons and plant avaÌlabìlty
as described in Dr. Shu's testimony.
BP A Residential Exchange (page 5.2) - The Company received a monthly
purchase power credìt from BPA which is treated as a 100 percent pass-though
customers elìgible to paricìpate in the Residentìal Exchange Program in Oregon,
Washington, and Idaho. This adjustment reverses the BPA purchase power
expense credit recorded.
James River Royalty Offset and Little Mountain Steam Sales (page 5.3) - On
Januar 13, 1993, the Company executed a contract with James River Paper
Company with respect to the Camas mill, later acquìred by Georgia Pacìfic.
Under the agreement, the Company built a steam tubìne and is recovering the
capìtal investment over the twenty-year operational term of the agreement as an
offset to royaltìes paid to James River based on contract provisions. The contract
costs of energy for the Camas unit are included in the Company's net power costs
as purchased power expense, but GRID does not include an offsettng revenue
credit for the capìtal.and maintenance cost recovery. This adjustment adds the
royalty offset to account 456, other electric revenue, for the Test Period.
1158 McDougal, Di - 26
Rocky MountaÌn Power
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21 A.
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This adjustment also normalizes the ongoing level of steam revenues
related to the Uttle MountaÌn plant. Contractually, the steam revenues from Uttle
Mountain are tìed to natual gas prices. The Company's net power cost study
includes the cost of running the Little MountaÌn plant but does not include the
offsetting steam revenues. This adjustment aligns the steam revenues to the gas
prices modeled in GRID.
Electric Lake Settlement (page 5.4) - Canyon Fuel Company ("CFC") owns the
Skylìne mine located near Electrc Lake. Electrc Lae is a reservoìr owned by
the Company that provides water storage for the Huntington generating plant.
The two companies have disputed a claÌm made by PacìfiCorp that CFC's mining
operatìons caused the lake to leak water into the Skylìne mine, thus makng it
unavailable for use by the Huntington generatìng plant. The Company has
incurred capìtal costs and O&M costs to pump water from the breach back ìnto
Electrc Lake. The two companies negotiated a settlement of the claims made by
the Company. The settlement of costs ìncludes reimbursement to the Company
for O&M and capital costs assocìated with the pumping. The value of the
settlement was amortized over three years. This adjustment includes the
appropriate Test Period amortization and rate base balances.
Tab 6 - Depreciation and Amortization Expense Adjustments
Please describe the adjustments included in Tab 6.
Depreciation and Amortization Expense (page 6.1) - This adjustment enters
into the Test Period results deprecìation and amortization expense for the major
plant added to rate base ìn adjustment 8.6.
1159 . McDougal, Di - 27
Rocky Mountain Power
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23.
Depreciation and Amortization Reserve (page 6.2) - This adjustment enters
into Test Period results depreciation and amortization reserve for the major plant
additions added to rate base in adjustment 8.6.
Hydro Decommissioning (page 6.3) - Based on the Company's latest
deprecìation study approved in Case No. PAC-E-07-14, an annual accrual of
$19.4 millon is requied for the decommssioning of varous hydro facìlìties.
This adjustment adjusts the decommssioning reserve balance to the end of the
Test Period leveL.
Tab 7 - Tax Adjustments
Q. Pleas describe the adjustments included in Tab 7.
A. Interest True Up (page 7.1) - This adjustment details the tre up to interest
expense requìred to synchronize the Test Period expense with rate base. This is
done by multiplying normlied net rate base by the Company's weighted cost of
debt in this case.
Property Tax Expense (page 7.2) - Property ta expense for the Test Period was
computed by adjustìng calendar year 2009 propert tax expense for known and
anticìpated changes in assessment levels through the end of the Test Period.
Please refer to Confidential Exhibìt No.3 for detaÌls supporting the Test Period
expense.
Renewable Energy Tax Credit (page 7.3) - The Company is entìtled to
recognize certaÌn tax credits as a result of placing qualifying renewable generatìng
plants into service. The federal tax credit is based on the generation of the plants
and the credit can be taken for ten years on qualifying propert. Under the
1160 McDougal, Di - 28
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calculation requìred by Internal Revenue Service Code Sec. 45(b )(2), the Test
Period renewable electrcìty productìon credit is 2.2 cents per kilowatt hour of the
electrcìty produced from wind energy. The Utah state tax credit is based on the
generation of the Blundell bottoming cycle, and the credit can be taken for four
years. In additìon to the Uta state tax credit, the Company is able to reognize
the Oregon Business Energy Tax Credit, which is based on investment ìn specìfic
assets and is taken over a five year period on qualifying propert.
Idaho State Investment Tax Credit (page 7.4) - The Idaho state investment tax
credit ("ITC") is based on the plant placed in service, and the credit is usually
utilzed in a subsequent period depending on the avaìlabìlty of Idaho state taxable
income. Since PacìfìCorp is a 46(f)(1) Company, this adjustment includes into
results the ITC unamortized balance as a rate base reduction.
AFUDC Equity (page 7.5) - This adjustment includes the appropriate level of
AFUDC - Equìty into results for the purPose of aligning the ta Schedule M's
wìth regulatory ìncome.
Adjust Accumulated Deferred Income Taxes to Actual (page 7.6) - This
adjustment alìgns the Company's original jurisdictìonaly allocated accumulated
deferred income taes related to deprecìable and amortizable assets with actual
deferred income tax expense from the Power Tax system.
Correct Allocation Factor (page 7.7) - This adjustment corrects an allocatìon
factor on an ìtem related to accumulated deferred income taxes.
Income Tax Normalization (page 7.8) - As described in the testimony and
exhibits of Company witness Mr. Ryan R. Fuller, the income taxes in this case
1161
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have been presented on a fully normlized basis, excluding AFUDC equity.
Accordingly, this adjustment removes the base period Idaho allocated income tax
flow-through.
Medicare Subsidy (page 7.9) - On March 23,2010, the Patient Protection and
Affordable Care Act was signed into law. The Act, including a subsequent
amendment to the Act (the amendment is known as the Health Care and
Education Reconcilation Act signed into law March 30, 2010), changes the
deductibilty of certain costs incur for post-retìrement prescription drg
coverage. This change is described in the Company's accounting applìcation in
Case No. PAC-E-I0-4 and in the testìmony of Mr. Fuller.
How have current state and federal income tax expenses been calculated?
Current state and federal income tax expenses were calculated by applying the
applìcable tax rates to the taxable income calculated in the Report. State income
tax expense was calculated using the state statutory rates applìed to the
jursdictional pre-tax income. The result of accumulating those state tax expense
calculatìons is then allocated among the jursdictions using the Income Before
Tax ("IBT") factor. Federal ìncome tax expense is calculated usìng the same
methodology that the Company uses.in preparng ìts fied income tax retus. The
detaÌI supporting this calculation is.contained on pages 2.18 through 2.20.
20 Tab 8 - Rate Base Adjustments
21 Q.
22 A.
23
Please describe the adjustments included in Tab 8.
Update Cash Working Capital (page 8.1) - This adjustment supports the
calculation of cash working capital included in rate base base on the normized
1162 McDougal, Di - 30
Rocky Mountain Power
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results of operatìons for the Test Period. Total cash workìg capital is calculated
by multiplying jurisdictional net lag days by the average daly cost of service.
Net lag days in this case are based on a lead lag study prepared by the Company
using calendar year 2007 informatìon. The Company's 200S general rate case
relied on this same lead lag study, a copy of which was provided along with the
Company's filìng ìn that case. Based on the results of the 2007 lead lag study, the
Company experiences 4.72 net lag days in Idaho requirng a cash working capita
balance of $2.1 millon to be included in rate base.
Trapper Mine Rate Base (page 8.2) - The Company owns a 21.4 percent share
of the Trapper Mine, which provides coal to the Craig generating plant. This
investment is accounted for on the Company's books ìn FERC account 123.1,
investment in subsidiar company, which is not included as a regulatory rate base
account. The normalìzed coal cost from Trapper Mine in net power costs includes
operatìon and maintenance costs but does not include a return on investment.
This adjustment adds the Company's portion of the Trapper Mìne net plant
investment to rate base in order for the Company to ear a retu on ìts
investment.
Jim Bridger Mine Rate Base (page 8.3) - The Company owns a two-thìrds
interest in the Bridger Coal Company, which supplìes coal to the Jim Bridger
generating plant. The Company's investment in Bridger Coal Company is
recorded on the books of Pacìfic Minerals, Inc. Because of this ownership
arangement, the coal mine investment is not included in electrc plant in service.
The normalized coal costs for Bridger Coal Company in net power costs include
1163 McDougal, Di - 31
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the operation and mantenance costs of the mine but provide no retu on
investment. This adjustment is necessar to properly reflect the Bridger Coal
Company investment in rate base in order for the Company to ear a retu on its
investment.
Environmental Settlement (PERCO) (page 8.4) - In 1996, the Company
received an insurance settlement of $33 millon for envìronmental clean-up
projects. These funds were trnsferred to a subsidiar called PacifiCorp
Envìronmental Remediatìon Company ("PERCO"). This fund balance is
amortized or reduced as PERCO expends dollars on clean-up costs. PERCO
received an additional $5 millon of insurance proceeds plus associated lìabìltìes
from Rocky Mountain Power in 1998. This adjustment includes the unspent
insurance proceeds in results of operations as a reductìon to rate base.
Customer Advances for Construction (page 8.S) - Refundable customer
advances for construction are recorded to FERC account 252. The December
2009 balances do not reflect the proper allocatìon because amounts were recorded
to a corporate cost center locatìon rather than state-'specifìc locations in the
Company's accountìng system. This adjustment corrects the allocation of
customer advances.
Pro Forma Major Plant Additions (page 8.6) - To reasonably represent the cost
of system infrastructue requìred to serve our customers, the Company has
identìfìed capital projects that wil be completed by the end of the Test Period.
Company business unìts identifed capìtal projects with expenditues over $5
milìon that wil be used and useful by December 31,2010. Additions by
1164
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Rocky Mountain Power
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functional category are summarzed on separate sheets, indicating the in-service
date and amount by project. The associated depreciation expense and
accumulated reserve impacts are accounted for in adjustment 6.1 and 6.2.
Miscellaneous Rate Base (page 8.7) - In this adjustment fuel stock is increased
due to the cost of coal and the number of tons stored at each sìte. Also, prepaÌd
overhaul balances in PERC account 186 for the Lake Side, Chehalis, and Curent
Creek plants are adjusted forward to reflect futue payments and transfers of
capìtal to electric plant in service expected durng the Test Period.
Powerdale Hydro Decommission (page 8.8) - Powerdale is a hydroelectrc
generating facilìty located on the Hood River in Oregon. This facilty was
scheduled to be decommssioned in 2010; however, in 2006 a flash flood washed
out a major section of the flow line. The Company determed that the cost to
repaì this facìlìty was not economical and determned it was ìn the ratepayers'
best interest to cease operation of the facìlty.
This adjustment reflects the treatment approved by the Commssion in
Case No. PAC-E-07-04. Durng 2007, the net book value (ìncludìg an offset for
insurance proceeds) of the assets to be retìred was transferred to the unrecovered
plant regulatory asset. In additìon, futue decommssioning costs are deferred as
they are spent and amortized over 10 years, beginning in the subsequent year.
Goose Creek Transmission (page 8.9) - On April 1,2008, the Company sold ìts
undivided ìnterest in 13.85 miles of transmission lìne, running from the
Company's Goose Creek switching statìon and extending north to the Decker 230
kV substation near Decker, Montana. The assets sold included strctues,
1165 McDougal, Di - 33
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.
miscellaneous support equipment, easements, and rights-of-way associated with
the transmission lìne. The sale of the transmission lìne resulted in the Goose
Creek swìtchìng statìon no longer being needed or useful to the Company. The
Company plans to remove the Goose Creek switching station including all above
ground facìlìties. Consistent with Commssion Order No. 30904, in September
2009 the Company wrote off the gaÌn assocìated with the sale. This adjustment
removes the rate base and accumulated depreciation balances and deprecìation
expense included in December 2009 unadjusted results.
FERC 105 (PHFU) (page 8.10) - This adjustment removes all plant held for
future use ("PHFU") assets from FERC account 105. The Company's is makng
this adjustment in complìance with Title 16 of Publìc Utìlìty Regulation, chapter
5, "Powers and Dutìes of Publìc Utilties Commssion" sectìon 61-502A.
EITF 04.6 Coal Stripping (page 8.11) - In Docket No. PAC-E-09-08, The
Company fied for an Accountìng Order authorizìng the Company to record, as a
regulatory asset, the costs associated with the removal of overburen and waste
materials at ìts affilìate coal mines. In January 2010, the Commssion ordered the
Company in Order No. 30987 to record the removal costs within its fuel expense
account but wìthheld its review and judgment regarding the propriety of these
removal costs unti such time as the Company fies an application with the
Commssion seeking a specific recovery of these costs though rates. This
adjustment aligns the costs of coal strpping and the benefits to customers by
adding the deferred stripping costs into rate base as a regulatory asset. The
1166
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related reductìon to fuel expense is accounted for in the net power costs
adjustment 5.1.
3 Tab 9 - Rolled In
4 Q.
5 A.
Please describe the information contained behind Tab 9 Rolled In
Tab 9 is Tab 2 restated with the Idaho allocation based on the rolled in allocation
6 method. This information is being provided pursuant to the Commssion order on
7 inter-jursdictional issues in Case No. PAC-E-02-03.
8 Tab 10 - Allocation Factors
9 Q.
10 A.
11.12
13
Please desribe the information contained behind Tab 10 Allocation Factors
Tab 10 Allocation Factors summzes the derivatìon of the jursdictional
allocatìon factors using the Revised Protocol allocation methodology. Factors in
this case are based on the load forecast though December 2010 and pro forma
account balances.
14 Rate Mitigation Cap
15 Q.
16
17
18 A.
19
20
21
22
23
24
25.26
In the Company's previous rate case the price increae was reduced by a rate
mitigation cap. Is a rate mitigation cap applied to the revenue requirement
in this case?
No. The rate mitìgatìon cap was approved by the Commssion in Case No. PAC-
E-02-03 and was applìed to rate cases as described in the following excerpt from
the stipulation in that case:
"For all Idaho general rate proceedngs initiated aftr the effectìve
date of this Stipulatìon and Revised Protocol, and until March 31,
2009, the Company's Idaho revenue requìrement to be used for
purposes of setting rates for Idaho customers wìl be the lesser of:
(i) the Company's Idaho revenue requìrement calculated under the
Rolled-In Allocatìon Method multiplied by 101.67 percent, or (ìì)
1167
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'the Company's Idao revenue requirement resulting from use of
the Revised Protocol."
3 The rate mitigation cap is no longer applìcable in Idaho under the Revised
4 Protocol as approved by the Commssion. The revenue increase sought in this
5 case is supported by revenue requìrement allocated to Idaho according to the
6 Revised Protocol.
7 Load Growth Adjustment Rate
S Q.
9
10 A.
11
12.13
14
15
16
17
is
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20
21 Q.
22 A.
.
Has the Company updated the calculation of the LGAR that is applied to the
calculation of net power costs to be recovered through the ECAM?
Yes. Exhibit NO.4 provides the detaÌled calculation, using revenue requìrement
numbers from Exhibit NO.2. To calculate the LGAR I have incorporated the
applìcable elements from this case, including production-related return on
investment and non-NPC expenses, ìnto the template approved by the
Commssion in Case No. PAC-E-OS-OS. The LGAR itself does not affect revenue
requìrement in this case, but is applied to the calculation of net power costs to be
deferred and recovered though the ECAM, and is to be updated each time base
net power costs are updated in a general rate case. Using the revenue requìrement
in the Company's fiing results ìn an increase in the LGAR from $ 1 7.4S per MW
to $20.19 per MW. The Company wìl also provide an updated calculatìon of
this rate based on the Commssion-approved outcome of this case.
Does this conclude your direct testimony?
Yes.
1168 McDougal, Di - 36
Rocky MountaÌn Power
.1 Q.Please state your name and business address.
2 A.My name is Steven R. McDougal and my business address is 201 South Main,
3 Suite 2300, Salt Lae City, Utah, 84111.
4 Q.Are you the same Steven R. McDougal who submitted pre-filed diect
5 testimony in thi proceeding?
6 A.Yes.
7 Purpose and Summary of Testimony
8 Q.
9 A.
10
11.12 Q.
13 A.
14
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What is the purpose of your rebuttal testimony in this proceeding?
The purpose of my testimony is to respond to adjustments proposed in the pre-
fìed diect testimony fìed by the intervening paries regarding the Company's
revenue requìrement.
Please summarize your testimony.
My testimony explains and supports the Company's revised overall revenue
increase request of $24.9 millon. This is a reduction from the $27.7 request
ìncluded in the Company's original fiing. My testìmony and exhibits also
provide: (1) a detailed calculatìon of the $24.9 millon requested revenue
increase, including a sumar of the differences between the $27.7 milion
request and the revised requested amount. The revised request ìncludes the impact
of adjustments proposed by other parties that the Company has accepted; 2) the
Company's response to certaìn revenue requìrement adjustments proposed by
intervening paries in this case which the Company contests; and (3) updates to
the Company's case due to a change in bonus depreciation law. The Small
Business Jobs Act of 2010, which became law on September 27,2010, extended
1169
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50 percent bonus depreciation for qualifying assets for one year (calendar year
2010). This update reduces the price increase in this rate case by approximately
3 $1.8 millon. This adjustment was not included in the diect testìmony of any of
4 the intervenors, but is being ìncluded in this rate case to accurately reflect this tax
5 law change occurrng after the case was fìed.
6 Required Revenue Increase
7 Q.
8
9 A.
10
11.12 Q.
13 A.
14
15
16
17
18
19
20
.
What price increase is required to achieve the requested return on equity in
this case?
As shown on Page 1.0 of Exhibìt No. 78, an overall price increase of $24.9
milion is required to produce the 10.6 percent return on equity requested by the
Company.
Please describe the calculation of the revised overall revenue increase.
The Company's revised revenue increase of $24.9 millon was calculated using
the same allocation methodology and factors included in the original filing and
incorporates certaÌn adjustments proposed by other paries. In support of the
revised calculatìon, Exhibit No. 79 shows a summar of the adjustments made to
the original revenue requìrement requested by the Company. Exhibit No. 79 is a
revised Exhibit NO.2 from the Company's original filìng with updated Tabs 1,2,
9 and 10 and includes a new Tab 11 containing backup pages for each new
adjustment made to the Company's filing.
1170
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.
.
1
2
Revenue Requirement Adjustments
Q. Is the Company incorporating any adjustments proposed by the intervening
3
4 A.
5
6
parties into its revenue requirement calculation?
Yes. The Company has incorporated the following new adjustments, including
some proposed by intervening pares, into the Company's revenue requìrement
calculation. Each is described fuer in my testìmony.
(figues are in $1,OOO's)
Original Request
Rebuttal Adjustments
Cost of Debt and Preferred
11.1 Bndger Unit 2 Overhaul Liquidated Damages
11.2 Medicare Subsidy
11.3 Avian Settement
11.4 Generation Overhaul Expense
11.5 Major Plant Additions - Plant in Service
11.6 Major Plant Additions - Tax Impact
11.7 Major Plant Additions - Depreciation Expense
11.8 Major Plant Additions - Depreciation Reserve
11.9 Net Power Costs
11.0 S02 Sales
Rebuttl Price Increase
7 Cost of Debt and Preferred
8 Q.
9 A.
10
11
Proposed
Price
Increase
$ 27,698
(127)
(2)
(5)
(10)
(82)
(226)
(1,784)
(45)
7
(274)
(280)
$24,870
Please summarize adjustments made to the cost of debt and preferred.
The revenue requìrement model has been updated with the 5.88 percent for the
cost of debt and 5.42 percent for the cost of preferred as described ìn the
testimony of Company witness Mr. Bruce N. Willìams.
1171
McDougal, Di-Reb- 3
Rocky MountaÌn Power
.1 Bridger Unit 2 Overhaul Liquidated Damages
2 Q.Please summariz IPUC staff witness Mr. Joe Leckie's proposed adjustment
3 related to an overhaul done on Bridger Unit #2 in 209.
4 A.Mr. Leckie proposes that an adjustment be made to remove $240,497 total
5 company rate base from results, along with the corresponding depreciation
6 expense and reserve, in order to properly account for lìquidated damages received
7 by the Company associated wìth an overhaul done on Bridger Unit #2 ìn 2009.
S Q.How has the Company accounted for those liquidated damages?
9 A.The Company and contractor agreed that $625,000 ìn lìquidated damges would
10 be treated as a reductìon to multiple Bridger Unit #1 overhaul projects ìn progress
11 for that contractor. In the Company's case, $264,254 was accounted for as a credit.12 agaÌnst the Bridger Unìt #1 Reheater project which was included in the
13 Company's Major Plant Additions Adjustment. The other projects that were also
14 allocated a portion of the liquidated damges were each less than the $5 millon
15 theshold for inclusion in this case.
16 Q.Has this adjustment been correctly reflected in IPUC's modeled position?
17 A.No. IPUC's adjustment removes the accumulated depreciation reserve from
is FERC Account 111 SP ìnstead of FERC Account 10SSP and the adjustment to the
19 accumulated deprecìation reserve is a negative amount and should be a positive
20 amount to reflect removing a piece of the reserve.
21 Q.Is the Company adopting the propos adjustment in its revenue
22 requirement computation?.23 A.Yes. The Company has correctly reflected this adjustment in the rebuttal posìtion
1172 McDougal, Di-Reb - 4
Rocky MountaÌn Power
.1 as adjustment 11.1 of Exhibit No. 79.
2 Medicare Subsidy
3 Q.Please summarize IPUC Staff's position regarding the Medicare Subsidy
4 regulatory asset.
5 A.IPUC Staf witness Ms. Cecìly Vaughn proposes to reduce 2011 amortization
6 expense reflected in Adjustment 7.9 of my Exhibit No.2 for the non-deductìble
7 post-retìrement prescription drg coverage ("Medicare Subsidy") regulatory asset,
8 approved ìn Case No. PAC-E-I0-04.
9 In this case, the Company originally requested recovery of the Medicare
10 Subsidy regulatory asset using December 31,2009, data; however, once the
11 Patient Protection and Affordable Care Act ("PPCA") was enacted March 30,.12 2010, a revision to the regulatory asset balance was necessar. The result is a
13 reduction to the regulatory asset balance of$19,996 or an equivalent reduction in
14 yearly amortization expense of $4,999.
15 Q.Does the Company agree with IPUC stas proposd adjustment to Medicare
16 Subsidy?
17 A.Yes. As stated by Ms. Vaughn, the Company provided a revised amortization
18 schedule reflecting accounting informtion through March 31,2010; therefore,
19 the Company has no objection to this adjustment. This adjustment is included as
20 adjustment 11.2 in Exhibit No. 79.
.
1173
McDougal, Di-Reb - 5
Rocky Mountan Power
.1 A vian Settlement
2 Q.Please explain the adjustments being proposed for the Avian Settlement
3 Agreement.
4 A.IPUC witness Ms. Vaughn and PIIC wìtness Mr. Greg Meyer both propose to
5 remove a $500,000 entr made though Adjustment 4.17 - Avian Settlement, for
6 Operatìon and MaÌntenance (O&M) expense. As shown on page 4.17.1, the
7 expense was recorded on December 31, 200S, and is not ìncluded in the rate case.
S This adjustment is backing out the Apri 30, 2009, reversing adjustment. Ms.
9 Vaughn argues for disallowance because this is a non-recurrng expense. Mr.
10 Meyer proposes removal under the premise that these are included in the balances
11 used to calculate a normalized level of Injures and Damages though the.12 Adjustment 4.14 - Insurance Expense. He argues that allowing the Company's
13 adjustment would represent a double recovery of costs if using a cash basis
14 method for Injures and Damages, or an overstatement of costs if usìng the
15 Company fied 3-year average accrual method. The proposed adjustments result
16 in a reduction to revenue requìrement of $26,961.
17 Additionally, Ms. Vaughn makes an adjustment to remove rate base
is related to transmission improvement projects to be completed as part of the Avian
19 Protection Plan because it falls below the $5,000,000 threshold for 2010 pro-
20 forma plant additions.
21 Q.Please explain the Company's position on the propoed adjustments.
22 A.The Company opposes the O&M adjustments. As described below, both
.23 adjustments are flawed. They are reversing costs which are not in the rate case.
1174
McDougal, Di- Reb - 6
Rocky Mountain Power
.1
2
3
4
5
6 Q.
7 A.
8
9
10
11.12
13
unclear. Page 5 states it would be a reductìon of $6,339, and page 15 states it
would be a reduction of $8,194, presumably takìg depreciatìon expense into
account. Because IPUC workpapers remove all rate base components, the
Company assumes the correct impact would be a reduction to Idao revenue
requìrement of $8,764.
Please explain the Company's proposed adjustment.
The Company does not oppose the proposed rate base adjustment on the basis that
if falls below the $5 millon theshold for 2010 pro-form plant additìons.
However, this holds no relevance when considering the project's usefulness.
Therefore, the Company agrees to make this adjustment ìn the current case, but
reserves the right to request recovery of these costs in its next general rate case
proceeding. The Company bears a responsibilty to operate, design and constrct
avian-safe power lines, and the capital projects are designed to do so. This
14 adjustment is ìncluded as Adjustment 11.3 in Exhibit No. 79.
15 Generation Overhaul Expense
16 Q.
17 A.
18
19
20
21 Q.
22.23 A.
Please describe the proposed adjustments to generation overhaul expense.
Mr. Meyer makes two adjustments to the Company's generation overhaul
adjustment. Fìrst,he rejects restating historical amounts to curent dollars prior to
averaging. Second, he proposes changing the four year average for new
generation units.
Does the Company agree with the adjustments made to generation overhaul
expense?
No. The Company belìeves that overhaul expenses should be restated to curent
1177
McDougal, Di-Reb - 9
Rocky Mountan Power
.1
2 Q.
3
4 A.
5
6
7
S
9
10
11 Q..12
13 A.
14
15
16
17
is
19
20
21
22.23
dollars prior to averaging.
Why doesn't the Company agree with the change in the four year average for
new generation units?
Mr. Meyer proposes to change the averaging method for the three newer plants -
Curant Creek, Lake Side, and Chehalìs - using a four-year average between 2007
and 2010. It is unreasonable to shift the four-year average of these plants to 2007
though 2010, considering Chehalis was fìrst put into service ìn September 200S.
The Company's adjustment uses the actual costs for the fìrst four full years plants
are in-service when avaÌlable. When the plants have not been online for four
years, the Company uses the budget for the fìrst four years of operatìon.
Does the Company agree with the adjustment not allowing the Company to
restate overhaul expenses to current dollars prior to escalation?
No. The Company belìeves that overhaul expenses should be restated to current
dollars prior to averaging and does not agree with Mr. Meyer's adjustment. The
Company continues to support the use of Global Insight indices to state overhauls
in curent dollars prior to calculating the four-year average. Averages are
intended to reduce year-to-year varances in expense, but not adjust for the time
value of money and the issue of ìnflation, as the value of the dollar in the test
period wil be less than the value of the dollar in historical years. Company
incurred expenses four years ago cost more in test year dollars to pay the same
expense. However, the Company is wiling to pursue discussions with paries on
this issue to brig more clarty to the Company's position and, therefore, for this
case only, the Company is removing the generation overhaul escalation, and
1178
McDougal, Di-Reb - 10
Rocky Mountan Power
.1
2
reserves its right to address this issue in the future with the Commssion. This
adjustment is ìncluded as Adjustment 11.4 in Exhibit No. 79.
3 Major Plant Additions
4 Q.
5
6 A.
7
8
9
10 Q.
11 A..12
13
14
15 Q.
16
17 A.
18
19
20
21
22
.
Please describe Mr. Leckie's proposed adjustment to the major plant
additions included in the Company's filing.
Mr. Leckie proposes that an adjustment be made to remove $34 milìon of total
company rate base from results, along with the corresponding depreciation
expense, to reflect updated project forecasts and in-servce dates that were
supplìed by the Company.
Has this adjustment been correctly reflected in IPUC's modeled position?
No. IPUC's adjustment removes capìtal from a transmission and intangible
FERC account, instead of the FERC account where the capital was origìnally
included in the adjustment. Additionally, the corresponding accumulated
deprecìation reserve adjustment has not been made in IPUC's modeled position.
Is the Company adopting the proposed adjustment in its revenue
requirement computation?
Yes. The Company is adopting this adjustment and has correctly reflected all
pieces of ths adjustment in the rebuttal posìtion. The corrected adjustment is
included as Adjustments 11.5 through 11.8 in Exhibit No. 79 to reflect the
updated plant in service (Adjustment 11.5), deferred income taxes (Adjustment
11.6), depreiation expense (Adjustment 11.7), and accumulated depreciatìon
reserve (Adjustment 11.8).
1179
McDougal, Di-Reb - 11
Rocky Mountain Power
.1 Q.
2
3 A.
4
5
6
7
8
9
10
.
.
Does Adjustment 11.6 include any change to taxes, other than updating for
the plant addition changes included in Adjustment 11.5?
Yes. In additìon to updating for the change in major plant additions included ìn
Adjustment 11.5, Adjustment 11.6 also updates this case for a change in bonus
depreciatìon. The Small Business Jobs Act of 2010 became law on September 27,
2010. The Act extended 50 percent bonus depreciation for qualifying assets for
one year (calenda year 2010). This update reuces the price increase in this rate.
case by approximately $1.8 millon. This adjustment was not included ìn the
diect testimony of any of the intervenors, but is being included in this rate case to
accurtely reflect this tax law change occurng after the case was fied.
11 Net Power Costs
12 Q.
13 A.
Have the net power CQsts been updated as part of the rebuttal filing?
Yes. As described in the testimony of Dr. Hui Shu, the Company has updated the
14 net power costs ìncluded in the case. These updates are ìncorporated into the
15 requested price ìncrease as Adjustment 11.9 of Exhibìt No. 79.
16 S02 Emision Allowance Revenues
17 Q.Please describe witness ,Mr. Meyer's proposd adjustment related to S02
18 emission allowance sales revenues.
19 A.Mr. Meyer proposes that past revenues from the sales of S02 emission
20 allowances be amortized over five years instead of the 15-year amortzatìon
21 schedule used by the Company in the initìal fìlng.
1180
McDougal, Di-Reb - 12
Rocky Mountain Power
.1 Q.Does the Company disagree with Mr. Meyer's adjustment to the
2 amortization of S02 allowances sales?
3 A.Yes. The Company agrees to shorten the amortization from 15 to 5 years;
4 however, Mr. Meyer's adjustment fails to take into account the impacts of the
5 adjustment to both rate base and taxes. The amortized sales are treated as a credit
6 to rate base. By excluding sales the rate base credit should also be reduced. All
7 revenues associated with new sales of S02 credits are given to customers in the
8 year they are received as par of the Company's ECAM filings. The Company
9 agrees that a 5-year amortization period flows back the revenues assocìated wìth
10 prior transactions to customers in a timelìer manner and help to reduce the
11 proposed rate increase in ths proceeding.
.12 Q.What is the impact of Mr. Meyer's adjustment when correctly calculated?
13 A.Correctly calculatìng the adjustment reduces the Idaho-allocated revenue
14 requìrement by $280,220.
15 Q.Has an adjustment associated with the amortization period of S02 emission
16 allowance sales revenues been reflected in your revised revenue
17 requirement?
18 A.Yes. Adjustment 11.10 of Exhibit No. 79 reflects the impact of changing the
19 amortization period assocìated with S02 emission allowance revenues from 15
20 years to 5 years.
.
1181
McDougal, Di-Reb - 13
Rocky Mountan Power
.
5
6
7
8
9
10
11
12
13
14
15
16
17
18.19
20
21
22
23
24
25
26
27
28
29
30
31
32
.
1 Contested Adjustments
2 Q. Are there adjustments to revenue requirement proposed by other parties
3 that the Company is not accepting?
4 A.Yes. I wìl address adjustments proposed by varous partes related to:
. Cash working capital
. Post test year rate base additions
. Pension expense
. Injuries and damages expense
. Affiliate management fees
. Outside services expense
. Uncollectible accounts expense
. Deferral of coal overburden strpping expense
. Imputed sublease revenue
. Property tax expense
. Residential retail revenue
· Jurisdictional load for allocations
. Allocatìon of the Monsanto specìal contract
· Allocation of the Idao Irgation Load Control Program
Other Company wìtnesses wìl also address issues raÌsed by other paries which I
have not incorporated into the Company's proposed revenue requìrement,
including:
· Residentìal load normlization and forecasted ìrgation load
· Jursdictionallìne 10sses
. General wage increases
. Incentive compensation
· Pension expense
· Supplementa executive retirement plan expense
. Fuel stock
· Incremental generation O&M expense
. Dunlap I wind plant capital costs
. Populus to Termnal transmission lìne
. Unbìled usage
1182
McDougal, Di-Reb - 14
Rocky Mountan Power
.1
2
3
4
5
6
7 Q.
8
9 A.
10
11.12
13
14
15
16
17 Q.
18
19 A.
20
.
Request 112, asking for the 2007 lead-lag study referenced in Steve McDougal's
diect testimony along with all supporting work papers, and Data Request 113
asking for any additional work papers supporting the Company's cash working
capital in the curent case. All responses were provided according to the pre-
determned procedural schedule, but Mr. Meyer did not request the study unti too
late to review prior to fìling his testìmony on October 14,2010.
Has the Company relied on a properly calculated lead.lag study to determine
cash working capital in this case?
Yes. The Company used a lead-lag study based on 2007 data to calculate Idaho's
cash working capital in this case. The Company updates ìts lead-lag study
approximately every five years or if there are significant changes in revenue
collection or expense remittance polìcy that would warant a new study. There
have been no significant changes since the 2007 study. The Company's previous
general rate cases in Idaho have calculated working capital in the same manner as
included in this case. The 2007 lead lag study was included in the Company's
last Idaho general rate case, Case No. PAC-E-08-07.
Has this study been used to calculate CWC in any other of PacifiCorp's
jurisdictions?
Yes. It has been used for rate setting puroses in Utah, Oregon, Wyoming and
Calìfornia.
1184
McDougal, Di-Reb - 16
Rocky MountaÌn Power
.1 Q. . Do you agree with Mr. Meyer's assertion that including other working
2 capital is merely another method to determine a working capital allowance,
3 and that the Company is attempting to double-recover that allowance?
4 A.No. Mr. Meyer made these assertions without ever reviewing the Company's
5 lead-lag study. The assets and liabilties underlying the other working capital
6 balances in this case, and theìr related business transactions, are not considered in
7 the Company's lead-lag study. The specifìc assets and lìabìltìes he refers to are
8 other cash working capital items ìn accounts 135, Working Funds; 141, Notes
9 Receivable; 232, Accounts Payable, related to employee benefìts; 253.3, Other
10 Miscellaneous Deferred Credits; and 254.105, Asset Retìrement Oblìgatìon
11 Regulatory Liabìlties, none of which are withìn the scope of the lead-lag study..12 Consequently, there is no double-recovery of working capital and this adjustment
13 is inappropriate.
14 Post Test-Year Rate Base Additions
15 Q.
16 A.
17
18
19
20
21
22.23
Please describe Mr. Meyer's proposed adjustment to post-test year rate base.
Mr. Meyer proposes an adjustment to remove approximately $665.8 milìon of
total company rate base and $6.9 millon total company deprecìation expense. Of
Mr. Meyer's total adjustment, $442.8 millon is due to increasing the accumulated
depreciation reserve and the remaining $223 millon is related to his estimated
impact on accumulated deferred income taxes based on incorrect assumptìons
regarding the calculatìon of the Company's test year in this case. In his
adjustment, Mr. Meyer reflects additìonal accumulated depreciatìon beyond the
historical test year and uses rough estimates to compute the impact on
1185
McDougal, Di-Reb - 17
Rocky MountaÌn Power
.
.
.
1
2
3
4 Q.
5 A.
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
accumulated deferred income taxes. Mr. Meyer also estimates pro form
retìrements to calculate the impact those retìrements wil have on deprecìation
expense.
Do you agree with Mr. Meyer's proposed adjustment?
No. This case is based on a historical test period with lìmited adjustments
reaching out twelve months beyond December 31,2009. The test period in this
case is based on traditìonal rate mang conventìons relied on in Idaho and is not
intended to be a full scale roll-forward into 2010. The Company has only
included capìtal projects over $5 millon that wil be used and useful by
December 31,2010. Accumulated deprecìation for these capìtal additions is
included as an offset based on the first full year of depreciation expense. Capital
projects below the $5 milìon threshold or projects that ar of a routìne natue (i.e.
feeder improvements, distrbution pole replacement, battery bank replacement,
etc.) are simply left out of the Company's case. The Company continues to place.
hundreds of millons of dollars worth of these capital projects into service each
year. If the Company had included all budgeted capital additions in its origìnal
filìng, total company electrc plant in service would have increased by over $530
milìon and would more than offset Mr. Meyer's additional accumulated
deprecìatìon. Mr. Meyer's argument that "one must properly consider all
increases in gross plant in post-test year periods, along with all ìncreases in
accumulated depreciation reserve" ignores the test period convention and the
limited nature of the Company's pro forma adjustments.
1186
McDougal, Di-Reb - 18
Rocky MountaÌn Power
.1 Q.Has any other party in this proceeding addressed the Company's proposed
2 test period convention in this case?
3 A.Yes. Commssion staff witness Mr. Randy Lobb mentions the Company's test
4 period on page 3 of his dìrect testimony. Mr. Lobb states, "Staff accepts the
5 Company's proposed historic test year of Januar 1,2009 through December 31,
6 2009 with reasonable pro form adjustments through December 31,2010."
7 Injuries and Damages
8 Q.Please describe the adjustments to injuries and damages ("I&D") expense
9 proposed by PUC witness Mr. Meyer and IPUC witness Mr. Donn English.
10 A.Mr. Meyer proposes that I&D expense be based on actual claÌms paid less
11 insurance reimbursements (Le. cash method) averaged over a thee year period.12 (2007-2009). Mr. Meyer points out that by basing I&D expense on the cash
13 approach, ratepayers are only requìred to pay the actual cost associated with I&D
14 claÌms.
15 Mr. English proposes that I&D expense be based on expense (Le. accrual
16 method) for calendar year 2009 only. Mr. Englìsh points out that the 2009 level is
17 the lowest expensed over the thee year period and that the amount expensed to
18 FERC account 925 has been trending downward. He attributes this trend to safety
19 measures undertaken by the Company durig 2008 and 2009.
20 Q.Are there any errors in Mr. Meyer's calculations which should be corrected?
21 A.Yes. In Mr. Meyer's cash basis calculation he includes actual claims paÌd but
22 mistakenly includes the ìnsurance receivable on an accrual basis, creating a
.23 mismatch wìthìn his own adjustment. The table below shows the correct
1187
McDougal, Di-Reb - 19
Rocky MountaÌn Power
.1 calculatìon of a thee year average under each method, accrual and cash basis.
2 Mr. Meyer's inconsistency is highlighted with the dashed outlìne.
I Injuries and Damges Accrual I Cash i I Variance I
Clais CY 2007 10,124,688 .'7,360,133 .(2,764,555)
Claims CY 2008 -6,052,960 !(2,447,373)8,500,333 .
Clais CY 200 4,492,982 !5,506,676 !1,013,694
Total Claims $23,118,003 L $18,919,769.-$(4,198,234)._._._._.-
Insurnce Receipts CY 2007 ,._._._._.,
(4,717,560)i 4,717,560 iInsurance Receipts CY 2008 5,340,408 .2,795,245 (2,545,163)
Insurance Receipts CY 2009 .2,615,133 !2,833,590 218,457
Total Insurance Receipts L $12,673,101 .1 $5,628,835 $(7,04,266)'-._._._.-
Total Claims Net of Insurce $10,44,902 $13,290,934 $2,846,032
3. Year Average $3,481,634 $4,430,311 $948,677
Idao SO Allocation %5.392%5.392%5.392%
Idaho Allocated $187,730 $238,882 $51,153
3
4.5
6
7
8 Q.
9
10 A.
11
12
13
14
15.16
The Company's filng is based on the three year average of accrued expenses net
of accrued receivables (the 'Accrual' column above). Correctly calculating the
three year average using a cash basis as proposed by Mr. Meyer would increase
the Company's case by $948,677 on a total Company basis and $51,153 on an
Idaho allocated basis.
Mr. Meyer argues that cash basis is needed so that rates are not set basd on
estimates of future claim that may not materialize. Do you agree?
No. The Company only records an accrual (reserve) for a specifìc claim if there is
a liabilty to the Company, a 70 percent likelihood of a payout probabilty, and a
documentable amount that can be used as justification for the reserve amount.
Once a claim is presented to the Company, an internal analysis is conducted by a
reserve commttee to determe the effect the claÌm may have on the Company.
This reserving and establishing of an accrual is governed by F AS 5 accounting
rules and Sarbanes-Oxley legislation. In addition, if the amount expected to be
1188
McDougal, Di-Reb - 20
Rocky Mountain Power
.1
2
3 Q.
4 A.
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22.23
paÌd out is subsequently changed, the adjustment is captued in the net insurance
expense.
Do you agree with the adjustment to I&D expense proposed by Mr. Englih?
No. Mr. Englìsh proposes to include I&D expense using just the calendar year
2009 results. His proposal is based on the fact that I&D expense in 2009 is the
lowest over the last three years. While I agree that the expense booked to PERC
account 925 has declined, I&Dexpense wil naturally vary year to year due to the
types of underlying claÌms. Expenses booked to this account include the cost for
claÌms from events in which there is damage or bodily injur to a thìrd pary.
This account does include expenses incurred as the result of auto accìdents, other
accidents and damages where a degree of employee negligence is involved,
however, the majority of the expenses recorded as injury and damages are the
result of events outside the diect benefit of the recent safety measures mentìoned
by Mr. Englìsh. These other types of events include, but are not limited to,
electrcal contact with power lìnes and equipment by the publìc, constrction
excavatìons of power lìnes and equipment by thìrd pares, damages from fires
caused by faulty transformers and other types of equipment,busìness interrption
from power outages and varous other types.
As Mr. English points out in his testimony, the Company has recently
improved ìts safety performnce, but claÌms wìl inevitably continue and the level
of expense wìl certnly var over time. One of the major safety improvements
.at the Company has been related to preventable vehicle accìdents. However, as
shown on page 4.14.1 of Exhibit No.2, auto damages account for less than 10
1189
McDougal, Di-Reb - 21
Rocky MountaÌn Power
.1
2
3
4
5
6 Q.
7
8 A.
9
10
11.12
13
14
15 Q.
16
17 A.
18
19
20
21
22.23
percent of claÌms paid. Contrar to Mr. Englìsh's implìcation, the Company's
improved safety is not the maìn reason for the low I&D claims in 2009. These
amounts tend to be unpredictable in natue. The purose of the thee year average
is to provide a smoothing of this expense over time because of the varabìlty and
ensure recovery of prudent costs while avoiding setting rates on high or low years.
Does Mr. English propose using an average to normalize other expenses in
this case?
Yes. Mr. English proposes using a five year average of cash contrbutions to the
Company's pension plan to set the level of pension expense in this case. His
argument there is just the opposite of his support for I&D expense - the base year
included in the Company's case is too high and that an average should be used to
reduce the amount included ìn rates. It appears Mr. Englìsh is trying to cherr-
pick actual, a historical average or a forecast average depending on which gives a
lower result.
What treatment does the Company recommend for injuries and damages
expense?
The Company continues to recommend using a thee year average of the net
injures and damages expense on an accrual basis, and respectfully requests the
Commssion make a determnation that a three year average be consistently
applìed in this and futue rate cases. The Commssion should reject the cash
method proposed by Mr. Meyer and also the method proposed by Mr. Englìsh
which uses only the base period (CY 2009) experience to determne the I&D
expen \Vel to be recovered in rates.
1190
McDougal, Di-Reb - 22
Rocky MountaÌn Power
.
.
.
1 Pension Expense
2 Q. Does the Company recommend any change to the Company's filed position
3 to calculate cash basis pension expense?
4 A.No.
5 Q.Please describe the $19.1 milion adjustment referenced in Mr. Williams'
6 testimony.
7 A.As described in the testìony of Mr. Wiliams, the Company does not accept Mr.
8 English's proposed adjustment, and proposes to continue on a cash basis as
9 included in Exhibit 2, page 4.13. However, if the Commssion proposes to use an
10 average, it should use a three-year historical average, which would result in an
11 adjustment of $ 19.1 millon. The calculation of the $ 1 9.1 miion is shown in the
12 table below.
1191
McDougal, Di-Reb - 23
Rocky Mountan Power
.
.
1 Q.
2
3 A.
4
5 Q.
6 A.
7
8
9
10.11
Cash Contributions:
Original Company Filng $ 104,800,00
Three Year Historical Average
2008 Actual
2009 Actual
2010 Actual (1)
3 Year A\irage
$ 65,627,000
49,564,280
112,800,000
75,997,093
Case adjustment to change to a 3 year average
Remo\i mines and joint \intures
Remo\i capitalization
Rate Case Adjustment - Total Company
Rate Case Adjustment - Idaho Allocated
28,802,907
(2,003,654)
(7,686,106)
$ 19,113,147
$ 1,030,623
(1) The case was filed using a preliminar estimate for 2010 pension contribution
of $104.8 million. Actual contribution for 2010 is $112.8 milion.
Has the Company proposed to use a 3-year historical average to calculate
any other level of expense in this case.
Yes. This is the same approach the Company recommends to calculate injuries
and damages expense.
Is Mr. English's adjustment consistent with the test period used in this case?
No. Mr. English is only allowing a forecast beyond the known and measurable
period to be used for this one item. All other items are based on the historical test
period with known and measurable changes. Over the next several years the
Company is forecasting cost increases related to plant-ìn-service, medical
benefits, general inflation, etc. While using a five-year projected average
prçiduces a decrease in pension costs, ìt is inconsistent with the test period used in
1192
McDougal, Di-Reb - 24
Rocky Mountan Power
.1 this case and is inappropriate.
2 This is also inconsistent with other adjustments proposed by the IPUC
3 staff.Staff is proposing to use a five-year historical average for propert taxes,
4 and at the same time they are proposing to eliminate the three year average use
5 for injuries and damages.
6 MidAmerican Energy Holdings Company ("MEHC") Management Fee
7 Q.Please describe the adjustments to the MEHC management fee proposed by
8 Mr. Meyer and Mr. English.
9 A.Mr. Meyer and Mr. Englìsh each propose to elimnate portions of the MEHC
10 management fee related to the incentive compensatìon. Mr. English also
11 recommends removìng supplemental executive retìrement plan ("SERP") costs.12 and Mr. Meyer recommends removing legislative expenses.
13 Q.Do you agree that the costs of SERP and incentive compensation should be
14 removed from the MEHC management fee?
15 A.No. As explained in furter detaÌI by Company witness Mr. Erich D. Wilson,
16 SERP and incentive compensatìon are individual components of total
17 compensatìon packages similar to those provided to PacifiCorp employees.
18 Expenses related to SERP and incentive compensation are appropriately ìncluded
19 in regulated results.
20 Q.Mr. Meyer also makes an adjustment to remove legislative costs from the
21 management fee. Do you agree with his proposal?
22 A.No. I agree that costs strictly related to the Company's legislative activity should.23 not be included ìn regulated results. However, contrary to Mr. Meyer's assertion,
1193
McDougal, Di-Reb - 25
Rocky MountaÌn Power
.1
2
3
4
5
6
7
.
8
9
10
11 Q.
12
13 A.
14
15.16
biled to PacìfiCorp was not booked above-the-line to begin with. The
Company's downward adjustment reduced the expenses booked above-the-line
from $8.4 millon to $7.3 millon. Durng 2009 MEHC biled PacìfìCorp atotal
of $ 11.6 millon, includìg costs related to legislative actìvities, incentive
compensatìon, SERP, and other charges. As shown in the table below, only $8.4
milion of the $ 11.6 millon bìled was originally booked above-the-lìne, and only
$7.3 milìon was included in the case.
MERC original invoices
Remove charges not eligible for inclusion in expense in the fiing:
Amount capitalized
Legislative
Aicraft costs excluded
LTIP
Eligible expenss
Cap per Commitment 28
Eligible expenses not included in filing
Summar of amount included in Idao GRC results
Amount charged to expense above the line in unadjusted results
Removed from unadjusted results in original filing
Amount charged to expense in original fiing
$11,568,011
(206,427)
(330,636)
(708,780)
(2,889,093)
$7,433,076
7,300,00
$133,076
$8,353,029
(1,053,029)
$7,300,000
The Company's original accounting and furter adjustment to lìmìt the
MEHC fee in rates to $7.3 millon adequately satisfies the Company's oblìgatìon
to bear the cost of inappropriate charges.
Has. the Company realized benefits from MEHC management since the
acquisition of PacifiCorp?
Yes. The Company has benefitted and wil continue to benefìt from having
MEHC as ìts holding company in several respects. Since MEHC acquìred
PacìfìCorp, it has implemented cost cutting strategies that have saved customers
milìons of dollars. For example, it is no coìncidence that labor costs either come
1195
McDougal, Di-Reb - 27
Rocky MountaÌn Power
.1
2
3
4
5
6
7
8
9
10
11.12
13
14
15
16
in lower or almost level with every rate case fìed - even during periods when
medical costs were rising significantly from year to year. MEHC's safety policies
have made a positive difference in the Company's safety record, which also
translates into dollars saved. Corporate functions that are performed by MEHC
on behalf of PacìfiCorp also save customers money because PacifiCorp does not
have to perform those functìons on its own. If MEHC were not performng those
functions, PacifìCorp would have to do so and may have to do it at a higher cost.
Also, because the Company's ownership changed from a publicly held company
to a privately held utilty, there are no shareholders' services costs that must be
paÌd. Notably, before MEHC ownership, the Company paid $15 millon to its
prior owners in management costs. In keeping with ìts cost cutting philosophies,
when MEHC acquìred the Company, MEHC agree that ratepayers need only pay
$7.3 millon of the $15 millon typically paid to the prior owner. In sum, the
Company has shown that as a result of MEHC' s philosophy of running a
streamlined company, millons of dollars have been saved to the benefit of the
Company, but most importntly, to the benefìt of the Company's ratepayers.
17 Outside Services Expense
18 Q.
19
20 A.
21
22.23
Please summarize Mr. Meyer's propos adjustment to outside services
expense.
Mr. Meyer proposes to adjust the Company's outside services expense (PERC
account 923) to a four year historical average of years 2006 - 2009. This
adjustment would reduce revenue requìrement by $327,080 on an Idaho allocated
basis.
1196
McDougal, Di-Reb - 28
Rocky Mountan Power
.1 Q.Does Mr. Meyer provide adequate evidence to support hi recommendation
2 for treating outside services expense differently than other O&M expenses?
3 A.No. Mr. Meyer's entìre argument consists of a single sentence statìng "the level
4 of expense incured in 2009 is the highest level of expense recorded by RMP
5 since 2006." 1 It is unclear why Mr. Meyer has singled out outside services for this
6 treatment, and he provides no concrete explanation why this paricular O&M
7 account deserves historical average treatment while others do not. Over the same
8 period of tìe renewable energy credits ("RECs") have increased from $3.7
9 milion to over $90 millon in the test period ìn this case. The level of expense or
10 revenue change over time is, by itself, no reason to use an average.
11 Q.Does Mr. Meyer challenge the prudence of any specific cost contained within.12 the outside services expense included in the test year?
13 A.No. He does not take issue with the prudence of any of the specific costs
14 contaÌned within the base period outside service expense.
15 Q.Do you believe that the level of outside services expense the Company
16 experienced in the 12 months ended December 31, 2009 represents a
17 reasonable, ongoing level of expense? Why?
18 A.Yes. I belìeve the level of outside services expense in the base period is
19 reasonable. Below is a table similar to the one Mr. Meyer included in his diect
20 testimony, except this table includes fiscal year 2005 to ìlustrate that the
21 fluctuations in this account are reasonable and do not warant the special
22 treatment proposed by Mr. Meyer..i Direct Testimony of Grg R. Meyer, Page 34, Line 1 - 2.
1197
McDougal, Di-Reb - 29
Rocky MountaÌn Power
.
1 Q.
2
3 A.
4
5
6
7.8
9
10 Q.
11 A.
12
13
14
15
16
17
18.19
Outside Services ExpensFY2006 1,542,476CY2006 1,067,814CY2007 580,987CY2008 670,661CY2009 1,209,260
4 yr avg $ 882,181
5 yr avg $ 1,014,240
What else concerns you with regards to Mr. Meyer's adjustment to outside
services?
Mr. Meyer proposes ìnconsistent adjustments to varous revenue requìrement
categories included in the Company case. He recommends weather normalized
usage be adjusted to a fìve-year average, S02 revenues be adjusted to a five year
average, injuries and damges expense be based on 3-year cash payments, and
uncollectìble expense be adjusted to a four-year average. The only consistency the
Company finds among these adjustments is that they all decrease revenue
requìrement.
Are there any other inconsistencies in Mr. Meyer's testimony?
Mr. Meyer is also very selectìve about which accounts he chooses to adjust. His
source for this adjustment to outside services was the Company's response to data
request PUC 64 which lìsts 2005 - 2009 O&M expense by FERC account. In
many accounts the 2009 test year expense is lower than the 4-year historical
average. However, no pary proposed an average methodology that would
increase test period revenue requìrement. In addition, he is even selective as to
which historical years to include in his average. Fiscal year 2006 outside services
expense was $1,542,476 so using a five-year average would have resulted in a
smaller adjustment to revenue requìrement.
1198
McDougal, Di-Reb - 30
Rocky MountaÌn Power
.1 Q.
2 A.
Should selected accounts be adjusted to a four year historical average?
No. It is important to consider the overall level of O&M for reasonableness
3 instead of isolatìng individual O&M accounts. In doing so, there wil always be
4 accounts that go up from a three, four or five year average and accounts that go
5 down. Mr. Meyer provides no arguments supportìng why outside service expense
6 is unique, therefore ìt would be no more appropriate to adjust this account
7 downward than it would be to adjust other FERC accounts upward to a four ýear
8 average. Acceptìng Mr. Meyer's adjustment would be unfai and would not
9 provide the Company a reasonable opportnity to recover ìts costs of providing
10 service to customers.
11 Uncollectible Accounts.12 Q.
13
14 A.
15
16
17
18 Q.
19
20 A.
21
22
.
Please briefly describe Mr. Meyer's proposed adjustment to uncòllectible
expense.
Mr. Meyer proposes to use a historical 4-year average of uncollectible expense
(PERC account 904) from calendar years 2006 - 2009 to estimate the appropriate
level for the test period. Using this methodology Mr. Meyer's adjustment would
reduce revenue requirement by $68,807.
What evidence does Mr. Meyer provide to support his recommendation for
using a four-year historical average treatment?
Mr. Meyer argues that because 2009 uncollectìble expense was at the highest
level since 2006 it should be adjusted. He also claims that the level of
uncollectible expense is not dictated by the level of revenues.
1199 McDougal, Di-Reb - 31
Rocky MountaÌn Power
.1 Q.Is Mr. Meyer's proposed adjustment a reaonable method of determining the
2 Company's uncollectible accounts expense?
3 A.No. This is another example of an adjustment that isolates a single expense
4 account to produce a reductìon to revenue requìrement. As discussed above, Mr.
5 Meyer recommends special treatment for this account but does not provide
6 adequate support for his argument. His proposal to use an historical average to
7 determne the level in 2010 is both unreasonable and inappropriate. The
8 Company's test period is based on 2009 actual data adjusted for known and
9 measurable events, not a test period of average costs from 2006 to 2009 and only
10 when those averages decrease the revenue requìrement.
11 Q.Why is it inappropriate to use a four-year historical average methodology?.12 A.This method fails to account for conditions during the rate effectìve period. The
13 Company has experienced a steady increase in uncollectible expense since 2008.
14 The char below shows Idaho uncollectible expense for the 2006 - 2009, the 12
15 months ended June 2010 and year to date Januar though October 2010.
.
1200
McDougal, Di-Reb - 32
Rocky MountaÌn Power
.
1.2
3
r....................................................................................................................................................................................................1¡ Idaho Uncollectible Expense .. ¡l I
I $700,000 r"-'" ""ôs2,ss4 I¡, I Meyer's Prposed $406,456
I $600,000 .1...SŠi9To6-..............._.-i............................................$5.10.42............ I¡ $500,000': ..-.-.-___. __...... $4U.i63 . ¡i $400,000 J. I:Il'i,l i; ii, $300,000 l--- ;
¡ $200 000 +...... ¡l ' I ¡
i $100,000 r II $0 .l....... i
I 12 ~~~e, 12 ~~~e, 12 ~~~e, 12 ~~~e, 12 2~~~un Ja;~,~'t Il Ll L\.......................................................................................................................................................................................................l
As shown in the table above, the averaging method produces a 2010
uncollectìble expense level that is below the actual expense for the fìrst 10 months
of 2010. Adopting Mr. Meyer's adjustment would result in under-recovery of the
4 Company's uncollectible expense.
5 Bridger Coal Stripping
6 Q.
7
8 A.
9
10
11
12.13
Please explain Ms. Vaughn's adjustment related to the coal stripping
deferral.
Ms. Vaughn proposes to reduce Idaho revenue requìrement by $6,133 by
removing deferred coal stripping costs from rate base. In Case No. PAC-E-09-08
the Company was authorized to defer in a regulatory asset the costs assocìated
with the removal of overburden and waste materials at the Bridger mìe. Ms.
Vaughn argues that because the regulatory asset was created as a result of an
accountìng procedural change, it would be inappropriate for the asset to accrue a
1201
McDougal, Di-Reb - 33
Rocky Mountan Power
.1
2
3
4 Q.
5 A.
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
.
carìng charge. She also argues that because the Company did not request a
caring charge in its origìnal application, it should not be included in rate base in
this case.
Do you agree with Ms. Vaughn's proposed adjustment?
No. Ms. Vaughn's adjustment unfaìly penalizes the Company for an attempt to
reduce the disparty created by timing difference between ìncurng the strpping
costs and the tìme when the uncovered coal is actually extracted. As approved by
the Commssion, stripping costs are now deferred to a regulatory asset rather than
immediately included in fuel stock inventory and amortzation is matched with
coal extractìon. Without the deferred accounting treatment, the Company is
.
requìred to reflect strpping costs as varable production costs during the period
that the strpping costs are incured, impactìng the cost of the inventory produced
in that period. Under this accounting requìrement, customers could pay for the
costs of uncovering coal well before it was extracted from the mine. Under the
former treatment, stripping costs would be included in fuel stock ìnventory in the
curent period and they would be ìncluded ìn rate base. The regulatory asset now
serves as a temporar holding place for these costs until coal is extracted and
included in fuel stock. There is no real change ìn the underlying business process,
and the Company should be allowed to include the regulatory asset ìn rate base
just as the costs would have been included in fuel stock prior to the approval of
deferred accounting treatment.
1202 McDougal, Di-Reb - 34
Rocky Mountan Power
.1 Q.
2
3 A.
Why did the Company not originally request a carring charge in Case No.
PAC-E-09-08?
The Company's application in that case did not addrss the ratemakng treatmen~
4 related to the change in accountìng. Rather, it deferred rate makng consideratìons
5 to a subsequent general rate case. In its order the Commssion witheld ìts review
6 and judgment regarding the propriety of the deferred coal stripping costs until the
7 Company requested recovery of such costs though rates.
8 Imputed Sublease Revenue
9 Q.
10
11.12
13 A.
14
15
.
Mr. English proposes to impute subleae revenue related to two below
market subleases to the Utah Sports Commission ("USC") and the Economic
Development Commission of Utah ("EDCU"). Do you agree with this
adjustment?
No. While I agree with the premise that Idaho customers should not subsidize
these below market subleases, in fact, the impact is already excluded from Idaho
allocated results in this case.
1203
McDougal, Di-Reb - 35
Rocky Mountan Power
.1 Q.
2 A.
3
4
5
6
7
8
9
10
11
.12
13
14
15
16
17
18
19
.
Please further describe the subleases in question.
As described by Mr. Englìsh, the Company sublets a portion of its offìce space in
the One Utah Center ("OUC") in Salt Lake City, Utah, to EDCU and USC at a
rate of $1 per month rent plus operating expenses. The rent subsidy is considered
a challenge grant to these organizations. Makng contrbutions to these entitìes by
absorbìng these lease expenses is a key element to partnering wìth economic
development organizations that, in effect, become an ìndustrial customers' first
point of contact in the state. For accounting purposes, the Company's results of
operations initìally ìnclude the tota cost of the master lease at the OUC,
approximately $2.1 millon per year, allocated to all states on the System
Overhead ("SO") factor. Each month, the subsidized porton of the subleases to
EDCU and USC is reclassifìed from rent expense to donation expenses in FERC
account 930 and is situs assigned to Utah. The accounting for calendar year 2009
is shown in the table below:
Description
OUCRent
Rent Subsidy to EDUISCU
FERC Account
931 - Rents
931- Rents
Allocation Factor Total CompanySO $ 2,141,496SO (157,072)
Net Rent Allocate to Idaho $ 1,984,425
Rent Donation/Challenge Grant 930.2 - Mise General Expenses $UT 157,072
In 2009, rent payments totaling $157,072 for these two subleases were
diectly assigned to Utah, rendering Mr. English's adjustment imputing $142,069
of sublease revenue unnecessar. None of the net costs assocìated wìth the below
market rate for these two subleases has been allocated to Idaho rate payers, so Mr.
English is removing a cost that is not included in the rate case.
1204 McDougal, Di-Reb - 36
Rocky Mountan Power
.1 Property Tax Expense
2 Q.Please describe the adjustment to property taxes proposed by Mr. English.
3 A.Mr. Englìsh states that the Company routinely and successfully appeals the
4 assessed value for the property that is taxed by varous states, resultìng in property
5 tax refunds. Mr. Englìsh reduces tota Company propert tax expense in the case
6 by $288,125, the average annual refund for tax years 2005 through 2010.
7 Q.Why does Mr. English's adjustment improperly reflect property tax expense
8 for the test period in this case?
9 A.The adjustment proposed by Mr. English is not applicable to the test period in this
10 case because ìt incorrectly assumes that prior year tax appeals weré completely
11 ineffective in resolving disagreements concerning the valuation methodologies.12 employed by state assessment personnel and that the use of such methodologies
13 must be challenged agaìn durng every futue assessment year. On the contrar,
14 as tax appeals are pursued and such appeals result in the use of more favorable
15 valuation methodologies, the adjusted valuatìon methods are incorporated into the
16 models employed by the Company when estimating property tax expense for rate
17 case purposes. In other words, the beneficial effect of prior year appeal actìvity
18 was taken into account by the Company when estimating 2010 property tax
19 expense in the current rate case. Makng an additional adjustment pertaìning to
20 prior year appeals would effectively double count the benefit of such appeals.
21 Q.How does the estimate included in the Company's case compare to curent
22 expectations of property ta expense in 2010?.23 A.As explaÌned to Mr. Englìsh during his on site visit to Portland, actual property tax
1205
McDougal, Di-Reb - 37
Rocky Mountain Power
.1 expense for 2010 is likely to be several millon dollars higher than the estìmate
2 contaÌned withn the Company's case. If the Commssion were to conclude that
3 the adjustment proposed by Mr. English is waranted, then it should also mae an
4 addìtional upward adjustment to recognize that the origìnal estimate ìn the
5 Company's case is understated. The size of that upward adjustment to 2010
6 property tax expense would substantially exceed the size of the downward
7 adjustment proposed by Mr. Englìsh.
8 Residential Revenue
9 Q.Do you agree with Mr. Meyer's proposal to use the historical 5-year average
10 kWh usage/per customer bil instead of temperature normalized sales?
11 A.No. As furer detaÌled in Company witness Dr. Peter C. Eelkema's testimony,.12 Mr. Meyer provides no rationale for ignoring temperature normlization for the
13 residential class, nor his choice to extend the period from a 2010 test year to a
14 historical 5-year average.
15 Q.Do you agree with Mr. Meyer's revenue requiement computation resulting
16 from the change in average residential use perbil?
17 A.No. Mr. Meyer has faÌled to properly account for the full effect of increasing
18 residentìal sales. Fìrst, his computation of the ìncremental net power cost is
19 incorrect. Second, he faÌls to account for the corresponding change to
20 jursdictional load (energy and peak) used for inter-jursdictional allocatìon.
21 Q.Please explain why you disagree with Mr. Meyer's calculation of net power
22 costs related to incremental sales..23 A.There are two problems with Mr. Meyer's calculation of the net power cost
1206 McDougal, Di-Reb - 38
Rocky Mountan Power
.1
2
3
4
5
6
7
8
9
10
11.12
13
14
15
16
17 Q.
18
19 A.
20
21
22
.23
impact of his adjustment. Fìrst, Mr. Meyer uses embedded rather than
incremental net power costs in his calculation. Second, Mr. Meyer incorrectly
calculates the Idaho's embedded net power cost.
To correctly calculate the net power cost impact related to incremental
revenues, Mr. Meyer needs to use a power cost dispatch model, or use an estìmate
based on the market price of energy. He faÌls to use either of these methods, and
instead assumes that the incremental cost of power is equal to the embedded cost
of power.
Mr. Meyer incorrectly calculated embedded net power costs. His
calculation relìes on the Idaho allocated net power cost adjustment included on
Page 5.1 ofExhibìt 2 and not the Idaho allocated total net power costs included in
the case. Mr. Meyer's calculation results in Idao net power costs of $65,023,822
rather than the correct amount of $69,234,037 as reflected on page 2.2 of Exhibìt
2. Correctìng Mr. Meyer's embedded net power cost approach, without changing
to an accurate incremental net power cost approach, reduces his adjustment by
$36,846.
Please explain the effect of including the change to loads at input based on
Mr. Meyer's proposed incremental sales.
Increasìng sales by 21,075 MWh as proposed by Mr. Meyer results in an increase
to Idaho system energy loads of 23,157 MW when grossed up for lìne losses,
and a corresponding increase of 32.7 MW to peak loads. This ìncrease has an
impact on Idaho jursdictìonal allocation factors, and increases Idaho-allocated
revenue requirement by $ 1,117,959 . When offsetting ths ìncrease in allocated
1207
McDougal, Di-Reb - 39
Rocky MountaÌn Power
.1
2
3 Q.
4 A.
5
6
7
8
9
10
11.12
13
14
15 A.
16
17
18
19 Q.
20 A.
21
22.23
costs agaìnst Mr. Meyer's imputed revenue adjustment of $ 1,168,333 (usìng the
corrected net power cost amount), the net result is an adjustment for $50,374.
What is your recommendation regarding Mr. Meyer's proposed adjustment?
The Company recommends no change be made to residentìal revenues as Mr.
Meyer fails to provide any proven support to indicate the validity of ignorig
temperature normlìzed sales. Dr. Eelkema provides testimony on why the
Company's forecast is more accurate than the simplistic average used by Mr.
Meyer. Furermore, the Companyrejects Mr. Meyer's adjustment to revenues
due to the miscalculation of net power costs and his faiure to look at incremental
costs, along with his faìlure to captue the effect on Idaho jursdictional factors by
having no incremental adjustment to loads at inputs.
Jurisdictional Load for Alloction
Q. Do you agree with Mr. Anthony J. Yankel's contention that the Company's
has overestimated line losse in jurisdictional loads?
No. The Company's load measurements are consistent with prior filìngs, and are
calculated in a similar manner for all states. Mr. Yanel's proposal is not
consistent with prior fiings, and he does not make simlar adjustments to other
states, leading to inconsistent allocation factors among states.
Please desribe the method that the Company used to estimate line losses.
The Company has taken the total energy coming into jurisdictìon plus any
generation ìn jurisdiction minus energy leaving the jursdiction. The Company
adjusts for losses resulting from moving Bridger generation to Goshen, Kìnport,
and Borah. After subtracting Idaho retail sales, the remainder is losses.
1208 McDougal, Di-Reb - 40
Rocky Mountan Power
.2 Idaho Cas No. PAC-E-02-3, Direct testimony of David L. Taylor, page 12, lines 11-15.
3 Rebuttal Exhibit 2, page 2.3, line 111
1209
McDougal, Di-Reb - 41
Rocky Mountaìn Power
.1 Q.
2
3
4 A.
5
6
7 Q.
8 A.
9
10
11
12.
Mr. Yankel states on page 20 and 22 of his testimony that tranmision losses
should be equally shared by all jurisdictions. Doe each state use the
transmission system equally?
No. Because there is insuffìcient generation in Idaho to support Idao customers'
load, generatìon must be brought in from other locations. This would utilze the
transmission system more than a load center that is located closer to generation.
Does Mr. Yankel's proposal treat all states consistently?
No. Mr. Yanel reduces Idao's load, but does not make simiar adjustments to
all other states. Mr. Yanel assumes he does not need to adjust net power costs
because his ìrgation and allocation load adjustments basically offset. This is an
ìnvalid assumption because, in addition to calculating Idaho load contrar to
Revised Protocol, he also calculates ìt inconsistently with other states.
13 Monsanto Special Contract Allocation
14 Q.
15
16
17 A.
18
19
20
21
22
.23
Do you agree with Ms. Kathryn E. Iverson's assertion that a proper
jurisdictional allocation study would reflect only Monsanto's firm demands
for purposes of allocating costs?
No. Ms. Iverson bases her argument on the claìm that the Company has not
planned for, or acquìred resources, on the basis of Monsanto's non-fìr load.
Company wìtness Mr. Gregory N. Duvall provides rebuttal testimony
demonstrating that Monsanto's claim is incorrect and that the Company does, in
fact, plan for Monsanto's load and is requìred to provide service to Monsanto for
the vast majority of the time. The curent curlment contract with Monsanto
lìmìts the number of hours in a year the Company can interrpt service to
1210
McDougal, Di-Reb - 42
Rocky Mountaìn Power
.1
2
3
4
5 Q.
6
7 A.
8 Q.
9
10 A.
11.12
13
14
15
16
17
18
19
20
21
22
.23
Monsanto and has specìfic constraints regarding the amount of load that can be
curtaìled at a given time. In order for Ms. Iverson's assertion to be tre the
Company would need the abilty to curtail service to Monsanto at any time with
no lìmitation over the course of a year.
Have you reviewed Ms. Iverson's calculation of the impact on revenue
requirement in this case using her suggested 'non-firm' allocation approach?
Yes.
Do you agree with her calculation of a $12 millon reduction to the overall
price increase sought by the Company in this case?
No. I found two maìn issues with Ms. Iverson's calculatìon ofthe non-fìr
allocatìon impact. Fìrst, because she claims the Company does not plan for
Monsanto's non-fìr load, Ms. Iverson has removed 170.1 MW of demand from
all twelve monthly coincìdent peaks used to determne Idaho's contrbution to the
system peak. In other words, Monsanto proposes to include only 9 out of 182
MW of Monsanto demand in the Idaho jursdictional coincident peak every
month. If Monsanto's load were to be excluded from the Idaho jurisdictional peak
for a study of this nature, it should only be excluded from a lìted number of
months, realistically representing the impact of the curaìlment on PacifiCorp's
operatìons. Second, Ms. Iverson improperly removed retaìl revenue from
Monsanto based on avoided non-firm demand charges. In reality Monsanto wìl
not avoid reaching its peak demand for an entìre month as a result of PacìfiCorp
curailment. Revenue should be removed based on curaìled energy at the non-
firm energy rate of 2.38 cents per kilowatt hour. Finally, Ms. Iverson's
1211
McDougal, Di-Reb - 43
Rocky Mounta Power
.1
2
3
4
5 Q.
6
7 A.
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22.23
adjustment does not remove the appropriate amount of revenues related to
interrptible demand changes. Ms. Iverson's representation of Monsanto
curtlment, removing 170.1 MW from the Idaho jursdictional peak every month
and avoiding demad charges for every month of the year, is certaìnly fiction.
Why is it not realistic to remove 170.1 MW from each of the monthly
jurisdictional peaks?
According to the term~ of the Company's contract with Monsanto for 2010,
economic curtaìlment of 67 MW is available for 850 hours and operatìng reserves
curtailment of 95 MW is available for 188 hours. After accountìng for line losses
the total curailment is 170.1 MW. However, removing all 170.1 MW from each
month's coincident peaks is in appropriate for thee reasons:
· The total hours avaìlable for some type of curilment equate to 1038, less
than 12 percent of the hours in the year. For the remaìning hours durng
which Monsanto load is not curtailed the Company must stand ready to
provide electrc service to Monsanto.
· Pursuant to the contract, the Company can never actually curaìl all 170.1
MW at one time. Curailment for operating reserves is assigned to two
smaller furnaces, with total load of 95 MW, and economic curilment is
assigned to one larger fuace with a load of 67 MW. If one of the
furaces is aleady not operating either for maintenance or overhaul, the
Company can curtaìl both remaining furnaces, but the total curaiment
would be less than the 170.1 MW. If one of the furaces is aleady not
operatìng for economic curtaìlment, the Company can only curaìl one
1212
McDougal, Di-Reb - 44
Rocky Mountaìn Power
.1
2
3
4
5
6
7
8
9
10 Q.
11.12 A.
13
14
15
16
17
18
.
additìonal furnace. Mr. Duval explaìns how the Company's resource
planning is impacted by this limitation to available curtlment. This
means the maximum actual curtilment is 116 MW out of the 170.1
proposed by Ms. Iverson.
· As shown on Tab 5 - Page 6 of Exhibìt 49 sponsored by Company wìtness
Craig Paice, for eight out of twelve months during the test period total
Monsanto load at the coincident peak is actually less than 170.1 MW. It
would be entìely inappropriate to reduce Monsanto load below zero in a
given month.
Have you properly calculated the impact of Monsanto's proposal on the
Company's case?
Yes. I performed a calculatìon similar to the one proposed by Ms. Iverson, but
that also considers the constraìnts of the Company's contract wìth Monsanto. I
firt reviewed the Company's annual results of operations reports since 20054 to
reveal the number of tìmes in a year Monsanto load was actually curtailed at the
time of the system peak. The table below shows that from April 2004 though
December 2009 Monsanto curailment events occurred at the time of the monthly
system peak at most five times durng a given year.
4 The IPUC approved the Revised Protocol Stipulation on Februar 28, 2005.
1213
McDougal, Di-Reb - 45
Rocky Mountaìn Power
.Curtilment Events at Hour of Monthly System Peak
FY20S FY2006 CY2006 CY2007 CY200S CY2009
Januar
Februar
March
April
May
June x x
July x x x
August x x x x
September x x
October x
November x x x x
December x x x
Count 3 3 5 5 1 2
1
2
3
4.5
6
7
8
9
10
11
12
13
14
15.
All of the events in the table above are the result of economic curailment;
no operatìng reserve events occured at the time of the system peak. Based on
that historical record I removed Monsanto load from 6 of the 12 monthly
coincident peaks, conservatively representing curaìlment events durng a given
year. I removed 70.3 MW (67 MW adjusted for lìne losses) from Idao
jursdictìonal peak, representing the economic curtaìlment porton of the contract
adjusted for lìne losses. In addìtion, I removed 850 hours of curtailed energy
from the Idaho jurisdictional energy, and I removed retail revenue for reduced
sales priced at the non-fir energy rate. This scenaro reduces the overall price
change to. Idaho in this case from $24.9 millon (the Company's rebuttal positìon)
to $18.7 millon, a reduction of $6.2 millon.
To get a better idea of the net impact on customers, this reduced revenue
requìrement must be allowed to flow though a similarly impacted cost of service
study. The tables below compare Monsanto's allocated cost of service under the
Company's rebuttal fììng and a corrected non-fir allocatìon scenaro.
1214
McDougal, Di-Reb - 46
Rocky Mountain Power
.Company Rebuttal
Description Annual
Revnue
Total
Cost of
Servce
Increase
(Decrease)
to = ROR
13,996,524
tØ,~1t,4!$
24,869,980
Percentage
Change frm
Current Rewnues
9.82%All Others 142,524,117 156,520,641
5$,S?4,497 '1t),Sg1,Øsa .............
202,048,614 226,918,594
Non-Firm Scenario
Description Annual
Revnue
Total
Cost of
Servce
Increase
(Decreae)
to = ROR
14,097,933
Percentage
Change frm
Current Rei.nues
9.89%All Others 142,524,117 156,622,051
,s,1Ø6,S1R 6?"('3~,Ø?$.
200,692,635 219,354,077
Under the non-fìr allocatìon scenaro, Monsanto's allocated cost of service is
$7.7 millon less than under the Company's rebuttal results. However,
Monsanto's allocated cost of service in the Company's rebuttal fìlìng would be
offset by the separate payment from the Company related to the value of the
curaìlment products. There would be no separate payment under the non-fir
scenaro. Under the non-fir scenaro, if the Company were to pay a curilment
payment or credit (as we have done ìn the past several contracts) ìt would results
in a double counting of curaìlment benefìts. The ultimate net impact on
Monsanto relatìve to the allocatìon methodology wìl be determned by the value
ascribed to the curaìlment products, an issue that wìl be determed in a separate
phase of this case.
Do you agree with Ms. Iverson's assertion that the Revised Prot~col
treatment of Monsanto is a fiction that has resulted in increases to Monsnto
year after yea?
No. The Revised Protocol was an agreement between paries ìn Idaho as well as
stakeholders across four states that underwent significant scrutìy and analysis.
1215 McDougal, Di-Reb - 47
Rocky Mountan Power
.
.
.
1
2
3
4
5
6 Q.
7
8 A.
9
10
11 Q.
12
13 A.
14
15
16
17
18
19
20
21
The primar purpose of the Revised Protocol was to achieve a consistent method
for allocating costs and benefits of providing service across the Company's multi-
state service terrtory. The cost of providing service to all of our customers in
Idaho has certinly risen since the Revised Protocol was adopted, but the
allocatìon methodology itself is not the man drver of rate increases to Monsanto.
Was Monsanto a party to the Stipulation supporting the Revised Protocol
approved in Case No. PAC-E-02-3?
Yes. Monsanto was a pary to the stipulation reached ìn that case supporting the
use of the Revised Protocol, and the signing paries to the Stìpulation belìeved the
terms of the Stìpulation were faì, just, and reasonable.
Is the allocation of costs and benefits related to special contracts with
industrial customers a significant issue addressed in the Revised Protocol?
Yes. The issue of allocating costs and benefìts related to specìal contracts is
repeated several times as an important issue addressed with the Revised Protocol
agreement. PacifiCorp's comments supporting the Stìpulation state, "The
Revised Protocol, if ratified by all of PacìfìCorp' s state commssions, wìl
establìsh uniform polìcies in respect to a number of critical issues. These
include. . .how the costs and benefìts of special contracts with ìndustral customers
wìl be allocated among states."s In addition, the joint motion for approval of the
settlement signed by PacìfCorp and the Idaho Commssion staff identìfes that
the Revised Protocol addresses the allocatìon of special contracts.
5 Page 4, PacifiCorp Comments in Support of Joint Motion for Acceptance of Settlement, Cas No. PAC-E-
02-3.
1216
McDougal, Di-Reb - 48
Roèky Mountain Power
1217
McDougal, Di-Reb - 49
Rocky Mountaìn Power
.1 Q.What is the appropriate forum for Monsanto to address the allocation of the
2 costs and benefits related to its special contract?
3 A.The MSP Standing Commttee was establìshed as par of the Revised Protocol to
4 "oversee contìnuing analytical efforts associated with inter-jursdictional
5 issues...and serve as a forum for the paries to discuss and hopefully resolve
6 emergìng inter-jursdictìonal issues. Meetìngs of the MSP Standing Commttee
7 are to be open to all interested paries. Those meetìngs are expected to assist in
8 maìntaìning an ongoing consensus among PacìfìCorp's states regardìng inter-
9 jursdictional issues, thereby preserving the accomplishments of the MSp"6
10 (emphasis added). It is of utmost importance to the Company that issues affecting
11 multiple states be brought to the MSP Stading Commttee ìn an effort to preserve.12 consistent allocations across paricipatìng states. Altering treatment of one
13 special contrct in this case simply because another method produces a smaller
14 rate ìncrease for one customer is inconsistent with the signed stipulation.
15 Q.Ms. Iverson compares her propos allocation treatment of Monsanto
16 curtailment to the Idaho irrigation load control program and another special
17 contract with a Rocky Mountain Power customer in Utah. Do you agree that
18 her proposal is comparable to these other examples?
19 A.No. Ms. Iverson's proposal is much more aggressive than the treatment of either
20 of these programs. As mentioned previously, Ms. Iverson removed 170.1 MW of
21 Monsanto demand in all twelve months of the year. While jursdctional load is
22 reduced for curailment from Idaho ìrgators and the Uta special contract, it is.6 Page 6, Order No. 29708, Case No. PAC-E-02-3.
1218
McDougal, Di-Reb - 50
Rocky Mountaìn Power
.1
2
3 Q.
4
5 A.
6
7
8
9
10
11
lìmìted to curaìlment achieved pursuant to the terms of the respective agreements
and is limited to a specific number of months.
Do you have additiona concerns with the comparin to the Idaho irrgation
load control program?
Yes. In this case the Idaho Commssion staff, ICL and Idaho Irgation Pumpers
Assocìation each propose that the costs and benefits of the Idaho ìrgation load
control program be allocated system-wide, rather than the curent treatment. But
Monsanto points to the ìrgation load control program as an example of proper
situs treatment. This varation of proposals highlights the Company's concern
that cìrcumventing the agreed-upon process of addressing multi-state issues
through the MSP Standing Commttee results in short sighted decisions and.12 contìnued inconsistent treatment.
13 Idaho Irrgation Load Control Program
14 Q.
15
16 A.
17
18
19
20
21
22.
Please describe the positions taken by parties with respect to the Idaho
Irrigation Load Control Program.
The Idaho Irgation Load Control Program is addressed by multiple paries in the
case. I wìl briefly describe some of the positions in the case.
Mr. Don C. Reading proposes that "the Commssion, Company, and other
paries should pursue allocating the ìrgation load control program Schedules 72
and 72A, as a system wide resource. While this proposal likely requìres a change
to the Revised Protocol for inter jursdictional cost allocations, we belìeve it is a
reasonable and prudent proposal."?
7 Direct testiony of Don Reading, page 2, lines 9 - 12.
1219
McDougal, Di-Reb - 51
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10 Q.
11.12
13 A.
14
15
16
17 Q.
18
19
20 A.
21
22.23
Mr. Yanel proposes that "in the long term (by the next rate case), that this
program be treated more as a system benefit where the curtlments are 'sold' to
the system at theìr tre value." He also proposes that the Company increase the
curaìlment used in this case to the amount that was available.
Mr. Lobb and Ms. Terr Carlock for the Commssion staff both fied
testimony on the ìrgatìon program. Mr. Lobb claìms that the costs of the
Irgation Load Control program assigned to Idaho customers is inequitable when
compared to the program benefìts received. Ms. Carlock supports assignìg the
costs of the ìrgation program as a power supply cost.
Do you agree with Mr. Lobb and Ms. Carlock that the progrm contracts are
more like purchase power agreements or ancilary service contracts and
should be similarly system allocated?
The Company agrees that there are characteristics that make the ìrgatìon
program more like an interrptible program. However, the Company believes
that this decision needs to be made by the MSP Standing Commttee, and needs to
be consistently applìed to all Class 1 DSM programs.
Do you agree with Mr. Reading's proposal that the Commission, Company,
and other parties should pursue allocating the irrgation load control
program as a system resource?
Although the Company does not belìeve this should be done in this case, the
Company is not opposed to Mr. Reading's proposal as long as ìt is done ìn the
correct foru and is applìcable to clearly defined resources. As mentioned
previously, the Company belìeves that this decision needs to be made by the MSP
1220
McDougal, Di-Reb - 52
Rocky Mountain Power
.1 Standing Commttee, and needs to be consistently applìed to all Class 1 DSM
2 programs.
3 Q.Did the Company incorrectly include only 229 MW of program participation
4 in the jurisdictional load decrement as alleged by Mr. Yankel?
5 A.No. As described in the Company's responses to IIPA data requests 64 and 90
6 sponsored by Dr. Eelkema, as well as in Dr. Eelkema's diect testimony, the
7 229MW included in the filìng is the correct amount as it represent the level of
8 potential interrptìbìlty of paricipatìng loads during a given dispatch event.
9 Q.Do you agree with Ms. Carlock's conclusion that a classification change for
10 thi program would allow it to be system allocated under the Revised
11 Protocol?.12 A.No. As stated in my diect testimony, this program as a Class 1 DSM program.
13 According to Sectìon iv, Subpar C of the Revised Protocol, demand-side
14 management programs are assigned to the State Resources category. According to
15 the Revised Protocol:
16 "Costs associated with Demand-Side Management Programs wìl be
17 assigned on a situs basis to the State in which the investment is made.
18 Benefits from these program, in the form of reduced consumption, wil be
19 reflected though tìme in the Load-Based Dynamc Allocation Factors."
20 The Company believes that there is sufficient justificatìon to bring ths
21 issue before the MSP standing Commttee for resolution.
22 Q.Do you agree with Mr. Yankel's proposed revision to the curtailment
23 adjustment?
24 A.No. Mr. Yankel proposes to revise the curtaìlment values for June, July and.
1221 McDougal, Di-Reb - 53
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9 Q.
10
11 A.
12
13
14
15
16 Q.
17 A.
18
19
20
21 Q.
22 A.
.
.23
1222
August to 234 MW, 260 MW and 246 MW respectively.8 However, as shown on
Tab 5, page 6 of Exhibit 49, the contribution to the coincident peak for the entìe
ìrtatìon class during those the months is only 277 MW, 180 MW and 178MW.
Mr. Yankel's proposal would remove 260 MW ìn July, even though the entìre
ìrgatìon class, including those not on the interrptible schedule, is only 180
MW. This same result occurs during the month of August when Mr. Yanel
would remove 246 MW and the ìrgation class contributìon to the coincident
peak is only 178 MW.
Do any other juridictions served by PacifiCorp have similar programs, and
are those programs treated in a similar manner in this case?
Yes. The Company operates programs to control ìrgation and central aì
conditioning load in its Utah service terrtory. Both of these programs are treated
in a similar manner as the Idaho ìrgation program, i.e. the Utah load used to
compute ìnter-jursdictional allocation factors is reduced to reflect program
paricìpatìon and the program costs are direct assigned to Utah.
Did any party propose adjusting this case for the Utah programs?
No. All adjustments made in this case were to the Idaho ìrgation only. None of
the pares attempted to adjust ths case for Utah Class 1 DSM programs. If a
change is made, it should be a universal change with specific rules about which
programs qualìfy for system treatment.
What changes does the Company propose to its filing in this case?
None. As noted above, the Company believes the ìrgation program is treated
correctly in this rate case. The Company proposes that the paries bring this issue
8 Yanel dirct testimony, page 31, line 12.
McDougal, Di-Reb '" 54
Rocky Mountaìn Power
.1
2
before the MSP Standing Commttee to make a recommendation on how tp treat
all Class 1 DSM programs.
3 Other Issues
4 Q.
5
6 A.
7
8
9
10
11.12
13
14 Q.
15
16 A.
17
18
19
20
21
22.
Did any party file testimony in opposition to the Company's proposed
treatment of revenue from the sale of renewable energy credits ("RECs")?
No. The Company's original filng proposed that RECs wìl be included as a
revenue credit in the Company's energy cost adjustment mechanism ("ECAM")
fììngs. Accordingly, the Company plans on ìncorporating RECs into the ECAM
mechanism staring Januar 1, 201 1. The base level of REC revenue wìl be
$91,779,696 on a total Company level, and $7,031,166 on an Idaho allocated
basis as shown on pages 3.6.1 though 3.6.3 of my Exhibit No.2, with varations
deferred and recovered or refunded on a dollar for dollar basis ìn subsequent
ECAM proceedings.
Did any party fie testimony regarding the Load Growth Adjustment Rate
("LGAR")?
Yes. Mr. Yanel addressed the LGAR in his fied testimony. He presents
arguments related. to the application of the LGAR in the Company's ECAM
filngs, specifically arguìng that the LGAR should only be utìlìzed in situations
where load is increasing and not when load decreases. Mr. Yanel states that he
is not addressing the level or dollar amount of the LGAR, but he recommends that
the LGAR is only to be applied in ECAM cases where there has been growth on
the Company's system.
1223
McDougal, Di-Reb - 55
Rocky Mountain Power
.
1224
McDougal, Di-Reb - 56
Rocky Mountaìn Power
.
.
.
10 A.
1
2
3
4 A.
5
6
7
8
9 Q.
Summary
Q. Please summarize your position on the rebuttal revenue requirement
propos by the Company?
The modified revenue requìrement of $24.9 millon is the appropriate revenue
requìrement based on the test period used in this case. The Company has carefully
reviewed the adjustments proposed by the paries and either made adjustments
that it belìeves are appropriate in this case or defended the proposals put forth by
the Company in its original filìng.
Does this conclude your rebuttal testimony?
Yes.
1225
McDougal, Di-Reb - 57
Rocky Mountaìn Power
.
.
.
20
1 (The following proceedings were had in
2 open hearing.)
3 Q.BY MR. HICKEY: And are you also sponsoring
4 testimony of another witness in this case?
5 A.Yes, I am.
6 Q.And is that the prefiled testimony -- the direct
7 testimony of Ryan Fuller that was filed on the 28th of May,
8 wi th accompanying Exhibits 41 through 46D?
9 A.Correct.
10 Q.And do you accept and adopt that testimony as if
11 it were your own, Mr. McDougal?
12 A.Yes, I do.
13 Q.I would move -- are you aware of any additions or
14 corrections that need to be made to that testimony?
15 A.No, I am not.
16 MR. HICKEY: I would move then, Chairman Smith,
17 that the prefiled direct testimony of Ryan Fuller also be
18 spread upon the record as if read, and that Exhibits 41 through
19 46D be marked for identification, please.
COMMISSIONER SMITH: If there is no objection, it
21 is so ordered.
22 (The following prefiled direct testimony
23 of Mr. Fuller is spread upon the record.)
24
25
1226
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
McDOUGAL ( Di)
RMP
.1 Q.Please state your name, business address and present position with
2 PacifiCorp ("Company").
3 A.My name is Ryan R. Fuller and my business address is 825 NE Multnoma St;,
4 Suite 1900, Portland, OR 97232.My present position is Assistant Tax Dìrector.
5 Qualifications
6 Q.Please describe your educational and professional background.
7 A.I graduated from the University of Idaho in 1997 with a Bachelor of Scìence
8 Degree in Accounting. I am a lìcensed CPA. Before joining the PacìfiCorp tax
9 deparment in 2003, I worked ìn publìc accounting for six years, first with Talbot,
10 Korvolaand Warick LLP and then for PricewaterhouseCoopers LLP.
11 Q.What are your responsibilties as Assistant Tax Director?.12 A.My primar responsibiltìes include income tax accountìng and providing support
13 for the ìncome tax component of the Company's regulatory fììngs.
14 Q.Have you testifed in previous regulatory proceedings?
15 A.Yes. I have previously testifìed on behalf of the Company in the states of Oregon
16 and Utah.
17 Q.What is the purpose of your direct testimony?
18 A.My dìrect testìmony addresses the calculation of the income tax portion of the
19 Idaho-allocated revenue requìrement requested in this case. More specìfically:
20 .I provide background on the "repaìrs deduction," a temporar book-tax
21 difference associated with a recent change in accounting method for income
22 tax puroses.
23 .I explaìn the Company's proposal for fully reflecting the benefìts of the.
1227
Fuller, Di - 1
Rocky Mountain Power
.1
2
3
4
5
6
7
8
9
10
11 Q..12 A.
13
14
15
16
17
18
19
20
21
22.23
repaìrs deductìon in this case, and propose the establishment of a regulatory
asset or liability for interest paìd to or received from the Internal Revenue
Service ("IRS") on adjustments made to the repaìs deductions taken in the
Company's 2008 and 2009 federal income ta retus.
. I sponsor the Company's proposal to fully normlize the repaì deduction and
all other temporar book-tax differences, with the exception of the equìty
allowance for funds used durng construction ("equity AFUDC"), and
. I discuss the revenue requìrement impacts of an accountìng application fied
by the Company with regards to a recent change in tax law that affected the
tax deductibìlty of post-retìrement prescription drg benefits.
Please explain the repairs deduction.
Generally, the repaìrs deduction permts a tapayer to take a tax deduction for
qualìfying expenditues in the taxable year paid or incured even though the same
expenditues are requìred to be capitalized and depreciated for book purposes. An
ìlustrative example of the new method of accounting is provided in confìdentìal
Exhibit No. 41.
For the Company, the repaìs deduction is a change in accountìng method
that requìred approval from the IRS. The change in accountìng method is
applicable for income tax puroses only and does not impactthe methods of
accountìng used for PERC or U.S. GAAP reporting purposes. Prior to the change
in accounting method, the Company was capitazing these costs in accordance
with FERC accountìng classìfcations and U. S. GAAP methods of accountìng.
The costs were then subject to accelerated ta deprecìation.
1228
Fuller, Di - 2
Rocky Mountain Power
.1 On December 30, 2008, the Company fied applìcations wìth the IRS for
2 the change in accounting method (Form 3115). On October 2, 2009, and October
3 7, 2009, the IRS granted the Company permssion to change its method of
4 accountìng beginning with the taxable year beginning Januar' 1,2008.
5 Q.Has the Company reflected the repairs deduction in its 2008 federa income
6 tax return?
7 A.Yes. The Company's 2008 federal income tax retu contains a repairs deduction
8 for the taxable year ended December 31,2008, and a one-time adjustment (tax
9 deduction) known as an Internal Revenue Code (IRC) Sectìon 481(a) adjustment.
10 IRC Section 481(a) adjustments are meant to prevent amounts from being
11 duplìcated or omitted in transìtion from the old method of accounting to the new.12 method of accounting and are generally determned as if the new method of
13 accountìng had always been used. The Company's IRC Sectìon 481(a)
14 adjustment, which was taken as a deductìon in the Company's 2008 federal
15 income tax return, is based on an analysis of the taxable year ended November
16 30, 1999, though December 31,2007. Confidential Exhibìt No. 42 provides a
17 sùmmar of the IRC Section 481(a) adjustment by year and the 2008 repaìs
18 deduction as taken in the 2008 federal income ta return.
19 Q.Does the Company intend to reflect the repairs deduction in its 209 federal
20 income tax return?
21 A.Yes. Beginning with taxable year beginning Januar 1,2008, therepaìs
22 deduction is the Company's ongoing method of accountìng for qualifyìng
23 expenditures. Accordingly, to the extent the Company incurs qualìfyìng.
1229
Fuller, Di - 3
Rocky Mountain Power
.1 expenditues, a repaìs deduction wil be taken in the Company's federal income
2 tax return for the respective tax year. In additìon to the IRC Section 481(a)
3 adjustment and the 2008 repair deduction, Confidentìal Exhibìt No. 42 provides
4 the 2009repaìs deduction estimated to be taen in the Company's 2009 federal
5 income tax return.
6 Q.Can you please ilustrate how an IRe Section 481(a) adjustment operates?
7 A.Yes. As a simple example, assume a company that uses the accrual basis of
8 accountìng for both book and ta puroses accrues a $1,000 liabilty and related
9 expense ìn year 1 and, in year 2, the company makes a cash payment to satisfy the
10 recorded lìabilty. Under the accrual basis of accounting, the company is entitled
11 to a tax deduction in the year the expenditue is accrued. Accordingly, the.12 company would take a $ 1 ,000 tax deduction in year 1. Now, assume that for
13 income tax purposes only, the company changes to the cash basis of accounting in
14 year 2. Under the cash basis of accounting, the company is entitled to a tax
15 deduction in the year the expenditure is paìd. Accordngly, the company would
16 take another $1,000 tax deductìon in year 2 for the same expenditue it deducted
17 in year 1. However, in this example, the company would be requìred to record an
18 IRC Section 481(a) adjustment increasìng taxable income by $1,000 in the year of
19 change, year 2, preventing the duplìcation.This example is ilustrated in Exhibit
20 No. 43.
21 Q.What is the status ofPacifiCorp's repairs deduction with the IRS?
22 A.To date, the IRS has only granted the Company permssion to change its method
.23.of accounting beginning with the taxable year beginning Januar 1,2008. The
1230
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Rocky Mountain Power
.1 amount of the IRC Section 481(a) adjustment and the 2008 repaìrs deductìon
2 taken as a deduction iIi the Company's 2008 federal income tax return are stìll
3 subject to adjustment by the IRS upon examation. The amount that wìl
4 ultìmately be sustained upon examnatìon is stìll uncertin.
5 Q.How has the Company proposed to treat the repairs deduction in this tiling?
6 A.Due to the uncertaìnty of how much of the repaìs deduction wìl ultimately be
7 sustained upon IRS examnatìon, the Company proposes to reflect the repaìs
8 deduction in a manner that also addresses its non-fìnal nature. Firt, as discussed
9 below, the Company has reflected the full value of the repaìs deductions taken or
10 expected to be taken though December 31, 2009, inthis rate case through a
11 reduction in rate base which wìl be adjusted if necessar after the IRS has
.12 completed its examinatìon of these repairs deductìons and the final amount is
13 known. Second, the Company respectfully requests that the Commssion approve
14 the establishment of a regulatory asset or liabilty for the recovery of interest paìd
15 to or received from the IRS, if any, for adjustments made to the repaì deductìons
16 taken ìn the Company's 2008 and 2009 federal income tax retus. This treatment
17 allows the Company to pass though the benefits of repaìs deductìon ìn this case
18 to customers while holding the Company haress pending IRS examinatìon.
19 Q.What is the impact of the repairs deduction on revenue requirement in thi
20 case?
21 A.The Company has reflected the tempora book-tax diference created by the
22 repaìs deduction on a normized basis, meang that customers benefìt from the
.23 accumulated deferred income tax liabilty generated by the repairs deduction by
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.1 way of a rate base reductìon. As enumerated in Exhibit No. 44, the rate base
2 reduction reduces revenue requìrement by $2.8 miion.
3 Q.Please explain how the Company has treated all other temporary book-tax
4 differences in this filing.
5 A.Consistent with the treatment of the repaìr deduction, the Company has reflected
6 all other temporar book-tax differences on a normlized basis, with the single
7 exceptìon of the tempora book-tax difference associated with equity AFUDC.
8 Historically, a lìmited number of property-related temporar book-tax differences
9 have been reported on a flow-through basis in Idao. As enumerated in Exhibit
10 No. 45, reporting these temporar book-tax diferences on a normalized basis
11 increases revenue requìrement by $147,033 compared to continuing to report
.'12 these same book-tax diferences on a flow~through basis.
13 Q.Is the Company proposing to move to full normalization in this rate case? If
14 yes, why?
15 A.Yes. The Company is proposing to move to the fully normized treatment of
16 income taxes. There are polìcy and practìcal reasons underlying this proposal.
17 As a polìcy matter, the Company supports tax normlizatìon based on the
18 matching pricìple and intergeneratìonal equity. Tax normalìzation matches tax
19 benefìts with cost responsibilty and prevents customers who pay for the cost of
20 an asset well past ìts tax lìfe from payìng a disproportonately higher ta rate than
21 customers that pay for the same asset durng its tax lìfe. Because ta
22 normalìzation matches tax benefits with cost responsibìlty, all customers pay the
.23 same effective tax rate over the asset's entie lìfe.
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.1 As a practìcal matter, the Company's income taxes are normalized in
2 Oregon, Utah, and Wyoming, which account for approximately 85 percent of the
3 Company's total regulated operations. The Company is also pursuing this
4 treatment in California and Washington. Idealy, the Company would have a
5 single and consistent policy across all of its regulated operations which would
6 provide benefits by increasing effìcìency in the Company's income tax accounting
7 . and reporting processes and income tax accounting systems.
8 Q.Does the repairs deduction ilustrate the policy reasons supporting the
9 Company's proposal to normaliz all temporary book-tax differences?
10 A.Yes. Under the flow-through treatment of the repaìs deduction, there are
11 signifìcant out-of-period issues with respect to the IRC Section 481(a) adjustment
12 and the 2008 repaìrs deductìon. As enumerated in Exhibit No. 46, under flow-.13 through accounting, 83 percent of the tax benefìts from the repaìrs deductìon
14 ($21.0 millon of the total of $25.4 miion in Idaho-allocated tax benefits
15 generated through the taxable year ended December 31,2009), would be
16 considered out-of-period. In contrast, under the Company's proposal for full
17 normalization, customers receive al of the tax benefìts of the repaìs deduction.
18 This demonstrates how ta normalìzatìon creates a more balanced outcome
19 between the Company and its customers.
20 Q.Why doesn't the Company propose to normalize the repairs deduction only
21 and continue flow-through treatment for all other temporary book-tax
22 differences?
23 A.This approach does not satìsfy the practical and policy considerations discussed.
1233 Fuller, Di - 7
Rocky Mountan Power
.1
2
3
4
5
6
7
8
9
10
11
12.13 Q.
14 A.
15
16
17 Q.
18
19 A.
20
21
22
23.
above. Additionally, it's possible that a polìcy of selective determnation of the
regulatory treatment of individual tempora book-tax differences could create
uncertnty as to the correct accounting treatment of the deferred ìncome taes
generated by the Company's temporar book-tax differences for SEC and FERC
financial reporting puroses.
Accordingly, with the normalizatìon of the repaìs deduction, the
Company has also normlized all other temporar book~tax diferences, with the
single exception of the temporar book-ta difference assocìated with equity
AFUDC. This is consistent with how the Company accounts for temporary book-
tax differences in other states and establìshes an ongoing regulatory polìcy for the
treatment of income taxes for the Company in Idaho that is balanced and
consistent.
. Are you recommending adoption of tax normalization for PacifiCorp?
Yes. The Company respectfully requests that the Commssion authorize the
Company to henceforth account for Idaho-allocated income taxes not currently
normalized on a fully normalized basis beginning Januar 1,2011.
Why is the Company proposing to exempt the temporary book-tax difference
related to equity AFUDC from its proposal for full normaliztion?
The Company has reviewed the income tax normalization polìcy for equity
AFUDC and has determed that, because equity AFUDC more closely resembles
a permanent difference for ratemakng puroses, an income tax flow-through
polìcy is more appropriate than normalization.
Equity AFUDC increases the book basis of assets. It originates as book
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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.
income and reverses as an expense though book depreciatìon. Over the book life
of the related asset, equity APUDC has no net impact on book income. Equìty
APUDC also has no impact on taxable income because the income created by
equity APUDC is never taxable and the book deprecìatìon attrbutable to equìty
AFUDC is never deductìble for income tax puroses. Items of book ìncome or
expense that are never taxable or never deductìble for ìncome tax puroses are
typically considered permnent book-tax differences for income tax accounting
puroses. Permanent book-tax differences do not generate deferrd income tax
expense because there is no correspondìng futue event that wìl generate a ta
receivable or payable on an income tax return.
However, because of the unique "in-and-out" aspect of equìty APUDC for
book puroses, accountìng guidance recommends that equity AFUDC be tracked
as a temporar book-tax difference for income tax accounting puroses. Equìty
AFUDC is a temporar book -tax difference in the sense that it ultimately has the
same impact on book income and taable income - zero. For income tax
accounting puroses, the temporar book-tax difference for equity AFUDC
generates deferred income tax liability upon origination, with a corresponding
debìt to deferred income tax expense. As the temporar book-tax difference
reverses over the book lìfe of the related asset, the income tax accounting entr is
to debit the deferred income tax lìabìlty and credt deferred income tax expense
until the deferred income ta lìabìlty is brought down to zero.
Accordingly, because deferred income taxes are included in revenue
requìrement under a polìcy of income tax normlization, normalization of ths
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.1
2
3
4
5
6
7
8
9
10
11 Q..12
13 A.
14
15
16
17
18
19
20
21
22.
item in rates effectively results in a loan to the Company from customers that is
returned to them over time with interest at the Company's rate of return with no
tax impacts or payments to the IRS. Under flow-though accountìg, the deferred
income taxes generated by equity APUDC never impact revenue requìrement,
which is appropriate since there is no corresponding income tax payable or
receivable between the Company and the IRS.
Curently, the Company uses flow-though accountìng for the deferred
income taxes generated by equity APUDC in all of its regulatory jursdictions,
including those regulatory jurisdictions that have adopted a polìcy of income tax
normalization.
Did the Company recently file an accounting application regarding income
taxes?
Yes. On March 23, 2010, the Patient Protection and Affordable Care Act ("the
Act"), was signed ìnto law.! The Act changes the deductibilty of certin costs
incurred for post-retìrement prescription drg coverage. On April 2,2010, the
Company fied an accountìng applìcatìon (Case No. PAC-E-1O-04) to request
authorization for the recordig of a regulatory asset for tax benefits previously
reflected ìn rates that wil no longer be realized as the result of the Act. Inthe
applìcation, the Company proposes to amortize the regulatory asset over a period
of four years beginning Januar 1, 2011, and to reflect the amortizatìon expense
in the Company's next general rate case. Subject to the Commssion's approval
of the Company's applìcatìon, the Company has ìncluded $209,996 for the firt
1 Certai provisions of the Act were subsequently modifed by the Health Care and Education
Reconciliation Act, which was signed into law on March 30, 2010.
1236
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.
.
.
1
2
3
4 Q.
5 A.
year of amortization in computing revenue requìrement in this case. Additìonally,
the Company has made an adjustment to the base period to properly reflect the
Company's ongoing. level of income tax expense as a result of the Act?
Does this conclude your direct testimony?
Yes.
2 See adjustment 7.9.
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.
.
.
20
21
22
1 (The following proceedings were had in
2 open hearing.)
3 Q.Mr. McDougal, you were mentioned a couple of
4 times over the first two days of this hearing. Were there any
5 questions that you understand are outstanding that were
6 deferred for you or to you?
7 A.There were several items which were mentioned to
8 other Counsel that they could address when I came on the stand.
9 I did not keep track of each, so I would be more than willing
10 to address them as they come up.
11 Q.Okay, we ill give everyone the opportunity to
12 cross-examine you.
13 A.Thank you.
14 MR. HICKEY: Mr. McDougal is available for
15 questions, Chairman Smith.
16 COMMISSIONER SMITH: Thank you.
17 Mr. Otto.
18 MR. OTTO: Yes, Madam, I do have a few questions
19 for Mr. McDougal.
CROSS-EXAMINATION
23 BY MR. OTTO:
24
25
Q.And I'm going to refer to page 55 of your
rebuttal testimony under Other Issues, beginning with basically
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1 the question and answer on lines 4 through 13, and that deals
2 wi th renewable energy credits.
3 A.Yes.
4 Q.What is the source of those renewable energy
5 credi ts to Rocky Mountain Power?
6 A.Renewable energy credits are generated generally
7 as part of the wind facilities of the Company, although there
8 are some minimal amounts associated with hydro. So as we have
9 generation from the wind and the hydro facilities, we are able
10 to sell the renewable energy credits from those resources into
11 the open market.
12 Q.Thank you. Were you here for Mr. Tallman IS
13 testimony?
14 A.Yes, I was.
15 Q.And I believe that he referred to RECs as a
16 pleasant surprise. Do you recall that, or something along
17 those lines?
18 A.Yes, I do.
19 Q.Would you agree with that?
A.I would agree with that to the extent that if I
21 look back historically, RECs were seven or eight million
22 dollars until this year, and all of a sudden they have started
23 to grow; where in this case, weI re putting a base of $91
24 million. So to the extent that we have seen a growth, I would
25 consider that a pleasant surprise.
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1 Q.And the $91 million you refer to, is that a
2 benefit to ratepayers or cost?
3 A.A benefit.
4 Q.Great. Thank you very much. That i s all I have.
5 COMMISSIONER SMITH: Mr. Olsen.
6 MR. OLSEN: Thank you, Madam Chair.
7
8 CROSS-EXAMINATION
9
10 BY MR. OLSEN:
11 Q.Mr. McDougal, if I can have you turn to page 40
12 of your rebuttal testimony
13 COMMISSIONER SMITH: Is that four or 40?
14 MR. OLSEN: Forty.
15 COMMISSIONER SMITH: Four zero?
16 MR. OLSEN: Four zero, yes. Thank you.
17 Q.BY MR. OLSEN: Beginning on line 12, you talk
18 about the jurisdictional load allocation, and you callout some
19 issues you have with Mr. Yankel' s adj ustment with the
20 jurisdictional load allocation there.
21 Now, beginning on line 15 there, you make a point
22 that Mr. Yankel' s analysis is inconsistent with the Company's
23 prior filings. Is that correct?
24 A. That i s one of the inconsistencies, yes.
25 Q.Okay. Well, let's assume for argument sake that
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1 your methodology overestimates the line losses that are
2 assigned to the Idaho jurisdiction. You know, if we assume
3 that is the case, then would it matter if Mr. Yankel' s method
4 is inconsistent with the Company's prior filings in this
5 case?
6 A.Yes, it would.
7 Q.Why would it?
8 A.It i S not only inconsistent with prior filings but
9 it's inconsistent among states, so if you are going to look at
10 one state and say, Let i s remove some of these line losses from
11 Idaho; Mr. Yankel should have attempted to remove the line
12 losses from other states also so he had every state on a
13 comparable basis. Mr. Yankel never attempted to do that.
14 Q.But aren't we just dealing with Idaho in this
15 case? I mean, we i re looking at the allocation to Idaho, and if
16 I understand the JAM model, we change that allocation, it all
17 works out to where 100 percent of your expenses get allocated
18 to the various jurisdictions, don i t they?
19 A.A hundred percent gets allocated, but if you
20 change Idaho without changing other states, it reduces Idahols
21 allocation while leaving other states allocated at a higher
22 amount. So if you adj ust every state equally, then you i re
23 going to have a completely different result, so you have to
24 look at it and say, Can we leave one at a larger amount and
25 then compare it to others that are calculated in a different
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1 manner? And the answer is "no."
2 Q. Going down further there, let i s move over to
3 page 41 here. Now, beginning on line 14 through 23, you
4 discuss the fact that there are other losses contained in your
5 jurisdictional loss study. Is that correct?
6 A.Yes.
7 Q.So, you callout wholesale sales, and then you
8 also talk about this Bridger generation that is not included
9 over to Goshen and Kinport and Borah.
10 What are Goshen and Kinport and Borah?
11 A.Goshen, Kinport, and Borah are three substations
12 or switching stations on the Company iS circuits.
13 Q.And is that just transferring power over there to
14 a nonresidential customer? Is that what you i re
15 A.It's, as I understand it -- and I am not an
16 expert in the transmission area -- that is where the power from
17 Bridger first comes into the state of Idaho.
18 Q.But irregardless of these other potential sources
19 of losses that you callout, you said beginning on -- or, on
20 line 19, you say there are some losses that occur as a result
21 of power moving through Idaho, don i t you?
22 A.Yes, and there are some power that is included in
23 our allocation factors from moving power through Utah, through
24 Oregon, through Wyoming; and that's how come if you go earlier
25 on that same page in lines 6 through 11, it states how we
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1 calculate loads for allocation purposes, giving a quote from
2 the MSP Docket in the state of Idaho.
3 Q.Well, you i re familiar with Mr. Yankel' s testimony
4 that was filed in this case, aren i t you?
5 A.Yes, I am.
6 Q.And do you recall on page 18, lines 8 through 10,
7 he talks about the fact that his observation shows that there IS
8 2.66 percent more energy used under the JAM model that is
9 attributed to Idaho for calculation of expenses as opposed to
10 revenue? And these, I guess, flaws that you're trying to point
11 out in his analysis, you haven't calculated the effect either
12 in this case, have you?
13 A.No, I haven't, but just like he was claiming that
14 Idaho is overstated by 2.66 percent, he never looked and said
15 Wyoming is overstated by it could be five percent, it could be
16 one percent. I have not done the calculation.
17 But if he is trying to make a change to the way
18 we i re calculating factors and the way we're measuring loads,
19 you need to be consistent in all six states if you're really
20 going to calculate what is Idaho i s percent, which is the whole
21 goal of the allocation factor.
22 Q.But, again, we're just dealing with Idaho here
23 and the model will adjust itself. If Idaho is lower, someone
24 else has to be higher. Isn i t that the net effect?
25 A.No, it is not, because if you take Idaho lower
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1 wi thout taking other states lower for the same reason, yes, it
2 is going to make Idaho lower but it i S lower than what it should
3 be.
4 What you have to look at is you i re tying to
5 calculate a percent or a ratio, and you have to have all states
6 calculated in a similar manner.
7 Q.Well, I guess I respectfully disagree, but I i II
8 move on.
9 Go forward to page 42 of your testimony,
10 beginning on line 7 -- line 7 through 12. You also take issue
11 that Mr. Yankel talks about as far as transmission losses
12 through the system in general that all jurisdictions should be
13 treated equally, and you take issue with that. Is that
14 correct?
15 A.Okay, exactly where are you looking?
16 Q.Page 42, lines 7 through 12.
17 Oh, I apologize.
18 A.I believe that i s still talking about the same
19 issue.
20 Q.I apologize. That's not the spot that I wanted
21 to go to.
22 lIm sorry, just up above that, page 42, lines 1
23 through 6, talking about there and that's what I would like
24 folks on here, that you take issue with -- you say that not all
25 states use the transmission system equally. Is that a fair
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1 statement of your testimony there?
2 A.Yes, it is.
3 Q.Okay. Can I direct you -- do you have
4 Mr. Yankel i $ testimony up there?
5 A.I do not have it in front of me.
6 Q.You do not? Well, what I represent to you,
7 subj ect to check, and page 20 of Mr. Yankel' s testimony, Table
8 4, that
9 Specifically, your own loss study shows that the
10 transmission line loss allocator is the same for all
11 jurisdictions?
12 A.That is correct.
13 Q.Okay. And that the Company treats it all
14 equally. Isn't that correct?
15 A. That is correct.
16 Q. SO why are you taking issue with Mr. Yankel i s
17 testimony?
18 A.I'm just stating that he is trying to treat Idaho
19 differently than all other states when he is calculating
20 losses. He is using a different methodology.
21 Q. But if the methodology is wrong to begin with,
22 why is that a bad thing, if you assume that?
23 A.If you assume that, one, you need to get the
24 methodology changed, but just as mentioned earlier, you should
25 change the methodology for all states.
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1 MR. OLSEN: I have no further questions, Madam
2 Chair.
3 COMMISSIONER SMITH: Thank you, Mr. Olsen.
4 Ms. Davison.
5 MS. DAVISON: Thank you, Madam Chair.
6
7 CROSS-EXAMINATION
8
9 BY MS. DAVISON:
10 Q.Good afternoon, Mr. McDougal.
11 A.Good afternoon.
12 Q.What is the test period that Rocky Mountain Power
13 is using in this proceeding?
14 A.We use calendar year 2009, adjusted for known and
15 measurable changes through calendar year 2010.
16 Q.Thank you. Are there a number of capital
17 proj ects that Rocky Mountain Power originally proj ected to be
18 in service by December 31, 2010, but now have later in-service
19 dates?
20
21
A.There are a few that have been adjusted, yes.
Q.I would like to hand you an exhibit that I have
22 premarked as Exhibit 622, and this is a Response to a Data
23 Request.
24 (PIIC Exhibit No. 622 was marked for
25 identification. )
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1 Q.BY MS. DAVISON: Do you recognize this
2 attachment?
3 A.Yes, I do.
4 Q.And if you look at this --
5 Well, perhaps just for the record, could you
6 state what this document is that i s Attachment that i s labeled as
7 PICC (sic) 186?
8 A.Yes. It is a listing of all of the proj ects
9 wi thin the rate case with the original in-service date and then
10 the current in-service date.
11 Q.Thank you. And if you look at this chart, do you
12 see that there are three proj ects that were proj ected to be
13 done in -- by the end of 2010 that are now projected to be
14 completed in 2011, and that would be Ul Huntington Clean
15 Air-S02; Chappel Creek 230 kV Cimarex Energy 20 megawatt phase
16 two; and Community Park convert to 115 from 12.5 kV,
17 transmission parts? Is that correct?
18 A.That is correct.
19 Q.Did you update the costs in this rate case to
20 remove those items from your revenue requirement Request?
21 A.There were -- several updates were made that were
22 gi ven to Mr. Joe Leckie of Staff that were made. Subsequent to
23 his Requests, there were a couple of changes, some projects
24 that have slipped further, we have others that have came
25 forward into the test year and those have not been updated.
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1 Q.So the three proj ects that I have identified from
2 our Exhibit 622, have you kept those costs in your revenue
3 requirement Request?
4 A.They are in the revenue requirement Request as
5 filed.
6 Q.And they go beyond your test period?
7 A.They -- like I said, there have been a lot of
8 movements, miscellaneous movements. If you look at those
9 projects, they are, you know, not any of the bigger projects,
10 and there have been other proj ects which have came forward into
11 the test year we have not updated that where -- and Staff --
12 Q.I'm sorry, I just want "yes" or "no."
13 A.Yes.
14 Q.Do these three proj ects go beyond your test
15 period?
16 A.Those three proj ects are later, yes.
17 Q.Thank you. And are there other capital proj ects
18 that have completion dates that have been delayed, as indicated
19 on Exhibit 622?
A.There are a couple which have been delayed, yes,
21 and some that have been moved earlier.
22 Q.And my check of your chart is I identify three
23 proj ects that you are now proj ecting to be completed by
24 December 2010, and that would be the Huntington Water
25 Efficiency Management Proj ect you i re going to have to help
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1 me with the name of this: Oquer (phonetic)?
2 A.Oaker (phonetic).
3 Q.-- Oquirrh and Camp Williams transmission; and I
4 don i t see it on the list, but for some reason I have Upper
5 Green River transmission listed.
6 Are those proj ects that are proj ected to be
7 completed by the end of December 2010?
8 A.They are, and if you look at some of them, the
9 largest dollar amount is the Camp Williams.
10 Q.lIm just asking simply whether theyl re projected
11 to be completed by
12 A.Well, and I'm trying to answer that, because
13 MR. HICKEY: Madam Chair, he's really trying to
14 answer. I didn i t jump into the middle of the first one but it
15 now seems to be pattern here, and I i d hope that the witness
16 could answer his -- her questions posed to him.
17 COMMISSIONER SMITH: Okay, Mr. Hickey.
18 Ms. Davison, let i s let the witness answer the
19 questions.
MS. DAVISON: Thank you, Madam Chair. What I 1m
21 trying to get for a clear record is if he could actually answer
22 my question, and then go off on his explanation. I think that
23 would give you a much better record.
24
25
COMMISSIONER SMITH: Good point, so try and do
that.
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1 THE WITNESS: Yeah, like I said, yes, they are,
2 but if you look at them, the largest one is the Camp
3 Williams-90th South that you were pointing out was supposed to
4 be done by the end of the year. It is already in service and
5 it actually came in service a couple of weeks ago.
6 Q.BY MS. DAVISON: And how about the other three?
7 A.I do not know specifically.
8 Q.So you don't know if they will be completed by
9 the end of December 2010 or not?
10 A.I was told they will be.
11 Q.But do you have personal knowledge?
12 A.No, I do not.
13 Q.Is it possible that there are additional capital
14 projects that could have delayed in-service dates in this rate
15 case?
16 A.In looking through the list, I think you have
17 already highlighted all of them that are not already in
18 service, and, therefore, the ones that are already in service
19 are definitely not going to get delayed beyond the test period.
20 So I am not aware of any that are not yet completed other than
21 those ones that you have highlighted.
22 Q.Right. But my question is is it possible that
23 there are additional projects that will not be completed by the
24 end of December 2010?
25 A.Could you clarify what you mean by "additional"?
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1 In addition to the ones we i ve talked about or
2 Q.The three that we i ve identified that have the
3 December 2010 proj ect completion date.
4 A.Those three could possibly. But like I say,
5 there i s also others that are coming forth, so --
6 Q.Thank you.
7 A.-- it's occurring in both directions.
8 Q.And can you explain why it's proper to include
9 costs in this rate case that go beyond the test period?
10 A.If you look at these costs, these were all
11 projected plants, and like I said, what we i re trying to do is
12 set an appropriate level of rate base, an appropriate level of
13 cost going forward. If we look at the rate base included in
14 this case compared to what we actually have in service today,
15 we look at proj ects going forward and some being delayed, I
16 believe the level in the case actually understates the rate
17 base we will have on December 31st, so I believe it i S a
18 reasonable level.
19 Q.So you think it's kind of an averaging out kind
20 of thing?
21
22
A.No, I think it's an accurate kind of thing.
Q.Well, how can it be accurate if you've got,
23 admittedly, at least three projects that youlve included in the
24 revenue requirement that go beyond your test period? How is
25 that accurate?
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1 MR. HICKEY: Excuse me. Asked and answered, and
2 argumentati ve.
3 COMMISSIONER SMITH: Oh, I'm going to overrule
4 that objection. She gets to do it one more time, that's it.
5 THE WITNESS: We are trying to proj ect maj or
6 plant additions. Forgetting the fact that we aren i t trying to
7 forecast all plant additions, we are trying to set a level and
8 there are a couple which have been delayed, there are a few
9 that have came forward. That was not included in her response.
10 This level is a reasonable level of cost and it,
11 in my opinion, correctly reflects the amount of revenue
12 requirement we are going to need in the test period.
13 Q.BY MS. DAVISON: So if I understand this schedule
14 in this case correctly, there will -- there is anticipated to
15 be a Commission Decision by the end of 2010. Is that
16 correct?
17 A.That is correct.
18 Q.And for the three proj ects that you have included
19 in your revenue requirement increase that we have identified
20 that won i t be in service until 2011, can you explain why that
21 does not violate the used and useful concept?
22 A.These rates are actually going to be set for all
23 of calendar year 2011, and these will be in even if theyl re
24 delayed for most of it. There are others that have came in if
25 you look at this list, there are a lot of plant that came in in
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1 May that are not included yet in rates. And so I think you
2 have to look and say we i re trying to project on December 31st
3 there will be some going both directions, and I believe this
4 level is reasonable.
5 Q. Mr. McDougal, I truly am not trying to be
6 argumentati ve. My question was narrowly focused toward those
7 three proj ects that you i ve identified that won i t be in service
8 until 2011, and my question is how did including those costs in
9 this case not violate the used and useful concept?
10 MR. HICKEY: Madam Chairman, I think he answered
11 it. If you want him to answer it again, lIm sure Mr. McDougal
12 would be glad to.
13 COMMISSIONER SMITH: I think, Ms. Davison, you
14 got the best answer you are going to get out of him to that
15 question.
16 MS. DAVISON: Okay. I apologize, Madam Chair. I
17 actually didn't hear him answer why it didn I t violate used and
18 useful, but
19 COMMISSIONER SMITH: I think you got the only
20 answer you I re going to get.
21 MS. DAVISON: Okay. Thank you. I will move on.
22 Q.BY MS. DAVISON: Your testimony response to
23 Mr. Meyer's adjustments related to post-test period
24 adj ustments. I refer you to pages 17 through 19 and generation
25 overhaul expenses pages 9 through 11. Is that generally
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1 correct that you respond to those issues?
2 A.Yes.
3 Q.And is it your position that only limited
4 adjustments should be made to the historic test period, and
5 that you go on to say that the test period is, quote: Not
6 intended to be a full scale rolling forward into 2011?
7 I refer you to your rebuttal testimony, page 18.
8 Is that correct?
9 A.I actually say it i S not intended to be a
10 full-scale roll forward into 2010, not 2011.
11 Q.Okay, I i m sorry. My mistake.
12 And at page 10, does your rebuttal testimony
13 oppose Mr. Meyer i s proposal to use a four-year average from
14 2007 to 2010 for generation overhaul expenses?
15 A.For new generation facilities, it does. The only
16 way we can get full recovery of overhaul expenses using a
17 four-year average for a new generation is if you include a
18 four-year average for each year of its life.
19 What Mr. Meyer is proposing is to use a four-year
20 average that includes years before the plant was built. I do
21 not consider that to be an appropriate adjustment.
22 Q.So in developing the Company's proposed
23 generation overhaul expenses for Lake Side and Chehalis, did
24 PacifiCorp rely upon budgeted expense levels out to 2012?
25 A.Yes, for all plants what we did is we looked at a
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1 four-year average and we looked at the four years from 27
2 through -- 2007 through 2010, except for new facilities. And
3 for new facilities, we looked at their first four years of
4 operations. So if those plants had been operational for two
5 years, we used two years i actuals and two years of budget. If
6 they are just coming into service, it would go out further than
7 that.
8 Q.And would you agree that using these budgeted
9 levels through 2012 goes beyond the test period in this case?
10 It does, but what we are trying to do is set aA.
11 four-year average.
12 Have you performed any analysis which reviews allQ.
13 of the relevant factors related to increasing and decreasing
14 costs for the post-test period expense in this proceeding?
15 A. I don i t think I completely understand the
16 question. Could you rephrase it?
17 Sure. I'm sorry. Have you performed anyQ.
18 analysis where you looked at all of the relevant factors of
19 what costs are increasing, what costs are decreasing for the
20 post-test period expenses in this case?
21 A.No, I have not.
22 In your rebuttal testimony at pages 15 throughQ.
23 17, you oppose Mr. Meyerls cash working capital adjustment. Is
24 that correct?
25 A.That is correct.
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1 Q.And is it correct that Rocky Mountain Power is
2 seeking a cash working capital allowance for its asset
3 retirement obligation regulatory liabilities?
4 A.Could you refer me to a specific spot? I am not
5 completely aware of that and I do not remember that in any of
6 the testimony as being an issue.
7 Q. I don i t have a -- I don i t have a testimony page
8 and cite. I was just asking the question generally.
9 A.I would have to look. I do not know the exact
10 answer to that.
11 Q.Okay.
12 MS. DAVISON: Thank you very much. I have no
13 further questions.
14 COMMISSIONER SMITH: Mr. Purdy.
15 MR. PURDY: No questions.
16 COMMISSIONER SMITH: Mr. Price.
17 MR. PRICE: Thank you, Madam Chair.
18
19 CROSS-EXAMINATION
21 BY MR. PRICE:
22 Q.Mr. McDougal, you made reference to the JAM model
23 in your testimony, so you i re familiar with how the Company
24 allocates its system and production costs to the different
25 jurisdictions. Correct?
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1 A.Yes, I am.
2 Q.Okay. And you i re familiar that the Company
3 allocates those costs based on a given state's energy and
4 demand. Correct?
5 A.Those are some of the allocations.There IS
several others,yes.
Q.Those are two of the factors?
A.Those are two of the factors.
Q.Okay.So if disproportionate growth occurs in
6
7
8
9
10 one jurisdiction but it doesn't occur in another, then that
11 jurisdiction where the disproportionate growth occurred would
12 be allocated a higher proportion of the system-wide costs.
13 Correct?
14 A.I don i t like the word "disproportionate." I
15 think it i S a fair proportion, yes, but it would be adj usted on
16 an annual basis.
17 Q.Okay. If more growth occurs in one jurisdiction
18 versus another, then that --
19 A.It would get a higher percentage of the cost.
Q.Okay. That i s what I was asking. It was probably
21 a poor question.
22
23
A.Okay.
Q.So if PacifiCorp -- if Rocky Mountain Power is
24 planning to put the costs associated with transmission in the
25 rates today for recovery today in order to serve future growth
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1 as has been the testimony throughout this proceeding, won i tall
2 the other state jurisdictions be allocated a portion of those
3 costs based on energy and demand relationships that are in
4 effect today, rather than the future relationships that cause
5 those costs in the future?
6 A.They will all be allocated according to their
7 allocation factors and the test period used in their cases
8 today, yes.
9 Q.I i m going to point you to a couple of the
10 accounting adj ustments that were made by the Company. One in
11 particular is the avian Settlement.
12 A.Yes.
13 Q.Why was the 2008 $500,000 charge to injuries and
14 damages reversed in April of 2009?
15 A.There was an original accrual made in 2008
16 related to the avian Settlement, and that accrual was reversed
17 in 2009.
18 Q.And in what account did that go into, was it
19 booked into?
20 A.Let me find the adjustment in the testimony.
Q.I had that page cite and I lost it when I retyped
22 this, I'm sorry about that. I think it was -- I have my
23 colleague i s testimony here so I don i t have mine.
24 The page cite, hels looking for it.
25 A.Okay, it looks like it was Account 925.
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1 Q.Okay. And an expense like this is not typically
2 viewed as a recurring expense. Correct?
3 A.No, it is not.
4 Q.Okay. And as a general principle, restitution
5 expenses like this don't offer a direct benefit to customers.
6 Correct?
7 A.There's a lot of variety of expenses like this
8 and a lot of the expenses can benefit future periods.
9 Like I said, right here what we're doing in the
10 adjustment referred to is we're actually just reversing the
11 accrual reversal to zero out the 500,000, but if you look at
12 the avian Settlement itself, a lot of the money was spent to
13 look at new ways of changing power lines and changing
14 configurations to help improve operations, and we i re
15 continually studying new ways to improve operations. So
16 hopefully it will benefit the future, and I think we're always
17 going to be trying to find new ways to improve our operations.
18 Q.Okay. lIm going to switch focus a little bit and
19 reference the Case No. PAC-E-09-08 that involved the Bridger
20 coal mine that -- the Company I s attempt to defer the costs for
21 removal of the overburden and waste material.
22 A.Correct.
Q.Okay. And in that case, the Company sought to
24 defer those costs and categorize it as a regulatory asset, and
25 they weren't seeking recovery in that case?
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i A.That is correct.
2 Q.And you're seeking recovery now for the costs of
3 that overburden and waste removal?
4 A.That is correct.
5 MR. PRICE: That i s all I have.
6 COMMISSIONER SMITH: Mr. Budge.
7 MR. BUDGE: Thank you.
8
9 CROSS-EXAMINATION
10
11 BY MR. BUDGE:
12 Q.Mr. McDougal, if you would, please, turn to your
13 direct testimony, page 14, line 8 through 10.
14 A.Okay.
15 Q.You make the statement there that the net power
16 cost study sponsored by Company witness Dr. Hui Shu includes
17 the payment to Monsanto based on the terms of the special
18 contract for 2010.
19 When you use the word "payment to Monsanto," are
20 you referring to the curtailment credit?
21 A.Correct. I believe that i s another term for the
22 same payment.
23 And when you say that that curtailment creditQ.
24 then was based on the terms of the special contract for 2010,
25 would it be correct for me to understand then that you were
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1 using the existing curtailment credit that Monsanto has in its
2 existing contract for purposes of the net power cost study that
3 was sponsored by Dr. Shu?
4 A.That is correct. Where there wasn't a new
5 contract in place, we i re using the existing one.
6 Q.And that testimony was filed in May of 2010 as a
7 part of the original filing?
8 A.That is correct.
9 Q.So would you expect that testimony would lead
10 Monsanto to believe that there was not a change proposed in the
11 interruptible credit at least at the time of the filing?
12 A.I wouldn i t think it would lead to that because
13 everything else was based upon a 2010 test period and this is
14 what i s going to be in place in 2010. As far as what's going to
15 happen after 2010, that is yet to be decided, as I understand,
16 as part of that separate document.
17 Q. Except Mr. Clements isn i t a witness in this
18 proceeding. You would be aware that his subsequent testimony
19 that was late filed in the fall would be the first indication,
20 would it not, that that curtailment credit was being reduced
21 from the existing number to a lower number?
22 MR. HICKEY: I obj ect to the form of the
23 question: It assumes facts not in evidence. And I think we Ire
24 at least on the border of the second phase of this case, and if
25 we're not on the border, I think I can see it from here.
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1 COMMISSIONER SMITH: I think I i II overrule your
2 obj ection, Mr. Hickey. I don't think this goes to the value of
3 the curtailment, which is the second phase. But I think
4 Mr. Budge is probably trying to get at a different issue,
5 although I think he needs to think about how he asked his
6 question.
7 So, if you could rephrase your question,
8 Mr. Budge.
9 MR. BUDGE: Yes.
10 Q.BY MR. BUDGE: Were you aware that Mr. Clements
11 sometime, many months later and after the original filing,
12 filed testimony utilizing a different interruptible credit
13 number than was contained in the contract that you refer to on
14 page 14 of your testimony?
15 A.I was aware that he had filed new testimony, yes.
16 Q.If you could turn, please, to your rebuttal
17 testimony, I have just a few questions there. The first would
18 be on page 44, line 16. And I just wanted to -- I had a
19 question concerning the statements you make there where you
20 say: Pursuant to contract, the Company can never actually
21 curtail all 170.1 megawatts at one time.
22 Are you simply referring to the fact that under
23 the contract, the Company can only curtail a lesser number of
24 megawatts for economic purposes or for operating reserves?
25 A.That is correct. I think I go into a little more
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1 detail. I get the -- you know, in preparing this and doing the
2 rate case, I talked to Mr. Clements, trying to find out about
3 the contract.
4 What I know is that there is really two
5 components. There is the operating reserves and then there's
6 the economic curtailment, and there are limitations.
7 Q.So you would agree then for system integrity
8 purposes, the Company could actually curtail the full 170
9 megawatts under the terms of the contract?
10 A.I cannot speak to the terms of the contract. I
11 have not seen it, nor have I read it.
12 Q.Well, what did you base your statement on then
13 when you say the Company can never actually curtail 170
14 megawatts if you didn't look at the contract?
15 A.Based upon discussions with our folks in C and T
16 like Mr. Clements and others, there are two things that we
17 consider excuse me consistent with other contracts:
18 One, there are 67 megawatts of economic
19 curtailment. And my understanding is if we take that 67
20 megawatts of economic curtailment, we can i t take the full 95
21 megawatts of operating reserves and there are some limitations.
22 I do not know all of the specifics in the contract, but I know
23 there are those two components.
24 Q.Wi thout belaboring the point or looking at the
contract, would you accept, subj ect to check, that the electric
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1 service Agreement currently in effect known as the 2008
2 Agreement states on the attached Exhibit 8, page 2,
3 Paragraph 3, quote: PacifiCorp may request system integrity
4 interruptions of up to 162 megawatts?
5 MR. HICKEY: I object to the question: The
6 document contract speaks for itself. This witness is not
7 sponsoring the contract as part of his testimony, and for all
8 the reasons that I believe the Commission is fully aware of,
9 this issue is at least set for another day.
10 COMMISSIONER SMITH: I i m going to overrule your
11 obj ection, Mr. Hickey. I think that Counsel is free to explore
12 the extent of this witness i s knowledge of the contract since he
13 has referred to it in his testimony.
14 THE WITNESS: Subj ect to check, I could get ahold
15 of the contract and find out, yes.
16 Q.BY MR. BUDGE: So l'm just assuming your answer
17 was given without knowledge of the fact that under the
18 contract, it was also a system integrity interruption right
19 that the Company has that does go up to the full 162
20 megawatts?
21 A.Subj ect to check, yes.
22 Q.Okay. You also made a statement that maybe --
23 maybe the answer is the same, but later down on the same page,
24 on page 44, line 19 through 22, you basically state there,
25 quote: If one of the furnaces is already not operating, the
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1 Company can curtail both the remaining for purpose -- excuse
2 me -- the Company can curtail both of the remaining furnaces,
3 but not -- total curtailment would be less than 170 megawatts.
4 So I guess wouldn't it be correct that if a
5 furnace were down for some reason and the other two were
6 curtailed for a system emergency, then you would, in fact, have
7 the full 170.1-megawatt load reduction? Correct?
8 A.I would think that, yes, if all three are down.
9 Q.Turn if you would, please, Mr. McDougal, to
10 page 45, and on pages -- excuse me, on lines 6 through 9, you
11 make a statement there that on eight of the 12 months during
12 the past test period, Monsanto load at the coincident peak is
13 less than 170 megawatts. Do you see that statement?
14 A.Yes, I do.
15 Q.And I think you prepared the chart on the
16 following page 46 that purported, if I understand it correctly,
17 to indicate when Monsanto was curtailed at the system peak?
18 A.Right, those are two separate issues, but both
19 were prepared by me.
20 Q.I'd like to hand you what we i II identify as
21 Monsanto Exhibit 249, and that i s the Company i s Response to
22 Monsanto Data Request 10.1, a Response being provided under
23 date of August 27, 2010, sometime prior to your rebuttal
24 testimony.
25 (Monsanto Exhibit No. 249 was marked for
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1 identification. )
2 Q.BY MR. BUDGE: Do you have that available, sir?
3 A.I am looking at it.
4 Q.The question there was asked to identify how much
5 of the Idaho monthly metered load is for Monsanto, and the
6 Company i s Response -- or, the question was directed to you. It
7 shows that Mr. Eelkema was the sponsor, so I i m not sure if that
8 was an error or not.
9 A.It was actually responded to by Mr. Eelkema.
10 Q.But the Response there, you can see, is:
11 Monsanto i s contribution to coincident peak is not identifiable.
12 So I guess my question is if Monsanto's
13 contribution to coincident peak is not identifiable for
14 purposes of the Company's Response to Data Request 10.1, how is
15 it identifiable for purposes of your testimony on page 45 and
16 for purposes of the preparation of your chart at the top of
17 page 46?
18 A.What we were looking at there is there is
19 actually two different sources of data. There's the Pete
20 Eelkema, which does the data for our load forecasts, and Pete
21 could not and does not have that broken out.
22 So, since he doesn't, I went to a second source,
23 which is labeled here. It's actually page 6 of Exhibit 49 in
24 this case, which is a cost of service study. In that cost of
25 service study, there is an amount. It is not prepared as part
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1 of our forecasting group, but it is prepared separately.
2 Q.Where is -- how do you derive that amount if
3 Monsanto's loads are not metered at peak?
4 A.You would need to talk to Company witness
5 Craig Paice, who actually sponsors that page.
6 Q.We have him yet to testify?
7 A.Yes.
8 Q.But were you aware of the Response to this Data
9 Request when you prepared your testimony?
10 A.No, I was not.
11 MR. BUDGE: No further questions.
12 COMMISSIONER SMITH: Thank you, Mr. Budge.
13 Do we have questions from the Commission?
14 COMMISSIONER REDFORD: No.
15 COMMISSIONER KEMPTON: No.
16 COMMISSIONER SMITH: I just have one question.
17
18 EXAMINATION
19
20 BY COMMISSIONER SMITH:
21 Q.In response to Ms. Davison's cross-examination,
22 you said you didn't have information available but you could
23 provide it. Do you recall what the information was, because I
24 didn't write it down? My question is, when will you provide
25 it?
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21
22
23
24
25
1 A.I do not remember what information that was
2 ei ther , I i m sorry.
3 COMMISSIONER SMITH: Ms. Davison, do you want to
4 help us with that? Did you ask for something he was going to
5 provide later, and if so, what is it and why donlt you --
6 MS. DAVISON: Madam Chair, I guess I didn i t get
7 the impression that he was actually going to physically provide
8 it, but he was just indicating that he would have additional
9 information about when these proj ects were completed. But I
10 guess I didn i t interpret that as he was going to provide an
11 update.
12 COMMISSIONER SMITH: All right. So she i s happy
13 without it.
14 Mr. Hickey.
15 MR. HICKEY: I would just concur with
16 Ms. Davisonls recollection.
17 COMMISSIONER SMITH: All right. I think we i re
18 done with Mr. McDougal.
19 MR. HICKEY: I do have limited redirect.
COMMISSIONER SMITH: Oh, I i m sorry.
MR. HICKEY: If I may.
COMMISSIONER SMITH: You may.
MR. HICKEY: Thank you.
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1 REDIRECT EXAMINATION
2
3 BY MR. HICKEY:
4 Q.I want to start with this last exhibit and your
5 testimony on wasn It it page 41 where you had been directed by
6 Mr. Budge?
7 A.Page 45, I believe.
8 Q.Forty-fi ve. And the chart on 45 that you did
9 addressing some aspects of curtailment, do you recall that
10 chart?
11 A.Yes, I do.
12 COMMISSIONER SMITH: It's on page 46.
13 MR. HICKEY: On page 46. Thank you.
14 THE WITNESS: Yes.
15 Q.BY MR. HICKEY: And on that chart, were you
16 looking at historical data?
17 A.Yes, I was.
18 Q.And now directing you to 249, why did Mr. Eelkema
19 Respond to this particular Request rather than you?
A.Mr. Eelkema develops our load forecasts, he
21 develops our coincident peaks, and he gives those all to me as
22 an input into our JAM model.
23 Q.And are all those based on forecasted data rather
24 than historical data?
25 A.For the test period, they were using a forecast
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1 for calendar year 2010.
2 Q.Then I i d like to next direct you to Exhibit 622.
3 Do you recall you were asked some questions by Ms. Davison
4 regarding it?
5 A.Yes.
6 Q.And at one point, I believe you were trying to
7 continue with an answer and lIm not sure that you got a chance
8 to fully respond. Were there any other comments regarding
9 Exhibit 622 that you wanted to make?
10 A.I believe I made them in the later responses,
11 which is that there have been additional transmission proj ects
12 and other projects that have exceeded the $5 million threshold
13 that we have not added into this case.
14 Q.Do you consider the listing of the investments
15 for which you were seeking to bring into rate base in this case
16 to be a reasonable level of investment?
17 A.Yes, I do.
18 Q.And can you tell us quickly why you believe it to
19 be reasonable?
A.In looking through the level of expenses compared
21 to the level that we have spent year to date, I believe that
22 this level is actually below the level we have spent, so I
23 think it's reasonable.
24
25
Q.Then I would like to lastly visit with you about
the allocation issues that Mr. Price was examining you on, and
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1 isn i tit true that the allocation of the capital investments
2 is, in fact, a dynamic issue?
3 A.Yes, it is.
4 Q.And it i S dynamic in the sense that although the
5 allocation factors may result in a specific allocation to Idaho
6 as a result of this case, that will change in the future, won It
7 it?
8 A.Yes, it will. It will change in every case.
9 Q.So if we even drill down and get a little more
10 specific about the large investment in this case of Populus to
11 Terminal even though it's being allocated in this case, the
12 next time the Company comes before this Commission with another
13 rate Application, the allocation of those capital investments
14 including Populus to Terminal will be inevitably revisited,
15 won't they?
16 A.Yes, every case we revisit allocations, we update
17 it to the current allocation factors.
18 Q.And do you have any idea of when the Company may
19 be before the Commission with another rate case?
A.Unfortunately, I tend to think we're going to
21 make a regular habit of this.
22 MR. HICKEY: I have no further questions and ask
23 that Mr. McDougal be excused.
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MR. BUDGE: Madam Chairman.
COMMISSIONER SMITH: Mr. Budge.
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1 MR. BUDGE: Before -- and I apologize for
2 interrupting, but I'm just a little concerned. The redirect
3 went into a little farther that issue, and I want to make sure
4 this witness can't answer the question I have on this forecast
5 of numbers so I don't end up with Mr. Paice up there and find
6 out he doesn't know either.
7 COMMISSIONER SMITH: Okay. Go ahead.
8 MR. BUDGE: Could I just ask a couple more?
9 COMMISSIONER SMITH: Sure.
10
11 RECROSS-EXAMINATION
12
13 BY MR. BUDGE:
14 Q.If I understood your response then, the data
15 shown on your chart on page 46 was based on forecast data?
16 A.No. When you were talking about forecast data
17 at least it was my opinion -- you were talking about page 45,
18 that last bullet, lines 5 through 9. Page 46 is actual data.
19 Q.What i s the source of the actual data on 46?
A.What we did is we looked at the time of
21 coincident peak and then we looked at the time of curtailments
22 for Monsanto and said, Do they match? So was Monsanto
23 historically curtailed at the time of the system peak?
24 We don't know what their load was at the time of
25 system peak, but we do know whether there was a called
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1 curtailment event.
2 Q.So back on your testimony on 45 when you say on
3 eight of 12 months during the test period, Monsanto i s load
4 coincident peak was less than 170, is that forecasted data that
5 you i re utilizing?
6 A.That is numbers from Craig Paice i s exhibit, and
7 that is the information he can answer for you.
8 Q.The forecasted number?
9 A.Yes.
10 Q.So he i s trying to forecast when the peak is going
11 to hit, and hel s trying to also forecast whether or not theyl II
12 interrupt Monsanto at that peak?
13 A.I believe for his purposes he's not assuming that
14 there will be any interruptions. He is trying to allocate
15 costs as if there are not. He could more fully answer that
16 question.
17 Q.And it would be the Company that makes that
18 decision whether or not to curtail Monsanto at the peak when it
19 hits. Correct?
A.That is correct, keeping in mind that the Company
21 never knows in advance when the peak will be or even when it
22 is. We never know what the next day will bring.
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Q.Thank you, Mr. McDougal. No further questions.
MR. BUDGE: Thank you, Chair and Counsel.
COMMISSIONER SMITH: Commissioner Redford.
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1 COMMISSIONER REDFORD: I have a couple of maybe
2 requests or questions.
3
4 EXAMINATION
5
6 BY COMMISSIONER REDFORD:
7 Q.I'm a bit concerned about your responses to the
8 questions posed by Ms. Davison and in regard to your inclusion
9 into the revenue requirements of proj ects which were outlined
10 in Exhibit No. 622. You identified three projects that will
11 not come online or be completed until 2011, and it seems to be
12 your testimony -- you said, Well, there are some that have come
13 online or so on and so forth, and it i S all kind of a wash.
14 Well, I'm wondering if you have provided
15 information or can you provide information to us that will
16 update the -- those proj ects that are completed, going to be
17 online in December, by December 31st, or arenlt; or, those that
18 have already been completed and so on?
19 I think it's pretty important, to me at least,
20 that you be a little firm in what you have included and what
21 you haven't included, and this idea where it just kind of
22 washes out just doesn't sit with me. And I'm wondering, can
23 you provide that information?
24 A.Yes, we can.
25 Q.When can you have that for us?
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1 A.I can have somebody work on it and I should be
2 able to get something to you by the end of the week.
3 Q.Do you have a -- don i t you have a schedule that
4 is a internal document that might be used for determining when
5 your proj ects what the status of your projects are, when
6 they i re going to be completed?
7 A.We have several schedules. Because of the way
8 the Company is organized, you actually have to go to several
9 different people because you have different people managing the
10 documents within the PacifiCorp Energy division versus the
11 other divisions of the Company.
12 Q.I don't want to pressure you as far as getting
13 that information to us by the end of the week, but one
14 follow-up question that I have:
15 Have you already provided to the Staff the
16 information in a document where they could -- where they can do
17 that?
18 A.They actually have a document that they could
19 pullout these three projects, yes.
Q.Well, why don i t you -- why don't you provide that
21 information to us I would say within ten days?
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A.Okay.
Q.And also provide it to Staff?
MR. HICKEY: Be more than happy to see that that
filing is made.
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i Q.BY COMMISSIONER REDFORD: And I i d like to see,
2 you know, some reference if it i S not too much difficulty, if
3 it i S not going to be completed by December 31st, give us a
4 completion estimate date; and for those items that have already
5 been completed but were scheduled to be completed in 2011, let
6 us know about those as well.
7 A.Okay.
8 Q.Thank you, and I hope that isn i t too much burden.
9 MR. HICKEY: No.
10
11 EXAMINATION
12
13 BY COMMISSIONER SMITH:
14 Q.While we're clarifying, I just want to clarify
15 something on the same page that Commissioner Redford was
16 discussing:
17 When you have a date like an in-service date on
18 the first one, Dave Johnson, of May 10th, and then the next one
19 says "updated in-service date" and there i s no change is stated,
20 does that mean that that came online in May 10th?
21
22
A.Yes.
Q.Okay. So the only ones that -- the three that
23 are different are the ones that were already identified?
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25
COMMISSIONER REDFORD: Well
THE WITNESS: I am going to have to verify one
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1 thing, and that is if they came in early, we may not have
2 updated this sheet.
3 Q.BY COMMISSIONER SMITH: Okay.
4 A.But I will verify that for you to make sure.
5 Q.So what "no change" really means is that it came
6 online in 2010, either before or after this -- the in-service
7 date?
8 A.Correct. And I believe they all hit the exact
9 month, but I will verify that just to make sure.
10 COMMISSIONER REDFORD: Well, I hope that your
11 request, Madam Chairman, is not just limited to what you just
12 stated. I kind of want an updated scheduling.
13 THE WITNESS: Right.
14 COMMISSIONER SMITH: I didn i t make a request,
15 Commissioner Redford. I 1m just clarifying that if it says "In
16 service May 10," it i S in service now
17 COMMISSIONER REDFORD: Well, whatever you want to
18 request is
19 COMMISSIONER SMITH: -- and not that "no change"
20 means it's still out there and it i S not in service.
21 THE WITNESS: No, they are all in service, I do
22 know that. My only question is did it come in in that exact
23 month or could it have came in earlier.
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Q.BY COMMISSIONER SMITH: And I i m not concerned
about that. I was just clarifying that that doesn i t mean that
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1 it's still hanging.
2 A.Right. And I know that is not the case.
3 Q.All right. Thank you.
4 COMMISSIONER REDFORD: Well, Commissioner Smith,
5 you have not asked for --
6 COMMISSIONER SMITH: I didn It alter in any way
7 your request.
8 COMMISSIONER REDFORD: Okay. Thank you.
9 Do you understand what it is I am requesting?
10 THE WITNESS: Yes. You want an updated table
11 that shows the dates and the amounts for all of these projects.
12 COMMISSIONER REDFORD: Yes, please.
13 I apologize if I've offended you.
14 COMMISSIONER SMITH: Why does this stop you?
15 Mr. Hickey.
16 MR. HICKEY: I have no re-redirect and would ask
17 that Mr. McDougal be excused, and we i II happily provide that
18 late-filed exhibit.
19 COMMISSIONER SMITH: Is there any obj ection to
20 Mr. McDougal being excused?
21
22
23
No? Then, he is.
(The witness left the stand.)
COMMISSIONER SMITH: All right, let iS just go off
24 the record for a moment.
25 (Discussion off the record.)
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1 COMMISSIONER SMITH: So we i II go back on the
2 record. Having outlined our work for tomorrow, we will adj ourn
3 now and commence again tomorrow morning at 8: 35.
4 Thank you all.
5 (The hearing adjourned at 5:48 p.m.)
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