20110201Shu Direct.pdf

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2011 FEB - ¡ AiîfO: 32
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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE )
APPLICATION OF ROCKY )
MOUNTAIN POWER FOR )
AUTHORITY TO INCREASE RATES )
BY $11.0 MILLION TO RECOVER )
DEFERRD NET POWER COSTS )
THROUGH THE ENERGY COST )
ADJUSTMENT MECHANISM )
CASE NO. PAC-E-11-07
Direct Testimony of Hui Shu
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-11-07
February 2011
1 Q.Please state your name, business address and present position with
2 PacifiCorp, dba Rocky Mountain Power (the "Company").
3 A.My name is Hui Shu, my business address is 825 N.E. Multnomah, Suite 600,
4 Portland, Oregon 97232, and my present position is Manager, Net Power Costs.
5 Qualifications
6 Q.Briefly describe your education and business experience.
7 A.I received an undergraduate degree in Electrical Engineering and finished trainng
8 in the program for Masters in Business Admnistration from University of
9 Shanghai for Science and Technology. I received a PhD degree in Systems
10 Science with a focus on Econometrics from Portland State University. I have
11 worked for PacifiCorp since 1992 and have held positions in the commercial and
12 trading and regulatory areas. I accepted my current position as manager of net
13 power costs in Februar 2008.
14 Q.Please describe your current duties.
15 A.I am responsible for the coordination and preparation of net power cost and
16 related analyses used in regulatory fiings. In addition, I represent the Company
17 on power resource and other related issues in regulatory proceedngs across the
18 Company's six-state service terrtory.
19 Summary of Testimony
20 Q.Wil you please summarize your testimony?
21 A.I am sponsoring testimony supporting the Company's request to increase Tarff
22 Schedule 94 to recover costs of approximately $12.8 millon resulting from the
23 implementation of the Company's Idao Energy Cost Adjustment Mechanism
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Rocky Mountain Power
1 ("ECAM") for the 12-month period ended November 2010. In doing so, I present
2 the background and calculation of the Company's ECAM and describe the actual
3 net power costs ("NPC") incured by the Company to serve retail load for the
4 historical 12-month period ended November 30, 2010 ("Deferral Period"). The
5 proposed increase to Tarff Schedule 94 is approximately $11.0 milion,l or an
6 average of 7.4 percent to Idao customers.
7 ECAM Background
8 Q.Pleas briefly describe the Company's ECAM authorized by the
9 Commission.
10 A.In Order No. 30904 dated September 29, 2009, in the Company's Case No. PAC-
11 E-08-08, the Commssion approved the stipulation entered into by the
12 Commssion Staff, the Idaho Irgation Pumpers Association, Monsanto and the
13 Company that set up the strctue and content of the ECAM mechanism. The
14 ECAM, which appears as a separate line item on customer bils, defers the
15 difference between actual NPC incurred by the Company to serve Idaho
16 customers over a specified period and a base NPC level established through a
17 general rate case proceeding. Where actual NPC is greater than the base NPC, the
18 difference is charged to customers through the ECAM (administered through
19 Electric Service Schedule No. 94). Conversely, where the base NPC is greater
20 than Actual NPC, the difference is credited to customers. In addition to the
1 The Company was authoried to set present Schedule 94 rates that were designed to recover
approximately $2.0 millon. Rates in the 2010 ECAM adjustment, Case No. PAC-E-1O-Ol were set using
the Company's then-most recent general rate case test penod, 12 months ending December 2007. In this
curent docket, the Company is using the test penod from its curent 2010 Rate Case, Case No. PAC-E-1O-
07, 12 months ending December 2010. Using this most recent test penod, present Schedule 94 wil collect
approximately $1.8 milion. As a result, the proposed recovery of approximately $12.8 milion in the
current filing results in a net rate increas to customers of approximately $11.0 millon.
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1 varance between actual and base NPC, the ECAM reflects the impact of
2 differences in the deferrl period between actual and base period retail load, a
3 credit. for SOz revenues, an adjustment for the treatment of coal strpping costs
4 and a renewable resource adder that reflects generation from new renewable
5 resources that have not been included in rates durng the deferral period. Puuant
6 to the terms of the stipulation, the annual deferral period for the ECAM is
7 December 1 to November 30; the Company is required to fie by February 1 each
8 year subsequent to the deferral period an application with the Commssion to
9 adjust the ECAM rate effective April 1.
10 ECAM Calculation
11 Q.
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Please describe the Energy Cost Adjustment Mechanism as calculated in
Exhibit 1.
In this application for the Deferral Period of December 1, 2009 to November 30,
2010, the Company compared the actual system net power costs ("Actual NPC")
to the net power costs embedded in rates ("Base NPC") from Case No. PAC-E-
08-07 ("2008 Rate Case"), on a monthly basis and deferred the differences into an
ECAM balancing account. This comparson is made on a system basis and in a
dollar per megawatt-hour rate. Exhibit 1 details the ECAM calculation and
contains supporting information, portions of which are confidential.
How are the Base NPC and Actual NPC dollar per megawatt-hour rates
calculated?
With respect to the Base NPC rate, the Company stared with the net power costs
of approximately $982 millon approved by the Commssion in Order No. 30783
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from the 2008 Rate Case. The Company then took the monthly NPC dollar
amount from that case and divided it by the monthly normalized load to express
the costs on a dollar per megawatt-hour basis (Exhibit 1, line 1). The Actual NPC
rate on a dollar per megawatt-hour basis is calculated by takng the monthly
Actual NPC dollar amount and dividing it by the actual monthly system load
(Exhibit 1, line 4).
. Please describe how the NPC deferral is determined.
The calculation of the deferral is done on a monthly basis by subtracting the Base
NPC rate from the Actual NPC rate. The resulting monthly NPC rate differential
(Exhibit 1, line 5) is then multiplied by actual Idaho retail load at input, excluding
the tarff contract load (Exhibit 1, lines 6 and 7) to calculate the NPC differential
for deferral (Exhibit 1, line 8). For the 12-month period endig November 2010
the NPC differential for deferral was approximately $6.1 millon.
Why is the tariff contract load excluded in the current ECAM calculation?
In the 2007 general rate case, Case No. PAC-E-07-05, the Commssion approved
a stipulation including electric service agreements with specific planned rate
increases for two tarff contract customers through December 31, 2010. The
Company commtted not to seek further rate changes for the contract customers
that would be effective prior to Januar 1, 2011 and is not proposing any
modifications to those rate plans in this Application. As a result, only the standard
tarff customers' load is included in the ECAM calculation while the tarff
contract customers' load is excluded from the calculation. The tarff contract
customers wil be responsible for their share of the ECAM deferred costs
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beginning Januar 1,2011 forward and wil be included in the Company's ECAM
application filed Februar 1,2012.
What types of costs are included in the NPC differential for deferral?
The NPC diferential for deferral captures all components of net power costs as
defined in the Company's general rate case proceedings and modeled by the
Company's production dispatch model ("GRID"). Specifically, Base NPC and
Actual NPC include amounts booked to the following FERC accounts:
Account 447 - Sales for resale, excluding on-system wholesale sales and
other revenues that are not modeled in GRID
Account 501 - Fuel, steam generation; excluding fuel handling, star up
fuel/gas2, diesel fuel, residual disposal and other costs that
are not modeled in GRID
Account 503 - Steam from other sources
Account 547 - Fuel, other generation
Account 555 - Purchased power, excluding BPA residential exchange
credit pass-through if applicable
Account 565 - Transmission of electrcity by others
In addition to the comparison of Actual NPC to Base NPC, what other
components are included in the ECAM?
There are thee additional components included in the ECAM calculations: (i)
Load Growth Adjustment Rate ("LGAR") revenues, (ii) credit for any SOz
allowance sales, and (iii) a renewable resource adder. In addition, in Order No.
30987 in the Company's Case No. PAC-E-09-08, the Commssion granted
authorization of the Company's application to defer costs associated with coal
mine stripping activities recorded under the Financial Accounting Standads
Board ("FASB") Emerging Issues Task Force standard 04-6 ("EITF 04-6").
2 Star up fuel is accounted for separately from the pnmar fuel for steam power generation plants. Sta up
costs are not accounted for separately for natural gas plants, and therefore all fuel for natural gas plants is
included in the determnation of both Base NP and Actual NPC.
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Based on this authorization, the Company records to Other Regulatory Assets the
mine strpping costs, and amortizes the costs to Fuel Expenses when coal is
extracted and consumed. In this fiing, the Company has included adjustments to
reflect this treatment.
Please describe the LGAR revenues and how they impact the ECAM.
The calculation of LGAR revenues is a symmetrcal adjustment for any over or
under collection of the Company's production plant related revenue requirement,
excluding NPC, due to varances in Idaho load. In Commssion Order No. 30904,
the Commssion approved a symmetrcal LGAR of $17.48 per megawatt-hour.
LGAR revenues are calculated by subtracting Idaho's load at input established in
the 2008 Rate Case ("Base Load" shown in Exhibit 1, line 9), from actual Idaho
load at input ("Actual Load" shown in Exhibit 1, lines 6 and 7). The difference
(Exhibit 1, line 10) is then multiplied by theLGAR of $17.48 (Exhibit 1, line 11)
to arve at the LGAR revenues (Exhibit 1, line 12) of approximately $5.3 millon
for the 12-month Deferral Period.
How is SOi sales revenue included in the ECAM?
Line 13 of Exhibit 1 contains the total Company SOz sales revenue during the
Deferral Period. Based on Idaho's System Energy allocation factor ("SE")
authorized by the Commssion from the 2008 Rate Case, line 15 of Exhibit 1 is
Idao's allocated share of the SOz sales revenue. Idaho's allocated share of the
SOz sales revenue is furter prorated to exclude the tarff contract customers' load
on line 16 of Exhibit 1. The resulting SOz sales revenue on line 17 of Exhbit 1 is
credited against the NPC differential for deferraL. For the 12-month Deferral
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Rocky Mountan Power
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Period, the total SOz sales revenue credit is a $93,906 reduction to the NPC
deferral balance.
How is the adjustment for the accounting pronouncement EITF 04-6
included in the ECAM?
Line 18 of Exhibit 1 reflects the Idaho allocated differences between excluding
coal stripping costs incurred by the Company and recorded on the Company's
books pursuant to the guidance of the accounting pronouncement EITF 04-6, and
the amortization of the coal striping costs when the coal was excavated and
consumed. Idaho's allocated share is further prorated to exclude the tarff contract
customers' load on line 19 of Exhibit 1. The resulting EITF 04-6 deferral
adjustment on line 20 of Exhibit 1 is added to the NPC differential for deferraL.
For the 12-month Deferral Period, the total EITF 04-6 coal stripping deferral
adjustment is a $108,588 reduction to the NPC deferral balance.
Is the deferral subject to a sharing ratio between the Company and
customers in the ECAM?
Yes. The ECAM includes a symmetrcal sharng ratio where customers payor
receive 90 percent of the ECAM deferral balance and the Company is responsible
for the remaining 10 percent. Line 23 of Exhibit 1 reflects the customers' 90
percent share of the monthly deferral on line 21 of Exhibit 1. For the 12-month
Deferral Period, the customers' share of the deferral balance is approximately
$10.0 millon. The remaining balance of approximately $1.1 millon is not
included in the deferral calculation and is not recoverable from customers.
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Is the deferral. balance adjusted for a renewable resource adder?
Yes.
Please describe the renewable resource adder for resources not yet in rates.
The renewable resource adder recognizes that the Company has made significant
investment in renewable generation resources that are not yet being recovered in
Idaho rates, and that these resources are providing benefits to customers through
the near-zero cost energy generation included in the Actual NPC. Therefore, from
the effective date of the ECAM to the date when the investment of these resources
is included in rates, the ECAM includes a renewable generation investment
adjustment. The adjustment is based on an authorized amount of $55.00 per
megawatt-hour multiplied by the actual megawatt-hour output generated by those
renewable resources that were not included in rates during the Deferral Period
(Exhibit 1, line 24). Line 26 of Exhibit 1 reflects this adjustment ona total
Company basis. The total Company amount is allocated to Idaho (Exhibit 1, line
28) based on the System Generation allocation factor ("SG"), which is furer
prorated to the tarff customer load (Exhibit 1, line 30). The renewable resource
adder results in a cost to customers of approximately $2.7 millon for the 12-
month Deferral Period.
Which renewable generation projects are included in the renewable resource
adder?
The renewable generation resources included in this application are Glenrock,
Glenrock III, Seven Mile, Seven Mile II, Rollng Hils, High Plains, McFadden
Ridge, and Dunlap wind generation facilties. These resources were included in
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the Company's application in Case No. PAC-E-I0-07 ("2010 Rate Case") and,
subject to final Commssion approval and inclusion of these investments in rate
base, accrual of costs into the ECAM for the renewable resource adder wil
termnate with the effective date of the rate change in the 2010 Rate Case.
What is the total ECAM deferred balance as calculated in Exhibit I?
The total ECAM deferral balance is the customers' share of the NPC differential
for deferral balance, the SOz allowance sales, LGAR, and EITF 04-6 adjustment
plus the renewable resource adder. That is, the ECAM balance in the current
application at November 30,2010 is approximately $13.6 millon, including $10.0
milion related to the customers' share of deferral balance, $2.7 millon of
renewable resource adder, approximately $760,000 of uncollected balance from
the Company's ECAM filng in 2010 and interest on the monthly ECAM balances
that is determned based on the Commssion authorized rate for customer deposits
at two percent in 2009 and one percent beginning in Januar 2010. The ECAM
balance is shown on line 38 of Exhibit 1.
In your opinion does the calculation of the $13.6 millon deferred NPC
adjustment proposed in this application comply with the parameters of the
Idaho ECAM as approved by the Commission in Case No. PAC-E-08-08?
Yes.
Is the Company requesting a rate increase to recover the full $13.6 millon
deferral?
No. The Company has subtracted the approximate $760,000 under collection
referenced previously from the $13.6 millon November 2010 balance as it is
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1 expected that the under collection wil largely be recovered though Schedule 94
2 rates from December 1, 2010 to March 31, 2011. Any over or under collection of
3 the original $2.0 millon deferral wil be addressed in future ECAM fiings.
4 Q.Please summarize the components of the Deferred ECAM Balance.
5 A.The components making up the deferred ECAM balance as detailed in Exhibit 1
6 are reflected in the following table:
Summary Table of Deferred ECAM Balance
NPC Differential for Deferral $6,073,522
LGAR 5,286,046
802 (93,906)
EITF 04-6 Adjustment (108,588)
Total $11,157,074
90%
Customer Responsibility $10,041,366
Renewable Resource Adder 2,696,763
Unamortized Previous Balance 760,036
Interest 61,885
November 2010 Deferral $13,560,051
Less: Unamortized 2010 ECAM Balance $(760,036)
Proposed Balance for Recovery $12,800,015
7 Actual NPC - Base NPC Comparison
8 Q.How does the Actual NPC differ from the Base NPC for this deferral period?
9 A.The Base NPC that is approved by the Commssion and included in rates is
10 approximately $982.0 millon on a total Company basis. Total adjusted Actual
11 NPC durng the deferral period beginning December 1, 2009 and ending
12 November 30,2010 is $1.172 bilion, which is approximately $190 millon higher
13 than what was included in rate during the Deferral Period.
14 Q.Please explain why Actual NPC are adjusted.
15 A.The Actual NPC recorded on the Company's books are adjusted to remove entres
16 that are not included in the determnation of the Company's Base NPC for
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regulatory purposes, such as adjustments made to correct entries in months
outside the current ECAM period, or prior Commssion approved adjustments,
such as the revenue imputation of the sales contract with Sacramento Municipal
Utilty Distrct.
What are the primary drivers that cause the Actual NPC to be different from
the Base NPC in rates during the Deferral Period?
The differences in NPC are mainly the result of the timng difference between
Actual NPC and Base NPC and changes in costs in the actual period that were not
reflected in the Base NPC. The Base NPC has a test period of calendar 2008,
while Actual NPC is for December 2009 though November 2010. Between the
base period and the actual period, several wholesale sales and purchase contracts
have expired and new contracts have become effective. Changes in the
Company's resource portfolio and market prices also have led to differences
between Actual NPC and Base NPC.
Could you give some example of these changes?
Yes. Some examples include:
. In November 2009, the original contract between the Company and the Grant
Public Utility District ("PUD") for the generation from the Mid Columbia
W anapum project expired. Because this contract was priced at the cost of the
Wanapum project, NPC in the Deferral Period are higher due to higher costs
of the replacement power. The amount of reduction in purchased power due to
expiration of this contract nets to approximately 590,000 megawatt-hours in
the Deferral Period. The higher costs of the replacement power are somewhat
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1 mitigated by the increase in revenues from the Reasonable Portion of the
2 contract with Grant PUD.
3 . A low-priced formula power transfer ("FPT") wheeling contract with the
4 Bonnevile Power Admiistration ("BP A") expired and was converted to a
5 higher priced point-to-point ("PTP") contract in November 2009. The Deferral
6 Period also includes additional wheeling expenses to transfer generation from
7 the Chehalis plant to the Company's load areas, as well as increases in wind
8 integration costs that BP A charges for the Company's wind generation
9 facilities located in the BP A's balancing authority area: Leaning Juniper and
10 Goodnoe Hils. Increases in BPA wheeling expenses are approximately $18.8
11 milion.
12 . The Idaho Power Company has restructued the wheeling contracts with the
13 Company for transferrng generation from Jim Bridger plant to the Company's
14 load areas, which are now priced at relatively higher PTP rates. The
15 restrctured contracts increased wheeling expenses by approximately $7.0
16 milion.
17 . Both third pary coal purchase expenses and captive mine costs have
18 increased. For example, the coal prices at the Naughton plant increased by
19 approximately $12 millon due to both a price reopener under the long-term
20 coal supply agreement with Chevron Mining and the escalation of the
21 producer price index under the previous contract; the coal prices at the Hunter
22 plant increased by approximately $7 millon due primarly to a fixed price
23 increase under the Sufco contract; the coal prices at the Huntington plant
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increased by approximately $8 millon, predominantly resulting from the
higher operating costs during July through November 2010 while the longwall
system was being reconstrcted; and the coal prices increased by
approximately $31 millon at the Bridger Plant as the result of higher Bridger
Coal Company production costs, a new coal supply agreement with Black
Butte and a new rail agreement with the Union Pacific Railroad.
. The actual hydro generation from the Company owned resources is lower than
what is reflected in the Base NPC by approximately 650,000 megawatt-hours.
. The availabilty of the Company's thermal plants are lower than what was
reflected in the Base NPC, in addition to the added requirement to fulfil the
requirements to integrate the Company's increasing amount of wind
generation into the system. The combined impact of these reduced thermal
generation by approximately 3.8 millon megawatt-hours, as compared with
what is reflected in Base NPC.
All of these changes have caused the Actual NPC to be higher than the Base NPC.
Are the increases in NPC offset by other components of the NPC?
Yes. Cal iso fees and short term wheeling expenses are lower in the deferral
period. Also, as discussed above, several new wind resources came online. since
the Company's 2008 Rate Case, which provided power at nearly zero varable
costs. The generation from these additional wind facilities during the Deferral
Period is approximately 1.5 millon megawatt-hours.
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1 Schedule 94 - Energy Cost Adjustment
2 Q.
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How is the deferred NPC adjustment allocated to retail tariffs?
Pusuant to Schedule 94, the deferred ECAM balance is allocated to all tarff rate
schedules based on delivery voltage levels adjusted for line losses as established in
the 2010 Rate Case. An overall average rate is developed by dividing the
November 30, 2010 ECAM balance by the line loss adjusted load. This average
rate is then multiplied by the prima, secondar, and transmission line loss
adjusted loads to calculate the amount each voltage service level would collect of
the deferred balance. This revenue by voltage level is then divided by the
corresponding metered loads by voltage service level to arve at a rate per service
voltage leveL. These rates are then applied to the voltage service level loads of each
rate schedule to calculate the revenue to be collected by rate schedule. This
allocation recognizes the differences in the cost to serve different levels of voltage.
Please describe Exhibit 2.
Exhibit 2 ilustrates the metered loads, the line loss adjusted loads, the allocation of
the deferred NPC price change, and the percentage change by rate schedule based
on present revenues ordered in the Company's 2010 Rate Case.
Please describe Exhibit 3.
Exhibit 3 is the proposed tarff Schedule 94, Energy Cost Adjustment, designed to
collect approximately $12.8 millon in ECAM deferred balance. Any under or over
recovery wil continue to be included in the ECAM deferred balance and trued-up
over time. Schedule 94 shows the electrc service schedules currently subject to the
ECAM deferral and their proposed rates based on customer delivery voltage.
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Schedule 94 is a separate line item, or rider, on customer bils that is adjusted
annually on April 1 following Commssion approval.
What is the monthly bil impact to the average residential customer of the
proposed Schedule 94 rates?
Based on the net increase of approximately $11.0 millon, the average Schedule 1
residential customer using 839 kWh per month wil see a monthly bil increase of
approximately $5.03, or 6.1 percent. This compares to the overall average increase
for all customer classes of 7.4 percent.
Does this conclude your direct testimony?
Yes.
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'\
tOri FEB -1 APi 10= 32
REDACTED
Case No. PAC-E-ll-07
Exhibit NO.1
Witness: Hui Shu
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
REDACTED
Exhibit Accompanying Direct Testimony of Hui Shu
Februar 2011
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Exhibit No.1 Pages 2-18 of 28
Case No. PAC-E-11-07
Witness: Hui Shu
PAGES 2-18
ARE CONFIDENTIAL AND PROVIDED
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Case No. PAC-E-11-07
Exhibit NO.2
Witness: Hui Shu
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Hui Shu
Februar 2011
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inn FEB -I Ar1 10: t'lie No. PAC-E-11-07Exhibit NO.3
Hui Shu
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Hui Shu
Februar 2011
~ROCKY MOUNTAIN'~ipOWER
.~ A O'V'$ll)NOFl'to,(:!fICORl'
I.P.U.C. No.1
Rocky Mountain Power
Exhibit No.3 Page 1 of 1
Case No. PAC-E-11-07
Witness: Hui Shu
First Revision of Sheet No. 94.1
Cancellng Orinal Sheet No. 94.1
ROCKY MOUNTAIN POWER
ELECTRC SERVICE SCHEDULE NO. 94
STATE OF IDAHO
Energy Cost Adjustment
AVAILABILITY: At any point on the Company's interconnected system.
APPLICATION: This Schedule shall be applicable to all retail tarff Customers takng service
under the Company's electric service schedules.
ENERGY COST ADJUSTMENT: The Energy Cost Adjustment is calculated to collect the
accumulated difference between total Company Base Net Power Cost and total Company Actual Net Power
Cost calculated on a cents per kWh basis.
MONTHLY BILL: In addition to the Monthly Charges contained in the Customer's applicable
schedule, all monthly bils shall have applied the following cents per kilowatt-hour rate by delivery voltage.
Secondar
Schedule 1 0.700ø per kWh
Schedule 6 0.700Ø per kWh
Schedule 6A 0.700Ø per kWh
Schedule 7 0.700Ø per kWh
Schedule 7A 0.700Ø per kWh
Schedule 9
Schedule 10 0.700Ø per kWh
Schedule 11 0.700Ø per kWh
Schedule 12 0.700Ø per kWh
Schedule 19 0.700ø per kWh
Schedule 23 0.700Ø per kWh
Schedule 23A 0.700Ø per kWh
Schedule 24 0.700Ø per kWh
Schedule 35 0.700Ø per kWh
Schedule 35A 0.700Ø per kWh
Schedule 36 0.700Ø per kWh
Delivery Voltage
Pnmary Transmission
0.676ø per kWh
0.676ø per kWh
0.658ø per kWh
0.676ø per kWh
0.676ø per kWh
0.676ø per kWh
0.676ø per kWh
0.676ø per kWh
Submitted Under Case No. PAC-E-11-07
ISSUED: February 1,2011 EFFECTIVE: Apri 1, 2011