20120413Direct Testimony.pdf

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E)HO PU3L UTfLITES COMWSS1ON
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO IMPLEMENT POWER
COST ADJUSTMENT ("PCA") RATES
FOR ELECTRIC SERVICE FROM JUNE 1,
2012, THROUGH MAY 31, 2013.
CASE NO. IPC-E-12-17
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
SCOTT WRIGHT
1 Q. Please state your name, business address, and
2 present position with Idaho Power Company ("Idaho Power" or
3 "Company").
4 A. My name is Scott Wright. My business address
5 is 1221 West Idaho Street, Boise, Idaho 83702. I am
6 employed by Idaho Power as a Regulatory Analyst II in the
7 Regulatory Affairs Department.
8 Q. Please describe your educational background.
9 A. I received a Bachelor of Science degree in
10 Business Economics from Eastern Oregon University. I have
11 also attended the Center for Public Utilities "Practical
12 Skills for a Changing Electric Industry" course at New
13 Mexico State University in Albuquerque, New Mexico, as well
14 as the Edison Electric Institute's "Electric Rate Advanced
15 Course" in Madison, Wisconsin.
16 Q. Please describe your work experience.
17 A. In May 1998, I accepted a position as Research
18 Assistant with Idaho Power in the Regulatory Affairs
19 Department. In March 2007, I was promoted to a Regulatory
20 Analyst. In March 2010, I was promoted to a Regulatory
21 Analyst II. As a Regulatory Analyst II, I am responsible
22 for running the AURORA model to calculate net power supply
23 expenses for ratemaking purposes, preparing the Power Cost
24 Adjustment ("PCA") filings in both Idaho and Oregon, as
25 well as the marginal cost of energy used in the Company's
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Idaho Power Company
1 marginal cost analysis. I also provide analytical support
2 for other regulatory activities within the Regulatory
3 Affairs Department, as well as providing testimony in other
4 Company filings.
5 Q. What is the Company requesting in this case?
6 A. The Company is requesting new PCA rates that

7 will:

8 (1) Recover $43.0 million of incremental
9 power supply expenses and;

10 (2) Reflect the separately requested $27.1
11 million reduction in revenues associated with the Company's
12 revenue sharing mechanism.

13 Although the combination of these two items suggests
14 a net change of $15.9 million, my testimony will focus on
15 the incremental change in power supply expense recovery and
16 not on revenue sharing that is being addressed in Case No.

17 IPC-E--12-13.

18 Q. What is the scope of your testimony in this
19 proceeding?

20 A. My testimony is divided into a number of
21 sections. The first section of my testimony provides an
22 overview of PCA components. The second section includes a
23 discussion of the quantification of the PCA forecast rate
24 using the PCA base components that were approved in Order
25 No. 31042 in Case No. IPC-E-10-01 and Order No. 32426 in
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Idaho Power Company
1 Case No. IPC-E-11-08. The third section discusses the
2 drivers of this year's PCA forecast rate. The fourth
3 section details the quantification of the True-Up and the
4 True-Up of the True-Up. The fifth section addresses the
5 PCA treatment of the revenue sharing amount that was filed
6 in Case No. IPC-E-12-13. The final section of my testimony
7 details the summation of all PCA components, which when
8 combined with the revenue sharing, provides a final PCA
9 rate for each rate class.
10 I. OVERVIEW OF PCA COMPONENTS
11
Q. Please describe the components of the PCA
12 base.
13 A. The PCA base level expenses are reflective of
14 the following Federal Energy Regulatory Commission ("FERC")
15 Accounts: FERC Account 501, fuel (coal); FERC Account 536,
16 water for power; FERC Account 547, fuel (gas); FERC Account
17 555, purchased power; FERC Account 565, transmission of
18 electricity by others; FERC Account 442, Hoku Materials,
19 Inc. ("Hoku") first block energy; and FERC Account 447,
20 sales for resale (typically referred to as surplus sales).
21 The PCA base expense component for FERC Account 555
22 includes both power purchases resulting from the Public
23 Utility Regulatory Policies Act of 1978 ("PURPA") and non-
24 PURPA (market) purchases. As per Order No. 32426, the
25 Company adjusts FERC Account 555 to include demand response
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Idaho Power Company
1 incentive payments that the Company provides to customers
2 for participating in any of its three demand response
3 programs.

4 Q. Does the inclusion of demand response
5 incentive payments as a PCA component represent a
6 modification to the cost categories historically tracked
7 through the PCA?

8 A. Yes it does. Order No. 32426, issued on
9 December 30, 2011, approved a settlement stipulation in the
10 Company's last general rate case and authorized the
11 inclusion of demand response incentive payments in PCA
12 computations. The Idaho Public Utilities Commission

13 ("Commission") also directed the Company to track such
14 payments in a subaccount of F'ERC Account 555. These costs
15 were previously recovered through the Company's Energy
16 Efficiency Rider, Schedule 91.

17 Q. Are there any other changes to the PCA base
18 components that have been approved since last year's PCA?

19 A. Yes. Order No. 32426 also approved an
20 additional PCA base component: FERC Account 442, Hoku
21 first block energy, which has been included in this year's
22 PCA. Prior to Order No. 32426, the Hoku first block energy
23 was included in the PCA calculation as an offset to the PCA
24 forecast, but was not included as a PCA base component.
25
WRIGHT, DI 4
Idaho Power Company
1
Q. Has the Commission required any one-time
2 changes to last year's PCA?
3 A. Yes. Last year, per Order No. 32217, the
Company was authorized to recover $10 million of the
Demand-Side Management deferral balance through the PCA
beginning on June 1, 2011. The $10 million recovery was a
VA one-time adjustment to last year's PCA; therefore, it has
8 been removed from this year's PCA computations. Any over
9 or under collection of the $10 million from last year's
10 recovery through the PCA will be captured in the Company's
11 PCA True-Up of the True-Up.
12 II. QUANTIFICATION OF PCA FORECAST
13 Q. Please quantify the PCA component amounts
14 described previously that are included in the PCA base from
15 which deviations are to be tracked based on customers
16 receiving a 95 percent share.
17 A. Order Nos. 31042 and 32426 approved the
18 Company's base level PCA component amounts from which
19 deviations are to be tracked at 95 percent for customer
20 responsibility as follows:
21 Account 501, coal $167,718,084
22 Account 536, water for power $1,828,640
23 Account 547, gas $6,062,472
24 Account 555, non-PURPA $66,689,601
25 Account 565, transmission $8,262,000
WRIGHT, DI 5
Idaho Power Company

1 Account 442, Hoku first block ($23,921,466)

2 Account 447, surplus sales ($92,642,114)

3 Net of 95 percent accounts $133,997,217

4 Q. Please quantify the PCA component amounts
5 included in the PCA base from which deviations are to be
6 tracked with a 100 percent customer responsibility.

7 A. Order No. 31042 approved the PCA base
8 component amounts from which deviations are to be tracked
9 with 100 percent customer responsibility as follows:

10 Account 555, PURPA $62,851,454

11
Q. Please quantify the PCA component amounts
12 included in the PCA base from which deviations are tracked
13 differently than described above.

14 A. The base level recovery of demand response
15 incentives in the amount of $11,252,265 was approved per
16 Order No. 32426. The $11,252,265 represents the Idaho
17 jurisdictional share of the incentive costs. Because the
18 demand response incentive payments are jurisdictionalized
19 prior to inclusion in the PCA, this cost category is
20 calculated separately from the net 95 percent accounts.
21 Under this separate treatment, an Idaho jurisdictional
22 sales denominator is used rather than the normalized system
23 firm sales denominator used for 95 percent accounts in the
24 PCA rate development process.
25
WRIGHT, DI 6
Idaho Power Company
1 Q. Please detail the amounts included in the PCA
2 forecast for which deviations from base are to be tracked
3 based upon a 95 percent customer sharing percentage.
4 A. Based upon the Company's March 29, 2012,
5 Operating Plan ("Operating Plan"), the forecast of amounts
6 for which deviations from base are to be tracked at 95
7 percent for customer responsibility is as follows:
8 Account 501, coal $147,503,921
9 Account 536, water for power $2,521,000
10 Account 547, gas $52,250,517
11 Account 555, non-PURPA $41,169,588
12 Account 565, transmission $7,554,520
13 Account 442, Hoku first block ($6,765,150)
14 Account 447, surplus sales ($110,167,401)
15 Net of 95 percent accounts $134,066,995
16 Q. What is the difference between the net of the
17 95 percent accounts of the forecast amount of $134,066,995
18 and the $133,997,217 PCA base amount approved in Order Nos.
19 31042 and 32426?
20 A. The PCA forecast amount of $134,066,995 is
21 nearly identical to the base amount of $133,997,217, a
22 difference of only $69,778.
23 Q. Does the Company's Operating Plan include the
24 Langley Gulch power plant?
25
WRIGHT, DI 7
Idaho Power Company
1 A. Yes. Langley Gulch, which is a 300 megawatts
2 combined cycle power plant, is included in the. Company's
3 Operating Plan, with an anticipated online date of July
4 2012. The Langley Gulch power plant is expected to
5 immediately be used and useful once it comes online.
6
Q. Please explain how the special contract with
7 Hoku is treated in this year's PCA computations.
8 A. As described previously, the Hoku first block
9 energy was not included in the PCA base components prior to
10 this year's PCA filing.
11 The Energy Sales Agreement ("ESA") between Idaho
12 Power and Hoku was approved on March 16, 2009, in Order No.
13 30748. The ESA is divided into two blocks of energy: a
14 marginal rate, or first block and an embedded rate, or
15 second block. The first block energy of the ESA is treated
16 similarly to surplus sales revenue in the Company's power
17 supply expense quantifications. Earlier this year, the
18 Company and Hoku agreed to reform the ESA and submitted a
19 settlement stipulation that was approved by the Commission
20 in Order No. 32486 on March 15, 2012. The reformed ESA
21 reduces Hoku's monthly minimum payment to $800,000 per
22 month for the period January 1, 2012, through June 30,
23 2013. The Company and Hoku submitted a revised ESA for
24 approval before the Commission on April 11, 2012. Until a
25
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Idaho Power Company
1 sales and load schedule for Hoku is received, the Hoku load
2 will be forecasted at zero.

3 Q. How does a Hoku forecasted load of zero affect
4 this year's PCA calculation?

5 A. The denominator used to calculate the PCA rate
6 will not include any load from Hoku. The numerator will
7 include the first block energy portion of the minimum
8 monthly payments that the Company will receive under the
9 reformed contract. The minimum monthly energy payments
10 will serve as surplus sales revenue, which will benefit
11 customers.

12 Q. How does the forecast of Hoku's first block
13 energy revenue compare to last year's PCA?
14 A. The Hoku first block energy forecast of
15 revenue included in this year's PCA filing is $6,765,150
16 compared to $22,196,712, a difference of $15,431,562.

17
Q. What is the Operating Plan quantification of
18 PURPA expenses anticipated from April 2012 through March

19 2013?

20 A. The Operating Plan anticipates $129,590,113 of
21 PURPA expenses during the April 2012 through March 2013
22 time period.

23
Q. How does this amount compare to the base level
24 of PURPA expenses approved in Order No. 31042?
25
WRIGHT, DI 9
Idaho Power Company
1 A. The Operating Plan quantification of PURPA
2 expense is $66,738,659 greater than the base level amount
3 of $62,851,454 (approved in Order No. 31042) in the
4 Company's update of power supply expenses.

5 Q. What is the Operating Plan quantification of
6 the demand response incentive payments anticipated from
7 April 2012 through March 2013?

8 A. The Operating Plan anticipates $14,723,210 of
9 Idaho jurisdictional demand response incentive payments
10 during the April 2012 through March 2013 time period.

11 Q. How does this amount compare to the base level
12 of Idaho jurisdictional demand response incentive payments
13 quantified in Order No. 32426?

14 A. The Operating Plan quantification of demand
15 response incentive payments is $3,470,945 greater than the
16 $11,252,265 quantified in the Company's update of power
17 supply expenses approved per Order No. 32426.

18 Q. What is the rate for the projection portion of
19 the PCA for April 2012 through March 2013?

20 A. The rate for the projection portion of the PCA
21 is equal to the sum of (1) 95 percent of the difference
22 between the non-PURPA expenses quantified in the Operating
23 Plan and those quantified in the Company's last approved
24 update of power supply expenses, divided by the Company's
25 normalized system firm sales and (2) 100 percent of the
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Idaho Power Company
1 difference between PURPA-related expenses quantified in the
2 Operating Plan and those quantified in the Company's last
3 approved update of power supply expenses, divided by the
4 Company's normalized system firm sales and (3) 100 percent
5 of the difference between the Idaho jurisdictional demand
6 response incentive payments quantified in the Operating
7 Plan and those quantified in the Company's last approved
8 update of power supply expenses, divided by the Idaho
9 jurisdictional sales.
10 The rate for non-PURPA expenses is 0.0005 cents per
11 kilowatt-hour ("kWh"), which is calculated by multiplying
12 $69,778 by 95 percent and then dividing it by the
13 normalized system firm sales of 13,816,139 megawatt-hour
14 ("MWh") (($69,778 * 0.95) / 13,816,139) = $0.005/NWh =
15 0.0005 cents/kWh) . The rate for PURPA expenses is 0.4830
16 cents per kWh, which is calculated by dividing $66,738,659
17 by the 13,816,139 MWh ($66,738,659 / 13,816,139 MWh =
18 $4.83/MWh = 0.4830 cents/kWh) . The rate for the demand
19 response incentive payment is 0.0264 cents per kWh, which
20 is calculated by dividing $3,470,945 by the Idaho
21 jurisdictional firm sales of 13,172,433 MWh ($3,470,945 /
22 13,172,433 MWh = $0.264/Mwh = 0.0264 cents/kWh). The
23 projection portion of the PCA rate is 0.5099 cents per kWh,
24 which is calculated by adding the non-PURPA expense of
25 0.0005 cents per kWh to the PURPA expense of 0.4830 cents
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Idaho Power Company
1 per kWh to the demand response incentive payment of 0.0264
2 cents per kWh (0.0005 + 0.4830 + 0.0264 = 0.5099 cents/
3 kWh).
4 Q. What is the recoverable deviation of forecast
5 power supply expenses from base level power supply
6 expenses?
7 A. The recoverable portion of power supply
8 expenses is $70.3 million (($69,778 x 0.95) + $66,738,659 +
9 $3,470,945 = $70,275,893).
10 III. 2012 PCA FORECAST DRIVERS
11 Q. In your opinion, what is the primary driver of
12 PCA forecast deviation from base levels in this year's PCA
13 forecast rate?
14 A. As can be deduced from my answer to the
15 previous question, a primary driver of the PCA forecast
16 deviation from base levels this year is the $66.7 million
17 of new PURPA expenditures. Of the total 2012 PCA forecast
18 deviation from base level power supply expense of $70.3
19 million, PURPA-related expenses account for $66.7 million
20 or 95 percent of the recoverable total.
21 Q. You have testified that the net forecasted
22 total for FERC accounts that require 95 percent customer
23 responsibility for deviations is very close to the total
24 for the same accounts in base rates. Are there differences
25 worth noting?
WRIGHT, DI 12
Idaho Power Company
1 A. Yes. While there may be many factors that
2 contribute to the net difference between the PCA base and
3 forecast accounts, I will discuss the factors that I
4 believe had variation worth noting.
5 FERC Account 501; coal: The base amount approved
6 per Order No. 31042 for coal was set at $167.7 million and
7 the forecast amount is for $147.5 million, a decrease of
8 $20.2 million. The decrease can be attributed a number of
9 factors including better than normal hydro generation
10 reducing the need for thermal generation, lower market
11 prices reducing the opportunity to make surplus sales, the
12 inclusion of the Langley Gulch power plant which depending
13 on gas prices may be dispatched before other thermal
14 generation and the additional PURPA power on the system,
15 which also reduces the need for thermal generation.
16 FERC Account 547, gas: The base amount approved per
17 Order No. 31042 for gas was set at $6.1 million and the
18 forecast amount is for $52.3 million, an increase of $46.2
19 million. The increase for gas can be attributed primarily
20 to the inclusion of the Langley Gulch power plant serving
21 load and being available for surplus sales.
22 FERC Account 442, Hoku first block energy: The base
23 amount approved per Order No. 32426 for the Hoku first
24 block energy was set at $23.9 million and the forecast
25 amount is for $6.8 million, a decrease of $17.1 million.
WRIGHT, DI 13
Idaho Power Company
1 The decrease is attributed to the revised ESA, which was
2 discussed earlier in my testimony.
3 FERC Account 447, surplus sales: The base amount
approved per Order No. 31042 for surplus sales was set at
$92.6 million and the forecast amount is for $110.2
I million, an increase of $17.6 million. The increase can be
I attributed in large part to the inclusion of the Langley
8 Gulch power plant, an additional resource available to sell
9 energy to the market when economical.
10 FERC Account 555, Non-PURPA: The base amount
11 approved per Order No. 31042 for Non-PURPA was set at $66.7
12 million and the forecast amount is for $41.2 million, a
13 decrease of $25.5 million. The decrease can be attributed
14 to the addition of Langley Gulch and PURPA energy, which
15 both contribute to a reduced need for purchased power.
16 As mentioned earlier in my testimony, the difference
17 between the base and the forecast for the total of the net
18 95 percent accounts is $69,778, a slight increase over the
19 approved base.
20
Q. How does this year's water forecast compare to
21 last year's water forecast?
22 A. Thi 3 year's water forecast is slightly better
23 than normal hydro conditions for the April-July runoff
24 period. "Normal" is defined as median, which is 4.9
25 million acre feet ("MAF") for the period (1962-2007) . This
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Idaho Power Company
1 year, the April-July streamflow forecast for Brownlee
2 reservoir is 5.6 MAF, or 0.7 MAF above the median level.
3 Last year's streamfiow forecast for April-July was 6.7 MAF,
4 1.1 MAF higher than this year's forecast.

5 Q. Please recap the changes that have occurred
6 between the base and forecast with regard to PURPA.

7 A. The base expense established in Order No.
8 31042 for PURPA was $62.9 million. The forecast PURPA
9 expense is approximately $129.6 million, an increase of
10 approximately $66.7 million.

11 Q. Please discuss the growth in PURPA expense in
12 recent years.

13 A. During the April 2001 through March 2002 PCA
14 year, the actual PURPA expense that flowed through the PCA
15 was $42.2 million. Over the next 10 years, actual PURPA
16 related expenses fluctuated between $39.6 million and $64.8
17 million. In last year's PCA, the actual PURPA expense that
18 flowed through the 2011 PCA was $103.8 million, and this
19 year the forecast is for $129.6 million. Further, 38
20 projects totaling $33.9 million of annual expense are
21 expected to come online during this year's PCA. As I
22 stated earlier in my testimony, PURPA expenses are the -
23 primary driver of this year's PCA filing and will continue
24 to drive future PCA increases.
25
WRIGHT, DI 15
Idaho Power Company

1 Q. Please recap the changes that have occurred
2 between the base and forecast with regard to demand
3 response incentive payments.

4 A. The base amount approved per Order No. 32426
5 for demand response incentive payments was set at $11.3
6 million and the forecast amount is for $14.7 million, an
7 increase of $3.5 million. This increase is based upon the
8 Company's current forecast of demand response program
9 participation and program operations for 2012.

10 IV. QUANTIFICATION OF THE TRUE-UP

11 AND TRUE-UP OF THE TRUE-UP

12 Q. Please describe the True-Up portion of the PCA

13 rate.

14 A. The True-Up portion of the PCA rate starts
15 with the deferral expense report, attached as Exhibit No.
16 1. This report compares actual PCA account results to last
17 year's PCA account projections on a monthly basis, with the
18 differences accumulated as the deferral balance. The
19 balance at the end of March 2012, with interest applied,
20 was ($17,646,658), as shown on row 90 of Exhibit No. 1.
21 The negative $17.6 million represents a benefit to
22 customers resulting from actual power supply expenses being
23 less than what had been forecast last year.

24 1 Q. Please describe the computation of this year's
25 True-Up rate.
WRIGHT, DI 16
Idaho Power Company

1 A. This year's True-Up component of the PCA is

2 ($17,646,658), divided by the Company's projected Idaho
3 jurisdictional sales of 13,172,433 NWh which results in a

4 rate of (0.1340) cents per kWh (-$17,646,658 / 13,172,433 =
5 -$1.340/MWh = -0.1340 cents/kWh).
6 Q. What is this year's True-Up of the True-Up
7 rate?

E:] A. The Company collected more than quantified in
9 this year's PCA True-Up Balance by ($5,165,169), as shown
10 on row 109 of the deferral expense report. The True-Up of
11 the True-Up rate is calculated by dividing ($5,165,169) by
12 the projected Idaho jurisdictional sales of 13,172,433 MWh,
13 which results in a rate of (0.0392) cents per kWh

14 (-$5,165,169 / 13,172,433 = -$0.392/MWh = -0.0392
15 cents/kWh) . As was the case for the True-Up value, the
16 True-Up of the True-Up is a benefit to customers this year.

17
Q. Please explain the combined effect of the
18 True-Up and the True-Up of the True-Up in this year's PCA.

19 A. The $17.6 million associated with the True-Up
20 and the $5.2 million associated with the True-Up of the
21 True-Up represent a $22.8 million benefit for customers.
22 This benefit in large part reflects that actual net power
23 supply expenses for the 2011/2012 PCA year were less than
24 forecast. This can be attributed to a number of factors
25 including better than forecasted stream flow conditions.
WRIGHT, DI 17
Idaho Power Company
1 If not for the benefits associated with the True-Up and the
2 True-Up of the True-Up, the total 2012 PCA would have been
3 $70.3 million ($67.2 million on an Idaho jurisdictional
4 basis), with $66.7 million of that amount related to PURPA
5 expenses.
6
Q. Does the quantified True-Up rate include the
7 sales of Renewable Energy Certificates ("RECs") and Sulfur
8 Dioxide ("SO2") proceeds?

9 A. Yes. The RECs and SO2 proceeds are included
10 in the Company's deferral expense report, included as
11 Exhibit No. 1 on lines 37 and 38. Order No. 32002 approved
12 on June 11, 2010, approved the Company's REC Management
13 Plan, which passes the customers share of REC benefits back
14 to the customer through the PCA. Order No. 32434 approved
15 on January 12, 2012, directed the Company to pass SO2
16 proceeds through the PCA to help offset the Company's PCA
17 deferral balance.

18 V. PCA TREATMENT OF REVENUE SHARING

19
Q. Based upon the quantification presented by Mr.
20 Matthew T. Larkin's Direct Testimony filed in Case No. IPC-
21 E-12-13, what is the amount of revenue sharing benefits
22 that the Company proposes to pass on to customers through
23 this year's PCA?
24
25
WRIGHT, DI 18
Idaho Power Company
1 A. As quantified in Case No. IPC-E-12-13, the
2 Company proposes to pass along revenue sharing benefits of
3 $27,098,897 to customers through this year's PCA.
4 Q. How has the Company incorporated this refund
5 into the PCA rate?
6 A. As detailed in the "Rate Design" section in
7 the Company's filing in Case No. IPC-E-12-13, the Company
8 plans to apportion the revenue sharing benefits based on
9 each class's proportion of test year base revenues. All
10 classes of customers will receive.revenue sharing benefits
11 in the form of a volumetric rate, with the exception of the
12 Company's special contract customers. The Company's
13 special contract customers will receive 12 equal monthly
14 payments over the 2012/2013 PCA year. Exhibit No. 2,
15 column A shows the annual benefits for all customers, while
16 column B shows the cents per kWh rate for the class's that
17 will receive revenue sharing amounts in the form of a
l volumetric rate.
19 VI. PCA RATE DETERMINATION
20 Q. What is the resulting PCA rate when you
21 combine all of the PCA components described previously?
22 A. The Company's PCA rate for the 2012/2013 PCA
23 year is detailed in Exhibit No. 2, column C. The uniform
24 PCA rate is comprised of (1) the 0.5099 cents per kWh
25 adjustment for the 2012/2013 projected power cost of
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Idaho Power Company
1 serving firm loads, under the current PCA methodology and
2 95 percent sharing, (2) the (0.1340) cents per kWh for the
3 2011/2012 True-Up portion of the PCA, and (3) the (0.0392)
4 cents per kWh for the True-Up of the True-Up. The sum of
5 these three components results in a 0.3367 cents per kWh
6 charge for all rate classes.
7 In addition to the uniform PCA rate, each rate class
8 is assigned a portion of the $27.1 million of revenue
9 sharing proposed in Case No. IPC-E-12-13. When this amount
10 is combined with the uniform PCA rate, each class will
11 receive a different PCA rate. The final PCA rate,
12 including revenue sharing, is listed by rate schedule in
13 column D of Exhibit No. 2.
14 Q. Have you calculated the expected PCA revenue
15 using the PCA rates described above?
16 A. Yes. The Company would expect to collect
17 $44.4 million through the uniform PCA rate using the
18 approved base power supply expenses approved in Order Nos.
19 31042 and 32426. This represents $43.0 million of
20 incremental revenues above the $1.4 million associated with
21 the current PCA rate. When the uniform PCA rate is
22 combined with the additional $27.1 million in revenue
23 sharing, the Company would expect to collect an incremental
24 amount of $15.9 million, through the final combined PCA
25 rates.
WRIGHT, DI 20
Idaho Power Company

1
Q. What is the revenue impact of the requested
2 PCA rate combined with the revenue sharing rates when
3 compared to the PCA rate currently in effect?

4 A. Attachment No. 3 to the Application provides a
5 detailed description of the overall revenue impact of this
6 filing on each customer class. As shown on Attachment No.
7 3, applying the requested PCA rates to expected customer
8 loads for June 2012 through May 2013 test year results in a
9 PCA increase of $15.9 million.

10 Q. Is there anything else worth mentioning
11 regarding this year's PCA collections?

12 A. Yes. It is worth mentioning that the PCA line
13 item on customers' bills will include the Fixed Cost
14 Adjustment ("FCA") amount that was approved per Order No.
15 32505 on March 30, 2012. Previously, the FCA amounts were
16 included in the "Energy Efficiency Services" line item on a
17 customer's bill.

18 Q. Should the Commission approve the Company's
19 computation of the PCA rates?

20 A. Yes. The Commission should approve the
21 Company's computation of the PCA rates. The calculation of
22 the PCA rates follows the methodology that was approved in

23 Order Nos. 30715, 30978, 31042, 32424, and 32426.

24
Q. Does this conclude your testimony?

25 A. Yes.

WRIGHT, DI 21
Idaho Power Company