20241127Lance Kaufman Rebuttal_Redacted.pdf

RECEIVED
Wednesday, November 27, 2024
IDAHO PUBLIC
UTILITIES COMMISSION
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION CASE NO. IPC-E-24-07
OF IDAHO POWER COMPANY TO
INCREASE RATES FOR ELECTRIC
SERVICE TO RECOVER COSTS
ASSOCIATED WITH
INCREMENTAL CAPITAL
INVESTMENTS AND CERTAIN
ONGOING OPERATIONS AND
MAINTENANCE EXPENSES
INTERVENOR
IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.
REBUTTAL TESTIMONY OF
LANCE D. KAUFMAN, Ph.D.
November 27, 2024

TABLE OF CONTENTS
IDAHO POWER'S GENERAL RATE CASE
Case No. IPC-E-24-07
Rebuttal Testimony of Lance D. Kaufman, Ph.D.
I. Introduction and Summary.............................................................................................................. I
II. Cost of Service and Rate Spread..................................................................................................... I
EXHIBIT LIST
Exhibit 207 Discovery Responses.....................................................................................................
Page i

1 I. INTRODUCTION AND SUMMARY
2 Q. PLEASE STATE YOUR NAME AND OCCUPATION.
3 A. My name is Lance D. Kaufman. I am a consultant representing utility customers before state
4 public utility commissions in the Northwest and Intermountain West. My witness qualification
5 statement can be found at Exhibit 201.
6 Q. PLEASE IDENTIFY THE PARTY ON WHOSE BEHALF YOU ARE TESTIFYING.
7 A. I am testifying on behalf of the Idaho Irrigation Pumpers Association, Inc. ("IIPA"). IIPA is a
8 non-profit trade association whose members are irrigation energy users in the Idaho, including
9 customers receiving electric services from Idaho Power Company. ("IPC" or"Company).
10 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
11 A. I provide response testimony on the following items:
12 • Cost of service;
13 • Rate spread;
14 Q. PLEASE SUMMARIZE YOUR RECOMMENDATIONS.
15 A. I make the following recommendations:
16 • Use January, July,November, and December when calculating 4CP for CCOS models.
17
18 II. COST OF SERVICE AND RATE SPREAD
19 Q. WHAT ISSUE DOES FEA RAISE REGARDING IPC'S CLASS COST OF SERVICE?
20 A. IPC's model uses a"4CP/12CP" allocation method for fixed generation costs. Under IPC's
21 method the fixed cost of peaking generation are assigned using coincident peak demand in
22 June through September, and base generation costs are assigned using 12 month coincident
Case No. IPC-E-24-07 Kaufman, L. (Di-Reb) 1
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I peaks. FEA argues that IPC's Class Cost of Service ("CCOS")model should weigh summer
2 months more heavily than the 4CP/12CP method does. FEA recommends considering a
3 average and excess ("AED") allocation based on June through September coincident peaks
4 when evaluating the range of revenue spread.' However, FEA later recommends that the
5 actual spread be based on IPC's filed cost study.2
6 Q. CAN YOU CLARIFY THE APPARENT MISMATCH BETWEEN FEA'S
7 RECOMMENDATION TO USE AN AED ALLOCATION AND FEA'S PROPOSED
8 RATE SPREAD BASED ON IPC'S FILED COOS?
9 A. The conclusion in the COSS section of FEA's testimony is that if FEA's AED model is given
10 some weight in this case, then it"serves to justify a broader cap- floor band for determination
11 of the class revenue spread." This clarifies that the purpose of FEA's AED analysis is not
12 intended to establish a more accurate COSS, but to support FEA's recommendation of a
13 different cap and floor. In fact, FEA does not provide an AED based CCOS that reflects
14 revenues and costs in this case.
15 Q. IS FEA CORRECT THAT AN AED MODEL JUSTIFIES A BROADER CAP AND
16 FLOOR BAND?
17 A. No, FEA's conclusion is faulty and does not follow FEA's analysis. FEA does not offer an
18 explanation that links it's analysis of the AED to FEA's conclusion that a broader band is
19 warranted. FEA's analysis simply shows that CCOS results are highly sensitive to model
20 assumptions. This sensitivity indicates that smaller bands, rather than larger bands are
21 warranted because it highlights the imprecise nature of cost of service studies.
' Direct Testimony of Larry Blank,page 14:14-17.
2 Direct Testimony of Larry Blank,page 21:1-3.
Case No. IPC-E-24-07 Kaufman, L. (Di-Reb) 2
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I Q. DO YOU AGREE WITH FEA'S ASSUMPTION THAT THE CCOS MODEL SHOULD
2 PLACE GREATER WEIGHT ON SUMMER DEMAND?
3 A. No, while IPC is currently summer peaking, IPC's capacity shortfalls will predominantly occur
4 in the winter in the future. This is because IPC's solar and battery resources provide little
5 capacity value during winter months. IPC's difficulty in service winter capacity is apparent
6 when examining loss of load probability, market prices, and resource effective load carrying
7 capability ("ELCC")
8 Q. FEA POINTS TO IPC'S MONTHLY SYSTEM PEAK DEMAND AS EVIDENCE
9 THAT ALLOCATIONS SHOULD BE MORE HEAVILIY WEIGTED ON SUMMER
10 MONTHS. DO YOU AGREE WITH FEA'S ANALYSIS?
11 A. No, FEA's analysis fails to account for the low winter capacity contribution of IPC's new
12 resources. If IPC's peak demand is converted into required nameplate capacity, IPC's winter
13 months require more nameplate capacity than summer months.
14 Q. HOW DO YOU CONVERT DEMAND INTO REQURIED NAMEPLATE CAPACITY?
15 A. A standard measure of resource capacity contribution is Effective Load Carrying Capability
16 ("ELCC"). ELCC is a common measure of a resources ability to serve capacity needs. ELCC is
17 expressed as the percentage of nameplate capacity that reliably serves capacity needs. For
18 example, if a resource has an ELCC of 30 percent, 100 MW of nameplate capacity of the
19 resource reliably serves 30 MW of demand. Many resources have different summer and winter
20 ELCC. The nameplate capacity required to serve monthly peak demand is calculated as the
21 peak demand divided by the ELCC. The table below illustrates IPC's nameplate capacity need
22 when winter resources have an ELCC of 50 percent and summer resources have an ELCC of
23 100 percent.
Case No. IPC-E-24-07 Kaufman, L. (Di-Reb) 3
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I Table 1: Nameplate Capacity Required to Meet Coincident Peak
Nameplate
Capacity Percent of
System Peak ELCC Required Maximum
January 2,219,506 50% 4,439,012 92%
February 2,128,273 50% 4,256,546 89%
March 2,153,910 100% 2,153,910 45%
April 1,714,832 100% 1,714,832 36%
May 2,455,950 100% 2,455,950 51%
June 3,496,120 100% 3,496,120 73%
July 3,224,178 100% 3,224,178 67%
August 3,071,846 100% 3,071,846 64%
September 2,995,520 100% 2,995,520 62%
October 1,851,866 100% 1,851,866 39%
November 2,043,833 50% 4,087,666 85%
2 December 2,402,388 50% 4,804,776 100%
3 Q. WHAT EVIDECNE IS THERE THAT WINTER ELCC IS LOWER THAN SUMMER
4 ELCC?
5 A. IPC is meeting capacity needs with solar and storage resources. These resources have low
6 winter capacity because solar production is low in the winter and storage durations are shorter
7 than consecutive hours of winter capacity need. This means that winter capacity needs often
8 exceed the storage duration. IPC does not report ELCC by month in its IRP. However, Portland
9 General Electric, a geographically proximal utility, does report ELCC by season and illustrates
10 the seasonal ELCC differences for Solar with Battery Storage resources. Summer ELCC is 2 to
11 4 times the winter ELCC depending on penetration.
Case No. IPC-E-24-07 Kaufman, L. (Di-Reb) 4
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1 Figure 1: Portland General Electric Summer Solar with Storage ELCC
100% —McMinnville 1:1
---McMinnville 1:1 CF 200
80%
McMinnville 2:1
e
e 60%
a - -
e McMinnville 2:1 CF 200
a ++•
•
`0 _ CV 1:1 Firm
0 _ ++•�
u 20% - '"`�. CV 1:1 CF200
j
W
0% CV 2:1 Firm
O O O O O O O O O O O O O O O O O O O O
O O O O O O O O O O O O O O O O O O O O
N M V N O r` 00 P O N n < Vf .p r. O 0 O
ri -CV 2:1 CF200
Nameplate MW added
2
3 Figure 2: Portland General Electric Winter Solar with Storage ELCC
—McMinnville 1:1
SO
-McMinnville 1:1 CF 200
40% McMinnville 2:1
e
C
E 30% �` McMinnville 2:1 CF 200
0 20% -- --_--- ��------------------- -- - CV 1.1 Firm
CV 1:1 CF200
w 10%
CV 2:1 Firm
0%
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 CV 2:1 CF200
N N1 V N O n m O O N e•f O N O n N 0 O
Nameplate MW added
4
5 Q. IPC HAS MATERIAL THERMAL AND HYDRO RESOURCES. DOES TABLE 1
6 ACCOUNT FOR IPC'S EXISTING PORTFOLIO?
7 A. No, Table 1 is primarily illustrative, however it is a reasonable representation of peak needs
8 when on considers incremental resource needs, because IPC's incremental resource
Case No. IPC-E-24-07 Kaufman, L. (Di-Reb) 5
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I acquisitions are solar and battery resources. Incremental costs are appropriate to consider if the
2 Commission wants to send appropriate price signals to customers. However, the concept
3 illustrated in table 1, namely that peak load is not the only factor informing the months driving
4 capacity need. A measure that accounts for IPC's existing portfolio is Loss of Load Probability
5 ("LOLP") and Loss of Load Expectation("LOLE"). These measures also indicate that IPC's
6 winter demand is driving capacity additions.
7 Q. WHAT IS LOSS OF LOAD PROBABILITY?
8 A. LOLP is the likelihood of the system load exceeding the available generating capacity during a
9 given time period.3 IPC acquires capacity resources sufficient to meet a threshold loss of load
10 probability.4 The months that IPC experiences LOLP provide an indication of the months
I I where IPC experiences capacity shortfalls. LOLE is a related measure calculated as the daily
12 maximum of hourly LOLP summed across a given time period, such as all days in a month.
13 Q. WHAT MONTHS DOES IPC EXPECT TO EXPERIENCE THE MAJORITY OF ITS
14 LOSS OF LOAD EXPECTATION?
15 A. IPC is transitioning from experiencing loss of load in summer and winter months to
16 experiencing loss of load in only winter months. The table below provides IPC's share of
17 LOLP by month from 2025 to 2034. In 2025 IPC's LOLE occurs primarily in July, August,
18 November, and December. In 2026 half of IPC's LOLE occurs in winter months. However, by
19 2032 99 percent of IPC's LOLE occurs from November to February.
3 Idaho Power 2023 Integrated Resource Plan—Appendix C page 89.
4 Idaho Power 2023 Integrated Resource Plan page 2.
Case No. IPC-E-24-07 Kaufman, L. (Di-Reb) 6
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I Table 2: Idaho Power Company's Future Loss of Load Expectations
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 Average
January 1% 12% 7% 7% 12% 32% 37% 47% 48% 50% 25%
February 0% 3% 0% 0% 1% 2% 2% 1% 2% 2% 1%
March 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%
April 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%
May 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%
June 2% 2% 4% 3% 1% 0% 0% 0% 0% 0% 1%
July 66% 43% 44% 28% 9% 3% 3% 1% 1% 1% 20%
August 19% 7% 14% 8% 3% 1% 1% 0% 0% 0% 5%
September 2% 1% 2% 1% 0% 0% 0% 0% 0% 0% 1%
October 1% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%
November 5% 15% 12% 22% 35% 24% 21% 13% 13% 13% 17%
2 December 4% 17% 17% 31% 38% 38% 36% 37% 37% 35% 29%
3 Q. HOW DO THESE LOLE RESULTS DIFFER FROM THE RESULTS REPORTED BY
4 FEA?
5 A. FEA points to IPC's LOLE to support it's assertion that greater weight should be placed on
6 summer months when allocating costs.6 However, FEA's analysis has two serious flaws: FEA
7 does not report the LOLE in winter months, and FEA does not report the LOLE for future
8 years. FEA's analysis is based on 2025 LOLE.' If both winter and summer months are
9 considered, the LOLE in November and December 2025 are more than double that of June and
10 September. Thus, the 2025 LOLE supports a conclusion that winter months have greater
11 capacity needs than the shoulder summer months of June and September.
12 While the 2025 LOLE is informative, a long-term look at LOLE is more appropriate for
13 allocating costs and providing accurate price signals to customers. In 2026 47 percent of IPC's
14 LOLE occurs in winter months. The growth of IPC's industrial load, the declining winter
5 Calculated from IPC's response to IIPA Data Request 2-12 Attachment 1.
6 Direct Testimony of Larry Blank,page 10:13-21.
7 Exh.207 IPC's response to IIPA Request for Production 3-7.
Case No. IPC-E-24-07 Kaufman, L. (Di-Reb) 7
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I capacity value of solar and battery resources, and the closure of coal facilities all coincide to
2 drive IPC's LOLE share from an equal split of summer and winter need in 2026 to a 99 percent
3 share in winter months by 2032. This is a very strong indication that winter capacity needs are
4 driving capacity costs.
5 Q. IF ONLY LOLE IS CONSIDERED WHEN SELECTING MONTHS FOR
6 ALLOCATING CAPACITY COSTS,WHAT MONTHS SHOULD BE USED?
7 A. IPC's LOLE supports the use of January, July,November, and December when allocating
8 capacity costs rather than June through September. This is appropriate because these months
9 have the four highest LOLE in 2026 and while the July's share of LOLE declines to I percent,
10 including July appropriately balances short term and long term expectations.
11 Q. CAN MARKET PRICES INFORM CAPACITY COSTS AND NEEDS?
12 A. Yes, prices are correlated with regional demand and therefore provide an indication of the
13 months where regions are capacity constrained.
14 Q. WHAT WERE THE DAY AHEAD ENERGY PRICES FOR THE MARKETS THAT
15 IPC PARTICIPATES IN FROM JANURAY, 2022 TO PRESENT?
16 A. IPC participates in the Mid-Columbia, Palo-Verde, and Mead energy markets. The table below
17 provides the average day ahead high load hour market price from 2022 to present for these
18 markets. At all three markets the highest priced month is December. The months in the top
19 quartile are January, August, September, and December. The months with prices above
20 average are January, July, August, September, and December. All three of these markets
21 require significant transmission to access.
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I Confidential Table 3: Day Ahead Market Energy Prices from 2022 to Present'
2
3
4 Q. WHAT MARKET PRICE MEASURE IS MORE SPECIFIC TO IDAHO POWER'S
5 SERVICE TERRITORY?
6 A. Ail alternative pricuig measure that accounts for transmission constraints is the Western
7 Energy Imbalance Market Load Aggregation Point("LAP")prices for IPC. This measure
8 reflects transmission constraints and local load and resources. The table below provides IPC's
9 heavy load hour LAP price from January, 2022 to present. The highest priced month is
10 December. The months uu the top quartile of prices are January,November, and December.
11 The months where price exceeds average price are January, October,November, and
12 December. The price of the 99'percentile of each month are reported in the"Top Hours"
13 column of the table below. The 99'percentile indicates that January, July, and December are
14 the most constrained months.
8 Calculated from IPC's response to IIPA Data Request 2-2 Confidential Attaclunent.
Case No. IPC-E-24-07 Kaufman, L. (Di-Reb) 9
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I Table 4: Idaho Power Company's Locational Average Price9
HLH Average Top Hours
January 97 629
February 48 147
March 44 127
April 42 128
May 24 102
June 27 91
July 56 230
August 56 181
September 56 184
October 62 163
November 71 160
December 488
75th Percentile 69 219
2 Average 61 219
3 Q. IF ONLY MARKET PRICES ARE CONSIDERED WHEN SELECTING MONTHS
4 FOR ALLOCATING CAPACITY COSTS,WHAT MONTHS SHOULD BE USED?
5 A. All four market price measures considered indicate December is the highest cost month and
6 that January is above cost. Regional markets, which don't account for transmission, indicate
7 July through September are high cost, while the EIM LAP price, which does accounts for
8 transmission constraints, indicates July through September have below average costs. Given
9 the inconsistency in results I recommend placing primary consideration on the top 1 percentile
10 of monthly LAP prices. This measure accounts for transmission constraints and reflects the
11 most constrained hours of each month. If only market prices are considered, capacity costs
12 should be allocated based on coincident peak demand in January, July, and December.
9 Calculated from IPC's response to IIPA Data Request 2-2 Confidential Attachment.
Case No. IPC-E-24-07 Kaufman, L. (Di-Reb) 10
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I Q. WHAT MONTHS DOES IPC EXPERIENCE THE HIGHEST NET POWER SUPPLY
2 EXPENSE IN?
3 A. IPC's monthly net power supply expense from 2020 to present is provided below. The highest
4 cost month is December, followed by July and November.
5 Table 5: Idaho Power Company's Locational Average Pricelo
$/M W h
January 39
February 31
March 27
April 25
May 24
June 33
July 43
August 36
September 26
October 33
November
December ma
75th Percentile 41
6 Average 34
7 Q. IF ONLY NET POWER SUPPLY EXPENSES ARE CONSIDERED WHEN
8 SELECTING MONTHS FOR ALLOCATING CAPACITY COSTS,WHAT MONTHS
9 SHOULD BE USED?
10 A. Net Power Supply Expense is highest in July,November, and December. If NPSE is treated as
11 a measure of capacity constraint, costs should be allocated based on coincident peak demand in
12 July,November, and December.
10 Calculated from IPC's response to IIPA Data Request 2-3 Attachment.
Case No. IPC-E-24-07 Kaufman, L. (Di-Reb) 11
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I Q. IF IPC'S MONTHLY NAMEPLATE CAPACITY NEED,LOLE, MARKET PRICING,
2 AND POWER COSTS ARE CONSIDERED WHOLISTICALLY, WHAT MONTHS
3 SHOULD BE GIVEN WEIGHT WHEN CONSIDERING ALLOCATING IPC'S
4 CAPACITY COSTS?
5 A. January and December have the highest capacity need and cost across all these measures. July
6 and November have a reduced but still material capacity need. These four months should be
7 given the greatest weight when allocating generation costs.
8 Q. HOW DOES FEA'S AED CCOS MODEL CHANGE WHEN YOUR RECOMMENDED
9 MONTHS ARE USED FOR THE 4CP COMPONENT?
10 A. The table below updates FEA's CCOS models 1 to reflect January, July,November, and
11 December. Note that FEA's original model indicates that a revenue decrease was warranted for
12 DOE, however when the correct months are used for the 4CP FEA's AED model indicates that
13 a revenue increase is warranted for DOE. This confirms that CCOS models are highly
14 sensitive to inputs, and that the Commission should issue a uniform rate increase for all
15 schedules. This is consistent with previous Commission findings that CCOS studies are
16 imperfect, subjective, and prone to errors."
11 Direct Testimony of Larry Blank,page 17 Table 2.
12 ,All cost-of-service studies suffer from common defects. They attempt to reduce a dynamic system to a static one for
purposes of study and thereby omit important considerations,and their results vary according to their originators'
subjective assumptions underlying their objective arithmetic.We do not belittle the value of cost-of-service studies for rate
setting purposes.But the limitations of the studies should be stated so that the results can be used with an awareness of
their limitations. ... we recognize the subjective assumptions underlying all cost-of-service studies and the inevitable errors
in any undertaking of such magnitude."IPUC Order No.21365. The IPUC has also found that"A cost-of-service study is
an imperfect tool for assigning system and service costs to customer classes.The Commission has previously recognized
that cost-of-service modeling is not an exact science,and that while most generally accepted cost-of-service methods are
based on similar principles,they may lead to disparate results and recommendations for class revenue allocation.Thus,the
Commission has repeatedly emphasized that a cost-of-service study is not a perfect tool for assigning system and service
costs to customer classes."IPUC Order No. 33757 at 27.
Case No. IPC-E-24-07 Kaufman, L. (Di-Reb) 12
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I Table 6: Update to FEA CCOS AED Model
IPC's FEA's IIPA's
4CP/12CP AED-4CP AED-4CP
Cost-Based Cost-Based Cost-Based
Revenue Revenue Revenue
Rate Class Change Change Change
Residential 10.49% 9.54% 18.1%
Residential On-Site Generation 51.56% 46.77% 79.3%
Small General Service 13.27% 8.63% 16.8%
Small General Service On-Site Generation 110.64% 94.26% 140.0%
Large General Service Secondary 0.33% -8.03% 0.5%
Large General Service Primary and Trans. -2.57% -11.21% -7.5%
Area Lighting -44.41% -36.68% -36.7%
Large Power Service 5.82% -5.29% 0.7%
Irrigation 19.59% 53.97% -2.5%
Unmetered Service 2.48% -3.11% -3.1%
Street Lighting -24.67% -13.96% -13.9%
Traffic Control Lighting 117.51% 102.61% 103.7%
DOE 7.02% -11.34% 12.9%
Simplot -0.30% 11.02% 9.1%
Micron 7.14% -7.65% -6.98%
2 Total Idaho Retail Jurisdictional Change 8.61% 8.61% 8.61%
3 Q. DOES THE AED MODEL INDICATE THAT IRRIGATION CUSTOMERS SHOULD
4 RECEIVE A HIGHER THAN AVERAGE RATE INCREASE?
5 A. No,FEA's AED model demonstrates that irrigation customers were overallocated costs in the
6 2023 GRC. Irrigation customers received 130 percent of the average increase, while the table
7 above indicates that these customers should have been subjected to the floor of 50 percent of
8 the average rate increase. IPC's CCOS model filed in this case only reflects incremental
9 revenue requirement and cannot remedy the misallocations imbedded in base rates indicated in
10 Table 6.
Case No. IPC-E-24-07 Kaufman, L. (Di-Reb) 13
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I Q. CAN YOU EXPLAIN WHAT IT MEANS THAT IPC'S CCOS MODEL REFLECTS
2 INCREMENTAL REVENUE REQUIREMENT?
3 A. IPC's CCOS model in this case only includes incremental revenues and costs, not all revenues
4 and costs. According to IPC this means that the CCOS study results are "muted".13 However,
5 this is an incorrect characterization of the study because it is not know how the unreported
6 costs and revenues would be allocated if they were included. It is therefore not possible to
7 conclude whether the excluded costs and revenue mute or exaggerate the results of the CCOS
8 study. For example, while the corrected 4CP has reversed the sign of the revenue deficiency
9 for irrigation customers when all costs and revenues are contemplated in Table 6 above, the
10 same correction to IPC's filed model has no material impact on IPC's CCOS results or revenue
11 deficiencies.
12 Q. ARE THERE OTHER PROBLEMS WITH IPC'S PARTIAL APPROACH TO IT'S
13 CCOS MODEL?
14 A. Yes, IPC allocates incremental revenue proportionally to the 2023 GRC revenue. However, I
15 demonstrate in my initial testimony that incremental revenue is not distributed proportionally
16 across classes. This means that IPC's CCOS model is simply erroneous.
17 Q. DOES THIS CONCLUDE YOUR TESTIMONY?
18 A. Yes
13 IPC's response to IIPA's Request for Production 3-5.
Case No. IPC-E-24-07 Kaufman, L. (Di-Reb) 14
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CERTIFICATE OF SERVICE
I HEREBY CERTIFIY that on this 6th day of November, 2024, I served a true, correct
and complete copy of the Idaho Irrigation Pumpers Association, Inc.'s Response Testimony of
Lance D. Kaufman to each of the following, via the method indicated below:
Monica Barrios-Sanchez, Commission Secretary ❑ U.S. Mail
Idaho Public Utilities Commission ❑ Hand Delivered
P.O. Box 83720 ❑ Overnight Mail
Boise, ID 83720-0074 ❑ Telecopy(Fax)
monica.barriossanchezgpuc.idaho.gov ® Electronic Mail (Email)
Chris Burdin ❑ U.S. Mail
Deputy Attorney General ❑ Hand Delivered
Idaho Public Utilities Commission ❑ Overnight Mail
P.O. Box 83720 ❑ Telecopy(Fax)
Boise, ID 83720-0074 ® Electronic Mail (Email)
Chris.burding]2uc.Idaho.gov
Lisa D. Norstrom ❑ U.S. Mail
Donovan E. Walker ❑ Hand Delivered
Megan Goicoechea Allen ❑ Overnight Mail
Idaho Power Company ❑ Telecopy(Fax)
1221 W. Idaho Street (83702) ® Electronic Mail (Email)
PO Box 70
Boise, ID 83707-0070
lnordstromgidahopower.com
dwalker(i�idahopower.com
mgoicoecheaallengidahopower.com
dockets(aidahopower.com
Tim Tatum ❑ U.S. Mail
Connie Aschenbrenner ❑ Hand Delivered
Matt Larkin ❑ Overnight Mail
Idaho Power Company ❑ Telecopy(Fax)
1221 W. Idaho Street(83702) ® Electronic Mail (Email)
PO Box 70
Boise, ID 83707-0070
ttatumgidahopower.com
caschenbrenner(i,idahopower.com
mlarkingidahopower.com
Case No. IPC-E-24-07 Kaufman, L. (Di-Reb) 15
11/27/24 IIPA

Lance Kaufman, Ph.D. ❑ U.S. Mail
Idaho Irrigation Pumpers Association, Inc. ❑ Hand Delivered
2623 NW Bluebell Place ❑ Overnight Mail
Corvallis, OR 97330 ❑ Telecopy(Fax)
lancekae isinsi hg t.com ® Electronic Mail (Email)
Peter J. Richardson ❑ U.S. Mail
Richardson, Adams, PLLC ❑ Hand Delivered
Industrial Customer of Idaho Power ❑ Overnight Mail
515 N. 27th St. ❑ Telecopy(Fax)
P.O. Box 7218 ® Electronic Mail (Email)
Boise, ID 83702
petergrichardsonadams.com
Dr. Don Reading ❑ U.S. Mail
Industrial Customer of Idaho Power ❑ Hand Delivered
280 S. Silverwood Way ❑ Overnight Mail
Eagle, ID 83616 ❑ Telecopy(Fax)
dreading(kmindspring com ® Electronic Mail (Email)
Matthew Nykiel ❑ U.S. Mail
Attorney for Idaho Conservation League ❑ Hand Delivered
710 N. 6th St. ❑ Overnight Mail
Boise, ID 83702 ❑ Telecopy(Fax)
matthew.nykielkgmail.com ® Electronic Mail (Email)
Adrian Gallo, Climate Manager ❑ U.S. Mail
Brad Smith, Program Directore ❑ Hand Delivered
Idaho Conservation League ❑ Overnight Mail
710 N. 6th St. ❑ Telecopy(Fax)
Boise, ID 83702 ® Electronic Mail (Email)
aaagalloA,idahoconservation.org
bsmithkidahoconservation.org
Peter Meier ❑ U.S. Mail
U.S. Department of Energy ❑ Hand Delivered
1000 Independence Ave., S.W. ❑ Overnight Mail
Washington, D.C. 20585 ❑ Telecopy(Fax)
peter.meierkhq.doe._og_v ® Electronic Mail (Email)
Case No. IPC-E-24-07 Kaufman, L. (Di-Reb) 16
11/27/24 IIPA

Emily W. Medlyn ❑ U.S. Mail
U.S. Department of Energy ❑ Hand Delivered
1000 Independence Ave., S.W. ❑ Overnight Mail
Washington, D.C. 20585 ❑ Telecopy(Fax)
Emily.medlynghq.doe.gov ® Electronic Mail (Email)
Jim Swier ❑ U.S. Mail
Micron Technology, Inc. ❑ Hand Delivered
8000 South Federal Way ❑ Overnight Mail
Boise, ID 83707 ❑ Telecopy(Fax)
jswierkmicron.com ® Electronic Mail (Email)
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Case No. IPC-E-24-07 Kaufman, L. (Di-Reb) 17
11/27/24 IIPA

ERIC L. OLSEN
Case No. IPC-E-24-07 Kaufman, L. (Di-Reb) 18
11/27/24 IIPA

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION CASE NO. IPC-E-24-07
OF IDAHO POWER COMPANY TO
INCREASE RATES FOR ELECTRIC EXHIBIT 207
SERVICE TO RECOVER COSTS
ASSOCIATED WITH
INCREMENTAL CAPITAL
INVESTMENTS AND CERTAIN
ONGOING OPERATIONS AND
MAINTENANCE EXPENSES
INTERVENOR
IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.
LANCE D. KAUFMAN, Ph.D. Exhibit 207 Discovery Responses

REQUEST FOR PRODUCTION NO. IIPA 2-2: Please provide the hourly real time
energy prices for each market hub IPC participates in from 2022 to present.
RESPONSE TO REQUEST FOR PRODUCTION NO. IIPA 2-2: Please see the
attached Excel file labeled "Response to IIPA Request No. 2-2 — Attachment" which
includes the hourly Western Energy Imbalance Market ("EIM") Load Aggregation Point
("ELAP") prices for Idaho Power for January 2022—September 2024. The EIM is the real-
time energy market that Idaho Power participates in and the ELAP price is reflective of
the real-time value of energy on Idaho Power's system.
The response to this Request is sponsored by Matthew Larkin, Revenue
Requirement Senior Manager, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
SECOND SET OF DATA REQUESTS- 3

REQUEST FOR PRODUCTION NO. IIPA 2-3: Please provide IPC's actual
system and Idaho jurisdictional net power costs by month from 2020 to present.
RESPONSE TO REQUEST FOR PRODUCTION NO. IIPA 2-3: Please see the
attached Excel file labeled "Response to I IPA Request No. 2-3—Attachment"to be posted
by 9:00 a.m. on October 31, 2024.
The response to this Request is sponsored by Matthew Larkin, Revenue
Requirement Senior Manager, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
SECOND SET OF DATA REQUESTS-4

REQUEST FOR PRODUCTION NO. IIPA 2-4: Please refer to Confidential
Attachment — Response to IIPA Request No. 1-6e.xlsx. Please provide these data for
retail sales by jurisdiction.
RESPONSE TO REQUEST FOR PRODUCTION NO. IIPA 2-4: Please see the
attached file labeled "Response to IIPA Request No. 2-4 —Attachment 1" to be posted by
9:00 a.m. on October 31, 2024, for the retail sales by jurisdiction.
The response to this Request is sponsored by Jordan Prassinos, Load Forecast
Manager and Principal Economist, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
SECOND SET OF DATA REQUESTS- 5

REQUEST FOR PRODUCTION NO. IIPA 2-5: Please provide the day ahead high
load hour and low load hour energy prices for each market hub IPC participates in from
2022 to present.
RESPONSE TO REQUEST FOR PRODUCTION NO. IIPA 2-5: Please see the
confidential attachment labeled "Response to IIPA Request No. 2-5 — Confidential
Attachment" which includes the day-ahead heavy-load ("HL") and light-load ("LL") energy
prices for the Mid-Columbia, Palo Verde and Mead market hubs as published by the
Intercontinental Exchange ("ICE").
The response to this Request is sponsored by Matthew Larkin, Revenue
Requirement Senior Manager, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
SECOND SET OF DATA REQUESTS- 6

REQUEST FOR PRODUCTION NO. IIPA 3-5: Please refer to the Direct
Testimony of Dr. Don Reading page 11 lines 1 to 5.
a. Please provide Schedule 19's COS Index as expressed in Column P of Tatum
Exhibit 4 using the 2023 CCOS, before and after the 2023 GRC rate increase.
b. Please explain the significance of the COS Index.
RESPONSE TO REQUEST FOR PRODUCTION NO. IIPA 3-5: Please see
responses below.
a. The 2023 GRC Settlement Stipulation did not explicitly include a "COS Index."
However, the Company has prepared the file labeled "Attachment — Response to
IIPA 3-5a," which contains the same metric for each customer class for the 2023
GRC Settlement Stipulation. The calculation compares each customer class's mill
rate (i.e., revenue requirement per kWh sales) as a result of the final revenue
allocation compared to the CCOS results. Therefore, a "before and after GRC" is
not a calculation that can be performed as the final results are inherently
embedded in the underlying calculation of the metric. As further described in
subpart (b) to this response, the COS Index in Tatum Exhibit 4 is overstated
towards 1.0 for each customer class due to the calculation being performed on
total revenue requirement rather than just the incremental revenue requirement at
issue in this limited issue rate case.
b. The "COS Index" is a customer class's final revenue allocation ratio relative to the
CCOS results. A customer class with a ratio greater than 1.0 or 100% is being
allocated revenue requirement above the results of the CCOS study, and a ratio
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
THIRD SET OF DATA REQUESTS- 7

less than 1.0 or 100% is being allocated revenue requirement below the results of
the CCOS study.
However, the CCOS study only includes the incremental revenue requirement in
this limited issue rate case. The COS Index illustrated in Tatum Exhibit 4 combines
existing base revenue with the CCOS results for the incremental revenue
requirement. Therefore, the index is muted because each customer class's base
revenue differs from the results of a CCOS study as if it had included all revenue
requirement— not just the incremental revenue requirement.
The response to this Request is sponsored by Grant T. Anderson, Regulatory
Consultant, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
THIRD SET OF DATA REQUESTS- 8

REQUEST FOR PRODUCTION NO. IIPA 3-7: Please refer to the IPC 2023 IRP
Technical Appendix C page 96, LOLE percentage by month.
a. What years do these data represent?
b. Please provide the data referenced in the footnote "January and February are
expected to be as high as November and December for the 2025-2026 winter
season due to forecasted industrial customer load ramps."
c. Please also refer to Response to IIPA Request No. 2-12 - Attachment 1.xlsx Tab
"Test Year 1", which indicates 35 percent of 2024 LOLP occurs in December.
Please explain the difference between test year 1 2024 results and the results in
Appendix C page 96.
d. Please also refer to Response to IIPA Request No. 2-12 attachments 1 and 2.
Please explain the difference between test years.
RESPONSE TO REQUEST FOR PRODUCTION NO. IIPA 3-7:
a. The monthly Loss of Load Expectation ("LOLE") results represent a 2025 load and
resource year. The 2023 Integrated Resource Plan ("IRP") LOLE analysis utilized
six test years reflecting historical data from the years 2017 through 2022.
b. Please see "Response to Request for Production No. IIPA 3-7 Attachment" for the
70th percentile peak load forecast and referenced industrial customer load ramps.
c. In reviewing the referenced Loss of Load Probability ("LOLP") data for test year 1
of 2024, Idaho Power would clarify that 35 percent of LOLP values occur in
January, not December. Generally speaking, as noted in part (a) above, the table
on page 96 of the 2023 IRP reflects the results for a 2025 load and resource year
(not a 2024 load and resource year). Also as stated in part (a) above, the monthly
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
THIRD SET OF DATA REQUESTS- 11