20250815Surrebuttal Testimony CEO - C. White.pdf

RECEIVED
Kelsey Jae (ISB No. 7899) August 15, 2025
Law for Conscious Leadership IDAHO PUBLIC
920 N. Clover Dr. UTILITIES COMMISSION
Boise, ID 83703
Phone: [phone]
[e-mail]
Attorney for Clean Energy Opportunities for Idaho
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO
POWER COMPANY'S
APPLICATION FOR APPROVAL
OF SPECIAL CONTRACT AND CASE NO. IPC-E-24-44
TARIFF SCHEDULE 28 TO
PROVIDE ELECTRIC SERVICE TO
MICRON IDAHO
SEMICONDUCTOR
MANUFACTURING (TRITON) LLC.
SURREBUTTAL TESTIMONY OF COURTNEY WHITE
On Behalf Of
CLEAN ENERGY OPPORTUNITIES FOR IDAHO

I Q: Please state your name, business affiliation, and address.
2 A: Courtney White, Managing Director, Clean Energy Opportunities for Idaho, 3778 N
3 Plantation River Dr Suite 102, Boise, ID 83714.
4 Q: On whose behalf are you testifying in this proceeding?
5 A: Clean Energy Opportunities for Idaho (CEO).
6 Q: Are you the same Courtney White who submitted direct testimony in this proceeding
7 on behalf of CEO?
8 A: Yes.
9 Q: What is the scope of your testimony?
10 A: In my July 30, 2025 direct testimony (Direct), I recommended that a process should be
11 ordered for the purpose of modifying the rate structure in the IPC-E-24-44 Application(Schedule 28)
12 to more accurately reflect the hourly, time-varying nature of cost causation. I have reviewed rebuttal
13 testimony. My Surrebuttal responds to matters raised in rebuttal testimony related to my
14 recommendations regarding a Schedule 28 Time of Use (TOU)rate structure. This testimony refines
15 my recommendations regarding a TOU rate design for energy and modifies my request regarding time-
16 varying rate design for capacity costs. Silence on my part related to other matters presented in this case
17 should not be taken to signify my acceptance of any assertions related to those other matters. The
18 scope of my testimony relates to rate design while my colleague Mr. Heckler's testimony relates to the
19 Micron Fab's share of revenue requirements.
20 Q: How is your testimony organized?
21 A: In Direct, I made proposals regarding a time-varying rate design for energy costs and for
22 capacity costs. Rebuttal comments responded to each separately. My surrebuttal is organized into:
23 I. Rate Design for Energy Costs
24 I1. Rate Design for Capacity Costs
25 III. Recommendations.
26
Case No. IPC-E-24-44 White, C. (Surrebuttal) 2
August 15, 2025 CEO

1 L Rate Design for Energy Costs
2 Q: With regard to energy costs and rate design, briefly summarize the principle for which
3 you are seeking the Commission's support.
4 A: The energy rate for the Micron Fab should more accurately reflect the time-varying nature
5 of energy costs.
6
7 Q: Where does the record stand on this matter in IPC-E-24-44?
8 A: Unopposed. As I posited in Direct, the fact that marginal energy costs vary substantially by
9 hour is well established, thus the flat energy rate proposed for the Micron Fab does not align with cost
10 causation. That assertion remains undisputed in Rebuttal testimony. I recommended that the proposed
11 rate structure in Schedule 28 be modified to more accurately reflect the hourly, time-varying nature of
12 cost causation. As Mr. Anderson stated in Rebuttal (p15), "Idaho Power is not opposed to
13 implementing TOU pricing in concept." In my own words, the Company is unopposed to a time-
14 varying energy rate for the Micron Fab assuming certain conditions which I address later.No other
15 party rebutted the recommendation.
16
17 Q.What justification has been provided as to why the energy rate in Schedule 28 should
18 not reflect the time-varying nature of energy cost causation?
19 A: Rebuttal testimony did not request that the Schedule 28 energy rates should remain flat.
20 In Mr. Anderson's original Direct testimony (p13), he had noted that issues such as "Increased
21 Complexity"and"Limited Load Flexibility" should be weighed. As I addressed in my Direct
22 testimony, I do not see Micron as less able to manage complexity than on-site generators, industrial
23 customers, Brisbie, or any other customer who takes service under time-varying rates. Regarding load
24 shaping, which could be impacted by storage, operational decisions, or other technologies behind the
25 meter, I addressed in my Direct testimony why I do not believe the Commission is in a position to
26 delineate which large customers will or will not have load flexibility over time:
27 As new large load customers are attracted to Idaho, a decision to allow one new large load
28 customer to choose a rate structure that fails to align price signals with the time-varying nature
Case No. IPC-E-24-44 White, C. (Surrebuttal) 3
August 15, 2025 CEO

I of cost causation is a step down a slippery slope.Neither the Commission nor customers can
2 predict with certainty what the costibenefits of load shaping options will be across different
3 customers over the coming decade. What we can do, to the best of our ability and with the most
4 current outlook, is to align price signals with time-varying cost causation so that customers and
5 innovators have the motive and information to pursue opportunities and make accurately
6 informed decisions. (IPC-E-24-44, White Direct, p5)
7
8 Approval of a flat energy rate that is known not to align with cost causation should require
9 compelling evidence as to why that choice better serves public interest. The record in this docket falls
10 far short of providing such evidence.
11
12 Q: With regard to energy costs and rate design, how would you frame the open matter
13 before the Commission?
14 A: Given the above, I believe the open matter is not whether Schedule 28 should be modified
15 but how Schedule 28 should be modified to reflect the time-varying nature of energy costs.
16
17 Q: Can you summarize the conditions asserted in the Company's Rebuttal testimony
18 regarding implementation of time-varying energy rates?
19 A: In Mr. Anderson's words (Rebuttal p15):
20 Idaho Power is not opposed to implementing TOU pricing in concept. However, there is
21 no singular approach that must apply to all customers. A uniform marginal energy
22 pricing structure, such as the one currently proposed, is a reasonable starting point for a
23 large customer with a high and consistent load factor. That said, the Company would
24 not be opposed to a TOU structure, so long as the same underlying data relied upon for
25 the proposed Energy Charge was used to calculate a weighted average by time period
26 for the time periods which are consistent with all other industrial load pursuant to tariff
27 Schedule 19.
28
29 Q: Of those conditions,what is your primary concern?
30 A: The lowest price time period. I would agree with the Company that"no singular approach
31 must apply to all customers."I recommend that a Schedule 28 TOU should not be constrained to
32 existing Schedule 19 time periods. Schedule 19 currently has a 15 hour Off-Peak in Summer and a 12
33 hour Off-Peak in Non Summer. To more accurately reflect current and forward-looking information on
Case No. IPC-E-24-44 White, C. (Surrebuttal) 4
August 15, 2025 CEO

I cost dynamics, and to send a more effective price signal, the lowest price time period in a Schedule 28
2 TOU should reflect that marginal costs during day hours (such as loam to 2pm) are substantially lower
3 than marginal costs at night. I will speak further below to options for addressing the Company's
4 interest in consistency after describing why I believe a low-price time window during day hours is
5 essential.
6 Historically, Idaho Power's TOU rates have focused on discouraging demand for utility-
7 supplied power during high-risk hours. Determination of which hours are high-risk is informed
8 primarily by Loss of Load analyses. Reliability risks tend to be concentrated within certain hours of the
9 day. This has resulted in Off-Peak time periods which cover many hours of day and night. Now cost
10 dynamics are changing. The growth of solar particularly impacts market prices, and the Company's
11 reliance on market purchases is projected to grow. There is a global movement toward rate designs
12 which reflect that certain day hours correspond to exceptionally low marginal costs along with low loss
13 of load risks.
14 For illustration see Figure 1, which shows the pattern of reliability risk and projected market
15 prices across 24 hours in summer, and note how those relate to Schedule 19 time periods.
Case No. IPC-E-24-44 White, C. (Surrebuttal) 5
August 15, 2025 CEO

Figure 1:Schedule 19S proposed summer rates relative to Avg Mid-C Prices(2026-2030) and Loss of Load
Probability(LOLP,secondary axis)by Hour of day for Summer(Jun-Sep)
L%JLr' mvurage
.$�MWhl The existing Schedule 19 Off Peak Time Period is (indicative of capacity cost drivers)
15 hours in Summer(Midnight to 3pm).Marginal
80 costs at night are substantially different than
during early to mid day.A Time Period offering a On Peak
70
dip in rates during day hours is needed. ~
1
Mid Peak
60
w�--' Off Peak
so
ao � ♦ �
Schedule 19Sproposed
♦♦_ ��
30 rates proposed in
20 2025 GRC(for Mid-C Avg Market prices
illustration of Time (indicative of hourly marginal cost pattern)
t0 Periods)
0
7 2 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour ending
Source:8760 Mid-C data,2023IRP Data,sourced from IPC-E-24-23;8760 LOLP data from IPC response to Staff PR 34b,IPC-E-23-14;avg of 6 test years;CEO calc ofaverages;
proposed rates from IPC-E-25-16Application,pdf p62 Schedule 19 Secondary Service Energy Rates
1
2 One can see that—by design -the existing Schedule 19 On-Peak and Mid-Peak periods
3 correlate with reliability risks. I have proposed no change to the On-Peak time period. The chart also
4 illustrates that market prices vary substantially during the 15-hour Off-Peak period in existing
5 Schedule 19 rates. For example, while the reliability risk is similarly nil at both 1 lam and 3am, the
6 marginal cost of energy is markedly different.
7 As another data point, consider that 2024 hourly ELAP prices were negative for roughly 400
8 hours. Of those, 99% occurred when the sun was out.1
9
10 Q: Has the Company's planning process generated evidence that a daytime window could
11 provide a more accurate price signal than the existing Schedule 19 Off-Peak time window?
12 A: Yes. While preparing the 2023 Integrated Resource Plan(IRP), the Company modeled a
13 "Load Flattening" scenario to compare costs if demand shifted from peak hours into lowest demand
'Hourly ELAP prices provided in Exhibit 2 Ellsworth Direct ECR Workpaper,IPC-E-25-15.
Case No. IPC-E-24-44 White, C. (Surrebuttal) 6
August 15, 2025 CEO

I hours. That scenario shifted load to night-time hours and resulted in higher portfolio costs. In the 2025
2 IRP, the Company modeled a"Load Shift" scenario that shifted load out of the 6-1 Opm hours and into
3 the loam—2pm hours in summer. That scenario resulted in lower portfolio costs.
4
5 Q: Can you identify and comment on options to address the Company's interest in
6 consistency between time periods in Schedule 19 and a Schedule 28 TOU?
7 A: Rate structures often balance tradeoffs across accuracy, complexity, stability, consistency,
8 and the effectiveness of price signals. Regarding the definition of time periods for a Schedule 28 TOU
9 rate, the table below summarizes the option which I proposed in more detail in Direct(row A option),
10 introduces an optional approach modifying Schedule 19 time periods (row B), and acknowledges the
11 option (row C) of using the existing Schedule 19 time periods.
Options How different than Sched 19? Comments
A)White Direct On-Peak is same.
3 Periods/Season Lowest price period is narrower Prioritizes accuracy and effectiveness of price
• On-Peak (-10am-2pm) signals
• "Base"price Remaining hours are combined Is partially consistent with Schedule 19 time
• Super Off-Peak rather than split into Off-Peak& periods.
Mid-Peak
B)Modified Sch 19 Adds the complexity of 4 rather than 3 time
4 Periods/Season: Same as Sched 19 yet splits the periods,though serves the Company's interest
• On-Peak existing 12&15 hour Off-Peak in consistency with Schedule 19 while also
• Mid-Peak windows into Off-Peak and Super providing a more accurate price signal than
• Off-Peak Off-Peak. current Off-Peak time periods.
• Super Off-Peak
C)Existing Sch 19
Periods/Season Constraining Schedule 28 time periods to be
3 P
• eri Peak No change. identical to Schedule 19 removes the potential
for a more accurate low-cost time period
• Mid-Peak during day hours&more effective price signal
• Off-Peak
12
13 I oppose using an Off-Peak time period identical to that in Schedule 19. As quoted earlier,the
14 Company's Rebuttal posits (pl5), "there is no singular approach that must apply to all customers." For
15 a new tariff and any future megaload, I believe the most current and forward-looking information
16 should inform the TOU time periods, and that options (A) and(B) offer a reasonable level of
17 consistency with Schedule 19.
Case No. IPC-E-24-44 White, C. (Surrebuttal) 7
August 15, 2025 CEO

I Q: What do you recommend regarding time periods for a Schedule 28 TOU rate?
2 A: I would recommend the 3 time periods per season as I proposed in my Direct testimony and
3 summarized as (A) above. I could support option (B) above - the same time periods as Schedule 19 yet
4 with the addition of a Super Off-Peak period within the existing Schedule 19 Off-Peak period for each
5 season. I am open to modifications to the specific time periods for the Super Off-Peak period provided
6 that, as is my highest priority, the lowest price time period should occur during day hours. The
7 definition of that time period should be informed by market price forecasts, and as such implies the
8 lowest price time period should occur during day hours.
9 In Direct, I proposed that the lowest price time period be 1 Oam to 2pm year-round. As an
10 example of potential modifications, others may view that a seasonal refinement of the lowest price
1 1 time period is more beneficial than the consistency of a year-round time period.
12
13 IL Rate Design for Capacity Costs
14 Q: With regard to capacity costs and rate design, briefly summarize what you requested
15 in Direct testimony.
16 A: I asked that the proposed rate structure in Schedule 28 should not be approved, and that a
17 process should be ordered for modifying the rate structure to more accurately reflect the hourly, time-
18 varying nature of cost causation. In this section I will address that request as it relates to capacity costs.
19
20 Q: Where does the record stand on this matter in IPC-E-24-44?
21 A: The rate structure proposed in Schedule 28 does not adequately provide price signals
22 aligned with the time-varying nature of capacity cost causation. My Direct posited that capacity cost
23 causation is time varying in nature. As an alternative to the monthly billing Demand Charge proposed
24 in the Application, I proposed that generation and transmission capacity costs should be recovered via
25 volumetric charges associated with hours of relatively higher risk and proposed a strawman rate design
26 to do so. I suggested a ratio be applied to spread a higher portion of costs to load occurring during
Case No. IPC-E-24-44 White, C. (Surrebuttal) 8
August 15, 2025 CEO

I highest risk hours, a lower portion across mid risk hours, and none across hours which are not capacity
2 constrained. The only rebuttal to my recommendation was that of the Company,which opposed and
3 raised concerns related to the recovery of capacity costs via volumetric rates. I will address those
4 below.
5 In sum, I believe that there is a strong case supporting the need for rate design to align with the
6 time varying nature of capacity cost causation and to provide price signals which mitigate future
7 capacity costs. The Company opposes my proposal for how to accomplish that. No other alternative
8 has been proposed to improve on the price signal related to the time-varying nature of generation and
9 transmission capacity.
10
11 Q: Why do you believe that a rate design reflecting the time-varying nature of capacity
12 costs is more challenging to resolve than one for energy costs?
13 A: I would highlight 2 challenges regarding rate design to reflect the time-varying nature of
14 capacity cost causation:
15 1) Rates recover actual costs, price signals mitigate future costs. With regard to capacity
16 costs, shifting load out of high-risk hours impacts the need for future additional resources though may
17 not result in system savings during the current year. Yet there is value when a customer causes future
18 system costs to be less than otherwise would occur, and there's a cost when a customer causes future
19 system costs to be more than otherwise would occur. It is not a simple question to resolve the fairness
20 of who pays and who benefits, though the public interest in affordability requires we pursue rather than
21 abandon opportunities to mitigate future costs.
22 2) Priorities. An investor-owned utility, in general, is not equally motivated to propose rate
23 designs which mitigate future costs as it is to ensure the recovery of costs. The public relies on the
24 Commission and Staff to ensure that opportunities to mitigate future costs are adequately pursued.
25
26
Case No. IPC-E-24-44 White, C. (Surrebuttal) 9
August 15, 2025 CEO

I Q: Is your interest in aligning capacity-related price signals with the time-varying nature
2 of capacity costs specific only to the Micron Fab?
3 A: No. My testimony in this docket is consistent with a general concern that rate designs put
4 before the Commission should reflect time-varying costs and should better allow for the potential that
5 demand-side behaviors impact future costs.
6 From a principle driven perspective, the regulatory process should seek to align who pays with
7 both who causes costs as well as who benefits from those costs. For example, in general, it is
8 appropriate for a customer to pay relatively more or less if they benefit relatively more or less from
9 sunk capacity costs. The Company reiterates a concern that when a customer lowers their bill in a
10 manner related to capacity costs, a fixed cost burden is unfairly shifted to other customers. Yet all
11 fixed costs are variable in the long run. If a customer causes future capacity costs that otherwise would
12 not occur,paying a higher bill does not equate to unfair cost shifting. Correspondingly, customers in
13 general should be given reasonable opportunity to reduce their own bill when they mitigate future
14 system costs.
15 Rather than pursue fairness by seeking to disallow any one customer from the opportunity to
16 save money when they mitigate system costs, I recommend that the Commission pursue fairness by
17 allowing more customers to take service under tariffs with price signals which better align with the
18 mitigation of future costs. This addresses not only a concern for fairness but also for long-term
19 affordability.
20
21 Q: Are there challenges specific to this docket which impact the degree to which rate
22 design alternatives for capacity related costs are fully explored?
23 A: Yes. The attention of the Commission, Staff, and parties is focused on matters related to the
24 determination of revenue requirements and specific to the Micron Fab. The complexity and magnitude
25 of those matters make it more challenging for the Commission to also fully consider substantial
26 changes to the proposed rate structure for capacity costs such as the alternative to demand charges
27 proposed in my Direct testimony.
Case No. IPC-E-24-44 White, C. (Surrebuttal) 10
August 15, 2025 CEO

I Meanwhile, Rebuttal testimony reflects a receptiveness to time-varying energy rates. Given that
2 and the challenges specific to this docket, I have modified my requests in order to focus on moving
3 forward with time-varying energy rates (see Section III Recommendations further below). Regarding
4 capacity costs, I am proposing an alternative to partially address the concern that Schedule 28 provides
5 inadequate capacity-related price si naregarding the time-varyng nature of capacity costs.
6
7 Q: Regarding rate design and capacity costs,what alternative approach are you
8 recommending to partially alleviate the concerns you raise with demand charges?
9 A: Though I am opposed to demand charges as a price signal, shifting a portion of the costs
10 currently in monthly Demand Charges into Energy Rates would lessen the magnitude of the problem
11 and would partially correct an inaccurate assumption underlying the calculation of those demand
12 charges: that fixed costs are unrelated to energy benefits.
13 The IPC-E-24-44 Application proposes a Billing Demand Charge based on Class Cost-of-
14 Service (CCOS) for the calculation of capacity costs (p7). The Company's approach to CCOS assumes
15 that Transmission and Generation Plant costs are used 100% for demand purposes, and that only Fuel
16 and Purchased Power are Energy related.2 I.e., the calculation that is extrapolated into a Demand
17 Charge for Schedule 28 assumes that no energy-related benefits flow from Transmission or Generation
18 Plant costs. Micron's Rebuttal testimony exemplifies the inaccuracy of that assumption.
19 In his Rebuttal, Mr. Gorman describes that-under the ESA pricing terms - Micron pays
20 its share of system resource capacity costs via demand charges, "However, as the Company adds
21 generation resources that serve Micron, the cost of demand and energy will likely shift. ,3 He further
22 explains (p7), in reference to capacity additions, "Micron will pay the fixed capacity cost for these
23 resources but will not receive the benefit of the lower energy costs associated [with] them."Even the
24 1992 NARUC Manual describes that"capital costs which reduce fuel costs may be classified as energy
25 related rather than demand related. ,4
2 IPC-E-25-16,Maloney Direct,p15,May 30,2025;and IPC-E-23-11,Goralski Direct,p15,March 31,2023.
3 IPC-E-24-44,Gorman Rebuttal,July 30,2025,p6.
4 National Association of Regulatory Utility Commissioners(NARUC), 1992.Electric utility cost allocation manual. p20.
Case No. IPC-E-24-44 White, C. (Surrebuttal) 11
August 15, 2025 CEO

I Regardless of how Micron Fab's revenue requirements are determined, which is outside the
2 scope of my testimony, if the Schedule 28 rate design continues to include monthly Demand Charges
3 (paragraph 18, Application p7), it is inaccurate to assume that no energy benefits are associated with
4 costs currently assigned to monthly Demand Charges. Shifting a portion of costs out of the Demand
5 Charge and into Energy Rates during higher risk hours would more accurately reflect that both
6 capacity and energy benefits flow from those costs and are time-varying in nature.
7
8 Q: Response to Company Issues: Can you speak directly to the issues raised by the
9 Company in response to your original proposal to recover capacity costs via volumetric charges?
10 A: My modified proposal serves to alleviate the Company's concerns with my original
11 proposal to shift all demand related costs into volumetric rates. Below I will quote and respond to each
12 issue raised by Mr. Anderson in the Company's Rebuttal, which I have lettered a through e:
13 a. "The Company opposes Ms. White's proposal because it would eliminate the fixed- cost
14 recovery safeguards built into the special contract, including the Contract and Minimum
15 Billing Demands. " (Anderson Rebuttal,p16)
16
17 Surrebuttal: I agree that stranded asset recovery safeguards should remain an element in the
18 contract. For example, Idaho Power has agreed to make incremental levels of capacity available to the
19 Micron Fab, and it is appropriate to recover those costs whether utilized or not. Minimum billing terms
20 for capacity costs and informed by the Scheduled Ramp Contract Demand and Embedded Contract
21 Demand can coexist with a time-varying price signal for capacity. Lastly, my request to shift a portion
22 of costs currently in Demand Charges into Energy Rates alleviates this concern.
23 b. "Penalizing high load factor customers is problematic for several reasons." (Anderson
24 Rebuttal,p 17)
25
26 Surrebuttal: "Penalizing" is an inaccurate characterization. As I noted in Direct, the rate
27 structure could be designed such that, "if Micron's actual load shape were the same as the projected
28 load shape associated with the approved revenue requirements, Micron's total bill under the time-
29 varying rate structure would be the same as that under the rate structure proposed in the application."
30 Neither the original nor my modified proposal penalizes Micron.
Case No. IPC-E-24-44 White, C. (Surrebuttal) 12
August 15, 2025 CEO

I c. "It could misalign prices with actual cost causation by disconnecting pricing from how
2 system costs are incurred. " (Anderson Rebuttal, p 17)
3
4 Surrebuttal: A time-varying price signal is more aligned to cost causation than monthly demand
5 charges.5 As the Company has previously testified, "The procurement of capacity resources is driven
6 by the identified hours of highest risk-the period that capacity can be avoided."6
7 d. "It could also encourage inefficient peaks and higher system costs by weakening incentives
8 for steady usage." (Anderson Rebuttal, p 17)
9
10 Surrebuttal: I was not aware that Micron needs strong incentives to maintain steady usage. A
11 monthly demand charge does not ensure steady or predictable usage, it only motivates a customer to
12 avoid exceeding its peak for that month. Time-varying price signals for capacity could coexist with
13 parameters to incentivize predictability and to charge for cost-causing fluctuations in the Micron Fab's
14 demand if that is merited. Nevertheless, my modified proposal in this Surrebuttal allows for a
15 significant demand charge to remain, which addresses the Company's concern.
16 e. "If Micron responded to price signals by reducing usage during peak periods and/or high-
17 risk hours, it would result in under collection of fixed costs and shift that cost burden to
18 other customers. " (Anderson Rebuttal, p17)
19
20 Surrebuttal: The Company's concern occurs if Micron reduces usage during high-risk hours,
21 therefore—if the concern is significant-then the opportunity to reduce usage during capacity
22 constrained hours is significant and merits consideration. Regarding remedies, there are instruments to
23 address the Company's concern such as minimum billing terms to narrow the scope of the concern and
24 mechanisms to ensure fixed cost recovery. My request to shift a portion of costs currently in Demand
25 Charges into Energy Rates also alleviates this concern. Lastly, the Company's argument implies that
26 no customer should have the opportunity to save money when they mitigate future system costs. As
27 stated earlier, I recommend that the Commission pursue fairness by allowing more customers to take
28 service under tariffs with price signals which better align with the mitigation of future costs.
29
s For examples,as discussed later, see Regulatory Assistance Project. (2020,June 16).Demand charges: What are they
good for?hM2s://www.raponline.org/knowledge-center/demand-charges-what-are-they-good-for/.
6 IPC-E-25-15,Jared Ellsworth Direct,p17.
Case No. IPC-E-24-44 White, C. (Surrebuttal) 13
August 15, 2025 CEO

I Q: Demand Charges: Can you provide further support for your recommendation that a
2 time-varying per kWh rate is preferable to demand charges for certain capacity costs?
3 A: The Regulatory Assistance Project(RAP) has published a thoughtful overview of the need
4 "to reconsider demand charges, even for industrial customers, and replace them with more efficient
5 time-varying energy(kilowatt-hour)rates."' I would highlight the takeaway that the historic
6 justification for demand charges no longer applies, and that a flat load is no longer the lowest cost load
7 shape. After stating that"Traditional monthly demand charges have always provided a perverse
8 incentive that does not reflect cost causation for shared system costs", RAP further explains and
9 concludes that a flat load is no longer the lowest cost load shape:8
10 The historic exception to this rule is a customer that has a nearly 100% coincidence factor with
11 the relevant peaks. The prototypical example of this in the mid-20th century was an industrial
12 customer with very high load factors. Demand charges could be reasonable in the past only as
13 applied to this specific category of customers. But, in today's electric system, even this
14 justification for demand charges falls away. High penetrations of nondispatchable but variable
15 renewable generation means that a 100% load factor is unlikely to be, from a system
16 perspective, the most desirable load shape.
17
18 Q: Other than your proposal to spread all or a portion of capacity costs across usage
19 during higher risk hours, are there alternatives approaches which could achieve similar goals?
20 A: Yes. For example, as an alternative to price signals, performance-based rates (PBR) could
21 be pursued. I would also invite the Company to propose a rate structure which not only serves the
22 purpose of fair and reasonable cost recovery but also allows the customer to benefit from decisions or
23 investments which mitigate future system costs.
24
25 Q: Do you have any closing remarks?
26 A: The Company is adding capital costs at an unprecedented pace and increasing its reliance on
27 markets. In this docket, as with any new tariff or any update to existing rate designs, the Commission
28 should be presented with rate designs which consider the time-varying nature of costs and any
Regulatory Assistance Project. (2020,June 16).Demand charges: What are they good for?
hM2s://www.raponline.oraUowledge-center/demand-charges-what-are-they-good-for/(p4).
8 ibid.
Case No. IPC-E-24-44 White, C. (Surrebuttal) 14
August 15, 2025 CEO

I demand-side opportunities to mitigate system costs. The regulatory process should not resign
2 customers to pay higher future rates than would otherwise be necessary if the opportunity for effective
3 time-varying price signals were adequately pursued.
4
5 III. Recommendations
6 Q: Please summarize your recommendations.
7 A: In Direct, I recommended that the proposed rate structure in Schedule 28 should not be
8 approved, and that a process should be ordered for modifying the rate structure to more accurately
9 reflect the hourly, time-varying nature of cost causation. I will further delineate and clarify that
10 recommendation with regard to energy costs and capacity costs below:
11 ENERGY COSTS:
12 With regard to the rate structure for energy rates, I ask that the Commission:
13 ➢ Direct either Staff or the Company to propose a revised Schedule 28 Time of Use (TOU)
14 Energy Rate and the associated update methodology to more accurately reflect the hourly,
15 time-varying nature of cost causation.
16 ➢ Require that the lowest price time period for a Schedule 28 TOU rate be informed by
17 forward-looking analysis, specifically market price forecasts, and should not exceed six
18 hours. This requirement does not replace the continued use of reliability risk analysis to
19 inform TOU time periods. A relatively lower and narrower low-cost time period(e.g., a
20 Super Saver or Super Off-Peak rate during day hours) is needed to achieve more accurate
21 price signals, and to achieve more effective price signals by augmenting the difference
22 between the highest and lowest prices.
23 Please see my Direct testimony and herein for specific recommendations on time periods.
24
25 CAPACITY COSTS:
26 With regard to the rate structure for capacity costs, I believe that the Company's concerns with
27 my proposal in Direct testimony, which shifted all generation and transmission capacity costs
Case No. IPC-E-24-44 White, C. (Surrebuttal) 15
August 15, 2025 CEO

I into volumetric rates, are alleviated by the modification I am proposing in Surrebuttal. I also
2 believe the Company's concerns are solvable yet require a structured process to resolve. My
3 modified recommendation is as follows:
4 ➢ Regarding the proposed determination of monthly Demand Charges (paragraph 18,
5 Application p7), shifting a portion of generation and transmission capacity costs out of the
6 monthly Demand Charge and into volumetric Energy Rates during higher risk hours would
7 more accurately reflect that both capacity and energy benefits flow from those costs and
8 would provide a more accurate price signal reflecting the time-varying nature of capacity
9 cost causation. It is inaccurate to assume that no energy benefits are associated with costs
10 currently assigned to monthly Demand Charges. Determination of the appropriate portion to
11 shift out of monthly Demand Charges and into Energy Rates for Schedule 28 could be
12 evaluated in the context of the follow-on process requested by my colleague Mr. Heckler.
13
14 Q: Does this conclude your testimony?
15 A: Yes.
Case No. IPC-E-24-44 White, C. (Surrebuttal) 16
August 15, 2025 CEO

CERTIFICATE OF SERVICE
I hereby certify that on this 15th day of August, I delivered true and correct copies of the
foregoing SURREBUTTAL TESTIMONY to the following persons via the method of service
noted:
Electronic Mail Delivery (See Order No. 34602)
Idaho Public Utilities Commission
Monica Barrios-Sanchez
Commission Secretary
secretary0puc.idaho.gov
Idaho PUC Staff
f
Chris Burdin
Deputy Attorney General
Idaho Public Utilities Commission
chris.burdin(@puc.idaho.gov
Idaho Power Company
Megan Goicoechea Allen
Donovan Walker
Connie Aschenbrenner
Grant Anderson
mgoicoecheaallenOidahopower.com
[e-mail]
caschenbrennerna idahopower.com
gandersonOidahopower.com
dockets idahopower.com
Industrial Customers of Idaho Power, Inc.
Peter J. Richardson
Dr. Don Reading
[e-mail]
dreadingna mindspring.com
Idaho Irrigation Pumpers Association, Inc.
Eric L. Olsen
Lance Kaufman, Ph.D.
elo(a)echohawk.com
lance(a�aegisinsight.com
CLEAN ENERGY OPPORTUNITIES FOR IDAHO -WHITE SURREBUTTAL - IPC-E-24-44

Micron Technology, Inc.
Austin Rueschhoff
Thorvald A. Nelson
Austin W. Jensen
Kristine A.K. Roach
Holland & Hart, LLP
darueschhoff0hollandhart.com
tnelson aphollandhart.com
awj [e-mail]
aclee(a)hollandhart.com
karoach(a)hollandhart.com
'U
Kelsey Jae
Attorney for CEO
CLEAN ENERGY OPPORTUNITIES FOR IDAHO -WHITE SURREBUTTAL - IPC-E-24-44