20250815Surrebuttal Testimony IIPA.pdf

RECEIVED
August 15, 2025
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IDAHO PUBLIC
UTILITIES COMMISSION
IDAHO POWER COMPANY'S CASE NO. IPC-E-24-44
APPLICATION FOR APPROVAL OF A
SPECIAL CONTRACT AND TARIFF
SCHEDULE 28 TO PROVIDE ELECTRIC
SERVICE TO MICRON IDAHO
SEMICONDUCTOR MANUFACTURING
(TRITON) LLC
INTERVENOR
IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.
SURREBUTTAL TESTIMONY OF
LANCE D. KAUFMAN, Ph.D.
August 15, 2025

TABLE OF CONTENTS
Micron Special Contract Application
Case No. IPC-E-24-44
Surrebuttal Testimony of Lance D. Kaufman, Ph.D.
I. Introduction and Additional Factors................................................................................................ 1
II. Correction to IRP based incremental Cost calculation....................................................................3
III. Estimated cost of CCCT Service.....................................................................................................4
IV. Use of IRP TO Establish Incremental Cost................................................................................... 10
V. Transmission Costs........................................................................................................................ 14
VI. ELCC as a Resource Adequacy Metric......................................................................................... 16
VII. Long Run Marginal Energy Costs................................................................................................. 18
VIII. Marginal Cost True-up.................................................................................................................21
IX. Termination Risk...........................................................................................................................22
X. IPC's system growth is already causing problems........................................................................25
EXHIBIT LIST
Exhibit 208— Surrebuttal Discover Responses
Confidential Exhibit 209—Corrected Micron CCCT Model
Exhibit 210—Bonneville Power Administration New Large Single Load Policy
Page i

1 I. INTRODUCTION AND ADDITIONAL FACTORS
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?
1 1 A. I respond to the reply testimony of Idaho Power Company ("IPC") and Micron.
12 Q. WHAT ISSUES DO YOU RESPOND TO IN THIS TESTIMOY?
13 A. Micron raises the following issues:
14 1. I correct an error noted by Micron and IPC in my IRP analysis;l
15 2. I correct some errors in Micron's estimate of the cost of a CCCT and rebut claims that a
16 standalone CCCT can be used to evaluate the cost of serving the ESA.2
17 3. I respond to concerns about the use of IRP scenarios to estimate incremental cost.3
18 4. 1 respond to IPC claims that all incremental transmission costs are paid for through the ESA.4
19 5. 1 respond to criticisms of the use of ELCC to evaluate capacity contribution.5
1 Direct Rebuttal Testimony of Michael P.Gorman,at 13 to 15.
2 Id.
3 Rebuttal Testimony of Grant T.Anderson at 9 to 10 and Direct Rebuttal Testimony of Michael P. Gorman,at 19 to 22.
4 Rebuttal Testimony of Jared L.Ellsworth at 9.
5 Id. at 7 to 9.
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1 6. I identify errors in Micron's testimony regarding the impact of new generation on embedded
2 energy costs.6
3 7. I respond to ICP's proposal to address marginal cost true-ups in the next update docket.
4 8. I respond to IPC concerns regarding my proposed floor to the termination payment.
5 Q. HOW HAVE YOUR VIEWS CHANGED AFTER REVIEWING OTHER PARTY
6 TESTIMONY?
7 A. Micron and IPC accurately identify a double-counting issue that appears in my IRP cost
8 analysis. I discuss this issue in more detail in my testimony below. The revised calculation of
9 $95 per MWh is correct. Parties have also questioned whether a levelized rate is appropriate
10 when revenue requirement is not levelized. IIPA is comfortable with either a levelized or non-
11 levelized rate, and this issue is discussed in more detail below. I acknowledge that a marginal
12 cost true-up mechanism could be developed in a separate docket, if the docket has sufficient
13 time and process in the schedule.
14 Q. WHAT RECOMMENDATIONS DOES CLEAN ENERGY OPPORTUNITIES FOR
15 IDAHO ("CEO")MAKE
16 A. CEO recommends that the ESA be amended to ensure that incremental transmission facilities
17 such as Mayfield and the associated transmission link be included in the upfront costs and paid
18 for by Triton as Contributions in Aid of Construction("CIAC"). CEO also notes that disputes
19 regarding termination payments could be avoided through the use of CAIC to pay the up-front
20 capital cost of generation and storage procured for the ESA.
6 Direct Rebuttal Testimony of Michael P. Gorman,at 22.
7 Rebuttal Testimony of Michael Heckler,at 6:10-13.
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I Q. HOW DO YOU RESPOND TO CEO?
2 A. The use of CIAC to cover the incremental cost that exceeds embedded rates is a novel and
3 acceptable approach. IIPA is amenable to this solution if it can be shown that the CIAC is
4 sufficient to hold existing customers harmless from the ESA load. CEO's CIAC solution does
5 not address the issue of PPA resources increasing embedded energy costs however. If the ESA
6 is modified to require up-front payment for incremental transmission, generation, and storage
7 resource investments, an additional adjustment is still necessary to insulate customers from
8 PPAs that exceed the embedded cost of energy.
9
10 II. CORRECTION TO IRP BASED INCREMENTAL COST CALCULATION
11 Q. DID OTHER PARTIES IDENTIFY A DOUBLE COUNTING ERROR IN YOUR
12 REBUTTAL
13 A. Yes, IPC and Micron offer corrections to my estimate of the incremental cost of 500 MW of
14 load in IPC's 2025 IRP. I originally estimated the cost to be $186 when in fact it is $95 per
15 MWh.
16 Q. CAN YOU EXPLIAN THE SOURCE OF THIS ERROR?
17 A. My calculations were based on an IRP workpaper produced by IPC in discover. I summed the
18 total resource cost and retail MWh by year for the scenarios with and without 500 MW of load
19 and divided by the difference in cost by the difference in MWh. The underlying cost
20 workpaper included both total and subtotal lines for each year within the same sheet as the
21 individual generator costs. I identified the total lines and removed them from my calculations,
22 however, I did not remove the sub-total line for resources, resulting in a double counting of
23 resource costs.
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I Q. WAS THE INCLUSION OF THE SUBTOTAL ROWS INTENTIONAL?
2 A. No.
3 Q. DO YOU AGREE WITH IPC'S REVISED CALCULATIONS IN ELLSWORTH
4 EXHIBIT NO. 2
5 A. Yes, I agree with the IPC's calculated incremental cost of$95 per MWh. This amount should
6 be used in place of the $186 initial estimate.
7 III.ESTIMATED COST OF CCCT SERVICE
8 Q. HOW DOES MICRON ESTIMATE THE INCREMENTAL COST OF SERVING
9 MICRON'S LOAD?
10 A. Micron uses IPC's 2025 IRP data as inputs into a simplified revenue requirement model and
11 estimates the cost to be around-/MWh and-/MWh in 2030, and 2035,
12 respectively.8
13 Q. DO MICRON'S ESTIMATES AGREE WITH THE 2025 IRP MODEL RESULTS?
14 A. No. IPC provides workpapers that allow generator by generator calculations of energy costs.9
15 IPC's IRP adds two CCCTs in the 500 MW scenario with costs ranging from $100 to $148 per
16 MWh. The table below summarizes average energy cost by year.10
8 Exhibit 208,Direct Rebuttal Testimony of Michael P. Gorman,at 17.
9 Exhibit 208,IPC Response to IIPA Request for Production 4-2(d)and 2-10.
10 Exhibit 208,IPC Response to IIPA Request for Production 4-2 and 2-10.
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I Table 1: 2025 IRP Energy Cost of CCCT
Nameplate Energy Cost Capacity
Item Capacity Year (MWh) ($000) $/MWh Factor
New Resource 2706 from CCCT NG PE 50 CCCT NG PE 50 300 2030 1,055,477 $114,974 $109 0.40
New Resource 2706 from CCCT_NG_PE_50 CCCT_NG_PE_50 300 2031 1,055,477 $116,409 $110 0.40
New Resource 2706 from CCCT NG PE 50 CCCT NG PE 50 300 2032 1,055,955 $117,731 $111 0.40
New Resource 2853 from CCCT NG PE 120 CCCT NG PE 120 300 2033 920,009 $130,673 $142 0.35
New Resource 2706 from CCCT_NG_PE_50 CCCT_NG_PE_50 300 2033 1,190,945 $119,714 $101 0.45
New Resource 2853 from CCCT NG PE 120 CCCT NG PE 120 300 2034 998,576 $135,526 $136 0.38
New Resource 2706 from CCCT NG PE 50 CCCT NG PE 50 300 2034 1,112,378 $120,277 $108 0.42
New Resource 2853 from CCCT_NG_PE_120 CCCT_NG_PE_120 300 2035 913,452 $135,462 $148 0.35
2 New Resource 2706 from CCCT NG PE_50 CCCT NG PE_50 300 2035 1,197,502 $125,830 $105 0.46
3 Q. WHAT ISSUES DO YOU FIND WITH MICRON'S ANALYSIS THAT COULD
4 EXPLIAN THIS DISCREPANCY?
5 A. I identified several errors with Micron's analysis. In addition, I offer several modeling
6 adjustments that I believe are more accurate.
7 1. Include a full year of depreciation expense rather than a half year.
8 2. Include a full year of O&M rather than a month of O&M.
9 3. Use a lower capacity factor.
10 4. Use IPC's actual gas price forecast.
1 1 Q. WHY DO YOU INCLUDE A FULL YEAR OF DERPECIATION EXPENSE RATHER
12 THAN A HALF YEAR?
13 A. Micron's model divides annual fixed costs by annual generation to derive a cost per MWh.
14 However, Micron only includes a half year of depreciation expense in the annual fixed cost
15 calculation. Micron appears to calculate a half year of depreciation expense for the purpose of
16 accounting for the "half year conv"in determining net plant. Assuming the plant is in service
17 for a full year is reasonable because the plant is assumed to produce a full year of generation.
18 Under this assumption, I agree it is reasonable to use a half year of depreciation when
19 determining accumulated depreciation and net plant, as this approach reflects the average
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I monthly net plant balance. However, in a general rate case a full year of depreciation expense
2 would be included in the revenue requirement.
3 Q. WHY INCLUDE A FULL YEAR OF FIXED O&M COSTS?
4 A. Micron uses the 2025 IRP Appendix C CCCT fixed O&M estimate of$1.6 per kW-Month.
5 Because this value is expressed in terms of months, the value should be multiplied by 12 to
6 determine annual fixed O&M costs.
7 Q. WHY USE A LOWER CAPACITY FACTOR?
8 A. Micron assumes a 90 percent capacity factor. The selection of capacity factor depends on the
9 approach and purpose of modeling. While a CCCT could in theory operate at 90% of capacity,
10 IPC's other CCCT, Langley Gulch, appears to operate closer to a 50-60 percent capacity factor.
11 IPC's 2023 IRP assumes a 55% capacity factor for CCCTs and IPC's 2025 IRP workpapers
12 show CCCTs average a 40 percent capacity factor. Micron's approach of using a 90 percent
13 capacity factor is reasonable if it is assumed that no other resource serves micron's energy.
14 However, as I note below, IPC's IRP shows a mix of gas, renewable resources, and batteries
15 will be used to serve Micron's load. I offer a revised calculation of CCCT costs under Micron's
16 90 percent capacity factor to allow the Commission to evaluate the standalone cost of using
17 only a CCCT, and under a 50 percent capacity factor to evaluate the more accurate expected
18 operations of IPC's new CCCTs.
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I Q. WHY USE IPC'S ACTUAL GAS PRICE FORECAST?
2 A. IPC's actual gas price forecast reflects expected transportation costs and is more specific to
3 IPC's expected operations. IPC's forecasted gas price, including transportation costs, are
4 confidential and different from the rate assumed by Micron.i i
5 Q. AFTER THESE ADJUSTMENTS IS THE ESTIMATED CCCT COST CONSISTENT
6 WITH IPC'S IRP DATA?
7 A. Yes. The resulting estimates are included in Confidential Exhibit 209
8 Q. CAN YOU COMMENT ON MICRON'S ASSERTION THAT ITS NOT REASONABLE
9 TO ASSUME THAT A BATTERY AND WIND CAN SERVE A HIGH LOAD FACTOR
10 CUSTOMER,AND THAT A CCCT IS A MORE REASONABLE ASSUMPTION?
11 A. Sure. In my testimony, I present the IRP incremental load model as the best approach to
12 modeling incremental costs for the new FAB and to test whether other customers are harmed
13 by the special contract. The IRP 500 MW sensitivity adds the following resources in response
14 to a 500 MW industrial load addition:
15 • 300 MW CCCT
16 • 150 MW SCCT
17 • 100 MW Reciprocating Engine
18 • 200 MW Solar
19 • 195 MW 4 Hour Batteries
20 • 67 MW Energy Efficiency
21 This shows IPC can be expected to meet Micron's load with both gas, renewable
22 generation, storage, and demand side management. This highlights that it's necessary to model
11 Exhibit 208,IPC Response to IIPA Request for Production 4-4 sheet"9-Gas Price Forecast". The confidential prices are
printed in Exhibit 209.
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I a material amount of duplicate capacity, the total nameplate capacity of these resources
2 exceeds 1,012 due to low capacity contribution and IPC's need to meet renewable energy
3 goals.
4 Q. IS IT FAIR TO ATTRIBUTE RENEWABLE ENERGY COSTS TO MICRON?
5 A. Yes. Micron has a goal of procuring 100 percent renewable energy in existing U.S.
6 operations.12 Thus it is reasonable to include renewable energy costs when modeling micron's
7 incremental cost, even if such resources may duplicate the capacity of IPC's planned gas
8 resources. Moreover, IPC is currently acquiring batteries, solar, and wind and it is appropriate
9 to attribute a portion of these acquisitions to Micron.
10 Q. CAN MICRON BE SERVED BY IPC'S PLANED BATTERY RESOURCES?
11 A. Yes. The Boise Bench battery resource is located at Boise Bench Substation property on Amity
12 and Holcomb roads.13 This is only 2 miles from Micron.
12"These goals complement our target to achieve 100%renewable energy for purchased electricity in our existing U.S.
operations by the end of 2025."Micron 2025 Sustainability Report
https:Hassets.micron.com/adobe/assets/um:aaid:aem:f2d222l a-6b76-4a98-9aO6-
f52fa958c91 e/renditions/original/as/Micron-2025-Sustainability-Report.pdf
13 https://www.idahopower.com/energy-environment/energy/energy-sources/battery-investmentsiboisc-bench-substation-
battcry-proj ect/
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1 Figure 1: Boise Bench BESS and Micron FAB
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Measure distance
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Total distance:2.04 mi(3.28 km)
2
3 Q. DOES THE BOISE BENCH BESS COINCIDE WITH THE NEW FAB?
4 A. Yes, the Boise Bench BESS is 200 MW and is expected to be operational in June 2026, the
5 first year with contract capacity for the new FAB June 2026 contract capacity of 129 MW.14
14 https://www.idahopower.com/energy-environment/enera/ey nergy-sources/battery-investments/boise-bench-substation-
battery_project/and Application Exhibit 3-1.
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I Q. IS IPC ALSO PROCURING SOLAR AND WIND RESOURCES?
2 A. The Commission has recently approved CPCNs for Jackalope Wind, and the Crimson Orchard
3 solar project. This highlights that IPC is meeting load growth with a mix of storage, renewable
4 resources, and gas generation.
5 IV.USE OF IRP TO ESTABLISH INCREMENTAL COST
6 Q. WHY DO MICRON AND IPC OPPOSE THE USE OF THE IRP TO ESTABLISH
7 INCREMENTAL COSTS?
8 A. The following objections are raised:
9 1. IRP is a forecast, and actual costs are uncertain and may differ from forecast.15
10 2. IPC's projected load growth after 2033 is not driven by large industrial load growth.16
11 3. Micron's rates will be updated as IPC acquires new resources.17
12 4. The IRP does not reflect revenue requirement.18
13 5. The IRP load sensitivity does not reflect the incremental FAB load.19
14 6. IRP based pricing bypasses regulatory process.20
15 7. The IRP load reflects the full 500 MW buildout while current prices are applicable to the initial
16 ramp of 130 MW, leading to a mismatch.21
17 8. The IRP based price is a 20 year price that ignores timing of load and investment.22
15 Rebuttal Testimony of Grant T.Anderson at 9:19-22 and Direct Rebuttal Testimony of Michael P.Gorman,at 19.
16 Direct Rebuttal Testimony of Michael P. Gorman,at 19.
17 Id., at 21.
18 Rebuttal Testimony of Grant T.Anderson at 7:14-17 and Direct Rebuttal Testimony of Michael P.Gorman,at 22.
19 Direct Rebuttal Testimony of Michael P. Gorman,at 23
20 Rebuttal Testimony of Grant T.Anderson,at 10:5-8.
21 Rebuttal Testimony of Grant T.Anderson,at 9:23-10:2.
22Id., at 10:8-11.
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I Q. WHAT IS YOUR RESPONSE TO CONCERNS THAT THE IRP REFLECTS A
2 FORECAST AND IS UNCERTAIN?
3 A. My recommended pricing is intended to reflect an initial price. As noted in my proposal, the
4 initial generation rate reflects forecasted costs.23 I recommended that the rate be updated as
5 costs become known.24
6 Q. WHAT IS YOUR RESPONSE TO LOAD GROWTH CONCERNS AFTER 2033?
7 A. The load growth after 2033 is reflected in both the with and without micron load scenarios. As
8 a result this issue is directly addressed by looking at the long-run cost differences. The IRP cost
9 comparison model does not attribute post 2033 load growth costs to Micron.
10 Q. WHAT IS YOUR RESPONSE TO THE CLAIMS THAT UNDER THE PROPOSED
11 SPECIAL CONTACT RATE THE RATE WILL BE UPDATED AS IPC AQUIRES
12 RESOURCES?
13 A. The proposed initial rate is based on a cost allocation methodology that gives the new FAB the
14 benefit of low cost legacy resources. Under this model, even if rates are updated as IPC
15 acquires resources for the FAB, the cost of the new resources will be spread disproportionately
16 to existing customers. IIPA is comfortable with a model that updates rates as long as such a
17 model allocates incremental costs to the special contract. However, because IPC is already
18 acquiring resources to serve the FAB, and IPC is already increasing rates to pay for these
19 resources, it is appropriate to set the starting rate for the special contract at the expected
20 incremental cost.
23 Written Testimony of Lance Kaufman,at 15:14.
24 Id.,at 15:12-22.
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I Q. WHAT IS YOUR RESPONSE TO CONCERNS THAT THE IRP DOES NOT
2 REFLECT REVENUE REQUIREMENT?
3 A. There are several issues embedded within this concern. First, with respect to the ability for the
4 Company to earn its revenue requirement, the Special Contract revenue can be included in any
5 future rate case to ensure that IPC's rates are set such that IPC's costs are recovered and IPC
6 has the opportunity to earn a fair rate of return.
7 Second, I based rates on a 20 year levelized cost estimate because this would ease the
8 burden to Micron. In discovery, IPC clarified that its concern with IRP data is the use of
9 levelized costs rather than actual nominal revenue requirement.25 If costs were not levelized
10 over 20 years, Micron would face the front-loaded revenue requirement cost of new capital
11 investments. IIPA is not opposed to restructuring the rates so that the special contract rate is
12 not levelized, but this would increase the special contract rate even further in the short run.
13 Third, my recommendation to allow the rate to be updated will also allow the rate to
14 align with the revenue requirement, whether the rate is levelized or not.
15 Fourth, even the proposed rates do not reflect revenue requirement because IPC has
16 already filed a new general rate case which does not include any revenue from the special
17 contract.
18 Q. WHAT IS YOUR RESPONSE TO CONCERNS THAT THE IRP 500 MW LOAD
19 SENSATIVITY DOESN'T REFLECT MICRON'S LOAD?
20 A. Micron argues that both the base case and the 500 MW incremental load IRP scenario include
21 micron's new FAB, thus the 500 MW incremental load is a double counting of the FAB load.
22 However, this concern does not negate the cost comparison as a reasonable estimate of the
25 Exhibit 208,IPC Response to IIPA Request for Production 4-3.
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I incremental cost of the new FAB. Consider that Micron has already announced plans to build a
2 second FAB.26 This means the incremental cost model can simply be thought of as the 500
3 MW scenario having the load of both FABs, and the base scenario having only the load of the
4 second FAB, appropriately isolating the incremental cost of the first FAB.
5 Q. HOW DO YOU RESPOND TO THE CONCERN THAT IRP BASED PRICING
6 BYPASSES THE REGULATORY PROCESS?
7 A. As noted above, the IRP based pricing is simply a starting point for the contract price. IPC's
8 rates will still be subject to review in a general rate case and IPC and Micron will continue to
9 benefit from the full regulatory process in general rate cases.
10 Q. HOW DO YOU RESPOND TO CONCERNS THAT THERE IS A MISMATCH IN THE
1 1 TIMING OF INVESTMENT AND LOAD?
12 A. IPC points out that there is a potential for a mismatch between cost basis and load across time
13 given the 20-year analysis.27 As I note above, the levelized price has the advantage of
14 smoothing Micron's rates and preventing front-loading of revenue requirement. However, IIPA
15 is not opposed to directly matching new resource revenue requirements with Micron's actual
16 load, as long as the incremental costs are directly assigned to the special contract. A directly
17 matched revenue requirement will be higher than a 20-year levelized cost because the revenue
18 requirement for capital investments is front loaded. Thus, IIPA's recommended starting rate
19 should still be adopted as a starting point until actual revenue requirement is known and
20 measurable.
26 In fact,Micron is already discussing energy procurement with IPC about service for the second FAB. "At this time,
Micron continues to engage with Idaho Power and is evaluating all available avenues for energy procurement."
Micron states that on average the demand use for a FAB plant is 400 MW.Exhibit 208,Micron Response to IIPA
Request for Production 1-1.
27 Rebuttal Testimony of Grant T.Anderson,at 9:23-10:12.
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I Q. ARE THERE ACCEPTABLE ALTERNATIVES TO USING AN IRP BASED PRICE
2 FOR THE SPECIAL CONTRACT?
3 A. Yes. The New Large Load Legislation contemplates a system of tracking costs that parallels
4 Bonneville Power Administration's method of assigning costs to New Large Single Loads. If
5 the Commission prefers to use a mechanism that more directly matches incremental revenue
6 requirement, the BPA method of calculating rates for New Large Single Loads could be
7 adopted. This methodology is discussed by BPA in Exhibit 210.
8 V. TRANSMISSION COSTS.
9 Q. WHAT IS IPC'S POSSITION REGARDING TRANSMISSION COSTS?
10 A. IPC maintains that there is no incremental transmission costs associated with Micron's load
11 that are not directly paid for upfront by Micron.28
12 Q. CAN YOU EXPLAIN WHY YOU DISAGREE?
13 A. I reviewed the costs included in the Procurement and Construction Agreements. I also
14 reviewed the Highly Confidential project management documents associated with this project.
15 The scope of work is limite
16
17
18 Q. CAN YOU EXPLAIN WHY BULK TRANSMISSION IS NECESSARY?
19 A. The incremental resources needed to serve Micron include wind, solar, batteries, and gas
20 generation. Of these resources, the only resources capable of being constructed locally are
21 batteries and gas generation. Batteries do not generate and must be charged to produce energy.
28 Rebuttal Testimony of Jared L.Ellsworth,at 9:14-21.
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I Thus, even if batteries are sited locally,bulk transmission is still necessary to deliver energy
2 from the generating resource to the battery. In theory, IPC could construct a combined cycle
3 plant next to or near Micron. However, this may not be the least cost as it would require
4 extensive gas transmission to replace bulk electric transmission. For example, Langley Gulch
5 is sited 50 miles from Boise. IPC's new renewable resources are also remote from the new
6 FAB. For example, Crimson Orchard is 35 miles from the FAB, and Jackelope Wind Project is
7 approximately 400 miles from the new FAB. Bulk transmission is undoubtedly necessary to
8 deliver 500 MW of wind.
9 Q. WHAT POSITION DID YOU TAKE IN WRITTEN TESTIMONY REGARDING
10 TRANSMISSION?
11 A. I addressed transmission in the context of IPC's no harm analysis. I observed that Micron
12 demand is equivalent to two thirds of the capacity of B2H and half the capacity of GWW
13 Segments 8 and 10, and therefore a proportional share of these costs should be assigned to the
14 "With Micron"portfolio.
15 Q. HOW DOES IPC RESPOND TO YOUR ANALYSIS OF TRANSMISSION?
16 A. IPC argues that assigning the Boardman to Hemingway and GWW projects is double counting
17 capacity costs.29
18 Q. IS THIS DOUBLE COUNTING?
19 A. No. Transmission does not provide energy; transmission only enables access to a generating
20 resource that provides energy. IPC expects to be a member of the Western Resource Adequacy
21 Program ("WRAP"). WRAP is a regional adequacy program that requires annual resource
22 adequacy showings. Transmission is not sufficient to show resource adequacy. Resource
29 Rebuttal Testimony of Jared L.Ellsworth,at 10:16-18.
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I adequacy is only demonstrated with firm energy supply and firm transmission. This means it is
2 not double counting to include bulk transmission as an incremental cost of serving the new
3 FAB, it is simply a question of correctly allocating the costs of new transmission. It is simply
4 physically impossible to deliver 500 MW of energy to the new fab without either siting all
5 resources directly adjacent to the FAB or using bulk transmission. IPC is not siting generation
6 resources adjacent to the FAB and IPC is clearly building out its transmission facilities,
7 indicating that a shortage of bulk transmission exists. Therefore any incremental load of
8 material size should be presumed to require incremental bulk transmission.
9 Q. HAS IIPA PROPOSED AN INCREMENTAL TRANSMISSION RATE?
10 A. No. IIPA did not propose an incremental transmission rate. IIPA's transmission analysis is only
11 provided in the context of IPC's no-harm analysis. The absence of incremental transmission
12 from the IRP analysis and IPC's no-harm analysis should be understood to be an omission that
13 leads to the underestimation of incremental costs.
14 VI.ELCC AS A RESOURCE ADEQUACY METRIC
15 Q. WHAT CONCERNS DOES IPC RAISE REGARDING YOUR USE OF ELCC?
16 A. IPC argues against my use of Effective Load-Carrying Capability("ELCC") in favor of a loss
17 of load probability analysis.30
18 Q. WHAT IS YOUR RESPONSE?
19 A. The ELCC analysis at issue is performed in context of IPC's no-harm study grounded in the
20 2023 IRP. In general, I find the no-harm analysis to be unreliable as it is out of date, and the
21 micron sensitivity was not reported on as part of the 2023 IRP, thus lacks transparency. I am
30 Id.,at 7-9.
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I not opposed to judging reliability using a loss of load probability, however I continue to
2 believe it is reasonable to use ELCC to evaluate capacity contribution,particularly in the face
3 of the WRAP forward showing process which applies a very similar measure, qualifying
4 capacity contribution. One important reason for evaluating the no-harm study using ELCC is
5 because the no-harm study does not include the full revenue requirement of the IRP scenarios.
6 Instead, it only includes fixed costs of specific resources. The problematic nature of this can be
7 seen by isolating the components of the no-harm analysis.
8 Micron correctly observes that a flat industrial load cannot be served by wind and
9 batteries alone. Taken one step further, a flat industrial load cannot be served by batteries
10 alone. Yet in 2030 the "With Micron"resource only has additional costs associated with
11 incremental 261 MW of gas and 170 MW of batteries to serve 400 MW of demand. Even with
12 an overly generous one for one matching of gas capacity and demand, the 170 MW of 4 hour
13 batteries must be capable of serving the residual 139 MW of flat industrial load, which Micron
14 admits is unreasonable. The 2025 IRP on the other hand meets 500 MW of incremental load
15 with 550 MW of incremental gas generation PLUS batteries and renewable generation.
16 Q. REGARDLESS OF WHETHER THE 2023 IRP WITH MICRION SCENARIO IS
17 ACCURATE, SHOULD THE COMMISSION RELY ON IT IN THIS CASE?
18 A. No, the 2025 IRP 500 MW scenario more closely aligns with Micron's incremental load and
19 has more current prices and assumptions and should be relied on in assessing whether there is
20 no harm.
Case No. IPC-E-24-44 IIPA-Kaufinan, Su
08/15/2025 Page 17

I VII. LONG RUN MARGINAL ENERGY COSTS
2 Q. WHAT POINT DO YOU MAKE WITH RESPECT TO THE MARGINAL COST OF
3 ENERGY?
4 A. I observed that the Company's modeling doesn't add up to total cost. The Company considers
5 demand costs, and marginal energy costs, and fails to account for long run energy costs.
6 Q. WHY IS THIS PROBLEMATIC?
7 A. This is problematic because it creates a hole in the pricing framework by which existing
8 customers bear a disproportionate share of energy costs. IPC is acquiring high cost renewable
9 energy through PPAs at a rate that is substantially higher than the proposed energy charge.
10 Because these costs are energy costs, they are not included in the proposed Special Contract
11 demand charge. Thus other customers are left paying for the difference between the PPA rate
12 and the marginal energy rate.
13 Q. HOW DOES THE COMPANY RESPOND?
14 A. The Company admits that its rate is a short run rate but offers no mechanism to make other
15 customers whole for the difference between short run costs and long run costs. The Company
16 appears to believe that the benefit of providing a price signal to the Micron FAB offers benefits
17 that outweigh the loss of equity associated with other customers paying for the difference
18 between long run and short run marginal cost. The Company is also concerned that long-run
19 marginal costs are speculative, not transparent, and would weaken the link between customer
20 behavior and cost causation.
21 Q. IS THE PRICE FOR JACKELOPE, CRIMSON ORCHARD,AND OTHER LONG
22 RUN POWER PURCHASE AGREEMENTS KNOWN?
23 A. Yes, these prices are known and transparent to those with access to confidential information.
Case No. IPC-E-24-44 IIPA-Kaufinan, Su
08/15/2025 Page 18

I Q. DOES CHARGING A LONG RUN MARGINAL PRICE PROVIDE A BETTER PRICE
2 SIGNAL THAN CHARGING A SHORT RUN MARGINAL PRICE?
3 A. Yes, a long run marginal price is a better price signal because it provides better information for
4 customers making long run energy decisions. Short run pricing is only helpful to the extent that
5 it can inform short run energy use. It seems speculative to assume that Micron will be
6 responsive to short run marginal price signals given the large capital outlay for the new FAB.
7 A more likely scenario is that providing a proper long run price signal will help micron make
8 an efficient decision regarding whether to build its second FAB.
9 Q. CAN YOU EXPLIAN WHY LONG RUN MARGINAL PRICING WILL IMPROVE
10 THE EFFICIENCY OF MICRON'S DECISION REGADING THE SECOND FAB?
11 A. Economic efficiency requires that decision makers bear the full cost of their decisions. For
12 example, suppose that the total revenue collected for the Micron FAB is $60 million per year,
13 and at that rate Micron can earn a profit of$10 million per year from building a new FAB.
14 Facing these prices, Micron would choose to build a second FAB. Now suppose the actual long
15 run marginal cost to Idaho Power for serving this energy is $100 million. In other words other
16 customers are subsidizing the FAB by $40 million. While Micron is making a profit of$10,
17 other customers are losing $40 million, a net loss to society of$30 million per year. If Micron
18 were charged the full cost of$100 million, Micron would realize the $30 million loss. Rather
19 than constructing a second FAB, Micron would opt not to proceed with its construction,
20 resulting in an outcome considered economically efficient.
Case No. IPC-E-24-44 IIPA-Kaufinan, Su
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I Q. IN YOUR EXAMPLE ABOVE,AREN'T THE NUMBERS JUST ILLUSTRATIVE,
2 AND ITS NOT GUARANTEED THAT THE SECOND FAB IS ECONOMICALLY
3 EFFICIENT?
4 A. That's correct. Only Micron knows the potential profit of the second FAB. The only way to
5 ensure that an efficient decision is made is to charge micron the full long run marginal cost, or
6 as close to it as the Commission reasonably can within the existing regulatory framework.
7 Q. CAN THE COMMISSION PRESERVE THE SHORT RUN MARGINAL ENERGY
8 RATE AND STILL EXPOSE MICRON TO THE LONG RUN MARGINAL COST; IE
9 GET THE BENEFIT OF BOTH ACCURATE SHORT RUN PRICE SIGNALS AND
10 ACCURATE LONG RUN PRICE SIGNALS?
11 A. Yes. The difference between long run energy costs and short run energy costs could be
12 wrapped into a customer charge or a demand charge. IIPA would not oppose this approach.
13 Q. HOW DOES MICRON RESPOND TO YOUR LONG RUN MARGINAL COST
14 TESTIMONY?
15 A. Micron argues that new resources procured to serve Micron will lower embedded costs but
16 have little impact on marginal energy Costs.31
17 Q. IS MICRON'S TESTIMONY ACCURATE?
18 A. No, the testimony is not consistent with IPC's accounting processes. Micron appears to assume
19 that solar and wind are rate based and treated as fixed generation costs and don't increase
20 embedded energy costs. However, IPC treats solar and wind as energy costs regardless, thus
21 these resources do increase embedded energy costs. Moreover, the cost of IPC's recent solar
22 and wind PPAs are substantially higher than the embedded energy cost. In addition, Micron
23 appears to assume that a CCCT will reduce embedded energy costs without considering IPC's
31 Direct Rebuttal Testimony of Michael P. Gorman,at 7:19 to 8:19.
Case No. IPC-E-24-44 IIPA-Kaufinan, Su
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I forward price curve for gas or the interaction of the CCCT's generating capability and
2 Micron's load.
3 Q. IF MICRON TRULY BELIEVES THAT ITS LOAD WILL LEAD TO REDUCED
4 ENERGY COSTS, SHOULD IT OBJECT TO IIPA'S PROPOSAL TO CHARGE
5 LONG RUN EMERGY COSTS?
6 A. No, if Micron actually thought its testimony were true, it would prefer to pay long run marginal
7 costs and would not object to IIPA's proposal.
8 VIII. MARGINAL COST TRUE-UP
9 Q. DID YOU RECOMMEND AN ANNUAL TRUE-UP FOR MARGINAL COST
10 PRICING?
11 A. Yes, in opening testimony I noted that there is substantial forecast error risk associated with the
12 marginal pricing and all of this risk is borne by non-marginal cost customers. While this risk is
13 relatively small currently because there is not a material amount of load exposed to marginal
14 cost pricing, the much larger Micron ESA would lead to a large and material risk impact for
15 other customers.
16 Q. HOW DOES THE COMPANY RESPOND?
17 A. The Company acknowledges that there is a material forecast risk but suggests that adding a
18 true-up mechanism should be considered in IPC's next annual power cost update docket.32
19 Q. IS THE COMPANY'S PROPOSAL ACCEPTABLE?
20 A. IIPA is open to considering true-up and long-run cost issues in the context of a separate docket.
21 However, IPC's power cost update docket may not have sufficient scope to explore these
32 Rebuttal Testimony of Grant T.Anderson,at 15.
Case No. IPC-E-24-44 IIPA-Kaufinan, Su
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I issues. The order referenced by the Commission appears to direct IPC to work informally with
2 Staff outside a docketed case:
3 "[T]he Company shall work with Staff to evaluate methods to verify the current
4 marginal cost forecasting methods against the Company's actual marginal costs prior to
5 the next annual update to marginal pricing."33
6 IPC's annual update docket appears to be very streamlined. For example, IPC-E-25-17 was
7 filed on April 1, 2025, and the final order was issued on May 30, 2025. A 60-day proceeding
8 may not have sufficient depth to fully develop a new method of calculating long run marginal
9 energy costs or developing a true-up mechanism. If the marginal energy cost update docket is
10 used for introducing a long run marginal cost and true-up mechanism, the Company should file
11 the docket earlier in the year to provide sufficient time for development of new methods.
12
13
14 IX.TERMINATION RISK
15 Q. WHAT ISSUE DO YOU RAISE REGARDING TERMINATION RISK?
16 A. In my initial testimony I observed that, due to the differentiation between contract demand and
17 minimum billing demand, a scenario could arise in which IPC is unable to fully mitigate losses
18 associated with contract termination. I propose a floor to the termination payment based on five
19 times the annual difference between revenue and net energy value.
33 Order No.36619.
Case No. IPC-E-24-44 IIPA-Kaufinan, Su
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I Q. HOW DOES IPC RESPOND TO THIS TESTIMONY?
2 A. IPC responds by stating that IPC could mitigate losses through reducing imports rather than
3 selling excess generation at a loss.34
4 Q. WHAT IS PROBLEMATIC WITH IPC'S POSITION?
5 A. IPC's proposal to mitigate by reducing imports or generation rather than selling at a loss does
6 not resolve the fundamental problem. First, its my understanding that PPAs are often take or
7 pay, and for owned renewable resources, reducing generation does not reduce expenses.
8 Second, the 2025 IRP data show that purchases are in fact even less expensive than the
9 illustrative $45 per MWh, as seen in the table below.
34 Rebuttal Testimony of Jared L.Ellsworth,at 12:3-6.
Case No. IPC-E-24-44 IIPA-Kaufinan, Su
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I Table 2: 2025 IRP Market Purchases Cost35
Energy Cost Cost
Item Year (MWh) ($000) ($000) aMW $/MWh
Market Purchases 2026 3,004,216 $121,687 $2,026 343 $41
Market Purchases 2027 2,956,831 $114,787 $2,027 338 $39
Market Purchases 2028 2,929,772 $98,455 $2,028 334 $34
Market Purchases 2029 3,422,467 $104,452 $2,029 391 $31
Market Purchases 2030 3,485,388 $99,433 $2,030 398 $29
Market Purchases 2031 6,559,326 $170,014 $2,031 749 $26
Market Purchases 2032 7,465,911 $189,913 $2,032 852 $25
Market Purchases 2033 7,965,000 $170,858 $2,033 909 $21
Market Purchases 2034 8,287,743 $169,906 $2,034 946 $21
Market Purchases 2035 8,314,063 $173,111 $2,035 949 $21
Market Purchases 2036 8,352,876 $170,322 $2,036 954 $20
Market Purchases 2037 8,333,634 $156,491 $2,037 951 $19
Market Purchases 2038 8,341,124 $150,353 $2,038 952 $18
Market Purchases 2039 8,436,747 $125,055 $2,039 963 $15
Market Purchases 2040 8,503,556 $114,766 $2,040 971 $13
Market Purchases 2041 8,527,726 $108,116 $2,041 973 $13
Market Purchases 2042 8,508,460 $110,117 $2,042 971 $13
Market Purchases 2043 8,554,873 $112,160 $2,043 977 $13
Market Purchases 2044 8,689,232 $101,646 $2,044 992 $12
2 Market Purchases 2045 8,747,547 $106,923 $2,045 999 $12
3 A $13 per MWh reduction in energy will come nowhere near the lost revenue associated with
4 Micron and would only make the illustrative example in my initial testimony even more severe
5 and problematic for IPC.
6 Q. IS YOUR PROPOSED TERMINATION PAYMENT SENSATIVE TO MARKET
7 PRICES AND OTHER LOSS MITIGATION EFFORTS?
8 A. Yes, my example was purely illustrative. If IPC is successful in fully mitigating lost revenue
9 through modifying dispatch and market purchases such that there is no loss or stranded assets
10 on termination, the difference between revenue and net energy value would be zero and the
35 Exhibit 208,IPC Response to IIPA Request for Production 2-10.
Case No. IPC-E-24-44 IIPA-Kaufman, Su
08/15/2025 Page 24

I proposed floor would not be binding. Thus my proposal adds no burden to Micron. If IPC is
2 wrong, and IPC isn't able to fully mitigate lost revenue, my proposal would protect IPC by
3 filling in for the revenue shortfall.
4 Q. IF IPC IS CONFIDENT THAT IT CAN MITIGATE SUCH LOSSES,WOULD IT BE
5 APPROPRIATE FOR IPC SHAREHOLDERS TO BEAR THE RISK OF STRANDED
6 ASSETS?
7 A. Yes. In my view IPC is muddying the waters by speculating about methods of mitigating lost
8 revenue. If IPC truly views my concern as unwarranted, then IPC shareholders should be
9 responsible for the corresponding risk. If IPC shareholders are unwilling to bear the risk, it is
10 because the risk is indeed material, in which case customers should be protected through a
11 minimum termination payment.
12 X. IPC'S SYSTEM GROWTH IS ALREADY CAUSING PROBLEMS
13 Q. IPC INSISTS THAT ITS NO HARM ANALYSIS IS ACCURATE AND THAT THE
14 ESA DOES NOT POSE PROBLEMS FOR OTHER CUSTOMERS. IS THIS
15 CONSISTENT WITH IPC'S RESENT RATE CASE FILELING?
16 A. No. In IPC's resent general rate case, IPC has taken the position that IPC is experiencing
17 "unprecedented growth", which in turn is driving it's requested rate increase.
18 Q. DON'T ALL UTILITIES GROW? WHAT MAKES IPC'S CURRENT RATE CASE
19 DIFFERENT?
20 A. IPC differentiates this rate case as a situation of"unprecedented growth":
21 [T]he Company is expected to experience unprecedented growth over the next
22 five years, requiring the addition of new dispatchable resources to meet system
23 needs. As a result of this growth, as well as limited third-party transmission
24 capacity and a decline in the peak serving effectiveness of certain supply-side and
Case No. IPC-E-24-44 IIPA-Kaufinan, Su
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I demand-side resources, Idaho Power rapidly moved to a near-term capacity
2 deficiency identifying a capacity deficit in summer 2025.36
3 Q. WHAT MAKES IPC'S GROWTH UNPRECEDENTED?
4 A. While IPC is experiencing growth in residential and commercial classes, the unprecedented
5 component of IPCs growth is attributable to Micron, Brisbie, and other new large loads.
6 Q. WHAT DOES IPC SAY IN THE RATE CASE REGARDING CAPITAL INVESTMENT
7 GENERALLY?
8 A. IPC acknowledges that its growing capital expenditure is due to recent and expected economic
9 growth in its service territory. IPC plans to invest $6 billion in capital over the next four years
10 to meet this growth.37 In response to a direct question about what is causing IPC's investment
11 growth, IPC responds "Investment growth has been driven by a combination of factors
12 including meeting growing customer demands,maintaining an aging infrastructure, and
13 required compliance and security investments. ,38
14 Q. WHAT DOES IPC SAY IN THE RATE CASE REGARDING COST OF CAPITAL?
15 A. IPC notes that economic growth is driving down IPC's credit rating, increasing IPC's cost of
16 capital.39 "Idaho Power faces a number of challenges to maintaining, and at this point
17 repairing, its financial health while continuing to provide safe, reliable service to customers
18 during the current climate of unprecedented growth."40
36 Case No.IPC-E-25-16 Direct Testimony of Eric Hacket,at 3:11-19.
37 Case No.IPC-E-25-16 Direct Testimony of Brian R.Buckham,at 26:1-8.
38 Case No.IPC-E-25-16 Direct Testimony of Lisa A. Grow,at 21:19-22.
39 Case No.IPC-E-25-16 Direct Testimony of Brian R.Buckham,at 33:15-19.
40 Id., at 75.
Case No. IPC-E-24-44 IIPA-Kaufinan, Su
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I Q. WHAT DOES IPC SAY IN THE RATE CASE REGARDING TRANSMISSION
2 INVESTMENT?
3 A. IPC states "Growth and reliability are the primary drivers of the transmission investments
4 reflected in the Company's request in this case. Growth-related projects typically include either
5 the construction of new transmission facilities or the expanded capacity of existing facilities."41
6 Q. WHAT DOES IPC SAY IN THE RATE CASE ABOUT THE IMPACT OF GROWTH
7 ON LABOR EXPENSE?
8 A. IPC states "The continued development of new technologies that are critical to meeting
9 customers' energy needs, particularly given the residential and industrial growth in Idaho,
10 make it challenging to find talent given the competition in the Western United States. ...
11 Additionally, the demand for experienced electricians has skyrocketed given the Micron
12 expansion project and other large projects where specialized expertise is critical. ,42
13 Q. WHAT DOES THE COMPANY SAY REGARDING GROWTH AND REGULATORY
14 LAG?
15 A. IPC states "The application of a historical test year in the current environment of high growth
16 and rising costs has resulted in unsustainable regulatory lag impacting the Company's ability to
17 achieve reasonable rates of return and maintain sufficient credit metrics between rate cases."
18 Q. ARE THESE GROWTH RELATED COSTS CONTEMPLATED IN IPC'S NO-HARM
19 ANALYSIS OR THE PROPOSED ESA
20 A. No. The no harm analysis does not consider the impact the ESA has on cost of capital,
21 transmission, labor, or regulatory lag.
41 Case No.IPC-E-25-16 Direct Testimony of Mitch Colbum,at 16-17.
42 Case No.IPC-E-25-16 Direct Testimony of Sarah Griffin,at 12.
Case No. IPC-E-24-44 IIPA-Kaufinan, Su
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I Q. IN IPC'S CURRENT RATE CASE,DOES THE COMPANY OFFER A POSITION
2 REGARDING THE FUNCTION OF THE SPECIAL CONTRACT PROCESS IN
3 PROTECTING EXISTING CUSTOMERS?
4 A. Yes. The Company states "Idaho Power, with support from the Commission, has a long history
5 of applying a `growth pays for growth' policy to guide its cost assignment practices. ... In
6 addition, the Company's tariff requires any load greater than 20 megawatts ("MW") to enter
7 into a special contract with cost-based pricing that must be approved by the Commission. The
8 terms of the contracts are negotiated by the Company to prevent any inappropriate cost shifting
9 to other customers. These are just a few examples of the `growth pays for growth' policies that
10 help keep our rates lower for customers."43
11 Q. CAN YOU EXPLAIN WHY A"GROWTH PAYS FOR GROWTH" POLICY WOULD
12 KEEP CUSTOMER RATES LOW?
13 A. If growth pays for growth, that means that the costs caused by a growing customer class are
14 paid for by the growing customer class. If this policy is followed, then rate changes would not
15 be driven by growth.
16 Q. IS THE GROWTH PAYS FOR GROWTH POLICY EVIDENT IN IPC'S TESTIMONY
17 IN THIS CASE OR THE GENERAL RATE CASE?
18 A. No. In this case, the Company opposes increasing the special contract rate despite clear
19 evidence that Micron is driving IPC's costs up. In the general rate case, growth is flagged at
20 nearly every turn as a major cause for IPC's rate increases. In fact, growth appears in IPC's
21 GRC testimony 193 times. More importantly for the IIPA, the irrigation class is repeatedly
22 asked to pay the largest percentage rate increases of any rate class for growth driven rate
43 Case No.IPC-E-25-16 Direct Testimony of Lisa A.Grow,at 9:21-23; 10:5-12.
Case No. IPC-E-24-44 IIPA-Kaufinan, Su
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I increases despite being one of the only customer classes that has not grown over the last 20
2 years.
3 Q. MICRON IS CONCERNED THAT YOUR RECOMMENDATION WILL LEAD TO
4 RATES THAT EXCEED THE COST TO SERVE MICRON.44 IS THAT YOUR
5 INTENTION?
6 A. No. The objective of my testimony is to identify rates that ensure Micron is not subsidized by
7 other customers. IPC's general rate case testimony is clear that load growth is driving customer
8 rates up. IIPA is not looking for a handout from Micron. IIPA simply asks that Micron's
9 growth pays for its growth, consistent with IPC's stated policy, such that irrigation rates remain
10 unharmed.
11 Q. MICRON ALSO ARGUES THAT YOUR POPOSAL IS DISCRIMINATORY.45 IS
12 YOUR RECOMMENDATION DISCRIMINATORY?
13 A. No. IPC's policy of having growth pay for growth should apply to all customer classes and all
14 special contracts. IIPA intends to advocate for similar treatment for all special contract
15 applications moving forward.
16 Q. DOES THIS CONCLUDE YOUR TESTIMONY?
17 A. Yes.
44 Direct Rebuttal Testimony of Michael P. Gorman,at 3:3-6.
45 Id.,at 3:3-6.
Case No. IPC-E-24-44 IIPA-Kaufinan, Su
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CERTIFICATE OF SERVICE
I HEREBY CERTIFIY that on this 15th day of August, 2025, I served a true, correct and
complete copy of the Idaho Irrigation Pumpers Association, Inc.'s Surrebuttal 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)
secretgU( ,puc.idaho. ov ® 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)
chri s.burding]2uc.idaho.gov
Megan Goicoechea Allen ❑ U.S. Mail
Donovan E. Walker ❑ Hand Delivered
Connie Aschenbrenner ❑ Overnight Mail
Grant Anderson ❑ Telecopy (Fax)
Idaho Power Company ® Electronic Mail (Email)
1221 W. Idaho Street (83702)
P.O. Box 70
Boise, ID 83707
mgoicoecheaallengidahopower.com
dwalkergidahopower.com
dockets gidahopower.com
caschenbrenner(kidahopower.com
gandersongidahopower.com
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)
lance(kae isg insi hg t.com ® Electronic Mail (Email)
Case No. IPC-E-24-44 IIPA-Kauftnan, Su
08/15/2025 Page 30

Austin Rueschhoff ❑ U.S. Mail
Thorvald A. Nelson ❑ Hand Delivered
Austin W. Jensen ❑ Overnight Mail
Kristine A.K. Roach ❑ Telecopy (Fax)
Holland& Hart, LLP ® Electronic Mail (Email)
Micron Technology, Inc.
555 17th Street Suite 3200
Denver, CO 80202
darueschhoff(a hollandhart.com
tnelsonkhollandhart.com
awj ensen(d),hollandhart.com
karoach&hollandhart.com
acleeghollandhart.com
Industrial Customer of Idaho Power ❑ U.S. Mail
c/o Peter J. Richardson ❑ Hand Delivered
Richardson, Adams, PLLC ❑ 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
280 S. Silverwood Way ❑ Hand Delivered
Eagle, ID 83616 ❑ Overnight Mail
dreadinggmindspring com ❑ Telecopy (Fax)
❑ Electronic Mail (Email)
Courtney White ❑ U.S. Mail
Mike Heckler ❑ Hand Delivered
Clean Energy Opportunities for Idaho ❑ Overnight Mail
3778 Plantation River Drive, Suite 102 ❑ Telecopy (Fax)
Boise, ID 83703 ® Electronic Mail (Email)
courtneygcleanenergyopportunities.com
mike(&,cleanenergyopportunities.com
Case No. IPC-E-24-44 IIPA-Kauftnan, Su
08/15/2025 Page 31

Kelsey Jae (ISB No. 7899) ❑ U.S. Mail
Clean Energy Opportunities for Idaho ❑ Hand Delivered
920 N. Clover Dr., Boise, ID 83703 ❑ Overnight Mail
kelseykkelseyjae.com ❑ Telecopy (Fax)
® Electronic Mail (Email)
ERIC L. OLSEN
Case No. IPC-E-24-44 IIPA-Kaufinan, Su
08/15/2025 Page 32

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IDAHO POWER COMPANY'S CASE NO. IPC-E-24-44
APPLICATION FOR APPROVAL OF A
SPECIAL CONTRACT AND TARIFF
SCHEDULE 28 TO PROVIDE ELECTRIC
SERVICE TO MICRON IDAHO EXHIBIT 208
SEMICONDUCTOR MANUFACTURING
(TRITON) LLC
INTERVENOR
IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.
LANCE D. KAUFMAN, Ph.D.
Exhibit 208
Surrebuttal Discover Responses

REQUEST FOR PRODUCTION NO. IIPA 4-1: Please update IIPA 2-10 and 2-12 to
reflect the final IRP data.
RESPONSE TO REQUEST FOR PRODUCTION NO. IIPA 4-1: Idaho Power has
reviewed the draft 2025 Integrated Resource Plan ("IRP") data referenced in its prior
response to IIPA 2-10. Upon review, the Company confirms that there have been no
changes to the relevant data between the draft and final versions of the 2025 IRP that
would alter the response to IIPA 2-10.
Additionally, the response to IIPA 2-12 relates to the schedule of Minimum Monthly
Billing Demand by year from June 1, 2030, to June 1, 2050. This schedule is established
in accordance with Section 5 and Exhibit 3 of the Energy Services Agreement and is not
derived from or impacted by the final IRP data. However, Micron requested an adjustment
to the Scheduled Ramp Contract Demand During Expansion for 2028, increasing
Scheduled Ramp Contract Demand effective February 1, June 1, and October 1, 2028,
by 7.0 megawatts ("MW"), 16.5 MW, and 13.5 MW, respectively.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, and Grant T. Anderson, Pricing and Tariff
Manager, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
FOURTH SET OF DATA REQUESTS- 2

REQUEST FOR PRODUCTION NO. IIPA 4-2: Please refer to the updated
response to IIPA DR 2-10.
a. For each natural gas resource in the "Item" column, please indicate the type of
generator, the heat rate, and the nameplate capacity. Please provide this data for
sheet "DRAFT Cost Preferred Portfolio" and "DRAFT Cost 500 MW".
b. On the sheet "DRAFT Cost Preferred Portfolio", does the column "Energy MWh"
reflect the annual generation of the corresponding row? If no, what does this
column represent.
c. On the sheet "DRAFT Cost Preferred Portfolio", does the column "Cost $000"
reflect the annual cost of owning and operating the resource for the corresponding
row? If no, what does this column represent?
d. On the sheet "DRAFT Cost Preferred Portfolio", does column G divided by column
F reflect the cost in $000 per MWh for the corresponding row? If no, what does this
column represent?
RESPONSE TO REQUEST FOR PRODUCTION NO. IIPA 4-2: Please refer to
the Company's Response to Request for Production No. IIPA 4-1, which confirms that no
update to the response to IIPA 2-10 is necessary because the relevant data did not
change between the draft and final versions of the 2025 IRP.
The following provides additional detail in response to specific follow-up questions
regarding the file labeled "Response to IIPA's Request for Production No. 2-10":
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
FOURTH SET OF DATA REQUESTS- 3

a. Gas Resource Details
The table below provides the name, generator type, nameplate capacity (MW), and
nameplate heat rate (Btu/kWh) for each gas resource included in the IRP tables
referenced in DR 2-10:
Name Generator Nameplate Heat Rate Preferred Additional
Type (MW) (Btu/kWh) Portfolio 500 MW
Bennett Mountain SCCT 179.2 10,674 X X
Evander Andrews Power Complex(1) SCCT 179.2 10,662 X X
Evander Andrews Power Complex(2) SCCT 45.405 11,057 X X
Evander Andrews Power Complex(3) SCCT 45.066 11,543 X X
Jim Bridger IPC(1) NG Boiler 177 10,410 X X
Jim Bridger IPC(2) NG Boiler 179.7 10,265 X X
New Resource 878 from Bridger3 NG Boiler 174.3 10,743 X X
New Resource 879 from Bridger4_NG Boiler 175.3 10,474 X X
Langley Gulch Power Plant(GTG) CCCT 320.9 6,930.5 X X
North Valmy IPC(1) NG Boiler 127 11,000 X X
North Valmy IPC(2) NG Boiler 134 11,000 X X
New Resource 2575 from RECIP_NG Recip 50 7,600 X X
New Resource 2576 from RECIP_NG Recip 50 7,600 X X
New Resource 2577 from RECIP_NG Recip 50 7,600 X X
New Resource 2706 from CCCT_NG_PE_50 CCCT 300 6,363 X X
New Resource 2738 from RECIP_NG_PE_75 Recip 50 7,600 X
New Resource 2742 from RECIP_NG_PE_75 Recip 50 7,600 X
New Resource 2744 from RECIP_NG PE_75 Recip 50 7,600 X
New Resource 2748 from RECIP_NG_PE_75 Recip 50 7,600 X
New Resource 2798 from RECIP_NG—PE_120 Recip 50 7,600 X
New Resource 2806 from RECIP_NG_PE_120 Recip 50 7,600 X
New Resource 2822 from SCCT_NG_PE_120 SCCT 150 9,717 X
New Resource 2853 from CCCT NG PE 120 CCCT 300 6,363 X
b. Annual Energy (MWh) Column Clarification
No, the "Energy MWh" column on the "DRAFT Cost Preferred Portfolio" sheet
reflects the annual energy associated with each item and not strictly generation.
For generation resources, it represents total annual generation. For storage
resources, it reflects the net energy charged and discharged. For energy efficiency
("EE") or demand response ("DR") resources, it reflects the reduction due to EE or
DR. For market transactions, it represents the total energy volume associated with
purchases or sales.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
FOURTH SET OF DATA REQUESTS-4

c. Annual Cost ($000) Column Clarification
No, the "Cost $000" column on the same sheet reflects the annual cost out of the
model for each resource or transaction. For resources that appear in all portfolios,
the value may be zero or represent incremental dispatch cost only if that cost
varies. For market transactions, the column shows the total monetary value of
purchases or sales for that year.
d. Cost per MWh
Yes, dividing column G ("Cost $000") by column F ("Energy MWh") yields the cost
per megawatt-hour ($000/MWh).
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
FOURTH SET OF DATA REQUESTS- 5

REQUEST FOR PRODUCTION NO. IIPA 4-3: Please refer to the Rebuttal
Testimony of Jared L. Ellsworth at 4:7-12.
a. Please refer to the Ellsworth Exhibit No. 2 and response to IIPA DR 3-3 part b
which indicates that the costs in IIPA 2-10 Attachment DRAFT Cost Preferred
Portfolio are not present value. Please clarify whether the analysis in Ellsworth
Exhibit No. 2 is in present value.
b. What analysis of IIPA's direct testimony was performed in net present value that
should not have been performed in net present value?
RESPONSE TO REQUEST FOR PRODUCTION NO. IIPA 4-3:
a. The calculations in Ellsworth Exhibit No. 2 are not present value figures. Exhibit
No. 2 does not represent the portfolio cost from Idaho Power's Integrated
Resource Plan ("IRP"), but rather, it contains raw cost data that serves as input to
the IRP's Present Value Revenue Requirement ("PVRR") calculations. While this
data informs the PVRR, it is a distinct dataset and should not be interpreted as a
levelized or net present value figure.
b. As stated in Jared L. Ellsworth's rebuttal testimony, the Company's position is that
the analysis presented in IIPA's direct testimony mischaracterizes the IRP portfolio
cost metric particularly in its proposed application for determining the revenue
requirement as discussed in Section Five of Kaufman's direct testimony. The
concern is not whether the analysis was performed in net present value terms, but
rather that it incorrectly interprets the levelized planning metric as a tool for
ratemaking or customer pricing.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
FOURTH SET OF DATA REQUESTS- 6

The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
FOURTH SET OF DATA REQUESTS- 7

REQUEST FOR PRODUCTION NO. IIPA 4-4: Please provide the workpaper
"Exhibit 103 CONF Updated Modeling Exercise Including Unused Sheets" filed under
Public Utility Commission of Oregon Docket No. UM 2000.
RESPONSE TO REQUEST FOR PRODUCTION NO. IIPA 4-4: Please see the
file labeled "Response to IIPA Request No. 4-4 - Confidential Attachment" for the
requested workpaper. The rates shown in the confidential attachment are illustrative and
for discussion purposes only as they reflect Oregon Staff's proposal at the time of exhibit
filing. The confidential attachment and its resulting data should not be utilized in matters
that are not related to Oregon Docket No. UM 2000.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
FOURTH SET OF DATA REQUESTS- 8

REQUEST FOR PRODUCTION NO. IIPA 4-5: Please provide the Company's
current forward price curve for each energy market the company participates in. Provide
such data by month from 2025 to 2045.
RESPONSE TO REQUEST FOR PRODUCTION NO. IIPA 4-5: Please see the
file labeled "Response to IIPA Request No. 4-5 - Confidential Attachment," which includes
forward and actual price information for the Intercontinental Exchange ("ICE") indices
corresponding to the market hubs in which the Company participates.
The forward price curves included are current as of August 2025. Monthly forward
price data is not available for historical periods; therefore, for the period January 2025
through July 2025, the Company is providing actual settled prices. The Company's
current forward price data extends through 2033. Because the Company does not have
forward market data beyond 2033, no data is provided for the period 2034 through 2045.
The response to this Request is sponsored by Camille Christen, Resource
Acquisition, Planning, and Coordination Manager, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
FOURTH SET OF DATA REQUESTS- 9

REQUEST FOR PRODUCTION NO. IIPA 4-6: Please refer to the Rebuttal
Testimony of Jared L. Ellsworth at 11:21 to 12:6
a. Does the IRP price imports differ from exports in any given hour? If yes, please
explain why. If no, please explain why reducing imports would have a different
financial impact than increasing sales in response to reduced Micron load.
b. Please provide the hourly imports and exports, and import price and export price
for the 2025 IRP preferred portfolio and 500 MW additional load growth scenario.
RESPONSE TO REQUEST FOR PRODUCTION NO. IIPA 4-6:
a. Yes, in any given hour, the IRP prices imports and exports differently. Import and
export prices reflect the zonal price of energy from the zone in which the
transaction originates. Specifically, the price of imported energy corresponds to
the cost of energy from the external zone supplying it, while the price of exported
energy reflects the value of energy from the exporting zone.
b. The Company does not have hourly-level detail for import and export prices for
either the 2025 IRP Preferred Portfolio or the 500 MW Additional Load Growth
scenario.
Additionally, these questions do not address the primary issue and flaw in Dr.
Kaufman's analysis - it assumes that a reduction in Micron's load would result in
surplus generation that Idaho Power would be forced to sell at a loss. This
assumption fails to consider that, in response to lower load, the Company could
maintain its generation and reduce imports instead of increasing exports. This
would avoid lower-value export transactions and instead displace higher-cost
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
FOURTH SET OF DATA REQUESTS- 10

imports, resulting in a different financial impact than assumed in Dr. Kaufman's
testimony.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
FOURTH SET OF DATA REQUESTS- 11

REQUEST FOR PRODUCTION NO. IIPA 4-7: Please refer to Attachment -
Response to IIPA's Request for Production No. 2-13.xlsx.
a. Is the termination payment in this scenario $154 million? If no, where does the
termination payment appear?
b. Please refer to the Opening Testimony of Lance Kaufman at 21 . Does the
Company agree that the lost revenue under current rates and the scenario
assumed in IIPA's Request for Production No. 2-13 is approximately $248 million?
If no, what is the expected lost revenue under the rates assumed in the response
to IIPA DR 2-13?
c. Does the Company agree that if purchases are reduced to match a reduction in
Micron load under the scenario explored in Opening Testimony of Lance Kaufman
at 21, and market prices are $45 per MWh, the Company will experience an annual
shortfall of $89 million per year? If no, why not?
RESPONSE TO REQUEST FOR PRODUCTION NO. IIPA 4-7:
a. Yes, the termination payment under this scenario is reflected as $154 million in the
file provided in response to IIPA Request No. 2-13.
b. No, the analysis overstates the financial exposure. Dr. Kaufman's calculation
assumes that the Company would be financially exposed to the full revenue
shortfall without any operational or planning adjustments. However, Idaho Power
designed the termination payment to account for unrecovered investment and a
portion of fixed cost exposure, not to fully replace all future revenues. The
Company's system planning and operations allow for adjustments in resource
procurement, project development, and system dispatch that reduce exposure to
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
FOURTH SET OF DATA REQUESTS- 12

such scenarios. Fuel costs, O&M expenses, capacity reserves, and capital
expenditures can be reduced or deferred in response to a major load reduction.
Dr. Kaufman's analysis also does not reflect revenues collected over the preceding
20 years of contract service. As such, his estimate does not accurately represent
net financial impact or appropriately consider the Company's ability to mitigate
losses over time.
c. No, the Company does not agree with the assertion that it would experience an
$89 million annual shortfall under the scenario described. This estimate presumes
that Idaho Power would continue procuring and incurring costs for surplus energy
without any change in strategy, and that excess energy could only be sold at a
market price of $45 per MWh. In practice, Idaho Power would adjust its market
purchases, generation dispatch, and resource portfolio to reflect updated load
forecasts. Additionally, the assumed $45 per MWh market price may not reflect
forward market expectations for the relevant year (2047) and does not account for
avoided costs, potential arbitrage value, or other offsets. The Company's IRP-
based modeling and procurement flexibility are specifically intended to manage the
type of risk described, and the scenario presented does not fully reflect that
dynamic planning environment.
The response to this Request is sponsored by Connie G. Aschenbrenner, Director
of Regulatory Affairs, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
FOURTH SET OF DATA REQUESTS- 13

REQUEST FOR PRODUCTION NO. IIPA 4-8: Please refer to Kaufman Exhibit
207, which states "Micron plans to invest an additional $30 billion beyond prior plans
which includes building a second leading-edge memory fab in Boise, Idaho". Has Micron
communicated with IPC about service for a second new FAB?
RESPONSE TO REQUEST FOR PRODUCTION NO. IIPA 4-8: Yes, Idaho Power
is aware of Micron's plans for a potential second memory fabrication facility in Boise. .
Pursuant to Section 5.3(a) of the Micron FAB Special Contract, the maximum Contract
Demand is 507 MW. Any request to serve load beyond this limit would be subject to
Commission review and approval of an amendment to the special contract. Additionally,
if a second memory fabrication facility were to be served through unique interconnection
facilities (e.g., transmission voltage), a separate special contract would need to be
executed and filed for Commission approval.
The response to this Request is sponsored by Grant T. Anderson, Pricing and
Tariff Manager, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
FOURTH SET OF DATA REQUESTS- 14

REQUEST FOR PRODUCTION NO. IIPA 4-9: Please refer to response to IIPA
Request No. 1-4.
a. Please provide the project description and project justification for each item in the
confidential attachment.
b. Please provide all documents and communications provided to Company's
Transmission & Distribution Project ("T&D") team regarding power flow analysis.
c. Please provide all documents produced by the T&D team in the process of scoping
out the required transmission upgrades.
RESPONSE TO REQUEST FOR PRODUCTION NO. IIPA 4-9:
a. For project descriptions please see Response 4-9(c).
b. Construction requirements for the transmission lines into CHIP substation were
communicated to the T&D team via scoping meetings. Those conversations
resulted in the transmission line construction requirements being documented in
the scope documents provided in 4-9c. Requirements for the capacitor banks were
communicated through the file labeled "Response to IIPA Request No. 4-9(b) —
CEII Confidential Attachment".
c. Please see the attached files labelled CEII Confidential Attachments 1-8 for this
response.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
FOURTH SET OF DATA REQUESTS- 15

REQUEST FOR PRODUCTION NO. IIPA 4-10: Please refer to the Idaho Power
Company 2025 IRP page 5 which states "The current regional electric market, regulatory
environment, pace of technological change, rapid load growth, and Idaho Power's goal of
100% clean energy by 2045 make the 2025 Near-Term Action Plan especially relevant."
a. Does Idaho power have a goal of 100 percent clean energy by 2045?
b. Has a clean energy goal affected Idaho Power's resource procurement? If no, why
not?
RESPONSE TO REQUEST FOR PRODUCTION NO. IIPA 4-10:
a. Yes, Idaho Power has established a goal of achieving 100 percent clean energy
by 2045.
b. No, the Company continues to evaluate resource procurement on a least-cost /
least-risk criteria and selects resources based on that standard.
The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.'S
FOURTH SET OF DATA REQUESTS- 16

MICRON TECHNOLOGY, INC.
CASE IPC-E-24-44
IIPA'S FIRST SET OF DATA REQUESTS TO
MICRON TECHNOLOGY, INC.
IIPA 1-1:
Please refer to Kaufman Exhibit 207,which states"Micron plans to invest an additional$30 billion
beyond prior plans which includes building a second leading-edge memory fab in Boise, Idaho".
Please provide the expected energy demand for the second Idaho FAB referenced in the press
release. If such data are not available please provide the potential range of energy demand.
OBJECTION
Micron objects to IIPA's Data Request IIPA 1-1 for at least three reasons.
First,the discovery request includes a partial quotation of a sentence in the referenced press release
and is misleading. The full sentence quoted in the press release marked as Kaufman Exhibit 207
is"As part of today's announcement,Micron plans to invest an additional$30 billion beyond prior
plans which includes building a second leading-edge memory fab in Boise, Idaho; expanding and
modernizing its existing manufacturing facility in Manassas, Virginia; and bringing advanced
packaging capabilities to the U.S.to enable long-term growth in High Bandwidth Memory(HBM),
which is essential to the Al market." The press release does not state or imply that Micron will
invest $30 billion solely in a second Micron Fab in Boise.
Second, the discovery request seeks information that is not relevant to Idaho Power's application
in this case and is not reasonably calculated to lead to the discovery of admissible evidence. This
case concerns the proposed tariff Schedule 28 and the terms and conditions of the proposed Special
Contract for the first Micron Fab. Electric service for a future second Micron Fab as discussed in
Kaufman Exhibit 207 and announced on June 12, 2025 is not at issue in this case.
Third, the discovery request seeks trade secret, proprietary, confidential, financial or commercial
sensitive information, the disclosure of which could negatively impact Micron's competitive
business position.
Sponsor: Micron Counsel
RESPONSE TO IIPA 1-1:
Subject to and without waiving Micron's objections,Micron is still in the early planning stages for
the second Micron Fab. A typical Micron Fab has a peak demand of approximately 400 MW. At
this time,Micron continues to engage with Idaho Power and is evaluating all available avenues for
energy procurement.
Sponsor: Micron Counsel
MICRON TECHNOLOGY, INC.'S
RESPONSES TO IDAHO IRRIGATION PUMPER ASSOCIATION, INC.'S
FIRST SET OF DATA REQUESTS -3-

MICRON TECHNOLOGY, INC.
CASE IPC-E-24-44
IIPA'S FIRST SET OF DATA REQUESTS TO
MICRON TECHNOLOGY, INC.
IIPA 1-2:
Please provide all work papers, models, calculations and source data, with formulas intact, relied
upon to support the rebuttal Testimony of witness Michael P. Gorman.
RESPONSE TO IIPA 1-2:
Please see the attached workpapers supporting Mr. Gorman's rebuttal testimony and exhibits:
• Attachment 1 (Confidential Exhibit MPG-1)
• Attachment 2 (Confidential Exhibit MPG-2)
Sponsor: Micron Counsel
MICRON TECHNOLOGY, INC.'S
RESPONSES TO IDAHO IRRIGATION PUMPER ASSOCIATION, INC.'S
FIRST SET OF DATA REQUESTS -4-

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IDAHO POWER COMPANY'S CASE NO. IPC-E-24-44
APPLICATION FOR APPROVAL OF A
SPECIAL CONTRACT AND TARIFF
SCHEDULE 28 TO PROVIDE ELECTRIC
SERVICE TO MICRON IDAHO EXHIBIT 209
SEMICONDUCTOR MANUFACTURING
(TRITON) LLC
INTERVENOR
IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.
LANCE D. KAUFMAN, Ph.D.
Confidential Exhibit 209
Corrected Micron CCCT Model

Idaho Power Company
Cost of CCCT at 2030
Line Description MPG-2 Correct Depr.Exp Correct O&M IPC Gas Price 50%Capacity Factor
(1) (1) (1) (1) (1)
1 Nameplate Capacity(MW)' 300 300 300 300 300
2 Capacity Factor 90% 90% 90% 90% 50%
3 Overnight Plant Capital' $495,000,000 $495,000,000 $495,000,000 $495,000,000 $495,000,000
4 AFUDC Rate 7.40% 7.40% 7.40% 7.40% 7.40%
5 AFUDC3 $75,970,620 $75,970,620 $75,970,620 $75,970,620 $75,970,620
6 Installed Cost of Plant(Line 3+Line 5) $570,970,620 $570,970,620 $570,970,620 $570,970,620 $570,970,620
7 Transmission Interconnection Plant' $57,300,000 $57,300,000 $57,300,000 $57,300,000 $57,300,000
8 Total Plant Cost(Line 6+Line 7) $628,270,620 $628,270,620 $628,270,620 $628,270,620 $628,270,620
9 Annual Depreciation Cost(Line 8/Assumed Life of 30 Yrs') $20,942,354 $20,942,354 $20,942,354 $20,942,354 $20,942,354
30 Accumulated Depreciation(1/2 yr conv) $10,471,177 $10,471,177 $10,471,177 $10,471,177 $10,471,177
11 Net Plant(2026)(Line 8-Line 10) $617,799,443 $617,799,443 $617,799,443 $617,799,443 $617,799,443
12 Pre-Tax ROR' 8.912% 8.912% 8.912% 8.912% 8.912%
13 Return(2026)(Line 11 x Line 12) $55,058,286 $55,058,286 $55,058,286 $55,058,286 $55,058,286
14 Fixed 0&M(2026)' $480,000 $480,000 $5,760,000 $5,760,000 $5,760,000
15 Total Fixed Cost(2026)(F Lines 9,13,14) $66,009,463 $76,480,640 $81,760,640 $81,760,640 $81,760,640
16 With LOLP Reserve at 20%. $79,211,356 $91,776,768 $98,112,768 $98,112,768 $98,112,768
17 Cost Per MWh if in-service 2026 CF 90%s $33.49 $38.80 $41.48 $41.48 $74.67
18 Supply Side escalation rate 2.40% 2.40% 2.40% 2.40% 2.40%
19 Fixed Cost Per MWh in-service 2030 and 2035,CF 90%6 $36.82 $42.66 $45.61 $45.61 $82.10
20 Heat Rate(BTU/kWh)' 6,431 6,431 6,431 6,431 6,431
21 Assumed Delivered Nat Gas($/Dth)8 $4.00 $4.00 $4.00
22 Fuel Expense($/MWh)(Line 20 x Line 21/1,000) $25.72 $25.72 $25.72 $29.84 $29.84
23 Variable 0&M($/MWh)2026' $3.40 $3.40 $3.40 $3.40 $3.40
24 Variable 0&M($/MWh)2030 and 20357 $3.74 $3.74 $3.74 $3.74 $3.74
25 Variable Cost($/MWh)(Line 22+Line 24) $29.46 $29.46 $29.46 $33.58 $33.58
26 Total Cost(2030 and 2035)(Line 19+Line 25) $66.29 $72.13 $75.07 $79.19 $115.68
Sources&Notes:
12025 Integrated Resource Plan-Appendix C:Technical Report Page 22.
22025 Integrated Resource Plan-Appendix C:Technical Report Page 21.
3 Line 3 x(1+Line 4)^2-Line 3-Assumes 2 years ofAFUDC.
°Calculated using data shown on 2025 Integrated Resource Plan-Appendix C:Technical Report Page 21.See tab'Pre-Tax ROR'.
5 Line 16/(Line 1 x Line 2 x 8760 hrs).
6 2030=Line 17 x(1+1_ine18)^4.2035=Line 17 x(1+Line18)^9.
'2030=Line 23 x(1+Line18)^4.2035=Line 23 x(1+Line18)^9.
s IPC Confidential Response to IIPA DR 4-4

Idaho Power Company
Cost of CCCT at 2035
Line Description MPG-2 Correct Depr.Exp Correct O&M IPC Gas Price 50%Capacity Factoi
(1) (1) (1) (1) (1)
1 Nameplate Capacity(MW)' 300 300 300 300 300
2 Capacity Factor 90% 90% 90% 90% 50%
3 Overnight Plant Capital' $495,000,000 $495,000,000 $495,000,000 $495,000,000 $495,000,000
4 AFUDC Rate' 7.40% 7.40% 7.40% 7.40% 7.40%
5 AFUDC3 $75,970,620 $75,970,620 $75,970,620 $75,970,620 $75,970,620
6 Installed Cost of Plant(Line 3+Line 5) $570,970,620 $570,970,620 $570,970,620 $570,970,620 $570,970,620
7 Transmission Interconnection Plant' $57,300,000 $57,300,000 $57,300,000 $57,300,000 $57,300,000
8 Total Plant Cost(Line 6+Line 7) $628,270,620 $628,270,620 $628,270,620 $628,270,620 $628,270,620
9 Annual Depreciation Cost(Line 8/Assumed Life of 30 Yrs) $20,942,354 $20,942,354 $20,942,354 $20,942,354 $20,942,354
10 Accumulated Depreciation(1/2 yr conv) $10,471,177 $10,471,177 $10,471,177 $10,471,177 $10,471,177
11 Net Plant(2026)(Line 8-Line 10) $617,799,443 $617,799,443 $617,799,443 $617,799,443 $617,799,443
12 Pre-Tax ROR4 8.912% 8.912% 8.912% 8.912% 8.912%
13 Return(2026)(Line 11 x Line 12) $55,058,286 $55,058,286 $55,058,286 $55,058,286 $55,058,286
14 Fixed O&M(2026)' $480,000 $480,000 $5,760,000 $5,760,000 $5,760,000
15 Total Fixed Cost(2026)(F Lines 9,13,14) $66,009,463 $76,480,640 $81,760,640 $81,760,640 $81,760,640
16 With LOLP Reserve at 20%. $79,211,356 $91,776,768 $98,112,768 $98,112,768 $98,112,768
17 Cost Per MWh if in-service 2026 CIF 90%s $33.49 $38.80 $41.48 $41.48 $74.67
18 Supply Side escalation rate' 2.40% 2.40% 2.40% 2.40% 2.40%
19 Fixed Cost Per MWh in-service 2030 and 2035,CF 90%6 $36.82 $42.66 $45.61 $45.61 $82.10
20 Heat Rate(BTU/kWh)' 6,431 6,431 6,431 6,431 6,431
21 Assumed Delivered Nat Gas($/Dth)8 $4.00 $4.00 $4.00
22 Fuel Expense($/MWh)(Line 20 x Line 21/1,000) $25.72 $25.72 $25.72 $29.84 $29.84
23 Variable 0&M($/MWh)2026' $3.40 $3.40 $3.40 $3.40 $3.40
24 Variable 0&M($/MWh)2030 and 20357 $3.74 $3.74 $3.74 $3.74 $3.74
25 Variable Cost($/MWh)(Line 22+Line 24) $29.46 $29.46 $29.46 $33.58 $33.58
26 Total Cost(2030 and 2035)(Line 19+Line 25) $66.29 $72.13 $75.07 $79.19 $115.68
Sources&Notes:
'2025 Integrated Resource Plan-Appendix C:Technical Report Page 22.
22025 Integrated Resource Plan-Appendix C:Technical Report Page 21.
3 Line 3 x(1+Line 4)A2-Line 3-Assumes 2 years ofAFUDC.
°Calculated using data shown on 2025 Integrated Resource Plan-Appendix C:Technical Report Page 21.See tab'Pre-Tax ROR'.
5 Line 16/(Line 1 x Line 2 x 8760 hrs).
6 2030=Line 17 x(1+Line18)A4.2035=Line 17 x(1+Line18)A9.
'2030=Line 23 x(1+Line18)A4.2035=Line 23 x(1+Line18)A9.
s IPC Confidential Response to IIPA DR 4-4

CONFIDENTIAL
PROTECTED INFORMATION
Table 9
Gas Price Forecast
$/M M Btu
Idaho Gas Fleet Forecast: Langley Gulch, Danskin, and Bennett
Henry Hub Forecast Updated Delivered NG Cost
Year Platt's Nymex Sumas Basis Transport Cost (Idaho City Gate Price)
(Nominal$/mmBtu) (Nominal$/mmBtu) (Nominal$/mmBtu) (Nominal$/mmBtu)
(a) (b) (c) (d)
(a) + (b) + (c)

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IDAHO POWER COMPANY'S CASE NO. IPC-E-24-44
APPLICATION FOR APPROVAL OF A
SPECIAL CONTRACT AND TARIFF
SCHEDULE 28 TO PROVIDE ELECTRIC
SERVICE TO MICRON IDAHO EXHIBIT 210
SEMICONDUCTOR MANUFACTURING
(TRITON) LLC
INTERVENOR
IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.
LANCE D. KAUFMAN, Ph.D.
Exhibit 210
Bonneville Power Administration New Large Single Load Policy

Bonneville Power Administration
New Large Single Load Policy
April 2001

Bonneville Power Administration
New Large Single Load Policy
Table of Contents
Summary of New Large Single Load Policy— Practices
CurrentlyUsed................................................................................. 1
I. Preface .............................................................................................................. 3
II. Overview of New Large Single Load Planning ............................................ 5
III. Contracted For, Committed To (CFCT) Determination Process ............... 8
IV. Facility Determination Process ...................................................................... 9
V. New Large Single Load (NLSL) Determination Process ............................ 10
VI. Northwest Power Act Section 3(13) Decisions ....................................13

SUMMARY OF NEW LARGE SINGLE LOAD POLICY
PRACTICES CURRENTLY USED
Section 3(13) of the Pacific Northwest Electric Power Planning and Conservation Act(Act)
defines a New Large Single Load(NLSL) to be any new load or expansion of an existing load at
a single facility whose power requirements increase by 10 average megawatts (aMW) or more in
any consecutive 12-month period as compared to its consumption during the immediately
preceding 12-month period.
"New Large Single Load"means any load associated with a new facility, an existing
facility, or an expansion of an existing facility:
(1) which is not contracted for, or committed to, as determined by Bonneville, by a
public body, cooperative, investor-owned utility, or Federal agency Customer prior
to September 1, 1979, and
(2) which will result in an increase in power requirements of such Customer of ten
average megawatts or more in any consecutive twelve-month period.
Power purchased from BPA to serve NLSLs must be at the section 7(f)new resource rate. Power
is available from BPA at the section 7(b)priority firm rate for non-NLSL firm loads of
preference customers. In providing service to new large loads, BPA has used the following
practices.
SERVICE PRACTICE
Phased-In Load
A load can be served with power purchased by a preference customer at the 7(b) rate if the
increase in load in any consecutive 12-month period does not reach 10 aMW as compared to the
previous 12-month period. Any increase of 10 aMW or more occurring in any consecutive
12-month period causes the load to become a NLSL; the increase and any future increases are to
be served at the 7(f)rate.
CFCT Determination
A new load of 10 aMW or more may be served with power purchased by a preference customer at
the 7(b)rate if it was "contracted for, or committed to" (CFCT)by the utility prior to September 1,
1979. CFCT status assures the load an agreed-upon base level of service at the 7(b)rate for the
life of the facility. Any load above the CFCT level which equals or exceeds 10 aMW in any
consecutive 12-month period as compared to the previous 12-month period is considered a NLSL
to be served at the 7(f) rate. Once this occurs, any subsequent increment of load is also considered
a NLSL to be served at the 7(f) rate.
Facility Determination
A preference customer's new load may be served with power purchased at the 7(b)rate if it
consists of two or more distinct loads which meet each of the following criteria:
- are separately metered;
- - experience annual load growth under 10 aMW;
- involve different manufacturing processes or products;
- are independent of one another;
- are contracted-for and customarily billed as separate loads; and
- are treated consistently with similar fact situations.
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Start-Up Date
Either the date of initial energization of a facility(for testing or start-up) or the commencement of
commercial operation may be selected, with BPA's concurrence, to define the start of the
consecutive 12-month periods. Depending on the anticipated first-year usage pattern of the load,
selection of one date over the other may enable a load to receive power purchased by a preference
customer at the 7(b) rate.
Resource Dedication
A NLSL need not be served with power purchased from BPA. A customer may declare all or a
portion of a customer-owned resource which is not included in the utility's Net Requirements
Exhibit or Firm Resources Exhibit(FRE) in its power sales contract or which has been withdrawn
from such exhibit may be dedicated to serving a NLSL. However, if the resource cannot supply
the total requirements of the NLSL, BPA may serve the difference at the 7(f)rate with
appropriate notice.
Change in Utility
A load is not a NLSL if it moves from one location to another within the serving utility's service
territory. A load which changes utilities becomes a NLSL if its energy consumption during the
first 12-month period commencing on the date it becomes served by the new utility is 10 aMWor
more.
2

NEW LARGE SINGLE LOAD POLICY
I. Preface
The NLSL statutory definition was first incorporated into BPA's 1981 power sales contracts with
its utility customers. BPA's newly executed subscription power sales contracts continue to
incorporate the definition and the NLSL policy. This policy includes background, an overview of
decisions involved in service to new large loads, and descriptions of the three principal types of
BPA determinations affecting those loads. These are: (1) contracted for, committed to (CFCT)
determinations; (2) facility determinations; and(3)new large single load determinations.
THIS DOCUMENT IN NO WAY ATTEMPTS TO CHANGE OR IMPLEMENT NEW
POLICY APPROACHES TO NEW LARGE SINGLE LOADS; IT IS MERELY A
CONSOLIDATION OF PREVIOUSLY ANNOUNCED POLICIES AND SERVICES
APPROACHES.
A. Origin of New Large Single Load Restrictions
When the Northwest Power Act was being developed in the late 1970s, BPA and the region fully
expected to be facing power supply deficits in the near future. In fact, in 1975, BPA had issued
Notices of Insufficiency to its investor-owned utility customers (IOU's), which ended firm sales
to IOU's. BPA's efforts to develop a power allocation policy anticipated shortages for another
major BPA customer group, the preference utilities. These expected shortages stimulated the
development of provisions in the act, including the new large single load provisions, which
would limit access to federal power. Congress considered a number of factors for inclusion of
the NLSL provisions in the Northwest Power Act.
First,NLSL provisions helped broaden the support for passage of the Act by representatives from
other parts of the country. NLSL restrictions in the Northwest would protect industry in other
parts of the country by eliminating rate inducements to relocate to the Pacific Northwest. This
was a critical element in securing support for the Act from Congressional members from the
Northeast. Second,NLSL restrictions were also intended to equalize rates to new industries
between BPA's preference utility customers and IOU's. This increased support for the Act from
Northwest IOU's. Third,NLSL provisions were included to induce DSI's to sign new contracts
with BPA. By preventing DSI's from obtaining retail service from preference utilities with
relatively low priority firm rates,NLSL provisions helped to obtain the regional reserves and rate
support from DSI's that were part of the structure of the Act. Fourth, NLSL provisions were
intended to preserve Federal base system resources for residential and farm loads (especially
important because of the expected regional resource deficits). Finally,NLSL provisions were
designed to motivate,by means of marginal cost pricing, the adoption of energy-efficient
processes or designs by new industries. Conservation and environmental groups therefore
supported NLSL provisions in the interest of energy efficiency.
B. Northwest Power Act References
Several sections of the Northwest Power Act refer to NLSL's. Section 3(13) defines New Large
Single Loads. Section 7(b)(4)prohibits NLSL's from receiving service at the Priority Firm
Power rate. Section 5(c)(7)(A) excludes the cost of resources used to serve NLSL's from a
utility's Average System Cost under the Residential Exchange program.
3

C. Effects on Preference Customers and IOU's
Preference customers who serve NLSL's would see an increase in their power bills from BPA
compared to the costs of serving other loads. Power to serve NLSL's must be sold to utilities at
the higher New Resources Firm Power(NR) rate,while BPA serves other loads at the relatively
lower Priority Firm Power(PF)rate. A preference utility would have to recover the higher cost
of NR power from its ratepayers. These higher costs may influence a new industry's decision on
where to locate a new operation.
Except for power exchanged to serve their residential loads, IOU's are required under the
Northwest Power Act to pay the NR rate for all requirements power from BPA. Hence, the rate
for BPA power to serve a NLSL of an IOU would not differ from the rate to serve other
commercial or industrial loads. However, the costs of resources to serve the NLSL are excluded
from the utility's Average System Cost (ASC), likely reducing payments under the Exchange
Program under section 5(c) of the Northwest Power Act. Service to NLSL's will remove high
cost resources from the utility's ASC, reducing the difference between the ASC and BPA's costs,
which in turn reduces the utility's exchange payments from BPA. The end result is to increase
the utility's costs, which will probably tend to increase rates.
For all utilities, the information requirements for NLSL determinations and the monitoring and
reporting requirements result in BPA's involvement in relations between the utility and the
consumer to a much greater degree than occurred prior to the Northwest Power Act. As the text
below shows,NLSL requirements and determinations require a lot of information and planning
which may significantly alter an industry's approach to the development of new operations.
D. Application of the New Large Single Load Policy To BPA's Power Sales
Contracts
In general, BPA power sales contracts contain specific language with regard to the application of
the NLSL policy on service to load under the contract. For example, existing 1981 power sales
contracts contain detailed provisions on service to a NLSL. See section 8 of the 1981 power
sales contract. Recently executed contracts all contain provisions for the exchange of
information and most contain NLSL provisions that reference and incorporate the NLSL policy.
The contracts that specifically reference the NLSL policy contain provisions that require BPA's
utility customers to notify and inform BPA of the development of a NLSL in their service area.
If such load is determined a NLSL and BPA is requested to serve the contracts specify that the
separate New Resources (NR)rate will apply. Contracts that do not reference the NLSL policy
generally do not obligate BPA to expect or plan to serve any new large loads placed on the
customer during the term of the contract. These contracts include presubscription contracts,
including sales of Hungry Horse Reservation power in Montana, and contracts which provide
Slice, Block or non-load following products and services.
4

II. Overview of New Large Single Load Planning
This section discusses the sequence of decisions involved in planning service to a potential
NLSL.
A. Before the Load Increase Occurs
Identify a planned new load, or a planned expansion of an existing load, of 10 aMW or greater
within a 12-month period. The utility shall notify BPA of the load's potential to become a
NLSL, and must notify BPA if it intends to serve the load with dedicated resources. If the utility
(other than an IOU) fails to report a NLSL, BPA will backbill the utility for the difference
between the PF and NR rates,plus interest and late charges, unless the utility reasonably could
not have known about the load.
Sequence of Decisions:
1. Was the load served by the utility, or did the utility make a commitment to serve the
load, prior to 9/1/79?
If so, request a contracted for, committed to (CFCT) determination. Once BPA
makes the CFCT determination,there is no NLSL potential until the load increases by
10 aMW over the CFCT amount in one 12-month measuring period.
2. Does the load consist of more than one facility?
If so, request a facility determination. The increase in load at each facility is
measured separately for the purpose of determining whether the facility is an
NLSL.
3. Can the increase in load be limited to annual increments of less than 10 aMW for
any facility, before a 10 aMW or greater increase occurs, as measured in
twelve-month periods from either the date of energization, the date of first
commercial operation for new loads, the date of service from the utility, or from
September 1 of each year for CFCT loads?
If so, for new operations, identify the start date alternative to be used for each
facility and request BPA's concurrence. Operate facilities so that, to the extent
feasible, increases in load over the 12-month measuring periods are less than
10 aMW.
4. Can renewable or cogeneration resources at the site be permanently committed to
the load so as to reduce the net annual increase in load to less than 10 aMW in any
of the prescribed measuring periods?
If so, apply the resources to the load. [Note: If the committed cogeneration or
renewable resources are withdrawn from service to the load, the entire load will
become a NLSL if it would have been a NLSL without the withdrawn resources,
unless the withdrawal was caused by uncontrollable events.]
5. Can resources other than Firm Resources under the utility's power sales contract
with BPA("NLSL resources")be dedicated to the NLSL?
5

[Note: Resources dedicated to serve NLSL's are designated"NLSL resources,"
rather than"dedicated resources," in order to distinguish them from resources
dedicated to utility firm loads.]
If so, dedicate resources to the expected NLSL by removal of the NLSL resources
and declaring the load to be served with the NLSL resources in the customer's
power sales contract. [Note: BPA has no obligation to serve the NLSL if the
NLSL resources fail or are not adequate to serve the load. Any BPA service to
such a load would be charged as an unauthorized increase in service.]
6. Is the load at a facility likely to become a NLSL, so that it should be billed as a
NLSL from the expected effective date of NLSL status?
If BPA and the utility agree that the load at a facility will become a NLSL, the
load will be treated as a NLSL for billing purposes from the start of commercial
operation or service from the utility. If the utility and the consumer are uncertain
whether the load will become a NLSL, they may want to select the rebating
option. Rebating allows billing as a NLSL from the beginning of the 12-month
period in which the load becomes a NLSL, instead of back billing after the load
has exceeded 10 aMW, and thus avoids interest charges on back billed amounts.
B. Measurement of Consumption to Determine NLSL Status
1. Begin measurement of the consumption of the load.
a. Establish the start date and hour for the 12-month measuring period. The
utility should select,with BPA's concurrence, either the date of
energization,the date of first commercial operation, or date of service
from the utility as the start date for measurement. To avoid complications
in metering and billing, it is preferable to start load measurement at the
beginning of the billing month. Knowing the precise hour of startup and
service may be important in measuring load at a facility if the annual
increase in consumption is close to 10 aMW. For existing loads, including
all CFCT loads, the start date for measurement is September 1, which is
based on the September 1, 1979, cutoff date for grand fathered loads under
the Northwest Power Act.
b. Measure consumption at the consumer's facilities rather than at the utility
point of delivery from BPA.
C. Construction loads are not included in first year consumption, and do not
establish the energization date. The energization date must be based on
the consumption of power by a permanent installation(other than
substation equipment) owned by the consumer.
2. Read the meter(s) at the load on the anniversary of the start date. As noted above,
it is preferable for the start date to match the start of the billing period; otherwise,
it will be necessary to arrange for a special reading on each anniversary date. To
obtain a precise measurement over the 12-month measurement period(necessary
when the increase in load over the measuring period is close to the 10 aMW
threshold amount) it may be necessary to read the meter at the same hour of the
day that the measuring period started.
6

3. Calculate the amount of the increase. If the load is a new load in its first year of
measurement, the increase is simply the total consumption for the measuring
period. If the load was in operation in previous measuring periods, the increase is
the difference between the consumption during the measuring period and the
consumption during the immediately preceding 12-month period.
4. Adjust for load normalization, if appropriate. BPA must adjust the comparison of
amounts of consumption in two 12-month periods to eliminate any reductions in
the load due to unusual events reasonably beyond the control of the Consumer.
Normalization is possible where the consumer's facility has a period of normal
operation, then a period of reduced load, and then an increase in load. The
consumer requests normalization through the retail utility, supplying data to
support the request.
5. If cogeneration or renewable resources are permanently committed to the load, the
load measured for the purpose of determining whether the load is a NLSL must be
the net load after the subtraction of the amount served by the committed
cogeneration or renewable resources. If the resource is removed from service to
the load, the entire load is measured to determine whether the load is a NLSL,
unless BPA determines that the removal was due to uncontrollable events.
6. If, after all of the above adjustments, the increase over the 12-month measuring
period is greater than 10 aMW, the facility is a NLSL as of the beginning of the
12-month measuring period. The amount of the NLSL includes both the threshold
10 aMW amount and the increase above 10 aMW. All future increases in the load
at the facility are also part of the NLSL.
7. Increases in load at a facility will continue to be a concern for large loads that have
not become NLSL's, particularly loads that decline in size but which may
eventually resume consumption at historical levels. The increase in load from one
year to the next will continue to control the status of the load, unless a reduction in
load is due to unusual events reasonably beyond the control of the Consumer.
Where the reduction is due to such events, the increase in load is "normalized,"
i.e., measured for NLSL purposes, as if the load reduction had not occurred.
In all other cases, especially where the reduction in load at a facility is the
consumer's voluntary choice, the consumer and the utility must be vigilant about
resuming consumption if the increase from the previous 12-month measuring
period will be 10 aMW or more. Except for normalized loads, PF service depends
on avoiding load increases of 10 aMW or more in any 12-month measuring period
as compared with the previous period.
C. Mechanics of NLSL Service (after NLSL status is established)
Several aspects of NLSL service must be developed specifically for each utility customer as a
NLSL develops. BPA will work on a case-by-case basis with a utility customer to develop
appropriate mechanisms for scheduling and billing NLSL's and arranging the dedication of
resources to serve NLSL's where appropriate. BPA realizes that other issues of NLSL service
will likely arise as plans for NLSL service proceed and as new variations of NLSL service occur.
7

III. Contracted For, Committed To (CFCT) Determination Process
Under section 3(13) of the Northwest Power Act, BPA has the sole responsibility to determine
claims made by utilities that they have "contracted for or committed to" load. BPA is to carefully
examine these claims that a facility is not a new large single load. See H. Rep.No 976, 96th
Cong. 2nd Sess., Part I(1980) at 52. BPA's policy has been a CFCT determination must be
based on a"paper trail" showing significant evidence that a"commitment" or a contract existed
prior to September 1, 1979.
The BPA Administrator has sole responsibility for CFCT determinations, which are made at his
or her discretion. CFCT determinations are not NLSL determinations. No NLSL determination
can be made for a CFCT load until it increases by 10 aMW or more above the CFCT amount
within the prescribed 12-month measurement period.
The normal steps in the CFCT determination process are as follows:
1. The utility makes an informal request to BPA for a CFCT determination(or
otherwise seeks guidance concerning service to large industrial loads in
circumstances that suggest that a CFCT determination may be appropriate).
2. BPA staff will meet with the utility and the consumer, as appropriate, to:
(a) identify the facts of the situation, specifically, the contractual and service
arrangements in place as of September 1, 1979;
(b) explain relevant NLSL theory, legislative history, and BPA interpretations
of NLSL provisions;
(c) discuss possible consequences of CFCT determination, including potential
future treatment as a single facility;
(d) explain BPA's interpretation of the terms "contracted for, or committed
to,"particularly the showing of commitment required(written
documentation of a commitment to acquire power to serve the load,
contemporaneous with September 1, 1979) if the retail contract does not
establish an obligation in the amount desired. In addition, BPA will
explain alternative bases for CFCT determinations, specifically, contract
energy, maximum energy consumption of the load, or contract demand(if
contract energy is not specified), and the evolution of CFCT
determinations to apply a 100 percent load factor to retail contracts based
on contract demand;
(e) outline the normal CFCT determination process; and
(f) identify needed documentation.
3. The utility submits a formal request for a CFCT determination to BPA, with
initial documentation of the utility's commitment to serve the load.
4. BPA reviews the submittal. If necessary, BPA requests supplemental information
or revisions from the utility.
5. BPA informs the utility of its decision by a letter accompanied, if appropriate, by
a revised power sales contract exhibit showing the amount of the CFCT load. The
8

utility also receives a copy of a decision paper describing the basis for BPA's
decision.
6. BPA will continue to monitor the load annually to establish the extent to which
the load is using the CFCT amount and to obtain advance notice if the load grows
in amounts that may require a NLSL determination. Earlier notice, if available,
will facilitate faster NLSL decisions. If the facility is transferred from one owner
to another, the utility should provide BPA with copies of the contracts transferring
ownership and assigning electrical service to the new owner, so that BPA has
proof that the new owner is entitled to CFCT treatment.
IV. Facility Determination Process
BPA will make the determination in cooperation with the utility with the information provided
by the utility and its consumer. A facility determination is not a NLSL determination. No NLSL
determination is warranted until the load at one of the facilities increases by 10 aMW or more
above the CFCT amount, if any, during the prescribed 12-month period.
The normal steps of the facility determination process are as follows:
1. The utility contacts BPA concerning a potential facility determination (or
otherwise seeks guidance concerning service to large industrial loads in
circumstances in which a facility determination may be appropriate).
2. BPA will meet with the utility and the consumer(as appropriate)to:
(a) identify the facts of the situation, i.e., the general features of the operations
involved, including the size of the load, type of process, schedule for
development, location, and electrical service requirements;
(b) explain relevant NLSL theory, including the legislative context and
objectives, and the NLSL mechanisms which may allow a load or portion
of load to receive service at a rate below the NR rate;
(c) discuss consequences of a facility determination:
(i) separate options for start dates for measuring load increases at each
facility;
(ii) separate schedules for phasing in load; and
(iii) separate allowances for increase in load up to 10 aMW in each
12-month measuring period;
(d) explain the application of the facility determination criteria, including:
(i) the determination based on the cumulative effect of all of the
criteria;
(ii) the absence of any prescribed weighting;
(iii) the application of particular criteria in previous facility
determinations; and
(iv) if appropriate, background on the development of the criteria in the
power sales contract negotiations;
(e) outline the normal facility determination process; and
(f) identify needed documentation.
9

3. When the plant design and electrical service plans are complete, the utility
submits a formal request for a facility determination to BPA. The request consists
of a letter from the utility summarizing the facts and requesting a determination,
together with documentation from the utility and the consumer showing the
factual background. Documentation should be directly related to the facility
determination criteria. Superfluous detail, such as technical specifications of plant
equipment, should be avoided.
4. BPA reviews the submittal. If necessary, BPA requests supplemental information
or revisions from the utility.
5. BPA informs the utility of its decision by a letter, accompanied by a copy of a
decision paper describing the basis for BPA's decision.
6. BPA will continue to monitor the load annually to determine whether the loads at
the facilities are using their CFCT amounts, and to obtain advance notice if the
load at any of the facilities grows in amounts that may require a NLSL
determination. The anniversary date for the 12-month measurement period should
be identified for each facility, and the utility should report the annual load
measurement for each facility to BPA.
V. New Large Single Load (NLSL)Determination Process
BPA alone will make NLSL determinations as well as make ASC adjustments under the
Exchange program if appropriate. A utility is required to report NLSL's to BPA. If a utility
(other than an investor-owned utility) fails to report an NLSL, it will be back billed for NLSL
service at the difference between the NR and PF rates,plus interest and late charges.
There are two principal sources of NLSL determinations. The first is ASC filings under the
Residential Exchange program, which has been the source of BPA's initial NLSL determinations.
The second is notifications made by the customer to BPA reporting additions in electrical
equipment of 10 MVA by a consumer, installation of additional transformation capacity of 10
MVA or more by the customer or a consumer, or the potential change in operation of a facility
which may result in an increase of 10 aMW or more in a 12-month period. The latter actions are
expected for some of the loads that have been the subject of facility determinations. Procedures
for both of these methods are described below.
A. Development of NLSL Determinations from Average System Cost (ASC)
Filings
When BPA identifies a possible NLSL from a utility ASC filing, BPA will notify the utility and
request information about the size of the load and its electricity consumption history.
1. BPA will meet with the utility and the consumer, as appropriate, to:
(a) identify the facts of the situation;
(b) explain relevant NLSL theory, legislative history, and BPA interpretations
of NLSL provisions (including CFCT determinations, facility determinations, and
other BPA practices that may affect the power costs to the load);
(c) discuss possible consequences of an NLSL determination, including:
10

(i) applicability of the NR rate to BPA requirements service
(Northwest Power Act section 7(f));
(ii) the inability of an NLSL to revert to PF service (unless equipment
creating the load is permanently removed);
(iii) the "last-on, first-off'treatment of NLSL loads;
(iv) identify, explain and illustrate in a generic manner relevant 1984 ASC
Methodology provisions impacting the calculation of the NLSL
exclusion (Northwest Power Act § 5(c)(7)(A), footnote f); and
(v) the potential to dedicate resources to serve the load.
(d) explain the following:
(i) the measurement of the increase in load based on total consumption
rather than load placed on the utility(unless cogeneration or
renewable resources are committed to the load);
(ii) the fixed 12-month measuring period; and
(iii) for new loads (not CFCT loads), the options for setting the start of
the period, i.e., either the date of energization or the date of first
commercial operation;
(e) outline the applicable NLSL determination process;
(f) identify needed documentation; and
(g) if appropriate, inform the utility that the ASC rate determined by BPA may
be adjusted contingent upon the NLSL determination.
2. BPA will request any additional information needed from the utility, or through
ASC data requests, including:
(a) any data necessary for the above analysis; and
(b) except for CFCT loads, the utility's choice of starting date for measuring
load increases--either the date of energization or the date of first
commercial operation. The anniversary date for measurement of load
increases at all CFCT loads is September 1.
3. BPA will inform the utility of its decision by a letter accompanied, if appropriate,
by a revised power sales contract exhibit showing the amount and location of the
NLSL. The utility will also receive a copy of a decision paper describing the basis
for BPA's decision.
B. Development of NLSL Determinations for Planned NLSLs
NLSL determinations for planned NLSL's are expected to occur in the context of a long-term
planning process, involving both the utility and BPA,to arrange service to a new or expanded
load. The issue of a NLSL determination for the planned load should be the final step in the
process of arranging service to a new industrial load.
The NLSL determination process for planned NLSL's has two phases. First, procedures are
established for service, load monitoring, and billing for the prospective NLSL. Second, the
formal NLSL determination is made once the load has increased by more than 10 aMW in a
12-month measuring period.
The steps to be taken in phase one (planning service, load monitoring, and billing) are as follows:
11

1. The utility notifies BPA that the consumer and the utility are committed to plans
that will result in load increases at a facility exceeding 10 aMW in one of the
prescribed 12-month measuring periods.
2. BPA requests any information needed from the utility, including:
(a) the expected size of the load and schedules of load development to determine
when the load is expected to exceed the 10 aMW threshold;
(b) the utility's choice, if any, of starting date for the 12-month load
measurement period--date of energization or date of first commercial
operation at the facility--unless the load is a CFCT load, in which case the
anniversary date for measurement of increases in load will be
September 1;
(c) the utility's plans, if any, to "phase in" load increases at the facility in
annual increments less than 10 aMW, including:
(i) the expected amount of phased-in load;
(ii) the monthly distribution of the phased-in energy load; and
(iii) the amount of demand to be associated with the phased-in energy;
(d) the utility's plans, if any, to dedicate resources to all or part of the load, or
to permanently commit cogeneration or renewable resources to the load,
including:
(i) identity of the resources to be dedicated, and the extent to which
they will be able to supply the requirements of the load;
(ii) integration of the dedicated resources into the annual load and
resource planning process;
(iii) appropriate revisions in exhibits to the power sales contract; and
(iv) firm transmission arrangement to deliver the dedicated resources to
the load;
(e) whether the utility has been, is, or would be a participant in the Residential
Exchange Program under the RPSA.
3. BPA and the utility will work together to resolve issues concerning service to the
load, including:
(a) billing procedures to address all classes of power to be delivered to the
facility, including any priority firm power for phased-in portions of the
load, resources to be dedicated to all or part of the prospective NLSL, and
new resources power to be supplied to the load by BPA;
(b) BPA's concurrence with the utility's choice of starting date for measuring
load increases, either the date of energization or the date of first
commercial operation;
(c) the utility's dedication of resources, if any,under its power sales contract
with BPA.
4. Once these procedures and plans are completed, service to the load can begin.
From the start of the first 12-month measuring period, BPA will monitor the load
12

to ascertain whether an increase of 10 aMW or more has occurred. If, after a
period of normal commercial operation, the load's growth is affected by unusual
events reasonably beyond the control of the Consumer which result in a reduction
in the load, BPA may consider whether normalization of the load is required, i.e.,
the energy consumption shall be computed as if such reductions had not occurred.
[Note: Normalization is possible only if there is a period of normal commercial
operation, followed by a period of load reduction, and then an increase in load.]
The steps to be taken in phase two (formal NLSL determination) are as follows:
5. Once the load at the prospective NLSL has increased by more than 10 aMW
during the selected 12-month measuring period, BPA begins the process of
making a NLSL determination. The determination process may begin before the
end of the 12-month period if the 10 aMW threshold has been exceeded.
6. BPA assembles available information concerning the load, including:
(a) the amount of the load during the 12-month period in which the 10 aMW
increase occurred and in the immediately preceding 12-month measuring
period;
(b) the start date of the 12-month period during which the 10 aMW increase
occurred, on which the load becomes a NLSL;
(c) any normalization of load during the 12-month measuring period
preceding the period of the 10 aMW increase.
7. BPA will inform the utility of its decision by a letter accompanied, if appropriate,
by a revised exhibit in the power sales contract showing the amount and location
of the NLSL. The utility will also receive a copy of a decision paper describing
the basis for BPA's decision.
VI. Northwest Power Act Section 3(13) Decisions
The decisions below are described in brief. Each decision remains fully in force. The decisions
in their entirety are available upon request.
• 1981 Section 5(g) Initial Contracts Record. Environmental Report dated September, 1981.
Published in conjunction with BPA's offer of initial power sale contracts under 5(g) of the
Northwest Power Act, BPA's environmental report included policy statements in response to
public comment on NLSL issues raised during the contract process. The policy decisions made
formed the basis for BPA's NLSL policy and interpretation of section 3(13). They included the
following decision:
BPA would use a rolling 12-month comparison for measuring the load at a facility of the
current twelve month period to the immediately preceding 12 month period. This policy was
denominated the "permissive" approach or referred to as "load creep" since it would allow a
consumer to increase its actual metered energy consumption load at the facility by 9.9 aMW
when measured over the 12 months without triggering the NR rate. At 32.
A corollary to this decision was that BPA would measure all load including the increases in
load at the consumer's facility and not the customer's load on BPA. A second corollary to
this policy was that once the load exceeded 10 aMW in any consecutive 12 month period and
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became a NLSL, all subsequent increases in load, whether above 10 average megawatts or
not, would be added to the NLSL amount and charged at the NR rate. At 33.
BPA also stated its decision on the issue of whether CFCT loads could be transferred from
service by the utility providing service as of September 1, 1979, to another utility at a later
date. A CFCT load which switched suppliers from one utility to a new utility would no
longer fall within the exception of section 3(13)(A) and would be served as a NLSL of that
new utility at the NR rate. This would limit access to lowest cost Federal Base System
resources and avoid potential resource additions raising costs. It was consistent with the
specific use of"such customer" in the statute when referring back from section 3(13)(B) to
3(13)(A) as stated in the Boise Cascade letter supra. At 33.
• Letter from Peter T. Johnson, Administrator(BPA), to John B. Frey, Boise Cascade
Corporation(Oct. 6, 1981)regarding whether a CFCT load is transferable to a new utility.
All industrial loads which are contracted for, or committed to and existed on September 1,
1979, and subsequently are served by a different utility will be classified as new large single
loads. The terms "such customer" in relation to contracted for, or committed to refers to a
contractual relationship that existed on September 1, 1979, between a specific utility and a
specific consumer. Once the consumer begins to receive service from a different utility,
under a different, the contractual relationship with the new utility is no longer"grand
fathered" and the load becomes a new large single load.
• Letter from Sydney D. Berwager, BPA, to Wilbur L. Anderson, Vigilante Electric
Cooperative, Inc. (July 13, 1992) regarding service to new load designated a NLSL and
formerly served as a direct service industry customer of BPA.
The determination that Stauffer and its successor-in-interest's (RP) load was and is a
NLSL remains unchanged. Therefore, the load sharing/shedding arrangement between
RP, MPC and Vigilante mentioned in RP's April 14, 1992, letter to Vigilante, is
irrelevant to an existing NLSL and not"recognized" or"permitted"by BPA's NLSL
Guide. BPA does not permit the "phasing on" of existing NLSL load to a new serving
utility; nor does the statute, the utility contract, or the NLSL Guide recognize or permit a
change in the serving utility for an existing NLSL(such as the RP load from MPC to
Vigilante) to be served at the PF rate. If a NLSL could avoid that status simply by
changing utilities, all such loads could attempt to do this to evade the intent of the
Northwest Electric Power Planning and Conservation Act.
BPA rejected the proposal that a contract limiting the customer's service to the consumer
to 9.9 aMW a year should be allowed to avoid NLSL treatment. Such a policy would run
counter to the utility responsibility to serve and would fail to consider and measure the
whole load at the facility of the consumer.
• 1992 Administrator's Record of Decision New Large Single Load Treatment of Utility
Service to Direct Service Industry Expansions; Initiating a Northwest Power Act Section
5(d)(3)Process to Increase Direct Service Industry Contract Demand
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BPA's record of decision(ROD) addressed NLSL treatment of a utility's retail service in excess
of a DSI's Contract Demand to an expansion of a load or new load of a DSI. BPA's policy
applied NLSL provisions to electric power service in excess of a DSI's Contract Demand when
an expansion of a load or a new load of a DSI customer is served by a utility customer.
The ROD stated that for an existing load under a BPA DSI power sales contract, it could become
a NLSL if electric power service to that load is transferred to a local utility from BPA. BPA
reaffirmed its policy on measuring the actual energy consumed by the load at a facility of a
consumer using the customer's meters, or other appropriate information. If actual energy
consumption exceeds the trigger, BPA has meter and billing data to establish that load as a
NLSL. BPA did not change its policy or practices in adopting this ROD and specifically rejected
any reliance upon a"contract limitation"between the utility and the DSI as establishing whether
a utility's service to a load at a specific facility of a consumer is less or more than 10 aMW in any
12 consecutive months.
BPA's policy for NLSL treatment of service to DSI loads above their Contract Demand will be to
measure only the increase in load at a consumer's (DSI) facility above the DSI's Contract
Demand. The NLSL provisions of the utility power sales contract will be applied to any
proposed service by a local utility. BPA will also apply its present longstanding practices,
interpretations, and policies in measuring the load served by a utility at a DSI site. The amount
of energy consumed at a facility will be measured from a floor amount of energy consumption,
which is either the greater of the amount of energy the DSI could take under its Contract Demand
or the prior 12 months'total energy consumption under the DSI power sales contract and the
utility's service to the expansion of load, whether the load is metered jointly or separately.
BPA will require full use of the DSI's Contract Demand for service with a utility in order to
preserve BPA's existing restriction rights and Industrial Firm Power revenues. In any BPA-utility
joint service agreement, the utility service would be provided only in excess of the DSI's
Contract Demand.
This policy applies only to new load which are expansions of existing DSI load above the DSI's
Contract Demand when served by a local utility purchasing or exchanging Federal power from
BPA. It does not apply to conversions of load from BPA service under the DSI power sales
contract to utility or other service. This policy does not apply in those circumstances in which a
DSI reduces Contract Demand or Operating Level of its existing BPA load and takes service
from a utility. This policy does not address whether such conversion will be permitted and, if
permitted, would be a NLSL.
• Initial Northwest Power Act Power Sales Contracts, Final Environmental Impact Statement
(1992) (DOE/EIS-0 13 1)
This EIS resulted from the Forelaws on Board v. Johnson, 743 F 2d. 677 (1984), decision in
which the Ninth Circuit directed BPA to prepare an environmental impact statement on the
section 5(g) contracts it had offered its customers. It contains a NLSL policy decision which had
not previously been included in either the contract record, correspondence, or the 1981
Environmental Report.
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As background, in 1986 BPA had an amount of annual planned surplus power. Some customers
proposed that BPA adopt a policy of permitting the use of the surplus power to serve a load
which would otherwise be a NLSL. The service to the load would be split between the surplus
power portion and a phase in of regular PF service in annual 9.9 megawatt increments until the
load was served entirely at PF. The contractual "phasing in" of PF load was discussed with
regional parties and opposed by many. BPA did not adopt the "phase in". In the 1992 EIS, BPA
stated surplus power would be available for service, from December 1988 through September
1990, to an NLSL under surplus (SL)power rate. Upon expiration of service under the SL
contract the load would revert to usual NLSL status and would be subject to the NR rate.
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