20260406Direct Mitchell - REDACTED.pdf

RECEIVED
APRIL 6, 2026
IDAHO PUBLIC
UTILITIES COMMISSION
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. PAC-E-26-04
OF PACIFICORP D/B/A ROCKY )
MOUNTAIN POWER FOR APPROVAL OF ) DIRECT TESTIMONY OF
SALE OF WASHINGTON SERVICE AREA ) RAMON J. MITCHELL
AND ACCOUNTING ORDER )
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-26-04
April 2026

1 I . INTRODUCTION AND QUALIFICATIONS
2 Q. Please state your name, business address , and present
3 position with PacifiCorp d/b/a Rocky Mountain Power.
4 A. My name is Ramon J. Mitchell, and my business address is
5 825 NE Multnomah Street, Suite 600, Portland, Oregon
6 97232 . My title is Managing Director, Energy Supply
7 Management Finance and Net Power Costs .
8 Q. Please describe your education and professional
9 experience.
10 A. I received a Master of Business Administration degree
11 from the University of Portland and a Bachelor of Arts
12 degree in Economics from Reed College. I was first
13 employed by PacifiCorp in 2015 and during my time at
14 PacifiCorp, I have held various positions in the
15 regulation, merchant, transmission, and finance
16 departments . After a brief departure from PacifiCorp, in
17 2022 I returned and now serve as Managing Director,
18 Energy Supply Management Finance and Net Power Costs .
19 With respect to this proceeding, I am responsible for
20 overseeing the power costs analysis of PacifiCorp' s sale
21 of its Washington service area and select Washington-
22 based assets ("Service Area Transfer") , inclusive of the
23 models and assumptions used in this analysis .
Mitchell, Di 1
Rocky Mountain Power

1 Q. Have you testified in previous regulatory proceedings?
2 A. Yes . I have previously provided testimony to the Idaho
3 Public Utilities Commission ("Commission") , as well as
4 commissions in California, Oregon, Utah, Washington, and
5 Wyoming.
6 II . PURPOSE OF TESTIMONY
7 Q. What is the overall purpose of your testimony?
8 A. My analysis demonstrates that the Service Area Transfer
9 decreases the average unit cost of power for
10 PacifiCorp' s remaining customers . Specifically, the unit
11 cost of power decreases in the 2030 Forward Period, and
12 this structural benefit is independently confirmed
13 across 48 months of actual historical system conditions .
14 In this testimony, I present a transparent,
15 verifiable analysis of the power costs impacts resulting
16 from the proposed Service Area Transfer to an affiliate
17 of Portland General Electric Company ("PGE") , referred
18 to as "Gem" for the purposes of this testimony. My
19 testimony explains the operational drivers that change
20 PacifiCorp' s power costs, details the physical energy
21 balance versus the financial cost of energy, and
22 quantifies the resulting benefits to PacifiCorp' s
23 remaining customers across all analyzed periods .
24 My power costs analysis supports the Service Area
25 Transfer, demonstrating that under forward-looking
Mitchell, Di 2
Rocky Mountain Power

1 system normal conditions, ' the transaction leaves
2 remaining customers strictly better off under a diverse
3 spectrum of market, load, and generation conditions . My
4 analysis is further supported by historical data across
5 48 months of actual system conditions from January 2022
6 through December 2025, which confirms that the
7 structural benefit continues to persist under a diverse
8 spectrum of conditions, with observed wholesale market
9 prices ranging from $36 to $248 per megawatt-hour.
10 III . DEFINITION OF POWER COSTS
11 Q. Please define power costs as the term is used in the
12 context of this testimony and explain how they are
13 calculated.
14 A. Power costs primarily represent the daily, variable
15 financial expenses PacifiCorp incurs to physically
16 generate and deliver electricity to its customers . These
17 costs do not include fixed capital expenses, such as the
18 cost to build a power plant or the salaries of our
19 employees . Furthermore, PacifiCorp only recovers these
20 direct costs; PacifiCorp does not earn a return on these
21 costs . In the context of this testimony, power costs are
22 calculated with three additions and two revenue credits .
23 The three additions are as follows :
' Post-2030, post-Service Area Transfer transitional agreements, post-
sale rate credits.
Mitchell, Di 3
Rocky Mountain Power

1 1 . First, we add the cost of the consumable fuel, such
2 as natural gas or coal, required to run
3 PacifiCorp' s thermal power plants .
4 2 . Second, we add the cost of purchasing supplemental
5 electricity — as and when economical—from the
6 wholesale markets .
7 3 . Third, we add the wheeling fees PacifiCorp must
8 pay to other transmission owners to transport
9 electricity across their transmission lines .
10 The two revenue credits are as follows :
11 1 . First, we credit the revenue PacifiCorp earns when
12 the system produces excess electricity that is sold
13 into the wholesale market. The revenue from these
14 sales acts as a financial credit that reduces
15 overall power costs .
16 2 . Second, we credit the revenue generated when
17 PacifiCorp' s wind facilities earn production tax
18 credits . This revenue also acts as a financial
19 credit that reduces overall power costs .
20 Figure 1 below illustrates the components of power
21 costs and the revenue credits that offset them.
Mitchell, Di 4
Rocky Mountain Power

What are Power Costs?
Purchased
Power 66 The Formula
(Sales) - (Credits) _
Fuel
Power Costs
it
� Wheeling
Purchased Power: 3uying from others
Sales for Resale ' Fuel: Coal,natural gas,etc.
Wheeling: Transmission tolls
■Tax Credits Sales for Resale: Selling excess energy
Tax Credits: -financial credits from wind
1 Q. How do you measure the impact of power costs on
2 customers?
3 A. To objectively evaluate the power costs impact of the
4 Service Area Transfer on customers, we measure the unit
5 cost of power. The unit cost of power isolates the
6 average power cost to produce exactly one standard unit
7 of electricity for customers, which is mathematically
8 expressed as dollars per megawatt-hour ("$/MWh") .
9 Therefore, when speaking of the unit cost of
10 electricity, the concept being discussed is the unit
11 cost of power costs ("unit cost of power") .
12 Q. Why is the unit cost of power a more appropriate metric
13 for evaluating customer impacts than total dollars?
14 A. Evaluating total dollars alone presents an incomplete
15 picture when assessing the impact on a customer. If a
16 utility divests a large segment of its customer base,
17 its total power costs will inherently decrease because
Mitchell, Di 5
Rocky Mountain Power

1 the aggregate volume of fuel and purchased power
2 required to serve the remaining system is substantially
3 smaller. However, if the utility concurrently loses
4 economic power plants, power costs to generate power for
5 the remaining customers could increase . The $/MWh metric
6 isolates the average power cost to produce exactly one
7 standard unit of electricity for customers, thereby
8 controlling for changes in system size . Therefore,
9 objectively evaluating the Service Area Transfer
10 requires prioritizing the $/MWh metric over these
11 offsetting changes in total dollar amounts .
12 Q. What is the difference between a megawatt and an average
13 megawatt?
14 A. A megawatt is a standard measure of instantaneous
15 electrical power capacity. It describes the maximum
16 output a power plant can produce, or the maximum demand
17 customers can draw, at a single moment in time .
18 Conversely, an average megawatt is a mathematical metric
19 used to express continuous energy production or
20 consumption over a period of time . Specifically, one
21 average megawatt denotes exactly one megawatt of power
22 supplied continuously, 24 hours a day, 365 days a year.
23 Using average megawatts allows us to compare highly
24 fluctuating variables on a standardized basis .
Mitchell, Di 6
Rocky Mountain Power

1 IV. REDUCTIONS IN THE UNIT COST OF POWER
2 Q. What specific physical assets and customer obligations
3 are included in the Service Area Transfer?
4 A. On an annualized average basis, under forward-looking
5 system normal conditions, 2 the transaction permanently
6 removes 515 average megawatts of retail customer load
7 from our system. Concurrently, the transaction removes
8 314 average megawatts of physical power supply. This
9 generation supply includes 104 average megawatts of wind
10 generation from the Goodnoe Hills and Marengo wind
11 facilities, 209 average megawatts of natural gas
12 generation from the Chehalis plant, and 1 average
13 megawatt of generation from specific legacy qualifying
14 facility power purchase agreements . The critical
15 structural fact is that the load removed (515 average
16 megawatts) exceeds the generation removed (314 average
17 megawatts) by 201 average megawatts . This surplus is the
18 primary driver of the power costs benefits I describe
19 below.
20 Q. How does removing both customer load and generation
21 facilities simultaneously affect the unit cost of power?
22 A. It results in a decrease to the system average unit cost
23 of power by 34 cents per megawatt-hour in aggregate
2 Post-2030, post-Service Area Transfer transitional agreements, post-
sale rate credits.
Mitchell, Di 7
Rocky Mountain Power

1 during the 2030 Forward Period, 3 a 0 . 92 percent
2 reduction. On an Idaho-allocated basis, this equates to
3 approximately $1 . 3 million in annualized aggregate power
4 costs savings, as shown on the `Summary' pages within
5 Confidential Exhibits No . 2 and 3 to my testimony. 4 This
6 result is driven by favorable avoided cost
7 differentials : the financial burden we avoid by no
8 longer serving the Washington load exceeds the market
9 cost required to replace the transferred generation,
10 which fundamentally optimizes the system' s load-resource
11 balance for the remaining customers .
12 Q. Please explain the mathematics behind this avoided cost
13 concept.
14 A. We compare the financial savings of no longer serving
15 the Washington customer load against the financial cost
16 of replacing the lost generation under forward-looking
17 system normal conditions .
18 First, we calculate the savings from removing the
19 load. The system avoids serving 515 average megawatts of
3 Under forward-looking system normal conditions. The 2030 Forward Period
employs a counterfactual assumption whereby transitional agreements with
PGE end on December 31, 2029. This allows us to evaluate a full 12-month
post-transition snapshot.
4 The Idaho-specific unit cost decrease of $0.34 per megawatt-hour and
the $1.3 million in annualized savings reflect the application of Idaho
allocation factors under the 2020 Inter-jurisdictional Cost Allocation
Protocol to total-company adjusted net power costs results. In calendar
year 2027, the savings are $0.34 million. For the 2030 Forward Period,
the 5-state system power costs decrease by $16. 6 million in total, and
for calendar year 2027, the 5-state system power costs decrease by $5.4
million in total.
Mitchell, Di 8
Rocky Mountain Power

1 Washington load. PacifiCorp avoids purchasing that power
2 at the system marginal cost, represented by the
3 wholesale market price of approximately $64 per
4 megawatt-hour. This results in a gross savings of
5 $32, 960 per hour. 5
6 Second, we calculate the cost of losing the
7 generation. The system loses 314 average megawatts of
8 energy. This total consists of 104 average megawatts of
9 wind at a renewable energy credit of approximately $6
10 per megawatt-hour, 6 209 average megawatts of natural gas
11 energy at a fuel cost of approximately $47 per megawatt-
12 hour, and one average megawatt of contract energy at a
13 contract cost of approximately $87 per megawatt-hour.
14 Replacing these 314 average megawatts of energy by
15 purchasing it from the wholesale market at an
16 approximate price of $64 per megawatt-hour costs $20, 096
17 per hour. ' However, because we no longer operate those
18 transferred plants, we avoid their total fuel,
19 production tax credit, and contract costs of
20 approximately $9, 286 per hour. 8 Therefore, the net cost
5 515 average megawatts ("aMW") * $64/MWh = $32, 960.
6 Under forward-looking system normal conditions, production tax credits
on Marengo and Goodnoe Hills expire.
314 aMW * $64/MWh = $20,096.
s 104 aMW * (-) $6/MWh + 209 aMW * $47/MWh + 1 aMW * $87/MWh = $9,286.
Mitchell, Di 9
Rocky Mountain Power

1 to purchase replacement power is approximately $10, 810
2 per hour. 9
3 Q. What is the result of comparing those costs and savings?
4 A. We subtract the net replacement power cost of $10, 810
5 per hour from the gross avoided load savings of $32, 960
6 per hour. This calculation yields net savings of
7 approximately $22, 150 per hour.
8 If we divide that net savings of $22, 150 per hour
9 by the 515 average megawatts of total load removed, we
10 find that the effective cost rate of the removed slice
11 of the system is approximately $43 . 1 per megawatt-hour.
12 The pre-sale average unit cost of power for our entire
13 system is approximately $38 . 4 per megawatt-hour. Because
14 we are removing a portion of the system whose effective
15 cost ($43 . 1/MWh) exceeds the system average ($38 . 4/MWh) ,
16 the remaining system' s average unit cost mathematically
17 decreases, which results in direct cost savings for
18 remaining customers .
19 Q. This average megawatt analysis appears simplified. How
20 do you validate the results?
21 A. The illustrative analysis above relies on averages to
22 clearly explain the fundamental economic mechanics of
23 the transaction. However, actual power operations are
24 highly dynamic. Therefore, to further evaluate impacts
9 $20,096 - $9,286 = $10,810.
Mitchell, Di 10
Rocky Mountain Power

1 on customers, we employed power costs modeling, whose
2 results are presented on the `Delta Model Forecast' page
3 within Confidential Exhibit No . 4 to my testimony.
4 This modeling confirms and extends the directional
5 analysis . As a further cross-check, PacifiCorp also
6 performed an independent average-megawatt-based
7 analysis that confirms the annual direction and
8 magnitude of the unit cost decrease . Specifically, the
9 production cost modeling provides unit cost of power
10 changes for each month of the 2030 Forward Period,
11 computed under that month' s unique combination of load,
12 generation, and wholesale market prices . Because market
13 conditions differ substantially across each of the 12
14 months, the dataset represents a diverse spectrum of
15 operating conditions . During these periods, forecasted
16 wholesale prices range from approximately $54 per
17 megawatt-hour up to $105 per megawatt-hour.
18 Q. Your analysis demonstrates favorable energy impacts for
19 customers . Are there also favorable impacts from changes
20 in system capacity?
21 A. My testimony deals with energy and its associated power
22 costs impacts . PacifiCorp witness Michael G. Wilding
23 speaks to resource adequacy and details how customers in
24 the remaining five states are favorably impacted by the
25 system' s capacity changes .
Mitchell, Di 11
Rocky Mountain Power

til Reductions in the System Average Unit Cost of Power
When you remove a"higher-than-average-cost"element of the system,the average cost for the remaining system
decreases.
N Summary
it
The portion of the system to be transferred has
Ok.r unit costs of power that are higher than the
pre-sale system average unit cost of power.
Removing this higher-than-system-average
portion creates"downward pressure"on the
remaining system's unit cost of power.
Pre-Sale System Transferred Portion Post-Sale System
1 V. HISTORICAL VALIDATION OF STRUCTURAL BENEFITS
2 Q. To provide additional assurance beyond production cost
3 modeling, you also performed a historical validation.
4 Can you describe that analysis and confirm whether the
5 structural benefit holds under actual observed
6 conditions?
7 A. Yes . To corroborate the forward-looking results, we
8 applied the same analytical framework to 48 months of
9 actual, observed system conditions and wholesale market
10 prices from January 2022 through December 2025 (the
11 "Historical Period") . This Historical Validation
12 analysis uses PacifiCorp' s actual load, actual wind
13 generation from Goodnoe Hills and Marengo, actual
14 Chehalis dispatch and fuel costs, actual qualifying
15 facility output, and actual wholesale market prices for
16 each month. No forecasted inputs were used. The
17 methodology is identical to the forward-looking analysis
Mitchell, Di 12
Rocky Mountain Power

1 discussed above: for each historical month, we calculate
2 what the unit cost of power would have been had the
3 Service Area Transfer been in effect, and compare it to
4 the actual unit cost of power for that month. The
5 detailed monthly results are presented on the `aMW Delta
6 Analysis Historical' page within Confidential Exhibit
7 No . 4 to my testimony.
8 Q. What do the historical results show?
9 A. On an aggregate basis across the 48 months, the unit
10 cost of power decreases . Across the 48 months, 71 percent
11 of the months show a decrease in the unit cost of power
12 and 29 percent of the months show an increase in unit
13 cost of power. On a dollar-weighted basis, 96 percent of
14 the total change reflects decreases in the unit cost of
15 power, and 4 percent reflects increases . This is
16 illustrated in Figure 3 below.
17 On an aggregate annual basis, the unit cost of power
18 decreases in three of the four calendar years examined. lo
19 Critically, the historical period encompasses actual
20 observed wholesale market prices ranging from $36 per
21 megawatt-hour to $248 per megawatt-hour—a range more
22 than four times as wide as the $54 to $105 per megawatt-
23 hour range reflected in the forward-looking analyses .
io Calendar year 2024 is the year with an increase in the unit cost of
power.
Mitchell, Di 13
Rocky Mountain Power

1 The structural benefit persists through the December
2 2022 price spike at $248 per megawatt-hour and the
3 January 2024 winter event at $208 per megawatt-hour.
4 Because the historical analysis uses actual data rather
5 than forecasted inputs, it is immune to the critique
6 that forecasted market prices, load shapes, or
7 generation profiles may not materialize .
Unit Cost of Power Impacts
F
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CO 2025 2024 2023 2022
Z
Cu
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bA N
N
O
a
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4-
O
U
8 Q. How does the 2024 historical data further validate the
9 robustness of the structural benefit?
10 A. Calendar year 2024 is the sole year with an aggregate
11 unit cost increase, yet it validates the structural
12 nature of the benefit even under extreme historical
13 market conditions . The 2024 result is driven by three
14 consecutive months—July, August, and September 2024—
Mitchell, Di 14
Rocky Mountain Power

1 during which wholesale market prices sustained extreme
2 levels between $130 and $159 per megawatt-hour. During
3 those specific conditions, Chehalis was dispatched at
4 very high capacity factors, causing the generation
5 removed by the transaction to approach parity with the
6 load removed. When the generation-to-load ratio
7 approaches one-to-one, the favorable imbalance that
8 structurally drives the unit cost of power decreases is
9 diminished.
10 Critically, however, even in this worst-case
11 historical year, the aggregate annual unit cost increase
12 was a relatively de minimis 15 cents per megawatt-hour.
13 This increase was overwhelmed by the decreases in the
14 other three calendar years : $1 . 67 per megawatt-hour in
15 2022, $1 . 06 per megawatt-hour in 2023, and $0 . 53 per
16 megawatt-hour in 2025 . Over the full four-year
17 historical period, the average annual net unit cost
18 decrease is approximately $0 . 76 per megawatt-hour,
19 demonstrating that even accounting for the unfavorable
20 2024 result, the long-run structural benefit is valid.
21 Moreover, these outlier 2024 summer conditions exceed
22 the worst-case market prices reflected in the 2030
23 Forward Period' s forward-looking analysis .
Mitchell, Di 15
Rocky Mountain Power

1 Q. Elaborate on how there is a structural benefit to
2 customers that persists under a diverse spectrum of
3 system conditions despite some months within the 2030
4 Forward Period and the Historical Period showing unit
5 cost increases .
6 A. Because each month reflects a unique combination of
7 seasonal load patterns, weather-dependent generation,
8 and prevailing wholesale market prices, some individual
9 months show a higher post-sale unit cost than the pre-
10 sale unit cost .
11 Operationally, these increases occur primarily in
12 some "shoulder" months (such as May) when low wholesale
13 market prices reduce the financial benefit of avoiding
14 Washington load service, or during some summer months
15 (such as July) when Chehalis is dispatched at very high
16 capacity factors, causing the generation removed by the
17 transaction to approach parity with the load removed.
18 However, during winter peaks (such as December and
19 January) wholesale market prices or natural gas fuel
20 prices are high. During these critical months, avoiding
21 over 515 average megawatts of load service yields
22 financial savings that dwarf the aforementioned
23 increases in some shoulder or summer months .
24 Net power costs and associated rate recovery
25 mechanisms are generally evaluated on an annual basis
Mitchell, Di 16
Rocky Mountain Power

1 specifically to absorb and smooth these seasonal
2 variances .
3 VI . RENEWABLE ENERGY CREDITS
4 Q. Is there another driver of power costs that decreases
5 customer rates in 20304
6 A. Yes . Currently, PacifiCorp must satisfy the requirements
7 of Washington' s Clean Energy Transformation Act, which
8 requires at least 80 percent of electric utilities'
9 electricity supply to be generated from renewable or
10 non-emitting resources by 2030 . In the 2030 Forward
11 Period PacifiCorp will avoid the need to procure
12 renewable energy credits equivalent to 80 percent of
13 Washington' s retail load. On the other hand, PacifiCorp
14 will also no longer own the Marengo and Goodnoe Hills
15 wind facilities . However, the amount of renewable energy
16 credits needed to comply with the Clean Energy
17 Transformation Act is greater than the amount of
18 renewable energy credits lost from those wind
19 facilities . The valuation of that net increase in
20 available renewable energy credits is $0 . 32 million, 11
21 as detailed on the `State Summary' page within
ii $0.021 million in 2027. For the 2030 Forward Period, the 5-state
system' s value of the net increase in renewable energy credits is a total
of $4.9 million, and for calendar year 2027, the 5-state system's value
of the net increase in renewable energy credits is a total of $0.32
million.
Mitchell, Di 17
Rocky Mountain Power

1 Confidential Exhibit No. 5 to my testimony. This further
2 decreases the unit cost of power.
3 VII . CURING A STRUCTURAL MISALIGNMENT
4 Q. How does the sale of the Chehalis natural gas plant
5 affect the economic cost of the system?
6 A. Currently, the Chehalis plant incurs annual costs under
7 Washington' s Climate Commitment Act, a cap-and-invest
8 program that requires regulated entities to obtain
9 allowances for greenhouse gas emissions . These costs
10 have been disallowed for recovery through customer rates
11 by the Commission. 12 However, these are actual costs
12 incurred by PacifiCorp to operate the Chehalis plant as
13 part of its integrated system. The Service Area Transfer
14 eliminates this ongoing inter-jurisdictional cost
15 allocation challenge .
16 Q. How does the Service Area Transfer impact this dynamic?
17 A. By transferring the Chehalis plant to Gem, PacifiCorp
18 permanently eliminates its exposure to the Climate
19 Commitment Act compliance costs and removes the
20 associated regulatory uncertainty from the remaining
21 system. This benefits remaining customers by eliminating
22 the risk that future proceedings could revisit the
23 allocation of these costs . From a power costs
12 In the Matter of Rocky Mountain Power's Application for Approval of
$62.4 Million SCAM Deferral, Case No. PAC-E-24-05, Order No. 36207 at
11 (May 31, 2024)
Mitchell, Di 18
Rocky Mountain Power

1 perspective, when conducting the pre-sale analysis
2 inclusive of Climate Commitment Act costs for operating
3 Chehalis, the system average unit cost of power
4 decreases even further upon the Service Area Transfer,
5 because PacifiCorp will no longer incur those compliance
6 costs . Under this context, the unit cost of power in the
7 2030 Forward Period reduces even further.
8 VIII . CONCLUSION
9 Q. In summary, what does your analysis demonstrate
10 regarding the impact of the Service Area Transfer on
11 power costs?
12 A. The evidence in this record demonstrates, on a
13 quantified, month-by-month basis across the 2030 Forward
14 Period and across 48 months of actual historical system
15 conditions, that the Service Area Transfer reduces the
16 average unit cost of power for PacifiCorp' s remaining
17 customers . Specifically:
18 1 . The unit cost of power decreases by $0 . 34/MWh in
19 the 2030 Forward Period, equating to approximately
20 $1 . 3 million in annualized, ongoing power cost
21 savings after the transitional agreements expire .
22 2 . Historical validation using 48 months of actual
23 system conditions from January 2022 through
24 December 2025 independently confirms the structural
25 benefit : the annual unit cost of power decreases in
Mitchell, Di 19
Rocky Mountain Power

1 three of four calendar years, with 96 percent of
2 the amount of the unit cost of power change being
3 a decrease across those 48 months .
4 3 . The net increase in available renewable energy
5 credits resulting from the Service Area Transfer is
6 $0 . 32 million.
7 4 . The transaction cures a structural misalignment
8 related to Washington' s Climate Commitment Act,
9 eliminating regulatory uncertainty.
10 5 . This analysis is robust across wholesale market
11 prices ranging from $54/MWh to $105/MWh in the 2030
12 Forward Period and from $36/MWh to $248/MWh in the
13 historical analyses, demonstrating that the benefit
14 is structural rather than dependent on any single
15 market assumption.
16 For all of these reasons, the Service Area Transfer
17 provides comprehensive and quantifiable power costs
18 benefits for PacifiCorp' s remaining customers .
19 Q. Does this conclude your direct testimony?
20 A. Yes .
Mitchell, Di 20
Rocky Mountain Power

REDACTED
Case No. PAC-E-26-04
Exhibit No. 2
Witness : Ramon J. Mitchell
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
REDACTED
Exhibit Accompanying Direct Testimony of Ramon J. Mitchell
Power Costs Allocation Pre Sale 2030 Forward
April 2026

THIS EXHIBIT IS CONFIDENTIAL IN
ITS ENTIRETY AND IS PROVIDED
UNDER SEPARATE COVER
AND IN EXCEL FORMAT ONLY

REDACTED
Case No. PAC-E-26-04
Exhibit No. 3
Witness : Ramon J. Mitchell
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
REDACTED
Exhibit Accompanying Direct Testimony of Ramon J. Mitchell
Power Costs Allocation Post Sale 2030 Forward
April 2026

Rocky Mountain Power
REDACTED Exhibit No.3 Page 1 of 1
SUMMARY Case No. PAC-E-26-04
Witness:Ramon J.Mitchell
State Year Power Costs Post-Sale $ Power Costs Pre-Sale $ Power Costs Delta $ Power Costs Delta $/MWh Power Costs Delta
CA 2030 $30,539,635 $30,989,612 $449,977 $0.56 1.45%
ID 2030 $144,766,714 $146,115,138 $1,348,423 $0.34 0.92%
OR 2030 $772,535,602 $777,761,364 $5,225,762 $0.29 0.67%
UT 2030 $1,185,483,724 $1,192,725,777 $7,242,053 $0.23 0.61
WY 2030 $331,923,235 $334,215,722 $2,292,487 $0.24 0.69%

REDACTED
Case No. PAC-E-26-04
Exhibit No. 4
Witness : Ramon J. Mitchell
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
REDACTED
Exhibit Accompanying Direct Testimony of Ramon J. Mitchell
Net Power Costs Report
April 2026

REDACTED Rocky Mountain Power
Exhibit No.4 Page 1 of 3
Delta Model Forecast Case No.PAC-E-26-04
Witness:Ramon J.Mitchell
Date Year Power Cot Pre-Sale Power Costs Post-Sale($)Power Costs Delta($) Unit Cost Delta($/MWh)
1/1/2027 2027 $151,166,788 $136,716,304 $14,450,485 $0.67
2/1/2027 2027 $147,563,080 $134,766,780 $12,796,301 $0.58
3/1/2027 2027 $151,870,970 $139,265,753 $12,605,217 $0.60
4/1/2027 2027 $140,925,618 $140,127,318 $798,300 $1.60
5/1/2027 2027 $156,920,882 $149,897,357 $7,023,525 $0.46
6/1/2027 2027 $171,174,583 $164,656,607 $6,517,977 $0.60
7/1/2027 1 2027 $207,070,860 $194,406,940 $12,663,920 $0.08
8/1/2027 2027 $202,110,312 $185,263,654 $16,846,658 $0.66
9/1/2027 2027 $186,660,442 $169,358,564 $17,301,878 $1.01
10/1/2027 2027 $150,845,609 $144,540,877 $6,304,732 $0.82
11/1/2027 2027 $153,282,860 $143,081,647 $10,201,213 $0.12
12/1/2027 2027 $168,231,939 $146,526,302 $21,705,636 $1.62
1/1/2030 2030 Forward $205,991,100 $187,759,163 $18,231,937 $0.59
2/1/2030 2030 Forward $200,183,016 $184,153,450 $16,029,566 $0.43
3/1/2030 2030 Forward $204,890,824 $188,948,065 $15,942,759 $0.50
4/1/2030 2030 Forward $207,379,648 $201,033,876 $6,345,772 $1.34
5/1/2030 2030 Forward $217,721,372 $205,278,985 $12,442,387 $0.19
6/1/2030 2030 Forward $226,332,203 $209,932,588 $16,399,616 $0.54
7/1/2030 2030 Forward $281,464,647 $259,461,781 $22,002,866 $0.74
8/1/2030 2030 Forward $264,008,972 $238,394,277 $25,614,695 $1.52
9/1/2030 2030 Forward $238,458,659 $225,293,051 $13,165,608 $0.34
10/1/2030 2030 Forward $200,301,643 $183,399,017 $16,902,626 $0.72
11/1/2030 2030 Forward $199,511,699 $181,438,600 $18,073,099 $0.88
12/1/2030 2030 Forv✓ard $202,483,846 $181,134,503 $21,349,343 $1.14
Year Power Costs Pre- Power Costs Post-Sale Unit Cost Delta Unit Cost Delta
Sale $ $ $/MWh
2027 $1,987,823,945 $1,848,608,103 $0.14 0.487/6
2030 Forward $2,648,727,630 $2,446,227,356 0 1.19%

REDACTED Rocky Mountain Power
Exhibit No.4 Page 2 of 3
Case No.PAC-E-26-04
a MW Delta Analysis Forecast Witness:Ramonj.Mitchell
Date Year Hours Avoided Load Generation Avoided Generation Net Replacement Net System Savings Power Costs Pre- Power Costs Post- nit Cost Delta
Cost$ Market Value($) Costs/Revenues Power Cost($) ($) Sale($) Sale $ $/MWh
1/1/2027 2027 744 $39,141,250 $21,922,025 $8,174,344 $13747,681 $25,393,569 $151,166,788 $125,773219 $2.68
2/1/2027 2027 672 ($23,664,525) $12.702.548 ($5,384,078 $7,318,470 ($16.346,055 $147,563,080 $131,217,026 ($1.32
3/1/2027 2027 744 m($16,501,436 $15,151,530 ($8,670,242 $6,481,288 ($10,020,148) $151,870,970 $141,850,822 $0.08
4/1r2027 2027 720 $12,716823 $13,880,693 $3.283,636 $10,597,056 $2,119,767 $140925,618 $138805851 $1.32
5/1/2027 2027 744 ($11,204,445) $9,855,770 ($1,937,496) $7,918,273 ($3,286,172) $156.920,882 $153,634,710 $1.21
6/1/2027 2027 720 ($13,623,735) $9,564,499 $1,599,149 $7,965,350 $5,658,385 $171,174,583 $165,516,198 $0.76
7/1/2027 2027 744 $20,064,226 $14,116,436 ($3,790,698) $10,325,737 ($9,738,488) $207,070,860 $197,332,372 $0.56
8/1/2027 2027 744 $23,027,985 $13,531,915 ($2,610,048) $10,921,867 ($12,106,118) $202,110,312 $190,004,194 $0.14
9/1/2027 2027 720 $22,881 81 $24,647,371 $6,199,700) $18,447,671 $4,433,610) $186,660,442 $182,226,832 $1.52
10/1/2027 2027 744 ($24,653,095 $23,870,636 ($5,356,191) $18,514,445 ($6,138,650) $150,845,609 $144,706,959 $0.85
11/1/2027 2027 720 ($21,776611 $19,106,738 ($10,325,674) $8,781,063 ($12,995,548) $153,282,860 $140,287,312 ($0A4
12/1/2027 2027 744 $27,985620 $19,232,035 $12,891,857 $6,340,177 $21,645,443 $168,231,939 $146.586,496 L$3
1/12030 2030 Forward 744 ($46,157,289 $19,951,090 ($7,591,894 $12,359,195 ($33,798,093 $205,991,100 $172,193,006 2/12030 2030 Forward 672 $29,681,928 $19,042,231 ($8,116,514 $10,925,717 ($18,756,211 $200,183,016 $181426,806 3/12030 2030 Forward 744 $19810395 $11057,447 $5,145764 $5,911,683 $13,898,712 $204,890,824 $190,992,112 4/1/2030 2030 Forward 720 ($13,021,892 $7,348,041 ($4,070,862 $3,277,179 ($9,744,713 $207,379,648 $197,634,934 5/1/2030 2030 Forward 744 ($9,157,888 $5,308,742 ($4,314,857 $993,885 $8.164,002 $217,721,372 $209,557,370 6/12030 2030 Forward 720 $18 535 043 $9 688 287 $4 036 062 $5 652,226 $12,882 818 $226,332 203 $213 449,386 7/12030 2030 Forward 744 $29,559,594 $21,870,981 ($8,528,890 $13,342,091 ($16,217,503) $281,464,647 $265,247,144
8/1/2030 2030 Forward 744 $29,103,515 $16,476,098 $6,242,943 $10,233,155 $18,870,359 $264,008,972 $245,138,613
9/1/2030 2030 Forward 720 $26,735,408 $25,395,380 ($10,644,946 $14,750,434 ($11,984,974 $238,458,659 $226,473,685 $0.57
10/1/2030 2030 Forward 744 ($23,048.010 $15,628,610 ($7,219,342 $8,409,268 ($14,638,742 $200,301,643 $185,662,901 ($027
11/12030 2030 Forward 720 $23.669,203 $16,917,087 $9,014,202 $7,902,885 ($15,766,318 $199,511,699 $183,745,381 $0.43
12/1/2030 2030 Forward 744 $26,467.928 $11,338,348 ($6,958,405 $4,379,944 ($22,087,984 $202,483,846 $180,395,862 $1.27
2030 Forward 2030 8760 ($288,933.317 $176,097,702 ($81.885,174 $94,212,528 ($194,720,789 $2,648,727,630 $2,454,006,841 ($0.34
2030 Forward 2030 1 $32,960 $20,096 $9,286 $10,810 $22,150 $302,366 $280,216 $0.32
Unit Cost
Per Costs Pre- Power Costs Post- Unit Cost
Power Sale($) Sale($) Delta($/MWh) Delta(%)
2027 $1,987,823945 $1,857,941992 $0.01 0.0%
2030 Forward $2,648,727 630 $2,451,917 200 $0.37 1.0%

REDACTED Rocky Mountain Power
Exhibit No.4 Page 3 of 3
Case No.PAC-E-26-04
aMW Detta Analysis Histoncal Witness:Ramonj.Mitchell
Date Year Hours voided Load Cost Generation Avoided Generation Net Replacement Net System Power Costs Pre- Power Costs Post- Unit Cost Delta
$ Market Value($) Costs/Revenues Power Cost($) Savings $) Sale($) Sale $
12/12025 2025 744 $29,047,544 $15,761421 $9,033,950 $6,727,470 $22,320,074 $136,041,610 $113721536 $2.26
11/12025 2025 720 ($29,226,044 $16.446,130 ($11,067,985 $5,378,146 ($23,847,899) $149,559,816 $125,711,918 $2.76
10/12025 2025 744 $27,606,783 $25,362,518 $7,638,149 $17,724,369 $9,882,413 $150,153,087 $140,270,674 $0.20
9/12025 2025 72 ($35730,016 $29,455,895 $5,176,081 $24,279,814 $11,450,202 $196,204,795 $184,754,593 $0.18
8112025 2025 744 ($31,320,545 $27,863,634 ($5,099.662) $22.763,971 ($8,556,574) $229.790,264 $221,233,690 $0.68
7112025 2025 744 $31,327,072 $26,682,891 $4,201,676 $22,481,215 $8,845,858 $241,506,087 $232,660.230 $0.70
6/12025 2025 720 $26,278,465 $18,155,982 ($2,450,181) $15,705,800 ($10,572,665) $188,153,657 $177,580,992 $0.63
5/1/2025 2025 744 $22,578,189 $15,470,109 ($2,575,118) $12,894,991 ($9,683,198) $155,991,690 $146,308,492 $0.58
4/1/2025 2025 720 $20.068,372 $8,408,251 $1,511,951 $6,896,300 $13,172,072 $136,562,909 $123,390,836 $0.672_
3/1/2025 2025 744 $28,373,102 $23,492,382 ($10,914,211 $12,578,171 ($15,794,931 $141,753,844 $125,958,913 ($1.23
2112025 2025 672 ($30.281,131 $24,184,030 ($12,075,001 $12,109,029 ($18.172,102 $173,740,897 $155,568,796 ($1.14
1/1/2025 2025 744 $33,728,235 $22,191.037 $14,263,188 $7,927,849 $25,800,386 $184,006,514 $158,206,128 $2.16Z_
12/12024 2024 744 $43,943,329 $26,702,646 $13,492,880 $13,209,766 $30.733.563 $168.105,668 $137,372,105 $3.19
11/12024 2024 720 $30,822,061 $29,736,289 ($13,265,008) $16,471,281 ($14,350,780) $169,800,091 $155,449,311 $0.42
10/1/2024 2024 744 $41,184,826 $42,403883 $5,584,969 $36,818,913 $4,365,913 $164,673,741 $160,307,828 $1.61
9/1/2024 2024 720 ($48,859,343 $43,998,595 ($3,980,079) $40,018,516 ($8,840,828 $248,578,673 $239,737,845 $'1.27
8112024 2024 744 $44,571.334 $43,645,610 $5,025,482 $38,620,129 $5,951,206 $279,859,798 $273,908,592 $1.67
7/1/2024 2024 744 $43 867,766 $45 408 574 $4 925 857 $40 482 717 $3 385 048 $314.852,101 $311 467 053 $2.37
6/1/2024 2024 720 $29,651,787 $13,278,818 ($1,850,229) $11,428,589 ($18,223,198) $189,026,409 $170,803,211 $0.77
5/1/2024 2024 744 $34,373,580 $22,347,190 $1,562,432 $20,784,757 $13,588,823 $152,092,127 $138,503,304 $0.32
4/1/2024 2024 720 $23,747,106 $18,250,415 ($2,001,357) $16,249,058 ($7,498,048) $148,189,148 $140,691,100 $0.90
3/12024 2024 744 ($20,734,535 $18,511,525 ($10,020,277 $8,491,248 ($12,243,287 $158,163,741 $145,920,454 $0.32
2/1/2024 2024 696 $28,624,121 $23,208,863 ($11,794,737 $11,414,126 $17,209995 $181,281,611 $164,071,615 $0.80_
1/12024 2024 744 $88,905,184 $73,416,397 ($14,962,900) $58,453,497 ($30,451,687) $318,001,079 $287,549,392 $1.20
12/1/2023 2023 744 ($32,490,022 $14,036,548 ($7,636,309) $6,400,239 ($26,089,783) $180,596,682 $154,506,899 $2.25
11/12023 2023 720 $35,416,193 $17,326,558 $7,054,690 $10,271.868 $25,144,325 $181,132,068 $155,987,743 $2.45
10/12023 2023 744 $46,861,472 $39,473,765 ($7,682,220 $31,791,544 ($15,069,928 $167,396,187 $152,326,259 ($0.43
9/12023 2023 720 $53,955,404 $49,479,572 ($5,822,595) $43,656,977 ($10,298,427) $224,866,312 $214,567,885 $0.95
8/12023 2023 744 $53.500 260 $48,449,944 $5 777 193 $42 672,750 $10 827 510 $287,309,093 $276,481,583 $0.77
7/1/2023 2023 744 $48,855,763 $28,376,663 ($4,424,532) $23,952,131 ($24,903,632) $288,981,994 $264,078,362 $1.66
6/12023 2023 720 $30,069,579 $11,414,715 $3,420,255 $7,994,460 $22,075,119 $171,185,695 $149,110,576 $1.93
5/1/2023 2023 744 $23,213,098 $12,129,941 $5,019,408 $7,110,533 ($16,102,564 $152,061,048 $135958484
4/12023 2023 720 ($28,634,758 $20,647,624 ($3,024,548 $17,623,076 $11,011,682) $147,599,301 $136,587,619 $0.25
3/1/2023 2023 744 $34,529,565 $42,750,262 ($14,019,008 $28,731,254 $5,798,311 $196,426,040 $190,627,729 $1.35
2/1/2023 2023 672 ($44,929,260 $30,597,567 ($15,176,081 $15,421,486 ($29,507,774) $197,011,038 $167,503,264
1/12023 2023 744 $61,990,505 $52,421,445 ($20,843,202) $31,578,242 ($30,412,263) $180,034,202 $149,621,938 $3.25
12/12022 2022 744 $118,779,756 $96.703,306 $37,725,130 $58,978,176 $59,801,580 $243,564,064 $183,762,484 11/12022 2022 720 ($37,084,307 $35,702,212 ($19,218,925) $16,483.287 ($20,601,021 $157,041,510 $136,440,489JE(WIZ7:�5�5
10/12022 2022 744 ($30,276,037 $32,255,382 ($13,621,958 $18,633,424 ($11,642,613 $129,497.942 $117,855,329
9/12022 2022 720 $68 958 285 $60 798 933 $9 504,075 $51,294 858 $17,663 428 $186 460,032 $168 796 605
8/1/2022 2022 744 ($36,999,268) $33,855,234 ($9,518,001) $24,337,233 ($12,662,035) $209,939,048 $197,277,013
7/1/2022 2022 744 ($29,172,121) $21,197,988 $6,711,159 $14,486,828 ($14,685,293) $221,012,116 $206,326,824 ($0.48
6112022 2022 720 $15 170 202 $2 622 730 $1 391 989 $4 014 719 $11 155 483 $124 640 439 $113,484,95E $0.08
5/12022 2022 744 $31,405,057 $7,407,138 $3,090,002 $10,497,141 $20,907,916 $125.298,871 $104,390,955 $2.25
4/1/2022 2022 720 $27,483,873 $25,596,298 $7,891,944 $17,704,355 $9,779,518 $117,893,958 $108,114,440 $( 0.34
3/1/2022 2022 744 $19649581 $9,613,395 $1,100,295 $8,513,100 $11,136,481 $105.311,001 $94174520 $0.84
2/12022 2022 672 $23,112,626) $12,731,409 ($3,845,309) $8,886,099 ($14,226,526L $107,047,721 $92,821,195 $1.14
1/12022 2022 744 $27299350 $9,887,416 $12945,223 $3,057,807 $30,357,157 $127,472,375 $97.115.218 $3.77
-
Power Costs Pre- Power Costs Post-Sale Unit Cost Unit Cost
Year Sale($) ($) MW
$ h Delta(%)
2025 $2,083,465,171 $1,905,366,798 ($0.53) (1.6%)
2024 $2,492,624,187 $2325781,811 $0.15 0.4%
2023 $2,374,599,659 $2,147,358,343 $1.06 (2.8%)
2022 $1,855,179,079 $1,620,560,028 $1.67 5.6%
Aggregate $8,805,868,096 $7,999,066,980 ($0.76) (2.20/6)
Direction Value Absolute Value Ratio
Decrease ($3.26) 3.257578017 96%
Increase $0.15 0.145993968 4%
Unit Cost of Power Delta
202 202a zo2 2tn
a>
G
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0
O
a
O
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0
U_
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Year
4

REDACTED
Case No. PAC-E-26-04
Exhibit No. 5
Witness : Ramon J. Mitchell
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
REDACTED
Exhibit Accompanying Direct Testimony of Ramon J. Mitchell
Renewable Energy Credits Report
April 2026

REDACTED Rocky Mountain Power
State Summary Exhibit No.5 Page 1 of 2
Case No. PAC-E-26-04
Witness:Ramon I Mitchell
Year State SG Allocation
2030 CA 1.43%
2030 ID 6.53%
2030 OR 28.27%
2030 UT 48.77%
2030 WY 14.98%
2027 CA 1.43%
2027 ID 6.53%
2027 OR 28.27%
2027 UT 48.77%
2027 WY 14.98%

REDACTED Rocky Mountain Power
Exhibit No.5 Page 2 of 2
REC Benefit Summary Case No. PAC-E-26-04
Witness:Ramon I Mitchell