20240531Direct R. Mitchell - Redacted.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. PAC-E-24-04
OF ROCKY MOUNTAIN POWER FOR )
AUTHORITY TO INCREASE ITS RATES ) DIRECT TESTIMONY OF
AND CHARGES IN IDAHO AND ) RAMON J. MITCHELL
APPROVAL OF PROPOSED ) REDACTED
ELECTRIC SERVICE SCHEDULES AND )
REGULATIONS )
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-24-04
May 2024

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 (the
4 "Company") .
5 A. My name is Ramon J. Mitchell, and my business address is
6 825 NE Multnomah Street, Suite 600, Portland, Oregon
7 97232 . My title is Manager, 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 the Company in 2015 and during my time at
14 the Company I have held various positions in the
15 regulation, merchant, and transmission departments .
16 After a brief departure from the Company, in 2022 I
17 returned to the Company as Manager, Net Power Costs . In
18 my current role I am responsible for leading and
19 overseeing various efforts associated with the Company' s
20 net power costs filings .
21 Q. Have you testified in previous regulatory proceedings?
22 A. Yes . I have previously provided testimony to the public
23 utility commissions in California, Oregon, Washington,
24 and Wyoming.
Mitchell, Di 1
Rocky Mountain Power

1 II . PURPOSE OF TESTIMONY
2 Q. What is the purpose of your testimony in this proceeding?
3 A. My testimony presents the Company' s proposed net power
4 costs ("NPC") for the 12-month forecast period ending
5 December 31, 2025 ("NPC test period") ; and proposes
6 changes to the annual Energy Cost Adjustment Mechanism
7 ("SCAM") to update the sharing band. The proposed NPC
8 would become the new base NPC for the ECAM, beginning
9 January 1, 2025 . Specifically, my testimony:
10 • Supports removing Renewable Energy Credit ("REC")
11 adjustments from the SCAM;
12 • Discusses Federal Energy Regulatory Commission
13 ("FERC") Order No . 898 which moves certain costs
14 from FERC account 555 to FERC account 509;
15 • Provides detail on the NPC component of the
16 Company' s rate mitigation proposal, which will ease
17 financial burdens on the Company' s customers;
18 • Summarizes forecasted NPC for the 2025 NPC test
19 period in this general rate case ("GRC") and
20 explains the calculation of NPC using the Company' s
21 Aurora production cost model;
22 • Explains the primary drivers behind the increase in
23 NPC compared to the current base NPC approved by
24 the Commission and incorporated into customer rates
25 in the Company' s last general rate case, Case No .
26 PAC-E-21-071 ("2021 GRC") , which includes a
27 discussion of extraordinary increases in regional
28 wholesale electricity (power) and natural gas fuel
29 (gas) market prices since the 2021 GRC;
1 In the Matter of the Application of Rocky Mountain Power for Authority
to Increase its Rates and Charges in Idaho and Approval of Proposed
Electric Service Schedules and Regulations, Case No. PAC-E-21-07, Order
No. 35277 (Dec. 30, 2021) .
Mitchell, Di 2
Rocky Mountain Power

1 • Describes new policy changes and operations changes
2 since the 2021 GRC that substantially impact NPC;
3 • Describes modeling changes the Company has made to
4 improve the NPC forecast accuracy since the 2021
5 GRC; and
6 • Proposes updating the ECAM sharing band considering
7 the Company' s pending participation in a complete
8 organized market along with observations on trends
9 in western markets since the inception of the
10 current sharing band in 2009 .
11 Q. Is there a summary of the proposed ECAM Base amounts to
12 be set in this filing for future ECAM filings?
13 A. Yes . Exhibit No. 51 attached to the testimony of Company
14 witness Shelley M. McCoy, summarizes the proposed base
15 amounts for all elements for ECAM deferrals beginning
16 January 1, 2025 . In addition to NPC discussed in my
17 testimony, the ECAM deferral includes the difference
18 between actual and base amounts for production tax
19 credits, and load change adjustment revenues .
20 Q. How is the testimony organized?
21 A. In section II, I first present the Company' s proposal to
22 adjust the ECAM to remove REC adjustments and I discuss
23 FERC Order No . 898 . I then provide an overview of the
24 NPC forecast for the 2025 NPC test period. This overview
25 includes a high-level discussion of the NPC changes
26 since the 2021 GRC followed by a more detailed discussion
27 of the individual NPC components along with narrative
Mitchell, Di 3
Rocky Mountain Power

1 explanations which touch on the impacts associated with
2 new policy and operations changes .
3 Next, Section III includes a discussion on the
4 reasonableness of the NPC forecast and section IV
5 explores in detail the drivers of regional forward power
6 market prices and regional forward fuel prices which
7 account for the majority of the change in the NPC
8 forecast since the 2021 GRC.
9 Section V discusses in detail new policy and
10 operations changes, along with the numeric impacts to
11 the NPC forecast that each change represents .
12 In Section VI, I discuss the transition from the
13 Generation and Regulation Initiative Decision Tools
14 production cost model ("GRID") to the Aurora production
15 cost model ("Aurora") for the forecast of NPC, then in
16 Section VII, I present and discuss changes to improve
17 modeling accuracy along with the numeric impacts to the
18 NPC forecast that each improvement represents .
19 In section VIII I transition the discussion to the
20 proposed NPC forecast based on 2023 weather normalized
21 load.
22 Finally, after the NPC portion of my testimony, I
23 transition into a discussion on NPC recovery in the ECAM,
24 in section IX.
Mitchell, Di 4
Rocky Mountain Power

1 Q. Please describe the proposed change in the ECAM related
2 to RECs .
3 A. The Company is proposing to remove the REC revenue
4 adjustment from the annual SCAM calculation. As
5 described in Company witness Craig M. Eller' s testimony,
6 the Company is proposing a new voluntary REC option
7 tariff. Company witness McCoy addresses the Company' s
8 proposed adjustments to the revenue requirement in this
9 case to facilitate the REC option tariff and Company
10 witness Robert M. Meredith introduces the proposed
11 tariff Electric Service Schedule No . 98 - REC Revenue
12 Adjustment ("'RRA") . Since REC revenue would now be
13 passed back to customers through proposed tariff
14 Electric Service Schedule No. 98, the REC revenue
15 adjustment would no longer be included in the ECAM.
16 Q. Please describe the movement of costs from FERC account
17 555 to FERC account 509.
18 A. On June 29, 2023, the FERC issued Order No . 898 (Docket
19 No . RM21-11-000) , 2 Accounting and Reporting Treatment of
20 Certain Renewable Energy Assets, to change the
21 accounting required for certain types of costs that have
22 been previously booked to FERC Account 555 to be booked
z File Rule, 183 FERC 1 61,205, Docket No. RM21-11-000 (Jun. 29, 2023)
available at https://www.ferc.gov/media/order-no-898.
Mitchell, Di 5
Rocky Mountain Power

1 to FERC account 509 . This change becomes effective on
2 January 1, 2025 .
3 Q. What costs will be affected by FERC' s Order No. 898
4 beginning January 1 , 2025?
5 A. The change in accounting affects the costs associated
6 with greenhouse gas ("GHG") allowances that have been
7 historically booked to FERC account 555 . Specifically
8 for NPC, California GHG costs and Washington GHG costs
9 will be booked to FERC account 509, beginning January 1,
10 2025 . Correspondingly, for those costs which would have
11 been recovered from FERC account 555, the Company
12 advises that they will now be recovered from FERC account
13 509 .
14 Q. Please provide detail on the NPC component of the
15 Company' s proposed rate mitigation proposal .
16 A. The Company proposes to phase in the increase to the
17 base ECAM across two years, with the ability to recover
18 100 percent of any ECAM variance up to and no further
19 than the Company' s proposed ECAM forecast . The proposed
20 ECAM forecast on a dollar per megawatt hour ($/MWh) basis
21 is $39 . 34/MWh and the ECAM base currently in rates is
22 $24 . 54/MWh. The rate mitigation proposal in this context
23 would phase in the proposed ECAM through two steps by
24 increasing the base from $24 . 54/MWh to $31 . 94/MWh on
25 January 1, 2025, and then increasing the base from
Mitchell, Di 6
Rocky Mountain Power

1 $31 . 94/MWh to $39 . 34/MWh on January 1, 2026 . As part of
2 this phase-in across the two years, the Company proposes
3 that the ECAM sharing band would only apply to ECAM
4 variances above $39 . 34/MWh or below $24 . 54/MWh, with 100
5 percent recovery of ECAM variances between the
6 $24 . 54/MWh base and the $39 . 34/MWh forecast . Company
7 witness Joelle R. Steward discusses this proposal in
8 further detail .
9 Q. Please explain the components of the Company' s NPC.
10 A. NPC are defined as the sum of fuel expenses, wholesale
11 purchased power expenses, allowances, and wheeling
12 expenses, less wholesale sales revenue . The NPC forecast
13 approved in this case becomes the base NPC used for
14 comparison to actual NPC in the Company' s annual SCAM
15 filings .
16 Q. Please explain how the Company calculates NPC.
17 A. NPC are calculated for the forecast NPC test period based
18 on projected data using Aurora, which simulates the
19 operation of the Company' s power system on an hourly
20 basis . The production cost model respects all system
21 requirements and constraints and commits and dispatches
22 the Company' s resources for an NPC-minimizing output
23 where demand and supply are balanced.
Mitchell, Di 7
Rocky Mountain Power

1 Q. Which version of Aurora was used to prepare this initial
2 filing?
3 A. The Aurora version used to prepare this initial filing
4 was version 14 .2 . 1059 . 3 No other version of Aurora is
5 assured to be able to identically reproduce the NPC
6 proposal in this initial filing. This - and all - Aurora
7 versions are available upon request from Energy Exemplar
8 provided that a license agreement is in place that allows
9 utilization of the software .
10 Q. What Aurora inputs were updated for this filing?
11 A. All inputs have been updated since the 2021 GRC,
12 including system load, reserves, wholesale sales and
13 purchase contracts for electricity, natural gas and
14 wheeling, market prices for electricity and natural gas
15 also known as the official forward price curve ("OFPC") ,
16 fuel expenses, transmission topology, and the
17 characteristics and availability of the Company' s
18 generation facilities .
19 Q. Did the Company update regulation reserves for this
20 filing?
21 A. Yes, consistent with the prior GRC, the Company has
22 updated regulation reserves to be aligned with the
s Specifically, Aurora version 14.2.1059 released on May 23, 2023.
Mitchell, Di 8
Rocky Mountain Power

1 recent integrated resource plan' s ("IRP") flexible
2 reserve study. 4
3 Q. What is the date of the OFPC the Company used for its
4 forecast NPC?
5 A. The forecast for 2025 NPC uses the OFPC dated March 29,
6 2024 .
7 Q. What reports do the Aurora model produce?
8 A. The major output from the Aurora model is the NPC report,
9 which is attached to my testimony as Exhibit No . 23 .
10 Q. What is the proposed total-Company NPC for the 2025 NPC
11 test period?
12 A. Under 2023 weather normalized load conditions, the
13 proposed NPC for the 2025 NPC test period is $2 . 382
14 billion, or $39 . 19/MWh, on a total-Company basis; or
15 $136 . 7 million, or $39 . 34/MWh on an Idaho-allocated
16 basis .
17 However, for narrative accuracy, the following
18 testimony provides NPC analyses based upon an NPC
19 forecast using expected NPC test period load (i .e. , 2025
20 forecast load) , unless otherwise noted. Then, at the end
21 of my testimony a final adjustment is made to bring NPC
22 in line with 2023 weather normalized load.
9 See PacifiCorp 2021 Integrated Resource Plan, Appendix F and PacifiCorp
2023 Integrated Resource Plan, Appendix F.
Mitchell, Di 9
Rocky Mountain Power

1 Under 2025 load forecast conditions, NPC for the
2 2025 NPC test period are $2 . 651 billion, or $39 . 83/MWh,
3 on a total-Company basis . Unless otherwise noted,
4 references to NPC or various individual cost items
5 throughout my testimony are stated in total-Company
6 system amounts .
7 Q. Please explain the changes in 2025 NPC as compared to
8 the 2021 NPC forecasted in the 2021 GRC.
9 A. Using the 2023 weather normalized NPC forecast to
10 compare to the 2021 GRC, which was also weather
11 normalized, the changes to NPC on a total-Company basis
12 are illustrated below in Table `NPC Variance Between
13 GRCs' and the associated energy changes on a total-
14 Company basis are illustrated below in Table `Energy
15 Variance Between GRCs' . Below, I expand on the
16 individual line items .
Mitchell, Di 10
Rocky Mountain Power

Table NPC Variance Between GRCs
Net Power Cost Reconciliation ($)
($ millions) $/MWh
ID 2021 GRC Final Forecast 1,368 23.41
Increase/ (Decrease) to NPC:
Wholesale Sales Revenue (201 . 7)
Purchased Power Expense 386. 4
Coal Fuel Expense 77 . 4
Natural Gas Fuel Expense 308 .2
Wheeling and Other Expense 39. 6
Total Increase/ (Decrease) to NPC 1013.4
ID 2024 GRC Initial Forecast 2 ,382 39.19
Table Energy Variance Between GRCs
Net Power Cost Reconciliation (MWh)
MWh $/MWh
ID 2021 GRC Final Forecast 58,444,451 23.41
Change to Net System Load:
Wholesale Sales Decrease (7, 334, 748)
Purchased Power Increase 1, 862, 120
Coal Generation Decrease (8, 838, 653)
Natural Gas Generation
3, 580, 407
Increase
Other Generation Decrease (1, 594, 690)
Total Change to Net System Load 2,343,932
ID 2025 GRC Initial 60,788,384 39.19
Mitchell, Di 11
Rocky Mountain Power

1 Q. Please explain the increase in purchased power expense.
2 A. The purchased power expense increases in tandem with
3 power market prices supplemented by increased purchased
4 power volumes due to: (1) reduced coal supply
5 availability in Utah; (2) the decrease in generation at
6 the Chehalis plant due to the Washington Cap and Invest
7 Program ("WA-GHG") ; and (3) lower hydroelectric
8 generation driven by the deconstruction/removal of
9 Klamath River hydroelectric facilities . I explain these
10 individual drivers in more detail below.
11 Q. Please explain the increase in coal fuel expense and the
12 increase in natural gas fuel expense.
13 A. The coal fuel expense increases due to coal fuel price
14 increases which result from increased domestic
15 competition for limited coal supply. Some of the coal
16 fuel expense is offset by: (1) coal supply challenges,
17 which decrease the amount of generation at certain coal
18 facilities; and (2) the gas conversion of Jim Bridger
19 units 1 and 2, which removes two generating units from
20 the coal fuel expense category. Natural gas fuel expense
21 increases due to : (1) the gas conversion of Jim Bridger
22 units 1 and 2, which adds two generating units into the
23 natural gas fuel expense category; and (2) increased
24 dispatch of natural gas units to meet load and reserve
25 obligations . Natural gas fuel expense also increases in
Mitchell, Di 12
Rocky Mountain Power

1 tandem with natural gas market prices .
2 Q. Please explain the decrease in wholesale sales revenue
3 and the increase in wheeling and other expense.
4 A. With decreased net generation, wholesale sales volumes
5 also decrease . Wheeling expenses increase relative to
6 the forecast in the 2021 GRC based on increases in the
7 historical wheeling expenses supporting recent actual
8 purchased power volumes .
9 Q. Please summarize the overall changes .
10 A. The overall changes are driven by: 1) the NPC under-
11 forecast in the 2021 GRC; and 2) increases in purchased
12 power and natural gas fuel expense that result from
13 increased power and natural gas commodity prices, a
14 reduction in generation due to the WA-GHG program, the
15 expectation of lower hydroelectric generation resulting
16 from the deconstruction of hydroelectric facilities
17 along the Klamath River, and coal supply challenges .
18 III . NPC VALIDATION
19 Q As an initial matter, please discuss the 2021 NPC
20 forecast from the prior GRC.
21 A The prior GRC forecasted NPC of $1 . 368 billion total-
22 Company for calendar year 2021 . Actual total-Company NPC
23 for calendar year 2021 were $1 . 715 billion. Therefore,
24 the prior GRC' s NPC was a $347 million total-Company
25 under-forecast for the 2021 NPC test period.
Mitchell, Di 13
Rocky Mountain Power

1 Q. Is $2 . 651 billion a reasonable forecast for total-
2 Company 2025 NPC using 2025 load expectations?
3 A. Yes . Calendar year 2023 actual NPC are $2 . 555 billion.
4 In 2025, as compared to 2023 :
5 (1) At the total-Company level, 2025 forecast NPC
6 are $2 . 651 billion, or $39 . 83/MWh while 2023 actual
7 NPC are $2 . 555 billion, or $41 .26/MWh. On a dollar
8 basis, NPC increase by 3 . 7 percent, however on a
9 $/MWh basis, NPC decrease by 3 . 5 percent;
10 (2) 2025 Pacific Northwest summer and winter peak
11 power prices increase by 18 percent and Desert
12 Southwest summer and winter peak power prices
13 increase by 9 percent;
14 (3) 2025 Pacific Northwest summer and winter natural
15 gas prices increase by 54 percent and Rocky
16 Mountain region summer and winter natural gas
17 prices increase by 21 percent (both calculations
18 excluding the anomalous January 2023 price
19 excursion) ; 5 and
20 (4) Although new Company-owned $0/MWh marginal cost
21 wind is estimated to produce 1 . 1 million megawatt-
22 hours ("MWh") more at the total-Company level, as
23 compared to 2023; load increases by 4 . 7 million MWh
24 at the total-Company level, as compared to 2023,
25 and completely absorbs that increased wind
26 production. After subtracting the new Company owned
27 wind generation increase, the remaining load
28 increase is 3 . 6 million MWh.
29 These fundamentals indicate that 2025 total-Company
30 NPC will be higher than 2023 total-Company NPC. All else
31 equal, the remaining load increase valued at the average
s The Company excluded the outlier data from January 2023 because inclusion
of that anomalous price spike skews the comparison of 2023 to 2025 data.
However, in the interest of complete analysis for the record, from 2023
to 2025, January natural gas prices in the Pacific Northwest and in the
Rocky Mountain region decreased by 31 percent and 56 percent,
respectively.
Mitchell, Di 14
Rocky Mountain Power

1 NPC of $39 . 83/MWh suggests that 2025 NPC should be an
2 increase of $142 million relative to 2023 NPC. This
3 implied increase is a conservative estimate given that
4 load increases are more likely to be fulfilled by market
5 purchases rather than the pre-existing generation mix.
6 From this basic analysis, the 2025 NPC forecast, pre-
7 weather normalization, is within reason, if not
8 conservative .
9 Q. Why are summer and winter prices particularly critical
10 when comparing price changes?
11 A. Summer and winter peak periods are periods of high
12 customer demand and stressed system conditions and
13 higher power prices in those periods will produce NPC
14 that is substantially higher relative to any decrease in
15 NPC that may result from lowered prices in spring and
16 fall months, which have light load and relatively mild
17 system conditions .
18 Q. Please provide the actual NPC incurred by the Company
19 since the filing of the prior GRC.
20 A. Table `NPC Variance' and Figure `NPC Variance' show both
21 actual and forecast NPC from calendar year ("CY") 2020
22 to CY 2025 where available .
Mitchell, Di 15
Rocky Mountain Power

Table NPC Variance6
NPC Total Company Total Company Rate Mitigation
Year Actual NPC Forecast NPC Proposed NPC
2020 1, 511, 314, 189 1, 441, 320, 020
2021 1, 714, 607, 879 1, 367, 917, 419
2022 2, 040, 318, 303 1, 369, 404, 716
2023 2, 555, 124, 438 2, 016, 140, 036
2024 2, 681, 145, 109
2025 2, 650, 729, 651 2, 009, 323, 535
2026 2, 650, 729, 651
Figure NPC Variance?
Actual vs Forecast NPC
$3.0
$2.5
p $2.0 r
I
z $1.5 F1
u $1.0
a
z
$0.5
$_ 4AMM LL
2020 2021 2022 2023 2024 2025 2026
Actual NPC �Forecast NPC m Rate Mitigation Base NPC in Rates
1 As can be seen in Table `NPC Variance' and Figure
2 `NPC Variance' , not only was there a substantial NPC
3 under-forecast in the prior GRC which forecasted CY
4 2021; also, actual NPC from 2020 to 2023 has increased
5 year over year. Most of this increase is attributable to
6 Calendar years 2020, 2022, 2023 and 2024 pull forecasts from the Oregon
Transition Adjustment Mechanism.
' Id.
Mitchell, Di 16
Rocky Mountain Power

1 wholesale electricity (power) and natural gas fuel
2 market prices, weather conditions, fuel supply
3 constraints, retail load increases, and regulatory
4 obligations .
5 Also of note is that calendar years 2020, 2021,
6 2022, and 2023 have seen an increase in abnormal/extreme
7 weather events that have resulted in higher-than-
8 expected load during stressed system conditions, and
9 this trend has set expectations amongst market
10 participants for similar conditions in 2024 and 2025 .
11 Q. Please describe some of the changes in system conditions
12 experienced by the Company in 2021 , the prior GRC' s NPC
13 test period.
14 A. In CY 2021, a few extreme and unforeseen weather events
15 drove increases in actual NPC. For instance, there was
16 a polar vortex engulfing the region in February 2021 and
17 a heat dome event in July 2021 . The average purchased
18 power price was $30 . 68/MWh higher than the average
19 purchased power price forecasted in the base NPC,
20 contributing to a substantial increase in purchased
21 power expense . Additionally, the Company also faced
22 severe drought conditions that resulted in hydroelectric
23 generation being lower than forecast, resulting in
24 increased purchased power volumes - and associated
25 expense - to provide replacement energy. The Company
Mitchell, Di 17
Rocky Mountain Power

1 also faced supply chain issues that were a result of a
2 global supply chain disruption which resulted in
3 construction delays for many of the Company' s renewable
4 resources that would have otherwise achieved an earlier
5 commercial online date . These delays resulted in
6 increased purchased power volumes and associated
7 expense .
8 Q. Please describe some of the changes in system conditions
9 experienced by the Company in 2022 .
10 A. In CY 2022, like 2021, unforeseen weather events again
11 drove increases in actual NPC, such as the multiple heat
12 waves in the region during the summer of 2022 and ongoing
13 drought conditions . These drivers increased peak period
14 power prices and reduced hydro generation availability,
15 respectively. Similarly, there was a historic cyclone
16 event in the winter of 2022 that impacted power and
17 natural gas prices . For example, average prices at the
18 Opal natural gas trading hub were 424 percent higher in
19 December 2022 as compared to December 2021 while peak
20 power prices at the Mid-Columbia trading hub were 380
21 percent higher. Lastly, the Russian invasion of Ukraine
22 substantially increased natural gas market prices
23 throughout the year. These events, taken together,
24 contributed to substantial increases in purchased power
25 expense and natural gas fuel expense .
Mitchell, Di 18
Rocky Mountain Power

1 Q. Please describe some of the changes in system conditions
2 experienced by the Company in 2023 .
3 A. In CY 2023 coal fuel supply constraints, which began at
4 the end of CY 2022 : (1) continued throughout 2023; (2)
5 still impact the Company today; and (3) are anticipated
6 to continue through 2025 . On a more comprehensive note,
7 power prices and natural gas prices have risen sharply
8 since the beginning of 2021 . Between 2016 and 2020, the
9 average monthly heavy load hour ("HLH") market price at
10 the Mid-Columbia power trading hub ("Mid-C") was
11 $29 .27/MWh and at the Four Corners trading hub ("4C") ,
12 $35 . 11/MWh. This is compared to the average monthly HLH
13 power prices in 2023 which were $85 . 51/MWh and
14 $81 . 12/MWh at Mid-C and 4C, respectively. Similarly,
15 between 2016 and 2020, the average monthly gas price at
16 the Opal gas trading hub was $2 . 51/MMBtu and at the Sumas
17 gas trading hub, $3 . 19/MMBtu. This is compared to the
18 average monthly gas prices in 2023 which were
19 $4 . 70/MMBtu and $4 .22/MMBtu at Opal and Sumas,
20 respectively. Reduced coal generation increased
21 purchased power expense and increased natural gas fuel
22 expense due to the need for replacement power.
23 Additionally, the impacts of the Washington Cap and
24 Invest Program increased NPC through increased expenses
25 related to the procurement of greenhouse gas ("GHG")
Mitchell, Di 19
Rocky Mountain Power

1 allowances for the out-of-state export of energy from
2 the Chehalis gas plant, physically located in
3 Washington. The associated increase in 2023 NPC was $42
4 million on a total-Company basis . Of note, the absence
5 of any generation from the Chehalis plant would result
6 in an increase to NPC, relative to the status quo of the
7 Washington Cap and Invest Program, due to replacement
8 energy being sourced from market purchases, which are
9 more expensive than the cost of Chehalis' fuel and GHG
10 allowances combined.
11 Q. Please generally describe the changes in 2025 NPC
12 compared to the 2021 NPC from the 2021 GRC.
13 A. The NPC forecast from the 2021 GRC used a March 31, 2021
14 vintage OFPC to set the price expectations for a calendar
15 year 2021 NPC forecast. Compared to calendar year 2025
16 price forecasts using a March 29, 2024 vintage OFPC,
17 average power market prices at the Mid-Columbia power
18 trading hub increased by 131 percent and average natural
19 gas fuel market prices at the Sumas gas trading hub
20 increased by 71 percent . The changes are illustrated in
21 Figure `OFPC' below. As a result of increase in prices
22 and other substantive changes to the 2025 landscape,
23 which I discuss in more detail below, total-Company NPC
24 increased by approximately $15 . 78/MWh, or 67 percent,
Mitchell, Di 20
Rocky Mountain Power

1 from the 2021 GRC forecast of $23 . 41/MWh to the current
2 weather normalized GRC forecast of $39 . 19/MWh.
3 On an Idaho-allocated basis, the Company' s weather
4 normalized NPC as modeled for the NPC test period in
5 this case have increased by $14 . 80/MWh, or 60 percent,
6 from the 2021 GRC forecast of $24 . 54/MWh to the current
7 weather normalized GRC forecast of $39 . 34/MWh.
Figure OFPC
Increase in Power and Gas Price Forecasts -
U
0 2021 Forecast vs 2025 forecast
a
cli0 90.00 $81.05/MWh
a F 80.00
� m
o 70.00
N ' 60.00
0 0
aa 50.00 -
40.00 $35.07/MWh
30.00
a v 20.00
Q
10.00 $2.90/MMBtu $4.97/MMBtu
U
z 0.00
Mid C 2021 vs 2025 Sumas 2021 vs 2025
■2021 ■2025
8 Q. What actions have the Company taken to lower NPC?
9 A. The Company has implemented a number of initiatives to
10 lower NPC. Prime examples of these initiatives are as
11 follows :
12 1 . Participation in the Western Energy Imbalance
13 Market ("'WEIM") . The Company has been an active
14 participant in the WEIM since its inception in 2014
15 and has realized substantial benefits, helping to
Mitchell, Di 21
Rocky Mountain Power

1 drive NPC downwards . From the prior GRC to 2023 the
2 Company realized an annual average of $147 million
3 in WEIM benefits . $
4 2 . Participation in the Extended Day-Ahead Market
5 ("EDAM") . The Company announced in 2022 that it
6 will join the California Independent System
7 Operator' s EDAM. 9 Similar to the WEIM, the EDAM will
8 leverage a diverse pool of participating utilities,
9 creating a region-wide day-ahead market, to lower
10 the Company' s NPC. Preliminary analysis indicates
11 that the Company may realize savings of up to $181
12 million per year, 10 which are incremental to (not
13 double counting) the current NPC benefits realized
14 through WEIM participation.
15 3 . Resource Expansion - Post 2021 the Company has
16 procured and repowered a number of owned wind
17 facilities (with marginal costs of $0/MWh) that
18 drive NPC down. Concurrently and synergistically,
19 the Company has increased investment in
20 transmission expansion in order to facilitate the
21 transfer of the aforementioned $0/MWh energy to the
22 wider system. These new wind and transmission
23 assets have driven NPC down by $87 million for the
24 NPC test period.
25 IV. REGIONAL MARKET PRICE INCREASES
26 Q. Why have regional power and gas market prices increased
27 to such extraordinary highs since the prior GRC?
28 A. Regional power market prices are driven primarily by
29 regional gas market prices which are in turn primarily
30 driven by natural gas fuel prices . Since March 2021 (the
31 vintage of the OFPC used in the 2021 GRC filing) , natural
8 https://www.westerneim.com/Pages/About/QuarterlyBenefits.aspx.
9 https://www.pacificorp.com/about/newsroom/news-releases/EDAM-
innovative-efforts.html; https://www.caiso.com/Documents/extended-day-
ahead-market-edam-fact-sheet.pdf.
io https://www.brattle.com/wp-content/uploads/2023/04/Brattle-EDAM-
Simulations-PacifiCorp-Results.pdf.
Mitchell, Di 22
Rocky Mountain Power

1 gas prices have seen extraordinary year-over-year
2 increases, as detailed below.
3 Q. Why have natural gas fuel prices seen extraordinary
4 increases since the March 2021 natural gas price
5 forecast?
6 A. Drivers of natural gas price increases in the 2025
7 forecast relative to the forecast created in the first
8 quarter of 2021 are : (1) the conflict in Ukraine which
9 decreased European availability of natural gas,
10 previously sourced from Russian imports . With decreased
11 European supply, the associated European demand turned
12 to U. S . domestic supply to fill the gap and the increased
13 competition over domestic supply drove regional natural
14 gas fuel prices upwards; and (2) expectations of
15 increased natural gas exports to Mexico and an uptick in
16 natural gas consumption in the power sector. The
17 expected increase in gas demand in the power sector can
18 be linked to substantial backlogs of renewable energy
19 projects currently in interconnection queues across the
20 region. Natural gas pipeline exports to Mexico are
21 anticipated to grow in response to increased power
22 demands and expanding liquid natural gas ("LNG") export
23 capacities . This increase in natural gas fuel prices
24 correspondingly increases regional gas market prices and
25 regional power market prices, in that order.
Mitchell, Di 23
Rocky Mountain Power

1 Q. What is the impact of increased natural gas fuel prices
2 on 2025 NPC?
3 A. NPC decreased by $104 million when the current 2025
4 forecast gas prices were replaced with the 2021 forecast
5 gas prices used in the prior GRC, under the weather
6 normalized modeling scenario .
7 Q. Why has renewable resource integration experienced
8 delays relative to prior expectations?
9 A. Global supply chain constraints delayed production and
10 transportation of key components and equipment necessary
11 for renewable resource construction across the nation.
12 Furthermore, increases in the prices of key renewable
13 resource construction commodities such as lithium,
14 nickel, and copper, as well as increases in labor costs
15 and interest rates, exacerbated the issue . Lastly,
16 substantial backlogs of renewable energy projects
17 currently in interconnection queues across the region
18 delay the integration of renewable resources into the
19 western interconnection.
20 Q. How have renewable resource integration delays impacted
21 regional power market prices?
22 A. In resource planning at the regional level, renewable
23 resource integration is expected to partially offset the
24 impact of thermal plant retirements on an energy basis .
25 In the short term, as the integration of these renewable
Mitchell, Di 24
Rocky Mountain Power

1 resources are delayed, thermal plant retirements
2 continue on schedule . The resulting energy shortfall
3 decreases supply without any associated decrease in
4 demand (load) . Consequently, this triggers an
5 incremental energy price rise across the competitive
6 regional power markets which is additive to the
7 exacerbation caused by natural gas fuel price increases .
8 Q. What is the impact of increased power prices on 2025
9 NPC?
10 A. NPC decreased by $304 million when the 2025 forecast
11 power prices were replaced with 2021 forecast power
12 prices from the March 2021 OFPC used in the prior GRC,
13 under the weather normalized modeling scenario .
14 Q. Have these global events impacted coal supply and
15 associated coal fuel prices?
16 A. Yes . Because of higher regional natural gas market
17 prices and delays in renewable resource constructions,
18 coal generation would be expected to increase, all other
19 things equal . This increase in the demand for coal
20 pressures domestic coal supply in the short term,
21 resulting in higher coal fuel prices, which in turn drive
22 regional power market prices higher. This situation is
23 further exacerbated by coal supply challenges, discussed
24 in more detail below. This increase in regional power
25 market prices is additive to the increase caused by
Mitchell, Di 25
Rocky Mountain Power

1 natural gas fuel price increases and additive to the
2 increase caused by delays in renewable resource
3 integration.
4 Q. What is the impact of increased coal fuel prices and new
5 coal supply agreements on 2025 NPC?
6 A. The NPC impact is a $280 million increase, under the
7 weather normalized modeling scenario, calculated by
8 replacing current coal assumptions with coal volumes and
9 prices prior to the increased fuel prices and new supply
10 agreements . These changes to coal supplies are discussed
11 in more detail below.
12 Q. Please elaborate on further drivers of regional power
13 market price increases .
14 A. A long-term drought, dating back to the 2019-2020
15 winter, continues across parts of the Pacific Northwest
16 and the consequent decrease in expected hydroelectric
17 generation (currently 25 percent lower than the 10-year
18 average at the regional level) diminishes the expected
19 regional energy supply.
20 Furthermore, calendar years 2020, 2021, 2022 and
21 2023 have seen an increase in abnormal/extreme weather
22 events that have resulted in higher-than-expected load
23 during stressed system conditions, and this trend has
24 set expectations amongst market participants for similar
25 conditions in 2024 and 2025 . Therefore, many utilities
Mitchell, Di 26
Rocky Mountain Power

1 across the region have revised their expectations of
2 load profiles upwards and this limits excess supply
3 offered into the regional power markets .
4 These two weather-based drivers increase regional
5 power market prices and both are additive to the increase
6 caused by natural gas fuel price increases, additive to
7 the increase caused by delays in renewable resource
8 construction and additive to the increase caused by
9 increased competition for coal supply.
10 V. POLICY AND OPERATIONS IMPACT TO NPC
11 Q. What policy or operations changes are forecast to have
12 a substantial impact on 2025 NPC as compared to the prior
13 GRC?
14 A. There are three, which are : 1) the introduction of a
15 dispatch adder impacting generation at Chehalis; 2)
16 decreased hydroelectric generation resulting from the
17 deconstruction of hydroelectric facilities along the
18 Klamath river; and (3) coal supply challenges .
19 A. The Washington Cap and Invest Program
20 Q. How does the WA-GHG Program impact the Company' s load
21 service in Idaho?
22 A. The WA-GHG program requires that the Company purchase
23 GHG allowances for any GHG emissions output within the
24 state of Washington associated with energy exported
25 outside the state of Washington. The only source of GHG
Mitchell, Di 27
Rocky Mountain Power

1 emitting energy owned by the Company in the state of
2 Washington is the Chehalis gas-fired plant. For all
3 energy exported out of Washington from the Chehalis
4 plant, there is an associated GHG cost proportionate to
5 the energy exported. Therefore, for all energy allocated
6 to Idaho from the Chehalis plant, there is an incremental
7 $/MWh cost based on the GHG allowance price for the NPC
8 test period.
9 Q. What is the GHG allowance price applied to the Chehalis
10 plant for this NPC test period?
11 A. The GHG allowance price is currently estimated at
12 $11 . 14/MWh for calendar year 2025 based on auction
13 results from March 6, 2024 .
14 Q. How is the WA-GHG program similar to other Commission
15 approved programs?
16 A. The WA-GHG program is a program that assesses a charge
17 per MWh of energy produced from certain types of
18 resources located in Washington state. From a cost
19 perspective, the impact of this program on the Company' s
20 service territory is identical to the impact of costs
21 associated with initiatives like wind taxes and coal
22 fuel taxes that increase Company NPC.
23 Q. What is the impact to NPC from this program?
24 A. The impact of this program is an increase of $29 million.
25 This increase is driven by the cost of GHG allowances
Mitchell, Di 28
Rocky Mountain Power

1 and increased market purchases to cover generation
2 reduction at the Chehalis plant .
3 B. Hydroelectric Generation Reduction
4 Q. How much has hydroelectric generation decreased between
5 the 2021 GRC and this current filing?
6 A. The forecast for calendar year 2025 hydroelectric
7 generation has decreased by approximately 663, 120 MWh
8 (19 percent) as compared to the calendar year 2021
9 forecast from the 2021 GRC.
10 Q. Why has hydroelectric generation decreased by 19
11 percent?
12 A. A long-term drought, dating back to the 2019-2020
13 winter, continues across parts of the Pacific Northwest
14 (current hydroelectric generation is 25 percent lower
15 than the 10-year average at the regional level) and is
16 picked up in the normalized hydroelectric generation
17 forecast . Furthermore, the removal of four Company-
18 operated hydroelectric projects" along the Klamath river
19 contribute to this decrease . These projects totaled
20 approximately 180 MW of capacity and have ceased
21 generation.
22 Q. What is the impact to NPC of the long-term drought as
23 well as the hydroelectric projects' removal?
24 A. The impact is an increase of $29 million . This increase
ii J.C. Boyle, Copco 1, Copco 2, and Iron Gate hydroelectric projects.
Mitchell, Di 29
Rocky Mountain Power

1 is driven by increased market purchases to cover the
2 generation reduction.
3 C. Coal Supply Challenges
4 Q. What changes are there to projected coal supply in this
5 GRC?
6 A. In 2022 through 2024, the coal market experienced
7 strained conditions . The unprecedented increase in coal
8 prices, instability in coal supply and overall market
9 fluctuations have caused adverse impacts to the Company
10 and other large consumers . This negative impact is due
11 to multiple factors, including but not limited to: (1)
12 increased coal demand due to high domestic natural gas
13 prices; (2) low inventories at coal-fired power plants;
14 (3) increased demand abroad for coal exports; (4)
15 international and domestic supply chain constraints; (5)
16 labor and material shortages; and (6) weather events and
17 general market inflation. 12
18 Moreover, the Lila Canyon mine fire removed
19 approximately 25 percent of Utah coal production and
20 disrupted the same portion of the Company' s coal supply
21 needs in Utah. 13 On November 18, 2023, the Company was
22 informed that the Lila Canyon mine will not reopen and
12 In the Matter of PacifiCorp d/bla Pacific Power, 2024 Transition
Adjustment Mechanism, Exhibit PAC/200, Owen/3-7 (April 3, 2023) .
13 In the Matter of PacifiCorp d/bla Pacific Power, 2024 Transition
Adjustment Mechanism, Exhibit PAC/200, Owen/4 (April 3, 2023) .
Mitchell, Di 30
Rocky Mountain Power

1 will be permanently closed. The closure of Lila Canyon
2 created a significant coal production shortfall in Utah,
3 beginning in 2022, and will continue to have negative
4 impacts to all large consumers, including the Company.
5 In addition to the Lila Canyon mine issues in Utah,
6 coal suppliers continue to experience issues relating to
7 unfavorable geologic and mining conditions, delays and
8 pressure relating to securing federal mining leases,
9 limited availability of trucking and railway
10 transportation for coal, long lead-times for procurement
11 of necessary mining equipment, and limitations in
12 availability of financing, which has put them at an
13 increased risk of becoming insolvent .
14 Q. What is the impact to NPC from these coal supply
15 challenges?
16 A. As mentioned above, the impact of these coal supply
17 challenges is an increase of $265 million on a total-
18 Company basis . This increase is driven by increased
19 natural gas generation and increased market purchases to
20 cover the coal generation reduction.
21 Q. What steps has the Company taken to alleviate these coal
22 supply challenges?
23 A. The Company focuses on achieving its target coal supply
24 at a reasonable price, along with contract terms that
25 provide flexibility. However, because the Utah coal
Mitchell, Di 31
Rocky Mountain Power

REDACTED
1 market has been supply constrained since 2022, the
2 Company has had limited leverage to accomplish these
3 goals .
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20 Q. How has the Company ensured a dependable and secure
21 future coal supply for the Hunter and Huntington plants?
22 A. In February 2024, the Company amended the Hunter and
23 Huntington coal supply agreements with Wolverine . The
24 amended Hunter/Wolverine CSA
25
Mitchell, Di 32
Rocky Mountain Power

REDACTED
1 for the Hunter plant .
2 Beginning in -, the Hunter/Wolverine CSA amendment
3 facilitates additional coal production through renewed
4 operations at the Fossil Rock mine in Emery County, Utah.
5 Deliveries from the Fossil Rock mine will begin in - .
6 When fully operational, the Fossil Rock mine will
7 provide tons per year to the Hunter plant,
8
9 _ . The contract amendment also allows the Company
10 to direct this coal to the Huntington plant as needed.
11 The amended Huntington/Wolverine CSA now also allows the
12 Company the flexibility to direct coal to the Hunter
13 plant as needed. The Huntington/Wolverine CSA
14
15
16 Q. How does the Company plan to meet fuel supplies for its
17 coal-fired plants in 2025?
18 A. The Company employs a diversified coal supply strategy,
19 with 84 percent of its 2025 coal requirements supplied
20 by third-party coal supplies and 16 percent with coal
21 from its captive affiliate mines . The third-party
22 contracts consist of fixed-price and variable-priced
23 contracts . Coal amounts in my testimony are shown on a
24 total-Company basis .
Mitchell, Di 33
Rocky Mountain Power

REDACTED
1 Q. Please generally describe the coal supply arrangements
2 across the Company' s coal-fired plants for 2025 .
3 A. The following Confidential Table `Coal Contracts'
4 summarizes the coal supply arrangements and costs for
5 2025 in comparison to the 2021 GRC :
Confidential Table Coal Contracts
2025
Delivered 2025 2021 $/Ton
Plant Vendor Comments
Tons $/Ton $/Ton Change
(millions)
Jim Black Butte
Bridger Coal Company
Jim Bridger Coal
Bridger Company
Westmoreland
Colstrip Rosebud
Mining
Craig Trapper Mine
Hayden Peabody Coal
Sales
Hunter Bronco Utah
Operations
Hunter Wolverine
Fuel Sales
Mitchell, Di 34
Rocky Mountain Power

REDACTED
2025
Delivered 2025 2021 $/Ton
Plant Vendor Comments
Tons $/Ton $/Ton Change
(millions)
Hunter Gentry
Mountain
Huntington Wolverine
Fuel Sales
Peabody Coal
Dave Sales
Johnston (Caballo
8500)
Peabody Coal
Dave Sales
Johnston (Caballo
8400)
Dave Arch Coal
Johnston Sales
Dave Open
Johnston positions
Naughton Kemmerer
Operations
Black Hills
Wyodak -Wyodak
Resources
1 D. Cumulative Impact
2 Q. What is the combined impact of the various changes on
3 NPC?
4 A. Total-company 2025 weather normalized NPC decrease by a
5 total of $508 million when 2025 assumptions were
6 replaced with the prior GRC' s 2021 forecast assumptions,
Mitchell, Di 35
Rocky Mountain Power

1 for power prices, fuel prices, and policy and operations
2 assumptions .
3 Put another way, 2025 weather normalized NPC as
4 modeled in Aurora is $1 . 766 billion when assuming
5 commodity prices, fuel supply, and polices and
6 operations that were expected for 2021 in the prior GRC.
7 This accounts for a majority of the increase between the
8 2021 NPC actuals (which the prior GRC attempted to
9 forecast) and the current 2025 weather normalized NPC
10 forecast .
11 VI . NPC AND TRANSITION BETWEEN MODELS
12 Q. Did the Company transition to Aurora to calculate NPC?
13 A. Yes . The Company has used GRID since it was deployed in
14 2008 but discontinued its use for NPC filings in 2021
15 and transitioned to Aurora, produced by Energy Exemplar.
16 Aurora provides additional functionality, increases
17 usability, as well as increases compatibility with the
18 Company' s information technology.
19 To date, the Company has filed NPC forecasts using
20 Aurora in California, Oregon, Washington, and Wyoming.
21 Additionally, Aurora includes certain functionality
22 necessary to perform the allocation of state-specific
23 NPC for ratemaking purposes in the post-interim period
Mitchell, Di 36
Rocky Mountain Power

1 as contemplated in the 2020 PacifiCorp Inter-
2 Jurisdictional Allocation Protocol ("2020 Protocol") . 14
3 Q. Is the Company' s general approach to the calculation of
4 NPC using GRID the same in this case as in previous
5 cases?
6 A. Yes . The general approach to the calculation of NPC is
7 the same, but the model has changed from GRID to Aurora.
8 A. An Overview of Aurora
9 Q. How does Aurora work?
10 A. Similar to GRID and other production cost models, the
11 objective of Aurora is to meet the projected load at the
12 lowest possible cost. This is accomplished by simulating
13 the dispatch of available resources, both supply-side
14 and demand-side, within their physical constraints,
15 economic constraints, transmission constraints and
16 emissions constraints, as well as adhering to the
17 profiles of the load requirements to produce a cost
18 minimizing simulation where demand and supply are
19 balanced.
20 Like GRID, Aurora' s simulations take as input
21 information such as system load, reserves, wholesale
22 sales and purchase contracts for electricity, natural
14 In the Matter of Rocky Mountain Power's Application for Approval of the
2020 PacifiCorp Inter-Jurisdictional Allocation Protocol. Case No. PAC-
E-19-20. Order No. 34640 (April 22, 2020) ; In the Matter of Rocky Mountain
Power's Petition for Approval of an Extension of the 2020 Inter-
Jurisdictional Allocation Protocol. Case No. PAC-E-23-13 Order No. 35984
(Nov. 2, 2023) .
Mitchell, Di 37
Rocky Mountain Power

1 gas and wheeling, market prices for electricity and
2 natural gas, fuel expenses, transmission topology, and
3 the characteristics and availability of the Company' s
4 supply-side and demand-side facilities .
5 Q. How does Aurora compare to GRID?
6 A. The model logic is conceptually the same between Aurora
7 and GRID; both models aim to minimize costs to serve
8 obligations, under various constraints . While the
9 categories of inputs are mostly the same between the two
10 models, Aurora has more parameters to model resources
11 and offers more flexibility to model more types of
12 resources .
13 Q. What are some of the modeling improvements gained by
14 moving to Aurora?
15 A. Aurora co-optimizes (as opposed to sequentially
16 optimizing) energy and ancillary service requirements,
17 allowing the model to create precise NPC forecasts that
18 simultaneously satisfy all load and reserve obligations
19 while appropriately reflecting the forecasted NPC. In
20 addition, Aurora can receive more than one incremental
21 price for the purpose of forecasting dispatch of coal-
22 fired resources and can recognize and optimize around
23 volumetric constraints in each price tier (minimum take
24 volumes, volume limits, etc. ) . Furthermore, Aurora
25 allows for the modeling of emissions constraints and
Mitchell, Di 38
Rocky Mountain Power

1 associated emissions rates and emissions prices,
2 allowing the Company to integrate compliance with
3 various emissions constraints within the model .
4 Q. What is the process by which the Company validated the
5 use of Aurora as compared to GRID?
6 A. Both GRID and Aurora are production cost optimization
7 models that use mathematical optimization techniques
8 with similar inputs that attempt to satisfy the
9 Company' s load and reserve obligations at minimum cost .
10 Aurora has more features and flexibility, but both
11 models are based on the same underlying economic
12 principles . The validation process started with the
13 understanding that the results from the two models will
14 be different . Based on that understanding, the process
15 included steps such as : 1) verify if the outputs of non-
16 dispatchable resources match the inputs, and the outputs
17 match between Aurora and GRID; 2) refine input
18 parameters in Aurora that are either not available in
19 GRID or have a different impact on optimization; and 3)
20 research the reasons why the same dispatchable resources
21 with generally the same inputs produce different results
22 between Aurora and GRID. And, finally, the total NPC
23 from the two models are compared and reviewed for
24 reasonableness which includes ensuring that the
25 deviation in the total NPC is within a reasonable range.
Mitchell, Di 39
Rocky Mountain Power

1 Q. Why would the same resources produce different results
2 from Aurora and GRID when they have the same inputs?
3 A. The inputs in the two models are not the same because
4 Aurora allows for more modeling parameters and more
5 levels of granularity. Additionally, Aurora co-optimizes
6 energy and ancillary service requirements by using an
7 advanced mixed integer program, whereas GRID
8 sequentially optimizes one requirement then the other.
9 Furthermore, Aurora uses its mixed integer program for
10 commitment (startup/shutdown) decisions whereas GRID
11 applies relatively basic static optimization techniques .
12 Differences in the optimization techniques lead to
13 different unit commitments and different unit dispatches
14 based on the prevailing economics .
15 Q. Can you provide the results of the Company' s validation
16 process?
17 A. Yes . Please refer to Exhibit No . 24 and Exhibit No . 25,
18 which contain the Aurora and GRID NPC test reports that
19 the Company used to validate Aurora. The test reports
20 show that there was less than 0 . 8 percent variation
21 between the NPC calculated with GRID as compared to
22 Aurora.
Mitchell, Di 40
Rocky Mountain Power

1 Q. While the overall variation was low, there may have been
2 greater variation in individual resources when comparing
3 the two test reports . Can you comment?
4 A. Yes . As I discussed above, there are differences between
5 Aurora and GRID with regards to optimization techniques .
6 In addition, each model contemplates different levels of
7 granularity of inputs . Those two in combination will
8 result in different dispatch of resources, and different
9 balancing transactions . Therefore, the validation
10 process compared the overall outcome of the NPC test
11 report .
12 Q. Would running GRID with the inputs used for this rate
13 case provide additional useful information regarding the
14 validation of the Aurora model?
15 A. No . As described above, the ability of each model to
16 accept different inputs and the internal optimization
17 techniques differ between the models even though the
18 underlying principles are similar. Furthermore, there
19 are inputs in Aurora that are not capable of being
20 accepted by GRID (example, emissions constraints and
21 tiered price/volume coal contracts) . There is no
22 reasonable expectation that the model results would be
23 the same or would provide additional insight, making the
24 proposed comparison a futile exercise . Additionally, the
25 Company has already benchmarked Aurora against GRID and
Mitchell, Di 41
Rocky Mountain Power

1 found that the overall NPC results exhibited a tolerable
2 variance between the two models when limiting the inputs
3 to those capable of being simultaneously accepted by
4 both models .
5 Q. Has the Company performed any other benchmark of Aurora?
6 A. Yes . The Company performed a backcast of calendar year
7 2020, wherein 2020 historical inputs were fed into
8 Aurora, and then the 2020 calendar year was "forecast"
9 ("backcast") to assess whether the resulting NPC would
10 align with the actual NPC observed in 2020 . The 2020
11 backcast, as well as a write up analyzing its results,
12 are provided in Confidential Exhibit No . 26 .
13 Q. What do the results of this backcast show?
14 A. The backcast demonstrates that Aurora produces accurate
15 results . 2020 actual NPC was $1 . 511 billion and Aurora' s
16 backcast of 2020 produced NPC of $1 . 453 billion, an
17 under-forecast of 3 . 9% and a demonstration of the
18 model' s reasonableness .
19 B. Inputs and Adjustments in Aurora
20 Q. How are inputs treated differently between the two
21 models?
22 A. Aurora incorporates many of the same inputs that GRID
23 formerly considered in its optimization. Consequently,
24 many of the same workpapers are still in use, but those
25 inputs flow through Aurora input workbooks to be
Mitchell, Di 42
Rocky Mountain Power

1 formatted for acceptance by the newer model . For inputs
2 that are distinct from their GRID equivalents (coal
3 prices, for example) , entirely new modeling approaches
4 were employed to take advantage of the additional
5 flexibility offered by Aurora. There are also inputs
6 that are the same but require slightly modified
7 calculations to account for the treatment given to those
8 inputs in Aurora (unit minimum operating levels and
9 thermal outage rates, for example) .
10 Q. How is the output from Aurora incorporated into Idaho-
11 allocated NPC?
12 A. The Aurora model results are used to create a total-
13 Company NPC forecast and the total-Company NPC report is
14 similar to the report that has been used in the past .
15 Those results are then allocated by Company witness
16 Shelley E . McCoy according to the 2020 Protocol to arrive
17 at an Idaho-allocated NPC forecast .
18 Q. Please describe any other significant modeling
19 differences between GRID and Aurora.
20 A. As mentioned above, Aurora accounts for unit minimum
21 operating levels ("unit minimums") and equivalent outage
22 rates ("EOR") differently, and both required formulaic
23 updates because of differences in the modeling of unit
24 availabilities . Aurora scales both the unit maximum
25 capacity and the unit minimum in response to a derate
Mitchell, Di 43
Rocky Mountain Power

1 because Aurora requires unit minimums to be expressed as
2 a percentage of unit maximum capacity. In GRID, unit
3 minimums were required to be expressed in absolute
4 megawatt ("W') amounts . Prior to settling upon a
5 revised approach to the calculation of these inputs, the
6 Company observed many hours where the generation
7 forecast showed output below a unit' s minimum. A
8 relatively straightforward solution was adopted by the
9 Company that only required the calculation and input of
10 an hourly unit minimum percentage (percentage of unit
11 capacity) timeseries to account for derates . To avoid
12 the possibility of infeasible operations, another
13 modification was made to the FOR to remove units from
14 service (that is, the FOR was set to 100 percent)
15 whenever the available capacity slipped below the unit
16 minimum. In addition, Aurora can receive more than one
17 incremental price for the purpose of forecasting
18 dispatch of coal fired resources and can recognize and
19 optimize around volumetric constraints in each price
20 tier (minimum take volumes, volume limits, etc. ) . That
21 modeling improvement allows the Company to more easily
22 arrive at a forecast of coal unit dispatch that is
23 subject to volumetric constraints and tiered pricing
24 across a range of consumption levels .
Mitchell, Di 44
Rocky Mountain Power

1 Q. Is the Day-Ahead/Real-Time ("DA/RT") Adjustment needed
2 in Aurora?
3 A. Yes . The DA/RT adjustment is used to better reflect
4 system balancing costs that are not fully captured in
5 the Aurora model . This adjustment indicates a deviation
6 of actual market prices available to the Company in real
7 operations from the historical monthly trading-hub-
8 indexed market prices . The DA/RT adjustment is the
9 result of multiple variables within a dynamic system in
10 which the Company has historically bought more during
11 higher-than-average price periods and sold more during
12 lower-than-average price periods .
13 To better reflect the market prices available to
14 the Company when it transacts in the real-time market,
15 the Company includes separate prices for forecast system
16 balancing sales and purchases in Aurora. These prices
17 account for the historical price differences between the
18 Company' s purchases and sales compared to the monthly
19 average market-indexed prices .
20 Additionally, like GRID, the volume of system
21 balancing transactions generated by Aurora do not
22 reflect the volumetric inefficiencies and associated
23 costs of the operational practice of transacting on a
24 quarterly, monthly, daily and real-time basis . Because
25 Aurora balances the Company' s load and resources to
Mitchell, Di 45
Rocky Mountain Power

1 fractions of a megawatt for each hour in a single step,
2 it avoids the additional purchase and sale transactions
3 that occur in actual operations as the Company
4 progresses through balancing its system on a quarterly,
5 monthly, daily, and real time horizon basis .
6 For instance, if the Company buys a monthly product
7 that aligns with the Company' s average open position for
8 the month, one can expect that approximately half of the
9 days will still have a remaining position to be covered
10 by additional daily purchases . On the other days, the
11 Company will have to make daily sales to unwind the
12 excess volume . The same is true for daily transactions-
13 in some hours the volume acquired will be too low, while
14 in others it will be too high, and additional purchases
15 and sales will be required to cover the Company' s actual
16 position in real-time .
17 Finally, buying or selling standard block products
18 will not result in a perfect balance of load and
19 resources . This difference then must be closed out in
20 the real-time market where the Company is a price-taker.
21 VII . MODELING IMPROVEMENTS TO THE NPC FORECAST
22 Q. Why are modeling improvements necessary?
23 A. Modeling improvements align the NPC forecast with
24 operational realities in order to produce an accurate
25 forecast .
Mitchell, Di 46
Rocky Mountain Power

1 Q. What modeling improvements have been implemented since
2 the 2021 GRC?
3 A. The Company has incorporated the following improvements
4 since the last rate case :
5 • The DA/RT market price adder will be changed from a
6 flat value to a percentage .
7 • Trapped energy will be appropriately substituted for
8 curtailment of generation to reflect actual
9 operations .
10 • The maximum capacity of certain thermal generation
11 units will be updated to reflect ambient temperature
12 derates to unit capacity during the summer months .
13 • The NPC forecast will simulate power hedging
14 transactions in order to maintain compliance with the
15 Company' s current Energy Risk Management Policy.
16 • The calculation of capacity limits on modeled market
17 sales have been updated, and no longer include power
18 hedging transactions .
19 A. DA/RT Adjustment - Price Component
20 Q. Please explain how the price component of the DA/RT
21 adjustment operates .
22 A. The price component of the DA/RT adjustment addresses
23 the costs incurred by the Company as a result of multiple
24 variables within a dynamic system in which the Company
25 has historically bought more during higher-than-average
26 price periods and sold more during lower-than-average
27 price periods .
28 To better reflect the market prices available to
29 the Company when it transacts in the real-time market,
Mitchell, Di 47
Rocky Mountain Power

1 the Company includes separate prices for forecast system
2 balancing sales and purchases in Aurora. These prices
3 account for the historical price differences between the
4 Company' s purchases and sales compared to the trading-
5 hub-indexed market prices . Previously these prices were
6 calculated by adding or subtracting a flat dollar amount
7 to the hourly scaled prices from the OFPC.
8 Q. Has the Company proposed a refinement to the price
9 component of the DA/RT in this case?
10 A. Yes . The Company proposes to change the DA/RT
11 adjustment' s price component from a flat dollar adder to
12 a percentage-of-market-price adder.
13 Q. Please explain how changing the DA/RT adjustment' s price
14 component from a flat value to a percentage of market
15 price results in a DA/RT adjustment that is more
16 reflective of actual operations .
17 A. Changing the price calculation to a percentage of the
18 market prices aids in accounting for the volatility
19 caused by prices and system conditions not captured in
20 day-ahead transactions . Take, for example, a $5 price
21 adder in an hour when the market price is $25 . This
22 resolves to a 20 percent price adder. But using the $5
23 price adder when market prices are $75 would fail to
24 account for the system and market conditions during that
25 hour. Using a 20 percent price adder during hours when
Mitchell, Di 48
Rocky Mountain Power

1 market price is $75 would yield in a $15 price adder,
2 which is more reflective of the system conditions . A key
3 benefit of using a percentage adder is that it allows
4 the modeling to capture intra-monthly variability.
5 Subsequently, this is a significantly more accurate
6 representation of real operating conditions experienced
7 by the Company.
8 Q. Why has the transition to Aurora not resolved the need
9 for a DA/RT price component?
10 A. As noted above, the basis of the DA/RT price component
11 is founded in the historical price differences between
12 the Company' s purchases and sales as compared to the
13 monthly average market prices . The fact that there are
14 historical price differences between the Company' s
15 purchases and sales as compared to the monthly average
16 market prices is agnostic to the model used to forecast
17 Company purchases and sales . Therefore, the transition
18 to Aurora has not resolved the basis for the DA/RT price
19 component .
20 Q. How does a percentage adjustment better capture intra-
21 month price variability as compared to a flat dollar
22 adjustment?
23 A. Below, I provide analysis on the drivers of the DA/RT
24 price component, including a discussion of historical
25 hourly scaled monthly average market prices as compared
Mitchell, Di 49
Rocky Mountain Power

REDACTED
1 to historical hourly scaled Company purchases and
2 associated purchase prices across four years of
3 historical data from 2020 to 2023 . This analysis shows
4 that the refinement proposed by the Company more
5 accurately accounts for intra-month price variability in
6 the context of the historical data.
7 Q. Why is it important to focus on Company purchases instead
8 of Company sales?
9 A. Across the historical period, the total net peak expense
10 incurred from Company purchases is approximately ■
11 = greater than the total net peak revenues gained
12 from Company sales . Confidential Figure `DART Net'
13 provides an illustration of this along with the average
14 four-year historical hourly shape of purchase volumes,
15 sales volumes, purchase expenses and sales revenues .
16 This data, along with the observation that throughout
17 the historical period the Company is a net purchaser
18 (importer) on a dollar and volume basis and that Aurora
19 has no market caps on purchases highlights the outsized
20 importance of purchased power and its attendant costs .
Mitchell, Di 50
Rocky Mountain Power

REDACTED
Confidential Figure DART Net
1 Q. What does the historical data show when comparing market
2 prices to the Company' s purchases?
3 A. Confidential Figure `DART Adder' uses data from 2020 to
4 2023 to create two curves—one illustrating hourly scaled
5 average market-indexed prices and one illustrating
6 hourly scaled average Company purchase prices . The
7 difference between the curves is an illustration of the
8 DA/RT price component . The concept of intra-month price
9 variability is exhibited by the change in price levels
10 across the day for the hourly scaled average market-
Mitchell, Di 51
Rocky Mountain Power

REDACTED
1 indexed prices as compared to the hourly scaled average
2 Company purchase prices . This price variability is set
3 forth numerically in Confidential Table `DART Adder' ,
4 which shows the numeric difference between the two
5 curves .
Confidential Figure DART Adder
Mitchell, Di 52
Rocky Mountain Power

REDACTED
Confidential Table DART Adder
Hour Ending Average Historical
DA/RT Price
Component 's Adder
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
1 Q. Why do you refer to the variability as "intra-month"
2 when the data appears to focus on variability within a
3 day?
4 A. It is important to recall that the OFPC uses monthly
5 prices, which are then scaled down to hourly prices . So
6 intra-month price variability is exhibited as hourly
7 price variability within each day of the month. In my
8 testimony above and as illustrated in Confidential
9 Figure `DART Adder' , this intra-month price variability
Mitchell, Di 53
Rocky Mountain Power

1 is presented as average hourly price variability across
2 the four-year historical period for the average day.
3 Q. The DA/RT price component has historically been a flat
4 dollar amount applied to the purchase and sales price.
5 Does the historical data support this approach?
6 A. No . The historical data in Confidential Figure `DART
7 Adder' and Confidential Table `DART Adder' shows intra-
8 month variability in the DA/RT price component (i .e . ,
9 the variability between the hourly scaled average
10 market-indexed prices and the hourly scaled average
11 Company purchase prices) is not constant across the day;
12 the difference is generally greater as the price
13 increases . If historical market prices supported the
14 DA/RT price component as a flat dollar amount, then the
15 historical values in Confidential Table `DART Adder'
16 would not exhibit change across the day but rather show
17 consistency.
18 Confidential Figure `DART Percentile' illustrates
19 this variability in the actual historical DA/RT price
20 component as compared to an illustration of a flat adder.
Mitchell, Di 54
Rocky Mountain Power

REDACTED
Confidential Figure DART Percentile
1 Q. Is Confidential Figure `DART Percentile' a visual of
2 historical market price curves in comparison to a flat
3 DA/RT price component?
4 A. No . Confidential Figure `DART Percentile' is a visual of
5 what the historical DA/RT price component is, based
6 solely on the historical relationship between actual
7 market prices and actual Company purchases along with a
8 comparison to a hypothetical flat adder that is
9 separated into heavy load hour ("HLH") and light load
10 hour ("LLH") components . Confidential Figure `DART
11 Percentile' is a visual of Confidential `DART Adder'
12 along with a comparison to a hypothetical flat adder
Mitchell, Di 55
Rocky Mountain Power

1 that is separated into HLH and LLH components .
2 Confidential Figure `DART Percentile' is not a visual of
3 a market price curve, even though it looks similar.
4 Q. Does the historical data support the usage of a
5 percentage adder to more accurately account for intra-
6 month price variability?
7 A. Yes . As illustrated in Confidential Figure `DART Adder'
8 and in Confidential Table `DART Adder' , as the
9 historical average market-indexed price increases, the
10 spread between the historical average market-indexed
11 price and the historical average buy price increases as
12 well . This suggests that a percentage adder is more
13 suitable for capturing the historical interplay between
14 monthly average market prices and Company purchase
15 prices . As illustrated in Confidential Figure `DART
16 Percentile' , the historical data definitively does not
17 suggest that a flat adder is appropriate for capturing
18 this intra-month dynamic. This means that the Company' s
19 refinement to the DA/RT price component is a more
20 accurate representation of the difference between
21 average market prices and the Company' s transaction
22 prices . Because the purpose of the DA/RT price component
23 is to reflect this difference, the Company' s refinement
24 is appropriate and more accurate .
Mitchell, Di 56
Rocky Mountain Power

1 Q. Please quantify the NPC impact of this adjustment.
2 A. The NPC impact of this adjustment is an increase of $12
3 million.
4 B. Trapped Energy
5 Q. Please explain the Company' s trapped energy concept.
6 A. Primarily, trapped energy is a modeling concept only and
7 does not exist in actual operations . It represents any
8 excess generation that cannot be used to serve load due
9 to transmission constraints or system-level oversupply.
10 Because of limited transmission and the need for supply
11 and demand to always be balanced, the trapped energy is
12 captured within a modeled trapped energy zone and serves
13 "pseudo load" that is regulated by a "pseudo generator"
14 with an infinite ramp rate ("pseudo" - i .e . , the load
15 and generation in the trapped energy zone are also
16 modeling constructs that do not exist in actual
17 operations) .
18 Q. Why was the trapped energy modeling concept necessary in
19 GRID?
20 A. Conceptually, the trapped energy zones allow for a
21 feasible model solution in the event of an inability to
22 maintain the supply/demand balance when there is excess
23 supply However, the primary function of trapped energy
24 zones in prior GRID NPC simulations was to allow for
25 company owned production tax credit ("PTC") eligible
Mitchell, Di 57
Rocky Mountain Power

1 wind to be modeled with a reasonable degree of accuracy.
2 Due to an inability in GRID to model resources with a
3 negative dispatch price (representative of PTCs, in the
4 case of wind) , these wind resources could not provide
5 the proper price signal to the model and therefore could
6 not be accurately represented within GRID' s resource
7 stack. As a work-around, the wind resources were
8 simulated as must run resources and all excess wind
9 generation within a transmission constrained area was
10 funneled into a trapped energy zone .
11 Q. How was energy in the trapped energy zone valued?
12 A. In the past, the Company valued trapped energy at 75
13 percent of market prices, which led to overstated sales
14 revenue . Since this trapped energy concept does not
15 exist in actual operations, the value of trapped energy
16 should be zero .
17 Q. How does Aurora eliminate the need for trapped energy
18 zones?
19 A. Aurora allows for wind curtailment while recognizing the
20 PTC benefits that produce an implied negative dispatch
21 cost . By placing the wind resources at the bottom of the
22 resource stack and allowing the model to dispatch the
23 wind resources downwards when there is more energy from
24 the wind resources than there is transmission to move
25 the energy to load, or when the ramp capability of
Mitchell, Di 58
Rocky Mountain Power

1 dispatchable resources are unable to follow the hour-
2 to-hour ramps in wind generation, the NPC simulation
3 dispatches (curtails) the wind downwards and
4 appropriately reflects how wind resources are actually
5 operated and actually dispatched downwards in actual
6 operations .
7 Q. Please quantify the NPC impact of allowing wind to be
8 curtailed in similar fashion as actual operations .
9 A. The NPC impact of allowing for realistic wind
10 curtailment is an increase of $34 million driven by: 1)
11 a reduction in pseudo-wholesale sales revenue earned
12 from the sales of energy derived from a modeling
13 construct that does not exist in actual operations; and
14 2) incremental wind curtailments to maintain the
15 supply/demand balance within a transmission congested
16 region when considering that any sharp hour-to-hour
17 ramps in wind generation are unable to be completely
18 balanced by relatively slow ramping coal units present
19 in the region.
20 Q. Please quantify the impact of valuing the trapped energy
21 zone at zero percent of market prices after allowing for
22 wind curtailments .
23 A. The impact to NPC is $0 since after allowing for
24 appropriate wind curtailment the trapped energy modeling
25 construct has been removed. That is to say, there are no
Mitchell, Di 59
Rocky Mountain Power

1 more trapped energy zones modeled in this filing.
2 C. Thermal Attributes
3 Q. What updates did the Company make to the characteristics
4 of some of its thermal resources?
5 A. Thermal plant capacities have been previously calculated
6 as the average of historical capacity over general
7 summer and winter periods . For some thermal plants,
8 performance decreases as the ambient temperature
9 increases . As temperatures are historically hotter
10 during the summer months of June through September, the
11 generation output from these thermal plants decreases
12 during those months . To account for this operational
13 constraint, the Company updated the maximum capacities
14 at certain plants during each summer month from June
15 through September. Exhibit No. 27 and Exhibit No. 28
16 demonstrate the degradation in generation capacity that
17 results from increased temperatures . The exhibit graphs
18 were provided to the Company by the General Electric
19 Company and by Siemens Energy AG.
20 Q. Please explain how this adjustment results in more
21 accurate forecast NPC.
22 A. Because maximum capacities of some thermal plants are
23 reduced as a result of increased temperatures in the
24 summer, not adjusting the capacity during the summer
25 months based on these conditions would result in Aurora
Mitchell, Di 60
Rocky Mountain Power

1 overstating plant capacity and generation output, which
2 would consequently understate the need to dispatch
3 higher cost units or increase purchases to serve load
4 during the summer months . Reducing generation capacity
5 during summer based on average summer temperatures is
6 reflective of actual ambient-temperature constraints .
7 Q. Please quantify the NPC impact of this adjustment.
8 A. The NPC impact of this adjustment is an increase of $16 . 9
9 million. This increase is driven by increased market
10 purchases .
11 D. Hedging Requirements
12 Q. Please briefly provide an overview of the Company' s
13 power hedging requirements .
14 A. The Company revised its Risk Management Policy in 2021
15 with the specific and stated goal of guiding energy
16 supply management to purchase increasing amounts of
17 power in periods with short positions . This is intended
18 to limit the possibility of being short during periods
19 of peak demand and peak pricing. This revised policy
20 imposes power hedge percentage limits that are applied
21 independently to each side of the system, varying by
22 quarter, and escalating as the time to delivery of power
23 approaches . The most relevant requirement in relation to
24 the Company' s NPC forecast is the requirement that
25 positions be hedged at a level where, on average, a
Mitchell, Di 61
Rocky Mountain Power

1 minimum of 75 percent of each month' s largest generation
2 deficit is hedged in the first quarter of the future
3 (e .g. , in December 2024 this would apply to the first
4 quarter of 2025) .
5 Q. In its original form, is the NPC forecast in compliance
6 with the Company' s power hedging requirements?
7 A. No . Aurora is a forward-looking, optimized,
8 deterministic dispatch model with no knowledge of the
9 Company' s hedging requirements or how they evolve over
10 time . While some quarters may be in compliance without
11 this modeling improvement, that is coincidental, not an
12 indication that the model intentionally satisfies the
13 requirements imposed by the Company' s risk management
14 policy.
15 Q. What change was made to align the NPC forecast with the
16 Company' s power hedging requirements?
17 A. To reflect the fact that the Company will eventually
18 need to hedge each quarter at a minimum average of 75
19 percent, additional short-term firm transactions are
20 calculated, in quarterly 25 MW energy blocks of heavy or
21 light load hour products, and loaded into the model to
22 ensure that the quarterly average hedge ratio in the
23 peak hour of each month satisfies the policy-dictated
24 minimum requirements for the first quarter. In that way,
25 the inputs to the model are created in a manner which
Mitchell, Di 62
Rocky Mountain Power

1 recognizes that all four quarters in the NPC test period
2 will eventually be the first quarter in actual
3 operations and the Company will need to execute forward
4 transactions to satisfy its hedging policy requirements .
5 Q. Does this change conform to the realities of actual
6 operations?
7 A. Yes . As noted above, each month in the NPC test period
8 will eventually be part of a quarter that needs to be
9 hedged at a minimum average of 75 percent in actual
10 operations . However, these hedges are based on
11 forecasted prices, and to the extent that actual prices
12 differ from the forecasted prices, the cost of hedges
13 will be different in actual NPC; this concept holds true
14 for the entire NPC forecast .
15 Q. Are these simulated hedge volumes subject to the DA/RT
16 price component?
17 A. No . The prices used in the DA/RT price component are
18 created in recognition of the fact that, in actual
19 operations, the Company purchases at prices above the
20 OFPC and sells at prices below the OFPC in the spot
21 market (i .e . , the day-ahead and real-time trading
22 horizons) ; and Aurora' s optimization is fundamentally a
23 spot market simulation. Because this modeling update is
24 intended to simulate forward transactions, the prices
25 for the simulated hedges are added to the model with no
Mitchell, Di 63
Rocky Mountain Power

1 price adjustment. This is reflective of the Company' s
2 transaction history, which indicates that forward hedges
3 are executed at or about the prevailing market price at
4 the time of execution, on average .
5 Q. Why was no change made to the NPC forecast for the
6 Company' s gas hedging requirements?
7 A. Because such a change would have no impact to the NPC
8 forecast . Aurora does not physically balance the gas
9 system, and the impact of gas hedges consists entirely
10 of the mark-to-market ("MTM") value of those hedges .
11 Were the Company to simulate gas purchases at expected
12 market prices (i .e . , the OFPC) , they would show no MTM
13 impact and additionally, the associated gas volumes are
14 not modeled in Aurora, so there would be no change to
15 the NPC forecast .
16 Q. Please quantify the NPC impact of this modeling
17 improvement.
18 A. The NPC impact of this adjustment is an increase of $0 . 67
19 million.
20 E. Market Sales Capacity Limits
21 Q. What are market sales capacity limits?
22 A. Market sales capacity limits refer to the amount of
23 energy that other market counterparties are willing to
24 purchase in aggregate from the Company. More
25 specifically, market capacity limits represent a
Mitchell, Di 64
Rocky Mountain Power

1 threshold above which no one else can be found in the
2 bilateral electricity markets to take the Company' s
3 energy at or above the Company' s cost of producing that
4 energy.
5 Q. Please explain what a liquid market is in the industry
6 of today.
7 A. From the perspective of market sales, a liquid market is
8 a market where the Company can find a buyer to take its
9 excess energy whenever the prevailing market price is at
10 or above the Company' s cost of production, regardless of
11 hour or day.
12 Q. Please explain why Aurora requires sales market capacity
13 limits .
14 A. Like GRID before it, Aurora operates with perfect
15 foresight and assumes near unlimited market depth and
16 full liquidity for the markets in which the Company makes
17 off-system sales, unless informed otherwise . Aurora
18 would therefore allow unrealistic off-system sales at
19 every market at any time of the day or night—an
20 assumption that is very different from the Company' s
21 actual, historical experience . The market capacity
22 limits inform Aurora of the limits on the depth of the
23 markets being modeled, thereby forcing Aurora to respect
24 those limits during the execution of its optimization
25 algorithm.
Mitchell, Di 65
Rocky Mountain Power

1 Q. Is the Company proposing to make changes to the market
2 sales capacity limits calculation?
3 A. Yes . With the inclusion of simulated hedge volumes in
4 the NPC forecast, the Company has removed volumes
5 related to hedges from its market sales capacity limits
6 calculation. Furthermore, the Company is applying the
7 market sales capacity limits to all market sales hubs
8 within Aurora, inclusive of the Palo Verde and Mid-
9 Columbia hubs, which did not have market capacity limits
10 in the 2021 GRC .
11 Q. Why is the Company proposing to remove hedge volumes
12 from its market sales capacity limits calculation?
13 A. Under the previous method, market sales capacity limits
14 were first calculated using historical sales volumes
15 inclusive of sales hedge volumes . Then, second, these
16 limits were reduced by executed sales hedge volumes for
17 the NPC test period, in order to provide for a realistic
18 modeled estimate of spot market sales volumes (i .e. ,
19 sales in the day-ahead and real-time trading horizons)
20 plus yet-to-be-executed sales hedge volumes in the NPC
21 forecast . However, since the NPC forecast is now fully
22 hedged with simulated hedge volumes from the "Hedging
23 Requirement" modeling update discussed above, the
24 modeled market sales in the NPC forecast now represent
25 only spot market sales . For this reason, the market sales
Mitchell, Di 66
Rocky Mountain Power

1 capacity limits calculation now includes only spot
2 market sales volumes (i .e . , excludes all hedge volumes)
3 in its calculation.
4 Q. Why is the Company proposing to apply the market sales
5 capacity limits to the Palo Verde and Mid-Columbia hubs?
6 A. As demonstrated in Confidential Figure `Market Caps'
7 below, the volume of Company spot market sales has been
8 in a declining trend over the past five years .
9 Furthermore, and additionally, trading hubs in the spot
10 market are no longer as liquid as they used to be; as
11 demonstrated by the increased risk of energy shortfalls
12 across the region, specifically "the risk of resource
13 shortfalls during extreme summer weather conditions
14 after 2024, "15 as identified by the North American
15 Electric Reliability Corporation ("NERC") .
16 Q. How have the Company' s spot market sales volumes been
17 decreasing over time?
18 A. As can be seen in Confidential Figure `Market Caps'
19 below, the Company has experienced a declining trend in
20 spot market sales volumes since 2018 . After removing the
21 hedge volumes from the market sales capacity limits
22 calculation, in addition to applying the limits to sales
is North American Electric Reliability Corporation, 2023 Long-Term
Reliability Assessment at 24 (Dec. 2023) (available at-
https://www.nerc.com/pa/RAPA/ra/Reliabilityo20Assessmentso20DL/NERC LTR
A 2023.pdf) (last visited Jan. 30, 2024) .
Mitchell, Di 67
Rocky Mountain Power

REDACTED
1 at the Palo Verde ("PV") and Mid-Columbia ("Mid-C")
2 power trading hubs, the forecast volumes are much closer
3 to actuals16 as compared to the prior calculation
4 methodology17 which produces demonstrably unreasonable
5 and substantially inaccurate (high) levels of spot
6 market sales volumes; all illustrated in Confidential
7 Figure `Market Caps' below.
Confidential Figure Market Caps
16 Confidential Figure `Market Caps' , column "Forecast 2025 Sales".
17 Confidential Figure `Market Caps' , column "Hedge Volumes and no PV/Mid-
C Limits".
Mitchell, Di 68
Rocky Mountain Power

1 Q. What are the drivers behind this decrease in spot market
2 sales volumes?
3 A. Coal supply challenges, increased regulation reserve
4 requirements and the energy imbalance market ("EIM") are
5 three of the drivers for this decreasing trend in spot
6 market sales volumes .
7 Q. How do regulation reserves contribute to the decrease in
8 spot market sales volumes?
9 A. As entities across the region integrate ever increasing
10 numbers of variable renewable resources into their
11 portfolio, their regulation reserve obligations
12 increase . This relationship is illustrated in Figure
13 `Regulation Reserves' . As these reserve obligations
14 increase, excess supply is diminished. This reduction in
15 excess supply will naturally result in lower sales in
16 the spot markets . The trend whereby variable renewable
17 resources occupy a larger portion of entities'
18 portfolios over time is one that will continue to
19 increase well into and past 2025 due to various federal
20 and state regulations .
Mitchell, Di 69
Rocky Mountain Power

Figure Regulation Reserves
Renewable Portfolio vs Regulation Reserves
500
8,000
450 3
a 400 r�,
7,000 cu
cu
0 350 6,000
300 5,000
Ln
250 — 4,000 m
M
200 3,000 Q v
fM 00 00 00 M Ql Ol O O O c-I ci ci N N N M M M � d
rl .--I ci c-I c-I ci N N N N N N N N N N N N N
O O O O O O O O O O O O O O O O O O O +
01 \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ Q
� ci ci ci ci ci ci ci ci ci ci ci ci ci ci ci ci ci ci ci
L ci Ln 01 c-I Ln Ol c-I Ln M c-I Ln M ci Ln M ci Ln Ol -1 [�
° Date U
= Q
Ma
Average Hourly MWh Regulation Reserves for Intra-hour EIM Balancing
— Total PACE+PACW BAA Renewable Capacity
1 Q. Are the regulation reserve numbers in Figure `Regulation
2 Reserves' representative of the Company' s balancing
3 authority reliability regulation reserve requirements?
4 A. No . These numbers are the EIM' s calculation of
5 regulation reserves using errors in load, wind and solar
6 forecasts made approximately 45 minutes before the
7 operating moment ("real-time") as compared to forecasts
8 made approximately 10 minutes before real-time . The
9 Company' s regulation reserve requirements, subject to
10 NERC standards and represented in the IRP' s flexible
11 reserve study, are calculated from errors in load, wind,
12 solar and other non-dispatchable generation forecasts
13 made approximately 107 minutes before real-time as
Mitchell, Di 70
Rocky Mountain Power

1 compared to actuals (i .e . , 0 minutes before real-time) .
2 As such, the trend is comparable but not the magnitude .
3 Q. How does the EIM contribute to diminishing excess
4 supply?
5 A. With the emergence of the EIM, which now serves 80
6 percents$ of the demand for electricity in the western
7 interconnection, EIM entities face additional
8 opportunity costs that must be contemplated in the spot
9 market timeframes . If an EIM entity finds itself with
10 excess supply and the expected price in the EIM is
11 greater than the prevailing price in the spot markets,
12 then the entity may forego selling their excess supply
13 into the spot markets and instead set that excess supply
14 aside for sale in the EIM. This naturally reduces sales
15 in the spot markets .
16 Q. Is the Company' s experience unique?
17 A. No . Looking at Figure `MidC Volumes' and Figure `PV
18 Volumes' below, HLH volumes at the Mid-Columbia and Palo
19 Verde power market hubs have been decreasing since 2018 .
20 This trend along with the discussion above supports the
21 position that the Mid-Columbia and Palo Verde trading
22 hubs are no longer as liquid as they used to be .
18 https://www.caiso.com/about/Pages/Blog/Posts/Evolution-of-the-
WEIM.aspx.
Mitchell, Di 71
Rocky Mountain Power

Figure MidC Volumes
Day-Ahead Mid-Columbia HLH Trading Volumes by Year and
Month
y
1,000,000
900,000
800,000
E 700,000
0 600,000 "" .
W^ 500,000
44\� . . ...... .......
L
1 400,000
ro
300,000
C 200,000
0
100,000
t 1 3 5 7 9111 3 5 7 9111 3 5 7 9111 3 5 7 9111 3 5 7 9111 3 5 7 911
c
0 2018 2019 2020 2021 2022 2023
Year/Month
Figure PV Volumes
Day-Ahead Palo Verde HLH Trading Volumes by Year and
> Month
v 450,000
E 400,000
0 350,000
300,000
250,000
200,000
c 150,000 .............
0
on 100,000
v
50,000
0 1 3 5 7 9111 3 5 7 9111 3 5 7 9111 3 5 7 9111 3 5 7 9111 3 5 7 911
2018 2019 2020 2021 2022 2023
Year/Month
1 Q. What is the NPC impact of this modeling update?
2 A. Removing hedge volumes from the market sales capacity
3 limits calculation, as well as applying limits to the
Mitchell, Di 72
Rocky Mountain Power

1 Mid-Columbia and Palo Verde sales hubs, result in a NPC
2 increase of $84 million.
3 Q. Has the Company done any other tests to prove that market
4 capacity limits are needed at the Mid-C and PV trading
5 hubs?
6 A. Yes . The Company used the Aurora validation 2020
7 backcast model (referenced in Section VI above) as a
8 starting point for testing. The Company then fixed (set
9 as static and known in the model) all 2020 historical
10 sales volumes with the exception of real-time sales
11 volumes (i .e. , from hedge volumes to day-ahead sales
12 volumes) and then ran the model to observe the in-model
13 (modeled) system balancing sales, which should be
14 representative of 2020 historical real-time sales
15 volumes, given the aforementioned fixing of all other
16 sales volumes .
17 Q. Please explain this simulation of real-time sales
18 volumes in further detail .
19 A. With modeled system balancing sales as a proxy for 2020
20 historical real-time sales there was a need to adjust
21 the DA/RT price component to only account for historical
22 real-time transactions . Furthermore, the DA/RT volume
23 component was adjusted to remove the inferred daily, 25
24 MW increment block products that represented products
Mitchell, Di 73
Rocky Mountain Power

1 from day-ahead trading. Lastly, the market capacity
2 limits were removed in order to assess their impact .
3 Q. How do the modeled real-time sales compare with the
4 actual, historical real-time sales?
5 A. The below Table `RT Sales' and Figure `RT Sales' shows
6 a comparison between modeled real-time sales and
7 historical real-time sales at the Mid-C and PV trading
8 hubs .
Table RT Sales
Real-Time Sales (MWh)
Actual Modeled
Mid-Columbia 58, 622 610, 866
Palo Verde 26, 432 175, 257
Figure RT Sales
Real-Time Sales
Modeled
Actual
100 200 300 400 500 600 700
SALES MWH (000-S)
❑Palo Verde ■Mid-Columbia
9 As can be seen from Table `RT Sales' and Figure `RT
10 Sales' , modeled real-time sales at the Mid-C and PV
11 trading hubs are greater than historical real time sales
Mitchell, Di 74
Rocky Mountain Power

1 by factors of 10 and 7 respectively. This demonstrates
2 that Aurora, like GRID before it, over-optimizes system
3 balancing sales . This over-optimization and the
4 consequent overstatement of wholesale sales revenue, as
5 exemplified best in the recent ECAM, 19 necessitates
6 application of market capacity limits to all trading
7 hubs, inclusive of Mid-C and PV.
8 Q. Do the increased modeled real time sales reflect
9 increased market depth?
10 A. No . Please refer to Confidential Figure `Market Caps'
11 above . The modeled real-time sales from this test
12 implies market depth that is contrary to the Company' s
13 recent experience .
14 VIII . 2023 WEATHER NORMALIZED LOAD
15 Q. What is the impact to NPC of adjusting the forecast to
16 incorporate 2023 weather normalized load?
17 A. Moving from a 2025 load forecast to 2023 weather
18 normalized load to set expectations for the 2025 NPC
19 test period produces NPC of $2 . 382 billion on a total-
20 Company basis and $136 . 7 million, or $39 . 34/MWh, on an
21 Idaho-allocated basis . On a $/MWh basis this lowers NPC
22 by 1 . 6 percent, relative to the NPC forecast that uses
23 2025 expected load.
19 In the Matter of the Application of Rocky Mountain Power Requesting
Approval of $62.4 Million SCAM Deferral, Case No. PAC-E-24-05,Direct
Testimony of Jack Painter, p. 14.
Mitchell, Di 75
Rocky Mountain Power

1 Q. Please summarize this NPC proposal section of your
2 direct testimony.
3 A. On an Idaho-allocated basis, the Company' s NPC as
4 modeled for the NPC test period in this case have
5 increased by $14 . 80/MWh, or 60 percent, from the 2021
6 GRC forecast of $24 . 54/MWh to the current weather
7 normalized GRC forecast of $39 . 34/MWh. This increase is
8 driven by: 1) the NPC under-forecast in the 2021 GRC; 2)
9 increases in purchased power and natural gas fuel
10 expense that result from increased power and natural gas
11 commodity prices, a reduction in generation due to the
12 WA-GHG program, the expectation of lower hydroelectric
13 generation, and coal supply challenges .
14 IX. NPC RECOVERY
15 Q. What is the purpose of this NPC recovery section?
16 A. The Company is proposing to update the sharing band of
17 the energy cost adjustment mechanism (SCAM) because the
18 current structure is outdated, and the continued under-
19 forecast of NPC contributes to the significant financial
20 risks currently faced by utilities . My testimony
21 presents the Company' s proposal to modify the ECAM
22 sharing band for 95 percent of NPC variances to be passed
23 through the mechanism. The remaining five percent of NPC
24 variances would remain outside the mechanism (95/5
25 sharing band) . In addition to the outdated sharing band
Mitchell, Di 76
Rocky Mountain Power

1 of the ECAM - due to changes in the regional energy
2 landscape - the Company' s planned entry into a complete
3 organized market - the California Independent System
4 Operator (CAISO) Extended Day Ahead Market (EDAM) -
5 further evidences the need for an update to the current
6 sharing band.
7 Q. Please explain the current ECAM structure as it relates
8 to the sharing band.
9 A. Commission Order No. 3090420 authorized the Company to
10 implement an ECAM, a mechanism to recover the
11 differences between actual NPC and base NPC in rates .
12 The difference between base and actual ECAM costs per
13 kWh, both multiplied by the Company' s actual retail load
14 in Idaho, is the amount eligible for sharing under the
15 ECAM. The current ECAM includes a 90/10 percent sharing
16 band, meaning 90 percent of the NPC differential
17 (variance) is either refunded to or paid by customers
18 and the Company retains or absorbs the other 10 percent
19 (90/10 sharing band) .
20 Q. Why is the structure of the ECAM outdated?
21 A. Energy policies and their associated impacts to power
22 costs, and the wider electric industry, in the West have
23 changed significantly in the past decade, however, the
zo In the Matter of the Application of Rocky Mountain Power for Approval
of an Energy Cost Adjustment Mechanism (ECAM) . Case No. PAC-E-08-08. Order
No. 30904 (Sept. 29, 2009) .
Mitchell, Di 77
Rocky Mountain Power

1 sharing band in Idaho that supports the recovery of
2 Company NPC has not changed concurrently - and has been
3 static since 2009 . Since the turn of the century there
4 has been a significant decrease in dispatchable
5 generation across the Western United States and
6 correspondingly, a significant increase in optimization
7 and dispatch efficiencies that are and will be realized
8 through participation in organized markets .
9 It is vital for ratemaking policies to move forward
10 with the state of the industry. The increased volatility
11 introduced to NPC, since 2009, by the significant shift
12 to renewable resources across the Western United States
13 remains unaddressed through reform of the ECAM and has
14 had a material impact on the Company' s financial health.
15 Furthermore, the volatility of both actual natural gas
16 fuel prices and market power prices, since 2009, exhibit
17 substantial deviation from the assumptions used to
18 forecast NPC and from the conditions that existed in
19 2009 because of the aforementioned changes in resource
20 mix across the Western United States . Additionally, the
21 short-term volatility caused by extreme weather events
22 that increase market and gas prices substantially
23 impacts these NPC variances, relative to conditions in
24 2009 which were markedly more predictable .
Mitchell, Di 78
Rocky Mountain Power

1 Lastly, the Company' s commitment to join the EDAM
2 is a tremendous change, one that will drive NPC
3 considerably lower than would otherwise be possible and
4 demonstrates that the Company is managing its NPC to the
5 best of its ability and following best practices within
6 the industry. These changes now warrant the Company' s
7 proposal to update the sharing band.
8 Q. Is this an attempt by the Company to shift NPC risk from
9 the Company to customers?
10 A. No . This is about appropriately situating the risk. In
11 the past, circa 2009, when demand service relied on base
12 load coal resources and some dispatchable natural gas
13 resources to follow load, NPC could be more easily
14 predicted because of long term fixed price coal
15 contracts . Most of the NPC variances were less
16 significant and caused by weather' s impact on load,
17 along with smaller fluctuations in markets prices . Under
18 those circumstances, when generation across the Western
19 Electricity Coordinating Council area ("WECC") was more
20 predictable, it may have been appropriate for the
21 Company to carry the current risk balance of NPC
22 variances . However, today' s regional load service
23 focuses more on net load, or load less renewable
24 generation. The costs associated with this type of load
25 service are much harder to predict and also increases
Mitchell, Di 79
Rocky Mountain Power

1 costs in times of market scarcity. For example, when
2 solar under performs in a region and load increases above
3 expectations this can reduce liquidity in the market and
4 drive power prices extremely high for all utilities, as
5 many buyers are looking to either replace that lost solar
6 energy or cover the unexpected load increase . Inversely,
7 when solar is over performing and load decreases below
8 expectations power prices can fall, but only slightly,
9 for all utilities, and there is less opportunity to make
10 a margin on excess energy. Apart from making NPC much
11 harder to predict, this asymmetry in market price
12 responses creates a NPC under-forecast bias in the SCAM
13 differential that leads to persistent under forecasts of
14 NPC as discussed and illustrated in further detail
15 below.
16 The Company has continued to reliably serve
17 customers as market conditions and load service has
18 changed over the years, even in times when the cost to
19 serve load exceeds the revenue collected from customers .
20 It is important to note that the Company does not earn
21 a return (profit) on NPC; the Company only includes costs
22 that have already been incurred in rates in the ECAM. As
23 the Company continues to adapt to the state of the
24 industry it is imperative that the regulatory structure
25 of NPC recovery is updated to adapt concurrently. This
Mitchell, Di 80
Rocky Mountain Power

1 will help support the financial health of the Company by
2 attracting the capital necessary to continue to reliably
3 serve customers and invest in the resources necessary to
4 meet reliable load service .
5 Q. Please explain how the asymmetry in market price
6 responses creates a NPC under-forecast bias in the ECAM
7 differential .
8 A. As an illustrative example, Figure `Regional Supply
9 Stack' below depicts a proxy supply curve (with
10 inelastic demand) based on actual load, wind, and solar
11 data within the West during the summer of 2022, scaled
12 to Rocky Mountain Power load.
13 In this illustrative example, because of the
14 asymmetry of regional market price response, a 500 MWh
15 increase in net load (load less wind less solar) results
16 in a $108/MWh increase in market price whereas an
17 identical 500 MWh decrease in net load results in only
18 a $39/MWh decrease to market price .
Mitchell, Di 81
Rocky Mountain Power

Figure Regional Supply Stack
Regional Supply Stack - Net Load
$400 0
0 0
$350 4
_ 0
� o
$300 80
° o
0
... ...............................................................................A.... ...... °
$250 00°60 °Qo °
aJ Ct O '8) °
$200 108$/MWh c�rO O 4 O 00
-SC
v �... ......................................... cS
.v $150
a
:39$/MWh
a, . . .............................. ........ ...
Y $100
—XI
$50 _ —
p0 Q� ° '500 MWh:500 MWh:
$0
1,500 2,500 31500 4,500 5,500 6,500
Net Load (MWh)
1 Because NPC move in proportion to regional market
2 prices, and continuing with the illustrative example
3 provided above, we observe that an unexpected increase
4 in net load will increase NPC by an amount far greater
5 than the decrease in NPC observed because of an identical
6 and opposite unexpected decrease in net load.
7 This asymmetrical response biases the NPC forecast
8 persistently downwards such that attempts to accurately
9 forecast NPC will probabilistically result in actual NPC
10 being greater than forecast NPC and consequently,
11 persistent under-forecast of NPC which flows through the
Mitchell, Di 82
Rocky Mountain Power

1 sharing band to the persistent detriment of the Company
2 as evidenced in further detail below.
3 Q. Please summarize the remainder of this NPC Recovery
4 section.
5 A. Below, I provide :
6 • An overview of the shift in resource mix across the
7 Western United States since the sharing band was
8 established in 2009 and how that impacts the
9 volatility of power costs;
10 • Next, I discuss the EDAM at a high level and how NPC
11 are handled by utilities in the Company' s other
12 jurisdictions;
13 • Additionally, I discuss how the current structure of
14 the ECAM has impacted the Company' s finances; and
15 • Finally, I describe how the NPC forecast set in
16 regulatory proceedings have no bearing on the
17 Company' s incurred NPC, and I describe how NPC
18 variances are disconnected from the reality of power
19 system operations .
20 Q. Are there any other Company witnesses providing
21 testimony on this NPC Recovery topic?
22 A. Yes, Company witness John Tsoukalis from The Brattle
23 Group is providing testimony on the mechanics of the
24 EDAM, how it provides efficient outcomes and customer
25 benefits, and how these results impact the SCAM. He
26 additionally provides information on the current state
27 of the industry with regards to the structure of other
28 NPC true-up mechanisms, like the ECAM.
Mitchell, Di 83
Rocky Mountain Power

1 A. Region-Wide change in Generation Resources
2 Q. How has dispatchable energy and demand changed within
3 the WECC since the implementation of the current ECAM
4 sharing band?
5 A. From 2009 to 2022, dependable, dispatchable capacity,
6 which includes coal and natural gas, has been on a
7 declining trend and has decreased significantly overall .
8 As shown in Table `Summer Megawatts' below, total summer
9 dispatchable capacity in the states compromising the
10 WECC has decreased from approximately 122, 000 megawatts
11 ("MW") to 110, 000 MW, or 10 percent . On the other side
12 of the equation, summer peak demand is on an upward
13 trajectory. As shown in Table `Summer Megawatts' below,
14 peak demand has steadily increased between 2009 and 2022
15 from approximately 134, 000 MW to 160, 000 MW, or 19
16 percent .
Mitchell, Di 84
Rocky Mountain Power

Table Summer Megawatts
Year Summer Dispatchable Summer Peak Load
Capacity (MW) (MW)
2009 121, 945 134, 477
2010 123, 997 135, 000
2011 125, 133 133, 100
2012 124, 332 141, 300
2013 123, 450 142, 200
2014 122, 073 145, 400
2015 121, 374 150, 200
2016 120, 669 146, 700
2017 117, 709 150, 800
2018 115, 979 151, 100
2019 112, 249 148, 000
2020 110, 590 151, 800
2021 110, 504 152, 700
2022 109, 998 160, 200
1 Q. Why is this shift in dispatchable capacity and demand
2 within the WECC important to the ECAM?
3 A. The ECAM operates as a mechanism for the Company to
4 refund or collect from customers a measure of normal
5 power cost variances incurred under the intent to
6 incentivize prudent decisions . Because of the
7 significant shift of both dispatchable capacity and
8 demand, power cost variances today are no longer normal,
9 relative to the norms of 2009 when the current ECAM
10 sharing band was established — and therefore, prudently
11 incurred costs are not being recovered. Additionally,
12 this significant shift in dispatchable capacity and
13 demand within the WECC has not only impacted the Company,
14 but all utilities in the West, compounding the problem
15 further by impacting utilities that the Company
Mitchell, Di 85
Rocky Mountain Power

1 transacts with and competes with for market purchases .
2 Figure `Capacity as % of Demand' below visually
3 illustrates the shift in the states comprising the WECC
4 where dispatchable capacity has steadily decreased in
5 absolute terms (MW) and decreased as a percentage of
6 annual peak demand. Shortly after the current ECAM
7 sharing band was established in 2009, summer
8 dispatchable capacity in 2011 was rated at 94 percent of
9 summer peak demand in 2011 . In 2022, dispatchable
10 capacity was much lower, rated at 69 percent of peak
11 demand.
Figure Capacity as % of Demand
WECC U.S. Summer DispatchaDle Capacity and Peak
0
Demand Q
w
130,000 100% o
Y
Q
95% a
125,000
O
n 90%
v 120,000 n 85% >
II U
� I I 80% a
a 115,000 a
U
U 75% w
QCO
110,000 70%
o U
w 65% a
105,000 0
N 60% LU
100,000 j L L L 55% 2
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 `n
YEAR
Summer Dispatchable Capacity Peak Demand%of Capacity
Mitchell, Di 86
Rocky Mountain Power

1 Q. Has the demand during summer peak hours changed?
2 A. Yes, as referenced above . Between 2009 and 2022, the
3 greatest shift in demand has been during summer peak
4 hours (June through September) . Figure `Summer Peak
5 Demand' below visually depicts this increasing trend in
6 peak demand since the inception of the current ECAM
7 sharing band in 2009 . In 2009, demand during summer peak
8 hours was approximately 134, 000 MW and increased to
9 160, 000 MW in 2022, or a 19 percent increase .
Figure Summer Peak Demand
WECC U.S. Summer Peak Demand (MW)
165,000
160,000
155,000
0
150,000
LU
145,000
Q
W
140,000
LU
135,000
130,000
125,000 - -
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
YEAR
10 Q. How has the increased demand during summer peak hours
11 impacted the ECAM?
12 A. In both 2021 and 2022, the Company experienced
13 heightened NPC due to extreme weather events during the
14 summer. The combination of increased demand,
Mitchell, Di 87
Rocky Mountain Power

1 particularly during the summer, and less dispatchable
2 capacity results in market scarcity and high prices and
3 the impact to NPC is intensified. June and July of 2021
4 alone accounted for 80 percent of the 2021 ECAM NPC
5 differential, while July, August and September of 2022
6 accounted for almost 50 percent of the total 2022 ECAM
7 differential . Both examples of these substantial NPC
8 variances are outside of the normal operating business
9 risk of the Company (wherein normal is based on
10 conditions in 2009) .
11 Q. Does the trend of decreasing dispatchable capacity and
12 increasing demand within the WECC necessitate and
13 warrant changes to the ECAM?
14 A. Yes . The risks between the Company providing reliable
15 energy and the commodity-driven costs to serve its
16 variable customer demand are not the same as when the
17 ECAM sharing band was established in 2009; the industry
18 is now substantively different . With the loss of
19 dispatchable capacity and with increased demand across
20 the West and the associated consequential changes in the
21 market, the risk balance for power costs has been
22 fundamentally altered. The Company is proposing this
23 sharing band change as consistent with the fact that
24 power cost variances have increased significantly and
25 can no longer be considered normal relative to 2009 when
Mitchell, Di 88
Rocky Mountain Power

1 the current sharing band was implemented. Now, with this
2 increased variance and associated volatility, a sharing
3 percentage of five (95/5 sharing band) is now
4 appropriate .
5 B. The EDAM - Utilities in Organized Markets
6 Q. The Company has announced its intention to join EDAM.
7 What is the EDAM?
8 A. The EDAM is an initiative by the CAISO to extend
9 participation of a developed and organized day-ahead,
10 hour-ahead and intra-hour market to the region. The EDAM
11 will provide economically optimal and least-cost
12 resource schedules, commitment instructions, and other
13 core functions integral to organized markets across the
14 footprints of independent system operators ("ISO") and
15 regional transmission organizations ("RTO") .
16 Operational control of resources will remain with the
17 Company, but the EDAM will allow for the co-optimization
18 of the Company' s resources along with the resources of
19 other EDAM participants for substantially lowered NPC,
20 than otherwise achievable by the Company in isolation.
21 Company witness Tsoukalis provides much greater detail
22 on the EDAM and how system dispatch and economic
23 efficiencies will change .
Mitchell, Di 89
Rocky Mountain Power

1 Q. Does participation in the EDAM create substantially
2 lowered NPC with minimal room for further decrease in
3 service of the Company' s customers?
4 A. Certainly. As a result of the decision to participate in
5 the EDAM, the economic operations of the Company' s
6 system on a day-ahead, hour-ahead and intra-hour basis
7 will be optimized by an ISO whose mandate is to leverage
8 state of the art optimization software to minimize power
9 costs for all market participants . As discussed in the
10 testimony of Company witness Tsoukalis, the EDAM will
11 provide lower NPC than what the Company could achieve on
12 its own.
13 Q. Does joining the EDAM impact the Company' s ability to
14 accurately forecast NPC?
15 A. Yes . As explained by Company witness Tsoukalis, NPC in
16 the EDAM is driven by conditions across the wider EDAM
17 footprint which extends into other utilities' systems .
18 Data on these conditions within other utilities' systems
19 will be unavailable to the Company due to their
20 confidential nature and therefore it will be extremely
21 difficult for any individual EDAM participant to
22 accurately forecast the NPC outcomes of the market .
23 Q. What impact does an inaccurate forecast have on the ECAM?
24 A. An inaccurate forecast can lead to significant NPC
25 variances (as evidenced in 2021, 2022, 2023 and 2024
Mitchell, Di 90
Rocky Mountain Power

1 year-to-date) in the ECAM that will lead to costs
2 prudently incurred by the Company, to reliably serve
3 customer load, to either: (1) not be collected; or (2)
4 when actual costs are below forecast, to be retained by
5 the Company and not properly returned to customers .
6 Q. How are utilities in organized markets treated in terms
7 of NPC variances in their power cost recovery
8 mechanisms?
9 A. While this is covered in greater detail in the testimony
10 of Company witness Tsoukalis, it is important to note
11 that across the 35 states he reviewed that have
12 vertically integrated utilities, 26 have full
13 passthrough of NPC. Of the 20 remaining that participate
14 wholly or partially in an ISO/RTO type organized market
15 like the EDAM, only Missouri, Montana and Vermont do not
16 have complete pass through of net power costs . 21
17 Q. How do the power cost recovery mechanisms in the
18 Company' s other jurisdictions operate?
19 A. The Company operates in six different state
20 jurisdictions, each with a power cost recovery
21 mechanism. Utah and California do not have a sharing
22 band, which represent almost half of the Company' s total
23 NPC. Wyoming has a sharing band. Oregon and Washington
21 Wisconsin is an exception among the 26 full passthrough states in that
it employs a 20 deadband to modify the cost deviations from forecasts
that are eligible for a full passthrough to customers.
Mitchell, Di 91
Rocky Mountain Power

1 have both dead bands and sharing bands . The Company has
2 or will be pursuing similar changes as proposed here, in
3 Oregon, Washington and Wyoming.
4 Q. Is there anything unique about the Company' s
5 jurisdictions?
6 A. Yes . Only four22 states that currently participate in
7 EDAM like markets do not have a pass-through mechanism
8 that result in full recovery of prudently incurred
9 costs . With the implementation of the EDAM there would
10 be eight, and four of those eight would be states the
11 Company serves, so a comparison to states served by the
12 Company is not representative of the ratemaking approach
13 to recovery of NPC across the utility industry. The four
14 states within the Company' s service area are therefore
15 outliers compared to the rest of the nation.
16 C. Current ECAM Structure
17 Q. Is the current ECAM sharing band functioning in an
18 equitable fashion?
19 A. Not at all . Based upon the current ECAM design, it would
20 be expected that over and under-forecasts of NPC along
21 with the attendant returns and collections would balance
22 each other out over the long term. Since the inception
23 of the ECAM in 2009, fourteen out of the fifteen years
22 Wisconsin is added here to the prior three of Missouri, Montana and
Vermont.
Mitchell, Di 92
Rocky Mountain Power

1 have resulted in NPC under-forecasts and associated
2 under-collection of prudently incurred NPC due to the
3 current sharing band. However, it' s expected that there
4 should be a more balanced distribution of under-forecast
5 and over-forecast of NPC. During this time frame, the
6 Company has seen a cumulative Idaho-allocated NPC under-
7 forecast of $212 million, which translates to an
8 approximate $21 . 2 million under-collection after
9 application of ten percent sharing. Table `Sharing Band
10 NPC Impact' and Figure `Sharing Band NPC Impact ' below
11 show the annual details of that under-forecast, and
12 vividly illustrates the opposite of long-term balance
13 between ratepayers and the Company.
Mitchell, Di 93
Rocky Mountain Power

Table Sharing Band NPC Impact
NPC 10o Sharing
Year - Over/ (Under)
Forecast
Jul 09 - Dec 09 ($12, 150)
Dec 09 - Nov 10 ($607, 352)
Dec 10 - Nov 11 ($1, 856, 902)
Dec 11 - Nov 12 ($1, 835, 877)
Dec 12 - Nov 13 ($979, 139)
Dec 13 - Nov 14 ($1, 273, 551)
Dec 14 - Nov 15 ($926, 976)
Dec 15 - Dec 16 $105, 107
2017 ($211, 347)
2018 ($715, 259)
2019 ($1, 027, 552)
2020 ($433, 086)
2021 ($1, 304, 085)
2022 ($3, 532, 283)
2023 ($6, 587, 473)
Total ($21,197, 925)
Mitchell, Di 94
Rocky Mountain Power

Figure Sharing Band NPC Impact
Cumulative Trend in Sharing 10% of the NPC Over/(Under) Forecast
$(5 Million)
$(10 Million) L
$(15 Million)
$(20 Million)
$(25 Million)
M o ti N m �t Ln t.n rn co M O N m
O 14 �-i rl � 1 -4 1-1 r-1 1H r1 r-I N N N N
0 o O O o O O
0 0 0 0 0 0 N N N N N (V N
❑ Z Z Z Z Z Z ❑
Ol 61 Q .--I N rn �T U"1
O O ti r-I r-1
3 u u u u u u u
❑ O ❑ O O ❑ O
Increase ■ Decrease 0 Total
1 Q. Does the current 90/10 ECAM sharing band act as an
2 appropriate incentive for the Company to manage costs
3 effectively?
4 A. No . As provided in more detail in the testimony of
5 Company witness Tsoukalis, the Company has announced its
6 intention to join the EDAM, which will create
7 efficiencies that reduce NPC. 23 Once the EDAM is
23 PacifiCorp to build on success of real-time energy market innovation
as first to sign on to new Western day-ahead market, PACIFICORP (Dec. 8,
2022) , https://www.pacificorp.com/about/newsroom/news-releases/EDAM-
innovative-efforts.html.
Mitchell, Di 95
Rocky Mountain Power

1 operational in 2026, the sharing band at 90/10 is neither
2 effective or necessary to incentivize the Company to
3 manage its NPC because the EDAM will more efficiently
4 optimize the dispatch of resources to produce the least
5 cost outcome subject to constraints on the power system,
6 in a manner which goes above and beyond the Company' s
7 capabilities in isolation. Lastly, the Company operates
8 its system on a least-cost basis on behalf of all its
9 customers in all six of its jurisdictions . As stated
10 above, two of these jurisdictions contain a full
11 passthrough of NPC and represent almost half of the
12 Company' s total NPC and associated variance . Given that
13 the Company' s participation in the EDAM will lower its
14 NPC to the lowest level attainable and given how it
15 operates its system across all six jurisdictions, the
16 current 90/10 sharing band is neither effective or
17 necessary to incentivize the Company to manage or reduce
18 its NPC .
19 Q. How does this continued under-recovery of prudently
20 incurred NPC in Idaho impact the financial health of the
21 Company?
22 A. Recovery of costs that are incurred to serve customers
23 are necessary to ensure that the Company has the
24 liquidity to fund its operations and to safely and
25 reliability serve its customers . To the extent that the
Mitchell, Di 96
Rocky Mountain Power

1 Company is continuously under recovering actual costs
2 that were prudently incurred to serve customers, it
3 places more pressure on the Company' s liquidity and cash
4 reserves and may result in increased short-term and
5 long-term borrowing. This larger debt increases the
6 Company' s leverage, which in turn increases the cost of
7 interest and places further pressure on the Company' s
8 credit metrics and limits the Company' s ability to
9 absorb increased prices for electricity and fuel to
10 serve its customers . To the extent that the Company has
11 an increased requirement to borrow money and higher
12 borrowing costs, these costs not only harm the health of
13 the utility but would be passed on to customers and can
14 ultimately result in a downgrade of its credit rating.
15 Company witness Nikki L. Kobliha discusses these topics
16 in more detail .
17 D. The NPC Forecast
18 Q. Does the Company operate the system with these
19 regulatory NPC forecasts in mind?
20 A. No, and it would be imprudent to do so . The Company' s
21 energy supply management ("ESM") group, which optimizes
22 actual NPC in actual operations, does not operate with
23 the NPC forecast as a target . Company NPC forecasts
24 created during general rate cases, or other filings, are
25 only used to set NPC for ratemaking purposes, they are
Mitchell, Di 97
Rocky Mountain Power

1 not used or referred to in actual Company operations .
2 ESM is constantly - on a daily and more granular basis
3 - updating its forward prices, renewable resource
4 forecast, load forecast, etc. to manage NPC for a least-
5 cost outcome on behalf of all of its customers .
6 Q. Can the Company improve the forecasting of model inputs
7 to capture all prudently incurred costs in the forecast?
8 A. No, for several reasons . First, it is very difficult to
9 accurately forecast key NPC variables such as
10 intermittent renewable resources, extreme weather
11 events, and volatile market conditions for market power
12 prices and natural gas prices, especially when the
13 forecast is required to be normalized. Even minor
14 variables can have a significant impact on the Company' s
15 large and complex power supply system. Second, as
16 mentioned above in further detail, the confidential
17 nature of other utilities' operational details will make
18 it extremely difficult for any individual EDAM
19 participant to accurately forecast the NPC outcomes of
20 the market, once the EDAM is implemented.
21 X. CONCLUSION
22 Q. Please summarize your recommendation to the Commission.
23 A. I recommend that the Commission: (1) adopt the proposed
24 base NPC for the NPC test period of $136 . 7 million, or
25 $39 . 34/MWh; and (2) approve a better solution for both
Mitchell, Di 98
Rocky Mountain Power

1 customers and the Company through modifying the sharing
2 band from a 90/10 percent Company/customer sharing
3 structure to a 95/5 percent Company/customer sharing
4 structure, which would ensure that the overwhelming
5 majority of prudently incurred NPC are appropriately
6 refunded to or collected from customers .
7 Q. Does this conclude your direct testimony?
8 A. Yes .
Mitchell, Di 99
Rocky Mountain Power

Case No. PAC-E-24-04
Exhibit No. 23
Witness : Ramon J. Mitchell
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Ramon J. Mitchell
2025 NPC Report
May 2024

Rocky Mountain Power
Exhibit No.23 Page 1 of 5
Case No. PAC-E-24-04
Witness:Ramon J.Mitchell
Exhibit 23
Total Jan-25 Feb-25 Mar-25 Apr-25 May-25 Jun-25 Jul-25 Aog-25 Sep-25 Oct-25 Nov-25 Dec-25
E
Spe ales For Resale
Long Tenn Firm Sales
Black Hills $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
H-i- Sale $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
LeaningJuniperReven- $ 292,041 $ 21,466 $ 19,348 $ 21,989 $ 14,723 $ 14,161 $ 13,437 $ 41,893 $ 46,324 $ 34,305 $ 23,624 $ 18,766 $ 22,007
PSCo_Sal, $ 13,182,454 $ 878,915 $ 812,880 $ 911,908 $ 663,180 $ 676,640 $ 868,951 $ 2,190,767 $ 2.214,464 $ 2,118,417 $ 687,033 $ 444,608 $ 714,692
Total Long Term Firm Sales $ 13,474,495 $ 900,381 $ 832,228 $ 933,897 $ 677,903 $ 690,801 $ 882,388 $ 2,232,660 $ 2.260,768 $ 2,152,721 $ T10,6% $ 463,374 $ 736,699
Short Term Firm Sales
Borah $ - $ $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
COB $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Colomdo $ - $ - $ - $ - $ - $ - $ - $ - S - $ - $ - $ - $ -
FoorCorners $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Idaho $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Mead $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Mid Columbia $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Mona $ - $ $ - $ - $ - $ - $ $ - $ - $ - $ -
NOS $ - $ - $ - $ - $ - $ - $ - $ - S - $ - $ - S - $ -
Palo Verde $ - $ - $ - S - $ - $ - $ - $ - $ - $ - $ - $ - $ -
SP15 $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Utah $ - $ $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Washington $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
WestMain $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
WYoming $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Total Short Term Firm Sales $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
SvV-Balancing Sales
COB $ 53,708,780 $ 3,900,189 $ 3,229,620 $ 1,593,738 $ 1,701,032 $ 1,674,744 $ 2,126,186 $ 6,495,281 $ 8,425,507 $ 17,472,693 $ 2,454,677 $ 2,169,901 $ 2,465,213
Four Comers $ 42,620,952 $ 5,026,368 $ 2,679,543 $ 2,378,502 $ 1,872,379 $ 1,093,437 $ 1,466,982 $ 4,330,703 $ 4,387,393 $ 9,640,334 $ 2,304,458 $ 3,371,222 $ 4,069,633
Mead $ 476,137 $ 1,569,682 $ 5,101 $ (574.020)$ 7,257 $ 13,725 $ 14,174 $ 7,692 $ 287,660 $ 4,285 $ (922,317)$ 6,192 $ 56,705
Mid Columbia $ 107,504,415 $ 21,519,395 $ 9,234,129 $ 5,265,866 $ 4,943,184 $ 1,860,054 $ 3,481,987 $ 10,542.246 $ 11,149,6T3 $ 7,4130,264 $ 9,045,541 $ 8,460,382 $ 14,591,694
Mona $ 11,077'006 $ 1,T45,241 $ 1,600,242 $ 60T,698 $ 566,5T4 $ 489,431 $ 696,902 $ 21135,08: $ 21530,603 $ 2,435,828 $ 732,765 $ 895,2131 $ 1,641,096
NOB $ 24,419,632 $ 3,0021149 $ 1,949,205 $ 1,4,3,816 $ 595,041 $ 532,T98 $ 915,989 $ 4,245,440 $ 3,718,665 $ 1,473,505 $ 1,936,T54 $ 1,952,254 $ 2,684,016
Palo Verde $ 3,661,376 $ 295,147 $ 218,322 $ 50,769 $ 162,353 $ 14T,882 $ 275,894 $ 567,030 $ 252,619 $ 767,216 $ 168,134 $ 273,889 $ 482,220
Trapped Energy $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Total System Balancing Sales $ 248,468,299 $ 37,058,171 $ 18,916,161 $ 10,736,369 $ 9,847,820 $ 5,812,070 $ 8.978,113 $ 28,323,482 $ 30,752,020 $ 39,204,125 $ 15,720.013 $ 17,129,378 $ 25,990,575
Total Special Sales For Resale $ 261,942,794 $ 37,958,552 $ 19,748,389 $ 11,670,266 $ 10,525,723 $ 6,502,870 $ 9,860,501 $ 30,556,142 $ 33,012,808 $ 41,356,846 $ 16,430.669 $ 17,592,752 $ 26,727,274

Rocky Mountain Power
Exhibit No.23 Page 2 of 5
Case No. PAC-E-24-04
Witness:Ramon J.Mitchell
Purchased Power 6 Net Interchange
Lone Term P'rm Purchases
Appaloosa lA Solar $ 10,292,182 $ 559,723 $ 593,465 $ 906,325 $ 978,713 $ 1,146,027 $ 1,210,510 $ 1,060,453 $ 1,033,174 $ 974,493 $ 775,447 $ 576,254 $ 4n,599
Appaloosa l B Solar $ 6,861,455 $ 373,148 $ 395,643 $ 604,217 $ 652,475 $ 764,018 $ 807,006 $ 706,969 $ 688,783 $ 649,662 $ 516,964 $ 384,170 $ 318,399
Castle Solar UOU $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Cas[le Solar IHC $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
CedarSpringsWlnd $ 11,723,272 $ 1,348,848 $ 1,095,201 $ 1,032,244 $ 1,016,035 $ 830,825 $ 743,881 $ 742,782 $ 585,990 $ 827,498 $ 1,090,534 $ 1,068,343 $ 1,341,093
Cedar Springs Wlnd 111 $ 8.908,094 $ 1,025,293 $ 832,068 $ 764,236 $ 7]2.171 $ 637271 $ 585,347 $ 564,366 $ 445,199 $ 628,829 $ 828,668 $ 811,823 $ 1,018,881
Cedar Springs Wind lV $ 35,181,067 $ 4,332,908 $ 3,096,960 $ 2,654,190 $ 2.509,530 $ 2.311,613 $ 2,072,340 $ 2.005,725 $ 2,086,972 $ 2,345,721 $ 3,189,306 $ 3,831,121 $ 4.545,280
Combine HMIs Wind $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Cove Mountain Solar $ 3,802,638 $ 182,379 $ 191,610 $ 333,997 $ 363,597 $ 418,499 $ 450,080 $ 436,591 $ 413,105 $ 354,252 $ 285,173 $ 204,900 $ 168,457
Cove Mountain Solar II $ 9,387,257 $ 450,472 $ 473272 $ 824,965 $ 898,077 $ 1,033,683 $ 1,111,688 $ 1,078,370 $ 1,020,362 $ 874,994 $ 704,370 $ 503,256 $ 413,748
Deseret Purchase $ - $ - $ - $ - $ - $ $ - $ - $ - $ - $ - $ -
EagleMountain-DAMPS/UMPA $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ $ -
ElektronSolar20yr $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
ElektronSolar25yr $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ $ -
Gemstate $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $Graphite Solar $ 6,197,453 $ 310,012 $ 351,184 $ 554,615 $ 608,658 $ 682,657 $ 700,495 $ 683,227 $ 639,131 $ 572,798 $ 477,596 $ 353,010 $ 264,071
Hermiston Purchase $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Horseshoe Solar $ 6,072,682 $ 266,686 $ 331,07' $ 499,533 $ 565,742 $ 674,491 $ 748,804 $ 734,022 $ 695,525 $ 578,539 $ 464,831 $ 287,300 $ 228,132
Hunter Solar $ 6,980.641 $ 367,45: $ 416,574 $ 634,629 $ 662,343 $ 75526] $ 781,559 $ 743,007 $ 698,452 $ 651,25: $ 555,766 $ 394,179 $ 320,154
Hurricane Purchase $ - $ - $ - $ - $ - $ $ - $ - $ - $ $ -
MagCorp Buylhrough $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
MagCorp Reserves $ - $ - $ - $ - $ - $ $ - $ - $ - $ - $ - $ -
Milican Solar $ 2.973,753 $ 98,000 $ 149,553 $ 229,015 $ 288,2 $ 342,133 $ 372:405 $ 419,382 $ 370,578 $ 298,239 $ 195,281 $ 125:077 $ 85,830
Milford Solar $ 6,870.872 $ 347,965 $ 400'29 $ 591,100 $ 657,459 $ 772,977 $ 814,984 $ 725,777 $ 698,695 $ 651:754 $ 525,630 $ 382,415 $ 301:336
Nucor $ 7,129,800 $ 594,150 $ 594,150 $ 594,150 $ 594.150 $ 594,150 $ 594,150 $ 594,150 $ 594,150 $ 594,150 $ 594,150 $ 594,150 $ 594,150
Old Mill Solar $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Monsanto Reserves $ 20,600,000 $ 1,716,667 $ 1,716,667 $ 1,716,667 $ 1,716,667 $ 1,716,667 $ 1,716,667 $ 1,716,667 $ 1,716,667 $ 1,716,667 $ 11716,667 $ 1,716,667 $ 1,716,667
Pavant III Solar $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
PGE Cove $ 164,065 $ 13,672 $ 13,672 $ 13,672 $ 13,672 $ 13,672 $ 13,672 $ 13,672 $ 13,672 $ 13,672 $ 13,672 $ 13,672 $ 13,672
Prineville Solar $ 1,981,22: $ 67,243 $ 102.616 $ 152,164 $ 191,528 $ 227,324 $ 243.437 $ 2]8,650 $ 246,223 $ 198,159 $ 129,751 $ 83,105 $ 57,028
Rocket Solar $ 6,473,420 $ 294.299 $ 354,922 $ :35:304 $ :06.639 $ 708,931 $ 796,698 $ 2816*78:52 $ 738,987 $ 621,305 $ 4]2.4]0 $ 288,847 $ 238,526
Sigurd Sdis $ 5,858,273 $ 306,467 $ 342,172 $ 504,657 $ 550,996 $ 633,287 $ 696,030 $ 647,114 $ 593,204 $ 553,621 $ 449.403 $ 315,824 $ 265,298
Small Purchases eas' $ - $ - $ - $ - $ - $ $ - $ - $ - $ $ -
Small Purchases wes' $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Sodo Lake Geotherma $ - $ - $ - $ - $ - $ $ - $ - $ - $ $ -
ThreeButtesWlnd $ 20,425,527 $ 2,791,462 $ 1,807,438 $ 2,137,611 $ 1,500,892 $ 1,396,261 $ 1,192,997 $ 808.784 $ 951,391 $ 1,185,538 $ 1,707,698 $ 2,352,258 $ 2,593,195
Top of the World Wind $ 36,016,304 $ 3,058,919 $ 2,762,895 $ 3,058,919 $ 2.960,244 $ 3.058,919 $ 2,980,244 $ 3.058,919 $ 3,058,919 $ 2,980,244 $ 3,058,919 $ 2,980,244 $ 3.058,919
Wolverine Creek Win, $ 10,564,645 $ 793,982 $ 927,710 $ 1,182,235 $ 1,015,380 $ 799,504 $ 863,936 $ 698,003 $ 667,573 $ 785,474 $ 149,044 $ 1,002,522 $ 979,281
Faraday B Sole $ 7,312,704 $ - $ - $ - $ - $ - $ - $ - $ - $ 178,512 $ 3,317,436 $ 2,124:238 $ 1,694,518
Hornshadow l Solo $ 4:732,093 $ - $ - $ - $ - $ - $ 36,191 $ 1,17,15 $ 980,187 $ 893,225 $ 771,362 $ 535,520 $ 448,084
Hornshad..Il Sola $ 9,470,203 $ - $ - $ - $ - $ - $ 72,382 $ 2,135,050 $ 1,960,374 $ 1,789,170 $ 1,542,724 $ 1,074,337 $ 896,167
Green River Energy Conte $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Anti Gine Wind $ 17,940,049 $ 2,163,887 $ 1,688,476 $ 1,1:9,:65 $ 1.313,666 $ 1,135,050 $ 1,085,959 $ 1,032,757 $ 1,092,044 $ 1:208,912 $ 1,590,032 $ 1,906,748 $ 2,184,552
Boswell Springs Wind $ 33,509,692 $ 3,812,555 $ 3,273,801 $ 3,185,8]4 $ 2,914,068 $ 2,654,216 $ 2,240,134 $ 1,876,535 $ 1,811,846 $ 2,082,505 $ 2,949,429 $ 3,157,338 $ 3.769,394
Two River Wind LLC $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Carer Creel $ 20,742,033 $ 1,898,940 $ 1,671,841 $ 2,588,474 $ 1,733,785 $ 1,837,879 $ 1,203,586 $ 1,378,214 $ 1,091,693 $ 1,311,073 $ 2,183,871 $ 2,128,399 $ 1,714,280
OR Schedule 126 CSF $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
UT Schedule Adjustment $ (41,924,762)$ (1,640,749)$ (1,887,207)$ (3,311,367)$ (3,698,587)$ (4,396,217)$ (3,933,075)$ (3,636,688)$ (3,372,916)$ (3,008,179)$ (6,117,686)$ (3,900,688)$ (3,021,402)
Long Tenn Firm Purchases Total $ 276,246,441 $ 25,334,404 $ 21,674,490 $ 23,747,390 $ 21,386,125 $ 20,743,103 $ 20,164,108 $ 22,388,115 $ 21,519,780 $ 22,490,285 $ 24,838,508 $ 25,274,825 $ 26,685,308

Rocky Mountain Power
Exhibit No.23 Page 3 of 5
Case No. PAC-E-24-04
Witness:Ramon J.Mitchell
Qualifying Facilities
OF Celifomia $ 1,314,277 $ 66,937 $ 226,676 $ 239,350 $ 143,699 $ 109,361 $ 127,769 $ 100,913 $ 959 $ 902 $ 942 $ 120,265 $ 176,503
OF Idaho $ 7,638,182 $ 661,629 $ 512,036 $ 706,334 $ 678,303 $ 642,185 $ 724,111 $ 637,195 $ 583,647 $ 563,518 $ 631,714 $ 634,197 $ 663,313
QFOregoo $ 38,426,688 $ 2,005,238 $ 2,478,115 $ 3,038,383 $ 3,518,395 $ 4,370,533 $ 4,575,096 $ 4,746,825 $ 4,245,142 $ 3,466,096 $ 3,001,624 $ 1,723,539 $ 1,257,702
OF Utah $ 5,159,202 1 359,100 $ 351,969 $ 437,654 $ 458,387 $ 588,1872 $ 549,751 $ 505280 $ 461,769 $ 457,985 $ 440105 $ 319,931 $ 229,099
OF Washington $ 418.404 $ - $ 0 $ - $ 17,826 $ 9,844 $ 66,132 $ 125,752 $ 127,291 $ 54,687 $ 16,872 $ - $OF Wyoming $ 37,864 $ 3,348 $ 3,684 $ 3,409 $ 5,781 $ 2,351 $ 966 $ 1,525 $ 1,513 $ 2,762 $ 7,404 $ 11169 $ 4,554
Biomass One OF $ 18,106,765 $ 1,488,124 $ 1,313,070 $ 1,441,737 $ 1,306,502 $ 1,726,920 $ 1,715,281 $ 1,600,718 $ 1,658,504 $ 1,630,706 $ 1,669,668 $ 1,665,167 $ 890,365
Chopin Wind OF S 2,012,997 $ 187,801 $ 192,540 $ 164,798 $ 187,529 $ 168,121 $ 173,396 $ 159,633 $ 144,262 $ 129,099 $ 174,434 $ 170,787 $ 160,596
Chopin Schumann Wind OF $ 350,933 $ 28,121 $ 26,579 $ 34,448 $ 32,592 $ 29,609 $ 31,270 $ 26,938 $ 26,579 $ 21,389 $ 25,602 $ 31,845 $ 35,960
DCFP OF $ 52,863 $ 7,735 $ 3,713 $ 3,050 $ 2,390 $ 3,336 $ 4,013 $ 28,625 $ - $ - $ - $ - $ -
EnterprlseSOlarIOF $ 11,486,229 $ 601,040 $ 728,906 $ 935,653 $ 986,969 $ 1,211,715 $ 1,100,258 $ 1,543,255 $ 1,364,298 $ 1,106,789 $ 767,407 $ 611,989 $ 527,951
Escalante Sol ar l QF $ 10,960,429 $ 552,577 $ 660,609 $ 855,376 $ 960,493 $ 1,170,000 $ 1,236,834 $ 1,421,370 $ 1,268,856 $ 1,025,355 $ 750,339 $ 565,164 $ 493.457
Escalante SOlartl OF $ 10.545,170 $ 517,171 $ 620.956 $ 805,"1 $ 910.:51 $ 1,106,171 $ 1:213:693 $ 1,357:664 $ 1,249,999 $ 977,757 $ 780,015 $ 544,9' $ 460.340
Escalante Solar III OF $ 10.231,225 $ 503,513 $ 606.095 $ 782,229 $ 889.843 $ 1,081,064 $ 1,183,314 $ 1.302,622 $ 1,245,053 $ 981,999 $ 731,313 $ 522:293 $ 421,846
Exxon Mobil QF $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Fivs Pine Wind OF $ 9,647,327 $ 605,136 $ 986,312 $ 889,62: $ 849.689 $ 549273 $ 603,818 $ 734,917 $ 696,6:3 $ 874,751 $ 131.130 $ 1,006,632 $ 1,119,371
Granite Mountain East Solar OF $ 10,828,730 $ 582,027 $ 681,713 $ 848,136 $ 953'738 $ 1,100,787 $ 1,236,204 $ 1.383,394 $ 1,221:769 $ 988,531 $ 795,084 $ 587,026 $ 492,320
Granite Mountain West Solar QF $ 6.029,042 $ 363.898 $ 417,364 $ 507.854 $ 102,582 $ 701,511 $ 616,766 $ 880,427 $ 733,3316 $ 599,306 $ 459,431 $ 334,626 $ 307.891
ron Springs Solar OF $ 10,623,665 $ 580,491 $ 666.604 $ 846,422 $ 944,453 $ 1,118,700 $ 1,116,806 $ 1.375,972 $ 1,234,830 $ 973,878 $ 744,0]1 $ 536,591 $ 487.650
Latigo Wind Park OF $ 9.187,773 $ 1,001,258 $ 894.241 $ 1,052,637 $ 824,543 $ 855,024 $ 614,626 $ 679,468 $ 516,350 $ 588,070 $ 720,120 $ 663,502 $ 7n 933
Mountain Wind 1 OF $ 8,786,370 $ 1,383,421 $ 1.044,417 $ 858,588 $ S.082 $ 485,398 $ 495,144 $ 401,433 $ 434:17 $ 455,7:7 $ 666,342 $ 882,811 $ 1,112:591
Mountain Wind 2 OF $ 13,536,729 $ 2,000,904 $ 1,551,179 $ 1,323,297 $ 1.006,259 $ 749,034 $ 888,797 $ 752.901 $ 717,302 $ 750,983 $ 968,898 8 1,361,006 $ 1,490,189
North Point Wind OF $ 20,612,280 $ 1,213,451 $ 2,029,595 $ 1,892,017 $ 1,835,127 $ 1,159,894 $ 1,304,004 $ 1,629,801 $ 1,647,255 $ 1:985,981 $ 1,11,710 8 2,042,749 $ 21017:691
Oregon Wind Farts OF $ 12,143,464 $ 998,097 $ 1,099,728 $ 836.188 $ 828.470 $ 576,410 $ 491,712 $ 1,462,155 $ 1,714,433 $ 1,207:746 $ 727,01 $ 838,154 $ 1,13,319
Orchard Wlnd 1 OF $ 2212:11 $ 171,682 $ 118,895 $ 219,195 $ 251.419 $ 235,568 $ 254,560 $ 223.460 $ 225,588 $ 164,749 $ 147,452 $ 133,885 $ 145,928
Orchard Wl nd 2 OF $ 2292,261 $ 171,662 $ 118,895 $ 219,195 $ 251.601 $ 235,743 $ 254,302 $ 223,460 $ 225,588 $ 164,74: $ 147,4:2 $ 133,685 $ 145,928
Orchard Wl nd 3 OF $ 2,292,583 $ 171,662 $ 118,895 $ 219,195 $ 252,009 $ 235,730 $ 254,229 $ 223,460 $ 225,588 $ 164,749 $ 147,452 $ 133,885 $ 145.928
Orchard Wl nd 4 OF $ 2,292,210 $ 171,662 $ 118,895 $ 219,195 $ 251,592 $ 235,730 $ 254,274 $ 223.460 $ 225,588 $ 164:19 $ 147,452 $ 133,885 $ 145.928
Pavan,II Solar QF $ 5,849,871 $ 240,093 $ 293.160 $ 433,611 $ :115 $ 597,794 $ 19,155 $ :25,386 $ 774,689 $ 591,181 $ 430750 $ 280,517 $ 233,053
Pioneer Wind Park I OF $ 10,665,762 $ 1,312,186 $ 930260 $ 1,18g,464 $ 900.854 $ 712,752 $ .7,784 $ 660,578 $ 679,609 $ 450,955 $ 824,756 $ 1,259,911 $ 1,096,655
Power County North Wind OF $ 6,180,712 $ 480,893 $ 628,902 $ 604,846 $ 538.724 $ 402,0]7 $ 364,669 $ 427.060 $ 418,091 $ 432,607 $ 570.]34 $ 598,542 $ 701.368
Power County South Wind OF $ 5:498,780 $ 424,333 $ 552.983 $ 546:339 $ 493.378 $ 347,184 $ 346:398 $ 371,860 $ 389:130 $ 382,558 $ 498,453 $ 537:476 $ 608.687
Roseburg Dillard OF $ 2,144,926 $ 165,687 $ 217.686 $ 158,169 $ 175,020 $ 240,890 $ 128,909 $ 272.096 $ 184,147 $ 115,915 $ 96.035 $ 139,Sol $ 250,374
Sage l Solar OF $ 2,224,685 $ 79,115 $ 78.138 $ 185,750 $ 201.479 $ 231,609 $ 255,641 $ 332.541 $ 326,288 $ 205,038 $ 152,736 $ 102,280 $ 73.871
Sage II Solar QF $ 2,223,183 $ 79,198 $ 78231 $ 185,945 $ 211.15 $ 230.91 $ 256,127 $ 330,821 $ 326,64: $ 204,200 $ 152,889 $ 102,691 $ 73.807
Sage III Solar OF $ 1,830,073 $ 88,690 $ 65.104 $ 153,415 $ 164218 $ 189.832 $ 209,266 $ 269.677 $ 286,077 $ 168,341 $ 128,726 $ 68,688 $ 62,640
Spanish Fork Wind 2 QF $ 2,833,148 $ 227,426 $ 183,910 $ 209,400 $ 162,146 $ 157,880 $ 220,088 $ 302,647 $ 322,851 $ 276.043 $ 250:057 $ 256,401 $ 264,297
Sunnyside OF $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
SweetwaterSolarOF $ 7,551,390 $ 252,907 $ 362,894 $ 547.261 $ 667,685 $ 791264 $ 9501104 $ 1,086,493 $ 1,005,887 $ 790:122 $ 610.411 $ 290,621 $ 195,741
Tesoro OF $ 213,0- $ 40,263 $ 43,016 $ 28,705 $ 8,564 $ 1,746 $ 1,858 $ 99 $ 1,906 $ 7,.5 $ 7,561 $ 14,833 $ 56,883
Three Peaks Solar OF $ 8,973,114 $ 140,505 $ 497.322 $ 648,798 $ 159,439 $ 938,938 $ 956,823 $ 1,133,177 $ 1,073,990 $ 839,474 $ 722,120 $ 463,326 $ 399202
Th.mile Canyon Wind OF $ 2,018,676 $ 88,630 $ 181,791 $ 158,295 $ 201,47: $ 206.750 $ 240,871 $ 244.129 $ 200,451 $ 142,666 $ 157,378 $ 108,829 $ 87,605
Utah Pavant Solar OF $ 7,159,995 $ 303,831 $ 346282 $ 509,076 $ 604,977 $ 784,942 $ 694,317 $ 1,063,89: $ 901,307 $ 793,052 $ 493.588 $ 12,653 $ 322.334
Utah Red Hills Solar OF $ 10,473,163 $ 478,923 $ 5B0,625 $ 677,548 $ 907'822 $ 1,146,134 $ 1,000,877 $ 1,534,779 $ 1,279,128 $ 1,213,095 $ 671,655 $ 517,784 $ 454,792
Skysol Solar OF $ 6,466,196 $ 337,321 $ 346,440 $ 521,412 $ 573,358 $ 628.554 $ 807,383 $ 867,608 $ 760,039 $ 566,178 $ 483,488 $ 285,341 $ 289,072
Qualifying Facilities Total $ 309,614,622 $ 21,415,669 $ 22,968,423 $ 26,137,861 $ 26,271,233 $ 28,068,864 $ 28,815,598 $ 33,476,466 $ 31,106,801 $ 26,639,511 $ 23,604,867 $ 21,064,579 $ 20,044,748
Mid-Columbia Contracts
Douglas-Wells $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
GrantReas-this $ (15,474,138)$ (1,289,511)$ (1,289,511)$ (1,289,511)$ (1,289,511)$ (1289,511)$ (1,289,511)$ (1,289,511)$ (1,289,511)$ (1,289,511)$ (1,289,511)$ (1,289,511)$ (1,289,511)
Grant Meaningful Priority $ 109,742,672 $ 9,145,223 $ 9,145,223 $ 9,145,223 $ 9,145,223 $ 9,145,223 $ 9,145,223 $ 9,145,223 $ 9,145,223 $ 9,145,223 $ 9,145,223 $ 9,145,223 $ 9,145,223
Grant Surplus $ 2,532,591 $ 211,049 $ 211,049 $ 211,049 $ 211,049 $ 211,049 $ 211,049 $ 211,049 $ 211,049 $ 211,049 $ 211,049 $ 211,049 $ 211,049
Mid-Columbia Contracts Total $ 96,801,125 $ 8,066,760 $ 8,066,760 $ 8,066,760 $ 8,066,760 $ 8,066,760 $ 8,066,760 $ 8,066,760 $ 8,066,760 $ 8,066,760 $ 8,066,760 $ 8,066,760 $ 8,066,760
----------------------"--"-- -----------------------"--------------------------- -------"--"----------"-----------"--"----------"---- --------"-----------"--"----------"----
Torsi Long Term FirmPurchases $ 682,662,188 $ 54,816,833 $ 52,709,673 $ 57,952,012 $ 55,724,119 $ 56,878,728 $ 57,046,466 $ 63,931,342 $ 60,693,341 $ 57,196,557 $ 56,510,135 $ 54,406,165 $ 54,796,817
Storage&Exchange
Rush lake BESS $ - $ - $ $ - $ $ - $ - $ - $ $ -
Fremon,Solar BESS $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - 5 - $ -
Green River Energy Center_BESS $ - $ - $ - $ - $ - $ $ - $ - $ - $ $ -
Faraday Solar_BESS $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - 5 - $ -
Umpqua Storage Placeholder $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - 5 - $ -
Cowlltz Swift $ - $ - $ - 5 - $ - $ - $ - $ - $ - $ - $ - 5 - $ -
EWEBFCI $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $PSG.
Exchange $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - 5 - $ -
PSCO FC III $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - 5 - $ -
SCLStateLine $ - $ - $ - $ - $ - $ - 5 - $ - 8 - $ - $ - 5 - $ -
Total Storage&Exchange $ - $ - $ - $ - $ - $ - S - $ - $ - $ - $ - 5 - $ -

Rocky Mountain Power
Exhibit No.23 Page 4 of 5
Case No. PAC-E-24-04
Witness:Ramon J.Mitchell
Short Term Firm Punch....
COB $ 16,121,750 $ 1,934,400 $ 1,785,600 $ 1,929,750 $ $ S $ 3,536,000 $ 3,536,000 $ 3,400,000 $ $ $
Colo do $ - $ - $ - $ - $ $ S $ - $ - $ - $ $ $
Four Comers $ $ $ $ $ $ S $ $ $ $ $ $
-
Idaho $ $ $ $ $ $ S $ $ $ $ $ $
-
Mead $ $ $ S $ $ S $ $ $ $ $ $
Mid Columbia $ 13,299,800 $ $ $ $ $ S $ 4,464.900 $ 4,484,900 $ 4,330,000 $ $ $
Mon. I - $ $ $ $ $ S $ - $ - $ - $ I $
NOB $ $ $ S $ $ S $ $ $ $ S $
Palo Verde $ $ $ $ $ $ S $ $ $ $ S $
S 15 $ $ $ S $ $ $ $ $ $ $ $ $
Utah $ $ $ $ $ $ 1 $ $ $ $ $ $
Washington $ $ $ $ $ $ $ $ $ $ $ $ $
W:t Asin $ $ $ $ $ $ $ $ $ $ $ $ $
Wyoming $ $ $ $ $ $ $ $ - $ $ $ $ $
0 $ 227,256,579 $ $ $ $ 15,518,466 $ 12,726,253 $ 12,021,138 $ 42,106,793 $ 53,982,301 $ 43,506,176 $ 15,024,096 $ 14,395,898 $ 17,975,459
Total Short Term Firm Purchases $ 256,678,129 $ 1,934,400 $ 1,785,600 $ 1,929,750 $ 15,518,466 $ 12,726,253 12,021,138 $ 50,127,693 $ 62,003,201 $ 51,236,176 $ 15,024,096 $ 14,395,898 $ 17,975,459
System Balancing Purchases
COB $ 1.10 $ 2:1202:626 $ 3,935,250 $ 7370:402 $ 211 071 $ 1721:1 1 10 0%732 $ 4 1:69 $ 6,400,131 $ 23' $ 91211 1 916,265 $ 1,919,751
Four Comers $ 23,79 0 82 0 247 11 300 47*97 3*299 $ 656 2:7512 7487 2009: 7 2:12 5313 1 2,327,422 $ 2,487,961
2::l $ 3 1072 $ 0 1 $ 1,7S $ B $ S $ $ 2:4 0.1 $ 2 8,1(li $ 2.1 3 Mead $ 855,154 $ 417,657 $ (13,259)$ 71:464 $ (14,040)$ - S (163,123)$ - $ (102,054)$ (94,128)$ 220:149 $ (160,512)
Mid Columbia $ 239.406,694 $ 53,212':99 $ 21,712,146 $ 11,231 7 $ 3,484,324 $ 1,712,197 S "01 7 73 $ 31,709,536 $ 27,872,948 $ 1 $ 11,171,711 19,838,2 $ 35,580,662
69 $ $ $ $ 1:4 5 1:117
Mon. $ 2 4 I4 3 $ 3, 6 2 1:11 $ 828,7;69 880,165 $ 966,994 $ 13:4'26 2,256,512 $ 2,338,665 115 499 $ 3103,525 $ 2,497,65N3 $ 651253
$ $ :3 $ $
NOB 61,953,918' ' B,97g:2 0 4:6883 415 $ 3,34:19 $ 1,251,312 $ 831,170 1,701 $ 11,609,150 $ 9,777,713 $ 3,093,13:1 4.33SI24 1 1,164,797 $ 6 87:1
Palo Verde $ 11:1.1:4 $ 3,958,841 g $ 91,453 $ 75725483 $ 168,322 $ 362,858 $ 154,002 $ 224,967 $ 700,692 $ 12,366
2 6 $ 2,61 461 1,109,405 $ 2:28:5 2
('0, $ (11
EIM p,rWExp a $ 352 6`4 300 75)$ (8,327,383)$ (7,127,129)$ (6,353,110)$ (5,748,156�$ (5,5 31)$ (113 671)$$ (142::�3O�393)$ (10,700:168)$ (16,90H.343) (7,890,338)$ (11,474,394)
7
$ $ $ 1:::5
Emergency Purchase. $ 7,631,0:5 $ 10,378 $ - - - - $ 103 $ 2,786,351 4'09 $ - $ - $ - $ 8,453
Total System Balancing Purchases $ 291,560,668 $ 64,279,770 $ 27,150,055 $ 12,315,973 $ 472,823 $ (1,072,138)$ 6,231,964 $ 44,707,283 $ 41,331,935 $ 4,171,942 $ 24,826,419 $ 23,963,505 $ 43,181,138
Total Purchased Power&Not Interchange $ 1,230,900,984 $ 121,031,003 $ 81,645,328 $ 72,197,735 $ 71,715,408 $ 68,532,843 $ 75,299,568 $ 158,766,318 $ 164,028,477 $ 112,604,674 $ 96,360,649 $ 92,765,568 $ 115,953,413
Wheeling&U.of F.Expense
Firm Wheeling $ 190,983,160 $ 20,254,042 $ 13,959,905 $ 15,042,470 $ 14,859,633 $ 14,055,026 $ 15,467,371 $ 17,559,023 $ 17,035,357 $ 15,499:99 $ 15,498:749 $ 15,5 $ 161�60,750
$ $ 2 $ $ $ 1:0:34 $
G&T EIM Admin fee 2,739,646 $ 230,970 222,455 285,739 $ 237,139 $ 241,142 256,561 $ 238,944 $ 221,26 240,69 181 475 8,35 94,490
ST Firm&Non-Firm - $ - $ - $ - $ - $ - S - $ - $ - $ - $ - $ - $ -
Total Wheeling&U.of F.Expense $ 193,722,805 $ 20,485,012 $ 14,182,360 $ 15,328,209 $ 15,096,773 $ 14,296,168 S 15,723,932 $ 17,797,967 $ 17,256,584 $ 15,740,468 $ 15,680,224 S 15,779,869 $ 16,355,240
Coal Fuel Bum Expense
C,latrip $ 20:49 61 121:0133 $ 6 $ 1,14,gl(I $ �.131.VS $ 1,232,839 S 1�31 0 $ 2,15.17 7 $ 2,�112,,O�71 $ 7,1.11 $ 749.:61 1 6,2t 793 $ 740
Ca $ 1:6'72 $ j::3 7 $ 1.12 1,7 7:4 4 $ :S $ 1 4, $ j,:4
1 12 1 $ 7 20 1:3 :32 $ 6,501
.9 20 3g 3 490,473 $ 14 $ 435"2: $ 1110,111 1 536 90 7 S 098$ 4.47 087 $ gg%7 $ $ 4 $ 4,908,875 $ 5'199'866 $
$ 1:3 151,139 3:317137 3,854,2713 $ 4,1611:8 9 D..Johnston $ 52:4610 316 $ 4,:03:2 1 4 310 4:575,01 S %2:09:1 $ 5: S
,. :3 $ 92 $ 7 s 38 1:2
Hayden 3054 4:0 707,756 $ 843,993 $ 812,501 $ 82,1
I $ 955,23,1 $ -2,800 $ MS'864 $ 546757 741,361 $ 1250333
250 3 3
Hunter $ 239 1:411,111 $ 20,473,510 0:::0 $ 222 1 $ 21,360069 $ 21,257276 19,905,
32:�9::::36: $ 20:0S4,:23 $ 17,073 311 $ 79:609 $ 21 0 21 $ 22:4 g 20,391,879 $ 172
$ 12053 �3 4 $ �::l 2 1 $ 1 1:6 1 3 $ S $ 1 1:::l, $
Huntington $ 17 75 $ 328,726 $ 15,644 51 4540 14,586,990 S 5: 5'65 1553 ' 'g la,24 147 $ 11,627 220 14,654,OW $ 11,459,619
Jim Bridge $ 106,868,456 $ 12,008'630 $ 11,146,114 $ 8,462,392 $ 5,571,554 $ 3,985,838 S B 161425 $ 13:93::10 $ 13'233'972 $ 8,248 179 $ 7,391 758 S 9,200,377 $ 7,522,479
$ 9 1:971:4 2 $ 299 568 $ Jt2 $ 5.
N.Ughto $ 33,496,936 $ 5,570,082 $ 4 $ 1,677,663 17*257 $ $ 84 $ 1,461 340 $ 1,894 138 2,127$ $ 111, 1,886 $ 74,704 �4:416
Wy.d.k 21,361,749 $ 2,089,977 2:0281 $ 2,196,699 $ 473 517,077 S 1,577,980 $ 1,997,928 $ 1,472,012 $ 1,872:998 $ 1,280:405 S 1,431,3603 $ 2.00 9056
Total Coal Fuel Bum Expense $ 677,234,146 $ 61,003,433 $ 57,786,582 $ 53,587,026 $ 45,679,797 $ 50,385,076 S 54,541,223 $ 67,009,508 $ 66,398,268 $ 58,875,362 $ 51,502,082 $ 55,779,274 $ 54,686,513
Gas Fuel Burn Expense
Chehalis $ :57:13�2:301 $ 10,352,616
7'371'S002 $ 12,9U,04 $ 1,439,817 $ 5,775,866 $ 1,110,360 S 1:310:1015 $ 6'90::17: $ 1:3631�O:�2442 $ 3,195,283 $ 5,11,311 6,4W,Ul $ �4:65::661
u $ 984 $ $ $ 3. 2,246,059
S $ $ 3 $ 1:;9
Conan Creak 17 0 52 16 6 351,6,12 $ 4,933,934 17:1 2 $ 1,999,838 $ 246 9 2.1 67 7 25:432 $ 820'029 $ 95,712 $ 1.7 114
$ 24,023,990 $ 3,134,941' ' $ 2:734 1,363,891
.3 S:j $ 95305 $ 1,173,11 $ 2 06:.311�2 $ 2,0 1,71341 $ 1,�2:2 2 $ 1, $ ':' 3
G'"Y "22 $ 595,686 2 483:,771 $ 41 1,133B
d $ 62 374 1:707.S O�g $ 1,.0,56B $ 627'1 9: S 7S4 1 26: $ 1 3 S 1 1:3 $ 4 112 1,703,551
,703 51 $ 1.92 4 2
G.Islby T 15,127.165 $ 1,868,054 $ 1, $$ 34. :I $ 7 0 5
' ' 8 `4 Hermiston $ 33'94.37 $ 4,574,089 $ 3,7 2:32 $ 1:1 21�122 $ - $ S 2:111,116 $ 3,315,057 S 3 045 50' $ 2,397,483 $ 2:642:059 $ 3,496,226 $ 5.91,907
m $ 9 , 5 $ 1:6
Jim Bridg-Gas $ 75.87:.&t45 688,260 $ 7219 07 7 $ 3,652,011
$ 2,989348"l 9: $ 722,591 $ 9.11.71 1 8'795'411 $ 5,494,092 $ 4,141,191 1 1,2�3 12 $ 7,]17,265
7 $ S
Lake S do 1 $ 0,:51.233 $ 1,1,4�7n 3. $ 6 6,773,374 $ 4.6,18,2 4,391:220 $ :::11:67029 $ .113,697 $ 7,375,649 4 237 $ 6 $ 12,704,70]
6 5,18],238 38 2 ],188,096 $ $ 3,980,272 $ 2 '3'::3 l''35 ".;6'4 $
Lake
Sid. $ 86,522,692
B 22 92 $ 2 $ 12,123 $ 5,312,76 OB 5 $ B 85:15 $ 1,126 014 $ 1 3:7" $ 7 093' 6 S ::76U:02' $ 14:312 2
2 1:213 3 $ $ $ 2 67 $ 1:9
1:6 0;B 827,473 $ 1,012,356
Nm�ghbm-G., $ 15,554,484 $ 2,544,777 $ 2,'2:� $ 0 136,40: 664,1" $ 1,120,256 $ 1714020 1242, 6 272 $ 957689 $
Total Gas Fuel Burn
Gas Physics $ *2217:817,$$ "124 9 $ (565,488)$ (166,005)$ 2,072)$ 5,929 $ (46,792)$ (198020)$ ::9320�$ (I 01:;:�7)$$ (65,133)$ - $ -
Ge Sweps $ 8,201,542
1 01 542 (8,214,1:7�$ (1,920,205)$ 10,091,]78
0'09':7' $ 3,5116,300 $ 4,392,971 $ 3,1984 8 $ 09'1 98 $ (307 14 $ 42 1,77:,5� $ 579,900 $ (5,369,239)
Clay Seem Gas Stomg, (1,574,818)$ (614,735)$ (4499 $ (113324)$ 739 $ 51,739 $ 73 $ 1 739 $ 51,739 $ 51,739
1 7 9 $ 11,739 $ (236,847)$ (522,111)
$ $ '267 $ 51 1:3 3,958,010 $ 3,5 Pi"Ifin.Reservation Fee $ 47,508,715 $ 3,910,818 3,845 3,910,124 $ 3,958,308 $ 3,999,386 $ 3,9:0 795 $ 3,9'88,868 $ 3,989,945 $ 3,975:1135 $ 3,990,701 $ 991,798
Total Gas Fuel Burn Expense $ 536,968,308 $ 62,795,737 $ 52,330,536 $ 49,121,139 $ 33,391,099 $ 26,008,884 $ 33,583,195 $ 46,910,702 $ 46,748,459 $ 33,707,413 $ 36,940,851 $ 45,001,760 $ 70,428,534

Rocky Mountain Power
Exhibit No.23 Page 5 of 5
Case No. PAC-E-24-04
Witness:Ramon J.Mitchell
Other Generation Ezpen
eBlundell $ 5,548,069 $ 426.194 $ 262,756 $ 516.438 $ 518,878 $ 295,633 $ 492,113 $ 481,258 $ 506,730 $ 491,247 $ 508,536 $ 506,047 $ 542,238
Blundell Bottoming Cycle $ - $ - $ - $ - $ - $ - S - $ - $ - $ - $ - S - $ -
Ceder Springs Wind 11 $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Dunlap I Wind $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Ekola Flats Wind $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Foote Creek I Wind $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Foote Creek II Wind $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Foote Creek III Wind $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Foote Creek IV Wind $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $
Glenrock Wind $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Glenrock III Wind $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Goodnoe Wind $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
High Plains Wind $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Lean ingdunipa,1 $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Marengo Wind $ - $ - $ - $ - $ $ $ - $ $Me Wind $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
MCFadden Ridge Wind $ - $ $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Pryor Mountain Wind $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Rolling Hills Wind $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Seven Mile Wind $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
S—In Mile II Wintl $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Black Cap Solar $ - $ - $ - $ - $ - $ - $ - $ $ - $ - $ - $ -
TB Flate Wind $ - $ - $ - $ - $ - $ - $ - $ - $ $ -
Rock Creek 1 $ - $ $ - $ - $ - $ - $ - $ - $ - $ - $ -
Rock Croak 2 $ - $ - $ - $ - $ - $ - $ - $ - $ $ - $ -
Rock River,1 $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Integration Charge $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Total Other Generation Expense $ 5,548,069 $ 426,194 $ 262,756 $ 516,438 $ 518,878 $ 295,633 $ 492,113 $ 481,258 $ 506,730 $ 491,247 $ 508,536 $ 506,047 $ 542,238
_______________________________________________________________________________________________________________ ____________________________________________________________________________________________________
Net Power Coat $ 2,382,431,518 $ 227,792,828 $ 186,459,172 $ 179,090,282 $ 155,876,231 $ 153,015,733 $ 169,779,529 $ 260,409,610 $ 261,925,709 $ 180,062,318 $ 184.561,674 $ 192,239,767 $ 231,238,666
___________________________________________________________________________________________________________________________________________________________________________________________________________________

Case No. PAC-E-24-04
Exhibit No. 24
Witness : Ramon J. Mitchell
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Ramon J. Mitchell
Aurora validation
May 2024

Rocky Mountain Power
Exhibit No.24 Page 1 of 4
Case No. PAC-E-24-04
Witness:Ramon J.Mitchell
Net Power Cost Report Aurora Validation NPC Report
--12 months ended December 2021
Total 1/1/2021 2/1/2021 3/1/2021 4/1/2021 5/1/2021 6/1/2021 7/1/2021 8/1/2021 9/1/2021 10/1/2021 11/1/2021 12/1/2021
5
Special Sales For Resale
Long Term Firm Sales
Black Hills Losses_S 308,860 26,315 21,811 23,518 22,569 21,526 33,190 28,307 25,794 26,552 26,173 25,272 27,832
Black Hills Sale-MC_S 3,714,881 352,854 345,348 381,005 260,897 132,813 168,939 358,954 334,088 341,594 352,854 331,273 354,262
Black Hills Sale-UTS_S 2,095,040 178,500 147,946 159,524 153,092 146,016 225,135 192,008 174,962 180,108 177,535 171,424 188,792
Black Hills Sale-WYE_S 1,789,443 152,463 126,365 136,255 130,761 124,717 192,295 164,000 149,441 153,836 151,638 146,419 161,253
Leaning Juniper Revenue_S 105,254 7,601 7,384 9,260 5,355 4,684 6,043 14,266 16,102 10,939 7,961 6,724 8,936
Hurricane Sale_S 7,474 623 623 623 623 623 623 623 623 623 623 623 623
Total Long Term Firm Sales 8,020,951 718,356 649,476 710,184 573,296 430,379 626,225 758,158 701,009 713,652 716,784 681,735 741,698
Short Term Firm Sales
STF Borah_S 0 0 0 0 0 0 0 0 0 0 0 0 0
STF COBS 0 0 0 0 0 0 0 0 0 0 0 0 0
STF Colorado_S 0 0 0 0 0 0 0 0 0 0 0 0 0
STF Four Corners_S 21,354,660 3,522,890 2,974,080 3,095,370 1,977,600 1,958,400 1,977,600 0 0 0 1,971,460 1,905,800 1,971,460
STF Mead_S 0 0 0 0 0 0 0 0 0 0 0 0 0
STF Mid Columbia_S 0 0 0 0 0 0 0 0 0 0 0 0 0
STF Mona_S 7,750,000 1,277,800 1,202,400 1,345,800 338,000 325,000 338,000 0 0 0 985,000 953,000 985,000
STF Palo Verde_S 23,424,050 3,801,450 3,397,800 3,751,050 1,877,100 1,834,950 1,877,100 0 0 0 2,320,550 2,243,500 2,320,550
STF PP-GC S 0 0 0 0 0 0 0 0 0 0 0 0 0
STF Wyoming East_S 0 0 0 0 0 0 0 0 0 0 0 0 0
STF Wyoming North_S 0 0 0 0 0 0 0 0 0 0 0 0 0
Total Short Term Firm Sales 52,528,710 8,602,140 7,574,280 8,192,220 4,192,700 4,118,350 4,192,700 0 0 0 5,277,010 5,102,300 5,277,010
System Balancing Sales
COB-Sale 30,427,339 3,321,041 2,293,355 2,180,958 1,039,510 1,269,402 1,794,325 2,202,105 2,341,634 2,079,633 3,621,494 3,901,647 4,382,234
Four Comers-Sale 42,302,885 3,616,086 2,682,091 1,824,757 2,167,706 1,285,084 2,332,335 6,126,247 5,688,306 5,761,445 3,516,089 3,408,296 3,894,444
Mead-Sale 27,629,244 3,348,249 2,397,171 1,442,945 926,949 1,123,344 1,722,920 2,366,515 3,561,802 3,095,697 2,591,993 2,557,454 2,494,205
Mid Columbia-Sale 34,612,093 4,897,083 2,708,596 981,339 1,039,686 551,854 1,601,827 4,489,554 5,590,328 4,654,937 3,100,223 2,428,095 2,568,571
Mona-Sale 21,211,278 2,080,627 1,218,820 160,368 985,792 1,033,466 1,965,544 2,312,725 2,418,449 5,456,820 1,344,863 1,112,031 1,121,774
NOB-Sale 5,309,085 0 0 71,541 695,008 217,231 90,618 1,093,834 1,576,831 627,172 40,264 76,189 820,397
Palo Verde-Sale 28,708,926 (155,506) (133,364) (146,895) 850,630 979,874 1,252,619 8,421,419 9,324,164 6,125,457 683,077 695,432 812,019
Trapped Energy Sale 101,435 0 0 93,029 0 500 0 0 0 0 0 7,906 0
Total System Balancing Sales 190,302,286 17,107,580 11,166,669 6,608,042 7,705,281 6,460,755 10,760,187 27,012,400 30,501,514 27,801,162 14,898,003 14,187,049 16,093,644
Total Special Sales For Resale 250,851,948 26,428,076 19,390,425 15,510,447 12,471,277 11,009,484 15,579,112 27,770,557 31,202,522 28,514,815 20,891,797 19,971,084 22,112,352
Purchased Power&Net Interchange
Long Term Firm Solar Purchases
SR Cove Mountain_P 3,863,928 185,318 194,698 339,380 369,457 425,244 457,334 443,628 419,764 359,961 289,769 208,202 171,172
SR Cove Mountain 11_P 343,571 28,534 28,675 28,713 28,701 28,534 28,701 28,624 28,624 28,609 28,624 28,609 28,624
SR_Hunter_P 7,122,377 374,917 425,032 647,514 675,791 770,602 797,428 758,093 712,634 664,479 567,050 402,182 326,655
SR_Milford_P 7,081,167 358,636 412,994 609,192 677,611 796,634 839,927 747,990 720,079 671,702 541,718 394,119 310,565
SR_Milican_P 2,668,657 90,574 138,221 204,961 257,983 306,198 333,291 375,334 331,655 266,914 174,771 111,940 76,815
SR Old Mill_P 831,936 26,484 46,325 52,432 79,715 99,415 118,812 111,013 94,492 83,002 59,410 33,957 26,880
SR_Pavantlll_P 2,686,563 111,395 134,597 228,283 257,419 312,381 326,190 313,964 299,310 261,828 215,287 136,955 88,955
SR_Prineville_P 1,772,986 60,175 91,830 136,171 171,397 203,430 221,430 249,362 220,343 177,331 116,113 74,370 51,034
SR_Sigurd_P 2,905,614 0 0 0 0 0 23,671 660,236 605,233 565,052 458,516 322,228 270,678
Total Long Term Firm Solar Purchases 29,276,799 1,236,034 1,472,372 2,246,646 2,518,075 2,942,439 3,146,785 3,688,242 3,432,133 3,078,876 2,451,256 1,712,562 1,351,377
Long Term Firm Wind Purchases
WD_Cedar Springs_P 11,723,272 1,348,848 1,095,201 1,032,244 1,016,035 830,825 743,881 742,782 585,990 827,498 1,090,534 1,068,343 1,341,093
WD_Cedar Springs lll_P 8,908,094 1,025,293 832,068 784,236 772,111 631,271 565,347 564,366 445,199 628,829 828,668 811,823 1,018,881
WD_Combine Hills_P 5,369,070 372,722 451,621 547,613 547,338 465,613 400,323 451,806 378,748 357,771 372,201 456,360 566,954
WD_Rock River_P 3,978,379 647,624 502,957 528,679 435,960 284,843 262,622 181,185 193,222 262,771 490,382 188,135 0
WD_Three Buttes_P 20,662,793 2,790,662 1,806,920 2,135,555 1,618,738 1,425,615 1,202,984 807,053 950,560 1,186,425 1,734,559 2,352,374 2,651,346
WD_Top of the WOrid_P 40,686,139 5,436,528 3,612,747 4,244,159 3,270,671 2,907,362 2,399,809 1,720,419 1,872,120 2,296,835 3,513,194 4,491,633 4,920,662
WD_Wolverine Creek_P 10,259,067 760,539 888,634 1,132,687 1,040,512 787,597 844,716 669,522 637,856 752,718 827,853 962,861 953,572
Total Long Term Firm Wind Purchases 101,586,814 12,382,216 9,190,148 10,405,173 8,701,365 7,333,126 6,419,682 5,137,134 5,063,696 6,312,848 8,857,391 10,331,529 11,452,507

Rocky Mountain Power
Exhibit No.24 Page 2 of 4
Case No. PAC-E-24-04
Witness:Ramon J.Mitchell
Long Term Finn Hydro Purchases
Douglas-Wells_P 0 0 0 0 0 0 0 0 0 0 0 0 0
Grant Wanapum Dev_P 0 0 0 0 0 0 0 0 0 0 0 0 0
Grant Priest Rapids Dev_P 2,072,011 172,668 172,668 172,668 172,668 172,668 172,668 172,668 172,668 172,668 172,668 172,668 172,668
Grant Reasonable_P 0 0 0 0 0 0 0 0 0 0 0 0 0
Meaningful Priority_P 25,591,632 2,132,636 2,132,636 2,132,636 2,132,636 2,132,636 2,132,636 2,132,636 2,132,636 2,132,636 2,132,636 2,132,636 2,132,636
Total Long Term Firm Hydro Purchases 27,663,643 2,305,304 2,305,304 2,305,304 2,305,304 2,305,304 2,305,304 2,305,304 2,305,304 2,305,304 2,305,304 2,305,304 2,305,304
Long Term Finn Other Purchases
APS Supp Coal_P 0 0 0 0 0 0 0 0 0 0 0 0 0
APS Supp Other_P 0 0 0 0 0 0 0 0 0 0 0 0 0
Deseret Purchase_P 33,411,787 2,792,683 2,843,537 2,655,766 2,590,568 2,513,634 2,552,753 2,979,150 2,979,150 2,947,854 2,946,550 2,674,022 2,936,119
CoolKeeper Reserve_P 0 0 0 0 0 0 0 0 0 0 0 0 0
Eagle Mountain-UAMPS1626656_P 546,803 16,316 15,456 17,263 17,566 16,566 68,739 118,561 120,073 82,257 0 35,667 38,341
Eagle Mountain-UAMPS1626657_P 2,068,850 140,576 125,592 108,610 111,251 137,604 215,863 318,185 287,362 158,816 156,349 118,011 190,629
Gemstate Purchase P 1,717,824 143,152 143,152 143,152 143,152 143,152 143,152 143,152 143,152 143,152 143,152 143,152 143,152
Hurricane Purchase_P 165,480 13,790 13,790 13,790 13,790 13,790 13,790 13,790 13,790 13,790 13,790 13,790 13,790
MacCorp Buylhru_P 0 0 0 0 0 0 0 0 0 0 0 0 0
MagCorp Reserves_P 4,828,040 401,000 392,980 401,000 409,020 401,000 409,020 413,030 392,980 388,970 372,930 433,080 413,030
Monsanto Buylhru_P 0 0 0 0 0 0 0 0 0 0 0 0 0
Monsanto Reserves_P 20,000,000 1,666,667 1,666,667 1,666,667 1,666,667 1,666,667 1,666,667 1,666,667 1,666,667 1,666,667 1,666,667 1,666,667 1,666,667
Nucor Reserve_P 7,129,800 594,150 594,150 594,150 594,150 594,150 594,150 594,150 594,150 594,150 594,150 594,150 594,150
PGE Cove Replacement_P 154,785 12,899 12,899 12,899 12,899 12,899 12,899 12,899 12,899 12,899 12,899 12,899 12,899
Small East Purchase P 14,288 1,173 1,213 1,172 1,172 1,233 1,203 1,226 1,202 1,153 1,157 1,209 1,176
GEO_Soda Lake_P 8,293,091 822,675 726,731 767,167 706,207 682,902 572,441 516,487 545,410 595,644 725,349 782,467 849,611
Biomass One_NonGen_P (1,241,584) 0 0 0 0 (626,892) (614,693) 0 0 0 0 0 0
Total Long Term Firm Other Purchases 77,089,163 6,605,080 6,536,166 6,381,635 6,266,441 5,556,705 5,635,983 6,777,296 6,756,835 6,605,352 6,632,993 6,475,113 6,859,562
Total Long Term Firm Purchases 235,616,418 22,528,634 19,503,990 21,338,758 19,791,185 18,137,574 17,507,754 17,907,976 17,557,967 18,302,379 20,246,944 20,824,508 21,968,750
Solar Qualifying Facilities
SIR Oregon CO Post-MSP_OF 2,300,677 77,816 111,034 162,715 227,354 268,324 306,338 316,611 288,014 228,682 160,007 82,963 70,817
SIR Oregon WM Post-MSP_OF 18,241,080 616,969 880,342 1,290,101 1,802,595 2,127,430 2,428,826 2,510,274 2,283,543 1,813,121 1,268,624 657,777 561,480
SIR Utah Post-MSP_OF 10,247,886 698,791 728,593 879,205 912,885 993,150 1,011,417 961,497 945,082 895,465 834,750 721,194 665,857
SIR_Chiloquin_OR_OF 0 0 0 0 0 0 0 0 0 0 0 0 0
SIR Enterprise I_UT_OF 12,563,620 617,060 756,869 980,643 1,117,040 1,257,239 1,382,201 1,554,604 1,501,679 1,181,692 958,192 710,651 545,749
SR_Escalante I_UT_OF 11,601,699 565,497 685,083 883,730 1,015,842 1,191,042 1,306,249 1,436,464 1,391,658 1,094,914 874,325 648,325 508,570
SR_Escalante 11_UT_OF 10,921,956 531,489 645,513 832,363 955,501 1,126,570 1,235,899 1,359,761 1,304,267 1,031,738 818,253 606,453 474,150
SR_Escalante III_UT_OF 10,520,814 517,551 627,998 806,130 929,680 1,098,976 1,206,562 1,321,201 1,268,973 1,003,181 750,478 555,442 434,642
SIR Glen Canyon A_UT_OF 0 0 0 0 0 0 0 0 0 0 0 0 0
SIR Glen Canyon B_UT_OF 0 0 0 0 0 0 0 0 0 0 0 0 0
SIR Granite Mountain East_UT_OF 10,913,762 548,826 618,770 895,200 990,553 1,158,652 1,258,453 1,338,832 1,261,327 978,568 810,799 585,874 467,909
SIR Granite Mountain West_UT_QF 7,220,476 363,517 409,549 593,814 657,018 766,608 830,757 887,222 834,460 645,109 536,218 387,167 309,035
SR_Imn Springs_UT_OF 11,200,375 634,276 666,108 897,183 1,017,894 1,130,821 1,283,101 1,346,598 1,318,720 1,006,219 817,161 582,281 500,011
SIR_Pavant_UT_OF 5,611,810 208,301 240,534 410,490 470,172 563,656 662,527 772,098 721,479 602,883 450,433 279,646 229,591
SR_Pavant 11_UT_OF 4,310,018 177,389 225,178 346,901 399,214 454,357 476,933 558,197 543,942 425,102 330,218 205,953 166,635
SIR Red Hills_UT_OF 11,565,267 484,032 621,327 787,699 1,034,403 1,204,545 1,240,487 1,530,453 1,463,983 1,326,490 812,004 594,449 465,395
SIR Sage I_WY_OF 2,270,456 80,679 79,891 190,158 206,003 234,995 262,709 337,883 333,611 208,547 155,711 104,870 75,399
SIR Sage 11_WY_OF 2,272,891 80,764 79,986 190,360 206,223 235,208 263,006 338,244 333,977 208,784 155,870 105,000 75,469
SIR Sage III_WY_OF 1,870,483 68,007 66,563 157,053 167,907 192,623 214,874 275,731 272,050 172,117 130,624 88,886 64,050
SR_Sweetwater_WY_OF 7,797,372 259,240 374,746 567,021 689,492 814,365 985,566 1,121,978 1,038,739 815,928 628,052 300,112 202,134
SIR Three Peaks_UT_OF 8,452,877 411,976 477,957 625,721 834,509 860,254 911,132 1,042,847 998,463 794,907 672,624 450,021 372,466
SR Tumbleweed OR OF 0 0 0 0 0 0 0 0 0 0 0 0 0
Total Solar Qualifying Facilities 149,883,520 6,942,181 8,296,040 11,496,488 13,634,285 15,678,816 17,267,036 19,010,493 18,103,968 14,433,446 11,164,343 7,667,064 6,189,359
Wind Qualifying Facilities
WD Oregon Post-MSP_OF 7,200,085 516,989 469,240 690,448 782,327 721,027 775,598 684,669 652,282 479,718 462,384 467,492 497,910
WD Chopin_OR_OF 0 0 0 0 0 0 0 0 0 0 0 0 0
WD Five Pine_ID_OF 8,399,980 515,184 843,295 749,871 802,886 485,844 529,260 630,392 591,216 751,568 738,975 881,157 880,333
WD Laligo Wind Park_UT_OF 9,672,433 1,007,976 917,725 1,119,717 895,550 857,781 745,592 682,684 563,374 621,378 790,071 708,277 762,309
WD Monticello UT OF 0 0 0 0 0 0 0 0 0 0 0 0 0
WD Mountain Wind 1_WY_OF 8,916,081 1,397,706 1,044,898 869,816 693,033 479,607 498,327 410,860 440,933 454,827 672,574 927,984 1,025,516
WD Mountain Wind 2_WY_OF 13,895,032 2,038,486 1,566,199 1,352,529 1,078,715 750,862 890,296 761,456 734,168 757,712 1,009,556 1,435,298 1,519,756
WD North Point_ID_OF 18,786,578 1,081,867 1,817,410 1,672,825 1,801,611 1,084,057 1,202,040 1,464,552 1,465,393 1,786,186 1,717,960 1,871,544 1,821,134
WD Oregon Wind Farm OR OF 12,468,786 729,862 971,741 1,115,635 1,312,367 1,260,504 1,201,740 1,261,215 1,114,408 919,425 735,728 801,715 1,044,447
WD Orem Family_OR_OF 0 0 0 0 0 0 0 0 0 0 0 0 0
WD Pioneer Wind Park I_WY_OF 10,639,652 1,303,917 924,898 1,187,446 905,027 704,142 650,577 649,784 680,906 450,437 820,675 1,263,591 1,098,250
WD Power County North_ID_OF 5,460,338 415,705 548,470 525,350 519,896 350,949 344,576 370,353 360,111 380,493 511,430 530,622 602,381
WD Power County South_ID_OF 4,865,045 367,049 482,868 474,030 482,998 302,559 306,289 327,761 335,462 336,896 447,464 479,427 522,240
WD Spanish Fork 2 UT OF 2,754,893 217,428 177,317 204,533 160,625 154,092 210,748 289,637 315,766 271,043 242,506 250,579 260,620
WD_Threemile Canyon_OR OF 0 0 0 0 0 0 0 0 0 0 0 0 0
Total Wind Qualifying Facilities 103,058,904 9,592,169 9,764,061 9,962,201 9,435,034 7,151,426 7,355,043 7,533,363 7,254,020 7,209,682 8,149,323 9,617,687 10,034,896

Rocky Mountain Power
Exhibit No.24 Page 3 of 4
Case No. PAC-E-24-04
Witness:Ramon J.Mitchell
Other Qualifying Facilities
California Pre Merger Pre-MSP_OF 981,258 91,344 121,650 139,635 189,175 178,961 121,479 40,661 13,623 9,962 9,370 16,818 48,582
California Post Merger Pre-MSP_OF 29,542 3,186 3,043 3,025 3,083 2,638 2,325 2,638 1,854 1,693 1,436 2,505 2,115
California Post Merger Post-MSP_OF 1,456,200 121,787 112,517 125,199 121,035 121,787 121,035 123,545 123,545 119,277 123,545 119,381 123,545
Idaho Pre Merger Pre-MSP_OF 4,958,064 344,783 308,524 392,179 443,898 588,668 585,708 527,676 348,862 344,348 322,121 383,309 367,989
Idaho Post Merger Pre-MSP_OF 120,952 5,666 5,917 13,514 18,531 11,795 14,462 13,405 9,064 7,353 6,781 8,797 5,666
Idaho Post Merger Post-MSP_OF 2,751,508 236,038 225,933 210,794 199,697 178,158 184,294 244,859 239,987 239,726 237,899 233,686 320,438
Oregon Pre Merger Pre-MSP_OF 8,408,916 714,509 661,242 742,175 851,029 849,743 758,373 666,101 666,393 721,883 572,965 533,515 670,985
Oregon Post Merger Pre-MSP_OF 584,796 47,831 41,135 61,541 100,349 97,645 84,416 31,946 18,992 18,727 12,349 27,155 42,711
Oregon Post Merger Post-MSP_OF 14,109,749 984,473 954,895 1,131,155 1,282,452 1,414,223 1,352,006 1,349,990 1,346,342 1,301,636 1,121,534 903,321 967,723
Utah N Post Merger Post-MSP_OF 632,177 46,396 49,136 55,415 53,863 62,149 61,998 48,793 55,340 48,604 50,933 53,978 45,574
Utah S Post Merger Post-MSP_OF 632,177 46,396 49,136 55,415 53,863 62,149 61,998 48,793 55,340 48,604 50,933 53,978 45,574
Washington Post Merger Post-MSP_OF 218,736 0 0 19 8,001 21,996 37,135 51,373 52,945 35,398 11,871 0 0
Wyoming Pre Merger Pre-MSP_OF 0 0 0 0 0 0 0 0 0 0 0 0 0
Wyoming Post Merger Pre-MSP_OF 0 0 0 0 0 0 0 0 0 0 0 0 0
Wyoming Post Merger Post-MSP_OF 86,184 10,091 8,471 10,115 6,257 4,967 2,992 8,382 7,360 4,207 5,944 6,878 10,520
Biomass One_OR_OF 16,515,565 1,240,650 1,202,754 1,328,737 1,605,809 1,642,614 1,605,809 1,455,965 1,407,485 1,392,619 1,454,920 1,426,918 751,284
DCFP_OR_OF 117,193 3,577 4,372 3,513 2,866 3,059 4,880 19,721 22,137 26,416 12,083 7,259 7,311
Roseburg Dillard_CA_OF 982,171 43,523 50,277 26,541 102,556 104,709 88,024 164,486 131,434 66,115 76,189 75,916 52,401
Sunnyside Base_LIT_OF 25,446,689 1,926,944 1,794,251 2,230,743 1,509,783 2,271,849 2,278,852 2,438,937 2,404,628 2,262,028 1,952,501 2,278,541 2,097,630
Sunnyside Additional_UT_OF 5,496,514 411,090 388,623 462,527 451,598 469,488 470,673 497,779 491,970 467,826 474,327 470,621 439,990
Tesoro_UT_QF 296,096 46,096 34,206 27,450 19,189 25,292 6,946 13,491 20,976 19,011 19,842 20,127 43,471
Total Other Qualifying Facilities 83,824,486 6,324,381 6,016,080 7,019,693 7,023,032 8,111,890 7,843,402 7,748,542 7,418,278 7,135,433 6,517,542 6,622,704 6,043,510
Total Qualifying Facilities 336,766,909 22,858,731 24,076,181 28,478,382 30,092,352 30,942,132 32,465,481 34,292,398 32,776,265 28,778,562 25,831,208 23,907,454 22,267,764
Exchanges
APS Exchange In-PPGC_P 0 0 0 0 0 0 0 0 0 0 0 0 0
APS Exchange In-FC_P 0 0 0 0 0 0 0 0 0 0 0 0 0
APS Exchange Out-PPGC_P 0 0 0 0 0 0 0 0 0 0 0 0 0
APS Exchange Out-FC_P 0 0 0 0 0 0 0 0 0 0 0 0 0
PSCol Exchange ln_P 5,400,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000
PSCol Exchange Out_P 0 0 0 0 0 0 0 0 0 0 0 0 0
WD SCL State Line Generation_P 0 0 0 0 0 0 0 0 0 0 0 0 0
SCL-Staleline DeWery_P 0 0 0 0 0 0 0 0 0 0 0 0 0
SCL-Staleline Losses_P 0 0 0 0 0 0 0 0 0 0 0 0 0
SCL-Staleline Reserves P 0 0 0 0 0 0 0 0 0 0 0 0 0
Total Exchanges 5,400,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000
Short Term Firm Purchases
STF Borah_P 0 0 0 0 0 0 0 0 0 0 0 0 0
STF COB_P 0 0 0 0 0 0 0 0 0 0 0 0 0
STF Colorado_P 0 0 0 0 0 0 0 0 0 0 0 0 0
STF Four Corners_P 0 0 0 0 0 0 0 0 0 0 0 0 0
STF Mead_P 0 0 0 0 0 0 0 0 0 0 0 0 0
STF Mid Columbia_P 14,768,640 1,621,000 1,556,160 1,750,680 0 0 1,216,800 2,912,000 2,912,000 2,800,000 0 0 0
STF Mona_P 0 0 0 0 0 0 0 0 0 0 0 0 0
STF Palo Verde_P 678,500 247,250 207,000 224,250 0 0 0 0 0 0 0 0 0
STF PP-GC P 0 0 0 0 0 0 0 0 0 0 0 0 0
STF Wyoming Easl_P 0 0 0 0 0 0 0 0 0 0 0 0 0
STF Wyoming North_P 0 0 0 0 0 0 0 0 0 0 0 0 0
Total Short Term Firm Purchases 15,447,140 1,868,250 1,763,160 1,974,930 0 0 1,216,800 2,912,000 2,912,000 2,800,000 0 0 0
System Balancing Purchases
COB 13,650,632 256,796 176,618 1,541,659 766,329 2,532,784 1,598,378 1,986,504 1,277,522 563,293 831,396 743,288 1,376,064
Four Corners 18,532,479 1,765,251 2,892,183 4,051,845 1,279,491 1,076,258 217,643 872,158 676,196 352,326 1,379,366 1,484,561 2,485,201
Mead 5,635,494 365,486 777,555 348,436 294,096 456,275 412,248 894,509 413,420 443,981 380,806 169,957 678,726
Mid Columbia 69,840,592 2,961,318 1,414,822 962,531 2,238,265 13,451,364 12,840,011 13,022,595 13,900,634 3,546,501 2,252,822 1,434,611 1,815,117
Mona 8,736,656 1,083,486 690,394 803,185 562,467 661,458 92,264 866,660 493,322 346,124 1,016,204 1,190,417 930,675
NOB 11,488,657 0 0 136,696 1,682,517 313,457 156,723 2,190,741 3,482,419 1,332,912 63,056 193,975 1,936,162
Palo Verde 2,469,641 675,237 564,123 515,725 79,395 79,395 79,395 79,395 79,395 79,395 79,395 79,395 79,395
Emergency Purchases 1,933,211 0 0 0 59,583 775,436 72,286 473,946 47,070 354,072 67,489 16,636 66,692
EIM Imports/Exports (59,250,810) (3,445,870) (3,105,010) (6,863,178) (6,863,641) (7,467,599) (3,035,622) (7,434,719) (7,740,230) (4,243,730) (2,826,239) (2,722,603) (3,502,369)
Total System Balancing Purchases 73,036,553 3,661,704 3,410,686 1,496,900 98,501 11,878,828 12,433,327 12,951,790 12,629,748 2,774,875 3,244,295 2,590,237 5,865,663
Total Purchase Expenses 666,267,021 51,367,319 49,204,017 53,738,969 50,432,038 61,408,533 64,073,362 68,514,163 66,325,980 53,105,815 49,772,447 47,772,200 50,552,178
Wheeling Expenses
Wheeling Expenses-East 23,995,497 2,219,922 2,390.245 2,269,358 2,207,351 1,635,627 1,914,090 1,728,308 1,692,073 2,055,323 1,763,481 2,190,283 1,929,437
Wheeling Expenses-West 116,275,997 9,811,383 9,417,188 9,833,558 9,701,806 8,965,309 9,514,241 9,218,342 9,372,759 9,720,813 9,853,080 10,010,925 10,856,596
Total Wheeling Expenses 140,271,494 12,031,304 11,807,432 12,102,916 11,909,157 10,600,935 11,428,331 10,946,650 11,064,831 11,776,136 11,616,561 12,201,208 12,786,032

Rocky Mountain Power
Exhibit No.24 Page 4 of 4
Case No. PAC-E-24-04
Witness:Ramon J.Mitchell
Coal Fuel Costs
Cholla 4 0 0 0 0 0 0 0 0 0 0 0 0 0
Colstrip 3 6,743,536 '24,525 460,344 505,129 577,625 380,624 579,040 685,894 730,984 620,364 444,777 340,907 693,325
Colstrip 4 7,257,302 709,552 447,732 502,498 610,693 322,258 514,926 794,727 836,314 681,105 440,641 651,044 745,813
Craig 1 8,763,907 824,967 622,614 691,539 747,355 293,600 627,907 824,252 858,234 788,247 797,021 756,402 931,770
Craig 2 9,161,302 873,615 708,999 791,182 670,943 408,898 732,671 702,234 890,943 845,996 854,299 820,614 860,910
Dave Johnston 1 8,434,015 730,346 705,893 775,742 708,441 775,808 716,878 743,263 776,284 278,650 778,026 705,531 739,154
Dave Johnston 2 7,754,005 709,832 722,008 793,552 587,225 533,917 430,615 661,715 652,029 651,369 808,199 688,034 515,510
Dave Johnston 3 15,400,725 1,637,875 1,442,794 619,873 1,072,752 1,537,518 863,880 1,215,356 1,400,568 1,450,972 1,516,502 1,244,365 1,398,272
Dave Johnston 23,843,984 2,298,785 2,228,426 2,430,399 1,678,943 1,618,128 2,189,781 1,964,259 2,207,277 2,170,358 1,923,463 1,172,154 1,962,012
Hayden 1 6,518,462 572,263 473,256 539,817 527,516 621,051 565,885 626,932 549,133 335,977 508,879 603,705 594,048
Hayden 2 4,353,641 362,981 276,043 319,885 388,815 502,406 428,546 432,920 343,132 265,390 256,070 343,396 434,056
Hunter 41,173,406 3,921,773 2,967,374 1,687,380 2,658,292 2,726,535 3,616,013 3,963,715 4,057,193 3,716,762 3,976,571 3,805,619 4,076,179
Hunter 26,065,012 2,875,507 2,130,482 2,129,285 1,385,982 1,852,422 2,193,159 2,482,615 1,816,154 2,040,061 2,073,104 2,584,924 2,501,317
Hunter 50,561,913 4,782,836 3,631,652 3,670,041 2,350,165 3,943,947 4,171,685 4,735,171 5,074,824 4,417,382 4,436,911 4,702,258 4,645,042
Huntington 1 60,145,415 5,457,542 3,979,840 3,943,189 4,991,971 3,989,142 4,395,989 6,433,773 6,127,715 4,468,420 5,220,835 4,901,357 6,235,641
Huntington 2 43,390,630 3,929,290 2,084,775 2,489,016 3,159,220 2,572,348 2,930,819 4,826,207 5,397,127 4,065,968 1,907,699 4,246,904 5,781,257
Jim Bridger1 44,451,387 2,984,935 2,618,409 2,894,337 3,781,950 1,887,600 2,781,931 5,563,463 5,610,212 4,748,675 3,814,928 4,309,198 3,455,750
Jim Bridger2 48,519,097 3,581,861 3,031,949 3,194,427 2,376,725 2,925,493 3,719,856 5,817,880 5,208,470 5,028,788 4,904,166 4,318,646 4,410,836
Jim Bridger3 38,769,170 2,568,113 2,108,772 2,558,268 3,387,973 2,487,063 3,303,153 4,537,483 5,111,074 4,069,382 2,515,083 3,165,380 2,957,427
Jim Bridger4 35,126,601 2,819,482 2,260,864 2,640,948 2,947,085 2,444,086 2,613,908 4,508,884 4,281,763 2,022,148 2,338,833 2,967,531 3,281,069
Naughton 1 328:1448 3,159,592 2,735,409 2,816,577 2,610,445 1,778,745 2,646,754 2,908,541 2,922,312 2,992,532 2,995,208 2,413,914 2,881,418
Naughton 2 44:99:355 4,267,375 3,608,743 3,623,729 3,836,804 3,501,728 3,440,209 3,759,965 3,935,783 3,716,798 4,053,936 3,878,647 3,365,638
Wyodak 29,331,659 2,665,998 2,596,607 2,858,330 2,549,670 2,837,949 2,204,888 2,706,063 2,551,464 2,386,598 2,416,783 2,007,256 1,550,053
Total Coal Fuel Costs 593,615,974 52,459,045 41,842,983 42,475,143 43,606,590 39,941,264 45,668,492 60,895,310 61,338,987 51,761,943 48,981,933 50,627,786 64,016,497
Gas Fuel Costs
GS_Chehalis 39,191,777 5,601,806 6,850,667 5,000,964 399,342 0 526,745 3,952,845 3,842,001 3,053,599 3,995,823 1,442,305 4,525,679
GS_Currant Creek 43,149,230 3,945,536 5,068,986 3,965,335 2,567,360 527,000 2,866,258 5,005,347 3,611,548 3,760,304 2,560,237 4,822,141 4,449,178
GS_Currant Creek DF 2,618,880 246,907 302,755 237,606 151,756 33,290 155,738 310,092 217,979 206,945 159,648 290,171 305,993
GS_Gadsby 1 1,500,904 113,808 138,029 123,398 38,707 21,139 77,313 302,329 261,884 132,164 74,250 74,174 143,708
GS_Gadsby2 1,544,554 106,788 111,251 105,308 60,446 63,419 96,089 273,185 250,801 141,443 78,103 97,828 159,893
GS_Gadsby 3 2501997 242,267 270,207 243,593 79,156 91,727 153,064 321,208 322,474 192,552 121,909 170,161 293,680
GS_Gadsby4 1:227:107 210,235 101,469 0 27,130 2,266 31,215 208,132 218,050 123,748 69,923 68,870 166,067
GS_Gadsby5 1:178,719 210,235 111,616 0 11,696 3,626 29,379 207,518 222,175 118,602 53,455 60,493 149,925
GS_Gadsby6 1280,244 210,235 142,056 0 14,970 0 22,034 215,727 226,455 139,508 61,666 77,286 170,307
GS_Hermiston 1 13,465,460 3,369,204 2,252,593 1,701,740 0 0 0 1,890,465 2,101,904 2,149,553 0 0 0
GS_Hermiston 2 8,258,348 0 0 0 1,300,107 301,995 585,250 0 0 0 1,650,244 1,995,280 2,425,472
GS_Lake Side 1 50,609,195 4,519,987 5,829,564 4,614,648 2,060,159 808,606 3,341,692 5,686,945 5,732,585 5,176,499 4,396,507 4,517,300 3,924,704
GS_Lake Side 1 DF 1,411,980 60,137 0 4,542 56,324 31,645 129,431 282,132 258,791 164,278 111,537 136,720 176,443
GS_Lake Side 2 59,058,338 6,060,646 6,527,223 5,744,565 3,750,550 1,805,471 3,893,581 5,414,014 5,368,840 4,684,680 4,953,688 4,533,242 6,321,837
GS_Lake Side 2 DF 1,917,085 67,549 5,857 30,896 108,461 55,289 121,837 333,354 318,119 197,238 168,692 169,799 339,995
GS_Naughton 3 6,328,837 202,467 160,436 199,615 108,007 168,133 400,542 1,267,035 1,147,091 551,778 433,359 369,884 1,320,489
Total Gas Fuel Costs 235,242,654 25,167,807 27,872,708 21,972,211 10,734,169 3,913,607 12,430,168 25,670,328 24,100,696 20,792,893 18,889,042 18,825,655 24,873,372
Gas Financials
GS_Clay Basin Gas Storage (588,564) (334,019) (307,763) (216,982) 52,242 52,242 52,242 52,242 52,242 52,242 52,242 2,850 (98,348)
GS_Gas Physical-Chehalis 0 0 0 0 0 0 0 0 0 0 0 0 0
GS_Gas Physical-East 84248 26,737 25,270 32,240 0 0 0 0 0 0 0 0 0
GS_Gas Physical-Hermiston (500:971) (105,851) (83,235) (56,541) (25,945) (23,006) (23,393) (50,730) (49,843) (45,141 (37,288) 0 0
GS_Gas Swaps-Chehalis (880,780) (649,915) (319,060) 88,195 0 0 0 0 0 0 0 0 0
GS_Gas Swaps-East (19,056,887) (3,887,012) (2,992,150) (1,327,188) (534,300) (308,760) (399,300) (2,547,968) (2,611,285) (2,249,700) 18,135 (364,800) (1,852,560)
GS_Gas Swaps-Hermiston 0 0 0 0 0 0 0 0 0 0 0 0 0
GS_Pipeline Lateral-Chehalis 601,800 50,150 50,150 50,150 50,150 50,150 50,150 50,150 50,150 50,150 50,150 50,150 50,150
GS_Pipeline Main-Chehalis 10,697,195 891,433 891,433 891,433 891,433 891,433 891,433 891,433 891,433 891,433 891,433 891,433 891,433
GS_Pipe line Lateral-Currant Creek 1,292,395 107,700 107,700 107,700 107,700 107,700 107,700 107,700 107,700 107,700 107,700 107,700 107,700
GS_Pipeline-Hermiston 2,533,944 212,720 204,708 212,720 210,049 212,720 210,049 212,720 212,720 210,049 212,720 210,049 212,720
GS_Pipe line-Kern River Gas 2,989,350 253,890 229,320 253,890 245,700 253,890 245,700 253,890 253,890 245,700 253,890 245,700 253,890
GS_Pipeline-Lake Side 2 5,334,796 444,566 444,566 444,566 444,566 444,566 444,566 444,566 444,566 444,566 444,566 444,566 444,566
GS_Pipe line Lateral-Lake Side 2,353,029 196,086 196,086 196,086 196,086 196,086 196,086 196,086 196,086 196,086 196,086 196,086 196,086
GS_Pipeline-Naughton 2,564,970 213,748 213,748 213,748 213,748 213,748 213,748 213,748 213,748 213,748 213,748 213,748 213,748
GS_Pipe line Reservation Fees 801,834 66,820 66,820 66,820 66,820 66,820 66,820 66,820 66,820 66,820 66,820 66,820 66,820
GS_Pipeline-Southern System Expansion 5,635,526 469,627 469,627 469,627 469,627 469,627 469,627 469,627 469,627 469,627 469,627 469,627 469,627
0
Total Gas Financials 13,861,885 (2,043,321) (802,780) 1,426,463 2,387,876 2,627,215 2,525,428 360,284 297,853 653,279 2,939,828 2,533,928 955,831
Geothermal Fuel Costs
GEO_Blundell 1 3,170,429 309,265 279,336 279,336 280,341 300,637 286,715 271,085 284,381 291,794 272,164 151,321 164,054
GEO_Blundell2 1,381,645 147,909 133,596 133,596 130,074 120,972 104,090 107,501 107,531 117,113 126,023 70,539 82,702
Total Geothermal Fuel Costs 4,552,074 457,175 412,932 412,932 410,415 421,609 390,805 378,586 391,912 408,907 398,186 221,859 246,757
Total Generation Fuel Costs 847,272,587 76,040,705 69,325,843 66,286,749 57,139,050 46,903,696 61,014,893 87,304,507 86,129,448 73,617,022 71,208,989 72,209,228 80,092,456
NPC 1,402,959,155 113,011,252 110,946,867 116,618,187 107,008,968 107,903,680 120,937,475 138,994,763 132,317,737 109,984,159 111,706,200 112,211,552 121,318,315

Case No. PAC-E-24-04
Exhibit No. 25
Witness : Ramon J. Mitchell
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Ramon J. Mitchell
GRID Validation
May 2024

Rocky Mountain Power
Exhibit No.25 Page 1 of 5
Case No. PAC-E-24-04
Witness:Ramon J.Mitchell
PacifiCorp GRID Validation NPC Report
Net Power Cost Analysis
12 months ended December 2021 01121-12121 Jan-21 Feb-21 Mar-21 Apr-21 May-21 Jun-21 Jul-21 Aug-21 Sep-21 Oct-21 Nov-21 Dec-21
Special Sales For Resale
Long Term Firm Sales
Black Hills 7,532,217 735,605 518,304 481,626 474,039 433,303 595,216 737,682 733,885 726,030 643,094 706,458 746,974
Hurricane Sale 7,474 623 623 623 623 623 623 623 623 623 623 623 623
Leaning Juniper Revenue 105,254 7,601 7,384 9,260 5,355 4,684 6,043 14,266 16,102 10,939 7,961 6,724 8,936
Total Long Term Firm Sales 7,644,944 743,829 526,310 491,509 480,016 438,610 601,882 752,571 750,609 737,591 651,677 713,806 756,532
Short Term Firm Sales
COB _ _ _ _ _ _ _ _ _ _ _ _ _
Colorado - - - - - - - - - - - - -
Four Corners 21,354,660 3,522,890 2,974,080 3,095,370 1,977,600 1,958,400 1,977,600 - - - 1,971,460 1,905,800 1,971,460
Idaho - - - - - - - - - - - - -
Mead
Mid Columbia - - - - - - - - - - - - -
Mona 7,750,000 1,277,800 1,202,400 1,345,800 338,000 325,000 338,000 - - - 985,000 953,000 985,000
NOB - - - - - - - - - - - - -
Palo Verde 23,424,050 3,801,450 3,397,800 3,751,050 1,877,100 1,834,950 1,877,100 - - - 2,320,550 2,243,500 2,320,550
SP15 _ _ _ _ _ _ _ _ _ _ _ _ _
Utah
Washington - - - - - - - - - - - - -
West Main - - - - - - - - - - - - -
Wyoming - - - - - - - - - - - -
Electric Swaps Sales - - - - - - - - - - - - -
STF Trading Margin - - - - - - - - - - - - -
STF Index Trades - - - - - - - - - - - - -
Total Short Term Firm Sales 52,528,710 8,602,140 7,574,280 8,192,220 4,192,700 4,118,350 4,192,700 - - - 5,277,010 5,102,300 5,277,010
System Balancing Sales
COB 29,651,914 3,332,735 2,357,695 1,898,661 1,035,907 1,048,019 1,760,434 2,240,054 2,231,577 2,100,152 3,520,890 3,894,654 4,231,137
Four Corners 39,704,708 3,303,662 3,448,953 2,009,392 1,765,495 1,113,323 640,820 6,174,110 5,483,323 5,864,117 3,124,169 3,104,731 3,672,614
Mead 32,132,100 4,416,682 3,016,064 1,456,847 948,624 1,219,709 1,728,477 2,297,774 3,511,400 3,195,582 3,421,497 3,562,410 3,357,034
Mid Columbia 44,001,091 3,786,533 803,610 528,753 2,209,685 1,371,110 2,444,523 6,701,841 7,389,368 7,080,796 4,269,499 4,171,327 3,244,045
Mona 19,491,384 1,825,358 547,950 233,377 784,958 995,043 1,432,010 2,289,681 2,400,963 5,463,776 1,324,799 1,133,092 1,060,377
NOB 6,320,250 - 14,777 588,915 784,080 22,523 47,501 1,252,386 1,907,945 654,601 26,842 11,956 1,008,724
Palo Verde 29,896,139 447,443 (13,689) 18,916 942,147 1,047,494 1,457,472 8,639,102 9,586,551 6,248,536 514,470 363,107 644,590
Trapped Energy 1,403 - - - - - - - - - - 1,403 -
Total System Balancing Sales 201,198,989 17,112,413 10,175,360 6,734,861 8,470,896 6,817,222 9,511,238 29,594,947 32,511,127 30,607,559 16,202,167 16,242,679 17,218,521
Total Special Sales For Resale 261,372,642 26,458,383 18,275,950 15,418,589 13,143,612 11,374,182 14,305,819 30,347,518 33,261,736 31,345,151 22,130,854 22,058,785 23,252,063

Rocky Mountain Power
Exhibit No.25 Page 2 of 5
Case No. PAC-E-24-04
Witness:Ramon J.Mitchell
Purchased Power&Net Interchange
Long Term Firm Purchases
APS Supplemental - - - - - - - - - - - - -
CedarSpdngsWind 11,723,273 1,348,849 1,095,201 1,032,244 1,016,035 830,825 743,881 742,782 585,990 827,498 1,090,534 1,068,343 1,341,093
Cedar Springs Wind III 8,908,095 1,025,294 832,067 784,236 772,110 631,271 565,348 564,366 445,200 628,830 828,668 811,823 1,018,881
Combine Hills Wind 5,369,068 372,723 451,621 547,613 547,338 465,612 400,323 451,804 378,748 357,771 372,201 456,360 566,954
Cove Mountain Solar 3,863,906 185,318 194,698 339,380 369,458 425,244 457,335 443,628 419,763 359,961 289,769 208,202 171,150
Cove Mountain Solar II 343,571 28,534 28,675 28,713 28,701 28,534 28,701 28,624 28,624 28,609 28,624 28,609 28,624
Deseret Purchase 33,416,953 2,792,679 2,843,532 2,655,765 2,590,568 2,494,076 2,584,049 2,979,142 2,979,142 2,947,847 2,946,543 2,667,501 2,936,112
Douglas PUD Settlement - - - - - - - - - - - - -
Eagle Mountain-DAMPS/UMPA 2,615,653 156,892 141,048 125,873 128,817 154,170 284,603 436,745 407,435 241,073 156,349 153,679 228,968
Gemstate 1,717,824 143,152 143,152 143,152 143,152 143,152 143,152 143,152 143,152 143,152 143,152 143,152 143,152
Hunter Solar 7,122,324 374,917 425,031 647,514 675,791 770,602 797,429 758,093 712,635 664,479 567,050 402,182 326,602
Hurricane Purchase 165,480 13,790 13,790 13,790 13,790 13,790 13,790 13,790 13,790 13,790 13,790 13,790 13,790
MagCorp - - - - - - - - - - - - -
MagCorp Reserves 4,828,040 401,000 392,980 401,000 409,020 401,000 409,020 413,030 392,980 388,970 372,930 433,080 413,030
Milican Solar 2,646,179 68,661 138,221 204,961 257,983 306,199 333,290 375,334 331,656 266,914 174,771 111,940 76,250
Milford Solar 7,081,219 358,636 412,994 609,192 677,611 796,634 839,927 747,990 720,080 671,702 541,717 394,020 310,716
Nucor 7,129,800 594,150 594,150 594,150 594,150 594,150 594,150 594,150 594,150 594,150 594,150 594,150 594,150
Old Mill Solar 860,113 27,048 47,956 54,277 82,521 102,914 122,994 114,920 97,817 85,923 61,501 35,152 27,089
Monsanto Reserves 19,999,999 1,666,667 1,666,667 1,666,667 1,666,667 1,666,667 1,666,667 1,666,667 1,666,667 1,666,667 1,666,667 1,666,667 1,666,667
Pavant III Solar 2,693,193 112,247 140,376 230,428 259,149 310,804 322,999 305,697 292,254 260,260 214,705 137,146 107,129
PGE Cove 154,785 12,899 12,899 12,899 12,899 12,899 12,899 12,899 12,899 12,899 12,899 12,899 12,899
Prineville Solar 1,795,505 82,013 91,830 136,171 171,397 203,430 221,430 249,362 220,343 177,331 116,113 74,370 51,717
Rock River Wind 3,949,010 647,624 502,957 528,679 435,960 284,843 262,621 181,185 193,222 262,771 490,382 158,766 -
Sigurd Solar 2,905,571 - - - - - 23,671 660,236 605,234 565,052 458,516 322,228 270,634
Small Purchases east 14,288 1,173 1,213 1,172 1,172 1,233 1,203 1,226 1,202 1,153 1,157 1,209 1,176
Small Purchases west - - - - - - - - - - - - -
Soda Lake Geothermal 8,293,074 822,678 726,727 767,161 706,202 682,900 572,444 516,493 545,404 595,645 725,353 782,463 849,605
Three Buttes Wind 20,662,796 2,790,663 1,806,921 2,135,557 1,618,738 1,425,615 1,202,984 807,052 950,561 1,186,424 1,734,559 2,352,376 2,651,346
Top of the World Wind 40,686,138 5,436,527 3,612,759 4,244,151 3,270,658 2,907,364 2,399,806 1,720,417 1,872,120 2,296,841 3,513,203 4,491,632 4,920,662
Wolverine Creek Wind 10,259,065 760,539 888,633 1,132,686 1,040,512 787,596 844,716 669,522 637,857 752,718 827,852 962,861 953,573
Long Term Firm Purchases Total 209,204,921 20,224,670 17,206,098 19,037,430 17,490,397 16,441,523 15,849,432 15,598,304 15,248,923 15,998,428 17,943,153 18,484,599 19,681,966

Rocky Mountain Power
Exhibit No.25 Page 3 of 5
Case No. PAC-E-24-04
Witness:Ramon J.Mitchell
Qualifying Facilities
OF California 2,467,000 216,317 237,210 267,860 313,293 303,385 244,839 166,844 139,023 130,932 134,351 138,704 174,243
OF Idaho 7,830,524 586,487 540,373 616,487 662,125 778,621 784,464 785,940 597,914 591,427 566,801 625,791 694,093
OF Oregon 50,845,304 2,958,588 3,117,888 4,078,136 5,046,106 5,478,394 5,705,557 5,559,591 5,255,566 4,563,767 3,597,862 2,672,224 2,811,626
OF Utah 11,512,240 791,583 826,865 990,034 1,020,610 1,117,447 1,135,413 1,059,082 1,055,762 992,673 936,615 829,151 757,005
OF Washington 218,736 - - 19 8,001 21,996 37,135 51,373 52,945 35,398 11,871 - -
QF Wyoming 86,184 10,091 8,471 10,115 6,257 4,967 2,992 8,382 7,360 4,207 5,944 6,878 10,520
Biomass One OF 15,273,904 1,240,648 1,202,763 1,328,736 1,605,813 1,011,582 995,142 1,455,970 1,407,489 1,392,627 1,454,930 1,426,922 751,283
Chevron Wind OF - - - - - - - - - - - - -
DCFP OF 117,193 3,577 4,372 3,513 2,866 3,059 4,880 19,721 22,137 26,416 12,083 7,259 7,310
Enterprise Solar I OF 12,563,411 617,060 756,870 980,643 1,117,038 1,257,240 1,382,198 1,554,604 1,501,679 1,181,692 957,986 710,651 545,749
Escalante Solar I QF 11,601,502 565,498 685,084 883,730 1,015,842 1,191,044 1,306,249 1,436,464 1,391,659 1,094,914 874,125 648,324 508,570
Escalante Solar 11 OF 10,921,713 531,489 645,513 832,362 955,502 1,126,572 1,235,898 1,359,761 1,304,268 1,031,738 818,007 606,453 474,150
Escalante Solar III QF 10,520,640 517,551 627,997 806,129 929,679 1,098,975 1,206,563 1,321,201 1,268,974 1,003,181 750,305 555,442 434,642
ExxonMobil OF - - - - - - - - - - - - -
Five Pine Wind OF 8,399,980 515,184 843,295 749,871 802,885 485,845 529,260 630,392 591,216 751,568 738,975 881,157 880,334
Glen Canyon A Solar OF - - - - - - - - - - - - -
Glen Canyon B Solar QF - - - - - - - - - - - - -
GraniteMountainEastSolarQF 10,913,761 548,826 618,770 895,198 990,554 1,158,651 1,258,453 1,338,832 1,261,328 978,568 810,799 585,874 467,909
Granite Mountain West Solar OF 7,220,477 363,517 409,549 593,815 657,017 766,608 830,760 887,222 834,460 645,109 536,218 387,167 309,035
Iron Springs Solar OF 11,200,371 634,276 666,108 897,183 1,017,893 1,130,820 1,283,100 1,346,598 1,318,721 1,006,219 817,161 582,281 500,011
Kennecott Refinery OF - - - - - - - - - - - - -
Kennecott Smelter OF - - - - - - - - - - - - -
Latigo Wind Park QF 9,674,740 1,007,477 917,570 1,126,955 897,120 856,897 745,979 673,722 567,152 616,686 799,252 709,690 756,240
Monticello Wind OF - - - - - - - - - - - - -
Mountain Wind 1 OF 8,916,080 1,397,705 1,044,898 869,816 693,034 479,607 498,327 410,860 440,933 454,827 672,574 927,984 1,025,515
Mountain Wind 2 OF 13,895,033 2,038,485 1,566,199 1,352,529 1,078,715 750,861 890,296 761,455 734,168 757,712 1,009,557 1,435,299 1,519,756
North Point Wind OF 18,786,576 1,081,867 1,817,411 1,672,826 1,801,611 1,084,057 1,202,040 1,464,551 1,465,394 1,786,186 1,717,960 1,871,542 1,821,132
Oregon Wind Farm OF 12,468,790 729,863 971,742 1,115,635 1,312,368 1,260,505 1,201,740 1,261,216 1,114,406 919,426 735,727 801,716 1,044,447
Pavant 11 Solar OF 4,310,019 177,389 225,179 346,901 399,215 454,358 476,933 558,197 543,942 425,101 330,218 205,953 166,635
Pioneer Wind Park I OF 10,639,652 1,303,917 924,899 1,187,446 905,027 704,142 650,577 649,784 680,906 450,438 820,675 1,263,591 1,098,250
Power County North Wind OF 5,460,338 415,705 548,470 525,351 519,896 350,950 344,576 370,353 360,112 380,493 511,430 530,622 602,381
Power County South Wind OF 4,865,045 367,049 482,868 474,030 482,998 302,560 306,289 327,761 335,462 336,896 447,464 479,428 522,241
Roseburg Dillard QF 982,170 43,523 50,277 26,541 102,556 104,709 88,024 164,486 131,433 66,116 76,189 75,916 52,402
Sage I Solar OF 2,270,456 80,679 79,891 190,158 206,003 234,995 262,709 337,883 333,611 208,547 155,711 104,870 75,399
Sage 11 Solar OF 2,272,891 80,764 79,986 190,360 206,223 235,208 263,006 338,244 333,976 208,784 155,870 105,000 75,469
Sage III Solar OF 1,870,483 68,007 66,563 157,054 167,907 192,623 214,874 275,730 272,050 172,117 130,624 88,886 64,050
Spanish Fork Wind 2 OF 2,754,893 217,428 177,317 204,533 160,626 154,092 210,749 289,636 315,766 271,043 242,505 250,579 260,620
Sunnyside OF 30,170,399 2,309,028 2,161,795 2,472,700 2,027,444 2,723,249 2,736,541 2,752,683 2,722,145 2,586,845 2,374,035 2,757,466 2,546,468
Sweetwater Solar OF 7,797,376 259,240 374,746 567,022 689,492 814,366 985,566 1,121,979 1,038,739 815,928 628,052 300,112 202,134
Tesoro OF 298,022 46,182 34,259 27,485 19,215 25,768 7,053 13,571 21,290 19,336 20,203 20,155 43,505
Three Peaks Solar OF 8,452,878 411,976 477,957 625,721 834,509 860,254 911,132 1,042,848 998,463 794,907 672,624 450,022 372,466
Utah Pavant Solar QF 5,611,720 208,301 240,534 410,490 470,172 563,656 662,527 772,097 721,480 602,883 450,433 279,646 229,501
Utah Red Hills Solar OF 11,565,119 484,032 621,327 787,698 1,034,405 1,204,547 1,240,486 1,530,453 1,463,983 1,326,491 812,004 594,449 465,244
Qualifying Facilities Total 334,755,618 22,829,307 24,055,015 28,265,079 30,160,014 30,292,609 31,842,323 34,099,488 32,605,910 28,631,195 25,787,141 23,917,202 22,270,336
Mid-Columbia Contracts
Grant Reasonable - - - - - - - - - - - - -
GrantMeaningfulPriority 25,591,630 2,132,636 2,132,636 2,132,636 2,132,636 2,132,636 2,132,636 2,132,636 2,132,636 2,132,636 2,132,636 2,132,636 2,132,636
Grant Surplus 2,072,011 172,668 172,668 172,668 172,668 172,668 172,668 172,668 172,668 172,668 172,668 172,668 172,668
Grant-Priest Rapids - - - - - - - - - - - - -
Mid-Columbia Contracts Total 27,663,641 2,305,303 2,305,303 2,305,303 2,305,303 2,305,303 2,305,303 2,305,303 2,305,303 2,305,303 2,305,303 2,305,303 2,305,303
Total Long Term Firm Purchases 571,624,179 45,359,280 43,566,416 49,607,813 49,955,714 49,039,435 49,997,058 52,003,095 50,160,136 46,934,926 46,035,597 44,707,103 44,257,606

Rocky Mountain Power
Exhibit No.25 Page 4 of 5
Case No. PAC-E-24-04
Witness:Ramon J.Mitchell
Storage&Exchange
APS Exchange - - - - - - - - - - - - -
Black Hills CTs - - - - - - - - - - - - -
Cowlitz Swift - - - - - - - - - - - - -
PSCo Exchange 5,400,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000
SCL State Line - - - - - - - - - - - - -
Total Storage&Exchange 5,400,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000 450,000
Short Term Firm Purchases
COB _ _ _ _ _ _ _ _ _ _ _ _ _
Colorado - - - - - - - - - - - - -
Four Corners - - - - - - - - - - - - -
Idaho - - - - - - - - - - - - -
Mead _ _ _ _ _ _ _ _ _ _
Mid Columbia 14,768,640 1,621,000 1,556,160 1,750,680 - - 1,216,800 2,912,000 2,912,000 2,800,000 - - -
Mona - - - - - - - - - - - -
NOB _ _ _ _
Palo Verde 678,500 247,250 207,000 224,250 - - - - - - - - -
SP15 _ _ _ _
Utah - - - - - - - - - - - -
Washington - - - - - - - - - - - - -
West Main - - - - - - - - - - - - -
Wyoming
STF purchase subtotal 15,447,140 1,868,250 1,763,160 1,974,930 - - 1,216,800 2,912,000 2,912,000 2,800,000 - - -
STF Electric Swaps - - - - - - - - - - - - -
STF Index Trades - - - - - - - - - - - - -
Total Short Term Firm Purchases 15,447,140 1,868,250 1,763,160 1,974,930 - - 1,216,800 2,912,000 2,912,000 2,800,000 - - -
System Balancing Purchases
COB 14,400,284 285,501 1,261,483 1,663,711 654,627 1,723,681 1,485,126 2,446,485 1,421,069 490,529 859,093 269,382 1,839,598
Four Corners 28,429,398 2,842,587 6,364,713 5,884,089 1,787,296 1,633,184 309,859 982,553 851,816 639,118 1,206,644 1,623,407 4,304,131
Mead 6,543,189 387,353 928,141 318,456 278,541 379,237 379,454 940,549 439,285 462,393 719,567 378,270 931,941
Mid Columbia 74,407,799 3,915,594 800,844 526,045 1,576,329 12,539,935 10,932,812 16,028,724 15,750,997 4,701,338 2,559,815 2,096,022 2,979,345
Mona 8,713,073 947,711 193,196 1,362,896 221,788 747,258 66,919 835,818 503,604 356,076 1,169,571 1,267,020 1,041,216
NOB 13,555,306 - 54,296 839,002 1,593,155 47,602 126,782 2,608,241 4,164,455 1,515,362 44,561 30,185 2,531,664
Palo Verde 3,291,208 1,912,292 661,767 450,253 9,223 39,536 - - 2,543 8,368 40,836 155,432 10,958
EIM Imports/Exports (59,250,810) (3,445,870) (3,105,010) (6,863,178) (6,863,641) (7,467,599) (3,035,622) (7,434,719) (7,740,230) (4,243,730) (2,826,239) (2,722,603) (3,502,369)
Emergency Purchases 1,904,827 - - - 59,287 773,282 72,269 451,177 44,688 354,008 67,468 16,629 66,017
Total System Balancing Purchases 91,994,275 6,845,168 7,159,431 4,181,275 (683,394) 10,416,116 10,337,600 16,858,829 15,438,227 4,283,462 3,841,317 3,113,745 10,202,500
Total Purchased Power&Net Inter, 684,465,594 54,522,699 52,939,007 56,214,017 49,722,320 59,905,551 62,001,457 72,223,924 68,960,363 54,468,388 50,326,914 48,270,848 54,910,106

Rocky Mountain Power
Exhibit No.25 Page 5 of 5
Case No. PAC-E-24-04
Witness:Ramon J.Mitchell
Wheeling&U.of F.Expense
Firm Wheeling 138,233,270 11,846,758 11,639,521 11,941,445 11,705,073 10,378,573 11,220,154 10,774,214 10,929,786 11,622,523 11,445,797 12,073,700 12,655,725
C&T EIM Admin fee 2,038,227 184,546 167,911 161,471 204,085 222,363 208,177 172,436 135,045 153,613 170,764 127,508 130,308
ST Firm&Non-Firm 43,029 13,235 3,760 3,011 434 - 1,277 4,049 2,190 1,585 2,870 7,203 3,415
Total Wheeling&U.of F.Expense 140,314,526 12,044,539 11,811,193 12,105,927 11,909,592 10,600,936 11,429,608 10,950,699 11,067,022 11,777,721 11,619,431 12,208,412 12,789,447
Coal Fuel Burn Expense
Cholla - - - - - - - - - - - - -
Colstrip 15,944,066 1,758,488 1,502,306 1,491,743 1,294,454 719,529 1,130,158 1,544,746 1,651,646 1,436,935 951,206 1,010,123 1,452,732
Craig 19,150,970 1,915,459 1,662,106 1,728,134 1,467,240 701,480 1,373,402 1,586,878 1,847,263 1,720,488 1,695,960 1,624,924 1,827,637
Dave Johnston 55,761,755 5,545,315 5,097,111 4,666,077 3,972,961 4,406,396 4,179,117 4,600,831 5,049,983 4,544,176 5,008,160 3,899,963 4,791,664
Hayden 11,314,790 1,092,517 971,852 996,901 891,991 1,119,222 980,957 1,054,345 890,611 583,886 745,023 962,052 1,025,432
Hunter 119,361,523 11,752,962 9,868,586 8,782,962 6,001,455 7,541,139 9,746,152 11,280,364 11,214,492 10,620,817 10,346,073 11,107,035 11,099,486
Huntington 99,922,532 9,902,243 8,280,046 7,685,095 7,137,019 5,729,828 6,704,581 10,577,674 10,714,065 7,672,838 6,652,417 8,067,526 10,799,200
Jim Bridger 160,568,885 10,891,597 11,572,897 12,951,734 11,209,268 8,629,348 10,713,340 21,122,415 20,810,479 14,798,137 11,635,424 13,336,149 12,898,097
Naughton 75,457,447 7,037,257 6,059,344 6,209,946 5,907,535 4,795,131 5,900,533 6,659,412 6,855,070 6,691,583 6,915,264 6,264,483 6,161,889
Wyodak 29,019,449 2,571,408 2,513,652 2,811,880 2,503,324 2,778,487 2,190,116 2,725,396 2,562,642 2,392,560 2,402,957 2,007,981 1,559,048
Total Coal Fuel Burn Expense 586,501,418 52,467,246 47,527,899 47,324,471 40,385,246 36,420,561 42,918,356 61,152,062 61,596,250 50,461,421 46,352,485 48,280,236 51,615,184
Gas Fuel Burn Expense
Chehalis 38,103,671 2,474,830 1,122,065 1,924,565 2,320,703 20,136 1,745,829 4,774,064 4,709,339 4,661,488 5,007,935 4,525,362 4,817,356
Currant Creek 36,936,636 2,483,854 453,011 132,129 2,689,159 1,529,496 3,400,255 4,743,362 3,618,956 3,968,192 4,557,262 4,945,180 4,415,780
Gadsby 5,491,715 35,942 50,150 123,858 150,209 174,358 456,732 1,067,946 1,075,590 711,177 409,440 460,218 776,095
Gadsby CT 2,787,073 29,777 3,274 5,485 72,169 69,796 139,815 522,811 511,036 277,374 230,875 235,501 689,160
Hermiston 22,167,592 2,345,965 1,350,019 1,282,104 1,844,660 8,533 869,383 2,327,739 2,463,347 2,398,513 2,294,975 2,401,167 2,581,189
Lake Side 1 54,900,622 5,103,037 3,688,461 2,687,692 4,180,292 2,382,044 4,198,764 5,870,751 5,853,992 5,353,046 4,549,555 5,320,139 5,712,850
Lake Side 2 63,220,546 6,524,249 4,749,373 3,899,626 4,119,433 3,713,927 4,787,196 5,935,265 5,954,663 5,608,375 5,437,945 5,486,567 7,003,926
Naughton-Gas 20,317,381 2,531,859 2,433,992 1,963,691 593,083 1,074,098 1,226,797 1,988,607 1,826,395 1,191,663 1,313,676 1,403,712 2,769,808
Total Gas Fuel Bum 243,925,235 21,529,514 13,850,343 12,019,150 15,969,706 8,972,388 16,824,770 27,230,545 26,013,318 24,169,828 23,801,662 24,777,847 28,766,164
Gas Physical (416,723) (79,114) (57,965) (24,301) (25,945) (23,006) (23,393) (50,730) (49,843) (45,141) (37,288) - -
Gas Swaps (19,937,668) (4,536,928) (3,311,210) (1,238,993) (534,300) (308,760) (399,300) (2,547,968) (2,611,285) (2,249,700) 18,135 (364,800) (1,852,560)
Clay Basin Gas Storage (588,564) (334,019) (307,763) (216,982) 52,242 52,242 52,242 52,242 52,242 52,242 52,242 2,850 (98,348)
Pipeline Reservation Fees 36,238,771 3,006,087 2,970,650 3,003,231 3,001,490 3,013,815 3,016,829 3,053,890 3,053,707 3,026,691 3,028,291 3,019,210 3,044,880
Total Gas Fuel Burn Expense 259,221,051 19,585,541 13,144,055 13,542,105 18,463,195 11,706,680 19,471,149 27,737,980 26,458,139 24,953,920 26,863,043 27,435,107 29,860,136
Other Generation
Blundell 4,501,334 457,175 412,932 412,932 402,228 418,278 386,442 365,375 383,296 405,974 390,495 223,692 242,515
Blundell Bottoming Cycle - - - - - - - - - - - - -
Total Other Generation 4,501,334 457,175 412,932 412,932 402,228 418,278 386,442 365,375 383,296 405,974 390,495 223,692 242,515
---------------- -------------------------------------------------------- ---------------------------- --------------------------------------------------------------------------------------
Net Power Cost 1,413,631,280 112,618,817 107,559,136 114,180,864 107,738,968 107,677,824 121,901,193 142,082,522 135,203,334 110,722,273 113,421,514 114,359,509 126,165,326

REDACTED
Case No. PAC-E-24-04
Exhibit No. 26
Witness : Ramon J. Mitchell
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
REDACTED
Exhibit Accompanying Direct Testimony of Ramon J. Mitchell
Aurora Benchmark
May 2024

Rocky Mountain Power
Exhibit No.26 Page 1 of 3
Case No. PAC-E-24-04
Witness:Ramon J.Mitchell
Results of the Aurora Benchmarkin2 Study
The results of the benchmarking study show that Aurora simulated 2020 historical net power
costs (NPC) at$58.7 million less than actual NPC. Aurora estimated total company 2020 NPC to
be $1,453 million compared to actual 2020 costs of$1,511 million, an under-forecast of 3.9
percent.
Confidential Table 1 illustrates a detailed comparison between the benchmarking study and
2020 Actual NPC. Long-term firm sales and long-term firm purchase dollars and megawatt-
hours (MWh) are based on actual transactions. Hydroelectric generation and solar generation are
based on actual generation. The variance between short-term firm and system balancing sales
and purchases is driven by the fact that Aurora balances the system differently than the Company
does in actual operations. More specifically, Aurora faces a different set of operational
constraints compared to what the Company faces in real time. For example, market liquidity in
the benchmarking study is predetermined based on market capacity limits that allow more sales
transactions than the Company's historical experience.
It is important to note that the NPC forecast is designed with hourly average inputs. Given a
certain set of hourly average input variables, Aurora applies its system balancing logic to meet
load and wholesale obligations under the operational constraints assumed in the model. In actual
operations, the Company faces a different set of real (moment-to-moment) system constraints,
many of which are not able to be fully reflected in Aurora's modeling assumptions. Furthermore,
Aurora is not able to forecast thermal dispatch in the same way that PacifiCorp dispatches its
thermal plants in real time and Aurora's optimization of the system is perfect which means that
after the optimization is complete no net savings can be further achieved by backing down one
unit and ramping up another unit.
In actual operations, as a matter of prudence, PacifiCorp seeks to optimize the system. However,
in reality, PacifiCorp faces a different set of constraints resulting from actual market conditions,
and in real time, system dispatch will choose to balance the system using coal plants, gas plants
and system balancing purchases and sales in an order that is feasible to current market
conditions. The order of selection of coal plants, gas plants and system balancing purchase and
sales results in differences in each resource category compared to the benchmarking study
results. Consequently, and as shown in Confidential Table 1 below, the coal and natural gas
dispatch (on a MWh basis) in Aurora was approximately one percent more and two percent less
than actuals,respectively.

Rocky Mountain Power
REDACTED Exhibit No.26 Page 2 of 3
Case No. PAC-E-24-04
Page 2 Witness:Ramon J.Mitchell
Confidential Table 1 —Net Power Cost Differential Summary—Benchmark
[CONFIDENTIAL BEGINS]
Net Power Cost Differential Summary
Benchmark
Aurora Actual Difference Difference%
Aurora Actual Difference Difference%
[CONFIDENTIAL ENDS]
Conclusions
When actual data is used as inputs, Aurora produces 2020 NPC below the actual 2020 NPC and
this is to be expected.
First,Aurora applies its system balancing logic with perfect foresight and perfect execution. That
is to say, Aurora knows the future and operates the system with perfect efficiency in every hour.
In reality, the future is uncertain, humans cannot know exactly at what level variable resources
will be producing in a future hour and there will always be some inefficiency within a grouping

Rocky Mountain Power
Exhibit No.26 Page 3 of 3
Case No. PAC-E-24-04
Page 3 Witness:Ramon J.Mitchell
of individuals (people). In the context of NPC, this reality of the human experience deviates from
the perfection inherent in Aurora and the associated perfectly-low Aurora NPC.
Second, there is an asymmetry in the response of market prices to changes in load and
generation. As an illustrative example, Figure 1 below shows a proxy supply/demand curve
(with inelastic demand)based on actual load, wind, and solar data within the region. It is
observed that because of the asymmetry of market price response, a 500 MWh increase in net
load(load less wind less solar) results in a $108 dollar per MWh ($/MWh) increase in market
price, whereas an identical 500 MWh decrease in net load results in only a $39/MWh decrease to
market price.
Figure 1
Regional Supply Stack - Net Load
$400 0
0
0 0
$350 °
_ o
o
$300 60
0
0 0
4...................................................................................."0 Q...0 0
� $250 s 0 00 °
v CPO 0 °
$200 I 108$/MWh 0 ° 0 00
°*0 0 d
v $150 t... ...............................................0 ..
aA.O�- 0... .a.. A.
L 39$/MWh 9 O °
. . . 0
O
i $ �.. .............................
100 a o.. ...
Y
0 00
> 0 0 a
$50 0 O
0
00 O 500 MWh'500 MWh:
$0
1,500 2,500 3,500 4,500 5,500 6,S00
Net Load (MWh)
This asymmetrical response impacts actual operations because the net load forecasts, in reality,
are uncertain(i.e., there is no perfect foresight). This uncertainty results in an equal chance of net
load being higher or lower than forecasted. However, the impact to NPC is an asymmetric
response wherein the actual NPC has a greater chance of being higher than the forecast NPC and
consequently the forecast NPC is biased downwards relative to the actual NPC. This result is
observed in this benchmarking study.

Case No. PAC-E-24-04
Exhibit No. 27
Witness : Ramon J. Mitchell
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Ramon J. Mitchell
General Electric Company - Effect of Temperature on Output
May 2024

Rocky Mountain Power
Exhibit No.27 Page 1 of 1
Case No. PAC-E-24-04
Witness:Ramon J. Mitchell
General Electric Model 7F.04 Gas Turbine
Estimated ReWrmancW���
Effect of Compressor Inlet Temperature on Output
Design Values Referenced on 104H6508 Rev-Sheet 1
Fuel_Gas
Mode:Base
1.1000
1.0500
1.0000
o
V
.. 0.9500
a
O
0.9000
0.8500 Curve Generated vnth design compressor
inlet Relative Humidity
0.8000
-10 0 10 20 30 40 50 60 70 80 90 100 0
Compressor Inlet Temperature-Deg.F
Units
mpressor Inlet Temperature I F 1 -2.55 1 6.00 1 18.00 1 30.00 1 4200. 54.00 1 66.00 1 78.00 1 90.00 102.00
tput Ratio 1.09008 1.09008 1.09008 1.07666 1.04701 1.01476 0.97597 0.93401 0.88979 0.83877
104H6508 Rev -
Sheet 3
This document contains GE proprietary information and may not be used or disclosed to others except with written permission of the GE company.

Case No . PAC-E-24-04
Exhibit No . 28
Witness : Ramon J. Mitchell
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Ramon J. Mitchell
Siemens Energy AG - Effect of Temperature on Output
May 2024

Rocky Mountain Power
Exhibit No.28 Page 1 of 1
Case No. PAC-E-24-04
Witness:Ramon J.Mitchell
SIEMENS
(3n(3r(3
Power Correction for Deviations in Compressor Inlet Temperature
FOR REFERENCE PURPOSES ONLY
1.30
1-20
0
;
LL 1.10
c
0
V 1.00
v
0
a
0 0.90
0.
0.80
0.70
-80 -70 -i_10 -50 -40 3) 20 10 0 10 20 -- -
Compressor Inlet Temperature Deviation from 45.5°F [A°F]