20260116APPLICATION.pdf

RECEIVED
January 16, 2026
IDAHO PUBLIC
UTILITIES COMMISSION
_ ROCKY MOUNTAIN 1407 W.North Temple,Suite 330
POWER. Salt Lake City,UT 84116
A DIVISION OF PACIFICORP
January 16, 2026
VIA ELECTRONIC DELIVERY
Commission Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd
Building 8 Suite 201A
Boise, ID 83714
RE: CASE NO. PAC-E-26-01
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER FOR
AUTHORIZATION TO UPDATE THE WIND AND SOLAR INTEGRATION RATE
FOR SMALL POWER GENERATION QUALIFYING FACILITIES
Attention: Commission Secretary
Please find for filing Rocky Mountain Power's Application in the above-referenced matter which
includes three attachments. Workpapers also accompany this application.
Informal inquiries may be directed to Mark Alder, Idaho Regulatory Manager at(801) 220-2313.
Very truly yours,
jAffj 9LO-1-D
Joelle Steward
Senior Vice President, Regulation

Joe Dallas (ISB# 10330)
825 NE Multnomah, Suite 2000
Portland, OR 97232
Telephone: [phone]
Email: joseph.dallas(&,pacificorp.com
Attorney for Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF ROCKY MOUNTAIN POWER FOR AU- )
THORIZATION TO UPDATE THE WIND ) CASE NO. PAC-E-26-01
AND SOLAR INTEGRATION RATE FOR )
SMALL POWER GENERATION QUALIFY- ) APPLICATION
ING FACILITIES )
Rocky Mountain Power, a division of PaciriCorp ("the Company"), in accordance with
Idaho Code §61-502, §61-503, and RP 052, respectfully submits this application ("Application")
to the Idaho Public Utilities Commission("Commission")to modify the wind and solar integration
rates applicable to new power purchase agreements ("PPA").
If approved, Rocky Mountain Power's integration rate for electric power from wind-pow-
ered qualified facilities,("QFs")would be$1.45 per megawatt-hour("MWh")in 2026, a levelized
price of$0.36 per MWh for a twenty year levelized contract starting in 2026. The proposed wind
integration rates are a reduction to current rates of$3.51 per MWh for 2026, or $0.83 per MWh
for a twenty year levelized contract starting in 2026. The proposed integration rate for Rocky
Mountain Power purchases of electric power from solar-powered QFs is $1.61 per MWh in 2026,
a levelized price of $0.58 per MWh for a twenty year levelized contract starting in 2026. The
proposed solar integration rates are a reduction relative to the approved rates of$4.80 per MWh
for 2026, or $1.35 per MWh for a twenty year levelized contract starting in 2026. The wind and
solar integration rates vary consistent with the results identified in the 2025 IRP, and are also
Application of Rocky Mountain Power 1

available as levelized rates for various contract lengths and online years. These amounts represent
the integration costs of wind and solar power to be applied against published avoided cost rates,
except in those circumstances where the QF developer specifies in the PPA to deliver the QF
output to Rocky Mountain Power on a firm hourly schedule. In support of this Application,Rocky
Mountain Power states as follows:
1. Rocky Mountain Power is a division of PacifiCorp, an Oregon corporation, which
provides electric service to retail customers through its Rocky Mountain Power division in the
states of Idaho,Utah, and Wyoming. Rocky Mountain Power is a public utility in the state of Idaho
and is subject to the Commission's jurisdiction with respect to its prices and terms of electric
service to retail customers in Idaho pursuant to Idaho Code § 61-129. Rocky Mountain Power is
authorized to do business in the state of Idaho and provides retail electric service to approximately
91,000 customers in the state.
I. BACKGROUND
2. In 2005, the Commission noted that it finds "that the unique supply characteristics
of wind generation and the related integration costs provided a basis for adjustment to the pub-
lished avoided cost rates, a calculated figure that may be different for each regulated utility."1
3. In 2007,pursuant to Order No. 29839, Rocky Mountain Power requested approval
of a utility-specific wind integration adjustment to published avoided costs rates.2 The Commis-
sion determined that a PacifiCorp-specific wind integration cost adjustment was appropriate, and
ordered the Company to file any changes to its wind integration charge in subsequent IRPs.3 The
1 In re Idaho Power Company's 2005 Application to Suspend PURPA Obligations. Case No. IPC-E-05-22, Order
29839 at 8(August 4,2005).
2 In re Rocky Mountain Power's 2007 Wind Integration Adjustment for Qualifying Facilities, Case No.PAC-E-07-07,
App. (Apr.23,2007).
3 Final Order No. 30497 at 12-13 (February 20,2008).
Application of Rocky Mountain Power 2

Commission subsequently requested that any updates to the Company's integration charges be
filed after IRP acknowledgement.'
4. On December 17, 2025,the Commission acknowledged the Company's 2025 Inte-
grated Resource Plan("IRP19).5
5. In compliance with Order No. 30497,Rocky Mountain Power files this Application
to update its wind and solar integration rates that can be deducted from the published avoided cost
rates to determine a purchase and sale price established for the duration of QF PPAs. This modifi-
cation reflects the cost of integrating wind and solar generation into the Company's electrical sys-
tem. These integration rates ensure that QFs that deliver less than 100 KW have a predictable rate.
6. In support of this Application the Company includes Attachment No. 1, Appendix
F — Flexible Reserve Study from Volume II of the 2025 IRP, as well as Attachments No. 2 and
No. 3. Attachment No. 1 details the methodology and results derived from PacifiCorp's analysis
of wind and solar integration costs. Attachment No. 2 includes the non-levelized wind and solar
integration rates as required by Order No. 34966,6 and Attachment No. 3 addresses the Commis-
sion's requirements identified in Order No. 36243.'
II. 2025 IRP—FLEXIBLE RESERVE STUDY
7. Appendix F of the 2025 IRP summarizes a Flexible Reserve Study("FRS") which
estimates the regulation reserve required to maintain PacifiCorp's system reliability and comply
with North American Electric Reliability Corporation ("NERC") reliability standards as well as
'In re Rocky Mountain Power 2017 Wind and Solar Integration Rate for Qualifying Facilities,Case No.PAC-E-17-
11,Order No. 33937.
'In re PacifiCorp's 2025 Integrated Resource Plan,Case No.PAC-E-25-12,Order No.36868(December 17,2025).
6 In re Rocky Mountain Power's 2020 Wind and Solar Integration Rate for Qualifying Facilities, Case No. PAC-E-
20-14,Order No. 34966 at p.5.
7 In re Rocky Mountain Power's 2023 Wind and Solar Integration Rate for Qualifying Facilities, Case No. PAC-E-
23-24,Order No. 36243 at p.7.
Application of Rocky Mountain Power 3

the incremental cost of this regulation reserve. The FRS also compares PacifiCorp's overall oper-
ating reserve requirements, including both regulation reserve and contingency reserve, to its flex-
ible resource supply over the IRP study period.
8. The FRS continues to be based on PacifiCorp's actual operational data from Janu-
ary 2018 through December 2019 for load, wind, solar, and Non-Variable Energy Resources
("Non-VERs"). PacifiCorp's primary analysis focuses on the variability of load, wind, solar, and
Non-VERs during this period. A supplemental analysis in the FRS discusses how the total varia-
bility of PacifiCorp's system changes with varying levels of load, wind and solar capacity.
9. To better represent the inter-hour variability of wind and solar resources in the 2025
IRP, the Company worked with a consultant to develop hourly wind and solar generation profiles
for the historical period from 2006-2023. Using global weather data sources that represent actual
historical conditions in specified locations, profiles were developed for all existing resources, for
all contracted resources that are not yet online, as well as for a range of locations in which future
resources might be sited. The use of historical time series for wind and solar generation allows the
output to be aligned with the variations in other system conditions, including load and market
prices, better capturing the relationship between these inputs within modeling results. While this
new data set significantly improves estimates of resource value, marginal capacity contribution,
and stochastic risk, those operating characteristics do not impact the integration costs in the 2025
IRP.
10. The integration cost methodology in the FRS is the same as used in the current
effective integration charges, but has been applied to the 2025 IRP preferred portfolio, including
wind and solar resource additions that drive integration requirements as well as changes in the mix
Application of Rocky Mountain Power 4

of dispatchable resources that can provide operating reserves, which impact the cost of providing
integration service.
11. The estimated regulation reserve amounts determined in the FRS represent the in-
cremental capacity needed in a particular operating hour to ensure compliance with NERC Stand-
ard BAL-001-2. The regulation reserve requirement for the combined portfolio is the sum of the
individual requirements for load,wind, solar,and Non-VERB,less the reserve"savings"associated
with diversity between the different classes, including diversity benefits realized as a result of
PacifiCorp's participation in the Western Energy Imbalance Market(WEIM) operated by the Cal-
ifornia Independent System Operator Corporation (CAISO).
12. The FRS produces an hourly forecast of the regulation reserve requirements for
each of PacifiCorp's Balancing Authority Areas that is sufficient to ensure the reliability of the
transmission system and compliance with NERC and WECC standards. This regulation reserve
forecast covers the combined deviations of the load, wind, solar and Non-VERs on PacifiCorp's
system and varies as a function of the peak load and wind and solar capacity on PacifiCorp's
system, as well as forecasted hourly levels of load, wind, solar.
13. The FRS first estimates the regulation reserve necessary to maintain compliance
with NERC Standard BAL-001-2 given a specified portfolio of wind and solar resources, specifi-
cally the 2025 IRP preferred portfolio. Next the FRS calculates the cost of holding regulation
reserve for incremental wind and solar resources. Finally, the FRS compares PacifiCorp's overall
operating reserve requirements over the IRP study period, including both regulation reserve and
contingency reserve, to its flexible resource supply.
14. In addition to estimating the regulation reserve based on the specific requirements
of NERC Standard BAL-001-2, the FRS also incorporates the current timeline for EIM market
Application of Rocky Mountain Power 5

processes, as well as EIM resource deviations and flexibility reserve benefits based on actual re-
sults. The FRS also includes adjustments to regulation reserve requirements to account for the
changing portfolio of solar and wind resources on PacifiCorp's system and for the diversity of
using a single portfolio of regulation reserve resources to cover variations in load,wind, solar, and
Non-VERs.
15. Based on the results of the FRS from the 2025 IRP the Company respectfully re-
quests that the wind and solar integration rates be updated consistent with the respective tables
provided in Attachment No. 2, applicable to wind and solar QFs that qualify for the Company's
published QF rates.
III. COMMUNICATIONS
Communications regarding this filing should be addressed to:
Mark Alder
Idaho Regulatory Affairs Manager
Rocky Mountain Power
1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
Telephone: [phone]
Email: mark.alder(&,pacificorp.com
Joe Dallas (ISB# 10330)
Assistant General Counsel
Rocky Mountain Power
825 NE Multnomah, Suite 2000
Portland, OR 97232
Telephone: [phone]
Email: joseph.dallas(&,pacificorp.com
In addition, Rocky Mountain Power requests that all data requests regarding this
Application be sent in Microsoft Word to the following:
Application of Rocky Mountain Power 6

By email (preferred): datarequestkpacificorp.com
By regular mail: Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, Oregon 97232
Informal questions may be directed to Mark Alder, Idaho Regulatory Affairs Manager at
[phone].
IV. MODIFIED PROCEDURE
Rocky Mountain Power believes that a hearing is not necessary to consider these issues
and respectfully requests that this Application be processed with Modified Procedures, including
written submissions rather than by hearing under RP 201. If the Commission determines that a
technical hearing is required, the Company can present testimony to support its application.
V. REQUEST FOR RELIEF
Rocky Mountain Power respectfully requests that the Commission issue an Order: (1) au-
thorizing this Application to be processed under Modified Procedure; (2) approving the wind in-
tegration rates presented in Table 1 of Attachment No. 2 for wind-powered QFs; and(3)approving
the solar integration rates presented in Table 2 of Attachment No. 2 for solar-powered QFs. These
rates will be used by the Company for wind or solar-powered QF PPAs(excluding hourly firm QF
PPAs), and represent the integration costs of wind and solar power for avoided cost purposes.
Application of Rocky Mountain Power 7

RESPECTFULLY SUBMITTED this 161h day of January 2026.
Joe Dallas (ISB# 10330)
PacifiCorp,Assistant General Counsel
825 NE Multnomah Street, Suite 2000
Portland, OR 97232
Email:joseph.dallas&pacificorp.com
Attorney for Rocky Mountain Power
Application of Rocky Mountain Power 8

Attachment I
Appendix F 2025 IRP Volume 2

PACIFICORO—2025 IRP PPENDIX F—FLEXIBLE RESERVE STUDY
APPENDIX F - FLEXIBLE RESERVE STUDY
Introduction
For the 2025 IRP, PacifiCorp is continuing to use the In dhodology developed in its 2021 Flexible
Reserve Study(FRS), which relied upon historical data from 2018-2019, as discussed below.I
The 2021 Flexible Reserve Study (FRS) estim Eted the regulation reserve required to m dntain
PacifiCorp's system reliability and com ply with North Am aican Electric Reliability Corporation
(NERC)reliability standards. Because the FRS m dhodology accounts for changes in PacifiCorp's
resource mix,both the quantity and cost of reserves has been updated for the 2025 IRP,as reported
herein.
PacifiCorp operates two balancing authority areas(BAAs)in the Western Electricity Coordinating
Council (WECC) NERC region--PacifiCorp East (PACE) and PacifiCorp West (PACW). The
PACE and PACW BAAs are interconnected by a lim ted am aunt of transm ssion across a third-
party transm ssion system and the two BAAs are each required to com ply with NERC standards.
PacifiCorp m u;t provide sufficient regulation reserve to rem an within NERC's balancing
authority area control error(ACE) lim I in com oiance with BAL-001-2,2 as well as the am cant of
contingency reserve required to com Oy with NERC standard BAL-002-WECC-2.' BAL-001-2 is
a regulation reserve standard that became effective July 1, 2016, and BAIL-002-WECC-3 is a
contingency reserve standard that became effective June 28, 2021. Regulation reserve and
contingency reserve are com pDnents of operating reserve,which NERC defines as"that capability
above firm system dem aid required to provide for regulation, load forecasting error, equipm ait
forced and scheduled outages and local area protection."4
Apart from disturbance events that are addressed through contingency reserve, regulation reserve
is necessary to com prnsate for changes in load dem aid and generation output to In dntain ACE
within m aidatory param tiers established by the BAL-001-2 standard. The FRS estim Aes the
am aunt of regulation reserve required to In alage variations in load, variable energy resources
(VERB), and resources that are not VERB ("Non-VERs") in each of PacifiCorp's BAAs. Load,
wind, solar, and Non-VERs were each studied because PacifiCorp's data indicates that these
'2021 IRP Volum eII,Appendix F(Flexible Reserve Study):
https://www.pacificorp.com bontent/dam hcorp/docum acts/en/pacificorp/energy/integrated-resource-plan/2021-
irpNolum&o 20II%2D-%2D9.15.2021%2DFinal.pdf
2 NERC Standard BAL-001-2, https://www.nerc.comba/Stand/Reliability%2DStandards/BAL-001-2.pdf, which
becam eeffective July 1,2016.ACE is the difference between a BAA's scheduled and actual interchange and reflects
the difference between electrical generation and Load within that BAA.
3 NERC Standard BAL-002-WECC-3,hlWs://www.nerc.com ha/Stand/Reliability%2DStandardsBAL-002-WECC-
3.pdf,which becam eeffective June 28,2021.BAL-002-WECC-3 rem wed the requirem ant that at least 50%of
contingency reserves be held as"spinning"resources,as this was deem ad redundant with frequency response
requirem acts under BAL-003-2.
4 Glossary of Term sUsed in NERC Reliability Standards:
https://www.nerc.com ba/Stand/GlossW%29of%2DTerm�Glossary—of Term spdf,updated March 8,2023.
5 VERs are resources that resources that: (1)are renewable;(2)cannot be stored by the facility owner or operator;
and(3)have variability that is beyond the control of the facility owner or operator.Integration of Variable Energy
Resources,Order No. 764, 139 FERC¶61,246 at P 281 (2012)("Order No. 764");order on reh g,Order No. 764-
A, 141 FERC¶61,232(2012)("Order No. 764-A");order on reh'g and clarification,Order No. 764-13, 144 FERC
¶61,222 at P 210(2013)("Order No. 764-13").
111

PACIFICURpk-2025 IRP PPENDIX F—FLEXIBLE RESERVE STUDY
com ponents or custom cr classes place different regulation reserve burdens on PacifiCorp's system
due to differences in the m Egnitude, frequency, and tim hg of their variations from forecasted
levels.
The FRS is based on PacifiCorp operational data recorded from January 2018 through Decem ber
2019 for load, wind, solar, and Non-VERs. PacifiCorp's prim ay analysis focuses on the actual
variability of load, wind, solar, and Non-VERs during 2018-2019. A supplem antal analysis
discusses how the total variability of the PacifiCorp system changes with varying levels of wind
and solar capacity. The estim aed regulation reserve am cants determ fined in this study represent
the incremental capacity needed to ensure com Iiiance with BAL-001-2 for a particular operating
hour. The regulation reserve requirem ant covers variations in load, wind, solar, and Non-VERs,
while im Iiicitly accounting for the diversity between the different classes. An explicit adjustm ant
is also m ale to account for diversity benefits realized because of PacifiCorp's participation in the
Western Energy Im talance M arket(EIM)operated by the California Independent System Operator
Corporation(CAISO).6
The m tthodology in the FRS is like that previously em Iioyed in PacifiCorp's 2019 IRP but was
enhanced in two areas.7 First,the historical period evaluated in the study was expanded to include
two years, rather than one, to capture a larger Sam lie of system conditions. Second, the
methodology for extrapolating results for higher renewable resource penetration levels was
m odified to better capture the diversity between growing wind and solar portfolios.
The FRS results produce an hourly forecast of the regulation reserve requirem ants for each of
PacifiCorp's BAAS that is sufficient to ensure the reliability of the transm ssion system and
com pliance with NERC and WECC standards. This regulation reserve forecast covers the
com tined deviations of the load,wind, solar and Non-VERs on PacifiCorp's system and varies as
a function of the wind and solar capacity on PacifiCorp's system,as well as forecasted levels of
wind, solar and load.
The regulation reserve requirem ant m ethodologies produced by the FRS are applied in production
cost m odeling to determ he the cost of the reserve requirem ants associated with increm antal wind
and solar capacity. After a portfolio is selected,the regulation reserve requirem ants specific to that
portfolio can be calculated and included in the study inputs, such that the production cost im pmct
of the requirem ants is incorporated in the reported results. As a result, this production cost im pact
is dependent on the wind and solar resources in the portfolio as well as the characteristics of the
dispatchable resources in the portfolio that are available to provide regulation reserves.
O wrview
The prim ay analysis in the FRS is to estim ae the regulation reserve necessary to m antain
com Iiiance with NERC Standard BAL-001-2 given a specified portfolio of wind and solar
resources. The FRS next calculates the cost of holding regulation reserve for increm antal wind and
solar resources. Finally, the FRS com fares PacifiCorp's overall operating reserve requirem ants
6 Western Energy Im lalance Market.www.westerneim com
2019 IRP Volum eII,Appendix F(Flexible Reserve Study):
hllps://www.pacificop2.com,6ontent/dam hcorp/docum acts/en/pacificorp/enerey/integrated-resource-
plan/2019 IRP_Volum e II Appendices A-L.pdf
112

PACIFICORBk-2025 IRP PPENDIX F—FLEXIBLE RESERVE STUDY
over the IRP study period,including both regulation reserve and contingency reserve,to its flexible
resource supply.
The FRS estim otes regulation reserve based on the specific requirem arts of NERC Standard BAL-
001-2. It also incorporates the current tim dine for EIM m Aet processes, as well as EIM resource
deviations and diversity benefits based on actual results. The FRS also includes adjustor acts to
regulation reserve requirem sits to account for the changing portfolio of solar and wind resources
on PacifiCorp's system and accounts for the diversity of using a single portfolio of regulation
reserve resources to cover variations in load, wind, solar, and Non-VERB. A com larison of the
results of the current analysis and that from previous IRPs is shown in Table F.1 and Table F.2.
Flexible resource costs are portfolio dependent and vary over tim e For in(re details, please refer
to Figure F.11 —Increm aital Wind and Solar Regulation Reserve Costs.
Table F.1 - Portfolio Regulation Reserve Requirem sits
gov
Wind Solar Stand-alone Portfolio Regulation
Capacity Capacity Regulation Diversity Requirem mt
Requirem ant Credit with Diversity
Case (MW) MW (MW) (%) (MW)
% -5 CY2017(2019 FRS) 2 750 1 021 9 94 4 7 1
2018-2019(2021 FRS) 2 745 1 ,080 1 1057 4 9% -40
[ AOL
Table F.2 - 2025 Flexible Reserve Costs as Compared to 2023 Costs, $/MWh
Wind 2025 Solar 2025 Wind 2023 Solar 2023
FRS FRS FRS FRS
(2024$) (2024$) (2024$ (2024
Study Period 2 025-2045 025-2045 025-2042 025-2042
Flexible Reserve Cost $ 0.47 $ 0.66 $ 1.22 $ 1.53
Flexible Resource Requirem Bits
PacifiCorp's flexible resource needs are the sam eas its operating reserve requirem ants over the
planning horizon for inantaining reliability and com Oiance with NERC regional reliability
standards. Operating reserve generally consists of three categories: (1) contingency reserve (i.e.,
spinning, and supplem antal reserve), (2) regulation reserve, and (3) frequency response reserve.
Contingency reserve is capacity that PacifiCorp holds available to ensure com Oiance with the
NERC regional reliability standard BAL-002-WECC-3.8 Regulation reserve is capacity that
PacifiCorp holds available to ensure com Oiance with the NERC Control Perform aice Criteria in
BAL-001-2.9 Frequency response reserve is capacity that PacifiCorp holds available to ensure
8 NERC Standard BAL-002-WECC-3—Contingency Reserve:
hLtps://www.nerc.com ha/Stand/Reliability%20Standards/BAL-002-WECC-3.pdf
9 NERC Standard BAL-001-2—Real Power Balancing Control Perform aice:
https://www.nerc.com ha/Stand/Reliability%2DStandards/BAL-001-2.pdf
113

PACIFICORBk-2025 IRP PPENDIX F—FLEXIBLE RESERVE STUDY
com Iliance with NERC standard BAL-003-2.10 Each type of operating reserve is further defined
below.
Contingency Reserve
Purpose: Contingency reserve in a' be deployed when unexpected outages of a generator or a
transm ssion line occur. Contingency reserve in aj not be deployed to in aiage other system
fluctuations such as changes in load or wind generation output.
Volum e NERC regional reliability standard BAL-002-WECC-3 specifies that each BAA in tst
hold as contingency reserve an am aunt of capacity equal to three percent of load and three percent
of generation in that BAA.
Duration: Except within 60 in nutes of a qualifying contingency event, a BAA in IEt m antain the
required level of contingency reserve at all tim cs. Generally, this in cans that up to 60 minutes of
generation are required to provide contingency reserve, though successive outage events in 3'
result in contingency reserves being deployed for longer periods. To restore contingency reserves,
other resources m ut be deployed to replace any generating resources that experienced outages,
typically either in xket purchases or generation from resources with slower ram prates.
Ram pRate: Only up capacity available within ten in nutes can be counted as contingency reserve.
This can include "spinning" resources that are online and im in diately responsive to system
frequency deviations to in dntain com Iliance with frequency response obligations under BAL-
003-1.1, as well as from "non-spinning" resources that do not respond im in diately, though they
in u;t still be fully deployed in ten in nutes.I I
Regulation Reserve
Purpose: NERC standard BAL-001-2, which becam eeffective July 1, 2016, does not specify a
regulation reserve requirem ait based on a Sim Ile form da, but instead requires utilities to hold
sufficient reserve to in at specified control perform nice standards. The prim ay requirem cat
relates to area control error ("ACE"), which is the difference between a BAA'S scheduled and
actual interchange and reflects the difference between electrical generation and load within that
BAA. Requirem ait 2 of BAL-001-2 defines the com Iliance standard as follows:
E ach Balancing Authority shall operate such that its clock-minute average of
Reporting ACE does not exceed its clock-minute Balancing Authority ACE Limit
(BAAL)for more than 30 consecutive clock-minutes...
In addition, Requirem ait I of BAL-001-2 specifies that PacifiCorp's Control Perform mce
Standard 1 ("CPS I") score m in be greater than equal to 100 percent for each preceding 12
consecutive calendar in anth period, evaluated in anthly. The CPS I score com fares PacifiCorp's
10 NERC Standard BAL-003-2—Frequency Response and Frequency Bias Setting:
hLtps://www.nerc.com ha/Stand/Reliability%20Standards/BAL-003-2—, df
" While the m him un spinning reserve obligation previously contained within BAL-002-WECC-2a was retired due
to redundancy with frequency response obligations under BAL-003-2, PacifiCorp's 2023 IRP does not explicitly
m odel the frequency response obligation and retains the spinning obligation to ensure a supply of rapidly responding
resources is m dntained.
114

PACIFICORBk-2025 IRP PPENDIX F-FLEXIBLE RESERVE STUDY
ACE with interconnection frequency during each clock m nute. A higher score indicates
PacifiCorp's ACE is helping interconnection frequency,while a lower score indicates it is hurting
interconnection frequency. Because CPS 1 is averaged and evaluated m cnthly, it does not require
a response to every ACE event but rather requires that PacifiCorp m(et a minim un aggregate level
of performance in each m mth. Regulation reserve is thus the capacity that PacifiCorp holds
available to respond to changes in generation and load to m anage ACE within the lira is specified
in BAL-001-2.
Volum e NERC standard BAL-001-2 does not specify a regulation reserve requirem ant based on
a Sim lie form da but instead requires utilities to hold sufficient reserve to m(et perform aice
standards as discussed above. The FRS estim aes the regulation reserve necessary to m d�t
Requirem ant 2 by com pensating for the com lined deviations of the load, wind, solar and Non-
VERs on PacifiCorp's system.These regulation reserve requirem ants are discussed in more detail
later in the study.
Ram p Rate: Because Requirem ant 2 includes a 30-m nute tim e lim i for com Oiance, ram Ong
capability that can be deployed within 30 m mutes contributes to m Ming PacifiCorp's regulation
reserve requirem ants. The reserve for CPS I is not expected to be increm altal to the need for
com Oiance with Requirem ant 2 but m a'require that a subset of resources held for Requirem ant 2
be able to m&e frequent rapid changes to m alage ACE relative to interconnection frequency.
Duration: PacifiCorp is required to subm i balanced load and resource schedules as part of its
participation in EIM.PacifiCorp is also required to subm i resources with up flexibility and down
flexibility to cover uncertainty and expected ram IT, across the next hour. Because forecasts are
subm iced prior to the start of an hour, deviations can begin before an hour starts. As a result, a
flexible resource In&be called upon for the entire hour. To continue providing flexible capacity
in the following hour, energy m W be available in storage for that hour as well. The likelihood of
deploying for two hours or In ae for reliability com liiance (as opposed to econom i s) is expected
to be sm dl.
Frequency Response Reserve
Purpose: NERC standard BAL-003-2 specifies that each BAA m t8t arrest frequency deviations
and support the interconnection when frequency drops below the scheduled level. When a
frequency drop occurs because of an event, PacifiCorp will deploy resources that increase the net
interchange of its BAAS and the flow of generation to the rest of the interconnection.
Volum e When a frequency drop occurs, each BAA is expected to deploy resources that are at
least equal to its frequency response obligation. The increm altal requirem ant is based on the size
of the frequency drop and the BAA'S frequency response obligation, expressed in m(gawatt
(M W 10.1 Herts (Hz). To com Oy with the standard, a BAA'S m a€lian m(asured frequency
response during a Sam Icing of under-frequency events m IEt be equal to or greater than its
frequency response obligation. PacifiCorp's 2024 frequency response obligation was 21.7
MWA.IHz for PACW, and 62.9 MWA.IHz for PACE.12 PacifiCorp's com lined obligation
am aunts to 84.6 M W for a frequency drop of 0.1 Hz, or 253.8 M W for a frequency drop of 0.3 Hz.
12 NERC.BAL-003-2 Frequency Response Obligation Allocation and Minim un Frequency Bias Settings for
Operating Year 2022.
115

PACIFICoRpk-2025 IRP PPENDIX F—FLEXIBLE RESERVE STUDY
The perform aice in easurem ait for contingency reserve under the Disturbance Control Standard
(BAL-002-3)13, allows for recovery to the lesser of zero or the ACE value prior to the contingency
event, so increasing ACE above zero during a frequency event reduces the additional deploym ant
needed if a contingency event occurs. Because contingency, regulation, and frequency events are
all relatively infrequent,they are unlikely to occur sim dtaneously.Because the frequency response
standard is based on in alian perform aice during a year, overlapping requirem ants that reduced
PacifiCorp's response during a lim i:ed num ber of frequency events would not im fast corn Oiance.
As a result, any available capacity not being used for generation is expected to contribute to
in a'ting PacifiCorp's frequency response obligation, up to the technical capability of each unit,
including that designated as contingency or regulation reserves. Frequency response must occur
very rapidly, and a generating unit's capability is lim ied based on the unit's size, governor
controls, and available capacity, as well as the size of the frequency drop. As a result, while a few
resources could hold a large am cunt of contingency or regulation reserve,frequency response in ay
need to be spread over a larger num ber of resources. Additionally, only resources that have active
and tuned governor controls as well as outer loop control logic will respond properly to frequency
events.
Ram p Rate: Frequency response perform aice is in c cured over a period of seconds, am punting
to under a in hute. Corn Oiance is based on the average response over the course of an event. As a
result, a resource that im in diately provides its full frequency response capability will provide the
greatest contribution. That Sam eresource will contribute a sm dler am cunt if it instead ram 1T, up
to its full frequency response capability over the course of a in hute or responds after a lag.
Duration: Frequency response events are less than one m inute in duration.
Black Start Requirem sits
Black start service is the ability of a generating unit to start without an outside electrical supply
and is necessary to help ensure the reliable restoration of the grid following a blackout. At this
tim e, PACW grid restoration would occur in coordination with Bonneville Power Adm histration
black start resources. The Gadsby combustion turbine resources can support grid restoration in
PACE. PacifiCorp has not identified any increm antal needs for black start service during the IRP
study period.
Ancillary Services O perational Distinctions
In actual operations,PacifiCorp identifies two types of flexible capacity as part of its participation
in the EIM. The contingency reserve held on each resource is specifically identified and is not
available for econom b dispatch within the EIM.Any rem aning flexible capacity on participating
resources that is not designated as contingency reserve can be econom Bally dispatched in EIM
based on its operating cost (i.e., bid) and system requirem ants and can contribute to in UAing
regulation reserve obligations. Because of this distinction, resources in ist either be designated as
https://www.nerc.com bom mOC/RS%20Landin%ge%20DL/Frequency%20Response%20Standard%20Reso
urces/BA FRO Allocations_for OY2024.pdf
13 NERC Standard BAL-002-3—Disturbance Control Standard—Contingency Reserve for Recovery from a
Balancing Contingency Event:hgps://www.nerc.com ha/Stand/Reliability Standards/BAL-002-3.pdf
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PACIFICORBk-2025 IRP PPENDIX F—FLEXIBLE RESERVE STUDY
contingency reserve or as regulation reserve. Contingency events are relatively rare while
opportunities to deploy additional regulation reserve in EIM occur frequently. As a result,
PacifiCorp typically schedules its lowest-cost flexible resources to serve its load and blocks off
capacity on its highest-cost flexible resources to m xt its contingency obligations, subject to any
ram Ong lim iations at each resource. This leaves resources with m oderate costs available for
dispatch up by EIM,while lower-cost flexible resources rem an available to be dispatched down
by EIM.
Regulation Reserve Data Inputs
O wrview
This section describes the data used to determ he PacifiCorp's regulation reserve requirem nits. To
estim zte PacifiCorp's required regulation reserve am cunt, PacifiCorp m tut determ he the
difference between the expected load and resources and actual load and resources. The difference
between load and resources is calculated every four seconds and is represented by the ACE. ACE
In W be maintained within the lim is established by BAL-001-2, so PacifiCorp m ist estim ete the
am aunt of regulation reserve that is necessary to m antain ACE within these lim is.
To estim de the am cunt of regulation reserve that will be required in the future, the FRS identifies
the scheduled use of the system as com fared to the actual use of the system during the study term.
For the baseline determ nation of scheduled use for load and resources, the FRS used hourly base
schedules.Hourly base schedules are the power production forecasts used for im talance settlem ant
in the EIM and represent the best inform aion available concerning the upcom hg hour.I4
The deviation from scheduled use was derived from data provided through participation in the
EIM. The deviations of generation resources in EIM were m csured on a five-m mute basis, so
five-m mute intervals are used throughout the regulation reserve analysis.
EIM base schedule and deviation data for each wind, solar and Non-VER transaction point was
downloaded using the SettleCore application, which is populated with data provided by the
CAISO. Since PacifiCorp's im Oem antation of EIM on Novem ber 1, 2014, PacifiCorp requires
certain operational forecast data from all its transm ssion custom ars pursuant to the provisions of
Attachm ant T to PacifiCorp's Federal Energy Regulatory Com mssion (FERC) approved Open
Access Transmssion Tariff(OATT). This includes EIM base schedule data(or forecasts)from all
resources included in the EIM network m odel at transaction points. EIM base schedules are
subm ited by transm ssion custom ars with hourly granularity, and are settled using hourly data for
load, and fifteen-m mute and five-m mute data for resources. A prim ay function of the EIM is to
14 The CAISO,as the m aaket operator for the EIM,requests base schedules at 75 m nutes(T-75)prior to the hour of
delivery.PacifiCorp's transm i sion custom as are required to subm i base schedules by 77 m mutes(T-77)prior to
the hour of delivery—two m nutes in advance of the EIM Entity deadline.This allows all transm ssion customer
base schedules enough tim eto be subm ited into the EIM system sbefore the overall deadline of T-75 for the entirety
of PacifiCorp's two BAAs.The base schedules are due again to CAISO at 55 m nutes(T-55)prior to the delivery
hour and can be adjusted up until that tim eby the EIM Entity(i.e.,PacifiCorp Grid Operations).PacifiCorp's
transm ssion custom as are required to subm i updated,final base schedules no later than 57 m nutes(T-57)prior to
the delivery hour.Again,this allows all transm ssion custom a base schedules enough tim eto be subm ited into the
EIM system sbefore the overall deadline of T-55 for the entirety of PacifiCorp's two BAAs.Base schedules m ay be
finally adjusted again,by the EIM Entity only,at 40 m nutes(T-40)prior to the delivery hour in response to CAISO
sufficiency tests.T-40 is the base schedule tim epoint used throughout this study.
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PACIFICoRBk-2025 IRP PPENDIX F-FLEXIBLE RESERVE STUDY
m ensure load and resource im balance (or deviations) as the difference between the hourly base
schedule and the actual In dered values.
A sum In ay of the data gathered for this analysis is listed below, and a m cre detailed description
of each type of source data is contained in the following subsections.
Source data:
- Load data
o Five-m hute interval actual load
o Hourly base schedules
- V ER data
o Five-m hute interval actual generation
o Hourly base schedules
- N on-VER data
o Five-m hute interval actual generation
o Hourly base schedules
Load Data
The load class represents the aggregate firm deco aid of end users of power from the electric
system.While the requirem acts of individual users vary,there are diurnal and seasonal patterns in
aggregated deco aid. The load class can generally be described to include three com ponents: (1)
average load,which is the base load during a particular scheduling period; (2)the trend,or"ram p"
during the hour and from hour-to-hour; and (3) the rapid fluctuations in load that depart from the
underlying trend. The need for a system response to the second and third com pDnents is the
function of regulation reserve in order to ensure reliability of the system .
The PACE BAA includes several large industrial loads with unique patterns of dem aid. Each of
these loads is either interruptible at short notice or includes behind the meter generation. Due to
their large size, abrupt changes in their dem aid are m zgnified for these custom ers in a m auier
which is not representative of the aggregated dem aid of the large num ber of sm ill custom ers
which m dce up m(st PacifiCorp's loads.
In addition, interruptible loads can be curtailed if their deviations are contributing to a resource
shortfall. Because of these unique characteristics, these loads are excluded from the FRS. This
treatm ant is consistent with that used in the CAISO load forecast m dhodology (used for PACE
and PACW operations),which also nets these interruptible custom er loads out of the PACE BAA.
Actual average load data was collected separately for the PACE and PACW BAAS for each five-
m hute interval. Load data has not been adjusted for transm ssion and distribution losses.
Wind and Solar Data
The wind and solar classes include resources that: (1) are renewable; (2) cannot be stored by the
facility owner or operator; and(3) have variability that is beyond the control of the facility owner
118

PACIFICORBk-2025 IRP PPENDIX F—FLEXIBLE RESERVE STUDY
or operator." Wind and solar, in com Iarison to load, often have larger upward and downward
fluctuations in output that im pose significant and sour dim es unforeseen challenges when
attem Ding to in dntain reliability. For exam Ile, as recognized by FERC in Order No. 764,
"Increasing the relative am cunt of[VERs] on a system can increase operational uncertainty that
the system operator in trt in aiage through operating criteria, practices, and procedures, including
the commitment of adequate reserves."16 The data included in the FRS for the wind and solar
classes include all wind and solar resources in PacifiCorp's BAAS,which includes: (1)third-party
resources (GATT or legacy contract transm ssion custom ars); (2) PacifiCorp-owned resources;
and (3) other PacifiCorp-contracted resources, such as qualifying facilities, power purchases, and
exchanges. In total, the FRS study period includes an average of 2,745 in gawatts of wind and
1,080 megawatts of solar.
Non-VER Data
The Non-VER class is a in k of therm d and hydroelectric resources and includes all resources
which are not VERs, and which do not provide either contingency or regulation reserve. Non-
VERs, in contrast to VERs, are often in cre stable and predictable. Non-VERs are thus easier to
plan for and in antain within a reliable operating state. For exam Ile, in Order No. 764, FERC
suggested that in aIy of its rules were developed with Non-VERs in in nd and that such generation
"could be scheduled with relative precision.""The output of these resources is largely in the
control of the resource operator, particularly when considered within the hourly tim dram eof the
FRS. The deviations by resources in the Non-VER class are thus significantly lower than the
deviations by resources in the wind class. The Non-VER class includes third-party resources
(GATT or legacy transm 'ssion custom ars); in aiy PacifiCorp-owned resources; and other
PacifiCorp-contracted resources, such as qualifying facilities,power purchases, and exchanges. In
total, the FRS includes 2,202 megawatts of Non-VERs.
In the FRS, resources that provide contingency or regulation reserve are considered a separate,
dispatchable resource class. The dispatchable resource class corn prnsates for deviations resulting
from other users of the transm 'ssion system in all hours. While non-dispatchable resources in ay
offset deviations in loads and other resources in som e hours, they are not in the control of the
system operator and contribute to the overall requirem aIt in other hours. Because the dispatchable
resource class is a net provider rather than a user of regulation reserve service, its stand-alone
regulation reserve requirem ant is zero (or negative), and its share of the system regulation reserve
requirem ait is also zero. The allocation of regulation reserve requirem acts and diversity benefits
is discussed in in are detail later in the study.
Regulation Reserve Data Analysis and Adjustm eit
O wrview
This section provides details on adjustm acts in ale to the data to align the ACE calculation with
actual operations, and address data issues.
15 Order No. 764 at P 281;Order No. 764-B at P 210.
16 Order No. 764 at P 20(em rhasis added).
17 Id. at P 92.
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PACIFICORBk-2025 IRP PPENDIX F—FLEXIBLE RESERVE STUDY
Base Schedule Ram ping Adjustm mt
In actual operations, PacifiCorp's ACE calculation includes a linear ram pfrom the base schedule
in one hour to the base schedule in the next hour, starting ten-m mutes before the hour and
continuing until ten-m mutes past the hour.The hourly base schedules used in the study are adjusted
to reflect this transition from one hour to the next. This adjustm ait step is im pDrtant because, to
the extent actual load or generation is transitioning to the levels expected in the next hour, the
adjusted base schedules will result in reduced deviations during these intervals, potentially
reducing the regulation reserve requirem ant. Figure F.1 below illustrates the hourly base schedule
and the ramping adjustm ant. The sam ecalculation applies to all base schedules: Load,Wind,Non-
VERs, and the com fined portfolio.
Figure F.1 -Base Schedule Ram ping Adjustm ant
3100 —
3000
2900
r
2800
v
2700
U
2600
m
2500
2400 111 7' �Iirr
—Base Schedule —Adjusted Base Schedule
2300
4�, 4�, � cn .n Ln Ln Ln Ln Ln Ln Ln Ln P LP am am am am am m am m am am am m -_1 -_1 -_1 -_1
_P1 U1 U1 O O N N N N W W _P1 A In In O O N N N N W W � _PN Ln Ln O O N N
U.n O LP O W O W O W O to O to O to O to O W O W O W O W O W O W O to
Tim e
Data Corrections
The data extracted from PacifiCorp's system sfor, wind, solar and Non-VERs was sourced from
CAISO settlem ant quality data. This data has already been verified for inconsistencies as part of
the settlement process and needs minim d cleaning as described below. Regarding five-m mute
interval load data from the PI Ranger system,intervals were excluded from the FRS results if any
five-m mute interval suffered from at least one of the data anom dies that are described further
below:
Load:
120

PACIFICORBk-2025 IRP PPENDIX F-FLEXIBLE RESERVE STUDY
• Telem dry spike/poor connection to meter
• Missing meter data
• Missing base schedules
VERs:
• Curtailm ant events
Load in PacifiCorp's BAAS changes continuously. While a BAA could potentially In antain the
exact Sam eload levels in two five-m mute intervals in a row, it is extrem dy unlikely for the exact
Sam eload level to persist over longer tim efram cs.When PacifiCorp's energy m anagem ant system
(EM S) load telem dry fails, updated load values m a' not be logged, and the last available load
m easurement for the BAA will continue to be reported.
Rapid spikes in load telem dry either up or down are unlikely to be the result of conditions which
require deploym ant of regulation reserve, particularly when they are transient. Such events could
be a result of a transm ssion or distribution outage, which would allow for the deploym ant of
contingency reserve, and would not require deploym ant of regulation reserve. Such events are also
likely to be a result of a single bad load m easurem ant. Load telem dry spike irregularities were
identified by exam ping the intervals with the largest changes from one interval to the next, either
up or down. Intervals with inexplicably large and rapid changes in load, particularly where the
load reverts within a short period,were assum ai to have been covered through contingency reserve
deploym ant or to reflect inaccurate load In easurem ants. Because they do not reflect periods that
require regulation reserve deploym ait, such intervals are excluded from the analysis. During the
study period, in PACW 15 m mutes' worth of telem dry spikes were excluded while no telem dry
spikes were observed in PACE. There were also 10 m mutes' worth of m 'sing load meter data,
and 82 hours of m sing load base schedules.
The available VER data includes wind curtailm ant events which affect m etered output.When these
curtailm sits occur, the CAISO sends data, by generator, indicating the m Tnitude of the
curtailm ant. This data is layered on top of the actual meter data to develop a proxy for what the
m etered output would have been if the generator were not curtailed. Regulation reserve
requirem ants are calculated based on the shortfall in actual output relative to base schedules. By
adding back curtailed volum es to the actual m etered output,the shortfall relative to base schedules
is reduced, as is the regulation reserve requirem ant. This is reasonable since the curtailm ant is
directed by the CAISO or the transm ssion system operator to help m antain reliable operation, so
it should not exacerbate the calculated need for regulation reserves.
After review of the data for each of the above anom sly types, and out of 210,216 five-m mute
intervals evaluated, approxim aely 1,000 five-m mute intervals, or 0.5% of the data, was rem wed
due to data errors. While cleaning up or replacing anom dous hours could yield a m(re com Bete
data set, determ fling the appropriate conditions in those hours would be difficult and subjective.
By rem wing anom dies, the FRS Sam lie is sm dler but rem ans reflective of the range of
conditions PacifiCorp experiences, including the im lact on regulation reserve requirem ants of
weather events experienced during the study period.
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PACIFICORBk-2025 IRP PPENDIX F—FLEXIBLE RESERVE STUDY
Regulation Reserve Requirem ait Methodology
O wrview
This section presents the in dhodology used to determ he the initial regulation reserve needed to
in aiage the load and resource balance within PacifiCorp's BAAS. The five-m nute interval load
and resource deviation data described above inform s a regulation reserve forecast in dhodology
that achieves the following goals:
- C om Hies with NERC standard BAL-001-2;
- Mi nim ies regulation reserve held; and
- U ses data available at tim eof EIM base schedule subm ssion at T-40.18
The components of the in dhodology are described below, and include:
- Operating Reserve: Reserve Categories;
- Calculation of Regulation Reserve Need;
- Balancing Authority ACE Lim I: Allowed Deviations;
- Planning Reliability Target: Loss of Load Probability("LOLP"); and
- Regulation Reserve Forecast: Am aunt Held.
Following the explanation below of the com portents of the in dhodology, the next section details
the forecasted am cunt of regulation reserve for:
- Wi nd;
- S olar;
- N on-VERB; and
- L oad.
Components of O perating Reserve Methodology
Operating Reserve: Reserve Categories
Operating reserve consists of three categories: (1) contingency reserve, (2)regulation reserve, and
(3) frequency response reserve. These requirem tilts in trt be in d by resources that are increm antal
to those needed to in cet firm system dem aid. The purpose of the FRS is to determ he the regulation
reserve requirem ant. The contingency reserve and frequency response requirem ants are defined
form laically by their respective reliability standards.
Of the three categories of reserve referenced above, the FRS is prim wily focused on the
requirem ants associated with regulation reserve. Contingency reserve in W not be deployed to
in anage other system fluctuations such as changes in load or wind generation output. Because
deviations caused by contingency events are covered by contingency reserve rather than regulation
reserve,they are excluded from the determ nation of the regulation reserve requirem arts. Because
frequency response reserve can overlap with that held for contingency and regulation reserve
requirem arts it is Sim iarly excluded from the determ nation of regulation reserve requirem arts.
18 See footnote 12 above for explanation of PacifiCorp's use of the T-40 base schedule tim epoint in the FRS.
122

PACIFICURpk-2025 IRP PPENDIX F—FLEXIBLE RESERVE STUDY
The types of operating reserve and relationship between them are further defined in in the Flexible
Resource Requirem acts section above.
Regulation reserve is capacity that PacifiCorp holds available to ensure com Oiance with the NERC
Control Perform nice Criteria in BAL-001-2, which requires a BAA to carry regulation reserve
increm aital to contingency reserve to in aintain reliability.19 The regulation reserve requirem ait is
not defined by a Sim Ile form da, but instead is the am cunt of reserve required by each BAA to
m(et specified control perform mce standards. Requirem ant two of BAL-001-2 defines the
com Oiance standard as follows:
Each Balancing Authority shall operate such that its clock-minute average of
Reporting ACE does not exceed its clock-minute Balancing Authority ACE Limit
(BAAL)for more than 30 consecutive clock-minutes...
PacifiCorp has been operating under BAL-001-2 since March 1, 2010, as part of a NERC
Reliability-Based Control field trial in the Western Interconnection, so PacifiCorp had experience
operating under the standard, even before it becam eeffective on July 1, 2016.
The three key elem ants in BAL-001-2 are: (1) the length of tim e(or "interval") used to in casure
com Oiance; (2)the percentage of intervals that a BAA in nst be within the lim is set in the standard;
and (3) the bandwidth of acceptable deviation used under each standard to determ he whether an
interval is considered out of com Iliance. These changes are discussed in further detail below.
The first elem ant is the length of tim eused to in casure com Oiance. Com Oiance under BAL-001-
2 is in casured over rolling thirty-m mute intervals, with 60 overlapping periods per hour, som eof
which include parts of two clock-hours. In effect, this in ains that every in mute of every hour is
the beginning of a new, thirty-m mute com Oiance interval under the new BAL-001-2 standard. If
ACE is within the allowed lim is at least once in a thirty-m mute interval, that interval is in
com Oiance, so only the minim un deviation in each rolling thirty-m mute interval is considered in
determ ping com Oiance. As a result, PacifiCorp does not need to hold regulation reserve for
deviations with duration less than 30 in mutes.
The second elem ant is the num brr of intervals where deviations are allowed to be outside the lim is
set in the standard. BAL-001-2 requires 100 percent com Oiance, so deviations in Ist be maintained
within the requirem ant set by the standard for all rolling thirty-m mute intervals.
The third elem ant is the bandwidth of acceptable deviation before an interval is considered out of
com Oiance. Under BAL-001-2, the acceptable deviation for each BAA is dynam i , varying as a
function of the frequency deviation for the entire interconnect. When interconnection frequency
exceeds 60 Hz, the dynam b calculation does not require regulation resources to be deployed
regardless of a BAA'S ACE. As interconnection frequency drops further below 60 Hz, a BAA'S
perm ssible ACE shortfall is increasingly restrictive.
Planning Reliability Target: Loss of Load Probability
When conducting resource planning, it is com in n to use a reliability target that assum cs a
specified loss of load probability (LOLP). In effect, this is a plan to curtail fine load in rare
19 NERC Standard BAL-001-2,hltps://www.nerc.com ha/Stand/Reliability%20Standards/BAL-001-2.pdf
123

PACIFICORBk-2025 IRP PPENDIX F—FLEXIBLE RESERVE STUDY
circum fiances,rather than acquiring resources for extrem dy unlikely events. The reliability target
balances the cost of additional capacity against the benefit of increm aitally in cre reliable
operation. By planning to curtail firm load in the rare event of a regulation reserve shortage,
PacifiCorp can in dntain the required 100 percent com fliance with the BAL-001-2 standard and
the Balancing Authority ACE Lim i.This balances the cost of holding additional regulation reserve
against the likelihood of regulation reserve shortage events.
The FRS assum es that a regulation reserve forecasting in dhodology that results in 0.50 loss of
load hours per year due to regulation reserve shortages is appropriate for planning and ratem Being
purposes. This is in addition to any loss of load resulting from transm ssion or distribution outages,
resource adequacy, or other causes. The FRS applies this reliability target as follows:
• If the regulation reserve available is greater than the regulation reserve need for an hour,
the LOLP is zero for that hour.
• If the regulation reserve held is less than the am cunt needed,the LOLP is derived from the
Balancing Authority ACE Lim i probability distribution as illustrated below.
Balancing Authority ACE Limt: Allowed Deviations
Even if insufficient regulation reserve capability is available to com pensate for a thirty-m mute
sustained deviation,a violation of BAL-001-2 does not occur unless the deviation also exceeds the
Balancing Authority ACE Lim i.
The Balancing Authority ACE Lim i is specific to each BAA and is dynam b,varying as a function
of interconnection frequency. When WECC frequency is close to 60 Hz, the Balancing Authority
ACE Lim i is large and large deviations in ACE are allowed. As WECC frequency drops further
and further below 60 Hz,ACE deviations are increasingly restricted for BAAs that are contributing
to the shortfall, i.e., those BAAS with higher loads than resources. A BAA com mfs a BAL-001-2
reliability violation if in any thirty-m mute interval it does not have at least one in mute when its
ACE is within its Balancing Authority ACE Lim i.
While the specific Balancing Authority ACE Lim i for a given interval cannot be known in
advance,the historical probability distribution of Balancing Authority ACE Lim i values is known.
Figure F.2 below shows the probability of exceeding the allowed deviation during a five-m mute
interval for a given level of ACE shortfall. For instance, an 82 M W ACE shortfall in PACW has a
one percent chance of exceeding the Balancing Authority ACE Lim i. WECC-wide frequency can
change rapidly and without notice, and this causes large changes in the Balancing Authority ACE
Lim i over short tim efram cs. Maintaining ACE within the Balancing Authority ACE Lim i under
those circum fiances can require rapid deploym ant of large am runts of operating reserve. To lim i
the size and speed of resource deploym ant necessitated by variation in the Balancing Authority
ACE Lim i, PacifiCorp's operating practice caps perm ssible ACE at the lesser of the Balancing
Authority ACE Lim i or four tim cs Lio. This also lim is the occurrence of transm ssion flows that
exceed path ratings as result of large variations in ACE.20,2I This cap is reflected in Figure F.2.
21"Regional Industry Initiatives Assessm ait."NWPP MC Phase 3 Operations Integration Work Group.Dec. 31,
2014.Pg. 14.Available at:www.nwpp.org/docum ants/MC-Public/NWPP-MC-Phase-3-Regional-Industry-
Initiatives-Assessm ait12-31-2014.pdf
21 "NERC Reliability-Based Control Field Trial Draft Report."Western Electricity Coordinating Council.Mar.25,
2015.Available at:www.wecc.biz/Reliability/RBC%2DField%20Tria1%29Report%29Approved%293-25-2015.pdf
124

PACIFICoRBk-2025 IRP PPENDIX F—FLEXIBLE RESERVE STUDY
Figure F.2 -Probability of Exceeding Allowed Deviation
100%
90% -
0
0 80%
0 70%
3 60%
0
Q
tin 50%
c
11 40%
x
w
0 30%
- 20%
0
10%
0%
02 55 07 51 00 1 25 1 50 1 75 2 00 225
ACE Shortfall (M W)
— Exceedance Probability (PACW) Exceedance Probability (PACE)
In 2018-2019, PacifiCorp's deviations and Balancing Authority ACE Lim is were uncorrelated,
which indicates that PacifiCorp's contribution to WECC-wide frequency is sm dl. PacifiCorp's
deviations and Balancing Authority ACE Lim is were also uncorrelated when periods with large
deviations were exam ned in isolation. If PacifiCorp's large deviations m ade distinguishable
contributions to the Balancing Authority ACE Lim i, ACE shortfalls would be In cre likely to
exceed the Balancing Authority ACE Lim i during large deviations. Since this is not the case, the
probability of exceeding the Balancing Authority ACE Lim i is lower, and less regulation reserve
is necessary to corn Oy with the BAL-001-2 standard.
Regulation Reserve Forecast: Am aunt H dd
To calculate the am aunt of regulation reserve required to be held while being com Oiant with BAL-
001-2—using a LOLP of 0.5 hours per year or less—a quantile regression m dhodology was used.
Quantile regression is a type of regression analysis. Whereas the typical m cthod of ordinary least
squares results in estim des of the conditional m ain(501h percentile)of the response variable given
certain values of the predictor variables, quantile regression aim s at estim ding other specified
percentiles of the response variable. Eight regressions were prepared, one for each class
(load/wind/solar/non-VER) and area (PACE/PACW). Each regression uses the following
variables:
• Response Variable: the error in each interval, in m gawatts.
• Predictor Variable: the forecasted generation or load in each interval, expressed as a
percentage of area capacity.
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PACIFICORBk-2025 IRP PPENDIX F-FLEXIBLE RESERVE STUDY
The forecasted generation or load in each interval used as the predictor variable contributes to the
regression as a com lination of linear, square, and higher order exponential effects. Specifically,
the regression identifies coefficients that correspond to the following functions for each class:
Load Error: Load Forecast'+ Constant
Wind Error: Wind Forecast2+Wind Forecast'
Solar Error: Solar Forecast4+ Solar Forecast3 + Solar Forecast2+ Solar Forecast'
Non-VER Error: Non-VER Forecast2+Non-VER Forecast'
The instances requiring the largest am cants of regulation reserve occur infrequently, and many
hours have very low requirem acts. If periods when requirem acts are likely to be low can be
distinguished from periods when requirem ants are likely to be high, less regulation reserve is
necessary to achieve a given reliability target. The regulation reserve forecast is not intended to
com pensate for every potential deviation.Instead,when a shortfall occurs,the size of that shortfall
determ Ines the probability of exceeding the Balancing Authority ACE Lim t and a reliability
violation occurring. The forecast is adjusted to achieve a cum 1lative LOLP that corresponds to the
annual reliability target.
Regulation Reserve Forecast
O wrview
The following forecasts are polynom al functions that cover a targeted percentile of all historical
deviations. These forecasts are stand-alone forecasts, based on the difference between hour-ahead
base schedules and actual meter data, expressing the errors as a function of the level of forecast.
The stand-alone reserve requirem ant shown achieves the annual reliability target of 0.5 hours per
year, after accounting for the dynam it Balancing Authority ACE Lim t. The com lined diversity
error system requirem ants are discussed later in the study. Figure F.3- Figure F.8 illustrate the
relationship between the regulation reserve requirem ants during 2018-2019 and the forecasted
level of output, for each resource class and control area. Both the regulation reserve requirem ants
and the forecasted level of output are expressed as a percentage of resource nam q)late (i.e., as a
capacity factor). Figure F.9 and Figure F.10 illustrate the Sam erelationship between the regulation
reserve requirem acts during 2018-2019 and the forecasted load for each control area. Both the
regulation reserve requirem ants and the forecasted load are expressed as a percentage of the annual
peak load(i.e., as a load factor).
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PACIFICORBk-2025 IRP PPENDIX F-FLEXIBLE RESERVE STUDY
Figure F.3 -Wind Regulation Reserve Requirem sits by Forecast- PACE
PACE Wind - Relationship between Forecast and Error
45%
40%
3s% _
a 30% _ •-
rn
10/o
SO
0% L.•.
0% 10% 20% 30% 40% 500/6 60% 70% 80% 90%
Forecast as a Percentage of Capacity
Reserves
M Reserve Requirement
Figure F.4 -Wind Regulation Reserve Requirements by Forecast Capacity Factor- PACW
PACW Wind-Relationship between Forecast and Error
45%
40%
3s%
ra •��__ sit,.�..
d �•Y.•-�b�`� •mod�,�� ty<ti :-
10% x A -
S%
0%
0% 10% 20% 30% 40% 50% 60% 70% 80% 90%
Forecast as a Percentage of Capacity
Reserves
M Reserve Requirement
127

PACIFICURBk-2025 IRP PPENDIX F-FLEXIBLE RESERVE STUDY
Figure F.5 - Solar Regulation Reserve Requirem wts by Forecast Capacity Factor-PACE
PACE Solar- Relationship between Forecast and Error
55%
SO%
45% ;:
T
m 40%
a '
-63
v -
15% s=
s
10%
5%
0%
00/. 10% 20% 30% 40% 50% 60% 70% 80% 90%
Forecast as a Percentage of Capacity
Reserves
0 Reserve Requirement
Figure F.6 - Solar Regulation Reserve Requirem tnts by Forecast Capacity Factor - PACW
PACW Solar-Relationship between Forecast and Error
55%
SO%
45%
T
a
40%
ra
0 3SO/..
°i �' .•:��3+s.,�y.:;:Y:�tir::.ma's'•':.�a�%'_� ��.:, •
25% t•.•1'
WN
MTim- • K��Y:C'e�;< .'s�.,:i:
w �c - a•[�� �f:� 3:
10%
5%
0%
0% 10% 20% 30% 40% 50% 60% 70% 80% 90�
Forecast as a Percentage of Capacity
Reserves
M Reserve Requirement
128

PACIFICURBk-2025 IRP PPENDIX F-FLEXIBLE RESERVE STUDY
Figure F.7—Non-VER Regulation Reserve Requirem ants by Capacity Factor- PACE
PACE Non-VER- Relationship between Forecast and Error
24%
22%
20%
t f
160
rn A A. �.
m
jell
:.
d Vr+ 1. -; •��' ..L ./•' •_�
w - X.�.i;Y„, r`• w+' ..t�'.• 'i:;i; ':. R�id.},'4' a:'.:S
. •�._{.- •fig- ,�.. :t`,+
4%
2%
0%
20% 30% 40% 50% 60% 70% 80% 90%
Forecast as a Percentage of Capacity
Reserves
M Reserve Requirement
Figure F.8—Non-VER Regulation Reserve Requirem acts by Capacity Factor- PACW
PACW Non-VER-Relationship between Forecast and Error
24%
22%
20%
> 18%
16%
m 14% -
Lu
` r
2% t-
0%
20% 30% 40% 50% 60% 70% 80% 9
Forecast as a Percentage of Capacity
Reserves
0 Reserve Requirement
129

PACIFICURBk-2025 IRP PPENDIX F-FLEXIBLE RESERVE STUDY
Figure F.9— Stand-alone Load Regulation Reserve Requirem eats - PACE
PACE Load-Relationship between Forecast and Error
7.0%
6.5%
6.0%
5.5%
5.0%
0
a
0 4.0% r.
rn c
c 3.5% E
t0 2.5°r0 ti '�Y'J '`•��}�=..±r 4•.•.v..
1.0% r ':
0.5%
0.00/.
30% 40% 500/0 60% 70% 809E U
Forecast as a Percentage of Peak Load
Reserves
M Reserve Requirement
Figure F.10—Stand-alone Load Regulation Reserve Requirements -PACW
PACW Load-Relationship between Forecast and Error
7.0%
6.0%
5 Ooro
o r
4.5% �q
0 4.0% _ S.�•. s
3 5% •-�`'i'cam;_}:t,;,{`j^ ::>p�
1.0%
o.s r°
ICI ��' • -
30% 40% 50% 60% 70% 80% 90%
Forecast as a Percentage of Peak Load
Reserves
M Reserve Requirement
130

PACIFICoRpk-2025 IRP PPENDIX F—FLEXIBLE RESERVE STUDY
The results of the analysis are shown in Table F.3 below.
Table F.3 — Sum m x of Stand-alone Regulation Reserve Re uirem ants
Stand-alone Regulation Capacity Stand-alone Regulation
Scenario Forecast(aMW) (MW Forecast
Non-VER 1 06 1 304 8 .2%
Load 3 34 1 0,094 3 .3%
VER-Wind 4 57 2 745 1 6.7%
VER-Solar 1 59 1 1080 1 4.8%
Total 1 ,057
Portfolio Diversity and EIM Diversity Benefits
The EIM is a voluntary energy imbalance in aket service through the CAISO where m Tket
system s autom otically balance supply and dem aid for electricity every fifteen and five in hutes,
dispatching least-cost resources every five in hutes.
PacifiCorp and CAISO began full EIM operation on Novem bier 1, 2014. Many additional
participants have since joined the EIM,such that it now includes nearly 80%of electricity dem aid
in the Western interconnection, and in(re participants are scheduled to join in the next several
years. PacifiCorp's participation in the EIM results in im lroved power production forecasting and
optim ied intra-hour resource dispatch. This brings im pDrtant benefits including reduced energy
dispatch costs through autom Aic dispatch, enhanced reliability with im proved situational
awareness,better integration of renewable energy resources,and reduced curtailm ant of renewable
energy resources.
The EIM also has direct effects related to regulation reserve requirem nits. First, because of EIM
participation, PacifiCorp has im proved data used in the analysis contained in this FRS. The data
and control provided by the EIM allow PacifiCorp to achieve the portfolio diversity benefits
described in the first part of this section. Second, the EIM's intra-hour capabilities across the
broader EIM footprint provide the opportunity to reduce the am cunt of regulation reserve
necessary for PacifiCorp to hold, as further explained in the second part of this section.
Portfolio Diversity Benefit
The regulation reserve forecasts described above independently ensure that the probability of a
reliability violation for each class rem dns within the reliability target; however, the largest
deviations in each class tend not to occur Sim dtaneously, and in som ecases, deviations will occur
in offsetting directions. Because the deviations are not occurring at the Sam etim q the regulation
reserve held can cover the expected deviations for in dtiple classes at once and a reduced total
quantity of reserve is sufficient to in dntain the desired level of reliability. This reduction in the
reserve requirem ant is the diversity benefit from holding a single pool of reserve to cover
deviations in Solar, Wind, Non-VERB, and Load. As a result, the regulation reserve forecast for
the portfolio can be reduced while still in ceting the reliability target. In the historical period,
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PACIFICoRBk-2025 IRP PPENDIX F-FLEXIBLE RESERVE STUDY
portfolio diversity from the interactions between the various classes results in a regulation reserve
requirem aft that is 36%lower than the sum of the stand-alone requirem arts,or approxim rtely 679
MW.
EIM Diversity Benefit
In addition to the direct benefits from EIM's increased system visibility and im proved intra-hour
operational perform nice described above, the participation of other entities in the broader EIM
footprint provides the opportunity to further reduce the am aunt of regulation reserve PacifiCorp
in tut hold.
By pooling variability in load and resource output, EIM entities reduce the quantity of reserve
required to in(et flexibility needs. The EIM also facilitates procurem alt of flexible ram Ong
capacity in the fifteen-m hute in aket to address variability that in 3' occur in the five-m nute
in xket. Because variability across different BAAS in a'happen in opposite directions,the flexible
ram Ong requirem ant for the entire EIM footprint can be less than the sum of individual BAA
requirem arts. This difference is known as the"diversity benefit"in the EIM.This diversity benefit
reflects offsetting variability and lower com fined uncertainty. This flexibility reserve(uncertainty
requirem art) is in addition to the spinning and supplem antal reserve carried against generation or
transm ssion system contingencies under the NERC standards.
The CAISO calculates the EIM diversity benefit by first calculating an uncertainty requirem ant
for each individual EIM BAA and then by com faring the sum of those requirem ants to the
uncertainty requirem ait for the entire EIM area. The latter am cunt is expected to be less than the
sum of the uncertainty requirem ants from the individual BAAS due to the portfolio diversification
effect of forecasting a larger pool of load and resources using intra-hour scheduling and increased
system visibility in the hypothetical, single-BAA EIM. Each EIM BAA is then credited with a
share of the diversity benefit calculated by CAISO based on its share of the stand-alone
requirem ant relative to the total stand-alone requirem ant.
The EIM does not relieve participants of their reliability responsibilities. EIM entities are required
to have sufficient resources to serve their load on a standalone basis each hour before participating
in the EIM. Thus, each EIM participant rem ans responsible for all reliability obligations. Despite
these lim lations,EIM im parts from other participating BAAS can help balance PacifiCorp's loads
and resources within an hour, reducing the size of reserve shortfalls and the likelihood of a
Balancing Authority ACE Lim i violation.While substantial EIM im parts do occur in som ehours,
it is only appropriate to rely on PacifiCorp's diversity benefit associated with EIM participation,
as these are derived from the structure of the EIM rather than resources contributed by other
participants.
Table F.4 below provides a num Tic exam lie of uncertainty requirem ants and application of the
calculated diversity benefit.
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PACIFICORBk-2025 IRP PPENDIX F—FLEXIBLE RESERVE STUDY
Table FA —EIM Dive sity Benefit Application Exam ple
a b c d e f g h i j
=a+b+c+ =e-f =g/e =c*h =c-i
d
CAISO NEW PACE PACW Total Total PACE
req't. req't. req't. req't. req't. req't. Total Diversity PACE req't.
diversity benefit
before before before before before after benefit ratio benefit after
benefit benefit benefit benefit benefit benefit benefit
H our (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW)
1 550 1 10 65 00 25 5 83 1 42 3 7.00% 6 1 04
2 600 1 10 65 00 75 6 36 1 39 3 4.80% 5 1 08
3 650 1 10 65 10 1035 6 89 1 46 3 3.40% 5 1 10
4 667 1 20 80 13 080 42 38 3 1.30% 1 24
While the diversity benefit is uncertain, that uncertainty is not significantly different from the
uncertainty in the Balancing Authority ACE Lim i previously described. In the FRS, PacifiCorp
has credited the regulation reserve forecast based on a historical distribution of calculated EIM
diversity benefits. While this FRS considers regulation reserve requirem acts in 2018-2019, the
CAISO identified an error in their calculation of uncertainty requirem arts in early 2018. CAISO's
published uncertainty requirem arts and associated diversity benefits are now only valid for March
2018 forward. To capture these additional benefits for this analysis, PacifiCorp has applied the
historical distribution of EIM diversity benefits from the 12 in rnths beginning March 2018. In the
historical study period, EIM diversity benefits used in the FRS would have reduced regulation
reserve requirem acts by approxim aely 140 M W.
The inclusion of EIM diversity benefits in the FRS reduces the in finitude, and thus probability,
of reserve shortfalls and, in doing so, reduces the overall regulation reserve requirement. This
allows PacifiCorp's forecasted requirem arts to be reduced. As shown in Table F.5 below, the
resulting regulation reserve requirem ait is 540 M W,which is a 49 percent reduction (including
the portfolio diversity benefit) com fared to the stand-alone requirem ait for each class. This
portfolio regulation forecast is expected to achieve an LOLP of 0.5 hours per year.
Table F.5—2018-2019 Results with Portfolio Diversity and EIM Diversity Benefits
Stand-alone Portfolio
Regulation Stand-alone Regulation Portfolio
Forecast Rate Forecast w/EIM Rate Capacity Rate
Scenario (aMW) (%) (aMW) (%) (MW) Determ rant
Non-VER 1 06 8 .2% 5 4 .2% 1304 N am q)late
Load 3 34 3 .3% F2 1 .7% D,094 1 2 CP
VER-Wind 4 57 1 6.7% 37 8 .6% Z745 IN am q)late
VER-Solar 1 59 1 4.8% -i 7 .1% 1080 N am tplate
Total 1 ,057 540
133

PACIFICORpk-2025 IRP PPENDIX F-FLEXIBLE RESERVE STUDY
Fast-Ram png Reserve Requirem acts
As previously discussed, Requirem ant 1 of BAL-001-2 specifies that PacifiCorp's CPS1 score
in W be greater than equal to 100 percent for each preceding 12 consecutive calendar in anth period,
evaluated in anthly. The CPS 1 score corn fares PacifiCorp's ACE with interconnection frequency
during each clock in mute. A higher score indicates PacifiCorp's ACE is helping interconnection
frequency, while a lower score indicates it is hurting interconnection frequency. Because CPS is
averaged and evaluated on a in cnthly basis, it does not require a response to each and every ACE
event but rather requires that PacifiCorp in at a in him un aggregate level of perform ance in each
in anth.
The Regulation Reserve Forecast described above is evaluating requirem ants for extrem e
deviations that are at least 30 in mutes in duration, for com Oiance with Requirem ant 2 of BAL-
001-2. In contrast, com Oiance with CPS requires reserve capability to compensate for in(St
conditions over a in mute-to-m mute basis. These fast-ram Ong resources would be deployed
frequently and would also contribute to com liiance with Requirem ant 2 of BAL-001-2, so they
are a subset of the Regulation Reserve Forecast described above.
To evaluate CPS 1 requirem ants, PacifiCorp com lared the net load change for each five-m mute
interval in the study period to the corresponding value for Requirem ant 2 com Oiance in that hour
from the Regulation Reserve Forecast, after accounting for diversity (resulting in a 540 M W
average requirem ant).Resources in a'deploy for Requirem ant 2 com liiance over up to 30 in mutes,
so the average requirem ant of 540 M W would require ram Ong capability of at least 18.0 M W per
in mute (540 M W/ 30 in mutes).
Because CPS 1 is averaged and evaluated in anthly,it does not require a response to each and every
ACE event but rather requires that PacifiCorp in xt a in him un aggregate level of perform ance in
each in cnth. Resources capable of ensuring com liiance in 95 percent of intervals are expected to
be sufficient to in Tt CPS 1 and given that ACE in a' deviate in either a positive or negative
direction, the 97.5th percentile of increm antal requirem ants versus Requirem ant 2 in that interval
was evaluated. At the 97.5th percentile, fast ram Ong requirem ants for PACE and PACW are 1.7
M W in mute and 0.8 M W kn mute higher than the Requirem ant 2 ram prate,respectively; however,
if dynam i transfers between the BAAs are available, the 97.5th percentile for system is 0.6 M W/
in mute lower than the Requirem ant 2 value. When viewed on a system basis, this in cans that 30-
m mute ramping capability held for Requirem ant 2 would be sufficient to cover an adequate portion
of the fast-ram ping events to ensure CPS 1 com liiance.
Note that resources in ist respond im in diately to ensure com liiance with Requirement 1, as
perform ance is in casured on a in mute-to-m mute basis. As a result, resources that respond after a
delay, such as quick-start gas plants or certain interruptible loads, would not be suitable for
Requirem ant 1 com liiance, so these resources cannot be allocated the entire regulation reserve
requirem ant.However,because Requirem ant 1 com liiance is a sm dl portion of the total regulation
reserve requirem ant,these restrictions on resource type are unlikely to be a in atningful constraint.
In addition, CPS 1 com liiance is weighted toward perform ance during conditions when
interconnection frequency deviations are large. The largest frequency deviations would also result
in deploym ant of frequency response reserves, which are sour ovhat larger in in Ognitude, though
134

PACIFICoRBk-2025 IRP PPENDIX F-FLEXIBLE RESERVE STUDY
they have a less stringent perform ance in etric under BAL-003-2,based on in edian response during
the largest events.
In light of the overlaps with BAL-001-2 Requirem ant 2 and BAL-003-2 described above, CPS
com nuance is not expected to result in an additional requirem ant beyond what is necessary to
com 1iy with those standards.
Portfolio Regulation Reserve Requirem Bits
The IRP portfolio optim kation process contem Bates the addition of new wind and solar capacity
as part of its selection of future resources, as well as changes in peak load due to load growth and
energy efficiency in a sure selection. These load and resource changes are expected to drive
changes in PacifiCorp's regulation reserve requirem ants that will vary from portfolio to portfolio.
The locations that have been identified as likely sites for future wind and solar additions are in
relatively close proxim ty to existing wind and solar resources, and PacifiCorp's portfolio of
resources is already relatively diverse with significant wind in Wyom hg, along the Colum ha
River gorge, and in eastern Idaho/western Wyom hg and significant solar in southern Utah and
southern Oregon. Because future resources are likely to be added in relatively close proxim iy to
these existing resources, they are not likely to change the diversity for that class of resources as a
whole. Given the sizeable Sam lie of existing wind and solar resources in PACE and PACW,
in antaining the existing level of diversity as a class of resources doubles or quadruples is a in cre
likely outcom ethan the continuing im lrovem ants previously assum al in the 2019 FRS. With that
in in hd, the increm antal regulation reserve analysis for the 2021 FRS in dhodology assum cs that
wind, solar, and load deviations scale linearly with capacity increases from the actual data in the
2018-2019 historical period.
While diversity within each class is not expected to change significantly, there is the opportunity
for greater diversity am ang the wind,solar,and load requirem ants. These portfolio-related benefits
are inherently tied to the portfolio, so it is appropriate that they vary with the portfolio. To that
end,the 2021 FRS in dhodology calculates the portfolio diversity benefits specific to a wide variety
of wind and solar capacity com tinations,rather than relying upon the historical portfolio diversity
value.
As part of the portfolio diversity calculation, the analysis assum cs that in him un EIM flexible
reserve requirem ants and EIM diversity benefits scale with changes in portfolio capacity. EIM
in him un flexible reserve requirem ants are tied to the uncertainty in PacifiCorp's requirem ants,
which grow with changes portfolio capacity, so it would be im fasted directly. EIM diversity
benefits reflect PacifiCorp's share of stand-alone requirem ants relative to those of the rest of the
BAA'S participating in EIM. All else being equal, increases in PacifiCorp's portfolio capacity
would result in a greater proportion of the EIM diversity benefits being allocated to PacifiCorp.
Portfolio diversity is driven by interplay am ang the deviations by wind, solar, and load, so it is not
a single num brr, but rather is dependent on the specific conditions. The 2021 FRS m dhodology
incorporates two in xhanism sto better account for these interactions. First, a portfolio diversity
value is calculated specific to each hour of the day in each season. Second,rather than applying an
equal percentage reduction to all hours, diversity benefits are assum od to be highest when stand-
135

PACIFICORBk-2025 IRP PPENDIX F-FLEXIBLE RESERVE STUDY
alone requirem arts are highest.For exam lie,there is in(re opportunity for offsetting requirem ants
when load, wind, and solar all have significant stand-alone requirem alts. With that in in nd,
diversity is applied as an exponent to the increm altal requirem ait in ore than the EIM in him un
requirem ait. The result of this calculation is a diversity benefit which is highest for large reserve
requirem arts, and which approaches zero as the requirem sit approaches the EIM in him u in 4s
illustrated in Table F.6.
Table F.6-Portfolio Diversity Exponent Exam ple
Increm vital Requirem ant w/
Diversity(MW) Portfolio Diversity(%)
By Diversity Ex onent By Diversity Ex onent
Stand-alone EIM Stand-alone
Reserve Floor Increm antal d= e= f= g=1 - h=1- i=1-
Req.(MW) (MW) Req.(MW) c ^75% c ^85% c ^ 95% (b+d)/a (b+e)/a (b+f)/a
a b c=a-b 75% 85% 95% 75% 85% 95%
200 2 00 0 0 0 0 % 0% 0i9
250 2 00 5 0 1 9 2 8 4 1 1 2% 9% 0,4
300 2 00 1 00 3 2 5 0 7 9 2 3% F% 7/0
350 2 00 50 4 3 7 1 1 17 3 1% 3% 9/0
400 2 00 2 00 5 3 9 0 1 53 3 7% D% P%
450 2 00 2 50 6 3 1 09 1 90 4 2% 3% B%
500 2 00 3 00 7 2 1 28 2 26 4 6% A% 5%
For each corn lination of wind and solar capacity,the hourly portfolio diversity exponents for each
season are increased in a stepwise fashion until the risk of regulation reserve shortfalls during an
interval is sufficiently low and the overall risk of regulation reserve shortfalls achieves the target
of 0.5 hours per year. The resulting portfolio diversity is in aim i?ed for a corn lination of wind
and solar as sum in sized in Table F.77 and Table F.8 for PacifiCorp East and PacifiCorp West,
respectively.
Table F.7-PacifiCorp East Diversity by Portfolio Composition
MW % % Reduction vs. Stand-alone Re uirem arts
8,224 548% 17.2% 18.8% 20.6
u 7,184 472% 19.2% 21.5% 23.0% 25.5% 26.5%
6,144 395% 22.9% 24.1% 25.6% 27.9% 28.5% 29.0%
U 5,104 319% 26.0% 27.3% 29.2% 30.7% 30.7% 30.5% 29.5%
4,064 242% 30.4% 31.6% 32.9% 33.8% 32.7% 32.8% 32.8%
3,024 166% 35.0% 36.2% 38.5% 37.1% 37.6% 36.2% 33.9% 31.9%
1,575 100% 48.0% 45.8% 43.1% 39.5% 35.8% 32.2% 29.4%
W
788 50% 1 46.4% 40.3% 36.4% 33.0% 30.0% 27.3%
50% 100% 166% 329% 493% 656% 820% 983% %
428 855 1,462 2,502 3,542 4,582 5,622 6,662 MW
East Solar Capacity
2018-2019 Actual Wind and Solar Capacity
136

PACIFICoRBk-2025 IRP PPENDIX F-FLEXIBLE RESERVE STUDY
Table F.8-PacifiCorp West Diversity by Portfolio Composition
MW % % Reduction vs. Stand-alone Re uirem arts
4,389 548% P W. 0 22.4% 22.9%
era 3,669 472% 23.4% 24.8% 25.4% /° 33.0%
2,949 395% 26.2% 26.7% 27.6% 32.1% 34.8% 38.1%
.� 2,229 319% 29.6% 30.6% 31.4% 36.2% 39.5% 42.70%;. 42.70:%
1,509 242% 33.8% 34.5% 36.3% 40.8% 45.2% 46.2% 43.9%
789 166% 38.8% 41.6% 43.1% 47.6% 48.4% 47.7% 45.0% 44.3%
y 726 100% 42.4% 42.9% 48.6% 49.3% 47.7% 46.2% 44.4%
363 50% 41.7% 47.1% 49.8% 47.4% 45.0% 43.2%
50% 100% 166% 329% 493% 656% 820% 983% %
111 221 321 1,041 1,761 2,481 3,201 3,921 MW
West Solar Capacity
2018-2019 Actual Wind and Solar Capacity
After portfolio selection is com Bete, regulation reserve requirem ants are calculated specific to a
portfolio's load,wind,and solar resources in each year. The hourly regulation reserve requirem aIt
varies as a function of annual peak load net of energy efficiency selections as well as total wind
and solar capacity. The regulation reserve requirem ant also varies based on the hourly load net of
energy efficiency and hourly wind and solar generation values. Diversity exponents specific to the
wind and solar capacity in each year are applied by hour and season, by interpolating am rng the
scenarios illustrated in Figure F.7 and Figure F.B. For exam lie, the diversity exponent for hour
five in the spring for a PACW study with 1,000 M W of wind and 1,000 M W of solar would reflect
a weighting of diversity exponents in hour five in the spring from four scenarios. The highest
weighting would apply to the 789 M W wind/1,041 M W solar scenario, and successively lower
weightings would apply to 1,509 M W wind/1,041 M W solar, 789 M W wind/321 M W solar, and
1,509 M W wind/321 M W solar, with the total weighting for all four scenarios sum mrig to 100%.
Finally, an adjustor ant is m ale to account for the ability of resources that are com hued with
storage to offset their own generation shortfalls beyond what is already captured by the model. For
exam lie, com lined solar and storage resources can offset their own generation shortfalls, up to
their interconnection lim i. In actual operation, a reduction in solar generation would enable
additional storage discharge. However, within the PLEXOS m odel, there are no intra-hour
variations in load or renewable resource output and thus no potential increase in storage discharge.
Note that com lined storage can only be discharged when there is a generation shortfall at the
adjacent resource, so it cannot cover all shortfalls across the system .For exam lie, many solar
resources do not have co-located storage, and their errors would continue to need to be m d with
increm aital reserves. Nonetheless, com lined solar and storage can cover a portion of their own
shortfalls, and that portion increases as m cre com lined storage resources are added to the system.
This adjustor ait reduces the hourly regulation reserve requirem ant that is entered in the m odel.
Regulation Reserve Cost
The PLEXOS m odel reports m aginal reserve prices on an hourly basis. So long as the change in
reserve obligations or capability from what was input for a study is relatively sm dl, this reserve
137

PACIFICoRBk-2025 IRP PPENDIX F-FLEXIBLE RESERVE STUDY
price can provide a reasonable estim ae of the im pact of changes in reserves, without requiring
additional In cdel runs.
To estim Ete wind and solar integration costs for the 2025 IRP, PacifiCorp prepared a PLEXOS
scenario that reflected the final regulation reserve requirem acts, consistent with the Com pany's
existing wind and resources plus selections in the preferred portfolio. Hourly regulation reserve
prices were reported from this study.
Wind Integration
The wind reserve case uses the 2021 FRS m dhodology to recalculate the wind reserve
requirem aIt for a portfolio with 5 M W m a7e wind resources in each year of the IRP study
horizon (2025-2045). The change in resources applies to both PACE and PACW and is
allocated pro-rata am rng all wind resources in the area, such that the aggregate hourly
capacity factor is not impacted by the change in capacity. The change in wind capacity
results in increm altal regulation reserve requirem arts that average approxim aely 15% of
the nam q)late capacity of the wind. Wind integration costs are calculated by multiplying
the hourly change in reserve requirem acts (in M W)by the hourly regulation reserve price
in each hour of the year and then dividing that total by the increm aital wind generation
over the year.
Solar Integration
The solar reserve case uses the 2021 FRS In dhodology to recalculate the solar reserve
requirem aIt for a portfolio with 5 M W m ore solar resources in each year of the IRP study
horizon (2025-2045). The change in resources applies to both PACE and PACW and is
allocated pro-rata am rng all solar resources in the area, such that the aggregate hourly
capacity factor is not im pacted by the change in capacity. The change in solar capacity
results in increm altal regulation reserve requirem acts that average approxim dely 7% of
the nam q)late capacity of the solar. Solar integration costs are calculated by multiplying
the hourly change in reserve requirem acts (in M W)by the hourly regulation reserve price
in each hour of the year and then dividing that total by the increm altal solar generation
over the year.
The incremental regulation reserve cost results for wind and solar are shown in Figure F.11. The
com parable regulation reserve costs from the 2023 IRP are also shown. Integration costs in the
2023 IRP were elevated in the near term as a result of com piiance with the Ozone Transport Rule.
In the absence of those requirem arts, integration costs in the 2025 IRP are reduced in the near
term .Integration costs fall as energy storage resources are added to the portfolio, as they can
provide operating reserves at no additional cost while charging and in any hour in which they are
not discharging and not fully depleted, which for a four-hour energy storage resource is m cst of
the day.
138

PACIFICORBk-2025 IRP PPENDIX F—FLEXIBLE RESERVE STUDY
Figure F.I I —Increm artal Wind and Solar Regulation Reserve Costs
$6.00
� •••••• Wind (231RP)
$5.00
Solar (231RP)
$4.00
( Wind (251RP)
U $3.00 —
C: Solar (251RP)
$2.00
c�
0) $1.00
$0.00
Ln k.D r, 0o m O ry M zt Ln �.D r, 00 M 0 -1 N M M
N N N N N M M M M M M M M M M
O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N r`4 rV rV rV rV rV rV rV rV rV rV rV N
Flexible Resource Needs Assessm mt
O wrview
In its Order No. 12-013 issued on January 19, 2012, in Docket No. UM 1461 on"Investigation of
in Aters related to Electric Vehicle Charging", the Oregon Public Utility Com mssion (OPUC)
adopted the OPUC staff s proposed IRP guideline:
1. Forecast the Dem aid for Flexible Capacity: The electric utilities shall forecast the
balancing reserves needed at different tim e intervals (e.g., ram Ong needed within 5
in nutes)to respond to variation in load and interm ttent renewable generation over the 20-
year planning period.
2. Forecast the Supply of Flexible Capacity: The electric utilities shall forecast the balancing
reserves available at different tim eintervals(e.g.,ram Ong available within 5 in nutes)from
existing generating resources over the 20-year planning period.
3. Fvaluate Flexible Resources on a Consistent and Com pmrable Basis: In planning to fill any
gap between the dem aid and supply of flexible capacity,the electric utilities shall evaluate
all resource options including the use of electric vehicles (EVs), on a consistent and
comparable basis.
In this section, PacifiCorp first identifies its flexible resource needs for the IRP study period of
2025 through 2045, and the calculation in ethod used to estim Lie those requirem aits. PacifiCorp
then identifies its supply of flexible capacity from its generation resources, in accordance with the
Western Electricity Coordinating Council (WECC) operating reserve guidelines, dem rnstrating
that PacifiCorp has sufficient flexible resources to in et its requirem arts.
139

PACIFICORBk-2025 IRP PPENDIX F—FLEXIBLE RESERVE STUDY
Forecasted Reserve Requirem sits
Since contingency reserve and regulation reserve are separate and distinct com pDnents,PacifiCorp
estim des the forward requirem acts for each separately. The contingency reserve requirem ants are
derived from the PLEXOS m odel. The regulating reserve requirem ants are part of the inputs to the
PLEXOS model and are calculated by applying the m dhods developed in the Portfolio Regulation
Reserve Requirem ants section. The contingency and regulation reserve requirem ants are two
distinct com pDnents that are m odeled separately in the 2025 IRP: 10-m mute contingency reserve
requirem ants and 30-m mute regulation reserve requirem ants. The average reserve requirem acts
for PacifiCorp's two balancing authority areas are shown in Table F.9 below.
Table F.9 - Reserve Requirements (Average MW)
e Fast Requirem a►t W st Requirem ait
Spin N on-spin R egulation S pin N on-spin R egulation
Year
(10-m mute) i 10-m mute) i 30-m Bute) i 10-m Bute) i 10-m mute) i 30-m mute)
2025 160 60 9E 4 41 06
2026 158 55 48 5 5 1 06
2027 161 6F 58 6 61 06
2028 163 63 69 8 8 92
2029 165 66 76 9 91 88
2030 169 69 7e 0 0 59
2031 172 715 2® 1 1 62
2032 173 7A 24 1 1 70
2033 177 76 29 3 3 87
2034 180 80 20 4S 4 97
2035 183 8A 29 5 5z 24
2036 185 86 19 6S 6z 51
2037 190 96 19 8 8z 76
2038 194 94 04 00 Oo 93
2039 198 96 07 02 02 35
2040 20P 06 02 04 04 69
2041 20a 06 83 06 06 77
2042 210, 16 92 oa 08 79
2043 212 13 91 10 16 77
2044 21a 16 80 12 13 91
2045 22E 2b 1 87 14 14 12
Flexible Resource Supply Forecast
Requirem acts by NERC and the WECC dictate the types of resources that can be used to serve the
reserve requirem acts.
140

PACIFICoRBk-2025 IRP PPENDIX F—FLEXIBLE RESERVE STUDY
• 10-m nute spinning reserve can only be provided by resources currently online and
synchronized to the transm ssion grid.
• 10-m nute non-spinning reserve in aj be served by fast-start resources that are capable of
being online and synchronized to the transm ssion grid within ten in hutes. Interruptible
load can only provide non-spinning reserve. Non-spinning reserve in ay be provided by
resources that are capable of providing spinning reserve.
• 30-m nute regulation reserve can be provided by unused spinning or non-spinning
reserve. Increm aital 30-m hute ram ling capability beyond the 10-m inute capability
captured in the categories above also counts toward this requirem ant.
The resources that PacifiCorp em lioys to serve its reserve requirem ants include owned hydro
resources that have storage, owned therm d resources, and purchased power contracts that provide
reserve capability.
Hydro resources are generally deployed first to in a t the spinning reserve requirem ants because of
their flexibility and their ability to respond quickly. The am cunt of reserve that these resources can
provide depends upon the difference between their expected capacities and their generation level
at the tim e The hydro resources that PacifiCorp in aj use to cover reserve requirem acts in the
PacifiCorp West balancing authority area include its facilities on the Lewis River and the Klam A
River as well as its share of generation and capacity from the Mid-Columha projects. In the
PacifiCorp East balancing authority area, PacifiCorp in a' use facilities on the Bear River to
provide spinning reserve.
Therm d resources are also used to in(et the spinning reserve requirem ants when they are online.
The am cunt of reserve provided by these resources is determ fined by their ability to ram pup within
a 10-m hute interval.For natural gas-fired corn hzstion turbines,the am cunt of reserve can be close
to the differences between their nam q)late capacities and their minim un generation levels. In
contrast, both coal and gas-converted steam turbines have slower ram prates and in ay ram pfrom
in him un to in aim un over an hour or in cre. In the current IRP, PacifiCorp's reserve needs are
increasingly in ct by energy storage resources, including contracted resources and proxy resource
selections in the preferred portfolio.
Table F.10 lists the annual reserve capability from resources in PacifiCorp's East and West
balancing authority areas.22 The changes in the flexible resource supply reflect retirem ant of
existing resources, addition of new preferred portfolio resources, and variation in hydro capability
due to forecasted stream fow conditions, and expiration of contracts from the M id-Colum ha
projects that are reflected in the preferred portfolio.
22 Frequency response capability is a subset of the 10-m hute capability shown. Battery resources are capable of
responding with their m aim un output during a frequency event and can provide an even greater response if they
were charging at the start of an event.PacifiCorp has sufficient frequency response capability at present and by 2026
the battery capacity currently contracted or added in the preferred portfolio will exceed PacifiCorp's current 266.4
M W frequency response obligation for a 0.3 Hz event.As a result,com Oiance with the frequency response obligation
is not anticipated to require increm anal supply.
141

PACIFICORBk-2025 IRP PPENDIX F-FLEXIBLE RESERVE STUDY
Table F.10 - Flexible Resource SupplyForecast(Avera De M W)
Year East Supply a V s t Supply as t Supply a V s t Supply
10-Minute 10-Minute 30-Minute 30-Minute
2025 1 816 9 42 2 507 1 016
2026 2 925 9 42 3 629 1 1016
2027 2 924 9 42 3 628 1 016
2028 2 920 2 1113 3 602 2 1188
2029 2 971 2 362 3 661 2 437
2030 3 065 3 1174 3 755 3 1249
2031 3 136 3 265 3 826 3 340
2032 3 313 3 390 4 003 3 1465
2033 3 327 3 433 4 017 3 508
2034 3 325 3 650 4 015 3 725
2035 3 327 3 676 4 1017 3 751
2036 3 308 3 750 3 998 3 825
2037 3 425 3 761 4 116 3 835
2038 3 1425 4 025 4 1116 4 1100
2039 3 432 4 132 4 122 4 207
2040 3 029 5 ,097 3 705 5 1246
2041 3 077 5 274 3 753 5 423
2042 3 977 5 1489 4 654 5 638
2043 3 1947 5 902 4 567 6 051
2044 4 1449 6 099 5 ,069 6 1248
2045 5 165 6 464 5 785 6 613
Figure F.12 and Figure F.13 graphically display the balances of reserve requirements and
capability of spinning reserve resources in PacifiCorp's East and West balancing authority areas
respectively. The graphs dem rnstrate that PacifiCorp's system has sufficient resources to serve its
reserve requirem acts throughout the IRP planning period.Note that keeping m him un am aunts in
energy storage or bringing therm d plants online and/or reducing their generation while online are
required to achieve the reserve capability shown in the figures. In addition, PacifiCorp currently
can transfer a portion of the operating reserves held in either of its balancing authority areas to
help m(et the requirem acts of its other balancing authority area, based on the reserve need and
relative econom bs of the available supply.
142

PACIFICORBk-2025 IRP PPENDIX F—FLEXIBLE RESERVE STUDY
Figure F.12 - Comparison of Reserve Requirements and Resources, East Balancing
Authority Area (MW)
6,000
5,000
4,000 ....... ------ ......�.....� :.
3,000
r
2,000
1,000
0
�o �o `'o �o `'o o o oo
PIP
East Spin(10-m nute) East Non-spin(10-m nute) E ast Regulation(30-m nute)
East Supply(10-M inute) ........East Supply(30-Minute)
Figure F.13 - Comparison of Reserve Requirements and Resources, West Balancing
Authority Area (MW)
7,000
6,000
5,000
3 4,000
3,000
2,000
1,000
0
�o `' `'o `'o �o `'o `'o To `'o `'o �o `'o `'o �1 `'o `O) To `O) 'Po �o
�O �1 `c `ems 7 `�S �6 'j `�� `�.9 po
West Spin(10-m nute) West Non-spin(10-m hate) W st Regulation(30-m nute)
West Supply(10-M inute) •••.*•••West Supply(30-Minute)
Flexible Resource Supply Planning
In actual operations, PacifiCorp has been able to serve its reserve requirem tilts and has not
experienced any incidents where it was short of reserve. PacifiCorp m amges its resources to m(et
its reserve obligation in the Sam e m alner as m Ming its load obligation — through long term
planning,m xket transactions,utilization of the transm ssion capability between the two balancing
authority areas, and operational activities that are perform al on an econom it basis.
143

PACIFICURBk-2025 IRP PPENDIX F-FLEXIBLE RESERVE STUDY
PacifiCorp and the California Independent System Operator Corporation im Oem anted the energy
im balance m aket (EIM)on Novem ber 1, 2014, and participation by other utilities has expanded
significantly with m cre participants scheduled for entry through 2026. By pooling variability in
load and resource output, EIM entities reduce the quantity of reserve required to m o-.t flexibility
needs. Because variability across different BAAS m 3' happen in opposite directions, the
uncertainty requirem ant for the entire EIM footprint can be less than the sum of individual BAAS'
requirem ants. This difference is known as the"diversity benefit"in the EIM.This diversity benefit
reflects offsetting variability and lower com fined uncertainty. PacifiCorp's regulation reserve
forecast includes a credit to account for the diversity benefits associated with its participation in
EIM.
As indicated in OPUC order 12-013, electric vehicle technologies m aj be able to m(et flexible
resource needs. Since the 2023 IRP, electric vehicle load control has been one of the demand
response options available for selection. While operating reserve supply is projected to be well in
excess of operating reserve requirem ants, the rising supply of zero-cost renewable resources
increases the value associated with shifting load within the day and seasonally,rather than just
within the hour as contem Bated in this appendix.
144

Attachment 2
Non-Levelized Wind and Solar Integration Rates

Table 1.Wind Integration Charges
Non-Levelized Rates Levelized Rates Online Year
Year $/MWh Contract Length 2026 2027 2028 2029 2030 2031
2026 1.45 1 $1.45 $0.44 $0.19 $0.24 $0.28 $0.35
2027 0.44 2 $0.96 $0.32 $0.22 $0.26 $0.32 $0.31
2028 0.19 3 $0.72 $0.30 $0.24 $0.29 $0.30 $0.29
2029 0.24 4 $0.61 $0.29 $0.26 $0.28 $0.29 $0.29
2030 0.28 5 $0.56 $0.30 $0.26 $0.28 $0.29 $0.28
2031 0.35 6 $0.53 $0.30 $0.26 $0.28 $0.28 $0.27
2032 0.25 7 $0.50 $0.29 $0.26 $0.27 $0.28 $0.27
2033 0.27 8 $0.47 $0.29 $0.26 $0.27 $0.27 $0.27
2034 0.27 9 $0.46 $0.29 $0.26 $0.27 $0.28 $0.28
2035 0.23 10 $0.44 $0.28 $0.26 $0.27 $0.28 $0.28
2036 0.24 11 $0.43 $0.28 $0.26 $0.27 $0.28 $0.28
2037 0.23 12 $0.42 $0.28 $0.26 $0.28 $0.28 $0.27
2038 0.32 13 $0.41 $0.28 $0.27 $0.28 $0.27 $0.26
2039 0.33 14 $0.41 $0.29 $0.27 $0.27 $0.26 $0.25
2040 0.34 15 $0.41 $0.28 $0.26 $0.26 $0.25 $0.24
2041 0.23 16 $0.40 $0.28 $0.25 $0.25 $0.24 $0.23
2042 0.05 17 $0.39 $0.27 $0.24 $0.24 $0.24 $0.23
2043 0.07 18 $0.38 $0.26 $0.24 $0.24 $0.23 $0.22
2044 0.03 19 $0.37 $0.26 $0.23 $0.23 $0.23 $0.22
2045 0.03 20 $0.36 $0.25 $0.23 $0.23 $0.22 $0.21
2046 0.03 21
2047 0.03 22
2048 0.03 23
2049 0.03 24
2050 0.03 25

Table 2.Solar Integration Charges
Non-Levelized Rates Levelized Rates Online Year
Year $/MWh Contract Length 2024 2025 2026 2027 2028 2029
2024 1.61 1 $1.61 $0.53 $0.41 $0.45 $0.51 $0.77
2025 0.53 2 $1.09 $0.47 $0.43 $0.48 $0.64 $0.86
2026 0.41 3 $0.88 $0.46 $0.45 $0.57 $0.73 $0.80
2027 0.45 4 $0.78 $0.47 $0.53 $0.65 $0.72 $0.77
2028 0.51 5 $0.73 $0.53 $0.60 $0.66 $0.71 $0.71
2029 0.77 6 $0.74 $0.58 $0.61 $0.66 $0.67 $0.67
2030 0.95 7 $0.76 $0.59 $0.61 $0.63 $0.65 $0.64
2031 0.66 8 $0.75 $0.60 $0.60 $0.61 $0.62 $0.61
2032 0.66 9 $0.75 $0.59 $0.58 $0.59 $0.59 $0.59
2033 0.47 10 $0.73 $0.58 $0.57 $0.57 $0.58 $0.57
2034 0.42 11 $0.71 $0.56 $0.55 $0.56 $0.57 $0.56
2035 0.35 12 $0.69 $0.55 $0.54 $0.55 $0.55 $0.54
2036 0.34 13 $0.67 $0.54 $0.54 $0.54 $0.53 $0.52
2037 0.37 14 $0.66 $0.54 $0.53 $0.52 $0.52 $0.50
2038 0.40 15 $0.65 $0.53 $0.51 $0.51 $0.50 $0.48
2039 0.34 16 $0.64 $0.51 $0.50 $0.49 $0.48 $0.47
2040 0.13 17 $0.62 $0.50 $0.49 $0.48 $0.47 $0.46
2041 0.14 18 $0.61 $0.49 $0.47 $0.47 $0.46 $0.45
2042 0.09 19 $0.59 $0.48 $0.46 $0.46 $0.45 $0.44
2043 0.09 20 $0.58 $0.47 $0.46 $0.45 $0.44 $0.43
2044 0.09 21
2045 0.09 22
2046 0.09 23
2047 0.09 24
2048 0.10 25

Attachment 3
Discussion of Integration Topics in Order No. 36243

Attachment No. 3
PacifiCorp Integration Cost
Discussion of Topics Identified in Order No. 36243
In Commission Order No. 36243, PacifiCorp (the Company)was directed to address the
following topics as part of its next Flexible Reserve Study(FRS):
- Fixed cost of regulation reserves: why capital and fixed O&M cost of regulation
reserves should be excluded in the wind and solar integration costs, including
quantifiable evidence.
- Integration for hybrid wind and solar resources: whether hybrid wind or hybrid solar
should receive different treatment than wind or solar alone.
- Impact of load on portfolio diversity: the effect of holding load constant in scaling
portfolio diversity benefits.
- Inter-hour integration costs: the cost implications of changes in wind and solar output
relative to expected levels.
A discussion of each of these topics is provided in the sections below.
Fixed Cost of Regulation Reserves
The FRS in the 2025 IRP accounts for the sub-optimal resource dispatch that occurs when
flexible lower-cost resources are held back to ensure adequate regulation reserves are available
to respond to deviations in the system load and resource balance. When flexible lower-cost
resources are held back to provide reserves,they are no longer be able to support wholesale sales
and higher-cost resources may be called upon to provide energy to serve load, resulting in a
higher net cost to meet system needs than would otherwise be incurred.
The existing and contracted resources in the Company's portfolio have operating reserve
capability that significantly exceeds the average reserve requirements through the end of the IRP
study horizon.' The marginal cost of operating reserves only rarely exceed$25 per megawatt-
hour,which on average occurs in less than one percent of the hours each year in 2027 and
beyond. This indicates that significant shortfalls of reserve capability are not occurring in
individual hours. This is in part due to the relationship between reserve need and wind and solar
output. If the forecasted wind or solar output is zero for the next hour, there is no risk that actual
output will come in below that level and operating reserves do not need to be held in the absence
of that risk. As the forecasted wind or solar output rises, the maximum reserve need grows nut
continues to be bounded by zero. Because of the variability of wind and solar, as the forecasted
capacity factor increases to the 10% to 20% level, having actual output of zero remains relatively
common, and the stand-alone regulation reserve requirement grows more or less linearly as the
forecast increases. However, as the forecasted capacity factor continues to increase the reserve
' See PacifiCorp's 2025 IRP.Volume II(Flexible Reserve Study).Figures F.12-F.13.Values for 2026 represent
existing and contracted resources.
— 1 —

need reaches a maximum level and begins to taper off. For example, the maximum stand-alone
reserve need for east wind is around 25 megawatts of reserves for a forecasted output of 60
megawatts per 100 megawatts of wind capacity.2 Similarly, the maximum stand-alone reserve
need for east solar is around 42 megawatts of reserves for a forecasted output of 65 megawatts
per 100 megawatts of solar capacity.' As forecasted output increases above these levels, it
becomes more certain, and reserve requirements decline.
As a result, forecasted wind and solar output will always exceed the stand-alone reserve
requirement that they impose upon the system. In addition, the stand-alone reserve need
attributed to individual resource types is reduced by around half when the diversity among load,
wind, solar, and non-variable energy resources is accounted for, including the diversity benefits
from pooling requirements among the many participants in the Western Energy Imbalance
Market. If a resource portfolio can reliably meet system needs during periods when wind and
solar output(and associated integration requirements) are near zero, increased wind and solar
output will generally lead to reduced operating levels on other generation sources, naturally
resulting in higher reserve holding, i.e. more resources that are available to respond.
To a degree this interaction is a characteristic of PacifiCorp's portfolio, with a sizeable fleet of
thermal resources that are frequently on the margin when wind and solar generation levels
change. When wind and solar output drops and a natural gas plant is the most economic available
alternative, it ultimately doesn't matter whether that unit is holding reserves or merely backed
down to due unfavorable economics. This is particularly true in WEIM, as shifts in wind and
solar output can be met by smaller generation changes on units spread across multiple utilities,
rather than relying on a large response from a single utility's own generators. An additional
benefit of WEIM is that in some periods a reduction in wind generation will be offset by an
increase in solar generation in a different location, reducing the magnitude and frequency of
dispatch changes by flexible resources. The presence of a range of flexible resource alternatives
is an inherent part of the WEIM, as participants are required to provide flexible capacity over
and above their expected load for dispatch within the market.
Forecasted resource additions are necessary to meet peak load requirements (and net load peak
requirements), and it is reasonable for the fixed costs of resources added to meet peak
requirements to be attributed to capacity rather than as part of the marginal integration costs
developed as part of the FRS in the 2025 IRP. If the 2025 IRP preferred portfolio included
sufficient capacity to meet peak requirements but still required additional flexible resource
additions in order to alleviate shortfalls in regulation reserve capability, it would then be
appropriate to include a fixed resource cost component in the integration rate. This could
potentially occur if utility's portfolio comprised many units with high minimum operating levels,
slow ramp rates, long start times, or restrictive hydro flow constraints.
The Commission recently approved a capacity deficit date of July 2028 for determining the
compensation for QFs.4 This deficit date was based in part on the use of short-term market
2 See PacifiCorp's 2025 IRP.Volume II(Flexible Reserve Study).Figures F.3-F.6.
3 Ibid.
4 PACIFICORP--APPLICATION FOR APPROVAL OF A CAPACITY DEFICIENCY PERIOD TO BE USED
FOR AVOIDED COST CALCULATIONS.Docket No.PAC-E-25-08.Final Order No.36780(October 3,2025)
—2—

purchases, which are most commonly comprised of heavy load hour blocks. While these
purchases can reduce the required dispatch from existing flexible resources (freeing up those
resources to hold operating reserves in much the same way as wind or solar additions), they are
fixed volumes and do not provide operating reserves on their own. Looking at the 2025 IRP
preferred portfolio, and focusing on the cost-effective resources allocated to the
Utah/Idaho/Wyoming/Califomia(UIWC)jurisdiction, the largest category of resource additions
is energy efficiency, which similarly can flee up flexible resources but do not provide operating
reserves directly.' While the UIWC jurisdiction is allocated relatively modest amounts of
demand response and battery storage,which are capable of providing operating reserves, it does
not appear that regulation reserve requirements are driving these resource selections.
The 2025 IRP includes modest amounts demand response in Idaho in 2030-2031, including
programs for irrigation load control, commercial and industrial interruptible load, and residential
smart thermostats. The most expensive of these (commercial and industrial) has an effective net
cost of capacity in the summer of$64/kw-yr, after accounting for the savings from the dispatch
and operating reserve benefits the program provides, and including a gross-up to account for the
capacity contribution of the program. Similarly, the 2025 IRP preferred portfolio includes a 2029
battery storage resource in Wyoming,with an effective net cost of capacity in the summer of
$70/kw-yr, after accounting for the cost of charging, the value of discharging and reserves, and
the capacity contribution of storage. Both of these costs are well below the all-in cost of a
simple cycle combustion turbine (SCCTs) in the 2025 IRP. For example,the modeled cost for a
SCCT in eastern Wyoming was approximately $148/kW-yr in 2030, of which 42% is fixed
operations and maintenance expense (including fixed pipeline costs). The net cost of capacity for
the SCCT amount to $171/kw-yr across the 2025 IRP horizon, significantly more than the
demand response or battery storage resources included in the 2025 IRP preferred portfolio.
Additional detail on the costs and benefits of these resources is provided at the end of this
document.
In light of the discussion above, PacifiCorp does not believe that fixed resource costs are a
necessary component of the proposed wind and solar integration costs.
Integration for Hybrid Wind and Solar Resources
The application of integration costs to hybrid resources depends on the contract structure and
how the resources interact with system requirements.
Independent Resource and Battery Storage Dispatch
One hybrid contracting option is for a resource and a battery at a single interconnection point to
be contracted and dispatched more or less independently, subject to the combined
interconnection limit(e.g. a battery cannot discharge if co-located solar is already generating at
max). PacifiCorp's 2025 IRP includes four 80 megawatt battery storage facilities (Enterprise,
Escalante, Granite Mountain, Iron Springs)which have this configuration. The underlying solar
resources were contracted roughly ten years ago as qualifying facilities (QFs) and are 80
megawatts each. In 2024, the Company contracted for battery storage resources to be co-located
with each of these solar resources. By sharing an interconnection using surplus interconnection
s PacifiCorp's 2025 IRP.Volume I(Chapter 9—Modeling and Portfolio Selections Results).Table 9.11.
—3 —

service these energy storage resources are able to be brought online without requiring upgrades
to the transmission system and without the need to wait for lengthy interconnection study
processes. The Company cannot control the output of the underlying solar QFs,but it will have
full control over the charging and discharging schedules of the energy storage (subject to the
aggregate output remaining within the interconnection limit). Because the sun reliably sets each
night, the battery storage can use the interconnection during relatively valuable periods in the
evening when it would most likely have been dispatched even if it was not using a shared
interconnection.
In this example, integration charges would continue to apply to the underlying solar resource, as
the battery would be economically dispatched in response to system needs,rather than smoothing
out the output of the co-located solar resource. In addition, because the battery is contracted and
compensated separately from the solar resource, all of the benefits of dispatching the battery
(including holding regulation reserves, i.e. the provision of integration service) should flow to
PacifiCorp on behalf of its retail customers who pay the contract costs,rather than to the owner
of the solar resource.
This hybrid contracting option can apply whether or not the co-located solar resource is a QF,
but the battery storage agreement would not be contracted as a QF, as that would limit the
Company's ability to negotiate pricing and other contract terms and to charge and discharge the
resource in an optimized manner. Given the flexibility and additional value this option provides,
it is the preferred means of procuring battery storage.
While battery storage can also be added to wind resources, the value is reduced because wind
resources may generate at or near their interconnection limit during the optimal periods for
battery discharge,unlike solar generation which always drops off as sunset approaches. While
the wind output would be valuable in such periods, a portion of the battery storage could be
trapped, such that it would not provide incremental capacity to serve customers during such
periods, thus resulting in a lower value. This effect can be reduced by adding storage at a fraction
of the wind resource's interconnection limit, for example a 25 MW battery co-located with a 100
MW wind resource would only be trapped once wind output exceeded 75 MW, and periods in
which wind output exceeded that level might tend to be less valuable (particularly if regional
wind resources follow a similar pattern). In contrast, the Company's recent co-located storage
contracts have had energy storage capacity equal to 100% of the solar nameplate.
Combined Resource and Battery Storage OF Contracts
A second hybrid contracting option is for a solar and battery under a single QF contract, with the
battery charging solely from the co-located solar,rather than from the grid as is possible with
non-QF contracts. For example, the Company's approved standard QF pricing in Oregon
includes a solar and storage resource type.6 To capture the value of the battery component,
Oregon's standard solar and storage rates include a customized"premium peak" definition with
very high prices that covers the five hours with the highest value in each month. The rest of the
6 Oregon Standard Avoided Cost Rates.Avoided Cost Purchases From Eligible Qualifying Facilities.Available at:
hllps://www.pacificpower.net/content/dam/pcorp/documents/en/pacificpower/rates-
regulation/oregon/tariffs/purpa/Standard_Avoided_Cost_Rates_Avoided_Cost_Purchases_From_Eligible Qualifyin
g_Facilities.pdf
—4—

hours in each month are compensated at a lower price that is closer to the price for solar-only
facilities. The Oregon solar and storage QF type and pricing methodology were approved on an
interim basis and have not yet been used by any of the Company's QFs. The current
methodology applies the integration cost to all output from solar and storage QF, including
deliveries during the premium peak period which could include some solar generation, and
changes are currently under consideration.7
PacifiCorp has also provided indicative pricing for non-standard hybrid solar and battery QFs,
though again no contracts have been executed. Generally, the Company identifies a monthly
peak definition that corresponds to the hours of storage (i.e. a four-hour battery would receive a
four-hour peak definition) in the proposed facility and provides avoided cost prices that
correspond to the developer's proposed aggregate output profile, which would account for the
ability of the proposed storage capability to move output into the peak period. This shift in
output increases the value of the project overall, including the capacity contribution,but it is
heavily influenced by the specific design and operating characteristics of the proposed energy
storage, limiting the applicability for standard QFs as a whole. Given Idaho standard QF rates for
wind and solar only apply to resources up to 100 kW, most hybrid QFs that include wind or solar
would be seeking non-standard contracts and project-specific parameters could be used to
develop appropriate avoided cost rates under the IRP methodology.
At present, integration costs do not apply to wind or solar QFs that agree to schedule and deliver
output on a firm hourly basis, for instance by paying a transmission provider for integration in
conjunction with a wheeling contract. It would be reasonable to apply that same standard to a
that uses its own co-located battery storage to schedule and deliver output on a firm hourly basis.
This would require additional contract language describing the required coordination with the
utility, similar to what is currently used for off-system customers.
The Company's diverse system, with geographically distributed load and resources of multiple
types including both solar and wind, has lower regulation reserve requirements than would be
required for an individual resource, resulting in low integration costs. Put another way, providing
integration service to firm the output of a single resource requires proportionately more
capability than balancing the system as a whole. Because energy storage can provide greater
value when dispatched to meet system needs, and can be contracted separately to capture that
flexibility, developing QF pricing that differentiates based on the provision of integration service
is of limited value,particularly when the proposed and current integration costs are very low, as
they are at present.
Impact of Load on Portfolio Diversity
In the 2025 IRP, the Company's FRS accounts for the diversity as the quantity of wind and solar
varies through time. When viewed independently, the stand-alone reserve requirements for load,
wind, solar, and non-variable energy resources amounted to 1,057 MW in the 2018-2019
historical period.$When assessed as a portfolio the regulation reserve requirement dropped to
approximately 680 MW,which represents a portfolio diversity credit of 36%. After incorporating
7 Oregon Investigation into PURPA Implementation.Docket No.UM 2000.
$2025 IRP:Volume II.Appendix F. Table F.5
—5 —

additional regional diversity from participation in the Western Energy Imbalance Market
(WEIM), the regulation reserve requirement dropped to approximately 540 MW, for an overall
reduction of 49%.
The FRS does not assume that the 36%portfolio diversity credit is static, and calculations were
made to assess the level of diversity over a range of potential wind and solar capacity levels, to
allow regulation reserves to be calculated consistent with possible resource selections over time.9
Wind and solar are the biggest drivers over the forecast period, as these could increase by five to
ten times or more over the forecast period relative to what was present in the Company's east
and west balancing authority areas in the 2018-2019 historical period. While not shown, the
Company had to develop additional calculations to identify appropriate diversity values for wind
and solar additions in excess of what was shown in the figures.
The portfolio diversity calculation in the FRS uses the 2018-2019 historical deviation for each
class (load,wind, solar, and non-variable energy resources),but scales the wind and solar
volumes and deviations by varying amounts. When wind capacity is doubled, wind deviations
are assumed to double and the stand-alone reserve requirements for wind would double. Because
the Company's existing portfolio of wind and solar in the 2018-2019 period is relatively diverse,
with a large number of generators, the addition of new wind or solar plants to the portfolio may
not result in a lower error rate,particularly if those additions are in close proximity to the
existing fleet. This is also true for solar. In the FRS, these expanded stand-alone requirements
for wind and solar were lined up against static requirements for load and Non-VERB, and
portfolio diversity was recalculated. On the east side of the system, where large quantities of
wind and solar were already present in the historical period, further additions result in declining
diversity. On the west side of the system, solar resource additions up to around five times the
historical capacity level would increase overall diversity while wind resource additions would
result in declining diversity.
While not accounted for in the current FRS, load is also projected to increase over the 2025 IRP
study horizon, though the relative change is much smaller than the projected changes in wind and
solar. By 2045, east and west load increasing by about 17% and 26%, respectively, relative to the
historical period, with most of that change in the last few years of the study horizon. As with
wind and load, increasing load would increase the magnitude of errors, and would result in a
linear increase in stand-alone reserve requirements. Because load represents roughly one-third of
the overall reserve need,proportionately higher reserves for load could act to dilute the impact of
reserve requirements to accommodate the wind and solar capacity additions. To estimate this
effect, the Company calculated regulation reserve requirements based on pro-rated wind and
solar capacity that was scaled to reflect the increase in load. For example, diversity values for the
east in 2045 were calculated based on wind and solar capacity values that were divided by 1.17.
This lowers the effective wind and solar capacity and shifts the diversity results down and to the
left, as illustrated in the figure below. At the wind and solar penetration levels in the 2025 IRP
preferred portfolio,this increases the relative level of diversity, resulting in slightly lower reserve
requirements. A similar impact occurs in the west.
12025 IRP:Volume II.Appendix F. Tables F.7-F.8
—6—

Figure: PacifiCorp East Portfolio Diversity with Load Adjustment
MW % %Reduction vs. Stand-alone Requirements)
8,224 548% 17. o 20.6% East Load Rsv.Req%
lt' 2035:+1.2% -0.1
u 7,184 472% 19.2% 21.5% 23.0% 25.5% 26.5% 2045:+16.9% -4.7%
6,144 395% 22.9% 24.1% 25.6% 27.9% 28.5% 29.0%
U 5,104 319% 26.0% 27.3% 29.2% 30.7% .7°1J 30.5% 29.5% 251RP Pref.Port.
4,064 242% 30.4% 31.6% 32.9% 33.8% 32.7% 32.8% 32.8% Nameplate(MW)
3,024 166% 35.0% 36.2% 38.5% 37.1% 37.6% 36.2% 33.9% 31.9% 2035 Wind:4,894
2035 Solar:3,798
e"a 1,575 100% 48.0% 45.8% 43.1% 39.5% 35.8% 32.2% 29.4% 2045 Wind:4,516
W 2045 Solar:3,184
788 50% 46.4% 40.3% 36.4% 33.0% 30.0% 27.3%
50% 100% 166% 329% 493% 656% 820% 983% %
428 855 1,462 2,502 3,542 4,582 5,622 6,662 MW
East Solar Capacity
2018-2019 Actual Wind and Solar Capacity
Accounting for the impact of load growth has a modest impact on regulation reserve
requirements, as peak loads are relatively flat in the 2025 IRP through 2035 (after accounting for
energy efficiency selections). Between 2036 and 2045, east regulation reserve requirements fall
by an average of 27 megawatts, or 2.3%, while west regulation reserve requirements fall by an
average of 61 megawatts, or 5.5%.
While overall regulation reserve requirements fall slightly, the integration costs reported in the
FRS are based on the marginal requirements associated with incremental wind and solar
additions, relative to the levels in the 2025 IRP. Over the study horizon from 2025-2045, this
load adjustment reduces the average integration cost for both wind and solar by approximately
one cent per megawatt-hour($0.01/MWh). Given the minimal impact, the proposed wind and
solar integration rates in this proceeding were not modified from what was reported in the 2025
IRP.
Inter-hour Integration Cost
In past FRS analysis, the Company has considered costs related to day-ahead uncertainty in wind
and solar forecasts: how much the forecasted output for the next day differs from what actually
occurs and the cost of system resources that need to be available to respond. Typically this has
captured the cost of sub-optimal natural gas plant startup decisions-when too many plants are
started on a day when renewables are higher than expected or when not enough plants are started
on a day when renewables are lower than expected. With relatively low natural gas prices,
increased diversity from geographically distributed wind and solar, and increased flexibility from
battery storage,natural gas plant starts are not as large of a cost driver as in the past. In addition,
with the upcoming start of the California Independent System Operator's (CAISO) Extended
Day-Ahead Market(EDAM), renewable supply and natural gas plant starts will be coordinated
across a much larger footprint, resulting in lower costs. The Company expects day-ahead
uncertainty has an important role in system costs, and anticipates that EDAM participation will
provide valuable data to quantify the costs and risks.
-7-

For the 2025 IRP, the Company opted to take a slightly different approach to wind and solar
forecasting and uncertainty. The Company worked with a consultant, Hendrickson Renewables,
to develop historical hourly wind and solar generation profiles from 2006-2023, for a large
number of geographic locations across its systems, including both existing resources and proxy
resources available for selection in the IRP.10 Because the data is based on historical weather
conditions (including global reanalysis data),the hourly data for individual facilities
automatically reflects the appropriate correlation between different locations and technologies.
While the Company has previously used load profiles based on selected historical conditions, for
the first time in the 2025 IRP, the Company was able to align wind and solar output with the
peak-producing weather conditions,by ensuring that load patterns and wind and solar profiles
were drawn from the same historical days. This technique was also extended to market prices for
electricity and natural gas as well as forced outages for thermal units. The result is that
correlation among all of these inputs is a better representation of the expected conditions. Each
month of the Company's chaotic normal load forecast reflects the range of weather conditions
experienced in the most typical month from 2013-2022, with wind, solar and market price
reflecting the same historical days as the load forecast.
In addition, stochastic analysis in the 2025 IRP reflected a range of possible wind and solar
outcomes for the first time, rather than a static single year generation profile. Using actual
weather conditions experienced in every year from 2006-2023 provides a range of realistic
outcomes with inherently correlated inputs. This annual weather selection also allows for the
effect of a range of hydro water years to be captured in a more realistic way than in the past.
While the variation is smaller than for hydro, average annual capacity factor for wind varied
between 31.2% and 36.7%, while the average annual capacity factor for solar varied between
27.9% and 29.5%.11 In both cases, variation for individual facilities is larger. While not
specifically tied to integration costs, the impacts of variation in wind and solar output are
measured as part of the stochastic risks.
Stochastic analysis based on these data sets can provide greater insight into reliability risks as
wind and solar become a larger share of the Company's resource mix. Marginal capacity
contribution analysis in the 2025 IRP is based on wind and solar conditions specific to the hour
where a shortfall occurs (i.e. the selected historical year from 2006-2023). As with any complex
system, shortfalls are never due to only one thing, and the ability to readily identify a specific
historical day is helpful for evaluating risks in a much more direct manner. In the past a shortfall
would have been much less tangible,not a specific day's events but a random draw of a two
standard deviation increase in load that happens to coincide with several randomized thermal
plant forced outages.
By more accurately representing wind and solar values across a range of load and market price
conditions, the 2025 IRP provides a better representation of the role these resources can fulfill as
well as their limitations. While day-ahead uncertainty and inter-hour integration costs have not
yet been calculated, this historical data framework should enhance the results by ensuring that
various system cost impacts are represented in a realistic manner.
10 2025 IRP:Volume II.Appendix H.p. 153-155
" 2025 IRP:Volume II.Appendix H.Table H.4
— 8 —

Capacity Summary
SCCT Frame -Wyoming East Brownfield
NPV 2029-2045 $167.42 $0.68 $166.74 $171.37
First Year Total
Fixed Capital Fixed Resource Total Net Resource Summer&
Estimated Cost at Real O&M+ Fixed Generation Fuel and Reserves Resource Cost/ Winter Net Cost of
Year Capital Cost LevelizedRate Pipeline Costs Revenue VOM(Cost) Revenue Benefits (Benefit) Contrib. Capacity
$/kW $/kW-yr $/kW-yr $/kW-yr $/kW-yr $/kyi-yr $/kW-yr $/kW-yr $/kW-yr % $/kW-yr
(a) (b) (C) (d)=(b)+(e) (e) (t) (9) (h)=(e)+(f)+(g) (i)=(d)-(h)
2029 $1,376 $83.96 $60.65 $144.61 $1.18 $1.10) $0.00 $0.08 $144.53 97% $148.54
2030 $85.79 $61.97 $147.76 $1.81 ($1.75) $0.00 $0.05 $147.71 97% $151.81
2031 $87.66 $63.33 $150.99 $1.04 ($3.72) $3.05 $0.37 $150.62 97% $154.80
2032 $89.57 $64.71 $154.28 $3.48 ($5.62) $2.88 $0.75 $153.53 97% $157.79
2033 $91.52 $66.12 $157.64 $2.84 ($3.88) $1.97 $0.92 $156.72 97% $161.06
2034 $93.52 $67.56 $161.08 $2.19 ($2.63) $1.14 $0.71 $160.37 97% $164.82
2035 $95.56 $69.03 $164.59 $4.31 ($4.50) $1.52 $1.33 $163.26 97% $167.79
2036 $97.64 $70.54 $168.18 $1.03 $1.09) $0.19 $0.13 $168.05 97% $172.71
2037 $99.77 $72.07 $171.84 $3.26 $2.51 $0.40 $1.15 $170.69 97% $175.43
2038 $101.94 $73.64 $175.59 $4.91 $5.78 $2.25 $1.38 $174.21 97% $179.04
2039 $104.17 $75.25 $179.42 $10.37 $9.19) $2.67 $3.84 $175.58 97% $180.45
2040 $106.44 $76.89 $183.33 $0.00 $0.00 $0.00 $0.00 $183.33 97% $188.42
2041 $108.76 $78.57 $187.32 $0.75 ($1.21) $1.21 $0.75 $186.57 97% $191.75
2042 $111.13 $80.28 $191.41 $0.00 $0.00 $0.00 $0.00 $191.41 97% $196.72
2043 $113.55 $82.03 $195.58 $0.00 $0.00 $0.00 $0.00 $195.58 97% $201.01
2044 $116.03 $83.82 $199.84 $1.90 ($1.85) $0.00 $0.06 $199.78 97% $205.32
2045 $118.56 $85.64 $204.20 $8.07 $7.85 $0.00 $0.22 $203.98 97% $209.64
Sources, Inputs and Assumptions
Source: (a)(b)(c) PlantCosts -20251RP
(b) _(a)x 6.100% Real Payment Factor@ 00%ITC
(e)(f)(g) Estimated based on Cradsby 4,5,6
-9-

Capacity Summary
Lithium Ion Battery Storage (4hr)-Wyoming North
NPV 2029-2045 $130.87 $80.73 $50.13 $70.34
Fixed
Capital
Cost at Net
Estimated Real Total Net Total Resource Net Cost of Net Cost of
Capital Levelized Fixed Resource Generation Costto Generation Reserves Resource Cost/ Summer Winter Summer Winter
Year Cost Rate O&M Costs Revenue Load Revenue Revenue Benefits (Benefit) Contrib. Contrib. Capacity Capacity
$/kW $/kW-yr $/kW-yr $/kW-yr $/kW-yr $/kW-yr $/kW-yr $/kW-yr $/kW-yr $/kW-yr % % $/kW-yr $/kW-yr
(a) (b) (c) (d)=(b)+(c) (e) (fl (g)=(e)+(t) (h) (i)=(g)+(h) 0)=(d)-(i) (k) (1) (m)=(j)/(k) (n)=O)/(1)
2029 $1,569 $69.86 $43.18 $113.04 $53.88 ($10.04) $43.84 $9.05 $52.90 $60.14 83% 54% $72.04 $111.88
2030 $71.38 $44.13 $115.51 $66.45 ($16.26) $50.19 $9.35 $59.54 $55.97 82% 52% $68.20 $106.83
2031 $72.94 $45.09 $118.02 $62.26 ($23.88) $38.38 $62.22 $100.60 $17.43 81% 51% $21.59 $34.20
2032 $74.53 $46.07 $120.60 $59.13 ($20.82) $38.32 $65.93 $104.24 $16.35 79% 50% $20.62 $33.01
2033 $76.15 $47.07 $123.23 $62.50 ($20.31) $42.19 $58.42 $100.61 $22.62 78% 48% $29.04 $46.95
2034 $77.81 $48.10 $125.91 $64.32 ($18.61) $45.72 $57.58 $103.30 $22.61 77% 47% $29.55 $48.38
2035 $79.51 $49.15 $128.66 $70.17 ($24.47) $45.70 $37.94 $83.64 $45.02 75% 45% $59.94 $99.34
2036 $81.24 $50.22 $131.46 $72.11 ($27.86) $44.25 $36.21 $80.46 $51.00 74% 44% $69.21 $116.03
2037 $83.01 $51.32 $134.33 $79.40 ($29.10) $50.29 $29.34 $79.63 $54.70 72% 43% $75.69 $128.61
2038 $84.82 $52.43 $137.26 $85.69 ($31.69) $54.00 $31.70 $85.70 $51.56 71% 41% $72.69 $125.43
2039 $86.67 $53.58 $140.25 $92.53 ($32.38) $60.16 $32.50 $92.65 $47.60 69% 40% $68.49 $119.78
2040 $88.56 $54.75 $143.31 $88.21 ($34.34) $53.87 $30.82 $84.68 $58.62 68% 38% $86.12 $153.01
2041 $90.49 $55.94 $146.43 $92.14 ($41.93) $50.21 $51.87 $102.08 $44.35 67% 37% $66.46 $120.23
2042 $92.46 $57.16 $149.62 $103.84 ($52.73) $51.11 $1.31 $52.42 $97.21 65% 35% $148.84 $274.11
2043 $94.48 $58.40 $152.88 $113.41 ($57.07) $56.34 $0.01 $56.35 $96.54 64% 34% $151.11 $283.13
2044 _ $96.54 $59.68 $156.22 $118.09 ($61.05) $57.04 $0.00 $57.04 $99.18 62% 33% $158.79 $303.58
2045 $98.64 $60.98 1 $159.621 $111.32 ($61.98) $49.33 $0.001 $49.33 1 $110.29 61% 31% $180.44 $352.99
Sources,Inputs and Assumptions
Source:
(a) Plant capacity cost
(b) _(a)x 0.04452
(c) Plant Costs -2025 n2P-Table 7.1&7.2
4.452% Real-Levelized Payment Factor,40%ITC
5.386% Nominal-Levelized Payment Factor,40%ITC

Capacity Summary
Demand Response -Commercial and Industrial- Goshen
NPV 2031-2045 $64.77 $19.54 $45.23 $64.27
Total Net Resource Net Cost of
Fixed Generation Reserves Resource Cost/ Summer Summer
Year O&M Revenue Revenue Benefits (Benefit) Contrib. Capacity
$/kW-yr $/kW-yr $/kW-yr $/kW-yr $/kW-yr % $/kW-yr
(a) (b) (C) (d)=(b)+(c) (e)=(a)-(d) (fl (h)=(e)/(f)
2031 $56.84 $1.54 $23.07 $24.61 $32.23 81% $39.93
2032 $58.08 $1.52 $22.54 $24.06 $34.03 79% $42.91
2033 $59.35 $1.66 $23.09 $24.75 $34.60 78% $44.43
2034 $60.64 $1.64 $23.78 $25.42 $35.22 77% $46.02
2035 $61.97 $1.80 $20.10 $21.90 $40.07 75% $53.34
2036 $63.32 $1.88 $19.44 $21.32 $42.00 74% $57.00
2037 $64.70 $1.87 $17.23 $19.10 $45.60 72% $63.10
2038 $66.11 $1.96 $19.19 $21.15 $44.95 71% $63.38
2039 $67.55 $1.77 $19.77 $21.55 $46.00 69% $66.19
2040 $69.02 $2.09 $19.07 $21.16 $47.86 68% $70.31
2041 $70.52 $2.38 $29.00 $31.38 $39.14 67% $58.66
2042 $72.06 $1.96 $1.33 $3.29 $68.77 65% $105.30
2043 $73.63 $2.46 $0.00 $2.46 $71.17 64% $111.41
2044 $75.24 $2.51 $0.00 $2.51 $72.73 62% $116.45
2045 $76.881 $2.43 $0.001 $2.43 1 $74.45 61% $121.81
- 11 -