20220311PAC to Staff 39-46.pdf

Y ROCKY MOUNTAIN
PO'I'ER
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:L,..n!n\l']tllL'iE Salt Lake City, Utah &4116
March 11,2022
Jan Noriyuki
ian.norivuki@ouc. idaho. eov (C)
Riley Newton
riley.newton@nuc. idaho. sov
RE: ID PAC-E-21-19
IPUC Set 2 (3946)
Please find enclosed Rocky Mountain Power's Responses to IPUC's 2od Set Data Requests 39-
46. Also provided are Attachments IPUC 41 and 45.
If you have any questions, please feel free to call me at [phone]
Sincerely,
-Jsl-J. Ted Weston
Manager, Regulation
Enclosures
C.c.: Rose Monahan/Sierra Club [e-mail] (C)
Ana Boyd/S iena C lub ana.bovd@ sierrac lub. ore (C)
Benj amin J. Otro/ICL botto@ idahoconservation. org
PAC-E-21-19 / Rocky Mountain Power
March 11,2022
IPUC Data Request 39
IPUC Data Request 39
2O2llntegrated Resource Plan - Please ans\iler the following regarding the
advanced nuclear NatriumrM demonstration project:
(a) Please list and explain the risks of selecting the advanced nuclear Natriumru
demonstration project as a resource in the Prefened Portfolio, noted in the
Updated 2021 IRP, Volume I, Chapter I - Executive Summary, 2021 IRP
Roadmap.
(b) For each of the risks listed above, please provide ttre Company's plans to
mitigate each of the identified risks, including the need for any contingencies.
(c) What are the potential risks that could cause the 500 MW advanced nuclear
NariumrM demonstration projec! scheduled to come online by summer 2028,
to be delayed?
(d) Please provide the specific checkpoints in the project schedule and the criteria
that would trigger a contingency in case of a potential delay.
Response to IPUC Data Request 39
(a) The selection of the Nafiiumru nuclear reactor demonstration project
assumes the technology can be licensed by the Nuclear Regulatory
Commission (NRC)), and that the United States (U.S.) Deparfinent of Energy
(DOE) will confribute to the investnent cost of the project. Please refer to the
Company's response to subpart (b) below for the explanation of risk.
(b) The Company is in the process of negotiating the NatiumrM nuclear reactor
demonstration project contract to establish project delivery, licensing,
invesfrnent and operating costs, fueling, and performance guarantees to ensure
customer risk is minimized.
(c) This project has potential risks which include licensing, fuel supply,
construction risks, etc. PacifiCorp is aware of these risks and will continue to
further evaluate, as well as develop contracts and contingencies, to ensure
customer risk is minimized.
(d) Checkpoints and project schedule potential contingency triggers are being
evaluated to ensure customer risk is minimized.
Recordholder:Dan Swan / Chuck Tack
Sponsor:Shay LaBray
PAC-E-21-19 / Rocky Mountain Power
March 11,2022
IPUC Data Request 40
IPUC Data Request 40
202llntegrated Resource Plan (IRP) - The Company indicates that no new
natural gas proxy resources were made available for selection in any of the Initial
Portfolios due to the risk of stranded-costs associated with planning a system that
is reliant on new natural gas resources having a depreciable life of between 30 to
40 years as noted on page 245, in the Updated 2021 IRP - Volume I, Chapter 8 -
Modeling and Portfolio Evaluation Approach, Initial Portfolios. Please provide
the following:
(a) Please identifr the specific resources categorized as "natural gas proxy
resources".
O) Did the Company consider an approach where over time the natural gas proxy
resource would transition initially from natural gas as the fuel, to a fuel blend
of natural gas and hydrogen, and then ultimately hydrogen as the final fuel
recognizing some need for plant upgrades or retrofitsl to the resource over
time? If not, why not? Please explain.
Response to IPUC Data Request 40
(a) The natural gas proxy resources are shown in PacifiCorp's2Dl Integrated
Resource Plan (lRP), Volume I, Chapter 7 (Resource Option), specifically
Table 7.1 (2021 Supply-Side Resource Table (2020$)) on pages 17l and 172,
and Table 7.2 (Total Resource Cost for Supply-Side Resource Options) on
pages 176 through 178.
(b) Conversion of resources from natural gas to a natural gas/hydrogen blend to
hydrogen fuel was not considered as a supply side resource. Equipment
manufacfurers were not offering conversion of a natural gas resource to
blended fuels or to hydrogen in the foreseeable future. Preparing reasonable
cost and performance estimates for resources that are not offered by the
market for deployment in the foreseeable future is not possible, and therefore
omitted from PacifiCorp's IRP analysis.
Recordholder:Dan Swan / Grant Laughter
Shay LaBraySponsor:
lhttps://www.ge.com/content/darn/gepower-new/global/en-US/downloads/gas-new-site/future-of:
energy/hy dro gen- fuel - lor-gas-turbines-sea3 4979.pd f
PAC-E-21-19 / Rocky Mountain Power
March 11,2022
IPUC Data Request 4l
IPUC Data Request 41
202llnteg:rated Resource Plan flRP) - Please provide the Company's analysis
and supporting documentation used to determine the "line loss factors'o contained
in section "System Losses" referenced on page 13, in the Updated 2021 IRP -
Volume II, Appendix A - Load Forecast Details.
Response to IPUC Data Request 4l
Please refer to Attachment IPUC 4l which provides the analysis and supporting
documentation used to determine the line loss factors used in PacifiCorp's2021
Integrated Resource Plan (IRP).
Recordholder: Lee Elder
Sponsor:Shay LaBray
PAC-E-21-19 / Rocky Mountain Power
March 11,2022
IPUC Data Request 42
IPUC Data Request 42
202llntegrated Resource Plan (IRP) - Please list the "consideration of risks" in
section "General Compliance" referenced on page 24,inthe Updated 2021 IRP -
Volume II, Appendix B - IRP Regulatory Compliance, and explain how they
were addressed.
Response to IPUC Data Request 42
The term "consideration of risks" is part of PacifiCorp's2021lntegrated
Resource Plan (tRP) process and is discussed further rr:,2021IRP, Volume I,
Chapter 8 (Modeling and Portfolio Evaluation Approach) on page 220. Specific
risks are quantified in the stochastic modeling through the reported present value
of revenue requirements (PVRR).
Resource portfolios developed by the long-term (LT) model and adjusted for
reliability by the short-term (SQ model, are simulated in the medium-term (MT)
model to produce mefiics that support comparative cost and risk analysis among
the different resource portfolio altematives. Stochastic risk modeling of resource
portfolio altematives is performed using Monte Carlo sampling of stochastic
variables across the 20-year study horizon, which include load, natural gas and
wholesale elecficity prices, hydro generation, and unplanned thermal outages.
The MT results are used to calculate a risk adjustnent which is combined with ST
model system costs to achieve a final risk-adjusted PVRR to guide portfolio
selection.
While there are specific risks identified throughout the [RP, neither
"consideration of risks" nor "uncertainties" should be construed as technical terms
that would limit the risks that may be considered throughout the IRP.
Also, please refer to the Company's response to IPUC Data Request 43.
Recordholder:Dan Swan
Sponsor:Shay LaBray
PAC-E-21-19 / Rocky Mountain Power
March 11,2022
IPUC Data Request 43
IPUC Data Request 43
2021lntegrated Resource Plan (IRP) - Please list the "uncertainties" referenced
on page 24 of the Updated 2021 IRP - Volume II, Appendix B - IRP Regulatory
Compliance, and explain how they were addressed.
Response to IPUC Data Request 43
The term "uncertainties" refers to potential changes in the planning environment
such as state and federal carbon dioxide (COz) legislation, regional haze, clean air
and water, new source review, renewable portfolio standards (RPS), federal and
state tax law, technology improvements, state policy and regulations, climate
change, transportation electrification, hydro licensing, request for proposals
(RFP), community solar, fundamental shift in power and natural gas markets, and
global events.
In response to the question, "how were uncertainties addressed," the evaluation of
risk is an overarching goal of the entire Integrated Resource Plan (lRP). In terms
of modeling, risks are encompassed in the Company's stochastic assumptions, a
broad consideration of price-policy futures, variant portfolios, sensitivities, and
specific analysis such as emission and unserved load, all of which comprise the
substance of the Company's portfolio development and selections. There are also
un-modeled risks, such as those reflective of the inclusion of new natural gas
resources, that are addressed in the appropriate sections of the 2021 tRP, which
are addressed in narrative form as well as a specific sensitivity.
Recordholder: Dan Swan
Sponsor:Shay LaBray
PAC-E-21-19 / Rocky Mountain Power
March 11,2022
IPUC Data Request 44
IPUC Data Request 44
202llntegrated Resource PIan ORP) - Please explain how the Company
determined the timeframe (hours, months, seasons, etc.) that the Company's
demand response programs can be dispatched. For example, did the Company
base the timeframe on hours with the highest loss of load probability, peak load,
or some other method? If each program used a different requirement for
determining dispatch timeframes or if the dispatch timeframes are different,
please explain the reason for the differences.
Response to IPUC Data Request 44
The months and seasons of assumed demand response @R) availability are
consistent with the end use (e.g. cooling or inigation). The number of hours a DR
resource could be called upon in a single day or year reflected values typical for
the specific program type. For example, an inigation program allowed for
curtailments of up to four hours per day and 52 hours per year. As part of
PacifiCorp's2021Integrated Resource Plan (tRP), the Company did not restict
the timing of curtailment events to particular hours in the day in the PLEXOS
model but allowed it to optimize. The timing of the Company's dispatch needs are
evolving, and a single curtailment defurition may not remain suitable over the IRP
horizon. Because many types of DR programs are becoming increasingly
automated, customer involvement during an event may not be necessary such that
a defined window is needed. Much of the benefits of the flexibility can be
achieved by allowing DR to be called in any hour for emergency conditions,
while limiting economic arbitrage to defned windows. The trade-offs would be
sorted out during the development of a specific program.
Recordholder: Dan MacNeil
Sponsor:Shay LaBray
PAC-E-21-19 / Rocky Mountain Power
March 11,2022
IPUC Data Request 45
IPUC Data Request 45
Z02llntegrated Resource Plan (IRP) - Please provide the following details for
each of the Company's demand response programs:
(a) Jurisdiction;(b) Name;(c) Directed customer class (i.e. residential, commercial, industrial, or
irrigation);(d) Nameplate capacity (MW);
(e) Program Season (summer, winter, year-round);(0 Yearly program cost ($/IvIW nameplate capacity);(g) Dispatchable periods (i.e. season dates, days of the week, and hours ofthe
daY);(h) Dispatchlimitations;
O Number of participants;
() Company required notification to participant prior to dispatch (hours); 4
hours(k) Participant incentive (fixed ($/kW1, variable ($/kwh));(l) Participant penalties for opt-out (fixed ($lkW), variable ($/kWh)); and
(m) Program contribution to operating reserves by type (spin, non-spin,
frequency, ... etc.).
Response to IPUC Data Request 45
Please refer to the responses below regarding the following demand response
@R) programs:
(l) Inigation Load Control Program,
(2) Cool Keeper Program,
(3) Wattsmart Batteries Program, and
(4) Oregon Irrigation Load Control Pilot Program.
(1) Irrigation Load Control Program:
(a) Jurisdiction - Rocky Mountain Power (RMP) - Idaho and Utah.(b) Name - Irrigation Load Control.(c) Directed customer class (i.e. residential, commercial, industrial, or
irrigation) - irrigation.(d) Nameplate capacity (megawatts (MW)) - Idaho 202MW, and Utah 14
MW.
PAC-E-21-19 / Rocky Mountain Power
March 11,2022
IPUC Data Request 45
(e) Program Season (summer, winter, year-round) - Summer (June I
through September 30).
(f) Yearly program cost ($/TvIW nameplate capacity) - This metric is
unavailable.(g) Dispatchable periods (i.e. season dates, days of the week, and hours of
the day) - June I through September 30, 2 PM to 9 PM (Mountain
Time), Monday through Friday excluding holidays.(h) Dispatch limitations - Limited to one dispatch per day. Not more
than four hours per event. Events are limited to a maximum of l2
event hours per week and 52 event hours per season.(i) Number of participants - 152 Idaho customers (1,240 sites), and 42Utah
customers (l3l sites).
0) Company required notification to participant prior to dispatch (hours) -
four hours minimum.(k) Participant incentive (fixed (dollars per kilowatt ($/kW)), variable
(dollars per kilowatt-hour ($/kWh)) - please refer to the table provided
below:
AveraSe
Expected kW
per Pump
Ease lncentlve Rate(t/kW)
Utah ld.ho
s2s
519
Bonu! lncentlve Rate(t/kW)
'1, proSram l5 ,125 MW
Utah ldaho
$27 S25
s23 527
Over 100 kW
Under 1OO kW s21
(l) Participant penalties for opt-out (fixed ($/kW), variable ($/kWn;) -
Customers may choose not to participate (opt out) in any
event. Opting out lowers average participation percentage and
payments proportional ly.
(m) Program contribution to operating reserves by type (spin, non-spin,
frequency, ... etc.) - Reduce load uncertainty
(2) Cool Keeper Prugram
(a) Jurisdiction - Utah.(b) Name - Cool Keeper.(c) Directed customer class (i.e. residential, commercial, industrial, or
irrigation) - residential and commercial.
(d) Nameplate capacity (lvftV) - 240 MW.
(e) Program Season (summer, winter, year-round) - Summer (May I
through September 30).
(0 Yearly program cost ($/lvIW nameplate capacity) - This metric is
unavailable.
PAC-E-21-19 / Rocky Mountain Power
March 11,2022
IPUC Data Request 45
(g) Dispatchable periods (i.e. season dates, days of the week, and hours of
the day) - May I through September 30, 2 PM to 9 PM (Mountain
Time), Monday through Friday excluding holidays.(h) Dispatch limitations - Maximum of four hours per day and not more
than 100 hoursperprogram year.(D Number of participants - 94,000 customers/ 108,000 devices.
0) Company required notification to participant prior to dispatch (hours) -
None.(k) Participant incentive (fixed ($/kW), variable ($/kWtrl; - Fixed - $30
(Level l: up to five tons), and Fixed - $60 (Level2:5.5 ton and
above)).
0) Participant penalties for opt-out (fxed ($/kW), variable ($/kWn; -
None.
(m) Program contribution to operating reserves by type (spin, non-spin,
frequency, ... etc.) - Flexible resource - frequency, contingency,
forecast uncertainty.
(3) Wattsmart Batteries Program
(a) Jurisdiction - Utah.
O) Name - Wattsmart Batteries.(c) Directed customer class (i.e. residential, commercial, indusfrial, or
irrigation) - residential and commercial.(d) Nameplate capacrty (MW) - 5 MW.(e) Program Season (summer, winter, year-round) - Year Round - January I
through December 31.(D Yearly program cost ($/tr4W nameplate capacrty) - This metric is
unavailable.(g) Dispatchable periods (i.e. season dates, days of the weelg and hours of
the day) - 12:00 AM to I l:59 PM (Mountain Time) , Monday through
Sunday.(h) Dispatch limitations - Up to two full battery cycles.(i) Number of participants - 800+.
0) Company required notification to participant prior to dispatch (hours) -
No advance notification.(k) Participant incentive (fixed ($/kW), variable ($/kWhp - please refer to
the table below:
PAC-E-21-19 / Rocky Mountain Power
March 11,2022
IPUC DataRequest 45
Enrollmcnt lnccntlvc
(one-tlme upfront cash
payment)
Partlclp.tlon
lncantlYC
(annual blll
credlt)
Resldentlal and
Commerclal Batteries
l4OOper kWt (based on 4- $15 per kW
year commltment)
Example lncentlve 6 kw x $4OO = 32.a0O 6kwx$15=390
O Participant penalties for opt-out (fixed ($/kW), variable ($/kWh)) -
None, and Reduced Incentive.
(m) Program confiibution to operating reseryes by type (spin, non-spin,
frequency, ... etc.) - Flexible Resource, frequency rcsponse, contingency
reserve.
(4) Oregon Irrigation Load Control Pilot Program
Please refer to Attachment IPUC 45 for details on this progrtrm.
Recordholder: Shawn Grant
Sponsor:Clay Monroe
PAC-E-21-19 / Rocky Mountain Power
March 11,2022
IPUC DataRequest 46
IPUC Data Request 46
202llntegLrated Resource Plan (IRP) - Please explain the differences in the
capacity factor approximation method used in the 2019 [RP as compared to the
methods used in the202l IRP (refer to Volume II, Appendix K - Capacity
Contribution). How does the method used in the202l IRP compare to the
methods contained in the NERC report: Methods to Model and Calculate
Capacity Contributions of Variable Generation for Resource Adequacy Planningl.
Response to IPUC Data Request 46
The Company's2019lntegrated Resource Plan (IRP) included several capaclty
contribution calculations:
(l) Equivalent Conventional Power (ECP) methodology: This technique was used
to identify the variation in the capaclty contribution as larger and larger
quantities of wind and solar resources were added to a portfolio. As more
wind and solar capacity is added, the capacity contribution declines, as shown
in the 2019 IRP, Volume II, Appendix N (Capacity Contribution Study),
Table N.l (ECP Method Capacity Contribution Values for Wind and Solar).
(2) Initial Capacity Factor Approximation Method (CF Method): Using the ECP
study results, the Company calculated profile-specific capacity contributions
values for proxy resources at locations around its system. This reflected the
Company's initial portfolio, developed at the outset of the 2019 IRP, which
was also used for planning reserve margin (PRM) analysis.
(3) Final Capacrty Factor Approximation Mettrod (CF Method): At the end of the
2019 IRP process, the Company calculated profile-specific capacity
contributions values for proxy resources at locations around its system. This
reflected the Company's P45CP portfolio, which was very similar to the P45-
CNW portfolio that was selected as the 2019 IRP preferred portfolio.
The 2019IRP is publicly available and can be accessed by utilizing ttre following
website link:
lntegrated Resource Plan (pacificorp.com)
PacifiCorp's2021IRP, Volume II, Appendix K (Capacrty Confiibution) reports
capacity contibution values based on the same methodology as the capacity
contribution calculation for the 2019IRP, item (3) discussed above. The inputs to
the calculation were updated to reflect values from the 2021 IRP, but are
otherwise equivalent to the calculation in the 2019 IRP. The version inthe202l
https://www.nerc.com/palRAPA/ralReliability%20Assessments%20DLll VGTF I -2.pdf
PAC-E-21-19 / Rocky Mountain Power
March 11,2022
IPUC Data Request 46
IRP reflects the loss of load probability (LOLP) results for a portfolio that is close
to the 2021 IRP preferred portfolio. It also reflects updated wind and solar
generation profiles for locations across the Company's system, as modeled in its
2021 IRP, as well as all of the other modeling inputs that relate to reliable system
operation.
The cited North American Elecfic Reliability Corporation (NERC) report discuss
a number of different techniques, but they generally fall into two categories.
Reliability-based techniques, such as Effective Load Carrying Capability (ELCC),
reflect two production cost model runs. One run reflects an initial portfolio. While
the second run reflects a change to add or remove a resource of interest, along
with changes to either load or other resources to balance out the impact of the
change. The goal of the two runs is to achieve identical reliability, based on the
utilities' chosen loss-of-load metic, typically measured in events, hours, or
megawatt-hours (MWh). While this type of reliability-based technique is very
accurate, it has to be repeated for every resource of interest and is only applicable
for a given initial portfolio and for the modeled increment of the resource in
question. For example, the addition of energy storage can increase the capacity
contibution of solar. Similarly, adding twice as much solar capacity as what was
evaluated in the reliability analysis would generally result in a different reliability
impact.
The second type of capacity contibution techniques are approximation methods,
which can be based on either the results of a reliability analysis, or some other
data set (such as load). "Garver's method" estimates the loss of load risk for each
hour as a function of load, relative to peak load, based on what was observed in a
reliability analysis. Other techniques do not require a reliability analysis, for
example, they might reflect the average output during a defined period, such as
the top I percent of load hours.
In past years when portfolios primarily consisted of baseload resources that
experienced random forced outages, load was the key non-random variable. But
because the Company's portfolio includes many renewable resources which vary
widely in their availability across the year, load is no longer the only non-random
variable, and neither of the methods described work well. The CF Method used by
the Company in the 2019 [RP and the 2021IRP includes elements of both
Garver's method and the highJoad hour technique. Instead of characterizing each
hour using a function based on load as in Garver's method, the loss of load events
(LOLE) that occur in a reliability analysis are directly compared to a resource's
generation profile. The more a resource is available during LOLE, the greater its
conftibution to a reliable system, and the higher its capacity contibution. While
this distribution is not as smooth from hour-to-hour as Garver's method, it does
not require analysis to determine the relative contributions of different variables
to the shortfall in an hour. Mathematically, the CF Method is also comparable to a
highJoad-based method, except instead of identiffing resource availability during
PAC-E-21-19 / Roc$ Mountain Poruer
I\darch 11,2022
IPUC DafaRequest 46
high load periods, it is substituting hours with high loss.of-load risk As aresult,
the CF Metlrod leverages the rezults of a single reliability analysis (which can
take several days of model run time for a single yffi), and that single sfirdy can be
applied to any generation profiles of interest. As with the reliability-based
techniques, capacity contibution values oaloulatod using the CF Method
technique may not be accurate if significant changes in the composition of a
portrolio occur.
Recordholder: Dan MacNeil
Sponsor:Shay LaBray