20220315Comments.pdf

RILEY NEWTON
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. II2O2
i.:'.I:ii'.rii)
- i.,.., i; P;'i !:55
Street Address for Express Mail:
1I33I W CHINDEN BLVD, BLDG 8, SUITE 2OI-A
BOISE, ID 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF'ROCKY MOUNTAIN
POWER'S FILING FOR
ACKNOWLEDGEMENT OF ITS 2021
INTEGRATED RESOURCE PLAII
CASE NO. PAC.E,-}I-I9
COMMENTS OF THE
COMMISSION STAFF
STAFF OF the Idaho Public Utilities Commission, by and through its Attomey of
record, Riley Newton, Deputy Attorney General, submits the following comments.
BACKGROUND
On September 1, 2021, PacifiCorp dba Rocky Mountain Power ("Company") filed its
2021 Electric Integrated Resource Planl ("2021IRP") pursuant to Commission Order No.22299
In January 1989, the Commission identified the foundational aspects of the current [RP.
Order No.22299. In 1989, the Commission specified the "Resource Management
Report"2("RMR") as the way to publicly document the status of a utility's plan for meeting
I On September 15,2021, the Company filed an updated IRP forthe purpose of clarifying some changes in the IRP filed on
September l, 2O2l . See updated IRP VoL I at I . The updated IRP, as the Company assured, did not "affect the analysis or
outcomes of the 2021 IRP." Id
2 U-1500-165 Order No. 22299 - Page 6
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1STAFF COMMENTS MARCH 15,2022
future resource needs. Order No.22299. This plan was ordered to be developed and completed
on a biennial basis to provide a public report documenting a utility's forecasted resource plan to
meet its needs over the next 20-year period. The Commission expected RMRs to "emphasize
clarity, understandability, resource capabilities, and planningflexibility."3 This report has
evolved and has come to be known as the IRP. Through acknowledgement and compliance with
Order No.22299, the Company recognizes the need to examine and discuss each of the
following:a
l. Load forecast uncertainties.
2. The effects of known or potential changes to existing resources.
3. Considerations of demand and supply side resource options; and
4. Contingencies for upgrading, optioning and acquiring resources at optimum times
(considering cost, availability, lead time, reliability, risk, etc.) as future events
unfold.
In the Order, the Commission considered "ongoing comprehensive planning essential to
good utility management".s The Commission recognized that resource planning is the sole
domain of utility executives and that only prudence reviews of the utility's plans are needed. As
such, the Commission, in response to a filed IRP, acknowledges that the Company has
completed the requirements of the Commission's Order. Recognizing that an IRP is a plan and
not a blueprint, the Commission believes the Company has met the requirements of the planning
process, and only provides acknowledgment of the IRP, but does not authorize the conclusions or
prudence of resources contained in the plan.6
3 U-1500-165 orderNo. 22299 -Page 12
a Updated 2021 lntegrated Resource Plan, Volume ll - Appendix B - IRP Regulatory Compliance, page 25
5 Commission Order No.22299 - Page 6
6 PAC-E- l9- I 6 Order No. 34780 - Page 12
2STAFF COMMENTS MARCH 15,2022
STAFF REVIEW
Staff recommends the Commission acknowledge the 2021 IRP. Through its review of
the Application, participation in stakeholder meetings, and review of responses to production
requests, Staff believes the Company's 2021 IRP meets the requirements in Order No. 22299.
Staff s overall conclusion is based on its assessment of the four requirements included in the
Order as outlined in the Background section above. First, the Company developed a load
forecast with load growth considering estimated energy sales and annual peak demand over
a2}-year time horizon. This load forecast considered a range of uncertainties related to the
econometrics of national and regional growth, weather, seasonal variance, customer usage, and
customer behavioral changes. Second, the Company considered changes to existing resources by
studying the economics and reliability of coal plant retirement dates, conversion of certain coal
units to natural gas fuel, and by veriffing the availability of market purchases, referred to as
Front Office Transactions ("FOT"). Third, the Company evaluated both demand and supply-side
resources in an equivalent manner when selecting them for inclusion in resource portfolios.
Finally, the Company considered a wide-range of resource alternatives and resource
contingencies in conjunction with a multitude of constraints in its determination of a least-cost,
least-risk preferred portfolio over a 2}-year time horizon.
While Staff believes the 2021 IRP complies with the requirements of Order No.22299,
Staff also identified the following areas of potential concern and need for future analysis and/or
improvement:
l. Differences in cost by selecting the Preferred Portfolio based on the need to meet
Washington Clean Energy Transformation Act ("CETA"1z requirements versus
selecting the portfolio on least-cost, least-risk without considering CETA. This
difference in cost provides a benchmark for evaluating equity of the Company's
Multi-State Protocol ("MSP").
2. Use of a historical fixed 13 percent planning reserve margin ("PRM") may not
support the loss-of-load hours reliability target of 2.4 hours per year.
7 Washington passed the Clean Energy Transformation Act (CETA), which requires utilities to meet three primary
clean energy standards: remove coal-fueled generation from Washington's allocation of electricity by 2025, serve
Washington customers with greenhouse gas neutral electricity by 2030, and to serve customers in Washington with
I 00oZ renewable and non- emitting electricity by 2045.
3STAFF COMMENTS MARCH 15,2022
3. The Company did not allow new natural gas generating resources for selection as a
new resource.
4. Selection of the proposed advanced Natrium nuclear plant. With the amount of
uncertainties with the technology, it may pose significant cost and schedule risk.
5. The need to improve clarity regarding FOT Availability Limits.
2021 IRP Overview
The202l IRP describes the Company's proposed plan to deliver continuous, reliable
electric service to its customers over the next 20 years using an approach that will result in a
least-cost, least-risk resource portfolio. In developing this plan, the Company considered a load
forecast with varying levels of load growth, future capability and capacity of existing resources,
and a wide range of potential future resources before determining the Company's recommended
Preferred Portfolio. The Company considered a number of risk variables and constraints in its
evaluation to ensure the Preferred Portfolio is least-cost and least-risk in meeting customers'
future needs, and can perform well under a reasonable range of possible futures.
Staff believes the 2021 tRP will inform future resource procurements, system upgrades,
and economic retirements utilizing a sophisticated analytical framework for modeling and
assessing resource investment tradeoffs.
Relative to the 2019 IRP, the202l IRP Preferred Portfolio identified the following
changes:
o Acceleratedcoal-unitretirements;
o No new fossil-fueled resources;
o Continued growth in energy-efficiency ("EE") programs;
o Incremental new renewable resources;
o Greater reduction in greenhouse gas emissions;
o Increased investment in transmission infrastructure;
o Conversion of two coal units to natural gas peaking units;
o Growth in demand response ("DR") capacity;
o New advanced nuclear resources;
o Increased reliance on energy storage resources; and
4STAFF COMMENTS MARCH 15,2022
o Non-emitting peaking resources using technology requiring further technology
development.
Preferred Portfolio
The Company selected portfolio P02-MM-CETA as its Preferred Portfolio. However, the
Preferred Portfolio on a risk-adjusted present-value revenue requirement ("PVRR") basis is $164
million higher than the top performing P02-MM portfolio.t By comparison, PO2-MM-CETA has
a risk adjusted PVRR of $26.343 billion compared to the $26.179 billion lower cost P02-MM
portfolio. The differences between the two portfolios are the changes in resources needed to the
top performing portfolio to meet Washington's CETA requirements. The graph below illustrates
the cumulative incremental cost of the P02-MM-CETA portfolio over the P02-MM least-cost
least-risk portfolio over the ZD-year planning horizon.
Due to the requirements needed to meet Washington's CETA, the Company identified a
shortfall in renewable capacity and needed to add incremental wind, solar, and battery storage in
Yakima, Washington. The cost difference between the two portfolios provides an indication of
8 Updated 2021lntegrated Resource Plan, Volume I - Chapter 9 - Modeling and Portfolio Selection Results, page
291
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STAFF COMMENTS MARCH 15,2022
the magnitude of additional cost that the State of Washington should be allocated in the MSP to
ensure that Washington legislation does not increase costs to customers in other jurisdictions.
Issues Addressed from the 2019 IRP Staff Comments
Staff comments in Case No. PAC-E-19-16 identified the following concerns that the
Company' addressed in the 2021 IRP:
l. Public tltilitv Resulatorv Policies Act of I 8 ("PURPA") Capacity Deficiency Date: In the
2019 IRP, Staff identified the capacity deficiency date based on the IRP Load and Existing
Resource Balance ("L&R"). Staff was concerned with including unauthorized early coal
plant retirements in the L&R for the IRP. These unauthorized early retirements should not be
included for determining the deficit date for assessing avoided cost of capacity in PURPA
contracts when the capacity deficiency date filing is submitted after acknowledgment of the
IRP. Although the L&R used for IRP purposes and the L&R for PURPA use much of the
same information, the purpose of each requires differences in the resources that should be
included.
2. Coal Unit Decommissionine Costs: The Company did not use the recently released costs for
coal unit decommissioning in the 2019IRP. Staff was concerned by the Company not
including updated coal unit decommissioning cost into the IRP. The Company responded by
including the base estimate demolition costs from the 2019 decommissioning study into the
2021 IRP. These costs were limited to the base estimate demolition costs from the study for
the coal-fueled generating units that include "take-or-pay" provisions, but do not include
contingency reserves as they cannot be reliably estimated at an acceptable level of
granularity.
3. Long-run gas cost assumptions: Staff noted that the Company's natural gas cost forecast
from its 2019 IRP was significantly higher than the Company's 2017 forecast. In the 2021
IRP response, the Company noted the following:
a. The 2021 IRP base case forecast for natural gas prices decreased along with a
decrease in wholesale power prices for most years relative to those in the 2019 IRP
6STAFF COMMENTS MARCH 15,2022
b. These forecasts are based on prices observed in the forward market and on
projections from third-party experts.
The lower power prices observed in the 2021 IRP are primarily driven by the
assumption of lower natural gas prices than what was assumed in the 2019 IRP
d. The202l IRP assumed lower natural gas prices than in the 2019 IRP due to
additional supply of natural gas available in the market from lower than expected
liquefied natural gas ("LNG") exports. LNG exports were limited by pipeline
expansions to LNG facilities that did not occur.
4. Transmission Planning: In the Company's 2019IRP, Staff was concerned that the relatively
high natural gas price forecast disadvantaged natural gas plants and transmission resources
compared to new renewable resources. According to the response in the 2021 IRP, the
Company believes that by implementing the Plexos software, it can now evaluate new
transmission topologies with new resource additions, simultaneously. Staff agrees that this is
a major improvement in modeling capability and can lead to portfolio options that may not
have been considered in past IRPs; however, Staff does not believe its concern was
addressed, especially given that new natural gas resources were not included as resources that
could be selected by the model.
5. Demand-Side Manasement ("DSM") and Time-of-Use Rates: Staff identified the need for
the Company to continue its efforts to expand its DSM resources and time-of-use rate
structures. The Company responded that it continues to evaluate new DSM opportunities,
both energy efficiency ("EE") and direct load control programs as a resource that competes
with traditional new generation and wholesale power market purchases when developing
resource portfolios within the IRP and that DSM resources continue to play a key role in its
resource mix. The Company did not respond to the use of time-of-use rate structures as a
DSM measure.
c
7STAFF COMMENTS MARCH 15,2022
Improved Modeline Capabilities
The 2021 IRP made several improvements to the quality of the IRP results . ln202l, the
Company began using Plexos, a more advanced third-party software developed by Energy
Exemplar, replacing System Optimizer (capacity expansion model) and Planning and Risk
(production cost model). Instead, Plexos performs much of the same functions, but uses a
combination of Long-term ("LT"), Medium-term ("MT"), and Short-term ("ST") models all of
which use a common database and are designed into an integrated platform.
The Plexos software solved problems that existed with the Company's previous modeling
software, which required the Company to perform a number of process steps outside of the
models in order to get valid results. Plexos also greatly reduced the volume of individual
portfolios needed to evaluate the impacts of varying resource decisions and has built-in
capabilities to model future resources and system designs that require future evaluation. Plexos
allows the Company to evaluate the timing of plant retirements, gas conversions of coal plants,
carbon capture and sequestration, retrofits to coal units, battery optimization, and alternative
transmission topologies. Portfolio performance measurement is also improved, allowing the
Company to calculate forecasted locational marginal prices for a given zone within the Western
Interconnect.
2021 IRP Process
The IRP process is used to assess the comparative cost, risk, and reliability characteristics
of different resource portfolios while meeting reliability requirements. The Company's models
allow the Company to evaluate the net present value revenue requirement ("NPVRR") for each
portfolio over the 2}-year planning horizon and by fuither evaluating the portfolios by
performing stochastic Monte Carlo simulations so that a risk-adjusted NPVRR can be
determined. The risk-adjusted NPVRR results indicate how robustly a portfolio performs under
uncertain future conditions so that meaningful comparisons can be made.e
e To determine a risk-adjusted NPVRR, the Company performs a stochastic analysis using Monte Carlo simulations
of each portfolio. This is done by first identifying model input assumptions or risk variables that exhibit future
uncertainty, such as load, natural gas prices, wholesale electricity prices, hydro-generation, and forced outages. The
models are then run 50 times by sampling values from statistical distributions for each of the risk variables for each
model run. The results of these Monte Carlo runs produces a distribution of NPVRR results for each portfolio so
that a risk-adjusted NPVRR can be determined and compared between each of the portfolios.
8STAFF COMMENTS MARCH 15,2022
The Company developed its 2021 IRP through the following planning steps
l. Develop Key Inputs and Assumptions
2. Model a Range of Resource Portfolios
3. Analyze Variants to the Top Performing Resource Portfolios
4. Select a Preferred Portfolio
5. Identiff Next Steps within the Action Plan
First, the Company prepared a L&R study comparing forecasted loads to existing
resource capacity over a 2D-year time horizon. The L&R study highlights deficiencies in
capacity that occur over the planning horizon. The Company considered a wide range of factors
including natural gas and wholesale power prices, along with regulatory, environmental, and
public policy issues. These factors, and additional inputs from stakeholders, were bundled into a
set of input assumptions that formed the basis of each unique planning case.
The Company then ran each case through the LT capacity expansion functionality within
Plexos. These runs produced a unique resource portfolio for each case optimized for cost that
had sufficient capacity to meet the load forecast plus a PRM across the 20-year planning horizon.
The set of selected resources also needed to meet other constraints including reliability, state and
federal environmental policies, resource limitations, etc. Each portfolio is unique regarding the
type, timing, location, and amount of new resources.
Each portfolio was then evaluated in the ST modeling functionality to determine the
system costs for each portfolio over the entire 20-year planning period. The ST model accounts
for resource availability and system requirements at an hourly level, producing reliability and
resource value outcomes as well as a present-value revenue requirement ("PVRR"), which
served as the basis for adjustments of risk in the next step of the process.
Once the portfolios were developed through the LT models, and then ran through the ST
modeling functionality, the Company then utilized the Plexos MT modeling functionality to
determine a risk adjustment to the system cost results determined in the previous step. Each
portfolio was evaluated for cost and risk among three natural gas price scenarios (low, medium,
and high) and three carbon dioxide (CO2) price scenarios (zero, medium, high). An additional
CO2 policy scenario was developed to evaluate performance of the portfolios that included a
9STAFF COMMENTS MARCH 15,2022
social cost ofgreenhouse gases. Taken together and using abookend approach, the Company
modeled five distinct price-policy scenarios (medium gas/medium CO2, medium gas/zero CO2,
high gas/hi gh CO2,low gas/zero CO2, and the social cost of greenhouse gases) in the 2021 IRP.
Informed by comprehensive modeling, the Company's Preferred Portfolio selection
process involved evaluating cost and risk metrics reported from the ST and MT models, and
comparing resource portfolios based on expected costs, low-probability high-cost outcomes,
reliability, CO2 emissions, and other criteria.
Finally, after the Company selected the Preferred Portfolio, the Company developed an
action plan that it will use to implement the IRP during the first 3 to 5 years of the planning
horizon.
Reliabilitv Assessment
As described above, the Plexos LT functionality develops initial portfolios at a
granularity level of 4-block data per month, using a minimum of l3 percent PRM. Subsequently,
the initial portfolios are simulated in the ST model to quantifu reliability shortfalls at an hourly
level and additional resources are added into the portfolios to resolve any shortfalls. Staff has
two major issues with the methods the Company uses to ensure adequate reliability of its
portfolios: (l) the use of a minimum of l3 percent PRM, and(2) whether the Company ensures
that the reliability target, measured in Loss of Load Hours ("LOLH"), was met.
Use of Minimum of 13 percent PRM
The 13 percent PRM was determined in the PRM Study in the 2019 IRP. See Response
to Stafls Production Request No. 19. However, many inputs, parameters, and assumptions have
changed in the 2021 IRP, such as the load forecast and the FOT Availability Limits, which were
used to determine the 13 percent PRM in the 2019 IRP. See Appendix I - Planning Reserve
Margin Study of the 20l9IRP. Staffis concemed that the 13 percent PRM determined in the
2019 IRP may not be appropriate for the 2021 IRP. Ideally Staff believes that each IRP should
determine its own PRM based on the inputs, parameters, and assumptions specific to each IRP.
If a dated PRM is used, the Company needs to justiff why the Company believes the old
planning margin is still appropriate.
The footnote on page 146 of the PRM Study in the 2019 IRP states:
STAFF COMMENTS 10 MARCH 15,2022
PacifiCorp must hold approximately six percent of its resources in reserve to meet
contingency reserve requirements and an estimated additional4.5 percent to 5.5
percent of its resources in reserve, depending upon system conditions at the time
of peak load, as regulating margin. This sums to 10.5 percent to I 1.5 percent of
operating reserves before even considering longer-term uncertainties such as
extended outages (transmission or generation) and customer load growth.
The Company states that the footnote still applies in the 2021 IRP. See Response to
Staffls Production Request No. l9 (b). Staff believes this footnote justifies a PRM floor of I1.5
percent, but it does not sufficiently justifu the 13 percent PRM. Staff believes the estimated 1 1.5
percent threshold existed before the 2019 PRM study was even conducted, which examined a
range of PRM from I 1 to l8 percent and ultimately chose 13 percent.
Verihcation of LOLH Reliabilitv Target
The l3 percent PRM was selected to meet a LOLH reliability target of 2.4 hours per
year, which equates to one day in ten years, a common reliability target in the industry. As such,
a PRM goal is not a reliability target in and of itself. It is an interim adjustment factor to
increase the amount of load that the resource plan must meet; however, without a process to
verifu whether the portfolios actually met the LOLH target is unclear.
Staff believes a reliability target should be established prior to the start of the modeling
process. A reliability target is a policy decision and should be based on what the public and
ratepayers can tolerate considering societal cost of outages. Once the target is established, the
Company needs to demonstrate that the PRM was derived from the target. After the portfolios
have been developed, the Company should be able to veriff whether the resulting portfolios met
the original target as a feedback loop. This feedback loop and final verification step is important
because portfolios with a significant amount of variable resources will require a higher PRM
than a portfolio with a higher concentration of dispatchable resources for a given reliability
target. Staff recommends that the Company provide greater clarity relative to these expectations
in future IRPs.
STAFF COMMENTS 11 MARCH 15,2022
Evaluation of IRP Resources
Nafural Gas Resources
The Company did not include or consider any new natural gas proxy resources for
inclusion in any of the Company's portfolios. The Company considered natural gas resources as
a stranded-cost risk due to depreciable lives ranging from 30 to 40 years (i.e., a new gas-fired
resource placed in service in 2030 would be depreciated as late as2070). Given current state
policies within the Company's seryice territory and potential for future federal policies, the
Company did not believe it feasible to assume new natural gas resources in the IRP. The
Company believed it was unlikely it could obtain the permits to site and operate such a facility in
many parts of its service territory. Finally, the Company observed that there is very limited
development activity for new natural gas facilities. This phenomenon recently evident in the
2020 all source request for proposal ("2020AS RFP") conducted by the Company did not result
in a single bid for new natural gas resources.
Staff believes the Company could have used an alternative approach that allows Plexos to
select new natural gas resources but consider the cost of these facilities becoming potential
stranded assets. The Company could develop an adder to the cost of new natural gas plants that
represents the expected value of the additional cost that customers would incur if the gas plants
needed to be retired early due to external factors. The value of this approach would allow the
benefits of a fully dispatchable resource that is not time limited, as is the case with battery
storage, to be considered.
However, the Company selected the conversion of Bridger Units #1 and #2 to natural gas
by June 1,2024. The cost of conversion is significantly less than installing Selective Catalytic
Reduction ("SCR") to comply with RegionalHaze federal regulations. Furthermore, the benefits
to the system of having two additional dispatchable gas peaker units was shown to be cost
effective compared to other alternatives for additional capacity due to the low capital cost of
conversions.
Coal Generation
Environmental regulations in Oregon and Washington and at the federal level are driving
the early retirement of much of the Company's coal fleet. The table below shows the
retirement/exit dates reflected in the Company's Preferred Portfolio:
STAFF COMMENTS 12 MARCH 15,2022
COAL GENERATION RESOURCE YEAR
Jim Bridger Units l-2 Retired/Conversion to Natural Gas Peakers 2023t2024
Naughton Units l-2 -Retired 2025
CraigUnitl-Retired 2025
Colstrip Units 3-4 - Retired 2025
Dave Johnston Units l-4 - Retired 2027
Hayden Untt2 - Retired 2027
Craig Unit2 - Retired 2028
HavdenUnit 1-Retired 2028
Huntington Units 1-2 - Retired 2036
Jim Brideer Units 3-4 - Retired 2037
Wyodak - Retired 2039
The Company's capacity expansion models selected the dates based on a combination of
coal plants that remain economical for the system, the system need for capacity, and current
environmental constraints. Coal plant capacity that will be retained beyond 2025 and 2030 due
to Washington and Oregon's restrictions on coal plants, will be reassigned to the Company's
other jurisdictions through MSP.
Renewables and Energv Storaee
The Company's2021Preferred Portfolio continued to add substantial new renewables as
declining cost of renewables and battery storage occur. As costs decline and technologies
improve, renewables and energy storage are displacing traditional fueled generation resources.
State renewable portfolio standards and new transmission infrastructure continue to drive the
addition of over 6,400 Megawatts ("MW") of new renewable resources by the endof 2023, with
nearly 11,000 MW of new renewable resources over the 2}-year planning period. These new
renewable resources are typically located in remote areas away from load centers. As retirement
of coal resources continue, the Company plans to continue to invest in a transmission system to
move energy across and between the Company's east and west balancing areas.
Energy storage resources can provide a variety ofgrid services since they are highly
flexible, with the ability to respond to dispatch signals and act as both a load and a resource.
This evaluation, refreshed for the202l IRP, details how these grid services and energy storage
resources can be configured and sited to maximize benefits to the system. With the variability of
renewable resources, the Company continues to increase energy storage typically through battery
STAFF COMMENTS 13 MARCH 15,2022
storage technology. But with the selection of the advanced nuclear NatriumrM projects, the
Company will utilize significant heat energy storage to support increasing amounts of
renewables over the long term.
Market Purchases and FOT Availabilitv
FOTs play a specific role in the IRP for fulfilling capacity requirements throughout the
2}-year planning horizon. The Company first determines FOT Availability Limits based on firm
transmission capacity and market liquidity and depth. Once the limits have been determined,
FOTs are used as a slack amount of capacity to fill short positions up to the limit for each time
period. If the market purchase needs exceed what the market can provide, the deficit triggers an
incremental amount of generation resources that needs to be added to the system.
The202l IRP assumes that the FOT availability limits are 500 MW for summer and
1,000 MW for winter, which are significantly reduced from the 1,425 MW for summer and 1,425
MW for winter used in the 2019 IRP. Staff has identified issues with the FOT Availability
Limits involving improving transparency of methods used to determine the limits, issues where
the Company appears to exceed its Availability Limits, and whether the contingency adder
required for market sellers is capacity available for use by the Company to meet load.
Transparency of Methodologfor determining FOT Availability Limtts
Staff believes that the Company should improve the transparency of the methodology for
determining FOT Availability Limits in the next IRP by describing the steps and the assumptions
used in the overall methodology. The Company uses regional studies, physical delivery
constraints, market liquidity, and market depth to make the determinations, but does not provide
any specificity for how the limits are determined.
FOT Availability Limit Exceedance
ln Table 6.1 1 (Summer Peak - System Capacity Loads and Resources without Resource
Additions), the "IJncommitted FOTs to meet remaining Need" amounts are significantly greater
than "Available Front Office Transactions" amounts in the summers of 2021,2022, and2023.
The Company stated that it will be reliant on a higher level of FOTs in the near term. See
Response to Staff s Production Request No. 21 (b). Staff believes it likely that during these early
STAFF COMMENTS t4 MARCH 15,2022
years, the Plexos model is constrained by resource acquisition lead times, and the only recourse
if these deficits actually occur, is to resort to the market.
However, this issue has implications for the First Capacity Deficit Date used for setting
PURPA rates. It is unclear whether the FOTs in the L&R above the Availability Limit are
properly reflected and can be counted upon to provide the stated amount of capacity. Staff
recommends that the Company provide greater clarity on this issue in the upcoming first def,rcit
year filing and in the next IRP.
Contingency Adderfor FOT Availability Ltmtts
The L&R in the 2019 IRP increases the FOT Availability limits by 3 percent, while the
2021 IRP does not include these increases. According to the Company, the 3 percent adder is for
contingency reserves that firm energy sellers are required to hold. See Response to Staff
Production Request No. l9 in Case No. PAC-E-20-13 and Supplemental Response to Staff
Production Request No. l8 in Case No. IPC-E-21-19. However, it is not clear whether this
additional amount of contingency held by a seller is available to the Company in order to meet
its load for firm market purchases. The answer to this question will determine whether the
additional 3 percent should be included in the L&R. Staff recommends that the Company
provide clarification of this issue in the upcoming first deficit year filing and in the next IRP.
Private Generation
Page 149 of Volume I of the 2021 IRP states that the hourly system load is reduced by
hourly private generation projections to determine the net system coincident peak load for each
of the first ten years (2021-2030) of the planning horizon. The reference to "the first ten years
(202I-2030) of the planning horizon" is incorrectly stated. According to the Company, the
hourly system load is reduced by hourly private generation projections for the 20 years of the
IRP planning horizon (2021through 2040). See Response to Staff s Production Request No. 25.
Staff also verified that the amount of private generation was included in the L&R for the entire
planning horizon.
STAFF COMMENTS 15 MARCH 15,2022
DSM
The Company has a mature portfolio of EE and DR programs it effectively deploys to
reduce and reshape loads. Because these programs are cost-effective, they reduce the cost the
Company incurs to serve customers.
EE Programs
In the Company's Preferred Portfolio, the Company's EE resource selections show a
decline in resource selections in2022, dropping to 12,824 Megawatt-hours ("MWh") from
17,590 MWh in202l. However, by 2025 resource selections begin to increase again and reach
near 2021 levels with 17,289 MWh of first-year EE savings. Despite EE resource selections
declining early in the planning horizon, Staff encourages the Company to continue pursuing all
cost-effective DSM resources.
DR Programs
The202l IRP changes how DR is treated in the L&R compared to its treatment in the
2019 IRP. DR programs include residential and small commercial air conditioner load control,
irrigation load management, and intemrptible contracts. In the 2019 IRP, the intemrptible
contracts were treated as a DSM resource to reduce load, thus were used in the calculation of the
planning margin. However, remaining DR (Class I DSM) was treated as a supply-side resource
and thus was not used to calculate the planning margin. In the 2021 IRP, all the existing DR
programs were treated as DSM resources and thus were all used to calculate the planning margin.
The Company decided it was appropriate because DR programs are dispatchable reductions to
load, and it was more appropriate to include them in the total amount of obligations. See
Response to Staff s Production Request No. 29 (e). Staff believes this change is acceptable
given the nature of DR programs.
In the Company's Preferred Portfolio, the Company shows an increase in DR selections
in the Company's Idaho territory. Notably, the Company selected 25.8 MW of additional DR in
the next ten years and an additional l0 MW by 2024 for DR in the summer. In Case No.
PAC-E-22-03, the Company proposed to increase Electric Service Schedule No. 191 to account
for an increase in DSM program expenditures for pending DR programs. Staff looks forward to
reviewing the Company's proposals for upcoming DR programs.
STAFF COMMENTS t6 MARCH 15,2022
vanced Nuclear
The TerraPower advanced nuclear NatriumrM demonstration project selected in the
Preferred Portfolio could potentially deliver significant benefits to the Company's electric
system, but there could also be significant risks. The 2021 IRP includes 1,500 MW of advanced
nuclear NatriumrM peaking resources as part of its least-cost, least-risk Preferred Portfolio. The
first 500 MW identified as a demonstration project is shown to come online by the summer of
2028. The portfolio also includes 1,000 MW of additional advanced nuclear generation being
added in 2038.
The operating characteristics for the advanced nuclear plants would significantly benefit
the Company's system for meeting peak load and reliability needs. The design is based on a
molten sodium-cooled nuclear reactor paired with a molten salt thermal energy storage tank.
The molten salt energy storage provides significant ramping in meeting the needs for system
reliability as increased renewable resources are added to the system. Both the reactor and the
molten salt energy storage generate power through a single steam turbine.
Although a facility with these types of performance characteristics would be highly
beneficial, Staff believes there are mrmerous concerns and risks. First, the licensing process by
the U.S. Nuclear Regulatory Commission ('NRC") has historically been a source of large
delays.1o Second, there are several technology issues that still require development, if not
resolved, could result in substantial delays. Third, the fuel source for this type of plant has yet to
be developed. Finally, there are issues related to spent fuel disposal and plant decommissioning,
which could add substantial cost, and should be included in the lifecycle cost of the plant.
Because of these risks, Staff requests the Company assess contingencies in future IRPs in
case the plant is determined to no longer be viable, or if significant delays are likely.
Non-emitting Peaker Resources
The Company has also included 1,224 MW of non-emitting peaker resources to its
Preferred Portfolio starting in year 2033. These are resources that are projected to be hydrogen-
fueled. Because the technology for these types of resources is not mature, Staff believes it is
appropriate to include them in portfolios during the second half of the 2}-year planning horizon
l0 https://www.nrc.gov/reactors/new-reactors/advanced/ongoing-licensing-activities/pre-application-
acti vities/natri um.htm I (Last Updated June | 6, 2021)
STAFF COMMENTS l7 MARCH 15,2022
beyond lead times of competing resources. The status of the technology can be updated in future
IRPs and determined whether they are likely feasible as the addition of these types of resources
approach construction lead times.
STAFF RECOMMENDATIONS
Staff recommends that the Commission acknowledge the Company's September 15,
2021, Updated IRP. Staff also recommends the following:
l. The Company provide greater clarity whether Loss of Load Hour reliability target of
2.4 hours per year was achieved by the Company's portfolios.
2. The Company provide greater clarity on: the development of FOT availability limits
in future IRPs, whether the inclusion of 3 percent contingency amounts for firm
purchases are appropriate to include to meet Company load, and the exceedance of
FOT limits in the early years of the planning horizon as it pertains to the first deficit
date for purposes of PURPA avoided cost rates.
3. The Company explore an approach to allow for the selection of natural gas resources
into a portfolio but provide an adjustment to the cost based on the expected cost risk
of becoming a stranded asset.
4. The Company assess the risks of Natrium nuclear plant implementation due to
technology viability and potential delays, and plan contingencies accordingly.
Technical Staff: Rick Keller
Travis Culbertson
Kevin Keyt
Taylor Thomas
Yao Yin
i:umisc/comments/pace2 l. I 9mrkkktncttyy comments
day of March2022.
Riley
Deputy Attorney General
Respectfully submitted this b+U
STAFF COMMENTS l8 MARCH 15,2022
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 15TH DAY OF MARCH 2022,
SERVED THE FOREGOING COMMENTS OF TIIE COMMISSION STAFF, IN CASE
NO. PAC-E-21-19, BY E-MAILING A COPY THEREOF, TO THE FOLLOMNG:
TED WESTON
ROCKY MOUNTAIN POWER
1407 WEST NORTH TEMPLE STE 330
SALT LAKE CITY UT 84116
E-MAIL : [e-mail]
DATA REQUEST RESPONSE CENTER
E.MAIL ONLY:
datareq uest@pacifi corp.com
[e-mail]
ROSE MONAHAN
ANA BOYD
SIERRA CLUB
2IOI WEBSTER ST STE I3OO
OAKLAND CA934I2
E-MAIL: [e-mail]
ana.boyd@ sierraclub.org
EMILY WEGENER
ROCKY MOUNTAIN POWER
I4O7 WN TEMPLE STE 320
SALT LAKE CITY UT 84116
E-MAIL: [e-mail]
BENJAMIN J OTTO
ID CONSERVATION LEAGUE
710 N 6TH ST
BOISE ID 83702
E-MAIL: [e-mail]
L /2,.r-
SECRETA*'/
CERTIFICATE OF SERVICE