20250710Staff Comments.pdf

RECEIVED
July 10, 2025
ADAM TRIPLETT IDAHO PUBLIC
DEPUTY ATTORNEY GENERAL UTILITIES COMMISSION
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 10221
Street Address for Express Mail:
11331 W CHINDEN BLVD, BLDG 8, SUITE 201-A
BOISE, ID 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF AVISTA'S 2025 )
ELECTRIC INTEGRATED RESOURCE ) CASE NO. AVU-E-24-13
PLAN )
COMMENTS OF THE
COMMISSION STAFF
COMMISSION STAFF ("STAFF") OF the Idaho Public Utilities Commission
("Commission"), by and through its Attorney of record, Adam Triplett, Deputy Attorney
General, submits the following comments.
BACKGROUND
On December 30, 2024, Avista Corporation d/b/a Avista Utilities ("Company") filed its
2025 Electric Integrated Resource Plan("2025 IRP") with the Commission. The 2025 IRP
outlines and analyzes the Company's strategy for meeting its customers' projected energy needs.
The Company files an IRP every two years and uses it to guide resource acquisitions.
On February 3, 2025, the Commission issued a Notice of Application and Notice of
Intervention Deadline, setting a February 24, 2025, deadline for interested parties to intervene.
Order No. 36453. No parties intervened.
STAFF COMMENTS 1 JULY 10, 2025

On March 14, 2025, the Commission issued a Notice of Modified Procedure, setting a
July 10, 2025,public comment deadline and a Company reply deadline of August 7, 2025.
The Commission requires the utility to update the IRP biennially, allow the public to
participate in its development, and to implement the IRP. See Order Nos. 22299 and 25260.
More specifically, the Commission has asked that a utility's IRP explain its current load/resource
position, expected responses to possible future events, and the role of conservation in its
explanations and expectations. The IRP should also discuss "any flexibilities and analyses
considered during comprehensive resource planning, such as: (1) examination of load forecast
uncertainties; (2) effects of known or potential changes to existing resources; (3) consideration 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." See Order No. 22299.
STAFF ANALYSIS
Staff recommends the Commission acknowledge the Company's 2025 IRP. This
recommendation is based on Staff s active participation in the IRP Technical Advisory
Committee, Staffs review of the Company's IRP filing, the Company's responses to Production
Requests, and Staff s review of the customer and stakeholder feedback received through the
public input process. Staff believes the 2025 IRP meets the minimum requirements set forth in
Order Nos. 22299 and 25260.
Staff has identified several topic areas from the 2025 IRP that it believes require
additional review and/or focus in future IRPs. Staff believes the Company can address these
topics in future IRPs because the 2025 IRP identified the long-term resource deficit in 2030,
which allows time to address these topics without impacting reliability of the system and cost to
Idaho. The topic areas identified include:
• Resource and Transmission Planning Input Assumptions
• Washington's Climate Commitment Act
• Qualifying Capacity Contribution and Planning Reserve Margin
• Reliability Analysis
• Demand Side Management Programs
STAFF COMMENTS 2 JULY 10, 2025

Staff comments are organized into sections to address these topic areas that Staff believes are
important.
Preferred Resource Strategy
The Company's 2025 IRP Preferred Resource Strategy("PRS") selected a total of 2,599
MWs of new resources during the IRP planning horizon. Table 2.4 from the Company's IRP and
presented below shows the new resource selections for the 2025 IRP PRS from 2026 through
2035. 2025 IRP at 59.
Table 2.4: Resource Selections (2026-2035)
CapabilityResource Year Jurisdiction Capability Energy
Northwest Wind 2029 Washington 200 69
Northwest Wind 2030 Washington 200 69
Natural Gas CT 2030 Idaho 90 86
Northwest Wind 2031 Washington 100 34
Montana Wind 2031 System 100 44
Montana Wind 2032 System 100 44
Northwest Wind 2033 System 157 54
Total 947 399
During this timeframe, the PRS selects a 90 MW natural gas combustion turbine for
Idaho, 500 MW of wind for Washington, and 357 MW of wind as a system resource. In May of
2025, the Company issued an all-source Request for Proposal ("RFP") to help determine the
actual resources that will be acquired to address capacity and energy needs through 2035. Staff
is concerned with the 500 MW of wind selected for Washington since this selection is driven by
Washington Environmental Legislation and could impact costs allocated to the state of Idaho. It
is important during the RFP process for the Company to evaluate the cost impact and the fair
allocation of generation and transmission resources for Idaho caused by Washington specific
resources.
STAFF COMMENTS 3 JULY 10, 2025

Resource and Transmission Planning Input Assumptions
Staff reviewed the resource and transmission planning input assumptions used to develop
the 2025 IRP and believes the input assumptions are reasonable for planning purposes. Staff
compared these inputs to previous IRP values, other utilities IRP values, and other utility data
sources. Staff s biggest concern with the input assumptions are related to transmission and
resource allocation in future IRPs due to Idaho and Washington's divergence in resource
strategies. As more state specific resources and/or transmission lines come onto the system,
there is the potential to create issues with continuing to use existing allocation methods.
For example, the IRP does not allocate available transmission between state jurisdictions
and the 2025 IRP determined the Company's transmission system can accommodate up to 500
MW of wind without substantial transmission expansion. 2025 IRP at 58. The Company's PRS
selected 500 MW of Northwest Wind for Washington during the 2029 to 2031 time period.
Washington and Idaho currently allocate the cost for supply-side resources and transmission
using the Production Transmission ratio that is approximately 65%Washington and 35% Idaho.
If the Company procured these wind resources as determined in the PRS, Idaho would pay for
35% of the wind projects and continue paying 35% of the transmission resources being used to
transport the new energy if the current allocation method remains in place.
Through production request, Staff asked the Company if it had considered any different
methods for resource allocation to address the divergence in Idaho and Washington's resource
strategies. The Company responded with the following:
While the Company acknowledges the challenges of future resource acquisition
where its regulated states have divergent preferences, and it has performed some
preliminary research and brainstorming on the potential need for resource
allocation to achieve the goals of divergent preferences between the states, it has
not yet identified any specific proposals or different methods for resource
allocation.
Response to Staff Production Request No. 2
Staff recommends the Company continue to evaluate potential resource allocation
methods due to the divergence in resource strategies and to keep the Commission informed about
any potential changes in the resource allocation method. In addition, during the RFP process, the
Company should evaluate the cost impact to Idaho and the fair allocation of generation and
transmission resources for Idaho caused by any Washington specific resources.
STAFF COMMENTS 4 JULY 10, 2025

Washington's Climate Commitment Act("CCA")
Staff s review focused on how the Company modeled the CCA in this IRP, specifically
the CCA costs associated with Idaho, the assumed market linkage between Washington and
California, the resulting market prices with and without the CCA. Lastly, Staff corrected several
incorrect market prices, which were made aware to the Company.
CCA Costs associated with Idaho
This IRP included the CCA costs associated with Idaho, such as the cost of the Boulder
Park plant, in the total cost calculation. Response to Staff Production Request No. 33 (b).
However, the Company stated this treatment does not impact the IRP results, and the IRP
analysis has no impact on Idaho ratepayers,because it is a plan for future resource acquisition,
and not a request for cost recovery. Responses to Staff Production Request Nos. 33 (b) and 44.
Staff does not believe this explanation is satisfactory for the following reasons.
First, Staff believes the CCA assumptions can affect IRP results. For example, a
portfolio with the CCA assumptions will likely select different resources than a portfolio without
the CCA assumptions. As a result, a portfolio with the CCA assumptions will have different net
present values than a portfolio without the CCA assumptions.
Second, Staff believes the treatment could impact Idaho ratepayers because the resulting
preferred portfolio in the IRP is used for subsequent ratemaking and prudence determination
purposes. For example, IRP-based PURPA projects and Demand Side Management ("DSM")
prudence analysis both use the preferred portfolio to determine avoided energy costs. Staff
recommends that the Company address these issues in the next IRP.
Market Linkage between Washington and California
The Washington Department of Ecology expected that the CCA markets in Washington
and California will be linked in 2026 or 2027. Response to Staff Production Request No. 32 (a).
This IRP assumes the linkage in all scenarios, except for Scenario#26, where the CCA policy
does not exist. Response to Staff Production Request No. 32 (d). The significance of the linked
markets is twofold: (1) the prices of the CCA allowances will likely be lower due to higher levels
of market liquidity, and(2)the electricity prices across the West will also likely be lower.
Response to Staff Production Request No. 16 (c). Given the uncertainty of the regulatory
STAFF COMMENTS 5 JULY 10, 2025

changes in the market linking process, Staff recommends that the Company include a scenario
where the Washington market and the California market are not linked in the next IRP.
Market Prices without the CCA
The IRP reported market prices with and without the CCA. For the market prices without
the CCA, there are actually two types of pricing: (1) market prices without the existence of the
CCA policy, and(2)market prices where energy is wheeled through or delivered to a destination
outside of Washington; thus the energy does not sink to loads in Washington in the presence of
the CCA policy (i.e. a situation where the CCA obligation is avoided when the policy is in
place). Responses to Staff Production Request Nos. 41 and 42. However, the IRP lacked clarity
in the labels and the descriptions of the two types of market prices. Staff recommends that the
Company improve the clarity in the next IRP to avoid confusion.
Incorrect Market Prices
The IRP made several mistakes when reporting market prices, and Staff corrected the
mistakes in Attachment A of these Comments.
Qualifying Capacity Contribution ("QCC") and Planning Reserve Margin ("PRM")
Although the QCC values were based on the Western Resource Adequacy Program
("WRAP"), not the generation capacity relative to the Company's peak load, Staff believes the
resulting capacity positions are reasonable and accurate,because the PRM is calculated using the
QCC values to achieve the Company's reliability target of 5% Loss of Load Probability
("LOLP").1 Also, Order No. 36056 required the Company to develop its PRM based on its
reliability target, and Staff believes the Company has complied with the order.
Reliability Analysis
Staff continues to have concerns with the Company moving toward relying on the WRAP
planning requirements since these requirements are based on a short-term regional prospective
and not on the Company's system. However, Staff appreciates the Company's development of
the Avista Resource Adequacy Model ("ARAM") to determine its own PRM requirements and
' See details in Staff s Comments in Case No.AVU-E-25-02.
STAFF COMMENTS 6 JULY 10, 2025

to calculate additional reliability metrics. Staff continues to recommend the Company conduct a
reliability analysis that measures resource adequacy metrics for additional portfolios and
multiple years across the full planning horizon instead of only evaluating select years and
portfolios.
For the 2025 IRP, the Company is continuing to use the WRAP methodology for capacity
planning similar to the 2023 IRP but has determined its own PRM requirements using an
internally developed LOLP study referred to as ARAM. ARAM is used to determine the ability
of the system to meet load and reserves in each hour when subject to 1,000 iterations of differing
potential futures and it is evaluated for two future years (2030 and 2045) for select portfolios. In
addition to LOLP, ARAM determines 5 other reliability metrics. The Company's use of ARAM
to determine its own PRM and to measure resource adequacy metrics addresses many of the
Staff s concerns from the 2023 IRP, but Staff would like to see additional portfolios and years be
included in the analysis to accurately validate the reliability of its portfolios.
Demand Side Management Programs
Energy Efficiency ("EE")
Energy efficiency continues to play an important role in the Company's planning.
However, the accuracy of the Company's estimates in its 2025 IRP is in question. In the
Company's PRS, energy efficiency is expected to provide 870 GWh of cumulative savings,
reducing the Company's future load growth by thirty-two percent. 2025 IRP at 50. Twenty-six
percent of the new energy efficiency savings are expected to come from the Idaho program. Id.
The majority of these Idaho savings are provided by interior lighting measures (55.7%) and
space heating and cooling measures (23.8%), with other measure types contributing smaller
amounts. Id. A large portion of savings is driven by lighting savings, the 2023 lighting backstop
for general service lamps and the increasing penetration of high efficiency lighting have led to
decreased savings potential in residential lighting programs. This is reflected in the
Conservation Potential Assessment("CPA"); however, the back stop does not extend to other
lighting types such as high bay and linear fixtures. The majority of estimated lighting savings
are from the commercial sector where these types of fixtures are more common. CPA at A-10.
In response to Staff Production Requests No. 23 and 29, Staff discovered several energy
efficiency measures provided by the CPA that were modeled with negative costs. Review of the
STAFF COMMENTS 7 JULY 10, 2025

supporting workpapers shows that the linear lighting, ovens, faucet aerators, exempt lighting, and
pre-rinse spray valve measures for all sectors are systematically affected. Additionally, the
ENERGY STAR Commercial washer measure was affected in several commercial segments. In
a follow-up production request, the Company stated that the negative values were the result of a
calculation error that resulted in the costs of some measures to be reported as negative, that it
worked with its CPA vendor to correct the negative cost values, and that the error did not impact
IRP resource selections. Response to Staff Production request No. 29. In discussion with the
Company, it provided corrected work papers that show those measures with a cost of zero. Staff
believes that these results are similarly concerning and may not accurately represent the cost of
implementing those measures. Staff recommends that the Company exercise caution when
planning DSM programs for these measures and be ready to provide detailed support for the
costs and cost-effectiveness of related programs. Staff encourages the Company to continue to
review the results of the CPA for additional errors and to carefully review the results of third-
party evaluations and studies in the future.
Demand Response ("DR')
The 2025 IRP's PRS includes selection of Idaho DR capacity. Most DR programs
require Advanced Meter Infrastructure ("AMI")meters in the Company's service territory. 2025
IRP at 166. The Company estimates the implementation of AMI meters to begin in 2026 and
complete in 2029. Id. at 166. The PRS calls for Idaho DR selections beginning in 2029 and
distributed across the forecast horizon. Id. at 55. The 2029 selections are for electric vehicle
TOU and variable peak pricing. Id. at 55. The next selection is battery energy storage in 2035.
Id. at 55. The total DR selection is for 10.6 MW of winter DR capacity, and 4.3 MW of Summer
DR capacity. Id. at 54. Consistent with the 2023 IRP filing, the Company considers DR
capacity as a load reduction in its WRAP modeling, this allows DR options to claim a higher
capacity benefit by avoiding some amount planning reserve margin. Id. at 173. However, DR
valuation may change due to uncertainty of dispatchable options ability to meet PRM and
behavior dependent nature of time of use options. Id. at 53. Staff will review DR selections as
the 2029 AMI completion date approaches.
STAFF COMMENTS 8 JULY 10, 2025

Avoided Costs
In order to select potential EE programs, the Company uses avoided costs to estimate the
value of program savings. Avoided costs are provided as an input into the Company's Preferred
Resource Strategy Model to define if potential EE measures are cost-effective. These value
streams represent the estimated energy, capacity, and transmission and distribution upgrade costs
that the Company defers or otherwise avoids through implementing the EE measures. These
values are important as they define the EE measures selected for DSM planning and to evaluate
the cost-effectiveness of those programs' performance. The Company's Idaho electric avoided
costs are shown in Table 2.8 of the IRP. Id. at 87. These avoided costs do not include clean
energy premiums, avoided social cost of greenhouse gases, or other adders. Id. at 84. Staff
believes that the Company's avoided costs are a reasonable forecast for DSM program planning.
STAFF RECOMMENDATION
Staff recommends the Commission acknowledge Avista's 2025 IRP filing. Additionally,
Staff recommends, as discussed above:
• The Company continue to evaluate potential resource allocation methods due to the
divergence in resource strategies and to keep the Commission informed about any
potential changes in the resource allocation method;
• The Company during the RFP process evaluate the cost impact to Idaho and the fair
allocation of generation and transmission resources for Idaho caused by any
Washington specific resources;
• The Company address the aforementioned CCA issues in the next IRP;
• The Company include a scenario where the Washington market and the California
market are not linked in the next IRP;
• The Company improve the clarity of market prices without the CCA in the next IRP;
• The Company continue to improve the IRP reliability analysis to measure resource
adequacy metrics on additional portfolios under evaluation across more years in the
planning horizon;
• The Company exercise caution when planning DSM programs for EE measures and
be ready to provide detailed support for the costs and cost-effectiveness of related
programs; and
STAFF COMMENTS 9 JULY 10, 2025

• The Company to continue to review the results of the CPA for additional errors and to
carefully review the results of third-party evaluations and studies in the future.
Respectfully submitted this 1 Oth day of July 2025.
Adam Triplett
Deputy Attorney General
Technical Staff. Michael Eldred
Vicki Stephens
Jason Talford
Yao Yin
I:\Utility\UMISC\COMMENTS\AVU-E-24-13 Comments.docx
STAFF COMMENTS 10 JULY 10, 2025

Attachment A—Staff Identified Mistakes in Market Prices
1. Page 246 of the 2025 IRP states that the 20-year nominal levelized price of the stochastic
study is $44.14 per MWh with CCA. "$44.14 per MWh" should have been "$44.11 per
MWh." Response to Staff Production Request No. 17.
2. Table 9.7 in the IRP should be replaced with the following table. Response to Staff
Production Request No. 20 (a).
20-year
20-year Levelized
Levelized without
with CCA CCA
Metric $/MWh $/MWh
Deterministic $45.45 $44.37
Mean $44.11 $42.77
10th Percentile $39.56 $38.42
50th Percentile $44.13 $42.85
95th Percentile $49.71 $48.05
Attachment A
Case No. AVU-E-24-13
Staff Comments
July 10, 2025

3. Table 9.8 in the IRP should be replaced with the following table. Response to Staff
Production Request No. 21.
Year Flat • • •
2026 41.98 $40.46 $43.12 $54.18
2027 $38.14 $38.58 $37.82 $50.78
2028 $35.40 $37.03 $34.18 $46.43
2029 $35.04 $36.64 $33.84 $45.19
2030 $39.18 $40.90 $37.89 $48.68
2031 $44.10 $46.40 $42.38 $53.18
2032 $44.33 $47.09 $42.27 $53.32
2033 $45.40 $48.29 $43.23 $54.77
2034 $45.55 S48.72 $43.17 $54.82
2035 $46.71 $49.96 $44.27 $56.59
2036 $46.40 $49.74 $43.90 $56.44
2037 $47.66 $51.45 $44.82 $57.60
2038 $47.77 $51.51 $44.98 $57.83
2039 $48.48 $52.35 $45.58 $58.86
2040 $49.59 $53.79 $46.43 $59.08
2041 $50.01 $54.44 $46.68 $59.91
2042 $52.31 $56.90 $48.88 $62.96
2U43 $b2.97 $51.bb $49.45 $b4.1 b
2044 $53.84 $58.61 $50.27 $65.39
2045 $55.07 $59.83 $51.48 $67.76
20-Year 1 $44.11 $46.58 $42.26 $54.53
Attachment A
Case No. AVU-E-24-13
Staff Comments
July 10, 2025

4. Table 9.9 in the IRP should have been replaced with the following table. Response to
Staff Production Request No. 21.
Year Flat • • Peak Evening$41.61 S40.42 $42.50 $53.43
2027 $37.88 S38.70 $37.26 $50.15
2028 $35.13 S37.19 $33.57 $45.89
2029 $34.57 S36.64 $33.01 $44.51
2030 $38.56 S40.85 $36.84 $47.91
2031 $43.00 S45.74 $40.96 $52.00
2032 $42.74 S45.92 $40.36 $51.69
2033 $43.82 $47.20 $41.29 $53.10
2034 $43.92 $47.54 $41.19 $53.13
2035 $44.93 $48.59 $42.18 $54.75
2036 $44.50 S48.21 $41.72 $54.48
2037 $45.69 S49.82 $42.61 $55.59
2038 $45.66 S49.68 $42.64 $55.67
2039 $46.29 $50.42 $43.19 $56.64
2040 $47.28 $51.69 $43.96 $56.76
2041 $47.66 S52.29 $44.19 $57.58
2042 $49.92 S54.68 $46.35 $60.58
2043 $50.52 $55.38 $46.88 $61.73
2044 $51.24 $56.12 $47.58 $62.81
2045 $52.39 $57.26 $48.71 $65.12
20-Year $42.77 $45.60 $40.64 $53.06
Attachment A
Case No. AVU-E-24-13
Staff Comments
July 10, 2025

5. Figure 9.22 in the IRP should be replaced with the following two figures. Response to
Staff Production Request No. 43.
Washington Price w/CCA(i.e.,Washington Zone)
$60.00
$52.89
$50.00
$41.52 $44.11
40.42
$40.00
$30.00
$20.00
$10.00
$0.00
Low Price Scenario High Price Scenario Expected Case No CCA
(Deterministic) (Deterministic) (Stochastic) (Deterministic)
Washington Price w/o CCA(i.e. Washington/Avista Zone Average)
$60.00
$51.86
$50.00
$40.41 $42.77
39.84
$40.00
$30.00
$20.00
$10.00
$0.00
Low Price Scenario High Price Scenario Expected Case No CCA
(Deterministic) (Deterministic) (Stochastic) (Deterministic)
Attachment A
Case No. AVU-E-24-13
Staff Comments
July 10, 2025

CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS '��DAY OF JULY 2025,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. AVU-E-24-13, BY E-MAILING A COPY THEREOF TO THE FOLLOWING:
PATRICK EHRBAR DAVID J MEYER
DIR OF REGULATORY AFFAIRS VP & CHIEF COUNSEL
AVISTA CORPORATION AVISTA CORPORATION
PO BOX 3727 PO BOX 3727
SPOKANE WA 99220-3727 SPOKANE WA 99220-3727
E-mail: Patrick.ehrbar(&avistacorp.com E-mail: david.maer(i�avistacorp.com
avistadocketskavistacorp.com
PATRICIA JORDA , SECRETARY
CERTIFICATE OF SERVICE