20251105Final_Order_No_36826.pdf

Office of the Secretary
Service Date
November 5,2025
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF AVISTA'S 2025 ) CASE NO. AVU-E-24-13
ELECTRIC INTEGRATED RESOURCE )
PLAN ) ORDER NO. 36826
On December 30, 2024, Avista Corporation d/b/a Avista Utilities ("Company") filed its
2025 Electric Integrated Resource Plan ("2025 IRP") with the Idaho Public Utilities Commission
("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 deadline for interested persons to intervene. Order No. 36453. No
parties intervened.
On March 14, 2025, the Commission issued a Notice of Modified Procedure, establishing
a deadline for public comments and Company reply deadline. Commission Staff("Staff'),the NW
Energy Coalition ("NWEC"), and two members of the public filed comments to which the
Company replied.
BACKGROUND
The Company uses its Integrated Resource Plan process ("IRP") to guide resource
acquisitions. 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. The
Commission has asked that a utility's IRP explain its current load/resource position, its expected
responses to possible future events, the role of conservation in its explanations and expectations,
and 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.
ORDER NO. 36826 1

THE FILING
The Company's 2025 IRP is approximately 365 pages,with approximately 1,354 pages of
appendices. The 2025 IRP has 12 sections: (1) Introduction; (2) Preferred Resource Strategy; (3)
Economic & Load Forecast; (4) Existing Supply Resources; (5) Resource Need Assessment; (6)
Distributed Energy Resources; (7) Supply-Side Resource Options; (8) Transmission &
Distribution Planning; (9) Market Analysis; (10) Portfolio Scenario Analysis; (11) Action Items;
(12) Washington Clean Energy Action Plan.
The contents of the 2025 IRP were developed through a series of public meetings with a
mix of traditional technical experts, such as public utility commission staff, regional utility
professionals, project developers, advocacy and environmental groups, concerned state agencies,
and both commercial and residential customers. Various issues are combined with assumptions
made about them and included in analysis and modeling that provides an expectation of future
prices for different resources, energy efficiency, demand response, and storage options. The
Company then develops a preferred portfolio of resources to serve future needs. According to the
Company, the 2025 IRP satisfies Idaho's regulatory requirements as provided in Commission
Order Nos. 22299 and 25260.
STAFF COMMENTS
Staff believed the 2025 IRP satisfies the requirements of Order Nos. 22299 and 25260 and
recommended that the Commission acknowledge it. However, Staff identified several key areas in
the 2025 IRP that need further review or greater focus in future IRPs.Because the 2025 IRP shows
a long-term resource shortfall beginning in 2030, there is sufficient time to address these issues
without affecting system reliability or increasing costs for Idaho customers. The areas of concern
include resource and transmission planning assumptions,Washington's Climate Commitment Act,
qualifying capacity contribution and planning reserve margin, reliability analysis, and demand-
side management programs. Staff s comments on each of these issues are described more
thoroughly below.
I. Preferred Resource Strategy
The Company's 2025 IRP Preferred Resource Strategy ("PRS") includes a total of 2,599
MW of new resources over the planning period. The table shown below outlines the new resources
selected under the PRS for the years 2026 through 2035.
ORDER NO. 36826 2

Resource • • . • . • Energy
(MW) Capability
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
The PRS includes a 90 MW natural gas turbine in Idaho, 500 MW of wind in Washington,
and 357 MW of system wind.In May 2025,the Company issued an all-source Request for Proposal
("RFP")to determine which resources will be acquired through 2035. Staff expressed concern that
the 500 MW of Washington wind, driven by state-specific environmental laws,may lead to unfair
cost impacts for Idaho customers. Staff urged the Company to closely evaluate these impacts
during the RFP process and ensure that generation and transmission costs are fairly allocated,
especially for resources driven by Washington-specific policy requirements.
II. Resource and Transmission Planning Input Assumptions
Staff reviewed the 2025 IRP resource and transmission assumptions and found them
reasonable for planning. These were compared to past IRPs, other utilities' plans, and industry
data. Staff's main concern is that differing energy strategies in Idaho and Washington may create
challenges for future resource and transmission allocations, especially as more state-specific
projects are added and current cost allocation methods become less effective.
The 2025 IRP does not assign available transmission capacity between states, though it
states the system can support up to 500 MW of wind without major upgrades. The PRS selects 500
MW of Northwest wind for Washington between 2029 and 2031.Under the current cost allocation
method—roughly 65%Washington, 35%Idaho—Idaho would pay 35% of both the wind projects
and the transmission used to deliver the energy, despite the projects serving Washington-specific
needs.
Staff inquired whether the Company had considered alternative resource allocation
methods to address Idaho and Washington's differing strategies. The Company acknowledged that
it has done some preliminary research but had yet to propose any specific changes. Staff
recommended the Company continue exploring allocation methods, keep the Commission
ORDER NO. 36826 3

updated, and during the RFP process, evaluate the cost impact and fair allocation of resources for
Idaho, especially related to Washington-specific projects.
III. Washington's Climate Commitment Act("CCA")
Staff reviewed how the Company modeled the CCA in the IRP, focusing on Idaho's costs,
the market link between Washington and California,and market prices. Staff also corrected several
pricing errors and informed the Company.
a. CCA Costs Associated with Idaho
The 2025 IRP included CCA costs for Idaho, like the Boulder Park plant, in its total cost.
The Company asserted that this will not affect IRP results or Idaho ratepayers since the IRP is a
planning tool, not a cost recovery request. Staff disagreed, noting that CCA assumptions can
change resource choices and portfolio costs. Also, the preferred portfolio impacts future rate
decisions and prudence reviews. Staff recommended the Company address these concerns in the
next IRP.
b. Washington and California Market Linkage
Staff indicated that the Washington Department of Ecology expects Washington and
California's CCA markets to link by 2026 or 2027. The IRP assumes this linkage in all scenarios
except one without the CCA policy. Linked markets will likely lower allowance and electricity
prices due to increased liquidity. However,because of regulatory uncertainty, Staff recommended
the Company include a scenario without market linkage in the next IRP.
c. Market Prices without the CCA
The 2025 IRP showed market prices with and without the CCA. Without the CCA, there
are two price types: one assuming no CCA policy exists, and another where energy is delivered
outside Washington to avoid CCA obligations. However, the 2025 IRP didn't clearly label or
explain these differences. Staff recommended the Company improve clarity on this in the next IRP
to prevent confusion.
d. Market Price Errors
The 2025 IRP included several errors in reported market prices, which Staff corrected in
Attachment A to its Comments.
ORDER NO. 36826 4

IV. Qualifying Capacity Contribution ("QCC") and Planning Reserve Margin
("PRN1")
Although the QCC values were based on the Western Resource Adequacy Program
("WRAP") rather than generation capacity relative to peak load, Staff believes the resulting
capacity positions are reasonable. This is because the Planning Reserve Margin ("PRM") was
calculated using QCC values to meet the Company's 5%Loss of Load Probability reliability target.
Staff also finds the Company has complied with Order No. 36056, which required PRM to be
based on this reliability target.
V. Reliability Analysis
Staff remained concerned about the Company relying on WRAP planning requirements, as
they reflect a short-term regional view rather than the Company's system needs. However, Staff
appreciated the development of the Avista Resource Adequacy Model("ARAM")to calculate the
Company's own PRM and additional reliability metrics. The 2025 IRP continued using WRAP for
capacity planning but used ARAM to evaluate reliability for select portfolios in 2030 and 2045.
While ARAM addresses many past concerns, Staff recommended expanding the analysis to
include more portfolios and years across the full planning horizon.
VI. Demand Side Management Programs
a. Energy Efficiency
Energy Efficiency ("EE") remains important in the Company's planning, but Staff
indicated the accuracy of its 2025 IRP estimates is uncertain. The PRS projects 870 GWh of
cumulative savings, reducing future load growth by 32%, with 26% of new savings from Idaho.
Most Idaho savings come from interior lighting (55.7%) and HVAC (23.8%). While residential
lighting savings are declining due to federal standards and high-efficiency adoption, commercial
lighting—especially high bay and linear fixtures—still offers significant potential, as reflected in
the Conservation Potential Assessment ("CPA").
Staff found that several energy efficiency measures in the CPA were incorrectly modeled
with negative costs,including lighting,ovens, faucet aerators, and other equipment. The Company
confirmed this was a calculation error and worked with its vendor to correct the values to zero.
However, Staff remained concerned that zero-cost assumptions may not reflect true
implementation costs. Staff recommended the Company be cautious when planning Demand-Side
ORDER NO. 36826 5

Management("DSM")programs for these measures, ensure accurate cost estimates, and continue
reviewing CPA results and third-party studies for errors.
b. Demand Response
The PRS of the 2025 IRP includes Idaho Demand Response ("DR") capacity, which
depends on Advanced Metering Infrastructure ("AMI"). AMI rollout is expected from 2026 to
2029,with DR programs starting in 2029, including electric vehicle time-of-use and variable peak
pricing, followed by battery storage in 2035. Total DR selected is 10.6 MW for winter and 4.3
MW for summer.DR is treated as load reduction in WRAP modeling,increasing its capacity value,
but its effectiveness may change due to uncertainty around dispatchability and user behavior. Staff
indicated that it will continue to monitor DR plans as AMI deployment progresses.
c. Avoided Costs
To select EE programs, the Company uses avoided costs to estimate the value of savings.
These costs—covering energy, capacity, and transmission and distribution deferrals—are inputs
in the PRS Model to determine if EE measures are cost-effective. Idaho's avoided costs, shown in
Table 2.8 of the IRP, do not include clean energy premiums or social costs of greenhouse gases.
Staff finds the avoided costs reasonable for DSM planning.
NWEC COMMENTS
The NWEC submitted high-level comments intended to help shape the final IRP. These
comments are summarized below.
I. Load Forecast
The NWEC expressed concern over future power demand.Although uncertain,the NWEC
believed rising demand presents opportunities for economic growth, emissions reductions, cost
stability, and improved system reliability through demand flexibility. According to the NWEC,
the growing gap between average and peak demand—highlighted in the Company's IRP—
emphasizes the importance of demand response, energy efficiency, and storage, especially given
lessons from recent extreme weather events. Consequently, the NWEC recommended Avista
conduct further studies on demand surges and load-shaping strategies. With less immediate
pressure than other utilities, the NWEC believed the Company is well-positioned to act
thoughtfully.
The NWEC observed that the IRP revealed increased interest in large data centers,
particularly in Idaho. These facilities, especially those supporting Al, have massive energy needs
ORDER NO. 36826 6

and could shift lower-cost resources away from existing customers, raise long-term costs, and
require major transmission upgrades. There is also a risk of stranded assets if planned projects do
not proceed. To protect current customers, the NWEC recommended that the Company and
Commission consider new rate structures, long-term contracts, and cost recovery mechanisms to
ensure large users like data centers do not burden residential and commercial customers. Given
projected national growth in data center load, the NWEC urged careful planning.
II. Customer Energy Efficiency, Demand Response, and Storage
The NWEC proposed using the term "customer-side resources" to highlight the broad
range of actions customers can take to support both their own needs and grid reliability.According
to the NWEC, this concept, which aligns with the "virtual power plant" model, emphasizes
collaboration between utilities and customers. However,NWEC urged a deeper evaluation of how
peak conditions, seasonality, and new large loads are increasing the value of energy efficiency,
which could support faster and greater acquisition.
The NWEC expressed concern over the draft IRP's limited DR targets—only 30 MW of
price-based DR and 58 MW of direct load control by 2045, most after 2035. NWEC believed the
Company's missing significant potential, especially from smart, automated technologies like grid-
connected water heaters and EV chargers.A realistic DR target of 10%of peak load—roughly 115
MW by 2030—would be comparable to a gas peaker plant, without the associated fuel and
reliability risks seen during recent extreme weather events.
The NWEC warned against"analysis paralysis" and urges the Company to accelerate DR
development. Technologies such as CTA-2045 water heaters and Bring Your Own Thermostat
programs, like those used by Idaho Power, offer near-term, scalable opportunities. Similarly, the
growing potential of battery storage—despite current costs—should be factored in more heavily,
as these resources can provide flexible, reliable capacity across many applications.
III. New Supply Resources
The NWEC expressed concern about the Company's plan to explore increased natural gas
availability due to the Northwest's limited gas infrastructure and growing risks during peak
demand. The NWEC urged caution, noting that greater reliance on gas—especially during critical
periods—should be carefully weighed against cleaner, more reliable alternatives.
The NWEC urged the Company to prioritize expanding customer-side resources (like
energy efficiency, demand response, and storage), building more transmission, and deepening
ORDER NO. 36826 7

participation in regional markets. For example, the Company's access to the Western Energy
Imbalance Market("WEIM")during the January 2024 gas curtailments helped maintain reliability.
Any gas supply study should include a full assessment of these non-gas options.
The NWEC believed that the critical development is the move from an imbalance market
to a day-ahead trading framework, which would expand access to diverse, lower-cost resources.
Two competing markets are being developed: the Extended Day-Ahead Market("EDAM"),which
builds on the WEIM, and Markets+, a new initiative from the Southwest Power Pool ("SPP").
EDAM offers a broader, more connected footprint—especially with nearby utilities like Idaho
Power and PacifiCorp—while Markets+ would limit Avista's trading to more distant partners,
requiring more complex transmission.
The NWEC supported EDAM's governing approach through a public benefit corporation
with representation for states and customers. In contrast, SPP's governance structure does not
reflect Western stakeholder priorities. Accordingly,the NWEC recommended that Avista analyze
the benefits of day-ahead market access and the governance structures of each option in its next
IRP.
IV. Transmission
The NWEC supported the Company's interest in the proposed North Plains Connector
project and encouraged continued collaboration with regional utilities. Although the 2025 IRP
notes potential upgrades to the Colstrip Transmission System ("CTS"), the NWEC recommended
exploring transmission expansion between CTS and the Company's system. This would be
complex,but could provide valuable access to Montana wind and broader markets like MISO and
SPP.
The NWEC also commended the Company's partnership with Idaho Power on the Lolo-
Oxbow upgrade and securing federal funding. It also encouraged further exploration of
transmission upgrades, including advanced conductors, to increase capacity and reduce
congestion.
V. Resource Adequacy
The NWEC also supported the Company's participation in the WRAP, but encouraged a
more nuanced use of its framework in IRP planning. According to the NWEC, WRAP's focus is
on short-term operations, which may not align with the long-term dynamics of IRP. The NWEC
ORDER NO. 36826 8

also agreed with the Company's decision to use its own planning PRM and cautioned against
directly applying other WRAP components to IRP modeling.
Despite supporting the Company's effort to adopt a climate-adjusted baseline, the NWEC
recommended consistent use of Intergovernmental Panel on Climate Change methods—
specifically applying Representative Concentration of Pathways("RCP")4.5 year-round. RCP 4.5
reflects emissions trajectories more aligned with current global commitments, while RCP 8.5 is
considered increasingly unrealistic. Using different scenarios seasonally may introduce
inconsistencies in analysis.
COMPANY REPLY COMMENTS
The Company briefly responded to many of Staffs recommendations, concurring with
some and opposing others.
I. Resource Allocation
The Company indicated that it is not currently proposing changes to the existing Production
Transmission ("PT") ratio used to allocate resource costs between Idaho and Washington. While
state-specific allocation could address future challenges from differing policies, any changes
would require agreement between both states and approval in a general rate case. The CCA and
Clean Energy Transformation Act ("CETA") may lead to higher-cost, cleaner resources or
dispatch changes, which could eventually require separate resource planning and cost allocation
by state if differences continue to grow.
II. Transmission Allocation
The Company indicated that it plans to evaluate bids from the 2025 All-Source RFP using
a methodology that considers both Idaho and Washington perspectives. According to the
Company, although the lowest-cost projects will be selected, if chosen resources primarily benefit
Washington, this could require a different cost allocation method than the current PT ratio.
III. Washington's CCA
The Company intends to exclude direct CCA costs from Idaho's cost forecast in the 2027
IRP, despite these costs currently applying to Idaho customers. The Company will also use an
electric price forecast that excludes CCA pricing—specifically, a forecast for northwest energy
without delivery into Washington—for avoided cost calculations.
ORDER NO. 36826 9

IV. Washington and California Market Linkage
The Company anticipates wholesale electric prices to be higher at times if the
Califomia/Quebec and Washington greenhouse gas credit markets don't link, due to needing
allowances for both programs. Although Washington passed legislation to enable this linkage, it
hasn't happened yet but efforts are ongoing. The Company will model a scenario without market
linkage or progress toward it for the 2028 forecast year, which will be included in the 2027 IRP.
V. Market Prices
The Company will present how the wholesale electric price forecast is developed and how
the CCA is included at a 2027 Technical Advisory Committee meeting.Additionally,the Company
will provide a price forecast for Idaho that excludes direct CCA pricing in the 2027 IRP.
VI. Reliability Analysis
The Company's 2025 IRP reliability analysis covered 2030 and 2045, but only for select
scenarios focusing on reliability concerns. Although analyzing every scenario could be beneficial,
all of them may be unnecessary because of their different goals. The Company anticipates
conducting more reliability analysis but is limited by current tools, which use an Excel-based
optimization. The Company is exploring the Aurora model to enable analysis of more years and
scenarios more efficiently.
VII. Demand-Side Management
The Company disclosed that it is making major updates to its energy efficiency analysis
for the 2027 IRP. The Company anticipates partnering with Cadmus to provide third-party
evaluations of potential energy efficiency and demand response measures for the 2027 and 2029
IRPs.
VIIL Price Errors
The Company agreed that thoroughly evaluating third-party studies in future IRPs will help
ensure the results are both reasonable and achievable.
VI. Load Forecast
The Company indicated that it is currently developing policies for large loads like data
centers and cryptocurrency miners. Although it is not planning to create a separate rate class for
these customers at this time, the Company stated that it is monitoring and evaluating whether such
a distinction may be needed as these loads grow in the region.
ORDER NO. 36826 10

VII. Customer Energy Efficiency,Demand Response, and Storage
The Company noted that its EE analysis for the 2025 IRP's CPA will be conducted by a
new consultant, Cadmus, for the 2027 and 2029 IRPs. This change, along with updated load
forecasting, the amount and types of cost-effective energy efficiency may differ in future IRPs.
The DR potential study for the 2027 and 2029 IRPs will also be conducted by Cadmus.
The results of the 2025 All-Source RFP, which included DR bids, will help identify actionable
projects if they are cost-competitive with other resource options. The Company stated that it is
currently reviewing bids from the 2025 All-Source RFP. If storage proves to be a cost-effective
way to address capacity needs, that will be determined through this process.
VIII. New Supply Resources
The Company stated that it will explore a comprehensive assessment of non-gas
alternatives as the NWEC recommended.
IX. Transmission
The Company agreed that strengthening the Montana transmission system will benefit its
customers.
X. Resource Adequacy
The Company disclosed that it plans to continue using WRAP data in its resource planning
where applicable.Additionally,the Company stated that it will revisit the base climate assumptions
used in the IRP forecasts and appreciates NWEC's input on using a single RCP year-round instead
of different ones for winter and summer.
COMMISSION FINDINGS AND DECISION
The Commission has jurisdiction over the Company's Application and the issues in this
case under Title 61 of the Idaho Code including Idaho Code §§ 61-301 through 303. The
Commission is empowered to investigate rates, charges,rules,regulations,practices, and contracts
of all public utilities and to determine whether they are just, reasonable, preferential,
discriminatory, or in violation of any provisions of law, and to fix the same by order. Idaho Code
§§ 61-501 through 503.
The Commission appreciates the active participation and input of Staff and NWEC in the
process and is confident that this input helps the Company develop a better and more
comprehensive IRP. The Commission also notes the significant effect that diverging state resource
strategies can have on the Company's resource acquisition. For example, Staff identified the
ORDER NO. 36826 11

potential for 500 MW of wind power in Washington, which is being developed in response to that
state's environmental regulations, to impose disproportionate or inequitable costs on Idaho
customers. Because it appears likely that state resource strategies will continue to diverge, we
direct the Company to assess Washington-specific resources for such disproportionate or
inequitable impacts on Idaho. Further, during the RFP process the Company is directed to explore
and evaluate resource allocation methods that will fairly allocate generation and transmission
resources for Idaho, and to keep the Commission apprised of any changes to its allocation
methodology.
Closely related to these allocation concerns is Washington's CCA, which presents several
unique issues the Company must address going forward. Despite the Company's contrary
assertion,we find that including CCA costs for Idaho can affect both the IRP and Idaho customers.
As Staff noted, CCA assumptions can influence resource selection and portfolio costs, which in
turn may affect future rate decisions and prudence reviews.
A specific modelling gap observed in the 2025 IRP is the Company's omission of scenarios
in which Washington's CCA persists but does not link with California's. If the two markets link,
the additional liquidity will likely depress both allowance and electricity prices; however,because
such linkage is uncertain at this point, we direct the Company to include non-linkage scenarios if
linkage does not occur before the next IRP submission.
We appreciate the Company's efforts to model market prices both with and without the
CCA in its 2025 IRP. That said, when presenting prices without the CCA the Company offered
two versions, one assuming the absence of any CCA policy and another reflecting deliveries
outside Washington to avoid CCA compliance costs but failed to clearly label or explain the
distinction. To prevent confusion in future filings, we direct the Company to provide clearer
labeling and descriptions in its next IRP and to separately identify costs associated with the
Washington CCA and CETA throughout the planning period.
Turning to system planning tools, we commend the Company for developing the ARAM.
To better align the analysis with the Company's long-term needs, however, we find it reasonable
to direct the Company to expand the ARAM analysis to include additional portfolios and more
years across the full IRP planning horizon. This will provide a fuller system perspective than the
shorter-term, regional view the WRAP presently supplies.
ORDER NO. 36826 12

Finally, we recognize that cost-effective DSM programs benefit both the Company and its
customers, but their success depends on accurate cost estimates and robust modeling. Given
potential weaknesses in the Company's DSM models, such as assuming that certain equipment
would cost nothing to implement, the Company must provide detailed evidence supporting actual
costs and cost-effectiveness when seeking to recover program costs. Considering errors identified
in the Company's initial DSM modeling, we also direct the Company to thoroughly review future
Conservation Potential Assessments and any third-party evaluations or studies to identify and
correct potential errors.
ORDER
IT IS HEREBY ORDERED that the Company's Electric 2025 IRP is acknowledged.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one (21) days of the service date upon this Order regarding any
matter decided in this Order. Within seven (7) days after any person has petitioned for
reconsideration, any other person may cross-petition for reconsideration. Idaho Code §§ 61-626.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho, this 5t1i day of
November 2025.
G
Grp
DWARD LODGE, RE I ENT
7OHN R. HAMMOND JR., COMMISSIONER
DAYN HARDI , COMMISSIONER
ATTEST:
9VA,
Laura Calderon Robles
Interim Commission Secretary
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ORDER NO. 36826 13