20211216Final_Order_No_35257.pdf

ORDER NO. 35257 1

Office of the Secretary
Service Date
December 16, 2021

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF AVISTA
CORPORATION DBA AVISTA UTILITIES’
2021 ELECTRIC INTEGRATED RESOURCE
PLAN
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CASE NO. AVU-E-21-04

ORDER NO. 35257

On March 31, 2021, Avista Corporation dba Avista Utilities (“Company”) filed its
2021 Electric Integrated Resource Plan (“Electric IRP” or “IRP”). The IRP outlines and analyzes
the Company’s strategy for meeting its customers’ projected energy needs over the next 24 years.
The Company files an IRP every two years and uses it to guide resource acquisitions.1
On April 23, 2021, the Commission issued a Notice of Filing and Notice of Intervention
Deadline. Order No. 35022. Idaho Conservation League (“ICL”) intervened on May 10, 2021.
Order 35041.
On June 4, 2021, the Commission issued a Notice of Modified Procedure establishing
deadlines for public comments and the Company’s reply. Order No. 35062. Commission Staff and
ICL filed comments to which the Company replied.
Having reviewed the record in this case, the Commission now issues this Order
acknowledging the Company’s IRP.
BACKGROUND
An IRP is a status report on the utility’s ongoing, changing plans to serve its customers
adequately and reliably at the lowest system cost and least risk over the next 20 years. The report
informs the Commission and the public about the utility’s plans and is like an accounting balance
sheet; that is, it is a “freeze frame” look at the utility’s fluid resource planning process. See Order
No. 22299. The IRP is meant to demonstrate to the public that the Company has reasonably
planned for different scenarios. The Commission thus expects a utility to vigorously test the IRP’s
assumptions to ensure the IRP accurately reflects potential changes to markets and customer
demand.

1 The Company was granted a six-month extension to file its 2019 IRP. Order No. 34312. The Commission changed
the caption for the Company’s filing to the “2020 Electric Integrated Resource Plan” when it issued the Notice of
Filing. Order No 34609. The Company’s 2020 Electric IRP was acknowledged on October 15, 2020. Order No. 34814.

ORDER NO. 35257 2
The Company must update its IRP every two years and allow the public to participate
in developing the IRP. See id.; Order No. 25260. The final IRP must include the subjects required
by the Commission’s prior Orders, including Order Nos. 22299 and 25260. In sum, the final IRP
should explain the Company’s present load/resource position, expected responses to possible
future events, and the role of conservation in those responses. It also should 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.
Order No. 22299. The IRP should separately address the Company’s: (1) existing resource stack;
(2) load forecast over a 20 year load growth scenario; and (3) additional resources which “should
consist of the utility's plan for meeting all potential jurisdictional load over the 20-year planning
period” ideally by describing “the most probable 20-year scenario followed by comparative
descriptions of scenarios showing potential variations in expected load and supply conditions, and
the utility's expected responses thereto.” Id.
By acknowledging the IRP, the Commission acknowledges the Company’s ongoing
planning process, not the conclusions or results reached through that process.
STAFF COMMENTS
Staff recommended the Commission acknowledge the Company’s 2021 Electric IRP.
Staff’s recommendation was based on its active participation in the IRP Technical Advisory
Committee (“TAC”), its review of the Company’s IRP filing, the Company’s responses to audit
and production requests, and its review of the customer and stakeholder feedback received through
the public input process. Staff acknowledged the Company’s IRP team’s work to solicit input and
feedback from parties throughout the IRP process.
Staff identified several topic areas it believed require additional review in the next
Electric IRP cycle. These include: (1) Reliability Analysis; (2) Market Reliance; (3) Colstrip
Economic Analysis; (4) Portfolio Optimization by State and System; and (5) Energy Efficiency
and Demand Side Management Programs.

ORDER NO. 35257 3
(a.) Reliability Analysis
Staff was still concerned with the Company’s reliability analysis. Staff expressed
concern with the Company assigning a single Planning Reserve Margin to all portfolio scenarios
and not verifying reliability across multiple years and portfolios in its 2020 IRP. See Staff
Comments. While it believed the Company made progress in addressing these concerns in the
current IRP, Staff expected the reliability analysis to receive increased focus in the next IRP cycle.
Specifically, Staff would have liked to see a reliability analysis which measured the resulting Loss
of Load Probability (“LOLP”) or Loss of Load Expectation (“LOLE”) of all its portfolios under
evaluation across the full planning time horizon.
The 2020 IRP reliability analysis only evaluated the resulting LOLP for the Preferred
Resource Strategy (“PRS”) portfolio for one-year. In the 2021 IRP, the Company increased the
number of portfolios it evaluated for the resulting LOLP, but still only for a single year. To
understand the reliability performance of the Company’s Clean Resource Plan portfolio, however,
the Company evaluated its reliability across an additional year. Staff looked forward to continuing
improvements in the future.
Coverage of reliability analysis in the IRP process is often limited and presented at the
end of the IRP cycle. In the 2021 IRP, the results of the reliability analysis were presented after
the draft IRP was sent out for review. Performing a reliability analysis at the very end of the
process can result in a portfolio that appears promising from a cost standpoint, only to end up
unreliable, according to Staff. Staff believed evaluating scenarios that are not known to meet
reliability standards has limited value in an IRP. Staff understood the 2021 IRP cycle was
shortened due to the extension of the 2019 IRP; however, Staff believed the reliability analysis
should be a larger priority due to the increasing number of factors potentially affecting system
reliability.
At a July 21, 2021, meeting, the Company stated its plan to start testing a new modeling
software, PLEXOS, with the intention to replace its current reliability modeling software. Staff
was encouraged by the Company’s efforts to improve reliability analysis and looked forward to
reviewing the results. Staff recommended the Company sufficiently test the new software to verify
the results are accurate before full implementation.

ORDER NO. 35257 4
(b.) Market Reliance
Due to load changes and reduced resource capacity contributions based on new
analyses and data, the Company changed its market reliance assumption from 250 MW, as in
previous IRPs, to 330 MW in this IRP. See Production Response No. 5(c). It was determined 330
MW was necessary during regionally stressed hours to maintain a 5% LOLP with a 16% planning
margin. See Production Response No. 5(b). Staff was still concerned, however, with the
Company’s reliability modeling and the Company’s failure to determine if it can rely on this
additional level of market availability long-term.
To determine a reasonable level of market reliance, Staff recommended that the
Company evaluate import capability considering market availability of both firm generation and
transmission capacity. The Commission shared this view in previous orders. Order No. 33425
indicated that a utility’s import capability—its ability to make short-term purchases using its
transmission capacity—should be included in the load and resource balance. Recent, unexpected
changes in the market for firm transmission have caused availability to tighten across the Western
Interconnection and have affected many utilities’ ability to rely on the market in the future.
The Company expected to set future market reliance based on the information gained
from its participation in the Northwest Power Pool’s Resource Adequacy Program (“RA
Program”). See Production Response No. 5. Staff indicated that the RA Program, in addition to
providing a process for participating utilities to reserve capacity and ensure that it will be available,
also provides visibility to capacity available across the region for making future reservations.
(c.) Colstrip Economic Analysis
Staff continued to express concern with the Company’s Colstrip analysis as it has in
the last three IRP cycles. The Company changed how it modeled Colstrip in the current IRP to
address Staff’s concerns. Staff appreciated the change and believed it is an improvement. Staff
was concerned, however, with how Colstrip’s removal in 2021 in the PRS affects reliability. In
addition, Staff preferred a Colstrip analysis that accurately quantifies the impact of different exit
dates on reliability, cost, and risk to Idaho customers.
In previous IRPs, the Company chose a limited number of years to evaluate Colstrip’s
retirement. Staff has recommended evaluating more years for retirement or allowing the model to
evaluate every year possible. In the current IRP, the Company allowed Colstrip to remain in the
Idaho portfolio in any year it remained economic. Staff believed this move was an improvement

ORDER NO. 35257 5
because it provided a resource portfolio and Colstrip exit scenario to compare against
environmental policy driven scenarios.
Staff’s concern with Colstrip’s removal in 2021 in the PRS was partially based on the
Company’s failure to provide evidence that retiring Colstrip in 2021 is possible. Staff did not
believe the PRS should include resource retirements that are infeasible. Staff was also concerned
that by making unrealistic exit date assumptions, portfolios would likely reflect incremental
replacement resources that are not optimal for the system. Staff believed it appropriate to evaluate
retiring Colstrip in 2021 as a scenario for comparison purposes, but that, ultimately, the Company
should not include unrealistic retirement dates for Colstrip in its PRS portfolios.
An additional concern related to removing Colstrip in 2021 was reliability. The
Company’s reliability analysis focused primarily on a single year—2030—which Staff believed
was a flaw in the current reliability analysis. Staff believed that, if Colstrip’s retirement is nigh,
the Company should conduct a deeper analysis to ensure an early retirement would not affect
reliability.
Staff understood the Company’s status as a minority partner in Colstrip and that its
existing contractual obligations create a difficult situation for modeling Colstrip in the IRP.
Commission Order No. 34814 requires the Company to file an annual update on its Colstrip
ownership interest by October 1. See Case No AVU-E-19-01. Staff looked forward to reviewing
the updated Colstrip economic analysis in the annual update later this year and would like to see
more on the reliability, cost, and risk to Idaho customers across diverse Colstrip exit dates.
(d.) Portfolio Optimization by State and for the System
The Company changed the IRP portfolio optimization model in the 2021 IRP to allow
new resources to be added to the system or assigned to a specific state to better understand the
drivers and cost responsibility of state specific resource decisions. Staff Comments at 6. Staff
agreed with the Company’s statement that “the reason for the modeling change was, ‘to better
understand the impacts of Washington State policies’ effect on Idaho’” and believed that such
changes would improve the IRP. Id. That said, Staff was concerned with the method the Company
used to divide load and resources in the IRP and recommended using methods that maintain the
benefits of the system but allow for state-by-state needs and constraints.
Loads and resources are divided using the Production-Transmission (“PT”) ratio in the
2021 IRP. Id. The PT ratio is the current state allocation method used for generation and cost

ORDER NO. 35257 6
allocation and is based on the breakdown of load between states. See Production Response No.
2(a). Staff believed using the PT ratio to divide existing resources was reasonable in this IRP so
long as this method was reevaluated in the future.
Staff believed the Company’s progress in developing a multi-jurisdictional workshop
to discuss and consider alternative methods to allocate costs and benefits of resources between
Idaho and Washington was important to developing resource planning methods, identifying state
specific resource needs, and aiding in the update of the current state allocation methods as state
policies continue to change.
(e.) Energy Efficiency and Demand Response Programs
Staff outlined its concern in its 2019 IRP comments that the Company’s method for
energy efficiency savings overstated the peak load reduction obtained from its energy efficiency
programs. Staff stated the Company has provided better, more accurate and reliable estimates of
energy efficiency savings in the 2021 IRP. Staff appreciated the Company’s efforts to improve
the accuracy of its estimated energy efficiency savings from these programs and believed the
results from the most recent prudency filing—Case No. AVU-E-20-13—will assist the Company
in accurately quantifying energy efficiency’s contribution to reducing peak load.
In the Company’s PRS, energy efficiency will reduce the Company’s future load
growth by 68% by 2045, with 23% of the new energy efficiency savings coming from Idaho
customers. In total, the Company’s commercial customers are set to achieve 47% of energy
efficiency savings, and its residential customers, 37%. Additionally, the demand response
programs in the PRS are estimated to reduce 16 MW of peak load by 2024 for the Company’s
Idaho service territory; an 8 MW peak load reduction is anticipated to come from third party
contracts and another 8 MW from Variable Peak Pricing and Time of Use Rates.
IDAHO CONSERVATION LEAGUE COMMENTS
ICL’s comments focused on two process issues in the IRP. First, ICL commented that
the IRP risk analysis section only considered a single risk metric for the IRP’s PRS that deals with
hydropower contracts for Washington customers and fossil fuel powered plants for Idaho
customers. ICL recommended the Commission direct the Company to assess the different risk
implications that arise from pursuing different resources for Idaho customers, who are subject to
volatile gas prices and fossil fuel pollution limitations, compared to Washington customers who
enjoy fixed-price hydropower.

ORDER NO. 35257 7
Second, ICL commented that the Company’s immediate exit from Colstrip is the least
cost option for Idaho customers. ICL indicated, however, that the IRP showed that the Company
planned to remain in Colstrip notwithstanding the potential of excess costs to Idaho customers.
ICL recommended that the Commission direct the Company to improve the IRP process by
incorporating methods to protect Idaho customers from decisions prioritizing corporate
relationships ahead of economics.
COMPANY REPLY COMMENTS
The Company replied to Staff and ICL. The Company acknowledged that it developed
the IRP over a 11-month period with the help of over 100 representatives, six TAC meetings, two
workshops, and a virtual public meeting to inform the public and take input. Company Reply
Comments at 2.
(a.) Response to Staff’s comments
i. Reliability Analysis
The Company agreed with Staff’s concerns regarding reliability of the Company’s
system when the potential resource portfolios are changing. Id. at 3. The Company stated that there
were two options to address reliability planning.
The first option was to continue improving existing methods. The Company stated it
“is evaluating new software (“PLEXOS”) to increase the breadth of reliability planning studies
across additional scenarios and time horizons as compared to its internal ARAM model.” Id. The
Company acknowledged its “evaluation of [PLEXOS], or an alternative software, may not be
available for a complete analysis of all portfolios in time for the 2023 IRP even if the Company
finds the new technology to be satisfactory.” Id.
The second option the Company offered was to forgo detailed utility reliability
modeling and use regional planning requirements set by the RA Program. Id. at 4. The Company
stated that it planned to “select resources in its next IRP to meet the requirements of the RA
Program so long as the region continues to pursue the objectives of regional coordination.” Id.
The Company stated, “it will plan to continue conducting reliability studies to understand its
market exposure using PLEXOS, ARAM, or other software.” Id. The Company noted that it “may
use this analysis to recommend higher planning margins to either increase reliability above the 1
in 10 criteria or to reduce market exposure.” Id. The Company planned to discuss the different

ORDER NO. 35257 8
concepts available with the TAC before deciding which option to pursue.
ii. Market Reliance
The Company stated “[t]here are two main tradeoffs to examine for [LOLP] reliability
studies for interconnected systems.” Id. at 5. The Company explained that “[b]y interchanging the
amount [sic] of excess resources under utility control” (Planning Reserve Margin (“PRM”)), as
compared to the amount of power available from the region during peak hours (expected peak load
and market reliance), “the utility can achieve the same reliability metric.” Id. “If market reliance
increases,” the Company explained, “then PRM lowers since the utility will rely on the market for
resources at time of peak rather than its own resources; increasing PRM will effectively create less
reliance on the market because the utility will have additional resources to access.” Id. The
Company noted that, “[i]n the 2021 IRP, [the Company] retains the same level of reliability metric
of 5[%] LOLP by retaining its PRM of 16[%]in the winter and 7[%] in the summer . . . .” Id. The
Company submitted that “[t]his decision increased market reliance based on the study results to
maintain 5[%] LOLP.” Id.
The Company stated that the first limitation in estimating the amount of regional market
availability is access to the market through transmission. Id. A second limitation, the Company
stated, “is whether there are excess resources from neighboring systems to meet demand.” Id. The
Company stated that its primary concern when it comes to accessing energy is availability of
surplus resources. Id. The Company stated it “has significant transmission interconnections to
other utilities including BPA and market purchases from the Mid-Columbia trading hub to the
[Company’s] system is in a direction that creates counter flow to congested east to west flow.” Id.
at 5. The Company considered the major issue when conducting a reliability analysis on a stand-
alone utility to be how the resource need of the Company differs from other utilities or, on other
occasions, occurs at the same time. To deal with this issue, the Company began developing the
RA Program and “ensuring utilities do not depend on the same market surplus to meet their
customers’ peak load.” Id. at 6.
The Company stated that, “it will use the RA Program’s planning criteria for resource
planning since these requirements are based upon a regional analysis ensuring regional reliability.”
Id. The Company also intended to “study the level of risk it will be relying on in the market and
determine if it should acquire additional resources beyond the minimum capacity levels to lessen
this market risk.” Id.

ORDER NO. 35257 9
iii. Colstrip Economic Analysis
The Company stated that it improved its “Colstrip modeling based on previous Staff
and TAC member recommendations.” Id. at 6. In particular, the Company examined the economic
feasibility of exiting Colstrip immediately, in 2021. The Company acknowledged that, while
uneconomic, Montana state legislation, a pre-existing operating agreement, and litigation and
arbitration between the owners of the plant, prevent it from having a “good understanding when it
can legally exit Colstrip.” Id.
The Company did, however, “consider reliability effects of exiting Colstrip in other
years than 2030.” Id. at 7. Specifically, the Company examined “the reliability effects in 2025
where the Company will still be within the 5[%] LOLP without Colstrip but will need to replace
this lost capacity when its capacity position reverses to a deficit due to the Lancaster contract
expiring in 2026.” Id. Because the resource portfolio is not materially different between 2021 and
2025, the Company did not model any earlier years.
iv. Portfolio Optimization by State or for the System
The Company stated that to begin the process of implementing Staff’s guidance on how
to optimize its energy portfolio it planned to hold its first workshop in late fall of 2021.
v. Energy Efficiency and Demand Response
The Company indicated it anticipated increased participation in demand response
programs. The Company acknowledged that it sought to be more transparent in how it examined
energy efficiency programs. The Company stated it intended to implement demand response
programs to help meet system peaks by 2026.
vi. Public Participation
The Company stated its plan was “to continue to engage all interested customers to
provide an overview of the Company’s resource planning efforts, answer questions and to listen
to customers concerns about resource planning.” Id. at 8.
(b.) Response to ICL
To ICL’s comment that the IRP risk analysis section was inadequate, the Company
responded that “it fully modeled the risk of natural gas resources by studying the cost of the
resource, natural gas prices and carbon pricing risk.” Id. The Company further explained that it
“conducted a risk analysis showing the portfolio cost impacts of a national carbon tax, priced at

ORDER NO. 35257 10
the social cost of carbon.” Id. As such, the Company concluded “that it provided significant risk
analysis of natural gas resources.” Id. at 9.
The Company responded to ICL’s second comment—that exiting Colstrip immediately
was the most economical outcome for Idaho customers—by reiterating that, due to the legal
obligations, it could not immediately exit Colstrip.
COMMISSION DISCUSSION AND FINDINGS
The Company is an electrical corporation and public utility as defined in Idaho Code
§§ 61-119 and -129, and the Commission has jurisdiction over it and the issues in this case under
Title 61 of the Idaho Code. Having reviewed the record, we find that the Company’s 2021 Electric
IRP satisfies the requirements in the Commission’s prior orders. We thus acknowledge that the
Company has filed its 2021 Electric IRP.
We also recognize the limited scope of the IRP. The IRP is intended to serve as a
planning document, and resource decisions are not made in the IRP. We appreciate the active
participation of Staff and ICL and members of the TAC in the process and are confident that their
input helps the Company develop a better and more comprehensive IRP. We particularly note Staff
and ICL’s comments discussing the economics of the Company’s involvement in Colstrip. We
look forward to continuing to work with Staff and the Company on the issues surrounding its
involvement in Colstrip.
O R D E R
IT IS HEREBY ORDERED that the filing of the Company’s 2021 Electric 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 of this Order with regard to 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. See Idaho Code § 61-
626.
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ORDER NO. 35257 11
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 16th day
of December 2021.

PAUL KJELLANDER, PRESIDENT

KRISTINE RAPER, COMMISSIONER

ERIC ANDERSON, COMMISSIONER

ATTEST:

Jan Noriyuki
Commission Secretary

I:\Legal\ELECTRIC\AVU-E-21-04\orders\AVUE2104_final order_rn.docx