20230502Notice_of_Filing_Order_No_35765.pdf

NOTICE OF FILING
NOTICE OF INTERVENTION DEADLINE
ORDER NO. 35765 1

Office of the Secretary
Service Date
May 2, 2023

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

On March 31, 2023, Avista Corporation, d/b/a Avista Utilities (“Avista” or
“Company”) filed its 2023 Natural Gas Integrated Resource Plan (“IRP”). Application at 1.
The IRP must discuss the subjects required by Commission Order Nos. 25342, 27024,
27098, and 32698, and Section 303(b)(3) of the Public Utility Regulatory Policies Act (“PURPA”),
15 USC § 3202. The Commission reviews the IRP to ensure it discusses these subjects and
represents a diligent effort by the Company to plan for the anticipated supply and demand for
natural gas.
With this Order, the Commission provides notice of the IRP filing and sets a deadline
for interested parties to intervene.
NOTICE OF IRP FILING
YOU ARE HEREBY NOTIFIED that the Company’s natural gas IRP contains an
Executive Summary, and chapters on Demand Forecasts; Demand-Side Resources; Current
Resources and New Resources Options; Policy Issues; Preferred Resource Strategy; Alternate
Scenarios; Distribution Planning; and the Company’s Action Plan. IRP at 5-9; 11-15. The
following information comes from the IRP’s Executive Summary and Application. See generally
IRP, Filing. Further detail may be obtained in the IRP’s remaining chapters and appendices.
YOU ARE FURTHER NOTIFIED that the Company stated its IRP identifies a
strategic natural gas resource portfolio that meets expected customer demand requirements over
the next 20 years. IRP at 11-16. The IRP involved input from the Company’s Technical Advisory
Committee (“TAC”), which includes Commission Staff, peer utilities, customers, and other
stakeholders. Id. at 22-23. Topics discussed with the TAC included resources to meet energy
IN THE MATTER OF AVISTA
CORPORATION’S 2023 NATURAL GAS
INTEGRATED RESOURCE PLAN (IRP)
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CASE NO. AVU-G-23-03

NOTICE OF FILING

NOTICE OF
INTERVENTION DEADLINE

ORDER NO. 35765
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demand, energy policy compliance, specific planning topics, reviewing the progress of planning
activities, and soliciting input on IRP development and results. Id. The Company stated the IRP
process results in a resource portfolio designed to serve customers’ natural gas needs while
balancing cost and risk. Id. at 21.
YOU ARE FURTHER NOTIFIED that the Company used new PLEXOS® planning
modeling software to perform the natural gas supply planning and analysis for the 2023 IRP. Id.
at 24. The Company represented the updated software allows for “unlimited flexibility” and ran
scenarios on “customer growth and customer natural gas usage to form demand forecasts; existing
and potential transportation and storage options and associated costs; existing and potential natural
gas supply availability pricing; revenue requirements on all new asset additions; weather
assumptions; and conservation.” Id. The Company used the additional modeling features to
analyze weather and price uncertainty, and adjusted its weather planning standard, as discussed
below. Id.
YOU ARE FURTHER NOTIFIED that the Company forecasted increased demand due
to customer growth and decreased demand based on the electrification of natural gas customers,
i.e.; jurisdictions changing building codes to require electrification (“electrification”). Id. at 30-31.
The Company anticipated growth from a current average of 379,669 core natural gas customers
with 38,871,519 dekatherms (Dth) of natural gas to 469,703 core natural gas customers with
45,082,213 Dth of natural gas. Id. at 50. The Company estimated that electrification could reduce
demand 33% or 6.9 million Dth for residential customers by 2045. Id. The Company updated its
weather planning standard to include a “99% probability of a daily temperature occurring” variable
instead of relying on the “coldest day on record” and Company performed a use-per-customer
weather, peak-day design, and load forecasts on weather variables as warming temperatures
decrease average demand. Id. at 32, 37.
YOU ARE FURTHER NOTIFIED that the Company discussed demand-side resources
factors of energy efficiency (“EE”) programs, avoided costs, the conservation potential assessment
(“CPA”) for Washington and Idaho, and electric demand response (“DR”) and related programs.
Id. at IRP Chapter 3. The Company stated its commitment to “offering natural gas efficiency
[(“EE”)] program to residential, low income, commercial and industrial customer segments” when
feasible and cost-effective. Id. at 53. The Company identified its CPA or EE potential assessment
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using the Total Resource Cost Test (“TRC”) and the Utility Cost Test (“UCT”). Id. at 55-56. The
Company estimates the first year UCT achievable economic potential in Idaho would be 46,414
Dth, and 13,451,011 Dth by 2045. Id. at 57. The Company’s estimated Conservation Targets for
Idaho for 2024-2025 totaled 1,091,136 therms. Id. at 58.
YOU ARE FURTHER NOTIFIED that the Company has electric DR programs to
provide capacity “when wholesale prices are unusually high, when a shortfall of generation or
transmission occurs, or during an emergency grid-operation situation.” Id. at 62. The Company
identified five Natural Gas Demand Response (“NGDR”) options—Direct Load Control Smart
Thermostat; Third Party Contracts- Firm Curtailment; Behavioral (voluntary reduction); Time-of-
Use (“TOU”) Rates Opt-in and Variable Peak Pricing (“VPP”) Rates—and the expected
participating market segment, program participation rates, costs and potential savings for each
option. Id. at 63-66. The Company estimated these five programs would potentially result in
savings of 5,091.47 Dth by 2030 and 6,116.02 Dth by 2045. Id. at 66. The Company also discussed
state policies promoting electrification and the conversion costs associated with electrification. Id.
at 66-74.
YOU ARE FURTHER NOTIFIED that the Company has regional pipeline resources,
storage resource options “to provide supply diversity, enhanced reliability, favorable price
opportunities, and flexibility to meet a varied demand profile.” Id. at 75. The Company also
considered carbon reducing supplies (natural gas and hydrogen) and represented it has a “low-cost
commodity environment with abundant supply availability, especially when compared to other
regions across the globe.” Id. The Company’s flexibility comes from its geographic proximity to
most of the Pacific Northwest regional market hubs, including AECO, Rockies,
Sumas/Huntingdon, Malin, Station 2, Stanfield, and Kingsgate. Id. at 76. The Company
represented its contracts include terms on firm versus non-firm; fixed versus floating pricing;
physical versus financial; load factor/variable take; and liquidated damages, and made assumptions
under a “firm, physical, fixed-price contract, regardless of contract execution date and type of
contract” for its IRP projections. Id. at 77-78. The Company described uncertainty in forecasting
because of dramatic changes in natural gas price outlook, including “improved drilling methods
and technology used in oil and natural gas production, increasing exports to Mexico, and LNG,
and policies toward the continued use of natural gas” as well as “more stringent renewable energy
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standards and increased need for natural gas-fired generation to back up such resources.” Id. at 78.
The Company acknowledged it can monitor factors and trends but cannot accurately predict
outcomes. Id. The Company also discussed its market-related risk and approaches to risk
management. Id. at 105-106.
YOU ARE FURTHER NOTIFIED that the Company represented it has consistently
sourced over half its electric generation portfolio from renewable resources. Id. at 107. The
Company reported there is no uniform approach to regulating greenhouse gas emissions among
the jurisdictions it serves. Id. at 109. While the Company does not expect an Idaho-specific
greenhouse gas policy, Idaho would be affected by any federal policies and regulations of
greenhouse gas emissions. Id. The Company conducted a customer market survey and reported
that many of its customers are supportive of sourcing green or local energy—noting that support
significantly decreases if customers’ bills increase more than 10%. Id. at 121.
YOU ARE FURTHER NOTIFIED that the Company represented its preferred resource
strategy (“PRS”) will “utilize the least cost natural gas basin, and storage, combined with energy
efficient to meet energy demand” and acquire natural gas on a “least cost basis from the available
hubs.” Id. at 146. The Company stated Idaho’s primarily available hub has been the AECO basin
because of its geographic proximity to Idaho and the Company’s largest amount of pipeline
capacity. Id. The Company used “Monte Carlo Risk Analysis” to model scenarios related to PRS.
Id. at 153-155.
YOU ARE FURTHER NOTIFIED that the Company stated it applied risk analysis to
model demand scenarios for PRS, electrification and supply (carbon intensity, limited RNG
availability, and interrupted supply) and high customer growth, social cost of carbon, and the
average case using “average daily weather for the past 20 years as compared to the PRS.” Id. at
IRP, Chapter 7. Table 7.1: 2023 IRP describes the different demand and price-influencing factors
the Company analyzed further in figures 7.1-7.18. Id. at 159-178. The Company indicated it would
integrate additional information for risk analysis on goals and legislation as they arise. Id. at 170-
175.
YOU ARE FURTHER NOTIFIED that the Company evaluated distribution planning,
primarily focusing on capacity requirements and integrity assessments. Id. at IRP, Chapter 8. The
Company discussed enhancements to its distribution system including pipelines, regulators, and
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compressors, along with targeted conservation resources that may “reduce or delay” the need for
these enhancements. Id. at 185. The Company summarized its plans for major distribution system
enhancements in Kettle Falls High Pressure Reroute, WA; Pullman High Pressure Reinforcement,
WA; and city gate station updates in Idaho, Oregon, and Washington. Id. at 188-189.
YOU ARE FURTHER NOTIFIED that the IRP contains an Action Plan to position the
Company to “provide the best cost/risk resource portfolio to support and improve IRP planning.”
Id. at IRP, Chapter 9. The Action Plan discussed the status of the 2021 IRP recommendations made
by Oregon, Washington, and Idaho, including the following:
• Further model carbon reduction (Oregon and Washington);

• Modeling all requirements from Executive Order 20-04 (Oregon);

• Ensuring the Energy Trust (“ETO”) has sufficient funding to acquire therm savings
of the amount identified and approved by the Energy Trust Board;

• Exploring the feasibility of using projected future weather conditions in its design
day methods; and

• Updating the Oregon distribution projects from the 2021 IRP to understand capital
costs outside of the 2021 IRP expectations.

Id. at 191-196.
The Company stated its new activities for the 2023-2024 Action Plan include:
• Purchasing Community Climate Investments for compliance to the Climate
Protection Plan for years 2022, 2023, 2024, 2025 and 2026 per Executive Order 20-04.

• Meeting IRP gross savings target of 568,000 therms in 2024 (ETO identified
546,000 therms in the 2023 IRP verses 427,000 therms of planned savings in the 2023
ETO Budget and Action Plan).

• Offering a new ETO program for interruptible customers in 2023 to save 15,000
therms.

• Exploring end use modeling techniques for forecasting customer demand.

• Considering outside entity contracting to help value supply side resource options
such as synthetic methane, renewable natural gas, carbon capture, and green hydrogen.

Id. at 195-196.

NOTICE OF FILING
NOTICE OF INTERVENTION DEADLINE
ORDER NO. 35765 6

YOU ARE FURTHER NOTIFIED that the filing is available for public inspection
during regular business hours at the Commission’s office. The filing and documents related to this
case are also available on the Commission’s website at www.puc.idaho.gov. Click on the “GAS”
icon, select “Open Cases,” and click on the case number as shown on the front of this document.
YOU ARE FURTHER NOTIFIED that all proceedings in this matter will be conducted
pursuant to the Commission’s Rules of Procedure, IDAPA 31.01.01.000 et seq.
YOU ARE FURTHER NOTIFIED that all proceedings in this case will be held
pursuant to the Commission’s jurisdiction under Title 61 of the Idaho Code.
NOTICE OF INTERVENTION
YOU ARE FURTHER NOTIFIED that persons desiring to intervene in this matter to
obtain parties’ rights of participation must file a Petition to Intervene with the Commission
pursuant to this Commission’s Rules of Procedure 71-73, IDAPA 31.01.01.072-073. Persons who
wish to intervene as a party must file a Petition to Intervene no later than 21 days after the
date of service of this Order. Persons desiring to present their views without parties’ rights of
participation do not have to intervene and may present their comments without prior notification
to the Commission or the parties.
YOU ARE FURTHER NOTIFIED that the Commission Secretary shall issue a Notice
of Parties after the deadline for intervention has passed. The Notice of Parties shall assign exhibit
numbers to each party in this proceeding.
YOU ARE FURTHER NOTIFIED that once the Notice of Parties is issued,
Commission Staff will informally confer with the parties to discuss a schedule to process this case
and other issues as may be raised by the parties.
YOU ARE FURTHER NOTIFIED that the following persons are designated as the
Company’s representatives in this matter:
David J. Meyer, Esq.
P.O. Box 3727
1411 E. Mission Ave
Spokane, WA 99220-3727
[e-mail]

Patrick D. Ehrbar
P.O. Box 3727
1411 E. Mission Ave
Spokane, WA 99220-3727
[e-mail]
[e-mail]

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NOTICE OF INTERVENTION DEADLINE
ORDER NO. 35765 7

ORDER
IT IS FURTHER ORDERED that persons desiring to intervene in this case for the
purpose of obtaining parties’ rights of participation must file a Petition to Intervene with the
Commission no later than 21 days after the service date of this Order.
IT IS FURTHER ORDERED that, after the Secretary issues a Notice of Parties, Staff
will informally confer with the parties to discuss the appropriate scheduling of this case.
IT IS FURTHER ORDERED that parties comply with Order No. 35375, issued April
21, 2022. Generally, all pleadings should be filed with the Commission electronically and will be
deemed timely filed when received by the Commission Secretary. See Rule 14.02. Service between
parties should continue to be accomplished electronically when possible. However, voluminous
discovery-related documents may be filed and served on CD-ROM or a USB flash drive.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 2nd day
of May 2023.

__________________________________________
ERIC ANDERSON, PRESIDENT

__________________________________________
JOHN R. HAMMOND JR, COMMISSIONER

__________________________________________
EDWARD LODGE, COMMISSIONER
ATTEST:

___________________________________
Jan Noriyuki
Commission Secretary

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