20210331Avista 2021 Natural Gas IRP.pdf

A vista Corp.
1411 East Mission P.O. Box 3727
Spokane. Washington 99220-0500
Telephone [phone]
Toll Free 800-727-9170
April 1, 2021
Jan Noriyuki, Secretary
Idaho Public Utilities Commission·
11331 W. Chinden Blvd. Bldg. 8, Ste. 201-A
Boise, Idaho 83714
RE: Case No. AVU-lr-21-..o...,_
Dear Ms. Noriyuki:
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Avista Corporation d/b/a/ Avista Utilities, hereby submits for filing with the Commission its final
2021 Natural Gas Integrated Resource Plan (IRP). Supporting documents can be found on our
website at https://myavista.com/about-us/integrated-resource-planning.
If you have any questions regarding this filing, please contact Tom Pardee at 509-495-2159.
Sincerely,
Shawn Bonfield
Sr. Manager of Regulatory Strategy & Policy
509-434-6502
shawn. [e-mail]
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2021 Natural Gas
Integrated Resource Plan

Safe Harbor Statement

This document contains forward-looking statements. Such statements are subject to a
variety of risks, uncertainties and other factors, most of which are beyond the Company’s
control, and many of which could have a significant impact on the Company’s operations,
results of operations and financial condition, and could cause actual results to differ
materially from those anticipated.

For a further discussion of these factors and other important factors, please refer to the
Company’s reports filed with the Securities and Exchange Commission. The forward-
looking statements contained in this document speak only as of the date hereof. The
Company undertakes no obligation to update any forward-looking statement or
statements to reflect events or circumstances that occur after the date on which such
statement is made or to reflect the occurrence of unanticipated events. New risks,
uncertainties and other factors emerge from time to time, and it is not possible for
management to predict all of such factors, nor can it assess the impact of each such factor
on the Company’s business or the extent to which any such factor, or combination of
factors, may cause actual results to differ materially from those contained in any forward-
looking statement.

Production

Primary Natural Gas IRP Team

Name Title Contribution
Tom Pardee Natural Gas Planning Manager IRP Core Team
Michael Brutocao Natural Gas Analyst IRP Core Team
Terrence Browne Sr Gas Planning Engr Gas Engineering
Grant Forsyth Chief Economist Load Forecast
Ryan Finesilver Mgr. of Energy Efficiency, Planning & Analysis Energy Efficiency

Natural Gas IRP Contributors
Name Title Contribution
Jody Morehouse Director of Gas Supply Gas Supply
John Lyons Sr. Policy Analyst Power Supply
Shawn Bonfield Sr. Manager of Regulatory Policy Regulatory
James Gall IRP Manager Power Supply
Justin Dorr Natural Gas Resource Manager Gas Supply
Michael Whitby Mgr Renewable Natural Gas Prog Gas Supply
Annie Gannon Communications Manager Communications

TABLE OF CONTENTS
0 Executive Summary…………………………………………………1
1 Introduction………………………………………………………….14
2 Demand Forecasts………………………………………………....24
3 Demand Side Resources………………………………………….44
4 Supply Side Resources……………………………………………68
5 Carbon Reduction………………………………………………….96
6 Integrated Resource Portfolio……………………………………111
7 Alternate Scenarios, Portfolios, and Stochastic Analysis……..138
8 Distribution Planning………………………………………………157
9 Action Plan………………………………………………………….167

Executive Summary

Executive Summary
Avista’s 2021 Natural Gas Integrated Resource Plan (IRP) identifies a strategic natural
gas resource portfolio to meet customer demand requirements over the next 20 years.
Price volatility, or uncertainty, in the Pacific Northwest region, due to fully subscribed
transportation has increased in recent years. As weather events throughout the United
States have continued to rise, the risk to energy providers, utilities and consumers to
these unknown events are also on the rise. Some recent examples include freezing
temperatures in Texas and wildfire risk in California. Both events created the loss of a
supply source and potentially dangerous circumstances for its customers. This IRP’s
primary focus is to meet our customers’ needs under peak weather conditions, while
evaluating our customer needs under normal or average conditions. The formal exercise
of bringing together customer demand forecasts with comprehensive analyses of
resource options, including supply-side resources and demand-side measures, is
valuable to Avista, its customers, regulatory agencies, and other stakeholders for long-
range planning.

Benefits of Natural Gas

For Customers: Natural gas is affordable, resilient, and reliable.
For Society: Natural gas is an abundant energy resource produced in North America,
which helps lessen our dependency on foreign oil.
For Innovation: Natural gas can play a supporting role in expanding the use of
renewable energy sources.
For Environment: Natural gas is the cleanest burning fossil fuel, so it helps reduce smog
and greenhouse gas emissions.
For Economy: Natural gas provides nearly a fourth of North America's energy today.

IRP Process and Stakeholder Involvement
The IRP is a coordinated effort by several Avista departments with input from our
Technical Advisory Committee (TAC), which includes Commission Staff, peer utilities,
customers, and other stakeholders. The TAC is a vital component of our IRP process that
provides a forum for discussing multiple perspectives, identifies issues and risks, and
improves analytical planning methods. TAC topics include natural gas demand forecasts,
price forecasts, demand-side management (DSM), supply-side resources, modeling
tools, distribution planning, and policy issues. The IRP process produces a resource
Avista Corp.2021 Natural Gas Integrated Resource Plan 1
Executive Summary

portfolio designed to serve our customers’ natural gas needs while balancing cost and
risk.

Planning Environment
A long-term resource plan addresses the uncertainties inherent in any planning exercise.
Natural gas is an abundant North American resource with expectations for ample supplies
for many decades because of continuing technological advancements in extraction. The
use of natural gas in liquefied natural gas (LNG) exports, power generation and exports
to Mexico will continue to add demand for natural gas. In addition to fossil fuel natural
gas, renewable natural gas and hydrogen are considered vital toward any carbon
reduction goal, but currently not as readily available. All future scenarios carry risk based
on unknown prices and expected resources. To account for risk associated with these
uncertainties, we model various sensitivities and scenarios to account for the risks in
supply and demand.

Demand Forecasts
Avista defines eleven distinct demand areas in this IRP structured around the pipeline
transportation and storage resources that serve them. Demand areas include Avista’s
service territories (Washington; Idaho; Medford/Roseburg, Oregon; Klamath Falls,
Oregon and La Grande, Oregon) and then disaggregated by the pipelines serving them.
The Washington, Medford and Idaho service territories include areas served only by
Northwest Pipeline (NWP), only by Gas Transmission Northwest (GTN), and by both
pipelines.
Weather, customer growth and use-per-customer are the most significant demand
influencing factors. Other demand influencing factors include population, employment,
age and income demographics, construction levels, conservation technology, new uses,
and use-per-customer trends.
Customers may adjust consumption in response to price, so Avista analyzed factors that
could influence natural gas prices and demand through price elasticity. These factors
include:
• Supply: shale gas, industrial use, and exports to Mexico and of LNG.
• Infrastructure: regional pipeline projects, national pipeline projects, and
storage.
• Regulatory: subsidies, market transparency/speculation, and carbon
regulation.
Avista Corp.2021 Natural Gas Integrated Resource Plan 2
Executive Summary

• Other: drilling innovations, thermal generation and energy correlations (i.e.
oil/gas, coal/gas, and liquids/gas).
Avista developed a historical-based reference case and conducted sensitivity analysis on
key demand drivers by varying assumptions to understand how demand changes. Using
this information, and incorporating input from the TAC, Avista created alternate demand
scenarios for detailed analysis. Table 1 summarizes these demand scenarios, which
represent a broad range of potential scenarios for planning purposes. The Average Case
represents Avista’s demand forecast for normal planning purposes. The Expected Case
is the most likely scenario for peak day planning purposes.
Table 1: Demand Scenarios
2021 IRP Demand Scenarios
Average Case
Expected Case
High Growth, Low Price
Low Growth, High Price
Carbon Reduction

The IRP process defines the methodology for the development of two primary types of
demand forecasts – annual average daily and peak day. The annual average daily
demand forecast is useful for preparing revenue budgets, developing natural gas
procurement plans, and preparing purchased gas adjustment filings. Forecasts of peak
day demand are critical for determining the adequacy of existing resources or the timing
for new resource acquisitions to meet our customers’ natural gas needs in extreme
weather conditions. Table 2 shows the Average and Expected Case demand forecasts:
Table 2: Annual Average and Peak Day Demand Cases (Dth/day)
Year Annual Average
Daily Demand
Peak Day
Demand
Non-coincidental Peak
Day Demand
2021 95,126 363,586 349,210
2040 102,054 407,216 388,615

Annual Average Daily Demand
Expected average day, system-wide core demand increases from an average of 95,126
dekatherms per day (Dth/day) in 2021 to 102,054 Dth/day in 2040. These numbers are
net of projected conservation savings from DSM programs. Appendix 3.1 shows gross
demand, conservation savings and net demand.
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Executive Summary

Peak Day Demand
The peak day demand for the Washington, Idaho and La Grande service territories is
modeled on and around February 28th of each year. For the southwestern Oregon service
territories (Medford, Roseburg, Klamath Falls), the model assumes this event on and
around December 20th of each year. Expected coincidental peak day, or the sum of
demand from each territories modeled peak, the system-wide core demand increases
from a peak of 363,586 Dth/day in 2021 to 407,216 Dth/day in 2040. Forecasted non-
coincidental peak day demand, or the sum of demand from the highest single day
including all forecasted territories, peaks at 349,210 Dth/day in 2021 and increases to
388,615 Dth/day in 2040. This is also net of projected conservation savings from DSM
programs.
Figure 1 shows forecasted average daily demand for the five demand scenarios modeled
over the IRP planning horizon.
Figure 1: Average Daily Demand (Net of DSM Savings)

Figure 2 shows forecasted system-wide peak day demand for the five demand scenarios
modeled over the IRP planning horizon.

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Executive Summary

Figure 2: Peak Day Demand Scenarios (Net of DSM Savings)

Natural Gas Price Forecasts
Natural gas prices are a fundamental component of integrated resource planning as the
commodity price is a significant element to the total cost of a resource option. Price
forecasts affect the avoided cost threshold for determining cost-effectiveness of
conservation measures. The price of natural gas also influences the consumption of
natural gas by customers. A price elasticity adjustment to use-per-customer reflects
customer responses to changing natural gas prices.
Avista expects carbon legislation at the state level through a cap and reduce (Oregon) or
social cost of carbon tax mechanism (Washington). Current IRP price forecasts include a
considerably higher carbon adder in Oregon and Washington, but no carbon cost in
Idaho. Avista analyzed three carbon sensitivities and their impact on demand forecasts
to address the uncertainty about carbon legislation. These sensitivities were applied to all
jurisdictions.
Avista combined forward prices with three fundamental price forecasts including a futures
pricing strip in the near term to develop an expected price strip at the Henry Hub. A set
of high and low price strips were developed based on the 95th and 25th percentile results
of 1,000 simulated prices. These three price curves represent a reasonable range of
pricing possibilities for this IRP analysis. The array of prices provides necessary variation
for addressing uncertainty of future prices. Figure 3 depicts the price forecasts used in
this IRP.

Avista Corp.2021 Natural Gas Integrated Resource Plan 5
Executive Summary

Figure 3: Low/Medium/High Henry Hub Forecasts (Nominal $/Dth)

Historical statistical analysis shows a long run consumption response to price changes.
In order to model consumption response to these price curves, Avista utilized an expected
elasticity response factor of -0.081 for every 10% of price movement, as found in our
Medford/Roseburg service territory, and applied it under various scenarios and
sensitivities. As this price response continues to have a near muted response, Avista will
look for additional studies and methodologies to account for elasticity in future resource
plans where applicable.

Existing and Potential Resources
Avista has a diversified portfolio of natural gas supply resources, including access to and
contracts for the purchase of natural gas from several supply basins; owned and
contracted storage providing supply source flexibility; and firm capacity rights on six
pipelines. For potential resource additions, Avista considers incremental pipeline
transportation, renewable natural gas, storage options, hydrogen, distribution
enhancements, and various forms of LNG storage or service. Avista models aggregated
conservation potential that reduces demand if the conservation programs are cost-
effective over the planning horizon. The identification and incorporation of conservation
savings into the SENDOUT® model utilizes projected natural gas prices and the
estimated cost of alternative supply resources. The operational business planning
process starts with IRP identified savings and ultimately determines the near-term
program offerings. Avista actively promotes cost-effective DSM measures to our
Avista Corp.2021 Natural Gas Integrated Resource Plan 6
Executive Summary

customers as one component of a comprehensive strategy to arrive at a mix of best
cost/risk adjusted resources.
Resource Needs
In both the High Growth and Low-price and the Carbon Reduction scenarios a resource
deficiency was observed. The High Growth and Low-Price scenario observed an energy
shortage, or it requires additional assets of any kind to supply more energy. The Carbon
Reduction scenario does not have an energy shortage, but rather a need for carbon
neutral or carbon reducing resources in order to reduce the carbon intensity of its supply
stream. Avista is not resource deficient within the Expected Case for the 20-year planning
horizon. As further information on goals and legislation come into focus, Avista will
integrate these guideposts into our Expected Case.
Figures 4 through 7 illustrate Avista’s peak day demand by service territory for both the
current and prior IRP. These charts compare existing peak day resources to expected
peak day demand by year and show the timing and extent of resource deficiencies, if any,
for the Expected Case. Based on this information, Avista has time to carefully monitor,
plan and analyze potential resource additions as described in the Ongoing Activities
section of Chapter 9 – Action Plan. Any underutilized resources will be optimized to
mitigate the costs incurred by customers until the resource is required to meet demand.
This management of long and short term resources provides the flexibility to meet firm
customer demand in a reliable and cost-effective manner as described in Supply Side
Resources – Chapter 4.

Avista Corp.2021 Natural Gas Integrated Resource Plan 7
Executive Summary

Figure 4: Expected Case – WA & ID Existing Resources vs. Peak Day Demand
(Net of DSM)

Figure 5: Expected Case – Medford/Roseburg Existing Resources vs. Peak Day
Demand (Net of DSM)

Avista Corp.2021 Natural Gas Integrated Resource Plan 8
Executive Summary

Figure 6: Expected Case – Klamath Falls Existing Resources vs. Peak Day
Demand (Net of DSM)

Figure 7: Expected Case – La Grande Existing Resources vs. Peak Day Demand
(Net of DSM)

Avista Corp.2021 Natural Gas Integrated Resource Plan 9
Executive Summary

Figure 8: Scenario Comparisons of First Year Peak Demand Not Met with Existing
Resources

A critical risk remains in the slope of forecasted demand growth, which although
increasing continues to be almost flat in Avista’s current projections. This outlook implies
that existing resources will be sufficient within the planning horizon to meet demand.
However, if demand growth accelerates, the steeper demand curve could quickly
accelerate resource shortages by several years. Figure 9 conceptually illustrates this risk.
In this hypothetical example, a resource shortage does not occur until year eight in the
initial demand case. However, the shortage accelerates by five years under the revised
demand case to year three. This “flat demand risk” requires close monitoring of
accelerating demand, as well as careful evaluation of lead times to acquire the preferred
incremental resource.

2020 2025 2030 2035 2040
Low Growth & High Prices
Average Case
Carbon Reduction
High Growth & Low Prices
Expected Case
First Year Shortage vs. carbon reduction goals
First Year Shortage vs. Existing Resources
Avista Corp.2021 Natural Gas Integrated Resource Plan 10
Executive Summary

Figure 9: Hypothetical Flat Demand Risk Example

Issues and Challenges
Even with the planning, analysis, and conclusions reached in this IRP, there is still
uncertainty requiring diligent monitoring of the following issues.

Demand Issues
Although the future customer growth trajectory in Avista’s service territory has slightly
decreased compared to the 2018 IRP, the need in considering a range of demand
scenarios provides insight into how quickly resource needs can change if demand varies
from the Expected Case.
With a robust supply forecast and continued low costs, there is increasing interest in using
natural gas. Avista does not anticipate traditional residential and commercial customers
will provide increased growth in demand. Power generation from natural gas is
increasingly being used to back up solar and wind technology as well as replacing retired
coal plants. In terms of North American demand, exports of LNG could consume 20 Bcf
per day by 2030 and more than 30 Bcf per day by 2040. Although smaller in size, Mexico
exports could increase from 5 Bcf per day in 2020 to over 8 Bcf per day in 2040. Most of
these emerging markets will not be core customers of the LDC, but could affect regional
natural gas infrastructure and natural gas pricing if an LNG export facility is built in the
area.
Avista Corp.2021 Natural Gas Integrated Resource Plan 11
Executive Summary

Price Issues
Shale oil and gas drilling technology is adding an abundant amount of supply at low cost.
This is primarily due to increasingly efficient drilling technology and the rapid
advancement in understanding of drilling shale wells. In areas such as the eastern United
States, shale production is so prolific the entire flow of gas on the pipeline infrastructure
has changed and is now flowing out of the highest demand areas in the US. This supply
also flows into Canada and across the U.S. which benefits Northwest consumers as the
prices for Canadian gas have deep discounts as compared to the Henry Hub.

Action Plan
Avista’s 2021-2022 Action Plan outlines activities for study, development and preparation
for the 2023 IRP. The purpose of the Action Plan is to position Avista to provide the best
cost/risk resource portfolio and to support and improve IRP planning. The Action Plan
identifies needed supply and demand side resources and highlights key analy tical needs
in the near term. It also highlights essential ongoing planning initiatives and natural gas
industry trends Avista will monitor as a part of its ongoing planning processes (Chapter 9
– Action Plan).
Key ongoing components of the Action Plan include:
1. Further model carbon reduction
2. Investigate new resource plan modeling software and integrate Avista’s system
into software to run in parallel with Sendout
3. Model all requirements as directed in Executive Order 20-04
4. Avista will ensure Energy Trust (ETO) has sufficient funding to acquire therm
savings of the amount identified and approved by the Energy Trust Board.
5. Explore the feasibility of using projected future weather conditions in its design day
methodology, rather than relying exclusively on historic data.
6. Regarding high pressure distribution or city gate station capital work, Avista does
not expect any supply side or distribution resource additions to be needed in our
Oregon territory for the next four years, based on current projections. However,
should conditions warrant that capital work is needed on a high-pressure
distribution line or city gate station in order to deliver safe and reliable services to
our customers, the Company is not precluded from doing such work. Examples of
these necessary capital investments include the following:
• Natural gas infrastructure investment not included as discrete projects in IRP
– Consistent with the preceding update, these could include system
investment to respond to mandates, safety needs, and/or maintenance
of system associated with reliability
Avista Corp.2021 Natural Gas Integrated Resource Plan 12
Executive Summary

• Including, but not limited to Aldyl A replacement, capacity
reinforcements, cathodic protection, isolated steel replacement,
etc.
– Anticipated PHMSA guidance or rules related to 49 CFR Part §192 that
will likely require additional capital to comply
• Officials from both PHMSA and the AGA have indicated it is not
prudent for operators to wait for the federal rules to become final
before improving their systems to address these expected rules.
– Construction of gas infrastructure associated with growth
– Other special contract projects not known at the time the IRP was
published
• Other non-IRP investments common to all jurisdictions that are ongoing, for
example:
– Enterprise technology projects & programs
– Corporate facilities capital maintenance and improvements
Ongoing Activities
Meet regularly with Commission Staff to provide information on market activities and
significant changes in assumptions and/or status of Avista activities related to the IRP or
natural gas procurement practices.
Appropriate management of existing resources including optimizing underutilized
resources to help reduce costs to customers.

Conclusion
A slightly lower customer growth level combined with an updated peak weather planning
standard combine to create a lower overall peak day demand. Prices have a lower
levelized price as compared to the 2018 IRP creating a slightly reduced amount of DSM.
When combined, the need for additional supply side resources is pushed well into the
future. By managing these assets through releases and optimization, Avista can help
offset these costs while managing peak day demand need. A changing dynamic related
to carbon emissions will continue to evolve future planning environments and any need
for supply side resources. Regardless of policy, prices or demand, Avista will continue to
properly plan to continue delivering safe, reliable, and economic natural gas service to
our customers.

Avista Corp.2021 Natural Gas Integrated Resource Plan 13
Executive Summary

Avista Corp.2021 Natural Gas Integrated Resource Plan 14
Chapter 1: Introduction

1: Introduction
Avista is an investor-owned utility involved in the production, transmission and distribution
of natural gas and electricity, as well as other energy-related businesses. Avista, founded
in 1889 as Washington Water Power, has been providing reliable, efficient and
reasonably priced energy to customers for over 130 years.
Avista entered the natural gas business with the purchase of Spokane Natural Gas
Company in 1958. In 1970, it expanded into natural gas storage with Washington Natural
Gas (now Puget Sound Energy) and El Paso Natural Gas (its interest subsequently
purchased by NWP) to develop the Jackson Prairie natural gas underground storage
facility in Chehalis, Washington. In 1991, Avista added 63,000 customers with the
acquisition of CP National Corporation’s Oregon and California properties. Avista sold the
California properties and its 18,000 South Lake Tahoe customers to Southwest Gas in
2005. Figure 1.1 shows where Avista currently provides natural gas service to
approximately 361,000 customers in eastern Washington, northern Idaho and several
communities in northeast and southwest Oregon. Figure 1.2 shows the number of firm
natural gas customers by state.
Figure 1.1: Avista’s Natural Gas Service Territory

Avista Corp.2021 Natural Gas Integrated Resource Plan 15
Chapter 1: Introduction

Figure 1.2: Avista’s Natural Gas Customer Counts

Avista’s natural gas operations covers 30,000 square miles in eastern Washington,
northern Idaho and portions of southern and eastern Oregon, with a population of 1.6
million. The company manages its natural gas operation through the North and South
operating divisions:
• The North Division includes Avista’s eastern Washington and northern Idaho
service area which is home to over 1,000,000 people. It includes urban areas,
farms, timberlands, and the Coeur d’Alene mining district. Spokane is the largest
metropolitan area with a regional population of approximately 523,000 followed
by the Lewiston, Idaho/Clarkston, Washington, and Coeur d’Alene, Idaho, areas.
The North Division has about 75 miles of natural gas transmission pipeline and
5,800 miles in the distribution system in Washington and 3,300 miles in Idaho.
The North Division receives natural gas at more than 40 points along interstate
pipelines for distribution to over 257,000 customers.
• The South Division serves four counties in southern Oregon and one county in
eastern Oregon. The combined population of these areas is over 514,000
residents. The South Division includes urban areas, farms and timberlands. The
Medford, Ashland and Grants Pass areas, located in Jackson and Josephine
Counties, is the largest single area served by Avista in this division with a regional
population of approximately 308,000. The South Division consists of about 15
miles of natural gas transmission main and 3,700 miles of distribution pipelines.
Avista receives natural gas at more than 20 points along interstate pipelines and
distributes it to more than 104,000 customers.
Avista Corp.2021 Natural Gas Integrated Resource Plan 16
Chapter 1: Introduction

Customers
Avista provides natural gas services to both core and transportation-only customer
classes. Core or retail customers purchase natural gas directly from Avista with delivery
to their home or business under a bundled rate. Core customers on firm rate schedules
are entitled to receive any volume of natural gas they require. Some core customers are
on interruptible rate schedules. These customers pay a lower rate than firm customers
because their service can be interrupted. Interruptible customers are not considered in
peak day IRP planning.
Transportation-only customers purchase natural gas from third parties who deliver the
purchased gas to our distribution system. Avista delivers this natural gas to their business
charging a distribution rate only. Avista can interrupt the delivery service when following
the priority of service tariff. The long-term resource planning exercise excludes
transportation-only customers because they purchase their own natural gas and utilize
their own interstate pipeline transportation contracts. However, distribution planning
includes these customers.
Avista’s core or retail customers include residential, commercial and industrial categories.
Most of Avista’s customers are residential, followed by commercial and relatively few
industrial accounts (Figure 1.3).
Figure 1.3: Firm Customer Mix

56,354 7,038
14
6,794 943
3
77,804 9,164
89
13,889 2,189
2
155,069 14,980 130
15,192 1,787 6
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20%
30%
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Avista Corp.2021 Natural Gas Integrated Resource Plan 17
Chapter 1: Introduction

The customer mix is found mostly in the residential and commercial accounts on an
annual volume basis (Figure 1.4). Volume consumed by core industrial customers is not
significant to the total, partly because most industrial customers in Avista’s service
territories are transportation-only customers.
Figure 1.4: 2019 Daily Demand by Area and Class

The seasonal nature of weather in the Pacific Northwest can drastically alter the amount
of energy demanded from the natural gas system (Figure 1.5). Industrial demand, which
is typically not weather sensitive, has very little seasonality. However, the La Grande
service territory has several industrially classified agricultural processing facilities that
produce a late summer seasonal demand spike.

-
10,000
20,000
30,000
40,000
50,000
60,000
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h
Res Com Ind
Avista Corp.2021 Natural Gas Integrated Resource Plan 18
Chapter 1: Introduction

Figure 1.5: Total System Average Daily Load

Integrated Resource Planning
Avista’s IRP involves a comprehensive analytical process to ensure that core firm
customers receive long-term reliable natural gas service in extreme weather. The IRP
evaluates, identifies, and plans for the acquisition of an optimal combination of existing
and future resources using expected costs and associated risks to meet average daily
and peak-day demand delivery requirements over a 20-year planning horizon.
Purpose of the IRP
Avista’s 2021 Natural Gas IRP:
• Provides a comprehensive long-range planning tool;
• Fully integrates forecasted requirements with existing and potential resources;
• Determines the most cost-effective, risk-adjusted means for meeting future
demand requirements; and
• Meets Washington, Idaho and Oregon regulations, commission orders, and other
applicable guidelines.
Avista’s IRP Process
The natural gas IRP process considers:
• Customer growth and usage;
• Weather planning standard;
-
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150,000
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Avista Corp.2021 Natural Gas Integrated Resource Plan 19
Chapter 1: Introduction

• Conservation opportunities;
• Existing and potential supply-side resource options;
• Current and potential legislation/regulation;
• Risk; and
• Least cost mix of supply and conservation.
Public Participation
Avista’s TAC members play a key role and have a significant impact in developing the
IRP. TAC members included Commission Staff, peer utilities, government agencies, and
other interested parties. TAC members provide input on modeling, planning assumptions,
and the general direction of the planning process.
Avista sponsored four TAC meetings to facilitate stakeholder involvement in the 2021
IRP. The first meeting convened on June 17, 2020 and the last meeting occurred on
November 18, 2020. All meetings were held virtually, via web meetings, due to the
restrictions and guidelines around the COVID-19 pandemic. Each meeting included a
broad spectrum of stakeholders. The meetings focused on specific planning topics,
reviewing the progress of planning activities, and soliciting input on IRP development and
results. TAC members received a draft of this IRP on January 4, 2021 for their review.
Avista appreciates the time and effort TAC members contributed to the IRP process; they
provided valuable input through their participation in the TAC process. A list of these
organizations can be found below (Table 1.1).
Table 1.1: TAC Member Participation
Cascade Natural Gas Northwest Energy Coalition Oregon Public Utility
Commission
Fortis Northwest Natural Gas Idaho Conservation League
Idaho Public Utilities
Commission
Biomethane, LLC

Washington State Office of
the Attorney General
Northwest Gas
Association
Washington Utilities and
Transportation Commission
Citizens Utility Board of
Oregon

Washington State
Department of
Commerce
Northwest Power and
Conservation Council Energy Trust of Oregon
Intermountain Gas
Company
Alliance of Western Energy
Consumers
Avista Corp.2021 Natural Gas Integrated Resource Plan 20
Chapter 1: Introduction

Preparation of the IRP is a coordinated endeavor by several departments within Avista
with involvement and guidance from management. We are grateful for their efforts and
contributions.
Regulatory Requirements
Avista submits a natural gas IRP to the public utility commissions in Idaho, Oregon and
Washington every two years as required by state regulation. There is a statutory
obligation to provide reliable natural gas service to customers at rates, terms and
conditions that are fair, just, reasonable and sufficient. Avista regards the IRP as a means
for identifying methodologies and processes for the evaluation of potential resource
options and as a process to establish an Action Plan for resource decisions. Ongoing
investigation, analysis and research may cause Avista to determine that alternative
resources are more cost effective than resources reviewed and selected in this IRP.
Avista will continue to review and refine our understanding of resource options and will
act to secure these risk-adjusted, least-cost options when appropriate.

Planning Model
Consistent with prior IRPs, Avista used the SENDOUT® planning model to perform
comprehensive natural gas supply planning and analysis for this IRP. SENDOUT® is a
linear programming-based model that is widely used to solve natural gas supply, storage
and transportation optimization problems. This model uses present value revenue
requirement (PVRR) methodology to perform least-cost optimization based on daily,
monthly, seasonal and annual assumptions related to the following:
• 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 and pricing;
• Revenue requirements on all new asset additions;
• Weather assumptions; and
• Conservation.
Avista incorporated stochastic modeling by utilizing a SENDOUT® module to incorporate
weather and price uncertainty. Some examples of the types of stochastic analysis
provided include:
• Price and weather probability distributions;
• Probability distributions of costs (i.e. system costs, storage costs, commodity
costs); and
• Resource mix (optimally sizing a contract or asset level of competing resources).
Avista Corp.2021 Natural Gas Integrated Resource Plan 21
Chapter 1: Introduction

These computer-based planning tools were used to develop the 20-year best cost/risk
resource portfolio plan to serve customers.

Planning Environment
Even though Avista publishes an IRP every two years, the process is ongoing with new
information and industry related developments. In normal circumstances, the process can
become complex as underlying assumptions evolve, impacting previously completed
analyses. Widespread agreement on the availability of shale gas and the ability to
produce it at lower prices has increased interest in the use of natural gas for LNG and
Mexico exports as well as industrial uses. One of the most prominent risks in the IRP
involves policies meant to decrease the use of natural gas as outlined in Chapter 5-
Carbon Reduction. However, there is uncertainty about the timing and size of those policy
decisions.

IRP Planning Strategy
Planning for an uncertain future requires robust analysis encompassing a wide range of
possibilities. Avista has determined that the planning approach needs to:
• Recognize historical trends may be fundamentally altered;
• Critically review all modeling assumptions;
• Stress test assumptions via sensitivity analysis;
• Pursue a spectrum of scenarios;
• Develop a flexible analytical framework to accommodate changes; and
• Maintain a long-term perspective.
With these objectives in mind, Avista developed a strategy encompassing all required
planning criteria. This produced an IRP that effectively analyzes risks and resource
options, which sufficiently ensures customers will receive safe and reliable energy
delivery services with the best-risk, lease-cost, long-term solutions. The following chart
summarizes significant changes from the 2018 IRP (Table 1.2).

Avista Corp.2021 Natural Gas Integrated Resource Plan 22
Chapter 1: Introduction

Table 1.2: Summary of Changes from the 2018 IRP
Chapter Issue 2021 Natural Gas IRP 2018 Natural Gas IRP
Demand
Expected
Customer
Growth
Expected Case – system
wide – growth is slightly
lower at 1.0%.
Expected Case – system
wide – growth at 1.2%.
Weather
Planning
Standard
99% probability of a
temperature occurring
based on the coldest
temperature each year
for the past 30 years
Coldest on record
DSM CPA
potential
A lower price curve and
slightly less conservation
potential

Cumulative Savings over
20 years:
ID: 21.4 Million Therms
OR: 14.8Million Therms
WA: 37.7 Million Therms
Cumulative Savings over
20 years:
ID: 21.1 Million Therms
OR: 17.2 Million Therms
WA: 41.4 Million Therms
Environmental
Issues
Carbon
Dioxide
Emission
(Carbon)
ID: No federal or State
initiatives ($0)
OR: Cap and Reduce
($15.83 – $97.90)
WA – Social Cost of
Carbon @ 2.5% discount
rate
($79.86 - $158.06)

*Prices are in nominal
dollars per MTCO2e
ID: No federal or State
initiatives ($0)
OR: HB 4001 & SB 1507
($17.86 – $51.58)
WA – SSB 6203 ($10 -
$30)

*Prices are in nominal
dollars per MTCO2e
Prices Price Curve
A lower price curve at
$3.73 levelized cost in
real 2019 US $
A levelized price at the
Henry Hub of $3.99 in
2017 real US $
Avista Corp.2021 Natural Gas Integrated Resource Plan 23
Chapter 1: Introduction

Supply Side
Resources
Supply Side
Scenarios
There are two cases
where resource
deficiencies occur, the
High Growth/Low Price
scenario and the Carbon
Reduction scenario. The
High Growth/Low Price
scenario is solved by
adding RNG landfill
within the city gate. The
Carbon Reduction
scenario is looking to
reduce emissions and
Dairy RNG provides the
greatest amount of
carbon intensity/carbon
capture of RNG sources.
The only case that
identifies a resource
deficiency is the High
Growth/Low Price
scenario. Avista solved
this case by using existing
resources plus added
contracted capacity on
GTN. Landfill RNG is also
selected as a resource in
Idaho. Also selected is
the upsized compressor
on the Medford lateral.

Avista Corp.2021 Natural Gas Integrated Resource Plan 24
Chapter 2: Demand Forecasts

2: Demand Forecasts
Overview
The integrated resource planning process begins with the development of forecasted
demand. Understanding and analyzing key demand drivers and their potential impact on
forecasts is vital to the planning process. Utilization of historical data provides a reliable
baseline; however, forecasting will always have uncertainties regardless of methodology
and data integrity. This IRP mitigates the uncertainty by considering a range of scenarios
to evaluate and prepare for a broad spectrum of outcomes.
Demand Areas
Avista defined eleven demand areas, structured around the pipeline transportation
resources ability to serve them, within the SENDOUT® model (Table 2.1). These demand
areas are aggregated into five service territories and further summarized as North or
South divisions for presentation throughout this IRP.
Table 2.1: Geographic Demand Classifications
Demand Area Service Territory Division
Washington NWP Spokane North
Washington GTN Spokane North
Washington Both Spokane North
Idaho NWP Coeur D' Alene North
Idaho GTN Coeur D' Alene North
Idaho Both Coeur D' Alene North
Medford NWP Medford/Roseburg South
Medford GTN Medford/Roseburg South
Roseburg Medford/Roseburg South
Klamath Falls Klamath Falls South
La Grande La Grande South

Demand Forecast Methodology
Avista uses the IRP process to develop two types of demand forecasts – annual and peak
day. Annual average demand forecasts are useful for preparing revenue budgets,
developing natural gas procurement plans, and preparing purchased gas adjustment
filings. Peak day demand forecasts are critical for determining the adequacy of existing
resources or the timing for acquiring new resources to meet customers’ natural gas needs
in extreme weather conditions.
In general, if existing resources are sufficient to meet peak day demand, they will be
sufficient to meet annual average day demand. Developing annual average demand first
Avista Corp.2021 Natural Gas Integrated Resource Plan 25
Chapter 2: Demand Forecasts

and evaluating it against existing resources is an important step in understanding the
performance of the portfolio under normal circumstances. It also facilitates
synchronization of modeling processes and assumptions for planning purposes.
Peak weather analysis aids in assessing resource adequacy and any differences in
resource utilization. For example, storage may be dispatched differently under peak
weather scenarios.
Demand Modeling Equation
Developing daily demand forecasts is essential because natural gas demand can vary
widely from day-to-day, especially in winter months when heating demand is at its highest.
In its most basic form, natural gas demand is a function of customer base usage (non-
weather sensitive usage) plus customer weather sensitive usage. Basic demand takes
the formula in Table 2.2:
Table 2.2: Basic Demand Formula

# of customers x daily base usage / customer
+
# of customers x daily weather sensitive usage / customer

SENDOUT® requires inputs as expressed in the Table 2.3 format to compute daily
demand in dekatherms.
Table 2.3: SENDOUT® Demand Formula

# of customers x daily Dth base usage / customer
+
# of customers x daily Dth weather sensitive usage / customer x # of daily degree days

Customer Forecasts
Avista’s customer base includes firm residential, commercial and industrial categories.
For each of the customer categories, Avista develops customer forecasts incorporating
national economic forecasts and then drilling down into regional economies. U.S. GDP
growth, national and regional employment growth, and regional population growth
expectations are key drivers in regional economic forecasts and are useful in estimating
the number of natural gas customers. A detailed description of the customer forecast is
found in Appendix 2.1 – Economic Outlook and Customer Count Forecast. Avista
combines this data with local knowledge about sub-regional construction activity, age and
other demographic trends, and historical data to develop the 20-year customer forecasts.
Avista Corp.2021 Natural Gas Integrated Resource Plan 26
Chapter 2: Demand Forecasts

300,000
350,000
400,000
450,000
500,000
550,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
SYSTEMCUS.syf Base SYSTEMCUS.syf High SYSTEMCUS.syf Low
Several Avista departments’ use these forecasts including Finance, Accounting, Rates,
and Gas Supply. The natural gas distribution engineering group utilizes the forecast data
for system optimization and planning purposes (see discussion in Chapter 8 – Distribution
Planning).
Forecasting customer growth is an inexact science, so it is important to consider different
forecasts. Two alternative growth forecasts were developed for this IRP. Avista developed
High and Low Growth forecasts to provide potential paths and test resource adequacy.
Appendix 2.1 contains a description of how these alternatives were developed.
Figure 2.1 shows the three customer growth forecasts. The expected case customer
counts are lower than the last IRP. This has impacted forecasted demand from both the
average and peak day perspective. Detailed customer count data by region and class for
all three scenarios is in Appendix. 2.2 – Customer Forecasts by Region. In comparison
to Avista’s 2018 IRP, the base forecast for customer growth decreases by nearly 1,400
new customers.
Figure 2.1: Customer Growth Scenarios

Avista Corp.2021 Natural Gas Integrated Resource Plan 27
Chapter 2: Demand Forecasts

Use-per-Customer Forecast
The goal for a use-per-customer forecast is to develop base and weather sensitive
demand coefficients that can be combined and applied to heating degree day (HDD)
weather parameters to reflect average use-per-customer. This produces a reliable
forecast because of the high correlation between usage and temperature as depicted in
the example scatter plot in Figure 2.2.
Figure 2.2: Example Demand vs. Temperature – 2019

The first step in developing demand coefficients was gathering daily historical gas flow
data for Avista city gates. The use of city gate data over revenue data is due to the tight
correlation between weather and demand. The revenue system does not capture data
daily and, therefore, makes a statistical analysis with tight correlations on a daily basis
virtually impossible. Avista reconciles city gate flow data to revenue data to ensure that
total demand is properly captured.
The historical city gate data was gathered, sorted by service territory/temperature zone,
and then by month. As in the last IRP, Avista used three years of historical data to derive
the use-per-customer coefficients, but also considered varying the number of years of
historical data as sensitivities. When comparing five years of historical use-per-customer
to three years of data, the five-year data had slightly higher use-per-customer, which may
overstate use as efficiency and use-per-customer-per-HDD have been relatively stable in
recent history. The two-year use-per-customer was much more pronounced for demand,
likely based on a shorter timeframe for weather to impact the overall use-per-customer.
Avista Corp.2021 Natural Gas Integrated Resource Plan 28
Chapter 2: Demand Forecasts

The three-year coefficient most closely aligns with economic expectations and use within
Avista’s territories in the short-term forecast. Figure 2.3 illustrates the annual demand
differences between the three and five-year use-per-customer with normal and peak
weather conditions.
You can see the three year and 5-year coefficients are very close, with the two-year
coefficient clearly higher.
Figure 2.3: Annual Demand – Demand Sensitivities 2-Year, 3-Year and 5-Year Use-
per-Customer

The base usage calculation used three years of July and August data to derive
coefficients. Average usage in these months divided by the average number of customers
provides the base usage coefficient input into SENDOUT®. This calculation is done for
each area and customer class based on customer billing data demand ratios.
To derive weather sensitive demand coefficients for each monthly data subset, Avista
removed base demand from the total and plotted usage by HDD in a scatter plot chart to
verify correlation visually. The process included the application of a linear regression to
the data by month to capture the linear relationship of usage to HDD. The slopes of the
resulting lines are the monthly weather sensitive demand coefficients input into
SENDOUT®. Again, this calculation is done by area and by customer class using
allocations based on customer billing data demand ratios.
Avista Corp.2021 Natural Gas Integrated Resource Plan 29
Chapter 2: Demand Forecasts

Weather Forecast
The last input in the demand modeling equation is weather. The most current 20 years of
daily weather data (minimums and maximums) from the National Oceanic Atmospheric
Administration (NOAA) is used to compute an average for each day; this 20-year daily
average is used as a basis for the normal weather forecast. NOAA data is obtained from
five weather stations, corresponding to the areas where Avista provides natural gas
services (four in Oregon and one for Washington and Idaho), where this same 20-year
daily average weather computation is completed for all five areas. The HDD weather
patterns between the Oregon areas are uncorrelated, while the HDD weather patterns
amongst eastern Washington and northern Idaho portions of the service area are
correlated. Thus, Spokane Airport weather data is used for all Washington and Idaho
demand areas.
The NOAA 20-year average weather serves as the base weather forecast to prepare the
annual average demand forecast. The peak day demand forecast includes adjustments
to average weather to reflect a five-day cold weather event. The weather history for the
Avista territories modeled within this IRP goes back 70 years and contains minimum,
maximum and average weather data. The program utilizes the historic weather data
patterns to simulate realistic weather data algorithms when running stochastic
simulations.
The weather planning standard is an important piece of system planning f or resources in
an IRP. In prior IRP’s a coldest on record approach was considered the planning
standard. With the complexities of changing weather and maintaining a reliable and
affordable system, finding a statistical methodology to weigh weather risk and cost risk
led to the development of a new weather planning standard methodology. The expected
weather planning standard will utilize a coldest average temperature each year for the
past thirty years, by planning area, and combine these temperatures with a 99%
probability of a weather occurrence. As shown in Figure 2.4. the coldest on record
temperature in Washington and Idaho has remained static, ignoring any weather trends.
With the updated methodology the 99% will adjust with changing trends in climate. This
will ensure capital is not being invested where an event is statistically unlikely to occur.
In the planning areas of La Grande and Klamath Falls, OR this peak weather standard
has become colder due to the large amount of peak or near peak events in the recent 30-
year weather history. This new standard will enhance Avista’s ability to plan for peak
weather events and paired with stochastic analysis will introduce more rigor and risk
analysis into the planning process and climate uncertainty.

Avista Corp.2021 Natural Gas Integrated Resource Plan 30
Chapter 2: Demand Forecasts

Figure 2.4: Spokane Weather Station – Weather Planning Standard Comparison

Utilizing a five-day cold weather event with the new weather planning standard will occur
by service territory while adjusting the two days on either side of the planning standard to
temperatures colder than average. For the Washington, Idaho and La Grande service
territories, the model assumes this event on and around February 28 each year. As
discussed in TAC 1, moving the peak day from February 15th to February 28th will allow
for availability of resources to serve customers in these late season cold weather events.
With supply side resources in the Pacific Northwest growing further constrained,
managing supply along with the ability to serve cold days is paramount. For the
southwestern Oregon service territories (Medford, Roseburg, Klamath Falls), the model
assumes this event on and around December 20 each year. The following section
provides a comparison of prior IRP planning standard vs. The updated methodology
(Table 2.4).

-12
-30
-20
-10
0
10
20
30
40
19
4
9
19
5
2
19
5
5
19
5
8
19
6
1
19
6
4
19
6
7
19
7
0
19
7
3
19
7
6
19
7
9
19
8
2
19
8
5
19
8
8
19
9
1
19
9
4
19
9
7
20
0
0
20
0
3
20
0
6
20
0
9
20
1
2
20
1
5
20
1
8
Coldest each year 99%Coldest on Record
Avista Corp.2021 Natural Gas Integrated Resource Plan 31
Chapter 2: Demand Forecasts

Table 2.4: Weather Planning Standard
Area Coldest on Record
(Prior IRP’s)
99% Probability
Avg. Temp
La Grande -10 -11
Klamath Falls -7 -9
Medford 4 11
Roseburg 10 14
Spokane -17 -12

Warming trends are beginning to emerge in Roseburg and Medford, though the volatility
surrounding the peak is still present as seen in Figures 2.6 and 2.9. This indicates that
although temperatures, specifically in the Roseburg and Medford areas, are deviating
from the base years of 1950-1981 the peaking potential remains the same. The following
figures show this same analysis for all weather areas for the months of December,
January and February.

Avista Corp.2021 Natural Gas Integrated Resource Plan 32
Chapter 2: Demand Forecasts

Figure 2.5: Spokane

Figure 2.6: Medford

Avista Corp.2021 Natural Gas Integrated Resource Plan 33
Chapter 2: Demand Forecasts

Figure 2.7: La Grande

Figure 2.8: Klamath Falls
Avista Corp.2021 Natural Gas Integrated Resource Plan 34
Chapter 2: Demand Forecasts

Figure 2.9: Roseburg

Developing a Reference Case
To adjust for uncertainty, Avista developed a dynamic demand forecasting methodology
that is flexible to changing assumptions. To understand how various alternative
assumptions influence forecasted demand Avista needed a reference point for
comparative analysis. For this, Avista defined the reference case demand forecast shown
in Figure 2.10. This case is only a starting point to compare other cases.
Figure 2.10: Reference Case Assumptions
1. Customer Compound Annual Growth Rates
Area Residential Commercial Industrial
Idaho 1.4% 0.4% -1.0%
Oregon 0.7% 0.6% 0.0%
Washington 1.0% 0.4% -0.08%
System 1.0% 0.5% -0.8%

2. Use-Per-Customer Coefficients
Mostly Flat Across All Classes
3-year Average Use per Customer per HDD by Area/Class
3. Weather
20-year Normal – NOAA (2000-2019)
4. Elasticity
None
Avista Corp.2021 Natural Gas Integrated Resource Plan 35
Chapter 2: Demand Forecasts

5. Conservation
None

Dynamic Demand Methodology
The dynamic demand planning strategy examines a range of potential outcomes. The
approach consists of:
• Identifying key demand drivers behind natural gas consumption;
• Performing sensitivity analysis on each demand driver;
• Combining demand drivers under various scenarios to develop alternative
potential outcomes for forecasted demand; and
• Matching demand scenarios with supply scenarios to identify unserved demand.
Figure 2.11 represents Avista’s methodology of starting with sensitivities, progressing to
portfolios, and ultimately selecting a preferred portfolio.
Figure 2.11: Sensitivities and Preferred Portfolio Selection

Avista Corp.2021 Natural Gas Integrated Resource Plan 36
Chapter 2: Demand Forecasts

Sensitivity Analysis
In analyzing demand drivers, Avista grouped them into three categories based on:
• Demand Influencing Factors directly influencing the volume of natural gas
consumed by core customers.
• Price Influencing Factors indirectly influencing the volume of natural gas consumed
by core customers through a price elasticity response.
• Emissions Influencing Factors directly influencing the volume of gas and the price
elasticity response.
After identifying demand, price, and emissions influencing factors, Avista developed
sensitivities to focus on the analysis of a specific natural gas demand driver and its impact
on forecasted demand relative to the Reference Case when modifying the underlying
input assumptions.
Sensitivity assumptions reflect incremental adjustments not captured in the underlying
Reference Case forecast. Avista analyzed 33 demand sensitivities to determine the
results relative to the Reference Case. Table 2.5 lists these sensitivities. Detailed
information about these sensitivities is in Appendix 2.5 – Demand Forecast Sensitivities
and Scenarios Descriptions.

Avista Corp.2021 Natural Gas Integrated Resource Plan 37
Chapter 2: Demand Forecasts

Table 2.5: Demand Sensitivities

Figure 2.12 shows the annual demand from each of the sensitivities modeled for this IRP
with the associated legend colors in Table 2.5.
Figure 2.12: 2021 IRP Demand Sensitivities

Avista Corp.2021 Natural Gas Integrated Resource Plan 38
Chapter 2: Demand Forecasts

Scenario Analysis
After testing the sensitivities, Avista grouped them into meaningful combinations of
demand drivers to develop demand forecasts representing scenarios. Table 2.6 identifies
the scenarios developed for this IRP. The Average Case represents the case used for
normal planning purposes, such as corporate budgeting, procurement planning, and
PGA/General Rate Cases. The Expected Case reflects the demand forecast Avista
believes is most likely given peak weather conditions. The High Growth/Low Price and
Low Growth/High Price cases represent a range of possibilities for customer growth and
future prices. The Carbon Reduction emissions scenario is intended to show a
progressive loss of demand in the areas of Oregon and Washington (Idaho is unaffected)
from policies targeting methane and carbon dioxide emissions to an estimated emissions
level. Each of these scenarios provides a “what if” analysis given the volatile nature of
key assumptions, including weather and price. Appendix 2.6 lists the specific assumptions
within the scenarios while Appendix 2.7 contains a detailed description of each scenario.
Table 2.6: Demand Scenarios
2021 IRP Demand Scenarios
Average Case
Expected Case
High Growth, Low Price
Low Growth, High Price
Carbon Reduction

Price Elasticity
The economic theory of price elasticity states that the quantity demanded for a good or
service will change with its price. Price elasticity is a numerical factor that identifies the
relationship of a customer’s consumption change in response to a price change. Typically,
the factor is a negative number as customers normally reduce their consumption in
response to higher prices or will increase their consumption in response to lower prices.
For example, a price elasticity factor of negative 0.15 for a good or service means a 10
percent price increase will prompt a 1.5 percent consumption decrease and a 10 percent
price decrease will prompt a 1.5 percent consumption increase. An example of price
elasticity is depicted in Figure 2.13:
Avista Corp.2021 Natural Gas Integrated Resource Plan 39
Chapter 2: Demand Forecasts

Figure 2.13: Price Elasticity Example

Complex regulatory pricing mechanisms shield customers from price volatility, thereby
dampening price signals and affecting price elastic responses. For example, comfort level
billing averages a customer’s bills into equal payments throughout the year. This popular
program helps customers manage household budgets but does not send a timely price
signal. Additionally, natural gas cost adjustments, such as the Purchased Gas Adjustment
(PGA), annually adjusts the commodity cost which shields customers from daily gas price
volatility. These mechanisms do not completely remove price signals, but they can
significantly dampen the potential demand impact.
When considering a variety of studies on energy price elasticity, a range of potential
outcomes was identified, including the existence of positive price elastic adjustments to
demand. One study looking at the regional differences in price elasticity of demand for
energy found that the statistical significance of price becomes more uncertain as the
geographic area of measurement shrinks.1 This is particularly important given Avista’s
geographically diverse and relatively small service territories.
Avista acknowledges changing price levels can and do influence natural gas usage. This
IRP includes a price elasticity of demand factor of -0.081 for every 10% change in price
as measured in the Roseburg and Medford service territories. We assume the same
elasticity for all service areas in this study. When putting this elasticity into our model, it
allows the use-per-customer to vary as the natural gas price forecast changes.
Recent usage data indicates that even with declines in the retail rate for natural gas, long
run use-per-customer continues to decline. This likely includes a confluence of factors

1 Bernstein, M.A. and J. Griffin (2005). Regional Differences in Price-Elasticity of Demand for Energy, Rand
Corporation.
Avista Corp.2021 Natural Gas Integrated Resource Plan 40
Chapter 2: Demand Forecasts

including increased investments in energy DSM measures, building code improvements,
behavioral changes, and heightened focus of consumers’ household budgets.
Results
During 2021, the Average Case demand forecast indicates Avista will serve an average
of 366,157 core natural gas customers with 34,720,917 Dth of natural gas. By 2040,
Avista projects 442,863 core natural gas customers with an annual demand of over
37,351,708 Dth. In Washington/Idaho, the projected number of customers increases at
an average annual rate of 1.11 percent, with demand growing at a compounded average
annual rate of 0.33 percent. In Oregon, the projected number of customers increases at
an average annual rate of 0.75 percent, with demand growing 0.54 percent per year.
The Expected Case demand forecast indicates Avista will serve an average of 366,157
core natural gas customers with 35,440,513 Dth of natural gas in 2021. By 2040, Avista
projects 442,863 core natural gas customers with an annual demand of 37,987,712 Dth.
Figure 2.14 shows system forecasted demand for the demand scenarios on an average
daily basis for each year.2
Figure 2.14: Average Daily Demand – 2021 IRP Scenarios

Figure 2.15 shows system forecasted demand for the Expected, High and Low Demand
cases on a peak day basis for each year relative to the Average Case average daily winter

2 Appendix 2.1 shows gross demand, conservation savings and net demand.
Avista Corp.2021 Natural Gas Integrated Resource Plan 41
Chapter 2: Demand Forecasts

demand. Detailed data for all demand scenarios is in Appendix 2.8 – Demand Before and
After DSM.
Figure 2.15: February 28th – Peak Day – 2021 IRP Demand Scenarios
The IRP balances forecasted demand with existing and new supply alternatives. Since
new supply sources include conservation resources, which act as a demand reduction,
the demand forecasts prepared and described in this section include existing DSM
standards and normal market acceptance levels. The methodology for modeling DSM
initiatives is in Chapter 3 – Demand-Side Resources.
Alternative Forecasting Methodologies
There are many forecasting methods available and used throughout different industries.
Avista uses methods that enhance forecast accuracy, facilitate meaningful variance
analysis, and allows for modeling flexibility to incorporate different assumptions. Avista
believes the IRP statistical methodology to be sound and provides a robust range of
demand considerations while allowing for the analysis of different statistical inputs by
considering both qualitative and quantitative factors. These factors come from data,
surveys of market information, fundamental forecasts, and industry experts. Avista is
always open to new methods of forecasting natural gas demand and will continue to
assess which, if any, alternative methodologies to include in the dynamic demand
forecasting methodology.
Key Issues
Demand forecasting is a critical component of the IRP requiring careful evaluation of the
current methodology and use of scenario planning to understand how changes to the
Avista Corp.2021 Natural Gas Integrated Resource Plan 42
Chapter 2: Demand Forecasts

underlying assumptions will affect the results. The evolution of demand forecasting over
recent years has been dramatic, causing a heightened focus on variance analysis and
trend monitoring. Current techniques have provided sound forecasts with appropriate
variance capabilities. However, Avista is mindful of the importance of the assumptions
driving current forecasts and understands that these can and will change over time.
Therefore, monitoring key assumptions driving the demand forecast is an ongoing effort
that will be shared with the TAC as they develop.
Flat Demand Risk
Forecasting customer usage is a complex process because of the number of underlying
assumptions and the relative uncertainty of future patterns of usage with a goal of
increasing forecast accuracy. There are many factors that can be incorporated into these
models, assessing which ones are significant and improving the accuracy are key. Avista
continues to evaluate economic and non-economic drivers to determine which factors
improve forecasting accuracy. The forecasting process will continue to review research
on climate change and the best way to incorporate the results of that research into the
forecasting process.
For the last few planning cycles, the TAC has discussed the changing slope of forecasted
demand. Growth has slowed due to a declining use-per-customer. Use-per-customer
seems to have stabilized, though it is still on a downward trajectory in some areas.
This reduced demand pushes the need for resources beyond the planning horizon, which
means no new investment in resources is necessary from an energy standpoint.
However, as discussed in Chapter 5 – Carbon Reduction, policy may change the resource
demand for fossil fuels based on carbon reduction goals where new carbon reducing
resources will be required to help meet these targets. Monitoring both growth and policy
changes is key to managing assets needed to serve customers energy demand in all
types of weather.
Emerging Natural Gas Demand
The shale gas revolution has fundamentally changed the long-term availability and price
of natural gas. An ever-growing demand for natural gas-fired generation to integrate
variable wind and solar resources along with an increasing demand from coal retirements
and fuel switching has developed over the last decade. This demand is expected to
increase due to the availability of natural gas combined with its lower carbon emissions.
Other areas of emerging demand include everything from methanol plants to food
processors, and interest in industrial processes using natural gas as a feedstock is
growing.
Avista Corp.2021 Natural Gas Integrated Resource Plan 43
Chapter 2: Demand Forecasts

Conclusion
Avista’s 20-year outlook for customer growth has decreased by nearly 1,400 customers,
as compared to Avista’s 2018 IRP. With the inclusion of energy efficiency, known as DSM,
measures going into new construction and purchased through Avista’s programs, homes
are becoming better equipped to keep the heat in. This in turn leads to a decreasing
amount of natural gas usage. Until a point is reached where maximum efficiency is found,
these trends will likely continue to decline in nature.
Avista Corp.2021 Natural Gas Integrated Resource Plan 44
Chapter 3: Demand Side Resources
3: Demand Side Resources
Overview
Avista is committed to offering natural gas Energy Efficiency portfolios to residential, low
income, commercial and industrial customer segments when it is feasible to do so in a
cost-effective manner as prescribed within each jurisdiction. Avista began offering natural
gas energy efficiency programs to its customers in 1995. Program delivery includes both
prescriptive and site-specific offerings. Prescriptive programs, or standard offerings,
provide cash incentives for standardized products such as the installation of qualifying
high-efficiency heating equipment. Delivering programs through a prescriptive approach
works in situations where uniform products or offerings are applicable for large groups of
homogeneous customers and primarily occur in programs for residential and small
commercial customers. Site specific is the most comprehensive offering of the
nonresidential segment. Avista’s Account Executives work with nonresidential customers
to aid in identifying energy efficiency opportunities. Customers receive technical
assistance in determining potential energy and cost savings as well as identifying and
estimating incentives for participation. Other delivery methods build off these approaches
and may include upstream buy downs of low-cost measures, free-to-customer direct
install programs, and coordination with regional entities for market transformation efforts.
Recently, programs with the highest impacts on natural gas energy savings include the
residential prescriptive HVAC measures, residential water heat measures, and
nonresidential prescriptive and site-specific HVAC.
Improved drilling and extraction techniques of natural gas has led to declines in natural
gas prices in recent years which has made offering cost-effective DSM programs
challenging using the Total Resource Cost Test (TRC) to test cost-effectiveness. Since
January 1, 2016, Washington and Idaho programs utilize the Utility Cost Test (UCT).
Effective January 1, 2017, all Oregon DSM programs, with the exception of low-income
conservation, are delivered and administered by the Energy Trust of Oregon (ETO)1.
Avista issued an RFP and chose Applied Energy Group (AEG) to perform an external
independent evaluation of Avista’s conservation potential in Idaho and Washington while
ETO continues to evaluate and manage DSM in Oregon. Included with these evaluations
was the technical, economic and achievable conservation potential for each state over a
20-year planning horizon (2021-2040).

1 As part of the settlement for the Avista 2015 Oregon General Rate case
Avista Corp.2021 Natural Gas Integrated Resource Plan 45
Chapter 3: Demand Side Resources
The preliminary cost-effective conservation potential is determined by applying the stream
of annual natural gas avoided costs to the Avista-specific supply curve for conservation
resources. This quantity of conservation acquisition is then decremented from the load
which the utility must serve and the SENDOUT® model is rerun against the modified
(reduced) load requirements. The resulting avoided costs are compared to those obtained
from the previous iteration of SENDOUT® avoided costs. This process continues until the
differential between the avoided cost streams of the most recent and the immediately
previous iteration becomes immaterial. The resulting avoided costs were provided to AEG
and ETO to use in selecting cost-effective potential within Avista’s service territories.

Applied Energy Group (AEG): Idaho and Washington - CPA
Avista Early in 2020, Avista Utilities (Avista) contracted with Applied Energy Group (AEG)
to conduct this Conservation Potential Assessment (CPA) in support of their conservation
and resource planning activities. This report documents this effort and provides estimates
of the potential reductions in annual energy usage for natural gas customers in Avista’s
Washington and Idaho service territories from energy conservation efforts in the time
period of 2021 to 2040. To produce a reliable and transparent estimate of energy
efficiency (EE) resource potential, the AEG team performed the following tasks to meet
Avista’s key objectives:
▪ Used information and data from Avista, as well as secondary data sources, to
describe how customers currently use gas by sector, segment, end use and
technology.
▪ Developed a baseline projection of how customers are likely to use gas in absence
of future EE programs. This defines the metric against which future program
savings are measured. This projection used up-to-date technology data, modeling
assumptions, and energy baselines that reflect both current and anticipated
federal, state, and local energy efficiency legislation that will impact energy EE
potential.
▪ Estimated the technical, achievable technical, and achievable economic potential
at the measure level for energy efficiency within Avista’s service territory over the
2021 to 2040 planning horizon.
▪ Delivered a fully configured end-use conservation planning model, LoadMAP, for
Avista to use in future potential and resource planning initiatives
▪ In summary, the potential study provided a solid foundation for the development of
Avista’s energy savings targets.
Avista Corp.2021 Natural Gas Integrated Resource Plan 46
Chapter 3: Demand Side Resources
Table ES-1 summarizes the results for Avista’s Washington territory at a high level. AEG
analyzed potential for the residential, commercial, and industrial market sectors. First-
year utility cost test (UCT) achievable economic potential in Washington is 75,820
dekatherms. This increases to a cumulative total of 173,838 dekatherms in the second
year and 1,386,479 dekatherms by the tenth year (2030).
Table ES-1: Washington Conservation Potential by Case, Selected Years
(dekatherms)
Scenario 2021 2022 2023 2030 2040
Baseline Forecast (Dth) 19,118,293 19,289,575 19,805,020 20,612,516 21,619,876
Cumulative Savings (Dth)
UCT Achievable Economic 75,820 173,838 457,423 1,386,479 3,560,512
Achievable Technical 41,871 416,584 1,221,810 3,183,398 6,309,826
Technical 187,983 897,098 2,314,334 5,084,999 8,908,493
Energy Savings (% of
Baseline)
UCT Achievable Economic
Potential 0.4% 0.9% 2.3% 6.7% 16.5%
Achievable Technical Potential 0.2% 2.2% 6.2% 15.4% 29.2%
Technical Potential 1.0% 4.7% 11.7% 24.7% 41.2%

Table ES-2 summarizes the results for Avista’s Idaho territory at a high level. First-year
utility cost test (UCT) achievable economic potential in Idaho is 35,816 dekatherms. This
increases to a cumulative total of 87,995 dekatherms in the second year and 737,710
dekatherms by the tenth year (2030).

Avista Corp.2021 Natural Gas Integrated Resource Plan 47
Chapter 3: Demand Side Resources
Table ES-2: Idaho Conservation Potential by Case, Selected Years (dekatherms)
Scenario 2021 2022 2023 2030 2040
Baseline Forecast (Dth) 10,019,377 10,144,894 10,520,169 11,004,568 12,006,819
Cumulative Savings (Dth)
UCT Achievable Economic 35,816 87,995 229,283 737,710 2,025,410
Achievable Technical 26,220 226,613 657,997 1,722,830 3,544,048
Technical 102,031 490,826 1,273,202 2,777,509 5,013,697
Energy Savings (% of Baseline)
UCT Achievable Economic
Potential 0.4% 0.9% 2.2% 6.7% 16.9%
Achievable Technical Potential 0.3% 2.2% 6.3% 15.7% 29.5%
Technical Potential 1.0% 4.8% 12.1% 25.2% 41.8%

As part of this study, we also estimated total resource cost (TRC) potential, with the focus
of fully balancing non-energy impacts. This includes the use of full measure costs as well
as quantified and monetizable non-energy impacts and non-gas fuel impacts (e.g. electric
cooling or wood secondary heating) consistent with methodology within the 2021
Northwest Conservation and Electric Power Plan (2021 Plan). We explore this potential
in more detail throughout the report.
The entire CPA report including the methodology can be found in Appendix 3.1.

Energy Trust of Oregon - CPA
Energy Trust of Oregon, Inc. (Energy Trust) is an independent nonprofit organization
dedicated to helping utility customers in Oregon and southwest Washington benefit from
saving energy and generating renewable power. Energy Trust funding comes exclusively from
utility customers and is invested on their behalf in lowest-cost energy efficiency and clean,
renewable energy. In 1999, Oregon energy restructuring legislation (SB 1149) required
Oregon’s two largest electric utilities—PGE and Pacific Power—to collect a public purpose
charge from their customers to support energy conservation in K-12 schools, low-income
Avista Corp.2021 Natural Gas Integrated Resource Plan 48
Chapter 3: Demand Side Resources

housing energy assistance, and energy efficiency and renewable energy programs for
residential and business customers.2

In 2001, Energy Trust entered into a grant agreement with the Oregon Public Utility
Commission (OPUC) to invest the majority of revenue from the 3 percent public purpose
charge in energy efficiency and renewable energy programs. Every dollar invested in energy
efficiency by Energy Trust will save residential, commercial, and industrial customers nearly
$3 in deferred utility investment in generation, transmission, fuel purchase and other costs.
Appreciating these benefits, natural gas companies asked Energy Trust to provide service to
their customers—NW Natural in 2003, Cascade Natural Gas in 2006 and Avista in 2017.
These arrangements stemmed from settlement agreements reached in Oregon Public Utility
Commission processes.
Energy Trust’s model of delivering energy efficiency programs as a single entity across the
five overlapping service territories of Oregon’s investor-owned gas and electric utilities has
experienced a great deal of success. Since its inception, Energy Trust has saved more than
783 aMW of electricity and 71 million annual therms. This equates to more than 32.7 million
tons of CO2 emissions avoided and is a significant factor contributing to the relatively flat or
lower energy sales observed by both gas and electric utilities from 2009 to 2018, as shown in
OPUC utility statistic books.3
Energy Trust serves residential, commercial, and firm industrial customers in Avista’s natural
gas service territory in the areas of Medford, Klamath Falls, and La Grande, Oregon. In 2019,
Energy Trust’s programs achieved savings of 384,000 therms—equivalent to 107% of the
established savings goal of 360,000 therms, as shown in Figure 3.1.

2 In 2007, Oregon’s Renewable Energy Act (SB 838) allowed the electric utilities to capture additional, cost-effective
electric efficiency above what could be obtained through the 3 percent charge, thereby avoiding the need to purchase
more expensive electricity. This new supplemental funding, combined with revenues from natural gas utility customers,
increased Energy Trust revenues from about $30 million in 2002 to $182 million in 2020.
3 OPUC 2018 Stat book – 10 Year Summary Tables: https://www.oregon.gov/puc/forms/Forms%20and%20Reports/2018-
Oregon-Utility-Statistics-Book.pdf
Avista Corp.2021 Natural Gas Integrated Resource Plan 49
Chapter 3: Demand Side Resources

Figure 3.1: 2019 Achieved Savings vs. Goals for Avista Service Territory

In addition to administering energy efficiency programs on behalf of the utilities, Energy Trust
also provides each utility with a 20-year forecast of cost-effective energy efficiency savings
potential expected to be achieved by Energy Trust. The results are used by Avista and other
utilities in Integrated Resource Plans (IRP) to inform the energy efficiency resource potential
in their territory that can be used to meet their customers’ projected load.

Energy Trust 20-Year Forecast Methodology
20-Year Forecast Overview
Energy Trust developed a DSM resource forecast for Avista using its resource assessment
modeling tool (hereinafter the ”RA Model”) to identify the total 20-year cost-effective modeled
savings potential. This potential is subsequently ‘deployed’ exogenously of the model to
estimate the final savings forecast for each of the 20 years. There are four types of potential
that are calculated to develop the final savings potential estimate. These are shown in Figure
3.2 and discussed in greater detail in the sections below.

Avista Corp.2021 Natural Gas Integrated Resource Plan 50
Chapter 3: Demand Side Resources

Figure 3.2: Types of Potential Calculated in 20-Year Forecast Determination
Not
Technically
Feasible
Technical Potential
Calculated within
RA Model
Market
Barriers
Achievable Potential
Not Cost-
Effective
Cost-Effective Achievable
Potential
Program
Design &
Market
Penetration
Final Program
Savings
Potential
Developed with
Programs &
Other Market
Information

The RA Model utilizes the modeling platform Analytica®4, an object-flow based modeling
platform that is designed to visually show how different objects and parts of the model
interrelate and flow throughout the modeling process. The model utilizes multidimensional
tables and arrays to compute large, complex datasets in a relatively simple user interface.
Energy Trust then deploys this cost-effective potential exogenously to the RA model into an
annual savings projection based on past program experience, knowledge of current and
developing markets, and future codes and standards. This final 20-year savings projection is
provided to Avista for inclusion in in their SENDOUT® Model as a reduction to demand on
the system.
20-Year Forecast Detailed Methodology
Energy Trust’s 20-year forecast for DSM savings follows six overarching steps from initial
calculations to deployed savings, as shown in Figure 3.3. The first five steps in the varying
shades of blue nodes - Data Collection and Measure Characterization to Cost-Effective
Achievable Energy Efficiency Potential - are calculated within Energy Trust’s RA Model. This
results in the total cost-effective potential that is achievable over the 20-year forecast. The
actual deployment of these savings (the acquisition percentage of the total potential each
year, represented in the green node of the flow chart) is done exogenously of the RA model.
The remainder of this section provides further detail on each of the steps shown below.

4 http://www.lumina.com/why-analytica/what-is-analytica1/
Avista Corp.2021 Natural Gas Integrated Resource Plan 51
Chapter 3: Demand Side Resources

Figure 3.3: Energy Trust’s 20-Year DSM Forecast Determination Flow Chart

1. Data Collection and Measure Characterization
The first step of the modeling process is to identify and characterize a list of measures to
include in the model, as well as receive and format utility ‘global’ inputs for use in the
model. Energy Trust compiles and loads a list of commercially available and emerging
technology measures for residential, commercial, industrial, and agricultural applications
installed in new or existing structures. The list of measures is meant to reflect the full suite
of measures offered by Energy Trust, plus a spectrum of emerging technologies.5 In
addition to identifying and characterizing applicable measures, Energy Trust collects
necessary data to scale the measure level savings to a given service territory (known as
‘global inputs’).

5 An emerging technology is defined as technology that is not yet commercially available but is in some stage of
development with a reasonable chance of becoming commercially available within a 20-year timeframe. The model is
capable of quantifying costs, potential, and risks associated with uncertain, but high -saving emerging technology
measures. The savings from emerging technology measures are reduced by a risk -adjustment factor based on what stage
of development the technology is in. The working concept is that the incremental risk-adjusted savings from emerging
technology measures will result in a reasonable amount of savings over standard measures for those few technologies that
eventually come to market without having to try and pick winners and losers.

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Chapter 3: Demand Side Resources

• Measure Level Inputs:
Once the measures have been identified for inclusion in the model, they must be
characterized in order to determine their savings potential and cost-effectiveness.
The characterization inputs are determined through a combination of Energy Trust
primary data analysis, regional secondary sources6, and engineering analysis.
There are over 30 measure level inputs that feed into the model, but on a high level,
the inputs are organized into the following categories:

1. Measure Definition and Equipment Identification: This is the definition of
the efficient equipment and the baseline equipment it is replacing (e.g., a
95% AFUE furnace replacing an 80% AFUE baseline furnace). A measure’s
replacement type is also determined in this step – retrofit, replace on
burnout, or new construction.
2. Measure Savings: natural gas savings associated with an efficient measure
calculated by comparing the baseline and efficient measure consumptions.
3. Incremental Costs: The incremental cost of an efficient measure over the
baseline. The definition of incremental cost depends upon the replacement
type of the measure. If a measure is a retrofit measure, the incremental cost
of a measure is the full cost of the equipment and installation. If the measure
is a replace on burnout or new construction measure, the incremental cost
of the measure is the difference between the cost of the efficient measure
and the cost of the baseline equipment.
4. Market Data: Market data of a measure includes the density, saturation, and
suitability of a measure. The density is the number of measure units that can
be installed per scaling basis (e.g., the average number of showers per
home for showerhead measures). Saturation is the share of equipment that
is already efficient (e.g., 50% of the showers already have a low flow
showerhead). Suitability of a measure is a percentage that represents the
percent of installation opportunities where the measure can actually be
installed. For example, a duct sealing measure would need to reflect the
share of homes that actually have ducted heating systems. These data
inputs are generally derived from regional market data sources such as
NEEA’s Residential and Commercial Building Stock Assessments.
• Utility Global Inputs:
The RA Model requires several utility-level inputs to create the DSM forecast.
These inputs include:

6 Secondary Regional Data sources include: The Northwest Power Planning Council (NWPPC), the Regional Technical
Forum (the technical arm of the NWPPC), and market reports such as NEEA’s Residential and Commercial Building Stock
Assessments (RBSA and CBSA)
Avista Corp.2021 Natural Gas Integrated Resource Plan 53
Chapter 3: Demand Side Resources

1. Customer and Load Forecasts: These inputs are essential to scale the
measure level savings to a utility service territory. For example,
residential measures are characterized on a ‘per home’ scaling basis, so
the measure densities are calculated as the number of measures per
home. The model then takes the number of homes that Avista has
forecasted to scale the measure level potential to their entire service
territory.
2. Customer Stock Demographics: These data points are utility specific
and identify the percentage of customer building stock that utilize
different fuels for space and water heating. The RA Model uses these
inputs to segment the total stock to the portion that is applicable to a
measure (e.g., gas water heaters are only applicable to customers that
have gas water heat).
3. Utility Avoided Costs: Avoided costs are the net present value of
avoided energy purchases and delivery costs associated with energy
savings. Energy Trust calculates these values based on inputs provided
by Avista. The avoided cost components are discussed in other sections
of this IRP. Avoided costs are the primary benefit of energy efficiency in
the cost-effectiveness screen.

2. Calculate Technical Energy Efficiency Potential
Once measures have been characterized and utility data loaded into the model, the nex t
step is to determine the technical potential of energy that could be saved. Technical
potential is defined as the total energy savings potential of a measure that could be
achieved regardless of cost or market barriers, representing the maximum potential
energy savings available. The model calculates technical potential by multiplying the
number of applicable units of a measure in the service territory by the measure’s savings.
The model determines the total number of applicable units for a measure utilizing several
of the measure level and utility inputs referenced above:

Total applicable
units =
Measure Density * Baseline Saturation * Suitability
Factor * Heat Fuel Multipliers (if applicable) * Total
Utility Stock (e.g., # of homes)
Technical
Potential = Total Applicable Units * Measure Savings

This savings potential does not consider the various cost and market barriers that will limit
the adoption of efficiency measures.

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Chapter 3: Demand Side Resources

3. Calculate Achievable Energy Efficiency Potential
Achievable potential is simply a reduction of the technical potential to account for market
barriers that prevent the adoption of the measures identified in the technical potential. This
is done by applying a factor to reflect the maximum achievability for each measure. For
Avista’s 2020 IRP, Energy Trust updated its methodology to reflect the maximum
achievability estimated by the Northwest Power and Conservation Council for the 2021
Power Plan. While in past power plans a universal assumption of 85% was used, these
factors now typically range from 85% to 95%.7

Achievable
Potential = Technical Potential * Maximum Achievability Factor

4. Determine Cost-effectiveness of Measure using TRC Screen
The RA Model screens all DSM measures in every year of the forecast horizon using the
Total Resource Cost (TRC) test. This test evaluates the total present value of all benefits
attributable to the measure divided by the total present value of all costs. A TRC test value
greater than or equal to 1.0 means the value of benefits is equal to or exceeds the costs
and the measure is cost-effective and contributes to the total amount of cost-effective
potential. The TRC is expressed formulaically as follows:

TRC = Present Value of Benefits / Present Value of Costs

Where the Present Value of Benefits includes the sum of the following two
components:
a) Avoided Costs: The present value of natural gas energy saved over the life of
the measure, as determined by the total therms saved multiplied by Avista’s
avoided cost per therm. The net present-value of these benefits is calculated
based on the measure’s expected lifespan using the company’s discount rate.
b) Non-energy benefits are also included when present and quantifiable by a
reasonable and practical method (e.g., water savings from low-flow
showerheads or operations and maintenance cost reductions from advanced
controls).

Where the Present Value of Costs includes:
a) Incentives paid to the participant; and

7 For details on this, see https://www.nwcouncil.org/sites/default/files/2019_0813_p5.pdf.
Avista Corp.2021 Natural Gas Integrated Resource Plan 55
Chapter 3: Demand Side Resources

b) The participant’s remaining out-of-pocket costs for the installed cost of the
measures after incentives, minus state and federal tax credits.
The cost-effectiveness screen is a critical component for Energy Trust modeling and
program planning because Energy Trust is only allowed to incentivize cost-effective
measures unless an exception has been granted by the OPUC.

5. Quantify the Cost-Effective Achievable Energy Efficiency Potential
The RA Model’s final output of potential is the quantified cost-effective achievable
potential. If a measure passes the TRC test described above, then the achievable savings
from a measure is included in this potential. If the measure does not pass the TRC test
above, the measure’s potential is not included in cost-effective achievable potential.
However, the cost-effectiveness screen is overridden for some measures under two
specific conditions:
1) The OPUC has granted an exception to offer non-cost-effective measures under
strict conditions or,
2) When the measure is not cost-effective using utility-specific avoided costs, but the
measure is cost-effective when using blended gas avoided costs for all of the gas
utilities Energy Trust serves and is therefore offered by Energy Trust programs.

6. Deployment of Cost-Effective Achievable Energy Efficiency Potential
After determining the 20-year cost-effective achievable modeled potential, Energy Trust
develops a savings projection based on past program experience, knowledge of current
and developing markets, and future codes and standards. The savings projection is a 20-
year forecast of energy savings that will result in a reduction of load on Avista’s system.
This savings forecast includes savings from program activity for existing measures and
emerging technologies, expected savings from market transformation efforts that drive
improvements in codes and standards, and a forecast of savings from very large projects
that are not characterized in Energy Trust’s RA Model but consistently appear in Energy
Trust’s historic savings record and have been a source of overachievement against IRP
targets in prior years for other utilities that Energy Trust serves.

Figure 3.4 below reiterates the types of potential shown in Figure 3.2, and how the steps
described above and in the flow chart fit together.

Avista Corp.2021 Natural Gas Integrated Resource Plan 56
Chapter 3: Demand Side Resources

Figure 3.4: The Progression to Program Savings Projections
Data Collection and Measure Characterization Step 1
Not
Technically
Feasible
Technical Potential Step 2
Market
Barriers
Achievable Potential Step 3
Not Cost-
Effective
Cost-Effective Achievable
Potential Steps 4 & 5
Program
Design &
Market
Penetration
Final Program
Savings
Potential
Step 6

Forecast Results
The results of Energy Trust’s forecast are shown below.
RA Model Results – Technical, Achievable and Cost-Effective Achievable Potential
The RA Model produces results by potential type, as well as several other useful outputs,
including a supply curve based on the levelized cost of energy efficiency measures. This
section discusses the overall model results by potential type and provides an overview of the
supply curve. These results do not include the application of ramp rates applied in Step 6
described above.
Forecasted Savings by Sector
Table 3.3 summarizes the technical, achievable, and cost-effective potential for Avista’s
system in Oregon. These savings represent the total 20-year cumulative savings potential
identified in the RA Model by the three types identified in Figure 3.4 above. Modeled savings
represent the full spectrum of potential identified in Energy Trust’s resource assessment
model through time, prior to deployment of these savings into the final annual savings
projection.

Avista Corp.2021 Natural Gas Integrated Resource Plan 57
Chapter 3: Demand Side Resources

Table 3.3: Summary of Cumulative Modeled Savings Potential - 2021–2040
Sector
Technical
Potential
(Million Therms)
Achievable
Potential
(Million Therms)
Cost-Effective
Achievable Potential
(Million Therms)
Residential 16.9 15.2 12.1
Commercial 7.8 6.8 5.7
Industrial 0.3 0.2 0.2
Total 24.9 22.2 18.0

Figure 3.5 shows cumulative forecasted savings potential across the three sectors Energy
Trust serves, as well as the type of potential identified in Avista’s service territory. Residential
sales make up the majority of Avista’s service in Oregon, which is reflected in the potential.
Firm industrial sales represent a small percentage of the total sales in Oregon for Avista, and
subsequently shows very little savings potential. Avista’s interruptible and transport
customers are not eligible to participate in Energy Trust programs. 85% of the industrial
technical potential is cost-effective, while in the residential and commercial sectors, cost-
effective achievable potential is 72% and 73% of technical potential, respectively.

Figure 3.5: Savings Potential by Sector and Type – Cumulative 2021–2040 (Millions of
Therms)

-
2
4
6
8
10
12
14
16
18
Residential Commercial Industrial
Mi
l
l
i
o
n
s

o
f

T
h
e
r
m
s
Technical Achievable Cost-effective Achievable
Avista Corp.2021 Natural Gas Integrated Resource Plan 58
Chapter 3: Demand Side Resources

Cost-Effective Achievable Savings by End-Use
Figure 3.6 below provides a breakdown of Avista’s 20-year cost-effective savings potential by
end use.

Figure 3.6: 20-Year Cost-Effective Cumulative Potential by End Use

As is typical for a gas utility, the top saving end uses are heating, water heating, and
weatherization. A large portion of the water heating end-use is attributable to new construction
homes due to how Energy Trust assigns end uses to the New Homes pathways offered
through Energy Trust’s residential programs. The New Home pathways are packages of
measures in new construction homes with savings that span several end-uses. Energy Trust
assigns an end-use to each of the New Homes pathways based on the end-use that achieves
the most significant savings in the package. For example, the most cost-effective New Home
pathway that was identified by the model (because it achieves the most savings for the least
cost) was designated as a water heating end-use, though the package includes several other
efficient gas equipment measures.

In addition to the New Homes pathway savings, the water heating end-use includes water
heating equipment from all sectors, as well as showerheads and aerators. Heating,
weatherization, and HVAC end uses represent the savings associated with space heating
equipment, retrofit add-ons, and new construction packages. The behavioral end use consists
primarily of potential from Energy Trust’s commercial strategic energy management measure,
a service where Energy Trust energy experts provide training and support to facilities teams
0.03
0.04
0.16
0.33
0.42
0.56
0.71
4.80
5.14
5.78
- 1 2 3 4 5 6 7
HVAC
Appliance
Process Heating
Cooking
Ventilation
Behavioral
Other
Weatherization
Water Heating
Heating
Millions of Therms
Avista Corp.2021 Natural Gas Integrated Resource Plan 59
Chapter 3: Demand Side Resources

and staff to identify operations and maintenance changes that make a difference in a
building’s energy use.
Contribution of Emerging Technologies
As mentioned earlier in this report, Energy Trust includes a suite of emerging technologies in
its model. The emerging technologies included in the model are listed in Table 3.4.
Table 3.4: Emerging Technologies Included in the Model
Residential Commercial Industrial
• Path 5 Emerging Super-
Efficient Whole Home
• Window Replacement
(U<.20)
• Absorption Gas Heat Pump
Water Heaters
• Advanced Insulation
• DOAS/HRV
• Gas-fired Heat Pump
Hot Water
• Gas-fired Heat Pump,
Heating
• Advanced Windows
• Gas-fired Heat Pump
Water Heater
• Wall Insulation-
Vacuum Insulated
Panel, R0-R35

Energy Trust recognizes that emerging technologies are inherently uncertain and utilizes a
risk factor to hedge against that uncertainty. The risk factor for each emerging technology is
used to characterize the inherent uncertainty in the ability for emerging technologies to
produce reliable future savings. This risk factor is determined based on qualitative risk
categories, including:
• Market risk
• Technical risk
• Data source risk

The framework for assigning the risk factor is shown in Table 3.5. Each emerging technology
was assessed within each risk category and then a total weighted score was then calculated.
Well-established and well-studied technologies have lower risk factors and nascent,
unevaluated technologies (e.g., gas absorption heat pump water heaters) have higher risk
factors. This risk factor is then applied as a multiplier to reduce the incremental savings
potential of the measure.

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Chapter 3: Demand Side Resources

Table 3.5: Emerging Technology Risk Factor Score Card

Figure 3.7 shows the amount of emerging technology savings within each type of potential.
While emerging technologies make up a relatively large percentage of the technical and
achievable potential, nearly 25%, once the cost-effectiveness screen is applied, the relative
share of emerging technologies drops to 20% of total cost-effective achievable potential. This
is because some of these technologies are still in early stages of development and are quite
expensive. Though Energy Trust includes factors to account for f orecasted decreases in cost
Emerging Technology Risk Factor
Risk
Category 10% 30% 50% 70% 90%
Market Risk
(25%
weighting)
High Risk:
• Requires new/changed
business model
• Start-up, or small
manufacturer
• Significant changes to
infrastructure
• Requires training of
contractors. Consumer
acceptance barriers exist.

Low Risk:
• Trained contractors
• Established business
models
• Already in U.S. Market
• Manufacturer committed
to commercialization
Technical
Risk
(25%
weighting)
High Risk:
Prototype in
first field
tests.
A single or
unknown
approach
Low volume
manufacturer.
Limited
experience
New product
with broad
commercial
appeal
Proven
technology
in different
application
or different
region
Low Risk:
Proven
technology
in target
application.
Multiple
potentially
viable
approaches.
Data Source
Risk
(50%
weighting)
High Risk:
Based only
on
manufacturer
claims
Manufacturer
case studies
Engineering
assessment
or lab test
Third party
case study
(real world
installation)
Low Risk:
Evaluation
results or
multiple
third-party
case studies
Avista Corp.2021 Natural Gas Integrated Resource Plan 61
Chapter 3: Demand Side Resources

and increased savings from these technologies over time where applicable, some are not
cost-effective at any point over the planning horizon.
Figure 3.7: Cumulative Contribution of Emerging Technologies by Potential Type

Cost-Effective Override Effect
Table 3.6 shows the savings potential in the RA model that was added by employing the cost-
effectiveness override option in the model. As discussed in the methodology section, the
cost-effectiveness override option forces non-cost-effective potential into the cost-effective
potential results and is used when a measure meets one of the following two criteria:
1. A measure is offered under an OPUC exception.
2. When the measure is not cost-effective using Avista-specific avoided costs, but the
measure is cost-effective when using blended gas avoided costs for all of the gas
utilities Energy Trust serves and is therefore offered by Energy Trust programs.

Table 3.6: Cumulative Cost-Effective Potential (2021-2040) due to Cost-Effectiveness
Override (Millions of therms)
Sector
With Cost
Effectiveness
Override
Without Cost
Effectiveness
Override
Difference
Residential 12.1 10.9 (1.2)
Commercial 5.7 5.7 -
Industrial 0.2 0.2 -
Total 18.0 16.8 (1.2)
24%23%
20%
0
5
10
15
20
25
30
Technical Achievable Cost-effective
Achievable
Mil
l
i
o
n
s

o
f

T
h
e
r
m
s
Conventional Emerging
Avista Corp.2021 Natural Gas Integrated Resource Plan 62
Chapter 3: Demand Side Resources

In this IRP, approximately 7% of the cost-effective potential identified by the model is due to
the use of the cost-effective override. The measures that had this option applied to them
included residential attic, floor, and wall insulation, clothes dryers, certain new homes
packages, and clothes washers in the commercial sector.
Supply Curves and Levelized Cost Outputs
An additional output of the RA Model is a resource supply curve developed from the levelized
cost of energy of each measure. The supply curve graphically depicts the total potential that
could be saved at various costs. The levelized cost provides a consistent basis for comparing
efficiency measures and other resources with different lifetimes. The levelized cost calculation
starts with the incremental cost of a given measure. The total cost is amortized over the
estimated measure lifetime using the Avista’s discount rate. The annualized measure cost is
then divided by the annual natural gas savings. Some measures have negative levelized
costs because these measures have non-energy benefits that are greater than the total cost
of the measure over the same period.

Figure 3.8 below shows the supply curve developed for this IRP that can be used for
comparing demand-side and supply-side resources. The cost-effective potential identified in
this assessment is approximately 18 million therms, which translates to approximately
$2.40/therm on this graph. This is not a precise point, however, since measures around this
point will save natural gas at different times in relation to Avista’s peak periods and therefore
have varying capacity values that function to make them more or less cost-effective.
Consequently, measures on either side of this point may or may not be cost effective. Finally,
after approximately $3/therm, additional potential comes at rapidly increasing cost
increments.

Figure 3.8: Natural Gas Supply Curve

-
5
10
15
20
25
-$5 -$3 -$1 $1 $3 $5 $7 $9
Cu
m
u
l
a
t
i
v
e

P
o
t
e
n
t
i
a
l

(
M
i
l
l
i
o
n
s

of

T
h
e
r
m
s
)
TRC Levelized Cost ($/therm)
Avista Corp.2021 Natural Gas Integrated Resource Plan 63
Chapter 3: Demand Side Resources

Deployed Results – Final Savings Projection
The results of the final savings projection show that Energy Trust can achieve 2.1 million
annual therm savings across Avista’s system in Oregon from 2021 to 2025 and nearly 14.8
million therms by the end of 2040. This represents a 14.4 percent cumulative load reduction
by 2040 and is an average of just under a 0.8 percent incremental annual load reduction. The
cumulative final savings projection is shown in Table 3.7, which compares the technical,
achievable, and cost –effective achievable potential for comparison.

Table 3.7: 20-Year Cumulative Savings Potential by Type (Millions of Therms)
Technical
Potential
Achievable
Potential
Achievable
Cost-Effective
Potential
Energy Trust
Deployed Savings
Projection
Residential 16.9 15.2 12.1 8.2
Commercial 7.8 6.8 5.7 6.1
Industrial 0.3 0.2 0.2 0.5
Total 24.9 22.2 18.0 14.8

The final deployed savings projection is less than the modeled cost-effective achievable
potential. The primary reason for this additional step down in savings is lost opportunity
measures. These measures are meant to replace failed equipment or be installed in new
construction. They are considered lost opportunity measures because programs have one
opportunity to influence the installation of efficient equipment when the existing equipment
fails or when the new building is built. This is because these measures must be installed at
that specific point in time, and if the efficient equipment is not installed, then the opportunity
is lost until the equipment fails again. Energy Trust assumes that most lost opportunity
measures have gradually increasing annual adoption rates as time passes due to increasing
program influence and increasing codes and standards.

However, in the commercial and industrial sectors, the final Energy Trust savings projection
is higher than the model-identified cost-effective potential. In the commercial sector, new
construction savings are difficult to adequately represent in the model and program forecasts
exceed the available potential quantified in the RA model. The industrial sector projection is
higher because it includes an adder for large projects that are not forecast by the RA model
but are nonetheless expected to be acquired over time.

Figure 3.9 below shows the annual savings projection by end use. The savings acquisitions
in the initial years are fairly flat due to expected market conditions. After this point, expected
Avista Corp.2021 Natural Gas Integrated Resource Plan 64
Chapter 3: Demand Side Resources

program savings ramp up over the forecast period, to achieve as much cost-effective potential
as possible.
Figure 3.9: Annual Deployed Final Savings Potential by End Use

Finally, Figure 3.10 shows the annual and cumulative savings as a percentage of Avista’s
load forecast in Oregon. Annually, the savings as a percentage of load varies from about 0.4%
at its lowest to just under 1% at its highest, as represented on the left axis and the blue line.
Cumulatively, the savings as a percentage of load builds to 14.4% by 2040, as shown on the
right axis and the gold line.

Heating
Water Heating
Weatherization
-
0.2
0.4
0.6
0.8
1.0
1.2
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
20
3
7
20
3
9
Mi
l
l
i
o
n
s

o
f

T
h
e
r
m
s
Large Project Adder
Weatherization
Water Heating
Ventilation
Process Heating
Other
Heating
Cooking
Behavioral
Avista Corp.2021 Natural Gas Integrated Resource Plan 65
Chapter 3: Demand Side Resources

Figure 3.10: Annual and Cumulated Forecasted Savings as a Percentage of Avista
Load Forecast

Deployed Results – Peak Day Results
In the state of Oregon and around the region, there is an increased focus on the peak savings
contributions of energy efficiency and their impact on capacity investments. This new focus
has led some utilities to embark on targeted load management efforts for avoiding or delaying
distribution system reinforcements. Therefore, Avista and Energy Trust have collaborated to
develop estimates of peak day contributions from the energy efficiency measures that Energy
Trust forecasts to install.

Peak day coincident factors are the percentage of annual savings that occur on a peak day
and are shown in Table 3.8 below. Avista is still reviewing this methodology and for the
purpose of this analysis, Energy Trust utilized the peak day factors that are used in the
avoided costs used to screen measure for cost-effectiveness to determine the cost-effective
achievable resource per the description above. These include residential and commercial
space heating factors developed by NW Natural in and hot water, process load (flat), and
clothes washer factors sourced from load shapes developed by the Northwest Power and
Conservation Council for electric measures that are analogous to gas equipment. The peak
day factors are the highest for the space heating load shapes, which aligns with a typical
0%
2%
4%
6%
8%
10%
12%
14%
16%
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
Cu
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S
a
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s

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A
n
n
u
a
l

L
o
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d

Annual Cumulative
Avista Corp.2021 Natural Gas Integrated Resource Plan 66
Chapter 3: Demand Side Resources

winter system peak of natural gas utilities. These peak day factors will be reviewed and
updated by Avista to be specific to Avista’s Oregon service territory in the next IRP.
Table 3.8: Peak Day Coincident Factors by Load Profile
Load Profile Peak Day Factor Source
Residential Space Heating 2.10% NW Natural
Commercial Space Heating 1.80% NW Natural
Water Heating 0.40% NWPCC
Clothes Washer 0.20% NWPCC
Process Load 0.30% NWPCC

Figure 3.11 below shows the annual, deployed peak day savings potential based upon the
results of the 20-year forecast developed for this IRP. Each measure analyzed is assigned a
load shape and the appropriate peak day factor is applied to the annual savings to calculate
the overall DSM contribution to peak day capacity. Cumulatively, this is equal to 207,427
therms, or 1.4% of the total deployed savings potential in Avista’s Oregon service territory
over the 20-year forecast, as shown below.

Figure 3.11: Annual Deployed Peak Day DSM Savings Contribution by Sector

-
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
De
p
l
o
y
e
d

P
e
a
k

D
a
y

S
a
v
i
n
g
s

(
T
h
e
r
m
s
)
Commercial Industrial Residential
Avista Corp.2021 Natural Gas Integrated Resource Plan 67
Chapter 3: Demand Side Resources

Table 3.9: Cumulative Deployed Peak Day DSM Savings Contribution by Sector
(Therms)
Sector Cumulative Peak Day
Savings (Therms)
% of Overall Sector
Savings
Commercial 76,529 1.3%
Residential 129,245 1.6%
Industrial 1,653 0.3%
Total 207,427 1.4%

Conclusion
Avista has a long-term commitment to responsibly pursuing all available and cost-effective
efficiency options as an important means to reduce its customer’s energy cost. Cost-effective
demand-side management options are a key element in the Company’s strategy to meet
those commitments. Falling avoided costs and lower growth in customer demand have led to
a reduced role for conservation in the overall natural gas portfolio compared with IRPs done
prior to 2012, however, a regulatory shift to utilizing the UCT in Washington and Idaho DSM
programs will continue to provide a vital role in offsetting future natural gas load growth. The
company transitioned its Oregon DSM regular income, commercial, and industrial customer
programs to the Energy Trust of Oregon (ETO), with the ETO being the sole administrator
effective January 1, 2017. Avista is continuing to adaptively manage its DSM programs in
response to the ever-shifting economic climate.
Market transformation is not itself called out within the CPA since the CPA focuses upon
conservation potential without regard to how that potential is achieved. The prospect for a
regional market transformation entity will potentially bring a valuable tool to bear in working
towards the achievement of the cost-effective conservation opportunities identified within the
natural gas CPA.
Avista Corp.2021 Natural Gas Integrated Resource Plan 68
Chapter 4: Supply-Side Resources

4: Supply-Side Resources
Overview
Avista analyzed a range of future demand scenarios and possible cost-effective
conservation measures to reduce demand. This chapter discusses supply options to meet
net energy demand. Avista’s objective is to provide reliable service at reasonable prices.
To help achieve this objective, Avista evaluates a variety of supply-side resources and
attempts to build a diversified natural gas supply portfolio. The resource acquisition and
commodity procurement programs resulting from the evaluation consider physical and
financial risks, market-related risks, and procurement execution risks; and identifies
methods to mitigate these risks.
Avista manages natural gas procurement and related activities on a system-wide basis
with several regional supply options available to serve core customers. Supply options
include firm and non-firm supplies, firm and interruptible transportation on six interstate
pipelines, and storage. Because Avista’s core customers span three states, the diversity
of delivery points and demand requirements adds to the options available to meet
customers’ needs. The utilization of these components varies depending on demand and
operating conditions. This chapter discusses the available regional commodity resources
and Avista’s procurement plan strategies, the regional pipeline resource options available
to deliver the commodity to customers, and the storage resource options available to
provide additional supply diversity, enhanced reliability, favorable price opportunities, and
flexibility to meet a varied demand profile. Carbon reducing supplies, such as renewable
natural gas (RNG) and hydrogen (H2) are also considered.

Commodity Resources
Supply Basins
The Northwest continues to enjoy a low-cost commodity environment with abundant
supply availability, especially when compared across the globe. This is primarily due to
the production in areas of the Northeast and Southern United States. This supply is
serving an increasing amount of demand in the population heavy areas in the middle and
eastern portions of Canada and the U.S displacing supplies that had historically been
delivered from the Western Canadian Sedimentary Basis (WCSB). Current forecasts
show a long-term regional price advantage for Western Canada and Rockies gas basins
as the need for this gas diminishes. High Canadian production paired with limited options
for flowing gas into demand areas has created a, generally, discounted commodity in the
Northwest when compared to the Henry Hub. Although stalled due to an oil price collapse
in 2020, associated gas from oil wells is still providing a large amount of the natural gas
supply. Access to these abundant supplies of natural gas and to major markets across
the continent has also led to the construction of multiple LNG plants. These LNG plants
Avista Corp.2021 Natural Gas Integrated Resource Plan 69
Chapter 4: Supply-Side Resources

will be a large demand addition to North American supply. There are a few LNG export
facilities in the Western half of North America. The first is Jordan Cove and although
approved by FERC, it is not expected to be built in the long-term outlook from Wood
Mackenzie. The second is Canadian project known LNG Canada and is in Kitimat B.C.
This facility is one of the largest investments in Canadian history and is currently under
construction. Its initial capacity, like Jordan Cove, is roughly 1 Bcf per day, but contains
an option for up to 3.5 Bcf per day in total. The large increase of natural gas demand by
either of these facilities moving forward could cause pressure on commodity prices with
the limited infrastructure in the Pacific Northwest.
Another relatively new demand area is Mexico. In 2013, Mexico reformed its energy
sector allowing new market participants, innovative technologies and foreign investment.
This market reformation opened new opportunities for natural gas export to Mexico.
Since these market changes, Mexican imports which were historically less than 2 Bcf per
day have more than doubled to over 5 Bcf per day.
Recent estimates from both the EIA and Natural Resources Canada reflect a large
potential supply of natural gas in North America of over 4,000 trillion cubic feet (Tcf) or
enough supply to last many decades at current demand levels. This estimate is based on
known geological areas combined with the ability to economically recover natural gas as
infrastructure expands and technology improves.
Regional Market Hubs
There are numerous regional market hubs in the Pacific Northwest where natural gas is
traded extending from the two primary basins. These regional hubs are typically located
at pipeline interconnects. Avista is located near, and transacts at, most of the Pacific
Northwest regional market hubs, enabling flexible access to geographically diverse
supply points. These supply points include:
• AECO – The AECO-C/Nova Inventory Transfer market center located in Alberta is
a major connection region to long-distance transportation systems which take
natural gas to points throughout Canada and the United States. Alberta is the
primary Canadian exporter of natural gas to the U.S. and historically produces 90
percent of Canada's natural gas.
• Rockies – This pricing point represents several locations on the southern end of
the NWP system in the Rocky Mountain region. The system draws on Rocky
Mountain natural gas-producing areas clustered in areas of Colorado, Utah, New
Mexico and Wyoming.
• Sumas/Huntingdon – The Sumas, Washington pricing point is on the
U.S./Canadian border where the northern end of the NWP system connects with
Avista Corp.2021 Natural Gas Integrated Resource Plan 70
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Enbridge’s Westcoast Pipeline and predominantly markets Canadian natural gas
from Northern British Columbia.
• Malin – This pricing point is at Malin, Oregon, on the California/Oregon border
where TransCanada’s Gas Transmission Northwest (GTN) and Pacific Gas &
Electric Company connect.
• Station 2 – Located at the center of the Enbridge’s Westcoast Pipeline system
connecting to northern British Columbia natural gas production.
• Stanfield – Located near the Washington/Oregon border at the intersection of the
NWP and GTN pipelines.
• Kingsgate – Located at the U.S./Canadian (Idaho) border where the GTN pipeline
connects with the TransCanada Foothills pipeline.

Given the ability to transport natural gas across North America, natural gas pricing is often
compared to the Henry Hub price. Henry Hub, located in Louisiana, is the primary natural
gas pricing point in the U.S. and is the trading point used in NYMEX futures contracts.
Figure 4.1 shows historic natural gas prices for first-of-month index physical purchases
at AECO, Station 2, Rockies and Henry Hub. The figure has changed in recent years due
to an alteration in flows of natural gas specifically coming from Western Canada.
Figure 4.1: Monthly Index Prices

Avista Corp.2021 Natural Gas Integrated Resource Plan 71
Chapter 4: Supply-Side Resources

Northwest regional natural gas prices typically move together; however, the basis
differential can change depending on market or operational factors. This includes
differences in weather patterns, pipeline constraints, and the ability to shift supplies to
higher-priced delivery points in the U.S. or Canada. By monitoring these price shifts,
Avista can often purchase at the lowest-priced trading hubs on a given day, subject to
operational and contractual constraints.
Liquidity is generally sufficient in the day-markets at most Northwest supply points. AECO
continues to be the most liquid supply point, especially for longer-term transactions.
Sumas has historically been the least liquid of the four major regional supply points
(AECO, Rockies, Sumas and Malin). This illiquidity contributes to generally higher relative
prices in the high demand winter months.
Avista procures natural gas via contracts. Contract specifics vary from transaction-to-
transaction, and many of those terms or conditions affect commodity pricing. Some of the
terms and conditions include:
• Firm vs. Non-Firm: Most term contracts specify that supplies are firm except for
force majeure conditions. In the case of non-firm supplies, the standard provision
is that they may be cut for reasons other than force majeure conditions.
• Fixed vs. Floating Pricing: The agreed-upon price for the delivered gas may be
fixed or based on a daily or monthly index.
• Physical vs. Financial: Certain counterparties, such as banking institutions, may
not trade physical natural gas, but are still active in the natural gas markets. Rather
than managing physical supplies, those counterparties choose to transact
financially rather than physically. Financial transactions provide another way for
Avista to financially hedge price.
• Load Factor/Variable Take: Some contracts have fixed reservation charges
assessed during each of the winter months, while others have minimum daily or
monthly take requirements. Depending on the specific provisions, the resulting
commodity price will contain a discount or premium compared to standard terms.
• Liquidated Damages: Most contracts contain provisions for symmetrical penalties
for failure to take or supply natural gas.

For this IRP, the SENDOUT® model assumes natural gas purchases under a firm,
physical, fixed-price contract, regardless of contract execution date and type of contract.
Avista pursues a variety of contractual terms and conditions to capture the most value for
customers. Avista‘s natural gas buyers actively assess the most cost-effective way to
meet customer demand and optimize unutilized resources.
Avista Corp.2021 Natural Gas Integrated Resource Plan 72
Chapter 4: Supply-Side Resources

Transportation Resources
Although proximity to liquid market hubs is important from a cost perspective, supplies
are only as reliable as the pipeline transportation from the hubs to Avista’s service
territories. Capturing favorable price differentials and mitigating price and operational risk
can also be realized by holding multiple pipeline transportation options. Avista contracts
for a sufficient amount of diversified firm pipeline capacity from various receipt and
delivery points (including storage facilities), so that firm deliveries will meet peak day
demand. This combination of firm transportation rights to Avista’s service territory, storage
facilities and access to liquid supply basins ensure peak supplies are available to serve
core customers. The regional map, from the Northwest Gas Association (NWGA), shows
the relative capacity of the pipelines and storage capacity (Figure 4.2)

Avista Corp.2021 Natural Gas Integrated Resource Plan 73
Chapter 4: Supply-Side Resources

Figure 4.2: Regional Pipeline and Storage Capacity

Avista Corp.2021 Natural Gas Integrated Resource Plan 74
Chapter 4: Supply-Side Resources

The major pipelines servicing the region include:
• Williams - Northwest Pipeline (NWP):
A natural gas transmission pipeline serving the Pacific Northwest moving natural
gas from the U.S./Canadian border in Washington and from the Rocky Mountain
region of the U.S.
• TransCanada Gas Transmission Northwest (GTN): A natural gas transmission
pipeline originating at Kingsgate, Idaho, (Canadian/U.S. border) and terminating
at the California/Oregon border close to Malin, Oregon.
• TransCanada Alberta System (NGTL): This natural gas gathering and
transmission pipeline in Alberta, Canada, delivers natural gas into the
TransCanada Foothills pipeline at the Alberta/British Columbia border.
• TransCanada Foothills System: This natural gas transmission pipeline delivers
natural gas between the Alberta - British Columbia border and the Canadian/U.S.
border at Kingsgate, Idaho.
• TransCanada Tuscarora Gas Transmission: This natural gas transmission
pipeline originates at Malin, Oregon, and terminates at Wadsworth, Nevada.
• Enbridge - Westcoast Pipeline: This natural gas transmission pipeline originates
at Fort Nelson, British Columbia, and terminates at the Canadian/U.S. border at
Huntington, British Columbia/Sumas, Washington.
• El Paso Natural Gas - Ruby pipeline: This natural gas transmission pipeline
brings supplies from the Rocky Mountain region of the U.S. to interconnections
near Malin, Oregon.

Avista has contracts with all of the above pipelines (with the exception of Ruby Pipeline)
for firm transportation to serve core customers. Table 4.1 details the firm
transportation/resource services contracted by Avista. These contracts are of different
vintages with different expiration dates; however, all have the right to be renewed by
Avista. This gives Avista and its customer’s available capacity to meet existing core
demand now and in the future.

Avista Corp.2021 Natural Gas Integrated Resource Plan 75
Chapter 4: Supply-Side Resources

Table 4.1: Firm Transportation Resources Contracted (Dth/Day)
Avista North Avista South
Firm
Transportation Winter Summer Winter Summer
NWP TF-1 157,869 157,869 42,699 42,699
GTN T-1 100,605 75,782 42,260 20,640
NWP TF-2 91,200 2,623
Total 349,674 233,651 87,582 63,339
Firm Storage Resources - Max Deliverability
Jackson Prairie 346,667 54,623

*Represents original contract amounts after releases expire

Avista defines two categories of interstate pipeline capacity. Direct-connect pipelines
deliver supplies directly to Avista’s local distribution system from production areas,
storage facilities or interconnections with other pipelines. Upstream pipelines deliver
natural gas to the direct-connect pipelines from remote production areas, market centers
and out-of-area storage facilities. Firm Storage Resources - Max Deliverability is
specifically tied to Avista’s withdrawal rights at the Jackson Prairie storage facility and is
based on our one third ownership rights. This number only indicates how much we can
withdraw from the facility, as transport on NWP is needed to move it from the facility itself.
Figure 4.3 illustrates the direct-connect pipeline network relative to Avista’s supply
sources and service territories.1

1 Avista has a small amount of pipeline capacity with TransCanada Tuscarora Gas Transmission, a
natural gas transmission pipeline originating at Malin, Oregon, to service a small number of Oregon
customers near the southern border of the state.
Avista Corp.2021 Natural Gas Integrated Resource Plan 76
Chapter 4: Supply-Side Resources

Figure 4.3: Direct-Connect Pipelines

Supply-side resource decisions focus on where to purchase natural gas and how to
deliver it to customers. Each LDC has distinct service territories and geography relative
to supply sources and pipeline infrastructure. Solutions that deliver supply to service
territories among regional LDCs are similar but are rarely generic.
The NWP system is effectively a fully contracted pipeline. Except for La Grande, OR,
Avista’s service territories lie at the end of NWP pipeline laterals. The Spokane, Coeur
d’Alene and Lewiston laterals serve Washington and Idaho load, and the Grants Pass
lateral serves Roseburg and Medford. Capacity expansions of these laterals would be
lengthy and costly endeavors which Avista would likely bear most of the incremental
costs.
The GTN system, also fully contracted, runs from the Kingsgate trading point on the
Idaho-Canadian border down to Malin on the Oregon-California border. This pipeline runs
directly through or near most of Avista’s service territories. Mileage based rates provide
an attractive option for securing incremental resource needs.
Peak day planning aside, both pipelines provide an array of options to flexibly manage
daily operations. The NWP and GTN pipelines directly serve Avista’s two largest service
territories, providing diversification and risk mitigation with respect to supply source, price
and reliability. Northwest Pipeline (NWP) provides direct access to Rockies and British
Columbia supply and facilitates optionality for storage facility management. The Stanfield
interconnect of the two lines is also geographically well situated to Avista’s service
territories.
Roseburg
Medfor
d
SUMAS
ROCKS
Stanfield
NWP GTN
Washington & Idaho
LaGrande
JP
Storage
Malin
Klamath Falls
AECO
Kingsgate Station 2
Sumas
Rockies
Roseburg &
Medford
Avista Corp.2021 Natural Gas Integrated Resource Plan 77
Chapter 4: Supply-Side Resources

The rates used in the planning model start with filed rates currently in effect (See
Appendix 4.1 – Current Transportation/Storage Rates and Assumptions). Forecasting
future pipeline rates is challenging. Assumptions for future rate changes are the result of
market information on comparable pipeline projects, prior rate case experience, and
informal discussions with regional pipeline owners. Pipelines will file to recover costs at
rates equal to their cost of service.
NWP and GTN also offer interruptible transportation services. Interruptible transportation
is subject to curtailment when pipeline capacity constraints limit the amount of natural gas
that may be moved. Although the commodity cost per dekatherm transported is generally
the same as firm transportation, there are no demand or reservation charges in these
transportation contracts. Avista does not rely on interruptible capacity to meet peak day
core demand requirements.
Avista's transportation acquisition strategy is to contract for firm transportation to serve
core customers on a peak day in the planning horizon. Since contracts for pipeline
capacity are often lengthy and core customer demand needs can vary over time,
determining the appropriate level of firm transportation is a complex analysis. The
analysis includes the projected number of firm customers and their expected annual and
peak day demand, opportunities for future pipeline or storage expansions, and relative
costs between pipelines and upstream supplies. This analysis is done on semi-annual
basis and through the IRP. Active management of underutilized transportation capacity
either through the capacity release market or engaging in optimization transactions to
recover some transportation costs, keeps Avista’s portfolio flexible while minimizing costs
to customers. Timely analysis is also important to maintain an appropriate time cushion
to allow for required lead times should the need for securing new capacity arise (See
Chapter 6 – Integrated Resource Portfolio for a description of the management of
underutilized pipeline resources).
Avista manages existing resources through optimization to mitigate the costs incurred by
customers until the resource is required to meet demand. The recovery of transportation
costs is often market based with rules governed by the FERC. The management of long-
and short-term resources ensures the goal to meet firm customer demand in a reliable
and cost-effective manner. Unutilized resources like supply, transportation, storage and
capacity can be combined to create products that capture more value than the individual
pieces. Avista has structured long-term arrangements with other utilities that allow
available resources utilization and provide products that no individual component can
satisfy. These products provide more cost recovery of the fixed charges incurred for the
resources. Another strategy to mitigate transportation costs is to participate in the daily
market to assess if unutilized capacity has value. Avista seeks daily opportunities to
purchase natural gas, transport it on existing unutilized capacity, and sell it into a higher
Avista Corp.2021 Natural Gas Integrated Resource Plan 78
Chapter 4: Supply-Side Resources

priced market to capture the cost of the natural gas purchased and recover some pipeline
charges. The recovery is market dependent and may or may not recover all pipeline costs,
but mitigates pipeline costs to customers.

Storage Resources
Storage is a valuable strategic resource that enables improved management of a highly
seasonal and varied demand profile. Storage benefits include:
• Flexibility to serve peak period needs;
• Access to typically lower cost off-peak supplies;
• Reduced need for higher cost annual firm transportation;
• Improved utilization of existing firm transportation via off-season storage injections;
and
• Additional supply point diversity.

While there are several storage facilities available in the region, Avista’s existing storage
resources consist solely of ownership and leasehold rights at the Jackson Prairie Storage
facility.
Avista optimizes storage as part of its asset management program. This helps to ensure
a controlled cost mechanism is in place to manage the large supply found within the
storage facility. An example of this storage optimization is selling today at a cash price
and buying a forward month contract or selling between different forward months. Since
forward months have risks or premiums built into the price the result is Avista locking in
a given spread. Storage optimization takes place all while maintaining the peak day
deliverability, at a not to exceed level, to plan for this cost-effective resource to serve
customer needs. All optimization of assets directly reduce customers monthly billing.
Jackson Prairie Storage
Avista is one-third owner, with NWP and Puget Sound Energy (PSE), of the Jackson
Prairie Storage Project for the benefit of its core customers in all three states. Jackson
Prairie Storage is an underground reservoir facility located near Chehalis, Washington
approximately 30 miles south of Olympia, Washington. The total working natural gas
capacity of the facility is approximately 25 Bcf. Avista’s current share of this capacity for
core customers is approximately 8.5 Bcf and includes 398,667 Dth of daily deliverability
rights. Besides ownership rights, Avista leased an additional 95,565 Dth of Jackson
Prairie capacity with 2,623 Dth of deliverability from NWP to serve Oregon customers.
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Incremental Supply-Side Resource Options
Avista’s existing portfolio of supply-side resources provides a mix of assets to manage
demand requirements for average and peak day events. Avista monitors the following
potential resource options to meet future requirements in anticipation of changing demand
requirements. When considering or selecting a transportation resource, the appropriate
natural gas supply pairs with the transportation resource and the SENDOUT® model
prices the resources accordingly.
Capacity Release Recall
Pipeline capacity not utilized to serve core customer demand is available to sell to other
parties or optimized through daily or term transactions. Released capacity is generally
marketed through a competitive bidding process and can be on a short-term (month-to-
month) or long-term basis. Avista actively participates in the capacity release market with
short-term and long-term capacity releases. Avista assesses the need to recall capacity
or extend a release of capacity on an on-going basis. The IRP process evaluates if or
when to recall some or all long-term releases.
Existing Available Capacity
In some instances, there is available capacity on existing pipelines. As previously
discussed, both GTN and NWP are fully subscribed, but GTN currently maintains the
ability to flow additional supply from Kingsgate to Spokane as noted in Chapter 7. Avista
has modeled access to the GTN capacity as an option to meet future demand needs in
addition to some capacity in the La Grande area where some quantities are available on
NWP.
GTN Backhauls
The GTN interconnection with the Ruby Pipeline has enabled GTN the physical capability
to provide a limited amount of firm back-haul service from Malin with minor modifications
to their system. Fees for utilizing this service are under the existing Firm Rate Schedule
(FTS-1) and currently include no fuel charges. Additional requests for back-haul service
may require additional facilities and compression (i.e., fuel).
This service can provide an interesting solution for Oregon customers. For example,
Avista can purchase supplies at Malin, Oregon and transport those supplies to Klamath
Falls or Medford. Malin-based natural gas supplies typically include a higher basis
differential to AECO supplies, but are generally less expensive than the cost of forward-
haul transporting traditional supplies south and paying the associated demand charges.
The GTN system is a mileage-based system, so Avista pays only a fraction of the rate if
it is transporting supplies from Malin to Medford and Klamath Falls. The GTN system is
approximately 612 miles long and the distance from Malin to the Medford lateral is only
about 12 miles.
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New Pipeline Transportation
Additional firm pipeline transportation resources are viable and attractive resource
options. However, determining the appropriate level, supply source and associated
pipeline path, costs and timing, and if existing resources will be available at the
appropriate time, make this resource difficult to analyze. Firm pipeline transportation
provides several advantages; it provides the ability to receive firm supplies at the
production basin, it provides for base-load demand, and it can be a low-cost option given
optimization and capacity release opportunities. Pipeline transportation has several
drawbacks, including typically long-dated contract requirements, limited need in the
summer months (many pipelines require annual contracts), and limited availability and/or
inconvenient sizing/timing relative to resource need. No new pipelines were considered
in the current IRP as resource options due to the exceedingly difficult legal path in getting
approval for their construction. If one of these pipeline projects were to come forward as
a viable option Avista would consider the costs and risks in a future IRP.
Pipeline expansions are typically more expensive than existing pipeline capacity and
often require long-term contracts. Even though expansions may be more expensive than
existing capacity, this approach may still provide the best option given that some of the
other options require matching pipeline transportation. Matching pipeline transportation is
creating equivalent volumes on different pipelines from the basin to the delivery point in
order to fully utilize subscribed capacity. Expansions may also provide increased reliability
or access to supply that cannot be obtained through existing pipelines. This is the case
with the Pacific Connector pipeline being proposed as the connecting feedstock for the
Jordan Cove LNG facility in Oregon. The pipeline’s current path connects into Northwest
Pipelines Grants Pass Lateral where capacity is limited. The Pacific Connector pipeline
would add an additional 50,000 Dth/day of capacity along that lateral flowing south from
the Roseburg interconnect.
Several specific projects have been proposed for the region. The following summaries
describe these projects while Figure 4.4 illustrates their location.

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Figure 4.4: Proposed Pipeline Locations

1. Enbridge T-South System Looping
FortisBC and Enbridge are system enhancement on the T-South pipeline.
Removing constraints will allow expansion of Enbridge’s T-South enhanced
service offering, which provides shippers the options of delivering to Sumas or the
Kingsgate market. Expanding the bi-directional Southern Crossing system would
increase capacity at Sumas during peak demand periods. Initial capacity from the
Enbridge system to Kingsgate would increase capacity by 190MMcf/d. This would
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add incremental gas into the Huntingdon/Sumas market through looping and
compressor station upgrades along the system.
2. FortisBC Southern Crossing Expansion:
The Southern Crossing pipeline system is a bidirectional pipeline connecting
Westcoast T South system at Kingsvale, BC and TransCanada’s Alberta/BC
border. This expansion would include over 90 miles of pipeline looping allowing
access to an additional 300-400 MMcf/d of bi-directional capacity, tying together
station 2 and AECO markets.
3. NWP - Sumas Express
NWP continues to explore options to expand service from Sumas, Wash., to
markets along the Interstate-5 corridor. This project could help relieve the
congestion along this highly populated geographical region in both Washington
and Oregon. Various methods could be used to add this additional capacity
including looping, additional compression and increasing the pipe size and can be
scaled based off demand.
4. TC Energy GTN Trail West
The pipeline taking natural gas off of GTN and onto NWP hub near Molalla is
referred to as Trail West. TransCanada GTN, Northwest Natural and Northwest
Pipeline are the project sponsors of this 106-mile, 30-inch diameter pipeline. The
initial design capacity of this pipeline is 500 MMcf/d and expandable up to 1,000
MMcf/d. This could be an important project if built as it would bring more gas into
the I-5 corridor where unused pipeline capacity is quickly disappearing based on
the demand for natural gas and population increase.
5. TC Energy NGTL and Foothills BC Enhancements
In order to meet existing aggregate demand in southern AB and incremental long-
term delivery commitments at the A/BC border, NGTL is ongoing and expected to
have an in-service date of 2022. This project will increase the delivery point
capacity at the A/BC border by 288,000 GJ per day and will operationally true-up
capacity differences between NGTL and Foothills and provide additional export
capacity into the US.
6. Pacific Connector
Pembina is currently attempting to acquire approval for a 232-mile, 36-inch
diameter pipeline designed to transport up to 1.2 billion cubic feet of natural gas
per day from interconnects near Malin, Oregon, to the Jordan Cove LNG terminal
in Coos Bay, Oregon. The pipeline would deliver the feedstock to the LNG terminal
providing natural gas to international markets, but also to the Pacific Northwest.
The pipeline will connect with Williams’ Northwest Pipeline on the Grants Pass
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lateral. This ties in directly within Avista’s service territory and will bring in an
additional 50,000 Dth/day of capacity into that area. This new option could provide
Avista’s customers in the area new capacity for growth and supply diversity.

Avista supports proposals that bring supply diversity and reliability to the region. Supply
diversity provides a varied supply base in the procurement of natural gas. Since there are
few options in the Northwest, supply diversity provides options and security when
constraints or high demand are present. Avista engages in discussions and analysis of
the potential impact of each regional proposal from a demand serving and
reliability/supply diversity perspective. In most cases, for Avista to consider them a viable
incremental resource to meet demand needs, it would require combining them with
additional capacity on existing pipeline resources.
In-Ground Storage
In-ground storage provides advantages when natural gas from storage can be delivered
to Avista’s city-gates. It enables deliveries of natural gas to customers during peak cold
weather events. It also facilitates potentially lower-cost supply for customers by capturing
peak/non-peak pricing differentials and potential arbitrage opportunities within individual
months. Although additional storage can be a valuable resource, without deliverability to
Avista’s service territory, this storage cannot be an incremental firm peak serving
resource.
Jackson Prairie
Jackson Prairie is a potential resource for expansion opportunities. Any future storage
expansion capacity does not include transportation and therefore cannot be considered
an incremental peak day resource. However, Avista will continue to look for exchange
and transportation release opportunities that could fully utilize these additional resource
options. When an opportunity presents itself, Avista assesses the financial and reliability
impact to customers. Due to the fast paced growth in the region, and the need for new
resources, a future expansion is possible, though a robust analysis would be required to
determine feasibility. Currently, there are no plans for immediate expansion of Jackson
Prairie.
Other In-Ground Storage
Other regional storage facilities exist and may be cost effective. Additional capacity at
Northwest Natural’s Mist facility, capacity at one of the Alberta area storage facilities,
Questar’s Clay Basin facility in northeast Utah, Ryckman Creek in Uinta County, Wyo.,
and northern California storage are all possibilities. Transportation to and from these
facilities to Avista’s service territories continues to be the largest impediment to these
options. Avista will continue to look for exchange and transportation release opportunities
while monitoring daily metrics of load, transport and market environment.
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LNG Exports
Liquefied natural gas is a process of chilling natural gas to -260 degrees Fahrenheit to
create a condensed version, 1/600 the volume, of natural gas. This process acts as a
virtual pipeline taking domestic production to nearly any location in the world. For years
the U.S. was expected to be an importer of LNG. This is a stark contrast to reality as in
2017 the export of LNG from the U.S. has quadrupled led by two projects, Sabine Pass
in Louisiana and Cove Point in Maryland. In recent history, this market dynamic has
changed from fixed price gas contracts to more spot purchases of LNG. The three largest
countries for U.S. LNG exports are South Korea, Japan and Spain. Waiting in the
wings to provide more LNG supply are four additional export facilities located mostly in
the gulf coast region of the U.S. and will bring the additional demand to nearly 9 Bcf per
day. This massive buildout of LNG exports has led to the U.S. becoming the third largest
exporter of LNG in the world.
LNG and CNG
LNG is another resource option in Avista’s service territories and is suited for meeting
peak day or cold weather events. Satellite LNG uses natural gas that is trucked to the
facilities in liquid form from an offsite liquefaction facility. Alternatively, small-scale
liquefaction and storage may also be an effective resource option if natural gas supply
during non-peak times is sufficient to build adequate inventory for peak events. Permitting
issues notwithstanding, facilities could be located in optimal locations within the
distribution system.
CNG is another resource option for meeting demand peaks and is operationally similar to
LNG. Natural gas could be compressed offsite and delivered to a distribution supply point
or compressed locally at the distribution supply point if sufficient natural gas supply and
power for compression is available during non-peak times.
Estimates for LNG and CNG resources vary because of sizing and location issues. This
IRP uses estimates from other facilities constructed in the area and from conversations
with experts in the industry. Avista will monitor and refine the costs of developing LNG
and CNG resources while considering lead time requirements and environmental issues.
Plymouth LNG
NWP owns and operates an LNG storage facility at Plymouth, Wash., which provides
natural gas liquefaction, storage and vaporization service under its LS-1, LS-2F and LS-
3F tariffs. An example ratio of injection and withdrawal rates show that it can take more
than 200 days to fill to capacity, but only three to five days to empty. As such, the resource
is best suited for needle-peak demands. Incremental transportation capacity to Avista’s
service territories would have to be obtained in order for it to be an effective peaking
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resource. With available capacity, Plymouth LNG was considered in our supply side
resource modeling but was not selected.
Avista-Owned Liquefaction LNG
Avista could construct a liquefaction LNG facility in the service area. Doing so could use
excess transportation during off-peak periods to fill the facility, avoid tying up
transportation during peak weather events, and it may avoid additional annual pipeline
charges.
Construction would depend on regulatory and environmental approval as well as cost-
effectiveness requirements. Preliminary estimates of the construction, environmental,
right-of-way, legal, operating and maintenance, required lead times, and inventory costs
indicate company-owned LNG facilities have significant development risks. Due to the
changing direction in policy and fossil fuels, Avista did not model this resource in the
current IRP.
Renewable Natural Gas (RNG)
Renewable Natural Gas, or biogas, typically refers to a mixture of gases produced by the
biological breakdown of organic matter in the absence of oxygen. RNG can be produced
by anaerobic digestion or fermentation of biodegradable materials such as woody
biomass, manure or sewage, municipal waste, green waste and energy crops. Depending
on the type of RNG there are different factors to quantify methane saved by its capture
as methane has been found to have a multiplier effect on global warming of 342 times that
of carbon dioxide. Each type of RNG has a different carbon intensity as compared to
natural gas as shown in table 4.2.

2https://www.ipcc.ch/

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Table 4.2: Carbon Intensity3
Source
Current Carbon
Intensity
(g CO2e/MJ)
Estimated % of Carbon
reduction as compared
to natural gas
lbs. per Dth
Natural Gas 78.37 128.27
Landfill 46.42 41% 75.98
Dairy -276.24 -452% (580.40)
WWT 19.34 75% 31.65
Solid Waste -22.93 -129% (165.80)

RNG is a renewable fuel, so it may qualify for renewable energy subsidies. Once
contained, RNG can be used by boilers for heat, as power generation, compressed
natural gas vehicles for transportation or directly injected into the natural gas grid. The
further down this line greater the need for pipeline quality gas.
Biogas projects are unique, so reliable cost estimates are difficult to obtain. Project
sponsorship has many complex issues, and the more likely participation in such a project
is as a long-term contracted purchaser. Avista considered biogas as a resource in this
planning cycle and depending on the location of the facility it may be cost effective. This
is especially the case when found within Avista’s internal distribution system where
transportation and fuel costs can be avoided. For more information about RNG and its
potential uses in energy policy within Avista territories please see Chapter 5 - Carbon
Reduction.

Avista’s Natural Gas Procurement Plan
Avista’s foundational purpose/goal of the natural gas procurement plan is to provide a
diversified portfolio of reliable supply while at the same time managing the volatility and
cost of that supply. Avista manages the procurement plan by layering in hedges over a
period of time based on average system load per month. Avista does not measure the
success of this plan based on a certain cost or loss risk, rather it is considered successful
when we have secured firm load at a reasonable price while addressing risk inherent

3 California Air Resources Board
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within these markets. The measurable objectives monitored toward this goal include a
daily financial position of the overall portfolio, tracking of all new and previously transacted
hedges, and the tracking of remaining hedges yet to be purchased based on a percentage
of forecasted load as specified in the procurement plan.
No company can accurately predict future natural gas prices, however, market conditions
and experience help shape Avista’s overall approach to natural gas procurement. The
Avista procurement plan seeks to acquire natural gas supplies while reducing exposure
to short-term price and load volatility. This is done by utilizing a combination of strategies
to reduce the impacts of changing natural gas prices in a volatile market. A portion of
hedges will be focused on the concentration risk of fixed-price natural gas purchases by
utilizing Hedge Windows, and another portion of hedges will target reducing risk in a
volatile market by utilizing Risk Responsive methods. This allows Avista to set a risk level
to help reduce exposure to events outside of our control such as the Energy Crisis in the
early 2000’s or the Enbridge pipeline rupture in 2018 or most recently the COVID-19
pandemic and the oil price collapse.
Hedge transactions may be executed for a period of one-month through thirty-six months
prior to delivery period and are for the Local Distribution Customer (LDC) only. Due to
Avista’s geographic location, transactions may be executed at different supply basins in
order reduce our overall portfolio risk. This procurement plan is disciplined, yet flexible,
allowing for modifications due to changing market conditions, demand, resource
availability, or other opportunities. Should economic or other factors warrant, any material
changes are communicated to senior management and Staff.
In addition to hedges, the Company’s procurement plan includes storage utilization and
daily/monthly index purchases. It is diversified through time, location, and counterparty
in accordance with Risk Management credit terms.

Market-Related Risks and Risk Management
There are several types of risk and approaches to risk management. The 2021 IRP
focuses on two areas of risk: the financial risk of the cost of natural gas to supply
customers will be unreasonably high or volatile, and the physical risk that there may not
be enough natural gas resources (either transportation capacity or the commodity) to
serve core customers.
Avista’s Risk Management Policy describes the policies and procedures associated with
financial and physical risk management. The Risk Management Policy addresses issues
related to management oversight and responsibilities, internal reporting requirements,
documentation and transaction tracking, and credit risk.
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Two internal organizations assist in the establishment, reporting and review of Avista’s
business activities as they relate to management of natural gas business risks:
• The Risk Management Committee includes corporate officers and senior-level
management. The committee establishes the Risk Management Policy and
monitors compliance. They receive regular reports on natural gas activity and meet
regularly to discuss market conditions, hedging activity and other natural gas-
related matters.
• The Strategic Oversight Group coordinates natural gas matters among internal
natural gas-related stakeholders and serves as a reference/sounding board for
strategic decisions, including hedges, made by the Natural Gas Supply
department. Members include representatives from the Gas Supply, Accounting,
Regulatory, Credit, Power Resources, and Risk Management departments. While
the Natural Gas Supply department is responsible for implementing hedge
transactions, the Strategic Oversight Group provides input and advice.

Strategic Initiatives
Strategic Initiatives are generally defined as the means through which a vision is
translated into practice. These initiatives are a group of projects and programs that are
outside of the organizations daily operational activities and help an organization achieve
a targeted performance.
The two primary roles of the Energy Resources Department (including Natural Gas
Supply) is two-fold:
1. Serve Load – Assure adequate and reliable energy supplies for Avista Utilities
natural gas customers.
2. Manage Resources – Exercise prudent stewardship of Avista Utilities energy
supply facilities and related Company resources.
Through the use of fixed-priced hedges, daily balancing transactions and storage
injections and withdrawals the Company can meet its obligation to serve load. In addition,
through our Dynamic Window Hedges and Risk Responsive Hedges, we are also able to
provide a level of price certainty in volatile commodity markets and reduce cost risk
exposure. Related to managing our resources, we have secured firm natural gas
transportation capacity in order to ensure we are able to reliably deliver the commodity to
our customers. Finally, we have secured a level of storage (through ownership at Jackson
Prairie) providing Avista with an additional level of firm supply and associated
transportation contracts.
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It is part of Avista’s culture to be good stewards of our customer’s resources. While there
is no “targeted performance level”, success is measured by the ability to capture benefit
from our existing resources to the best of our ability, which results in either lower overall
expenses for our customers or a higher level of price certainty. As such, we are
continuously monitoring the procurement plan, evolving market conditions, new supply
opportunities, and regulatory conditions.
Accordingly, effective in 2015 the Company implemented a new Storage Optimization
Model which meets the definition of “Strategic Initiative” as described above. Prior to the
implementation of the model, Storage had been utilized in the standard way – to purchase
natural gas in the spring and summer when prices are historically low, inject into Storage,
and withdraw in the winter when prices are historically high. Through the use of this
model, we are able to still provide reliability of supply for our customers, but also capture
benefits of price spreads between time periods. The model is governed by a storage
management program that sets boundaries on injections and withdrawals as well as
tracks real time market data to guide the purchase and sale of natural gas storage
transactions with favorable spreads. Through this model, the Company can purchase
natural gas in one period and sell into a higher priced market, effectively locking in a
benefit for our customers.
The program enforces storage constraints and requirements such as the storage fill
schedule, peak day load requirements, transportation capacity limits, and deliverability
constraints.
The Company also has mechanisms in place which allow us to optimize the value of our
existing pipeline and storage assets in order to reduce costs for customers until such
resources are required to meet demand. Should there be transportation capacity that is
not required to serve load, we may be able to optimize this capacity by purchasing natural
gas, transporting it, and selling it into a higher priced market. Commodity purchases and
sales are carefully tracked and allocated, or directly assigned, jurisdictionally based on
the unique characteristics of each individual pipeline capacity.4 Avista may also be able
to release a portion of this unutilized firm transportation capacity to third parties, further
reducing customer’s firm transportation expense.

4 Allocation between Washington and Idaho for Commodity purchases and sales is based on actual
calendar load for each respective month.
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Dynamic Window Hedges (DWH)

The DWH portion of the plan secures a pre-determined, minimum hedge portion for LDC
load with fixed priced purchases. These transactions are diversified in terms of time,
location and delivery period. The target delivery periods, development, procures, and
execution are described below. Dynamic Window Hedging reduces the cost risk and
increases the loss risk.5
The target delivery periods for the DWH portion of the Plan is for a period of 30 to 36
months depending on market availability of the hedging period (Figure 4.5).
Figure 4.5: Dynamic Window Hedging Plan

DWH Development
A DWH is defined by its set-price (SP), an upper control limit (UCL), a lower control limit
(LCL) and an expiration date. The SP is the closing price of the day prior to the window

5 Loss risk is the potential to pay more than the daily gas price with a forward hedge. Cost risk is the potential for daily
prices to rise above the hedge price.
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opening. The UCL and LCL are developed using quantitative mathematics to define
boundaries in relation to the SP. Expiration dates are determined based on the remaining
volumes to be hedged and remaining time to expiration. Each DWH’s SP is based upon
the closing price, of the selected supply basin for the delivery period. The supply basin
for each hedge window will be selected from available term markets, based on whichever
market has the highest volatility.
Hedge windows remain “open” as long as the previous day’s forward delivery period price
remains between the UCL and the LCL, and the window has not reached its time
expiration. The selected basin closing price will be the determining benchmark of the
forward delivery period price. Hedge window status is examined each business day. If
the hedge window’s current rate moved outside the UCL or LCL, a hedge transaction is
triggered, subject to execution provisions described later in this report. If a SP does not
move outside the UCL or LCL prior to time expiration, then the window’s hedge
transaction is executed on the expiration date.
Figure 4.6 shows a hedge which was executed for the Summer of 2022 (April – October)
time period and the associated limits.
Figure 4.6: Dynamic Window Hedge (April 2022 – October 2022)

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Risk Responsive Hedging Tool (RRHT)
In 2018, Gas Supply incorporated a Risk Responsive Hedging Tool in addition to the
Dynamic Window Hedges discussed above. The RRHT helps to manage the Value at
Risk (VaR) of Avista’s LDC natural gas portfolio’s open position on a daily basis. The
forward gas prices are the basis for the VaR analysis. The analysis utilizes a confidence
level and historic volatility to calculate a portfolio VaR, and combines it with the current
mark-to-market portfolio price to develop a price risk metric that is compared to a
predetermined threshold value (Operative Boundary). If the price metric exceeds the
Operative Boundary, then one or more hedges will be executed to bring the price metric
back within the Operative Boundary. In any case, hedge volumes should not exceed the
Maximum Hedge Ratio. Upon trigger, Gas Supply will begin to transact to bring the price
metric back within the Operative Boundary.
The Dynamic Window Hedging will continue to systematically hedge to a certain minimum
hedge level through the use of time limits and UCL/LCL. RRHT will monitor the market
financially and call for additional hedging if pre-determined risk tolerance limits are
triggered.
The RRHT includes all utility purchase and sales transactions, estimated customer load,
and storage injections and withdrawals to derive open positions (by basin) that are
marked to forward market prices. These monthly financial positions, along with market
volatility, are then used to calculate the Value at Risk (VaR) by basin, which in turn is
used to evaluate recommended hedging actions.

Supply Issues
The abundance and accessibility of shale gas has fundamentally altered North American
natural gas supply and the outlook for future natural gas prices. Even though the supply
is available and the technology exists to access it, there are issues that can affect the
cost and availability of natural gas.
Hydraulic Fracturing
Hydraulic fracturing (commonly referred to as fracking) was invented by Hubbert and
Willis of Standard Oil and Gas Corporation back in the late 1940’s. The process involves
a technique to fracture shale rock with a pressurized liquid. In the past 15 years, the
techniques and materials used have become increasingly perfected opening up large
deposits of shale gas formations at a low prices. The Energy Information Administration
(EIA) tracks production per well in the seven key oil and natural gas production formations
in the United States as shown in Figure 4.7. Figure 4.8 shows the continued increase in
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efficiency of production compared to just a year ago as shown by the EIA’s Drilling
Productivity Report 4.96.
Figure 4.7: Seven Major Drilling Regions in the United States

Figure 4.8: December 2020 Drilling Productivity Report, EIA7

With the increasingly prevalent use of hydraulic fracturing came concerns of chemicals
used in the process. The publicity caused by movies, documentaries and articles in

6 Drilling Productivity Report, https://www.eia.gov/petroleum/drilling/pdf/summary.pdf
7 www.eia.gov
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national newspapers about “fracking” has plagued the natural gas and oil industry. There
is concern that hydraulic fracturing is contaminating aquifers, increasing air pollution and
causing earthquakes. The actual cause of earthquakes is wastewater injection used in
operations at the well site. Based on research at the U.S. Geological Survey, only a small
number of these earthquakes are from fracking itself.8 Additionally, wastewater injections
are used for all well types, not just those where fracking is involved.
The wide-spread publicity generated interest in the production process and caused some
states to issue bans or moratoriums on drilling until further research was conducted. To
help combat these fears, Frac Focus9 was created and is a chemical disclosure registry
allowing users to view chemicals used by over 125,000 wells throughout North America.
This information, voluntarily submitted by Exploration and production companies,
provides a detailed list of materials used to frack each individual well.
Pipeline Availability
The Pacific Northwest has efficiently utilized its relatively sparse network of pipeline
infrastructure to meet the region’s needs. As the amount of renewable energy increases,
future demand for natural gas-fired generation will increase. Pipeline capacity is the link
between natural gas and power.
There are currently a few industrial plants being considered in the Pacific Northwest. The
project with the highest likelihood is the project located in Washington’s Port of Kalama.
This process uses large amounts of natural gas as a feedstock for creating methanol,
which is used to make other chemicals and as a fuel. At over 300,000 Dth per day this
plant would consume large amounts of natural gas.

Ongoing Activity
Without resource deficiencies or a need to acquire incremental supply-side resources to
meet peak day demands over the next 20 years, Avista will focus on normal activities in
the near term, including:
• Continue to monitor supply resource trends including the availability and price of
natural gas to the region, LNG exports, supply dynamics and marketplace, and
pipeline and storage infrastructure availability.

8 https://profile.usgs.gov/myscience/upload_folder/ci2015Jun1012005755600Induced_EQs_Review.pdf
9 https://fracfocus.org/
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• Monitor availability of resource options and assess new resource lead-time
requirements relative to resource need to preserve flexibility.
• Appropriate management of existing resources including optimizing underutilized
resources to help reduce costs to customers.
• Monitor renewable supply resource options, availability and pricing trends.

Conclusion
North American fossil natural gas supply continues to show its robustness in spite of
challenges it faces. Regional supply constraints are beginning to increase in their
likelihood causing prices to act in a more volatile fashion. This volatility in pricing paired
with supply side resource availability has made Avista’s procurement plan an increasingly
important piece to manage customer rates, diversity of supply and peak day demand.
Without new supply side resources, the region will face some difficult decisions in the
coming decades. This in combination with the optimization of our storage, transportation
and basin resources have helped Avista to provide natural gas reliably to our customers
at a fair and reasonable price.
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5: Carbon Reduction
Regulatory environments regarding energy topics such as renewable energy, carbon
reduction, carbon intensity and greenhouse gas regulation continue to evolve since
publication of the last IRP. Current and proposed regulations by federal and state
agencies, coupled with political and legal efforts, have implications for the reduction of
carbon in the natural gas stream.
Avista and Carbon Reduction:
Focus on solutions that balance carbon reduction, affordability, and reliability.

Avista’s Environmental Objective
Avista has always been on the forefront of clean energy and innovation. Founded on
clean, renewable hydro power on the banks of the Spokane River, Avista has maintained
a generation portfolio that is already more than half renewable, while continuously making
investments in new renewable energy, advancing the efficient use of electricity and
natural gas, and driving technology innovation that has enabled and will continue to
become the platform and gateway to a clean energy future.

Environmental Issues
The evolving and sometimes contradictory nature of environmental regulation from state
and federal perspectives creates challenges for resource planning. The IRP cannot add
renewables or reduce emissions in isolation from topics such as system reliability, least
cost requirements, price mitigation, financial risk management, and meeting changing
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environmental requirements. All resource choices have costs and benefits requiring
careful consideration of the utility and customer needs being fulfilled, their location, and
the regulatory and policy environment at the time of procurement.

Natural Gas System Emissions
Upstream emissions include any emission found upstream of the point of combustion and
includes production, processing, transmission and equipment. To fully account for
emissions in the natural gas stream the upstream emissions are now included in the totals
as measured in pounds of carbon dioxide equivalent. This becomes important when
placing a tax or cost of emissions on the price per Mmbtu. The emissions are measured
at the standard 100-year Global Warming Potential (GWP) meaning a 34 multiplier of the
heat that would be absorbed by the same mass of carbon dioxide. The levels of upstream
gas are determined by production region, specifically in Canada and the Rockies in the
United States and multiplied by the associated emissions estimate. Over the past five
years, nearly 90 percent of Avista’s natural gas was sourced from Canadian production
leaving roughly 10 percent of estimated upstream emissions to the Rockies region. When
combined with a 0.77 percent of Canadian production attributed to upstream emissions,
as calculated in a study for the Tacoma LNG project, the majority of Avista’s fossil fuel
natural gas is less intensive as compared to the fossil natural gas emissions from the
Rockies region of 1.0 percent as calculated in the EIA sinks and emissions estimates.
This estimate1 from the EIA is updated on a yearly basis and will show gains and losses
as they occur as compared to a point in time study.
The final upstream emissions from CH4 in carbon equivalent add nearly 10.66 pounds
per MMBtu as shown in Table 5.1:
Table 5.1: Avista Specific LDC Natural Gas Emissions
Avista Specific Natural Gas
Combustion Lbs. GHG/MMBtu Lbs. CO2e/MMBtu
CO2 116.88 116.88
CH4 0.0022 0.0748
N2O 0.0022 0.6556
Total Combustion 117.61
Upstream
CH4 0.313406851 10.66
Total 128.27

At a national level, overall methane emissions in the U.S. have been on the decline for
many decades. As illustrated in Figure 5.1, the EPA has estimated methane emissions
as decreasing by nearly 20 percent as compared to 1990. As coal fired plants have

1 Inventory of U.S. Greenhouse Gas Emissions and Sinks | Greenhouse Gas (GHG) Emissions | US EPA
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retired, production of electricity natural gas generation has dramatically increased to
cover this demand. Interestingly, during this reference period, production from natural gas
has more than doubled while total electric production increased 35 percent during this
same timeframe.
Figure 5.1: United States Methane Emissions

Carbon dioxide equivalent (CO2e) is the most common unit to measure climate warming.
In order to understand how different greenhouse gasses such as methane (CH4) and
nitrous oxide (N20) affect the earths warming a conversion must occur. As illustrated in
Table 5.2 below, the Intergovernmental Panel on Climate Change released their 5th
assessment study to help define these impacts to global warming in units of CO2e.
Table 5.2: Global Warming Potential (GWP) in CO2 Equivalent
5th Assessment of the Intergovernmental Panel on Climate Change
Greenhouse Gas GWP – 100 Year GWP – 20 Year
CO2 1 1
CH4 34 86
N2O 298 268

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Local Distribution Pipeline Emissions - Methane Study
In a study led by Washington State University (WSU), and sponsored by the
Environmental Defense Fund (EDF) and others, an estimate of utility pipeline distribution
systems leakage found that overall levels of leakage were around 0.1 percent to 0.2
percent of methane delivered nationwide. The study goes on to state that the Eastern
regions of the United States contribute much more methane to the total, as compared to
the Western regions, which were found to account for only 5 percent of these emissions
overall. The study theorizes that older infrastructure and material types are the likely
culprit, but also goes on to attribute regulations and better infrastructure and monitoring
by utilities for these decreased emissions. It found that “out of 230 measurements, three
large leaks accounted for 50 percent of the total measured emissions from pipelines
leaks. In these types of emission studies, a few leaks accounting for a large fraction of
total emissions are not unusual.”2
State and Regional Level Policy Considerations
The lack of a comprehensive federal greenhouse gas policy encouraged states, such as
California, to develop their own climate change laws and regulations. Climate change
legislation takes many forms, including economy-wide regulation under a cap and trade
system, a cap and reduce system, and a carbon tax. Comprehensive climate change
policy can include multiple components, such as renewable portfolio standards, DSM
standards, and emission performance standards. Individual state actions produce a
patchwork of competing rules and regulations for utilities to follow and may be particularly
problematic for multi-jurisdictional utilities such as Avista.

Idaho
Idaho Policy Considerations
Idaho does not regulate greenhouse gases. There is no indication Idaho is moving toward
regulation of greenhouse gas emissions beyond federal regulations.

Oregon
Oregon Policy Considerations
The State of Oregon has a history of greenhouse gas emissions and renewable portfolio
standards legislation. In March of 2020, Governor Brown signed into law Executive Order
(EO) 20-04 requiring the reduction of greenhouse gas emissions to at least 45 percent
below 1990 levels by 2035 and 80 percent below 1990 levels by 2050. This EO requires
the reductions statewide by all carbon emitting sources and managed by the respective
emissions sources governing agencies. State agencies are directed to exercise any and
all authority to achieve GHG emissions reduction goals expeditiously. Many specifics of

2 https://methane.wsu.edu
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this EO will be taking shape in the upcoming year including systems, carbon costs,
programs such as to a cap and reduce program to buy or sell offsets and many other
complexities of an endeavor of this magnitude.
Oregon SB 334
In Oregon, Senate Bill 3343 was passed in to help develop, update, and maintain the
biogas inventory available. This includes the sites and potential production quantities
available in addition to the quantity of renewable natural gas available for use to reduce
greenhouse gas emissions. This bill will also help promote RNG and identify the barriers
and removal of barriers to develop and utilize RNG. In September 2018 the Oregon
Department of Energy issued the report to the Oregon legislature titled “Biogas and
Renewable Natural Gas Inventory.”
Oregon SB 844
Senate bill 844 passed in 2013 with rulemaking following under AR 580, placed into effect
in December of 2014. This bill directed the OPUC to establish a voluntary emission
reduction program and criteria for the purpose of incentivizing public natural gas utilities
to invest in emission reducing projects providing benefits to their respective customers.
The public utility, without the emission reduction program, would not invest in the project
in the ordinary course of business.
To date, this legislation has not yielded any emission reducing projects. Avista is aware
that Governor Brown’s Executive Order 20-04 has the OPUC reconsidering the
usefulness of SB844.
Oregon SB 98 & AR 632 Rule Making
Oregon Senate Bill 98 passed during the 2019 regular session and mandates the Oregon
Public Utility Commission (PUC) “to adopt by rule a renewable natural gas program for
natural gas utilities to recover prudently incurred qualified investments in meeting certain
targets for including renewable natural gas purchases for distribution to retail natural gas
customers.”
The Oregon PUC initiated the AR 632 rulemaking process in late 2019 with a series of
public workshops. This collaborative process with various stakeholder involvement and
input concluded in the spring of 2020. Final rules were made effective on July 17, 2020.
The rule allows investment recovery. In order to participate in Oregon’s SB 98 RNG
Program, a petition to participate is required. Small utilities desiring to participate are
required to define their respective percent of revenue requirement per year needed to
support potential project investment costs. The bill allows investment in gas conditioning
equipment without RFP process. Per AR 632 the RNG attributes will be tracked by the

3 https://olis.leg.state.or.us/liz/2017R1/Downloads/MeasureDocument/SB334
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M-RETS system as renewable thermal certificates (RTC) in which (1) RTC = (1)
Dekatherm of RNG.

Washington
Washington State Policy Considerations4
In December 2020 a State Energy Strategy was released as a roadmap that commits
Washington to reducing greenhouse gas emissions:
• By 2030 a 45% reduction below 1990 levels
• By 2040 a 70% reduction below 1990 levels
• By 2050 a 95% reduction below 1990 levels and net-zero emissions
Washington HB 2580
Washington State House Bill 25805 was signed by Governor Jay Inslee on March 22,
2018 and will become effective on July 1, 2018 bringing into law a bill to help encourage
production of renewable natural gas (RNG). This bill requires the Washington State
University Extension Energy Program and the Department of Commerce (DOC) along
with the consulting of the Washington State Utilities and Transportation Commission, to
submit recommendations on promoting the sustainable development of RNG. The DOC
will consult with natural gas utilities and other state agencies to explore developing
voluntary gas quality standards for the injection of RNG into natural gas pipeline systems
in the state.
Washington HB 1257
The bill passed during the 2019 Regular Session, coined the “Building Energy Efficiency”
bill, mandates that each gas company must offer by tariff a voluntary renewable natural
gas service. The bill also allows for LDCs to create an RNG program to supply a portion
of the natural gas to customers. This program is subject to review and approval by the
UTC. With regard to natural gas distribution companies, this bill was designed for the
purpose of establishing “efficiency performance requirements for natural gas distribution
companies, recognizing the significant contribution of natural gas to the state’s
greenhouse gas emissions, the role that natural gas plays in heating buildings and
powering equipment within buildings across the state, and the greenhouse gas reduction
benefits associated with substituting renewable natural gas for fossil fuels.”
Section 12 of the bill “finds and declares that:

4 2021 State Energy Strategy - Washington State Department of Commerce
5 http://apps2.leg.wa.gov/billsummary?Year=2017&BillNumber=2580&Year=2017&BillNumber=2580
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a) Renewable natural gas provides benefits to natural gas utility customers and to
the public;
b) The development of RNG resources should be encouraged to support a smooth
transition to a low carbon energy economy in Washington;
c) It is the policy of the state to provide clear and reliable guidelines for gas
companies that opt to supply RNG resources to serve their customers and that
ensure robust ratepayer protections.”
Section 13 of the bill allows LDC’s to propose an RNG program under which the company
would supply RNG for a portion of the natural gas sold or delivered to its retail customers.
Section 14 of the bill states that LDC’s must offer by tariff a voluntary RNG service
available to all customers to replace any portions of the natural gas that would otherwise
be provided by the gas company.
HB 1257 provided limited direction and the necessary details to advance RNG programs
and projects. As such, there has been an effort on behalf of the impacted utilities to
provide the commission with feedback and clarity with respect to gas quality and cost
treatment. More specifically, the Northwest Gas Association (NWGA) has collaborated
with Washington LDC’s to develop a common Gas Quality Standard Framework, and
proposed language defining the treatment of RNG program costs.
On December 16, 2020, the Washington UTC issued a Policy Statement to provide
guidance with respect to the following elements of HB 1257 as follows; General Program
Design, RNG Program cost cap, Voluntary Program cost treatment, gas quality
standards, and pipeline safety, environmental attributes and carbon intensity, renewable
thermal credit (RTC) tracking, banking and verification.
RNG at Avista
Avista has been preparing for RNG. A new RNG Program, RNG Manager, and a cross-
functional working team has been assembled and includes representatives from Gas
Engineering, Gas Supply, Legal, Governmental Affairs, Regulatory Affairs, Products &
Services, Business Development & Strategy, Corporate Communications, and
Environmental. This team meets on a routine basis for program and project updates and
coordination purposes. Additionally, internal efforts to prepare for and advance RNG
include but are not limited to; draft charter document, draft business cases for use in
Capital Budget Planning process, internal communications, gas quality, interconnection
requirements, and business development efforts in pursuit of potential RNG projects.

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Program Considerations
As Avista prepares to move forward with RNG, some of the primary considerations given
are as follows:
• Evaluate available RNG procurement options
• Pursue potential RNG development opportunities from local RNG feedstock
resources under new legislation (Washington HB 1257 & Oregon SB 98)
• Develop an understanding of RNG development cost, cost recovery impacts to
customers, resulting supply volumes and RNG costs
• Evaluate potential RNG customer market demands vs. supply
• Participation in rule making and policy:
• Participation in HB 1257 Policy development
• Participation in SB 98 Policy Rulemaking via AR 632 informal and formal
• Cost recovery proposal led by NWGA with input from all four Washington LDC’s
• Collaborative RNG Gas Quality Framework established across four Washington
LDC’s
Pipeline Safety & Interconnection Requirements
Avista’s Gas Engineering Department has researched and learned about gas quality,
testing, and interconnection requirements from those at the forefront of the RNG industry.
Additionally, through a collaborative effort coordinated by the Northwest West Gas
Association (NWGA), all four Washington LDC’s have developed a common Gas Quality
Framework which is now that basis for Avista’s Gas Quality Specification. The
development of Interconnection requirements and draft contractual language has also
been developed and has taken form as an Interconnection Agreement template. Other
procedural documents such as an Interconnection Study Agreement and RNG
Interconnection Request Form have been developed.
RNG workshops and rulemaking
In addition to participating in RNG industry workshops and conferences to learn how
others are implementing RNG projects and programs, Avista has actively participated in
Oregon SB 98 informal and formal rulemaking, and Washington HB 1257 workshops
including collaborative efforts with the NWGA to develop a common Gas Quality
Framework, and proposed cost cap language.

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Utility RNG Projects
RNG projects require feedstocks that are not always readily available and feedstock
owners who are willing to partner with an LDC. Even with potential willing feedstock
partners, Avista recognizes many practical complexities associated with developing RNG
projects as well as the many benefits. The following examples are based on what we
have learned during our business development efforts;
• New legislation allows LDC’s to invest in RNG infrastructure projects with
feedstock partners
• LDC’s are credit worthy partners offering long term off-take contracts to feedstock
owners
• Each RNG project is unique with respect to capital development costs & resulting
RNG costs
• Each RNG project will vary in size, location, and distance to interconnection
pipeline, feedstock type, gas conditioning equipment and requirements, and
operating costs
• Economies of scale – Low volume biogas opportunities face economic challenges
• The utility cost of service model is typically a foreign concept to feedstock owners,
requiring an educational process to get them comfortable
• Feedstock owners over-valuing their biogas can degrade project economics
• New RNG Projects can take 3-4 years to develop given myriad factors. A new
RNG project is a multi-year endeavor involving the usual phases expected for
major capital construction projects, coupled with many first ever discussions
between the utility and the feedstock owner, a new regulatory process and
program requirements, the identification of customer cost impacts, environmental
benefits, and tracking process just to name a few
• Customers have paid for a vast pipeline infrastructure that can be utilized for a
cleaner future by transitioning the fuel and keeping the pipe

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Project Evaluation - Build or Buy
Avista recognizes the two primary options to procure RNG; build RNG project(s) or buy
RNG. In the build scenario, new RNG facilities are developed, and the costs are
recovered the through AAC or GRC. Avista can also buy RNG from other RNG producers
and pass the costs through the GPA.
Build
Both Oregon SB 98 and Washington HB 1257 are both focused on decarbonization for
the greater good of society and both pieces of legislation clearly support the development
of new RNG infrastructure and RNG resources by allowing utility companies (LDC’s) to
build and deliver RNG on a utility cost-of-service model for utility customer building heat
usage. Both allow the recovery of investments through an AAC or GRC. Avista believes
the “build” option best meets the intent of the legislation as it affords a higher level of cost
control through the elimination of for-profit intermediary burdens, delivering RNG to
customers at the true cost. Further, local projects contribute to improved local air quality,
and support the local economy during construction and during annual operations.
Naturally, feedstock biogas royalties are expected to be a key factor in project economics,
as will operating costs including power, conditioning equipment type, interconnection
pipeline distance and cost. Since utility companies are institutional credit worthy partners
that can offer long term off-take contracts for biogas, it is expected that these types of
arrangements will be desirable with feedstock owners, and that long-term arrangements
will temper biogas royalty pricing. Ultimately the utility customer benefits from this
scenario.
Buy
The new legislation in Oregon and Washington is an intentional shift away from the
transportation market and opens the door for a new renewable thermal credit (RTC)
market which is not intended to compete with the existing heavily subsidized
transportation markets, federal and state alike. In the short term, and since the
transportation and utility markets are in conflict with respect to RNG values, the
procurement of RNG for utility use is an inherent challenge for utility use.
At Avista, we expect our voluntary RNG program demands to be limited volumes, and
short-term in nature in the initial years. Since a short-term, low-volume off-take purchase
scenario is not likely to be attractive to producers that typically seek long-term off-take
agreements, the expectation is higher RNG costs. Given the nature of this temporary
interim situation, a short-term voluntary pilot program in which off-take volumes may be
procured from a local producer with excess supply, at a negotiated price may be
advantageous.

This strategy will allow Avista to ramp-up and learn more about our new first ever
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voluntary RNG program and minimize risk until at a point in time in which Avista can
supply RNG from new RNG infrastructure investment projects.
Voluntary RNG Programs
Avista’s Products and Services Department will be developing Avista’s first ever voluntary
RNG product. To date the following market studies and observations have been
completed:
• RNG Commercial Market Study completed in 2019
• RNG Residential Market Survey concluded in September 2020
• Customers lack understanding of RNG since it is a new concept
• Customers like the environmental aspects of RNG
• Customers like to choose their level of participation to manage costs predictably
The voluntary customer RNG program design will advance based on the studies above.
Estimated voluntary customer program demands are yet to be defined, however volumes
are expected to be very small initially. Eventually, Avista is looking forward to adding RNG
to Avista’s renewables portfolio.
Cost Effective Evaluation Methodology
At Avista, developing a methodology has been a work in process. To date, the
methodology shown is derived from OPUC UM2030, also referenced in the OPUC SB 98
AR 632 Rulemaking. The evaluation method shown herein is subject to input, refinement
and reconsideration (Figure 5.2).

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Figure 5.2: Avista Renewable Resource Development and Procurement Decision
Tree – Part 16

6 The Avista Renewable Resource Development and Procurement Decision Tree described above is a
work in progress and is subject to change at any time.
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Figure 5.3: Avista Renewable Resource Development and Procurement Decision
Tree – Part 2

In-depth descriptions of the calculations and components used in the Avista Renewable
Resource Development and Procurement Decision Tree are in Appendix 5.
Environmental Attribute Tracking
Oregon SB 98 specifies M-RETS as the third-party entity designated to manage
environmental attribute tracking and banking. M-RETS will utilize a proprietary
transparent electronic certificate tracking system in which (1) renewable thermal
certificate (RTC) is equal to (1) dekatherm (Dth) of RNG per the OPUC.
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Given the Oregon requirement, and in lieu of contracting with another vendor for the
tracking and banking of Washington environmental attributes, Avista will likely use M-
RETS for Washington RNG attributes.
The California RNG market will continue to be a major draw for renewable resources due
to the low carbon fuel standard (LCFS) in addition to the federal RIN market. These
incentives can bring the value of these specific renewable resource attributes to many
multiples of conventional natural gas prices. While the market has volatility based on
demand, the primary issue of bringing additional projects into the market are based on
the unknowns as related to the market itself. There are currently no forward prices for
these renewable credits and the environmental attribute value for local markets is
unidentified. These are just a few of the major obstacles potential producers run into
when looking for financing of their projects.
A potential solution to some of these unknowns in the market are through utility RNG
projects. These feedstock owners would now be able to partner with LDC’s to cultivate
new RNG projects. The obstacle of financing becomes less of an issue as most LDC’s
are credit worthy and can provide a measure of certainty with long term offtake
agreements. This concept would test the project owner’s willingness to partner with the
utility’s cost of service model, which is a foreign concept when seeking the highest value
for their biogas.
Developing a generic cost for RNG based on feedstock will require several assumptions
as each specific RNG project will have its own capital development costs. Each RNG
project will vary in size, location and distance to interconnection pipeline, feedstock type,
gas conditioning equipment and requirements and operating costs. In general terms, new
RNG projects can take 2-3 years to develop depending on size and scope.
Hydrogen
Hydrogen is a fuel source with a long history and a great potential to help solve f uture
energy needs. Its energy factor, as measured in a kilogram (kg) of low heating value
(LHV), is roughly equivalent to a gallon of gasoline. While hydrogen can be made from
any energy source including nuclear (pink H2) and electric renewables (green H2), most
is currently made by reforming natural gas, also known as grey H2. The high cost of this
energy has been the primary barrier to an accelerated use and adoption. With expanding
renewable electricity production, the ability to create green H2 with excess renewable
electricity is moving from concept to market throughout the world. While it is assumed
hydrogen can only be mixed and stored in a natural gas distribution pipeline system as a
small percentage of the total volume of gas in the pipe, it can be combined with a carbon
dioxide source first to produce methane, referred to as methanation, and then injected in
a natural gas pipe without limits on the percent in the gas stream. This process of using
power to separate water into hydrogen and oxygen is known as power to gas. This
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process can provide seasonal energy storage needs while providing a useful product
based on when renewable electricity is being produced.

Conclusion
Avista views RNG and low carbon fuels as an important component of its corporate
environmental strategy and decarbonization goals. By utilizing waste streams to create
green fuel, RNG and H2 both support Avista’s environmental strategy and will provide
Avista’s customers with a new environmentally friendly, low carbon fuel choice, delivered
seamlessly via Avista’s existing natural gas system.

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6: Integrated Resource Portfolio
Overview
This chapter combines the previously discussed IRP components and the model used to
determine resource deficiencies during the 20-year planning horizon. This chapter
provides an analysis of potential resource options to meet resource deficiencies as
exhibited in the High Growth, Low Prices scenario and the Carbon Reduction scenario.
The foundation for integrated resource planning is the criteria used for developing
demand forecasts. The weather planning standard has been updated in the current IRP
cycle. The new planning standard has Avista moving away from coldest on record and
into a 99 percent probability of a daily temperature occurring. Avista plans to serve
expected peak day in each demand region with firm resources. Firm resources include
natural gas supplies, firm pipeline transportation and storage resources. In addition to
peak requirements, Avista also plans for non-peak periods such as winter, shoulder
months (April and October) and summer demand. The modeling process includes an
optimization for every day of the 20-year planning period.
It is assumed that on a peak day all interruptible customers have left the system to provide
service to firm customers. Avista does not make firm commitments to serve interruptible
customers, so IRP analysis of demand-serving capabilities only includes the firm
residential, commercial and industrial classes. Using the weather planning standard, a
blended price curve of three studies developed by industry experts, and an academically
backed customer forecast all work together to develop stringent planning criteria.
Forecasted demand represents the amount of natural gas supply needed. In order to
deliver the forecasted demand, the supply forecast needs to increase between 1.0
percent and 3.0 percent on both an annual and peak-day basis to account for additional
supplies purchased primarily for pipeline compressor station fuel. The range of 1.0
percent to 3.0 percent, known as fuel, varies depending on the pipeline. This fuel is used
to move the gas from point A on the pipeline to point B or the delivery point. The FERC
and National Energy Board approved tariffs govern the percentage of required additional
fuel supply.

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SENDOUT® Planning Model
SENDOUT® is a linear programming model used to solve natural gas supply and
transportation optimization questions. Linear programming is a proven technique to solve
minimization/maximization problems. SENDOUT® analyzes the complete problem at one
time within the study horizon, while accounting for physical limitations and contractual
constraints.
The software analyzes thousands of variables and evaluates possible solutions to
generate a least cost solution given a set of constraints. The model considers the
following variables:
• Demand data, such as customer count forecasts and demand
coefficients by customer type (e.g., residential, commercial and
industrial).
• Weather data, including minimum, maximum and average
temperatures.
• Existing and potential transportation data which describes the network
for physical movement of natural gas and associated pipeline costs.
• Existing and potential supply options including supply basins, revenue
requirements as the key cost metric for all asset additions and prices.
• Natural gas storage options with injection/withdrawal rates, capacities
and costs.
• Conservation potential.

Figure 6.1 is a SENDOUT® network diagram of Avista’s demand centers and resources.
This diagram illustrates current transportation and storage assets, flow paths and
constraint points.

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Figure 6.1 SENDOUT® Model Diagram

The SENDOUT® model provides a flexible tool to analyze scenarios such as:
• Pipeline capacity needs and capacity releases;
• Effects of different weather patterns upon demand;
• Effects of natural gas price increases upon total natural gas costs;
• Storage optimization studies;
• Resource mix analysis for conservation;
• Weather pattern testing and analysis;
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• Transportation cost analysis;
• Avoided cost calculations; and
• Short-term planning comparisons.

SENDOUT® also includes Monte Carlo capabilities, which facilitates price and demand
uncertainty modeling and detailed portfolio optimization techniques to produce probability
distributions. More information and analytical results are located in Chapter 7 – Alternate
Scenarios, Portfolios and Stochastic Analysis. The SENDOUT® model is used by LDC’s
across the U.S., however it is becoming increasingly outdated for the current regulatory
environment when it comes to carbon reduction. Because of this enhanced need for
modeling software, Avista is planning on replacing SENDOUT® as stated in Chapter 9 –
Action Plan.

Resource Integration
The following sections summarize the comprehensive analysis bringing demand
forecasting and existing and potential supply and demand-side resources together to form
the 20-year, least-cost plan. Chapter 2 - Demand Forecasts describes Avista’s demand
forecasting approach.
Avista forecasts demand in the SENDOUT® model in eleven service areas given the
existence of distinct weather and demand patterns for each area and pipeline
infrastructure dynamics. The SENDOUT® areas are Washington and Idaho (each state
is disaggregated into three sub-areas because of pipeline flow limitations and the ability
to physically deliver gas to an area); Medford (disaggregated into two sub-areas because
of pipeline flow limitations); and Roseburg, Klamath Falls and La Grande. In addition to
area distinction, Avista also models demand by customer class within each area. The
relevant firm customer classes are residential, commercial and industrial customers.
Customer demand is highly weather-sensitive. Avista’s customer demand is not only
highly seasonable, but also highly variable. Figure 6.2 captures this variability showing
monthly system-wide average demand, minimum demand day observed by month,
maximum demand day observed in each month, and winter projected peak day demand
for the first year of the Expected Case forecast as determined in SENDOUT®.

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Figure 6.2: Total System Average Daily Load (Average, Minimum and Maximum)

Natural Gas Price Forecasts
Natural gas prices play an integral role in the development of the IRP. It is the most
significant variable in determining the cost-effectiveness of DSM measures and of
procuring new resources. The price of natural gas also influences consumption through
price elasticity, which affects demand in Avista’s natural gas service territories.
The natural gas price outlook has changed dramatically in recent years in response to
several influential events and trends affecting the industry, including improved drilling
methods and technology used in oil and natural gas production, increasing exports to
Mexico, and LNG. These factors, in addition to more stringent renewable energy
standards and increased need for natural gas-fired generation to back up such resources,
are contributing to the rapidly changing natural gas environment. The uncertainty in
predicting future events and trends requires modeling a range of forecasts.
Many additional factors influence natural gas pricing and volatility, such as regional supply
and demand issues, weather conditions, storage levels, natural gas-fired generation,
infrastructure disruptions, and infrastructure additions, such as new pipelines and LNG
terminals. Estimates of these supply resource additions vary between studies as does the
study date and ultimately drive the primary differences between sources in pricing
expectations.
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Although Avista closely monitors these factors, we cannot accurately predict future prices
across the 20-year horizon of this IRP. As a result, several price forecasts from credible
industry experts were used in developing the price forecasts considered in this IRP.
Figure 6.3 depicts the annual average prices of these forecasts in nominal dollars and
includes the expected price resulting from a blending technique.
Figure 6.3: Henry Hub Forecasted Price (Nominal $/Dth)

Expected prices at Henry Hub were derived through a blend of forecasts from four
sources, including the New York Mercantile Exchange (NYMEX) forward strip on June
30, 2020, the Energy Information Administration’s (EIA) 2020 Annual Energy Outlook
(AEO), and two reputable market consultants. Combining an ensemble of forecasts
improves the accuracy of our model based on the premise that the aggregate market
knows more than any single entity or model.
The weightings applied to each source vary throughout the twenty-year forecasting
horizon. Due to the high volume of market transactions, expected prices align completely
with those of the NYMEX forward strip in the first two years. From 2023 through 2025,
market activity and speculation on the NYMEX deteriorate significantly, so forecasts from
the other three sources, proportionally, are applied incrementally more weighting. By the
year 2026, and through the end of our forecasting horizon, the expected price is the result
of an equally weighted blend of forecasts from the EIA’s AEO and our two market
consultants. The specific weightings applied are described in Table 6.1 and the resulting
annual average expected price at Henry Hub is depicted in Figure 6.4 below.
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Table 6.1: Price Blend Methodology
Years Price Blend Methodology
2021 & 2022 forward price only
2023 forward price / 25% average consultant
forecasts
2024 50% forward price / 50% average consultant
forecasts
2025 25% forward price / 75% average consultant
forecasts
2026 - 2040 100% average consultant forecasts

Figure 6.4: Expected Price with Allocated Price Forecast

To accommodate for the likelihood that the expected prices at Henry Hub do not perfectly
reflect future natural gas prices and to help measure price risk in resource planning, a
stochastic analysis of 1,000 possible futures were modeled based on the expected price
forecast. Each future contains unique monthly price movements throughout the twenty-
year forecasting horizon. With the assistance of the TAC, Avista selected the 95th and
25th highest prices in each month from the stochastic results to determine high and low
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price curves, respectively. The high, expected, and low price curves in nominal dollars
are illustrated in Figure 6.5 below.
Figure 6.5: Henry Hub Forecasts for IRP Low/ Expected/ High Forecasted Price –
Nominal $/Dth

Henry Hub is located in southeastern Louisiana, near the Gulf of Mexico. It is recognized
as the most important pricing point in the U.S. due to its proximity to a large portion of
U.S. natural gas production and the sheer volume traded in the daily, or spot, market and
forward markets via the NYMEX futures contracts. Consequently, prices at other trading
points tend to follow the Henry Hub with a positive or negative basis differential. Of the
two market consultants Avista uses, only one forecasts basis pricing at the gas hubs
modeled throughout the twenty-year horizon.
The natural gas hubs at Sumas, AECO, and the Rockies (and other secondary regional
market hubs) determine Avista’s costs. Prices at these points typically trade at a discount,
or negative basis differential, to Henry Hub because of their proximity to the largest natural
gas basins in North America (Western Canada and the Rockies). Figure 6.6 below shows
the resulting regional prices as compared to the Henry Hub.

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Figure 6.6: Regional Price as a compared to the Henry Hub Price

Carbon Policy Resource Utilization Summary
Avista uses an estimated carbon price as an incremental adder to address any potential
policy. Carbon adders increase the price of a dekatherm of natural gas and impact
resource selections and demand through expected elasticity (Chapter 2 – Demand
Forecasts, Price Elasticity). Oregon was assumed to have a cap and reduce market as
estimated by Wood Mackenzie, through a cap and trade estimate, and presented to the
TAC on September 30, 2020. In this price estimate, the initial level starts low per
MTCO2e at around $15.83, rising to $97.90 by 2040. The cap and reduce market
discussed in Oregon’s EO 20-041 is still under development at the time of this filing
making modeling of a market price difficult. Washington State was modeled at $79.86
per MTCO2e starting in 2021 and rising to $158.06 per MTCO2e by 2040. These
carbon tax figures are based on the requirement to utilize SCC at 2.5% discount
estimates from the EPA as required by RCW 80.28.395. The State of Idaho does not
have a carbon adder as there is no current or proposed state or federal legislation
associated with carbon in that jurisdiction.

Avista also completed sensitivities to account for risk including a lower and higher than
expected price of carbon and are applied to all three jurisdictions. The low carbon price
is assumed at $0, or no cost, of carbon to help measure the risk of a continued stalemate

1 https://www.oregon.gov/gov/Documents/executive_orders/eo_20-04.pdf
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with carbon pricing. The high carbon price is the EPA’s high impact scenario of the
average of 95 percent of results at a 3 percent discount rate. This rate produces a much
higher cost of carbon beginning in 2021 at $151.01 and increasing to $219.33 per
MTCO2e by 2040. The effect of these modeled carbon prices, combined with our
expected elasticity as described in Chapter 2 Demand Forecasts, change demand as
shown in Figure 6.7.
Figure 6.7: Carbon Legislation sensitivities

Transportation and Storage
Valuing natural gas supplies is a critical first step in resource integration. Equally
important is capturing all costs to deliver the natural gas to customers. Daily capacity of
existing transportation resources (described in Chapter 4 – Supply-Side Resources) is
represented by the firm resource duration curves depicted in Figures 6.8 and 6.9.

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Figure 6.8: Existing Firm Transportation Resources – Washington & Idaho

Figure 6.9: Existing Firm Transportation Resources – Oregon

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Current rates for capacity are in Appendix 6.1 – Monthly Price Data by Basin. Forecasting
future pipeline rates can be challenging because of the need to estimate the amount and
timing of rate changes. Avista’s estimates and timing of future pipeline rate increases are
based on knowledge obtained from industry discussions and participation in pipeline rate
cases. This IRP assumes pipelines will file to recover costs at rates equal to increases in
GDP (see Appendix 6.2 – Weighted Average Cost of Capital).

Demand-Side Management
Chapter 3 – Demand-Side Resources describes the methodology used to identify
conservation potential and the interactive process that utilizes avoided cost thresholds for
determining the cost effectiveness of conservation measures on an equivalent basis with
supply-side resources.

Demand Results
After incorporating the above data into the SENDOUT® model, Avista generated an
assessment of demand compared to existing resources for several scenarios. Chapter 2
– Demand Forecasts discusses the demand results from these cases, with additional
details in Appendices 2.1 through 2.9.
Figures 6.10 through 6.13 provide graphic summaries of Average Case demand as
compared to existing resources on a peak day. This demand is net of conservation
savings and shows the adequacy of Avista’s resources under normal weather conditions.
For this case, current resources meet demand needs over the planning horizon.

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Figure 6.10: Average Case – Washington/Idaho Existing Resources vs. Average
Demand – February 28th

Figure 6.11: Average Case – Medford / Roseburg Existing Resources vs. Average
Demand – December 20th

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Figure 6.12: Average Case – Klamath Falls Existing Resources vs. Average
Demand – December 20th

Figure 6.13: Average Case – La Grande Existing Resources vs. Average Demand
February 28th

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Figures 6.14 through 6.17 summarize Expected Case peak day demand compared to
existing resources, as well as demand comparisons to the 2018 IRP. This demand is net
of conservation savings. Based on this information Avista has time to carefully monitor,
plan and analyze potential resource additions as described in the Ongoing Activities
section of Chapter 9 – Action Plan. Any underutilized resources will be optimized to
mitigate the costs incurred by customers until the resource is required to meet demand.
This management, of both long- and short-term resources, ensures the goal to meet firm
customer demand in a reliable and cost-effective manner as described in Supply Side
Resources – Chapter 4.
Figure 6.14: Expected Case – Washington & Idaho Existing Resources vs. Peak
Day Demand – February 28th

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Figure 6.15: Expected Case – Medford / Roseburg Existing Resources vs. Peak
Day Demand – December 20th

Figure 6.16: Expected Case – Klamath Falls Existing Resources vs. Peak Day
Demand – December 20th

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Figure 6.17: Expected Case – La Grande Existing Resources vs. Peak Day
Demand – February 28th

If demand grows faster than expected, the need for new resources will be earlier. Flat
demand risk requires close monitoring for signs of increasing demand and reevaluation
of lead times to acquire preferred incremental resources. The monitoring of flat demand
risk includes a reconciliation of forecasted demand to actual demand on a monthly basis.
This reconciliation helps identify customer growth trends and use-per-customer trends. If
they meaningfully differ compared to forecasted trends, Avista will assess the impacts on
planning from procurement and resource sufficiency standing.
Table 6.2 quantifies the forecasted total demand net of conservation savings and
unserved demand from the above charts.

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Table 6.2: Peak Day Demand – Served and Unserved (MDth/day)

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New Resource Options
When existing resources are insufficient to meet expected demand, there are many
important considerations in determining the appropriateness of potential resources.
Interruptible customers’ transportation may be cut, as needed, when resources are not
sufficient to meet firm customer demand.
Resource Cost
Resource cost is the primary consideration when evaluating resource options, although
other factors mentioned below also influence resource decisions. Newly constructed
resources are typically more expensive than existing resources, but existing resources
are in shorter supply. Newly constructed resources provided by a third party, such as a
pipeline, may require a significant contractual commitment. However, newly constructed
resources are often less expensive per unit, if a larger facility is constructed, because of
economies of scale.
Lead Time Requirements
New resource options can take one to five or more years to put in service. Open season
processes to determine interest in proposed pipelines, planning and permitting,
environmental review, design, construction, and testing contribute to lead time
requirements for new facilities. Recalls of released pipeline capacity typically require
advance notice of up to one year. Even DSM programs can require significant time from
program development and rollout to the realization of natural gas savings.
Peak versus Base Load
Avista’s planning efforts include the ability to serve firm natural gas loads on a peak day,
as well as all other demand periods. Avista’s core loads are considerably higher in the
winter than the summer. Due to the winter-peaking nature of Avista’s demand, resources
that cost-effectively serve the winter without an associated summer commitment may be
preferable. Alternatively, it is possible that the costs of a winter-only resource may exceed
the cost of annual resources after capacity release or optimization opportunities are
considered.
Resource Usefulness
Available resources must effectively deliver natural gas to the intended region. Given
Avista’s unique service territories, it is often impossible to deliver resources from a
resource option, such as storage, without acquiring additional pipeline transportation.
Pairing resources with transportation increases cost. Other key factors that can contribute
to the usefulness of a resource are viability and reliability along with carbon intensity. If
the potential resource is either not available currently (e.g., new technology) or not reliable
on a peak day (e.g., firm), they may not be considered as an option for meeting unserved
demand.
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“Lumpiness” of Resource Options
Newly constructed resource options are often “lumpy.” This means that new resources
may only be available in larger-than-needed quantities and only available every few
years. This lumpiness of resources is driven by the cost dynamics of new construction,
where lower unit costs are available with larger expansions and the economics of
expansion of existing pipelines or the construction of new resources dictate additions
infrequently. The lumpiness of new resources provides a cushion for future growth.
Economies of scale for pipeline construction provide the opportunity to secure resources
to serve future demand increases.
Competition
LDCs, end-users and marketers compete for regional resources. The Northwest has
efficiently utilized existing resources and has an appropriately sized system. Currently,
the region can accommodate the regional demand needs. However, future needs vary,
and regional LDCs may find they are competing with other parties to secure firm
resources for customers. RNG resources specifically will have an increased amount of
competition as the drive for carbon reducing supplies increases with associated policy.
Risks and Uncertainties
Investigation, identification, and assessment of risks and uncertainties are critical
considerations when evaluating supply resource options. For example, resource costs
are subject to degrees of estimation, partly influenced by the expected timeframe of the
resource need and rigor determining estimates, or estimation difficulties because of the
uniqueness of a resource. Lead times can have varying degrees of certainty ranging from
securing currently available transport (high certainty) to building underground storage
(low certainty).

Demand-Side Resources
Integration by Price
As described in Chapter 3 – Demand-Side Resources, the model runs without future DSM
programs. This preliminary model run provides an avoided cost curve for both Applied
Energy Group (AEG) and Energy Trust of Oregon (ETO) to evaluate the cost
effectiveness of DSM programs against the initial avoided cost curve using the Utility Cost
Test, Program Administrator Costs Test, Total Resource Cost Test, and Participant Cost
Test. The therm savings and associated program costs are incorporated into the
SENDOUT® model. After incorporation, the avoided costs are re-evaluated. This process
continues until the change in avoided cost curve is immaterial.
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Avoided Cost
The SENDOUT® model determined avoided-cost figures represent the unit cost to serve
the next unit of demand with a supply-side resource option during a given period. If a
conservation measure’s total resource cost (Oregon), or utility cost (for Idaho and
Washington), is less than this avoided cost, it will be cost effective to reduce customer
demand and Avista can avoid commodity, storage, transportation and other supply
resource costs while reducing the risk of unserved demand in peak weather.
SENDOUT® calculates marginal cost data by day, month and year for each demand area.
A summary graphical depiction of avoided annual and winter costs for each jurisdictional
area is in Figure 6.18. The detailed data is in Appendix 6.4 – Avoided Cost Details. Other
than the carbon tax adder, avoided costs include additional environmental externality
adders for adverse environmental impacts. Appendix 3.2 – Environmental Externalities
discusses this concept more fully and includes specific requirements required in modeling
for the Oregon service territory.
Figure 6.18: Avoided Cost (by jurisdiction)

Conservation Potential
Using the avoided cost thresholds, AEG selected all potential cost-effective DSM
programs for the Idaho and Washington service areas, while ETO performed the CPA
study for Oregon. Table 6.3 shows potential DSM savings in each region from the
selected conservation potential for the Expected Case.

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Table 6.3: Annual and Average Daily Demand Served by Conservation

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Conservation Acquisition Goals
The avoided cost established in SENDOUT®, the conservation potential selected, and
the amount of therm savings is the basis for determining conservation acquisition goals
and subsequent DSM program implementation planning. Chapter 3 – Demand-Side
Resources has additional details on this process.
Supply-Side Resources
SENDOUT® considers all options entered into the model, determines when and what
resources are needed, and which options are cost effective. Selected resources represent
the best cost/risk solution, within given constraints, to serve anticipated customer
requirements. Since the Expected Case has no resource additions in the planning
horizon, Avista will continue to review and refine knowledge of resource options and will
act to secure best cost/risk options when necessary or advantageous.

Resource Utilization
Avista plans to meet firm customer demand requirements in a cost-effective manner. This
goal encompasses a range of activities from meeting peak day requirements in the winter
to acting as a responsible steward of resources during periods of lower resource
utilization. As the analysis presented in this IRP indicates, Avista has ample resources to
meet highly variable demand under multiple scenarios, including peak weather events.
Avista acquired most of its upstream pipeline capacity during the deregulation or
unbundling of the natural gas industry. Pipelines were required to allocate capacity and
costs to their existing customers as they transitioned to transportation only service
providers. The FERC allowed a rate structure for pipelines to recover costs through a
Straight Fixed Variable rate design. This structure is based on a higher reservation charge
to cover pipeline costs whether natural gas is transported or not, and a much smaller
variable charge which is incurred only when natural gas is transported. An additional fuel
charge is assessed to account for the compressors required to move the natural gas to
customers. Avista maintains enough firm capacity to meet peak day requirements under
the Expected Case in this IRP. This requires pipeline capacity contracts at levels in
excess of the average and above minimum load requirements. Given this load profile and
the Straight Fixed Variable rate design, Avista incurs ongoing pipeline costs during non-
peak periods.
Avista chooses to have an active, hands-on management of resources to mitigate
upstream pipeline and commodity costs for customers when the capacity is not utilized
for system load requirements. This management simultaneously deploys multiple long-
and short-term strategies to meet firm demand requirements in a cost effective manner.
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These strategies and plan is discussed in detail in Chapter 4 – Supply side resources.
The resource strategies addressed are:
• Pipeline contract terms;
• Pipeline capacity;
• Storage;
• Commodity and transport optimization; and
• Combination of available resources.

Pipeline Contract Terms
Some pipeline costs are incurred whether the capacity is utilized or not. Winter demand
must be satisfied, and peak days must be met. Ideally, capacity could be contracted from
pipelines only for the time and days it is required. Unfortunately, this is not how pipelines
are contracted or built. Long-term agreements at fixed volumes are usually required for
building or acquiring firm transport. This assures the pipeline of long-term, reasonable
cost recovery.
Avista has negotiated and contracted for several seasonal transportation agreements.
These agreements allow volumes to increase during the demand intensive winter months
and decrease over the lower demand summer period. This is a preferred contracting
strategy because it eliminates costs when demand is low. Avista refers to this as a front
line strategy because it attempts to mitigate costs prior to contracting the resource. Not
all pipelines offer this option. Avista seeks this type of arrangement where available.
Avista currently has some seasonal transportation contracts on TransCanada GTN in
addition to contracted volumes of TF2 on NWP. This is a storage specific contract and
matches up the withdrawal capacity at Jackson Prairie with pipeline transport to Avista’s
service territories. TF2 is a firm service and allows for contracting a daily amount of
transportation for a specified number of days rather than a daily amount on an annual
basis as is usually required. For example, one of the TF2 agreements allows Avista to
transport 91,200 Dth/day for 31 days. This is a more cost-effective strategy for storage
transport than contracting for an annual amount. Through NWP’s tariff, Avista maintains
an option to increase and decrease the number of days this transportation option is
available. More days correspond to increased costs, so balancing storage, transport and
demand is important to ensure an optimal blend of cost and reliability.
Pipeline Capacity
After contracting for pipeline capacity, its management and utilization determine the
actual costs. The worst-case economic scenario is to do nothing and simply incur the
costs associated with this transport contract over the long-term to meet current and future
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peak demand requirements. Avista develops strategies to ensure this does not happen
on a regular basis if possible.
Capacity Release
Through the pipeline unbundling of transportation, the FERC establishes rules and
procedures to ensure a fair market developed to manage pipeline capacity as a
commodity. This evolved into the capacity release market and is governed by FERC
regulations through individual pipelines. The pipelines implement the FERC’s posting
requirements to ensure a transparent and fair market is maintained for the capacity. All
capacity releases are posted on the pipelines Bulletin Boards and, depending on the
terms, may be subject to bidding in an open market. This provides the transparency
sought by the FERC in establishing the release requirements. Avista utilizes the capacity
release market to manage both long-term and short-term transportation capacity.
For capacity under contract that may exceed current demand, Avista seeks other parties
that may need it and arranges for capacity releases to transfer rights, obligations and
costs. This shifts all or a portion of the costs away from Avista’s customers to a third party
until it is needed to meet customer demand.
Many variables determine the value of natural gas transportation. Certain pipeline paths
are more valuable and this can vary by year, season, month and day. The term, volume
and conditions present also contribute to the value recoverable through a capacity
release. For example, a release of winter capacity to a third party may allow for full cost
recovery; while a release for the same period that allows Avista to recall the capacity for
up to 10 days during the winter may not be as valuable to the third party, but of high value
to us. Avista may be willing to offer a discount to retain the recall rights during high
demand periods. This turns a seasonal-for-annual cost into a peaking-only cost. Market
terms and conditions are negotiated to determine the value or discount required by both
parties.
Avista has several long-term releases, some extending multiple years, providing full
recovery of all the pipeline costs. These releases maintain Avista’s long-term rights to the
transportation capacity without incurring the costs of waiting until demand increases. As
the end of these release terms near, Avista surveys the market against the IRP to
determine if these contracts should be reclaimed or released, and for what duration.
Through this process, Avista retains the rights to vintage capacity without incurring the
costs or having to participate in future pipeline expansions that will cost more than current
capacity.
On a shorter term, excess capacity not fully utilized on a seasonal, monthly or daily basis
can also be released. Market conditions often dictate less than full cost recovery for
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shorter-term requirements. Mitigating some costs for an unutilized, but required resource
reduces costs to our customers.
Segmentation
Through a process called segmentation, Avista creates new firm pipeline capacity for the
service territory. This doubles some of the capacity volumes at no additional cost to
customers. With increased firm capacity, Avista can continue some long-term releases,
or even reduce some contract levels, if the release market does not provide adequate
recovery. An example of segmentation is if the original receipt and delivery points are
from Sumas to Spokane. Avista can alter this path from Sumas to Sipi, Sipi to Jackson
Prairie, Jackson Prairie to Spokane. This segmentation allows Avista to flow three times
the amount of natural gas on most days or non-peak weather events. In the event of a
peak day, and the transport needs to be firm, the transportation can be rolled back up to
ensure the natural gas will be delivered into the original firm path.
Storage
As a one-third owner of the Jackson Prairie Storage facility, Avista holds an equal share
of capacity (space available to store natural gas) and delivery (the amount of natural gas
that can be withdrawn daily).
Storage allows lower summer-priced natural gas to be stored and used in the winter
during high demand or peak day events. Like transportation, unneeded capacity and
delivery can be optimized by selling into a future higher priced market. This allows Avista
to manage storage capacity and delivery to meet growing peak day requirements when
needed.
The injection of natural gas into storage during the summer utilizes existing pipeline
transport and helps increase the utilization factor of pipeline agreements. Avista employs
several storage optimization strategies to mitigate costs. Revenue from this activity flows
through the annual PGA/Deferral process.
Commodity and Transportation Optimization
Another strategy to mitigate transportation costs is to participate in the daily market to
assess if unutilized capacity has value. Avista seeks daily opportunities to purchase
natural gas, transport it on existing unutilized capacity, and sell it into a higher priced
market to capture the cost of the natural gas purchased and recover some pipeline
charges. The amount of recovery is market dependent and may or may not recover all
pipeline costs but does mitigate pipeline costs to customers.
Combination of Resources
Unutilized resources like supply, transportation, storage and capacity can combine to
create products that capture more value than the individual pieces. Avista has structured
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long-term arrangements with other utilities that allow available resource utilization and
provide products that no individual component can satisfy. These products provide more
cost recovery of the fixed charges incurred for the resources while maintaining the rights
to utilize the resource for future customer needs.
Resource Utilization Summary
As determined through the IRP modeling of demand and existing resources, new
resources under the Expected Case are not required over the next 20 years. Avista
manages the existing resources to mitigate the costs incurred by customers until the
resource is required to meet demand. The recovery of costs is often market based with
rules governed by the FERC. Avista is recovering full costs on some resources and partial
costs on others. The management of long- and short-term resources meets firm customer
demand in a reliable and cost-effective manner.
Conclusion
Choosing reliable information and methods to utilize in these analyses help Avista
determine an expected standard. To do this, Avista utilizes industry experts to help
determine prices and a market environment, decades of historic weather by major service
area, daily weather adjusted usage metrics combined with a statistical based customer
forecast all help to provide a reasonable range of expectations for this planning period.
There are no expected resource deficiencies during this 20-year forecast in either the
Average Case or Expected Case in this IRP. Avista will rely on its Expected Case for
peak operational planning activities and in its optimization programs to sufficiently plan
for cold day events.
Avista recognizes that there are other potential outcomes. The process described in this
chapter applies to the alternate demand and supply resource scenarios covered in
Chapter 7 – Alternate Scenarios, Portfolios and Stochastic Analysis.

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7: Alternate Scenarios, Portfolios and Stochastic
Analysis
Overview
Avista applied the IRP analysis in Chapter 6 – Integrated Resource Portfolio to alternate
demand and supply resource scenarios to develop a range of alternate portfolios. This
modeling approach considered different underlying assumptions vetted with the TAC
members to develop a consensus about the number of cases to model.
Avista also performed stochastic modeling for estimating probability distributions of
potential outcomes by allowing for random variation in natural gas prices and weather
based on fluctuations in historical data. This statistical analysis, in conjunction with the
deterministic analysis, enabled statistical quantif ication of risk from reliability and cost
perspectives related to resource portfolios under varying price and weather conditions.

Alternate Demand Scenarios
As discussed in the Demand Forecasting section, Avista identified alternate scenarios for
detailed analysis to capture a range of possible outcomes over the planning horizon.
Table 7.1 summarizes these scenarios and Chapter 2 – Demand Forecasts and
Appendices 2.6 and 2.7 describes them in detail. The scenarios consider different
demand influencing factors and price elasticity effects for various price influencing factors.

Table 7.1: 2021 IRP Scenarios

Demand profiles over the planning horizon for each of the scenarios shown in Figures 7.1
and 7.2 reflect the two winter peaks modeled for the different service territories.
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Figure 7.1: Peak Day (Feb 28) – 2021 IRP Demand Scenarios

Figure 7.2: Peak Day (Dec 20) – 2021 IRP Demand Scenarios

As in the Expected Case, Avista used SENDOUT® to model the same resource
integration and optimization process described in this section for each of the five demand
scenarios (see Appendix 2.7 for a complete listing of portfolios considered). This
deterministic analysis identified the first-year unserved dates for each scenario by service
territory shown in Figure 7.3.
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Figure 7.3: First Year Peak Demand Not Met with Existing Resources

Steeper demand highlights the flat demand risk discussed earlier. This could be a regional
issue with utilities look toward carbon reduction with limited resources available. The
likelihood of this scenario occurring is remote due to a yearly recurrence of the weather
planning standard paired with a much steeper growth of customer population; however,
any potential for accelerated unserved dates warrants close monitoring of demand trends
and resource lead times as described in the Ongoing Activities section of Chapter 9 –
Action Plan. The remaining scenarios do not identify resource deficiencies in the planning
horizon.

Alternate Supply Resources
Avista identified supply-side resources that could meet resource deficiencies or provide
a least cost solution. There are other options Avista considered in its modeling approach
to solve for High Growth & Low-Price unserved conditions and to determine whether the
Expected Case with existing resources is least cost/least risk. A list of the modeled
available renewable supply resources is displayed in Table 7.2 and fossil resources are
included in Table 7.3.

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Table 7.2: Levelized Cost of Renewable Resources
Resource Dth per
year
20-year Levelized Cost
Per Dth (Year 1)
$ per kWh
(retail)
Distributed Renewable
Hydrogen Production 60,509 $47.25 $0.161
Distributed LFG to RNG
Production 231,790 $15.90 $0.054
Centralized LFG to RNG
Production 662,256 $14.11 $0.048
Dairy Manure to RNG
Production 231,790 $14.30 $0.049
Wastewater Sludge to RNG
Production 187,245 $23.34 $0.080
Food Waste to RNG Production 108,799 $33.14 $0.113

Table 7.3: Other Supply Resources

Additional
Resource Size Cost/Rates Availability Notes
Unsubscribed
GTN Capacity
Up to
50,000 Dth GTN Rate 2021
Currently available
unsubscribed capacity from
Kingsgate to Spokane
Medford
Lateral
Expansion
50,000 Dth /
Day
$35M
capital +
GTN Rate
2022
Additional compression to
facilitate more gas to flow
from mainline GTN to
Medford
Plymouth
LNG
241,700 Dth
w/70,500
Dth
deliverability
NWP Rate 2021
Provides for peaking
services and alleviates the
need for costly pipeline
expansions

Pair with excess pipeline
MDDO’s to create firm
transport

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As discussed in Chapter 5 – Carbon Reduction, Hydrogen is beginning to emerge as a
true potential as a clean fuel to help offset emissions in the natural gas system. Excess
electricity from renewable resources can create green. Not only will this act as a type of
storage desperately needed by the electric grid, it will capture excess green energy for
future use. Some estimates have green hydrogen as a major fuel in the supply mix by
2050. However, the market-based price and other terms are difficult to reliably determine
until a formal agreement is negotiated. Exchange agreements also have market-based
terms and are hard to reliably model when the resource need is later in the planning
horizon. Current tariff prices were used to model additional GTN capacity and Plymouth
LNG, while an estimate was provided from GTN for the upsized Medford lateral
compressor combined with tariff rates in order to flow the gas. For those costs specifically
related to all four RNG projects and hydrogen Avista contracted with a consultant to
provide cost estimates for these types of facilities. Some of the major costs include:
Capital, O&M, Avista’s revenue requirement, federal income tax, and depreciation. Avista
also included any subsidies known at the time of modeling. These projects include a cost
of carbon adder for any amount of carbon intensity still associated with each project type.
Specifically, dairy and solid waste have a negative carbon intensity, as discussed in
Chapter 5. The net effect of using this is the removal of carbon from the atmosphere.
Finally, Renewable Identification Number (RIN) values were not included in the valuation
of RNG as it is assumed that these RIN’s would be needed to provide proof of Avista’s
utilization of RNG or in complying with new environmental legislation1.
Many of the potential resources are not yet commercially available or well tested,
technically making them speculative. Avista will continue to monitor all resources and
assess their appropriateness for inclusion in future IRPs as described in Chapter 9 –
Action Plan.

Deterministic – Portfolio Evaluation
There is no resource deficiency identified in the planning period and the existing resource
portfolio is adequate to meet forecasted demand. The alternate demand scenarios and
supply scenarios are placed in the model as predicted future conditions that the supply
portfolio will have to satisfy via least cost and least risk strategies. This creates bounds
for analyzing the Expected Case by creating high and low boundaries for customer count,
weather and pricing. Each portfolio runs through SENDOUT® where the supply resources
(Chapter 4 – Supply Side Resources) and conservation resources (Chapter 3 – Demand
Side Management) are compared and selected on a least cost basis. Once new

1 https://www.epa.gov/renewable-fuel-standard-program/renewable-identification-numbers-rins-under-renewable-fuel-
standard
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resources are determined, a net present value of the revenue requirement (PVRR) is
calculated. Results from each scenario can be found in Table 7.4.
Table 7.4: PVRR by Portfolio
Scenario
System Cost
(PVRR)
Billions of $
Expected Case $6.88
High Growth & Low Prices $2.68
Carbon Reduction* $5.70
Average Case $5.69
Low Growth & High Prices $9.80

*Carbon Reduction Scenario does not have sufficient factors to stochastically represent alternative futures due to
the unknown nature of the cost and availability of RNG and H2.

Stochastic Analysis2
The scenario (deterministic) analysis described earlier in this chapter represents specific
what if situations based on predetermined assumptions, including price and weather.
These factors are an integral part of scenario analysis. To understand how each scenario
will respond to cost and risk, through price and weather, Avista applied stochastic analysis
to generate a variety of price and weather events.
Deterministic analysis is a valuable tool for selecting an optimal portfolio. The model
selects resources to meet peak weather conditions in each of the 20 years. However, due
to the recurrence of design conditions in each of the 20 years, total system costs over the
planning horizon can be overstated because of annual recurrence of design conditions
and the recurrence of price increases in the forward price curve. As a result, deterministic
analysis does not provide a comprehensive look at future events. Utilizing Monte Carlo
simulation in conjunction with deterministic analysis provides a more complete picture of
portfolio performance under unknown weather and price profiles.
This IRP employs stochastic analysis in two ways. The first tested the weather-planning
standard and the second assessed risk related to costs of our Expected Case (existing
portfolio) under varying price environments. The Monte Carlo simulation in SENDOUT®
can vary index price and weather simultaneously. This simulates the effects each have
on the other.

2 SENDOUT® uses Monte Carlo simulation to support stochastic analysis, which is a mathematical technique for
evaluating risk and uncertainty. Monte Carlo simulation is a statistical modeling method used to imitate future
possibilities that exist with a real-life system.
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Weather
In order to evaluate weather and its effect on the portfolio, Avista developed 1,000
simulations (draws) through SENDOUT®’s stochastic capabilities. Unlike deterministic
scenarios or sensitivities, the draws have more variability from month-to-month and year-
to-year. In the model, random monthly total HDD draw values (subject to Monte Carlo
parameters – see Table 7.5) are distributed on a daily basis for a month in history with
similar HDD totals. The resulting draws provide a weather pattern with variability in the
total HDD values, as well as variability in the shape of the weather pattern. This provides
a more robust basis for stress testing the deterministic analysis.
Table 7.5: Example of Monte Carlo Weather Inputs – Spokane

The model considers five weather areas: Spokane, Medford, Roseburg, Klamath Falls
and La Grande. A new weather planning standard was introduced into the 2021 IRP, and
Avista assessed the frequency of the weather planning standard peak day occurs in each
area from the simulation data. The stochastic analysis shows that in over 1,000, 20-year
simulations, peak day (or more) occurs with enough frequency to utilize the new planning
standard for the current IRP. This topic remains a subject of continued analysis. For
example, the Medford weather pattern over the 1,000 20-year draws (i.e, 20,000 years)
HDDs at or above peak weather (49 HDDs) occur 1,926 times or once every 10 years.
See Figures 7.4 through 7.8 for the number of peak day occurrences by weather area.
help explain why this can occur we look to the process itself. Monte Carlo simulations use
historic data to obtain randomly generated weather events. Due to the change in planning
standard, no peak days were simulated above the historic coldest on record temperature.
Though due to the number of peak days occurring in the past 30 years, probability sees
it is a higher likelihood of occurrence.

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Figure 7.4: Frequency of Peak Day Occurrences – Spokane

Figure 7.5: Frequency of Peak Day Occurrences – Medford

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Figure 7.6: Frequency of Peak Day Occurrences – Roseburg

Figure 7.7: Frequency of near Peak Day Occurrences – Klamath Falls

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Figure 7.8: Frequency of near Peak Day Occurrences – La Grande

Price
While weather is an important driver for the IRP, price is also important. As seen in recent
years, significant price volatility can affect the portfolio. In deterministic modeling, a single
price curve for each scenario is used for analysis. There is risk that the price curve in the
scenario will not reflect actual results.
Avista used Monte Carlo simulation to test the portfolio and quantify the risk to customers
when prices do not materialize as forecast. Avista performed a simulation of 1,000 draws,
varying prices, to investigate whether the Expected Case total portfolio costs from the
deterministic analysis is within the range of occurrences in the stochastic analysis. Figure
6.9 shows a histogram of the total portfolio cost of all 1,000 draws, plus the Expected
Case results. This histogram depicts the frequency and the total cost of the portfolio
among all of the draws, the mean of the draws, the standard deviation of the total costs,
and the total costs from the Expected Case.

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Figure 7.9: 2018 IRP Total 20-Year Cost
(Billions of $)

Measuring risk in both weather and price is done through a statistical approach of
shocking each of these measures to reflect the uncertain nature of a future outcome. Risk
can be measured in the variation of cost outcome of resources in addition to unknown
weather events and the ability to serve customer demand. This analytical perspective
provides confidence in the conclusions and stress tests the robustness of the selected
portfolio of resources, thereby mitigating analytical risks.

Solving Unserved Demand
High Growth & Low Price
The components, methods and topics covered in this and previous chapters will now help
to solve unserved demand in The High Growth & Low Price scenario. This scenario
includes customer growth rates higher than the Expected Case, incremental demand
driven by emerging markets and no adjustment for price elasticity. Even with aggressive
assumptions, deterministic analysis shows resource shortages do not occur until late in
the planning horizon.
• 2036 in Washington/Idaho
• 2040 in La Grande
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We begin to solve for unserved demand by adding additional resources as supply side
options. The resources Avista modeled for the current IRP include 5 types of renewable
natural gas, hydrogen, and an upsized compressor on the Medford lateral, additional GTN
capacity and Plymouth LNG as seen in Table 7.2. All costs are entered by location with
the associated daily, pipeline quality, volume available to inform the model. A
deterministic resource mix is performed allowing the model to solve the demand based
on the optimal least cost solution for the system. Avista performed this selection process
both deterministically and stochastically with the statistical measures shown for each
resource option as illustrated in Table 7.6.
Table 7.6: System Cost, Standard Deviation and Outcome of Adding Resource to
System
Solve – No Unserved Average Stdev Median Max Min
RNG Resources Only $2.683 $0.043 $2.681 $2.861 $2.542
Plymouth, RNG in La Grande $2.721 $0.043 $2.719 $2.901 $2.580
GTN – RNG in La Grande $2.734 $0.042 $2.675 $2.855 $2.540
Medford Lateral Expansion,
RNG in La Grande $2.734 $0.044 $2.731 $2.915 $2.600
*$ in Billions
**1,000 draws each scenario

Once an optimal resource is found deterministically a stochastic analysis takes place to
measure risk. Figure 7.10 shows the frequency of occurrence from the solve (RNG
Resources Only) by cost in addition to a running sum of overall percentage of the total
number of future 20 year draws.

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The Optimal Solution Figure 7.10: High Growth and Low Price Cost vs. Risk
(1,000 Draws – Billions of $)

Carbon Reduction Scenario
As carbon policy continues to shift and evolve, mapping out potential supply options to
meet these climate goals is increasingly important. Understanding the dynamic between
serving the energy demand while reducing carbon emissions is a relatively new paradigm
in the natural gas industry. Reducing carbon can take the form of alternate fuel choices
either partially reducing, increased energy efficiency (DSM) or fully offsetting the carbon
intensity of fossil natural gas. Some RNG sources, as mentioned in Chapter 5 – Carbon
Reduction, will turn each unit of energy into a methodology to capture carbon rather than
just fully offset the emissions of fossil fuel natural gas. These sources such as dairy or
WWTP RNG will leave a deficit of energy for the number of emissions offsets provided.
Pairing the right amount of energy with the necessary amount of emissions reduction is
where this IRP will begin to discover solutions and provide answers.
Future IRP’s will have the ability to solve for emissions and costs to meet a dual goal least
cost and risk set of supply side resources. Emissions reduction goals can be measured
to include various goals as a percentage based on a specific year or timeframe. In this
scenario, we take the Expected case assumptions as inputs and combine them with an
estimated 1990 emissions goal for Oregon and Washington. The emissions reduction for
Oregon and Washington can be seen in Figure 7.11.

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Figure 7.11: Expected Emissions vs. Emissions with Climate Goals (Net of DSM)

It is assumed the goal and reductions need to be met on a yearly basis based on the
average emissions reduction needed to meet these major milestones. Carbon emissions
offsets are not modeled in the current IRP as their costs are unknown as are the allowable
quantity by timeframe for their use. The selling of carbon credits, like RINs, will need
consideration in future resource plans. As the cost of carbon increases, the levelized cost
of resources decreases especially those with the ability to capture carbon as opposed to
just offsetting emissions. This places dairy RNG into the preferred supply side resource
if the ability to obtain the quantity of projects and the respective output is available as
displayed in Figure 7.12 along with each modeled scenario’s carbon emissions (Figure
7.13).

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Figure 7.12: Carbon Reduction Solve

Figure 7.13: Depicts System Emissions for each Scenario

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Electrification Scenarios
Avista uses three scenarios to identify impacts to the power system if space and water
heating is electrified in the Washington service area3, specifically for the residential and
commercial customers. The first scenario of electrification uses current electric
technology and efficiency. The second, continues to use the natural gas system for peak
heating needs with non-peak electrified. Finally, the third scenario uses an assumption of
high efficiency electric equipment. Each scenario uses the conversion from natural gas
to electric assumes a 50 percent reduction in natural gas load by 2030 and an 80 percent
reduction by 2045. Avista estimates 75 percent of the added electric load will be on
Avista’s system and the remaining load on other utilities.
Figure 7.14 below illustrates additional Avista load on the Avista electric system in
Washington:
Figure 7.14: Additional Avista Load on Avista Electric System - Washington

Figure 7.15 displays the natural gas supplied for each electrification scenario:

3 The load conversion analysis also includes natural gas process conversion such as cooking, cloths drying, etc.
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Figure 7.15: Natural Gas Supply by Electrification Scenario

While these scenarios have advanced our understanding of an electrification future,
further studies are needed to fully understand the full impacts and costs of electrification.
Some of these areas include:
• cost to homeowners to convert equipment;
• transmission or distribution grid impacts and costs;
• Avista has not re-studied the northwest electric market to account for pricing and
resource availability impacts.
Given the large scope and impacts of this future scenario it may be best suited for a non-
IRP analysis on a regional level. For additional detail on these scenarios, please refer to
the Avista 2021 Electric IRP (Chapter 12-Portfolio Scenario Analysis).

Regulatory Requirements
IRP regulatory requirements in Idaho, Oregon and Washington call for several key
components. The completed plan must demonstrate that the IRP:
• Examines a range of demand forecasts.
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• Examines feasible means of meeting demand with both supply-side and demand-
side resources.
• Treats supply-side and demand-side resources equally.
• Describes the long-term plan for meeting expected demand growth.
• Describes the plan for resource acquisitions between planning cycles.
• Takes planning uncertainties into consideration.
• Involves the public in the planning process.
Avista addressed the applicable requirements throughout this document. Appendix 1.2 –
IRP Guideline Compliance Summaries lists the specific requirements and guidelines of
each jurisdiction and describes Avista’s compliance.
The IRP is also required to consider risks and uncertainties throughout the planning and
analytical processes. Avista’s approach in addressing this requirement was to identify
factors that could cause significant deviation from the Expected Case planning
conclusions. This included dynamic demand analytical methods and sensitivity analysis
on demand drivers that impacted demand forecast assumptions. From this, Avista
created multiple demand sensitivities and five demand scenario alternatives, which
incorporated different customer growth, use-per-customer, weather, and price elasticity
assumptions.
Avista analyzed peak day weather planning standard, performing sensitivity on HDDs and
modeling an alternate weather-planning standard using the coldest day in 20 years.
Stochastic analysis using Monte Carlo simulations in SENDOUT® supplemented this
analysis. Avista also used simulations from SENDOUT® to analyze price uncertainty and
the effect on total portfolio cost.
Avista examined risk factors and uncertainties that could affect expectations and
assumptions with respect to DSM programs and supply-side scenarios. From this, Avista
assessed the expected available supply-side resources and potential conservation
savings for evaluation.
The investigation, identification, and assessment of risks and uncertainties in our IRP
process should reasonably mitigate surprise outcomes.

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Conclusion
In planning, a reasonable set of criteria is necessary to help measure the inherent risk of
the unknown in future events. With the inclusion of the Carbon Reduction scenario, Avista
will continue to consider resources to solve the energy demand in combination with new
policy, specifically those requiring carbon reductions. As policy continues to require green
sources from the electric grid, the existing natural gas infrastructure should be used in the
battle against climate change. Resources such as RNG and H2 can play an important
part in these electric generation green resources, utilizing the excess energy while
providing mitigation to outages and weather-related events that are far more common in
the electric industry4. Energy security during the coldest of times is a pillar of resource
planning and Avista will continue to consider all the environment, affordability and
reliability of resources to meet our customer’s needs.

4 www.energy.gov
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8: Distribution Planning
Overview
Avista’s IRP evaluates the safe, economical and reliable full-path delivery of natural gas
from basin to the customer meter. Securing adequate natural gas supply and ensuring
sufficient pipeline transportation capacity to Avista’s city gates become secondary issues
if distribution system growth behind the city gates increases faster than expected and the
system becomes severely constrained. Important parts of the distribution planning
process include forecasting local demand growth, determining potential distribution
system constraints, analyzing possible solutions and estimating costs for eliminating
constraints.
Analyzing resource needs to this point has focused on ensuring adequate capacity to the
city gates, especially during a peak event. Distribution planning focuses on determining if
there will be adequate pressure during a peak hour. Despite this altered perspective,
distribution planning shares many of the same goals, objectives, risks and solutions as
integrated resource planning.
Avista’s natural gas distribution system consists of approximately 3,300 miles of
distribution main and service pipelines in Idaho, 3,700 miles in Oregon and 5,800 miles
in Washington; as well as numerous regulator stations, service distribution lines,
monitoring and metering devices, and other equipment. Currently, there are no storage
facilities or compression systems within Avista’s distribution system. Distribution network
pipelines and regulating stations operate and maintain system pressure solely from the
pressure provided by the interstate transportation pipelines.

Distribution System Planning
Avista conducts two primary types of evaluations in its distribution system planning
efforts: capacity requirements and integrity assessments.
Capacity requirements include distribution system reinforcements and expansions.
Reinforcements are upgrades to existing infrastructure or new system additions, which
increase system capacity, reliability and safety. Expansions are new system additions to
accommodate new demand. Collectively, these reinforcements and expansions are
distribution enhancements.
Ongoing evaluations of each distribution network in the five primary service territories
identify strategies for addressing local distribution requirements resulting from customer
growth. Customer growth assessments are made based on factors including IRP demand
forecasts, monitoring gate station flows and other system metering, new service requests,
field personnel discussion, and inquiries from major developers.
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Avista regularly conducts integrity assessments of its distribution systems. Ongoing
system evaluation can indicate distribution-upgrading requirements for system
maintenance needs rather than customer and load growth. In some cases, the timing for
system integrity upgrades coincides with growth-related expansion requirements. These
planning efforts provide a long-term planning and strategy outlook and integrate into the
capital planning and budgeting process, which incorporates planning for other types of
distribution capital expenditures and infrastructure upgrades.
Gas Engineering planning models are also compared with capacity limitations at each
city gate station. Referred to as city gate analysis, the design day hourly demand
generated from planning analyses must not exceed the actual physical limitation of the
city gate station. A capacity deficiency found at a city gate station establishes a potential
need to rebuild or add a new city gate station.

Network Design Fundamentals
Natural gas distribution networks rely on pressure differentials to flow natural gas from
one place to another. When pressures are the same on both ends of a pipe, the natural
gas does not move. As natural gas exits the pipeline network, it causes a pressure drop
due to its movement and friction. As customer demand increases, pressure losses
increase, reducing the pressure differential across the pipeline network. If the pressure
differential is too small, flow stalls and the network could run out of pressure.
It is important to design a distribution network such that intake pressure from gate stations
and/or regulator stations within the network is high enough to maintain an adequate
pressure differential when natural gas leaves the network.
Not all natural gas flows equally throughout a network. Certain points within the network
constrain flow and restrict overall network capacity. Network constraints can occur as
demand requirements evolve. Anticipating these demand requirements, identifying
potential constraints and forming cost-effective solutions with sufficient lead times without
overbuilding infrastructure are the key challenges in network design.

Computer Modeling
Developing and maintaining effective network design is aided by computer modeling for
network demand studies. Demand studies have evolved with technology to become a
highly technical and powerful means of analyzing distribution system performance. Using
a pipeline fluid flow formula, a specified parameter for each pipe element can be
simultaneously solved. Many pipeline equations exist, each tailored to a specific flow
behavior. These equations have been refined through years of research to the point
where modeling solutions closely resemble actual system behavior.
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Avista conducts network load studies using GL Noble Denton’s Synergi software. This
modeling tool allows users to analyze and interpret solutions graphically.

Determining Peak Demand
Avista’s distribution network is comprised of high pressure (90-500 psig) and intermediate
pressure (5-60 psig) mains. Avista operates its intermediate networks at a maximum
pressure of 60 psig or less for ease of maintenance and operation, public safety, reliable
service, and cost considerations. Since most distribution systems operate through
relatively small diameter pipes, there is essentially no line-pack capability for managing
hourly demand fluctuations. Line pack is the difference between the natural gas contents
of the pipeline under packed (fully pressurized) and unpacked (depressurized) conditions.
Line pack is negligible in Avista’s distribution system due to the smaller diameter pipes
and lower pressures. In transmission and inter-state pipelines, line-pack contributes to
the overall capacity due to the larger diameter pipes and higher operating pressures.
Core demand typically has a morning peaking period between 6 a.m. and 10 a.m. and
the peak hour demand for these customers can be as much as 50 percent above the
hourly average of daily demand. Because of the importance of responding to hourly
peaking in the distribution system, planning capacity requirements for distribution systems
uses peak hour demand.1

Distribution System Enhancements
Demand studies facilitate modeling multiple demand forecasting scenarios, constraint
identification and corresponding optimum combinations of pipe modification, and
pressure modification solutions to maintain adequate pressures throughout the network.
Distribution system enhancements do not reduce demand, nor do they create additional
supply. Enhancements can increase the overall capacity of a distribution pipeline system
while utilizing existing gate station supply points. The two broad categories of distribution
enhancement solutions are pipelines and regulators.
Pipelines
Pipeline solutions consist of looping, upsizing and uprating. Pipeline looping is the most
common method of increasing capacity in an existing distribution system. Looping
involves constructing new pipe parallel to an existing pipeline that has, or may become,
a constraint point. Constraint points inhibit flow capacities downstream of the constraint
creating inadequate pressures during periods of high demand. When the parallel line
connects to the system, this alternative path allows natural gas flow to bypass the original

1 This method differs from the approach that Avista uses for IRP peak demand planning, which focuses on peak day
requirements to the city gate.
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constraint and bolsters downstream pressures. Looping can also involve connecting
previously unconnected mains. The feasibility of looping a pipeline depends upon the
location where the pipeline will be constructed. Installing natural gas pipelines through
private easements, residential areas, existing paved surfaces, and steep or rocky terrain
can increase the cost to a point where alternative solutions are more cost effective.
Pipeline upsizing involves replacing existing pipe with a larger size pipe. The increased
pipe capacity relative to surface area results in less friction, and therefore a lower
pressure drop. This option is usually pursued when there is damaged pipe or where pipe
integrity issues exist. If the existing pipe is otherwise in satisfactory condition, looping
augments existing pipe, which remains in use.
Pipeline uprating increases the maximum allowable operating pressure of an existing
pipeline. This enhancement can be a quick and relatively inexpensive method of
increasing capacity in the existing distribution system before constructing more costly
additional facilities. However, safety considerations and pipe regulations may prohibit the
feasibility or lengthen the time before completion of this option. Also, increasing line
pressure may produce leaks and other pipeline damage creating costly repairs. A
thorough review is conducted to ensure pipeline integrity before pressure is increased.
Regulators
Regulators, or regulator stations, reduce pipeline pressure at various stages in the
distribution system. Regulation provides a specified and constant outlet pressure before
natural gas continues its downstream travel to a city’s distribution system, customer’s
property or natural gas appliance. Regulators also ensure that flow requirements are met
at a desired pressure regardless of pressure fluctuations upstream of the regulator.
Regulators are at city gate stations, district regulator stations, farm taps and customer
services.
Compression
Compressor stations present a capacity enhancing option for pipelines with significant
natural gas flow and the ability to operate at higher pressures. For pipelines experiencing
a relatively high and constant flow of natural gas, a large volume compressor installation
along the pipeline boosts downstream pressure.
A second option is the installation of smaller compressors located close together or
strategically placed along a pipeline. Multiple compressors accommodate a large flow
range and use smaller and very reliable compressors. These smaller compressor stations
are well suited for areas where natural gas demand is growing at a relatively slow and
steady pace, so that purchasing and installing these less expensive compressors over
time allows a pipeline to serve growing customer demand into the future.
Compressors can be a cost-effective option to resolving system constraints; however,
regulatory and environmental approvals to install a compressor station, along with
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engineering and construction time can be a significant deterrent. Adding compressor
stations typically involves considerable capital expenditure. Based on Avista’s detailed
knowledge of the distribution system, there are no foreseeable plans to add compressors
to the distribution network.

Conservation Resources
The evaluation of distribution system constraints includes consideration of targeted
conservation resources to reduce or delay distribution system enhancements. The
consumer is still the ultimate decision-maker regarding the purchase of a conservation
measure. Because of this, Avista attempts to influence conservation through the DSM
measures discussed in Chapter 3 – Demand-Side Resources, but does not depend on
estimates of peak day demand reductions from conservation to eliminate near-term
distribution system constraints. Over the longer-term, targeted conservation programs
may provide a cumulative benefit that could offset potential constraint areas and may be
an effective strategy.

Distribution Scenario Decision-Making Process
After achieving a working load study, analyses are performed on every system at design
day conditions to identify areas where potential outages may occur.

Avista’s design HDD for distribution system modeling is determined using a 99%
statistical probability method for each given service area. This practice is consistent with
the peak day demand forecast utilized in other sections of Avista’s natural gas IRP.

Utilizing a peak planning standard based on a statistical probability method of historical
temperatures may seem aggressive since extreme temperatures are experienced rarely.
Given the potential impacts of an extreme weather event on customers’ personal safety
and property damage to customer appliances and Avista’s infrastructure, it is a prudent
regionally accepted planning standard.

These areas of concern are then risk ranked against each other to ensure the highest risk
areas are corrected first. Within a given area, projects/reinforcements are selected using
the following criteria:

• The shortest segment(s) of pipe that improves the deficient part of the distribution
system.
• The segment of pipe with the most favorable construction conditions, such as
ease of access or rights or traffic issues.
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• Minimal to no water, railroad, major highway crossings, etc.
• The segment of pipe that minimizes environmental concerns including minimal to
no wetland involvement, and the minimization of impacts to local communities
and neighborhoods.
• The segment of pipe that provides opportunity to add additional customers.
• Total construction costs including restoration.

Once a project/reinforcement is identified, the design engineer or construction project
coordinator begins a more thorough investigation by surveying the route and filing for
permits. This process may uncover additional impacts such as moratoriums on road
excavation, underground hazards, discontent among landowners, etc., resulting in
another iteration of the above project/reinforcement selection criteria. Figure 8.1 provides
a schematic representation of the distribution scenario process.

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Figure 8.1: Distribution Scenario Process

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An example of the distribution scenario decision making process is from the Medford high
pressure loop reinforcement where the analysis resulted in multiple paths or pipeline
routes. The initial path was based on quantitative factors, specifically the shortest length
and least cost route. However, as field investigations and coordination with local city and
county governments began, alternative routes had to be determined to minimize future
conflicts, environmental considerations, and field and community disruptions. The final
path was based on several qualitative factors that including:

• Available right-of-way along city streets;
• Availability of private easements from property owners;
• Restrictions due to City of Medford future planned growth with limited planning
information; and
• Potential to avoid conflict with other utilities including a large electric substation
along the initial route.

Planning Results
Table 8.1 summarizes the cost and timing, as of the publication date of this IRP, of major
distribution system enhancements addressing growth-related system constraints, system
integrity issues and the timing of expenditures.
The Distribution Planning Capital Projects criteria includes:

• Prioritized need for system capacity (necessary to maintain reliable service);
• Scale of project (large in magnitude and will require significant engineering
and design support); and
• Budget approval (will require approval for capital funding).
These projects are preliminary estimates of timing and costs of major reinforcement
solutions whose costs exceed $500,000 in any year. The scope and needs of distribution
system enhancement projects generally evolve with new information requiring ongoing
reassessment. Actual solutions may differ due to differences in actual growth patterns
and/or construction conditions that differ from the initial assessment and timing of planned
completion may change based on the aforementioned ongoing reassessment of
information.
The following discussion provides information about key near-term projects.
Airway Heights High Pressure Reinforcement, WA: The Airway Heights high pressure
line has provided natural gas to one of the fasted growing regions in all of Avista’s service
territories. Recent rapid growth has included both residential and industrial customers,
quickly depleting the available capacity of the high pressure line. This reinforcement will
provide additional capacity and ensure reliable pressure at the end of the high pressure
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line, which supplies a major regulator station feeding the Downtown Spokane
neighborhoods.
Cheney High Pressure Reinforcement, WA: This project will reinforce the Cheney
distribution system, whose customer demands have exceeded the capacity of the high
pressure line constructed in 1957. During cold weather conditions, Avista periodically
asks some large firm customers to reduce their natural gas usage in order to serve core
customer demand. Project began in 2020 and will continue in 2021.
Pullman High Pressure Reinforcement, WA: The Pullman high pressure reinforcement
would connect both Moscow and Pullman’s high pressure systems. This would bring
Moscow gas to Pullman, avoiding the need to rebuild the Pullman City Gate Station which
is currently exceeding its physical capacity. Additionally, this interconnection would
increase reliability as both Moscow and Pullman would then have two sources of
gas. Design is tentatively scheduled for 2024 and we continue to monitor existing
customer demand. Construction timelines may change due to customer growth
expectations.

Warden High Pressure Reinforcement, WA: The Warden high pressure reinforcement
is necessary to serve either new or increased industrial customer demand. At this time,
prospective industrial customers, whose projected demands necessitated
reinforcements, have either cancelled expansion plans or are considering alternative
locations. In anticipation of similar industrial loads in the future, Avista will continue to list
this project, but defer major construction until supply constraints subside.

Table 8.1 High Pressure - Distribution Planning Capital Projects
Location 2021 2022 2023 2024 2025+
Airway Heights
High Pressure
Reinforcement, WA
$3,000,000 $3,000,000 --- --- ---
Cheney High
Pressure
Reinforcement, WA
$3,100,000 --- --- --- ---
Pullman High
Pressure
Reinforcement, WA
--- --- --- $2,400,000 ---
Warden High
Pressure
Reinforcement, WA
$100,000 $2,950,000 $2,950,000 --- ---

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Table 8.2 shows city gate stations identified as possibly over utilized or under capacity.
Estimated cost, year and the plan to remediate the capacity concern are shown.
These projects are preliminary estimates of timing and costs of city gate station upgrades.
The scope and needs of each project generally evolve with new information requiring
ongoing reassessment. Actual solutions may differ due to differences in actual growth
patterns and/or construction conditions that differ from the initial assessment.

The city gate station projects in Table 8.2 are periodically reevaluated to determine if
upgrades need to be accelerated or delayed.

Those assigned a TBD year have relatively small capacity constraints, and thus will be
monitored. There are no plans to rebuild or upgrade these city gate stations at this time.

Table 8.2 City Gate Station Upgrades
Location Gate Station Project to Remediate Cost Year
Colton, WA Colton #316 TBD - TBD
Medford, OR Medford #2431 TBD TBD
Pullman, WA Pullman #350 TBD - TBD
Roseburg, OR Melrose #2608 TBD - TBD
Sprague, WA Sprague #117 TBD - TBD
Sutherlin, OR Sutherlin #2626 TBD - TBD

Conclusion
Avista’s goal is to maintain its natural gas distribution systems reliably and cost effectively
to deliver natural gas to every customer. This goal relies on modeling to increase the
capacity and reliability of the distribution system by identifying specific areas that may
require changes. The ability to meet the goal of reliable and cost-effective natural gas
delivery is enhanced through localized distribution planning, which enables coordinated
targeting of distribution projects responsive to customer growth patterns.

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9: Action Plan

The purpose of an action plan is to position Avista to provide the best cost/risk resource portfolio
and to support and improve IRP planning. The Action Plan identifies needed supply and
demand side resources and highlights key analytical needs in the near term. It also highlights
essential ongoing planning initiatives and natural gas industry trends Avista will monitor as a
part of its planning processes.

2017-2018 Action Plan Review

Avista’s 2020 IRP will contain an individual measure level for dynamic DSM program
structure in its analytics. In prior IRP’s, it was a deterministic method based on based on
Expected Case assumptions. In the 2020 IRP, each portfolio will have the ability to select
conservation to meet unserved customer demand. Avista will explore methods to enable
a dynamic analytical process for the evaluation of conservation potential within individual
portfolios.
Result – Result- Avista discussed with Energy Trust of Oregon. It was decided that we
will continue to use Energy Trust’s current modeling protocols to run scenarios analyses
for the Conversation Potential Assessment (CPA). This decision enables the greatest
alignment between what Energy Trust expects they will be able to achieve under different
policy scenarios. These scenarios may include modeling using differential assumptions
such as: a) different avoided costs and b) accelerated and decelerated program uptake
scenarios. This also allows Energy Trust to include measures in the CPA that are offered
through Energy Trust programs under cost-effectiveness exceptions granted by the
OPUC under UM-551 guidelines. These CPA practices coincide well with the capabilities
of the software that Avista is using for other IRP modeling purposes. Consequently,
Avista has chosen not to further investigate dynamic DSM program structure modeling in
its analytics. Based on Avista’s efforts with ETO, it was decided to forgo the ability to
analyze DSM in Washington and Idaho due to any disparities that may occur from the
separation of analysis types.

Work with Staff to get clarification on types of natural gas distribution system analyses for
possible inclusion in the 2020 IRP.
Result - Any large natural gas distribution system analysis will be included in all future
IRP’s against system resources where necessary.

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Work with Staff to clarify types of distribution system costs for possible inclusion in our
avoided cost calculation.
Result – Distribution system costs are included in the avoided cost calculation and will
be included in all future IRP documents.

Revisit coldest on record planning standard and discuss with TAC for prudency.
Result – Avista has changed its weather planning standard based on a probability of
occurrence based on each weather planning location. The current methodology uses the
most recent 30 years of weather and the coldest day of each year combined with a 99%
probability of a weather event occurring.

Provide additional information on resource optimization benefits and analyze risk
exposure.
Result – Chapter 4 – Supply Side Resources has been expanded to not only add in
resource optimization benefits and risk exposure, but also includes additional details of
Avista’s natural gas hedging program

DSM—Integration of ETO and AEG/CPA data. Discuss the integration of ETO and
AEG/CPA data as well as past program(s) experience, knowledge of current and
developing markets, and future codes and standards.
Result – The integration of Avista’s CPA providers is discussed in Chapter 3 – Demand
Side Management.

Carbon Costs – consult Washington State Commission’s Acknowledgement Letter
Attachment in its 2017 Electric IRP (Docket UE-161036), where emissions price modeling
is discussed, including the cost of risk of future greenhouse gas regulation, in addition to
known regulations.
Result – The social cost of carbon is used in the Expected Scenario for the State of
Washington.

Avista will ensure Energy Trust of Oregon (ETO) has sufficient funding to acquire therm
savings of the amount identified and then approved by the OPUC and ETO Board.
Result – The ETO has received the necessary funding to acquire therm savings as
identified and then approved by the OPUC and ETO Board.
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Regarding high pressure distribution or city gate station capital work, Avista does not
expect any supply side or distribution resource additions to be needed in our Oregon
territory for the next four years, based on current projections. However, should conditions
warrant that capital work is needed on a high-pressure distribution line or city gate station
in order to deliver safe and reliable services to our customers, the Company is not
precluded from doing such work. Examples of these necessary capital investments
include the following:
• Natural gas infrastructure investment not included as discrete projects in IRP
o Consistent with the preceding update, these could include system
investment to respond to mandates, safety needs, and/or maintenance of
system associated with reliability
▪ Including, but not limited to Aldyl A replacement, capacity
reinforcements, cathodic protection, isolated steel replacement, etc.
• Anticipated PHMSA guidance or rules related to 49 CFR Part §192 that will likely
require additional capital to comply
o Officials from both PHMSA and the AGA have indicated it is not prudent for
operators to wait for the federal rules to become final before improving their
systems to address these expected rules.
▪ Construction of gas infrastructure associated with growth
▪ Other special contract projects not known at the time the IRP was
published
• Other non-IRP investments common to all jurisdictions that are ongoing, for
example:
o Enterprise technology projects & programs
o Corporate facilities capital maintenance and improvements

An updated table 8.1 for those distribution projects in Oregon:
Location Gate Station Project to Remediate Cost Year
Klamath
Falls, OR Klamath Falls #2703 TBD - 2023+
Sutherlin, OR Sutherlin #2626 TBD - 2023+

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Result – Large High-pressure distribution and City Gas projects did not occur since the
2018 IRP. Quarterly updates will continue to occur with Oregon Staff to ensure any
change in projects is known along with reasons for any major changes in expected capital
expenditures.

Avista will work with members of the OPUC to determine an alternative stochastic
approach to Monte Carlo analysis prior to Avista’s 2020 IRP and share any
recommendations with the TAC members.
Result – Avista and the OPUC agreed on a 1,000 draw minimum in all scenarios and
were performed to this standard in all stochastic simulations in the current IRP.

2021-2022 Action Plan

New Activities for the 2023 IRP
1. Further model carbon reduction in Oregon and Washington
2. Investigate new resource plan modeling software and integrate Avista’s system
into software to run in parallel with Sendout
3. Model all requirements as directed in Executive Order 20-04
4. Avista will ensure Energy Trust (ETO) has sufficient funding to acquire therm
savings of the amount identified and approved by the Energy Trust Board.
5. Explore the feasibility of using projected future weather conditions in its design day
methodology.
6. Regarding high pressure distribution or city gate station capital work, Avista does
not expect any supply side or distribution resource additions to be needed in our
Oregon territory for the next four years, based on current projections. However,
should conditions warrant that capital work is needed on a high-pressure
distribution line or city gate station in order to deliver safe and reliable services to
our customers, the Company is not precluded from doing such work. Examples of
these necessary capital investments include the following:
• Natural gas infrastructure investment not included as discrete projects in IRP
– Consistent with the preceding update, these could include system
investment to respond to mandates, safety needs, and/or maintenance
of system associated with reliability
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• Including, but not limited to Aldyl A replacement, capacity
reinforcements, cathodic protection, isolated steel replacement,
etc.
– Anticipated PHMSA guidance or rules related to 49 CFR Part §192 that
will likely require additional capital to comply
• Officials from both PHMSA and the AGA have indicated it is not
prudent for operators to wait for the federal rules to become final
before improving their systems to address these expected rules.
– Construction of gas infrastructure associated with growth
– Other special contract projects not known at the time the IRP was
published
• Other non-IRP investments common to all jurisdictions that are ongoing, for
example:
– Enterprise technology projects & programs
– Corporate facilities capital maintenance and improvements

Ongoing Activities

• Continue to monitor supply resource trends including the availability and price of
natural gas to the region, LNG exports, methanol plants, supply and market
dynamics and pipeline and storage infrastructure availability.
• Monitor availability of resource options and assess new resource lead-time
requirements relative to resource need to preserve flexibility.
• Meet regularly with Commission Staff to provide information on market activities
and significant changes in assumptions and/or status of Avista activities related to
the IRP or natural gas procurement practices.
• Appropriate management of existing resources including optimizing underutilized
resources to help reduce costs to customers.

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